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O 116
1. -------------------- 2. October 2, 2015 3. ------------------- 4. October 6, 2015 5. October 8, 2015 6. October 9, 2015 7. --------------------- 8. October 27, 2015 OTHER ORDER 116 Hilcorp Alaska, LLC Docket OTH-15-025 ---- Background information Notice of Investigation, Unauthorized Changes to Approved Permit ---- Emails Hilcorp response to Notice of Investigation AOGCC request for more information re: investigation Hilcorp response to second request for additional 9. ------------------------ 10. November 12, 2015 11. November 18, 2015 12. November 20, 2015 13. November 23, 2015 14. November 25, 2015 15. December 15, 2015 16. January 29, 2016 17. February 18, 2016 18. February 19, 2016 19. February 24, 2016 information Emails Hilcorp letter regarding conditions for Hilcorp restart to workover operations Emails Notice of Proposed Enforcement Action Lane Powell entry of appearance as attorneys of records for Hilcorp Hilcorp's request for Informal Review AOGCC letter regarding Informal Review and counsel present during informal review Hilcorp requesting informal review without counsel AOGCC letter scheduling informal review Hilcorp informal review submission (held in secure storage, non -confidential version submitted 2/24/16 Informal review sign -in sheet Email regarding informal review questions Hilcorp informal review submission without confidential information, requested during informal review ORDERS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue Anchorage, Alaska 99501 Re: Failure to Notify of Changes to an Approved ) Docket Number: OTH-15-025 Permit. Failure to Maintain a Safe Work ) Other Order 116 Environment. Milne Point Unit J -08A, PTD ) 1991170. ) March 3, 2017 DECISION AND ORDER On November 12, 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 J -08A (MPU J -08A). The Notice was based upon Hilcorp's performance of well operations on MPU J -08A by failing to obtain approval to change an approved program, failing to follow good oilfield engineering practices, and failing to provide BOPE test reports to the AOGCC within 5 days after completing the test. The Notice proposed specific corrective actions and a $720,000 civil penalty. At Hilcorp's request an informal review was held February 18, 2016. Summary of Proposed Enforcement Action: The conduct which gave rise to the Notice occurred during workover operations conducted by Hilcorp on the MPU J -08A well on September 23 — 25, 2015. Hilcorp notified the AOGCC that three Automated Services Rig 1 (ASR1) personnel had been "overcome by something" while performing a well cleanout with nitrogen at MPU J -08A, and an AOGCC inspector was sent to the location to gather information about the workover operation and incident. Nitrogen had not been approved for use during a well cleanout on MPU J -08A. The Notice identified violations of 20 AAC 25.507, 20 AAC 25.526, and 20 AAC 25.285. After review of information gathered and discussions with Hilcorp about the events at MPU J - 08A, the Notice proposed civil penalties as follows: - $100,000 for the unauthorized change to the work procedure approved in Sundry 315- 527 - use of nitrogen in the cleanout of MPU J -08A; Other Order 116 March 2, 2017 Page 2 of 8 $600,000 for failure to maintain a safe work environment in accordance with good oilfield engineering practices: o $100,000 for failure to engage in formal hazards identification; o $100,000 for failure to identify and implement safeguards to ensure personnel safety in the event of a nitrogen release; o $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; o $100,000 for failure to have in place a robust "Stop Work Authority" that was clearly understood and readily implemented by ASR1; o $100,000 for failure to assess and manage changes that potentially introduce new hazards or unknowingly increase risk of existing hazards during a rig workover, and o $100,000 for inadequate training of personnel on ASR1. $20,000 for failure to provide the results of a blowout prevention test to AOGCC within five days after completion of the test on September 24, 2015, including $10,000 for the initial event and $5,000 per day for the remaining two days that elapsed until the test report was received. Changes to an Approved Permit: An operator may not undertake a change to an approved program or activity without AOGCC approval. To make a valid change, the proposed change must be provided in advance to AOGCC for review and approval. Good Oilfield Practices: An operator must conduct all operations in a safe and skillful manner in accordance with good oilfield engineering practices. The hazards associated with the commercial uses of nitrogen are well documented and readily available.' Safety training programs and standardized safety procedures required for working in North Slope oilfield operations emphasize not only the hazards represented by nitrogen but also the good oilfield operating practices that should be employed when nitrogen is part of a work activity. 2,3 I U.S. Chemical Safety and Hazard Investigation Board, Safety Bulletin No.2001-10-13, Hazards of Nitrogen Asphyxiation; June 2003 2 North Slope Training Cooperative, Range of Oz Levels 3 2014 Alaska Safety Handbook; At the time of this incident, Hilcorp had adopted the Alaska Safety Handbook for its North Slope operations (October 6, 2015 letter from Hilcorp to AOGCC) Other Order 116 March 2, 2017 Page 3 of 8 Blowout Prevention Equipment Testing: Blowout prevention equipment test reports must be provided to AOGCC within five days after completing the test. Hilcorp ASR1 blowout prevention equipment was tested on September 24, 2015, and the AOGCC received the test report on October 2, 2015. Informal Review: On January 29, 2016 Hilcorp submitted documentation in advance of the informal review. Included were: a timeline of activities associated with the workover of MPU J -08A; Hilcorp's Root Cause Analysis; a claim that the use of seawater, nitrogen, or other substances is standard industry practice dependent on actual well conditions encountered during the operation; and a claim that the imposition of multiple penalties for the same event is not within the AOGCC's authority. During the February 18, 2016 informal review, Hilcorp expressed a desire to move toward a resolution with "fair fines", argued against AOGCC's choice of language in the proposed enforcement and asserted AOGCC was imposing separate penalties for one course of conduct. Discussion: Workover operations on MPU J -08A, approved on August 31, 2015 (Sundry Approval 315-527), authorized Hilcorp to replace a failed electric submersible pump (ESP) and perform a well cleanout using 8.5 ppg seawater. The approval did not authorize the use of nitrogen during the workover operations. Hilcorp commenced the workover with the ASR1 rig on September 23, 2015. The failed ESP completion was pulled from the well. After attempting to clean out the well with 8.5 ppg seawater on September 24, 2015, Hilcorp rigged up Halliburton pumping equipment the same day and began to pump nitrogen down the well to aid in the well cleanout. The pumping of nitrogen was completed at 6:30 am on September 25th. While attempting to pump seawater into the well to displace the nitrogen, unexpected annulus pressure of 1100 psi was encountered and pumping was stopped at approximately 8:50 am. The ASR1 rig crew was directed by Hilcorp to bleed off the annulus pressure of 1100 psi, and lined up to bleed off the pressure through the enclosed mud Other Order 116 March 2, 2017 Page 4 of 8 trailer4, not to the external open top tanks that were staged at location for the nitrogen returns. Shortly after the rig crew started to bleed off the annulus pressure, two crew members in the mud pit trailer experienced dizziness and felt light headed. After reporting the dizziness, three crew members lost consciousness for an unknown duration after re-entering the mud pit trailer. A crew member shut in the well, stopping the flow of nitrogen into the mud pit trailer. The well site work was stopped for an incident investigation, and the three affected rig crew members were evacuated to the Milne Point clinic for evaluation. Hilcorp notified the AOGCC of the incident, and AOGCC immediately sent a field inspector to the location. Upon arrival, he interviewed Hilcorp's Wellsite Manager and others, checked records, observed the equipment staged at the location, noted the position of choke manifold and blowout preventer stack valve, and attempted to determine the flowback piping arrangement from the well to the storage tanks, both external and inside the mud trailer. The fill cleanout approach was described to the AOGCC Inspector as pumping nitrogen and seawater to displace the well followed by 100 barrels of seawater pumped in two 50 -barrel increments.5 The Inspector's review of the ASR1 rig files confirmed that the written workover procedure was the same as was attached to the AOGCC's approved sundry, i.e., the onsite procedure did not authorize nitrogen. There was no written procedure available at the location that detailed the overall fill cleanout operation, and there was no written procedure or safety protocol for the use of nitrogen. The ASR1 rig was equipped with a gas buster located in the enclosed mud trailer above the mud tanks. A gas buster - a simple separator vessel used to remove free or entrained gas from fluids 4 ASR1 mud trailer is a fully enclosed module consisting of mud tanks, fluid management equipment, and mud pumps. Mud tanks are housed in a separate from the choke and kill manifolds. A gas buster was also located inside the mud trailer with gas vent piped through the roof to outside. s The well cleanout was designed to pump down the tubing -casing annulus with return flow to surface up the tubing (workstring) to an external flow back tank. Records of the cleanout operations indicate 200,000 standard cubic feet of nitrogen were pumped on 9/25/2015 (Halliburton Job Log #902780922) and that was mixed with 207 barrels of 8.5 pounds per gallon seawater (Hilcorp's Comprehensive List of Causes; Incident Investigation Events Sequencing Chart). Hilcorp reports that the first 50 -barrel seawater pill was successfully pumped (Hilcorp's Internal Incident Investigation). Unexpected pressure was encountered after pumping approximately 4 barrels of the second 50 -barrel seawater pill causing rig personnel to shut down the pumping operation, and realign the flow path to bleed pressure from tubing -casing annulus of MPU J -08A. Records show the flow path was adjusted to allow the returning well bore fluids to flow through the choke manifold valves, gas buster and finally to tanks all within the enclosed mud trailer (instead of bleeding to the exterior tank). Other Order 116 March 2, 2017 Page 5 of 8 circulated in the wellbore, such as fluid used during cleanout - typically contains a series of baffles with a liquid exit on the bottom and a gas -vent line at the top of the vessel .6 During the MPU J - 08A workover, the dump valve on the liquid exit was left open effectively dumping the nitrogen in the return fluids into the enclosed mud trailer. The nitrogen displaced oxygen to a deadly level.° s Findings and Conclusions: Hilcorp has a significant history of noncompliance with AOGCC regulations. Prior to the MPU J - 08A incident, AOGCC issued several enforcement actions against Hilcorp for various noncompliant activities, including one involving a civil penalty. AOGCC also met several times with Hilcorp's Alaska managers regarding concerns about regulatory compliance, including an unprecedented meeting with Hilcorp operations personnel at its Kenai field office to advise Hilcorp of AOGCC compliance expectations.' A list of regulatory violations, provided as part of the discussions, was intended to draw attention to and correct Hilcorp's relatively high frequency of noncompliant activities. Hilcorp has violated three distinct regulations in the conduct of workover operations at MPU J - 08A: failure to obtain prior approval for a plan change (20 AAC 25.507); failure to conduct workover operations in accordance with good oilfield engineering practices (20 AAC 25.526), and failure to provide a required report (20 AAC 25.285). Specifically, - Hilcorp did not seek and Sundry 315-527 did not authorize the use of nitrogen for a cleanout out of MPU J -08A. - In proceeding with the nitrogen fill cleanout, Hilcorp failed adequately to identify, assess, and mitigate the hazards associated with the use of nitrogen, and in doing so failed to conduct the cleanout in accordance with good oilfield practices. Specifically, Hilcorp: 6 Schlumberger Oilfield Glossary; liitl}.device is also commonly referred to as a "mud gas separator" or a "poor boy degasser" U.S. Chemical Safety and Hazard Investigation Board, Safety Bulletin No.2001-10-13, Hazards of Nitrogen Asphyxiation; June 2003 S North Slope Training Cooperative, Range of Oz Levels 9 Meeting requested and arranged by Hilcorp; held November 11, 2013 Other Order 116 March 2, 2017 Page 6 of 8 o failed to engage in the formal hazards identification process (facilitated by hazards/risk experts) integral to the work planning process, including assessing the risks of using nitrogen in a fill cleanout on ASR1; o failed to identify and implement safeguards to ensure personnel safety in the event of a nitrogen release for the fill cleanout operation; o failed 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; o failed to have in place a "Stop Work Authority" that was clearly understood and readily implemented by ASR1 personnel; o failed to provide a documented process for assessing and managing changes to approved sundries that potentially introduce new hazards or increase risk of existing hazards during a rig workover. Hilcorp ASR1 blowout prevention equipment was tested on September 24, 2015, representing the initial test after rigging up on MPU J -08A. By regulation, blowout prevention equipment test reports must be provided to AOGCC within five days after completing the test. AOGCC received the required test report three days past due on October 2, 2015, violating 20 AAC 25.285. The AOGCC has considered the factors in AS 31.05.150(g) in its determination of penalties for the MPU J -08A violations. Hilcorp has demonstrated neither mitigating factors relative to this incident nor that AOGCC missed information in reviewing the enforcement action. The extent and seriousness of the consequences of the violations cannot be overstated: nothing but luck prevented the deaths of three workers during the cleanout operations. Hilcorp's conduct cannot be characterized as a good faith attempt to comply with AOGCC regulations. The potential severity of the outcome of Hilcorp's actions, Hilcorp's ongoing history of performing work outside of approved permits or management -of -change protocols, its history of compliance issues and the need to deter are significant factors in the AOGCC's analysis. 10 However during the past twelve months, Hilcorp has taken initiatives that have improved their overall regulatory compliance. Also, after the initial investigation of this incident, the AOGCC stopped work on all four Hilcorp workover rigs in Alaska from 10/1/15 to 10/26/15, until Hilcorp could demonstrate compliance with AOGCC's conditions for restarting well work. The AOGCC recognizes that this shutdown of well workover operations had a significant financial impact to Hilcorp. AOGCC finds some 10 AS 31.05.150(g) requires AOGCC to consider nine criteria in setting the amount of a civil penalty. Other Order 116 March 2, 2017 Page 7 of 8 merit in Hilcorp's claim that AOGCC has issued multiple penalties for a single act, specifically that some of the penalties under 20 AAC 25.526 are overlapping. However, AOGCC does not agree the entire incident comprises a single act and finds that Hilcorp has violated three distinct regulations in the conduct of workover operations at MPU J -08A. Now Therefore It Is Ordered That: A civil penalty in the amount of $200,000 is imposed for violating 20 AAC 25.507, 20 AAC 25.526, and 20 AAC 25.285 during the workover operations on MPU J -08A as follows: $80,000 for changing the work procedure in Sundry approval 315-527 - performing the cleanout of MPU J -08A using an unapproved contingent plan (nitrogen); $100,000 for failure to maintain a safe work environment in accordance with good oilfield engineering practices. Included are: o failure to engage in the formal hazards identification; including the failure to assess and manage changes that introduced new hazards or unknowingly increased risk of existing hazards during a rig workover; o failure to identify and implement safeguards to ensure personnel safety in the event of a nitrogen release; including 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; and o inadequate training of personnel performing cleanout operations on ASR1. $20,000 for failing to provide the results of a blowout prevention test to AOGCC within five days after completing the test on September 24, 2015. Included is $10,000 for the initial event and $5,000 per day for the remaining two days that elapsed until the test report was received. Done at Anchorage, Alaska and dated March 3, 2017. Loa Cath P. F erster Daniel T. Sreamount, Jr. Hollis S. French Chaff , Commissioner Commissioner Commissioner Other Order 116 March 2, 2017 Page 8 of 8 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. E3 Postal TM CERTIFIED o RECEIPT QTotal Postage and Fees Mr. David Wilkins ul Domestic Mail Only a ---------- --------------------Hilcorp Alaska, LLC Street and Apt. No., or PO Box No. co _____ _____ ___ __________________ 3800 Centerpoint Dr., Ste. 1400 city, state, ZIP+4® Anchorage, AK 99503-5832 ,r r trt COMPLETE.N USE LnF COMPLETE THIS SECTIONON DELIVERY ■ Complete items 1, 2, and 3. q] Certified Mail Fee ■ Print your name and address on the reverse X rl $ so that we can return the card to you. Ln ❑ Addressee Extra Services & Fees (check box, add fee as appropriate) B. Received by (Printed ❑ Retum Receipt (hardcopy) $ o or on the front if sn��---°•- M ❑ Return Recelpt (electronic) $ Postmark ED 1:3 ❑Certified Mail Restricted Delivery $ Here 1:3 ❑Adult Signature Required $ Hilcorp Alaska, LLC ❑ Adult Signature Restricted Delivery $ 3800 Centerpoint Dr., Ste. 1400 E3 Postage i $ QTotal Postage and Fees Mr. David Wilkins ul $ ent To Senior Vice President to O ---------- --------------------Hilcorp Alaska, LLC Street and Apt. No., or PO Box No. r- _____ _____ ___ __________________ 3800 Centerpoint Dr., Ste. 1400 city, state, ZIP+4® Anchorage, AK 99503-5832 ,r r COMPLETE.N COMPLETE THIS SECTIONON DELIVERY ■ Complete items 1, 2, and 3. A. ■ Print your name and address on the reverse X Agent so that we can return the card to you. ❑ Addressee ■ Attach this card to the back of the mailpiece, B. Received by (Printed �of 11vgry C.ar -31 o or on the front if sn��---°•- m item 1? Ye Mr. David Wilkins a below: ❑ No Senior vice President Hilcorp Alaska, LLC MAR 0 7 2017 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503-5832 A0GCC 3. Service Type ❑ Priority Mall Express® II I I III II IIII III I II I IIIII I I III III II III ❑Adult Signature 11 Registered MailTM ❑ Adult Signature Restricted Delivery ❑ Registered Mail Restricted 9590 9402 1823 6104 6489 93 ❑ Certified Mail Restricted Delivery 4I etu n Receipt for ❑ Collect on Delivery Merchandise 2. Article Number (Transfer from service label) ❑ Collect on Delivery Restricted Delivery Mail ❑ Signature Confirmationm El Confirmation 7 015 0640 0 0 0 3 518 5 5 819 lured ured Mail Restricted Delivery Restricted Delivery r$500) PS Form 3811, July 2015 PSN 7530-02-000-9053 Domestic Return Receipt STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue Anchorage, Alaska 99501 Re: Failure to Notify of Changes to an Approved ) Docket Number: OTH-15-025 Permit. Failure to Maintain a Safe Work ) Other Order 116 Environment. Milne Point Unit J -08A, PTD ) 1991170. ) March 3, 2017 DECISION AND ORDER On November 12, 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 J -08A (MPU J -08A). The Notice was based upon Hilcorp's performance of well operations on MPU J -08A by failing to obtain approval to change an approved program, failing to follow good oilfield engineering practices, and failing to provide BOPE test reports to the AOGCC within 5 days after completing the test. The Notice proposed specific corrective actions and a $720,000 civil penalty. At Hilcorp's request an informal review was held February 18, 2016. Summary of Proposed Enforcement Action: The conduct which gave rise to the Notice occurred during workover operations conducted by Hilcorp on the MPU J -08A well on September 23 — 25, 2015. Hilcorp notified the AOGCC that three Automated Services Rig 1 (ASR1) personnel had been "overcome by something" while performing a well cleanout with nitrogen at MPU J -08A, and an AOGCC inspector was sent to the location to gather information about the workover operation and incident. Nitrogen had not been approved for use during a well cleanout on MPU J -08A. The Notice identified violations of 20 AAC 25.507, 20 AAC 25.526, and 20 AAC 25.285. After review of information gathered and discussions with Hilcorp about the events at MPU J - 08A, the Notice proposed civil penalties as follows: - $100,000 for the unauthorized change to the work procedure approved in Sundry 315- 527 - use of nitrogen in the cleanout of MPU J -08A; Other Order 116 March 2, 2017 Page 2 of 8 $600,000 for failure to maintain a safe work environment in accordance with good oilfield engineering practices: o $100,000 for failure to engage in formal hazards identification; o $100,000 for failure to identify and implement safeguards to ensure personnel safety in the event of a nitrogen release; o $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; o $100,000 for failure to have in place a robust "Stop Work Authority" that was clearly understood and readily implemented by ASR'; o $100,000 for failure to assess and manage changes that potentially introduce new hazards or unknowingly increase risk of existing hazards during a rig workover, and o $100,000 for inadequate training of personnel on ASRI . $20,000 for failure to provide the results of a blowout prevention test to AOGCC within five days after completion of the test on September 24, 2015, including $10,000 for the initial event and $5,000 per day for the remaining two days that elapsed until the test report was received. Changes to an Approved Permit: An operator may not undertake a change to an approved program or activity without AOGCC approval. To make a valid change, the proposed change must be provided in advance to AOGCC for review and approval. Good Oilfield Practices: An operator must conduct all operations in a safe and skillful manner in accordance with good oilfield engineering practices. The hazards associated with the commercial uses of nitrogen are well documented and readily available.' Safety training programs and standardized safety procedures required for working in North Slope oilfield operations emphasize not only the hazards represented by nitrogen but also the good oilfield operating practices that should be employed when nitrogen is part of a work activity.2,3 ' U.S. Chemical Safety and Hazard Investigation Board, Safety Bulletin No.2001-10-13, Hazards of Nitrogen Asphyxiation; June 2003 z North Slope Training Cooperative, Range of 02 Levels s 2014 Alaska Safety Handbook; At the time of this incident, Hilcorp had adopted the Alaska Safety Handbook for its North Slope operations (October 6, 2015 letter from Hilcorp to AOGCC) Other Order 116 March 2, 2017 Page 3 of 8 Blowout Prevention Equipment Testing: Blowout prevention equipment test reports must be provided to AOGCC within five days after completing the test. Hilcorp ASR1 blowout prevention equipment was tested on September 24, 2015, and the AOGCC received the test report on October 2, 2015. Informal Review: On January 29, 2016 Hilcorp submitted documentation in advance of the informal review. Included were: a timeline of activities associated with the workover of MPU J -08A; Hilcorp's Root Cause Analysis; a claim that the use of seawater, nitrogen, or other substances is standard industry practice dependent on actual well conditions encountered during the operation; and a claim that the imposition of multiple penalties for the same event is not within the AOGCC's authority. During the February 18, 2016 informal review, Hilcorp expressed a desire to move toward a resolution with "fair fines", argued against AOGCC's choice of language in the proposed enforcement and asserted AOGCC was imposing separate penalties for one course of conduct. Discussion: Workover operations on MPU J -08A, approved on August 31, 2015 (Sundry Approval 315-527), authorized Hilcorp to replace a failed electric submersible pump (ESP) and perform a well cleanout using 8.5 ppg seawater. The approval did not authorize the use of nitrogen during the workover operations. Hilcorp commenced the workover with the ASR1 rig on September 23, 2015. The failed ESP completion was pulled from the well. After attempting to clean out the well with 8.5 ppg seawater on September 24, 2015, Hilcorp rigged up Halliburton pumping equipment the same day and began to pump nitrogen down the well to aid in the well cleanout. The pumping of nitrogen was completed at 6:30 am on September 25th. While attempting to pump seawater into the well to displace the nitrogen, unexpected annulus pressure of 1100 psi was encountered and pumping was stopped at approximately 8:50 am. The ASR1 rig crew was directed by Hilcorp to bleed off the annulus pressure of 1100 psi, and lined up to bleed off the pressure through the enclosed mud Other Order 116 March 2, 2017 Page 4 of 8 trailer4, not to the external open top tanks that were staged at location for the nitrogen returns. Shortly after the rig crew started to bleed off the annulus pressure, two crew members in the mud pit trailer experienced dizziness and felt light headed. After reporting the dizziness, three crew members lost consciousness for an unknown duration after re-entering the mud pit trailer. A crew member shut in the well, stopping the flow of nitrogen into the mud pit trailer. The well site work was stopped for an incident investigation, and the three affected rig crew members were evacuated to the Milne Point clinic for evaluation. Hilcorp notified the AOGCC of the incident, and AOGCC immediately sent a field inspector to the location. Upon arrival, he interviewed Hilcorp's Wellsite Manager and others, checked records, observed the equipment staged at the location, noted the position of choke manifold and blowout preventer stack valve, and attempted to determine the flowback piping arrangement from the well to the storage tanks, both external and inside the mud trailer. The fill cleanout approach was described to the AOGCC Inspector as pumping nitrogen and seawater to displace the well followed by 100 barrels of seawater pumped in two 50 -barrel increments.s The Inspector's review of the ASR1 rig files confirmed that the written workover procedure was the same as was attached to the AOGCC's approved sundry, i.e., the onsite procedure did not authorize nitrogen. There was no written procedure available at the location that detailed the overall fill cleanout operation, and there was no written procedure or safety protocol for the use of nitrogen. The ASR1 rig was equipped with a gas buster located in the enclosed mud trailer above the mud tanks. A gas buster - a simple separator vessel used to remove free or entrained gas from fluids 4 ASRl mud trailer is a fully enclosed module consisting of mud tanks, fluid management equipment, and mud pumps. Mud tanks are housed in a separate from the choke and kill manifolds. A gas buster was also located inside the mud trailer with gas vent piped through the roof to outside. 5 The well cleanout was designed to pump down the tubing -casing annulus with return flow to surface up the tubing (workstring) to an external flow back tank. Records of the cleanout operations indicate 200,000 standard cubic feet of nitrogen were pumped on 9/25/2015 (Halliburton Job Log #902780922) and that was mixed with 207 barrels of 8.5 pounds per gallon seawater (Hilcorp's Comprehensive List of Causes; Incident Investigation Events Sequencing Chart). Hilcorp reports that the first 50 -barrel seawater pill was successfully pumped (Hilcorp's Internal Incident Investigation). Unexpected pressure was encountered after pumping approximately 4 barrels of the second 50 -barrel seawater pill causing rig personnel to shut down the pumping operation, and realign the flow path to bleed pressure from tubing -casing annulus of MPU J -08A. Records show the flow path was adjusted to allow the returning well bore fluids to flow through the choke manifold valves, gas buster and finally to tanks all within the enclosed mud trailer (instead of bleeding to the exterior tank). Other Order 116 March 2, 2017 Page 5 of 8 circulated in the wellbore, such as fluid used during cleanout - typically contains a series of baffles with a liquid exit on the bottom and a gas -vent line at the top of the vessel.6 During the MPU J - 08A workover, the dump valve on the liquid exit was left open effectively dumping the nitrogen in the return fluids into the enclosed mud trailer. The nitrogen displaced oxygen to a deadly leveL7, s Findings and Conclusions: Hilcorp has a significant history of noncompliance with AOGCC regulations. Prior to the MPU J - 08A incident, AOGCC issued several enforcement actions against Hilcorp for various noncompliant activities, including one involving a civil penalty. AOGCC also met several times with Hilcorp's Alaska managers regarding concerns about regulatory compliance, including an unprecedented meeting with Hilcorp operations personnel at its Kenai field office to advise Hilcorp of AOGCC compliance expectations.9 A list of regulatory violations, provided as part of the discussions, was intended to draw attention to and correct Hilcorp's relatively high frequency of noncompliant activities. Hilcorp has violated three distinct regulations in the conduct of workover operations at MPU J - 08A: failure to obtain prior approval for a plan change (20 AAC 25.507); failure to conduct workover operations in accordance with good oilfield engineering practices (20 AAC 25.526), and failure to provide a required report (20 AAC 25.285). Specifically, - Hilcorp did not seek and Sundry 315-527 did not authorize the use of nitrogen for a cleanout out of MPU J -08A. - In proceeding with the nitrogen fill cleanout, Hilcorp failed adequately to identify, assess, and mitigate the hazards associated with the use of nitrogen, and in doing so failed to conduct the cleanout in accordance with good oilfield practices. Specifically, Hilcorp: ' Schlumberger Oilfield Glossary; Iiitp: �rIOss aiitie;d.sIh.coiii; device is also commonly referred to as a "mud gas separator" or a "poor boy degasser" ' U.S. Chemical Safety and Hazard Investigation Board, Safety Bulletin No.2001-10-13, Hazards of Nitrogen Asphyxiation, June 2003 a North Slope Training Cooperative, Range of Oz Levels 9 Meeting requested and arranged by Hilcorp; held November 11, 2013 Other Order 116 March 2, 2017 Page 6 of 8 o failed to engage in the formal hazards identification process (facilitated by hazards/risk experts) integral to the work planning process, including assessing the risks of using nitrogen in a fill cleanout on ASR1; o failed to identify and implement safeguards to ensure personnel safety in the event of a nitrogen release for the fill cleanout operation; o failed 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; o failed to have in place a "Stop Work Authority" that was clearly understood and readily implemented by ASRl personnel; o failed to provide a documented process for assessing and managing changes to approved sundries that potentially introduce new hazards or increase risk of existing hazards during a rig workover. Hilcorp ASR1 blowout prevention equipment was tested on September 24, 2015, representing the initial test after rigging up on MPU J -08A. By regulation, blowout prevention equipment test reports must be provided to AOGCC within five days after completing the test. AOGCC received the required test report three days past due on October 2, 2015, violating 20 AAC 25.285. The AOGCC has considered the factors in AS 31.05.150(g) in its determination of penalties for the MPU J -08A violations. Hilcorp has demonstrated neither mitigating factors relative to this incident nor that AOGCC missed information in reviewing the enforcement action. The extent and seriousness of the consequences of the violations cannot be overstated: nothing but luck prevented the deaths of three workers during the cleanout operations. Hilcorp's conduct cannot be characterized as a good faith attempt to comply with AOGCC regulations. The potential severity of the outcome of Hilcorp's actions, Hilcorp's ongoing history of performing work outside of approved permits or management -of -change protocols, its history of compliance issues and the need to deter are significant factors in the AOGCC's analysis. 10 However during the past twelve months, Hilcorp has taken initiatives that have improved their overall regulatory compliance. Also, after the initial investigation of this incident, the AOGCC stopped work on all four Hilcorp workover rigs in Alaska from 10/1/15 to 10/26/15, until Hilcorp could demonstrate compliance with AOGCC's conditions for restarting well work. The AOGCC recognizes that this shutdown of well workover operations had a significant financial impact to Hilcorp. AOGCC finds some 10 AS 31.05.150(g) requires AOGCC to consider nine criteria in setting the amount of a civil penalty. Other Order 116 March 2, 2017 Page 7 of 8 merit in Hilcorp's claim that AOGCC has issued multiple penalties for a single act, specifically that some of the penalties under 20 AAC 25.526 are overlapping. However, AOGCC does not agree the entire incident comprises a single act and finds that Hilcorp has violated three distinct regulations in the conduct of workover operations at MPU J -08A. Now Therefore It Is Ordered That: A civil penalty in the amount of $200,000 is imposed for violating 20 AAC 25.507, 20 AAC 25.526, and 20 AAC 25.285 during the workover operations on MPU J -08A as follows: $80,000 for changing the work procedure in Sundry approval 315-527 - performing the cleanout of MPU J -08A using an unapproved contingent plan (nitrogen); $100,000 for failure to maintain a safe work environment in accordance with good oilfield engineering practices. Included are: o failure to engage in the formal hazards identification; including the failure to assess and manage changes that introduced new hazards or unknowingly increased risk of existing hazards during a rig workover; o failure to identify and implement safeguards to ensure personnel safety in the event of a nitrogen release; including 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; and o inadequate training of personnel performing cleanout operations on ASR1. $20,000 for failing to provide the results of a blowout prevention test to AOGCC within five days after completing the test on September 24, 2015. Included is $10,000 for the initial event and $5,000 per day for the remaining two days that elapsed until the test report was received. Done at Anchorage, Alaska and dated March 3, 2017. //signature on file// //signature on file// //signature on file// Cathy P. Foerster Daniel T. Seamount, Jr. Hollis S. French Chair, Commissioner Commissioner Commissioner OIL �o Other Order 116 March 2, 2017 Page 8 of 8 TION AND APPEAL 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. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711-0055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639-0309 Fairbanks, AK 99706-0868 vlr�- �� L 3.3 - �2-0 �`-' Singh, Angela K (DOA) From: Carlisle, Samantha 1 (DOA) Sent: Friday, March 03, 2017 12:29 PM To: AK, GWO Projects Well Integrity; AKDCWellIntegrityCoordinator, Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Ann Danielson; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Ben Boettger, Bill Bredar; Bob Shavelson; Brandon Viator; Brian Havelock, Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller, Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Darci Horner, Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David McCraine; David Tetta; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Evan Osborne; Evans, John R (LDZX); George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jdarlington Darlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); John Stuart; Jon Goltz; Chmielowski, Josef (DNR); Juanita Lovett; Judy Stanek; Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin 1 (DNR); Kruse, Rebecca D (DNR); Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Motteram, Luke A; Mueller, Marta R (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky; Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Ted Kramer, Teresa Imm; Thor Cutler; Tim Jones; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Well Integrity, Well Integrity; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Assmann, Aaron A; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; Corey Munk; Don Shaw, Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck; Josh Kindred; 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); Umekwe, Maduabuchi P (DNR); Pat Galvin; Bettis, Patricia K (DOA); Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana 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); French, Hollis (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (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) INDEXES 19 IN LANE POWELL ATTORNEYS & COUNSELORS February 24, 2016 VIA HAND -DELIVERY Ms. Samantha Carlisle BREWSTER H. JAMIESON 907.264.3325 j ami esonb@lanepowel 1. com RECEIVED FEB 2 4 2016 Executive Secretary III AOGCC 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, 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, egal 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 RECEIVED FEB 2 4 206 AOGGC Hilcorp Alaska, LLC's Submission to the AOGCC for Informal Review of AOGCC Docket Nos. OTH-15-259 OTH-15-29, OTH-15-30, and OTH-15-31 Submitted: January 29, 2016 Mr. David Wilkins Mr. Bo York Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage AK 99503-5826 Phone: (907) 777-8300 Email: dwilkins(a,hilcorn.com Brewster Jamieson, Esq. Lane Powell PC 301 W. Northern Lights Blvd, Ste 301 Anchorage, AK 99503 Phone: (907) 277-9511 Email: jamiesonb@lanepowell.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 11E, 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. Hileorp 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 (ASRI). 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 .5 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. 7 Ex. 3, ASR Rig Crew Contacts. 8 Id. 9 Ex. 4, ASRI 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 regulations 10 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 '('20 AAC 25.280. ' 1 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 attachments 13 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. 18 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 1 s Id. 19 Ex. 7, Well J-0 IA. 20 Id. 21 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 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 ASRI 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 Analysis 27 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 ASR1 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 25`h. 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 (3`d 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 24`x'. 3' 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 ASR rig starting just after midnight on the 25th, 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 ASR I'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. 32 Ex. 15, ASR 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 ASR1 Tank Trailer Passenger Side View; Ex. 18 ASR1 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-I5-30, 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 matrix 39 detailing numerous action items to address the CLC. A Lessons Learned Summary 40 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.41 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 ASRI 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/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. (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."46 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) .47 Section .285(f)(2) requires a re -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 Notices 48 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.ss sa Supra, at Section IID, n. 42. " 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 operation 56 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 nitrogen 60 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 ASRL 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 which 63 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 Conun 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_S tatement_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 198 1) (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 Comm'n, 753 P.2d 703, 714 (Alaska 1988). 76 Id. Hilcozp 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 ASR 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-0IA (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 ASR1 Fluid Flow Diagram J -08A Incident 16 J -08A Jobsite Overview 17 ASR1 Tank Trailer Passenger Side View 18 ASR 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 I-03 (May 2, 2015) 23 Halliburton Pressure Test and N2 Pumping Procedures TABLE OF CONTENTS SECTION I: INTRODUCTION.........................................................1 1. MANAGEMENT POLICY STATEMENT.............................................................................1 2. SAFETY GOALS............................................................................................................................................2 3. SAFETY RESPONSIBILITIES......................................................................................................................2 A. EMPLOYEES...................................................................................................................................2 B. SUPERVISORY PERSONNEL........................................................................................................3 C. EH&S DEPARTMENT....................................................................................................................4 D. MANAGEMENT..............................................................................................................................4 E. CONTRACTORS..............................................................................................................................4 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 S. 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 PURPOSE OF PROGRAM...................................................................................33 B. CRANE...........................................................................................................................................22 HAZARD ASSESSMENT..............................................................................................................33 C. SLINGS AND WIRE ROPES.........................................................................................................24 SELECTION GUIDELINES..........................................................................................................33 18. FORKLIFT....................................................................................................................................................25 D. A. GENERAL......................................................................................................................................25 E. 19. HYDROGEN SULFIDE CONTINGENCY PLAN......................................................................................25 F. A. SCOPE............................................................................................................................................25 B. CONTINGENCY PLAN.................................................................................................................26 2. STATIONARY MACHINERY/GUARDING & OPERATION...................................................................37 C. TRAINING.....................................................................................................................................27 WORK..................................................................................................................................................38 D. EQUIPMENT AND LOCATION OF EQUIPMENT.....................................................................27 AND WORKING SURFACES.................................................................................................39 E. BRIEFING AREA SAFETY TRAILER AND WIND DIRECTION INDICATORS ....................27 F. H2S DETECTION AND MONITORING EQUIPMENT..............................................................27 7. COMPRESSED 20. TOXICITY AND FIRST AID.......................................................................................................................28 A. TABLE: TOXICITY OF VARIOUS GASES................................................................................28 A. B. PROPERTIES OF VARIOUS GASES...........................................................................................28 B. C. PHYSICAL PROPERTIES AND PHYSIOLOGICAL EFFECTS ON HUMANS ........................28 C. D. FIRST AID TREATMENT FOR H2S EXPOSURE.......................................................................29 D. E. RESCUE BREATHING..................................................................................................................29 E. F. WELL OUT OF CONTROL...........................................................................................................30 F. G. EMERGENCY TELEPHONE NUMBERS....................................................................................32 G. 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 SECTION IV: OTHER WORK AREAS............................................................59 1. FIELD LOCATION SAFETY......................................................................................................................59 O. EXTENSION CORDS....................................................................................................................47 P. RUBBER MATS IN LABS AND SHOPS......................................................................................47 C. Q. BATTERIES AND STAND BY GENERATORS..........................................................................47 D. PRESSURE RELIEVING VESSELS AND PIPE BEFORE OPENING........................................59 R. OVERLOADING CIRCUITS.........................................................................................................47 REMOTE STARTING EQUIPMENT............................................................................................60 S. GIN POLES....................................................................................................................................47 G. T. ELECTRICAL BOXES..................................................................................................................47 H. PRODUCT SAMPLING.................................................................................................................60 U. PORTABLE ELECTRIC MOTORS AND PUMPS.......................................................................47 J. GAS METERS................................................................................................................................60 V. GROUNDING OF FENCES...........................................................................................................48 A. W. CATHODIC PROTECTION RECTIFIERS...................................................................................48 B. PROPER GAUGING AND SAMPLING EQUIPMENT...............................................................61 X. RUBBER GLOVES........................................................................................................................48 OPENING THE GAUGE HATCH.................................................................................................61 Y. HOT STICKS..................................................................................................................................48 E. Z. STATIC ELECTRICITY................................................................................................................48 F. 10. PLANT EQUIPMENT - CONTROL OF HAZARDOUS ENERGY (LOCKOUT/TAGOUT)...................51 G. TANK DIKE MAINTENANCE.....................................................................................................62 A. GAS COMPRESSORS...................................................................................................................51 RECEIVING PROCEDURES TO AVOID SPILLS.......................................................................62 B. COMPRESSORS............................................................................................................................51 3. GATHERING SYSTEM AND LEASE TANK GAUGING.........................................................................63 C. AIR COMPRESSORS....................................................................................................................52 GAUGING TANKS........................................................................................................................63 D. HEATERS.......................................................................................................................................52 C. E. BOILERS........................................................................................................................................52 GATHERING SYSTEM LEAK REPAIR......................................................................................64 F. PRESSURE SAFEGUARDS..........................................................................................................52 4. WATER 11. LAWN MOWERS, TRACTORS, ATV'S AND CHAIN SAWS.................................................................53 A. 12. CONFINED SPACE ENTRY.......................................................................................................................53 B. 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 RECORDS LIST AND FILING SYSTEM...................................................................................................78 SECTION X: EMERGENCY ACTION PLAN..................................................78 1. 2. 3. 4. 5. 6. 7. 8. 9. 10 11 PURPOSE......................................................................................................................................................78 EMERGENCY ESCAPE PROCEDURES AND ASSIGNMENTS.............................................................79 RESCUE AND MEDICAL DUTY ASSIGNMENTS..................................................................................80 EMERGENCY REPORTING PROCEDURES............................................................................................81 EH&S DEPARTMENT RESPONSIBILITIES.............................................................................................81 TRAINING....................................................................................................................................................81 DRILLS.........................................................................................................................................................82 MEDICALEMERGENCY...........................................................................................................................82 FIREAND EXPLOSIONS............................................................................................................................83 BOMBTHREAT...........................................................................................................................................84 HOSTAGESITUATION..............................................................................................................................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 [Ta ET41-11X41 F41 Hilcorp Alaska, LLC (hereinafter referred to as "COMPANY") stresses the importance of safety and safety requirements as outlined in the Minimum Contractor Saflaty, Requirements herein (the "Standards"), 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, flicility, 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 Program 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 runctions. COMPANY prohibits the possession of firearms, weapons, or explosives on or around any property, 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 broken 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 onshore, in an office, warehouse, or other COMPANY facility. COMPANY expects CONTRACTOR to train its employees to recognize common hazards associate ' d 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, LIX. MSA Master form, Novearber2014 Lxhibit 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 EQUIPMENT (PPE CONTRACTOR is required to provide all applicable PPE for its employees. The following PPE is required to he worn by all persons while on COMPANY work sites; Clothing - Flame Resistant Clothing (FRC) must be worn at all times while on COMPANY work sites. COMPANY accepts only shirt and pant combinations and coverall FRC. FRC must be filly buttoned and/or zipped (no eotton showing) at all times. Foot Protection - Steel -toed boots must be worn at all times. Please note that steel -toed tennis shoes are not allowed. ffeadProfecliott - Each person in a work- area must wear a hard hat secured by the chinstrap, it'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 Ves6 - For job locations located on or near water, life vests must be worn at work. sites when working outside of handrails near or over water. This includes docks, shore based facilities (within 10 feet of water's edge), platforms, and camps. Inflatable life vests are discouraged, but, ifused, must be auto -inflating. In the situations identified below, COMPANY requires that life vests be worn at all times, • When travelling on a built or barge • When loading or unloading from a boat or barge • When working an a construction barge (unless the life vest creates an unsafe working condition) Addlilonal PPE Protection - Additional PPE may he 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, li filines, 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. 308 SAFETY ANALYSES (JSAs} 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 Hileorp Alaska, LLC, MSA Moster Form, November 2014 CxhibitC-2 EXHIBIT 2 Page 2 of 4 • SIMOPS (Multiple operations occurring simultaneously on the same work site) • Heavy Lifts • New Equipment Startup • Adverse Weather Conditions Hot Work - COMPANY prohibits any Hot Work (Welding, Cutting Torch, grinding or other spark or beat 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. Cotifined Space Entry - COMPANY prohibits Confined Space Entry unless an approved Confined Space Entry Permit has been issued by an authorized COMPANY representative., Pat/ Protection - COMPANY requires that each CONTRACTOR follow all applicable Federal, State and Local Saky Regulation!;, 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 safety belts, lifelines and lanyards, safety nets, and climbing devices. Lock OnvTag Out - 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 of electric shock; including, but not limited to, Lock Out/Tag Out procedures. Dentition 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 boat. Methods used may include physical searches and, as appropriate, scheduled or random drug urinalysis screening. infractions ref policy; including failure to submit to a search, will be grounds for disciplinary action, up to and including 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 INCIDENTS 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, audiotapes, 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 fails to timely report an incident, including, without limitation, termination ofthis 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 CEH&Sl at the COMPA'NY's corporate offices via facsimile transmission to (713) 299-2750 or email to hert(Milogirp,com. If CONTRACTOR cannot notify an on-site COMPANY representative, CONTRACTOR shall immediately notify EH&S st,713-209-2400. ffilcotp Alaska, LLC, MSA Master Form, November 2014 Ekhibit 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 fallow 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 713-209-2400 with any questions or concerns. THE REMAINDER OF THIS PAGE IS INTENTIONALLY LEFT BLANK Hilcorp Alaska, LLC, MSA Master Form, November 2014 f--'xlubitC-4 EXHIBIT 2 Page 4 of 4 ASR Rig Crew Contacts 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 Gas Buster/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 2 2 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 1 1 1 1 1 1 1 1 1 1 2 2 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 1995 1491 1996 1998 1999 2002 2003 2005 2012 2036 2051 11/2/2015 11/2/2015 11/3/2015 11/3/2015 11/3/2015 11/3/2015 11/4/2015 11/4/2015 11/6/2015 11/8/2015 1/5/2016 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 SO1 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 THE STOPd9 SAFETY OBSERVATION CYCLE DECIDE IUM REPORT TOP �.``.„`�zAC/ 06arwr 'c�B;�T�I��a�a�rt+SttCln.�i�ciClf>�t Actions Unsafe Safe Unsafe Safe of P 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 Tools and of People All Safe EqUilanfent All Safe Injury Causes — Right for the Job — Striking Against or — --- Used Correctly — Being Struck by Objects — In Safe Condition — Caught In, On, or Between Objects ,Procedures Ali Sawn Falling _ Contacting —Available Temperature Extremes — 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 DECIDE REPORT \roP � 1 o® v nc/ OBSERVE Actions Unsafe Safe Unsafe —. Adjusting Personal —Head -to -Toe Check Protective Equipment —Head — — Changing Position — Eyes and Face — r Rearranging Job — Ears - - Stopping Job Between Objects — Respiratory System — Attaching Grounds -- Arms and Hands - -- Performing Lockouts — — Trunk - — Adequate. - Legs and Feet — injury Causes — Right for the Job — Striking Against or — — Used Correctty Being Struck by r In Safe Condition Objects — Caught In, On, or Between Objects Procedures All Safe 51 — Failing - - ContactingAvailable — Temperature Extremes — Adequate. — Contacting Electric Current N Known Understood — — Inhaling, Absorbing, — — or Swallowing a — Falfowed — Hazardous Substance — Repetitive Motions - - Awkward Positions! Static Postures Standards — Known - - Understood — __ Followed — STOP00.00L-ENG-0003 EXHIBIT 4 Pagel of 33 tui aTOM vvan uscay.t oN a'rte ELIMINATE UNSAFE CONDITIONS— \ PREVENT INJURIES r 7 Conditions Unsafe Safe Safe acts observed IL rn 7A,Tfiey_Right for the Job n Safe Condition Are They Unsafe acts observed — Clean — — Orderly — Ordetiy - In Safe Condition — - Right for the Job - Date - In Safe Condition — • SiieLa� c) tn% ^}�ptrti Is It A Available Glean - �_ Adequate — - Orderly In Safe Gondidon - Name Date 73 ;._.,i i • • - site Standards — Available Area — Adequate r i,.l S Shift Time spent on observation Q # of People Contacted Q http:'hla vo stoPd eckl st wm' # of People Observed Additionel STOP' observation Checklists D.PonL Please visit 1K!' .',treini Pan order on -tine. Capydgnt C� 2011 and the STOPv'kgo are registered trademarks can be obtained by contacting for contact Information or to Pont. All rights reserved. S70Pv of DuPont. txe eTOP'utttr neaem.m.evwe ELIMINATE UNSAFE CONDITIONS... j PREVENT INJURIES Conditions Unsafe Safe Safe acts observed 7AThey7Ctondition — Are They — Clean - - Orderly - - Right for the Job — .