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O 149
Other Order 149 1. ----------------------- Backup documentation 2. December 13, 2018 Letter from AOGCC requesting well investigation updates 3. December 17, 2018 BPXA 5 -day prelim report 4. December 28, 2018 Notice of Public Hearing, email list, bulk mailing list 5. December 31, 2018 AOGCC letter to BPXA requesting information 6. December 31, 2018 Email re: request to reschedule hearing 7. January 8, 2019 BPXA 30 -day report 8. January 10, 2019 Topic list for hearing 9. January 11, 2019 Events summaries 10. January 14, 2019 BPXA request for rescheduling of hearing 11. January 15, 2019 Email to BPXA 12. February 6, 2019 BPXA pre -hearing submission in response to questions received from AOGCC 13. February 7, 2019 Transcript and hearing sign in sheet 14. February 13, 2019 Transcript and hearing sign in sheet 15. February 15, 2019 Email re: follow up questions 16. February 21, 2019 Email re: 3 string P&A's and DS 02-02A status 17. February 26, 2019 BPXA post hearing submissions 18. March 13, 2019 BPXA email re: Points for Clarification 19. March 14, 2019 BPXA Submission of 02-02 well failure investigation rpt 20. March 20, 2019 BPXA request for reconsideration 21. December 13, 2019 BPXA geotechnical review report STATE OF ALA ALASKA OIL AND GAS CON ERV TION COMMISSION 333 West Seventh Avenue Anchorage, Alaska 99501 Re: Mechanical Integrity of Prudhoe Bay ) Other Order 149 Wells Docket Number: OTH-18-064 Prudhoe Bay Field February 28, 2019 IT APPEARING THAT: In the last 18 months, BP Exploration Alaska. Inc. (BPXA), operator of the Prudhoe Bay Field, experienced sudden well head rise on two Drillsite 2 wells — DS 02-03B (April 2017) and DS02- 02A (December 2018). Each incident resulted in permanent damage to surface casing and the flow tree assembly when the wellhead rose abruptly and impacted the well house. In a third incident on March 30, 2017, an injection well, 1,543, failed during a mechanical integrity test resulting in permanent damage to the casing strings. In all three incidents well bore fluids were released at the surface. Because these three events raised concerns about the mechanical integrity of wells at Prudhoe Bay Field relating to permafrost subsidence, on its own motion the Alaska Oil and Gas Conservation Commission (AOGCC) noticed a public hearing for February 7, 2019 at 10:00 a.m. Due to unforeseen circumstances, AOGCC did not have a quorum of commissioners to conduct the hearing and it was continued until February 13, 2019 at 10:00 a.m. At the February 13, 2019 hearing, BPXA presented evidence regarding the failures and how it intended to proceed in order to assure there are no additional failures. In advance of the hearing, guidance was provided to BPXA in the form of questions and specific topics AOGCC wanted BPXA to address. BPXA answered the questions posed before the hearing. During BPXA's presentation, additional questions arose. As a result, at the close of the hearing, the record was left open until February 26, 2019 to allow BPXA to provide the information requested. BPXA Provided the information on February 26, 2019. FACTUAL BACKGROUND: 1. BPXA discussed the findings of the investigation of the well integrity failure of injection well L5-13, a 2 -casing -string well that failed during a routine, scheduled mechanical integrity test (pressure test on the tubing -casing annulus). Analysis by a forensic metallurgy company was summarized in BPXA's February 6, 2019 pre -hearing response to AOGCC. That study led BPXA to a conclusion that L5-13 likely failed as a result of annular ice plugs which deformed the inner casing and the surface casing rather than as a result of permafrost subsidence. Other Order 149 February 28, 2019 Page 2 of 5 2. The L5-13 metallurgical examination report leaves several unanswered questions with implications for other Prudhoe Bay Field injectors. 3. DS 02-03B failed April 14, 2017 causing a sudden rise of the wellhead which impacted the roof of the well house resulting in leaks in the production tree. Well 02-03B was flowing at the time of failure. 4. In its investigation of the Prudhoe Bay 02-03B well failure, BPXA produced a model for Prudhoe Bay Field 3 -casing -string wells to describe a scenario where the subsidence of 20" casing into the permafrost could produce compressive loading into the inner strings of pipe. 5. BPXA provided AOGCC a summary report of its investigation dated June 14, 2017 noting that Well 02-0313's sudden wellhead rise was attributed to permafrost subsidence loading effects on the surface casing string. BPXA further noted that this type of failure at Prudhoe Bay is limited to wells with a 3 -casing -string design with the base of the surface casing set within the permafrost zone. BPXA relied on inquiries, well history research, physical and digital evidence, interviews with subject matter experts, and modeling to investigate potential causal and contributory factors for DS 02-0313's failure. 6. BPXA identified 23 3 -casing -string design wells out of approximately 1700 wells at Prudhoe Bay, and made 8 risk-based recommendations to address the DS 02-03B investigation findings. 7. AOGCC ordered a North -Slope -wide assessment of all wells and found no other wells with similar 3 -string casing design. 8. On December 6, 2018, DS 02-02A suffered the same failure as DS 02-0313: a sudden rise of the wellhead which resulted in the loss of primary containment in the production tree. At the time, DS 02-02A had been shut in for over twelve years. DS 02-02A was one of the listed 3 - casing -string -design wells to be suspended and risk -assessed to determine the appropriate response in light of each well's integrity. FINDINGS FROM THE HEARING: 1. In response to the DS 02-02A failure the AOGCC instructed BPXA to begin the process of abandonment for 14 3 -casing -string wells with shoes set in the permafrost. Applications for Sundry Approval to abandon 13 of the 14 3 -casing string wells identified as similar to DS 02- 02A were granted from January 9, 2019 to February 8, 2019. 2. During the drilling of the original Prudhoe Bay wells conductors were surveyed primarily in the X -Y plane but highly accurate wellhead elevations surveys were not conducted, as subsidence was not considered a concern. In response to awareness of the risks posed by subsidence, in 2011 BPXA initiated an annual wellhead elevation survey for all BPXA- operated wells. 3. Wells identified by BPXA with significant vertical displacement may require additional intervention measurements to determine if the well is undergoing deformation to the point where well integrity could be at risk. 4. BPXA believes the permafrost soil types and ice contents are so highly irregular and localized that broad application of subsidence models may provide limited guidance. BPXA is engaged in ongoing studies to determine permafrost thaw behavior on its existing pads. BPXA also testified that it plans to undertake an independent geotechnical study for Prudhoe Bay Drillsite Other Order 149 February 28, 2019 Page 3 of 5 2 to gain additional understanding of the permafrost loading across casing strings. That study has not yet begun. CONCLUSIONS: 1. The two failures of the 3 -casing string design demonstrate the inner strings of casing could be displaced into compression and result in the 20" casing being loaded in tension to the point where the 20" casing fails. The remaining intact strings of tubing and casing would have enough stored energy from the compression that when the surface casing fails, the sudden release of stored energy would displace the wellhead and flow tree upward with significant force into the ceiling of the wellhouse. If the tubing or annuli are in communication with the Prudhoe Bay reservoir, the result could be an uncontrolled release of produced fluids at the surface. 2. For wells with 2 -casing -string designs in the Prudhoe Bay Field, BPXA does not currently have evidence to suggest that the permafrost subsidence loading and resulting displacement of the surface casings will impart enough unidentified loads on the surface casing to result in sudden catastrophic failure. Of greater significance, BPXA also has no evidence that permafrost subsidence will not result in sudden catastrophic failure. Given the lack of evidence, BPXA's current well integrity management methods may not be sufficient to identify 2 -casing - string wells that develop subsidence risk. 3. For the failed well DS 02-03B, the BPXA model for loads imparted by the downward movement of surface casing shows these loads to be in the margin of error for the surface casing tensile failure and resulting upward wellhead movement observed in that well. However, BPXA acknowledges that untested hypotheses and unevaluated potential impacts are the bases for the assumptions used to formulate its conclusions about the cause of failure for the 3 -casing -string wells and to prioritize well actions to prevent recurrence of permafrost subsidence events. Areas of uncertainty include the implications of surface casing placement relative to the depth of permafrost, the comparison of subsidence loads on the 20" surface casing versus that on the 18-5/8" casing, and the likely importance of the high degree of variability in rock properties of the geologic strata occurring in the permafrost zone. These unquantified impacts and their resultant assumptions lend substantial uncertainty to BPXA's 3 -casing -string model. 4. The inadequacy of BPXA's model is demonstrated by BPXA's model -based assessment that shut in wells are less likely to fail followed by the failure of DS 02-02A, which had been shut in for over 12 years when it failed. 5. BPXA's understanding of the DS 02-02A surface casing failure and 5-1/2" tubing connection failure is incomplete. This problem is exacerbated by the fact that BPXA's current plans for abandoning well 02-02A with plugs and cement will prevent the opportunity to gather information that may assist in understanding of the failure mechanism for this well. 6. BPXA does not have good engineering records from the original PBU operator to understand the movement or the mechanical strength of the 3 or 4 slip joints placed in the 20" surface casing for the two failed DS2 wells. The purpose for these, as stated in the DS 02-03B Other Order 149 February 28, 2019 Page 4 of 5 investigation summary, was to compensate against buckling for an unknown level of subsidence arising from the thaw bulb around a well. 7. Because quantitative historical subsidence measurements of Prudhoe Bay wells are only known from 2011 on, early subsidence could have been significant (and possibly non-linear with time) and may now have imparted unquantifiable stored energy into the casing strings for Prudhoe Bay wells. 8. BPXA does not have any casing recovery plans to identify and analyze casing deformations within the 20" annuli of any of the current well stock with three -string casing designs that have the surface casing shoes set in the permafrost. NOW, THEREFORE IT IS ORDERED THAT: 1. Rig interventions are required in 2019 to recover production tubing, production casing, outer casing, surface casing, and conductor on at least two of the 3 -casing -string wells with 20" surface casing set in permafrost, one of which must be DS 02-02A. The remaining well or wells will be determined by AOGCC in consultation with BPXA. 2. Sundry approval applications for the rig interventions to decomplete the 3 -string wells must include the specifics of data acquisition and analysis that will be performed. 3. Not later than March 15, 2019 BPXA must provide all reports for the Prudhoe Bay 02-02A failure. 4. BPXA must provide the geotechnical review report upon its completion. 5. Rig interventions will be required on at least two separate wells with 2 -casing -string designs within the Prudhoe Bay Field to understand effects of wellbore surface casing subsidence. These wells will be selected by AOGCC in consultation with BPXA for inclusion in either the 2019 or 2020 P&A schedule. 6. Sundry approval applications for the rig interventions to decomplete the 2 -casing -string wells must include specifics of data acquisition and analysis that will be performed. 7. BPXA must provide all reports for the 2 -casing -string design rig interventions within 3 months of completing those interventions. 8. Previously approved sundries for the 14 wells identified with risk of failure of the surface casing on the 3 -casing -string wells are rescinded. All 14 wells must be secured with tested downhole plugs and kill weight brine to isolate the reservoir. AOGCC must be afforded the opportunity to witness these downhole plugs and reports are required upon completion of the plugging operations on each well. Additional abandonment operations will be considered after reviewing the above required decompletions of 2- and 3 -casing -string design wells. Cathl. Foerster Commissioner Daniel T. Seamount, Jr. Commissioner Other Order 149 February 28, 2019 Page 5 of 5 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 Carlisle, Samantha J (DOA) From: Carlisle, Samantha 1 (DOA) Sent: Thursday, February 28, 2019 2:23 PM To: 'AOGCC_Public_Notices@list.state.ak.us' Subject: Other Order 149 Attachments: other149.pdf Mechanical Integrity of Prudhoe Bay Wells Samantha Carlisle Executive Secretary III Alaska Oil and Gas Conservation Commission 333 West 71h Avenue Anchorage, AK 99501 (907) 793-1223 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska aid 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 Sanantha Carlisle at (907) 793-1223 or Samantha.Carhsleti alaska.eov. Bernie Karl Gordon Severson Penny Vadla K&K Recycling Inc. P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue Anchorage, Alaska 99501 Re: Mechanical Integrity of Prudhoe Bay ) Other Order 149 Amended Wells ) Docket Number: OTH-18-064 Prudhoe Bay Field April 1, 2019 BP Exploration (Alaska), Inc. (BPXA) moved for reconsideration of Other Order 149, entered February 28, 2019. BPXA seeks reconsideration only of paragraph 1 of the actions BPXA is ordered to undertake in Other Order 149. Specifically, BPXA wants paragraph 1 rewritten to require only recovery of "sections" of the tubing and casings "to the extent reasonably possible." The justification offered by BPXA for its request is a claim that the actions ordered in paragraph 1 "may not be technically feasible and presents unnecessary risk without providing additional/useful information beyond that to be obtained via the work proposed in the above amendment." AOGCC rejects the language proposed by BPXA. However, the request for reconsideration is granted to modify the language of paragraph 1 to clarify the intent of paragraph 1: that the amount of "production tubing, production casing, outer casing, surface casing, and conductor" to be recovered will be determined on a well by well basis during the sundry approval process and as appropriate information becomes available during the well's decompletion. That modification is set forth below. IT APPEARING THAT: In the last 18 months, BPXA, operator of the Prudhoe Bay Field, experienced sudden well head rise on two Drillsite 2 wells — DS 02-03B (April 2017) and DS02-02A (December 2018). Each incident resulted in permanent damage to surface casing and the flow tree assembly when the wellhead rose abruptly and impacted the well house. In a third incident on March 30, 2017, an injection well, L5-13, failed during a mechanical integrity test resulting in permanent damage to the casing strings. In all three incidents well bore fluids were released at the surface. Because these three events raised concerns about the mechanical integrity of wells at Prudhoe Bay Field relating to permafrost subsidence, on its own motion the Alaska Oil and Gas Conservation Commission (AOGCC) noticed a public hearing for February 7, 2019 at 10:00 a.m. Due to unforeseen circumstances, AOGCC did not have a quorum of commissioners to conduct the hearing and it was continued until February 13, 2019 at 10:00 a.m. At the February 13, 2019 hearing, BPXA presented evidence regarding the failures and how it intended to proceed in order to assure there are no additional failures. In advance of the hearing, Other Order 149 Amended April 1, 2019 Page 2 of 5 guidance was provided to BPXA in the form of questions and specific topics AOGCC wanted BPXA to address. BPXA answered the questions posed before the hearing. During BPXA's presentation, additional questions arose. As a result, at the close of the hearing, the record was left open until February 26, 2019 to allow BPXA to provide the information requested. BPXA provided the information on February 26, 2019. FACTUAL BACKGROUND: 1. BPXA discussed the findings of the investigation of the well integrity failure of injection well L5-13, a 2 -casing -string well that failed during a routine, scheduled mechanical integrity test (pressure test on the tubing -casing annulus). Analysis by a forensic metallurgy company was summarized in BPXA's February 6, 2019 pre -hearing response to AOGCC. That study led BPXA to a conclusion that L5-13 likely failed as a result of annular ice plugs which deformed the inner casing and the surface casing rather than as a result of permafrost subsidence. 2. The L5-13 metallurgical examination report leaves several unanswered questions with implications for other Prudhoe Bay Field injectors. 3. DS 02-03B failed April 14, 2017 causing a sudden rise of the wellhead which impacted the roof of the well house resulting in leaks in the production tree. Well 02-03B was flowing at the time of failure. 4. In its investigation of the Prudhoe Bay 02-03B well failure, BPXA produced a model for Prudhoe Bay Field 3 -casing -string wells to describe a scenario where the subsidence of 20" casing into the permafrost could produce compressive loading into the inner strings of pipe. 5. BPXA provided AOGCC a summary report of its investigation dated June 14, 2017 noting that Well 02-0313's sudden wellhead rise was attributed to permafrost subsidence loading effects on the surface casing string. BPXA further noted that this type of failure at Prudhoe Bay is limited to wells with a 3 -casing -string design with the base of the surface casing set within the permafrost zone. BPXA relied on inquiries, well history research, physical and digital evidence, interviews with subject matter experts, and modeling to investigate potential causal and contributory factors for DS 02-0313's failure. 6. BPXA identified 23 3 -casing -string design wells out of approximately 1700 wells at Prudhoe Bay, and made 8 risk-based recommendations to address the DS 02-03B investigation findings. 7. AOGCC ordered a North -Slope -wide assessment of all wells and found no other wells with similar 3 -string casing design. 8. On December 6, 2018, DS 02-02A suffered the same failure as DS 02-0313: a sudden rise of the wellhead which resulted in the loss of primary containment in the production tree. At the time, DS 02-02A had been shut in for over twelve years. DS 02-02A was one of the listed 3 - casing -string -design wells to be suspended and risk -assessed to determine the appropriate response in light of each well's integrity. FINDINGS FROM THE HEARING: 1. In response to the DS 02-02A failure the AOGCC instructed BPXA to begin the process of abandonment for 14 3 -casing -string wells with shoes set in the permafrost. Applications for Other Order 149 Amended April 1, 2019 Page 3 of 5 Sundry Approval to abandon 13 of the 14 3 -casing string wells identified as similar to DS 02- 02A were granted from January 9, 2019 to February 8, 2019. 2. During the drilling of the original Prudhoe Bay wells conductors were surveyed primarily in the X -Y plane but highly accurate wellhead elevations surveys were not conducted, as subsidence was not considered a concern. In response to awareness of the risks posed by subsidence, in 2011 BPXA initiated an annual wellhead elevation survey for all BPXA- operated wells. 3. Wells identified by BPXA with significant vertical displacement may require additional intervention measurements to determine if the well is undergoing deformation to the point where well integrity could be at risk. 4. BPXA believes the permafrost soil types and ice contents are so highly irregular and localized that broad application of subsidence models may provide limited guidance. BPXA is engaged in ongoing studies to determine permafrost thaw behavior on its existing pads. BPXA also testified that it plans to undertake an independent geotechnical study for Prudhoe Bay Drillsite 2 to gain additional understanding of the permafrost loading across casing strings. That study has not yet begun. CONCLUSIONS: 1. The two failures of the 3 -casing string design demonstrate the inner strings of casing could be displaced into compression and result in the 20" casing being loaded in tension to the point where the 20" casing fails. The remaining intact strings of tubing and casing would have enough stored energy from the compression that when the surface casing fails, the sudden release of stored energy would displace the wellhead and flow tree upward with significant force into the ceiling of the wellhouse. If the tubing or annuli are in communication with the Prudhoe Bay reservoir, the result could be an uncontrolled release of produced fluids at the surface. 2. For wells with 2 -casing -string designs in the Prudhoe Bay Field, BPXA does not currently have evidence to suggest that the permafrost subsidence loading and resulting displacement of the surface casings will impart enough unidentified loads on the surface casing to result in sudden catastrophic failure. Of greater significance, BPXA also has no evidence that permafrost subsidence will not result in sudden catastrophic failure. Given the lack of evidence, BPXA's current well integrity management methods may not be sufficient to identify 2 -casing - string wells that develop subsidence risk. 3. For the failed well DS 02-03B, the BPXA model for loads imparted by the downward movement of surface casing shows these loads to be in the margin of error for the surface casing tensile failure and resulting upward wellhead movement observed in that well. However, BPXA acknowledges that untested hypotheses and unevaluated potential impacts are the bases for the assumptions used to formulate its conclusions about the cause of failure for the 3 -casing -string wells and to prioritize well actions to prevent recurrence of permafrost subsidence events. Areas of uncertainty include the implications of surface casing placement relative to the depth of permafrost, the comparison of subsidence loads on the 20" surface casing versus that on the 18-5/8" casing, and the likely importance of the high degree of Other Order 149 Amended April 1, 2019 Page 4 of 5 variability in rock properties of the geologic strata occurring in the permafrost zone. These unquantified impacts and their resultant assumptions lend substantial uncertainty to BPXA's 3 -casing -string model. 4. The inadequacy of BPXA's model is demonstrated by BPXA's model -based assessment that shut in wells are less likely to fail followed by the failure of DS 02-02A, which had been shut in for over 12 years when it failed. 5. BPXA's understanding of the DS 02-02A surface casing failure and 5-1/2" tubing connection failure is incomplete. This problem is exacerbated by the fact that BPXA's current plans for abandoning well 02-02A with plugs and cement will prevent the opportunity to gather information that may assist in understanding of the failure mechanism for this well. 6. BPXA does not have good engineering records from the original PBU operator to understand the movement or the mechanical strength of the 3 or 4 slip joints placed in the 20" surface casing for the two failed DS2 wells. The purpose for these, as stated in the DS 02-03B investigation summary, was to compensate against buckling for an unknown level of subsidence arising from the thaw bulb around a well. 7. Because quantitative historical subsidence measurements of Prudhoe Bay wells are only known from 2011 on, early subsidence could have been significant (and possibly non-linear with time) and may now have imparted unquantifiable stored energy into the casing strings for Prudhoe Bay wells. 8. BPXA does not have any casing recovery plans to identify and analyze casing deformations within the 20" annuli of any of the current well stock with three -string casing designs that have the surface casing shoes set in the permafrost. NOW, THEREFORE IT IS ORDERED THAT: 1. Rig interventions are required in 2019 to recover production tubing, production casing, outer casing, surface casing, and conductor, to the extent approved by AOGCC via Sundry 10-403, on at least two of the 3 -casing -string wells with 20" surface casing set in permafrost, one of which must be DS 02-02A. The remaining well or wells will be determined by AOGCC in consultation with BPXA. 2. Sundry approval applications for the rig interventions to decomplete the 3 -string wells must include the specifics of data acquisition and analysis that will be performed. 3. Not later than March 15, 2019 BPXA must provide all reports for the Prudhoe Bay 02-02A failure. 4. BPXA must provide the geotechnical review report upon its completion. 5. Rig interventions will be required on at least two separate wells with 2 -casing -string designs within the Prudhoe Bay Field to understand effects of wellbore surface casing subsidence. These wells will be selected by AOGCC in consultation with BPXA for inclusion in either the 2019 or 2020 P&A schedule. 6. Sundry approval applications for the rig interventions to decomplete the 2 -casing -string wells must include specifics of data acquisition and analysis that will be performed. 7. BPXA must provide all reports for the 2 -casing -string design rig interventions within 3 months of completing those interventions. Other Order 149 Amended April 1, 2019 Page 5 of 5 8. Previously approved sundries for the 14 wells identified with risk of failure of the surface casing on the 3 -casing -string wells are rescinded. All 14 wells must be secured with tested downhole plugs and kill weight brine to isolate the reservoir. AOGCC must be afforded the opportunity to witness these downhole plugs and reports are required upon completion of the plugging operations on each well. Additional abandonment operations will be considered after reviewing the above required decompletions of 2- and 3 -casing -string design wells. DONE at Anchorage, Alaska and dated April 1, 2019. ssie L. Chmielowski ommissioner Qe� Daniel T. Seamcii$t, Jr. Commissioner 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 Carlisle, Samantha J (DOA) From: Carlisle, Samantha J (DOA) Sent: Monday, April 1, 2019 10:54 AM To: 'AOGCC_Public_Notices@list.state.ak.us' Subject: Other Order 149 amended Attachments: other149 amended.pdf Mechanical Integrity of Prudhoe Bay Wells Samantha Carlisle Cxecutive Secretary III Alaska Oil and Gas Conservation Commission 333 West 711, Avenue Anchorage, AK 99501 (907) 793-1223 CONFIDENTIALITY NOTICE: This e. -mail message, including any attachments, contains information from the Alaska Oiland 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 lain. 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.Cartisle!ii'alHSka.goy. 23 BP Exploration (Alaska) Inc. Ryan Daniel, Well Integrity Engineering Team Leader Post Office Box 196612 Anchorage, Alaska 99519-6612 December 13, 2019 Via Hand Delivery DEC 13 2019 /aOGCC Jeremy Price Commission Chair Alaska Oil and Gas Conservation Commission 333 West 71" Avenue Anchorage, Alaska 99501 )1IR RE: Order Number OIJ4-�B�Y#�mended, dated April 1st 2019 Submission of two reports: A geotechnical review report, and the Interpretation of Well Abandonment Data on Wells DS02-02 & DSO4-01 Dear Chair Price, BP Exploration (Alaska) Inc. (BPXA), as operator on behalf of the Prudhoe Bay Unit (PBI working interest owners, and pursuant to AOGCC Order OTH 18-149 amended, dated April 1st 2019, submit two documents by hand delivery: Report #1: Geotechnical review report by Atkins et al, titled "Prudhoe Bay, AK — Independent geotechnical review of DS02-03 and DS02-02 well incidents, Report #2: Interpretation by BPXA of Well Abandonment Data on Wells DS02-02 & DSO4-01 Sincerely, Ryan Daniel BPXA Wells Integrity Engineering Team Leader 8e � ole ii iF ir+ DEC 13 2019 ATKINS Member of the SUC Lavahn Group Prudhoe Bay, AK — Independent geotechnical review of DS02-03 A and DS02-02 well incidents Technical file Note 1 BP Exploration (Alaska) Ltd F ; i 5r' December 2019 1 ! 1 '» ATKINS SNC•LAVALIN - Technical Note Project: BP XA PBU - Independent geotechnical review of DS02-03 and DS02-02 well incidents, Prudhoe Bay Subject: Technical Note for BP Exploration Alaska Inc (BPXA) Author: WS Atkins Limited Date: 5th December 2019 Project No.: 5187945 Document history Client signoff Client BP Exploration (Alaska) Inc Project BP XA PBU - Independent geotechnical review of DS02-03 and DS02-02 well incidents, Prudhoe Bay Project No. 5187945 Registered Alaskan Reviewed and approval by Torsten Mayrberger (Indepenoz � afr:4 � d Geotechnical Geotechnical Engineer) 5'h December 2019 i �.` •'' • .,tS�+ Engineer /00 A0 4 TH S/ signature /date //: • • t • 0 Torsi ayrtSerg:, t+f CE 14702 i r (�1� 94pj�gSlONa�= 20182272-BPXA-001 12.0 15' December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents —Tehnical Note Rev02 FINAL Page 1 of 26 Purpose Revision description Originated Checked Reviewed Authorised Date Rev 1.0 DRAFT for client David Thushy Paul David 15/11/19 comment Champness / Thusyanthan Nowak Champness Alexandros Loukas Rev 2.0 FINAL for Issue David Thushy Paul David 05/12/19 Champness Thusyanthan Nowak Champness //% L Client signoff Client BP Exploration (Alaska) Inc Project BP XA PBU - Independent geotechnical review of DS02-03 and DS02-02 well incidents, Prudhoe Bay Project No. 5187945 Registered Alaskan Reviewed and approval by Torsten Mayrberger (Indepenoz � afr:4 � d Geotechnical Geotechnical Engineer) 5'h December 2019 i �.` •'' • .,tS�+ Engineer /00 A0 4 TH S/ signature /date //: • • t • 0 Torsi ayrtSerg:, t+f CE 14702 i r (�1� 94pj�gSlONa�= 20182272-BPXA-001 12.0 15' December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents —Tehnical Note Rev02 FINAL Page 1 of 26 '» ATKINS SNC•LAVALIN - Contents Executive Summary 3 1. Introduction 4 2. Incident Reports 5 3. Review historical permafrost studies 6 4. Site Setting & Geology 7 4.1. Location and setting 7 4.2. Geomorphology 7 4.3. Regional Geological Setting 7 4.4. Shallow Localized Geology 8 4.4.1. Gubik Formation 8 4.4.2. Sagavanirktok Formation 8 4.5. DS02 Lithological Profile 8 5. Numerical modelling 10 5.1. Introduction 10 5.2. Analysis Methodology 10 5.2.1. Staged approach 11 5.2.2. Numerical model details 11 5.3. Constitutive model used in numerical analysis 12 5.3.1. Introduction 12 5.3.2. Validation of the PLAXIS constitutive model 13 5.4. Input for numerical analysis 15 5.4.1. Numerical ground model 15 5.4.2. Casing and cement properties 15 5.4.3. Ground temperature and thaw profile 16 5.4.4. Constitutive model parameters 17 5.4.5. Boundary Conditions 18 6. Numerical Results 18 6.1. Permafrost and ice saturation at the final phase 19 6.2. Ground deformations 20 6.3. 20" Casing Forces and Strains 21 6.3.1. Results from Set A — 20" casing as linear elastic 21 6.3.2. Results from Set B —20" casing as elastic fully plastic 22 7. Conclusions 24 8. References 25 20182272-BPXA-001 1 2.01 51" December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents — Tehnical Note Rev02 FINAL Page 2 of 26 '» ATKINS SNC•LAVALIN hr��, m,nsxcr ,uo�o Executive Summary Atkins was commissioned by BP Exploration (Alaska) Ltd (BPXA) to undertake an independent geotechnical study relating to two well failure incidents (DS02-03 in April 2017, and DS02-02 in December 2018) at the Prudhoe Bay Unit (PBU) operations on the Alaskan North Slope. The well failures at DS02-02 and DS02-03 were investigated by BPXA who concluded that the tensile failure of the 20" surface casing was the main contributing factor for the incidents. Failure was attributed to a load imparted by subsurface permafrost thaw subsidence acting on the surface casing resisted by the inner casing strings. The main objective of this study was to verify, from a geotechnical point of view, that the subsurface subsidence of the permafrost formations could lead to a shallow tensile failure of the 20" casing. Atkins utilized a three -phased approach as follows: • A thorough review of available technical information was undertaken. This review included the recent casing failure incident reports prepared by BPXA (BPXA, 2017) (BPXA, 2019), key engineering and field- testing results, related publications on the topic of production wells in permafrost, thaw -induced permafrost subsidence and the mechanical response of frozen and thawing soils. • Derivation of a site-specific lithological profile and associated geotechnical properties. • Numerical modelling to simulate the 3 -string wells of DS02-02 and DS02-03 and evaluate the 20" casing forces and strains. A thermal -hydro -mechanical soil constitutive model in PLAXIS software and simplified lithological profile were utilized in the numerical analysis. Evaluating thaw induced casing strains is a complex and challenging problem with several interacting phenomena. As such, to enable credible verification of the 20" casing forces and strains, a number of assumptions and simplifications were applied including: • Simplified lithological profile • Standardized material properties of casing • Elastic fully plastic stress -strain profile of 20" casing material (as provided by BPXA) • Simplified thaw profile from singular well analysis (Hazen, 2019) The numerical modelling and analysis undertaken in this study of permafrost subsidence, specifically "thaw induced" deformations (soil strain) and the resultant surface casing mechanical strain for three string well designs has verified: • That, if a 20" surface casing tensile failure does occur, it will most likely occur near the well surface where maximum axial tensile strain is predicted by the modelling. • And that, the overall magnitude of the axial forces and strains generated in the 20" surface casing, attributed to 40 years of permafrost thaw induced subsidence loading, is sufficient to lead to tensile failure of the 20" surface casing, based again on the properties used in the modelling. 20182272-BPXA-001 1 2.01 51" December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents — Tehnical Note Rev02 FINAL Page 3 of 26 0 ATKINS SNC-LAVALIN 1. Introduction WS Atkins International Limited (herein Atkins) were approached by BP Exploration (Alaska) Ltd (herein BP) in early 2019 for support with expert geotechnical services under Master Services Agreement and Regional Agreement CW2165609. The support requested related to two well incidents at Drill Site 02 (DS02-02 & DS02-03) at the Prudhoe Bay field located on the North Slope, Alaska. The field is located 400 miles (640 km) north of Fairbanks and 650 miles (1,050 km) north of Anchorage, 250 miles (400 km) north of the Arctic Circle, and 1,200 miles (1,900 km) south of the North Pole (BPXA, 2006). Due to the complex nature of the scope, and to ensure alignment between all stakeholders, a workshop was held over two days from 19th to 20th March 2019 at Embassy Suites in Anchorage, AK, attended by stakeholders from Atkins, BP, ConocoPhillips and their subject matter experts. Upon completion of the workshop, BP commissioned Atkins to undertake the scope of works detailed below. The Atkins scope of work included: 1. Review of permafrost subsidence and associated casing loads: a) Verify modelling and other geotechnical methods of permafrost subsidence mechanismsfrom ground surface to a depth of permafrost of circa 2000 feet (actual top to base permafrost varies by pad/drill site location); b) Verify the casing strain loads that lead to the surface tensile failure of the 20" casing of Drill Site wells 02-03 and 02-02; c) Review historical permafrost studies conducted by ARCO, Exxon, University of Alaska Anchorage College of Engineering, University of Alaska Fairbanks, and others, as available, and the potential impact on subsidence loading, casing strains and well design. 2. Verification of DS02-03 and DS02-02 displacements and damage: a) Verify and describe the possible displacements and damage to the casing/wellhead systems of the two failed wells, b) Verify the differential strain model and casing/soil strain distribution across the permafrost of the failed wells and their particular well design and location. 20182272-BPXA-001 1 2.01 5" December 2019 Atkins I BP Independent geotechncial review of OS02-03 and OS02-02 well incidents - Tehnical Note Rev02 FINAL Page 4 of 26 ATKINS SNC°LAV'ALIN - 2. Incident Reports The two incidents referenced in section 1 were recorded in two separate incident reports by BPXA: DS02-03 (BPXA, 2017) and DS02-02 (BPXA, 2019). Salient points from these reports are as follows: DS02-03 uncontrolled well release 1411 April 2017 DS02-02 uncontrolled well release Th December 2018 Both wells are 3 string design constructed by Atlantic Richfield in 1970 In both cases Xmas tree moved upwards by some 3 feet (0.91 m), contacting the roof of the wellhouse Failure in both cases related to near surface tensile failure of the outer 20" casing Failure was attributed to permafrost thaw subsidence causing 'down -drag' on the surface casing in three string design wells. The failure mechanism observed was different from that of single string wells on Kuparuk field, where compressional buckling of the casing has been recorded. For both incidents Atkins has endeavored to capture the chronology of key events through the wells lifecycle from their original construction in 1970 to observed failures in 2017 and 2018, shown in Figure 2-1 and Figure 2-2. DS02-03 Well Timeline %% reMeO Nlluesser¢ QiY6Pre M�YMn 1'mW[Nn m0ftle.Vack RMwlmm meeO F,oOuidmw,Odn IiWutlion �a rM V}rYFa7 D111 ie-prNuc,nn 11Wuce0n eM uk.earAs laoe-19+e ImermeRn, pN,rMraMnxWl m+9-mfe ahs•'°Iricnem snpemea +910- +9i5- f91i- 1M8- tO+Na+l lawul E006- ]W8X16 f9io-f9n 19n -fma ,.eglRya ww.mm AIINW La4gM WYr C1M9ge MM-Af< 30+41019 A+l E0f9- i° MCO ,re POWUm eM (5e^n w �'� e'iNo 0.emMal >rauu 201. E018 pa 050].0J1- +y0_ 0]RI Al xy0le W16 eemW to ]Of)_u v ro aoOauwn A d� - OanmWr GmNrtlm 0q0 npl°r° µ9 n Sri A1] CMMI3�La wm�oM HM neaktl 66968 � ma prwx wr+or 1w11- ♦ tl'na efewLe 1811- (02. 1�- 1 b�wene OmwBLNO apwfutl �6666� ° ^nueeee p,•_ 0 f llu re awWO Mxe iw+l0 ee moree anrya 9rm.avn enCMUn as rer� a Iye4MwMn m,meE %^9 No] 6I6t" 0u P.a-rov Q0�- 1 W J - waM ME .n'n L Pa ^ rou ola% a« gw gaW d� ap:w Figure 2-1 - DS02-03 Well lifecycle chronology of key events DS02-02 Well Timeline %% reMeO Nlluesser¢ QiY6Pre M�YMn 1'mW[Nn m0ftle.Vack RMwlmm meeO �a rM MamMeli�mro nm+m 1m-1006 laoe-19+e m+9-mfe +910- +9i5- f91i- 1M8- E006- ]W8X16 AIINW La4gM WYr C1M9ge wMn -M�u°eye A+l E0f9- i° MCO ,re POWUm eM (5e^n w �'� ]S9Y1O06 w^WaW 201. E018 pa 050].0J1- +y0_ 0]RI 19Y. xy0le M1a_ eemW to .9ereror wl°'a 5ro12' °rmtul d� ]pi6yune OanmWr N19- erta 0q0 npl°r° µ9 n S�bx CMMI3�La wm�oM HM neaktl pWEenO � ma prwx M1°I4°9ro[i�bn eaWpsea eauy' Euero netryuaw b�wene OmwBLNO apwfutl �M ° ^nueeee M1ea:e MLOOW ee moree anrya 9rm.avn °i Ja wa .a]6ea»;w nowF9 P.a-rov Figure 2-2 - DS02-02 Well lifecycle chronology of key events 20182272-BPXA-001 1 2.01 5" December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents - Tehnical Note Rev02 FINAL Page 5 of 26 ATKI N S SNC-LAV'ALIN n,,,e,ws cu. 3. Review historical permafrost studies In order to verify the geotechnical failure mechanisms for DS02-03 and DS02-02 it was imperative to review the considerable historical work that has already been undertaken. Atkins were provided with a large number of papers and technical studies by BPXA, thought to be relevant. Atkins also reviewed a significant amount of independently sourced material. The literature and data can be classified into three separate groups: • Early pioneering studies — These studies were typically focused on the potential effect of interaction with oil and gas structures and permafrost at the commencement of drilling operations in northern Alaska and the North Slope. Previous investigations regarding production wells in deep permafrost in the 1970s and 1980s focused on the effect of soil layering on casing strains during permafrost thaw around a single well (Smith & Clegg, 1971), (ARCO, 1975) (Goodman, 1975), (Goodman, 1977a), (Goodman, 1977b), (Goodman, 1982), (Mitchell, 1977), (Mitchell, et al., 1983).These studies identified the importance of pore pressure changes and soil stiffness contrast on casing strain and generally concluded that permafrost thaw around production wells in permafrost would not generally cause casing integrity issues. • Modern evolution studies —These studies considered a time period of nominally 15-20 years after start of well production and did not extend to time periods of 40 or more years with additional operational variables such as infill wells, as those considerations were not necessary at the time. (ARCO, 1985), NES, 2008), (Xie, 2009), (Xie & Matthews, 2011), (ExxonMobil, 2013), (C-FER, 2014). • BPXA literature for DS02 — These were site-specific documents and data prepared by BPXA, including operational histories, well -schematics and downhole gamma ray logs. The literature review period informed Atkins thought process, particularly in terms of the continuous radial heat transfer from wellbores to the surrounding frozen soils, leading to many design and operational challenges for developing and producing from an oil well in the Arctic region. Any production and injection well operations in the Arctic region may disturb the original thermal equilibrium of the permafrost. Well induced permafrost thaw subsidence is a function of slow thawing of near well bore permafrost with time and occurs mainly because of four different (Suryawanshi, 2016) but interrelated mechanisms which include: • Phase change contraction - Occurs when excess ice melts as melting decreases the resulting fluid some 9% by volume. • Thaw consolidation accompanied by fluid expulsion, (Consolidation with Fluid Flow) - Tends to be a near surface phenomenon when pressures exceeding hydrostatic are generated during thaw causing fluid flow out of the thawed zone with resulting soil compaction • Pore pressure reduction in thawed soils - Considered to be the major mechanism for thaw subsidence in deeper permafrost. In normally consolidated permafrost soils phase change contraction with the thaw of pore ice is accompanied by a decrease in pore pressure. • Stiffness reduction in the soils surrounding the well - Associated with a decrease in the mechanical properties of the soil with thaw. The soil layer is softer and can deform with loss of support provided by the pore ice. 20182272-BPXA-001 1 2.0 16" December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents - Tehnical Note Rev02 FINAL Page 6 of 26 +0 ATKIN5 SNC•LAVALIN 4. Site Setting & Geology 4.1. Location and setting The Prudhoe Bay Unit (PBU) is some 232 square miles (600 square kilometers) in plan area and contains 42 drill sites/pads with over 2500 wells (Approx 1800 are active with 1200 producers and 600 injectors) (Emerson, 2019). The focus of this report is on DS02 site and wells DS02-02 and DS02-03, shown in Figure 4-1. DS02 is located east of center in the field approximately 2.5 miles (4km) south of the Prudhoe Bay body of water and approximately 6.2 miles (10km) east of the Sag River. Figure 4-1 - Drill Site DS02. OS -02-02 and DS02-03 are shown in red to the right of the image DS02 site is approximately 0.6 miles (1km) in length and 1 mile (1.7km) wide with three distinct well rows. DS02- 02 and DS02-03 wells are in the eastern well row which consists of 16 wells of varying ages. The ground level at DS02 has been modified by the construction of the pad but the area is generally on flat ground. The surrounding elevation typically ranges from ranges from 17 - 38ft (5.2-11.6m) above mean lower low water (MLLW). 