-- In Safe Condition — Unsafe acts observed to It — Clean — Orderly — Name In Safe Condition — Date • SiieLa� c) tn% ^}�ptrti Standards A Available Adequate — Slutt �1b -- Time spent on observation I ! # of peapja Contacted H1 http-tf www tra�ing.dupont.comi videolstop�c4:khst # of people Observed 10 nal STOP" observation eheckksts can be obtained bq contacting d. Please visit p��,�y2p�i�tc for contest information or to ewrle, Io o are regis erred tredem®rksoot OuPonts reserved. STOP" EXHIBIT 4 Page 2 of 33 THE STO PK SAFETY OBSERVATION CYCLE �. DE.poe REPORT V STOP \ y / Unsafe Safe Personal Protect,ive y�OBSE�RVyyEyy�}�. p t The7�✓�TQt'ra}Wxiii''�il�it. ., Actions Unsafe Safe I Reactions, Unsafe Safe_ Personal" Pratei;tiW Ail Sat of peop$: All Safe 1i -, Adjusting Personal — Head -to -Toe Check Proteetive Equipment _ Head Changing Position — Eyes and Face - - Rearranging Job — — Ears - - Stopping Job — Respiratory System - - Attaching Grounds -- Arms and Hands - - Performing Lockouts — — Trunk - — Striking Against or - Legs and Feet of I People All Sa;fv Injury Causes Tools Equipment — Right for the Job - - Striking Against or — Used Correctly — Being Struck by In Safe Condition — Objects — Caught In, On, or — Available Between objects — Adequate — — Falling - — Known - -- Contacting Temperature Extremes _ Available — — Contacting -- Adequate — Electric Current — Known - - Inhaling, Absorbing, — — Understood — or Swallowing a Followed — Hazardous Substance _ — Repetitive Motions Standards — Awkward Positions/ -- • ' Static Postures - Understood Standards ST0P0fJ-GCL-ENG-0003 — Known - - Understood - - Followed -- STGiP00-OCL-ENG-0003 THE STOP" SAFETY OBSERVATION CYCLE DECIDE REPORT ST.'* A OBSERVE I�Rr���{7aKit�r�N�tt v+R.w��l4 Actions Unsafe Safe i Reactions Unsafe Safe Personal Protect,ive of Pe iple: Ail Safc — Adjusting Personal — All &j I,! 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 Injury Causes Equipment� — Right for the Job — Striking Against or — Used Correctly — Being Struck by Objects — In Safe Condition — Caught In, On, or _ Between Objects — Palling - - Contacting Temperature Extremes Available — Contacting — — Adequate — Electric Current — Known - - Inhaling, Absorbing, — — Understood or Swallowing a — Followed Hazardous Substance — Repetitive Motions - - Awkward Positions( — °rderliness All Safe Static Postures Standards — Known - - Understood — Followed ST0P0fJ-GCL-ENG-0003 EXHIBIT 4 Page 3 of 33 ELIMINATE UNSAFE CONDITIONS... PREVENT INJURIES `T� M! Conditions � Unsafe Safe + Safe acts observed Are They — Right for the Job - - In Safe Condition _,._ Are They Unsafe acts observed — Clean f ' �'1y nand,S — Orderly — Right for the Job a51� tier-f,� y — Name — G hr t o -SSL 5 — In Safe Condition 1 herr I,, Date � ct L r"t t0 h is IY - - Clean — — Orderly — Name — In Safe Condition L 2- Additional STOPS Observation checklists DuPont. Please visit ' Date • — li -"L + - [1 site Standards,j- Standards - Available_ plea Adequate �rr Cl '2- 6 rd f rme spent on observation hlry:7emw. # of People Contacted CaCting. dupentcpm' wdeolstoo-cherxl;t # Of PBopie Observed i( -..2..I Additional STOPS Observation checklists DuPont. Please visit ' can be obtained 6y oonlacting nrvrvvt ,i t.rgp7 for contact information or to t Place an order on-line. Copyright �J?,C 1 DuPont. All rights reserved. STOP' ! arui the STOP logo arereoistered ELIMINATE UNSAFE CONDITIONS... PREVENT INJURIES ,.e eror s.rar caa.wro+crc Conditions — Clean -- Unsafe Safe >. — Orderly Safe acts observed — In Safe Condition ^ 42 " S ". Are They - - Right for the Job - + - [1 - In Safe Condition Site Are They — Clean - - Orderly - - Right for the Job — In Safe Condition — Unsafe acts observed Is It — Clean -- — Orderly Name — In Safe Condition ^ 42 " S ". Date • + - [1 Site Standards � Area — Available — __. Adequate — 1, a _ Shift %Ulml Time spent an observation # of Peopie Contacted Q 1111 *941airrinp.dUponl Coral dde. �?`nL4*'i't # of People Observed Q Additional STOP" Observation checklists can be obtained byy contacting DuPont. Please visit cwrw.l210168, place an ordar on-line. Copyright it fir contact iniormatnn or to DuPont. At! rights reserved. STOP° and the STOP logo are registered trademarks of DuPont. EXHIBIT 4 Page 4 of 33 a4i 1 O O C 8 o. b G? 67Q rO O I I I I ( I I W I I IWy C 0 o O _® z U E Z� v ,L I— Cr C .� 1`s L ro � ED t1) c to m !a a t7 a ;P }�, ' �O • U fS C U O wa % CC • VJ I a .F32 EXHIBIT 4 Page 4 of 33 THE STOP" SAFETY OBSERVATION CYCLE DECIDE REPORT 1 a STOP ,,.o....oa,,. ACT pOBSERVE Actions Unsafe Safe Unsafe Safe Reactions All S06 W,Equipment of People All Safe Z41 — Adjusting Personal — Head -to -Toe Check Protective Equipment — Head - - Changing Position — — Eyes and Face — Rearranging Jab — — Ears — Stopping Job — — Respiratory System - - Attaching Grounds — Arms and Hands - - Performing Lockouts — — Trunk - - Legs and Feet r 1 Positions of People All Safe Or—. Injury Causes Tonl� and tq"ipr"enf AILSato FA, — 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 - - Inhaiing, Absorbing, — — Understood — or Swallowing a — Followed — Hazardous Substance — Repetitive Motions - - Awkward Positions! — Static Postures Standards — Known - - Understood — Followed STOPCID-OCL-ENG-0003 III1141� 4{I II{I{ 441 rn E 41 _N U r V LL �, LI. .,.. Occ O 2 0 F; m A ° Y w V 0 m c % o ��g Y poi T tEE GOi rK c Os 'C y rn f6 m O Y7 m 'O -Q S W w a F`- � 5 ° �� �•�� o� .. - RC1 I l i i!! I I I I I I! I r!J I I I 0 Cc:_o. Q .00 L) o `03 o h % jjLiC LN OCh3 q? cd� aV doQ �o z Y C d tt�� N 4 0- V tY in 4 +i 8,20 V m 2 V 1- U ui � 13 i K <1 g EXHIBIT 4 Page 5 of 33 IR ELIMINATE UNSAFE CONDITIONS... �� PREVENT INJURIES T? Conditions Unsafe Safe Safe acts observed All h h?5 7Theyobion Are They — Clean — Orderly __ Right for the Job — In Safe Condition Is It — Clean — Orderly — In Safe Condition Standards — Available Adequate %,� hltp.lMww.kaningdurn;nf.�am! �1daaStoryrhscklist Additional STOPP Observation C DuPont. Please visit www tMoinc pl-. an ardor on -tine. Copyright and in. STOP -logo are registers Unsafe acts observed _ Name �J-1►- i5 Date - 9.4 Site 1'n,1!1c t�a'ti�fi Area ft — 3 � !ice-'-. r+�s Time spent on observation # of People Contacted Zi # of People Observed ZI can be obtained by contactirig S,QM for contact information or to DuPont All rights reserved" STOP` ,arks of DuPont. ate sii piilaGhpeldi8 Are They — Right for the Job — In Safe Condition �§trrtwtures and Are They Clean — Orderly Right for the Job — In Safe Condition Is It — Clean Orderly In Safe Condition Standards _ Available Adequate %111� l,if NMv ;raining dupcnLComi �idedstdpcneckllst an order 01,4111e. t to si-OFalobo are FIM 121111111111111111 L-1, Unsafe acts observed — Name _ Dat Site _ Area Shift Trine spent on observation # of People Contacted Ka -J # of People Observed Q ecklists can be obtained Dy conlacting d for contact In ormatlon or to as I , Zf .all lohls reserved. STOPo EXHIBIT 4 Page 6 of 33 K � 1 U 9F�t i a -i o Z �� { y 4 a a 4<6 IL4 � rn iw xt xl: ❑ � . O U ., �W —Oi .0 o al $� V EXHIBIT 4 Page 6 of 33 THE STOP" SAFETY OBSERVATION CYCLE DECIDE REEPPORT M, J STOP ,�,., ......-. ACT OBlRRVF y- Sys AC !Actions Unsafe Safe Unsafe Safe personal P e :,of Pecopie All Sate C4 — 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 — Followed — Legs and Feet injury Causes — Repetitive Motions ToolsPositions — Right for the Job - - Striking Against or — — Used Correctly — Being Struck by _._ In Safe Condition — Objects _ —. Caught In, On, or Between Objects Procedures Alt Sate 74. — Failing - - Contacting — Available --- Temperature Extremes — Contacting —Adequate — Electric Current — Known - - tnhaling, Absorbing, — — Understood — or Swallowing a — Followed — Hazardous Substance — Repetitive Motions - - Awkward Positions/ — OrderlineSs Ali Safe 1A Static Postures Standards Known - - Understood — Followed — STOP00-OCL-ENG-0003 THE STOP SAFETY OBSERVATION CYCLE OEC09 REPORT C..'ac OP ov:w��..� AC/ � l OBSERVE Actions Unsafe Safe Unsafe Safe — Adjusting Personal — H95Wo-Too Check Protective Equipment lead — — Changing Position f — — Eyes and Face — Rearranging Job — — Ears — Stopping Job — — Respiratory System — Attaching Grounds — __ Arms and Hands — Performing Lockouts — — Trunk / — Legs and Feet ,Z Injury Causes — Right for the Job — Striking Against or — — Used Correctly Being Struck by Objects — to Safe Gopdition Caught In, On, or Between Objects — Failing — Contacting Temperature Extremes 7Adequate — Contacting Electric Current Inhaling, Absorbing, --- or Swallowing a — Followed Hazardous Substance — Repetitive Motions — Awkward Posit ons1 — &M Static Postures STOPOO-OCL-ENG-0003 Standards — Known - - Understood — Followed EXHIBIT 4 Page 7 of 33 Lm ,x. SroP• aN.rcn onmvmw c+cu PREVELIMENATE UNSAFE NT INJURIES CONDITIONS... �\ f Conditions Unsafe Safe Safe acts observed J'a7 0/ 'f,�J>' mF1N,rr Are They%Inti --_ Right for the Job — a..-'kr� — In Safe Condition — �' r Are They Unsafe acts observed — Clean - -- Orderly _ w Right for the Job # of People Observed In Safe Condition Erwironment Ali I Safe Is It �:%,SS//��/�r^- — Clean _ — Orderly Q�t - In Safe Condition - ❑+ ate httpf visroG•Gwcklrst.wM Obs, site Additional STOP' Observation Checklists can for bttaineii%cor,li'mati ctln to DuPont Please visit 201tPfD� nt. All rights reserved. STOPn _rp _4 Standards — Available A reaII� ._ Adequate , J��{ 4 0 ,H[ eTDPTymvWieN.PON cvu[ L.IMINATE UNSAFE CONDITIONS... IREVENT INJURIES \ / Conditions _ Unsafe Safe Safe acts oiaserved Are They Right for the Job - - In Safe Condition — Are They � NE — , ' "t Orderly # Of People Contacted hllp:riwtev.tra�ilg.dupor,l.mmf vidm(stvp-&eckiist # of People Observed Dnal STOP" Obsorvation Checklists can be obtained by contacting nt. Please visrl Ja ;SG9ltllC14,d,�,�t},53Hit for contact informabon or to an order on-line. Copyright ®ffil uPont. All rights reserved. STOP ie STOP* logo are registered tratlemarks of DuPont 4 0 ,H[ eTDPTymvWieN.PON cvu[ L.IMINATE UNSAFE CONDITIONS... IREVENT INJURIES \ / Conditions _ Unsafe Safe Safe acts oiaserved Are They Right for the Job - - In Safe Condition — Are They Unsafe acts observed j — Clean — , ' "t Orderly — At rcr�+•-`� I c c+,, Right for the Job /Ajt .1 l'.'IA� �4nSafe Condit'ony1455r3–.–�— Area — Available — �:%,SS//��/�r^- — Adequate — %MI6. Is it — Clean — Orderly ame _. In Safe Condition — All Safp Cafe r �y� Site _ Standards Area — Available — A I< — Adequate — Shift 1 Q�t 0'r Time spent on observation ❑+ # offbople Contar ted httpf visroG•Gwcklrst.wM Obs, # of people Additional STOP' Observation Checklists can for bttaineii%cor,li'mati ctln to DuPont Please visit 201tPfD� nt. All rights reserved. STOPn place an order on ine. COpyri9 nt �� ma STOffe InOD are registered trademarks Of DUPon1. N 3 fie a $- i m z�n EXHIBIT 4 Page 8 of 33 4 .r 2 1 i7 N l y 0 t C� j o + r L Caw o Ueopp� U X v y 2 cc v z n18 Y N 3 fie a $- i m z�n EXHIBIT 4 Page 8 of 33 \ \ we =gam» w\ ƒ/§,;a 2o¥±\mD �a��a§■ §■ ! 2z/rn § >ƒmm= \{ § \�/®!)it'3 EXHIBIT 4 Page 9 0 33 &> m =oe 3n»o a =o oE@ J z-/n �m a f} ER 77\a 23 }f2! a » Fr S5,- n/ E± ®{7 s o® - » ` ;$ ■ ;&ate f ¥- ° { (9 tT J - / II`i ILII � I IIIA �lI�) IIS ƒa0 fEƒ$[cn 73lA 7\m2E #\J we =gam» w\ ƒ/§,;a 2o¥±\mD �a��a§■ §■ ! 2z/rn § >ƒmm= \{ § \�/®!)it'3 EXHIBIT 4 Page 9 0 33 �• .� ,arrneerrTit!W urleCJtti$t.,- ELIMINATE UNSAFE CONDITIONS_ PREVENT INJURIES Unsafe s: 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 %"� h#P,limw trairing.dupcntarts mern'slop•choulst Additional STOPS observation cf DuPont. Please visit maw—• train» place an order o"Ine. Copyright and the STOP° I o are ragistere Unsafe acts observed ame Date O{! Site Area Time spent on observation #ofPeopleContacted ❑ # of PeoPIC Observed ❑ can be obtained by contacting tom for contact information or to :)-Pont. All rights reserved. STOP" o a o •�. srov^a..e:•wu...nar=rM ELIMINATE UNSAFE CONDITIONS... PREVENT INJURIES .f+� Conditions — In Safe Condition Unsafe Safe Date Safe acts observed Z-06 NrWJ war.+ srtQd[ru'°t�td Are They =no 1z �QLy.Jr — Right for the Jot) Y W-lLen 3r✓Eb — In Safe Condition to gJri,raL- c i4 z o Struclurcl_ and 'Wolrk Area AI(Sare !A: s iii Y Are They Unsafe acts observed 2 0 # of People Contacted ❑ httplA•nnv.haio,ina.dr.pc nt.coml N videa�stcP-checNllst # of Peopfe observed ❑ Additional STOP° Observation Checklists can be obtained byY contacting DuPont. Please visit ag,pu;tgq roto for contact inio ,trsrmatlon or to Place an order on-line. Copyright 0 2011 DuPont. All rights reserved. STOP' Find the $TOP° logo are registered trademarks of DuPont. o U w in r Q to a Q z U Unsafe acts observed ame Date O{! Site Area Time spent on observation #ofPeopleContacted ❑ # of PeoPIC Observed ❑ can be obtained by contacting tom for contact information or to :)-Pont. All rights reserved. STOP" o a o — Clean — Orderly _.- Right for the Job — In Safe Condition Is N •�. srov^a..e:•wu...nar=rM ELIMINATE UNSAFE CONDITIONS... PREVENT INJURIES .f+� Conditions — In Safe Condition Unsafe Safe Date Safe acts observed Z-06 NrWJ war.+ srtQd[ru'°t�td Are They =no 1z �QLy.Jr — Right for the Jot) Y W-lLen 3r✓Eb — In Safe Condition to gJri,raL- c i4 — :,,c__,______ Struclurcl_ and 'Wolrk Area AI(Sare !A: s iii Y Are They Unsafe acts observed — Clean — Orderly _.- Right for the Job — In Safe Condition Is N ..-- Clean - - Orderly Name — In Safe Condition — Date Orderliness Ali Safp.W Z-06 Site Standards hP V — Available Area — Adequate — :,,c__,______ Shift Orf a YrY4L:- Time spent on observation 0 # of People Contacted ❑ httplA•nnv.haio,ina.dr.pc nt.coml videa�stcP-checNllst # of Peopfe observed ❑ Additional STOP° Observation Checklists can be obtained byY contacting DuPont. Please visit ag,pu;tgq roto for contact inio ,trsrmatlon or to Place an order on-line. Copyright 0 2011 DuPont. All rights reserved. STOP' Find the $TOP° logo are registered trademarks of DuPont. ( !oOfl J. CL v ° 78 5 i H � a; � m • �� m 4. tl $�"� ar I I iEffI_ 01— m H vm L A EXHIBIT 4 Page 10 of 33 THE STOP SAFETY OBSERVATION CYCLE bECIOEREPORT ..e(��(e,�,pp���� \TOP\ �n.; p, AC� 1 / O.BERVE Ttte$T+�:tib&etvssrri CtteG(clist Actions Unsafe Safe Unsafe Safe �Reaction5 Personal — 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 ositions Tools and Injury Causes — Right for the Job — Striking Against or — — Used Correctly Being Struck by — In Safe Condition Objects - - Caught In, On, or — Between Objects Procedures Ali safe M Falling — Contacting — _Available Temperature Extremes — 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 EXHIBIT 4 Page 11 of 33 me srovn,usr. neen•.x,.rox crew ELIMINATE UNSAFE CONDITIONS... PREVENT INJURIES '—X, (,`jp / Conditions Unsafe Safe r: Safe acts observed Are They --a — Right for the Job — In Safe ConditionT Are They Unsafe dots observed — Clean Conditions — Ordedy _ Right for the Job — in Safe Condition Is It N — Clean 4 -- Orderly — Right for the Job — to Safe.Condition — i j r s Date • Are They z Z o sire Standards W w 0 — Available Area Adequate Shift e. ,r Time spent on observation © # of Peaple Contacted http;'Nww.t ngdupor4.sam! mdedamo-crackl:sf # of People Observed Additional S"OP$ Observation Checklists can be oblairsd by contacting DuPont. Please visit W18 tp t]IQg,tiypont.ccm for contact infomnabon or to place an order on-line. Copyright* 20011 DuPont. All rights reserved. STOP" J and the STOPziogo ara regiMered 11'atlemarks of DuPont. '1`ica �'�tiftt�tn �eltli�c �r.o.r rre BTOP°e,rerro,etn ELIMINATE UNSAFE CONDITIONS... PREVENT INJURIES Conditions 3�c Unsafe Safe ` 5a��fejja�ct� observed N moi. Y� 4 D — Right for the Job 0 N r s 0 h` � Are They z Z o m A W w 0 — Orderly _-, Right for the Job — In Safe Condition '1`ica �'�tiftt�tn �eltli�c �r.o.r rre BTOP°e,rerro,etn ELIMINATE UNSAFE CONDITIONS... PREVENT INJURIES Conditions Unsafe Safe ` 5a��fejja�ct� observed Are They i -t — Right for the Job - In Safe Condition r s J Are They Unsafe acts observed — Clean — Orderly _-, Right for the Job — In Safe Condition Is It — Clean — OrderlyName — — In Safe Condition "T'a f<. Date :Ordertiness Ali Safe Siie Standards Area --.. Available — Adequate — s Shift Time spent on observation 0%121' #ofpeopla contacted Q h41IWgM1ttlminillg.tl;lpOnl.coml vftle�!9tap-cnecki®t # of People Observed Additional STOPY Observation Chemists DuPont. Please visit ww _lrainl a tluoopyconi can be obtained b contacting for contact informatlon or to place an order on-line. Copyright ©2071 and the STOPS logo are registered lradsma*s DuPoni. All rights reserved. 870P - of DuPont. o G v U O a Si � `� � i t O oE34 �` �4 t3'd Z Q I Q II Ifil III If m$� To o -0 o & ti RUA.Ip EXHIBIT 4 Page 12 of 33 THE STOP® SAFETY OBSERVATION CYCLE D2C@E JREPORT \TOP..esn. as xF ACT OBSERVE ti�'�fg�'�'i�b�t'�ltlon;Gtt�rettttst Actions Unsafe 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 — aC Legs and Feet Ot People injury Causes — Right for the Job — Striking Against or — Used Correctly Being Struck by _-. In Safe Condition — Objects VCaught in, On, or Between Objects I Proceft�es; All Safe I& — Falling — Contacttng — Available Temperature Extremes — Contacting — Adequate — Electric Current — Known — Inhaling, Absorbing, Understood or Swallowing a V Followed — HaZardOIIS Substance — Repetitive Motions '! Awkward Positionsi — Orderliness Static Postures _ — Standards — Known -- Understood - - Followed STOPv^0-OCl.-ENG-0003 THE STOPR SAFETY OBSERVATION CYCLE DECIIDDE* REPORT STOP \ r...a�,�. /fE ACT l OBSERVE Tt4a'STtyt�° tl�is�wv�t��ttrt Clt�cicttsi- Actions Unsafe Safe Unsafe Safe tions Personal — Adjusting Personal Equipment — Mead -to -Toe Check Protective Equipment — Head — Changing POVtIOry — — Eyes and Face Lf — Rearranging Job — — Ears — Stopping Job — Respiratory System Attaching Grounds — Arms and Hands — Performing Lockouts — _ Trunk O b a O — Legs and Feet .. -Equipment Injury Causes Tools All SafeE .— Right for the Job — Striking Against or — Used Correctly Being Struck by 01 Objects — In Safe Condition — _- Caught In, On, or Between Objects s Y — Falling Procedures All Safe 0 — — 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 C !A Standards — Known y _.-. Understood — Followed STOP00-�C�-EtiG-D003 i ( dN o_- � Tnzn — n d -QR LS 's1N� C! m ��_CL 0(a 5" C O b a O A b < O g - c m 01 . t0 w s Y y 6���10 �Q: rD x oO �Q �c °. C7:3 L7 0 0 m� 0 Cr N. a� m o o oC' 1 g 0 j C !A y I• I {I i ( > N '� r °a d c M� CL c 7 ro -i>Xm{pmCL ecn c tD y v� 2sa 7c Q fl a O Q @ 1 Q I o j = v. = ° S m :: x m z � a a 8 Fn 0 EXHIBIT 4 Page 13 of 33 C t tMINATE UNSAFE COsron=.� a oesenv.n- PREVENT INJURIES NDITIQN3.,, TQp Condit on -5 Unsafe T0019 an Safe acts obse�rveJd,, Are They �'- - Right for the jobi� t a — In Safe Condition ' Are They — Clean Unsafe acts observed Orderly JE � — Right for the Job - - In Safe Condition is It _ — Clean nerek - -Orderly — to Safe Condition Date • 5 —_— Standards — Available _ ~ Area ----- - Adequate _ r DM1.Q o 0 o�13 am Time spent on obs ne aho l �9c Q C7 b'r�"'^Y�'Mn9d�aonlcamt vfdeYelaOctreckllsl # of People Contacted c # ofAeopfe Observed 0 anal STOPS pb�rvation Chec}Ilists can be ob nt. Pfease visit r-' i<Jfnad by 0ontacn.ng an crderoo-tlne. �ID for Co}n ooniaci In or to �e STOPS l090 aro PY 0 0 1 DuPont. All rights reserved. STOP --��9�$lerod traCerrlerks of n„o.._. d nra I ! i I I a a.m4 soca _ �o0 `° I � a o n -`ni . d nc3i e 7 m m m ..i s.0. Or 0 w v m m y ev' t o a a 0 °cr ?...3n I I o 0 o�13 am �9c Q C7 CD a I I ®1 I f KL o -A CD a c N mmcz N T rn y n a Z 0 m KL o -A a c N mmcz N T rn y n a Z 0 m O z!v EXHIBIT 4 Page 14 of 33 THE STOP' SAFETY OBSERVATION CYCLE DECIDE ` REPORT STOP\ fw«., /ACT OaSERVE fiha►F14EItexSrt►ja Ctttrt;kltst Actions Unsafe Safe Unsafe Safe React! ns 110, of People All Safe Piotective — Adjusting Personal — Headd0-Toe Check Protective Equipment r Head — Changing Position — Eyes and Face - - Rearranging Job — — Ears _ -- Stopping Job — Respiratory System Attaching Grounds — Arms and Hands --- Performing Lockouts — — Trunk _ Legs and Feet PositiGoo, Tools a 1:qutpment All Sate. Injury Causes — Right for the Job -- Striking Against or — Used Correctly ObjStruck by — In Safe Condition Objacts - - Caught In, On, or — Between Objects — Falling Procedur.es 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 STOP00-OCL-ENG-0003 THE STOP" SAFETY OBSERVATION CYCLE DECIDE REPORT STOP ACT OBSERVE T#ie $ ftJt?%ttvat8on �d�cktt Actions Unsafe Safe Unsafe Safe Protective All Safe IN — 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 -W- - Striking Against or — Used Correctly !" Being Struck by Objects — In Safe Condition Y — Caught In, On, or Between Objects All Safe EE — Falling - Protpdurres - Contacting - Temperature Extremes — - Available - Contacting — — Adequate — Electric Current — Known — Inhaling, Absorbing, — Understood — or Swa lowing a — Followed — Hazardous Substance — Repetitive Motions - - Awkward Positions/ — • ' Static Postures Standards Known - - Understood — Followed — STOP00.OCL-ENG-0003 EXHIBIT 4 Page 15 of 33 L MS@fS►S��k7fl . 4 ... STOP ssrn moenvnio. orcie ELIMINATE UNSAFE CONDITIONS— PREVENT INJURIES p\ / Conditions Unsafe Safe , Are They Safe acs observed n 3 — Right for the Job - Is it - In Safe Condition Structures an '".d — Area All bate NO Are They Name Unsafe acts observed — Clean — Orderly -Orderlinesst_ — Right for the Job — In Safe Condition Standards 4jr—t'/ 11 r— — Available Is It — Adequate _L" _'/ Clean — — Orderly — _ In Safe Condition — Naame., / 2 Date • • - U Site /� Standards — Available .zK Area _ Adequate —hift 'z S Time spent on observation # of People Contacted f� httpJ,4 decist D -ch uponlown! vide-.�etoo-chi # of People Observed Additional STOP'Cbservation Checklists DuPont. Please visit www.train ;no Cnt.ca�1 duo Place an order on-line., Copyright 9 2011 and lna STOP° Itn�C ere registered trademarks Can be obtained b'y/ contacting for contact infomation or to DuPonl. Ail rights reserved. STOP° of DuPont. —Top, we,rner.e..,•m.cec.a ELIMINATE UNSAFE CONDITIONS... W� ice• PREVENT INJURIES \ f Conditions Unsafe Safe 7A,h Safe acts observed r the Job —Condition Are They Unsafe acts observed — Clean — Orderly — Right for the Job _ _. In Safe Condition Is it — Clean — — Orderly Name — In Safe Condition — 1-.Z4 Date -Orderlinesst_ OL Site Standards 4jr—t'/ 11 r— — Available _ Area — Adequate _L" _'/ ❑� .r � S..r,'n Time spent on observation i ❑' # of People Contacted http;tiwwrr training.dupantcom! raaolstopmhacklisl # of People Observed Additional STOP' Observation Checklists can be obtained by contacting DuPont. Please visit wwit.irainlna duoont cam for contact information or to place an order on-line Copyright Q 2011 DuPont, Alt rights reserved. STOPe and the STOP logo are registered trademarks of DuPont. EXHIBIT 4 Page 16 of 33 E O m @ m L a 0 O tl . © v y5 '. tWi w _ c O o ' C C ❑A t F-, N� a y� = c ? WZ t_� O T d ? d v m ca t0 @ v EXHIBIT 4 Page 16 of 33 THE STOPO SAFETY OBSERVATION CYCLE DECIDE REPORT ACT sTOP �.µ�.�• \ 1 OBSERVE Actions Unsafe Safe Unsafe Safe — Adjusting Personal — I 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 - - Contacting— Temperature Extremes - Legs and Feet — injury Causes — Right for the Job — Striking Against or — Used Correctly Being Struck by _ In Safe Condition — Objects — Ears — Caught in, On, or — Respiratory System — Between Objects — Arms and Hands — Falling - — Trunk - Contacting— Temperature Extremes _ Available Contacting — Adequate - - Electric Current —Known — Inhaling, Absorbing, — —Understood — or Swallowing a — Followed — Hazardous Substance — Repetitive Motions — Awkward Positions/ Static Postures —lKnown ndards UnderstoodFollowed — S70Poo-OCL-ENG-0003 THE STOP" SAFETY OBSERVATION CYCLE DECIDEREPORT \i B��jg, STOP ,.�,.,.,..,u„�` / OBSERVE Actions Unsafe Safe Unsafe — 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 — Inhaling, Absorbing, — — 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 - - Contacting — Temperature Extremes _Available Contacting _ — Adequate Electric Current _ Known — Inhaling, Absorbing, — — Understood or Swallowing a — Followed Hazardous Substance — Repetitive Motions — — Awkward Positions! — Static Postures STOP00-OCL-ENG-0003 Standards -.._ Known — Understood --- Followed EXHIBIT 4 Page 17 of 33 rxr 9Tai°v.rarr eearxnr ryn crc r ELIMINATE UNSAFE CONDITIONS... PREVENT INJURIES c'Top m\ J Conditions Unsafe Safe Are They _ Right for the Job — In Safe Condition Worv. Are. Are They — Clean JC ...- Orderly �C --- Right for the Job — In Safe Condition ie Es it _-_ Clean — Orderly L/ In Safe Condition L% I,-- — Available — Adequate T Area/ - !U l Unsafe acts observed Shin �rr •. Time spent on observation ti _ Name Standards ? J 1-1.) 10C `-' — Available — Adequate T Area/ - !U l - Shin �rr •. Time spent on observation ti # of People Contacled hMpi:wxw,training.du[onkccld videastop-checkikt ,mow # of People Observed L rA Additona. STOP" Obsarvatlon Checklists con be obtained by contacting DuPont. Please visit www.trainina dunont.Cam for contact information or to place an order an -line. Copyright w 2D11 DuPont. All rights reserved. STOP• and ilia STOP"' logo a -a registered trademarks of DuPont. Th,� Bids �5t*erva�ioF� �iva�ti%t r� r eTPP^rnmrorr.a..iicxcrcte ELIMINATE UNSAFE CONDITIONS... PREVENT INJURIES lm z Unsafe Safe acts observed . Tools t 9 IYE �r Are TheyAWL` �) �— — Right for the Job - - In Safe Condition — Are They — Clean — Orderly Right for the Job — In Safe Condition — Unsafe acts observed Is It — Clean - - Orderly _ In Safe Condition Date Sif JJ r CS -1 Standards Available _ Rrea _._ Adequate — Shit httpJ,*e training durant.coml wdealsmp-checHisL Additional STOP• Observation C DuPont, Please visit m5W_ re+nln place an order on-line. Copyright and the STOP= logo are register Time spent on observation # of People Contacted Q, # of People Obser✓ed i can be obtained by contacting com for contact Information or to DuPont. All rights reserved. STOP" narks of DuPont, �a I i` fE L n 8Jn t�i A yr �. td . O E N v 'moi y o U p aT� z . UU-1W C }}.. Z� •� N a p 0 $� D Q4 W " O ¢ z U � Uc m9m g 'LL%@N ° S '2 ° UO >tiL o Na_�Bo s ma o1; EXHIBIT 4 Page 18 of 33 THE STOPS SAFETY OBSERVATION CYCLE DECIDE REPORT \ o / OBSERVE Actions Unsafe Safe Reactions Unsafe Safe Personal P"PIP"I"Vo 01 People All Safe All 5atC 9 — 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 — NoPle All qafIn 12 Injury Causes ToolsPositions Equipment "All Safe M — Right for the Job — Striking Against or — Used Correctly — Being Struck by Objects — In Safe Condition — Caught in, On, or — Between Objects W4 — Failing rocedurea Ail Saft- — 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 EXHIBIT 4 Page 19 of 33 L T $ tdP+vibn Gttt�tc; Are They Are They - — Right for the Job — Right for the Job _. In Safe Condition — fn Safe ConditionWolrk.Area Ail safe, — All Sife'S Are They Unsafe acts observe Are They Un1.1 tsafe acts obsery d o1 — Clean — Clean — rV 9 _ Orderly 7f ear — Orderly LG Right for the Jo — Right for the Job In Safe Condition — In Safe Condition mac' D -i zs•tfk f� �tr.i� S Ce" �0, SQ f' Is It L. :'f l n r` N C Is It _ Clean-- — Clean — Orderly Name — Orderly NameL _ r in Safe Condition Date — � , � — in Safe Condition !1 -s} % d Date r� _ • - - Orderliness 4 9 - Site. Site �.• Standards Area Standards ' i — Available — Adequate — Available - / — Shift _. Adequate j fir_ Shift — err © Time spent on observation %,621" Time spent on observation ` Q # of People Contacted ❑ # of People Oontacfed h°�'r"' i �";nxktrei corm # of People Observed ❑ ngrilwww.traininacuirontcom" Ndealslop-&ecklst # of People Observed x,4.1 Conte tin Additional STOP' Observation Checktisr om mrace"tacctt information or to Dupont. Please vis" na du o place ar. cider on-line p right ®2011 6upont. Ali rights reserved. STOP' Additional STOPT Observation Chaeldisis can be obtained byp contacting Istered irademarhs of DuPont. Dupont. Please visit wwfy im a co for contact intarmation or to antl+.he STOPa'logo are reg piece an leas visite ogyright 2011 DuPont. All rights reserved. STOP" and the STOP -Togo are registered trademarks of UuPont. EXHIBIT 4 Page 20 of 33 m 0 Oit a cc U. W t1 W Cn C' 0 O O C O � O C a- Z� a = -s o ... Q Z V m en L n�i m m •O EXHIBIT 4 Page 20 of 33 EXHIBIT 4 Page 21 of 33 [IR eta pt�sn�raiit �he�lt!(� rM33TOV'e.r,x06 -. ELIMINATE UNSAFE CONDITIONS... PREVENT INJURIES —limp.! Unsafe Safe .. Safe acts observed Are They — Right for the Job - - In Safe Condition — Are They k- Unsafe acts — Clean — t4, _-- Orderly — kA Ifs — Right for the Job — t✓al Ln/ v In Safe Condition Time spent on Observation __ _ Is It — Clean _ — Orderly - - In Safe Condition — s. - 0 r k- PREVENT INJURIES Site Standards Unsafe Safe. .--- Available — --_ Adequatai — Area fe acts observed Shift ❑'r v Olt h -r Time spent on Observation 0 # of People Contacted Q rn:pawww.traimng.aupont COW videaek� ohed list # of People Observed Additionai STOPS Observation Checklists Dupont. Please visit www. Not can be obtained t contacting coin or contact information or to place en oftler on-line. Copyright 02011 DUPenG All rights reserved. STOPS and the STOP" logo are registered trademarks of DuPont. The `i 1�°.C1bs rt tato t leOust. •w. STOP'.uen pB.enwrnnev:tN ELIMINATE UNSAFE CONDITIONS— PREVENT INJURIES Conditions Unsafe Safe. fe acts observed 3 S r �tti :r Iii Are They — Right for the Job Olt h -r — in Safe Condition 'C J' • `�'� I� l�tffWd� Are They Unsafe acts o rved 4c { Clean — Orderly - - Right for the Job - - In Safe Condition — nVirortment All $a e Is It -- - Clean �N�77ame — Orderly — In Safe Condition — i?at n, Standards Site Area — Available - -Adequate — Shy Time spent an observation # of people Contacted r;iwrxw.trainirg.dupont.coml videa§tov, eckmst # ofpeople Observed Additior',al STOP' Observation Cheo dNL DUPOnI. Pie85¢ visit www.train can be obtained by contacting G for cnntact tnfonnetian or tc a DuPont. All rights +eserved. STOP' place en order an -lino. Copyright ®20 end the STOW lopro are reg<stered trademarks of DuPont. ui m w n a U O .. ku? Q w —O y. r —O The `i 1�°.C1bs rt tato t leOust. •w. STOP'.uen pB.enwrnnev:tN ELIMINATE UNSAFE CONDITIONS— PREVENT INJURIES Conditions Unsafe Safe. fe acts observed 3 S r �tti :r Iii Are They — Right for the Job Olt h -r — in Safe Condition 'C J' • `�'� I� l�tffWd� Are They Unsafe acts o rved 4c { Clean — Orderly - - Right for the Job - - In Safe Condition — nVirortment All $a e Is It -- - Clean �N�77ame — Orderly — In Safe Condition — i?at n, Standards Site Area — Available - -Adequate — Shy Time spent an observation # of people Contacted r;iwrxw.trainirg.dupont.coml videa§tov, eckmst # ofpeople Observed Additior',al STOP' Observation Cheo dNL DUPOnI. Pie85¢ visit www.train can be obtained by contacting G for cnntact tnfonnetian or tc a DuPont. All rights +eserved. STOP' place en order an -lino. Copyright ®20 end the STOW lopro are reg<stered trademarks of DuPont. 0f v� Ow7o o wh EXHIBIT 4 Page 22 of 33 k ❑ ❑ i U o c`oO y OZ v Q) 'C 4 0f v� Ow7o o wh EXHIBIT 4 Page 22 of 33 THE STOP SAFETY OBSERVATION CYCLE DECIDE T REPORT \TOP\ %' Top Y / OBSERVE "cif, . 4�YtifjD? Cj 4*t Actions Unsafe Safe Unsafe Safe tective - 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 — Repetitive Motions - Legs and Feet — •.-rools Injury Causes and — Right for the Job - - Striking Against or Struck — Used Correctly — Being by Objects _ in Safe Condition — — Caught In, On, or — - Understood Between Objects :Procedurer�- Safe' 11110-1� _.- Failing -- All _- Contacting Temperature Extremes — Available - - Contacting — --- Adequate — Electric Current — Known - - Inhaling, Absorbing, — — Understood or Swallowing a — Followed — Hazardous Substance — Repetitive Motions - - Awkward Positions/ —7-9tandards Static Posturesd STOPOO-OCL-ENG-0003 THE STOP SAFETY OBSERVATION CYCLE DECIDE REPORT ACT oesERVE Actions Unsafe Safe Unsafe — 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 _ — Contacting — Legs and Feet Electric Current 'Positions' Of P•. Injury Causes Tools and' — Right for the Job - - Striking Against or — — Used Correctly — Being Struck by Objects — In Safe Condition taught In, On, or — Between Objects Failing Yr.oq — Contacting Temperature Extremes - Available — Contacting - Adequate — Electric Current — Known - Inhaling. Absorbing, — — Understood or Swallowing a — Followed Hazardous Substance — Repetitive Motions - - Awkward Positions/ — Statr/ �" Postures X. Standards — Known - - Understood _- Followed STOPOO-OCL-ENG-D003 EXHIBIT 4 Page 23 of 33 �ftet5'�1�° 'ta#Co�i:rviYe�tlilis# ; +�e STOnawv.rr o..e. ELIMINATE UNSAFE CONDITIONS,.. PREVENT INJURIES Conditions 13nsafe Safe Are They afe acts observed a[_ — Right for the Job Area — In Safe Condition —� Structures and Sh!10 Wor� Area Are They Unsafe acts observed — Clean _ htl?",M$g — Orderly - La�nin5 &punt.c3w vldaalstaptPeckist -. Right for the Job Addticnei STOP- Observation Checkliats Dupont. Please Vlsii Vain°no In Safe Condition Environment, Aws�aw µyw h r ror contact infurmatioo or to place an order or.•Iine. copyright 6 2M, DuPont.. All rights reeerved. 8TOP' and the SToaa logo are registered trademarks or Dupont. Is It Clean _ — Orderly — — In Safe Condition Ai i l�?�-� ,',Orderliness A It SateP Da Standards Site �� H' Areai�r / --'" — Available — — Adequate—' Shift Time spent on observation C�dP�i»vn+.irainNg.dupanteom' v6ieorstap<hackl;st # of People Contacted 0 # of People Observed ❑ Additional STOP" Observaiicn Checklists DuPont. Pewee vist Lan order on-line. Copyright92g1I and the STOP ;ogo are mgisiered trademarks can be ottained by contacting for contact information or to DuPont AO rights reserved. STOP"' or DuPont. t1TE UNSAFE CONDITIONS... JT INJURIES \rt E'1Tt]!'' Conditions Unsafe acts observed Are They — Right for the Job - - In Safe Condition _ Are They Unsafe acts observed — Clean _ — Orderly- - Right for the Job — r — in Safe Condition !s !t — Clean _ — Orderly _ — In Safe Condition — EXHIBIT 4 Page 24 of 33 site Standards — Adequate — Available7,�Time Area Sh!10 spent on observation htl?",M$g # of People contacted La�nin5 &punt.c3w vldaalstaptPeckist # of People Observed Q Addticnei STOP- Observation Checkliats Dupont. Please Vlsii Vain°no can be obtained byy contactlna µyw h r ror contact infurmatioo or to place an order or.•Iine. copyright 6 2M, DuPont.. All rights reeerved. 8TOP' and the SToaa logo are registered trademarks or Dupont. EXHIBIT 4 Page 24 of 33 THE STOP SAFETY OBSERVATION CYCLE DECIIDEE" REPORT j"CT OBSERVE Actions Unsafe Safe Unsafe Safe — Adjusting Personal — Head -to -Toe Check Protective Equipment — Head f Changing Position — __. Eyes and Face rearranging Job — Ears — Stopping Job — Respiratory System - - Attaching Grounds — Arms and Hands — — Performing Lockouts ,n — ._ Trunk — Contacting Temperature Extremes — Legs and Feet — Vry Causes — Right for the Job Striking Against or — Being Struck by — Used Correctly Objects — In Safe Condition f 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 — STOPOO-OCL-ENO-0003 THE STOP' SAFETY OBSERVATION CYCLE DECIDE REPORT \TOP ��. m AC/ OBSERVE j1@' P�j�i�3&8t1I�tfo ldh>?CiS �S Actions Unsafe Safe Unsafe Safe Protective All.Safe M: — Adjusting Personal — He -to-Toe Check Protective Equipment -9 Head - - Changing Position — Eyes and Face — Rearranging Job — — Ears - - Stopping Job — — Respiratory System _- - Attaching Grounds .--_ Arms and Hands -- Performing Lockouts — — Trunk - - Legs and Feet — .P,siitfons Tools' And Injury Causes — Right for the Job — Striking Against or — Used Correctly — BE�Objects track by Objects — In Safe Condition e Caught In, On, or Between Objects 7Adequate Falling�.tactingTemperature ExtremesContacting — — Electric Current Inhaling, Absorbing, d — or Swallowing a — Followed — Hazardous Substance — Repetitive Motions - - Awkward Positions/ 'ioclerlilness, All Saf4; M, Static Postures Standards — Known — Understood — Followed STOPOO-OCL-ENG-0003 EXHIBIT 4 Page 25 of 33 WMINATE UNSAFE CONDITIONS,,, stow .F co, a.,.,a tie ;REVENT INJURIES �J� ��+`Rfir 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 It Clean — Orderly — in Safe Condition Standards — Available — Adequate %"'4 `tt .li+rww.traiaing dupontcom' '+idso/stopthackiist Additionar STOP* Obsannhnn ri Unsafe acts observed — Sko�� 0.cKe Ile- Name l Naam_e w-ls�- _ Date Site _ Area Y 1ji Time spent nn observation #offecpeConracred i1 # of People Observed Q wrists can be obtained by contacting - MoiLn for contact information or to l "l, All rights reserved STOP•' ' ademarks of DuPoni. Are They _ Right for the Job - ---- In Safe Condition Are They Unsafe acts observed -.- Clean - not - Orderly _ wrw�nn�.n-'�`f-�J�•5 - Right for the Job - In Safe Condition s Is It - Clean - Orderly _ Name _ In Safe Condition q-2 f S Crate • ` Site Standards Area — Available _ — Adequate Shift %WTTime spent on observation #' of People Contacted IJ hf4D;lwJ,^w.lre'rirg dugoM wM v�eeclstop<hecJ-a� # of People Observed Q Addiiionai STOP- Observation Checsrisis DuPont. Please visit !�7YN4ktglLf'1A51frRgat place an order on -tine. Copyright (0 2011 and the STOP'lcgo are registered trademarks can t;e obtainedby rantacting mit for contact information or to DuPont Ail rights reserved. STOP6 r of DuPont. EXHIBIT 4 Page 26 of 33 - INTEGRATED WELL SERVICE, INC Near Miss Report Name: Date: 4 -13F1$- Location of Incident: o Rig # ajg ita.. Date of Incident: p- / Time: amlpm Describe in Full what you were doing before, during and after the incident: •4iw Ltirr � li Describe in detail what actions or steps will be taken to prevent incident from reoccurring: Name: Name•• Name of Supervisor: EXHIBIT 4 Page 27 of 33 INTEGRATED v WELL SERVICES Near Miss Report Name, -Date: Location of Incident: ''- Rig # S � Date of Incident: - 14! Time: am/o< Describe in Full what you were doing before, during and after the incident: 547 �Ur " hd &14., AZ , Z,11Yr AWDescribe in detail what actions or steps will be taken to prevent incident from reoccurri , Name: Name: Name of Supervisor: EXHIBIT 4 Page 28 of 33 INTEGRATED WELL SERVICE, INC Near Miss Report Name: _Date: Location of Incident: _ i� - 'P016 Rig Date of Incident: $ - - 15 Time: ''1 W S 'h NI 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: t 1a Name: Name: Name of Supervisor: EXHIBIT 4 Page 29 of 33 INTEGRATED WELL SERVICE, INC Near Miss Report Name: Date: Location of Incident: )t -AL 14 Rig # s \ *:j ) Date of Incident: W i' e-`- Time: am/pm Describe in Full what you were doing before, during and after the incident: �`'k�..}.er3 w�ic ra�oi7'-s �[ �K 1� ��1-r%f tr'YIP✓ ftp - Avr- &4^ pt �_4 _P4 1� ,Cr k I —f 5,t-... J- x:. el �.,r � .,, y k.. �r fJ w C /t Describe in detail what actions or steps will be taken to prevent incident from reoccurring: �%C t (4 n } /j F.e )-c ie, Y'4v% w ✓) )-p e,.sj oi» re hr; Name: _ Name: Name of Supervisor: EXHIBIT 4 Page 30 of 33 INTEGRATED WELL SERVICE, INC Near Miss Report Name: Date:- ilo - tS Location of Incident: Rig Date of incident: 11 I S Time: am/pm Describe in Full what you were doing before, during and after the incident: til �_` p( -x A -k ("' AC Describe in detail what actions or steps will be taken to prevent incident from reoccurring: a, C1�e /C'S Cr" ��Clwj 1[CCe-7k' >c L,.h<^ l)Lf�- Name: Name: Name of Supervisor: EXHIBIT 4 Page 31 of 33 INTEGRATED WELL SERVICE, INC Near Miss Report Name•=OEMDate: e- r Location of Incident: -3Y"--i �{ Rig # 5 -V Date of incident: r- ja - l � Time: am/pm Describ in Full what you were doingbefore, during and after the incident: I.-/, Ire I t s i " � w r, 2 /� F_ Y h©c n -'I n c, ;eC"l C dem e, 0 01 S rhe 0 Oror. !1I» 1,d- •tib- �ue�c j., Ir e. 'f k�jee -,4 q, evt a of "t '�-e! ! r / d- of ".i Aa; n t. ✓( Describe in detail what actions or steps will be taken to prevent incident from reoccurring: �i -t YC P-ZJ ✓� O ,;i �-fp,�S � l «-'�'S H+ n i �1 D. 'ei �'f ry O .a *� G' o hN2 KIt i c�.�. f p/1 Name: Name: Name of Supervisor: EXHIBIT 4 Page 32 of 33 INTEGRATED WELL SERVICE, INC Near Miss Report Name: Date: f� Location of Incident U Rig #� Date of Incident: Time: ¢-5 J00am/ Describe in Full what you were doing' before,/during and after the lw./��S% �.L.�bCti7!! !!✓7 �/.,NL Qi �f' �w i r� %r E'�� Describe in detail what actions or steps will be taken to prevent incident from Name: Name.- Name ame:Name of Supervisor: EXHIBIT 4 Page 33 of 33 THE' STATE AI,ASKA 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: as k a C' "L a .1S 333 1r1Cst 3crvenlh AvC:rrcc', Almka 99.50 3,5/2 M -in: 907 27. 9.14;33 Fnx: Ki -216-7.542 www.up<;peC_C,ic,sk(r,-.,i ,/ 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 er%ster 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 25-280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well Q Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate E] Pull Tubing n 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 21 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: 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 n 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 4,108 9,050 4,106 NIA N/A Casing Length Size MD TVD Burst Collapse Conductor 112' 20" 112' 112' 1,490psi 470psi Surface 3,085' 9-5/8" 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' 4-1/2" 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: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 2-718" 6.5# 1 L-80 / EUE 8rd 4,312 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): ZXP Liner Top Packer and N/A 5,102'(MD)/ 4,026'(TVD) and N/A 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ( ] Stratigraphic ❑ Development D Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 3/2 512 01 5 Oil Q Gas ❑ WINJ [ GINJ [-1 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 Kanyer Title Operations Engineer Signature 1� Phone 777-8377 Date 312012015 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test IV -/' Mechanical Integrity Test ❑ Location Clearance U Other 3 (jC (,a lee �y� 16f", 6 tt� f ryt` � t C 4.SrJ+� "i"�' .:✓ � J`r-�-,,, fit,. Spacing Exception Required? Yes ❑ No Subsequent Form Required: APPROVED BY COMMISSION Date: 3 ' S Approved by: COMMISSIONER THE Submit Form and (Revised IP" L JIL STT E PP A Form 10-403 10l2g12) A plica Id o months from the date of approval. Attachments in Duplicate EXHIBIT 5 Page 2 of 13 Well Prognosis Well: MPI -15 Date: 3/20/201S Well Name: MPI -15 API Number: 50-029-23106-00-00 Current Status: 51 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 Obiective: 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" ROPE and test to 250psi low/3,OOOpsi 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 Ifilr'rlp AlaAa..U, 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 BOPE 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 ff llilrnrp Aha>ka.11C RKB Elev = 25.7 Milne Point Unit Well: MPI -15 SCHEMATIC Last Completed: 5/7/2014 PTD: 202-152 CASING DETAIL Size Type Wt/ Grade/ Conn ID Tap 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" 4-1/2" Sltd Liner OA Sltd Liner 08 12.6 / L-80 / IBT 12.6 J L-80 / IBT 3.958 3.958 4,869' 5,200' 8,922' 9,041' TD = 9,050' (MD) / TD = 4,105(ND) PBTD= 9,050' (LVID) / P13TD = 4,1W(TVD) TUBING DETAIL 8" 1 Tubing 1 6.5N / L-80 / ELIE 8rd 2..441 Surface 1 4,312' JEWELRY DETAIL Depth Item 139' GLM - Camco 2-7/8'x 1" Sidepocket KBMM 4,074' GLM - Carrico 2-7/8'x 1" Sidepocket KBMM 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 SB/SB PFSA & GS83DBLT SB/SB PFSA 4,300' Motor -84hp, 2,210 Volt, 23 Amp, Model MSP1 / 84 4,308' Pumpmate w/ 6 fin Centralizer - Bottorn ril 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 @ 4,1217 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" -SM FMC Wellhead 11" SM Gen w/ 2-7/8" EUE T&B Tubing Hanger with CIW "H" BPV Profile GENERAL WELL INFO API: 5"29-23106-00-00 __ Drilled and Cased Multi-Lat by Doyon 141 - 9/1/2002 ESP RWO by Nabors 4ES - 8/21/2008 ESP Changeout by Doyon 16-5/7/2014 Created By: TDF 3/10/2015 EXHIBIT 5 Page 5 of 13 RKB Elev = 25.7 Milne Point Unit Well: MPI -15 PROPOSED 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/Stc. 8.835 Surface 3,085' 7" Production 26 / L-80 / BTC -Mad 6.276 Surface 4,849' 4-1/2" Sltd Liner OA 12.6/ L-80 / IST 3.958 4,869' 8,922' 4-1/2" Slid Liner OB 12.6 / L-80 / IST 3.958 5,200' 9,041' TD=9,050'(ND)/TD=4,IW M) PBTD=9,050' (ND) / PBTD= 4,106'MM) TUBING DETAIL 3 TubBmg 6.521/1-80/EUE8rd 1 2.441 1 swface 1 ±4,200' JEWELRY DETAIL Depth Item +139' GLM °3,974' GLM ^4,146' XN Nipple x4,158' Pump 24,165' Gas Separator 14,166' Tandem Seal Section 24,180' Motor ±4,194' PumpmatewJ6fin Centralizer -Bottorn@t4,200' 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 Uner 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 4,504 M0. 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" Cm[ wJ 919 sx 'las "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" -SM FMC 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 Multi-Lat by Doyon 141 - 9/1/2_002 ESP RWO by Nabors 4ES - 8/21/2008 ESPChangeout by Doyon 16-5/7/2014 Created By: TDF 3/10/2015 EXHIBIT 5 Page 6 of 13 11" BOP Stack es 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 Plug Perforations I Perforate 0 Other Z ESP Change -out Performed: Alter Casing ❑ Pull Tubing Stimulate - Frac ❑ Waiver U Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Stimulate - Other [] Re-enter Suspended Well ❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development 0 Stratigraphic ❑ Exploratory ❑ Service ❑ 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 1-151-1 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 POOL 11. Present Well Condition Summary: Total Depth measured 9,050 feet Plugs measured N/A feet true vertical 4,106 feet Junk measured N/A feet Effective Depth measured 9,050 feet Packer measured 5,102 feet true vertical 4,106 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' NIA N/A Slotted Liner'OB' 3,841' 4-112" 9,041' 4,106' NIA NIA Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) 2-7/8" 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 NIA 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: NIA 13. Representative Daily Average Production or Injection Data Oft -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 Exploratorl [ ] Development Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16, Well Status after work: Oil 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 NIA if C.O. Exempt: 315-158 Contact Chris Kanyer Email ckanveraC)hiicorR.Com Printed Name Chris Kanyer Title Operations Engineer Signature " Phone 907-777-8377 Date 5/5/2015 Form 10-404 Revised 1012012 Submit Original Only EXHIBIT 5 Page 9 of 13 RKB Elev= 25.7 SCHEMATIC 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 4,849' 4-1/2" Sltd Liner OA 12.6 / L-80 / IBT 3.958 4,869' 8,922' 4-1/2" ltd Liner 08 12.6 / 1-80 / 187 3.958 5,200 9,041' TD=9,050' (IVU) /TD=4,10WMM) PBTD= 9,050' (MD) / PBTD=4,106 (TVD) TUBING DETAIL B" Tubing 6.511 / L-80 / EUE 8rd 1 2..441 1 Surface 1 4,198' JEWELRY DETAIL Depth Item 141 GLM 3,966' GLM 4,140' XN Nipple 4,151' Discharge Head 4,151' U erTandemPump 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/6fin Centralizer - Bottom @4,198' 4,840' Baker Hook Wall Hanger inside 7" Window (21') 4,861' Baker Hook Wall Nan er 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 60de + 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: 50-029-23106-00-00 Drilled and Cased Multi-Lat by Doyon 141 - 9/1/2002 ESP RWOb Nabors 4ES-8/21/2008 ESP Change -out by Doyon 16-5/7/2014 ESP Change -out by Nordic 3-3/29/2015 Created BY: TDF 5/4,12015 EXHIBIT 5 Page 10 of 13 Hilcorp Alaska, LLC ►i,�, ,,, ,�,,.k,,.�.�.,: Weekly Operations Summary Well Name 1API 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: 3/18/15 - 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 10PM, 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 bbis 140` 8.5ppg seawater down tubing, no returns. Swap over down csg after 23 bbis quick pressure increase and break aver. Intermittent gas/oil returns on tbg. Continue and pump to liner top volume+total pumped 244 bbl swap over and pump tubing volume 24 bbis. 119 bbls recovered oil water mix. Monitor well is on vacuum both sides install BPV. Blow down Break all lines-ND Tree, prepare to NU BOPS. EXHIBIT 5 Page 11 of 13 EXHIBIT 5 Page 12 of 13 UHileorp Alaska, LLC „;, Weekly Operations Summary Well Name API Number Well Permit Number Start Date JEnd Date MPI -15 50-029-23106-00-00 202-152 3/24/2015 3/29/2015 Dail Operations: 3/25/15 - Wednesday PJSM. ND tree, inspect hanger and graphite grease surfaces, grooves and recesses. NU BOPS, install TWC. Fill stack, purge lines, shell test BOPE, 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 sea( Bell nipple. Re -install and hydra 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 bbls 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 5,'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 its 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 SCFM @ 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 bbls, 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. 51 well to stabilize and observe pressure SICP 170 psi 51TP 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 bbls down tbg and 164 bbls down down csg. Intermittent returns after 112 bbls. 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 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, Rl 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 -Tuesday No operations to report. EXHIBIT 5 Page 13 of 13 THE STATE; WAS GOVERNOR BILL WA!,KFR 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 J -09A Sundry Number: 315-162 Dear Mr. Kanyer: Aiagka Oil and Gas Conservation commissior wosi Seve?n#h ,Averw- A.^icho';zgc ..,. Ac.kc. .35/2 ctx:9 %.275.754;' wu�w.acur�-al,rkct.;�_,v 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, av� j�V ' /F Cathy P. Wberster Chair DATED this day of March, 2015 Encl. EXHIBIT 6 Page 1 of 15 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 70 oar: 25280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ 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 DNI Number. Hiicorp 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 Will planned perforations require a spacing exception? Yes Ll No C MI LNE PT UNIT SS J -09A 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0025517 I Milne Point Field I 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): 8,235 4,046 8,235 1 4,046 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 112' 13-3/8" 112' 112' 1,730psi 740psi Surface 2,936' 9-518" 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 2,098' 4-112 8,235 4,060' N/A N/A Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 2-718" 6.5#/ L-80/ EUE 8rd 5,083' Packers and SSSV Type: Packers and SSSV MD (it) and TVD (ft): Baker ZXP Liner Top Packer and WA 5,199'(MD)l 3,749'(TVD) and N/A 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic (� Development d Service L] 14. Estimated Date for 15. Well Status after proposed work. Commencing Operations: 4/1/2015 Oil (�' Gas Li 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 Kanyer Email Ck�ilcorp.cgm Printed Name Chris Kanyer Title Operations Engineer Signature1�z Phone 777-8377 Date 3/2312015 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: p� Plug Integrity [] BOP Test [f,' Mechanical Integrity Test �] Location ClearanceEl Other } 6, la S W Spacing Exception Required? Yes ❑ No Subsequent Form Required: U n ! APPROVED BY 2 y � COMMISSIONER THE COMMISSION Date: �7 �!�-'✓/� Approved by: ✓'_�. t 1 7 ) T Submit Form and Form 20-403 (Revised 1012012) ru"v d a li tLC••f_ 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: 1 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 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) 777-8345 (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: 4 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) c The Milne Point 1-09A 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 was performed ✓` to 2,p00psi on 4121201-3. 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 Objective: 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 Al k.. LL 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. 5. 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 +/-8,209. 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 llilcorn Alaska. LLC KB 0ev.: 29.6'/ GL Elev.: 17.0' TD = 8,235' (MD) / TD = 4,064 (TVD) PBTD= 8,235' (MD) / PBTD= 4,06411VD) SCHEMATIC CASING DETAIL Milne Point Unit Well: MPU 1-09A Last Completed: 4/13/13 PTD: 199-114 Size Type Wt/ Grade/ Conn ID Top Btm 13-3/8" Conductor 54.5 / H40 / N/A 12.615 0 112' 9-518" Surface 40/ L-80 / Btrc. 8.835 0 2,936' 7" Intermediate 26 J L-80 / NSCC 6.276 0 5,334' 4-i/2" Liner 12.6 / L-80 / IBT 3.958 5,199" 6,137' 4-i/2'' Slotted Liner 6.2/L-80/SIT 3.958 6,137' 8,235' TUBING DETAIL Tubing I &5/L-80/1 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 @ 2,000psi 3 4,985' 2-7/8" XN Nipple (2.25' ID) 4 5,02T WellUft Discharge Gauge Unit 5 5,030' ZCentrilift ESP: PCP 200D 2600 Pump 3.75"/ 22.42' 6 5,053' Flex Shaft Assembly EUE 8rd Box 7 5,062' Single Seal Section 8 5,068' Gear Reduction Unit GRU 538811.57:1 9 5,070' Motor MSP1/ 54 HP, 890 Volt, 39 Amp 30 5,079' WellLift MGU w 6 fin Centralizer — Bottom @ 5,083' 11 5,199' Baker ZXP Liner Top Packer w/ 6' Tie Back 5.25" 10) 12 51215' 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 eushin 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 J 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 6-118" Hole TREE & WELLHEAD Tree Cameron 2-9/16" SM W KM 11"x 11"5M, W KM w/ 11'x 2-7/8" tubing hanger/ NSCT Wellhead threads top and bottom and 3" CIW H PBV Profile GENERAL WELL INFO API: 50-029-22495-01-00 Drilled and Cased by Nabors 22E -1/14/1995 Completion by Nabors 4ES-2/15/1995 Schrader Bluff Recompletion by Nabors 4ES — 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 Revised By: TDF 3123/2014 EXHIBIT 6 Page 5of15 KB Elev.: 29.6/ GL Elev.:17.9 TD=8,235' (TVD) / TD=4,064'(WD) PMTMD=8,235' (MVD) / POM =4,064'(TVD) CASING DETAIL Milne Point Unit Well: MPU J -09A Last Completed: 4/13/13 PTD: 199-114 Size Type Wt/ Grade/ Conn ID Top Stm 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/IST 3.958 5,199" 6,137 4-1/2" Slotted Liner 6.2 / L-80/ SILT 3.958 6,137 8,235' TUBING DETAIL 2-7/8" Tubing EUE 8rd 1 2.4411 6 1 n5,083' JEWELRY DETAIL No Depth Item 1 1133' 2-7/8" x 1" Side Pocket KBMM w/ DPSOV 2 #4,846' 2-7/8" x 1" Side Pocket K8MM Shear Valve set @ 2,000psi 3 ±4,985' 2.7/8" XN Nipple (2.25' ID) 4 ±5,027' WellLift Discharge Gauge Unit 5 ±5,030' 2Centrilift ESP: PCP 200D 2600 Pump 3.75"/ 22.42' 6 15,053' Flex Shaft Assembly EUE 8rd Box 7 ±5,062' Single Seal Section 8 ±5,068' Gear Reduction Unit GRU 538811.57:1 9 ±5,070' Motor MSPS/ 54 HP, 890 Volt, 39 Amp 10 ±5,079' WellLift MGU w 6 tin Centralizer - Bottom @ ±5,083' 11 5,199' Baker ZXP Liner Top Packer w/ 6' tie Back (5.25" ID) 12 1 5,215' Baker 5" x 7" HMC Liner Hanger 14.375" 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 _WEL_L INCLINATION DETAIL KOP @ 600' Max Hole Angle = S9 deg. @ 3,300 - 3,500' MaxHole Angle = Horizontal OPEN HOLE / CEMENT DETAIL 133/8"" 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 Gass "G" in 6-1/8" Hole TREE & WELLHEAD Tree Cameron 2-9/16" SM Wellhead WKM 11"x 11" 5M, WKM w/ 11'x 2-7/8" 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 4E5 -4/19/1997 Schrader BluffSand 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 Revised By: TDF 3/23/2014 EXHIBIT 6 Page 6 of 15 11" BOP Stack EXHIBIT 6 Page 7 of 15 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon ❑ Plug PerforationsEl Fracture Stimulate ❑ Pull Tubing M 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): NIA Milne Point Field / Schrader Bluff Oil 11. Present Well Condition Summary: Total Depth measured 8,235 feet Plugs measured NIA 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' 4-1/2" 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): NIA 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 83 240 232 14. Attachments (required per 20 aac 25.070, 25.071, &25.283) 15. Well Class after work: Daily Report of Well Operations ❑✓ Exploratory❑ Development❑ Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Q Gas ❑ 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: 315-162 Contact Chris Kanyer Email ckanyer(ji3hilcore.com Printed Name Chris Kanyer Title Operations Engineer Signature Phone 777-8377 Dale 6/3/2015 IF Form 10-404 Revised 5/2015 Submit Original Only EXHIBIT 6 Page 8 of 15 Ailenrp Alauku, 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) SCHEMATIC CASING DETAIL Milne Point Unit Well: MPU J -09A Last Completed: 4/29/2015 PTD: 199-114 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' 6,137' 4-1/2" Slotted Liner 6.2 / L-80 / SILT 3.958 6,137' 8,235' TUBING DETAIL Tubing 1 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' WeliLift 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 5,051' Motor MSP1/ 54 HP, 890 Volt, 39 Amp 10 5,059' Welilift 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 16 8,235' 1 4.5" Baker Drillable Guide Shoe WELL INCLINATION DETAIL KOP @ 600' Max Hole Angle = 59 deg. @ 3,30_0-3,500' 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 Cameron 2-9/16" SM Wellhead WKM 11" x 11" SM, WKM w/ 11" x 2-7/8" 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 35-6/16/2008 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 EXHIBIT 6 Page 10 of 15 Hilcorp Alaska, LLC I,i�cnpAlaylcn,LLC Weekly Operations Summary Well Name JAPI Number Well Permit Number IStart Date jEnd Date MP J-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. 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 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, O psi. Pump 180 bbl 8.6# saltwater down annulus, partial returns after 60 bbls. Pump 40 bbis 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 4/29/15 Wednesday 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 P1 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. 