4.2. Geomorphology Prudhoe Bay, including DS02, is located within an area classified as Arctic Coastal Plain. The Arctic Coastal Plain is very flat in topography and the geomorphic features are characterized by more cyclic behaviour. For example, geomorphic evidence of the thaw lake cycle is ubiquitous with remnant lake basins, filled basins and draining basins clearly visible on the terrain of the coastal plain. The surface is characterized by polygonal features, low shrubby vegetation and an abundance of standing water including thousands of lakes formed from the thawing of ground ice (Hall, 1979). The DS02 site is underlain by approximately 1970ft (600m) of permafrost. The temperature of permafrost at Prudhoe Bay is colder than elsewhere on the coastal plain and varies between -9°C at 50m depth and about 0°C at around 1970ft (600m) depth (Rawlinson, 1983). Permafrost is a ground (soil or rock) in which a temperature below 0°C has existed for two or more years (Van Everdingen, 1998). The Prudhoe Bay area including DS02 sits within a region classified as a continuous -permafrost zone. 4.3. Regional Geological Setting The Prudhoe Bay Field is located in the North Slope geologic province, which is part of a continental microplate The geological history of this region is very complex, including a development of a south -facing passive continental margin from Devonian to Triassic, a northern rifted margin from Jurassic to Early Cretaceous, and a southern orogenic margin (the Brooks Range) and an associated foreland basin (North Slope) with fold -and thrust belts from Jurassic to Recent (Bird, 1999). 20182272-BPXA-001 1 2.01 5" December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents - Tehnical Note Rev02 FINAL Page 7 of 26 0 ATKINS SNC•LAVALIN <. 4.4. Shallow Localized Geology Since permafrost is only expected in the first kilometer below ground surface in the Prudhoe Bay area, the soil model for assessing the thaw subsidence focuses only in the shallow geology. The Coastal Plain is a surface primarily of deposition. The surface sediments of unconsolidated silts and sands with some clays and gravels comprise the primarily marine Gubik Formation of Pleistocene age (Black, 1969). This overlies the Tertiary Sagavanirktok Formation which extends down to a depth of around 6000ft (1800m) below ground level (bgl). 4.4.1. Gubik Formation Gubik Formation strata are present on the coastal plain throughout north-eastern Alaska (Detterman, at al., 1975). They are unconformably overlain by a thin glacial outwash of poorly stratified sand and gravel, and unconformably underlain by the Tertiary sedimentary beds of the Sagavanirktok Formation. Inferred thickness of the formation ranges from 33-197ft (10-60m) (Detterman, et al., 1975) to around 591ft (180m) (Smith & Clegg, 1971). Exposures between Canning and Kavik River and along Niguanak River suggest that the Gubik Formation generally varies from limonite stained coarse gravel with considerable amount of sand and silt, to clean cross - bedded sand with thin beds of dark -bluish gray laminated silt and clay. The gravel is typically composed of gray quartzite, tuff, gray chert, and weathered limestone. Small pebbles of black chert can also be found in the upper part of the cross -bedded sand. The sand units of the formation are interpreted to have a marine origin. During the 5 spot well study outlined in (Ruedrich, et al., 1976) which was located approximately 2 miles (3.2km) south of DS -02, the pore pressure in the 'first gravels' (Gubik Formation) upper 400ft (122m) was recorded as essentially equal to a head of water and did not significantly decrease during thawing. This is thought to be attributed to the nature of the Gubik Formation being a loosely deposited and ice rich lithology, with high permeability and an ability to maintain pore pressure for groundwater influx during thaw. Due to the nature of analysis conducted this was not explicitly modelled, however this does not impact on the conclusions of this study. The Gubik formation has been deposited and frozen, and so is considered under -consolidated with free ice content. At Prudhoe Bay free ice has been proven to occur to some 50ft (15m) bgl. This is shallower than that encountered on the neighboring Kuparuk field. 4.4.2. Sagavanirktok Formation The Sagavanirktok Formation underlies the Gubik Formation in the Prudhoe Bay area. It consists of the Nuwok Member, the Franklin Bluff Member and the Sagwon Member, and is described as a sequence of poorly consolidated siltstone, sandstone, conglomerate, and lignite exposed in Franklin Bluffs along the lower Sagavanirktok River. Thickness of the Sagavanirktok Formation ranges from around 3780ft (1150m) to 6000ft (1800m) (Detterman, et al., 1975). BP have conducted extensive research on the Lower Sagavanirktok and found it to be comprised of four to five upward fining deltaic to nearshore marine sequences that prograded from southwest to northeast over the Prudhoe Bay Unit, termed SV's (Emerson, 2019). A transgressive marine shale stratum overlies each sandstone unit and is the base of the next progradational sequence. SV5 sequence is eroded to varying degrees over PBU by the Mid -Eocene Unconformity. The SW marker occurs at the top of one of these upward fining sequences. It corresponds to a peak on seismic data due to cementation near the top of the sand. The SV1 marker occurs at the top of the lowermost upward fining sequence. It corresponds to a seismic trough due to the low density of the sand. An upward fining sand occurs within the SV1 sequence in the southern portion of Prudhoe Bay Unit (Perkins, et al., 1975) report that the SV was deposited in cool and humid conditions and subjected to refrigeration and permafrost development in the Pleistocene period. 4.5. DS02 Lithological Profile Atkins has derived a lithological profile for pad DS02 from interpretation of the natural gamma ray log data for well DS02-40 adjacent to well DS02-02. The log data from this well is considered by Atkins to be representative of the stratigraphy of pad DS02, based on correlation with the regional lithological profiles presented by (Ruedrich, at al., 1976) and (Smith & Clegg, 1971) and through lithological comparisons with the neighbouring Kuparuk field. Atkins has used the following criteria to derive soil type from the natural gamma ray log for well DS02-40: • API' values <60 have been interpreted as sand • API` values >60 have been interpreted as clay. `Note: The gamma ray log is reported in pseudo -units called API units. The API unit is defined empirically by calibration to a reterence well 20182272-BPXA-001 1 2.0 1511 December 2019 Atkins I BP Independent geotechncial review of DS02-03 and D802-02 well incidents - Tehnical Note Rev02 FINAL Page 8 of 26 '» ATKINS SNC•LAVAL[N ena=..,,. Atkins notes that the API scale on the natural gamma ray log is typically correlated to site-specific sample or core data to identify lithology from the gamma ray log. In the absence of such site-specific sample data, Atkins has selected the API values representative of each soil types using the typical values presented by Hilchie (1978). The gamma ray log may be used as a semi -quantitative measure of clay content, therefore, the ranges of gamma ray API are not expected to vary significantly between rocks (e.g. shale) and soils (e.g. clay) that have similar clay contents. A typical maximum API value for clean sands is 30API, and a typical minimum API value for shale is 80API. Atkins has, therefore, selected a value of 60API to differentiate between predominantly granular material (e.g. clayey SAND) and predominantly cohesive material (e.g. sandy CLAY). Using this methodology, a bespoke lithological profile has been derived for use in detailed geotechnical analysis. The profile included 64 layers of alternating granular (SAND) and cohesive (SILT) units shown in Table 4-1. Table 4-1 - DS02 lithological profile for analysis based on Gamma Ray Interpretation with 64 layers in total 20182272-BPXA-001 12.0 1 5" December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents - Tehnical Note Rev02 FINAL Page 9 of 26 *0 ATKINS SNC•LAVALIN ae.aamll�stc,.wt•c.wn 5. Numerical modelling 5.1. Introduction The scope of numerical modelling was to verify that the long term permafrost thawing, from a geotechnical perspective, may in some cases lead to the 20" casing failures as reported in the two incidents (BPXA, 2017), (BPXA, 2019). The focus of numerical modelling was to evaluate the casing forces and strain distribution across the permafrost depth in the 20" casing. Numerical analysis of the permafrost thawing process around a wellbore is a complex problem consisting of several coupled mechanisms such as: • Non-linear heat transfer; • Soil pore pressure and effective stress changes; • Change of phase from frozen soil to unfrozen soil; and • Soil and casing deformations leading to casing forces and strains. The numerical modelling is required to capture the coupled thermal, hydraulic and mechanical behaviour of the soil and well casing. In order to capture this complex process, the numerical analysis was undertaken using PLAXIS software utilizing the "Frozen and unfrozen' soil constitutive model (PLAXIS, 2016), which was developed by The Norwegian University of Science and Technology (NTNU), in collaboration with PLAXIS. This constitutive model is a thermo-hydro-mechanical (THM) coupled constitutive model which can model the soil behaviour from the frozen to the unfrozen state. 5.2. Analysis Methodology The overall methodology of the numerical analysis is summarized pictorially in Figure 5-1. The numerical modelling and analyses were undertaken using an axisymmetric model and utilizing a thermo-hydro-mechanical (THM) coupled constitutive model. Further details on the input parameters and the numerical modelling are provided in subsequent sections of this report. The numerical analysis initial phase was based on a thaw profile up to 1969ft (600m) while the final phase (40 years of operation) was based on a thaw profile developed by NES (Hazen, 2019). Input Parameters r20• casts was madded as linear affeal antl as elastic WIN Plane, X9 W antl 13 We' were modelled salmear.lase. ZG anal cw det temperelure >Izl (ls TNM cunstilrters model >Madel Paremete s form • C-FER Report •PW IS Refamnces Lg.retur. Initial and Final Thaw Profile Initial condmon as pemahasl to -196911 (a00m) depth athgN area 9D anW.ela Aran Horan (2019) IDaw Dmfinal fter we -40 we poolk el years Figure 5-1 — Overview of numerical analysis methodology Numerical Analysis Methodology Numerical model Numerical ground model, casing BeomalrY, soil end catnep Properties antl telanlely conditions in PERMS teasel Initial Temperature Profile Base of Permafrost at 1969ff (600.) Analysis In PLAXIS lhenny, HydfoaAeWnieal u Sol hadges from frozen slat(staiato thwad state msmg THM consfild ive soil mode0lo reach the end pmfils while Intermang with casings sell thaws, so1131ruGure interectron takes place Nat de to brces end steins in gs (thaw induced sod- sWclule i,nemctan) accodiy to temperate changes aid Gould conditons. Final Temperature Profile Thaw HfAW from Hazen 20191 N...6.1 Rnayaia Rewae S.1 Sememeds > 20- Casing. romes and Scams 20182272-BPXA-001 1 2.01 5h December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents — Tehnical Note Rev02 FINAL Page 10 of 26 r Gemma ray logs from wml DS02- 40 (BP Provided) and litereture Ground model >Gmund model far Dsw-o2 and DS02-03 with sand and Sias layers level and 0°C al i tlepth INN (600m) 0-10-C Temperate. Profile aam -40 ,ors (2019 of operefimis aom Hazen at an (2019) r20• casts was madded as linear affeal antl as elastic WIN Plane, X9 W antl 13 We' were modelled salmear.lase. ZG anal cw det temperelure >Izl (ls TNM cunstilrters model >Madel Paremete s form • C-FER Report •PW IS Refamnces Lg.retur. Initial and Final Thaw Profile Initial condmon as pemahasl to -196911 (a00m) depth athgN area 9D anW.ela Aran Horan (2019) IDaw Dmfinal fter we -40 we poolk el years Figure 5-1 — Overview of numerical analysis methodology Numerical Analysis Methodology Numerical model Numerical ground model, casing BeomalrY, soil end catnep Properties antl telanlely conditions in PERMS teasel Initial Temperature Profile Base of Permafrost at 1969ff (600.) Analysis In PLAXIS lhenny, HydfoaAeWnieal u Sol hadges from frozen slat(staiato thwad state msmg THM consfild ive soil mode0lo reach the end pmfils while Intermang with casings sell thaws, so1131ruGure interectron takes place Nat de to brces end steins in gs (thaw induced sod- sWclule i,nemctan) accodiy to temperate changes aid Gould conditons. Final Temperature Profile Thaw HfAW from Hazen 20191 N...6.1 Rnayaia Rewae S.1 Sememeds > 20- Casing. romes and Scams 20182272-BPXA-001 1 2.01 5h December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents — Tehnical Note Rev02 FINAL Page 10 of 26 '110 ATKINS SNC•LAVALIN -.sac...., 5.2.1. Staged approach The numerical modelling was undertaken in two stages to ensure that the complexity in the model was built gradually, the mechanisms that influence casing forces and strains were captured. The two -staged approach was as follows; • Stage 1 - model with single soil type • Stage 2 - model with site specific soil layers that represent the DS02-02 and DS02-031ithologies A schematic representation of the Stage 1 and 2 models is presented in Figure 5-2 (a) & (b). In Stage 1, a model with single soil (sand) was utilized. The model included all three casings (9-5/8", 13-3/8" and 20") which were modelled as linear -elastic and were connected at the top. The purpose of this stage was to assess permafrost thawing for full scale model and to perform a sensitivity analyses of various soil parameters in order to assess their effect to the axial forces along the 20" casing. Based on the sensitivity analyses results, the parameters that mainly affect the axial force in the 20" casing were identified as: • Thaw profile • Unfrozen water content • Soil void ratio • Casing temperature The Stage 2 model was developed with a layered soil profile that reflects DS02-02 and DS02-03 site specific conditions and, hence, was the most relevant model for the purpose of investigating the well failures at the DS02 site. The 9-5/8", 13-3/8" and 20" casings were connected at the top. In stage 2 model, two sets of analyses were undertaken: set A and B. In set A, 20" casing was modelled as linear elastic and in set B it was modelled as elastic fully plastic. stage i Madel IGenedcl Stage 2 Model (DS0242 6 D302 -0]I Axisymmenic ,eaymmama Single soil layer MuNayered sail (sand and sits) Liccar Elastic casings linear Elastic anal Elastoplasnc casmgs 1640a(500,n1 r ieaon l5aam) E � Layeretl soil Single soil F Dayth__ m Pxmatmt0aplh —i5846(886injhf _ _ _ 196M(ost 1989fi (SOOm) Ej (a) (b) (c) Figure 5-2 — (a) Schematic representation of Stage I numerical model, (b) schematic representation of Stage 2 numerical model, (c) 3-D schematic representation of the axisymmetric model 5.2.2. Numerical model details The numerical modelling was based on axisymmetric model with the center axis of the well located at the left boundary of the model domain at radius of Oft (0m) as illustrated in Figure 5-2(c). This represents a single well case with radial symmetry. The axisymmetric model was created with 15 -node triangle elements. The 15 -node triangle element is very accurate at producing high quality stress results and it is recommended by PLAXIS for axisymmetric analyses. The automated meshing by PLAXIS with localized optimization was adapted to produce 20182272-BPXA-001 1 2.01 5" December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents—Tehnical Note Rev02 FINAL Page 11 of 26 '» ATKINS SNC- LAV'ALIN .,. a mesh that captured the full stress -stain behaviour of the soil and the casing while optimizing the model run time. The model mesh had total of 98000 nodes as presented in the Figure 5-3(b). All three casings (9-5/8", 13-3/8" and 20") were explicitly modelled using plate structures with appropriate properties. The presence of 30" conductor casing at the top 115ft (35m) isolates the 20" casing from the permafrost up to a depth of 115ft (35m). This was not modelled explicitly but its effect was captured by having zero interface element in 20" casing for the top 115ft (35m). The 9-5/8" casing was fully fixed at the base at 3281ft (1000m) depth. This is considered appropriate as model behaviour below this depth does not affect the soil - casing interaction of the 20" casing. rn � Sand and Silt Layered soil m i+t o N 930 ft (283m) 1464 ft (446m) 1810 ft (552m) C 9 E 0 2691 ft (820m) 3281 ft (1000m) (a) (b) Figure 5-3 — (a) Schematic of the full model (not to scale); (b) Stage 2 Numerical soil model with mesh profile 5.3. Constitutive model used in numerical analysis 5.3.1. Introduction The behaviour of frozen soils has been studied for several decades. Numerical constitutive models have been developed and implemented with different degrees of sophistication. A constitutive model is required to model the behaviour of frozen soil numerically. The Norwegian University of Science and Technology (NTNU), in collaboration with PLAXIS developed an advanced numerical model that is a thermo-hydro-mechanical (THM) constitutive model (Figure 54(a)) deals with multi -physical processes where temperature, hydraulic pressure and mechanical deformation are simultaneously considered (Nishimura, et al., 2009), (Peppin & Style, 2012).This constitutive model for frozen and unfrozen soil is a critical -state elastoplastic, mechanical soil model formulated within the framework of two - stress state variables. In this model, stress state variables are "solid state stress", (a`) and "cryogenic suction", (Sc). The solid phase stress is the sum of stresses in both ice and soil grains minus the pressure of the unfrozen 20182272-BPXA-001 1 2.01 51" December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents - Tehnical Note Rev02 FINAL Page 12 of 26 ATKINS SNC•LAVALIN snc�.nr,ao,o part of water. Cryogenic suction is the difference between ice and water pressure, and it enables the model to consider the effect of ice content and temperature. The soil is assumed to be a fully saturated, isotropic and elastic natural particulate composite. It can be unfrozen, partially frozen or fully frozen (Figure 5-4(b)). The unfrozen soil is composed of solid grains and pore water, whereas partially frozen soil consists of solid grains, pore ice and pore water. When the temperature is sufficiently low, the soil may experience a fully frozen state, where the composite consists of soil grains and pore ice. Full details of the model, model calibration and verification are provided in section 5.3.2. This constitutive model can represent fundamental and crucial behaviors of frozen soil, such as ice segregation phenomena, thawing consolidation and settlement and strength weakening due to pressure melting. Thus, this constitutive model is utilized in the current investigation. 