4/3O%15 - Th�,irsday 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 its 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 11 of 15 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon [_] Plug PerforationsEl Fracture Stimulate ❑ Pull Tubing 121 Operations shutdown ❑ Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ erforale New Pool ❑ Repair Well ❑✓ 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 Q Exploratory ❑ Stratigraphie ❑ Service ❑ 199-114 3. Address: 6. API Number: 3800 Centerpoint Drive, Suite 1400, Anchorage AK, 99503 50-029-22495-01-00 7. Properly 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): NIA Milne Point Field I Schrader Bluff Oil 11. Present Well Condition Summary. Total Depth measured 8,235 feet Plugs measured NIA feet true vertical 4,046 feet Junk measured 7,075 (Fill) feel Effective Depth measured 7,075 feel 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' 4-1/2" 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 NIA 12. Stimulation or cement squeeze summary: NIA Intervals treated (measured): NIA 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 25.283) 15. Well Class after work: Daily Report of Well Operations P1 Exploratory ❑ Development 0 Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Gas F 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: 315-162 Contact Chris Kanyer Email ckanyerahilcore.com Printed Name Chris Kanyer Title Operations Engineer Signature Phone 77T8377 Date 6/312015 Form 10-404 Revised 5/2015 Submit Original Only EXHIBIT 6 Page 12 of 15 corn 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'(WD) SCHEMATIC CASING DETAIL Milne Point Unit Well: MPU 1-09A Last Completed: 4/29/2015 PTD: 199-114 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 S,199" 6,137' 4-1/2" Slotted Liner 6.2/L-80/SLT 3.958 6,137' 8,235' TUBING DETAIL 2-7/8" 1 Tubing 1 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' WeIILift 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 538811.57:1 9 5,051' _ Motor MSPI/ 54 HP, 890 Volt, 39 Amp 10 5,059' WeIILift 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 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 Cameron 2-9/16" SM Wellhead WKM 11" x 11" SM, W KM w/ 11" x 2-7/8'" 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 13 of 15 EXHIBIT 6 Page 14 of 15 Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number lWell Permit Number Start Date jEnd Date MPJ-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 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,OOOpsi). Tested BOPE per sundry, annular 250psi low/ 2,500psi high, rams 250psi low/ 3,OOOpsi 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 TIN 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 bbi losses and crude in partial returns. POOH w/ 2-7/8" tbg racking back in derrick. EXHIBIT 6 Page 14 of 15 x}/29/15 Wednesday 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. 4/317%1 Th�lrsday Continue RIH w/ ESP/cap/HT. P 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 its 2-7/8" L-80 6.5# tbg, pup, GLM @ 139', 150 jts tbg, pup GLM @ 4,853', 4jts 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 °fALASIA GOVERNOR BILI. WALKER Stan Porhola Operations Engineer Hilcorp Alaska, LL.0 3800 Centeipoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Pool, MPU SB J -01A Sundry Number: 315-459 Dear Mr. Porhola: Alaska 0J] and Gas cons('n-vafion Commission 333 West Seventh Avenue Anchorage, Alciska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alciska.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 � day of July, 2015 Encl. EXHIBIT 7 Page 1 of 12 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 2n AAC 2ti 2Rn Ilal 1 9 Mh 1. Type of Request: Abandon ❑ Plug for Redril' ❑ Perforate New Pool ❑ Repair Well MChange Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing 0 Time Extension ❑ Operations Shutdown ❑ Re-enter Susp. Wei' ❑ Stimulate ❑ Alter Casing ❑ Other: ESP Change -out [I 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp 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? G.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 (it): 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' 13-5/8" 105' 105, 2,730psi 1,130psi Surface 2,409' 9-518" 2,409' 2,364' 3,520psi 2,020psi Production 3,640' 7" 3,640' 3,502' 7,240psi 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' 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-80 / EUE 8rd 3,469' Packers and SSSV Type: Parkers and SSSV MD (ft) and TVD (ft): N/A and N/A NIA and N/A 12. Attachments: Description Summary of Proposal ❑✓ 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch J❑ Exploratory ❑ Stratigraphic ❑ Development ❑ Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 8/11/2015 Oil ❑ Gas ❑ WDSPL ❑ Suspended ❑ WIN.) ❑ GINJ E]WAG ElAbandoned F]Commission 16. Verbal Approval: Date: Representative: GSTOR ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Porhola Email ckanyer@hilcor ,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-�f5� Plug Integrity ❑ BOP Test [ Mechanical Integrity Test ❑ Location Clearance ❑ Other: SpacingSpacing Exception Required? Yes ❑ No 1� Subsequent Form Required: APPROVED BY �-� COMMISSIONER THE COMMISSION Date: Approved b Submit Form and OURPLIZATE.rith.Form 10-403 (Revised 1012012) from the date of approval. Attachments {n Duplicate EXHIBIT 7 Page 2 of 12 IMCorp Ainsku, LU Well Prognosis Well: MPU 1-01A 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. Objective: 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 HilcorpASR #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 lfilcoro Alaska. LU Well Prognosis Well: MPU 1-01A 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 ROPE. 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 RKB Elev = 35' SCHEMATIC Milne Point Unit Well: MPJ-01AL1 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 / BTC 6.276 Surface 3,640- 4-1/2" SltdLiner A 12.6/L-80/HIT 3.958 3,512' 7,135' 2-3/8" 1 Sltd Liner B I N/A / L-80 / N/A N/A 1 4,567 7,709' TD= 7,950' (MD) /TD = 4,165f(TVD) PBTD= 7,950' (MD) / PBTD= 4,165(TVD) TUBING DETAIL B" I Tubing 1 9.3 / L-80 / EUE 8rd 1 2.867 1 Surface 3,469' Capstring Stainless Steel N/A Surface 3,469' JEWELRY DETAIL D Depth Item 171' GLM 3,253' GLM 3,394' 2-7/8" XN Nipple, 2.25010 3,405' Discharge Head — FPHVDIS 3,406' Dual Tandem Pump Section — 71 Flex 10 SXD (2) 3,435' Gas Separator —GRSFTXAR H6 3,440' Tandem Seal Section - GSBDBUT SB/S8 PFSA : GSBDBIT SB/SB PFSA 3,454' Motor — MSPl-250 126HP/ 2,445 V/ 31A 3,465' Sensor / Centralizer— t.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 Hale 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 WKM 2-9/16" 5M Wellhead 11" x 11" 5M Tubing Spool, ll" 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"" Lateral 3S, Nabors $-ES & Nordic #3 — 5/27/2001 Replace ESP - Nabors 4ES— 8/20/2003 Replace 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 Milne Point Unit Well: MPJ-01AL1 PROPOSED Last Completed: Proposed uilcvn•,r .nt:r.,kn, f,f.r. PTD: 201-021 CASING DETAIL RKB Elev = 35' 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" Sltd Liner A 12.6 / L-80 / IBT 3.958 3,512' 7,135' 2-3/8" 1 Sltd Liner B I N/A / L-80 / N/A I N/A 4,567 7,709' TD=7,99Y (MD) / TD = 4,165'(TVD) PBTD = 7,959 (MD) / PBTD = 4,165(TVD) TUBING DETAIL 8" Tubing 1 65 / L-80 / EUE 8rd 1 2.867 1 Surface 1 ±3,475' JEWELRY DETAIL o Depth Item ±200' GLM ±3,250' GLM ±3,400' 2-7/8" XN Nipple, 2.250 ID ±3,411' DischargeHead— FPIIVDIS ±3,412' Dual Tandern 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 — MSP1-250 126HP/ 2,445 V/ 31A ±3,471' 3/8" Stainless Steel External Capstring ±3,471' Sensor / Centralizer —±Bottom@3,475' L 3,512' Baker 5" x 7" HMC Liner Hanger 4,567' 2-3/8" Liner Tap w/ 3.70" Deploy Sleeve 3 4,68Z' Baker HMCV Cementing Valve 4 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 TRFF A WFI I HFAn INFn Tree I W KM 2-9/16" SM Wellhead 11" x 11" 5M 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"" 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 7/27/2015 EXHIBIT 7 Page 6 of 12 11" BOPE Milne Point 2015 ASR Rig 1 Knight Oil Tools ROP Updated 7/23/15 7/8 -5 variables ind ,es 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 U Plug Perforations Fracture Stimulate ❑ Pull Tubing U, Operations shutdown U Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Well E] 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 ❑✓ Stratigraphic ❑ Exploratory ❑ 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): N/A Milne Point Field I Schrader Bluff Oil Pool 11. Present Well Condition Summary: Total Depth measured 8,034 feet Plugs measured N/A feet true vertical 4,141 feet Junk measured NIA feet Effective Depth measured 7,135 feet Packer measured NIA feet true vertical 4,108 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Conductor 105' 13-5/8" 105' 105' 2,730psi 1,130psi Surface 2,409' 9-518" 2,409' 2,346' 3,520psi 2,020psi Production 3,640' 7" 3,640' 3,502' 7,240psi 5,410psi Slotted Liner 3,623' 4-1/2" 7,135' 4,154' N/A NIA Slotted Liner 3,142' 2-3/8" 7,709' 4,161' NIA 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-801 EUE 8rd 3,496' 3,368' Packers and SSSV (type, measured and true vertical depth) N/A NIA NIA N/A 12. Stimulation or cement squeeze summary: NIA Intervals treated (measured): NIA 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: 19 54 54 300 223 Subsequent to operation: 59 0 103 340 226 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 15. Well Class after work: Daily Report of Well Operations Q Exploratory ❑ Development D Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Q Gas 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: 315-459 Contact Stan Porhola Email sporhola@hllcorg.com Printed Name Stan Porhola Title Operations Engineer Signature TPhone 777-8412 Date 10/30/2015 Form 10-404 Revised 512015 Submit Original Only EXHIBIT 7 Page 9 of 12 Milne Point Unit Well: MPJ-01AL1 14 ACTUAL SCHEMATIC Last Completed: 8/11/2015 Hilcorp Alaska, LIX PTD: 201-021 CASING DETAIL RKB Elev = 35' 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" Sltd Liner A 12.6 / L-80 / IBT 3.958 3,512' 7,135' 2-3/8" Sltd Liner B N/A / L-80 / N/A N/A 4,567 7,709' TD=7,950' (MD) /TD=4,165'(TVD) PBTD= 7,950' (MD) / PBTD= 4,165(TVD) 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' DischargeHead— FPHVDIS 3,441' Pump Section —119 -Flex 10SXD 3,464' Gas Separator —GRSFTXARH6 3,469' Tandem Seal Section - GSBDBUT SB/SB PFSA : GSBDBIT SB/SB PFSA 3,483' Motor —MSP3-250 84HP/ 2,210 V/ 23A 3,491' 3/8" Stainless Steel External Capstring 3,491' Sensor XT -150 / Centralizer — Bottom@ 3,496' 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 @ 2,50V 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 Vin 6.1/8" Hole TREE & WELLHEAD INFO Tree WKM 2-9/16" 5M Wellhead 11" x 11" 5M 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 & Camp. Nabors 4ES &Completion —10/05/99 2" Lateral 3S, Nabors $-ES & Nordic #3 — 5/27/2001 Replace ESP - Nabors 4ES — 8/20/2003 Replac.ESP_ ESP —yon 16— 8/20/2003 Replace ESP - Doyon 16 — 4/24/2011 Created By: STP 10/29/2015 EXHIBIT 7 Page 10 of 12 EXHIBIT 7 Page 11 of 12 Hilcorp Alaska, LLC Ifilro,.,,Alaska, LLC 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 bbis gone. Caught circulation 1st tbg volume — 20 bbis all water, turned to oil. Continue pumping 80 bbls until oil returns clean@ 4BPM with 50-60% losses, Pump additional 20 bbis 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 bbis 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 (Pits 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" Muleshoe jt 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 8.5 ppg SW. Pump 24 bbis 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 3,512') 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 bbis 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 bbis down annulus, 20 bbis down tbg. Hole is standing full. Open annular. Check flow. Break Swivel. POOH LD 2- 7/8". EXHIBIT 7 Page 11 of 12 EXHIBIT 7 Page 12 of 12 Hilcorp Alaska, LLC ItiluacpAlaska.,1AA: 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 bbls 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 2.25ID @ 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 BOPE NU Tree and test 250/5,000 psi RDMO turn well to production. EXHIBIT 7 Page 12 of 12 THE STATE GOVBRNOR 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 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1 433 Fax: 907.276.7542 www.00gcc.alask(-.i.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. Gerster Chair 4 - DATED this 3) day of August, 2015 Encl. EXHIBIT 8 Page 1 of 15 t 1' ` yy �, 11 � . �Y STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALSOn AAroroon )k�. 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 ❑� Plug for Redrill ❑ Perforate New Pool ❑ Repair Well Re-enter Susp Well ❑ Other. ESP Change -out ❑✓ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number. Hilcorp Alaska, LLC Exploratory ❑ Development Q Stratigraphic ❑ Service ❑ 199-117 1 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 [J MILNE PT UNIT SB J -08A 9. Property Designation (Lease Number): 10. Field/Pool(s): I ADL0025515 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 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 112' 13-3/8" 112' 112' 3,730psl 1,130psi Surface 2,516' 9.518" 2,516' 2,476' 6,750psi 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 7,500ps1 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 (ft): ZXP Liner Top Packer and N/A 4,714 MD / 3,810 TVD and N/A 12. Attachments: Description Summary of Proposal 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑✓ Exploratory ❑ Stratigraphic (J Development ❑✓ Service ❑ 14. Estimated Date for 15. Well Status after proposed work: CommencingOperations: 9/1.5/2015 p OIL � 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 sporhola@hilcor .conn Printed Name Stan Porhola Title Operations Engineer Signature __ Phone 777-8412 Date 8/26/2015 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3, C 5 2_1 7 Plug Integrity ❑ BOP Test [rE]Mechanical Integrity Test ❑ Location Clearance Other:t _ �, �/_ k's / / it j, Spacing Exception Required? Yes ❑ No Subsequent Form Required: /,e -/ C,` APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: / D U ( _-P ati A � Submit Form and Form 10-403 Revises 512015 p r ap i alio Ii 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: 1 -Pad _ Estimated Start Date: September 15t", 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 J -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. M1RU 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. S. 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 J-08A I ilrorp Al—ka, LU Date: 8/26/2015 c. Conduct a roiling 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, remove the old hanger, MU new hanger or test plug to the completion tubing. Re-land hanger (or test plug) in tubing head. Test BOPS 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. 4. � f'r , _ 'r A- 9. POOH, Lay 2-7/8" tubing on the pipe rack (utilize as workstring). 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 Hih,,n Al,.4a, MA: PTD: 199-117 Orig. KB Elev.: 651/ GL Elev.: 35.7' (N22E) TD = 8,495' (MD) / TD = 4,107(TVD) PBTD= 8,495' (MD) / 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" j 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 4,634' 2-7/8" XN Nipple — 2.313 ID: 2.205 no-go _3 4 4,645' Discharge Head S_ 4,646' Pum 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/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 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 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 Wellhead WKM 11" x 11" SM, WKM w/ 11" x 3.5" tubing hanger/ NSCT 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 Recompletion —1/28/2000 Schrader Bluff Recompletion by Nabors 4ES — 4/19/1997 ESP Replacement by Nabors 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 uih, T„ AIu9k,,l.t.c PTD: 199-117 CASING DETAIL Orig. K8 Elev.: 65.Y/ GL Elev.: 35.7' (N22E) TD=8,495' (MD) /TD=4,107(TVD) PBTD = 8,495' (MD) / 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" 4-1/2" Intermediate Liner 26/L-80/Btrc 12.6 / L-80 / IRT 6.276 3.958 0 4,729' 4,866' 5,901' 4-1/2" Slotted Liner 6.2/L-80/SLT 3.958 5,901' 8,451' TUBING DETAIL 2-7/8" Tubing 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 Capillary 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' 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 95/8" 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 5M Wellhead W KM 11" x 11" SM, WKM w/ 11" x 3.5" tubing hanger/ NSCT 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 Recompletion -1/28/2000 Schrader Bluff Recompletion by Nabors 4ES - 4/19/1997 ESP Replacement by Nabors 3S - 2/11/2007 Revised By: STP 8/19/2015 EXHIBIT 8 Page 6 of 15 Milne Point 2015 ASR Rig 1 n i. ' �i.,►�. i.i Knight Oil Tools BOP 11" BOPE Updated 8/19/15 7/8 -5 variables ind 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 U Plug Perforations U Fracture Stimulate Pull Tubing ✓ Operations shutdown TT Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Well ❑✓ Re-enter Susp Well ❑ Other: ESP Change -out Q 2. Operator Name: 4. Well Class Before Work: 5. Permit to Drill Number: Hiicorp Alaska, LLC Development ❑✓ Exploratory ❑ Stratigraphic❑ Service ❑ 199-117 3. Address: 6. API Number: 3800 Centerpoint Drive, Suite 1400, Anchorage AK, 99503 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' 13-3/8" 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' 8,430psi 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 NIA 4,714'MD / 3,810'TVD N/A 12. Stimulation or cement squeeze summary: NIA 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, 8 25.283) 15. Well Class after work: Daily Report of Well Operations ❑ Exploratory❑ Development❑ Service ❑ Straligraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil ✓ Gas Lj 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 sporholaia-�.hilcorp.com Printed Name Stan Porhola Title Operations Engineer Signature /� Phone 777-8412 Date 10/19/2015 Form 10-404 Revised 5/2015 Submit Original Only EXHIBIT 8 Page 9 of 15 Orig. KB Elev.: 65.2/ GL Elev.: 35.7' (N22 E) TD = 8,495' (MD) / TD = 4,107(TVD) PBTD = 8,495' (MD) / PBTD = 4,107'(TVD) SCHEMATIC CASING DETAIL Milne Point Unit Well: MPU 1-08A 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 3.958 5,901' 8,451' TUBING DETAIL �2-7/8" 1 Tubing 1 6.5 / L-80 / EUE 8rd 2.441 0 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 12 4,729' Baker 5" x 7" HMC Liner Hanger (4.375" ID) 13 5,776' _ Baker HMCV Cement Valve 14 51794' 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 TREE & WELLHEAD Tree 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 5M Wellhead _ WKM 11" x 11" 5M, VV w/ 11" x 3.5" tubing hanger/ NSCT 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 Recompletion —1/28/2000 _ Schrader Bluff Recom letion by Nabors 4ES — 4/19/1997 ESP Replacement by Nabors 3S— 2/11/2007 ESP Change -out by Nordic N3 — 7/5/2015 ESP Change -out by ASR Ni —10/3/2015 Revised By: TDF 10/20/2015 EXHIBIT 8 Page 10 of 15 EXHIBIT 8 Page 11 of 15 Hilcorp Alaska, LLC Weekly Operations Summary Well Name IAPI Number lWell Permit Number IStart Date I 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 40bbls of 60/40. Pumped 35 bbls of 60/40 and broke circulation. SD Pump. Lined valves to perform full body Test. Performed shell test 250-3,500ps!-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 ACP, 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 GOP's, PT 4,000psi- test good. Circulated 35 bbis 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 JAPI Number lWell Permit Number IStart Date End Date MPJ -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 BOPE 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 2bbis out. With no returns, Discuss plan with Anchorage, continued RIH pumping .4bpm and tagged the Discharged Head at 4,651. Increased rate to 1bpm pumped away 10 bbis back flushing thru ESP. 140 bbls 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 bbi 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 EXHIBIT 8 Page 13 of 15 Hilcorp Alaska, LLC Weekly Operations Summary Well Name JAPI Number Well Permit Number Start Date jEnd Date MPJ -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 throujzh 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 5.7tf 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 bbls cleaned up after 20 bbls total pumped 100 bbls. 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 bbis 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 bbls 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 9/27/15 - Sunday`: 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. 9/28/15 - Monday Operations on standby. 4/29/15 •Tuesday Operations on standby. EXHIBIT 8 Page 14 of 15 EXHIBIT 8 Page 15 of 15 Hilcorp Alaska, LLC llilcorPAlaku,LL[; Weekly Operations Summary Well Name JAPI Number JWell Permit Number Start Date JEnd Date MP 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 500bbls 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 ROPE 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 Nit..p %I.A.. IAA Hill CORP ALASKA, I I C- INTERNAL INCIDENT INVESTIGATION 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 Push erSUPERVISOR: , Owner EMPLOYMENT STATUS: ❑P/T XF/T ❑TEMP CONTRACTOR GENDER: XM OF TYPE OF INCIDENT: M 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 25`h, 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 1 EXHIBIT 9 Pagel 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 (D1) and Driller 2 (D2) 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) ..fazufald IQU 3fahMd 1 VVELL Rig or .1ud Pit ....:........,..:.. .. .....:. 2 Operator 3 Location - r-40 3 EXHIBIT 9 Page 3 of 5 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 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: Rio 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: C'wd Q. Jvnes DATE: 10/1/2015 INJURED EMPLOYEE (if applicable): Click here to enter text. SIGNATURE: DATE: Click here to enter a dale. INJURED EMPLOYEE'S SUPERVISOR: Click here to enter text. SIGNATURE: DATE: Click here to enter a date. EXHIBIT 9 Page 5 of 5 Automated Service Rig 1 (ASR 1) 25 September 2015 Incident Investigation Events Sequencing Chart Monitor sys. Rig & Crew meets industry Operationally Design Ready Adequate Ade uate Ade q / \ q � Halliburton N2 clean- out. Leak and pause of ASR day shift began ASR day shift began Abbreviations: LTA - Less Than Adequate NI - Needs Improvement SPAC-Standards, Procedures &Controls crew change activities.. Walked Enclosed mud pit Crew trained and designed w/new gas deemed qualified to monitoring system operate ASR. After S - 27 mins after 133 mscf. ASR night shift 27, ASR WOs 5 wells detectors ) J ASR Rig and crew down job, reviewed nitrogen) Flowing back to ASR Rig Constructed by ASR arrived MPU deployed Well 5-]I hookup, performed ASR Mobe in and rig outside tanks. ASR BOPE tested on J- 200mscf and 207 bbls on duty. Flowback Rangeland Drilling and assembled. Crew JSA, discussed N2. n and began first well seawater pumped. p p up on J -08A. of N2 to exterior tanks. 08A. Witness waived. hardlined to exterior Automation. Inc. in training on rig. work Commence work over. tanks. 20150925 06:35 Alberta, CA 20150925 06:30 20150925 06:30 20150531 20150610 20150719 20150923 20:00 20150924 12:00 20150925 02:30 ASR day shift began ASR day shift began Abbreviations: LTA - Less Than Adequate NI - Needs Improvement SPAC-Standards, Procedures &Controls crew change activities.. Walked Enclosed mud pit Crew trained and designed w/new gas deemed qualified to monitoring system operate ASR. After S - (LEL and H25 27, ASR WOs 5 wells detectors ) J (including J -01A down job, reviewed nitrogen) ASR day shift began ASR day shift began Abbreviations: LTA - Less Than Adequate NI - Needs Improvement SPAC-Standards, Procedures &Controls crew change activities.. Walked Halliburton in final stages of N2 clean. Halliburton finished down job, reviewed Flowing back to N2 clean-out. Total Halliburton blew down ASR crew ASR crew began well hookup, performed outside tanks. 200mscf and 207 bbls lines, disconnected blow down JSA, discussed N2. seawater pumped. p p truck, stand by on site. of N2 to exterior tanks. 20150925 05:30 20150925 06:00 20150925 06:35 20150925 06:30 20150925 06:30 EXHIBIT 10 Page 1 of 5 Pumped 50 bbls seawater via ASR pump at 3.5 bbls/min down annulus 20150925 Tool pusher and OP 1 meet in tank module manifold room to align valves to bleed pressure from annulus to tank module gas buster and interior tanks 20150925 ^ 08:53 Door between tank manifold room and interior tank room is cl osed. Abbreviations: LTA - Less Than Adequate NI - Needs Improvement SPAC -Standards, Procedures & Controls Tool pusher radioed OP2 from manifold room to open HCR valve to bleed annulus pressure. 20150925 "08:55 OP2 opened HCR valve. Tool pusher Bleeding pressure OPl and OP2 Once HCR opened, OP2 exposed to tank from work string to exterior tanks. Pressure in tubing noted to be 0 psig. heads to WSM trailer. room for -30 Completed pumping pressure was being Pumped 4.1 bbls, 50 bbls seawater. 227 noise in manifold Observed A P from weird smell. Annulus reading of 300 noted immediate bbls recovered in room (gas flowing 1,000 to 300 psig in - psig (incorrect outside where they pressure bump from exterior tanks annulus. However reading). ASR directed "nothing" to 1,000 OP1 does not hear call activities. Passes manifold). Motions for pressure reading not to Pump 2"d 50 bbls of through choke psig. Ceased pumping. 20150925 07:00 OP1 to follow him back indicative of annulus pressure. Was reading seawater 20150925 08:50 up stairs to drillers drop within minutes. trapped pressure choke manifold 20150925 08:48 manifold room. WSM stated on � between ASR pump ( through tank room on and check valve. radio from WSM 20150925 ^'08:59 trailer"I'm confused 20150925 07:00 fellas, let's sit down 09:00 and talk" OP2 opened HCR valve. Tool pusher OPl and OP2 Once HCR opened, OP2 exposed to tank OP2 (in drillers console OP2 notes extreme heads to WSM trailer. room for -30 on rigfloor) radios OPl pressure was being OP2 walks down stairs seconds while noise in manifold OPi started to bleed weird smell. (in choke manifold to manifold room to room (gas flowing pressure via auto - room) to check status. outside where they check on OPl through choke choke to interior tanks. OP1 does not hear call activities. Passes manifold). Motions for Reading pressure on due to noise of fluid through choke through "B ft of tank OP1 to follow him back annulus. Noted 50 psig (gas)flowing through room to enter up stairs to drillers drop within minutes. choke manifold manifold room. console. Both pass through tank room on 20150925 - 08:56 20150925 -08,58 20150925 ^'08:59 way out.- 09:00 / OPl and OP2 Once HCR opened, OP2 exposed to tank exposed to tank first time annulus room for -10 room for -30 pressure was being seconds. Noted ! seconds while read. weird smell. i motioning to go - outside where they could talk. Start of gas bleed off through choke manifold into interior tank EXHIBIT 10 Page 2 of 5 OPl and OP2 felt dizzy and light headed after —45 seconds of exposure to tank room. Had hard time climbing stairs. 20150925 09:00 Crew recognized "something was not right" i OPl 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. OP2 descends stairs and walks to WSM trailer to find Tool Pusher. OP1 goes back through tank room through manifold room and waits outside on landing to manifold room. 20150925 — 09:03 / Workers started feeling better once they got outside to top of steps Door btwn manifold and \ mud rooms closed Abbreviations: LTA - Less Than Adequate NI - Needs Improvement SPAC -Standards, Procedures & Controls OP2 Regains consciousness on outside stairs . Sees OPS, drags him down stairs. Shuts in well at tree with manual valves. Goes to sound man down alarm. 20150925 —09:11 OP2 meets tool pusher in yard outside WSM trailer. Communicates odd feeling and smell. 20150925 "'09:05 Worker did not recognize hazard and great risk OP 2 and tool pusher join OP 1 at manifold room. 20150925 09:07 Tool pusher enters tank room to open hatch to increase ventilation. No alarms sounding in module since monitors did not detect any hazardous conditions; unknown 02 Deficient atmosphere existed 20150925 "' 09:09 Well still bleeding gas through choke manifold to tank room for —13 minutes. I room to check on Tool Pusher. Sees him slumped in far corner. Takes deep breath, tries to walk across the room, makes it half way and turns around. Loses consciousness on outside stairs on drillers console side of the tank module. EXHIBIT 10 Page 3 of 5 Unconscious tool OP 1, OP2, and tool Mandown call made, pusher extricated from pusher received Incident reported to Emergency Response tank room by IWS oxygen on site and external agencies; initiated owner via hatchtransported to MPU investigation began 20150925 09:12 opening. 20150925 09:14 clinic for evaluation. 20150925 09:20 20150925 10:10 EXHIBIT 10 Page 3 of 5 Automated Service Rig 1 (ASR 1) 25 September 2015 Incident MID and Valve Status at time of Pumping Second 50 bbls of Seawater -0848 hrs 8 9 6 5 a 3 2 Status of valve .Y a ® Valve open , Valve closed ° -; Valve status n r_-__----, obtained through I i W'Mallf I 1 I - -T �` interviews, no photo evidence -- Y --- - `--------- of valve status at 0848 hrs on 25 j I September 2015 I i I I I rw ec nao._j` li ' I f uu mreerc I B janm I .. svrc c artxE rxx raux A Y1ett A am.w.an .c na arami m w s rw a oa .n shrz n cma n w ornmoc iaa� sac..._ m a _ MPU GEN PROCESS PIPING & INSTRUMENT DIAGRAM ASR -1 M PI-MW-OOf}Xf( 00 001 8 7 6 5 w 3 2 t EXHIBIT 10 Page 4 of 5 Automated Service Rig 1 (ASR 1) 25 September 2015 Incident MID and Valve Status at time of Incident - — 0856 hours, Started to Bleed Annulus Pressure EXHIBIT 10 Page 5 of 5 6 S 4 3 2 S Status of valve AY 1QR ® Valve open Valve closed ra r________� O Not confirmed in v i photo I AOfAmk iTPI T 9 1 —-- M9 I I C— I I i I I se nar i 1 MWRMf ae nar L_---_wr[�vrao —_._� 9a/N K AGS � I I 'u f` Ilj '• " % smear[ OLLM mmw I — — 1A FA!" swe arc t1JI3l[ ills A 1Y�U_ A aomn-swan _ .. - a wx irvm� m a s +�mtan n n a>< avm trt v uA� .. er w� oa. as MPU GAN PROCESS PIPING * INS?RUMENr DIAGRAM ASR -1 RR; .aAwe � an etor PI)OC 1001 001 � 8 7 6 5 0 3 2 l EXHIBIT 10 Page 5 of 5 September 25, 2015 Incident Root Cause Analysis (RCA) Comprehensive List of Causes (CLC) 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 .Hilcorp Alaska, LLC Milne Point Automated Service Rig 1 (ASR 1) Incident Safety - Sharingtheexperience Lessons Learned Summary Incident: ASR 1 Oxygen Deficient Atmosphere Type of Incident: Recordable Location: Milne Point, North Slope, Alaska Date: 25 September 2015. What happened? 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 f 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. 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. 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. 5) Atmospheric hazard was not recognized. The crew did not realize the installed atmospheric alarms would only detect H2S 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. Learnings to 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 Inte rated Well Service, Inc. Daily Tailgate Meeting ! Job Safety Mai Sis JSA Form Date: Com n Re resentative: Time: Ra resenative Phono N: Attendees Sl' nature: ) 2 3 4 5 to Company Attendees 51 nature: B 9 i t? 11 12 company Hazards lApiallcablis Check Check Hazards Applicable Check Hazards Applicable- (1) Pinch Po!nts (13) Lock Out Taq Out (25 Temperature Exlrama5 (2 Electecal t4 PPE 26High Winds (3) Elevated 1 suspended loads (15) Special PPE Required (27) Communlgllan {4) Hot Wark permit (16) Pressure Testi (28) Rotating E ipmonl (5) Confined Space En (17) Slick! Unavan swfecas OTHER: 6) Equipment Hand&rtg & INs;oinl' (t6) Driving Conditions 29 7 Simultaneous operaltons (18) Workin at H ' cis (30 8 S1omd Prossure Systems L-- 20 Short Service Em o 31) (8) H h Naiea 4avels _ (21 I Meuse Keeping Ll/ (32 (10 Hea Linin (22) MoCile Equipmmt 33) 11 Traffic Pattems around Rig 23) 3rd Pa work 34 (12 Trippi huanfs (./' (24)Oas' Hated Areas smoklrq.etc.}V 1(35) _ .-sitespecificJSAa.,: _ Job Steps / Equipment, Tools, & Material / PPE Hazards Controls pc tbi ttor.J G\wr n5 (k iwaci dais Look UP S{snd baclt d- �al� tt tate 16V s� 04} dot air 9-t&, �—' a(Mru.r<,io,Ly �5�0 t'�t✓'r t.,K.,,r SEa�-�C-'� SOP N reviewed - Tal! to / PtcJob MeeUn Lmergency N ISupervisor Name: I lPhone# I z S EXHIBIT 13 Page 1 of 2 Integrated Well Service, Inc. Daily Tailgate Meetin / Job Safety Analysis JSA Form Date: } 25-05- Com any Representative: Re resenative Phone #: Attendees Signature: Company Attendees Signature: Company 1) 2) 66-5 j9 3)_ 4 5 Hazards 7 8 10 11 12 Check Check Applicable Hazards Applicable Check Hazards Applicable (1) Pinch Points 13) Lock Out Ta Out 25 Temperature FAremes (2 Electrical 14 PPE ✓ (26) High Winds z/ '3) Elevated ! suspended loads 15) Special PPE Required (27) Communicabun ✓ 4 Hot Work permit 5t Confined Space Ent (16) Pressure Testing__ �' 17 Slick ( Uneven surfaces , /` (28RotatingEquipment OTHER: 6` Equipment Handling & Disjointing 03 Driving Conditions (29) 7 Simultaneous operations 19 Working at Heights 8) Stored Pressure Systems / 20) Short Service Em to ee (31) (9 High Noise Levels (21) House Kee in ✓ 32 '10 HeavyLilting(22) 01 Traffic Patterns around Rig Mobile Equipment 23 3rd Party work` ((33) (34) 12 Td inr hazards 24 Desi nated Areas (smokin , eta' -� 35) Site Specific JSA Job Steps / Equipment, Tools, & Material 1 PPE Hazards Controls ��jj).ne5 rkr^ �/ /" X pil11 o.<r c�,.,,... r, ,az;� K'«p a, rrr ^ . Ti SOP # reviewed Tailgate/ Pre -Job Meeting Emergency # ISupervisor Name: I I lPhone# EXHIBIT 13 Page 2 of 2 EXHIBIT 14 Page 1 of 1 JOB LOGI 902780922 TIOWTDATE 09/24/15 c+oN NWA/COUNTRY Alaska l6fATE Ala ka Ml— North Sb Borough N.E.6 EMPLOYEE NUMOM NE.S EAVWYEE HAMS PBL DETMMRTAIEM 1450 OCATON COMPANY Hillcoro ICMLIMT=IPHONE 1562207 Pumping Work over Milne Point PURPOSE CODE 363672 N2 pumpina Date Time N2 VOLUME HES GAL HR Job Description l Remarks SAFETY 09124/16 16:30 Depart with Pumper# 11280516 with 2,499 gal. 18:00 X Arrive on location; Safety meeting; Spot Equipment. Day 2 09/26115 0:02 Rig up 2:00 Cool Down 2:10 X Safety Meeting 2.30 Pressure Test to 3,600 psi 2:40 Online 500 scfm; 140 psi 2:41 750 schn; 275 psi 2:46 1,000 scfm; 577 psi 2:57 1,200 scf n; 935 psi 3:30 1,200 scfm; 1,263 psi 4:30 Offline; N2 hose started to leak. Replaced hose. 4:66 jOnline 1,000 scfm; 1,181 psi 6.30 1,000 scfm; 1,280 psi 6:30 2498 lne; 1,327 psi. Pumped 200,000 scf. Pump has 0 gal left Standby. Rig is pumping 50 bbis fluid to kill the well. 8:00 X Partial rig down. Standby. 11:00 Left location. 15:00 jArrive at yard 2499 Gals used 2 days pumping PE REV.02 -3 EXHIBIT 14 Page 1 of 1 Hilcorp ASR Rig #I Fluid Fluid Flow Diagram „A J -08A Incident NITROGEN UNIT ................................... •••••••••. NITROGEN PUMP �,...;. KILL MANIFOLD K7 KS Y K3 K4 KS JIG— Vent PIT SYSTEM GAS BUSTER Fill CIRC Standpipe ASR RIG MUD PUMP K2 KI Kill Line Open Open 90 BBL CUTTINGS TANK Updated 1/21/16 500 BBL KILL TANK 500 BBL PIGGING TANK CHOKE MANIFOLD apnea A Nr�-o-1 BOPE Panic Line C12C13 C15 Open N N Open U U 6 e C1 HCR Gate Valve 1 Choke Line Butterfly Valve Open Open Automatic Choke *t Manual Choke I Casing Valve 0 Gas Buster Line B LEGEND: Fluids Pumped . Fluids Returned 0 Valve Open = Valve Closed M Gate Valve D4 Ball Valve Dod Butterfly Valve Lo Torq Valve DM Automatic Choke Manual Choke I Pressure Gauge 0 Check Valve N Bleeder Tee Db EXHIBIT 15 Page 1 of 1 z IN Y z Alaska StatePlane Zone 4 NAD 1983 (Feet) Milne Point Unit Aerial Photography: 0 10 20 30 40 5Meters ASR #1 J-08 Quantum Spatial Inc 0 100 200 300 Map Date: 1121/2016 Site Map 2014 Feet EXHIBIT 16 Page 1 of 1 Rear ASR #1 TANK TRAILER PASSENGER SIDE VIEW N Valve Front EXHIBIT 17 Page 1 of 1 Front ASR #1 TANK TRAILER DRIVER SIDE VIEW ...... MV V Door Rear EXHIBIT 18 Page 1 of 1 EXHIBIT 19 Page 1 of 2 i 0 9/25/2015 ASR Rig —CLC Corrective Actions Description CL.C�Responsible.,PajV Due Date Cohn ' plqsq, 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 level of hazard awareness tag. The Integrated Well Services ToolPusher will be responsible 2c and for control of the lock and will assess all situations prior to removing the lock to orient the upon rig up current valve to a position other than closed Review and revise the Integrated Well Services SOP for nitrogen cleancruts. Revisions shall include requiring hardline from both the annulus and work string to the external flow back DONE, SOP tank, language directing employees to visually 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 lement 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 lines are 3 receive a specific briefing regarding the proper orientation of the dump valve (closed) on the 2a,b,c 11/15115 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 andA equipment shall be documented and all Integrated Well Services employees will sign a roster I once completed. arrows Design and produce a poster of the manifold and gas buster systems schematics. Poster should be in detail to allow manifold operators to help trace systems down while walking MPU DONE' 7 4 down lines prior to flowback and pumping activities. 3 posters should be printed and hung in 2a,b,c Safety 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 be added to the system. This will include oxygen sensing equipment to alarm during oxygen installed, but wiringand deficient atmospheres below 19.5% as well as carbon monoxide sensing equipment set to programing not alarm at 25 parts per million. Equipment shall be installed and function tested after 3a, 5a HAK 12/1/15 finished. All Ask 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 anddocumented. on the mechanical capabilities and limitations of the gas detection equipment. All trainees will acknowledge completion and understanding of the system by signing a training roster to I I I I Wiring and EXHIBIT 19 Page 1 of 2 i 0 Additional Actions / Lessons Learned: Investigation findings determined that improper decision making or lack of judgment took place while pumping the 21d fluid pill. (See CLC 4a,b,c,d and la) Asan 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 be maintained on site by the ToolPusher. In the interim of gas detection upgrades, personal pr amming to four gas monitors will be used by employees performing work activities within the confines e place when of the pit/manifold skid w is days off Flefirst week in Febua . 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 Policy is 11/15 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 7 HAK Motorola radios. Once in place, headsets will be evaluated for effectiveness, durability, 8a 11/1/15 use for hands and ease of use. Once evaluated Integrated Well Services ToolPusher will purchase adequate stock to ensure communications can be maintained between employees in high noise in high noise environments. are Review the pit/manifold trailer ventilation systems capabilities and ensure that ventilation Done, aIr 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. maximum excha Additional Actions / Lessons Learned: Investigation findings determined that improper decision making or lack of judgment took place while pumping the 21d fluid pill. (See CLC 4a,b,c,d and la) Asan 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 byork@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 Sent from my iPhone Chris Kanyer <ckanyer@hilcorp.com> Saturday, May 02, 2015 2:33 PM Re: I-03 Follow up Flagged 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, hilcorp.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 1 EXHIBIT 21 Page 1 of 2 0430 Successfully straddled hole in casing. 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 I-03 Thanks, engineering wanted to be sure all bases covered. Thanks Jim. Hilcorp Alaska LLC WSM Milne Point Email@hilcorp.c_o_m USA Cell + 1 Rig Office Direct 907-� From:, "James B (DOA)" <iim.regg@alaska.gov> Reply -To: "Regg, James B (DOA)" <iim.regg@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 .bav@alaska.gov>,"Regg, James B (DOA)" <iim.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 EXHIBIT 22 Page 1 of 3 From: Ogclnspector (DOA sponsored)[mailto:doa.ogc.lnspector@alaska.Qov] 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: BOPE, Nordic 3 MPU 1-03 Witness waived Chuck Do not reply directly to this e-mail or doa.Ogc_inspectorn,Alaska.yov Please reply to AOGCC.inspeectors(Lcb, ska.gov or Doa.AOGCC.prudhoe.bayas 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.aov] 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 )_eff.iones@alaska-ggv.. From: �[mailto:noreplly(�i)formresponse com] Sent: Wednesday, April 29, 2015 7:39 AM To: DOA AOGCC Prudhoe Bay Subject: AOGCC Test Witness Notification Request: BOPE, Nordic 3 MPU I-03 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 1-03 Name E-mail EjjjjU&hilcoM.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 "5".... 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 Pagel of 3 • • • 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 01 N2 Pumping job 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 EXHIBIT 23 Page 3 of 3 18 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 1 (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 Net 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). Lil o i _ y two __-_, .ET UPON 25 SEPT 2015 ON J 08 N2 PUMPING 0PERAT10NS YELL! -:8 MPU GEN PR9t"E$$ PIPING h +NSTRUMENT DIAGRAM ASR -1 RIG Pi-MDO-0000 t Exhibit 15 correctly shows the IA "casing valve" with no gauge but does not depict the OA valve and gauge. Standpipe f ASR R W r...........................: MUD PUMP S4 KOPi Tank Lina C12t K2 KI�CI HCR KJltine -a� 1.-.__ CMYe Line 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 1-08A? 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 1-08A 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 byork@Hilcorp.com 907.777.8345 907.727.9247 cell Serial Number Equipment Type Equipment Category 12024J7-016 MX4 Instrument Unscheduled Calibration 12050YF-001 MX4 Instrument :Scheduled Calibration 13034D6-010 MX4 Instrumental IScheduled Calibration 13044C5-001 MX4 Instrument jUnscheduled Calibration 13032QH-026 MX4 Instrument 238 Hilcorp Alaska LLC Milne Point Scheduled Calibration 12052P7-002 MX4 Instrument 231 Hilcorp Alaska LLC Milne Point !Unscheduled Calibration 13015PA-078 MX4 Instrument Scheduled Calibration 150121Q-011 MX4 Instrument Scheduled Calibration 14021NZ-005 MX4 Instrument tScheduled Calibration 120741 S-015 MX4 Instrument Scheduled Calibration 13032 H-026 Q MX4 Instrument j Scheduled Calibration 150121Q-011 MX4 Instrument Passed ;Scheduled Calibration 11041Z1-005 MX4 Instrument sScheduled Calibration 13034D6-010 MX4 Instrument !Forced Calibration 13034D6-010 MX4 Instrument i Scheduled Calibration 120741S-015 MX4 InstrumentScheduled Calibration 150121Q-011 MX4 Instrument EScheduled Calibration 1211324-001 MX4 Instrument !Scheduled Calibration 13044C5-001 MX4 Instrument Scheduled Calibration 14021NZ-005 MX4 Instrument �j Scheduled Calibration 13044C5-001 MX4 Instrument Scheduled Calibration 12113OM-071 MX4 Instrument 'Scheduled Calibration 130444T-012 MX4 Instrument Scheduled Calibration 13031132-003 MX4 Instrument !Scheduled Calibration 12112QU-026 MX4 InstrumentScheduled Passed Calibration 130444T-012 MX4 Instrument Scheduled Calibration 12112QU-026 MX4 Instrument ;Scheduled Calibration 13015PA-078 MX4 Instrument !Scheduled Calibration 12113OM-071 MX4 Instrument :Scheduled Calibration 13070XB-035 MX4 Instrument ;Unscheduled Calibration 13070XB-035 MX4 Instrument Scheduled Calibration 13031D2-003 MX4 Instrument !Scheduled Calibration 1211324-001 MX4 Instrument ; Scheduled Calibration 13070XB-035 MX4 Instrument __Scheduled Calibration �, Titer . j Retiult, i D�xrking Statism Duratrun .acwunt ; 9/16/2015 13:28 Passed 11052EF-001 237 Hilcorp Alaska LLC Milne Point 9/15/2015 9:56 Passed 11052EF-001 218 Hilcorp Alaska LLC Milne Point 9/12/2015 17:50 Passed 11052EF-001 251 Hilcorp Alaska LLC Milne Point 9/6/2015 7:34 Passed 11052EF-001 238 Hilcorp Alaska LLC Milne Point 9/5/2015 13:41 Passed 11052EF-001 231 Hilcorp Alaska LLC Milne Point 9/5/2015 7:07 Passed 11052EF-001 237 Hilcorp Alaska LLC Milne Point 9/4/2015 8:45 Passed 11052EF-001 248 Hilcorp Alaska LLC Milne Point 9/3/2015 8:01 Passed 11052EF-001 240 Hilcorp Alaska LLC Milne Point 9/1/2015 23:06 Passed 11052EF-001 j 258 Hilcorp Alaska LLC Milne Point 9/1/2015 0:07 Passed 11052EF-001 368 Hilcorp Alaska LLC Milne Point 8/23/2015 12:20 Passed 11052EF-001 249 Hilcorp Alaska LLC Milne Point 8/4/2015 11:35 Passed 11052EF-001- 240 Hilcorp Alaska LLC Milne Point 8/2/2015 9:02 Passed 11052EF-001 267 Hilcorp Alaska LLC Milne Point 8/1/2015 14:26 Passed 11052EF-001 _I 271. Hilcorp Alaska LLC Milne Point 8/1/2015 7:22 Failed 11052EF-001 — 1080 Hilcorp Alaska LLC Milne Point 9/30/2015 23:04 Passed 11083SW-012 251 Hilcorp Alaska LLC Milne Point 9/4/2015 7:04 Passed 11083SW-012 �I 242 Hilcorp Alaska LLC Milne Point 9/3/2015 7:27 Passed 11083SW-012 269 Hilcorp Alaska LLC Milne Point 9/1/2015 23:08 Passed 11083SW-012 - 262 Hilcorp Alaska LLC Milne Point 8/31/2015 23:02 Passed 11083SW-012 274 Hilcorp Alaska LLC Milne Point 8/2/2015 6:57 Passed 11083SW-012 244 Hilcorp Alaska LLC Milne Point 8/2/2015 0:36 Passed 11083SW-012 261 Hilcorp Alaska LLC Milne Point 8/1/2015 23:10 Passed 11083SW-012 238 Hilcorp Alaska LLC Milne Point 8/1/2015 12:18 Passed 11083SW-012 220 Hilcorp Alaska LLC Milne Point 9/1/2015 23:08 Passed 11094KP-004 249 Hilcorp Alaska LLC Milne Point 9/1/2015 6:26 Passed 11094KP-004 I 235 Hilcorp Alaska LLC Milne Point 8/3/2015 23:06 Passed 11094KP-004 I 229 Hilcorp Alaska LLC Milne Point 8/1/2015 23:11 Passed 11094KP-004 —�— 249 Hilcorp Alaska LLC Milne Point 9/6/2015 23:03 Passed 11094KP-005 266 Hilcorp Alaska LLC Milne Point _I 9/4/2015 23:06 Passed 11094KP-005 248 Hilcorp Alaska LLC Milne Point 9/1/2015 23:09 Passed 11094KP-005 279 Hilcorp Alaska LLC Milne Point 9/1/2015 6:25 Passed 11094KP-005 229 Hilcorp Alaska LLC Milne Point 8/4/2015 6:26 Passed 11094KP-005 276 Hilcorp Alaska LLC Milne Point 8/1/2015 23:10 Passed 11094KP-005 257 Hilcorp Alaska LLC Milne Point 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 ''Scheduled 11041Z1-005 MX4 Instrument '— Calibration 8/5/2015 7:49 Passed 131003C-010 i 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 Wanual Calibration 9/13/2015 13:59 Passed - Instrument 17 Hilcorp Alaska LLC Milne Point 13044C5-001 MX4 Instrument iManual Calibration 9/11/2015 9:36 Passed Instrument 18 Hilcorp Alaska LLC Milne Point 13044C5-001 MX4 Instrument Wanual Calibration 9/10/2015 8:51 Passed Instrument 17 Hilcorp Alaska LLC Milne Point 12024J7-016 MX4 Instrument IManual 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 i 17 Hilcorp Alaska LLC Milne Point 1211324-001 MX4 Instrument Wanual 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 i Manual Calibration 9/3/2015 3:26 Passed Instrument 16 Hilcorp Alaska LLC Milne Point 14021 NZ -005 MX4 Instrument _ Manual Calibration 9/3/2015 3:26 Passed Instrument 17HilcorpAlaska LLC Milne Point 13031132-003 MX4 Instrument Manual Calibration 9/3/2015 3:09 Passed Instrument 17 Hilcorp Alaska LLC Milne Point 13031132-003 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 1 13031132-003 MX4 Instrument Manual Calibration 8/25/2015 3:45 Passed Instrument 16 Hilcorp Alaska LLC Milne Point 13031132-003 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 16 Hilcorp Alaska LLC Milne Point 150121Q-011 MX4 Instrument Manual Calibration 8/8/2015 12:37 jPassed 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 IMAGINE YOUR PEACE OF MIND. The Gas Detection People INDUSTRIAL sc►FNr►F►c www.indsci.com IMAGINE WWW. I NDSCI . COM/IMAGINE- INET/ 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. 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And begin to �f I MAGINE -1000 $ U U OHSAS 18001 ISO 9001 IS014001 Certified Certified Certified AMERICAS Phone: +11-4112-788-4353 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 REV 0115 © 2015 Industrial Scientific Corporation 17 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 NAME =1 47,, !,NOW DATE: 2/18/2016 AFFILIATION IyllKfL-�Cvuc,� AC)G cc- 16 Regg, James B (DOA) From: Carlisle, Samantha 1 (DOA) Sent: Friday, January 29, 2016 3:34 PM To: Regg, James B (DOA); Quick, Michael J (DOA); Schwartz, Guy L (DOA); Foerster, Catherine P (DOA); Seamount, Dan T (DOA); Ballantine, Tab A (LAW) Subject: FW: 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 From: Marc Bond [mailto:mbond@hilcorp.com] Sent: Friday, January 29, 2016 3:28 PM To: Carlisle, Samantha J (DOA) Cc: Larry Greenstein Subject: 0TH -15-25, 0TH -15-29, 0TH -15-30, OTH-15-31: Hilcorp Alaska Submission for Informal Review 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.corn 3800 Centerpoint Drive • Ste 1400 • Anchorage • Alaska • 99503 Uft 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. 15 THE STATE ® i J ASKA 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 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.cogcc.alaska.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 ASR 1, 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-15-024, U fH-15-025, OTH-15-029, OTH-15-030, and Ol n-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, 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 a Cards to `exec --dire Secretal~y II ` ;4task a C)rf r .a2i{C as (v 7��ser�� tic n or�l,r�zis.,ic��l 333 'est f'`` ✓1wefl e, -`,"Inchorage, _f .K 99501 t' (")0;) 7-�-) -122,3�cl:nal�t6� r.cu.r(5S6 �,c�klskC1_ CONFIDENTIALITY NOTICE: This e-inail message, including any attachments, contains information fro.tn the Alaska Oil aid 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 inforination. The rrnauthorized review, use or diseosa.re of such information mav violate. state or federal law. if you are an unintended recipient of this e-mail, please delete it, withou t first saving, or forwarding it, and, so tha t the AOC;C..0 is aware of the mistake in sending it to you, contact Sanhantlia Carlisle at (707) 93-122.3 or Samantha.C. irhsleCg alaska.�*ov. Domestic Mail Only Ln For delivery information, visit our welosite at wilvilm.usps.com' [` Certified Mail Fee C� $ Extra Services & Fees (check box, add tee as appropriate) ❑ Retum Receipt (hardcopy) $ "'D ❑ Retum Receipt (electronic) $ Postmark O O ❑Certified Mail Restricted Delivery $ Here ❑ Adult Signature Required $ ❑ Adult Signature Restricted Delivery $ O Postage --j- 1:3 -j-o Mr. David Wilkins U-) Senior Vice President a o Hilcorp Alaska, LLC r� 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. A. Signature ❑ Agent X r ' ❑ Addressee B. Received by (Printed Name) C. Date of Delivery •—rte __ __ " _ f _ t s delivery address different froa4 item 1? U Ye; YES, enter delivery address below: ❑ No Mr. David Wilkins Senior Vice President Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 OFF 8 2015 Anchorage, AK 99503 s. aervlCe Type ❑ Priority Mail Expresso ❑ Adult Signature ❑Registered MaiITM II I III III IIII I'I I I I I I I I I II III'lI Ill IIII III l Il l ❑ Adult Signature Restricted Delivery ❑ Registered Mail Restricted 9590 9403 0910 5223 5231 57 VCertified Mail@ ❑ Certified Mail Restricted Delivery Delivery P Return Receipt for ❑ Collect on Delivery ❑ Collect on Delivery Restricted Delivery Merchandise ❑ Signature ConfirmationTM ❑ Signature Confirmation 2. Article Number (Transfer from service label) 7 015 0640 0006 0779 5890 Ired Mail lred Mail Restricted Delivery Restricted Delivery rr $500) PS Form 3811, July 2015 PSN 7530-02-000-9053 Domestic Return Receipt t 14 Hilcorp Alaska, LLC M E `AA F I V E U NOV 213 2015 November 25, 2015 David Wilkins Senior Vice President Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 CC Phone: a' Fax: 907/777-8580 Cathy Foerster 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, 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 >�d David Wi ins Senior Vice President 13 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 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: Carlisle, Samantha J (DOA) Sent: Monday, November 23, 2015 1:05 PM To: David Wilkins Cc: Foerster, Catherine P (DOA); Seamount, Dan T (DOA); 'Regg, James B (DOA) Oim.regg@alaska.gov)' Subject: Response to informal review request Attachments: AOGCC response to informal review request by Hilcorp OTH-15-025, 029, 030, 031_ 11232015.pdf Mr. Wilkins, Please see the attached. Thank you, Jt�.tfbc�t;Y.i:�i,ta �t�t"list`@ `Execltl-ivE" SOcI,etca='ti/ H Ifasl�a C)i afld C7as C..'ot2sa ��vczfio'n C'frnli-pli-sSion 3,53 l-Vcjst 7 ` it enue ..Ant flovage, <)07) 793-1223 (Phone) 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.(;ar.lisle< alaska.�ov. CO M .. 17 Priority Mail Express® r In D-• rti Certified Mail Fee II P- $ ® Extra Services & Fees (check box, ad; Il ❑ Return Receipt (hardcopy) $ ILII E]RReturnReceipt (electronic) $ O O []Certified Mail Restricted Delivery $ 0 ❑Adult Signature Required $ ❑ Adult Signature Restricted Delivery $ E3 Postage 9590 9403 0910 5223 5233 55 2AdultSignature iCertifed Mair O Certifed Mail Restricted Delivery Delivery El Return Receipt for °-3 Total Postage and Fees 2. Article Number Transfer from service label) as appropnate) Postmark Here $ Mr. David Wilkins Ln Sent To Senior Vice President E3 O-------------- ------------------- Hilcorp Alaska, LLC r` __________________ 3800 Centerpoint Dr., Ste. 1400 c;iy, sraie; zia+a® Anchorage, AK 99503 ■ Complete items 1, 2, and 3. A. Signature ■ Print your name and address on the reverse X�d•e so that we can return the card to you. CCCceived �2 ■ Attach this card to the back of the mailpiece, B. Received by (Printed Name) or on the front if space permits. C '�G Mr. David Wilkins Senior Vice President Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 D. is delivery address different N If YFS, ente JelivUdclress ❑ Agent 0 Addressee C. Date of Delivery item 1? 13 Yes .low: ❑ No 3. Service Type 17 Priority Mail Express® Ill II III II Ill ❑ Adult Signature L1 Registered MaiITM Il I IIIIII ILII I'I I I I I I I I l II llllll I Restricted Delivery 0 Registered Mail Restricted 9590 9403 0910 5223 5233 55 2AdultSignature iCertifed Mair O Certifed Mail Restricted Delivery Delivery El Return Receipt for ❑ Collect on Delivery ❑ Collect on Delivery Restricted Delivery Merchandise ❑ Signature Confirmation T"' ❑ Signature Confirmation 2. Article Number Transfer from service label) 7 015 0640 0006 0779 5838 ed Mail 'ed Mail Restricted Delivery Restricted Delivery $500) PS Form 3811, July 2015 PSN 7530-02-000-9053 Domestic Return Receipt 12 Hilcorp Alaska, LLC November 20, 2015 Cathy Foerster Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501-3572 RECEIVE U NOV 2 0 2015 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 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, 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 Daviilkins Senior Vice President cc: Brewster H. Jamieson 11 jN LANE POWELL ATTORNEYS & COUNSELORS +CED NOV 2 0 2015 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 BREWSTER H. JAMIESON 907.264.3325 jamiesonb@lanepowell.com 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. BHJ:lg 1293 87.0002%6491743.1 www.lanepowell.com T. 907.277.9511 F. 907.276.2631 Very truly yours, LANE POWELL LLC 7� Brewster H. amieson A PROFESSIONAL CORPORATION SUITE 301 301 W. NORTHERN LIGHTS BLVD. ANCHORAGE, ALASKA 99503-2648 LAW OFFICES ANCHORAGE, AK . PORTLAND, OR SEATTLE, WA. LONDON, ENGLAND 10 TILE STATE 9101111wa's . GOVERNOR BILL WALKER November 12, 2015 CERTIFIED MAIL — RETURN RECEIPT REQUESTED 7015 0640 0006 0779 5982 Mr. David Wilkins Senior Vice President Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket No. OTH-15-025 Failure to Notify of Changes to an Approved Permit Failure to Maintain a Safe Work Environment Hilcorp Rig ASRI MPU J -08A (PTD 1991170) Dear Mr. Wilkins: Alaska Oil 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.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 25.507 ("Change of an approved program") while performing workover operations with Automated Service Rig #1 (ASRI) at Milne Point Unit (MPU) well J -08A. Hilcorp has also violated the provisions of 20 AAC 25.526 ("Conduct of operations") by failing to follow "good oilfield engineering practices" during those workover operations. In addition, Hilcorp has violated the provisions of 20 AAC 25.285 ("Secondary well control for tubing workover operations: blowout prevention equipment requirements") by failing to report blowout prevention equipment test results within five days. Basis for Finding the Violation or Noncompliance (20 AAC 25.535(b)(2)). Hilcorp ASRI commenced workover operations at MPU J -08A on September 24, 2015. Sundry approval 315-527 dated August 31, 2015 authorized Hilcorp to pull a failed electric submersible pump (ESP) and rerun a new ESP completion. As part of the workover procedure, a fill cleanout step was included prior to running the new ESP and 2 -7/8 -inch production tubing. Only seawater was referenced in the sundry work procedure for the planned fill cleanout. Daily Notice of Proposed Enforcement November 12, 2015 Page 2 of 7 reports for September 24-25, 2015 show the following well work was completed in preparation for the fill cleanout: ESP completion had been removed; a fill cleanout string was run in the well to 6535 feet measured depth consisting of 3395 feet of 2 -3/8 -inch workstring and 3140 feet of 2- 7/8 -inch tubing; the annular preventer was closed on the 2 -7/8 -inch tubing; equipment was rigged up to perform the fill cleanout. The fill cleanout began pumping operations at 2:30 am on September 25, 2015. Hilcorp notified AOGCC on September 25, 2015 of an incident at MPU J -08A which occurred earlier that day while performing a well cleanout with nitrogen. The incident was described as follows: - three ASRl personnel were reported to have been "overcome by something" in the enclosed mud trailers and were evacuated from the rig; - well status is shut-in; - a safety shut down has been imposed on the rig; - fluid returns from the well cleanout operation were designed to flow to outside tanks staged near the well; - investigation is underway. An AOGCC Inspector was sent to the location on September 25, 2015 to gather information about the workover operation and incident. Upon arrival he interviewed Hilcorp's Wellsite Manager and others, checked records, observed how equipment was staged at the location, noted the position of choke manifold and blowout preventer stack valve positions, and attempted to determine the flowback piping arrangement from the well to the storage tanks (external and inside the mud trailer). The intended fill clean out approach was described to the AOGCC Inspector as pumping nitrogen and seawater to displace the well followed by 100 barrels of seawater pumped in two 50 -barrel increments.2 The Inspector's review of the ASRI rig files confirmed that the work procedure was the same as was attached to the AOGCC's approved sundry. There was no written procedure available at the location that detailed the fill cleanout operation. Reports show that Halliburton finished pumping the nitrogen at 6:30 am September 25, 2015 and was released from the location before the AOGCC Inspector arrived. The AOGCC Inspector was also told the three injured workers had been evacuated from the location for further medical evaluation and had been released to go back to work. t ASR mud trailer is a fully enclosed module consisting of mud tanks, fluid management equipment, and mud pumps. Mud tanks are housed in a separate from the choke and kill manifolds. A gas buster was also located inside the mud trailer with gas vent piped through the roof to outside. 