1lrmal mrtlP mnaeero,g mead nest rnermei €. % Frozen J fringe { Efferdn shwa as ry �c T� Eue b Para Prassrve chargec" ad Sf � 8J Pore pr®eum cl,anp y due bwlumetrc span y (a) (b) Figure 5-4 — (a) Thermo -hydro -mechanical interaction mechanism in frozen soil from (Nishimura, et al., 2009); (b) schematic of freezing soil with a frozen fringe (Peppin & Style, 2012) Published literature [ (Goodman, et al., 1982), (Goodman, 1977), (Matthews, at al., 2012)] has highlighted that thaw subsidence and ground lithology along the casing are the main components that affect induced casing forces and strains. Thaw subsidence is primarily understood to be the result of four main mechanisms previously discussed in section 3 of this report. Phase change contraction and thaw consolidation in zones of excess ice, as described in section 3, will lead to compression of the casing and tension of zones above and below. Stiffness reduction and pore pressure reduction are dependent on type of soil lithology (Goodman, 1977). When 'stiff sand layers are adjacent to'soft' silt layers in the soil column, the sand layers tend to expand due to the flow of unfrozen pore water into the more permeable granular materials. This will generate tensile forces in the casing. The adjacent silt layers are prone to compaction due to reduction of stiffness due to thaw which will generate compressive forces in the casing. Of the four mechanisms in section 3, phase change contraction and thaw consolidation are most likely to affect the zone close to the ground surface. 5.3.2. Validation of the PLAXIS constitutive model The PLAXIS frozen -unfrozen THM model has been validated by several researchers [ (Aukenthaler, 2016), (Ghoreishian Amid & Grimstad, 2016), (Ghoreishian Amid & Grimstad, 2017), (Rostani, et al., 2017), (PLAXIS, 2016)], by comparing the frozen and unfrozen soil behaviour under laboratory conditions and field conditions with that predicted by the numerical predictions. Aukenthaler (2016) undertook validation of Frozen -unfrozen THM constitutive model by comparing the model simulation results with triaxial compression test data. Triaxial tests were performed with confining pressures up 20182272-BPXA-001 1 2.01 5" December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents—Tehnical Note Rev02 FINAL Page 13 of 26 0 ATKINS SNC•LAVALIN I to 14 MPa at temperatures of -2°C, -40C and -6°C. The comparison is presented in Figure 5-5(a), which shows that the model can accurately capture the triaxial results. The model was also shown to be able to capture freeze -thaw cycles and resulting volumetric strains as shown in Figure 5-5(b) (Aukenthaler, 2016). This analysis simulates both the ice segregation phenomenon (frost heave) as well as the thaw settlement behaviour. The ability of the constitutive model to predict thaw and loading induced settlement was also verified by comparing with field measurements (Ghoreishian Amid & Grimstad, 2017). The settlement of a long-term plate loading testing was compared with that predicted by PLAXIS THM constitutive model results. The comparison illustrates the ability of the constitutive model to simulate the settlement profile of the field experiment (Figure 5-6(a)). Rostani (2017), examined the capabilities of PLAXIS frozen -unfrozen soil model to simulate frost heave by comparing the outputs of the model with the results from Caen frost heave experiment. Caen's experiment is a field -scale test reporting frost heave deformation of soils due to freezing. Results, (Figure 5-6(b)), show that Plaxis frozen -unfrozen soil model can simulate the frost heave phenomenon as a result of ice segregation (Rostani, at al., 2017). Further validations had been undertaken, (Ghoreishian Amid & Grimstad, 2016) by comparing the PLAXIS model results with experimental triaxial compression tests of frozen soil under different temperatures and confining pressures. Based on this work, it has been verified that the PLAXIS constitutive model can represent ice segregation phenomena and strength weakening due to pressure melting which are two of the basic mechanical behaviors observed in frozen soils. Finally, PLAXIS (PLAXIS, 2016) demonstrated the capabilities of the THM frozen -unfrozen soil model through three examples. In the first example, triaxial tests under different temperatures and confining pressures were simulated, in the second a freezing -thawing cycle was applied on a soil sample and in the third a chilled pipeline was buried in unfrozen ground. Based on the results, the model was shown to be fully capable to produce accurate results through various conditions, to simulate frost heave and thaw settlement. g.. 2 x G j I - , a o ' / a S 2 - d / 0 0m 0.02 004 0.u: (a) — T. SO"CCWrv6W M. °CCaleul.M4u n n :u a 11 nu 0.16 0.19 exiRi Jeein..,,.. FI non �--1 1•r,me-Mwha 1 0.(3 SIN LLGI -nos -II IXi � � \ 2`�hae[elMu'gtle EM -01 . -0.10 20 2w 266 2n9 r0 'Ta 9kmwratumlio (b) Figure 5-5 — (a) Comparison of stress -strain curves under constant confining pressure at -2, -4 and -60C (Aukenthaler, 2016), (b) Change of volumetric strain after two freeze -thaw cycles (Aukenthaler, 2016) 20182272-BPXA-001 1 2.01 5t0 December 2019 Atkins I BP Independent geotechncial review of OS02-03 and DS02-02 well incidents-Tehnical Note Rev02 FINAL Page 14 of 26 -0.or -0o= = -0.03 E vas ODS -066 -0.07 -0.OB Time (year) E m i +0 ATKIN5 SNC•LAVALIN Pipe servemem 16 14 t E�yalmMel RB•Af NunwN.W a,ml�4m 12 e E 0 (a) (b) W IOU 1w eao as xv aw Time (Days) Figure 5-6 - (a) Comparison of calculated and measured settlement results (Ghoreishian Amiri & Grimstad, 2017), (b) Pipe heave movement from experiment and simulation (Rostani, et al., 2017) 5.4. Input for numerical analysis The numerical analysis model input parameters can be subdivided into four main categories: 1. Numerical ground model 2. Casing and cement properties 3. Temperature and thaw profiles 4. Constitutive model properties The sections below provide insight into each of the categories. 5.4.1. Numerical ground model The lithological profile detailed in Section 4.5 was simplified in the numerical model to enable the numerical modelling to run in acceptable time frame whilst capturing the ground lithology. The simplification was based on the following criteria: • For depths up to 1476ft (450m), soil layers with thickness of less than 13ft (4m) were combined with the adjacent major layers. • For depths greater than 1476ft (450m), soil layers with thickness of more than 33ft (10m) were combined with the adjacent major layers. The simplified ground model used in the numerical analysis is provided in Figure 5-3(b). This model consists of 29 layers of alternating granular (Sand) and cohesive (Silt) units of varying thickness. The lithological profile for the Gubik Formation (detailed in Section 4.4.1) is modelled as a sand unit. 5.4.2. Casing and cement properties Figure 5-3(a) provides schematic representation of the three well strings and the cement modelled in PLAXIS. The properties of steel and cement that were used in the numerical analyses are summarized in Table 5-1 and Table 5-2 respectively. Casing properties were obtained from the BP Incident Reports. (BPXA, 2017) (BPXA, 2019). BP also provided the stress -stain profile for the 20" casing as shown in Figure 5-7. The yield stress of 276MPa in 20" casing leads to a yield force of 4790KN. The 20" casing was modelled as linear elastic material in initial set of analyses, and it was later modelled as elastic fully plastic material as shown in Figure 5-7. It is to be noted that the numerical model utilised the fully plastic material model that accommodates very high strains and was not limited to 1% as shown in Figure 5-7. Cement thicknesses next to the casings were modelled as below (as provided by BPXA), 3" for the 20" casing; • 2-1/16" for the 13-3/8" casing; 1-7/16" for the 9-5/8" casing. 20182272-BPXA-001 1 2.01 5" December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents — Tehnical Note Rev02 FINAL Page 15 of 26 0 ATKINS 5NC•LAOALIN nei 1101N%Cb� 1000 250 0 0 0.0% 0.1% 0.2% 0.3% 0.4% 0.5% 0.6% 0.7% 0.8% 0.9% 1.0% Axial Strain (%) Figure 5-7 -Stress-stain behaviour of 20" casing used in the numerical analysis (provided by BPXA). Table 5-1 -Thermal and mechanical properties of steel casing Casing Length [ft) (m) Weight 9000 Inner moo Thermal v Z 8000 p � 1I50 Diameter heat expansion m 7000 (m) [ft] (m) ii 6nnn 1911 [MPa] b z ; ATKINS SNC•LAVALIN Ts p . 1*9 CI mb December 2018 d t0 8 6 4 2 0 2 4 0 0 §- Temperature`, -- profile used in numerical model 2001 +------------ - Final thaw profile used in k. numerical model ". co -------- -------. aJAIL a--n-b-9b Based on Pgrmpfrost � _ °°0 in numerical model y ... "t0` °.10"r Sze a 36r m3zw wv ccom a5 .,wr (a) (b) Figure 5-8 - (a)Ground temperature profiles from Nine Prudhoe Bay Wells (Lachenbruch, et al., 1982), (b) Extract from Hazen (2019) 3D Single Well Analysis of DS02-02 and thaw profile used in the current numerical model Figure 5-9(a) and (b) provide the thermal profile of the numerical model at the start and end of the analysis. The thermal profile at the start is based on permafrost at 1969ft (600m) depth and the temperature profile at the end is based on the thaw profile (Hazen, 2019) which was based on single well analysis, after -40 years of operation (Figure 5-8(b)). E m MW QQ V.M A.ffi X11 31.53 3295 vm H.A ID.21 XW no nQ 3109 2AY 10.74 IJ.Ib nY u.m Operation time - 40years In MW 4242 Q.N A.ffi 3).(8 ffi. t1 39.51 n.95 31.n nn 25121 no no a. 21" ID.IZ 1634 17,% 15." I4.m (a) (b) Figure 5-9 (a) Initial Ground temperature profile (pre 1977); (b) Temperature profile after -40 years of well operation (single well model) 5.4.4. Constitutive model parameters The sand and silt constitutive model properties were obtained from an extensive review of published sources that included publications linked to Alaska regions and recommendations from PLAXIS literature [ (PLAXIS, 2016), (Yang, et al., n.d.), (Aukenthaler, 2016), (Agrawal, 2015), (C-FER, 2014), (Yao, et al., 2013), (Goodman, 1975), (Parameswaran & Jones, 1981), (Wang, et al., 2007)]. 20182272-BPXA-001 1 2.01 5" December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents - Tehnical Note Rev02 FINAL Page 17 of 26 ATKINS SNC-LAVALIN „seaa.w mwc Whenever possible, the sand and silt constitutive properties have been obtained from Alaska region related publications and BP provided data. Nevertheless, the available literature for frozen soils at temperatures (from 0°C to -10°C) and appropriate stress level (permafrost depth reaches 1969ft (600m)) is limited. When constitutive properties were not available from site relevant data, typical values recommended by PLAXIS references have been used (Aukenthaler, 2016), (PLAXIS, 2016). The unfrozen water content with temperature for sands and silts, which determines the water percentage in the soil pores based on its temperature, have been obtained from C-FER report (C-FER, 2014). Figure 5-10(a) and (b) present the unfrozen water content data from C-FER report and that utilized for sand and silt in the numerical modelling respectively. i-------------------- z s a ♦emw+,ve MI 100% 90% d 80% Q —70% y `o �0% 30% 20% 10% o°/ —SAND —SILT z T3emperafure6("Cf -6 -s -10 (a) (b) Figure 5-10 - (a) Unfrozen Water Content of Sand and Silt from C-FER report (C-FER, 2014), (b) Unfrozen water content of Sand and Silt used in the PLAXIS model 5.4.5. Boundary Conditions Table 5-3 presents the thermal, mechanical and hydraulic boundary conditions that were utilized in the numerical model. Each of the numerical analyses have an initial and final phase. The mechanical and the hydraulic boundary conditions are the same for both phases. The value of the geothermal heat flux for each phase was obtained by an iteration process until the permafrost depth in the model was -1969ft (600m). As presented in Table 5-3 at the vertical left mechanical boundary horizontal displacement is restrained and hydraulic boundary is closed. This is the result of model's symmetry of left boundary which prevents both soil and water from moving laterally (Figure 5-2(c)). Table 5-3 - Thermal -mechanical -hydraulic boundary conditions Boundary Horizontal Top Horizontal Base Vertical Left Vertical Right Conditions Mechanical No restraint in Horizontal and Only horizontal Only horizontal horizontal and vertical displacement displacement vertical direction displacement restrained restrained restrained Thermal Initial Constant at -10°C Geothermal heat Linear variation Linear variation phase flux ( -10°C at ground ( -10°C at ground surface to 0°C at - surface to 0°C at - 1969ft (600m)) 1969ft (600m)) Thermal Final Constant at -10°C Geothermal heat Constant at 80°C Linear variation from phase flux -10°C to 0°C at -600m Hydraulic Open Closed Closed Open 6. Numerical Results The stage 1 numerical analyses as discussed in 5.2.1 were undertaken using a simplified generic numerical model with a singular soil column to understand the key soil properties and sensitivities which affected the 20" casing loads. 20182272-BPXA-001 1 2.0 1511 December 2019 Atkins I SP Independent geotechncial review of DS02-03 and D802-02 well incidents—Tehnical Note Rev02 FINAL Page 18 of 26 ATKINS SNC-LAV'ALIN 1 - 1. 'SNC W', The Stage 2 model represents the DS02-02 and DS02-03 site conditions and, hence, is the most relevant to verify the axial forces and strains in the 20" casing that led to the failure incidents at the DS02 site. Table 6-1 provides summary of the numerical analyses undertaken in stage 2. Two sets of analyses were undertaken, set A and B. In set A, all casings were modelled as linear -elastic and in set B, the 20" casing was modelled as elastic - fully -plastic, as detailed in section 5.4.2. For each set, two analyses were performed to investigate the effect of casing connection type at the surface. In sets Al and B1, the 20" casing was fixed at the top to an anchor while in sets A2 and B2, 20" casing was connected to 13-3/8" and 9-5/8" casings. It is to be noted that the soil stratigraphy, initial and final thaw profiles and casing temperature were consistent for all analyses. Table 6-1 — Summary of numerical analyses 6.1. Permafrost and ice saturation at the final phase The variation of ice saturation with depth is presented in Figure 6-1(a), at four different vertical sections at 16ft (5m), 33ft (10m), 49ft (15m) and 820ft (250m) from the center of the model. The figure demonstrates the advancement of the thaw profile from the casings. Note that sections were chosen to capture the final thaw profile, the section at 820ft (250m) is similar to the initial thaw profile, whilst those at 16ft (5m), 33ft (10m) and 49ft (15m) are thawed due to proximity to wellhead temperature. Figure 6-1(b) indicates the ice saturation for the entire model. The various silt layers in the model within the permafrost can be clearly identified as the ice saturation in silt layers is lower than sand layers. 20182272-BPXA-001 1 2.01 S" December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents —Tehnical Note Rev02 FINAL Page 19 of 26 Numerical Test 20" Casing material 9-5/8" and 13-3/8" 20" Casing fixity at the top Analysis set number Casings material 1 Set Al Fixed at the top Set A Linear elastic Linear elastic 2 Set A2 Connected to 9" and 13" 3 Set B1 Fixed at the top Set B Elastic fully plastic Linear elastic Set B2 Connected to 9" and 13" 4 6.1. Permafrost and ice saturation at the final phase The variation of ice saturation with depth is presented in Figure 6-1(a), at four different vertical sections at 16ft (5m), 33ft (10m), 49ft (15m) and 820ft (250m) from the center of the model. The figure demonstrates the advancement of the thaw profile from the casings. Note that sections were chosen to capture the final thaw profile, the section at 820ft (250m) is similar to the initial thaw profile, whilst those at 16ft (5m), 33ft (10m) and 49ft (15m) are thawed due to proximity to wellhead temperature. Figure 6-1(b) indicates the ice saturation for the entire model. The various silt layers in the model within the permafrost can be clearly identified as the ice saturation in silt layers is lower than sand layers. 20182272-BPXA-001 1 2.01 S" December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents —Tehnical Note Rev02 FINAL Page 19 of 26 Saturation Ice%] 0 20 40 60 0 100 0 1 -100 -200 Ill -400 7-500 0 -600 v W —X=Sm ice saturation -700 —X=10m ice saturation -800 —X=15m ice saturation -900 )—x=250m ice saturation -281 -781 1281 x 1781 -2281 -2781 0 ATKINS SNC-LAYALIN 1%) 100.00 90.00 80.00 70.00 60.00 50.00 40.00 30.00 21.00 10.00 1640ft(500m) 1111, -1,000 - -3281 0.00 (a) (b) Figure 6-1 — (a) Change of ice saturation with depth at 4 different distances from the well center (x=16ft (5m), x=33ft (10m), x=49ft (15m) and x=820ft (250m)), (b) Ice saturation map in the final phase 6.2. Ground deformations Figure 6-2 presents the thaw induced settlement results from the numerical model at the final phase (after —40 years of operations). The behaviour exhibited by the numerical model aligns well with the findings from literature, which shows that settlement is greatest at the surface near the casing and heave occurs at the base of the permafrost (Goodman, 1977). The fluctuations in the settlement line are due to the soil layering and associated soil arching. This is illustrated from the numerical model results in Figure 6-2. Pore pressure reduction and stiffness reduction are the key mechanisms that cause the settlements in deeper permafrost in the numerical analysis. The temperature of the permafrost increased from the surface to the base at -1969ft (600m) depth and the frozen soil stiffness decreased as temperature is increased. Thus, the stiffness reduction, due to thawing, near the surface would be greater than at the base of permafrost. Soil movement from this mechanism is, therefore, greater near the surface than at the base of permafrost (Goodman, 1977). 20182272-BPXA-001 1 2.01 5 December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents–Tehnical Note Rev02 FINAL Page 20 of 26 Settlement 1 m from 20" casing [m] -1.25 -1 -0.75-0.50.25 0 0.25 0.5 0 1 -100 -200 -300 -400 E -500 c -600 m W -70D -800 -900 -1,000 -4 -3.2-24-1.6-0.8 0 0.8 1.6 [ft] -281 -781 -1281 -1781 -2281 -2781 -3281 (a) (b) SNC-LAV'ALIN [ml 0.31 0.10 0.00 -0.10 -0.31 AM -0.41) -0.50 -0.60 -0.A .0.80 -0.90 -1.00 -1.10 ATKINS n—.. m1M sncIv.n' a"c Figure 6-2 -(a) Settlement profile at 3.28ft (1m) distance from 20" casing, (b) Settlement map of the model 6.3. 20" Casing Forces and Strains In Set A (Table 6-1), the 20" casing was modelled as linear elastic. Thus, the axial forces from the 20" casing is presented and compared with the yield force and tensile strength of the casing to conclude whether casing failure is expected. In Set B (Table 6-1), 20" casing was modelled as elastic fully plastic. Thus, the axial forces on 20" casing would be limited to its yield strength (4790kN) and hence the axial strains plots provide an insight into potential casing failure. 6.3.1. Results from Set A — 20" casing as linear elastic Figure 6-3 presents the axial forces from the numerical model results that developed in the 20" casing due to the thaw induced soil deformation. Set Al results represent the case when the 20" casing is fully fixed at the top such that it cannot move vertically downwards. This situation is considered hypothetical as it is known that the 20" casing is connected to the 13-3/8" and 9-5/8" casings. In this case, it is evident that if the 20" casings were to be fully fixed at the top, the axial forces imposed on it would easily exceed the tensile strength and, hence, could lead to failure at the top. The axial force change observed below 919ft (280m) is due to the top of cement occurring at this depth. The set A2 analysis results represent more a realistic situation in which the 20" casing was connected to the 13- 3/8" and 9-5/8" casings and, hence, the casings are allowed to move downwards. The results show that the axial force in the 20" casing exceeds its yield strength and is marginally below its modeled tensile strength. It is also evident that the maximum axial forces occur in the top 1 15f (35m) of the 20" casing. As it is likely that the final phase thaw profile utilized in the numerical assessment is smaller than the thaw profile that would have been in DS02-02 and DS02-03 sites due to nearby well operations, the tensile forces in the casing is expected to exceed the tensile strength of the 20"casing and, hence, failure would be expected. 20182272-BPXA-001 1 2.0 1 5" December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents — Tehnical Note Rev02 FINAL Page 21 of 26 •» SNC•LAVALIN Axial Force on the 20" casing [kN] -12,000 -3,000 6,000 1s,000 24,000 0 1 I. -s0 -100 -150 -200 c 0 w -250 w 300 -350 -400 Set Al, 20" casing Fixed at Top — Set A2, 20" Connected t 9" and 13" casings – – –Yield Strength – -Tensile Strength -450 -2,698 -1,198 302 1,802 3,302 4,802 [kips] -76 -276 A76 -676 s -876 -1,076 -1,276 -1,476 Figure 6-3 - Axial force along the 20" casing for Set A 6.3.2. Results from Set B — 20" casing as elastic fully plastic ATKINS The axial forces and strains that developed in the 20" casing due to the thaw induced soil deformations are presented in Figure 6-4 and Figure 6-5 respectively. As the 20" casing material was modelled as elastic fully plastic material, the maximum axial force that can develop in the 20" casing is limited by the yield strength (4790kN/1077kips). As it is evident from Figure 6-4, the axial forces near the surface has reached the yield strength of the 20" casings in both the set B1 (fixed at the top) and set B2 (20" casing connected with 13-3/8" and the 9-5/8" casing) results. Based on the strains results of the 20" casing for the realistic site scenario (set B2), it can be noted that that the 20" casing can experience excessive strains in excess of —5% near the ground surface and, hence, failure can be expected due to the thaw induced soil deformations. 