2 The well cleanout was designed to pump down the tubing -casing annulus with return flow to surface up the tubing (workstring) to an external flow back tank. Records of the cleanout operations indicate 200,000 standard cubic feet of nitrogen were pumped on 9/25/2015 (Halliburton Job Log #902780922) and that was mixed with 207 barrels of 8.5 pounds per gallon seawater (Hilcorp's Comprehensive List of Causes; Incident Investigation Events Sequencing Chart). Hilcorp reports that the first 50 -barrel seawater pill was successfully pumped (Hilcorp's Internal Incident Investigation). Unexpected pressure was encountered after pumping approximately 4 barrels of the second 50 -barrel seawater pill causing rig personnel to shut down the pumping operation, and realign the flow path to bleed pressure from tubing -casing annulus of MPU J -08A. Records show the flow path was adjusted to allow the returning well bore fluids to flow through the choke manifold valves, gas buster and finally to tanks all within the enclosed mud trailer (instead of bleeding to the exterior tank). Notice of Proposed Enforcement November 12, 2015 Page 3 of 7 AOGCC notified Hilcorp by letter dated October 2, 2015 that it was investigating whether rig workover operations at MPU J -08A comported with the regulations. Information requested in the AOGCC letter was provided by Hilcorp on October 6, 2015. A second AOGCC request for information dated October 8, 2015 was responded to by Hilcorp on October 9, 2015. Hilcorp initially provided process and instrumentation diagrams for the fill cleanout of MPU J -08A on October 2, 2015. Diagrams that more accurately show the flow path for fluids pumped into and fluids returned from the well were provided on October 26, 2015. Hilcorp ASR1 was equipped with a gas buster located in the enclosed mud trailer above the mud tanks. A gas buster is a simple separator vessel used to remove free or entrained gas from fluids circulated in the wellbore, such as mud used during drilling operations. The gas buster typically comprises a vessel containing a series of baffles with a liquid exit on the bottom and a gas -vent line at the top of the vessel.3 Investigation revealed that the gas buster dump valve was left open during the MPU J -08A workover. The open valve provided a flow path for the nitrogen in the return fluids to enter the enclosed mud trailer and displace oxygen to a deadly level .4 5 Changes to an Approved Permit. Per 20 AAC 25.507 an operator may not undertake a change to an approved program or activity without AOGCC approval. Paragraph (a) of 20 AAC 25.507 further describes the information that must be submitted to AOGCC. To make a change, the well's current condition and proposed change must be provided to AOGCC for review and approval. Sundry 315-527 did not authorize the use of nitrogen for a cleanout out of MPU J - 08A. As part of AOGCC's information gathering related to MPU J -08A, Hilcorp states that the use of nitrogen for a fill cleanout is a contingent plan executed only if well conditions warrant.6 Good Oilfield Practices. The hazards associated with the commercial uses of nitrogen are well documented and readily available.7 Safety training programs and standardized safety procedures required for working in North Slope oilfield operations emphasize not only the hazards represented by nitrogen but also the good oilfield operating practices that should be employed when nitrogen is part of a work activity.8 9 Hilcorp failed adequately to identify the hazards, to assess the hazards, and to implement actions to mitigate the hazards, and in doing so failed to maintain a safe work environment during the fill cleanout operations. AOGCC notes the following deficiencies to good oilfield practices: - failure to engage in the formal hazards identification (process facilitated by hazards/risk experts) integral to the work planning process, including assessing the risks of using nitrogen in a fill cleanout on ASR1; 3 Schlumberger Oilfield Glossary; http:// lg ossaa.oilfield.slb.com; device is also commonly referred to as a "mud gas separator" or a "poor boy degasser" 4 U.S. Chemical Safety and Hazard Investigation Board, Safety Bulletin No.2001-10-13, Hazards of Nitrogen Asphyxiation; June 2003 5 North Slope Training Cooperative, Range of Oz Levels 6 Hilcorp correspondence dated October 9, 2015 U.S. Chemical Safety and Hazard Investigation Board, Safety Bulletin No.2001-10-13, Hazards of Nitrogen Asphyxiation; June 2003 'North Slope Training Cooperative, Range of O2 Levels 9 2014 Alaska Safety Handbook; adopted by Hilcorp for North Slope operations (October 6, 2015 letter from Hilcorp to AOGCQ Notice of Proposed Enforcement November 12, 2015 Page 4 of 7 - failure to identify and implement safeguards to ensure personnel safety in the event of a nitrogen release for the fill cleanout operation; - 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; - failure to have in place a robust "Stop Work Authority" that was clearly understood and readily implemented by ASRI; - failure to provide a documented process for assessing and managing changes to approved sundries that potentially introduce new hazards or increase risk of existing hazards during a rig workover. Documentation of the job safety analyses reference the potential for an oxygen -deficient environment; the only mitigation identified was avoidance ("stay away from lines"; "stay away from nitrogen clouds"; "keep out of N2 areas"). Job safety assessments conducted on ASRI were not comprehensive enough to address the entire fill cleanout process (pumping nitrogen and seawater, and flowing back the wellbore fluids). The near deaths of three rig personnel indicate the job safety analyses and Hilcorp's oilfield practices were woefully inadequate to address nitrogen -related hazards and the controls necessary to prevent an exposure incident. The deficiencies noted above led to decisions based on assumptions rather than facts. The lack of audible gas alarms was interpreted by those assigned to work in the enclosed tank trailer as establishing the absence of any gas hazard (gas detection system capability was not understood). Despite symptoms from the initial exposure to the oxygen deficient atmosphere in the enclosed mud trailer, the same affected personnel returned to the trailer without taking appropriate precautions (testing the space with appropriate gas monitoring equipment). Exposure to the oxygen -deficient environment — which occurred because of the release of nitrogen from the open gas buster dump valve (valve position unknown) — resulted in three rig personnel losing consciousness. The events associated with subsequent entry into the oxygen -deficient space would have been fatal for three ASRI personnel except for one worker's good fortune to collapse into the fresh air environment outside of the enclosed trailer. Exposure could have been prevented. The job safety analysis is just one component of the larger commitment of a safety and health management system that are part of good oilfield practices.10 Responsibility for assuring rig operations comply with good oilfield practices rests with Hilcorp management and engineering staff. Blowout Prevention Equipment Testing. Hilcorp ASRI blowout prevention equipment was tested on September 24, 2015 representing the initial test after rigging up on MPU J -08A. AOGCC witness of the blowout prevention equipment test was waived. By regulation, blowout prevention equipment test reports must be provided to AOGCC within five days after completing the test. AOGCC received the required test report three days past due on October 2, 2015. 10 OSHA 3071, Job Hazard Analysis; U.S. Department of Labor, Occupational Safety & Health Administration (2002 Revised) Notice of Proposed Enforcement November 12, 2015 Page 5 of 7 The MPU J -08A violations are neither isolated nor innocent and are 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 ASR — would not pull the completion until the gas system was operational". Less than one hour after providing that notice to AOGCC, Hilcorp made the 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. This was done 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) Other 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 the incident at MPU J -08A. Hilcorp's conduct is inexcusable. 11 3) Failure to Report Use of Blowout Prevention Equipment — A rig workover performed with Nordic 3 in early May 2015 encountered the well flowing after running a packer in MPU I-03. The Weekly Operations Summary reports that the well was shut in and well pressures were monitored while waiting on additional fluid to kill the well. No report was filed with AOGCC describing the use of blowout prevention equipment to prevent the flow of fluids from the well. No record exists of Hilcorp testing the blowout prevention equipment that was used. 12 Proposed Action (20 AAC 25.535(b)(3)). On October 1, 2015 AOGCC ordered Hilcorp to suspend all rig workover operations until further notice. AOGCC developed a list of corrective actions imposed on Hilcorp prior to recommencing rig workover operations. The list was provided to Hilcorp on October 21, 2015 and followed up with a meeting on October 26, 2015. Hilcorp acceptance of the conditions was documented in responses dated October 27 and 28, 2015. Hilcorp was released to restart rig workover operations by email dated October 29, 2015 and reminded that AOGCC is performing a detailed review of 11 Other Order 80 12 20 AAC 25.285(f)(2) and (t)(8) Notice of Proposed Enforcement November 12, 2015 Page 6 of 7 existing approved well workover sundry applications. Hilcorp has been instructed to contact AOGCC before commencing workover operations on any well — regardless of a past approval. For violating 20 AAC 25.507, 20 AAC 25.526, and 20 AAC 25.285 the AOGCC intends to impose civil penalties on Hilcorp under AS 31.05.150(a) as follows: - $100,000 for changing the work procedure in Sundry approval 315-527 - performing the cleanout of MPU J -08A using an unapproved contingent plan (nitrogen); - $600,000 for failure to maintain a safe work environment in accordance with good oilfield engineering practices. Included are: o $100,000 for failure to engage in the formal hazards identification; o $100,000 for failure to identify and implement safeguards to ensure personnel safety in the event of a nitrogen release; o $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; o $100,000 for failure to have in place a robust "Stop Work Authority" that was clearly understood and readily implemented by ASR I; o $100,000 for failure to assess and manage changes that potentially introduce new hazards or unknowingly increase risk of existing hazards during a rig workover, and o $100,000 for inadequate training of personnel on ASR1. - $20,000 for failing to provide the results of a blowout prevention test to AOGCC within five days after completing the test on September 24, 2015. Included is $10,000 for the initial event and $5,000 per day for the remaining two days that elapsed until the test report was received. The total proposed civil penalty is $720,000. In addition to the potential severity of the outcome of Hilcorp's actions, Hilcorp's ongoing history of performing work outside of approved permits or management -of -change protocols, its history of compliance issues and the need to deter are factors in the AOGCC's analysis. 13 In imposing this penalty, the AOGCC notes a prior penalty of $115,000 (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 is AS 31.05.150(g) requires AOGCC to consider nine criteria in setting the amount of a civil penalty. Notice of Proposed Enforcement November 12, 2015 Page 7 of 7 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 11th 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 Postal - CERTIFIED o RECEIR ru Domestic o-11 M-71 U-); Er s r\, Certified Mail Fee r� $ 0 Extra Services & Fees (check box, add tee as appropriate) ❑ Return Receipt (hardcopy) $ 0 ❑ Return Receipt (electmnlc) $ Postmark O El Mail Restricted Delivery $ Here C3 E] Adult Signature Required $ ❑ Adult Signature Restricted Delivery $ O Postage $ - 0 Total Postage and Fees C3 $ Mr. David Wilkins Ln Sent To Senior Vice President rq c3 Street and Apt: No., or PO Box Nc Hilcorp Alaska, LLC r` ______________ 3800 Centerpoint Dr., Ste. 1400 City State, ZIP+4® . Anchorage, AK 99503 SENDER:. •N COMPLETE THIS SECTIONON DELIVERY ■ Complete items 1, 2, and 3. A. Si ure ■ Print your name and address on the reverse ❑ Agent so that we can return the card to you. ❑ Addressee ■ Attach this card to the back of the mailpiece, B ed by (rinte Na 11C. pat of De'very f/ or on the front if space permits. % ± 7 6- 1 ' "''''---A ,^' D. Is delivery address differ t fro em 1? ❑ Yes If YES, enter delivery add elow: ❑ No Mr. David Wilkins ESQ •' t fif L;1 Senior Vice President Hilcorp Alaska, LLC NOV 19 2015 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 3. S2rVIC y ❑ Priority Mail Express® II "IIII I'I'I ❑ Adult Signature ❑ Registered MaiIT II II I III I II II I II I IIII I I IIII ❑ Adult Signature Restricted Delivery ❑ Registered Mail Restricted fd�Certified Mail® Delivery 9590 9401 0057 5071 0132 15 D Certified Mail Restricted Delivery H Return Receipt for ❑ Collect on Delivery Merchandise 2. Article Number (Transfer from service label) ❑ Collect on Delivery Restricted Delivery El Signature Confirmation— Ared Mail ❑ Signature Confirmation ?015 0640 0006 0779 5982 tred Mail Restricted Delivery Restricted Delivery r $500) PS Form 3811, April 2015 PSN 7530-02-000-9053 Domestic Return Receipt Carlisle, Samantha J (DOA) From: Carlisle, Samantha J (DOA) Sent: Thursday, November 12, 2015 3:02 PM To: David Wilkins Cc: Foerster, Catherine P (DOA); Seamount, Dan T (DOA); Regg, James B (DOA) Subject: OTH-15-025, Notice of Proposed Enforcement Attachments: Hilcorp OTH-15-025, Notice of Proposed Enforcement.pdf Importance: High Dear Mr. Wilkins, Please see the attached regarding Docket Number: OTH-15-025, Notice of Proposed Enforcement. Thank you, Samantha CarCrsCe Eve c-IiIi ve SecreIarti/ II lfc�. l a Oi "I'll f't7as lst:l,rI'a Iicrtl C'trt��.t7t�issiorl ,33 1.Wcst 7;" 1:V01'1110 1:rti3iartt Ie, 1.'Ii sat) t?I (01);7) l g -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.Carlisle((!)alaska.a)v. Regg, James B (DOA) From: Regg, James B (DOA) Sent: Thursday, October 29, 2015 4:34 PM To: John Barnes; David Wilkins Cc: Foerster, Catherine P (DOA); Seamount, Dan T (DOA); Schwartz, Guy L (DOA) Subject: RE: Supplemental Information Hilcorp may proceed with its rig workovers. As a reminder, AOGCC initiated a review (ongoing) of all approved Sundry applications at the same time rig workovers were suspended. Make sure you check the status of our review before commencing rig workover activities on a well. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501. 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or jim.regg @alaska.gov. From: Betty Veldhuis [mailto:bveldhuis@hilcorp.com] Sent: Wednesday, October 28, 2015 3:45 PM To: Foerster, Catherine P (DOA); Regg, James B (DOA) Cc: John Barnes; David Wilkins Subject: Supplemental Information Hi Cathy and Jim: Here is some additional information to Hilcorp's response. Please let me know if you need anything else. Thanks, Betty Betty J. Veldhuis ( Executive Assistant I Hilcorp Alaska, LLC 0: 907-777-8370 C C: 907-230-4788 1 bveld.huis@hilcorp.com 3800 Centerpoint Dr., Ste 1400 ( Anchorage I AK ( 99503 1 Regg, James B (DOA) From: Betty Veldhuis <bveldhuis@hilcorp.com> Sent: Wednesday, October 28, 2015 3:45 PM To: Foerster, Catherine P (DOA); Regg, James B (DOA) Cc: John Barnes; David Wilkins Subject: Supplemental Information Attachments: Supplemental Information to AOGCC 10-28-15.pdf Hi Cathy and Jim: Here is some additional information to Hilcorp's response. Please let me know if you need anything else. Thanks, Betty Betty J. Veldhuis 0 Executive Assistant I Hilcorp Alaska, LLC O: 907-777-8370 C: 907-230-4788 1 bveldhuis@hilcorpcom 3800 Centerpoint Dr., Ste 1400 1 Anchorage I AK 199503 1 David5. Wilkins Hilcorp Alaska, LLC Senior vice President Post Office Box 244027 Anchorage, AK 99524-4027 October 28, 2015 Cathy P. Foerster Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, AK 99501-3572 Re: Docket Number: OTH-15-025 Restart of Hilcorp Rig Workovers, Conditions for Hilcorp to restart rig workover (RWO) ops dated 21 October 2015 Hilcorp Alaska ASR -1 Rig MPU J -08A (PTD 1991170, Sundry 315-527)) Dear Chair Foerster: 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 We provide below additional clarification related to Conditionl of AOGCC's 21 October 2015 "Conditions for Hilcorp to restart rig workover (RWO) ops" regarding the safety incident Hilcorp Alaska, LLC (Hilcorp Alaska) experienced on 25 September 2015, while performing workover operations with the Automated Service Rig 1 (ASR 1) at Milne Point Unit well J -08A. 1. AOGCC's Condition: Establish a single Hilcorp Alaska person responsible for .RWO's; this individual would be the signature authority that certifies info provided in a workover Sundry application is true, work will be conducted in accordance with AOGCC regulations, orders, and conditions of approval, and that the Sundry information will not be altered except as approval by AOGCC. Hilcorp Alaska's Response: For Hilcorp Alaska, the Operations Manager for each asset team is the individual responsible for all aspects of well work, including rig workovers. This individual will sign Sundry applications certifying information provided in a workover Sundry application is true, work will be conducted in accordance with AOGCC regulations, orders, and conditions of approval, and that the Sundry information will not be altered except as approved by AOGCC. Thank you for the opportunity to supplement our earlier submission. Sincerely, David S. Wi ins cc: John Barnes David S. Wilkins Hilcorp Alaska, LLC Senior Vice President Post Office Box 244027 Anchorage, AK 99524-4027 October 27, 2015 Cathy P. Foerster Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, AK 99501-3572 Re: Docket Number: OTH-15-025 Restart of Hilcorp Rig Workovers, Conditions for Hilcorp to restart rig workover (RWO) ops dated 21 October 2015 Hilcorp Alaska ASR -1 Rig MPU J -08A (PTD 1991170, Sundry 315-527)) Dear Chair Foerster: 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 We respond to the AOGCC's 21 October 2015 "Conditions for Hilcorp to restart rig workover (RWO) ops" regarding the safety incident Hilcorp Alaska, LLC (Hilcorp Alaska) experienced on 25 September 2015, while performing workover operations with the Automated Service Rig 1 (ASR 1) at Milne Point Unit well J -08A. 1. AOGCC's Condition: Establish a single Hilcorp Alaska person responsible for RWO's; this individual would be the signature authority that certifies info provided in a workover Sundry application is true, work will be conducted in accordance with AOGCC regulations, orders, and conditions of approval, and that the Sundry information will not be altered except as approval by AOGCC. Hilcorp Alaska's Response: Hilcorp Alaska currently designates an operations engineer as a "first contact" and "second contact" for all sundry submittals. The "first contact" is the responsible engineer to ensure the sundry is accurate and contains adequate detail and is the single Hilcorp Alaska person responsible for the rig workover (RWO) sundry. In addition to this existing organizational structure, Hilcorp Alaska will add the operations managers for the respective teams (i.e., Cook Inlet Offshore, Kenai, and North Slope) to the review and sign off of the sundry. The Operations Manager(s) is/are responsible for the execution of rig workovers and this addition will formalize the responsibility for all aspects of rig workovers under the Operations Managers. Cathy P. Foerster Docket Number: OTH-15-025 October 27, 2015 Page 2 of 5 2. AOGCC's Condition: Provide detailed operations procedures in the Sundry applications. Hilcorp Alaska's Response: Hilcorp Alaska will provide detailed operations procedures in our sundry applications. The level of detail will be tailored to meet AOGCC's requests and appropriate to the complexity of the planned work. The approved sundry will be utilized in the field as the procedural steps for the well work. 3. AOGCC's Condition: Sundry applications that have pumping operations as part of the rig workover must include proposed piping/fluid path diagrams (include valve positions) and list of all fluids to be pumped. Hilcorp Alaska's Response: Hilcorp Alaska will incorporate piping and fluid path diagrams as well as a list of all fluids to be pumped into our sundry submittals. The fluid path diagrams will include valve positions and flow paths. An example of a reverse circulating fluid path diagram for the ASR 1 is included in the attachments. Hilcorp Alaska will follow the procedure revision change management protocol discussed below in Item 5 if an approved fluid is changed. 4. AOGCC's Condition: Prior written approval from AOGCC is required for changes to an approved Sundry. Hilcorp Alaska's Response: Concur. Hilcorp Alaska will follow the procedure revision change management protocol discussed below in Item 5 and receive written approval from AOGCC prior to executing a change in an approved sundry procedure. Changes may be made without written approval in specific emergent cases involving well control or other situations involving personnel or facility safety. If this occurs, verbal notification with follow-up written notification will occur as soon as circumstances allow. Cathy P. Foerster Docket Number: OTH-15-025 October 27, 2015 Page 3 of 5 5. AOGCC's Condition: Develop and provide a documented management -of -change process applicable to rig workovers. Hilcorp Alaska's Response: Hilcorp Alaska will utilize the procedure revision change management protocol attached to this response. This protocol is the same process and similar document that Hilcorp Alaska's drilling department implemented in 2012 at the request of AOGCC. This document will be included in the sundry submittal and will be a working document for the Hilcorp Alaska team. It is Hilcorp Alaska's understanding that AOGCC does not require the completed MOC form to be submitted with the 10-404. 6. AOGCC's Condition: There must be a different Wellsite (Rig) Supervisor per work shift on all Hilcorp- operated rigs. Hilcorp Alaska's Response: Hilcorp Alaska will add a wellsite supervisor per work shift for all work over rigs. 7. AOGCC's Condition: Train rig personnel in hazard identification, rig safety systems and their capabilities, proper response to potentially hazardous conditions, and Hilcorp's "Stop Work Authority"; provide documentation of training materials and list of who has been trained. Hilcorp Alaska's Response: Hilcorp Alaska and rig crew's parent companies have trained their staff in hazard identification, rig safety systems and their capabilities, proper response to potentially hazardous conditions, and Hilcorp Alaska's "Stop Work Authority". Specifically, Stop Work Authority is communicated in ASH training for North Slope workers and reinforced in Hilcorp Alaska provided site specific training, campaign kickoff meetings, and daily tailgate and JSA discussions for North Slope and Cook Inlet workers. Hilcorp Alaska also conducts "boot camp" training for employee and contract staff that focuses on hazard identification, job planning, and permit requirements. The training consists of 8 x 1 hour each modules (8 hours total). An example slide deck of the Cathy P. Foerster Docket Number: OTH-15-025 October 27, 2015 Page 4 of 5 "Permit" module is attached for reference. This training is generally offered approximately 10 times a year throughout our Alaska operations. Representative training rosters are also attached. In addition to the "boot camp" 8 -hour training, Hilcorp Alaska also conducts specific hazard identification training focusing on the "hazard wheel" and identifying common industry hazards. This training class is approximately 90 minutes and includes a practical JSA exercise and examples of quality JSAs. The training slides are attached for reference. This training class is offered approximately 5 times a year throughout our Alaska operations. Representative training rosters are also attached. 8. AOGCC's Condition: Post at appropriate locations in rig modules Hilcorp's "Stop Work Authority" policy and procedure. Hilcorp Alaska's Response: Hilcorp Alaska will post additional posters detailing every worker's obligation to utilize Stop Work Authority as necessary. 9. AOGCC's Condition: Provide Hilcorp's current RWO schedule for Cook Inlet and North Slope rigs (include rig; well; start date; simple description of the type of workover — e.g., replace ESP; prep for sidetrack; etc.); provide the updated schedule at least monthly. Hilcorp Alaska's Response: Hilcorp Alaska will provide the current RWO schedules for Cook Inlet and the North Slope every two weeks to AOGCC. Views of the current Cook Inlet Offshore and North Slope schedules are included in the attachments. The Kenai Asset Team currently does not have any planned work overs. Cathy P. Foerster Docket Number: OTH-15-025 October 27, 2015 Page 5 of 5 10. AOGCC's Condition: Workover rigs not currently working will be inspected by AOGCC prior to commencing work with a focus on winterization (equipment suitable to reliably operate under the range of weather conditions that may be encountered at the location); written rig -specific BOPE testing procedures that account for subfreezing conditions; operations and property maintenance conducted in a safe and skillful manner in accordance with good oilfield engineering practices Hilcorp Alaska's Response: Hilcorp Alaska will coordinate with AOGCC for an inspection time for the workover rigs prior to re -commencing activities. Should you have any questions, please let us know. Sincerely, HILCORP ALASKA, LLC David S. WiYkins cc: John Barnes Carlisle, Samantha J (DOA) From: Sent: To: Subject: Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 Regg, James B (DOA) Thursday, October 29, 2015 9:33 AM Carlisle, Samantha J (DOA) FW: Meeting notes - Hilcorp Restart of RWO's CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or jim.regg@alaska.gov. From: Bo York [mailto:byork@hilcorp.com] Sent: Monday, October 26, 2015 5:28 PM To: Regg, James B (DOA); John Barnes Subject: RE: Meeting notes - Hilcorp Restart of RWO's Thanks Jim for sending this out promptly. I hope to have response letter back to you tmrw. Bo York Operations Manager, Milne Point byork@Hilcorp.com 907.777.8345 907.727.9247 cell From: Regg, James B (DOA) [mailtoJim.regg@alaska.gov] Sent: Monday, October 26, 2015 3:58 PM To: John Barnes; Bo York Subject: Meeting notes - Hilcorp Restart of RWO's Attached reflects what we heard during this morning's meeting. Please review and provide any clarification or suggested changes. Thank you. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or jim.regg@alaska.gov. Carlisle, Samantha J (DOA) From: Sent: To: Subject: Attachments: Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 Regg, James B (DOA) Thursday, October 29, 2015 9:32 AM Carlisle, Samantha J (DOA) FW: Meeting notes - Hilcorp Restart of RWO's 2015-1026 meeting notes - Restart of Hilcorp Rig Workovers.docx CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or jim.regg@alaska.gov. From: Regg, James B (DOA) Sent: Monday, October 26, 2015 3:58 PM To: John Barnes; Bo York Subject: Meeting notes - Hilcorp Restart of RWO's Attached reflects what we heard during this morning's meeting. Please review and provide any clarification or suggested changes. Thank you. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.regg@alaska.gov. Restart of Hilcorp Rig Workovers — Meeting Notes 10/26/2015; 1000hrs Meeting was held at AOGCC offices (333 W. 7th Avenue, Anchorage, AK) to discuss the 10 conditions imposed on Hilcorp for the restart of rig workovers (email dated 10/21/2015). The meeting was attended as follows: HilcoKp AOGCC John Barnes Jim Regg Bo York Guy Schwartz Chad Helgeson Jody Colombie Chet Starkel Ted Kramer Condition 1 - Establish a single Hilcorp person responsible for RWO's; this individual would be the signature authority that certifies info provided in a workover Sundry application is true, work will be conducted in accordance with AOGCC regulations, orders, and conditions of approval, and that the Sundry information will not be altered except as approval by AOGCC Discussion - Wording in condition is in part a preview of changes that will be implemented to Form 10-403, Application for Sundry Approval - Clarified this is only addressing rig workovers - Hilcorp raised concerns about frequent changes due to "discovery " while performing rig workovers — different than drilling (drilling changes tend to be major; workovers can range from minor changes to major) - Questions from Hilcorp included if this condition was designed for administrative (signature) or operational (one person tracking all workover operations) purposes — AOGCC intent is both administrative and operational o Hilcorp mentioned role of 1 St and 2" d call engineers — AOGCC is not looking to change the day-to-day operations interaction among engineering staffs - AOGCC mentioned emulating how drilling operations are handled by Hilcorp (dedicated Drilling Manager); single authority responsible for all drilling operations - Hilcorp assets are currently organized into 3 teams: North Slope; Cook Inlet Offshore; Cook Inlet Onshore; can there be 3 separate single points of contact? Hilcorp can make that proposal for AOGCC consideration; important point here is a consistent approach to sundry applications, details included in sundry applications, reports, and a single authority (potentially 1 per Team) that provides both consistency and accuracy Condition 2 - Provide detailed operations procedures in the Sundry applications Discussion - Hilcorp confirmed it has a more detailed operations procedure for the rig than what is submitted to AOGCC in the Sundry application - Should submit the same procedure that is going to the rig (warned about the pitfalls of maintaining procedures with differing levels of detail) - Include contingencies (e.g., alternate BOPE test procedure) Meeting Notes — Restart of Hilcorp Rig Workovers 10/26/2015 Page 2 of 4 Pumping operations need to be more detailed — refer to Condition 3 Standardize the level of detail in procedures for both North Slope and Cook Inlet workovers Condition 3 - Sundry applications that have pumping operations as part of the rig workover must include proposed piping/fluid path diagrams (include valve positions) and list of all fluids to be pumped Dkcn-,aion Discussion carried over from previous (details included in Sundry application) AOGCC is ok with less detailed drawings (flow schematic) instead of process and instrumentation diagrams; must show the valve positions in addition to flow direction Regarding questions about the status of existing approved Sundry applications, AOGCC did not rescind any approvals. All approved sundries that have yet to start work will need to be supplemented with additional details per Condition 2 and 3. Hilcorp should check with AOGCC before commencing work under an existing sundry. Condition 4 - Prior written approval from AOGCC is required for changes to an approved Sundry Condition 5 - Develop and provide a documented management -of -change process applicable to rig workovers Discussion - Conditions 4 and 5 combined for discussion purposes - Things change more frequently with workovers than for drilling operations - AOGCC has 3 points of contact for Hilcorp workovers available by phone and email 24 hours per day — primary contact is Guy Schwartz; secondary contacts are Victoria Loepp and Jim Regg. - 20 AAC 25.507 provides for verbal approvals; Form 10-403, Application for Sundry Approval may be required (submit within 3 days after verbal approval is granted) - Hilcorp is amending its Management -of -Change procedure to be inclusive of workover changes - Hilcorp referred to and provided a DRAFT copy of a form titled "Changes to Approved Sundry Procedures for Well XX -XX" o A blank copy will be attached to the Sundry Application; filled out copy will be attached to the Report of Sundry Operations (Form 10-404) Condition 6 - There must be a different Wellsite (Rig) Supervisor per work shift on all Hilcorp- operated rigs Discussion - Clarified this applies to both North Slope and Cook Inlet operations - Note — Well Site Supervisor term is interchangeable with Well Site Manager; Drill Site Supervisor, Rig Manager, Company Man, etc. - No provisions intended for a single Well Site (Rig) Supervisor (simple rig workovers) Meeting Notes — Restart of Hilcorp Rig Workovers 10/26/2015 Page 3 of 4 - Hilcorp has hired 2 new Well Site Supervisors for its Automated Services Rig #1 working at Milne Point o Don Haberthur (days) and Craig Smith (nights); both have previous experience at Milne Point working on Nabors 4ES Condition 7- Train rig personnel in hazard identification, rig safety systems and their capabilities, proper response to potentially hazardous conditions, and Hilcorp's "Stop Work Authority "; provide documentation of training materials and list of who has been trained Condition 8- Post at appropriate locations in rig modules Hilcorp's "Stop Work Authority " policy and procedure Discussion - Conditions 7 and 8 combined for discussion purposes - Hilcorp attendees expressed confusion about what AOGCC is requesting; per Hilcorp: o Rig personnel working for Hilcorp already receive a safety orientation that includes Hilcorp procedures, the Alaska Safety Handbook, and normal oilfield hazards o Contractors are responsible for training their employees (e.g., North Slope Training Cooperative; Hazardous Waste Operations and Emergency Response) o A Job Safety Analysis (JSA) is performed at the rig (targets the hazards associated with specific task) Hilcorp describes its JSA as a process to identify hazards, steps to mitigate the hazards, signed by all participants before starting job; referred to a specific form to document o Well Site Supervisor is responsible for making sure the JSA is properly documented For the nitrogen pumping operation at Milne Point Unit well J -08A, Halliburton led the JSA for both night and day crews Process seems to place the burden on field personnel to be able to identify the potential hazards associated with a particular job thus the reason for this condition o Do personnel involved the particular job have related experience to be able to identify the hazards? o Is the JSA sufficiently in-depth to assess the hazards? o Assumes that any change to the procedure will result in pause to reassess; o Too much reliance on a "Stop Work" authority, especially if the rig crew doesn't identify the potential hazards in the field (during JSA) Hilcorp should explain what they are currently doing for training personnel; assess the adequacy of current JSA's; strengthen its Stop Work authority and train personnel in how it is supposed to work. Condition 9 - Provide Hilcorp's current RWO schedule for Cook Inlet and North Slope rigs (include rig; well; start date; simple description of the type of workover — e.g., replace ESP; prep for sidetrack; etc.); provide the updated schedule at least monthly Discussion - No questions regarding the work schedule; will be provided as requested Meeting Notes — Restart of Hilcorp Rig Workovers 10/26/2015 Page 4 of 4 Condition 10 - Workover rigs not currently working will be inspected by AOGCC prior to commencing work with a focus on winterization (equipment suitable to reliably operate under the range of weather conditions that may be encountered at the location); written rig -specific BOPS testing procedures that account for subfreezing conditions; operations and property maintenance conducted in a safe and skillful manner in accordance with good oilfield engineering practices Discussion - Clarified that Moncla 404 (Granite Point Field Anna Platform; well 46) and Rig 56 (on Trading Bay Unit Monopod platform; well A-4) inspections will be done in conjunction with AOGCC's witness of the initial BOPE tests when these rigs restart. Regg, James B (DOA) From: Donald Haberthur - (C) <dhaberthur@hilcorp.com> Sent: Wednesday, October 28, 2015 8:30 AM To: Regg, James B (DOA); DOA AOGCC Prudhoe Bay; Schwartz, Guy L (DOA) Cc: Stan Porhola Subject: STOP Work Authority placards I I , Attachments: Change house.jpg; Gas Buster in pits jpg; Rig Floorjpg; Rig Manager Office.jpg; Rig Mangager Trailerjpg Attached are the pictures throughout the Rig of STOP work Authority placards. Don Haberthur ASR Rig 1 907-398-3915 Stop Work Authority Placards — Hilcorp Automated Services Rig #1 Photos provided courtesy of Hilcorp 10/28/2015 AOGCC shut down Hilcorp rig workover activities in response to the MPU J -08A (PTD 1991170) injury incident (occurred while performing a fill cleanout with nitrogen). On October 21, 2015 AOGCC imposed 10 conditions for the restart of Hilcorp rig workover operations. Condition 8 stated: "Post at appropriate locations in rig modules Hilcorp's "Stop Work Authority" policy and procedure " The following pictures document placement of the Stop Work Authority placards on Hilcorp ASR I: Change house 2015-1028_Rig_HAK_ ASR 1 _stop -work -placards. docx Page 1 of 5 STOP WORK AUTHORITY STOP WORK IF: UNSURE UNSAFE r CONCERNED HAVE THE COURAGE TO SPEAK UP! IT IS YOUR RESPONSIBILITY YOU HAVE THE AU`fHORiTY YOU HAVE HILCORPS COMMITMENT TO YOLIti SAFETY g. Y -L AREA OPEGATIONS MA -G, u S1%_ OP[MTH)NS tkGw I k m -k O'M.44" -,IN, POINT MLO (m-,, t Gas Buster (in enclosed mud trailer tank room) 2015-1028_Rig_HAK_ ASR 1 _stop-work-placards.docx Page 2 of 5 0 STOP WORK AUTHORITY, STOP WORK IF: • UNSURE • UNSAFE , • CONCERNED 1 HAVE THE COURAGE TO SPEAK UP! IT IS YOUR RESPONSIBILITY } YOU HAVE THE AUTHORITY YOU HAVE HILCORPS COMMITMENT TO YOUR SAFETY E!n ("k. AArA OPIRArONS MAr,0ZER Sfe... P++r'f�6ia 6PFAAlFDN� ENGINEER eit+iDMa12.y MItNlMNTFIELD FOREMAN Urgency-Imegrlty. Innovation -Ownership-Alig n mem IL Rig floor 2015-1028_Rig_HAK_ASR 1 _stop -work -placards. doex Page 3 of 5 it STOP WORK AUTHORITY STOP WORK IF: • UNSURE • UNSAFE • CONCERNED HAVE THE COURAGE TO SPEAK UP IT IS YOUR RESPONSIBILITY YOU HAVE THE AUTHORITY YOU HAVE HILCORPS COMMITMENT TO YOUR SAFETY Str*, poykota_ OPERATIONS ENGINEER Be -York. AREA OPERATIONS MANAGER Mark, ®'Mau -j MILNE POINT FIELD FOREMAN U rgency- Integrity -Innovation -Ownership -Al ignment Rig Manager's office 2015-1028_Rig_HAK_ASR 1 _stop-work-placards.docx Page 4 of 5 i 10.lcorp Alaska.. LLC r WAI Rig Manager's trailer 2015-1028_Rig_HAK_ASR 1 _stop-work-placards.docx Page 5 of 5 David S. Wilkins Hilcorp Alaska, LLC Senior Vice President Post Office Box 244027 Anchorage, AK 99524-4027 October 27, 2015 Cathy P. Foerster Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, AK 99501-3572 Re: Docket Number: OTH-15-025 Restart of Hilcorp Rig Workovers, Conditions for Hilcorp to restart rig workover (RWO) ops dated 21 October 2015 Hilcorp Alaska ASR -1 Rig MPU J -08A (PTD 1991170, Sundry 315-527)) Dear Chair Foerster: 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 We respond to the AOGCC's 21 October 2015 "Conditions for Hilcorp to restart rig workover (RWO) ops" regarding the safety incident Hilcorp Alaska, LLC (Hilcorp Alaska) experienced on 25 September 2015, while performing workover operations with the Automated Service Rig 1 (ASR 1) at Milne Point Unit well J -08A. 1. AOGCC's Condition: Establish a single Hilcorp Alaska person responsible for RWO's; this individual would be the signature authority that certifies info provided in a workover Sundry application is true, work will be conducted in accordance with AOGCC regulations, orders, and conditions of approval, and that the Sundry information will not be altered except as approval by AOGCC. Hilcorp Alaska's Response: Hilcorp Alaska currently designates an operations engineer as a "first contact" and "second contact" for all sundry submittals. The "first contact" is the responsible engineer to ensure the sundry is accurate and contains adequate detail and is the single Hilcorp Alaska person responsible for the rig workover (RWO) sundry. In addition to this existing organizational structure, Hilcorp Alaska will add the operations managers for the respective teams (i.e., Cook Inlet Offshore, Kenai, and North Slope) to the review and sign off of the sundry. The Operations Manager(s) is/are responsible for the execution of rig workovers and this addition will formalize the responsibility for all aspects of rig workovers under the Operations Managers. Cathy P. Foerster Docket Number: OTH-15-025 October 27, 2015 Page 2 of 5 2. AOGCC's Condition: Provide detailed operations procedures in the Sundry applications. Hilcorp Alaska's Response: Hilcorp Alaska will provide detailed operations procedures in our sundry applications. The level of detail will be tailored to meet AOGCC's requests and appropriate to the complexity of the planned work. The approved sundry will be utilized in the field as the procedural steps for the well work. 3. AOGCC's Condition: Sundry applications that have pumping operations as part of the rig workover must include proposed piping/fluid path diagrams (include valve positions) and list of all fluids to be pumped. Hilcorp Alaska's Response: Hilcorp Alaska will incorporate piping and fluid path diagrams as well as a list of all fluids to be pumped into our sundry submittals. The fluid path diagrams will include valve positions and flow paths. An example of a reverse circulating fluid path diagram for the ASR 1 is included in the attachments. Hilcorp Alaska will follow the procedure revision change management protocol discussed below in Item 5 if an approved fluid is changed. 4. AOGCC's Condition: Prior written approval from AOGCC is required for changes to an approved Sundry. Hilcorp Alaska's Response: Concur. Hilcorp Alaska will follow the procedure revision change management protocol discussed below in Item 5 and receive written approval from AOGCC prior to executing a change in an approved sundry procedure. Changes may be made without written approval in specific emergent cases involving well control or other situations involving personnel or facility safety. If this occurs, verbal notification with follow-up written notification will occur as soon as circumstances allow. Cathy P. Foerster Docket Number: OTH-15-025 October 27, 2015 Page 3 of 5 5. AOGCC's Condition: Develop and provide a documented management -of -change process applicable to rig workovers. Hilcorp Alaska's Response: Hilcorp Alaska will utilize the procedure revision change management protocol attached to this response. This protocol is the same process and similar document that Hilcorp Alaska's drilling department implemented in 2012 at the request of AOGCC. This document will be included in the sundry submittal and will be a working document for the Hilcorp Alaska team. It is Hilcorp Alaska's understanding that AOGCC does not require the completed MOC form to be submitted with the 10-404. 6. AOGCC's Condition: There must be a different Wellsite (Rig) Supervisor per work shift on all Hilcorp- operated rigs. Hilcorp Alaska's Response: Hilcorp Alaska will add a wellsite supervisor per work shift for all work over rigs. 7. AOGCC's Condition: Train rig personnel in hazard identification, rig safety systems and their capabilities, proper response to potentially hazardous conditions, and Hilcorp's "Stop Work Authority"; provide documentation of training materials and list of who has been trained. Hilcorp Alaska's Response: Hilcorp Alaska and rig crew's parent companies have trained their staff in hazard identification, rig safety systems and their capabilities, proper response to potentially hazardous conditions, and Hilcorp Alaska's "Stop Work Authority". Specifically, Stop Work Authority is communicated in ASH training for North Slope workers and reinforced in Hilcorp Alaska provided site specific training, campaign kickoff meetings, and daily tailgate and JSA discussions for North Slope and Cook Inlet workers. Hilcorp Alaska also conducts "boot camp" training for employee and contract staff that focuses on hazard identification, job planning, and permit requirements. The training consists of 8 x 1 hour each modules (8 hours total). An example slide deck of the Cathy P. Foerster Docket Number: OTH-15-025 October 27, 2015 Page 4 of 5 "Permit" module is attached for reference. This training is generally offered approximately 10 times a year throughout our Alaska operations. Representative training rosters are also attached. In addition to the "boot camp" 8 -hour training, Hilcorp Alaska also conducts specific hazard identification training focusing on the "hazard wheel" and identifying common industry hazards. This training class is approximately 90 minutes and includes a practical JSA exercise and examples of quality JSAs. The training slides are attached for reference. This training class is offered approximately 5 times a year throughout our Alaska operations. Representative training rosters are also attached. 8. AOGCC's Condition: Post at appropriate locations in rig modules Hilcorp's "Stop Work Authority" policy and procedure. Hilcorp Alaska's Response: Hilcorp Alaska will post additional posters detailing every worker's obligation to utilize Stop Work Authority as necessary. 9. AOGCC's Condition: Provide Hilcorp's current RWO schedule for Cook Inlet and North Slope rigs (include rig; well; start date; simple description of the type of workover — e.g., replace ESP; prep for sidetrack; etc.); provide the updated schedule at least monthly. Hilcorp Alaska's Response: Hilcorp Alaska will provide the current RWO schedules for Cook Inlet and the North Slope every two weeks to AOGCC. Views of the current Cook Inlet Offshore and North Slope schedules are included in the attachments. The Kenai Asset Team currently does not have any planned work overs. Cathy P. Foerster Docket Number: OTH-15-025 October 27, 2015 Page 5 of 5 10. AOGCC's Condition: Workover rigs not currently working will be inspected by AOGCC prior to commencing work with a focus on winterization (equipment suitable to reliably operate under the range of weather conditions that may be encountered at the location); written rig -specific BOPE testing procedures that account for subfreezing conditions; operations and property maintenance conducted in a safe and skillful manner in accordance with good oilfield engineering practices Hilcorp Alaska's Response: Hilcorp Alaska will coordinate with AOGCC for an inspection time for the workover rigs prior to re -commencing activities. Should you have any questions, please let us know. Sincerely, HILCORP ALASKA, LLC David 5 Witkins cc: John Barnes Regg, James B (DOA) From: Bo York <byork@hilcorp.com> Sent: Monday, October 26, 2015 1:11 PM�l°1 To: Regg, James B (DOA) Subject: RE: Missing Info - ASR1 Incident Attachments: ASR P&ID_50 BBL FLUSH revl.pdf; ASR P&ID_Annulus Bleed revl.pdf; ASR P&ID_N2 Connection revl.pdf Jim - As I mentioned this morning, the previously attached drawings had an error in them. The "rev 1" drawings attached have been corrected. The previous drawings indicated there was a flow line from the "panic line" off the choke manifold to an "outside tank". That was misrepresented. There was no line plumbed in. Please let me know if you would like to walk through the drawings and flow paths. Bo York Operations Manager, Milne Point byork@Hilcorp.com 907.777.8345 907.727.9247 cell From: Bo York Sent: Monday, October 26, 2015 8:24 AM To: 'Regg, James B (DOA)' Subject: RE: Missing Info - ASR1 Incident Jim - Requested info is attached or answered below. The drawings are revised and I believe simplified to more easier depict the flow paths as requested. Valve status is depicted via the indicated flow path. We can go through them after this morning's 1000 meeting. The drawings are: o ASR P&ID N2 Connection — depicts flow path during N2 cleanout o ASR P&ID 50 bbl flush — depicts flow path during the 1" 50 bbl flush and the second attempted 50 bbl flush o ASR P&ID annulus bleed — depicts the flow path during the bleeding of the annulus after the second 50 bbl flush attempt o BOP schematic — details which valves were open/closed during the various steps of the work over Diameter and length of: o Tubing 3,140' of 2-7/8" o Work string 3,395' of 2-3/8" NSTC training roster attached. Individual cards can be supplied if necessary. Both Integrated Well Services and Rangeland Drilling personnel are listed on the roster. The pages in the ASH book are from the 2014 book. It is correctly shown as page 60 and 61 in the previously supplied submittal. There may be confusion if you are looking at an electronic version of the ASH book. In the .pdf copy, page 60 and 61 of the book are actually on page 69 and 70 of the .pdf document. Though the .pdf document still has the correct page numbers listed on the actual page (i.e., 60 and 61). The .pdf of the 2014 ASH book is also attached for your reference. I think this answers your question but am not sure since I am not sure where the confusion on this lays. Bo York Operations Manager, Milne Point byork@Hilcorp.com 907.777.8345 907.727.9247 cell From: Regg, James B (DOA) [mailto:jim.regg@Ccaalaska.gov] Sent: Friday, October 23, 2015 10:08 AM To: Bo York Subject: Missing Info - ASR1 Incident Hilcorp provided P&IDs related to ASR1 identified as a generic flow diagram (request was for non -cleanout workover ops), "Pumping Second 50 bbls of Seawater" (0848 hrs), and "Started to Bleed Annulus Pressure" (0856 hrs). Information relating to the pumping operations during the fill cleanout ops — in particular the P&IDs — is confusing. Also, Hilcorp has not provided all the pumping schematics that were previously requested (we also requested a "flow diagram for pumping nitrogen"). The following is requested: - Clarify the return path for fluids during each stage of the well cleanout. Was the fill cleanout normal (pump down tubing and flow up the IA) or reverse (pump down IA and returns up tubing)? - Provide schematics (as -configured drawings) showing the entire flow path of fluids pumped for each stage of the fill cleanout (N2 from Halliburton mixed with seawater; seawater pill #1; seawater pill #2); include valve positions in the flow path. Clearly state any valve position changes that occurred between pumping the nitrogen and seawater pill 1 and seawater pill 2 - Provide the position of BOP stack valves (annular; rams; choke and kill line valves) during pumping ops Additional info requested: What was the diameter and length of each — work string (bottom), and tubing (at surface) — used in the J -08A during cleanout? Provide copies of NSTC cards issued to the ASR 1 crew members Confirm version of the Alaska Safety Handbook referenced by Hilcorp in previously submitted documents. The page numbers in my copy of ASH 2014 do not match copied pages included in Hilcorp submittals. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or jim.regg@alaska.gov. 5 4 3 2 I 1 8 I 7 6 C B A jkka JC 1 yr vry GJ Vt_• • �� �+ -+•- ANNULUS BLEED OPERATIONS /r C!K IQ DATE @EVIfI[D0 DY CN( ENONMUIG � DATE DRAVD� �y N6 DATE REVIS�1 Dios BT 5 oo 09 15 IS91ED FOR 67 Mo+ Cwl APFI �, vsD r SCALE, HtLCORP ALASKA, LLC wx 5 4 3 2 8 7 6 WELL A8 MPU GEN PROCESS PIPING & INSTRUMENT DIAGRAM ASR -1 RIG &E DDAVDV. IDMQED -- PI-M00-000XX - 1 D C B A 8 I 7 6 I 5 4 ATM, Y£Ri KLL HOPPER BI II I AI I swum I 4 STAW WE I ML !BOLD _ I rurvre uro u AS SET UPON 25 SEPT 2015 ON J_08 III I�I i I I 1ST & 2ND STAGE 50 BBL FLUSH OPERATIONS WELL J-08 ENSDI03 DIG A£m Dh7E yp�yp�y on STs MPU GEN PROCESS mc" PIPING &INSTRUMENT DIAGRAM `p ASR -1 RIG APA VM PPS AEE WAVM WPM sc" HILCORP ALASKA, LLC PI—MOO-000XX NOPE "ME 3 I 1 ID IC IA i 2 1 B A MnS1W 8 7 6 5 4 N2 NUMF'INU UrtKH IIUlv�) KUM DATE BT 5 4R 11m ffiLCORP ALASKA, LLC l�F+ 3 WELL J-08 MPU GEN PROCESS PIPING & INSTRUMENT DIAGRAM ASR -1 RIG RK PACKADE MAWM NUMM I KV SHEET PI-M00-000XX 00 001 D6 1 2 1 D C B A 5 4 8 I 7 I lir i 2 1 B A MnS1W 8 7 6 5 4 N2 NUMF'INU UrtKH IIUlv�) KUM DATE BT 5 4R 11m ffiLCORP ALASKA, LLC l�F+ 3 WELL J-08 MPU GEN PROCESS PIPING & INSTRUMENT DIAGRAM ASR -1 RIG RK PACKADE MAWM NUMM I KV SHEET PI-M00-000XX 00 001 D6 1 2 1 D C B A Regg, James B (DOA) From: Bo York <byork@hilcorp.com> Sent: Monday, October 26, 2015 8:24 AM �lG I �ZL ��' To: Regg, James B (DOA) Subject: RE: Missing Info - ASR1 Incident Attachments: ASH 2O14.pdf, ASR P&ID_N2 Connection.pdf; ASR P&ID_50 BBL FLUSH.pdf; ASR P&ID_Annulus Bleed.pdf; BOP Schematic during N2 pumping Hilcorp ASR#1 ll.pdf; ASR NSTC Training Roster.pdf Jim - Requested info is attached or answered below. The drawings are revised and I believe simplified to more easier depict the flow paths as requested. Valve status is depicted via the indicated flow path. We can go through them after this morning's 1000 meeting. The drawings are: o ASR P&ID N2 Connection — depicts flow path during N2 cleanout o ASR P&ID 50 bbl flush — depicts flow path during the 1S` 50 bbl flush and the second attempted 50 bbl flush o ASR P&ID annulus bleed — depicts the flow path during the bleeding of the annulus after the second 50 bbl flush attempt o BOP schematic — details which valves were open/closed during the various steps of the work over Diameter and length of: o Tubing 3,140' of 2-7/8" o Work string 3,395' of 2-3/8" NSTC training roster attached. Individual cards can be supplied if necessary. Both Integrated Well Services and Rangeland Drilling personnel are listed on the roster. The pages in the ASH book are from the 2014 book. It is correctly shown as page 60 and 61 in the previously supplied submittal. There may be confusion if you are looking at an electronic version of the ASH book. In the .pdf copy, page 60 and 61 of the book are actually on page 69 and 70 of the .pdf document. Though the .pdf document still has the correct page numbers listed on the actual page (i.e., 60 and 61). The .pdf of the 2014 ASH book is also attached for your reference. I think this answers your question but am not sure since I am not sure where the confusion on this lays. Bo York Operations Manager, Milne Point byork@Hilcorp.com 907.777.8345 907.727.9247 cell From: Regg, James B (DOA) [mailtoJim.regg alaska.gov] Sent: Friday, October 23, 2015 10:08 AM To: Bo York Subject: Missing Info - ASR1 Incident Hilcorp provided P&IDs related to ASR1 identified as a generic flow diagram (request was for non -cleanout workover ops), "Pumping Second 50 bbls of Seawater" (0848 hrs), and "Started to Bleed Annulus Pressure" (0856 hrs). Information relating to the pumping operations during the fill cleanout ops — in particular the P&IDs — is confusing. Also, Hilcorp has not provided all the pumping schematics that were previously requested (we also requested a "flow diagram for pumping nitrogen"). The following is requested: - Clarify the return path for fluids during each stage of the well cleanout. Was the fill cleanout normal (pump down tubing and flow up the IA) or reverse (pump down IA and returns up tubing)? - Provide schematics (as -configured drawings) showing the entire flow path of fluids pumped for each stage of the fill cleanout (N2 from Halliburton mixed with seawater; seawater pill #1; seawater pill #2); include valve positions in the flow path. Clearly state any valve position changes that occurred between pumping the nitrogen and seawater pill 1 and seawater pill 2 - Provide the position of BOP stack valves (annular; rams; choke and kill line valves) during pumping ops Additional info requested: - What was the diameter and length of each — work string (bottom), and tubing (at surface) — used in the J -08A during cleanout? - Provide copies of NSTC cards issued to the ASR 1 crew members - Confirm version of the Alaska Safety Handbook referenced by Hilcorp in previously submitted documents. The page numbers in my copy of ASH 2014 do not match copied pages included in Hilcorp submittals. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or jim.reggPalaska.gov. 2 8 7 6 5 4 3 2 nn VW xonsx � D I w r----- ---, STNO PPL � I I eauTdl (T>P) � I -- -- __ L__ —KIL Iu1igD--J -------- I — 91CIIOII I � r MD TNK i 4 I I C I I I I I II CIL RW I I I I PA K u[ I I tlG P P IID 1RNEP — — — — — — I I J JS! 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Dmmac RYam a.Tt M»01 M B�diS MPU GEN PROCESS wa PIPING k INSTRUMENT DIAGRAM ASR -1 RIG ..�., vve rAnA¢ NMYND MAaoI NW HILCORPALAS" LLC PI—M00-000XX 4 3 �2 1 A A 8 7 6 5 4 3 Ari mw "WPM � D I wm e m I I U�+- nj-- "° °rc--u I I AmATa O+PI MLI Y 11 Y -- -- L---Idl ll/fipp--J su r------------1 i loo o , omem v4 TNef � I I I I c I I I II ae nAr I I,I i _I Poet LK CR Pow T WM TANK I se:tnx Ae"� � I I , — — Pup VAR — — N OR 1 ON 1' ANNULUS BLEED OPET; momomm it WELL Ja MPU GEN PROCESS PIPING & INSTRUMENT DIAGRAM ASR -1 RIG envtxG Y.oa PI—MDO-000XX 1 D C B A Milne Point 2015 ASR Rig 1 Knight Oil Tools BOP 11" BOPE Shaffer Bag was closed on 2-7/8" tubing during the N2 pumping, Two 50 Bbl flush & Annulus bleed 2-1/16" Kill line valves were open and the choke line 2-1/16" & HCR valves were closed during the N2 pump job and the ( 2 ) 50 Bbl flush pump jobs. 2-1/16" Kill line valves were closed and the choke line 2-1/16 & HCR valves were open during the annulus N2 bleed operations. DSA, 115M X71/16 5M (If Needed) Updated 8/19/15 7/8 -5 variables ind North Slope Training Cooperative 13MAPICC rte' Unescorted Training provMar. BaaaW OHSS instructor Na Ursa grin Data: wunru"Ur argna[ura: lnstructar NSTC 1D: EFH hks, oo H:S-FeS NO1'f3: 2/21%14-2014 SP ASH release &P ASH & ASH 006- - 4/7/14-2014 ASH release ti✓ V Books c,e b 00& f 4 b 006- Z.to24O O 006- - -- Student Full Nam (printed) S1 1 r t .Q 7 c�31iw•. M *'t. M 41 y.. t 10 12 iS is 16 �t7N1►YKRN (, .[ IS �... 17 is 19 L_ F 20 21 2: f 21 24 Company lnk IsInhiais�_ Beacon Student ID NSTC Card M jo- Z Zj c, wbZ-2bZ5) .INC, v� �r5t)1 006- 006.2 7-6 6 C Ye -0 ©1 006- - �a ►• �•• �..+ rr1 ls�t. T 1*'' ti✓ W (' 1 lu ori r v I W6- 006- 2 to Z, 006- 2(a c,e b 00& f 4 b 006- Z.to24O O 006- - -- 00& Z v-- 06- 006- 006- 006-006- W6- Ow Ow 006- . 006- 1 006- ► 006- Regg, James B (DOA) From: Stan Porhola <sporhola@hilcorp.com> Sent: Friday, October 23, 2015 4:00 PM ��� To: Regg, James B (DOA) Cc: Bo York; Schwartz, Guy L (DOA); DOA AOGCC Prudhoe Bay Subject: RE: Restart at HAK ASR1 Understood. We will provide the inspectors at least 24 hours notice for the rig inspection Stan From: Regg, James B (DOA) [mailto:jim.regg@alaska.aov] Sent: Friday, October 23, 2015 3:54 PM To: Stan Porhola Cc: Bo York; Schwartz, Guy L (DOA); DOA AOGCC Prudhoe Bay Subject: Restart at HAK ASR1 To reiterate our discussion this afternoon, AOGCC is authorizing Hilcorp to mobilize and rig up ASR1 at MPU G -08A (PTD 1930480). Per Sundry approval 315-494 — supplemented with a revised work procedure on 10/15/2015 — Hilcorp may proceed through Step 11, work you describe as necessary to install the rig winterization. AOGCC Inspection of the rig is required before proceeding beyond Step 11 of the supplemental work procedure. Please provide 24 hour notice to AOGCC Inspectors for the required rig inspection. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. if you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.regg@alaska.gov. Regg, James B (DOA) From: Regg, James B (DOA) Sent: Friday, October 23, 2015 3:54 PM To: Stan Porhola Cc: Bo York; Schwartz, Guy L (DOA); DOA AOGCC Prudhoe Bay Subject: Restart at HAK ASR1 To reiterate our discussion this afternoon, AOGCC is authorizing Hilcorp to mobilize and rig up ASR1 at MPU G -08A (PTD 1930480). Per Sundry approval 315-494 — supplemented with a revised work procedure on 10/15/2015 — Hilcorp may proceed through Step 11, work you describe as necessary to install the rig winterization. AOGCC Inspection of the rig is required before proceeding beyond Step 11 of the supplemental work procedure. Please provide 24 hour notice to AOGCC Inspectors for the required rig inspection. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or jim.regg@alaska.gov. Regg, James B (DOA) From: Bo York <byork@hilcorp.com> Sent: Friday, October 23, 2015 12:12 PM To: Regg, James B (DOA) Subject: RE: Missing Info - ASR1 Incident Jim - For our meeting on Monday I will bring over revised drawings that more clearly depict the flow paths and valve positioning for: • Haliburton N2 truck to well, mixed with seawater, down IA, returns up tubing to open top tank (reverse circ) • Seawater pill #land #2 chasingffoIlowing same path as N2 (path for pill #1 and #2 were the same). Valve positions changed from N2 to pill #1 and #2 will he noted. • Annulus pressure bleed off to ASR 1 internal tanks following attempt to pump pill #2 • BOP stack valve positions Bo York Operations Manager, Milne Point byork@Hilcorp.com 907.777.8345 907.727.9247 cell From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Friday, October 23, 2015 10:08 AM To: Bo York Subject: Missing Info - ASR1 Incident Hilcorp provided P&IDs related to ASR1 identified as a generic flow diagram (request was for non -cleanout workover ops), "Pumping Second 50 bbls of Seawater" (0848 hrs), and "Started to Bleed Annulus Pressure" (0856 hrs). Information relating to the pumping operations during the fill cleanout ops — in particular the P&IDs — is confusing. Also, Hilcorp has not provided all the pumping schematics that were previously requested (we also requested a "flow diagram for pumping nitrogen"). The following is requested: Clarify the return path for fluids during each stage of the well cleanout. Was the fill cleanout normal (pump down tubing and flow up the IA) or reverse (pump down IA and returns up tubing)? Provide schematics (as -configured drawings) showing the entire flow path of fluids pumped for each stage of the fill cleanout (N2 from Halliburton mixed with seawater; seawater pill #1; seawater pill #2); include valve positions in the flow path. Clearly state any valve position changes that occurred between pumping the nitrogen and seawater pill 1 and seawater pill 2 Provide the position of BOP stack valves (annular; rams; choke and kill line valves) during pumping ops Additional info requested: - What was the diameter and length of each — work string (bottom), and tubing (at surface) — used in the J -08A during cleanout? - Provide copies of NSTC cards issued to the ASR 1 crew members - Confirm version of the Alaska Safety Handbook referenced by Hilcorp in previously submitted documents. The page numbers in my copy of ASH 2014 do not match copied pages included in Hilcorp submittals. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or jim.regg@alaska.gov. Regg, James B (DOA) From: Regg, James B (DOA)jr� Sent: Friday, October 23, 2015 10:08 AM To: Bo York Subject: Missing Info - ASR1 Incident Hilcorp provided P&IDs related to ASR1 identified as a generic flow diagram (request was for non -cleanout workover ops), "Pumping Second 50 bbis of Seawater" (0848 hrs), and "Started to Bleed Annulus Pressure" (0856 hrs). Information relating to the pumping operations during the fill cleanout ops — in particular the P&IDs — is confusing. Also, Hilcorp has not provided all the pumping schematics that were previously requested (we also requested a "flow diagram for pumping nitrogen"). The following is requested: - Clarify the return path for fluids during each stage of the well cleanout. Was the fill cleanout normal (pump down tubing and flow up the IA) or reverse (pump down IA and returns up tubing)? - Provide schematics (as -configured drawings) showing the entire flow path of fluids pumped for each stage of the fill cleanout (N2 from Halliburton mixed with seawater; seawater pill #1; seawater pill #2); include valve positions in the flow path. Clearly state any valve position changes that occurred between pumping the nitrogen and seawater pill 1 and seawater pill 2 - Provide the position of BOP stack valves (annular; rams; choke and kill line valves) during pumping ops Additional info requested: - What was the diameter and length of each — work string (bottom), and tubing (at surface) — used in the J -08A during cleanout? Provide copies of NSTC cards issued to the ASR 1 crew members Confirm version of the Alaska Safety Handbook referenced by Hilcorp in previously submitted documents. The page numbers in my copy of ASH 2014 do not match copied pages included in Hilcorp submittals. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or lim.reg@alaska.�ov. Regg, James B (DOA) From: Regg, James B (DOA) Sent: Wednesday, October 21, 2015 5:25 PM To: David Wilkins (dwilkins@hilcorp.com); John Barnes; Bo York Cc: Foerster, Catherine P (DOA); Seamount, Dan T (DOA); Schwartz, Guy L (DOA); DOA AOGCC Prudhoe Bay Subject: Restart of Hilcorp Rig Workovers Conditions for Hilcorp to restart rig workover (RWO) ops: - Establish a single Hilcorp person responsible for RWO's; this individual would be the signature authority that certifies info provided in a workover Sundry application is true, work will be conducted in accordance with AOGCC regulations, orders, and conditions of approval, and that the Sundry information will not be altered except as approval by AOGCC - Provide detailed operations procedures in the Sundry applications - Sundry applications that have pumping operations as part of the rig workover must include proposed piping/fluid path diagrams (include valve positions) and list of all fluids to be pumped - Prior written approval from AOGCC is required for changes to an approved Sundry - Develop and provide a documented management -of -change process applicable to rig workovers - There must be a different Wellsite (Rig) Supervisor per work shift on all Hilcorp-operated rigs - Train rig personnel in hazard identification, rig safety systems and their capabilities, proper response to potentially hazardous conditions, and Hilcorp's "Stop Work Authority"; provide documentation of training materials and list of who has been trained - Post at appropriate locations in rig modules Hilcorp's "Stop Work Authority" policy and procedure - Provide Hilcorp's current RWO schedule for Cook Inlet and North Slope rigs (include rig; well; start date; simple description of the type of workover — e.g., replace ESP; prep for sidetrack; etc.); provide the updated schedule at least monthly - Workover rigs not currently working will be inspected by AOGCC prior to commencing work with a focus on winterization (equipment suitable to reliably operate under the range of weather conditions that may be encountered at the location); written rig -specific BOPE testing procedures that account for subfreezing conditions; operations and property maintenance conducted in a safe and skillful manner in accordance with good oilfield engineering practices Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or lim.regg@alaska.gov. Carlisle, Samantha J (DOA) From: Regg, James B (DOA) Sent: Thursday, October 15, 2015 3:48 PM To: Carlisle, Samantha J (DOA); Colombie, Jody J (DOA) Subject: OTHER 15-025 (Hilcorp MPU J -08A; Rig ASR1) I put the wrong PTD in the official correspondence related to this docket (2 formal letters to Hilcorp; 10/2 and 10/8). MPU J -08A should be PTD 1991170, not 1992770. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.regg@alaska.gov, Regg, James B (DOA) From: NSK HSE Admin Assist <n1154@conocophillips.com> Sent: Monday, October 12, 2015 6:03 AM Subject: Safety Toolbox Communication - Hilcorp Oxygen Deficient Atmosphere Lessons Learned Attachments: Lessons learned from ASR Rig final.pdf Hilcorp Oxygen Deficient Atmosphere Lessons Learned Phase do not reply to this note. ; Contact your Safety Dept with comments or for further information. Safety Bulletins may also be viewed via the HSE Web Page CLICK HERE Please share with others and post appropriately. NSK HSE Administrative Assistant ConocoPhillips Alaska, Inc. Work: (907) 659-7593 Email: N1154(a)conocophillips com flHilcorp Alaska, LLC Safety - Sharingtheexperience Incident: ASR 1 Oxygen Deficient Atmosphere Type of Incident: Recordable Location: Milne Point, North Slope, Alaska Date: 25 September 2015. Milne Point Automated Service Rig 1 (ASR 1) Incident What happened? 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 I bleed the pressure to the ASR 1 tank module interior t 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 r allowed the nitrogen to vent into the tank module I 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. Lessons Learned Summary 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. 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. 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. Learnings to share 1) Walk down valves and lines as part of 1SA 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 RECEIVED OCT 12 2015 AOGCC Hileorp Alaska, LLC David S. Wilkins Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 100 Anchorage, AK 99503 October 9, 2015 Cathy P. Foerster Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, AK 99501-3572 Re: Docket Number: OTH-15-025 Additional Information Request dated 8 October 2015 Hilcorp Alaska ASR -1 Rig MPU J -08A (PTD 1991770, Sundry 315-527)) Dear Chair Foerster: We respond to the AOGCC's 8 October 2015 second request for additional information regarding the safety incident Hilcorp Alaska, LLC (Hilcorp Alaska) experienced on 25 September 2015, while performing workover operations with the Automated Service Rig 1 (ASR 1) at Milne Point Unit well J -08A. 1. AOGCC Request: "Why was Hilcorp's intent to use the nitrogen cleanout omitted from the work procedure included in Hilcorp's sundry application for the MPU J -08A well workoverT Hileorp Alaska Response: Hilcorp Alaska did not have an intent to use nitrogen when the sundry was submitted. Typically, a nitrogen cleanout is a contingent plan that is executed only if well conditions warrant. While the submitted sundry addressed performing a cleanout, nitrogen was not specifically addressed as a potential cleanout media. 2. AOGCC Request: "Who authorized the use of nitrogen for a well cleanout in MPU J -08A? The response to this question should include that person's title, duties, training in the use of nitrogen and job description." Hileorp Alaska Response: The Hilcorp Alaska operations engineer authorized the contract wellsite supervisor to use nitrogen. The contract wellsite supervisor contacted the nitrogen provider to setup the job. The operations engineer is responsible for the well work procedures. The contract wellsite supervisor is responsible for the well work activities on site. Duties and job description for both positions are attached. 3. AOGCC Request: "Provide copies of Hilcorp's written procedures for the use of nitrogen, including nitrogen cleanout and any procedures specific to this well. Cathy P. Foerster Docket Number: OTH-15-025 October 9, 2015 Page 2 of 5 Hilcorp Alaska Response: The Hilcorp Alaska and Haliburton nitrogen procedures were attached to the Hilcorp Alaska 6 October 2015 response. 4. AOGCC Request: "Did Hilcorp formally assess the hazards associated with the use of nitrogen prior to the cleanout operation? If so, what type of assessment was performed and who was involved in the hazards assessment? Provide documentation demonstrating the assessment of downhole and surface hazards associated with the use of nitrogen in a rig - operated well cleanout." Hilcorp Alaska Response: The hazard assessment was conducted on site during the JSA for both the night and day shifts. All crew members participated in the JSA. The JSAs were attached to the Hilcorp Alaska 6 October 2015 response. 5. AOGCC Request: "Did Hilcorp provide formal training to all rig personnel (both day and night crews) for safe work with nitrogen? If done, what information did the training program include? Provide any written materials used as part of the training program." Hilcorp Alaska Response: The Integrated Well Services (IWS) crew is contracted by Hilcorp Alaska to operate the ASR 1. For liability and co -employment reasons and as detailed in Hilcorp Alaska's Master Service Agreement, IWS is responsible for training their employees. Most of the training was presented by third party educators over a number of years; therefore, not all the written training materials are feasibly available. A list of their pertinent training includes: • North Slope Training Cooperative (NSTC) (includes low oxygen environments and the hazards of nitrogen). Specific slides from the NSTC training that addresses nitrogen or low oxygen environments are attached. • PEC training (lifetime cards) • Emergency Reaction plan • Fire Prevention • Flammable and combustible liquids • Personal Protective Equipment • Hazard Communication • Hazwoper • Confined space • Respiratory Protection (includes fit tested) • H2S awareness • JSA • Stop card (DuPont) • Stop work authority • Material Safety Data Sheet (MSDS) • LOTO Energy isolation • Hot work • Compressed air safety • 1st aid, CPR(adult), and Blood Borne Pathogens Cathy P. Foerster Docket Number: OTH-15-025 October 9, 2015 Page 3 of 5 In addition, Haliburton is responsible for training their employees who performed the nitrogen job. Their provided training includes: • NSTC • BP's Control of Work (COW) Alaska Safety Culture Workshop • Exxon's Artie Pass • 2014 ASH Update 6. AOGCC Request: "What safety equipment was provided at the location to mitigate the potential danger associated with the use of nitrogen?" Hilcorp Alaska Response: Bleeding the nitrogen to exterior open top tanks as standard procedure greatly mitigates the nitrogen risk. Haliburton has an 02 monitor mounted in the cab of their pump truck. In addition, the wellsite supervisor had an Industrial Scientific Ventis MX4 gas monitor which reads 02, H2S, LEL, and CO. 7. AOGCC Request: "What was Hilcorp's policy for site supervision at the time of the MPU J -08A workover? Include training requirements, number of well site leaders and what dictated the decision, and any controls established for allowable hours worked without rest. Provide all documents which embody these policies. Also provide the chain of authority at MPU J -08A, including all documents which demonstrate the chain of authority." Hilcorp Alaska Response: Hilcorp Alaska employed one wellsite supervisor for the ASR 1. See attachment for Item 2 for the job description (e.g., training requirements). Hilcorp Alaska had determined one well site leader could manage the work over activities of the ASRI. No set controls were in place to ensure appropriate rest was taken other than the wellsite supervisor's judgment and experience. Going forward, Hilcorp Alaska has changed that determination and will have a day supervisor and a night supervisor with hand-off communications at the changeover. The wellsite supervisor is responsible for the on-site work and direct supervision of the crew. The operations engineer oversees the wellsite supervisor and reports to the operations manager and asset team leader. (The job descriptions for the wellsite supervisor and the operations engineer are attached in response to Question 2.) An organizational chart for the North Slope Asset team is attached. 8. AOGCC Request: "Why was the flow back during the well cleanout routed to an interior tank located inside the ASRI tank trailer instead of the designated exterior flow back tanks?" Hilcorp Alaska Response: The rig crew anticipated only bleeding off 4.1 bbls of fluid that they thought was due to blocked flow. They did not anticipate bleeding off nitrogen. As discussed in the root cause analysis documents, they did not re-evaluate their course of action when they realized they were flowing gas and not liquid. 9. AOGCC Request: "Did the ASRI personnel involved in the flow back operation assess the integrity of the barriers to prevent a release of nitrogen during flow back before the flow back fluids were directed into the interior tank located inside the ASR I tank trailer? State the qualifications of the personnel who made that assessment?" Cathy P. Foerster Docket Number: OTH-15-025 October 9, 2015 Page 4 of 5 Hilcorp Alaska Response: No, they did not assess the integrity of barriers. As stated above they did not believe they were going to receive nitrogen during the bleed off. No assessment was made by the on-site personnel. 10. AOGCC Request: "Why was the drain valve on the gas buster open during the workover? Who made the decision to open the drain valve on the gas buster? When was the gas buster drain valve opened and by whom?" Hilcorp Alaska Response: We do not know why the drain valve was left open, who opened it, or when it was opened. It was not opened as part of the bleed off procedure. The rig crew stated it was simply left open from a previous flush/clean out of the vessel. 11. AOGCC Request: "Provide a copy of Hilcorp's policy for enclosed space entry. Were the procedures established in the policy followed? a. In the document labeled "Internal Incident Investigation" the individuals that entered the ASRI tank trailer (enclosed space including the manifold room and tank room) are identified as Tool Pusher, Operator 1, and Operator 2; later in the same document reference is made to Supervisor, Driller 1, and Driller 2; the "Incident Investigation Events Sequencing Chart" refers to individuals as Tool Pusher, OP 1, and OP2 - are these all referencing the same individuals? If not, clarify." Hilcorp Alaska Response: Hilcorp Alaska does not have an enclosed space entry policy. Hilcorp Alaska utilizes the Confined Space Entry Standard set out in the 2014 Alaska Safety Handbook (ASH). This standard was not applicable to the incident as the trailer was designed for continuous employee occupancy. The legend for the tank module schematic in the Internal Incident Investigation references "Supervisor, Driller 1 and Driller 2." Those labels are the same as the "Tool Pusher, Operator 1 (or OP 1), and Operator 2 (or OP 2) referenced throughout the document and the other documents. 12. AOGCC Request: "Did Hilcorp post signs warning of the nitrogen hazard? If so, provide photographs of the signs." Hilcorp Alaska Response: The Haliburton crew posted a sign warning of the nitrogen hazard when they rigged up on the site. The sign was then taken down when they rigged down. A photo of the sign which is used by Halliburton is attached. 13. AOGCC Request: "How long was each of the injured workers exposed to the low oxygen atmosphere during the September 25, 2015 event?" Hilcorp Alaska Response: As detailed in the sequence of events provided on 2 October 2015 the tool pusher was in the room from approximately 0909 hrs to approximately 0914 hrs. Operator 1 and Operator 2 were each in the room for less than one minute. These times are approximate and are based on re-creation of the events from witness statements. Cathy P. Foerster Docket Number: OTH-15-025 October 9, 2015 Page 5 of 5 14. AOGCC Request: "What medical evaluations have been performed on the injured personnel to assess the potential for physical and mental impairment and by whom were the evaluations performed? What are the medical qualifications and credentials of those who performed the evaluations?" Hilcorp Alaska Response: The Beacon licensed physician assistant at Milne Point performed on-site assessments of the individuals. She consulted with the Beacon supporting physician and a supporting ophthalmologist during her assessment. All three IWS employees were cleared by the physician assistant to return to duty the same day of the incident. Hilcorp Alaska does not know if additional evaluations of the IWS employees were undertaken by IWS or the individual employees, and, because of the Health Insurance Portability and Accountability Act (HIPAA), Hilcorp Alaska would not have access to that information or the results of any such evaluation. Should you have any additional questions, please let us know. Sincerely, HILCORP ALASKA, LLC David S. Wilkins Sr. Vice President Enclosures as described above cc: John Barnes (w/encs.) Response 2 Attachment Operations Engineer Job Description Wellsite Supervisor Job Description Hilcorp Company: Hilcorp Energy Company Job Title: Operations Engineer III Department: Engineering Report to: Area Operations Manager Job Status: Federal Labor Standards Act (FSLA Status) © Full-time ❑ Contractor © Exempt ❑ Part-time ❑ Intern ❑ Non -Exempt Job Objective: Completion, workover and production facilities Operations Engineering. Proficient in the design for these operations including rod and tubing string, wellhead equipment and controls design and sizing, fluids systems requirements and design, screen & liner assemblies, packers, control nipples and plugging devices (temporary and permanent), logging (open hole & cased hole) and perforating selection and execution, squeeze cementing, acidizing and fracture stimulation design, slick line operations, production facilities design & installation (including artificial lift systems), and proper plugging and abandonment of wells and facilities. Essential Job Responsibilities: • Highly proficient in monitoring the gathering and analyzing of daily production data such as oil, water and gas producing rates and pressures and temperatures and understands how to respond to the data to efficiently maximize hydrocarbon producing rate and operating profits. • A mastery of understanding and analyzing lease operating expenses (LOE) is required. Highly proficient in production systems operations, being able to oversee the planning and sizing of flow line heaters, separators, oil/water storage & disposal, gas & liquid metering, dehydration facilities, gas compression and flowlines. • Highly proficient knowledge of artificial lift processes including sizing and selection of gas compression, rod pumping systems, gas lift systems, electric submersible pump systems, plunger lift systems, foaming with capillary strings and progressive cavity pumps. • Proficient in the planning and interpreting both open and cased hole logging operations and data. • Highly proficient in constructing or overseeing a detailed procedure to implement the objective of completion, workover and facilities installation or repair projects outlining personnel, equipment and materials required and the order in which they are to be implemented including cased hole evaluation logging, perforating systems, plugging and squeeze cementing techniques and design and formation stimulation (acid/frac/other). • Highly proficient in constructing or overseeing the construction of Authority For Expenditure (AFE) forms by determining and applying the proper per unit cost of each product and service to be used as described in a completion, workover or facilities installation project to assimilate the total cost estimate. • Highly proficient at performing (and could oversee others in) economic analysis of completion, workover, and production facilities projects. • Proficient in implementing (and could assist less qualified in) creative and entrepreneurial problem solving thinking and techniques for contributing to company goals to be the premier private energy company in the industry by efficiently developing energy that would otherwise be lost. • Keeping in mind that the core values are: Integrity - Do the right thing. Urgency - Act Today, Not Tomorrow. Ownership - Work like you own the Company. Alignment - When Hilcorp Wins, We All Win. Improvement - Get Better Every Day. • Capable of demonstrating effective people skills to interact with partners, service providers, peers and support staff and field and wellsite personnel. • Must be willing and capable of effectively soliciting ideas from all people that you involve in the project to maintain a high degree of efficiency and buy -in to meet the goals of the projects and the company. Assists with hiring and retention of personnel. Ability to be available 24 hours per day (on call for questions, emergencies, etc.). • Adheres to established work schedules, attendance standards and is punctual to work and meetings. Maintains employee confidence and protects company assets, including intellectual property, by keeping information confidential. • Maintains technical knowledge by attending educational workshops and reviewing professional publications, establishing personal networks, and participating in professional associations. Contributes to team effort by accomplishing related results, as needed. • Adheres to the company's values — integrity, ownership, urgency, alignment and innovation. • Supports company vision and mission. • Adheres to established work schedule, attendance standards and is punctual to work and meetings. Other Job Responsibilities: • Other duties as assigned by management. Qualifications: • Five (5) years oil and gas production field operations experience required, 10 years' experience preferred. • Ability to solve problems accurately and exceptional proficiency in interpreting production related data. • Ability in developing self-directed teams to meet performance goals. • Ability in developing team momentum, enthusiasm, and pride in company when accomplishing company goals. • Ability to demonstrate strong dynamic team leadership skills. • Ability to establish and maintain effective working relationships with employees, supervisors, other departments, officials, and the public. • Ability to complete multiple, diverse tasks of differing priorities. • Excellent written and verbal communication skills, with specific ability to translate complex financial information into an organized and presentable manner. • Outstanding management, administrative, and organizational skills. Proficiency in the use and application of the following software: Preferred: Microsoft Office (Excel, Word and Outlook. Education Requirements: • Bachelor's Degree from an accredited four-year university or college with a degree in engineering. Certifications, Licenses, Registrations: 0 None. Date Job Description Became Effective: September 27, 2013 The above statements are intended to describe the general nature and level of work being performed by employees assigned to this classification. They are not intended to be construed as an exhaustive list of all responsibilities, duties and/or skills required of all personnel so classified. I have read and agree to the job duties outlined above and understand that in order to adjust to changes in business, it may be necessary to modify the job, add to or remove certain duties and responsibilities, or be reassigned to an alternate position. Absent a written agreement signed by either Hilcorp's President or CEO, this statement does not alter the "at -will" status of employment at Hilcorp Energy Company. Employee Signature: Title: Approved by: Title: F171 Hilcorp Job Description Company: Hilcorp Alaska, LLC Job Title: Sr. Wellsite Supervisor Department: Exploitation Report to: Area Operations Manager Job Status: Federal Labor Standards Act (FSLA Status) ❑X Full-time ❑ Contractor ❑X Exempt ❑ Part-time ❑ Intern ❑ Non -Exempt Job Objective: Supervises all wellsite activities including workover, maintenance and service operations and field employees and contractors. Essential Job Responsibilities: • Documents operations with daily progress reports. • Monitors and maintains up-to-date communications with rig crews, vacuum truck drivers, and transportation department and field operators (pumpers/gaugers) regarding current workovers and/or changes. • Coordinates services with service companies (wireline, cementing, production equipment, etc.) to assure availability or special service requirements. • Coordinates State of Alaska testing requirements and supervises tests • Provides information to service companies regarding workover procedures or delays in order to facilitate a cooperative, efficient, and safe work place. Obtains and coordinates bids from service providers. • Reviews daily costs on all active rig operations. Supervises acid and Frac stimulations. • Provides cost estimates to assist the operations engineer with authorization for expenditures (AFE's). • Contributes to team effort by accomplishing related results, as needed. • Adheres to the company's values — integrity, ownership, urgency, alignment and innovation. • Supports company vision and mission. • Adheres to established work schedule, attendance standards and is punctual to work and meetings. Other Job Responsibilities: • Ability to work two week on/off schedule at remote location and be available 24 hours per day while on shift (on call for questions, emergencies, etc.). • Ability to travel to remote locations via large and small planes, helicopter or boat, and ability to don and doff immersion suit. • Ability to work in Arctic conditions. • Maintains employee confidence and protects company assets, including intellectual property, by keeping information confidential. • Other duties as assigned by management. Qualifications: • Ten (10) years minimum experience in workover, completion, fishing, and recompletion operations. • Ability to work established work schedule. • Mastery of mechanical skills. • Ability to accurately solve problems. • Ability to work long hours in order to cover/monitor assigned field territory. • Ability to establish and maintain effective working relationships with employees, supervisors, other departments, officials, and the public. • Ability to complete multiple, diverse tasks of differing priorities. • Good written and verbal communication skills, with specific ability to translate complex information into an organized and presentable manner. • Self-starter with proven leadership skills, team player, comfortable working under pressure, and dedicated to developing workforce. • Good management, administrative, and organizational skills. • Proficiency in the use and application of the following computer software: • Preferred: Microsoft Office (Word, Excel, and Outlook) Education Requirements: • Graduation from a high school or GED equivalent. Certifications, Licenses, Registrations: • None. Date Job Description Became Effective: March 20, 2015 The above statements are intended to describe the general nature and level of work being performed by employees assigned to this classification. They are not intended to be construed as an exhaustive list of all responsibilities, duties and/or skills required of all personnel so classified. I have read and agree to the job duties outlined above and understand that in order to adjust to changes in business, it may be necessary to modify the job, add to or remove certain duties and responsibilities, or be reassigned to an alternate position. Absent a written agreement signed by either Hilcorp's President or CEO, this statement does not alter the "at -will" status of employment at Hilcorp Alaska, LLC. Employee Signature: Title: Approved by: Title: Response 5 Attachments Select NSTC Training Materials �J North Slope Training Cooperative © North Slope Training Cooperative—All Rights Reserved 46 Oo, When to sample? Prior to entry (from outside). Continuously during entry. Prior to re-entry (from outside). Oo,Where to sample? Top, middle, bottom Ooo. Why sample? Stratification, weights, mix 19 © North Slope Training Cooperative—All Rights Reserved 47 METHANE -o' do 4P • - • • - © North Slope Training Cooperative—All Rights Reserved v Test the atmosphere from outside the confined space through wall openings and roof hatches: At the top of the space, At intermediate points and in breathing zones, Near floor and other low points (i.e. sumps). Where liquids or sludge are present, samples should be taken within 6 inches of the surface in addition to the areas mentioned above. 2014 ASH, page 92, #3-4 2014 BP ASH, pages 64-68; 69-71 © North Slope Training Cooperative—All Rights Reserved 49 v Oo. Hazardous conditions can exist ANYWHERE at ANYTIME. O,Always use a calibrated gas detection instrument. Oo. Don't rely only on your SENSES Poll., Usually performed by the Safety Advisor (BP ASH) or Safety Personnel (ASH). Oo, Must be trained in atmospheric testing. © North Slope Training Cooperative—All Rights Reserved W1 Why is it critical to perform the atmospheric test in the following sequence? 1. Test for oxygen content. A test for normal breathing air is 20.9%. 2. Test for flammable gases and vapors. 3. Test for toxic gases and vapors. 2014 ASH, pages 92, 102; 2014 BP ASH, pages 66-67 OSHA 29 CFR 1910.146, Appendix B (5) CNorth Slope Training Cooperative—All Rights Reserved 51 Oo-An oxygen -deficient atmosphere has less than 19.5% Oby volume_ 2 ►An oxygen -enriched atmosphere has greater than 23.5% 02by volume. Deficient < 19.5% Q� Q■ Q* Q Q O ■ r> ■ O� Q ; `, �,■ w ON Q■ L * - _ Q ■ Normal C� 20.9% Deficient < 19.5% Q� Q■ Q* Q Q O ■ r> ■ O� Q ; `, �,■ w ON Q■ L * - _ Q ■ Normal Enriched 20.9% > 23.5% —M © North Slope Training Cooperative—All Rights Reserved 52 Do not enter above 23.5% because an oxygen -enriched atmosphere may 23% .5% trigger an explosion. Check before assuming that readings between 0.9% and 23.5% are safe levels. 0 21% Normal level ° Below19.5%., an air supply will be 19.5% required if entry is permitted. 19% 15% 10% Significant physical impairment, loss of coordination, slurring of7 speech, impaired judgment Below 10%, nausea, vomiting, death 10. NW© North Slope Training Cooperative—All Rights Reserved 53 ► Displacement by gases used during the inerting process (carbon dioxide, nitrogen, argon) Oo, Chemical exposure to gases which reduce or stop the body's ability to use oxygen (oxidation due to rusting and corrosion; decaying organic matter) OoAerobic bacteria have used up the oxygen © North Slope Training Cooperative—All Rights Reserved 54 Oo-Airborne contaminants loo -Asphyxiants 001, Simple asphyxiants (N2, CO2, CH4, Ar, C31-18) 110o, Chemical asphyxiants (CO, 1-12S, CN-, C6H5NO2) Oo, Oxygen deficient atmospheres (< 19.5%) NX. © 2008 NSTC/APICC—All Rights Reserved Response 7 Attachment North Slope Asset Team Organization Chart Operations Engineer Sean Lowther Kyler Dunford Paul Marko Julianne Dickerson Taylor Wellman Walton Crowell Paul Chan Stan Porhola HILCQRP North Slope Asset Team Asset Team Leader North Slope John Barnes Geophysicist Dan Yancey Reservoir Engineer Operations Manager Geologist g Bo York Matt Brown Sr. Ops/Reg Tech Vanessa Hughes Anthony McConkey Mike Dunn Kevin Eastham Tom Fouts Chris Kanyer Well Integrity Engineer Geo Tech Wyatt Rivard Maile Sweigert 1 - Dept. Head Page 51 19 - Employees Updated 9/11/2015 Response 12 Attachment Haliburton Nitrogen Sign Photograph 000- 1r1ig� Pressure Nitrogen Pumping 11% Protivess 14. Caution High Pressure Nitrogen pumping In Progress a ---- I Regg, James B (DOA) From: Bo York <byork@hilcorp.com> Sent: Monday, October 12, 2015 7:24 AM To: Regg, James B (DOA); Carlisle, Samantha J (DOA) Cc: David Wilkins; John Barnes Subject: FW: Additional Information OTH-15-025 Attachments: Signed 2015-10-09 HA Response to AOGCC 8 Oct Request for Information ASR 1 Incident v00.pdf Jim - Attached are the responses to your additional questions regarding the ASR incident. A hard copy will be delivered this morning to your offices. Please let me know if you would like to discuss further. Bo York Operations Manager, Milne Point byork@Hilcorp.com 907.777.8345 907.727.9247 cell From: David Wilkins Sent: Thursday, October 08, 2015 9:50 AM To: Bo York; Marc Bond; John Barnes Subject: FW: Additional Information OTH-15-025 From: Carlisle, Samantha J (DOA)[ma iIto: samantha.carlisle@alaska,gov] Sent: Thursday, October 08, 2015 9:49 AM To: David Wilkins Cc: John Barnes Subject: Additional Information OTH-15-025 Mr, Wilkins, Please see the attached letter regarding Docket Number OTH-15-025. Thank you, Sa.mv'n. h a f: ar t isfe '!'xE�c.'�t.lt:i��c� .Sr�cr��tcarti� Il Ifas/ ci Oil u,nd,. Gas (�'c�ltsf�l�ti�c�ttcrrt t'on�.nlr.�,�ir�fz 3 blest 7,; '1nctio� ctr�c?, .%1" oq; oI (t)fq)7« 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 VAN 1 GOVERNOR BILL WALKER October 8, 2015 Certified Mail Return Receipt Requested 7015 0640 0006 0779 5807 Mr. David Wilkins Senior Vice President Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: OTH-15-025 Additional Information Unauthorized Changes to Approved Permit Hilcorp ASR -1 Rig MPU J -08A (PTD 1991770; Sundry 315-527) Dear Mr. Wilkins: ,ska GSI and Gay 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.cogcc.alaska.gov The Alaska Oil and Gas Conservation Commission (AOGCC) is continuing its investigation into the incident during Hilcorp Alaska LLC's (Hilcorp) September 25, 2015 workover operations on Rig ASRI (ASR1) at Milne Point Unit J -08A (MPU J -08A). To date AOGCC has received Hilcorp's "Internal Incident Investigation" report, the "Incident Investigation Events Sequencing Chart" and the "Comprehensive List of Causes" analysis report received on October 2, 2015 in addition to gathering initial information from a September 25, 2015 wellsite visit. Hilcorp has also responded to the request for information in the AOGCC's Notice of Investigation dated October 2, 2015. Written responses to the following additional questions / requests for information are requested from Hilcorp no later than October 14, 2015: 1. Why was Hilcorp's intent to use the nitrogen cleanout omitted from the work procedure included in Hilcorp's sundry application for the MPU J -08A well workover? 2. Who authorized the use of nitrogen for a well cleanout in MPU J -08A? The response to this question should include that person's title, duties, training in the use of nitrogen and job description. 3. Provide copies of Hilcorp's written procedures for the use of nitrogen, including nitrogen cleanout and any procedures specific to this well. 4. Did Hilcorp formally assess the hazards associated with the use of nitrogen prior to the cleanout operation? If so, what type of assessment was performed and who was involved Mr. Dave Wilkins October 8, 2015 Page 2 of 3 in the hazards assessment? Provide documentation demonstrating the assessment of downhole and surface hazards associated with the use of nitrogen in a rig -operated well cleanout. 5. Did Hilcorp provide formal training to all rig personnel (both day and night crews) for safe work with nitrogen? If done, what information did the training program include? Provide any written materials used as part of the training program. 6. What safety equipment was provided at the location to mitigate the potential danger associated with the use of nitrogen? 7. What was Hilcorp's policy for site supervision at the time of the MPU J -08A workover? Include training requirements, number of wellsite leaders and what dictated the decision, and any controls established for allowable hours worked without rest. Provide all documents which embody these policies. Also provide the chain of authority at MPU J - 08A, including all documents which demonstrate the chain of authority. 8. Why was the flow back during the well cleanout routed to an interior tank located inside the ASR tank trailer instead of the designated exterior flow back tanks? 9. Did the ASR1 personnel involved in the flow back operation assess the integrity of the barriers to prevent a release of nitrogen during flow back before the flow back fluids were directed into the interior tank located inside the ASRI tank trailer? State the qualifications of the personnel who made that assessment? 10. Why was the drain valve on the gas buster open during the workover? Who made the decision to open the drain valve on the gas buster? When was the gas buster drain valve opened and by whom? 11. Provide a copy of Hilcorp's policy for enclosed space entry. Were the procedures established in the policy followed? a. In the document labeled "Internal Incident Investigation" the individuals that entered the ASR1 tank trailer (enclosed space including the manifold room and tank room) are identified as Tool Pusher, Operator 1, and Operator 2; later in the same document reference is made to Supervisor, Driller 1, and Driller 2; the "Incident Investigation Events Sequencing Chart" refers to individuals as Tool Pusher, OP1, and OP2 — are these all referencing the same individuals? If not, clarify. 12. Did Hilcorp post signs warning of the nitrogen hazard? If so, provide photographs of the signs. 13. How long was each of the injured workers exposed to the low oxygen atmosphere during the September 25, 2015 event? 14. What medical evaluations have been performed on the injured personnel to assess the potential for physical and mental impairment and by whom were the evaluations performed? What are the medical qualifications and credentials of those who performed the evaluations? This request is made pursuant to 20 AAC 25.300. Failure to comply with this request is itself a regulatory violation. The AOGCC reserves the right to pursue an enforcement action in this matter according to 20 AAC 25.535. Mr. Dave Wilkins October 8, 2015 Page 3 of 3 Should you have any questions about the information request, please contact Jim Regg at (907) 793-1236. Sincerely, J James B. Regg Supervisor, Inspections cc: John Barnes, Hilcorp r� 0 CO Ln Er r - r` 0 _n M O 17-10 0 ra O r- 3 .xtra Services & Fees (check box, add fee as appropriate) ❑ Return Recelpt (hardcopy) $ ❑ Return Receipt (electronic) $ Postmark ❑ Certified Mail Restricted Delivery $ Here ❑ Adult Signature Required $ ❑ Adult Signature Restricted Delivery $ Mr. David Wilkins ,t To Senior Vice President ietandApt. No., or PO BoxIVc Hilcorp Alaska, LLC ware; ziP+d�----"'"""---- 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 ■ Complete items 1, 2, and 3. A. ■ Print your name and address on the reverse X so that we can return the card to you. ■ Attach this card to the back of the mailpiece, B. or on the front if space permits. Mr. David Wilkins Senior Vice President Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 ❑ Agent ❑ Addressee D. Is deliXery address different from item`s? LJ Ye: If YES, enter delivery address below: ❑ No r�ry, -- 3. Service Type D Priority Mail Express@ ❑ Adult Signature ❑ Registered Mail - ll I Illl�l I'll ISI II Il I Il II lIl Il I III II l III I lI Ill El Adult Signature Restricted Delivery El Registered Mail Restricted 9590 940], 0049 5071 320], 47 Getertified Mail® D Certified Mail Restricted Delivery Delivery �iteturn Receipt for Merchandise ❑ Collect on Delivery ❑ Collect on Delivery Restricted Delivery Insured [I Signature ConfirmationT"' El Signature Confirmation 2. Article Number (Transfer from service label) 70 5 01340 0006 0 7 79 5807 Mail ver $5 0)il Restricted Delivery Restricted Delivery PS Form 381 1 , April 2015 PSN 7530-02-000-9053 Domestic Return Receipt RECEIVED OC1 0 0 2015 Hilcorp Alaska, LLC David S. Wilkins AOGCC Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 100 Anchorage, AK 99503 October 6, 2015 Cathy P. Foerster Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, AK 99501-3572 Re: Docket Number: OTH-15-025 Notice of Investigation Unauthorized Changes to Approved Permit Hilcorp Alaska ASR -1 Rig MPU J -08A (PTD 1991770, Sundry 315-527)) Dear Chair Foerster: We respond to the AOGCC's request for additional information regarding the safety incident Hilcorp Alaska LLC (Hilcorp Alaska) experienced on 25 September 2015, while performing workover operations with the Automated Service Rig 1 (ASR 1) at Milne Point Unit well J -08A. 1. AOGCC Request: "Detailed flow diagram for pumping nitrogen and seawater used for the well cleanout; including annotations for all equipment and the position of all valves and blowout preventers that are in a potential flow path to/from the well" Hilcorp Alaska Response: Detailed flow diagrams for pumping nitrogen and seawater were submitted to AOGCC as part of the Root Cause Analysis documents submitted on 2 October 2015. 2. AOGCC Request: "Detailed flow schematic for non -cleanout related workover operations" Hilcorp Alaska Response: The ASR 1 set up varies with individual and specific well workover activities. A generic system P&ID is attached and is similar to the detailed flow diagram provided in response to item 1 above. 3. AOGCC Request: "Copy of the written test procedure for verifying the piping integrity prior to pumping nitrogen and seawater; including evidence of the test being performed (e.g., test chart)" Hilcorp Alaska Response: The Haliburton job log is attached. Haliburton followed their procedure after rigging up to test their lines to ensure they had integrity to 3,500 psig. Cathy P. Foerster Docket Number: OTH-15-025 October 6, 2015 Page 2 of 4 Haliburton's written procedure for pressure testing is attached. Haliburton does not have the capability to chart their pressure tests. Also attached is Haliburton's procedure for performing nitrogen jobs. 4. AOGCC Request: "Copy of the written procedure specific to MPU J -08A and ASRI for cleanout operations involving the use of nitrogen" Hilcorp Alaska Response: The written procedure for performing nitrogen cleanouts is attached. This is the same procedure Hilcorp Alaska utilized without incident on the wells detailed in item 6 below. A specific procedure for J -08A was not completed, as the written procedure noted above was followed. See also the Haliburton nitrogen job procedure noted in response to Request 3. 5. AOGCC Request: "Copy of documentation of job safety assessments, risk evaluations, and any safety meetings before pumping nitrogen for the cleanout operation; also, a copy of Hilcorp Alaska's written policy regarding conduct of such and what is included" Hilcorp Alaska Response: Attached is a copy of the JSA performed prior to the nitrogen job and also a copy of the JSA for the day crew that came on shift as the nitrogen job was being completed. Both JSA's appropriately identified the hazards of nitrogen and both crews discussed the hazards. Hilcorp Alaska's Minimum Contractor Safety Requirements document and also the Alaska Safety Handbook (ASH) (adopted by Hilcorp Alaska for our North Slope operations), both reference conducting JSAs prior to performing work. In addition, our on-site safety representatives discuss JSAs in the Milne Point Site Safety Briefing which is given to all contractors on location prior to initiating work. All three documents are attached. 6. AOGCC Request: "List the dates, wells and rigs of all Hilcorp Alaska rig workovers (excluding coil tubing units) in Alaska that have used nitrogen for a wellbore cleanout." Hilcorp Alaska Response: Below is a listing of the nitrogen clean out jobs sorted by date of nitrogen cleanout work, rig, and well designation. The contract well site supervisor was the same for all the nitrogen jobs. Date Rig Well Designation 27 March 2015 I-15 Nordic 3 28 April 2015 J -09A Nordic 3 10 August 2015 J -01A ASR 1 25 September 2015 J -08A ASR 1 Cathy P. Foerster Docket Number: OTH-15-025 October 6, 2015 Page 3 of 4 7. AOGCC Request: "Copy of all daily reports commencing with the date of mobilization of ASR1 to MPU J -08A" Hilcorp Alaska Response: Attached are the daily reports for 23 September through 4 October. 8. AOGCC Request: "Copy of reports that document the analyses of samples taken (mud pit fluids; mud pit trailer insulation; etc.)" Hilcorp Alaska Response: Multiple Integrated Well Services (IWS) employees worked inside the tank trailer the morning of the incident prior to the 0850 hr bleed off activities. They worked within the tank trailer while all four tank agitators were activated. No issues were noted and no incident occurred. Oxygen was displaced in the tank room only after nitrogen in the well was bled off through the gas buster into the internal tanks. Therefore, the contents of the tanks were determined to not be an issue. In addition, following the incident a test was designed by the well site supervisor and performed by the Hilcorp Alaska safety specialist on site. The test consisted of flowing tank fluids through the gas buster and into the internal tanks while sampling the air at the "P" trap and gas buster stack remotely using tubing connected to separate atmospheric monitors. The well site supervisor's intent of the test was to try and recreate the incident to determine if fluids mixed with the contents of the gas buster to create a toxic or hazardous vapor. The atmospheric monitor sampling the air at the "P" trap sucked oily liquids into the tubing's filter and alarmed due to the plugging. The atmospheric monitor sampling the air at the gas buster stack, where any vapors or gas would have exited, did not plug and did not alarm. The test confirmed that no toxic vapors/gases or other oxygen displacing vapors/gases were present in or created by the contents of the tank trailer tanks or the gas buster. Samples were taken from the tanks in the trailer. However, given the above and the fact that there is no record of H2S or other hazardous gas in J-08 or the Milne Point field, the certified industrial hygienist that was part of the investigation team recommended that the samples not be submitted for laboratory analysis. The hygienist concluded it was not possible that any vapors, other than nitrogen from the well, could have been created by the contents of the tank or gas buster or coating of the walls of the tank room, in any volume—let alone in a sufficient volume to displace the oxygen in the tank over the period of time of the incident. Hilcorp Alaska has retained the samples and they are held at Milne Point. 9. AOGCC Request: "Copy of detailed sequence of operations from rig up to perform wellbore cleanout through the incident" Hilcorp Alaska Response: Detailed sequence of operations was submitted to AOGCC as part of the Root Cause Analysis documents submitted on 2 October 2015. Cathy P. Foerster Docket Number: OTH-15-025 October 6, 2015 Page 4 of 4 10. AOGCC Request: "A list of all gas detection equipment used during rig up of ASR1 at MPU J -08A and copies of gas detection equipment test records for testing performed after rigging up ASR1 on MPU J -08A" Hilcorp Alaska Response: A listing of the H2S and methane detectors is attached as well as the alarm logs detailing the test performed at rig up on 23 September 2015. The passing test was also noted on the BOPE test form. Note that the detectors were not designed to detect N2 or an oxygen deficient atmosphere. 11. AOGCC Request: "Copy of any specifications for air exchange/ventilation in the enclosed mud pit trailer." Hilcorp Alaska Response: In June 2015, Hilcorp Alaska contracted Mr. Augustino Bacher, PE, of H&K Sheet Metal to calculate and confirm that the ventilation fans provided for the tank room satisfied the recommended 6 air changed an hour. The calculation sheet provided by Mr. Bacher is attached. In addition, the certified industrial hygienist that was part of the investigation team evaluated the ventilation fans during the investigation. He used a velometer to measure air velocity at the face of each exhaust hood. Five readings were taken at the face of each hood and an average exhaust velocity was determined. The air volume of the space was then determined and calculations were made to confirm that the ventilation system was operating as designed resulting in more than 6 air exchanges per hour. 12. AOGCC Request: "Copy of full reports of any investigation, risk assessments, and root cause analysis reports." Hilcorp Alaska Response: A copy of the investigation report and root cause analysis was submitted to AOGCC as part of the Root Cause Analysis documents submitted on 2 October 2015. Should you have any additional questions, please let us know. Sincerely, HILCORP ALASKA, LLC David S. Wilkins Sr. Vice President Enclosures as described above cc: John Barnes (w/encs.) Response 2 Attachment Generic ASR MID 0 o J 4 3 AY Von XaPYt � D r----- ---, SM WEI I AarAAI prry T —I I I aL 1 r -------------I I I COExa I — weaox I "a -I At—�I — � I I � I I C I I II as RW I I Pm LK I _ I - - - - - -- Q NAP L _ — — — —CIYE WtlipO YYt 11Aa11 11 wm 2 1 1 ID IC � � Y B I I aun� wY nYx B I I Yu sm m ML IEE w aw.a I Soto FK Am 7EF OEM N � aaaYE aN1( WELL A A ionic ars a nrt �v� n we wa r ave ommmo s� a�a ao a s WS tan n 1 1 �. rt 0605 MPU GEN PROCESS oe PIPING & INSTRUMENT DIAGRAM ASR -1 RIG rxn va rrwii ..vm M� r am NNE �O�^LA�* PI-MOD-ODOXX 00 001 San I 8 7 6 5 � Response 3 Attachments Haliburton Nitrogen Job Log dated 24 September 2015 Haliburton written pressure test procedure Haliburton written nitrogen job procedure JOB LOGKAi;as;;;North TWIMT OATS 09/2&15 FiC.A.TM NWAICOUNTRY Alaska Ca W" S Borou h E7�lOYEE Nut ohn 97 EWI.OYff NAM camANr Hillcory Wa ne Burt 1652207 Pumpina Work over Milne Point PURPOSE COOS 363672 N2 pumpina Oil Date Time N2 VOLUME "m UL IM Job Description / Remarks SAFM 09/24/15 15:30 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 Rig up 2:00 Cool Down 2:10 X Sammy Meeting 2:30 Pressure Test to 3,500 psi 2:40 Online 500 scfm; 140 psi 2.41 750 scam; 276 psi 2.45 1,000 scfm; 577 psi 2:57 1,200 scfm; 935 psi 3:30 1,200 scfm; 1,263 psi 4.30 Otfiine; N2 hose started to leak. Replaced hose. 4:55 Online 1,000 scfm; 1,181 psi 6:30 1,000 scfm; 1,280 psi 6:30 2489 Offline; 1,327 psi. Pumped 200,000 ad. 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. 15:00 Arrive at yard 2498 Gals used 2 days pumping PF REV 02- 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 "5".... 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. 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. N2 Pumping job 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 job 1. Turn off engine, generator 2. Close blow down 3. Open road relief valve, rig down Response 4 Attachment Hilcorp nitrogen job procedure Nitrogen Procedure Utilized in Well Operations Procedures 1. Rig up with N2, PT all lines to 3,OOOpsi and Stripping head to 1,000 psi. 2. Pump N2 Nitrified, 8.5ppg SW with surfactant, & N2 tubing flush taking all returns to kill tank with 3. H open hatch! Procedure a. Mobilize N2 equipment (270 N2 pumper & transport) b. Rig up N2 equipment with 2" hard line and hose to rig floor c. Clear personnel from iron and rig floor and Pressure test iron to 3,000 psi. Once pressure test is confirmed pump N2 volume at 700 —1000 scf/min i. Let pressure dictate the rate at which we are pumping N2 d. Close valve on the tubing and rig down N2 iron from rig floor e. Rig down N2 equipment and demobilize Blow down if needed. Full circ and pump 2 tbg Vol. 8.5 ppg SW to annulus. Observe well and repeat this may take some time as formation will possibly retain some N2 charge. POOH after bleeding of N2 residual pressure and insuring well dead. Response 5 Attachments Hilcorp JSA 1743 hrs, 24 September 2015 Hilcorp JSA 0600 hrs, 25 September 2015 Hilcorp's Minimum Contractor Safety Requirements document Alaska Safety Handbook (ASH) Hilcorp's Milne Point Site Safety Briefing Integrated Well Service, Inc. Daily Tailgate Meeting i Job Safety Analysis (JSA) Form Date: Company Representative: Time. Represenative Phone #: Attendees Signature: Company Attendees Signature: Company 1 7 2 t. 8 3 J6,4 9 4 10 5 11 6 12 Check Check Check Hazards Applicable Hazards Applicable Hazards Applicable (1) Pinch Points (13) Lock Out Tag Out (25) Temperature Extremes v (2) Electrical (14) PPE 26) High Winds (3) Elevated / suspended loads (15) Special PPE Required (27) Communication , (4) Hot Work permit (16) Pressure Testing (28) Rotating Equipment (5) Confined Space Entry (17) Slick / Uneven surfaces OTHER: (6) Equipment Handling & Disjointing (18) Driving Conditions (29) (7) Simultaneous operations v' (19) Working at Heights (30) (8) Stored Pressure Systems V (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 V (24) Designated Areas (smoking, etc.) (35) Site Specific JSA Job Steps / Equipment, Tools, & Material / PPE Hazards Controls (x -Ll G\e"- O .,;LO, I'd �' 5tit Ioc,Ewet� �nys�- y o,)trb•� between► tt-+e NSC ac nN4QaL LN ✓ U!L, VVb( J V k✓G X3er 0 t cti JUa4> V;e– S�o +–+–ev- G -,.,r SPw� 1 D 0e h C, S • r te S S _,G�� SOP # reviewed Tailgate / Pre -Job Meeting Emergency # Isupervisor Name: I lPhone# Integrated Well Service, Inc. Daily Tailgate Meeting I Job Safety Analysis (JSA) Form Date: 1 Company Representative: I n t Time: lRepresenative Phone #: Attendees Signature: Company Attendees Signature: Company 1 7) } 2) 8) 3) 9) 4) 10) 5) /K A,r. p. 11) 6) — 12 Hazards Check Check Check Applic ble Hazards Applicable Hazards Applicable (1) Pinch Points (13) Lock Out Tag Out (25) Temperature Extremes (2) Electrical (14) PPE (26) High Winds (3) Elevated I suspended loads (15) Special PPE Required (27) Communication ✓ (4) Hot Work permit (16) Pressure Testing (28) Rotating Equipment (5) Confined Space Entry (17) Slick / Uneven surfaces OTHER: (6) Equipment Handling & Disjointing (18) Driving Conditions (29) (7) Simultaneous 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) 1(24) (12) Tripping hazards Designated Areas (smoking, etc.) (35) Site Specific JSA Job Steps I Equipment, Tools, & Material I PPE Hazards Controls PkM " /�'T p, Z / we ,- L /✓ eX c,y XC ,P 4, r e' ^ �-a C/0 -4i •� � h �+• I r 5. S 7 - � Q �l'% 1 .t C, c, . I �G l'T M r M1 . i ,: f _� "{ SOP # reviewed Tailgate / Pre,lob Meeting Emergency # Supervisor Name: /I Phone # Pre job planning is an integral part of a mature safety culture. Hilcorp Alaska expects all personnel to perform a hazard assessment of assigned work activities prior to initiating the work. This assessment should be documented on a Hilcorp Job Safety Analysis or your companies form which may be commonly referred to as a Task Hazard Assessment or Job Hazard Assesment. Regardless of the form used to document the analysis it is imperative that single employees or work groups work together to identify the job steps associated with the task, identify the specific hazards that will be confronted, and document the appropriate controls or mitigations that will be necessary to accomplish the task without incident. Additionally f conditions change or the scope of work changes while performing the work identified in the JSA take the time to stop and re-evaluate any additional risks and revise the JSA accordingly. If you're unfamiliar with the how to complete a hazard assessment be sure to ask for clarification in the site specific orientation that follows. 