20182272-BPXA-001 1 2.01 5" December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents – Tehnical Note Rev02 FINAL Page 22 of 26 '» ATKINS SNC-LAVALIN Axial Force on the 20" casing [kN) -10,000 -5,000 0 5,000 10,000 0 1 -76 -50 -100 150 -200 0 M -250 W -350 1 I -476 1 1 —Set 81, 20" Fixed at the Top -676 —Set Bl, 20' Fixed at the x Set B2, 20" 676 Connected to 9" -976 and 13" casings x — — — Yield Strength -1,076 — — — Tensile Strength -400 I -1,276 I -450 I I 1 -1,476 -2,248 -1,498 -748 2 752 1,502 [kips) Figure 6-4 - Axial force along the 20" casing for Set B Total Strains on Elastoplastic 20" casing Total Strains on Elastoplastic 20" casing E £ [%) e o tib 3b Vii° yl° 0 0 -4 76 -50 -5 24 -100 276 -10 44 -150 476 -15 200 0 0 >-250 w -300 -35 1,076 -350 -40 -124 400 -1,276 -45 -144 -450 -1,476 -50 - --- - -164 (a) (b) Figure 6-5 - Total strains along the 20" casing (a) Strains along full casing length; (b) Strains in top 164ft (50m) 20182272-BPXA-001 12.0 1 5" December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents - Tehnical Note Rev02 FINAL Page 23 of 26 -64 3` T-20 —Set Bl, 20' Fixed at the 676 Top x -25 0 -84 v —Set B2, 20" Connected to -876 w .30 9" and 13" casings -104 -300 -35 1,076 -350 -40 -124 400 -1,276 -45 -144 -450 -1,476 -50 - --- - -164 (a) (b) Figure 6-5 - Total strains along the 20" casing (a) Strains along full casing length; (b) Strains in top 164ft (50m) 20182272-BPXA-001 12.0 1 5" December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents - Tehnical Note Rev02 FINAL Page 23 of 26 •%� ATKINS SNC -LAV.ALIN 7. Conclusions An extensive literature review was undertaken to fully understand local site condition and operations as far as possible, fundamentals of frozen soil behaviour, and casing loading mechanisms. Utilizing this knowledge, Atkins carried out following sequence of verification: • A lithological profile for DS02 from interpretation of the natural gamma ray log data for well DS02-40. The natural gamma ray log data from this well is considered by Atkins to be representative of the stratigraphy of pad DS02, based on correlation with the regional lithological profiles • Numerical modelling was undertaken to simulate the 3 -string wells of DS02-02 and DS02-03 and verify the 20" casing forces and strains that that lead to the surface tensile failure of the 20" casing in the two incidents. • A thermal -hydro -mechanical soil constitutive model and the localized lithological profile was utilized in numerical analysis to verify the casing forces and strains distribution in the 20" casing. BP incident reports for both failures identified the main contributing factor to be that of tensile failure of the 20" surface casing. Failure was determined to have been due to a load imparted by subsidence of permafrost formations acting on the 20" surface casing resisted by the 13 3/8" and 9 5/8" inner casing strings. The numerical modelling and analysis undertaken in this study of permafrost subsidence, specifically "thaw induced" deformations (soil strain) and the resultant surface casing mechanical strain for three string well designs has verified: • That, if a 20" surface casing tensile failure does occur, it will most likely occur near the well surface where maximum axial tensile strain is predicted by the modelling. • And that, the overall magnitude of the axial forces and strains generated in the 20" surface casing, attributed to 40 years of permafrost thaw induced subsidence loading, is sufficient to lead to tensile failure of the 20" surface casing, based again on the properties used in the modelling. 20182272-BPXA-001 1 2.01 5" December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents - Tehnical Note Rev02 FINAL Page 24 of 26 +%) ATKINS SNC•LAVALIN 8. References Agrawal, N. D., 2015. Thermal Analysis on Permafrost Subsidence on the North Slope of Alaska, Alaska: University of Alaska Fairbanks. ARCO, 1975. Prudhoe Bay Field Permafrost Casing and Well Design for Thaw Subsidence Protection, s.l.: Atlantic Richfield Company. ARCO, 1985. Thaw -Subsidence Studies for Prudhoe Bay Infill Wells; Status Reports 1, 2 & 3, s.l.: Atlantic Richfield Company. Aukenthaler, M., 2016. The Frozen & Unfrozen Barcelona Basic Model. A verification and validation of a new constitutive model. s.I.:Delf University of Technology. Bird, K., 1999. Geographic and geologic setting. The Oil and Gas Resource Potential of the 1002 Area, Artic National Wildlife Refuge, Alaska, Volume USGS 98-34. Black, R., 1969. Geology, Especially Geomorphology, of Northern Alaska. Terrestrial Science, pp. 283-299. BPXA, 2006. The Prudhoe Bay fact sheet. Anchorage, Alaska: BP. BPXA, 2017. Well 02-03 Investigation report as filed with AOGCC (DS02-03], s.l.: BP. BPXA, 2019. Well 02-02 Investigation Report as filed with AOGCC (DS02-02). s.I.:BP. C-FER, 2014. ]-Pad Well Design and Minimum Spacing Requirements to Mitigate Thaw Subsidence Risk, s.l.: C-FER Technologies. Detterman, R., Reiser, H., Brosge, W. & and Dutro Jr, J., 1975. Post -Carboniferous Stratigraphy, Northeastern Alaska. US Geological survey professional paper, Volume 886. Emerson, R., 2019. Prudhoe Bay Geological overview presentation - BP Kickoff workshop. Anchorage, Alaska: BP. ExxonMobil, 2013. Point Thomson Permafrost Thaw Induced Subsidence Study - Internal presentation by Yao Yao, Sheng-Yuan Hsu, and Pablo Sanz. Exxon Mobil Upstream Research Company. Ghoreishian Amiri, S. A. & Grimstad, G., 2016. Constitutive model for rate -independent behavior of saturated frozen soils. Canadian Geotechnical Journal, pp. 1646-1657. Ghoreishian Amid, S. A. & Grimstad, G., 2017. Constitutive model for long-term behaviour of saturated frozen soil, s.l.: s.n. Goodman, A. M., Fischer, F. J. & Garrett, D., 1982. Thaw subsidence analysis for multiple wells on a gravel island. s.l., Engineering Applications in Permafrost Areas. Goodman, M. A., 1975. Mechanical Properties of Simulated Deep Permafrost. Journal of Engineering for Industry, pp. 417-425. Goodman, M. A., 1975. Mechnical Properties of Simulated Deep Permaforst. Jornal of Engineering for Industry, Issue ASME. Goodman, M. A., 1977a. How Permafrost Thaw/Freeze Creates Wellbore loading. World Oil, Artic Well Completion Series. Goodman, M. A., 1977b. Loading Mechanisms in Thawed Permaforst around Artic Wells. Jomal of Pressure Vessel Technology, ASME. Goodman, M. A., 1977. Loading Mechanisms in Thawed Permafrost Around Arctic Wells. Journal of Pressure Vessel Technology. Goodman, M. A., 1982. Thaw Subsidence Analysis for Multiple Wells on a Gravel Island. 4th Canadian Permafrost Conference. Hall, D., 1979. Geomorphic Processes on the North Slope of Alaska, Maryland: NASA. Hazen, B., 2019. Temperature profiles of Overlay of temperature profiles at DS02 with hydrate stability curves. Anchorage, Alaska: Northern Engineering and Scientific. Hilchie, D., 1978. Applied openhole log interpretation (forgeologists and petroleum engineers). s.I.:Goldon, Colo. Lachenbruch, A. H., Sass, J. H., Marshall, B. V. & Moses, T. H., 1982. Thermal Regime of Permafrost at Prudhoe Bay, Aaska, s.l.: United States Department of the Interior Geological Survey. Matthews, C. M. at al., 2012. Importance of Deep Pemafrost Soil Characterization for Accurate Assessment of Thaw Subsidence Impacts on the Design and Integrity of Arctic Wells. Houston, OTC. 20182272-BPXA-001 1 2.01 51" December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents-Tehnical Note Rev02 FINAL Page 25 of 26 ATKINS SNC-LAUALIN n«me��onmv+wam�c,o�c Mitchell, R. F., 1977. A Mechnical Model for Permafrost Thaw Subidence. Journal of Pressure Vessel Technology, ASME . Mitchell, R. R. at al., 1983. Well Casing Strains due to Permafrost Thaw Subsidence in the Canadian Beaufort Sea. 4th International Permafrost Conference Proceedings, pp. 855-860. NES, 2008. On the Occurrence of water Infiltrating into the Cellar at DS01-05. A Working Theory Related to Pressurization of Soil Port Volume Upon Refreezing around Shutln Wells, s.l.: Northern Engineering & Scientific. Nishimura, S., Gens, A., Olivella, S. & Jardine, R. J., 2009. THM-coupled finite element analysis of frozen soil: formulation and application. Geotechnique, Volume 59, pp. 159-171. Parameswaran, V. R. & Jones, S. J., 1981. Triaxial Testing of Frozen Sand. Journal of Glaciology, 27(95), pp. 147-155. Peppin, S. S. L. & Style, R. W., 2012. The physics of frost heave and ice -lens growth, Oxford: Oxford Center of Collaborative Applied Mathematics. Perkins, T. K., Rochon, J. A., Schuh, F. J. & Wooley, G. R., 1975. Prudhoe Bay Field, Permafrost Casing and Well Design for Thaw Subsidence Protection, s.l.: Atlantic Richfield Company Report. PLAXIS, 2016. The Frozen and Unfrozen Soil Model, s.l.: Plaxis. Rawlinson, S., 1983. Guidebook to permafrost and related features, Prudhoe Bay, Alaska. Fourth International Conference on Permafrost, Volume Univerisity of Alaska. Rostani, H., Ghoreishian, S. A. A. & Grimstad, G., 2017. Back analysis of Caen's test by the recently developed frozen/unfrozen soil, Trondheim: Norwegian University of Sciencen and Technology (NTNU). Ruedrich, R., Perkins, T., Rochon, J. & and Christman, S., 1976. Casing Strain resulting from thawing of Prudhoe Bay permafrost. AtlanticRichfieldCompany (ARCO), Volume PD 76-21. Smith, R. & Clegg, M., 1971. Analyses and Design of Production Wells through thick permaforst. Proceedings of hte Eigth World of Petroleum Congress, Moscow, pp. 279-389. Suryawanshi, S., 2016. Integrated experimental and computer modeling approach to understand permafrost thaw subsidence induced oil well instability for Alaska North Slope oil wells. s.I.:University of Alaska Fairbanks. Van Everdingen, R., 1998. Multi -Language glossary of Permafrost and related ground -ice terms. Revised 2005 ed. Alberta, Canada: International permafrost association . Wang, D. -Y., Ma, W., Wen, Z. & Wu, Z. -J., 2007. Stiffness of Frozen Soils Subjected to KO Consolidation Before Freezing. Japanese Geotechnical Society, 47(5), pp. 991-997. Xie, J., 2009. Analysis of Thaw Subsidence Impacts on Production Wells. 2009 SIMA Customer Conference. Xie, J. & Matthews, C. M., 2011. Methodology to Assess Thaw Subsidence Impacts on the Design and Integrity of Oil and Gas Wells in Artic Regions. SPE Artic and Extreme Enviroments Conference & Exhibition, Moscow, October 18-20. Yang, Z. at al., n.d. Elastoplastic Modeling of Well Casing Subsidence in Thawing Permafrost. Yao, Y., Hsu, S. -Y. & Sanz, P., 2013. Point Thomson Permafrost Rhaw Induced Subsidence Study, s.l.: ExxonMobil. 20182272-BPXA-001 1 2.0 151' December 2019 Atkins I BP Independent geotechncial review of DS02-03 and DS02-02 well incidents — Tehnical Note Rev02 FINAL Page 26 of 26 GEC 13 2719 A®CCC Interpretation of Well Abandonment Data Wells 02-02 and 04-01 Date: October 31, 2019 Prepared By: BPS nior Advisor Tubular Design 10/31/2019 Issued T0: BPXA Well Integrity Team Leader Revision No.: 1 Interpretation of Well Abandonment Data 1. Summary The deconstruction and logging activities at wells 02-02 and 04-01 have yielded some limited data regarding the manner that a three -string casing with surface casing set within permafrost can fail. • Well 04-01 provided no indications of substantial formation -induced loads on any of the casing strings. This is not surprising, as the well did not experience a 20 in. parting and subsequent upward wellhead movement. • The 20 in. casing in Well 02-02 was substantially ovalized at the point of failure. This could have caused the casing to part at a lower applied load than if it was not deformed. However, prior work considered 20 in. parting strength as a model sensitivity. Therefore, the observed 20 in. deformation is interesting but does not alter the model or provide new insight. • Well 02-02 showed indications of inner string compression. The finding of potential compression in the 13-3/8 in. casing is insightful in explaining the magnitude of upward wellhead movement, but does not alter the model or the explanation of the failure. • The inability to pull 13-3/8 in. casing out of Well 02-02 does not ultimately inform how to improve downhole modelling of thaw -induced subsidence loads acting on wells with surface casing set within the permafrost. 2. Acquired Data Data is noted from daily reports summarizing the abandonment campaign and from interpreted multi - finger caliper (MFC) data. READ, the logging service provider, provided some interpretation of their MFC logs. C-FER Technologies has developed software for visualizing MFC data and provided a report analyzing the 02-02 logs. 2.1 Well 02-02 2.1.1 5-1/2 in. tubing The 5-1/2 in. tubing string had parted shallow at some time after a caliper run in 2017. The MFC log showed the part between 31 and 42 ft. wireline depth. C-FER analysis suggests sinusoidal buckling over the lower half of the log. This is expected since the parted tubing slumped down the hole, resulting in compressive force that increases along the length of the string. In simplified terms, string compression can cause buckling. READ did not make note of anything unusual except for the parting between 31 and 42 ft. The tubing was pulled prior to rigging up for the deconstruction. 2.1.2 9-518 in. casing The 9-5/8 in. casing was cut at 1,330 ft and retrieved. Logs show tool eccentricity between 44 and 52 ft. This was later interpreted as string interaction with the 13-3/8 in. casing, described below. C-FER noted changes to tool inclination and eccentricity throughout the string, e.g. from 220 to 310 ft and again from 590 to 710 ft. They interpreted this as an indication of global buckling, whether helical or sinusoidal. Interpretation of Well Abandonment Data An alternative explanation for the 9-5/8 in. variation in inclination could result from string -to -string interaction with a buckled 13-3/8 in. READ did not note signs of significant buckling. The logging tool hung up a bit at 48 ft, the same region of eccentricity described by C-FER. 2.1.3 13-3/8 in. casing Both READ and C-FER identify ovalized casing deformation at in the vicinity of 50 to 52 ft. C-FER further identified changes in tool inclination and eccentricity as indications of buckling due to compressive loading, e.g. from 185 to 270 ft. and from 495 to 545 ft. The 13-3/8 in. casing was cut at 1,268 ft MD and at 59 ft. The wellhead was lifted with 14 ft of 13-3/8 in. casing and the 20 in. casing stub attached. The 20 in. was severely deformed onto the 13-3/8 in. casing, shown in Figure 1. Repeated attempts to pull the 13-3/8 in. were unsuccessful. The casing was cut at 100 ft. and could not be retrieved with up to 450 kips of overpull. One more cut was made at 68 ft. and the 35 ft. segment of 13-3/8 in. came free. Milling of 5 feet of 20 in. casing and cut and removal of an additional 12.3 ft. of the same did not affect the inability to recover the 13-3/8 in., though the fish did move upward a total of 24 ft. Recovery operations were ultimately suspended. Figure 1- 20 in. Casing Deformation at Parting Depth 2.2 Well 04-01 Well abandonment operations commenced without difficulty. The 9-5/8 in. casing was cut at 1,200 ft. and pulled with 230 kips. The 13-3/8 in. casing was cut at 1,095 ft and pulled with 108 kips. The 20 in. was cleaned out to the 13-3/8 in. stub. READ ran MFC logs in the tubing and the three casings. The tubing run showed variations in inclination toward the bottom of the 3,818 ft interval. READ noted that this could indicate corkscrewing. They found no indication of buckling in any of the casings. The 20 in. log showed ovalization at it ft, though the tool did not move substantially off -center. Interpretation of Well Abandonment Data 3. Comparison of Findings with Model Predictions Engineering models were built to understand the potential cause and observed response of the 02-03 and 02-02 well failures and associated upward wellhead movements. The observations from well deconstruction are compared to those engineering models. 3.1 Well 02-02 3.1.1 20 in. ovalization The 02-02 model used a baseline assumption of 1,615 kips required to part the 20 in. casing, reflecting the nominal cross-sectional area multiplied by the minimum tensile strength for grade H40. A sensitivity analysis of predicted wellhead movement to parting load was also conducted. The observed 20 in. deformation at the point of tensile failure has some bearing on the model. It is quite possible that the deformation—likely due to a shallow ice feature—affected the casing axial strength. The actual casing strength influences predicted wellhead movement in response to the 20 in. part. This effect is illustrated in Figure 2, taken from the 02-02 investigation report. Though the observed 20 in. deformation is interesting, it does not alter the model or provide new insight. 70 60 c t 50 w E > 40 0 i X 30 3 a � 20 3 a 10 WH Movement vs. 20 in. Parting Load Blue Line Relates Model Movement to 20 in. Parting Load Red Lines Translate Net 20 in. Gap to Applied Force L=300ft L=500ft 0 1,000 2,000 3,000 4,000 20 in. Parting Load (kips) Figure 2 - 02-02 Model Sensitivity to 20 in. Parting Load 3.1.2 Casing buckling The log interpretation suggesting buckling of the 13-3/8 in. casing has bearing on the predicted wellhead movement. Buckling is generally induced by string compression. The observation of 13-3/8 in. buckling Interpretation of Well Abandonment Data indicates that the permafrost thaw subsidence could have imposed both a tensile load on the 20 in. and a compressive or upward force on the 13-3/8 in. The potential for 13-3/8 in. compression was incorporated into the model and identified as likely based on the magnitude of observed wellhead movement. A sensitivity of model results to 13-3/8 in. compression was not previously presented. The point in Figure 2 identified by the label "min. tensile" is selected as a baseline condition. This point reflects a 20 in. casing parting load of 1,615 kips equal to the minimum tensile strength and nominal casing dimensions. The corresponding 24.6 inches of upward wellhead movement assumes no compressive force applied by the formation to the 13-3/8 in. Figure 3 illustrates wellhead movement sensitivity to 13-3/8 in. compression, all other variables remaining constant. The finding of potential compression in the 13-3/8 in. casing is insightful in explaining the magnitude of upward wellhead movement, but the finding does not alter the model or the explanation of the failure. 50 40 d E 30 0 2 3 20 WH Movement Sensitivity to 13-3/8 in. Compression 200 400 600 800 1,000 Compressive Load on 13-3/8 in. (kips) Figure 3 - Sensitivity of WH Movement to Formation -induced Compression on 13-3/8 in. 3.1.3 Stuck 13-3/8 in. casing The difficulty in pulling 13-3/8 in. casing could affect the wellhead movement model, though evidence is not conclusive. The baseline model results assume a 13-3/8 in. casing that is not fixed between the wellhead and the top of cement at 1,810 ft. An alternative model considered the case that the 13-3/8 in. was coupled with the 20 in. near the 20 in. shoe. In both cases, an upward wellhead movement is predicted in response to a parted 20 in. casing. If the 13-3/8 in. casing is coupled with the 20 in. casing shallow, then downward force applied to the 20 in. casing would either be resisted by both strings or would cause a parting of the outer string below the depth of coupling. The latter scenario is not consistent with the observed depth of failed 20 in. casing. The former scenario would likely mute the corresponding wellhead growth. Interpretation of Well Abandonment Data Prior to making any conclusions, two complicating factors are noted: • The resistance to pulling 13-3/8 in. is not the same as a mechanical coupling of two strings. 24 feet of pipe movement was achieved with up to 450 kips of force. • The timing of the shallow interaction between the two casings is unknown. In particular, the interaction could have occurred prior to any permafrost thaw subsidence -induced loads, after the wellhead movement, or at some intermediary time and set of conditions. Because there is no way to resolve either of these complications, the observation does not provide any guidance on improvements to the model explanation for the failure sequence. 