7 FIARVFST P1PF.I.INI�. Hilcorp Energy / Hilcorp Energy GOM / Harvest Pipeline Minimum Contractor Safety Requirements Hilcorp Energy Company (HEC), Hilcorp Energy GOM, LLC (HGOM), and Harvest Pipeline Company (HPL), (hereinafter collectively referred to as "HILCORP") stress the importance of Safety and Safety Requirements. HILCORP will prohibit anyone from entering a HILCORP work site who fails to comply with the Minimum Contractor Safety Requirements outlined herein (the "Standards"). HILCORP, 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. Please be advised that these Standards do not reduce or replace a Contractor's responsibility to maintain a safe work environment for all persons, and regularly and repeatedly perform appropriate training and safety programs for its and its subcontractors' employees and agents. Contractors 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. Contractors shall take all necessary and appropriate precautions to safeguard its and its subcontractors' employees and agents, HILCORP 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 HILCORP. SAFE WORK PRACTICES HILCORP requires that Contractors 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 HILCORP work sites. HILCORP 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 HILCORP. (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.) HILCORP requires each Contractor to have its own Comprehensive Substance Abuse and Alcohol Misuse Program. Strict compliance with these requirements is mandated while working on HILCORP work sites. HILCORP prohibits the possession or consumption of alcoholic beverages on any property, facility, aircraft, vehicle, or boat owned or used by HILCORP, except where such possession or consumption is explicitly authorized by HILCORP for limited business or social functions. HILCORP prohibits the possession of firearms, weapons, or explosives on or around any property, facility, aircraft, vehicle, or boat owned or used by HILCORP. (Transportation of firearms for sporting activities or for personal protection in vehicles is not prohibited by this policy, provided the firearms are broken 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 HILCORP facility. Page 1 of 5 HILCORP expects Contractors to train their employees to recognize common hazards associated with their work tasks and Contractors must adhere to all Hazard Communication Standards as required by all applicable Federal, State, and Local Safety Regulations or industry safety standards. All HILCORP employees, Contractors and their 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. HILCORP reserves the right to audit any contractor or sub -contractor or its programs, policies, or procedures while working on HILCORP work sites. PERSONAL PROTECTIVE EQUIPMENT (PPE) Contractors are required to provide all applicable PPE for their employees. The following PPE is required to be worn by all persons while on HILCORP work sites: Clothing - Flame Resistant Clothing (FRC) must be worn at all times while on HILCORP work sites. HILCORP accepts only shirt and pant combinations and coverall FRC. FRC must be fully buttoned and/or zipped (no cotton showing) at all times. Foot 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 when working outside of handrails near or over water. This includes docks, shore based facilities (within 10 feet of water's edge), platforms and camps. Inflatable life vests are discouraged, but, if used, must be auto -inflating. In the situations identified below, HILCORP 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) Additional PPE Protection - Additional PPE may be required based on the task being performed. Consult additional safety resources such as Material Safety Data Sheets (MSDS) 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. Page 2of5 SAFETY MEETINGS HILCORP requires that all contractors conduct safety meetings prior to starting work each day. Meetings should be documented and that documentation maintained at the work site. JOB SAFETY ANALYSES (JSAs) In order to help further identify workplace hazards, HILCORP 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 • SIMOPS (Multiple operations occurring simultaneously on the same work site) • Heavy Lifts • New Equipment Startup • Adverse Weather Conditions Hot Work - HILCORP 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 HILCORP 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 - HILCORP prohibits Confined Space Entry unless an approved Confined Space Entry Permit has been issued by an authorized HILCORP representative. Fall Protection - HILCORP 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, safety belts, lifelines and lanyards, safety nets, and climbing devices. Lock Out/Tag Out - HILCORP 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 of electric shock; including, but not limited to, Lock Out/Tag Out procedures. Demolition Work - A HILCORP 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 HILCORP reserves the right, with or without notice, to lawfully and reasonably search any person, including any contractor's or subcontractor's employees or agents along with their personal effects, prior to entry or departure from a HILCORP work site, facility, vehicle, aircraft, or boat. Methods used may include physical searches and, as appropriate, scheduled or random drug urinalysis screening. Page 3of5 Infractions of this policy, including failure to submit to a search, will be grounds for disciplinary action, up to and including immediate discharge. When appropriate, if any item is discovered through HILCORP searches, inspections or otherwise, which is deemed dangerous or harmful to life or property, law enforcement officials may be notified. Contractor's and subcontractor's employees and visitors not complying with this policy will be removed from HILCORP premises and not allowed to return. REPORTING In the event of an accident or an emergency, Contractor shall immediately provide oral notification to HILCORP and shall prepare and furnish to HILCORP an incident report as soon as reasonably practicable, but not later than EIGHT (8) hours after each such accident or emergency. Contractor shall provide HILCORP with copies of all written or electronic documents associated with the incident. All written reports shall be submitted to the onsite HILCORP representative or to the Environmental Health & Safety Department ("EH&S") department at the HILCORP corporate offices via facsimile transmission to (713) 289-2750 or email to hert@hilcorp.com. If CONTRACTOR cannot notify an on-site HILCORP representative, Contractor shall immediately notify EH&S at 713-209-2400. COMPLIANCE HILCORP strives to create a safe work environment for all who enter our work sites. HILCORP'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 HILCORP work site may result in immediate dismissal. Working safely is a habit that must be formed individually; however, we are all collectively responsible for making the worksite safe. Please feel free to contact the HILCORP Environmental Health & Safety Department at 713-209-2400 with any questions or concerns. Page 4 of 5 Contractor Acknowledgment and Agreement I have received and read a copy of the Minimum Contractor Safety Requirements on the date set forth below. I understand the contents of the above Safety Requirements and further understand that I should consult with management Initials regarding any questions not answered herein. I agree to the terms of the Minimum Contractor Safety Requirements and understand that this Acknowledgment will be retained in my contract file. I agree that the obligations and restrictions set forth within the Minimum Contractor Safety Requirements are reasonable and necessary. I further agree to adhere to the Initials restrictions and protections contained herein. Contractor/ Company Name Contractor's Representative Date Signature Printed Name Title HILCORP Representative Date Page 5of5 A6H Book Company Representative: An individual, either Company or contract, who has been designated by Company management as a Company representative for the purpose of initiating permits. Safety & Health Group: It is recognized that not all field work sites have full time Safety Department coverage or that Safety Depart- ment availability may be minimal. When this is the case, Safety Department responsibilities, as required by the standards of this Safety Handbook, may be redistributed to line management or other qualified personnel with prior approval of the Company Safety Department. General Permittina Rules 1. The risks introduced by simultaneous operations must be thoroughly assessed, documented and managed. The number of operations that can be performed simultaneously, at the same location, depends on a number of factors, including the type of activity, location in relation to other activities, duration of the work, etc. In order to create and maintain a safe operation, it may be necessary to assign one person to be the SimOps coordinator who will be accountable for the overall coordination of the total operation. 2. Any individual may invalidate a work permit at any time if they consider the conditions or work methods to be unsafe. Anyone stopping work in this manner will inform the person doing work, remove the site copy of the permit and return it to the Issuing Authority, giving their reasons for this action. In such instances, the Issuing Authority will inspect the work site and decide whether the permit should be revalidated. 3. When any Emergency Alarm or Emergency Announce- ment made, stop all work, close all gas cylinders and secure ignition sources. Do not resume any work until notified by the Unit Operator. If the condition is in the permitted area and evacuation is required, the affected permit becomes invalid and must be reissued f or revalidated by the Issuing Authority when the area is cleared for work again. 4. It is the responsibility of the Unit Operator or Issuing Authority to safe out and prepare the work area. The Person Doing Work is responsible for verifying the safe out and ensuring the work is performed in a safe manner. 5. The permit is a triplicate form. Mark items "not applicable"(N/A) as appropriate. No line shall be left blank on a permit. The bottom copy or hard copy shall be displayed at the work site or be in the worker's possession. The middle copy shall be kept in the main control room or a site designated by the First Line Supervisor. The top copy or original shall be kept by the Unit Operator/Issuing Authority. 6. Work is restricted to the scope and time duration stated on the permit. Permits are valid until job completion, but shall not extend beyond the end of the shift in which they were issued. A permit must be renewed by the Unit Operator/ Issuing Authority for any changes to conditions, job scope, or time duration. 7. One of the main purposes of the work permit is communication. It is the responsibility of all personnel involved to ensure adequate communication takes place so the work can be performed safely. If work to be done impacts more than one area, all affected areas shall be informed. 8. On the back of the permit are questions and a task hazard assessment. Use the questions, checklist items, and any other assessments that are applicable to the job to ensure all safety aspects are considered. The THA should be reviewed between the Issuing Authority and the Person Doing the Work. 9. All permits must be revalidated if work is not started within a maximum of 2 hours of issue or if there is a break in the work of 2 hours or more. Revalidation consists of the Unit Operator verifying that the condi- tions of the permit are still applicable and it is safe to work. The Unit Operator will then initial the permits, 61 Response 7 Attachment Hilcorp J -08A daily reports, 23 September through 4 October 2015 HILCORP ENERGY COMPANY DAILY OPERATIONS REPORT REPORT NO. 4 DATE: 9/23/2015 JOB: 11552207 - MPJ -08A ESP Change -out #2 LEASE: WELL: MP J -08A JAFEIPROJ NO: 1 1552207 FIELD: COUNTY/ PARISH / API#: /500292249700 STATE: ALASKA PRESENT OPERATION AT REPORT TIME: IWOR DAILY COST:CUM. JOB COST: AFE Budget: CUM. DRILL COST: ICUM. CMPL COST: I Total D&C Cost: REPORTED BY: Wayne Biart ICONTRACTOR REP: PHONE LAST BOP TEST: 907 310 0243 NEXT BOP TEST: 1CONTRACTOR / RIG #: FUNC DUE: /ASR 1 FLUID: TYPE: WEIGHT: DAILY LOSS: I ICUM LOSS: 1 84 CASING DATA PRODUCTION TUBING SIZE: WT: DEPTH: ID: SIZEAVT/THD: H GRADE ID: SIZE: WT: DEPTH: ID: SIZE: WT: DEPTH: ID: SIZE: WT: DEPTH: ID: H EQUIPMENT DATA Packer. SIZEIDEPTH: / NIPPLES: DEPTH: ID: SCSSV: DEPTH: ID: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: TBG HD/FLANGE: PROD TREE: SMALLEST ID: DEPTH: PBTD: I ELEVATION: WD: PRESENT PERFS: 0 to 0 Packer Fluid: FROM TO ACTIVITY SUMMARY (Chronological orderfor the last 24 hrs. 6:00 12:00 WOR Notify AOGCC for 9/23 test. 12:00 20:00 Move in equipment 20:00 6:00 ND tree NU BOP , spot well house, mudboat and rig, Raise derrick, Spot tank catwalk, pipe racks. Run and connect all Hydraulic and pump lines. Prep for BOP test ACCIDENTS? HILCORP ENERGY COMPANY DAILY OPERATIONS REPORT REPORTNO. 5 DATE: 9/24/2015 JOB: 11552207 - MPJ-08A ESP Change-out #2 LEASE: I WELL: MP J-08A AFE/PROJ NO: 1552207 FIELD: I COUNTY / PARISH I API#: /500292249700 STATE: ALASKA PRESENT OPERATION AT REPORT TIME: 1POOH DAILY COST: I CUM.JOB COST: AFE Bud et CUM. DRILL COST. CUM. CMP- —CO., Total D&C Cost: REPORTED BY: Wayne BiarlCONTRACTOR REP. PHONE LAST BOP TEST: 907 310 0243 CONTRACTOR I RIG #: /ASR 1 1 9/23/2015 1 NEXT BOP TEST: 9/30/2015 1 FUNC DUE: FLUID: TYPE: WEIGHT. DAILY LOSS: 91 CUM LOSS: T 175 CASING DATA PRODUCTION TUBING SIZE: WT: DEPTH: ID: SIZFJWT/THD: // GRADE ID: SIZE: WT: DEPTH: SIZE: WT: DEPTH: SIZE: WT: DEPTH: ID: EQUIPMENT DATA Packer: SIZE/DEPTH: I/ NIPPLES: DEPTH: ID: SCSSV: DEPTH: ID: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: TBG HDIFLANGE: PROD TREE: SMALLEST ID: I I DEPTH:PBTD: ELEVATION: WD: PRESENT PERFS: 0 to 0 Packer Fluid: FROM TO ACTIVITY SUMMARY (Chronological order for the last 24 hm. 6:00 8:00 PJSM, Continue RU prepare for BOP test. BOPE test waived by John Crisp 0530 AM by E-mail 800 12:00 PJSM, Test all lines 3500 Psi, Test gas detectors Test ROPE, Psi 250/3000, Annular 250/2500, Accumulator draw down test, offload 225 8.5# 150° sea water. 12:00 15:00 PJSM, Pump 42 bbl down mg, 150° sea water, puny 11 bbl down tbg caught psi, hang sheaves, Pick up landing It, BO lock downs 8 pull hanger SW 43K 15:00 3:00 PJSM, BO landing . 8 hanger, POOH, w/ESP, heat trace and ca . Lost generator a8emator continue POOH 3:00 Continue POOH through end of heal trace, continue POOH to —450'. ACCIDENTS? HILCORP ENERGY COMPANY DAILY OPERATIONS REPORT REPORT NO. 6 DATE: 1 9/25/2015 JOB: 1552207 - MPJ -08A ESP Change -out #2 LEASE: WELL: i MP J -08A JAFEIPROJ NO: 1552207 FIELD: COUNTY / PARISH /API#: /500292249700 STATE: ALASKA PRESENT OPERATION AT REPORT TIME: Flowi back N2 DAILY COST: CUM. JOB COST: I AFE Budget CUM. DRILL COST:CUM. CMPL COST. I Total D&C Cost: REPORTED BY: Wayne Biart I CONTRACTOR REP: PHONE LAST BOP TEST: 907 310 0243 CONTRACTOR / RIG M /ASR 1 9/23/2015 NEXT BOP TEST: 9/30/2015 1 FUNC DUE: FLUID: ITYPE, I WEIGHT: DAILYLOSS: CUM LOSS: 175 CASING DATA PRODUCTION TUBING SIZE: WT: DEPTH: ID: SIZFJWilTHD: // GRADE ID: SIZE: WT: DEPTH: SIZE: WT: DEPTH: SIZE: WT: DEPTH: EQUIPMENT DATA Packer: SIZEIDEPTH: / NIPPLES: DEPTH: ID: SCSSV: DEPTH: to: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: TBG HD/FLANGE: PROD TREE: SMALLEST ID: I I DEPTH:I JPBTDIJ ELEVATION: WD: PRESENT PERFS: 0 to 0 Packer Fluid: FROM TO ACTIVITY SUMMARY (Chronological order for the last 24 hn. 6:00 9:30 PJSM continue POOH 11 .G BOILD ESP motor and um assy. Close Blind rams LD Baker equipment 9:30 13:00 O anize floor for standard tubi o erations rack 109 jts 2-3/8" PH -6 5.7# P110 , 1 mule shoe 30.24 x -aver to 2-7/8" eue 1.45'. 13:00 16:30 Pu MU 2-3/8" PH6 Mule shoe RIH w 65j1s 2-3/8" PH -6 5.7# P110 , 1 mules shoe and 109 jts 3395.10'— Change out floor hardware. to 2-7/8" 1630 21:30 PJSM Continue RIH w 2-7/8" to TOL of 4716' TMD. RIH to 8567' PU SO change +- 5K. Repeat 4 times check drag. Cannot interpret load cell weight indicator. 21:30 23:00 RU pump lines to reverse circ. Pump 9 bbl catch fluid 48 bbl get returns oil , pump 42 bbls cleaned up after 20 bbls total pumped 100 WIS. 28 recovered losses at 70%. 23:00 0:00 Blow down /drain up PU sin le make connection cannot ao anv further. LD single rig up to circulate non rotating connection. 0:00 1:00 PJSM RU to reverse circ. previous circ was conventional. Catch pressure at 21 bbls attempt to work down tag is solid@ 6567'. Pump total 33 bbls 3 BPM at 600 psi. No returns obstruction not washi off. LD 2 sin as de th of muleshoe is 6535'. 1:00 2:30 RU Halliburton N2 to pump dawn annulus, returns plumbed to pigging tank, JSA P/T all lines to 3500 psi. Mix 2 drums Baraklean w seawater 8.5 ppg temp 100 " F. 2:30 6:00 Initial pump rate .5 bpm /500 scf work to 1.25bpm11500 scf @ —1300 psi pump 1.75 hrs, heavy sand returns, develop leak in downstream connections, SD/Slops, 107.6 bbls/ 113 rrscf away, repair down 27 minutes SITP —1150 psi. Resume ops 1.25bpm/1000scf @ —1200 psi. OR loading seawater, pump total 200 mcsf 207 bbls seawater chase w 50 bbls seawater. Total 4.5" clean is 1800'total slotted liner clean is 634'. ACCIDENTS? None DAILY OPERATIONS REPORT HILCORP ENERGY COMPANY REPORT NO. 7 DATE: 1 9/26/2015 JOB: 1552207 - MPJ -08A ESP Change -out #2 LEASE: WELL: MP J -08A AFEIPROJ NO: 1552207 FIELD: COUNTY/ PARISH /API#: /500292249700 STATE: ALASKA PRESENT OPERATION AT REPORT TIME: loperations suspended DAILY COST: CUM. JOB COST: AFE Bud et CUM. DRILL COST: CUM. CMPL COST: Total D&C Cost: REPORTED BY: Wayne Bian CONTRACTOR REP: PHONE LAST BOP TEST: 907 310 0243 CONTRACTOR I RIG #: /ASR i 9/23/2015 NEXT BOP TEST: 9/30/2015 FUNC DUE: FLUID: TYPE: WEIGHT: DAILY LOSS: ICUM LOSS: 1 175 CASING DATA PRODUCTION TUBING SIZE: WT: DEPTH: ID: S¢EmT/rHD: // GRADE ID: SIZE: WT: DEPTH: ID: SIZE: WT: DEPTH: ID: SIZE: WT: DEPTH: ID: EQUIPMENTDATA Packer: SIZEIDEPTH: / NIPPLES: DEPTH: ID: SCSSV: DEPTH: ID: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: TBG HD/FLANGE: PROD TREE: SMALLEST ID: I DEPTH: I IPBTD: I ELEVATION: WD: PRESENT PERFS: 0 to 0 Packer Fluid: FROM TO ACTIVITY SUMMARY Chronolo IcaI order for the last 24 hra. 6:00 9:00 PJSM, blow down N2 pressure. 227 bbis recovered. tubinglight blow annulus at 300 si. O en annulus bleed down. 9:00 Line up to pump 50 bbls down annulus, after 4 bbls casing pressure climbed to 1100 psi. Shut down pump begin to bleed oft pressure. Pressure bleeding off stow. Discuss w pusher and proceed to evaluate. 0915 Operator met oo man enroute to pits preceeded by pusher, Disoriented operator a.Vlained 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 11:30 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, BTIW . 11:30 600 Operations suspended until further notice. Three personnel iron incident have been released to work. SICP is 173 psi. ACCIDENTS? Injury DAILY OPERATIONS REPORT HILCORP ENERGY COMPANY REPORT NO. 8 DATE: 1 9/27/2015 JOB: 11552207- MPJ-08A ESP Change-out #2 LEASE: WELL: MP J-08A AFE/PROJ NO: 1552207 FIELD: COUNTY/ PARISH /API#: /500292249700 STATE: ALASKA PRESENT OPERATION AT REPORT TIME: Monitor secured well waiting AOGCC approve to resume operations DAILY COST: CUM. JOB COST: AFE Bud et CUM. DRILL COST. CUM. CMPL COST: Total D&C Cost: REPORTED BY: Wayne Biart CONTRACTOR REP: PHONE LAST BOP TEST: 907 310 0243 CONTRACTOR / RIG M /ASR 1 9/23/2015 NEXT BOP TEST: 9/30/2015 FDNC DUE: FLUID: TYPE: WEIGHT: DAILY LOSS: CUM LOSS: 175 CASING DATA PRODUCTION TUBING SIZE: WT: DEPTH: ID: SIZEWT/rHD: // GRADE ID: SIZE: WT: DEPTH: ID: SIZE: WT: DEPTH: ID: SIZE: WT: DEPTH: ID: EQUIPMENT DATA Packer: SIZE/DEPTH: / NIPPLES: DEPTH: ID: SCSSV: DEPTH: ID: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: TBG HD/FLANGE: PROD TREE: SMALLEST ID: I DEPTH:PBTD: ELEVATION: WD: PRESENT PERFS: 0'.0 to0 Packer Fluid: FROM TO ACTIVITY SUMMARY (Chronological order for the last 24 hm. 6:00 9:30 Well is SI and rig is secured awaiting AOGCC permission to freeze protect well. Investigation continues safety and Investigation team on location 0800. 9:30 10:00 Break down unnecessary lines and organize location monitor well. 1000 12:00 AOGCC permission to Freeze proted well. Rig up lines to blow down well, bypassing all lines still in place from N2 operation. Bleed oRtrapped pressure in choke rtlanifoltl — 100 i. SITP 0 si SICP 640 i. Bleed otf annulus ressure to light blow no fluid in returns. 12:00 PJSM RU LRS PT lines Pump 65 bbls Freeze protect down 7" annulus . Annulus on vac.. Close and lock pipe rams, open annular. Pump 20 bbls freeze 16:00 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 hallibudon pumping HP hose and hardline. 16:00 18:00 Investigation Continues InvesC ation team returns to site. 18:00 6:00 Night crew resumes schedule, NO WELL WORK, work on maintenaince and storage facilities. ACCIDENTS? None HILCORP ENERGY COMPANY REPORT NO. DAILY OPERATIONS REPORT 9 DATE: 9/28/2015 JOB: 11552207- MPJ-08A ESP Change-out #2 LEASE: WELL: MP J-08A JAFEIPROJ NO: 1 1552207 FIELD: COUNTY/PARISH IAPW /500292249700 STATE: I ALASKA PRESENT OPERATION AT REPORT TIME: wailina on AOGCC approwl to resume ops. DAILY COST: CUM. JOB COST: AFE Budget CUM. DRILL COST: ICUM. CMPL COST: Total D&C Cost: REPORTED BY: Wayne Biart CONTRACTOR REP: PHONE LAST BOP TEST: 907 310 0243 9/23/2015 NEXT BOP TEST: CONTRACTOR I RIG #: 9/30/2015 FDNC DUE: /ASR 1 FLUID: TYPE: WEIGHT: DAILY LOSS: CUM LOSS: 1 175 CASING DATA PRODUCTION TUBING SIZE: WT: DEPTH: ID: SIZENJT?HD: // GRADE ID: SIZE: WT: DEPTH: ID: f/ SIZE: WT: DEPTH: ID: SIZE: WT: DEPTH: ID: # EQUIPMENT DATA Packer: SIZEIDEPTH: I/ NIPPLES: DEPTH: ID: SCSSV: DEPTH: ID: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: TBG HD/FLANGE: PROD TREE: SMALLEST ID: I DEPTH: I jPBTD:jELEVATION: WD: PRESENT PERFS: 0 to 0 Packer Fluid: FROM I TO ACTIVITY SUMMARY (Chronological order Tor the last 24 hw. &00 W/O AOGCC approwl. ACCIDENTS? HILCORP ENERGY COMPANY REPORT NO. DAILY OPERATIONS REPORT 10 DATE: 9/29/2015 JOB: 71552207- MPJ-08A ESP Change-out #2 LEASE: WELL: MP J-08A AFEIPROJ NO: 1552207 FIELD: COUNTY /PARISH /API#: /500292249700 STATE: ALASKA PRESENT OPERATION AT REPORT TIME: lWaltina on AOGCCA royal To Resume Operations DAILY COST: 1 CUM. JOB COST: AFE Bud et CUM. DRILL COST: CUM. CMPL COST. Total D&C Cost: REPORTED BY: Wayne Biart CONTRACTOR REP. PHONE LAST BOP TEST:TYPE: 907 370 0243 9/23/2015 NEXT BOP TEST: CONTRACTOR I RIG #: 9/30/2015 FDNC DUE: /ASR 7 FLUID: WEIGHT: DAILY LOSS: CUM LOSS: 175 CASING DATA PRODUCTION TUBING SIZE: WT: DEPTH: ID: SIZENJT/THD: // GRADE ID: SIZE: WT: DEPTH: SIZE: WT: DEPTH: ID: SIZE: WT: DEPTH: ID: EQUPMENT DATA Packer: SIZE/DEPTH: / NIPPLES: DEPTH: I. SCSSV: DEPTH: ID: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: TBG HD/FLANGE: PROD TREE: SMALLEST 10: 1 DEPTH: I PBTD:j ELEVATION: WD: PRESENT PERFS: 0 to 0 Packer Fluid: FROM TO ACTIVITY SUMMARY Chromlo ical order for the last 24 hm. 6:00 6:00 Waiting on AOGCC a roval to resume operation ACCIDENTS? HILCORP ENERGY COMPANY REPORT NO. DAILY OPERATIONS REPORT 11 DATE: 1 9/30/2015 JOB: 1552207- MPJ-08A ESP Change-out#2 LEASE: WELL: MP J-OSA AFE/PROJ NO: 1552207 FIELD: I COUNTY/PARISH /API#: /500292249700 STATE: ALASKA PRESENT OPERATION AT REPORT TIME: lWaitina on AOGCCa roval to resume operations DAILY COST: CUM. JOB COST: AFE Budget CUM. DRILL COST: CUM. CMPL COST: Total D&C Cost: REPORTED BY: Wayne Start CONTRACTOR REP: PHONE LAST BOP TEST: 907 310 0243 9/23/2015 NEXT BOP TEST: CONTRACTOR / RIG #: 9/30/2015 FDNC DUE: /ASR 1 FLUID: TYPE: WEIGHT: DAILY LOSS: ICUM LOSS: 1 175 CASING DATA PRODUCTION TUBING SIZE: WT: DEPTH: ID: SIZEMRRHD: 9 GRADE ID: SIZE: WT: DEPTH: 10: SIZE: WT: DEPTH: ID: SIZE: WT: DEPTH: ID: EQUIPMENT DATA Packer. SIZE/DEPTH: / NIPPLES: DEPTH: ID: SCSSV: DEPTH: ID: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: TBG HD/FLANGE: PROD TREE: SMALLEST ID: I DEPTH: I JPSTD, I ELEVATION: WD: PRESENT PERFS: 0 to 0 Packer Fluid: FROM TO ACTIVITY SUMMARY (Chronological order for the last 24 hm. 5:00 8:00 Waiting on AOGCC approval to resume operations ACCIDENTS? DAILY OPERATIONS REPORT HILCORP ENERGY COMPANY REPORT NO. 12 DATE: 10/1/2015 JOB: 1552207 - MPJ-08A ESP Change-out #2 LEASE: WELL: MPJ-08A AFE/PROJ NO: 1552207 FIELD: COUNTY/ PARISH IAPI#: /500292249700 STATE: ALASKA PRESENT OPERATION AT REPORT TIME: IAOGCC proval to resume Ops, Landed Workstring and Pe for BOPS Test DAILY COST: CUM. JOB COST: AFE Budget CUM. DRILL COST: CUM. CMPL COST: Total DRC Cost: REPORTED BY: Wade Hudgens CONTRACTOR REP: PHONE 907 310 0243 CONTRACTOR I RIG #: /ASR 1 LAST BOP TEST: 9/23/2015 NEXT BOP TEST: 9/30/2015 FDNC DUE: FLUID: TYPE: WEIGHT: DAILY LOSS: ICUM LOSS: 175 CASING DATA PRODUCTION TUBING SIZE: WT: DEPTH: ID: SIZ—TITM // GRADE ID: SIZE: WT: DEPTH: ID: SIZE: WT: DEPTH: ID: SIZE: WT: DEPTH: ID: I EQUIPMENT DATA Packer: EIDEPTH: / NIPPLES: ID: SCSSV: DEPTH: 10: NIPPLES: ID: NIPPLES: ID: ]][gD�PTH: NIPPLES: ID: TBG HD/FLANGE: PROD TREE: SMALLEST ID: DEPTH: P8TD: I ELEVATION: WD: PRESENT PERFS: 0 to 0 Packer Fluid: FROM TO ACTIVITY SUMMARY (Chronological order for the last 24 hrs. 6:00 14:00 Waiting on AOGCC approval to resume operations 14:00 Approval from the AOGCC to resume operation. Hell PJSM, MIRU LRS and tested to 3,000psttest ok. Pumped ISbbls of60/40 methanol down tbg broke 17:30 circulation up the asg to the erdernal 500bbis kill tank. With tbg under balanced with methanol bullheaded 20 bbS of seawater down tbg and monitored tbg on a vac. Resend ROPE test notice with estimated test time. 17:30 16:00 Held PJSM with M crew. Notified b the state that no waiver will be given for RigavitiAies until ROPE test is completed. 1800 21:00 BOLD TIW valve, MU/PU LandingJt Hanged with TWC installed and landed secured hanged with LDS. 21:00 6:00 Perp for BOPE Testing, Preformed Shell Test, Function tested SOP's and gas detection system. Notified Inspector that we are ready to begin testing at 06:00. ACCIDENTS? HILCORP ENERGY COMPANY DAILY OPERATIONS REPORT REPORT NO. 13 GATE: 10/2/2015 JOB: 1552207- MPJ -08A ESP Change -out #2 LEASE: WELL: MP J -08A AFE/PROJ NO: 1552207 FIELD: COUNTY(PARISH IAPUI: /500292249700 STATE: ALASKA PRESENT OPERATION AT REPORT TIME: Test ROPE TOH w/workstrin . PU RIH w/new ESP DAILY COST. CUM. JOB COST: AFE Budget CUM. DRILL COST: CUM. CMPL COST. Total D&C Cost: REPORTED BY: Wade Hudgens ICONTRACTOR REP: PHONE LAST BOP TEST: 907 310 0243 CONTRACTOR / RIG #: /ASR 1 9/23/2015 NEXT BOP TEST: 9/30/2015 FUNC DUE: FLUD: TYPE: seawater WEIGHT: 8.4 DAILY LOSS: 90 CUM LOSS: 1 265 CASING DATA PRODUCTION TUBING SIZE: WT: DEPTH: ID: sIZEA4TRHD: // GRADE ID: SIZE: WT: DEPTH: SIZE: Wi: DEPTH: ID: SIZE: WT: DEPTH: ID: // EQUIPMENT DATA Packer: SIZE/DEPTN: / NIPPLES: DEPTH: ID: SCSSV: DEPTH: ID: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: TBG HD/FLANGE: PROD TREE: SMALLEST ID: DEPTH: PBTD: I ELEVATION: WD: PRESENT PERFS: 0 to 0 Packer Fluid: FROM TO ACTWITY SUMMARY (Chronological order for the last 24 hm. 6:00 6:30 Held PJSM 6:30 8:00 Waited on State Inspector to arrive. Pe foe BOP Test 8:00 12:30 Preformed BOPE Testing with AOGCC Inspector Chuck Scheve as follows; Valves 250-3,00psi, Raps 250.3,000psi, Annular 250-3,000psi, Gad Dection and Accumulator drawdown test. 1 FP was recordedon C-12. 12:30 14:30 PJSM, Pulled TWC MU landing' and pulled hanger to ' floor BO/LD same. 14:30 21:30 TOH/LD 149' of 2-7/8" Srd 1, sof 2-3/8" and mule shoe usin cha e u to kee tyle full. 21:30 I c 2:00 PU/MU and serviced new ESP assembl . S,n cable over sheave, made motor and ca connection. 2:00 600 TIH w/new ESP on 2-7/8" 8rd Tbg with wl-nipple and lower GLM(dummy), continued RIH ACCIDENTS? None DAILY REPORT HILCORP ENERGY COMPANY REPORT NO. 14 DATE: 10/3/2015 JOB: 11552207- MPJ-08A ESP Change-out #2 LEASE: I WELL: MP J-08A AFE/PROJ NO: 1552207 FIELD: COUNTY /PARISH/API#: /500292249700 STATE: ALASKA PRESENT OPERATION AT REPORT TIME: ITIH WESP Completion DAILY COST: CUM. JOB COST: IAFEBud et CUM. DRILL COST. CUM. CMPL COST: Total O&C Cost: REPORTED BY: Wade Hudgens CONTRACTOR REP: PHONE LAST BOP TEST: 907 310 0243 CONTRACTOR / RIG #: /ASR 1 9/23/2015 NE%T BOP TEST: 9/30/2015 FDNC DUE: FLUID: TYPE: WEIGHT: I DAILY LOSS: ICUM LOSS: 1 265 CASING DATA I PRODUCTION TUBING SIZE: WT: DEPTH: AV ID: SIZET/THD: // GRADE ID: SIZE: WT: DEPTH: ID: SIZE: WT: DEPTH: ID: // SIZE: I WT: DEPTH: ID: I EQUIPMENT DATA Packer: I SIZE/DEPTH: / NIPPLES: DEPTH: ID: SCSSV: DEPTH: ID: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: TBG HD/FLANGE: PROD TREE: SMALLEST ID: DEPTH: IPBTD:l ELEVATION: WD: PRESENT PERFS: 0 to 0 Packer Fluid: FROM TO ACTIVITY SUMMARY (Chronological order for the last 24 ho. 6:00 6:30 Held PJSM and walk through wuth changeout crew 6:30 8:00 Continued TIH with ESP completion. PU Heat Trace at 2,992'. 8:00 PU top GLM continued TIH w/ ESP completion from Hanger depth, Top of Tool Detphs as following:Hanger, Pup, 4 its 2-7/8 L-80 6.5# tbg, pup, GLM @ 4:30 174', jls ibg, pup GLM @ 4,395', 4.jts ibg, XN Nip 'a4,537', pup. Head 4,548', Pump @ 4,549 gas separator 4,572', Tandem Seals @ 4,577', Motor 4,591', Pum mate 4,598', Centralizer 4,800', EOC 4,602'. 430 6:00 Heat Trace Spool was 40' short of 3,000'. Made splice 2" s down from hanger. Continued splice at report 8me ACCIDENT 57 None HILCORP ENERGY COMPANY DAILY OPERATIONS REPORT REPORT NO. 15 DATE: 10/4/2015 JOB: 11552207 - MPJ -08A ESP Change -out #2 LEASE: WELL: MP J -08A AFE/PROJ NO: 1552207 FIELD: COUNTY/ PARISH / API#: /500292249700 STATE: I ALASKA PRESENT OPERATION AT REPORT TIME: Land ESP Completion, RDMO well to Production DAILY COST. CUM. JOB COST: AFE Budget: CUM. DRILL COST: ICUM. CMPL COST: Total D&C Cost: REPORTED BY: Wade Hudgens CONTRACTOR REP: PHONE LAST BOP TEST: 907 310 0243 CONTRACTOR / RIG #: /ASR 1 9/23/2015 NEXT BOP TEST: 9/30/2015 FUNC DUE: FLUID: TYPE: seawater WEIGHT: 8.5 DAILY LOSS: 1 130 ICUM LOSS: 1 395 CASING DATA PRODUCTION TUBING SIZE: WT: DEPTH: ID: SIZE11 T/THD: H GRADE ID: SIZE: WT: DEPTH: ID: SIZE: WT: DEPTH: ID: SIZE: WT: DEPTH: ID: EQUIPMENT DATA Packer. SIZE/DEPTH: I/ NIPPLES: DEPTH: ID: SCSSV: DEPTH: ID: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: NIPPLES: DEPTH: ID: TBG HDIFLANGE: PROD TREE: SMALLESTID: DEPTH: PBTD: I ELEVATION: WD; PRESENT PERFS: 0 to 0 1 Packer Fluid: FROM TO ACTIVITY SUMMARY (Chronological order for the last 24 hrs. 600 6:30 Held PJSM and walk thru with crew. 6:30 14:00 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 K 43up 41 k down. Run in lock down screws. Set BPV. 15:00 0:00 RDMO ASR 1 and associated equipment and stacked on A Pad. 0:00 6:00 ND BOP's and NU Production Tree and tested-ok. Well transfered over to production. ACCIDENTS? Response 10 Attachment ASR 1 Fire and Gas Equipment Inventory ASR 1 Fire and Gas Alarm Log for 23 September 2015, tests highlighted in yellow ASR 1 Fixed Fire and Gas Detection and Alarm System Equipment Ta Equipment T e Location Action on Alarm SSR -GD -01 Combustible Gas Mudpit Trailer "Generator Room" 20% "Low"LEL alarm or 40% "High" LEL alarm activate audible notification (methane) detector appliances and combustible gas visual (clear strobe) notification applicances SSR -GD -02 Combustible Gas Mudpit Trailer "Mud Pump Room' 20% "Low"LEL alarm or 40% "High" LEL alarm activate audible notification (methane) detector appliances and combustible gas visual (clear strobe) notification applicances SSR -GD -03 Combustible Gas Mudpit Trailer "Mud Pump Room" 20% "Low"LEL alarm or 40% "High" LEL alarm activate audible notification (methane) detector (above shale shaker) appliances and combustible gas visual (clear strobe) notification applicances SSR -GD -04 Combustible Gas Mudpit Trailer "Choke Room" 20% "Low"LEL alarm or 40% "High" LEL alarm activate audible notification (methane) detector appliances and combustible gas visual (clear strobe) notification applicances SSR -GD -OS H25 detector (20ppm) Mudpit Trailer "Mud Pump Room" 10 PPM Low Alarm and 15 PPM High Alarm Activate audible notification appliances and H2S visual (amber strobe) notification applicances SSR -GD -06 H2S detector (20ppm) Mudpit Trailer "Mud Pump Room" 10 PPM Low Alarm and 15 PPM High Alarm Activate audible notification (near shale shaker) appliances and H2S visual (amber strobe) notification applicances SSR -GD -07 H25 detector (20ppm) Mudpit Trailer "Mud Pump Room" 10 PPM Low Alarm and 15 PPM High Alarm Activate audible notification appliances and 1-12S visual (amber strobe) notification applicances ASR -GD -01 H2S detector (20ppm) ASR -1 "cellar" 10 PPM Low Alarm and 15 PPM High Alarm Activate audible notification appliances and H2S visual (amber strobe) notification applicances ASR -GD -02 Combustible Gas ASR -1 "cellar" 20% "Low"LEL or 40% "High" LEL activate audible notification appliances (methane) detector and H2S visual (amber strobe) notification applicances ASR -GD -03 Combustible Gas ASR -1 "drill floor" 20% "Low"LEL or 40% "High" LEL activate audible notification appliances (methane) detector and 112S visual (amber strobe) notification applicances ASR -GD -04 H2S detector (20ppm) ASR -1 "drill floor" 10 PPM Low Alarm and 15 PPM High Alarm Activate audible notification appliances and H2S visual (amber strobe) notification applicances V Controller Logs Datefiane Points Channel # Alar Tvae Twwjne Event Text Value 9/22/2015 9:23:57 AM 1 2 Output Inhibit HI GAS_RELAY Intubit FALSE 9122/2015 9:23:59 AM 1 1 Output Lthibit FIRE_RLY Inhibit FALSE 9/22/2015 9:54:29 AM 1 2 Supervisory SSR_FLAME_DET PChsnnel Active TRUE 9/22/2015 9:54:30 AM 1 1 Supervisory SSR_GAS_DET BYPChanncl Active TRUE 9122/2015 9:54:31 AM 1 3 Supervisory ASR—GAS—DET BYIChamul Active TRUE 9/22/2015 9:57:00 AM 16 N/A High Gas SSR-GD-03 High Alarm TRUE 9/22/2015 9:57:00 AM 16 NIA Low Gas SSR-GD-03 Low Alar TRITE 912212015 9:57:07 AM 16 NIA High Gas SSR-GD-03 High Alar FALSE 9/22/2015 9:57:08 AM 16 NIA Low Gas SSR-GD-03 Low Alarm FALSE 9/22/2015 9:57:22 AM 16 N/A Low Gas SSR-GD-03 Low Alarm TRUE 9/222015 9:57:23 AM 16 NIA high Gas SSR-GD-03 High Alarm 'TRUE 9222015 9:57:26 AM 16 N/A HA Gas SSR-GD-03 Hipp Alar FALSE 9222015 9:57:27 AM 16 NIA Low Gas SSR-GD-03 Low Alar FALSE 922/2015 9:57:36 AM I NIA No Alar (Evert) SSR-FAGCP-01 Reset Activated TRUE 9222015 9:58:07 AM 16 N/A Trouble SSR-GD-03 Sensor Fault TRUE 9222015 9:58:07 AM 16 NIA Trouble SSR-GD-03 Dirty Optics TRUE 922/2015 9:58:14 AM 16 N/A Trouble SSR-OD-03 Sensor Fault FALSE 9222015 9:58:14 AM 16 NIA Trouble SSR-GD-03 Dirty Optics FALSE 9222015 9:58:44 AM 14 N/A Trouble SSR-GD-02 Sensor Fault TRUE 9222015 9:58:50 AM 14 NIA Trouble SSR-GD-02 Sensor Fault FALSE 922/2015 9:59:16 AM 14 NIA Trouble SSR-GD-02 Sensor Fault TRUE 9222015 9:59:21 AM 14 NIA Trouble SSR-GD-02 Sensor Fault FALSE 922201510:01:29 AM 1 NIA No Alar (Event) SSR-FAGCP-01 Reset Activated TRUE 922/2015 10:01:33 AM 1 NIA No Alar (Event) SSR-FAGCP-01 Reset Activated TRUE 922201510:06:45 AM 1 1 Supervisory SSR GAS DBT_BYPCha nel Active FALSE 9222015 10:06:46 AM 1 2 Supervisory SSR_FLAMB_DET_IChannet Active FALSE 9222015 10:06:46 AM 1 3 Supervisory ASR GAS_DET BYIChannel Active FALSE 9222015 10:06:50 AM 1 NIA No Alum (Event) SSR-FAGCP-01 Reset - Faceplate Button TRUE 9232015 8:07:53 AM I NIA No Alar (Event) Ver 12.37 Power-Up TRUE 923/2015 8:07:56 AM 1 NIA No Alnr (Event) SSR-FAGCP-01 at Program Mode TRUE 9232015 8:07:59 AM 1 NIA No Alar (Event) SSR-FAGCP-01 Enter Standby Mode TRUE 9232015 8:07:59 AM 1 NIA No Alarm (Event) SSR-FAGCP-01 Enter Master Mode TRUE 9232015 8:08:04 AM 1 NIA Trouble SSR-FAGCP-01 Download Active TRUE 9232015 8:08:22 AM 1 N/A Trouble SSR-FAGCP-01 Download Active FALSE 92312015 8:08:26 AM 1 NIA No Alar (Event) SSR-FAGCP-01 Reset - Faceplate Button TRUE 9/2312015 8:15:09 AM I1 NIA Low Gas SSR-GD-01 Low Alar TRUE 9/232015 8:15:14 AM 11 NIA High Gas SSR-GD-01 High Alar TRUE 923/2015 8:15:18 AM 1 N/A No Alar (Event) SSR-FAGCP-01 Acknowledge - Faceplate Button TRUE 9232015 8:15:26 AM 1 NIA No Alarm (Event) SSR-FAGCP-01 Silence - Faceplate Button TRUE 9232015 8:15:28 AM 11 NIA High Gas SSR-GD-01 High Alarm FALSE 9/232015 8:15:52 AM 1 NIA No Alarm (Event) SSR-FAGCP-01 Reset - Faceplate Button TRUE DateMme Pc Charnel# Alarm Type TeonAme Event Text V Controller Logs Value 9/23!2015 8:15:54 AM I 1 NIA Low Gas SSR -GD -01 Low Alarm FALSE 9/23/2015 8:15:54 AM 1 NIA No Alarm (Event) SSR-FAGCP-01 Reset - Faceplate Button TRUE 9/23/2015 8:16:40 AM 14 N/A Low Gas SSR -GD -02 Low Alam TRUE 9/23/2015 8:16:44 AM 14 N/A High Gas SSR -GD -02 high Alarm TRUE 9/23/2015 8:16:48 AM 1 N/A No Alun (Event) SSR-FAGCP-01 Acknowledge - Faceplate Button TRUE 9/23/2015 8:16:54 AM 1 NIA No Alum (Event) SSR-FAGCP-0 t Silence - Faceplate Button TRUE 9/232015 8:17:25 AM 1 N/A No Alum (Event) SSR-FAGCP-01 Reset - Faceplate Button TRUE 9232015 8:17:26 AM 16 N/A Low Gas SSR -GD -03 Low Alarm TRUE 9232015 8:17:27 AM 1 NIA No Alarm (Event) SSR-FAGCP-01 Reset - Faceplate Button TRUE 9/232015 8:17:30 AM 16 N/A HWI Gas SSR -GD -03 High A.I.I. TRUE 9232015 8:17:32 AM 14 NIA High Gas SSR -GD -02 High Alarm FALSE 9232015 8:17:34 AM I NIA No Alarm (Event) SSR-FAGCP-01 Silence - Faceplate Button TRUE 9232015 8:17:59 AM 16 NIA High Gas SSR -GD -03 High Alarm FALSE 9232015 8:18:36 AM 16 N/A Low Gas SSR -GD -03 Low Alarm FALSE 9232015 8:18:46 AM I NIA No Alum (Event) SSR-FAGCP-01 Reset - Faceplate Button TRUE 9232015 8:18:47 AM 1 NIA No Alam (Event) SSR-FAGCP-01 Reset - Faceplate Button TRUE 9232015 8:18:56 AM 18 NIA Low Gas SSR -GD -04 Low Alarm TRUE 9232015 8:18:59 AM 18 N/A Hipjt Gas SSR -GD -04 High Alun TRUE 9232015 8:19:02 AM 14 NIA Low Gas SSR -GD -02 Low Alarm FALSE 9232015 8:19:07 AM 1 NIA No Alarm (Event) SSR-FAGCP-01 Silence - Faceplate Button TRUE 9/232015 8:19:21 AM 1 N/A No Alarm (Event) SSR-FAGCP-01 Reset - Faceplate Button TRUE 9232015 8:19:22 AM 1 NIA No Alarm (Event) SSR-FAGCP-Ol Reset - Faceplate Button TRUE 9232015 8:19:23 AM 18 N/A High Gas SSR -GD -04 High Alarm FALSE 9/232015 8:19:25 AM 18 NIA Low Gas SSR -GD -04 Low Alum FALSE 9232015 8:19:37 AM 1 N/A No Alum (Event) SSR-FAGCP-0l Reset - Faceplate Button TRUE 9232015 8:21:21 AM 13 NIA Low Gas SSR -GD -05 Low Alarm TRUE 9232015 8:21:24 AM 13 N/A High Gas SSR -GD -05 High Alarm TRUE 9232015 8:21:27 AM 1 N/A No Alarm (Event) SSR-FAGCP-01 Acknowledge - Faceplate Button TRUE 9232015 8:21:34 AM 1 NIA No Alum (Event) SSR-FAGCP-01 Silence - Faceplate Button TRUE 9232015 8:21:34 AM 13 N/A MO Gas SSR -GD -05 Htigh Alum FALSE 9232015 8:21:39 AM 13 NIA Low Gas SSR -GD -05 Low Alcorn FALSE 9232015 8:21:42 AM 1 N/A No Alarm (Event) SSR-FAGCP-01 Reset - Faceplate Button TRUE 923/2015 8:22:09 AM 15 N/A Low Gas SSR -GD -06 Low Alun TRUE 9/232015 8:22:11 AM 15 NIA High Gas SSR -GD -06 High Alarm TRUE 9232015 8:22:19 AM 1 NIA No Alun (Event) SSR-FAGCP-01 Acknowledge - Faceplate Button TRUE 9232015 8:22:20 AM 1 NIA No Alarm (Event) SSR-FAGCP-01 Silence - Faceplate Button TRUE 9232015 8:22:35 AM 15 NIA High Gas SSR -GD -06 Hugh Alarm FALSE 9232015 8:22:37 AM 15 NIA Low Gas SSR -GD -06 Low Alun FALSE 9232015 8:22:37 AM 1 NIA No Alum (Event) SSR-FAGCP-01 Reset - Faceplate Button TRUE 9232015 8:23:20 AM 21 NIA Low Gas SSR -GD -07 Low Alun TRUE 9232015 8:23:23 AM 21 NIA High Gas SSR -GD -07 High Alarm TRUE V Controller Logs Datefrime Point # Channel # Alarm Type T a ame Event Text Value 923/2015 8:23:26 AM 1 N/A No Alarm (Event) SSR-FAGCP-01 Acknowledge - Faceplate Button TRUE 9232015 8:23:27 AM 1 NIA No Almm (Event) SSR-FAGCP-01 Acknowledge - Faceplate Button TRUE 9232015 8:23:31 AM 1 N/A No Alarm (Event) SSR-FAGCP-01 Silence - Faceplate Button TRUE 9232015 8:23:49 AM 21 NIA High Gas SSR -GD -07 High Alarm FALSE 9232015 8:23:53 AM 21 NIA Low Gas SSR -GD -07 Low Alarm FALSE 923/2015 8:23:55 AM 1 NIA No Alarm (Event) SSR-FAGCP-01 Reset - Faceplate Button TRUE 9232015 8:23:55 AM 1 NIA No Alarm (Event) SSR-FAGCP-01 Reset - Faceplate Button TRUE 9232015 8:24:26 AM 5 1 Fire Alum SSR -PS -01 Channel Active TRUE 923/2015 8:24:27 AM 5 1 Fire Almm SSR -PS -01 Charnel Active FALSE 92312015 8:24:33 AM 1 N/A No Almm (Event) SSR-FAGCP-01 Silence - Faceplate Button TRUE 9232015 8:24:34 AM 1 N/A No Almm (Event) SSR-FAGCP-01 Reset - Faceplate Button TRUE 9/232015 8:25:18 AM 24 NIA Low Gas ASR -GD -01 Low Alarm TRUE 9232015 8:25:20 AM 24 N/A High Gas ASR -GD -01 High Alamn TRUE 923(2015 8:25A 1 AM 24 NIA High Gas ASR -GD -01 High Alarm FALSE 9232015 8:25:44 AM 24 NIA Low Gas ASR -GD -01 Low Alarm FALSE 9123/2015 8:25:44 AM I N/A No Alsem (Event) SSR-FAGCP-01 Silence - Faceplate Button TRUE 9232015 8:25:46 AM 1 N/A No Alarm (Event) SSR-FAGCP-01 Reset - Faceplate Button TRUE 9/2312015 8:26:03 AM 23 N/A Low Gas ASR -GD -02 Low Alarm TRUE 9232015 8:26:08 AM 23 N/A High Gas ASR -GD -02 TE& Alamn TRUE 9232015 8:26:18 AM 1 NIA No Almm (Event) SSR-FAGCP-01 Silence - Faceplate Button TRUE 91232015 8:26:18 AM 23 NIA High Gas ASR -GD -02 High Alarm FALSE 9232015 8:26:20 AM 23 N/A Low Gas ASR -GD -02 Low Alarm FALSE 9232015 8:26:26 AM 1 NIA No Alarm (Event) SSR-FAGCP-01 Reset - Faceplate Button TRUE 9/232015 8:27:58 AM 25 NIA Low Gas ASR -GD -03 Low Alamn TRUE 9232015 8:28:01 AM 25 N/A MO Gas ASR -GD -03 High Alarm TRUE 9/232015 8:28:07 AM 1 N/A No Alarm (Event) SSR-FAGCP-0l Silence - Faceplate Button TRUE 9232015 8:28:08 AM 25 NIA HLSgh Gas ASR -GD -03 High Alum FALSE 9/232015 8:28:18 AM 25 N/A Low Gas ASR -GD -03 Low Alarm FALSE 9232015 8:28:19 AM 1 NIA No Alarm (Event) SSR-FAGCP-01 Reset - Faceplate Button TRUE 9232015 8:28:57 AM 26 NIA Low Gas ASR -GD -04 Low Almm TRUE 923/2015 8:28:59 AM 26 N/A High Gas ASR -GD -04 High Alann TRUE 9232015 8:29:09 AM 1 N/A No Alarm (Event) SSR-FAGCP-01 Silence - Faceplate Button TRUE 9232015 8:29:22 AM 26 N/A High Gas ASR -GD -04 HO Alarm FALSE 9232015 8:29:27 AM 26 N/A Low Gas ASR -GD -04 Low Alum FALSE 9232015 8:29:31 AM 1 NIA No Alarm (Event) SSR-FAGCP-01 Reset - Faceplate Button TRUE 9232015 8:30:19 AM 10 NIA Flee Alam SSR -FD -01 Fire Alarm TRUE 9232015 8:30:28 AM 1 NIA No Alarm (Event) SSR-FAGCP-01 Silence - Faceplate Button TRUE 9232015 8:30:29 AM 10 NIA Fire Ala un SSR -FD -01 Fire Alarm FALSE 923/2015 8:30:29 AM 1 N/A No Alum (Event) SSR-FAGCP-01 Reset - Faceplate Breton TRUE 9/242015 2:58:33 AM 250 N/A Trouble PSM -250 AC Failed TRUE 9242015 9.01:09 AM 15 NIA Low Gas SSR -GD -06 Low Alamn TRUE Response 11 Attachment ASR 1 tank module HVAC calculation sheet, prepared by Mr. Augustino Bacher, PE, of H&K Sheetmetal H & K SHEETMETAL FABRICATORS, INC. 6517 ARCTIC SPUR RD. ANCHORAGE, ALASKA 99518 (907) 561-8746 FAX (907) 561-7969 E-MAIL: frontdesk@hksheetmetalfab.com SHEET OF CALCULATED BY DATE CHECKED BY SCALE DATE Regg, James B (DOA) From: Trudi Hallett <thallett@hilcorp.com> Sent: Thursday, October 08, 2015 10:43 AM To: Regg, James B (DOA); Daniel Duckworth - (C) Cc: Ted Kramer; Dan Marlowe; Harold Soule - (C); Schwartz, Guy L (DOA); Juanita Lovett Subject: RE: AN -46 / Moncla 404 Sundry No. 315-555, PTD: 182-072 Attachments: An -46 Schematic as of 2015-10-07.pdf, Scan0008.pdf; Scan0007.pdf Mr. Regg -- attached is the summary for the Anna 46 final day of well work complying with the AOGCC's workover suspension mandate. I have also attached the current (as -is) wellbore schematic and pressure test charts. Please let me know if there is any add'I information you need. All rig crews and support personnel are standing by until further notice. r� Nilcorp Alaska, LLC Operations Summary W i Namt _-P11 NNumbef WtA Perm t Numb-er Sundr§° s Granite Pt St 18742 #46 50-733-20355-00 182-072 315-555 Daily Operations: 10/06115 -T ae sddy Circulated hole clean at 4,200' sending returns to production. Reduced rate to 2 BPM 200 PSI to match rate fluid was going to production. Diluted drilling mud in returns. No gas after bottoms up. Full returns. 8/0 L/D power swivel. N/D 13 3/8 x 7 1/16" stripping head. N/U 11" x 13 3/8" spool. POOH w/ 12" Varel rock bit and Swaco scraper f/ 13 3/8" casing. 3/0 bet & scraper. M/U Tripoint CIBP f/ 13 3/8" 72# casing w/ running tool on 3 1/2" 12.95# PH -6 workstring. TI (as directed by Tripoint) to 4,200' and tagged 9 5/8" stub lightly (P/U 56k S/0 50K). Picked up to 4,190' and set CIS?. Tested plug to 15009s. Rotated out of SP and pulled up 2'. R/U SL8 cementing (held PJSM discussing cement procedure at tour change) and tested iron to 200#s. Opened well and established circ. Spotted 5 bbls of 15.8 pp& yield 1.16 h/sx, 5.107 gal/sx DW cement on top of CIBP at 4,190' holding 300#s BP. TOC est at 4,157'. 8/0 HP cementing lines (well balanced) & pulled two stands. Reversed out two tbg volurnes at 4,066'. Tested 13 3/8" to 1500#s on chart for 30 n1ins. POOH w/ 3 1/2" PH6 workstring. B/O Tripoint running tool. M/U 3 1/2" mule shoe and TIH tier/ PH6 workstring to 3,784'. M/U Halb storm pkr w/ valve + 3 stands (211.03') and continued in hole setting pkr in 13 3/8"° casing at 207'. Released from pkr and POOH laying down 3 stands of workstring. Tested storm pkr to 1500#s for 30 mins on chart. Closed blinds and began preparing rig for inactivity. Thanks Tr k4i., From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Monday, October 05, 2015 10:08 AM To: Daniel Duckworth - (C); Trudi Hallett Cc: Ted Kramer; Dan Marlowe; Harold Soule - (C); Schwartz, Guy L (DOA) Subject: RE: AN -46 / Moncla 404 Thank you. OK to install second barrier (C|BPand cement) inthe 133/8"atthe top of9S/8"casing. What are your plans to verify the plug? How much cement on top of the CIBP is planned. When work is completed, send a summary of the work to suspend the well (including actual plug setting depth and volume of cement) and a schematic of the well's configuration. ]imRegg Supervisor, Inspections AOGCC }BW.7th Ave, Suite 100 Anchorage, AK 99501 907'793'1236 CONFIDENTIALITYNOTICE: This e-rnail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (m]GC[)'State nfAlaska and isfor 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-nnail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236or From: Daniel Duckworth '(C) Sent: Monday October 05, 2015 9:40 AM To: Regg,James B(DDA) Cc:Trudi Hallett; Ted Kramer; Dan Marlowe; Harold Soule '(C) Subject: RE: AN -46/ Monc|a 404 Presently vveonly have one barrier inthis well which isour blind rams- the top ufthe 9S/O"is4,193'and the b!mofthe 13 3/8" is 4'232' The top of the cement behind our 9 5/8" is calculated to be 6,003'' we need that second barrier (C|BP & cement) inour 13 3/8"atthe top ofthe 9S/8" Please advise, thanks! From: Regg,James B(DOA) Sent: Monday October 05, 2015 9:20 AM To: Daniel Duckworth '(C) Subject: RE: AN -46 / Moncla 404 Ok to remove double gate from BOPE stack and shell test the stack. Unclear the status of your well and how it is secured. ]imRegg Supervisor, Inspections AOGCC B3w.7th Ave, Suite 100 Anchorage AK 99501 907-7e3-1236 CONFIDENTIALITY NOTICE: This e-mail r-nessage, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. if you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or . From: Daniel Duckworth '(C) Sent: Sunday October 04, 2015 4:47 PM Cc: Trudi Hallett; Ted Kramer Subject: AN -46 / Moncla 404 Mr. Jim at the rate we're laying 9 5/8" casing down we should be out of the hole in the early hrs of the morning. We will close the blind rams at that point. If permitted we would like to remove that dual ram stack w/ the 9 5/8" blocks since they're not needed anymore- shell test the stack and be prepared to P/U 13 3/8" cleanout assy inorder to plug off that casing w/ CIBP & cement. Please advise as to how far we can go, thanks! Begg, James B (DOA) From: Regg, James B (DOA) Sent: Tuesday, October 06, 2015 2:25 PM To: 'Chad Helgeson'; David Wilkins Cc: Taylor Nasse Subject: RE: SRU 213-15 As stated below, non -rig work is allowed to continue if covered by an existing approved sundry. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907-793-1236 or jim.regg@alaska.gov. -----Original Message ----- From: Chad Helgeson [mailto:chelgeson@hilcorp.com] Sent: Tuesday, October 06, 2015 11:36 AM To: Regg, James B (DOA); David Wilkins Cc: Taylor Nasse Subject: RE: SRU 213-15 Jim, Thanks for the clarification, We planned to do some additional perf add work this week on some existing Sundries. Kenai Gas Field, KBU 31-18 Sundry # 315-493, PTD# 215-024 Cannery Loop Unit, CL#13 Sundry # 315-480, PTD# 214-171 Is it okay to continue with plans for perf adds on these projects in accordance with these sundries? Chad -----Original Message ----- From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Tuesday, October 06, 2015 9:12 AM To: David Wilkins Cc: Chad Helgeson Subject: RE: SRU 213-15 Wireline/slickline and eline are allowed to continue. These operations were excluded from the workover shut down order issued last week. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907-793-1236 or jim.regg@alaska.gov. -----Original Message ----- From: David Wilkins [mailto:dwilkins@hilcorp.comj Sent: Monday, October 05, 2015 5:24 PM To: Regg, James B (DOA) Subject: Fwd: SRU 213-15 Jim, You gave me verbal confirmation that we could this electric line work on Friday. Can you please clarify. Thanks. Dave Sent from my iPhone Begin forwarded message: From: Chad Helgeson <chelgeson@hilcorp.com<mailto:chelgeson@hilcorp.com>> Date: October 5, 2015 at 5:03:05 PM AKDT To: "'samantha.carlisle@alaska.gov<mailto:samantha.carlisle@alaska.gov>"' <samantha.carlisle @alaska.gov<mailto:samantha.carlisle @alaska.gov>> Cc: Larry Greenstein <Igreenstein@hilcorp.com<mailto:lgreenstein@hilcorp.com>>, Luke Saugier <Isaugier@hilcorp.com<mailto:lsaugier@hilcorp.com>>, David Wilkins <dwilkins@hilcorp.com<mailto:dwilkins@hilcorp.com>>, John Barnes <jbarnes@hilcorp.com<mailto:jbarnes@hilcorp.com>>, Joe Kaiser <jkaiser@hilcorp.com<mailto:jkaiser@hilcorp.com>> Subject: RE: SRU 213-15 Samantha, The work included in this sundry # 315-591 was for eline and slickline work associated with SRU 213-15. There is no rig work associated with this Sundry. Is wireline/slickline work considered "workover" and is this type of work included in the shut -down? The sundry was received on Thursday (10/1) in the afternoon and we completed some of the perforating work (in accordance with the sundry) on Friday 10/2. The well is currently flowing, but there is additional perforating work we would like to complete on this well. Please let us know when we can continue the eline work associated with this Sundry. If more specifics are needed on this well or the work that has been completed, please let me know and I would be happy to collect the information you may need. Regards Chad Helgeson Operations Manager Kenai Asset Team Hilcorp Alaska, LLC Office: 907-777-8405 Mobile: 907-229-4824 From: David Wilkins Sent: Monday, October 05, 2015 4:06 PM To: Luke Saugier; Chad Helgeson; Larry Greenstein Subject: Fwd: SRU 213-15 Sent from my iPhone Begin forwarded message: From: "Carlisle, Samantha J (DOA)" <Samantha.carlisle@alaska.gov<mailto:samantha.carlisle@alaska.gov>> Date: October 5, 2015 at 3:37:07 PM AKDT To: "John Barnes - Hilcorp Alaska, LLC (jbarnes@hilcorp.com<mailto:jbarnes@hilcorp.com>)" <jbarnes@hilcorp.com<mailto:jbarnes@hilcorp.com>>, David Wilkins <dwilkins@hilcorp.com<mailto:dwilkins@hilcorp.com>> Subject: SRU 213-15 An approval for sundry number 315-591 for permit to drill number 215-100 was sent to you late last week. The approval is inoperative in light of the workover shut -down in force at this time. Thank you, Samantha Carlisle Executive Secretary II Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 (phone) (907) 276-7542 (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<mailto:Samantha.Carlisle@alaska.gov>. Regg, James B (DOA) From: Regg, James B (DOA) Sent: Tuesday, October 06, 2015 10:36 AM To: 'Trudi Hallett' Cc: Ted Kramer; Schwartz, Guy L (DOA); Daniel Duckworth - (C) Subject: RE: Anna 46 - Sundry No. 315-555 Hilcorp is approved to install the kill string after pressure testing the 13-3/8". Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. if you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or jim.regg@alaska.gov. From: Trudi Hallett [mailto:thallett@hilcorp.com] Sent: Tuesday, October 06, 2015 8:57 AM To: Regg, James B (DOA) Cc: Ted Kramer; Schwartz, Guy L (DOA); Daniel Duckworth - (C) Subject: RE: Anna 46 - Sundry No. 315-555 Mr, Regg, Given the unknown duration of the shut -down, we feel it is in Hilcorp's and the State's best interest to run a kill string after we pressure test the 13-318". Does the AOGCC give us permission to move forward with the kill string? Thanks - T ru44r From: Regg, James B (DOA) [mailto:jim.regg(aalaska.gov] Sent: Monday, October 05, 2015 4:28 PM To: Trudi Hallett Cc: Ted Kramer; Schwartz, Guy L (DOA) Subject: RE: Anna 46 - Sundry No. 315-555 Follow-up to our phone conversation. Request to run the completion in Anna -46 (PTD 1820720 )is denied. Work should be suspended after completing step #16. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITYNOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.regg@alaska.gov. From: Trudi Hallett [mailto:thallett(cbhilcorp.com] Sent: Monday, October 05, 2015 9:12 AM To: Regg, James B (DOA) Cc: Ted Kramer Subject: Anna 46 - Sundry No. 315-555 Good morning - Mr. Regg, As per AOGCC request, the Rig 404 on the Anna Platform is shut -down as of Sam this morning. The current condition of the wellbore is such we have the 9-5/8" casing cut @ 4,200'w/ the 13-3/8" to surface. Below — I have outlined the approved sundry procedure we have remaining with the approximate timeline. With the Commission's approval, we are requesting to move forward with our approved sundry which allow us to safely secure the well, completely shut -down rig operations and move the off the platform. I have also attached a current schematic, the proposed wellbore schematic and our approved sundry for you convenience. Here is the remaining scope of work to finish rig operations: 14.) Run bit and scraper in 13-3/8" to top of 9-5/8" casing at ±4,200'. 15.) Set CIBP at ±4,180' and dump ±20' cement on top. 16.) Pressure test 13-3/8"to 1,500 psi charting for 30 minutes. 17.) Run GR/CBL/RST log in 13-3/8" casing from ±4,150' to surface. 18.) PU storm packer. RIH and set same at 200' and hang off string. Pressure test to 1500 psi and chart. 19.) Release from storm packer, POOH. 20.) Install 13 5/8 3M x 13 5/8 5M completion spool on top of casing spool. 21.) Test all flange breaks to 1500 psi and chart. RIH, engage storm packer, release same, POOH, LD storm packer. 22.) Run 3-1/2" completion and set packer @ ±3,120'. Test IA to 1500 psi and chart. 23.) ND ROPE, NU tree, test same. NOTE: *Rig will be de-mobed at this point. 24.) RU Wireline to swab well down and perforate per log. 25.) RD Wireline. 26.) Turn well over to production. We appreciate AOGCC's consideration for this request — thank you. Trudi Hallett! Operalions Cook I I) It, 1, 0 )fh o�,� A,�,cL I cuam I I i1corp AhNka, I[,(,: Hilcorp A CompanY Btjift on Energy thal lettoyhilcoEp.com 0., 907 8323 C., 9017.301,065' Regg, James B (DOA) From: Trudi Hallett <thallett@hilcorp.com> Sent: Tuesday, October 06, 2015 8:57 AM To: Regg, James B (DOA) Cc: Ted Kramer; Schwartz, Guy L (DOA); Daniel Duckworth - (C) Subject: RE: Anna 46 - Sundry No. 315-555 Mr. Regg, Given the unknown duration of the shut -down, we feel it is in Hilcorp's and the State's best interest to run a kill string after we pressure test the 13-3/8". Does the AOGCC give us permission to move forward with the kill string? Thanks - Tri From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Monday, October 05, 2015 4:28 PM To: Trudi Hallett Cc: Ted Kramer; Schwartz, Guy L (DOA) Subject: RE: Anna 46 - Sundry No. 315-555 Fallow -up to our phone conversation. Request to run the completion in Anna -46 (PTD 1820720 )is denied. Work should be suspended after completing step #16. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.regg@alaska.gov. From: Trudi Hallett [mailto:thallett@hilcorp.com] Sent: Monday, October 05, 2015 9:12 AM To: Regg, James B (DOA) Cc: Ted Kramer Subject: Anna 46 - Sundry No. 315-555 Good morning - Mr. Regg, As per AOGCC request, the Rig 404 on the Anna Platform is shut -down as of Sam this morning. The current condition of the wellbore is such we have the 9-5/8" casing cut @ 4,200'w/ the 13-3/8" to surface. Below — I have outlined the approved sundry procedure we have remaining with the approximate timeline. With the Commission's approval, we are requesting to move forward with our approved sundry which allow us to safely secure the well, completely shut -down rig operations and move the off the platform. I have also attached a current schematic, the proposed wellbore schematic and our approved sundry for you convenience. Here is the remaining scope of work to finish rig operations: 14.) Run bit and scraper in 13-3/8" to top of 9-5/8" casing at ±4,200'. 15.) Set CIBP at ±4,180' and dump ±20' cement on top. 16.) Pressure test 13-3/8"to 1,500 psi charting for 30 minutes. 17.) Run GR/CBL/RST log in 13-3/8" casing from ±4,150' to surface. 18.) PU storm packer. RIH and set same at 200' and hang off string. Pressure test to 1500 psi and chart. 19.) Release from storm packer, POOH. 20.) Install 13 5/8 3M x 13 5/8 5M completion spool on top of casing spool. 21.) Test all flange breaks to 1500 psi and chart. RIH, engage storm packer, release same, POOH, LD storm packer. 22.) Run 3-1/2" completion and set packer @ ±3,120'. Test IA to 1500 psi and chart. 23.) ND BOPE, NU tree, test same. NOTE: *Rig will be de-mobed at this point. 24.) RU Wireline to swab well down and perforate per log. 25.) RD Wireline. 26.) Turn well over to production. We appreciate AOGCC's consideration for this request — thank you. Trloc ti, Truth Hallett 'inecr Hilcorpf i�:W: ,';!V BUill ail LOCI`gy' thallett@,Iiilcorp.com 0. )0.. t:': 90 '301,065. : Regg, James B (DOA) From: Daniel Duckworth - (C) <dduckworth@hilcorp.com> Sent: Monday, October 05, 2015 10:16 AM To: Regg, James B (DOA) Cc: Trudi Hallett; Ted Kramer; Dan Marlowe; Glen Payment; Robert Baker; Dan Moultrie; Harold Soule - (C) Subject: RE: AN -46 / Moncla 404 Once the CIBP is set at top of 9 5/8" (— 4,180'), 20' of cement will be spotted on top- plug will be tested to 1500#s on chart f/ 30 mins. Thanks! From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Monday, October 05, 2015 10:08 AM To: Daniel Duckworth - (C); Trudi Hallett Cc: Ted Kramer; Dan Marlowe; Harold Soule - (C); Schwartz, Guy L (DOA) Subject: RE: AN -46 / Moncla 404 Thank you. OK to install second barrier (CIBP and cement) in the 13 3/8" at the top of 9 5/8" casing. What are your plans to verify the plug? How much cement on top of the CIBP is planned. When work is completed, send a summary of the work to suspend the well (including actual plug setting depth and volume of cement) and a schematic of the well's configuration. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or lim.regg@alaska.gov. From: Daniel Duckworth - (C) [mailto:dduckworth@hilcorp.com] Sent: Monday, October 05, 2015 9:40 AM To: Regg, James B (DOA) Cc: Trudi Hallett; Ted Kramer; Dan Marlowe; Harold Soule - (C) Subject: RE: AN -46 / Moncla 404 Presently we only have one barrier in this well which is our blind rams- the top of the 9 5/8" is 4,193' and the btm of the 13 3/8" is 4,232'. The top of the cement behind our 9 5/8" is calculated to be 6,003'- we need that second barrier (CIBP & cement) in our 13 3/8" at the top of the 9 5/8". Please advise, thanks! From: Regg, James B (DOA) [mailtoJim.reggCcbalaska.gov] Sent: Monday, October 05, 2015 9:20 AM To: Daniel Duckworth - (C) Subject: RE: AN -46 / Moncla 404 Ok to remove double gate from BOPS stack and shell test the stack. Unclear the status of your well and how it is secured. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of .such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.regg@alaska.gov. From: Daniel Duckworth - (C)[mailto:dduckworthCaDhilcorp.com] Sent: Sunday, October 04, 2015 4:47 PM To: Regg, James B (DOA); Schwartz, Guy L (DOA) Cc: Trudi Hallett; Ted Kramer Subject: AN -46 / Moncla 404 Mr. Jim at the rate we're laying 9 5/8" casing down we should be out of the hole in the early hrs of the morning. We will close the blind rams at that point. If permitted we would like to remove that dual ram stack w/ the 9 5/8" blocks since they're not needed anymore- shell test the stack and be prepared to P/U 13 3/8" cleanout assy inorder to plug off that casing w/ CIBP & cement. Please advise as to how far we can go, thanks! Regg, James B (DOA) From: Daniel Duckworth - (C) <dduckworth@hilcorp.com> Sent: Monday, October 05, 2015 9:40 AM To: Regg, James B (DOA) Cc: Trudi Hallett; Ted Kramer; Dan Marlowe; Harold Soule - (C) Subject: RE: AN -46 / Moncla 404 Presently we only have one barrier in this well which is our blind rams- the top of the 9 5/8" is 4,193' and the btm of the 13 3/8" is 4,232'. The top of the cement behind our 9 5/8" is calculated to be 6,003'- we need that second barrier (CIBP & cement) in our 13 3/8" at the top of the 9 5/8". Please advise, thanks! From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Monday, October 05, 2015 9:20 AM To: Daniel Duckworth - (C) Subject: RE: AN -46 / Moncla 404 Ok to remove double gate from BODE stack and shell test the stack. Unclear the status of your well and how it is secured. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. if you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact.lim Regg at 907- 793-1236 or iim.regg@alaska.gov. From: Daniel Duckworth - (C)[mailto:dduckworth(aahilcorp.com] Sent: Sunday, October 04, 2015 4:47 PM To: Regg, James B (DOA); Schwartz, Guy L (DOA) Cc: Trudi Hallett; Ted Kramer Subject: AN -46 / Moncla 404 Mr. Jim at the rate we're laying 9 5/8" casing down we should be out of the hole in the early hrs of the morning. We will close the blind rams at that point. If permitted we would like to remove that dual ram stack w/ the 9 5/8" blocks since they're not needed anymore- shell test the stack and be prepared to P/U 13 3/8" cleanout assy inorder to plug off that casing w/ CIBP & cement. Please advise as to how far we can go, thanks! Regg, James B (DOA) From: Trudi Hallett <thallett@hilcorp.com> Sent: Monday, October 05, 2015 9:22 AM To: Regg, James B (DOA) Subject: An -46 Sundry - Sundry 315-555, Approx. forward plan Timeline Hi Jim, Apologies for the second email. Below is the proposed timeline for your review - we will keep the well secure until otherwise approved. Thank you. Nion N/D h ddl hl.0 top dual rani 4U hyddl- shell test 7.0 0 0 1015!15 10:30 AM 10!5115 5:301 Mon RAJ tongs & PIU coo asst 3.0 0.0 1015!15 5:30 PM 1015115 8.301 Mon IRIH V top of 9 EVE Casing and Marc hole clean 7.0 € ,0 10!5115 8.30 PM 1016115 3:30, Tut POOH 4;0 0.0 1016115 3:30)W 1016115 7:30, Tue Wu rih w. DISP V 4180' 5.0 0.0 10/6;'15 7:30 ANI 10.