3.2 Well 04-01 Modelling of the 02-03 casing parting and subsequent wellhead movement gave insight into what could happen if subsidence -induced downhole forces were sufficient to part surface casing set within the permafrost. The model assumed that such downhole forces could exist but did not hypothesize a detailed explanation on the geomechanics. Well 04-01 did not experience such a failure scenario. The deconstruction did not show signs of significant compression in the 13-3/8 in. casing. There are no indications of 20 in. tension approaching a parting load. Observations do not alter or invalidate the model explanation for wellhead movement at wells 02-02 or 02-03. E• March 20, 2019 Via Hand Delivery Jessie Chmielowski and Daniel Seamount Commissioners Alaska Oil and Gas Conservation Commission 333 West 71h Avenue, Suite 100 Anchorage, Alaska 99501 Re: Docket Number: OTH-18-064--Application for Reconsideration Other Order 149 (00 149) Re: Mechanical Integrity of Prudhoe Bay Wells Prudhoe Bay Field Dear Commissioners: BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907)561-5111 MAR L 0 Kqq A0G,a' BP Exploration (Alaska), Inc. (BPXA), as operator of the Prudhoe Bay Unit (PBU), respectfully submits this Application for Reconsideration regarding Other Order 149 (00 149) issued on February 28, 2019. BPXA is committed to safe and reliable operations in PBU and appreciates the efforts of the Commission to better understand the causes of sudden wellhead rise on two Drillsite 2 wells. However, for the reasons discussed in this application, 00 149 contains certain requirements that BPXA may technically be unable to achieve. We therefore respectfully propose the following amendment to 00 149 so that BPXA may expeditiously complete rig intervention work on certain wells in order to further analyze the causes of the above -referenced sudden wellhead rise. Proposed Amendment of Ordered Action 1: Rig interventions are required in 2019 to recover sections of the production tubing, production casing, and outer casing, SUFfOCe ^^S1^^ ^^a 619ndtilCteF to the extent reasonably possible on at least two of the 3 -casing -string wells with 10" surface casing set in permafrost one of which must be DS 02-01A. The remaining well or wells will be determined by AOGCC in consultation with BPXA. (underlined text to be added; strikethrough text to be deleted). Application for Reconsideration Docket Number: CO -17-009 Conservation Order 736 Prudhoe Bay Field February 26, 2018 Page 2 Justification for Reconsideration As written, Ordered Action 1 may not be technically feasible and presents unnecessary risk without providing additional/useful information beyond that to be obtained via the work proposed in the above amendment. BPXA will recover sample sections of the 20" surface casing & conductor from approx 3ft below tundra grade to the well head during final excavation and abandonment. For these reasons, BPXA respectfully requests that the Commission reconsider 00 149 and amend Ordered Action 1 as proposed above. BPXA and the PBU owners share AOGCC's focus on safety and integrity of PBU wells. BPXA would welcome further discussion of the proposed modifications to 00149 to help understand and address any concerns. Sincerely, Ryan Daniel Intervention and Integrity Engineering Team Leader BP Exploration (Alaska) Inc. cc: Eric Reinbold Jon Schultz Gerry Smith Rett Tanner Dave White 19 SE March 14, 2019 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Docket Number: OTH-18-064 Other Order 149 Prudhoe Bay Field Submission of 02-02 Well Failure Investigation Report Dear Commissioners: BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907)561-5111 Via Hand Delivery W A ) BP Exploration (Alaska) Inc. (BPXA), operator of the Prudhoe Bay Unit, encloses our Investigation Report of the 02-02 well failure, in compliance with the referenced order. We have redacted employee names in the report to protect their privacy. BPXA are in the process of engaging an outside engineering firm to conduct a geotechnical review of Drillsite 2 in the Prudhoe Bay Field. The engineering firm are being asked to review and build on our modelling of the failure mechanism of the 02-02 and 02-03 wells, as well as to identify and analyse other potential factors that could have contributed to these two well failures. BPXA respectfully requests that the commission receive the enclosed Investigation Report and include it in the record for this matter. Sincerely, Doug Cismoski P.E. Wells Manager Interventions and Integrity BP Exploration (Alaska) Inc. Enclosure by V INCIDENT INVESTIGATION REPORT FS1 DS2 WELL 02 RELEASE BP Alaska - Greater Prudhoe Bay - GWO Incident Date: December 7", 2018 Investigation Start Date: December 17'", 2018 Report Issued: February 22nd, 2019 IRIS Report: 1014356 Investigation Team InvestigationPosition Name Job Title Investigation Team Leader GWO RVP Trinidad Investigation Leader S&OR CIT Lead Investigator Investigation Team Member GWO S&OR Engineering Authority Investigation Team Member Well Intervention & Integrity Mgr. Sr. WI&C Advisor Dry Trees Investigation Team Member GWO-Alaska HSE Manager Investigation Resource GWO Alaska Integrity Engineer Investigation Resource Senior Advisor Tubular Design / TA for Casing and Tubing GSI Well 2-02 Release Incident Investigation 14 March 2019 Page 1 Table of Contents 1 Executive Summary ................................................................................................4 1.1 Incident Summary ......................................................................................................................4 1.2 Investigation Summary ..............................................................................................................4 2 Background Information.........................................................................................5 2.1 Scope (refer to Appendix D for full investigation Terms of Reference) ............................. 5 2.2 Well History ................................................................................................................................. 5 3 Incident Description................................................................................................8 4 Analysis.................................................................................................................10 4.1 Movement of the Wellhead.................................................................................................... 30 4.1.1 Reason for wellhead movement...............................................................................................10 4.1.2 Inputs and assumptions............................................................................................................ 10 4.1.3 Sensitivity on parting load........................................................................................................ 11 4.1.4 Comparison to previous PBU wellhead movement analysis .................................................... 12 4.2 Reasons for hydrocarbon LOPC............................................................................................. 13 4.2.1 Failure of Wellhead/Xmas Tree Well Barrier Envelope............................................................ 13 4.2.2 Downhole Well Barrier.............................................................................................................13 4.3 Well 02-03 Incident Recommendations Action Closure.....................................................15 4.3.1 Communication between Anchorage and the North Slope Wells Team ..................................15 4.3.2 Scope of Work......................................................................... 4.3.3 Actions not systematically tracked to closure ........................ 5 Recommendations..................................................... AppendixA: Logic Tree................................................................. Appendix B: Chronology of Drill Site (DS) 02 Well 02 .............. Appendix D: Terms of Reference ................................................ 16 17 F51 Well 2-02 Releaw Incident Ineetiga0an 14 March 2019 Page 2 .....................19 ........................ 22 ........................ 27 ........................ 29 F51 Well 2-02 Releaw Incident Ineetiga0an 14 March 2019 Page 2 Table of Figures Figure 1: Well 2-02 showing McEvoy Gen 1 Wellhead 6 Figure 2: Well 2-02 Schematic 7 Figure 3: Well 2-02 post incident 8 Figure 4: Well 2-02 Impact 8 Figure 5: Hydrocarbon release point 9 Figure 6: Overview of the Wellhead Movement Model 11 Figure 7: Model Sensitivity to 20" Parting Load 12 Figure 8: Load Transfer for Casing Set Within (left) and through (right) Permafrost 13 F51 Well 2-02 Release Incident Investigation 14 March 2019 Page 3 1 Executive Summary 1.1 Incident Summary At approximately 2:00 pm on December 7th, 2018, a Prudhoe Bay Unit (PBU) pad operator conducting daily well checks discovered an uncontrolled hydrocarbon release (Loss of primary containment, or "LOPC") emitting from Well 02-02. The venting hydrocarbon caused a mist inside the wellhouse. Initial responders determined that the wellhead and tree had moved upward by 38". When the Xmas tree moved upward, it contacted the wellhouse roof, causing a bending moment at a flange connection between the wellhead tubing adapter and the lower master valve where the leak developed. The response team opened the wellhouse doors to facilitate dispersion of the gas. A temporary flowline was established from Well 02-02 to the well pad's test separator. This allowed lowering of the well's surface pressure and reduced the amount of gas venting inside the wellhouse. The wellhouse was then removed and a team tightened the bolts on the leaking flange to stop the release. The well was declared secure at 6:00am on December 1011 2018. During the incident, no people were injured, and no wildlife was harmed. The hydrocarbon release was confined to the wellhouse and no oil impacted the tundra. Spill Response Technicians estimated the crude oil release to be two US gallons (7.6 Itrs), and BP Process Safety Engineering estimates the gas release to be 241 mscf (5,776 kg) leaked from the well and 508 mscf (12,160 kg) cold vented through the well pad's separator. The total gas volume released was 749 mscf (17,936 kg). 1.2 Investigation Summary The Investigation team found the cause of the event to be the tensile failure of the 20" surface casing which allowed an upward force generated in the inner casing strings to lift the wellhead. The failure was determined to have been due to a load imparted by subsidence of the permafrost formations on the surface casing resisted by the compression of the inner casing strings. A similar failure mechanism occurred on Well 02-03 in April 2017. The investigation team determined this failure mechanism is limited to wells with a three - string casing design with the surface casing shoe set in the permafrost. Similar to the Well 02-03 event, when the Well 02-02 wellhead lifted, the Xmas tree contacted the roof of the wellhouse shelter putting a sideload on the flange connection between the lower manual valve and the tubing hanger adaptor causing the release. Contributing factors that led to the LOPC were, failure to mitigate the risk of the Xmas tree contact with the wellhouse shelter, and isolation of the reservoir with a downhole barrier subsequent to the Well 02-03 event. Both of these contributory factors resulted from a lack of clearly defined actions to address the risk specific to Well 02-02, ineffective communication between the Anchorage and North Slope Alaska Wells personnel and not using a systematic method to track actions to closure. The specific findings and recommendations are contained in Section 5 of this report. The recommendations (which have all been accepted and agreed to be actioned) include confirming that a downhole well barrier conformant with BP Practice 100222 Well Barriers (10- 65), is in place for the remaining three -string casing design wells with the surface casing set in the permafrost. F51 Well 2-02 Release Incident Investigation 14 March 2019 Page 4 2 Background Information 2.1 Scope (refer to Appendix D for full investigation Terms of Reference) The scope of the investigation is to identify the potential causes and contributing factors of the incident and prepare a report of the investigation team's findings. The report includes recommendations intended to reduce the risk of recurrence. The investigation team followed the necessary lines of inquiry, including gathering and preserving evidence, conducting interviews and performing other assessments and analysis. The Terms of Reference (ToR) included the direction to study the May 2017, Well 02-03 incident investigation report recommendations and the actions taken to meet the report recommendations. 2.2 Well History Well 02-02 was drilled by ARCO Alaska, Inc. (ARCO) June 91h through July 2911, 1970. The well is a three -string casing design with 30" conductor, 20" surface casing, 13 1/8 intermediate casing, 9 5/e" production casing and 5 1/2" production tubing. Well 02-02 was fitted with a McEvoy Generation 1 wellhead (figure 1). Before the well was completed the 13 3/e" and 9 5/a" casing collapsed due to inadequate freeze protection. In September of 1975, the collapsed casing strings were retrieved. A 13 3/s'" tie -back was run from 1,399' to surface followed by a 9 5/e" tie -back from 1,923' to surface. The well was completed with 51/2" tubing on October 15, 1975, however the 5 1/2" tubing was pulled and re -run in November 1976 prior to perforating the well in March 1977 in preparation for Production Start-up (June 1977). Other activities that were completed on Well 02-02 included The 5 1/2" tubing was pulled and re -run in 1980 — A through -tubing coiled tubing side-track from the original well bore 02-02 was completed in January 1998 (see figure 2 Wellbore Schematic) — In June 2006, a cast iron bridge plug was set in the coiled tubing liner above the perforations. The plug failed to isolate the source of the pressure during the inflow test. Shortly thereafter an inflatable bridge plug was set in the tubing tail below the production packer to isolate the pressure. This was the first in a series of attempts to isolate the production tubing from the reservoir — One week later in June 2006 the S -riser was removed and the flowline disconnected — Between June 2006 and February 2017, there had been seven different tubing plugs set to isolate the reservoir that were pulled and replaced due to them failing to meet the inflow test acceptance criteria — In February 2017 a 3'/a" Inflatable Bridge Plug (IBP) was set at 9906' Electric Line Measured Depth (ELMD). Subsequent testing demonstrated pressure build-up in the tubing above the plug — A well servicing report confirmed communication between the production tubing and the inner annulus. FS1 Well 2-02 Release Incident Investigation 14 March 2019 Page 5 Figure 1: Well 2-02 showing McEvoy Gen 1 Wellhead F61 Well 2-02 Release Incident Investigation 14 March 2019 Page 6 D52 -02A sl/r EnwnllG-NMIPa114srq — �— 9-S/a'4Yry fel an [M SYM�]59.(Mr — I})/f 4Ury felm EM Lqf p SM (Aw r a. a Jim ra r }5/r • as Y iw --rarssn- ew iw ssn•.sa'e.nlsu r.n.. }W. •ioc aa,e .� Sa[ki VURiPM an0 2U% naE wailglll wa r bapll Mu 3PLWbrI MJ'.5a5'.aN'.iaa' 90R w ` 0 `f( N IY CwYUMr11M' ism SM m ' 1. Ila [-SS `3. 3IC E(IC[aY. a93IlE' 1503 13-3/r o 15-1n'L+UY WINIVlp4 ry1O �I9p' n tlAl 5980 _.—IYMUTem i}3n.30' � 3l5plro� 1 95/r 0 025 399/r 09(aYr�IlSl' 50Ws saw 71M ffi �t9s0I�9aW tleaa'IYOS- 1925 Q390 a0 1(I[Yl a. a Jim ra r }5/r • as Y iw --rarssn- ew iw ssn•.sa'e.nlsu r.n.. }W. •ioc aa,e .� Sa[ki VURiPM an0 2U% naE wailglll wa r aL bapll Mu .-PI-Ift 90R w m 0 491 N 14tl1 ism SM m a9t 1. Ila [-SS IOGO 1503 13-3/r o M1 n tlAl 5980 26M 95/r 0 025 47 50Ws saw 71M 9.S/Y 1925 Q390 a0 Yb95 "M 4199 93/r was 9149 as SC995 2510 SOW 9.5/r 9749 11503 47 50095 9150 7150 Figure 2: Well 2-02 Schematic F51 W012-02 Release Incident Investigation 14 March 2019 Page 7 3 Incident Description At approximately 2:00pm on December 71"• 2018, a PBU pad operator conducting daily well checks discovered an uncontrolled hydrocarbon release emitting from wellhead of Flow Station IFS) 1 Drill Site IDS) 2 Well 02 (Well 02-02). The venting hydrocarbon caused a mist inside the wellhouse. The pad operator initiated a "code red" notification, and the mobilization of Tactical Responders. Initial responders determined that the wellhead and the Xmas tree had moved upwards - 38" (Figure 3). This upward movement caused the Xmas tree swab valve and work platform to contact the wellhouse roof, resulting in a side load being applied to the Xmas tree causing a leak from the flange between the wellhead tubing head adapter and the Xmas tree lower master valve. (Figure 4 & Figure 5) Figure 3: Well 2-02 post incident Figure 4: Well 2-02 Impact F51 Well 2-02 Release Incident Investigation 14 March 2019 Page 8 J Leaking area of Master Valve base Flange x Tubing Head Adapter with residual crude that was released Figure 5: Hydrocarbon release point A BP incident management team was established to manage the event. The response team opened the wellhouse doors to facilitate dissipation of the gas and gained access to the wellhouse and wellhead. A temporary flowline was established from Well 02-02 to the well pad test separator which allowed lowering of the well's surface pressure and reduced the amount of gas venting inside the wellhouse. The wellhouse was then removed, which was followed by a team tightening the bolts on the leaking connection thus stopping the release. A pressure test was conducted to verify integrity. The well was declared secure at 6:00 am on December 10", 2018 and the Incident Management Team stood down. During the incident, no people were injured, and no wildlife was harmed. The hydrocarbon release was confined to the wellhouse, and no oil impacted the tundra. Spill Response Technicians estimated the crude oil release to be two US gallons (7.6 Itrs), and BP Process Safety Engineering estimates the gas release to be 241mscf (5,776 kg) leaked from the well and 508 mscf (12,160 kg) cold vented through the well pad's separator. The total gas volume released was 749mscf (17,936 kg). Post -incident review of the inner annulus (IN pressure data (communicated via wireless telemetry to field SCADA system at approx. one data -point per minute), shows that at 10:06 pm on December 61, 2018, a spike upward in IA pressure occurred, from 566 psi to 913 psi, followed by a rapid dropoff in IA pressure. The investigation team concludes that this upward spike occurred at the moment the 5-1/2" tubing parted, and tubing x IA pressure communication was created. The parting of the tubing was caused by the wellhead's upward movement. Therefore, the loss of primary containment (LOPC) and hydrocarbon release began at 10:06 pm on Dec 6th, 16 hours earlier than the time the Pad Operator discovered the release at approximately. 2:00 pm on December 7'", 2018. The alarm set -point for the IA pressure was 2,000 psi, so no alarm registered to alert the control room operator when the upward spike to 913 psi in the IA occurred. F$1 Well 2-02 Release Incident Investigatian 14 March 2019 Page 9 4 Analysis The incident investigation was conducted in accordance with the BP Group Defined Practice (GDP) 4.4-002 Incident Investigation. The team applied the BP RCA Methodology and used the Logic Tree technique to record the analysis of facts collected in the data gathering phase of the investigation. The logic tree is provided in Appendix B of this report. The investigation team found that the incident occurred due to permafrost subsidence induced failure of the surface casing. The failure allowed upward movement of the wellhead and Xmas tree, causing contact between the swab valve on the Xmas tree and the wellhouse roof. This created a bending moment at the tubing head adapter x lower master valve flange creating a leak path at the flange (figure 5). This section provides a description of the analysis and the findings of the investigation. For ease of discussion, the analysis is grouped into 3 areas: 1. Movement of the wellhead 2. Reasons for the hydrocarbon LOPC 3. Well 02-03 Incident Recommendations Action Closure. 4.1 Movement of the Wellhead The Incident response team reported a 38" upward movement of the wellhead/Xmas tree. Evidence revealed the 20" surface casing to be parted in the pipe body in the first joint below the wellhead (visual evidence), and the 5 1/2" tubing parted —21' below the wellhead (established during wireline operations). 4.1.1 Reason for wellhead movement To explore the cause and effects of the wellhead movement a numerical model of wellhead movement was constructed. The geomechanics of the shallow permafrost formations applying a downward force on the 20" surface casing and deeper permafrost formations possibly applying an upward force on the 13 3/e" intermediate casing, is a hypothesis based on published geotechnical literature, as well as observations of the results of this force application within the oilfields of Alaska's North Slope. The parted 20" casing is evidence that the formation load was sufficient to cause a failure and the focus of the movement model is the mechanical response to that parting. 