=6/15 12:30 Tue Dump bail snit on trap 3.0 0.0 10/6615 12:30 PM 10.16915 3:301 Tue P17 tr 1500psi 1.0 0.0 10 8?15 3:30 PM 1096/15 4:30 1 Tue On w1 gr cbtlrst log 13 318 V surface 8,0 0.0 10.8915 4:30 PM 10.17/15 12:30 We'd rih p1u storm packer set L 200, 3.0 I 0.0 10j'7/ 15 12:30 AM 10.7115 3:30, Wed PT V1500: release t+ pacer POOH 1.0 j 0.0 10'`7%15 3:30 AM 101%115 4:30, Wed rd floor 2.0 ! 0.0 10,1715 4:30 AM 10..17,'15 6:30, Wed WC 80P 2.0 0.0 10/7!15 6:30 Abri 10fT15 8':30 , Wed nid 9 5;8- head f•VU TD head on 13 318' 1.0 0.0 10.7115 8:.30 AM 10!7915 9:30 Wed WU bripe 2.0 0.0 1017/15 9:30 Al 1017f15 11:30 "fed test breaks 161500 psi 1.0 10,7/15 11:30 AM 10.17/15 12:30 Wed Vu floor 2.0 10/7,; 15 12:.0 PM 10.'7115 2.30 I Wed Wed Wed Tesl POPES rih retrieve storm packer, POOH ltd ��RIH set pacer @ 3120'+1- 6.0 1.0 �.0 10'7,•-15 2:30 PM 10,7/15 8:30 PM 1017115 MI) PM 1017115 8:30 1 10!71115 9:301 1018115 1:30, Thu POOH ltd 311, wf: string 10,0 10/8/15 1:30 AM 10/13/15 11:30 Thu P&I RIP! 3112" completion string 8,0 '10/8./15 11:30 AM 101$/15 7:30 1 Thu UN hanger & land M10/$.115 7:30 PM 10/8115 9:30 1 Thu Set BPV & rVd SOPS 7.0 10.18./15 9;30 PM 10:19115 3:30, Fri NAJ true test 4,0 10/9f 15 3:3'0 ANI 1019115 7:30, Fri RAJ wireline swab down well 6.01019!15 7:30 AM 1019/15 3:301 Fri perforate as per log 4.0 10:19;15 3:30 PM 101,19115 T301 Thanks- Trudi Hallett O,ocr ulicory i'rrgincer I, 1111el 01T -Al t-" ASsc, "T�<tn, ]lil t,r13 \!<; k;r. 11 ( Hilcorp A Company Built on Energy thallettn,hilcormcom 0.` 907. Regg, James B (DOA) From: Trudi Hallett <thallett@hilcorp.com> Sent: Monday, October 05, 2015 9:12 AM To: Regg, James B (DOA) Cc: Ted Kramer Subject: Anna 46 - Sundry No. 315-555 Attachments: An -46 Schematic as of 2015-09-30 In progress.doc; An -46 Schematic -PROPOSED - 2015-Sep-08.doc; 10-403 Granite Pt St 18742 46 - Approved 2015-09-16.pdf Good morning - Mr. Regg, As per AOGCC request, the Rig 404 on the Anna Platform is shut -down as of Sam this morning. The current condition of the wellbore is such we have the 9-5/8" casing cut @a 4,200'w/ the 13-3/8" to surface. Below - I have outlined the approved sundry procedure we have remaining with the approximate timeline. With the Commission's approval, we are requesting to o move forward with our approved sundry which allow us to safely secure the well, completely shut -down rig operations and move the off the platform. I have also attached a current schematic, the proposed wellbore schematic and our approved sundry for you convenience. Here is the remaining scope of work to finish rig operations: 14.) Run bit and scraper in 13-3/8" to top of 9-5/8" casing at ±4,200'. 15.) Set CIBP at ±4,180' and dump ±20' cement on top. 16.) Pressure test 13-3/8"to 1,500 psi charting for 30 minutes. 17.) Run GR/CBL/RST log in 13-3/8" casing from ±4,150' to surface. 18.) PU storm packer. RIH and set same at 200' and hang off string. Pressure test to 1500 psi and chart. 19.) Release from storm packer, POOH. 20.) Install 13 5/8 3M x 13 5/8 5M completion spool on top of casing spool. 21.) Test all flange breaks to 1500 psi and chart. RIH, engage storm packer, release same, POOH, LD storm packer. 22.) Run 3-1/2" completion and set packer @ ±3,120'. Test IA to 1500 psi and chart. 23.) ND BOPE, NU tree, test same. NOTE: *Rig will be de-mobed at this point. 24.) RU Wireline to swab well down and perforate per log. 25.) RD Wireline. 26.)Turn well over to production. We appreciate AOGCC's consideration for this request - thank you. FAN Trudi Hallett 1 Operrriio ns L'm ineer Hiicorp "Alaska. 1-1,C: Hilcorp A Company Built on i-;eecroN thallett owlhilcorp.corn Regg, James B (DOA) From: Trudi Hallett <thallett@hilcorp.com> Sent: Monday, October 05, 2015 9:22 AM To: Regg, James B (DOA) Subject: An -46 Sundry - Sundry 315-555, Approx. forward plan Timeline Hi Jim, Apologies for the second email. Below is the proposed timeline for your review - we will keep the well secure until otherwise approved. Thank you. Mon *V hydril NX top dual ram NN hydric- shell test TO 0.0 10:5115 10:30 Mill 10/5/15 9:30 1 Mon RAJ tongs 3 PIU uo assy 3.0 0.0 1015115 5:30 PM 1015115 5:301 Mon V top of 9 518 casing and circ hole clean 7.0 0.0 -5 1015115 5-30 PM 10i611 3:31' ; Tue ---- -- POOH 4.0 0.0 1016/15 3:30 MA 1016119 7:30 , Tue rfu nh w.i CISP tw 4180* 5.0 0.0 110J&06 7:30 AM 1016115 12:30 Tue Damp bail cmt on top 3.0 0.0 1016115 1230 PM 10.16115 3:30 1 Tue Pj7 V 1500psi 1.0 I 0.0 1016J15 3:30 PM 1016115 4:30 1 Tue nh wi gr cbVrst log 13 318 Y surface 8.0 0.0 10./6./15 4:30 PM 10/7119 12:30 Jed nM p}u storm packer set @ 200' 3,0 0.0 10;13115 12:30 All 1011:115 3:30 , Wed PT V1500I release iJ packer POOH 1.0 0.0 1017/15 3:30 AM 107115 4:30 Wed rid floor 2.0 0.0 10,`7115 4:30 kil 1017115 6:30 a We'd nid SOP 2.0 0.0 10:7115 6:30 AM 1017/15 5:30 a Jed ntd 9 518" head N/U T8 head on 13 318" 1.0 I 0.0 103115 8:30 AM 9017115 9:30 'Hied Wed ro'Li hope test breaks 1/1500 psi 2.0 1.0 I 0.0 i 10.'7115 9:30 AM 10/7115 11:30 AM 10.17/15 11:30 1017115 12:30 Wed rlu floor 2.0 10!7;115 12:30 PM 10,/7/'15 2:30 1 Wed Wed Wed Test BOPE rih retrieve storm packer, POOH 110 RIH set packer 31.20' *J- 5„0 1.0 .1.0 1017/15 2:30 PM 1017115 8:30 PM 1013715 9:30 PM 1017115 8:301 1011115 9.301 1018,/15 1:301 Thu POOH ltd 3112 wk string 10.0 1018115 1:30 AM 10.181115 11:30 Thu P1t_J RIH 3112"completion string 8.0 1018J15 11;30 Moll 10/81'15 7:30 1 Thu WU hanger & land 2.0 ; 10/'8/15 7:30 PM 10J8115 9:30 1 Thu Set BPV & Nd SOPE 6.0 j 1018/15 9:30 PM 10.19/15 3:30, Fri f' II J tree test 4.0 j 10.19/1: 3:30 AM 101'9/15 7:30 , Fri RAJ wireline swab down well 13,0 ; 10,-9.115 7:30 AM 1019/15 3:30 1 Fri 1perforate as per log 4.0 1019115 3:30 PM 1 10191155 7:30 1 Thanks - Gam.. Trudi Hallett 1 01lei wlions b;rtgineer t'ouE<[rilctOtfstu�4asset'l<<�ru 1;11 otp:llaslca.I_LC Hilcorp A C.orupauy Built on Enerl) thallett g hilcor .com 0: 90'-''-'7,8323 Granite Point Field Well: Granite Pt St 18742-46 Current Completed: Future Hilcorp Alaska, LLC API: 50-703-20355-00 PTD: 182-072 RKB: MSL =105' CASING DETAIL PBTD =9,365' TD =9,455' Size Wt Grade Conn ID Top Btm Comments 20" 94.0 K-55 19.124" Surf 625' 1,500 sacks Class G 13-3/8" 54.5 K-55 12.459" Surf 1575.5' 2,555 sacks Class G 68.0 K-55 12.415" 1575.5' 2,704.4' 72.0 L-80 12.347" 2,704.4' 4,232.2' 9-5/8" 6 ±4180' ±4156' CIBP w/ Cement plug 7 675 sacks Class G ±7834' 43.5 5-95 8.755" ±4,200' 4,337.6' 47.0 5-95 8.681" 4,337.6' 6,225.5' 53.5 5-95 8.535" 6,225.5' 8,332.4' 7 29.0 N-80 6.184" 8,121.3' 9,272.0' 305 sacks Class G 29.0 5-95 6.184" 9,272.0' 9,455' 7922' Muleshoe 8,330' TUBING DETAIL 8,048' 8,091' 3-1/2" 9.30 L-80 Supermax Plugged Surf ±3,170' 3-1/2" 9.30 N-80 DSS -HTC Phase ±8,1.70' ±8,199' C-5 JEWELRY DETAIL No Depth (MD) Depth (TVD) ID Item 1 33.3' 34' Tubing Hanger 2 ±300' ±300' SSSV 3 ±3070' ±3068' Chemical mandrel 4 ±3120' ±3118' 4.00" ASI -X 13-3/8" Mechanical Packer 5 ±3170' ±3168' ECT 6 ±4180' ±4156' CIBP w/ Cement plug 7 ±8110' ±7834' CRET w/ Cement plug 8 ±8170' ±7894' Top of 3-1/2" tbg 9 8187' 7910' Baker F Packer w/ locator and 10' Seal Assembly 10 8199' 7922' Muleshoe PERFORATION DETAIL Top Btm Top Btm Zone (MD) (MD) (TVD) (TVD) FT SPF Comments Date Status ±3,222 ±4,000 ±3,220' ±3,877' -+778' 6 Interval will be based Future Proposed on logs C-4 8,330' 8,374' 8,048' 8,091' 44' 4 2-1/8" Enerjet, 0 8/11/1982 Plugged Phase C-5 8,458' 8,518' 8,171' 8,229' 60' 4 2-1/8" Enerjet, 0 8/11/1982 Plugged Phase C-6 8,551' 8,596' 8,260' 8,303' 45' 4 2-1/8" Enerjet, 0 8/11/1982 Plugged Phase 8,840' 8,878' 8,537' 8,573' 38' 4 2-1/8" Enerjet, 0 8/11/1982 Plugged gged C-7 8,950' 9,017' 8,642' 8,706' 67' 4 2-1/8" Enerjet, 0 8/11/1982 Plugged Phase 9,056' 9,077' 8,743' 8,763 21' 4 2-1/8" Enerjet, 0 8/11/1982 Plugged Phase 9,198' 9,226' 8,879' 30' 4 2-1/8" Enerjet, 0Phase 8/11/1982 Plugged C-8 9,246' 9,296' 8,925' 8,972' 50' 4 2-1/8" Enerjet, 0 8/11/1982 Plugged Phase 9,304' 9,324' 8,980' 8,999' 20' 4 2-1/8" Enerjet, 0 8/11/1982 Plugged Phase Updated By: JILL 09/30/15 PROPOSED Hileorp Alaska. LLC RKB: MSL =105' 20" 13-3/8" Calculated TOC 6,003' 4 6 ' r C-7 PBTD =9,365' TD =9,455' Granite Point Field Well: Granite Pt St 18742-46 Completed: Future API: 50-703-20355-00 PTD: 182-072 CASING DETAIL Size 17 Grade Conn ID ., 8,213'4 Holes ' 20" No Cement K-55 vt Bond 07/30/82 625' 1,500 sacks Class G 13-3/8" 54.5 K-55 12.459" Surf 1575.5' 2,555 sacks Class G 68.0 K-55 12.415" 1575.5' 2,704.4' 72.0 L-80 12.347" 2,704.4' 4,232.2' C-4 6 ±4180' ±4156' 35/8" 7 675 sacks Class G ±7834' 43.5 S-95 8.755" ±4,200' 4,337.6' 47.0 S-95 8.681" 4,337.6' 6,225.5' 53.5 S-95 8.535" 6,225.5' 8,332.4' 7 C-5 N-80 6.184" 8,121.3' 9,272.0' .y 29.0 S-95 6.184" 9,272.0' 9,455' 7922' Muleshoe C-6 ' r C-7 PBTD =9,365' TD =9,455' Granite Point Field Well: Granite Pt St 18742-46 Completed: Future API: 50-703-20355-00 PTD: 182-072 CASING DETAIL Size Wt Grade Conn ID Top Btm Comments 20" 94.0 K-55 19.124" Surf 625' 1,500 sacks Class G 13-3/8" 54.5 K-55 12.459" Surf 1575.5' 2,555 sacks Class G 68.0 K-55 12.415" 1575.5' 2,704.4' 72.0 L-80 12.347" 2,704.4' 4,232.2' 9-5/8" 6 ±4180' ±4156' CIBP w/ Cement plug 7 675 sacks Class G ±7834' 43.5 S-95 8.755" ±4,200' 4,337.6' 47.0 S-95 8.681" 4,337.6' 6,225.5' 53.5 S-95 8.535" 6,225.5' 8,332.4' 7 29.0 N-80 6.184" 8,121.3' 9,272.0' 305 sacks Class G 29.0 S-95 6.184" 9,272.0' 9,455' 7922' Muleshoe 8,330' TUBING DETAIL 8,048' 8,091' 3-1/2" 9.30 L-80 Supermax Surf ±3,170' 3-1/2" 9.30 N-80 DSS -HTC ±8,170' ±8,199' JEWELRY DETAIL No Depth (MD) Depth (TVD) ID Item 1 33.3' 34' Tubing Hanger 2 ±300' ±300' SSSV 3 ±3070' ±3068' Chemical mandrel 4 ±3120' ±3118' 4.00" ASI -X 13-3/8" Mechanical Packer 5 ±3170' ±3168' EOT 6 ±4180' ±4156' CIBP w/ Cement plug 7 ±8110' ±7834' CRET w/ Cement plug 8 ±8170' ±7894' Top of 3-1/2" tbg 9 8187' 7910' Baker F Packer w/ locator and 10' Seal Assembly 10 8199' 7922' Muleshoe PERFORATION DETAIL Zone Top Btm Top Btm FT SPF Comments Date Status (MD) (MD) (TVD) (TVD) ±3,222 ±4,000 ±3,220' ±3,877' ±778' 6 Interval will be based Future Proposed on logs C-4 8,330' 8,374' 8,048' 8,091' 44' 4 2-1/8" Enerjet, 0 8/11/1982 Plugged Phase C-5 8,458' 8,518' 8,171' 8,229' 60' 4 2-1/8" Enerjet, 0 8/11/1982 Plugged Phase C-6 8,551' 8,596' 8,260' 8,303' 45' 4 2-1/8" Enerjet, 0 8/11/1982 Plugged Phase 8,840' 8,878' 8,537' 8,573' 38' 4 2-1/8" Enerjet, 0 8/11/1982 Plugged Phase C-7 8,950' 9,017' 8,642' 8,706' 67' 4 2-1/8" Enerjet, 0 8/11/1982 Plugged Phase 9,056' 9,077' 8,743' 8,763 21' 4 2-1/8" Enerjet, 0 8/11/1982 Plugged Phase 9,198' 9,226' 8,879' 30' 4 2-1/8" Enerjet, 0 8/11/1982 Plugged Phase C-8 9,246' 9,296' 8,925' 8,972' 50' 4 2-1/8" Enerjet, 0 8/11/1982 Plugged Phase 9,304' 9,324' 8,980' 8,999' 20' 4 2-1/8" Enerjet, 0 8/11/1982 Plugged Phase Updated By: TRH 09/08/15 Regg, James B (DOA) From: Trudi Hallett <thallett@hilcorp.com> Sent: Monday, October 05, 2015 9:12 AM To: Regg, James B (DOA) Cc: Ted Kramer Subject: Anna 46 - Sundry No. 315-555 Attachments: An -46 Schematic as of 2015-09-30 In progress.doc; An -46 Schematic -PROPOSED - 2015-Sep-08.doc; 10-403 Granite Pt St 18742 46 - Approved 2015-09-16.pdf Good morning - Mr. Regg, As per AOGCC request, the Rig 404 on the Anna Platform is shut -down as of Sam this morning. The current condition of the wellbore is such we have the 9-5/8" casing cut @a 4,200'w/ the 13-3/8" to surface. Below - I have outlined the approved sundry procedure we have remaining with the approximate timeline. With the Commission's approval, we are requesting to move forward with our approved sundry which allow us to safely secure the well, completely shut -down rig operations and move the off the platform. I have also attached a current schematic, the proposed wellbore schematic and our approved sundry for you convenience. Here is the remaining scope of work to finish rig operations: 14.) Run bit and scraper in 13-3/8" to top of 9-5/8" casing at ±4,200'. 15.) Set CIBP at ±4,180' and dump ±20' cement on top. 16.) Pressure test 13-3/8"to 1,500 psi charting for 30 minutes. 17.) Run GR/CBL/RST log in 13-3/8" casing from ±4,150' to surface. 18.) PU storm packer. RIH and set same at 200' and hang off string. Pressure test to 1500 psi and chart. 19.) Release from storm packer, POOH. 20.) Install 13 5/8 3M x 13 5/8 5M completion spool on top of casing spool. 21.)Test all flange breaks to 1500 psi and chart. RIH, engage storm packer, release same, POOH, LD storm packer. 22.) Run 3-1/2" completion and set packer @ ±3,120'. Test IA to 1500 psi and chart. 23.) ND BOPE, NU tree, test same. NOTE: *Rig will be de-mobed at this point. 24.) RU Wireline to swab well down and perforate per log. 25.) RD Wireline. 26.) Turn well over to production. We appreciate AOGCC's consideration for this request - thank you. Trv4t , Trudi flalletf r xir;c�>r _ou 1'' � Hilcorp A Com ntyy 13uilt on Ener�!y thallettL&hilcorp.com C., 907,301,0657 Regg, James B (DOA) From: Wade Hudgens - (C) <whudgens@hilcorp.com>i 0 Sent: Friday, October 02, 2015 5:03 PM vl e! To: Regg, James B (DOA); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (DOA) Cc: Stan Porhola; Tom Fouts Subject: FW: BOP TEST FORM ASR 1 J08A.xlsx Attachments: BOP ASR 1 9-23-15.xlsx 9/23/15 BOPE Test Report for ASR 1. Thank You, Wade Hudgens From: Stan Porhola Sent: Friday, October 02, 2015 4:15 PM To: Wade Hudgens - (C) Subject: FW: BOP TEST FORM ASR 1 J08A.xlsx FYI. Here is what Wayne sent me originally. From: Wayne Biart - (C) Sent: Wednesday, September 23, 2015 1:14 PM To: Stan Porhola Subject: BOP TEST FORM ASR 1 J08A.xlsx For your approval 9-ff STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report Submit to: Iim.reggCa�alaska.gov AOGCC.Inspectors(a-)alaska.gov Phoebe. brooksCDalaska.gov Contractor: Hilcorp Rig No.: ASR 1 DATE: 9/23/15 Rig Rep.: Dusty Shulze Rig Phone: 907-310-0887 Operator: Hilcorp Alaska, LLC Op. Phone: 907-310-0243 Rep.: Wayne Biart E -Mail wbiart@ ilcorp.com 2 Well Name: MPU SB J -08A PTD # 1991170 Sundry # 31saiur Operation: Drilling: Test: Initial: Test Pressure (psi): Rams: MISC. INSPECT( Test Result Location Gen. P Housekeeping P PTD On Location P riding Order Posted P XX 250/3000 ONS: Workover: XX Explor.: Test Result MUD SYSTEM: Visual Weekly: Bi -Weekly: 0 NA Annular: 250/2500 Valves: 250/3000 MASP: 177 ' 1 TEST DATA FLOOR SAFETY VALVES: Pit Level Indicators P Test Result #1 Rams Quantity Test Result Well Sign P Upper Kelly 0 NA Rig P Lower Kelly 0 NA Hazard Sec. P Ball Type 1 P Misc. NA Inside BOP 1 P NA FSV Misc 0 NA BOP STACK: Quantity Size/Type Test Result MUD SYSTEM: Visual Alarm Stripper 0 NA Trip Tank NA NA Annular Preventer 1 Shaffer 11" P Pit Level Indicators P P #1 Rams 1 ' VBR2 7/8"-4 P Flow Indicator NA NA #2 Rams I CIW Blinds P Meth Gas Detector P P #3 Rams 0 NA H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA Quantity Test Result Choke Ln. Valves 1 2-1/16" 5M P Inside Reel valves 0 NA HCR Valves 1 2-1/16" 5M P Kill Line Valves 2 2-1/16" 5M P Check Valve 0 NA ACCUMULATOR SYSTEM: BOP Misc 0 NA Time/Pressure Test Result System Pressure (psi) 3200 P CHOKE MANIFOLD: Pressure After Closure (psi) 1700 P Quantity Test Result 200 psi Attained (sec) 14 P No, Valves 15 P Full Pressure Attained (sec) 54 P Manual Chokes 1 P Blind Switch Covers: All stations Yes Hydraulic Chokes 1 P Nitgn. Bottles Avg. (# and psi): 4/2450 P CH Misc 0 NA ACC Misc 0 NA Test Results Number of Failures: 0 Test Time: 4.0 , Hours Repair or replacement of equipment will be made within N/A days. Notify the AOGCC of repairs with written confirmation to: AOGCC. Ins (Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 9/22/15 0742 Waived By John Crisp Test Start Date/Time: 9/23/2015 0742 am (date) (time) Witness Test Finish Date/Time: 9/23/2015 1200 pm Form 10-424 (Revised 06/2014) BOP ASR 1 9-23-15.xlsx Regg, James B (DOA) From: Regg, James B (DOA) 2� Sent: Friday, October 02, 2015 4:01 PM ( � "I To: 'Wade Hudgens - (C)' Cc: Brooks, Phoebe L (DOA) Subject: RE: ASR #1 BOPE Test 10-1-15 Missing 9/24/15 BOPE test report for ASR1 Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or jim.regg@alaska.gov. From: Regg, James B (DOA) Sent: Friday, October 02, 2015 2:38 PM To: 'Wade Hudgens - (C)' Cc: Brooks, Phoebe L (DOA) Subject: RE: ASR #1 BOPE Test 10-1-15 Revised reports for 9/18 and 10/1 attached (missing valve sizes). Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.regg@alaska.gov. From: Wade Hudgens - (C) [mailto:whudgens@hilcorp.com] Sent: Friday, October 02, 2015 9:20 AM To: DOA AOGCC Prudhoe Bay; Regg, James B (DOA); Brooks, Phoebe L (DOA) Cc: Tom Fouts; Stan Porhola Subject: ASR #1 BOPE Test 10-1-15 Attached 10-424 for the ASR # 1 Regg, James B (DOA) RSS Feed: AOGCC Inspection Request �, Posted on: Tuesday, September 22, 2015 7:42 AM ! �-, T � 5 Author: AOGCC Inspection Request Subject: AOGCC Inspection Request - Submission (2015-09-22 07:42:17) Full article link: http://www.jotform.com/submission/318745732985210817 Submission Date: 2015-09-22 07:42:17 IP Address : 24.237.158.9 Type of Test Requested:: BOPE Requested Time for Inspection : 09-23-2015 7:00 AM Location : ASR 1 MPU J -08A Name: Wayne Biart E-mail : wbiart e hilcorp.com Phone Number: (907) 3100243 Company: Hilcorp Other Information: View article... Regg, James B (DOA) From: Regg']onnes B (DOA) Sent: Friday, October O2,20I54:OlPK4 To: VVadeHudgens (C) Cc Brooks, Phoebe L(DOA) Subject: RE: ASR #1 8C)PETest lO-l'lS Missing 9/24/15 BOPE test report for ASR1 ]imRegg Supervisor, Inspections AO6L[ 333 W. 7th Ave, Suite 100 Anchorage, Ax985O1 90 7-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). Vmay contain confidential and/or privileged information. The. unauthorized review, use or disclosure of such information rnay 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 tnyou, contact Jim neggatB0,- r93'12s6or, ym.neOK@/a|psko.gvv. From: Rcgg,James B(OOA) Sent: Friday, October 02, 2015 2:38 PM To: 'Wade Hudgens'(C)' Cc: Brooks, Phoebe L(DOA) Subject: RE: ASR #1 BOPETcst 10-1'15 Revised reports for 9/18 and 10/1 attached (missing valve sizes). jimRegg Supervisor, Inspections ADGCC B3vv,7th Ave, Suite 100 Anchorage, Axg9501 907-7e3-1236 CONFIDENTIALITYNOTICE: 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 o,forwarding it, and, ,nthat the 4oscz|saware nfthe mistake insending ittoyou, contact Jim neggat907- 793-1236 or o7',9y'1zssnr . From: VVadeHudgens (C) Sent: Friday, October 02, 2015 9:20 AM To: DDAAOGCC Prudhoe Bay; Regg, James B (DOA); Brooks, Phoebe L(DOA) Cc: Tom Fouts; Stan Pnrho|a Subject: ASR#1BOPETest 1O -11S Attached 10-424 for the ASR # 1 Thank You, Wade Hudgens Hilcorp WSM 903-331-6711 whudgens@hilcorp.com Regg, James B (DOA) From: Trudi Hallett <thallett@hilcorp.com> Sent: Friday, October 02, 2015 1:24 PM To: Regg, James B (DOA) Subject: Re: AN - 46 Sequence of Events With the 9-5/8" Casing Cuts Hi Mr. Regg, Do we have approval to move forward with the proposed BOPE configuration Mr. Duckworth sent to you yesterday? We are due for weekly BOPE test today. Please advise. Thank you, Sir. Trudi Hallett 907-301-6657 Sent from my iPhone > On Oct 2, 2015, at 1:07 PM, Regg, James B (DOA) <jim.regg@alaska.gov> wrote: > Thank you for the daily reports and summary below. Hilcorp is authorized to continue pulling the 9-5/8" casing before suspending workover operations on Anna 46 (PTD 1820720). > Jim Regg > Supervisor, Inspections > AOGCC > 333 W. 7th Ave, Suite 100 > Anchorage, AK 99501 > 907-793-1236 > CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907-793-1236 or jim.regg@alaska.gov. > -----Original Message----- > From: Ted Kramer [mailto:tkramer@hilcorp.com] > Sent: Friday, October 02, 2015 12:09 PM > To: Regg, James B (DOA) > Cc: Juanita Lovett; Stan Golis > Subject: AN - 46 Sequence of Events With the 9-5/8" Casing Cuts > Jim, > Attached please find rig reports for 10/1/2015 and 10/2/2015. These reports end as of 0600 on the date of the report and reflect work completed for the prior 24 hours. > The 10/1/2015 report shows that the first cut of the 9-5/8" at 4,200' occurred 1900 to 2000 hrs on Wednesday September 30, 2015. The second cut at 86' occurred 0200 to 0300 hrs the morning of October 1, 2015. The shallow cut was made because we were not confident that the 404 could pull enough to both unseat the slips and pull the casing. The shallow cut would allow Hilcorp to pull the 9-5/8" slips /hanger separately and get it out of the way. > Hilcorp's WSM recognized that we needed 9-5/8" rams in the stack to be able to pull the 9-5/8" casing. Adding the additional double gate to the stack allows for the 9-5/8" Rams. > Hilcorp's WSM called Lou Grimaldi and discussed the situation with him and told him what Hilcorp wanted to do. Lou advised the Hilcorp WSM to call you directly and get permission to modify the BOP stack. That is the background for Hilcorp's e-mail from Danny Duckworth to you on October 1, 2015. > The cuts were already made prior to being advised by you in your e-mail dated 4:03 PM October 1, 2015 that Hilcorp was to suspend all workover operations until further notice. No reason was given in the e-mail as to why. Danny contacted me and I told him the secure the well and await further orders. That was immediately done. > Hilcorp requests that we be allowed to return to work to finish pulling the 9-5/8" casing. > Sincerely, > Ted Kramer > Sr. Operations Engineer > Hilcorp Alaska, LLC. > O 907-777-8420 > C 985-867-0665 Regg, James B (DOA) From: Regg, James B (DOA) Sent: Friday, October 02, 2015 1:07 PM To: 'Ted Kramer' Cc: Juanita Lovett; Stan Golis; Trudi Hallett; Foerster, Catherine P (DOA); Seamount, Dan T (DOA) Subject: RE: AN - 46 Sequence of Events With the 9-5/8" Casing Cuts Thank you for the daily reports and summary below. Hilcorp is authorized to continue pulling the 9-5/8" casing before suspending workover operations on Anna 46 (PTD 1820720). Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907-793-1236 or jim.regg@alaska.gov. -----Original Message ----- From: Ted Kramer [mailto:tkramer@hilcorp.com] Sent: Friday, October 02, 2015 12:09 PM To: Regg, James B (DOA) Cc: Juanita Lovett; Stan Golis Subject: AN - 46 Sequence of Events With the 9-5/8" Casing Cuts Jim, Attached please find rig reports for 10/1/2015 and 10/2/2015. These reports end as of 0600 on the date of the report and reflect work completed for the prior 24 hours. The 10/1/2015 report shows that the first cut of the 9-5/8" at 4,200' occurred 1900 to 2000 hrs on Wednesday September 30, 2015. The second cut at 86' occurred 0200 to 0300 hrs the morning of October 1, 2015. The shallow cut was made because we were not confident that the 404 could pull enough to both unseat the slips and pull the casing. The shallow cut would allow Hilcorp to pull the 9-5/8" slips /hanger separately and get it out of the way. Hilcorp's WSM recognized that we needed 9-5/8" rams in the stack to be able to pull the 9-5/8" casing. Adding the additional double gate to the stack allows for the 9-5/8" Rams. Hilcorp's WSM called Lou Grimaldi and discussed the situation with him and told him what Hilcorp wanted to do. Lou advised the Hilcorp WSM to call you directly and get permission to modify the BOP stack. That is the background for Hilcorp's e-mail from Danny Duckworth to you on October 1, 2015. The cuts were already made prior to being advised by you in your e-mail dated 4:03 PM October 1, 2015 that Hilcorp was to suspend all workover operations until further notice. No reason was given in the e-mail as to why. Danny contacted me and I told him the secure the well and await further orders. That was immediately done. Hilcorp requests that we be allowed to return to work to finish pulling the 9-5/8" casing. Sincerely, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. O 907-777-8420 C 985-867-0665 Regg, James B (DOA) From: Ted Kramer <tkramer@hilcorp.com> Sent: Friday, October 02, 2015 12:09 PM To: Regg, James B (DOA) Cc: Juanita Lovett; Stan Golis Subject: AN - 46 Sequence of Events With the 9-5/8" Casing Cuts Attachments: 20151002110532637.pdf Jim, Attached please find rig reports for 10/1/2015 and 10/2/2015. These reports end as of 0600 on the date of the report and reflect work completed for the prior 24 hours. The 10/1/2015 report shows that the first cut of the 9-5/8" at 4,200' occurred 1900 to 2000 hrs on Wednesday September 30, 2015. The second cut at 86' occurred 0200 to 0300 hrs the morning of October 1, 2015. The shallow cut was made because we were not confident that the 404 could pull enough to both unseat the slips and pull the casing. The shallow cut would allow Hilcorp to pull the 9-5/8" slips /hanger separately and get it out of the way. Hilcorp's WSM recognized that we needed 9-5/8" rams in the stack to be able to pull the 9-5/8" casing. Adding the additional double gate to the stack allows for the 9-5/8" Rams. Hilcorp's WSM called Lou Grimaldi and discussed the situation with him and told him what Hilcorp wanted to do. Lou advised the Hilcorp WSM to call you directly and get permission to modify the BOP stack. That is the background for Hilcorp's e-mail from Danny Duckworth to you on October 1, 2015. The cuts were already made prior to being advised by you in your e-mail dated 4:03 PM October 1, 2015 that Hilcorp was to suspend all workover operations until further notice. No reason was given in the e-mail as to why. Danny contacted me and I told him the secure the well and await further orders. That was immediately done. Hilcorp requests that we be allowed to return to work to finish pulling the 9-5/8" casing. Sincerely, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. 0 907-777-8420 C 985-867-0665 Regg, James B (DOA) From: Bo York <byork@hilcorp.com> Sent: Friday, October 02, 2015 8:36 AM To: Regg, James B (DOA); Foerster, Catherine P (DOA); Schwartz, Guy L (DOA) Cc: John Barnes; David Wilkins; Marc Bond; Carl Jones; Stan Porhola Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Attachments: September 25 Incident RCA (v6).pdf; 293_2015-09-25_EventSequence R2.pdf; 293_ 2015-09-25_Investigation-Recordables_MPU_JPad -02-Deficiency rl.pdf Jim - Attached are the Root Cause Analysis documents. They include: 1. Root Cause Analysis utilizing the Comprehensive List of Causes (CLC) template ("25 September 2015 J-08 Incident RCA (v6)") Detailed sequence of events. This powerpoint deck also includes two P&Ids that depict valve alignment immediately prior to the incident when 50 bbls of seawater was attempted to be pumped into the annulus and valve alignment at the time of the incident. Hilcorp internal investigation incident form We would like to walk you through the events that lead up to the incident and discuss these documents at your earliest convenience. We are available anytime this morning to come to your offices. Confirming status of ASR and Nordic work overs. ASR is running completion on J-08 and will cease activities when complete. Nordic 3 is completing L-20 workover and will complete activities this weekend and will return to drilling. Regards Bo York Operations Manager, Milne Point byork@Hilcorp.com 907.777.8345 907.727.9247 cell From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Wednesday, September 30, 2015 1:20 PM To: Stan Porhola Cc: John Barnes; Grimaldi, Louis R (DOA); DOA AOGCC Prudhoe Bay; Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Bo York; David Wilkins; Marc Bond Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Based on Hilcorp's response below and the proposed procedure received by email on September 27, 2015, AOGCC approves Hilcorp's request to continue with operations on MPU J -08A (PTD 1991170) under Sundry 315-527 using rig MAK ASR1. Any changes from the proposed procedure must receive prior written approval from AOGCC. All other sundry approvals involving HAK ASR1 are currently under review and may require additional discussion with Hilcorp before commencing work. This approval is without prejudice to AOGCC's ongoing investigation. Please resend the BOPS test notice with updated start date/time. Jim Regg Supervisor, Inspections AOGCC zBW.7th Ave, Suite 100 Anchorage, AK 99501 90/'7e3-1236 CONFIDENTIALITY NOTICE: Fhis 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 o,disclosure cf such information may violate state or federal law. if you are an unintended recipient of this e-mail, please delete it, without first saving o,forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or From: Stan Porho|a [mai Ito: sporhola (& hi lcorD.COMI Sent: Tuesday, September 29, 2015 3:18 PM To: Ragg,James B(DOA) Cc: John Barnes; Grimaldi, Louis R(DOA); DOA AOGC[Prudhoe Bay; Foerster, Catherine (DOA); Schwartz, Guy (DOA); 8o York; David Wilkins; Marc Bond Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Jim, 1) Hilcorp has completed field activities for the investigation and is currently preparing a Root Cause Analysis Incident Report due Thursday, 10/01/2015. No final conclusions have been made at this time. However, the gas buster's drain valve is locked inthe close position preventing any gas returns toour pit system. Our planned normal operations will be for all well returns to be taken to our external 500 bbl kill tank. 2) Current well status for MPU ]-)8A(PTD 199-117)—Tubing: 0psi (Echnmeterfluid level shot at*-SOO);Casing: Vacuum (Echometer fluid level shot inconclusive), Well Configuration: Well has workstring on bottom at 6,535' IVID with 2-7/8" tubing at surface; on Sunday 9/27/2015 purnped 20 bbl neat MeOH down the tubing and 20 bbl neat MeOH and 45 bbI 60/40 MeOH down the annulus. Both tubing and annulus were on a vacuum after pumping the freeze protect fluid. 3) Thep|ansfo/A3Rlafte/comp|etingK;PU]'O8Aarek/movethehgtothenextweU,MPUG-08A. 4) List ofwells with approved sundries involving HAKASR1areas follows: MPU G-08A,MPU E-21,MPU S-34,and MPU E-15. Planned sequence of well workovers is as follows: MPU G -08A, MPU E-21, then evaluate the next wells to move to from the list of current of approved sundries and future sundries for recent failed ESP wells (MPU H-16, 5> The rig winterization for ASR1 includes 2 jet heaters installed and running providing heat to the BOPE in our enclosure under the rig floor, blankets for exposed choke, kill, and hydraulic lines are located at Milne Point and will be installed on the next rig up. A box has been installed on the mud tank trailer to allow heated air to be circulated down the blankets for the choke and kill lines. We are currently pending a decision on moving up a rental glycol/steam boiler system out ofFairbanks. 6) It is our intent to normally have the ASR complete a well before going off - shift. However, the procedures for securing well is detailed below: a. In the event the well is capable of flow to surface unassisted, we would install the necessary clownhole plugs that would be the same or similar to a conventional storm packer with a kill string hung below and a tubing hanger with oback-pressure valve installed. b. Freeze protecting the well and the BOPE would be completed before crews were to leave the rig. The BOPE stack will beinaheated enclosure under the rig floor, the blind rams locked and secured, and the hydraulic lines removed to prevent freezing. Temperature conditions will be monitored in the heated enclosure. c. Hilcorp will evaluate weather conditions on a daily basis, recognizing that the rig derrick materials are rated to -40`F. |tisvery likely that we will suspend operations at or before we reach this ambient temperature. d. VVewill test the BOPEtothe k14SP,for partial and full tests. e. BOPE tests will be done with a non'comp/essib|e fluid and charted with records maintained forA0GCC review. f. The securing of the manual valves on the choke and kill lines will include standard lock -out tag -out procedures. g. The kill line does not have any 1502 union connections. It currently has a G/ay|occnnnecdon. h. The choke manifold will not be connected to the BOPE while the crew is off location. The choke and kill lines will be placed in a secure location until the crews return before re -attaching tothe 8OPE stack, i VVhentheASR'1crevvgoesnndaysoff,wevvi||identifyvve||cnntno||edcertihedindividua|sfromtheNordic #Jwho will be prepared 1oand will respond to anevent that requires mitigating well pressures or anomalous well conditions. A full BOPE test will be conducted post -suspension operations. Let meknow ifyou need any additional information. Stan Porbola|Operations Eugbnecr North Slope AssetTeamm |0Q«orp Alaska, LL[ soorhn/a6@bUrorozouz From: Rcgg,]anles B(OOA) Sent: Tuesday September 29, 2015 9:20 AM To: VVayneBiart (C) Cc: Stan Porho|a; John Barnes; Grimaldi, Louis R(DOA); DOA AOGCCPrudhoe Bay; Foerster, Catherine P(DOA); Schwartz, Guy L(DOA) Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Couple issues before AOGCC makes a decision allowing Hilcorp to proceed with J -08A: 1) Has Hilcorp completed the incident investigation, and is the report sent Sunday the final, full investigation report? Is Hilcorp's final conclusion that the drain valve on the gas buster was left open? 2) Confirm status ofwell — current tubing and annulus pressures, fluid levels, well configuration (pipe inhole) —we understand the well should have been freeze protected with MeOH on Sunday (AOGCC approved the procedure). 3) Plans for A6R1 after completing J'08A. 4) List of wells with approved sundries involving HAK ASR1 and planned sequence of well workovers. 5) Status ofwinterization onthe rig. 6) Status ofHi|corp's reply toAO6[[comments/questions (sent O/2S/15) relating tothe proposed program for securing vve||s during shutdown periods when HAK A6R1 crews are on days off crews. ]imRegg Supervisor, Inspections AOGCC 333 W. 7th Ave, svhe 100 Anchorage, Ansyso1 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236oriim.re.I-as_ka_gov-. From: Wayne Biart - (C) [mailtQ. wbia.rt. .hil.corp,coml Sent: Tuesday, September 29, 2015 8:31 AM To: Grimaldi, Louis R (DOA); DOA AOGCC Prudhoe Bay Cc: Stan Porhola; John Barnes Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Will do Lou. Regards Wayne From: Grimaldi, Louis R (DOA) [mailto:lou. rimaldi@alaska.god Sent: Tuesday, September 29, 2015 8:27 AM To: Wayne Biart - (C); DOA AOGCC Prudhoe Bay Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Wayne Update this evening around dinner please. Lou Lou Grimaldi (on cell) Petroleum Inspector Alaska Oil and Gas Conservation Commission (907) 776-5402 (Home) (907) 252-3409 (Cell) -------- Original message -------- From: Wayne Biart Date:09/28/2015 22:15 (GMT -09:00) To: DOA AOGCC Prudhoe Bay Subject: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Question Type of Test Requested: Requested Time for Inspection Location Name E-mail Answer C•' 09-30-2015 6:00 AM ASR 1 MPU J -08A Wayne Biart ,' Mart ii..hi(coti-).Co n Phone Number Company Other Information: Submission ID: (907) 3100243 Hilcorp 319316522218349748 Regg, James B (DOA) From: Bo York <byork@hilcorp.com> Sent: Friday, October 02, 2015 8:36 AM To: Regg, James B (DOA); Foerster, Catherine P (DOA); Schwartz, Guy L (DOA) Cc: John Barnes; David Wilkins; Marc Bond; Carl Jones; Stan Porhola Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Attachments: September 25 Incident RCA (v6).pdf, 293_2015-09-25_EventSequence R2.pdf; 293_ 2015-09-25_Investigation-Recordables_MPU_JPad -02-Deficiency rl.pdf Jim - Attached are the Root Cause Analysis documents. They include: Root Cause Analysis utilizing the Comprehensive List of Causes (CLC) template ("25 September 2015 J-08 Incident RCA (v6)") Detailed sequence of events. This powerpoint deck also includes two P&IDs that depict valve alignment immediately prior to the incident when 50 bbls of seawater was attempted to be pumped into the annulus and valve alignment at the time of the incident. Hilcorp internal investigation incident form We would like to walk you through the events that lead up to the incident and discuss these documents at your earliest convenience. We are available anytime this morning to come to your offices. Confirming status of ASR and Nordic work overs. ASR is running completion on J-08 and will cease activities when complete. Nordic 3 is completing L-20 workover and will complete activities this weekend and will return to drilling. o Regards. Bo York Operations Manager, Milne Point bvork@Hilcorp.com 907.777.8345 907.727.9247 cell From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Wednesday, September 30, 2015 1:20 PM To: Stan Porhola Cc: John Barnes; Grimaldi, Louis R (DOA); DOA AOGCC Prudhoe Bay; Foerster, Catheri (DOA); Schwartz, Guy L (DOA); Bo York; David Wilkins; Marc Bond Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J - Based on Hilcorp's response below and the proposed procedure re ived by email on September 27, 2015, AOGCC approves Hilcorp's request to continue with operations on MP J -08A (PTD 1991170) under Sundry 315-527 using rig HAK ASR1. Any changes from the proposed procedure m receive prior written approval from AOGCC. All other sundry approvals involving HAK ASR1 are currently u er review and may require additional discussion with Hilcorp before commencing work. This approval is with prejudice to AOGCC's ongoing investigation. Please resend the BOPE test notice with)4dated start date/time. Jim Regg September 25, 2015 Incident Root Cause Analysis (RCA) Comprehensive List of Causes (CLC) 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. 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. H If.l-1, HILCORP ALASKA, LLC: INTERNAL INCIDENT INVESTIGATION 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: Jerry Chitwood, Owner EMPLOYMENT STATUS: ❑P/T XF/T ❑TEMP CONTRACTOR GENDER: XM 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 XA.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 DRAINING ❑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 25"', 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 exterior flow 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 1 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. 2 Driller 1 (131) and Driller 2 (D2) 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) 5. Incident Pictures WELL ................... ... P 4 8 Rig choke I Manibld IVa llait101d �- ='F6 ....... ....... Mud Pit. , j 7;) 4 , Operator 3 Location li r incidentDiagram of Pit Trailer Choke and Kill Manifold, taken immediately after 1 Ht r 7 Mud Pits w/View toward Far End 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 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. EHBS REPRESENTATIVE COMPLETING INVESTIGATION: Carl A. Jones, Safety Manager SIGNATURE: ead Cl 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. Automated Service Rig 1 (ASR 1) 25 September 2015 Incident Investigation Events Sequencing Chart Monitor sys. , Rig &ew Cr meets industry Operationally Design Ready i \ Adequate Adequate ASR RigConstructed b ASR Rig and crew y ASR arrived at MPU deployed to Well 5-27 ASR Mobe in and rig ASR tested on J- RanQeland Drilling 08A.. Witness waived. Automation, Inc. in and assembled. Crew and began first well up on J -08A. Commence work over, Alberta, CA training on rig. work 20150531 20150610 20150719 20150923 20:00 20150924 12:00 Enclosed mud pit designed w/new gas monitoring system (LEL and H2S detectors) ASR day shift began crew change activities.. Walked down job, reviewed hookup, performed JSA, discussed N2. 20150925 05:30 Abbreviations: LTA - Less Than Adequate NI - Needs Improvement SPAC - Standards, Procedures & Controls ASR day shift began. Halliburton in final stages of N2 clean. Flowing back to outside tanks. 20150925 06:00 Crew trained and deemed qualified to operate ASR. After S- 27, ASR WOs 5 wells (including J -01A nitrogen) Halliburton finished N2 clean-out. Total 200mscf and 207 bbls seawater pumped. 20150925 06:30 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 Halliburton N2 clean- out. Leak and pause of 27 mins after 133 mscf. ASR night shift on duty. Flowback hardlined to exterior tanks. 20150925 02:30 Pumped 50 bbls seawater via ASR pump at 3.5 bbls/min down annulus 20150925 06:40 Completed pumping 50 bbls seawater. 227 bbls recovered in exterior tanks 20150925 07:00 Bleeding pressure from work string to exterior tanks. Observed 0 P from 1,000 to 300 psig in annulus. However pressure reading not indicative of annulus pressure. Was reading trapped pressure between ASR pump and check valve. 20150925 07:00 Pressure in tubing noted to be 0 psig. Annulus reading of 300 prig (incorrect reading). ASR directed to pump 2nd 50 bbls of seawater 20150925 08:48 Pumped 4.1 bbls, noted immediate pressure bump from "nothing" to 1,000 prig. Ceased pumping. 20150925 08:50 WSM stated on radio from WSM trailer "I'm confused fellas, let's sit down and talk" OP2 opened HCR valve. Tool pusher OP2 (in drillers console OP2 notes extreme Tool pusher and OP 1 heads to WSM trailer. on rig floor) radios OP2 walks down stairs noise in manifold meet in tank module OP1 started to bleed (in choke manifolldd to manifold room to room (gas flowing manifold room to align Tool pusher radioed pressure via auto room) to check status. check on OP1 through choke valves to bleed OP2 from manifold choke to interior tanks. OP1 does not hear call activities. Passes manifold). Motions for pressure from annulus p Reading pressure on due to noise of fluid through "8 ft of tank g OP1 to follow him back to tank module gas room to open HCR valve to bleed annulus annulus. Noted 50 psig (gas)flowing through room to enter up stairs to drillers buster and interior tanks pressure. drop within minutes. choke manifold manifold room. console. Both pass through tank room on 20150925 ' 08:53 20150925 08:55 20150925 08:56 20150925 ' 08:58 20150925 08:59 20150925way out. 09:00 Door between tank Once HCR opened, OP2 exposed to tank and OP2 exposed tank manifold room and first time annulus room for —10 room forr -30 interior tank room is pressure was being seconds. Noted seconds while closed. read. weird smell. motioning to go outside where they could talk. Abbreviations: -- _ LTA - Less Than Adequate Start of gas bleed off NI - Needs Improvement through choke SPAC - Standards, Procedures & Controls manifold into interior tank OP1 and OP2 felt dizzy and light headed after —45 seconds of exposure to tank room. Had hard time climbing stairs. 20150925 —09:00 Crew recognized "something was not right" 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. OP2 descends stairs and walks to WSM trailer to find Tool Pusher. OP1 goes back through tank room through manifold room and waits outside on landing to manifold room. 20150925 — 09:03 Abbreviations: LTA - Less Than Adequate NI - Needs Improvement SPAC-Standards, Procedures & Controls Workers started feeling better once they got outside to top of steps Door btwn manifold and mud rooms closed 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 vrt steps into ianK 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 Itries to walk across OP2 meets tool pusher detect any hazardous the room, makes it half in yard outside WSM OP 2 and tool pusher conditions; unknown way and turns around. trailer. Communicates join OP 1 at manifold 02 Deficient Loses consciousness odd feeling and smell. room. atmosphere existed on outside stairs on drillers console side of 20150925 ` 09:05 20150925 09:07 20150925 09:09 the tank module. 20150925 09:10 Well still bleeding gas Worker did not through choke manifold recognize hazard and to tank room for —13 great risk minutes. Unconscious tool OP 1, OP2, and tool Mandown call made, pusher extricated from pusher received Incident reported to Emergency Response tank room by IWS oxygen on site and external agencies; initiated owner via hatchinvestigation began transported to MPU opening. clinic for evaluation. 20150925 09:12 20150925 09:14 20150925 09:20 20150925 10:10 I ■ ■ Automated Service Rig 1 (ASR 1) 25 September 2015 Incident MID and Valve Status at time of Pumping Second 50 bbls of Seawater— 0848 hrs E I b � a ♦ I s � c _ I Status of valve ti CI Valve open UL C3 Valve closed Valve status b I ddr — obtained through „ interviews, no "TAM17V' T WA photo evidence _Ir T — — — —`�'°' — — J of valve status at 0848 hrs on 25 ----- ----- i I September 2015 Palo stcicsed w w� I I I PI Al:7KN 1Y�It Otl11M I I II I I� WWI g07I "Law I �w M0E A U F".f 11PP 51 qK it WELL WPU GEN PROCESS PIPING & INSTRUMENT DIAGRAM ASR -1 REG a rrau ■re PI—MCO—ODGXX E =I© Mn =n Automated Service Rig 1 (ASR 1) 25 September 2015 Incident MID and Valve Status at time of Incident - — 0856 hours, Started to Bleed Annulus Pressure KU 7 OMM r r--------� j mOU ot T own L---- I 1 AWAM(M I I I �...._:. OftI C--L� C- -0_ low _SvccaL I I I C I I II OL wr 3 1 I 1 WA man L F — — — — — — — — —1 I I MM R I 1ww TM I I rim PI 5MME W. I I rm� ■ ■ ■ ■ ■ ■ I 0 � I Status of valve C3 Valve open ® Valve closed ONot confirmed in a I photo IdL IME In f131 YI w DA WPU GEM PROUSS PIPING & INSTRUMENT DAGRAM ASR -1 F*G Paz= 1wMM ■roe PI- MOO-OOGA Ow $ 4 SIN ME IA THE STATE GOVERNOR BILL WALKER October 2, 2015 Certified Mail Return Receipt Requested 7015 0640 0006 0779 6002 Mr. David Wilkins Senior Vice President Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number: OTH-15-025 Notice of Investigation Unauthorized Changes to Approved Permit Hilcorp ASR -1 Rig MPU J -08A (PTD 1991770, Sundry 315-527)) Dear Mr. Wilkins: A -11 -ask Oil aid Gas Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3.572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov Due to a safety incident during Hilcorp Alaska LLC's (Hilcorp) September 25, 2015 workover operations on Rig ASR1 (ASR1), the Alaska Oil and Gas Conservation Commission (AOGCC) is investigating whether those operations at Milne Point Unit well J -08A (MPU J -08A) comported with the requirements of 20 AAC 25.507 and 25.526. AOGCC requests Hilcorp provide the following information no later than October 12, 2015: - Detailed flow diagram for pumping nitrogen and seawater used for the well cleanout; including annotations for all equipment and the position of all valves and blowout preventers that are in a potential flow path to/from the well; Detailed flow schematic for non -cleanout related workover operations; Copy of the written test procedure for verifying the piping integrity prior to pumping nitrogen and seawater; including evidence of the test being performed (e.g., test chart); - Copy of the written procedure specific to MPU J -08A and ASR1 for cleanout operations involving the use of nitrogen; - Copy of documentation of job safety assessments, risk evaluations, and any safety meetings before pumping nitrogen for the cleanout operation; also, a copy of Hilcorp's written policy regarding conduct of such and what is included; - List the dates, wells and rigs of all Hilcorp rig workovers (excluding coil tubing units) in Alaska that have used nitrogen for a wellbore cleanout; - Copy of all daily reports commencing with the date of mobilization of ASR1 to MPU J - 08A; Mr. Dave Wilkins October 2, 2015 Page 2 of 2 - Copy of reports that document the analyses of samples taken (mud pit fluids; mud pit trailer insulation; etc.); - Copy of detailed sequence of operations from rig up to perform wellbore cleanout through the incident; - A list of all gas detection equipment used during rig up of ASR1 at MPU J -08A and copies of gas detection equipment test records for testing performed after rigging up ASR1 on MPU J -08A; - Copy of any specifications for air exchange/ventilation in the enclosed mud pit trailer. - Copy of full reports of any investigation, risk assessments, and root cause analysis reports. This request is made pursuant to 20 AAC 25.300. Failure to comply with this request is itself a regulatory violation. The AOGCC reserves the right to purse an enforcement action in this matter according to 20 AAC 25.535. Should you have any questions about the information request, please contact Jim Regg at (907) 793-1236. cc: John Barnes, Hilcorp Jim Regg AOGCC Inspectors Sincerely, 4�4p /,0 / Cathy P. Foerster Chair, Commissioner AND APPEAL 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. ru Domestic Mail Only 0 0 For delivery information, visit our website at www.usps.com". 3800 Centerpoint Dr., Ste. 1400 IT- r` Certified Mail Fee ❑ Priority Mail Express& Ct $ r-3 Extra Services & Fees (check box, add fee as appropriate) ❑ Return Receipt (hardcopy) $ ..3 ❑ Return Receipt (electronic) $ Postmark r-3 1:3ElAdult ❑ Certified Mail Restricted Delivery $ Here C3 signature Required $ _. ❑ Registered Mail I ❑ Adult Signature Restricted Delivery $ I I O Postage III II II I II II -J3 Total Postage and Fees III ED Mr. David Wilkins I III ❑Adult Signature Restricted Delivery Mail Restricted ❑ Restricted Ln Sent To Senior Vice President a C3StreetanorApt.IVo.,oiPC7 Box i Hilcorp Alaska, LLC r` _____________ 3800 Cen±erpoint Dr; Ste. 1400 ._ City, State, ZIP+4� Anchorage, AK 99503 :rr t Certified Mail@ Delivery 9590 9401 0049 5071 3202 53 COMPLETE•N COMPLETE THIS SECTIONON DELIVERY ■ Complete items 1, 2, and 3. A. Signat \ ., 2. Article Number (Transfer from service label) ■ Print your name and address on the reverse X Agent ^7 7 7 015 0 6 4 0 0006 0 r�7 1 p 1 6 0 0 2 so that we can return the card to you. ❑ Addressee ■ Attach this card to the back of the mailpiece, B. a byI(Printed Name) Dateofeliv ' PS Form 3811, April 2015 PSN 7530-02-000-9053 or on the front if space permits. , !U/ V 4f ,, 1 • " - ^ '^' - D. Is delive address different from item 1 e ❑ Yes If ter delivery address below: ❑ No Mr. David Wilkins V Senior Vice President Hilcorp Alaska, LLC 2015 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 3. Service Type ❑ Priority Mail Express& ❑Adult Signature ❑ Registered Mail I I I I II III III II II I II II III II I III I IIIII I III ❑Adult Signature Restricted Delivery Mail Restricted ❑ Restricted Certified Mail@ Delivery 9590 9401 0049 5071 3202 53 L1 Certified Mail Restricted Delivery ®'Return Receipt for ❑ Collect on Delivery Merchandise 2. Article Number (Transfer from service label) ❑ Collect on Delivery Restricted Delivery �d Mail L Signature Confirmation— ❑ Signature Confirmation ^7 7 7 015 0 6 4 0 0006 0 r�7 1 p 1 6 0 0 2 �d Mail Restricted Delivery Restricted Delivery 1500) PS Form 3811, April 2015 PSN 7530-02-000-9053 Domestic Return Receipt Regg, James B (DOA) From: Schwartz, Guy L(DOA) Sent: Thursday, October Ol'2OlS4:40PIVI To: Reog.]ames B (DOA); dduckworth@hi|co/pzom Subject: RE: AN'46Sundry #]l5-55SRequest for BOP reconfiguration Storm packer is not required to be set at this time to safety well. Closing blinds on tested casing is adequate. Regards, Guy Schwartz Sr. Petroleum Engineer AOGC[ 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-rnoil message, including any attachments, contains information from the Alaska Oil arid Gas Conservation Cory) mbsion(xOGCq.State of Alaska arid is for the sole use of the intended recipient(s). If 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 ofthis e'mai|' please delete it, without first saving or forwarding it, and, sothat the xO6CCisaware o(the mistake in sending i||o you, confoo|Guy Schwartz o|(907-7p3-/z26)or< � From: Regg,James B(OOA) Sent: Thursday, October U1,30154:J8PM To: Schwartz, Guy L(DOA) Subject: FW: AN -46 Sundry #315-555 Request for BOP reconfiguration Jim Regg Supervisor, Inspections AOGCC 333 W.7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY woncs 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 nrdisclosure ofsuch information may violate state o/federal law. |fyou are anunintended recipient nfthis e-maU. please delete it, without first saving o,forwarding it, arid, sothat the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or From: Daniel Duckworth-([) Sent: Thursday, October 01,2U154:27PM To: Regg,James B(DOA) Cc: Trudi Hallett; Ted Kramer; Dan Marlowe; Stan Go|is; [het5tarka|; Harold Soule - (C) Subject: RE: AN -46 Sundry #315-555 Request for BOP reconfiguration The blinds have been closed and there is a CRET @ 8,107' w/ 397' of cement on top- that plug has been tested to 2500#s onchart f/3Omins. If that is not sufficient we do have a storm pkr on board and can set it if need be. From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Thursday, October 01, 2015 4:03 PM To: Daniel Duckworth - (C) Cc: Schwartz, Guy L (DOA) Subject: RE: AN -46 Sundry #315-555 Request for BOP reconfiguration As I stated earlier today in our phone call (223pm), Hilcorp has been instructed to suspend all workover operations until further notice. Anna 46 (PTD 1820720) should be secured. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501. 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or lim.regg@alaska.gov. From: Daniel Duckworth - (C) [mailto:dduckworth@hilcorp.com] Sent: Thursday, October 01, 2015 3:25 PM To: Regg, James B (DOA) Subject: AN -46 Sundry #315-555 Request for BOP reconfiguration Due to well work conditions (pulling 9 5/8" casing) we are requesting a change to our BOP stack to include pipe rams for the 9 5/8" casing that will be pulling. We could not find a single stack so we had to go with a double. We will be ready to pretest/test on our weekly schedule tonight at midnight. Regg, James B (DOA) From: Daniel Duckworth - (C) <dduckworth@hilcorp.com> Sent: Thursday, October 01, 2015 4:27 PM To: Regg, James B (DOA) Cc: Trudi Hallett; Ted Kramer; Dan Marlowe; Stan Golis; Chet Starkel; Harold Soule - (C) Subject: RE: AN -46 Sundry #315-555 Request for BOP reconfiguration The blinds have been closed and there is a CRET @ 8,107' w/ 397' of cement on top- that plug has been tested to 2500#s on chart f/ 30 mins. If that is not sufficient we do have a storm pkr on board and can set it if need be. From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Thursday, October 01, 2015 4:03 PM To: Daniel Duckworth - (C) Cc: Schwartz, Guy L (DOA) Subject: RE: AN -46 Sundry #315-555 Request for BOP reconfiguration As I stated earlier today in our phone call (223pm), Hilcorp has been instructed to suspend all workover operations until further notice. Anna 46 (PTD 1820720) should be secured. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, Al< 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCQ, State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. if you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or jim.regg@alaska.gov. From: Daniel Duckworth - (C) [mailto:dduckworth@hilcorp.com] Sent: Thursday, October 01, 2015 3:25 PM To: Regg, James B (DOA) Subject: AN -46 Sundry #315-555 Request for BOP reconfiguration Due to well work conditions (pulling 9 5/8" casing) we are requesting a change to our BOP stack to include pipe rams for the 9 5/8" casing that will be pulling. We could not find a single stack so we had to go with a double. We will be ready to pretest/test on our weekly schedule tonight at midnight. Regg, James B (DOA) From: Regg, James B (DOA) T 1 Sent: Thursday, October 01, 2015 3:17 PM To: DOA AOGCC Prudhoe Bay Subject: Hilcorp Workover Operations Importance: High Heads up. Hilcorp has been instructed this afternoon to suspend workover operations. Drilling operations are not affected. HAK ASR1 is authorized to finish running the ESP completion in MPU J -08A only; Nordic 3 is also authorized to complete the ongoing work on MPU L-20 (1-2 days). Moncla 404 (Anna Platform well 46) should be suspending operations today (roughly 2 weeks remaining to complete workover; currently at a point in operation where well is secure). Any inquiries should be directed to me. Please do not discuss this with anyone as the ASR1 incident is under investigation. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.regg@alaska.gov. Regg, James B (DOA) From: Foerster, Catherine P (DOA) Sent: Thursday, October 01, 2015 2:45 PM tt�, To: David Wilkins Cc: Seamount, Dan T (DOA); Regg, James B (DOA); Schwartz, Guy L (DOA) Subject: suspension of workover operation FYI, Commissioner Seamount and I have instructed our staff to notify all Hilcorp workover rigs to find the next opportunity safely to suspend operations until such time as the AOGCC can regain confidence that Hilcorp can conduct such operations using good oilfiled practices and can stick to the steps and procedures approved in writing in the sundries that come before the AOGCC. If you have any questions, please don't hesitate to contact Commissioner Seamount or me. Regg, James B (DOA) From: Stan Porhola <sporhola@hilcorp.com> Sent: Wednesday, September 30, 2015 1:45 PM To: Regg, James B (DOA) Cc: John Barnes; Grimaldi, Louis R (DOA); DOA AOGCC Prudhoe Bay; Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Bo York; David Wilkins; Marc Bond Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Understood, Jim. We will have our company man on location make the proper notifications (web form) to you and your inspectors regarding the BOPE test. Stan From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Wednesday, September 30, 2015 1:20 PM To: Stan Porhola Cc: John Barnes; Grimaldi, Louis R (DOA); DOA AOGCC Prudhoe Bay; Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Bo York; David Wilkins; Marc Bond Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Based on Hilcorp's response below and the proposed procedure received by email on September 27, 2015, AOGCC approves Hilcorp's request to continue with operations on MPU J -08A (PTD 1991170) under Sundry 315-527 using rig HAK ASR1. Any changes from the proposed procedure must receive prior written approval from AOGCC. All other sundry approvals involving HAK ASR1 are currently under review and may require additional discussion with Hilcorp before commencing work. This approval is without prejudice to AOGCC's ongoing investigation. Please resend the ROPE test notice with updated start date/time. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or jim,.r_eM.@a.laska...gov-, From: Stan Porhola [maiito sporhola(a>h_i3corp co.m.] Sent: Tuesday, September 29, 2015 3:18 PM To: Regg, James B (DOA) Cc: John Barnes; Grimaldi, Louis R (DOA); DOA AOGCC Prudhoe Bay; Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Bo York; David Wilkins; Marc Bond Subject: RE: AOGCC Test Witness Notification Request: ROPE, ASR 1 MPU J -08A Jim, 1\ Hi|corp has completed field activities for the investigation and is currently preparing a Root Cause Analysis Incident Report due Thursday, 10/01/2015. No final conclusions have been made at this time. However, the gas buster's drain valve is locked in the dose position preventing any gas returns to our pit system. Our planned normal operations will be for all well returns to be taken to our external 500 bbl kill tank. 2) Current well status for MPU ]-U8A(PTD 1g9'117)—Tubing: 0psi (Echomete/fluid level shot at*c500');Casing: Vacuum (Echometer fluid level shot inconclusive), Well Configuration: Well has workstring on bottom at 6,535' MD with 2-7/8" tubing at surface; on Sunday 9/27/2015 pumped 20 bbl neat MeOH down the tubing and 20 bbl neat MeOH and 45 bbl 60/40 MeOH down the annulus. Both tubing and annulus were on a vacuum after pumping the freeze protect fluid. 3) The plans for A6R1after completing MPU J'O8Aare tomove the rig tothe next well, MPU G-OOA. 4\ LisiofweUovvithapprovedsundriesinvo|vingHAKASK1areasfoUowcMPUG'88A,MPUE'21,IVIPUS-34,andK4PU E-15.Planned sequence ofwell workovers isasfollows: MPU G'08A,MPU E'21,then evaluate the next wells to mnvetofnomthe|isiofcurnentofapprovedaundriesandfutureoundhesforneorntfai|edESPwe||s(MPUH'16, MPU E-19, and MpUJ'09A). 