4.1.2 Inputs and assumptions The first step in the numerical model is to build the well as a system of casing and tubing connected at the wellhead. Step two applies a downward subsidence force on the 20" casing to the point of failure, resulting in compressive loading on the inner strings. The final step is to allow the inner strings to find their point of equilibrium and establish the amount of consequent upward wellhead movement. Figure 6 provides an overview of the model with the casing and tubing portrayed as springs. F51 Well 2-02 Release Incident Investigation 14 March 2019 Page 10 `X! 2 20 in. part m m m o a N m ^ 7 P T Figure 6: Overview of the Wellhead Movement Model The initial well model assumes the following strings: • 30" freestanding conductor 20" 94 ppf and 133 ppf surface casing landed on the 30" with an assumed hanging weight of 75 kips and a top of cement (TOC) of 930' 13 V workover with a patch at 1,399' and landed with 50k overpull assumed with respect to the weight of the tieback rather than the original string • 9 5/8" workover with a patch at 1,923' and landed with 250k overpull assumed with respect to the weight of the tieback rather than the original string 5 1/2" tubing hanging weight reflects the tubing only, neglecting the packer and tail pipe The 13 %" string had an initial TOC listed at 1,350' inside the 20" setting depth of 1,464'. During the workover, the 13 V was washed over to 1,418'. It is possible that there is cement from 1,418' down to a DV collar at 1,451', providing some load transfer between the 20" and 13 %" strings. The presence of this cement plug is treated as a model variable and has a minor effect on results. The schematic shows the tubing string with floating seals in a packer. There was likely no way to confirm that the seals were indeed floating. Furthermore, the parted tubing indicates that the tubing string was likely fixed downhole, whether in the packer itself or at some other location. The wellhead movement model assumes a fixed tubing seal. 4.1.3 Sensitivity on parting bad All base -line calculations assume a 20" casing parting load of 1,615 kips equal to the nominal cross-section multiplied by the minimum material tensile strength. The model without the cement plug is run with a range of assumed parting loads, illustrated by the blue line in Figure 7. The line shows an upward trend of wellhead movement increasing with the load required to part the 20" casing. Three ratings are noted on the plot: the minimum pipe body yield strength of 1,077 kips, the minimum tensile strength of 1,615 kips, and the maximum pipe body yield strength of 2,153 kips based on the cross-sectional area multiplied by the upper yield stress limit of 80 ksi for grade H40. The plot excludes thermal forces and includes only an inner annulus pressure of 513 psi. F81 Well 2-02 Release Incident Investigation 14 March 2019 Page 11 20 60 c c 50 v 40 = 30 3 9 ry 20 y a 10 WH Movement vs. 20 in. Parting Load Blue Line Relates Model Movement to 20 in. Parting Load Red Lines Translate Net 20 in. Gap to Applied Force c d E E L=930tt L=1OOft L = 500 ft l'ODO 2,000 3,000 4,000 10 in. Parting Load (kips) Figure 7: Model Sensitivity to 20" Parting Load A measurement of 47" was found between the parted sections of 20" casing. This gap is the combination of wellhead growth and casing stretch due to force on the 20" casing. For a given wellhead movement AwH, the implied 20" casing force at parting is found using equation 1. gap -Awn Flo=i (1) �gAp)zc Equation 1 has two unknowns, AWH and the unconstrained length of 20" casing, L. The relationship between the force at parting, Flo, and AwH is found for four different values of L. Those four curves are plotted in shades of red in Figure 7. The point where a particular red line intersects the blue line identifies the model wellhead growth where the parting load force equates with the implied force from post -incident measurements. Figure 7 illustrates that Well 02-02 wellhead movement fits within modelled well parameters. 4.1.4 Comparison to previous PBU wellhead movement analysis The Well 02-03 investigation report noted thirteen wells including Well 02-02 that had the same well configuration (i.e. three -string casing design with surface casing shoe set within the permafrost). Following the Well 02-03 incident investigation recommendations, other wells were analyzed for the potential of a casing failure leading to upward wellhead movement. The analysis consistently demonstrated a trend on casing configuration. Specifically, when subsidence loads are transferred solely to the wellhead, then the three -string casing failure scenario is possible. Conversely, when subsidence loads can be partially transferred to a competent formation below the base of the permafrost, then the three -string casing failure scenario is not credible. FSI Well 2-02 Release Incident Imestigation 14 March 2019 Page 12 Figure 8 illustrates the two basic configurations. The sketch on the left shows load transfer to the wellhead. If the inner strings can support a force sufficient to part the surface casing, then subsequent upward wellhead movement is possible. The sketch on the right shows the case where formation loads act on a string that extends to competent formation. In this case, subsidence loads transfer to both the wellhead and the formation, thereby reducing the potential for a parting load. formation loads permafrost base formation loads permafrost base Figure 8: Load Transfer for Casing Set Within (left) and through (right) Permafrost Finding 1: The failure mode observed on Well 02-02 is similar as that observed on Well 02- 03. The hypothesis is that a load on the 20" casing is caused by permafrost subsidence. This load caused the 20" surface casing to fail in tension below the wellhead, which then allowed the inner casing strings, production tubing and Xmas tree to move upward. 4.2 Reasons for hydrocarbon LOPC 4.2.1 Failure of Wellhead/Xmas Tree Well Barrier Envelope At the time of the Well 02-02 incident there was 12"-16" of clearance between the top of the swab valve and the wellhouse roof. As the Well 02-02 wellhead moved upward, the swab valve contacted the wellhouse roof placing a side load on the Xmas tree. This sideloading created a bending moment on the tree which resulted in the flange bolts elongating on the opposite side of the swab valve. As the bolts elongated the pressure integrity of the ring gasket was lost resulting in the LOPC. 4.2.2 Downhole Well Barrier On February 22nd, 2017, an Inflatable Bridge Plug (IBP) was set in the packer -bore to isolate the reservoir. The IBP was set at 9906' MD, with 1250 psig on the tubing and 810 psig on the inner annulus. Review of the well servicing reports indicates this was the seventh plug set over the past eleven years with the intent of isolating the reservoir. The previous plugs of differing designs had eventually failed to meet the pressure build-up acceptance criteria for 'Flow Restricted' during periodic testing. The IBP was inflow tested and the well was classified as "Flow Restricted" on February 24, 2017. In response to the Well 02-03 incident, an inflow test was started on Well 02-02 February 24, 2018 but was interrupted due to weather. The IBP was re -tested on March 7', 2018 and met the requirement of "Flow Restricted" as stated in the local practice. FS1 Well 2-02 0.elease Incident Imestgation 14 March 2019 Page 13 At 10:06 pm on December 61, 2018 the recorded pressures of the inner casing annulus shows a 347 psig upward spike in pressure (from 566 to 913 psig). The IA pressure had reduced to -200 psig when the hydrocarbon release was discovered at 02:00pm December 7", 2018. The IA pressure stabilized to -100 psig while bleeding the IA pressure during the incident response. y Well 02-02Inner Annulus Pressure(S1/1"w95/8")Trend oa.ar.a- a 7 :1 u x Iu'+e ntto.e. i t:lrle:`1' �ams.,vn rleem Figure 9: Inner Annulus (5-'/2" Production Tubing x 9'/8" Production Casing) Pressure Trend Wireline operations during the incident response confirmed the production tubing was parted at -21' Measured Depth (MD). The 'spike' in IA pressure at the time of the event most likely resulted from communication with the production tubing at the time the tubing parted. The pressure fluctuations after the event can be explained by the fluid levels in the tubing and annulus equalizing and the IBP plug moving up hole. A wireline drift run tagged at 9765' Slick Line Measurement (SLM) depth near the sliding sleeve (9775' MD) indicated the IBP had possibly moved up the hole during the event allowing additional hydrocarbon influx into the well and to pass around the plug element. Subsequent to the Well 02-03 incident and communication of the investigation findings, an emerging risk to the integrity of the wellhead primary barrier was identified by the Well 02-03 investigation team for similar wells with this three -string casing design. For Well 02-02, the primary barrier was the wellhead and Xmas tree and had the same emerging risk as Well 02- 03. The IBP restricted the flow but was not a qualified well barrier (as discussed below) that prevented flow. The investigation team was unable to identify a revised well barrier risk assessment by Alaska Wells for Well 02-02 after Well 02-03 incident taking into consideration this emerging risk. The Alaska Region Recommended Practice: Flow Restriction (AK-GWO-RP-DOC-0039) describes methods to reduce the absolute open flow potential to atmosphere from wells that have been designated as 'long term shut-in'. The installation of a qualified downhole barrier such as a mechanical plug, meeting the pressure test acceptance criteria in BP Practice 100222, Well Barriers, was not required but would have prevented a sustained release. F51 Well 2-02 Release Incident Investigation 14 March 2019 Page 14 Finding 2: In Well 02-02, the lack of reservoir isolation by a downhole well barrier was not risk assessed after the Well 02-03 event. 4.3 Well 02-03 Incident Recommendations Action Closure The investigation team reviewed the Well 02-03 recommendations to assess their adequacy in preventing a similar LOPC incident reoccurring. The Alaska Wells team had effectively addressed many of the recommendations. However, the investigation team finds the second recommendation (R2) that required the region to "assess the risk of collision damage associated with upward movement of the Xmas tree and the resultant impact on the integrity of the well barrier elements and take appropriate mitigating actions" was not adequately implemented for Well 02-02, as the wellhouse contact risk had not been mitigated. Wellhouses remained on six of the wells with the three -string casing design in December 2018 at the time of Well 02-02 incident. Of these wells, two wells (02-02 and 02-05), had tree clearance to wellhouse roof of less than 20". Through interviews and documentation review, the investigation team explored the performance shaping factors (PSF) that influenced decisions and actions made in relation to how R2 was implemented. Three main factors were identified that impacted human performance, as discussed below. 4.3.1 Communication between Anchorage and the North Slope Wells Teem In response to the Well 02-03 incident report recommendations, a 'clash risk survey' was completed in November 2017 for all PBU wells (-1780). Well 02-02 was identified as a well at risk of Xmas tree contact in the event of upward movement because it had 12"-16" of clearance between the wellhouse roof and the top of the swab valve. Based on the previous known movement of Well 02-03 wellhead that moved up three feet when its surface casing parted the clearance on Well 02-02 was insufficient. The survey was done in concert with a campaign to document wellhouse conditions on all 1,780 PBU wells to determine which wellhouses needed repair or replacement. Those individuals interviewed in the course of this investigation believed inclusion of the wells with the three -string casing design within the wider campaign potentially reduced the priority of mitigating the clash risk. Interviews with North Slope personnel also suggest that effective communication of the reasons why a priority risk existed for the three -string casing design wells was lacking. Information gathered in the 'clash risk survey' was completed by November 2017. However, the investigation team were unable to identify a specific plan to address the clash risk survey findings for Well 02-02. The lack of a clearly defined plan to mitigate the clash risk left the scope of work and the timeline for delivery open to different interpretation by the North Slope team. Action status update emails from June 41, 2018 to August 27', 2018 North Slope based and Anchorage based Wells Management were ambiguous about what work had been done or additional actions were needed to close out the recommendations. This ambiguity contributed to different interpretations of what was required to address the clash risk. Evidence from interviews indicated that Anchorage Wells Management attention to the PBU field wide well clash risk survey resulted in less communications with those in the field executing 'close out' of Well 02-03 investigation recommendations. The frequency of these F51 Well 2-02 Release Incident Investigation 14 March 2019 Page 15 communications diminished from daily to monthly and did not result in effective communication of plans and actions for this scope of work and activity prioritization. Finding 3: The risk prioritization of the work related to recommendation 2 of the Well 02-03 investigation report was not differentiated from other scopes of work due to its inclusion within the all PBU Well clash risk survey. 4.3.2 Scope of Work The Job Management System (JMS) is a database used by the Wells team to coordinate interventions activity, maintenance and some of the surface infrastructure work done by the Wells team. To address the Well 02-03 recommendations, 11 separate JMS entries were made in March 2018 to 'Evaluate clearance, Pull shelter, disconnect (DISCO) Surface pipe, Re -Set shelter including Well 02-02. This activity as it was written in the JMS system applied to all wells and did not specifically state that for Well 02-02 the shelter should be removed and left off the well to avoid the Xmas tree contact risk. In addition, the flowline was already disconnected on Well 02-02. Therefore, the JMS entry for Well 02-02 was partially incorrect. Based on evidence collected (JMS entries, North Slope Wells Team database and emails) there did not appear to be a clear well specific scope of work documented to mitigate the risk of Xmas tree contact with the wellhouse on Well 02-02. The North Slope Wells Team was not given a date to complete all the actions related to the Well 02-03 investigation. However, in June 2018 Anchorage Wells Management confirmed via an email to the North Slope Wells Team that the work on these 11 wells was a 'priority'. After this instruction, work commenced in July 2018 on the scope of work documented in the JMS for the set of wells with the three -string casing design. Based on interviews, some personnel on the North Slope believed that once the flowlines were disconnected a similar event to the Well 02-03 failure would not occur. In addition, North Slope personnel believed the reservoir was isolated and the LOPC risk was mitigated. These beliefs may have contributed to the conclusion that no further work was required on Well 02-02. The North Slope Wells Team removed the JMS entry for Well 02-02 in September 2018. The North Slope Wells Team believed that because the flowline was already disconnected from Well 02-02, it was not necessary to remove the wellhouse and the work scope was considered complete. During interviews, North Slope personnel expressed the view that leaving the well shelters in place would be beneficial to future well monitoring and P&A work. Finding 4: The actions, scope of work and activity plan to address recommendation R2 from Well 02-03 investigation report were not clearly established, nor prioritized for Well 02-02. F51 Well 2-02 Release 1 u d.t 1t .stigatim 14 Mach 2019 Page 16 4.3.3 Actions not systematically tracked to closure To understand what may have contributed to the lack of clarity and visibility of actions after the Well 02-03 incident, the investigation team explored the processes and tools used by the Alaska Wells team to manage and track actions. To manage and track activity resulting from Well 02-03 incident investigation recommendations, actions were created within the "GWO Alaska Action Tracker". These actions largely replicated the recommendations made in the report. Responsible Persons, Approvers and due dates were created for these activities. The majority of these activities were completed between Sept -Dec 2017. Actions were closed on the Action Tracker but there was no requirement to provide supporting evidence. The GWO Alaska Action Tracker did not fully reflect Well 02-03 recommendation (R2). R2 stated: "Alaska Region to assess the risk of collision damage associated with upward movement of the Xmas tree and the resultant impact on the integrity of the Well Barrier Elements and take appropriate mitigating actions." When this recommendation was transferred to the GWO Alaska Action Tracker the action read: "Evaluate options to reduce damage to well barrier elements from wells with potential for upward movement of tree/wellhead'. The second part of the investigation recommendation R2, "...and take appropriate mitigating actions." was not included in the GWO Alaska Action Tracker, nor were any actions that addressed this part of the recommendation. This more limited action to evaluate options was completed and closed in the action tracker on February 23rd, 2018. Despite this, the Alaska Wells Team appear to have understood that a further scope of work was required to mitigate the clash risk of the three -string casing design wells as evidenced by the fact that after this action was closed on the GWO Alaska Action Tracker, the North Slope Wells Team added 11 jobs to disconnect the flowlines of three -string casing design to another system used to track work fronts (the North Slope Wells Team database) at a later date the scope of work to remove the flowline from Well 02-02 was added to JMS. After the actions identified in the GWO Alaska Action tracker were closed, there was no systematic process used by the Alaska Wells team to maintain visibility to the further actions in the North Slope Wells Team database that were generated to mitigate the risk. Action status updates were shared informally via emails and conversations between the Anchorage team and the North Slope. On August 271, 2018, the North Slope Wells Team confirmed to Anchorage Wells Management "...project is complete other than some clean-up work and a few odds and ends to wrap up." Subsequent handover notes between the back-to-back individuals responsible for the work were clear that further work was required to mitigate the risk, however this was not communicated to Anchorage Wells Management. The Alaska Wells team was not using a process to prioritize the surface infrastructure work related to Well 02-03 incident recommendations other than the normal 6 Week schedule that was maintained by GWO and GOO teams on the North Slope. Once activity was removed from either the JMS or the 6 Week schedule there appears to have been an assumption that the work was complete. Based on the multiple interviews conducted as part of the investigation, it seems that the team trusted that actions were complete once that status was declared and there was no self -verification of the completed work. The IRIS record for Well 02-03 incident includes Findings and Recommendations from the investigation report but no actions were entered. The investigation team interviewed witnesses who were involved in developing actions and management of the IRIS Record, and determined that the authority, accountability and responsibility for elements of the process was not clearly defined or communicated. FS1 Well 2-02 Release Incident In a tigation 14 March 2019 Page 17 Finding 5: Once actions were stated to be closed, the part of the Wells organization that managed surface infrastructure activity, trusted that they were properly completed, and verification of that work was not performed. Finding 6: Alaska Wells team did not utilize a systematic process to maintain visibility of Well 02-03 incident investigation report recommendations and related actions. F51 Well 2-02 Release Incident Investigation 14 March 2019 Page IS 5 Recommendations The following table contains the recommendations to address the identified findings. The applicable Finding Categories and Barrier Families are referenced. Risk Event: Loss of Well Integrity: Well Operations Findings g Finding CategoryDescriptor Barrier Barrier Family Recommendations F1. The failure mode observed on Well 02- 02 is similar as that observed on Well 02-03. The hypothesis is that a load on R1. As a priority Alaska Wells to develop and implement operational the 20" casing is caused by permafrost Casing & Well WP007 mitigations for potential upward wellhead movement during subsidence. This load caused the 20" 5.C.1 Integrity future operations on the wells with three -string casing design surface casing to fail in tension below P4 with the surface casing set in the permafrost. the wellhead, which then allowed the inner casing strings, production tubing and Xmas tree to move upward. F2. In Well 02-02, the lack of reservoir 5.C.1 Well Pressure WP024 isolation by a downhole well barrier wasContainment 4.A.6 P6 R2. For the remaining three -string casing design wells with the not risk assessed after the Well 02-03 surface casing set in the permafrost, Alaska VP Wells to event. 