5) The rig winterization for46Rl includes 2iet heaters installed and running providing heat to the BOPE in our enclosure under the rig floor, blankets for exposed choke, kill, and hydraulic lines are located at Milne Point and will be installed on the next rig up. A box has been installed on the mud tank trailer to allow heated air to be circulated down the blankets for the choke and kill lines. We are currently pending a decision on moving up a rental glycol/steam boiler system out nfFairbanks. 6) It is our intent to normally have the ASR complete a well before going off -shift. However, the procedures for securing well isdetailed below: a. In the event the well is capable of flow to surface unassisted, we would install the necessary clownhole plugs that would he the same nrsimilar to a conventional storm packer with a kill string hung below and a tubing hanger with a back -pressure valve installed. b. Freeze protecting the well and the BOPE would be completed before crews were to leave the rig. The BOPE stack will be in a heated enclosure under the rig floor, the blind rams locked and secured, and the hydraulic lines removed to prevent freezing. Temperature conditions will be monitored in the heated enclosure. c Hi|co/pwiU evaluate weather conditions on a daily basis, recognizing that the rig derrick materials are rated to -40~F. It is very likely that we will suspend operations at or before we reach this ambient temperature. d. VVewill test the BOPEtothe &4A5P,for partial and full tests. e. BOPE tests will be done with a non-com pressi ble fluid and charted with records maintained for AOGCC review. f. The securing of the manual valves on the choke and kill lines will include standard lock -out tag -out procedures. g. The kill line does not have any 1502 union connections. It currently has a Grayloc connection. h. The choke manifold will not be connected to the BOPE while the crew is off location. The choke and kill lines will be placed in a secure location until the crews return before re -attaching to the BOPE stack. i. When the ASR -1 crew goes on days off, we will identify well controlled certified individuals from the Nordic #3 who will be prepared to and will respond to an event that requires mitigating well pressures or anomalous well conditions. A full BOPE test will be conducted post -suspension operations. Let meknow ifyou need any additional information. • Stan Porhola 1 Nortlx Slope sset `i'c ani Hilcorp Alaska, LLC sporhola@hilcorp.com Officc: }() i'77 �1�1112 From: Regg, James B (DOA) [ma ilto:jimxeggCcbalaska.gov] Sent: Tuesday, September 29, 2015 9:20 AM To: Wayne Biart - (C) Cc: Stan Porhola; John Barnes; Grimaldi, Louis R (DOA); DOA AOGCC Prudhoe Bay; Foerster, Catherine P (DOA); Schwartz, Guy L (DOA) Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Couple issues before AOGCC makes a decision allowing Hilcorp to proceed with J -08A: 1) Has Hilcorp completed the incident investigation, and is the report sent Sunday the final, full investigation report? Is Hilcorp's final conclusion that the drain valve on the gas buster was left open? 2) Confirm status of well — current tubing and annulus pressures, fluid levels, well configuration (pipe in hole) — we understand the well should have been freeze protected with McOH on Sunday (AOGCC approved the procedure). 3) Plans for ASR1 after completing J -08A. 4) List of wells with approved sundries involving HAK ASR1 and planned sequence of well workovers. 5) Status of winterization on the rig. 6) Status of Hilcorp's reply to AOGCC comments/questions (sent 8/25/15) relating to the proposed program for securing wells during shutdown periods when HAK ASR1 crews are on days off crews. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim,r -Ea alaska-.gov. From: Wayne Biart - (C) [maiito..biart�a-hilcorp.com] Sent: Tuesday, September 29, 2015 8:31 AM To: Grimaldi, Louis R (DOA); DOA AOGCC Prudhoe Bay Cc: Stan Porhola; John Barnes Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Will do Lou. Regards Wayne From: Grimaldi, Louis R (DOA) [mailto:lou.rimaldi@alaska.gov] Sent: Tuesday, September 29, 2015 8:27 AM To: Wayne Biart - (C); DOA AOGCC Prudhoe Bay Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Wayne Update this evening around dinner please. Lou Lou Grimaldi (on cell) Petroleum Inspector Alaska Oil and Gas Conservation Commission (907) 776-5402 (Home) (907) 252-3409 (Cell) -------- Original message -------- From: Wayne Biart Date:09/28/2015 22:15 (GMT -09:00) To: DOA AOGCC Prudhoe Bay Subject: AOGCC Test Witness Notification Request: BOPS, ASR 1 MPU J -08A 0 Question Type of Test Requested: Requested Time for Inspection Location Name E-mail Phone Number Company Other Information: Submission ID: Answer He= 09-30-2015 6:00 AM ASR 1 MPU J -08A Wayne Biart �d ?ial t,ii l ilt: orv.con (907) 3100243 Hilcorp 319316522218349748 4 Regg, James B (DOA) From: Regg, James B (DOA) �l Sent: Wednesday, September 30, 2015 1:20 PM To: Stan Porhola Cc: John Barnes; Grimaldi, Louis R (DOA); DOA AOGCC Prudhoe Bay; Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Bo York; David Wilkins; Marc Bond Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Based on Hilcorp's response below and the proposed procedure received by email on September 27, 2015, AOGCC approves Hilcorp's request to continue with operations on MPU J -08A (PTD 1991170) under Sundry 315-527 using rig HAK ASR1. Any changes from the proposed procedure must receive prior written approval from AOGCC. All other sundry approvals involving HAK ASR1 are currently under review and may require additional discussion with Hilcorp before commencing work. This approval is without prejudice to AOGCC's ongoing investigation. Please resend the BOPE test notice with updated start date/time. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or jim.regg@alaska.gov. From: Stan Porhola [mailto:sporhola@hilcorp.com] Sent: Tuesday, September 29, 2015 3:18 PM To: Regg, James B (DOA) Cc: John Barnes; Grimaldi, Louis R (DOA); DOA AOGCC Prudhoe Bay; Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Bo York; David Wilkins; Marc Bond Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Jim, 1) Hilcorp has completed field activities for the investigation and is currently preparing a Root Cause Analysis Incident Report due Thursday, 10/01/2015. No final conclusions have been made at this time. However, the gas buster's drain valve is locked in the close position preventing any gas returns to our pit system. Our planned normal operations will be for all well returns to be taken to our external 500 bbl kill tank. 2) Current well status for MPU J -08A (PTD 199-117) — Tubing: 0 psi (Echometer fluid level shot at +/- 500'); Casing: Vacuum (Echometer fluid level shot inconclusive), Well Configuration: Well has workstring on bottom at 6,535' MD with 2-7/8" tubing at surface; on Sunday 9/27/2015 pumped 20 bbl neat McOH down the tubing and 20 bbl neat McOH and 45 bbl 60/40 McOH down the annulus. Both tubing and annulus were on a vacuum after pumping the freeze protect fluid. 3) The plans for ASR1 after completing MPU J -08A are to move the rig to the next well, MPU G -08A. 4) List of wells with approved sundries involving HAK ASR1 are as follows: MPU G -08A, MPU E-21, MPU S-34, and MPU E-15. Planned sequence of well workovers is as follows: MPU G -08A, MPU E-21, then evaluate the next wells to move to from the list of current of approved sundries and future sundries for recent failed ESP wells (MPU H-16, MPU E-19, and MPU J -09A). 5) The rig winterization for ASR1 includes 2 jet heaters installed and running providing heat to the BOPE in our enclosure under the rig floor, blankets for exposed choke, kill, and hydraulic lines are located at Milne Point and will be installed on the next rig up. A box has been installed on the mud tank trailer to allow heated air to be circulated down the blankets for the choke and kill lines. We are currently pending a decision on moving up a rental glycol/steam boiler system out of Fairbanks. 6) It is our intent to normally have the ASR complete a well before going off -shift. However, the procedures for securing a well is detailed below: a. In the event the well is capable of flow to surface unassisted, we would install the necessary downhole plugs that would be the same or similar to a conventional storm packer with a kill string hung below and a tubing hanger with a back -pressure valve installed. b. Freeze protecting the well and the BOPE would be completed before crews were to leave the rig. The BOPE stack will be in a heated enclosure under the rig floor, the blind rams locked and secured, and the hydraulic lines removed to prevent freezing. Temperature conditions will be monitored in the heated enclosure. c. Hilcorp will evaluate weather conditions on a daily basis, recognizing that the rig derrick materials are rated to -40°F. It is very likely that we will suspend operations at or before we reach this ambient temperature. d. We will test the BOPE to the MASP, for partial and full tests. e. BOPE tests will be done with a non-compressible fluid and charted with records maintained for AOGCC review. f. The securing of the manual valves on the choke and kill lines will include standard lock -out tag -out procedures. g. The kill line does not have any 1502 union connections. It currently has a Grayloc connection. h. The choke manifold will not be connected to the BOPE while the crew is off location. The choke and kill lines will be placed in a secure location until the crews return before re -attaching to the BOPE stack. i. When the ASR -1 crew goes on days off, we will identify well controlled certified individuals from the Nordic #3 who will be prepared to and will respond to an event that requires mitigating well pressures or anomalous well conditions. j. A full BOPE test will be conducted post -suspension operations. Let me know if you need any additional information. Regards, Stan Porhola I Operaimns l,;ngim et North Slol)c asset 'f'ciam Hilcorp Alaska, LLC sporholaPhilcorp.com {:Afice: (907) 7'7 X3412 From: Regg, James B (DOA) [mailto:jim.regg alaska.clov] Sent: Tuesday, September 29, 2015 9:20 AM To: Wayne Biart - (C) Cc: Stan Porhola; John Barnes; Grimaldi, Louis R (DOA); DOA AOGCC Prudhoe Bay; Foerster, Catherine P (DOA); Schwartz, Guy L (DOA) Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Couple issues before AOGCC makes a decision allowing Hilcorp to proceed with J -08A: 1) Has Hilcorp completed the incident investigation, and is the report sent Sunday the final, full investigation report? Is Hilcorp's final conclusion that the drain valve on the gas buster was left open? 2) Confirm status of well — current tubing and annulus pressures, fluid levels, well configuration (pipe in hole) —we understand the well should have been freeze protected with McOH on Sunday (AOGCC approved the procedure). 3) Plans for ASR1 after completing J -08A. 4) List of wells with approved sundries involving HAK ASR1 and planned sequence of well workovers. 5) Status of winterization on the rig. 6) Status of Hilcorp's reply to AOGCC comments/questions (sent 8/25/15) relating to the proposed program for securing wells during shutdown periods when HAK ASR1 crews are on days off crews. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. if you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or Lm.regg@alaska_gov. From: Wayne Biart - (C) [maiIto: wbiart@hilcorp.com1 Sent: Tuesday, September 29, 2015 8:31 AM To: Grimaldi, Louis R (DOA); DOA AOGCC Prudhoe Bay Cc: Stan Porhola; John Barnes Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Will do Lou. Regards Wayne From: Grimaldi, Louis R (DOA) [mailto:lou.grimaldi@alaska.govj Sent: Tuesday, September 29, 2015 8:27 AM To: Wayne Biart - (C); DOA AOGCC Prudhoe Bay Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Wayne Update this evening around dinner please. Lou Lou Grimaldi (on cell) Petroleum Inspector Alaska Oil and Gas Conservation Commission (907) 776-5402 (Home) (907) 252-3409 (Cell) -------- Original message -------- From: Wayne Biart Date:09/28/2015 22:15 (GMT -09:00) To: DOA AOGCC Prudhoe Bay Subject: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A uestion Type of Test Requested: Requested Time for Inspection Location Name E-mail Phone Number Company Other Information: Submission ID: Answer :•' 09-30-2015 6:00 AM ASR 1 MPU J -08A Wayne Biart ,,vbiartL&hilcorp.com (907) 3100243 Hilcorp 319316522218349748 Regg, James B (DOA) From: Stan Porhola <sporhola@hilcorp.com> 5 e ( qh cl,� Sent: Tuesday, September 29, 2015 3:18 PM L To: Regg, James B (DOA) Cc: John Barnes; Grimaldi, Louis R (DOA); DOA AOGCC Prudhoe Bay; Foerster, Catherine P (DOA); Schwartz, Guy L (DOA); Bo York; David Wilkins; Marc Bond Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Jim, 1) Hilcorp has completed field activities for the investigation and is currently preparing a Root Cause Analysis Incident Report due Thursday, 10/01/2015. No final conclusions have been made at this time. However, the gas buster's drain valve is locked in the close position preventing any gas returns to our pit system. Our planned normal operations will be for all well returns to be taken to our external 500 bbl kill tank. 2) Current well status for MPU J -08A (PTD 199-117) — Tubing: 0 psi (Echometer fluid level shot at +/- 500'); Casing: Vacuum (Echometer fluid level shot inconclusive), Well Configuration: Well has workstring on bottom at 6,535' MD with 2-7/8" tubing at surface; on Sunday 9/27/2015 pumped 20 bbl neat McOH down the tubing and 20 bbl neat McOH and 45 bbl 60/40 McOH down the annulus. Both tubing and annulus were on a vacuum after pumping the freeze protect fluid. 3) The plans for ASR1 after completing MPU J -08A are to move the rig to the next well, MPU G -08A. 4) List of wells with approved sundries involving HAK ASR1 are as follows: MPU G -08A, MPU E-21, MPU S-34, and MPU E-15. Planned sequence of well workovers is as follows: MPU G -08A, MPU E-21, then evaluate the next wells to move to from the list of current of approved sundries and future sundries for recent failed ESP wells (MPU H-16, MPU E-19, and MPU J -09A), 5) The rig winterization for ASR1 includes 2 jet heaters installed and running providing heat to the BOPE in our enclosure under the rig floor, blankets for exposed choke, kill, and hydraulic lines are located at Milne Point and will be installed on the next rig up. A box has been installed on the mud tank trailer to allow heated air to be circulated down the blankets for the choke and kill lines. We are currently pending a decision on moving up a rental glycol/steam boiler system out of Fairbanks. 6) It is our intent to normally have the ASR complete a well before going off -shift. However, the procedures for securing a well is detailed below: a. In the event the well is capable of flow to surface unassisted, we would install the necessary downhole plugs that would be the same or similar to a conventional storm packer with a kill string hung below and a tubing hanger with a back -pressure valve installed. b. Freeze protecting the well and the BOPE would be completed before crews were to leave the rig. The BOPE stack will be in a heated enclosure under the rig floor, the blind rams locked and secured, and the hydraulic lines removed to prevent freezing. Temperature conditions will be monitored in the heated enclosure. c. Hilcorp will evaluate weather conditions on a daily basis, recognizing that the rig derrick materials are rated to -40°F. It is very likely that we will suspend operations at or before we reach this ambient temperature. d. We will test the BOPE to the MASP, for partial and full tests. e. BOPE tests will be done with a non-compressible fluid and charted with records maintained for AOGCC review. f. The securing of the manual valves on the choke and kill lines will include standard lock -out tag -out procedures. g. The kill line does not have any 1502 union connections. It currently has a Grayloc connection. h. The choke manifold will not be connected to the BOPE while the crew is off location. The choke and kill lines will be placed in a secure location until the crews return before re -attaching to the BOPE stack. i. When the ASR -1 crew goes on days off, we will identify well controlled certified individuals from the Nordic #3 who will be prepared to and will respond to an event that requires mitigating well pressures or anomalous well conditions. A full BOPE test will be conducted post -suspension operations. Let me know if you need any additional information. Regards, Stan Porhola. ( E pep ations I'll ngitwer Norb't :Slope Asset 'l'€: atn Hilcorp Alaska, LLC sporhola@hilcorp.com 0If'ii e: (907) 177 11 Mohile: (907) ' 31--8228 From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Tuesday, September 29, 2015 9:20 AM To: Wayne Biart - (C) Cc: Stan Porhola; John Barnes; Grimaldi, Louis R (DOA); DOA AOGCC Prudhoe Bay; Foerster, Catherine P (DOA); Schwartz, Guy L (DOA) Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU 3-08A Couple issues before AOGCC makes a decision allowing Hilcorp to proceed with J -08A: 1) Has Hilcorp completed the incident investigation, and is the report sent Sunday the final, full investigation report? Is Hilcorp's final conclusion that the drain valve on the gas buster was left open? 2) Confirm status of well — current tubing and annulus pressures, fluid levels, well configuration (pipe in hole) —we understand the well should have been freeze protected with McOH on Sunday (AOGCC approved the procedure). 3) Plans for ASR1 after completing J -08A. 4) List of wells with approved sundries involving HAK ASR1 and planned sequence of well workovers. 5) Status of winterization on the rig. 6) Status of Hilcorp's reply to AOGCC comments/questions (sent 8/25/15) relating to the proposed program for securing wells during shutdown periods when HAK ASR1 crews are on days off crews. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.regg@alaska.gov. From: Wayne Biart - (C) [mailto:wbiart@hilcorp.com] Sent: Tuesday, September 29, 2015 8:31 AM To: Grimaldi, Louis R (DOA); DOA AOGCC Prudhoe Bay Cc: Stan Porhola; John Barnes Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Will do Lou. Regards Wayne From: Grimaldi, Louis R (DOA) [mailto:lou.grimaldi alaska.gov] Sent: Tuesday, September 29, 2015 8:27 AM To: Wayne Biart - (C); DOA AOGCC Prudhoe Bay Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Wayne Update this evening around dinner please. Lou Lou Grimaldi (on cell) Petroleum Inspector Alaska Oil and Gas Conservation Commission (907) 776-5402 (Home) (907) 252-3409 (Cell) -------- Original message -------- From: Wayne Biart Date:09/28/2015 22:15 (GMT -09:00) To: DOA AOGCC Prudhoe Bay Subject: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Question Type of Test Requested: Requested Time for Inspection Location Name E-mail Phone Number Company Other Information: Submission ID: Answer 09-30-2015 6:00 AM ASR 1 MPU J -08A Wayne Biart wbiart! Regg, James B (DOA) From: Regg, James B (DOA) c6�Ilf,, Sent: Tuesday, August 25, 2015 2:46 PM ef� To: Stan Porhola Cc: Schwartz, Guy L (DOA); Wayne Biart - (C); DOA AOGCC Prudhoe Bay Subject: RE: Hilcorp ASR #1 Rig Suspension of Operations Procedure Questions/Observations regarding the proposed program for securing wells during shutdown periods when ASR1 crews are on days off: 1) Hilcorp is approaching the securing plan from the status of the operations; does not appear that the ability to flow to surface is factored into the secured well configuration. For example, a well that will flow to surface unassisted should have a storm packer installed with a kill string hung off below, the tubing hanger plugged with a back pressure valve, and a storm packer retrieval tool hung off the tubing hanger 2) No where do you reference freeze protecting the well and BOPE (including control lines; choke/kill lines; bypass line); we understand Hilcorp plans to work ASR1 during the winter months 3) At what temperature does Hilcorp plan to suspend workover operations? 4) Pressure testing of the BOPE — partial tests such as Blind Rams before disconnecting hydraulic control lines and full BOPE test —are dictated by the MASP in approved Sundry application (may exceed the procedure's stated high pressure test of 3000psi) 5) Pressure testing of the BOPE must be done with a non-compressible fluid and charted; records maintained for AOGCC review upon request 6) Steps #12 (Startup procedure) and #7 (Active procedure) state "secure inner choke line valve, inner kill line valve"; secure these manual valves how? 7) Step #13 (Startup) references a 1502 union/companion flange on the kill line; AOGCC regulations require the choke and kill lines to be assembled without hammer unions or internally -clamped swivel joints. 8) Step #8 (Active) says secure the rig/location; in this case it appears the choice manifold remains connected to the BOP stack at the well. How will the choke and kill lines be protected during the rig crews' absence? 9) Wells will be turned over to Production Operators — Step #16 (Startup) and Step # 9 (Active); are these individuals well control certified? Who is responsible for mitigating the well pressures/anomalous well conditions observed while the rig crews are on days off? 10) Both Startup and Active procedures should include the required full BOPE performance test before continuing post -suspension wellbore operations. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or jim.regg@alaska.gov. From: Stan Porhola [mailto:sporhola@hjlcorp.com] Sent: Tuesday, July 21, 2015 3:03 PM To: Regg, James B (DOA) Cc: Schwartz, Guy L (DOA); Wayne Biart - (C) Subject: Hilcorp ASR #1 Rig Suspension of Operations Procedure Jim, We have a day rig crew and a night rig crew working a roughly 3 week -on, 2 week -off schedule for the Hilcorp ASR #1 rig (new build workover rig currently at Milne Point). We would like to formally communicate our proposed program for securing wells during shutdown periods when rig crews will be going on their days off. The plan will be to include this procedure in all future sundries submitted using the Hilcorp ASR #1 rig. Start-up operations on a well (crews to leave after initial rig up over the well): 1.) Kill Well 2.) Install BPV 3.) ND Tree 4.) NU BOPE 5.) Rig up Manlift 6.) Remove BPV 7.) Install TWC 8.) Pressure Test Blind Rams, inner Choke Line valve, inner Kill Line valve to 250 psi for 5 min, 3,000 psi for 5 min 9.) Remove TWC 10.) Install BPV 11.) Close and Lock Blind Rams (disconnect hydraulic line) 12.) Close and secure inner Choke Line valve, inner Kill Line valve 13.) Install 1502 union/companion flange on kill line (to circulate/kill well if required) 14.) Move in ASR Rig over well/BOPE (raise derrick, install rig floor and wellbore insulation over BOPE) 15.) Secure rig/location and notify production when rig crews leave location 16.) Production operators to note wells pressures/inspect well on a daily basis 17.) Continue rig up when rig crews return Active operations on a well (crews to leave while actively working on a well): 1.) MU tubing hanger or storm packer and set tubing hanger in wellhead or storm packer at required depth. 2.) Install TWC (unless storm packer set) 3.) Pressure Test Blind Rams, inner Choke Line valve, inner Kill Line valve to 250 psi for 5 min, 3,000 psi for 5 min 4.) Remove TWC (unless storm packer set) 5.) Install BPV (unless storm packer set) 6.) Close and Lock Blind Rams (disconnect hydraulic line) 7.) Close and secure inner Choke Line valve, inner Kill Line valve 8.) Secure rig/location and notify production when rig crews leave location 9.) Production operators to note wells pressures/inspect well on a daily basis 10.) Continue well operations when rig crews return If you have any questions or concerns, please let me know. Regards, Stan Porhola I Operations i?iigkieer- North Slope Asset "9'eavn Hilcorp Alaska, LLC sporhola(a hilcorp.corn 0f11ce: ('()07') 777-84"12 Regg, James B (DOA) From: Regg, James B (DOA) Sent: Tuesday, September 29, 2015 9:20 AM To: Wayne Biart - (C) Cc: Stan Porhola; John Barnes; Grimaldi, Louis R (DOA); DOA AOGCC Prudhoe Bay; Foerster, Catherine P (DOA); Schwartz, Guy L (DOA) Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Couple issues before AOGCC makes a decision allowing Hilcorp to proceed with J -08A: 1) Has Hilcorp completed the incident investigation, and is the report sent Sunday the final, full investigation report? Is Hilcorp's final conclusion that the drain valve on the gas buster was left open? 2) Confirm status of well — current tubing and annulus pressures, fluid levels, well configuration (pipe in hole) —we understand the well should have been freeze protected with McCIH on Sunday (AOGCC approved the procedure). 3) Plans for ASR1 after completing J -08A. 4) List of wells with approved sundries involving HAK ASR1 and planned sequence of well workovers. 5) Status of winterization on the rig. 6) Status of Hilcorp's reply to AOGCC comments/questions (sent 8/25/15) relating to the proposed program for securing wells during shutdown periods when HAK ASR1 crews are on days off crews. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or jim.regg@alaska.gov. From: Wayne Biart - (C) [mailto:wbiart@hilcorp.com] Sent: Tuesday, September 29, 2015 8:31 AM To: Grimaldi, Louis R (DOA); DOA AOGCC Prudhoe Bay Cc: Stan Porhola; John Barnes Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU 3-08A Will do Lou. Regards Wayne From: Grimaldi, Louis R (DOA)[mailto:lou.grimaldi@alaska.gov] Sent: Tuesday, September 29, 2015 8:27 AM To: Wayne Biart - (C); DOA AOGCC Prudhoe Bay Subject: RE: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Wayne Update this evening around dinner please. Lou Lou Grimaldi (on cell) Petroleum Inspector Alaska Oil and Gas Conservation Commission (907) 776-5402 (Home) (907) 252-3409 (Cell) -------- Original message -------- From: Wayne Biart Date:09/28/2015 22:15 (GMT -09:00) To: DOA AOGCC Prudhoe Bay Subject: AOGCC Test Witness Notification Request: BOPE, ASR 1 MPU J -08A Question Type of Test Requested: Requested Time for Inspection Location Name E-mail Phone Number Company Other Information: Submission ID: Answer 09-30-2015 6:00 AM ASR 1 MPU J -08A Wayne Biart wbiar u.hilcor0.com (907) 3100243 Hilcorp 319316522218349748 PJ Regg, James B (DOA) From: Stan Porhola <sporhola@hilcorp.com> Sent: Monday, September 28, 2015 12:33 PM To: Regg, James B (DOA) Subject: RE: Hilcorp ASR #1 Investigation Report - Milne Point MPU J -08A (PTD 199-117) Thanks for the update. Stan From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Monday, September 28, 2015 12:32 PM To: Stan Porhola Subject: RE: Hilcorp ASR #1 Investigation Report - Milne Point MPU J -08A (PTD 199-117) Compiling our questions and information request. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 1.00 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail rnessage, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. if you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or lim.regg@alaska.gov. From: Stan Porhola [mailto:sporholaC-ahilcorp.com] Sent: Monday, September 28, 2015 12:31 PM To: Regg, James B (DOA) Cc: Wayne Biart - (C); John Barnes; Bo York; Carl Jones; Sarra Ghiassi; Schwartz, Guy L (DOA); Alaska NS - Milne - Field Foreman; Jerry Chitwood - (C); Kacey Bond; David Wilkins; Alaska NS - Milne - Plant Foreman; Foerster, Catherine P (DOA) Subject: RE: Hilcorp ASR #1 Investigation Report - Milne Point MPU 3-08A (PTD 199-117) Is there any update on your review of this investigation report? Stan From: Regg, James B (DOA) [mailto:Ji� m.reg_ alaska.gov] Sent: Sunday, September 27, 2015 7:44 PM To: Stan Porhola Cc: Wayne Biart - (C); John Barnes; Bo York; Carl Jones; Sarra Ghiassi; Schwartz, Guy L (DOA); Alaska NS - Milne - Field Foreman; Jerry Chitwood - (C); Kacey Bond; David Wilkins; Alaska NS - Milne - Plant Foreman; Foerster, Catherine P (DOA) Subject: RE: Hilcorp ASR #1 Investigation Report - Milne Point MPU J -08A (PTD 199-117) We will review this when back in the office tomorrow. AOGCC is investigating and there will likely be a request for additional information. Decision to continue operations pending our reviews of the info provided and the work procedure. Sent from my Samsung Galaxy smar(phone. -------- Original message -------- From: Stan Porhola <sporhola(a-,) orp.corn> Date: 09/27/2015 12:01 PM (GMT -09:00) To: "Regg, James B (DOA)" <jim.reggga,alaska.gnv> Cc: "Wayne Biart - (C)" <wbiartLc hilcorp.com>, John Barnes <jbarnes a,hilcorp.coin>, Bo York <byork &hilcorp.com>, Carl Jones <cajoi nesra�hilcorp.com>, Sarra Ghiassi <s h� iassira�hilcorp.com>, "Schwartz, Guy L (DOA)" <guy.schwa rtz(c�alaska.gov>, Alaska NS - Milne - Field Foreman <AlaskaNS-Milne- FieldForemanL)hilcorp.com>, "Jerry Chitwood - (C)" <jchitwoodghilcorp.com>, Kacey Bond <kbondghilcorp.com>, David Wilkins <dwilkinsnhilcorp.com>, Alaska NS - Milne - Plant Foreman <AlaskaNS-Milne-P1antForeman(7hilcorp.com> Subject: RE: Hilcorp ASR #1 Investigation Report - Milne Point MPU J -08A (PTD 199-117) Report attached. From: Stan Porhola Sent: Sunday, September 27, 2015 3:00 PM To: Regg, James B (DOA) (jim.regg@alaska.gov) Cc: Wayne Biart - (C); John Barnes; Bo York; Carl Jones; Sarra Ghiassi; guy.schwartzCa>alaska.gov; Alaska NS - Milne - Field Foreman; Jerry Chitwood - (C); Kacey Bond; David Wilkins; Alaska NS - Milne - Plant Foreman Subject: Hilcorp ASR #1 Investigation Report - Milne Point MPU J -08A (PTD 199-117) Jim, Attached is the Preliminary Investigation Report for the incident on the Hilcorp ASR #1 WO Rig on 9/25/2015 at well MPU J -08A (PTD 199-117). Below is the proposed procedure to continue with operations under Sundry 315-507. 1.) Open TIW valve, confirm no pressure on tubing, previous check had tubing on vacuum. 2.) Open annulus valve, confirm no pressure on casing, previous check had casing on vacuum. 3.) Open pipe rams. 4.) PU on 2-7/8" workstring to confirm it is free. 5.) POOH w/ 2-7/8" workstring. LD 2-7/8" workstring and cleanout BHA. a. Pump 8.5 ppg Seawater to replace pipe displacement while POOH. 6.) RU to run ESP. 7.) PU new ESP pump and RIH. RIH w/ existing 2-7/8" tubing. 8.) Land tubing hanger with base of ESP pump at +/- 4,600' MD. a. Run heat trace to +/- 3,000' MD. b. No control line to be run with pump. c. Confirm ESP cable connectivity is good. 9.) Lay down landing joint. Set BPV. RD Hilcorp ASR #1 WO Rig. 10.) RU Crane. ND BOPE. NU existing 3-1/8" 5,000# tree. Pull BPV. 11.) Set TWC. Test tubing hanger to 250/5,000 psi. Test tree to 250/5,000 psi. Pull TWC. ND Crane. 12.) Replace IA x OA pressure gauge if removed (7"x9-5/8") 13.) Turn well over to production. Let us know if you need additional information and if we are allowed to continue operations. Regards, Stan Porhola I Operations Engineer North loj)e Asset Team Hilcorp Alaska, LLC sporholaRbilcorp.corn C)ffic.e: (907) 777-84'12 Mobile: (907) :331-822€3 Regg, James B (DOA) From: Jones, Jeffery B (DOA) Sent: Monday, September 28, 2015 11:53 PM To: Regg, James B (DOA) Subject: FW: Procedure for frz. protecting J-08 Attachments: ASR 1 J-08 Frz. protect well wb.docx MPF J-08 Freeze protect procedure. Jeff B. Jones Petroleum Inspector Alaska Oil & Gas Conservation Commission N, Slope Ofc: 907-659-2714 Mobile: 907-744-4446 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 ieff.jones@alaska.gov. From: Mark O'Malley [mailto:momalley@hilcorp com] Sent: Saturday, September 26, 2015 7:59 AM To: Jones, Jeffery B (DOA) Subject: Procedure for frz. protecting 3-08 Jeff, Here you go. Our investigation team is on its way to the ASR rig. I would like to attempt this procedure after we complete our walk around. Thanks, Mark O'Malley MPU Field/Wells Foreman MOMalley hilcorp 907-670-3330 Office Alternate: Rob Handy III-lilcorp Alaska, LLC A Company Built on Energy 1 ASR #1 j -08A Freeze protection procedure Current well condition 2-7/8" pipe sitting on bottom @ 6525' 640 into the slotted lateral. BOP'S, Shaffer Annular preventer bag closed on pipe and TIW valve closed. Both tree annulus valves are closed. 0 -Psi. on tubing / 185 psi. on 2-7/8" by 7" annulus Proposed frz protection procedure. This can be accomplished by not removing or disturbing the current lines to the tank or the positions of the choke manifold. Bleed pressure off the annulus we will need to arrange the bleed lines to go to the Open Top or Kill tank. This can be accomplished without disrupting the rig piping. We will tie into the Halliburton hardline and back to the tanks with a 1" bleed hose. After this we will be able to close the pipe rams and lock them out until we are able to resume well completion operations. Frz. Protecting the work string. 1" stand pipe line is tied onto the TIW valve on one end and the other end is tied into the hardline run to the open top and kill tank. LRS can tie onto the hardline and pump back towards the well . Open TIW and pump 20 Bbls of Neat McOH. Frz. Protecting the work string / annulus . Currently Halliburton hard line is tie into the wells annulus valve. Tie LRS tie into that hard line and open the annulus valve and spear head Neat McOH 20 Bbls followed by 50 Bbls of 60/40 McOH. Close both the annulus valve the TIW valve and the pipe rams the well will stay in this configuration until our investigation is completed and permission is given to resume RWO operations. Regg, James B (DOA) From: Stan Porhola <sporhola@hilcorp.com> p Sent: Sunday, September 27, 2015 12:00 PM To: Regg, James B (DOA) Cc: Wayne Biart - (C); John Barnes; Bo York; Carl Jones; Sarra Ghiassi; Schwartz, Guy L (DOA); Alaska NS - Milne - Field Foreman; Jerry Chitwood - (C); Kacey Bond; David Wilkins; Alaska NS - Milne - Plant Foreman Subject: Hilcorp ASR #1 Investigation Report - Milne Point MPU J -08A (PTD 199-117) Jim, Attached is the Preliminary Investigation Report for the incident on the Hilcorp ASR #1 WO Rig on 9/25/2015 at well MPU J -08A (PTD 199-117). 3t S-Sz� Below is the proposed procedure to continue with operations under Sundry 31-5-S07. 1.) Open TIW valve, confirm no pressure on tubing, previous check had tubing on vacuum. 2.) Open annulus valve, confirm no pressure on casing, previous check had casing on vacuum. 3.) Open pipe rams. 4.) PU on 2-7/8" workstring to confirm it is free. 5.) POOH w/ 2-7/8" workstring. LD 2-7/8" workstring and cleanout BHA. a. Pump 8.5 ppg Seawater to replace pipe displacement while POOH. 6.) RU to run ESP. 7.) PU new ESP pump and RIH. RIH w/ existing 2-7/8" tubing. 8.) Land tubing hanger with base of ESP pump at +/- 4,600' MD. a. Run heat trace to +/- 3,000' MD. b. No control line to be run with pump. c. Confirm ESP cable connectivity is good. 9.) Lay down landing joint. Set BPV. RD Hilcorp ASR #1 WO Rig. 10.) RU Crane. ND BOPE. NU existing 3-1/8" 5,000# tree. Pull BPV. 11.) Set TWC. Test tubing hanger to 250/5,000 psi. Test tree to 250/5,000 psi. Pull TWC. ND Crane. 12.) Replace IA x OA pressure gauge if removed (7"x9-5/8"). 13.) Turn well over to production. Let us know if you need additional information and if we are allowed to continue operations. Regards, Stan Porhola I Oljcrationr ; 1 ragineer North Shope Asset Team am Hilcorp Alaska, LLC sporholaC@hilcorp.com Office,: (9 07) 7 7/ -81 <51 J Mobile: ('90 ) ;5:31-�t228 Preliminary Investigation Report - September 25, 2015 Recordable Incident Investigation We have initiated a root cause analysis. The team performing the analysis includes the HAK Alaska Safety Manager (Carl Jones), two safety reps from the North Slope asset (Sarra Ghiassi, Kacey Bond), the North Slope Asset Team Leader (John Barnes), the Milne Operations Manager (Bo York), the Milne Field and Plant Foremen (Mark O'Malley and Richard Knox), the owner of Integrated Well Services (Jerry Chitwood), and Greg Lomax (ASRC Industrial Hygienist). Summary Three Integrated Well Services Employees lost consciousness approximately 9:12 am the morning of September 251H 2015 while attempting to bleed pressure off the J-08 workstring by casing annulus. 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 with returns taken off the tubing string to a flowback tank. One 50 bbl seawater pill had been successfully pumped following the nitrogen treatment. Findings 1. Employees encountered unexpected pressure on the backside while beginning to pump the second 50 bbl seawater pill. 2. Employees shutdown pumping operations and began to bleed off the pressure through the choke manifold located in the ASR pit trailer. 3. The timeline constructed shows the following events occurring over a very short period, several minutes: a. One employee entered the pit portion of the trailer and lost consciousness while attempting to open a door to increase ventilation in the room. b. Two additional employees independently entered the pit portion of the trailer in an attempt to recover the first employee. They both were affected, but able to exit the trailer, though each lost consciousness for some period of time. One employee assisted the other in completing exit of the trailer. 4. Response was immediate and effective: a. The employee in the trailer was rescued through a side opening. b. Life saving response onsite was immediate, and continued until replaced by Emergency Response Team. 5. IPs were treated onsite and transported to MPU clinic. All are expected to fully recover. 6. The source of the release, believed to be Nitrogen, was the bottom dump valve on the gas buster in the pit room of the pit trailer. The dump valve was in the open position. Corrective Actions 1. Flowback of any wellbore fluids which reasonably can be expected to include nitrogen will be through hardlines to external flowback tanks. 2. Although the pits are not normally used for flowback, employees will be trained around this operational practice. Other actions under engineering and operational review include: a. Additional training on the capabilities of the two existing air monitors (hydrocarbon and H2S monitors). b. Installation of low oxygen level alarms. c. Engineering review of HVAC system. d. Improved secondary egress of the trailer. Regg, James B (DOA) From: Jones, Jeffery B (DOA) j�trj qJi mq 15 Sent: Saturday, September 26, 2015 9:51 AM To: Regg, James B (DOA) Subject: FW: Procedure for frz. protecting J-08 FYI Jeff B. Jones Petroleum Inspector Alaska Oil & Gas Conservation Commission N. Slope Ofc: 907-659-2714 Mobile: 907-744-4446 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). may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. 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.iones@alaska.gov. From: Jones, Jeffery B (DOA) Sent: Saturday, September 26, 2015 9:50 AM To: 'Mark O'Malley' Subject: RE: Procedure for frz. protecting J-08 Mark, You have approval to freeze protect the well. Thanks, Jeff B. Jones Petroleum Inspector Alaska Oil & Gas Conservation Commission N. Slope Ofc: 907-659-2714 Mobile: 907-744-4446 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 Jones@alaska.gov. From: Mark O'Malley [mailto:momalley(a)hilcorp.com] Sent: Saturday, September 26, 2015 7:59 AM To: Jones, Jeffery B (DOA) Subject: Procedure for frz. protecting J-08 Jeff, Here you go. Our investigation team is on its way to the ASR rig. I would like to attempt this procedure after we complete our walk around. Thanks, Mark O'Malley MPU Field/Wells Foreman MOMalley@hilcorp 907-670-3330 Office Alternate: Rob Handy HI-filcorp Alaska, LLC A Company Built on Energy d/�a� TO: Jim Regg ��Jei P. I. Supervisor FROM: Jeff Jones Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: September 26, 2015 SUBJECT: Hilcorp ASR Rig #1 Mud Tank Incident Well J -08A (PTD 1991770) Milne Point Field / MPU September 25, 2015: 1 traveled to Hilcorp's MPU well J -08A where an incident had occurred that injured 3 ASR Rig #1 personnel. On my arrival, I met with Hilcorp Wellsite Supervisor Wayne Biart and Hilcorp Production Supervisor Mark O' Malley. They relayed to me the following information regarding the incident that occurred this morning at approximately 9:00 am while ASR Rig #1 personnel were performing a clean out operation on Hilcorp's Milne Point Field well J -08A. The 3 injured ASR Rig #1 employees have been medically evaluated and all 3 have been released to go back to work. Hilcorp's Robert (Bo) York notified OSHA of the incident and I was told the OSHA representative was on his way to the slope. Mr. Biart was unable to provide a written N2 cleanout procedure and indicated he didn't have one. Halliburton had pumped the N2 and they were released and left the location at approx. 2:00 pm. Mr. Biart indicated that the decision to use N2 for the clean out operation was made by Hilcorp engineering staff in Anchorage, specifically Stan Porhola. The copy of the Sundry on location for workover operations matched the AOGCC approved Sundry on file and made no mention of using N2 for cleanout. Seawater was the only fluid mentioned in the approved Sundry. When questioned about the discrepancy, Mr. Biart indicated that using N2 was standard operating procedure. The sequence of events, as relayed to me by Wayne Biart (Hilcorp Wellsite Supervisor) follows: J--C,bA Halliburton pumped the N2 to displace well MPU J --G8 and they made the volume calculations. No other operations were being performed on MPF J pad at the time. They pumped 207 BBLS and got 227 BBLS return to an open top tank positioned behind the mud tank trailer, not the pit tank trailer. A small venturi mix tee set-up was used to blend N2 with 8.5 PPG seawater and pumped down the tubing and back up the IA and routed through the choke manifold using the hydraulic superchoke to the outside open top tank with a gas buster apparatus on top. Mr. Biart indicated that it was a textbook N2 cleanout operation with no problems encountered. After the clean out procedure, they attempted to pump 50 BBLS of 8.5 PPG seawater down the IA and with 4 BBLS away, the IA pressured up to 2015-0925_Investigate_MPU_J-08A_HAK_ASR 1 _j j.docx 1 of 2 1100 PSI and when they attempted to bleed off this pressure, it would only bleed off very slowly. Mr. Biart and ASR Rig #1 Supervisor Dusty Schultz were discussing this issue in his office and Mr. Schultz went back out to the rig to troubleshoot the problem. Mr. Biart followed him out to the rig a few minutes later. When Mr. Biart got to the rig one of the rig operators (John) was helping the other -- operator (Mike) out of the mud tank trailer and told Mr. Biart that Mr. Schultz was down inside the mud tank trailer. Mr. Shultz was removed from the mud tank trailer and once revived, he went to the choke manifold room to check valve alignment and then secured the well by installing the TIW floor valve and closing the annular and the manual choke & kill valves on the BOPE stack. Mr. Biart then initiated evacuation procedures and moved the 3 injured men to a fresh air environment. No gas alarms were activated. Emergency response personnel were on site in approx. 10 minutes rendering medical assistance and removed the 3 injured men to the medical facility in the main MPU camp. Results of atmospheric sam Ip ing done in the mud tank trailer by emergency response personnel were negative or inconclusive. A field wide safety stand down was initiated and later limited to a stand down of ASR Rig #1 activity. A Hilcorp investigation team is on the way up to the slope today to conduct an incident investigation and Hilcorp/ASR #1 employee interviews. The alarm system data is being downloaded for analysis. The fluid in bottom of the mud tank trailer is being analyzed. Mr. Biart indicated that some sprayed insulation had been applied to the mud tank trailer recently and that is being checked as a possible contamination source. Observations: Although Mr. Biart claimed it would be impossible to introduce N2 into the mud tank trailer during this cleanout operation, in my opinion, his statement has no basis in fact. Leaking and/or improperly aligned choke manifold valves or wind direction in relation to equipment positioning could definitely have introduced N2 into the mud tank trailer. I documented the choke manifold and BOPE stack valve positions on arrival, but Mr. Biart indicated their positions may have been changed by ASR rig #1 personnel to secure the well after the incident, prior to my arrival. There are also 2 generator exhaust pipes exiting the mud tank trailer in close proximity to the fresh air intake fan duct. The wind direction yesterday appeared to be such that N2 or carbon monoxide could possibly have been introduced into the trailer via the air intake fan duct. It should also be noted that the area ambient temperature had dropped below freezing and the outside equipment used for the clean out operation was not insulated or heat traced. Attachments: Photos & CMV alignment schematic (5) Confidential 2015-0925_lnvestigate_MPU_J-08A_HAK_A SRI _i j. docx 2 of 2 y 719 �'WA m Asci Pressure Transmitter Manual Choke Keverse nne oaCK TO Nns une From Choke Line INA 0 End Capped with Needle Valve I B I C.wS t tD To Gas Buster K ISP 'EF-- c N�"If� Ami ■ Ll 1W ' Olt' 1t'•'r ` 0 R�' &I �1P�t J -0eA- Reqq, James B (DOA) From: Regg, James B (DOA) �el � q(zs1 ,S Sent: Friday, September 25, 2015 11:24 AM To: Foerster, Catherine P (DOA); Seamount, Dan T (DOA) Cc: DOA AOGCC Prudhoe Bay; Schwartz, Guy L (DOA) Subject: Incident at Hilcorp ASR 1 Rig this morning Received a call at 1018am this morning from Dave Wilkins (Hilcorp; 777-8345) reporting an incident at the ASR1 rig working at MPU with the following info: - 3 men down in the rig's enclosed mud pits trailer "overcome by something" - Well is MPU SB J -08A (PTD 1991170); sundry approval (315-527)to replace failed ESP - Doing a well cleanout with Nitrogen at the time of this incident; Mr. Wilkins stated they were "supposed to be flowing back to outside tanks" - 3 men were evacuated to the MPU Camp and are conscious - Shut in annular preventer and installed TIW valve in tubing; 429psi well pressure slowly bleeding off to formation - No gas alarms were triggered; no methane or H2S sensed in atmosphere - Rig is on safety stand -down; Hilcorp is investigating - State OSH is being notified by Hilcorp Other info: - Initial BOPE test done 9/23/15; good test but waiting for report; not witnessed by AOGCC; incident not related to BOPE - Guy checked and sundry work procedure; it does not include using nitrogen for the well cleanout - Sending an Inspector to gather some information (condition of men; how was flowback lined up?; decision to use nitrogen instead of seawater; coil tubing unit being used?) Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. if you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or lim.re��@alaska.gov. STATE OF ALASKA ALAbr\A OIL AND GAS CONSERVATION COMMIbjION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Ll Plug Perforations Lj Fracture Stimulate Ll Pull Tubing ✓ Operations shutdown Performed: Suspend ❑ Perforate ❑ 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 ❑ 199.117 3. Address: 6. API Number: 3800 Centerpoint Drive, Suite 1400, Anchorage AK, 99503 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' 13-3/8" 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' 8,430psi 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 1 350 224 Subsequent to operation: 58 0 523 230 225 14. Attachments (required per 20 AAC 25.070..25.071, & 25.293) 15. Well Class after work: Daily Report of Well Operations Q Exploratory❑ Development Q Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil ✓ Gas U WDSPL Printed and Electronic Fracture Stimulation Data ❑ IGSTOR ❑ 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(W-hilcorp.com Printed Name Iq Stan Porhola Title Operations Engineer Signature Z�k� Phone 777-8412 Date 10/19/2015 �C Form 10-404 Revised 512015 FT 2% T 212015 Submit Original Only Hilcorp Alaska, LLC 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(1VD) 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 3.958 5,901' 8,451' TUBING DETAIL 2-7/8" Tubing 6.5 / L-80 / EUE 8rd 1 2.441 1 0 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 5M Wellhead WKM 11" x 11" 5M, WKM w/ 11" x 3.5" tubing hanger/ NSCT 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 Recompletion —1/28/2000 Schrader Bluff Recompletion by Nabors 4ES — 4/19/1997 ESP Replacement by Nabors 3S — 2/11/2007 ESP Change -out by Nordic #3 — 7/5/2015 ESP Change -out by ASR #1-10/3/2015 Revised By: TDF 10/20/2015 1- , , . r"ilx Hilcorp Alaska, LLC Hilcurp Alaska, LLC Weekly Operations Summary Well Name API Number lWell Permit Number IStart Date I 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 40bbls 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 ACP, 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 J-08. Hilcorp Alaska, LLC Hilcorp Alaska, LLC Weekly Operations Summary Well Name JAPI Number JWell Permit Number Start Date End 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 BOPE 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 bbls 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 seawater. Pump 30 bbl hot seawater down tbg 68 bbl heavy oil and water return, 84 bbl lost. 9/22/15 -Tuesday Pending Report. Hilcorp Alaska, LLC IfilcurpAlaska, LLC Weekly Operations Summary Well Name JAPI Number lWell Permit Number 15tart Date End Date MP J-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. ccumulator 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 bbls cleaned up after 20 bbls total pumped 100 bbls. 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 bbls 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 bbls seawater chase w 50 bbls seawater. Total 4.5" clean is 1,800' total slotted liner clean is 634'. 9/25/15 - Friday PJSM. Blow down N2 pressure. 227 bbls recovered. Tubing light blow annulus at 300psi. Open annulus bleed down. Line up to pump 50 bbls down annulus, after 4 bbls 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. 9/27/15 - Sunday 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 bbls 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. 9/28/15 - Monday Operations on standby. 9/29/15 -Tuesday Operations on standby. Hilcorp Alaska, LLC Hilcorp Alaska, LLC. Weekly Operations Summary Well Name JAPI Number =Well Number IStart Date I End Date MP J -08A 50-029-22497-00-00 199-117 9/16/2015 10/3/2015 Daily 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 6.5# tbg, pup, GLM @ 174', jts tbg, pup GLM @ 4,395', 4 jts 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', ECIC @ 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. a.-Nf( A R B I [ 1, WA 1, K I-, R Stan Porhola Operations Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 95503 Anchorage, Re: Milne Point Field, Schrader Bluff Oil Pool, MPU SB J -08A Sundry Number: 315-527 Dear Mr, Porhola: Alaska Oil and G -as Conservation Cornmission; Ar.CLhofncw Alo�kf ".'57*2 407279,1413 Fox 907.271, "Al 00 r' C. klkj 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, /(-4— Cathy, P. "oerster Chair DA'rED this L) day of August, 2015 UMI STATE OF ALASKA OT5 8131 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 9n AA(-. 9r, qRn 1. Type of Request Abandon El Plug Perforations 7 Fracture Stimulate ❑ Pull Tubing 2 Change Approved Plan 71 SuspendEj Perforate 0 Other Stimulate ❑ Alter Casing 11 Fill Clean-out 21 Plug for Redrill ❑ Perforate New Pool 0 Repair Well Re-enter susp well 1:1 Other: ESP Change -out 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number. Hilcorp Alaska, LLC Exploratory ❑ Development - Stratigraphic ❑ Service 71 199-117 , 3. Address: 6. API Number. 3800 Genterpoint 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 477.05 Will planned perforations require a spacing exception? Yes F-1 No Mr 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 MID (ft), Total Depth TVD (ft): Effective Depth MID (ft) Effective Depth TVD (it): Plugs (measured): Junk (measured): 8,495 4,107 8,495 4,107 N/A N/A Casing Length Size MO TVD Burst Collapse Structural Conductor 112' 13-3/8" 112' 112' 3,730psi 11130psi Surface 2,516' 9-5/8" 2,516' 2,476' 5,750psi 3,090psi Production 4.866' 1 7" 1 4,866' 3,850' 7,240psi 5,410psi Liner 3,766' 4-1/2" 1 8,495' 4,107' 8,430psi 7,500psi Perforation Depth MID (it): Perforation Depth TVD (it): -7 Tubing Size; Grade: Tubing MID (ft): See Attached Schematic I See Attached Schematic 2-7/8" 6.5# L-80 t EUE 8rd 4,687 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): ZXP Liner Top Packer and N/A 1 4,714 MID / 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 Lj 14. Estimated Date for 15. Well Status after proposed work. Commencing Operations: 9/15/2015 OIL VVINJ 11 WDSPL ❑ Suspended ❑ GAS ❑ WAG 11 GSTOR ❑ SPLUG El 16- Verbal Approval: Date: N/A Commission Representative: N/A GINJ 0 Op Shutdown E] Abandoned 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Porhola Email sporhola hilcor corn Printed Name Stan Porhola Title Operations Engineer Signature Phone 777-8412 Date 8/2612015 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number'. Plug Integrity BOP Test r Mechanical Integrity Test Location Clearance Other: Spacing Exception Required? Yes No 601 Subsequent Form Required: APPROVED BY Approved by:��/' COMMISSIONER THE COMMISSION Date: ' r 14Z V/ �/',Itj ii -a Submit Form and P & Form 10-403 Rewsed 512015 f, L,,alld for 12 months from the date of approval. Attachments in Duplicate 0 RI1 `1 �11" A Ilileorp Alaska, I..h 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`'' , 2015 Reg. Approval Req'd7 Yes Regulatory Contact: Tom Fouts First Call Engineer: Stan Porhola Rig: Date Reg. Approval Rec'vd: Permit to Drill Number: ASR 41 199-117 (907) 777-8412 (0) W(907) 331-8228 (M) Second Call Engineer: IPaulChan (907) 777-8333 (0) (907) 444-2.881 (M) AFE Number: Current Bottom Hole Pressure: Maximum Expected BHP: Max. Allowable Surf Pressure: Brief Well Summary: 1,717 psi @ 4,000' TVD 1,717 psi @ 4.000' TVD 177 psi (Last BHP measured 11/11/2013) (No new perfs being added) (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) The Milne Point J -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 U. No subsidence issues are expected in this well. Notes ReRardine 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" ROPE, 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. 1 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 c Conduct erolling test: Test the rams and annular with the Pump continuing tnpump, (monitor the surface equipment for leaks to ensure that the fluid is going down -hole and not leaking anywhere atsurface.) d. Hold a constant pressure on the equipment and monitor the Uuid/pump /ate into the well. Record the pumping rate and pressure. e. Once the BOP ram and annular tests are completed, test the remainder of the systern following the normal test procedure (floor valves, gas detection, etcj 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 omBOP Equipment and list items, pressures and rates. D. Pull hanger tmsurface. (Requires tubing cuts asnecessary to free tubing). CBUtodisplace annulus and tubing with kill weight fluid. 6. Ifarolling test was conducted, remove the old hanger, MUnew hanger ortest plug to the completion tubing, Re -land hanger (or test plug) intubing head. Test 8OPEper standard procedure, 7, Bleed any pressure off tubing and casing. Pull BPV. & K4U|andingjoint(2'7/8"EUE8RDhan8erthreud)andpuUoversirin8we}8ht(prev|ousriolstrioA wei,ght 38kUVVTwith Nordic #3does not include block weight of2]K)nntubing han8ertocon�rm free, 9, POOH. Lay 3-7/8"tubing onthe pipe rack (utilize asworksthng). a. Drift |Dof2'7/8"tubing is7.347" 10, MU 6'1/8" hit and junk baskets. 11. R|Hw/Z-7/O"tubing toliner top packer +c4,714'MD. 12. POOH. Lay down bit and junk baskets. Lay down 7'7/8" tubing, 13. K8U3-3/4"mill and junk baskets. 14. R|H w/2']/8^ workstringtn liner top packer +/-4'714' MD. 15. Cleanout fill inside screens down toPBTD+/8,4SO'MD, a. Min |D is 3.844" at Indicator Subs at 5,768' and 5,787^ MD. b. Drift |Dofliner is3.8]3" 16. Circulate bottoms upx3with 8.Sppg seawater. 17.POOH. Lay down mill and junk baskets. Lay down 2'3/8°wurksthn8. 18. PU new 475 series ESP and R/H with new 2-7/8" 8RD EDE L-80 tubing. 19. Set base ofESP at+/ -4,70O MD(Pump intake around +/-4.68(YK*D). Land tubing hanger. a. Re -run 3/8^control line w/clamps down 0mpump gauge centralizer. b. Re -run heat trace to+/'9,O0O' MD� 20, Lay down landing joint. Set BPV. NQ 8OPE. NU existing 3-1/8^ 5,080# tee. Pull 8PV. 21. Set TVV[.Test tubing hanger toZ5U/5,OOOpsi. Test tree to25O/5'OQ0psi. Pull TW[, 22. RDH||corpASR #1VVDRig. 23. Replace |A x OA pressure gauge if removed (7° x9'S/O''). 24.Turn well over toproduction. Attachments: l. As -built Schematic 2. Proposed Schematic 3. BC]PESchernat|m n Ifilvorp Ala4a, UC Orig. KB Elew 65.2'/ GL Elev.: 35.7' (N22E) To = 8,495' (MD) /TD=4,107(TVD) PBTD = 8,495' (NID) / PHTD = 4,107(TVD) ron3weTin M, Milne Point Unit Well: MPU J -08A 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' 9-5w surface 40 J L-80 Strc. 8.835 0 2,516' 7- intermediate 26 J L-80 Btrc 6,276 0 4,866' 4-1/2" 4-i7/2" Liner Slotted Liner 12,6 / L-80 / 18T 6.2 / L-80 / SLT 3.958 4,729' 5,901' 3.958 5,901' 8,451' TUBING DETAIL 2-7/8" T�g 6.S / L-80 / ELIE 8rd _2,44�__jQL 4,687' JEWELRY DETAIL No Depth Item Cmt w/ 504sx PF "E", 250 sx Class "G" in 12-1/4" Hole_ 178' GLM 2 4,491' GLM 3 4,634' 7/9- XN Nipple — 2,313 ID: 2,205 no-go 4 4,645' Discharge Head 5 4,646' 1 Pump 6 Gas Separator --.4,656! 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/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' Baker HMCV Cement Valve is 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 133/8 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 -1/8" CfW SM Wellhead WKM 11" x 11" SM, WKM w/ 11' x 3.5" tubing hanger/ NSC threads top and bottom and 3" CIW H PBV Profile API: 50-029-22497-01-00 Sidetracked & Completed by Nabors 22E - 12/29/1999 Recompletion — 1/28/2000 Schrader Bluff Recompletion by Nabors 4ES — 4/19/1997 ESP Replacement by Nabors 3S — 2/11/2007 Revised By: STP 8/19/2015 Ong. KB Elev.: 65.2/ GL Elev.: 35.7 (N22E) TD= 8,495' (NU) TD = 4,1070 W) P8Tl) = 8,495' (NII) PBTD = 4,107'(TVD) Milne Point Unit Well: MPU J -08A LR-St—C*-1wRWP—d--2A5,L) 1-5 PTD: 199-117 Size Type Wt/ Grade/ Conn ID Top 8trn 13-3/8" Conductor 54.5 / L-80 / N/A 12.615 0 112' 9-5/81' Surface 40 J L -80J 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 / I BT 3,958 4,729! 5,901' —9 10 Slotted Liner 6.2 / L-80 / SLT _3.958 _I 5,901! _$451'_j TUBING DETAIL Tubing _j 6.5 / L-80 / CUE 8rd 1 2.441 1 0 _t_j4,687'_j JEWELRY DETAIL No Depth Item 1 1178' GLM 2 :t4,491' GLM 3 t4,634' 2-718" XN Nipple- 2313ID: 2.205no-go 4 ±4,645' Discharge Head 5 t4,646' Pump 6 t4,656' Gas Separator 7 ±4,661- — Upper Tandern Seal Se-c t—,oT 8 ±4,668, Lower Tandem Seal Section ±4,680' Motor —9 10 14,689' 3/8" External Capillary String 11 ±4,689' PurnprnatL & Centralizer/Downhole Gauge: Bottom @ t4,687' 12 4,714' Baker ZXP Liner Top Packer w/ 6' Tie Back (5,25" ID) 13 14 4,729' 5,776' Baker 5' x 7" HMC Liner Hanger (4.375" ID) Baker HMCV Cement Valve is 5,794' Baker CTC 20' PZP ECP 16 8,451' 1 4.5- Baker Drillable Pack -off Bushing_ 17 8,495' Baker Drillable Guide Shoe WELL INCLINATION DETAIL KOP @ 1,500' MaxHole Angle_Horizontal OPEN HOLE/ CEMENT DETAIL 13-3/8"" Cmt /250sxofArcticseti in 24" Hole 9-5/81, Cmt wl 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" Clw SM -d Wellhead � W V KM 11" x 11' 5M, WKM wl 11" x 3.5" tubing hanger/ NSCT _t threads top and bottom and 3" ClW H PBV Profile t GENERAL WELL INFO API: 50-029-22497-01-00 --Sidetracked & Complete by —Nabors 22E- 12/29/1999 Recompletion - 1/28/2000 Schrader Bluff Recompletion by Nabors 4ES-4/19/1997 ESP Replacement by Nabors 3S - 2/11/2007 Revised By: STP 8/19/2015 ju)d� Milne Point 2015 ASR Rig I Knight Oil Tools BOP Updated 8/19/15 7/8 -5 variables m