5.C.1 document the primary and secondary well barrier envelopes. For each of these wells, confirm the existence of a downhole well barrier envelope conformant with BP Practice 100222 Well Barriers (10-65). R3. GWO VP Global Solutions to review and update BP Practice 100006 Well Integrity Management Strategy to address barrier requirement for wells that have been shut in long term. F51 Well 2-02 Release Incident Investigation 14 March 2019 Page 19 Findings Finding Barrier Barrier Recommendations Category Descriptor Family F3. The risk prioritization of the scope of 1.A.2 Clearance WPO12 work related to recommendation R2 of 1.A.4 between the P1 the Well 02-03 investigation report, Xmas Tree & was not differentiated from other 1.C2 Wellhouse Roof See R4. Below scopes of work due to its inclusion 4.F.11 within the all PBU Well clash risk survey. F4. The actions, scope of work and activity 4.F.2 Clearance WPO12 R4. GWO to implement the requirements contained in section 5.8 plan to address recommendation R2 4 F 3 between the P1 'Acting on Recommendations' of BP Practice 4.4-0002 from Well 02-03 investigation report Xmas Tree & Incident and clarify region VP Wells accountabilities for were not clearly established, nor Wellhouse Roof development of the action plan and verification of action prioritized for Well 02-02 closure. F5. Once actions were stated to be 1.A.5 Clearance WP012 closed, the part of the Wells 1 A 8 between the P1 organization that managed surface Xmas Tree & infrastructure activity, trusted that 1'D'2 Wellhouse Roof R5. Alaska Wells to implement a process to verify, with supporting they were properly completed, and evidence that surface infrastructure work has been completed verification of that work was not performed. F6. Alaska Wells team did not utilize a 2.C.2 Clearance WPO12 systematic process to maintain between the P1 R6. Alaska Wells to review and update the Anchorage Wells visibility of Well 02-03 incident Xmas Tree & Management process for tracking incident and functional investigation report recommendations Wellhouse Roof actions to closure including verification and documenting how and related actions the actions were completed with supporting evidence. NOTE: In relation to recommendations above, the investigation team will submit to the Segment Learning Lead for inclusion within the S&OR learning process, of the following possible wider learnings alongside other potential risk reduction opportunities. F51 Well 2-02 Release Incident Investigation 14 March 2019 Page 20 Interpretative note: The purpose of a BP incident investigation is to gain an understanding of the incident so that lessons can be learned from it. This report is based on the understanding of the investigation team at the relevant time. Other information may become available after the report is complete, that could affect the validity of its conclusions. Accordingly, nothing in this report should be construed as conclusively determining facts or establishing causes or legal conclusions. FS1 Well 2-02 Release Incident Investigation 14 March 2019 Page 21 Appendix A: Logic Tree. F51 Well 2-02 Release Incident Investigation 14 Match 2019 Page 22 Y A 9 5/8" casing fails increasing tension on the 20" 13 3/8 fails increasing tension on the 2131 Tubing fails increasing tension on the 20' Casing coupling fails under burs[ pressure ',- Casino couplmo fails under collapse oressure V Seismic event © Impact from hydrocarbon flow from cretaceous formation © Pressure from other wells © Hydrate Pluq release Failed below design rating lim rtsj-, Fatigue of 20" coupling LA - Permafrost subsidence applies downward force on conductor and 20" resulting in compression of tubing, 9. 5/8 and 13. 3/B casing strings. FSI Well 2-02 Release Incident Investigation 14 March 2019 Page 23 expansion of 9 5/8' and 13 3/8' 20' casing failed (production in close proximity) IfQ © Thermal cycling of 9 5/8 and 13 3/8 resulting in upward movement of neu [rel ppm[ releasing [he stored energy in the other casing- strings Annulus pressure applies force to the cross sectional areas ©Bending force on coupling' Q Tensile forces exceeded the capacity of the 2o" couolino © Impact from hydrocarbon flow from cretaceous formation © Pressure from other wells © Hydrate Pluq release Failed below design rating lim rtsj-, Fatigue of 20" coupling LA - Permafrost subsidence applies downward force on conductor and 20" resulting in compression of tubing, 9. 5/8 and 13. 3/B casing strings. FSI Well 2-02 Release Incident Investigation 14 March 2019 Page 23 eliminate risk ay LOPC a, a result of collision were not implemented elsk posed by well house was ora ravetmae idmwmp initialwellhouse loth urvey Mere was a lack a an agreed plan an meb,ate the dash nos fou we] OZ -02 _-.. V Aled(a Was TWT did net use a ayrtemMc pr¢Ws to mentor vumbility a Well 02-03 lnadent nvWb, atlm report redommeMadons and related W inannicr aro incomplete actors were entered Into the kib Mana,ament Steen (AS) fm well 02-02. agmhcardy, eeoanded m'odude emprehenuve Well ahelter enMbon 12 mdawon of Well V-02 and aimd,r three-dnng ca in, dmgn with,ri a wider campaign redcued Me onorny a asses ung and nutted., the dote V WoiMmad a Moseresponsible for eaecubng actions was hindered by adipo emmuniubon of by Mus nsli r divided1 mere was a ladle a day -today aammum.be behveen the plasm accountable for the doedre a the adorn and the berth Slope Team resomable for the work Me o There waa no reuwenent to enter reOWred for cad 02-02 M mm,ale Me r ds of elbuan WW ran develceed underYppd or a team member. k/' Ins ,s net an dtedbve Mal h manage all scenes a euAace inhaatuaMre work. Q IMS wu oat uaed efftttvNI W deliver the work sees p WBk entry (incorrectly) deeded MVM slope ham to relay well house after nowlma e disrmed p "dCachan thin rW 0 waa ,salated and flaWllnu removed Ilv McNVeleu ml(a LOK $� serrle 0 ferrel Overton Mat Mere was car, n role between swab valve n and wen had. Q Bial be prated well And horn mint and use eefladlnp u a work cded m I. future pBA M 39 F51 Well 2-02 Release Incident Investigation 14 March 2019 page 24 G51 Wei 12-02 Release Incident Investigation 14 March 2019 Page 25 J Isolated Is IBP set at 9900' failed during event resulting in release IBP set at 9900' was known not to isolate pressure prior to the 2-02 eventand was classified as 'flow Pressure source was leak in 9-5/8" 0 The Alaska Wells team considered the IBP set in Well 02-02 in Feb 2017, to be sufficient to meet requirements of Well 02-03 investigation recommendation to suspend the well Q Wrong Size or type of Plug Q Exceeded plug design pressure differential Q Tubing x Inner Annulus Communication above plug 0 Leak across packer (Element, internal seals, external seal Misinterpretation of what constituted a well barrier Thought the pi ug was a well Harrier There was a¢eptance of the known risk of LOPC Q Flow Restricted is a risk reduction status for Wells not requiring two verified barriers Flow reshiction considered to be a means to 'suspend' the well and was Q There was a lack of recognition of in conformance with Alaska the emerging risk of LOPC due to the Recommended Practice potential loss of the primary well barrier Q Well 'Suspension' is not defined in BP Practices 2-02 was not included on the list of wells to suspend F51 Well 2-02 Release Incident Investigation 14 March 2019 Page 26 Appendix B: Chronology of Drill Site (DS) 02 Well 02. Date / Time Event 15/06/1970 Well 02-02 Original Drill 15/07/1970 Well 02-03 Original Drill Well worked over cut and pull 113/8 and 9-% casing and ran new tie -back 12/09/1975 strings. 15/06/1977 Well placed on production 15/11/1980 1 Pulled tubing and re -ran 5-'/2" tubing 15/01/1998 02-02 CT Side Track 25/05/2006 Last recorded production from 02-02 04/06/2006 Set CIBP at 10776' md, Set IBP at 9,933' and in tubing tail (Long term Shut- in from this date) 12/06/2006 S -riser removed, Flowline disconnected from well 02-02 2006-2016 Multiple bleeds were done, indicating communication between T x IA and possible IBP leak 30/12/2016 02-02 CMIT-T x IA failed 4 attempts to set downhole plugs. Then set 3-% IBP at 9906' ELMD (Fop 22/02/2017 of plug at 9900' ELMD) 24/02/2017 02-02 DHD. Bled Tubing, tubing re -pressures 80 psig in 30min, Tubing and IA equalized at 340 psig 13/04/2017 Well 02-03 LOPC Incident 5/8-5/10/17 JMS entries made to "Secure Well" for 01-02, 01-04B, 01-05A, 02-04A, 02-05C, 04-02A & 04-03. 11/05/2017 Installed wireless gauges on OOA (13-3/8 x 20 annulus) 31/05/2017 Well 02-03 Incident Investigation Report Issue 15/06/2017 GWO Alaska 02-03 actions from investigation recommendations in place 07/09/2017 3 -casing string design Risk Assessment conducted (well 4-03 test case) 17/10/2017 Stakeholder (S&OR and Regional LT) Risk Assessment Review 30/11/2017 S -Riser and Tree clash / shelter survey complete (all PBU wells) 6-8 week project 11/12/2017 Well 02-03 Investigation Lesson Summary issued 23/02/2018 All 02-03 actions on GWO Alaska Action tracker shown as completed and verified closed. 24/02/2018 11 Jobs added to POP Coordinator data Base to disconnect the flow lines 09/03/2018 02-02 Tubing pressure recorded at 1130 psig, IA at 320 psig. 27/03/2018 IM conversation between POP coordinator and WIE to clarify forward plan for Well 02-02 and other 3- string casing wells 28/03/2018 POP Coordinator summary table stated: confirm XT clearance envelope to allow 36in growth POP Coordinator defines scope of work for Xmas tree collision risk. 28/03/2018 Summary table stated: confirm XT clearance envelope to allow 36" growth 28/03/2018 Well 04-03 Wellhouse Removed 29/03/2018 JMS Job submitted by WIE for Well 02-02 to: Evaluate clearance, Pull Shelter, DISCO Surface pipe, RE -Set shelter 04/04/2018 Well 04-03 Flowline Disconnected F51 Well 2-02 Release Incident Investigation 14 March 2019 Page 27 F51 Well 2-02 Release Incident Investigation 14 March 2019 Page 28 11 Jobs added to Well Work Back Log (WBL) (The WOBL is a data pull from 04/04/2018 JMS, The JMS Entries were made on 3-29-18) 05/04/2018 Well 02-03 BP Internal Presentation - Anchorage Office 15/04/2018 Surface Casing Depth Verification Project added 3 wells to project scope 15/05/2018 Plan updated to disconnect 02-02 in July WIM queries POP Coordinator on status of the 14 wells. And confirms the 05/06/2018 work is not a low priority describing the failure mode to mitigate against. 08/06/2018 FS1 field OTL request this work to be pushed out to August POP Coordinator Database entry for Well 02-02 Disconnect by GWO WTI 02/07/2018 Planner: Per [POP Coordinator], this will be OK to be left alone as is, he said he will verify that the SV being close to the roof is not an issue, I have deleted this entry 17/07/2018 Well 02-04. Disconnected flowline and re -set Wellhouse Well 02-05. Pulled wellhouse, Disconnected Production line, Reset 17/07/2018 Wellhouse. 17/07/2018 Well 02-06. Pulled wellhouse, Disconnected Production line, Reset Wellhouse Well 04-02. Pull WH, Disconnect flowline and A/L line, stage WH on edge 23/07/2018 of pad. 23/07/2018 Well 04-01. Pulled WH, Disconnected Production and A/L line. Wellhouse left on edge of pad. 08/08/2018 Well 01-05. Set Well house back on. (disconnected flowline on Jun 2nd) 20/08/2018 Well 04-05. Pulled wellhouse, Disconnected Production line POP Coordinator handover notes plan is to pull 2-02 and leave it without a 22/08/2018 well shelter 22/08/2018 POP Coord issues update to WIM confirming 'XT clearance envelope to allow 36 growth, pull shelter and demo' Well 02-02 23/08/2018 Well 01-02. Pulled WH, Disconnected Production and A/L line. Removed wellhouse. Well J-02. LTSI no flowline. Permits for wells support to remove wellhouse 24/08/2018 and disconnect. Wellhouse left on. 27/08/2018 Well 01-04 Complete. Pulled WH, Disconnected Production and A/L line. Removed wellhouse from location POP Coord. email to WIM: ...Project is complete other than some clean up 27/08/2018 work & few odds & ends to wrap up. 12/09/2018 Well 02-02 job removed from WBL (email from POP Coord attached to JMS) POP Coord handover notes: did not pull 2-02 ... rumour was there was 13/09/2018 concern about swab cap to roof clearance but don't think that is the case so no urgency to pull the WH... 06/12/2018 Well 02-02 LOPC Incident at 22.06 coincident with IA pressure spike [POP Coord.] Again, at some point the decision was made that tree to roof 11/12/2018 clearance was not a trigger to pull the WH or re -configure the tree. Wells were plugged & flowlines disco'd & were thought to be secured at that time. 12/12/2018 Issued status of 17 wells (original 14 + 3 additional). Table developed by Well Integrity Supt. F51 Well 2-02 Release Incident Investigation 14 March 2019 Page 28 Appendix D: Terms of Reference Terms of Reference for the BP Alaska 'FS1 DS2 Well 2 Release' Event Investigation BP entity GWO-Alaska Site/Location Greater Prudhoe Bay / Flow Station 1, Drill Site 2 Well 2 Date of Incident December 7, 2018 IRIS Report Number 1014356 Incident Type Tier 1 and/or Well Control Level 1 Process Safety Incident Incident Description A hydrocarbon release occurred on Greater Prudhoe Bay well at Dr/ll Site 02 from Well 02 on 7 December 2018. There were no injuries to personnel and the release consisted primarily of natural gas which dispersed to atmosphere. Initial indications of the cause indicate that the wellhead moved contacting the well shelter which resulted in a leak at a flange connection on the tree. Scope of Investigation The scope is to investigate the potential causes and contributing factors of the material release event. The investigation team shall follow all necessary lines of enquiry, including gathering physical and digital evidence, conducting interviews and performing other assessments, to do so. The response to the incident and how it was managed is not recommended to be reviewed by this investigation team. If, during the investigation there are aspects to the response that are seen to require further exploration or other observations of events/conditions not relevant but important then these should be captured as an action or passed to VP GWO Alaska to resolve in region supported by VP S&OR Alaska. Investigation Team The investigation leader and investigation team will be appointed by VP GWO Alaska with the agreement of-, VP HSE & Process Safety Engineering and_ _, VP S&OR Alaska. Investigation Role Name Job Title Investigation Leader Master Investigator Investigation Team Leader VP GWO Trinidad Investigation Team Member GWO S&OR Engineering Authority F51 Well 2-02 Release Incident Investigation 14 March 2019 Page 29 Investigation ream Member Well Intent. & Integrity Mgr. / Sr. WI&C Advisor Dry Trees Investigation Team Member GWO Alaska HSE Manager Investigation Resource GWO Alaska Integrity Engineer FSI Well 2-02 Release Incident Investigation 14 March 2019 Page 30 Investigation Timeline It is possible to complete the incident investigation within 30 days from the date of the incident but given proximity to seasonal holidays there is potential for this timing to slip and there may be a case where quality of the investigation and report take priority over this anticipated timeline. If during the investigation it becomes apparent that the report will not be issued within this anticipated timeline, the investigation leader shall inform the other signatories of this Terms of Reference in writing and proposed alternate timing. Conducting the Investigation • The investigation team shall conduct the sole BP RCA investigation of this incident in accordance with BP Practice 4.4-0002 Incident Investigation and use the BP RCA methodology. • VP GWO Alaska will source in region support for a human factor analysis as required by the Upstream HSE Incident and Action Management procedure for a Tier 1 or Well Control Level 1 event. • The investigation leader shall consult BP Legal prior to commencing the investigation and prior to issuing the final report. To preserve the legal privilege attached to the 02-03 investigation, the investigation team shall also consult with BP Legal prior to accessing any 02-03 incident material that BP has not released to the public. • In consultation with-, the investigation team should study the 02-03 report and the recommendations, and the actions taken to meet the recommendations. • The investigation team should build a chronology of events associated with the 02-02 well history as it pertains to the incident and determine if any associated activities may have been causal in the incident. • The investigation team shall identify through the investigation any possible causal factors such as changes in permafrost conditions, changes in well conditions and operation practices. The team shall recommend if further monitoring, review, or action is needed on any of the remaining well stock based on findings of this investigation. • The investigation team shall review the Action plan recommended by the Region for the remaining three -string casing design wells. • The investigation leader may appoint additional members to the investigation team or engage further expertise to support the work of the investigation team members, such as well integrity specialists or other geotechnical experts. • The investigation leader has the authority to commit costs on behalf of the entity in support of the investigation. This may include the retention of consulting expertise or services required in the conduct of the investigation. • The investigation leader shall periodically update-, VP GWO Alaska and_ _ VP S&OR Alaska. Given the timing and seasonal holidays It is expected that there will be a verbal review with- (HoF GWO),- and- prior to Christmas primarily to understand if there is a need for any urgent / immediate actions. • The investigation leader shall review a draft of the proposed findings and recommendations (i.e., recommended actions intended to reduce the risk of recurrence) with entity management (and with deployed S&OR leadership, if requested to do so), prior to the issuance of the report. The purpose of the entity review is to help identify any potential factual errors or omissions, determine applicability and authority for implementation and check that implementation of the recommendations would be consistent with applicable legal and regulatory requirements. • The investigation should test if on-going verification and monitoring activities detected a change in this well and if so, review the steps taken. If no, consider a recommendation F51 Well 2-02 Release Incident Investigation 14 March 2019 Page 31 to update the appropriate self -verification process to enable earlier detection of changes in well condition. Reporting • The investigation report shall include recommendations that are actionable by the BP entity with a bias for preventative controls (I.e. L1-3 Hierarchy of Controls). Recommendations for on-going self -verification should be made in the event lower level L4£ recommendations are made. • The investigation team may identify recommendations that are beyond the control of the entity and are more appropriate to group, segment or divisional level. • The investigation team may make recommendations on functional ownership with respect to the IRIS records as this is a cross functional incident (using the guidelines in UG 4.4-0003 Upstream Supplementary Guidance on HSSE Reporting Boundaries). • Other broader learnings may include recommendations regarding potential amendments to practices, BP Alaska LOPC barrier effectiveness, information about specific plant or broad insights or themes that point to systemic causal and contributory factors related to the incident. They are to be worked with the relevant deployed VP GWO / S&OR and Segment Learning Lead. If the investigation team submits a request to the appropriate Learning Lead under the Learning Process, that request shall be documented in the report. • Prior to issue, the investigation leader shall provide a copy of the draft investigation report for legal advice as previously discussed. • The investigation leader shall issue the investigation report to RP Alaska and GWO Head of Function. • The investigation leader shall provide copies of the investigation report to VP GWO Alaska, - VP S&OR Alaska and - HSE Manager, GWO Alaska • The report shall be labeled- and handled accordingly. • The investigation team shall collate all investigation materials and provide them to the entity who shall secure them according to the local procedure. Terms of Reference agreed on December 17, 2018 by Cascoinmeescaw . 12/18/2018 Name: - VP GWO Alaska �ESnCFiNP06ieiUE2 1271-9F2-018 Name: - VP GWO HSE & PSE oecvI•neCW WI 12/18/2018 Name.'- VP S&OR Alaska F51 Well 2-02 Release Incident Investigation 14 March 2019 Page 32 Colombie, Jody 1 (DOA) From: Rixse, Melvin G (DOA) Sent: Thursday, March 14, 2019 1:38 PM To: Daniel, Ryan Cc: Colombie, Jody J (DOA); Schwartz, Guy L (DOA); sean.mclaughlin@bp.com; Loepp, Victoria T (DOA); Worthington, Aras J; Regg, James B (DOA) Subject: RE: BPXA Request for Clarification: AOGCC Other Order 149 Ryan, AOGCC will provide written clarification guidance to BPXA on Other Order 149 after meeting with BPXA ETL for Rig Work Over, Sean McLaughlin, on Monday, March 18th. AOGCC would like to better understand from Mr. McLaughlin, the technical abilities and/or limitations for decompletion on the wells with 3 strings of casing. AOGCC may request a brief written description from BPXA why wells 01-02, 03-04, 01-05, 02-03, 02-04, 02-06, 04-02, 04-03 are unacceptable for decompletion and why wells 02-05, 04-04, 04-05, and J-02 are acceptable. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231) or (Melvin.Rixse@alaska.aov). cc. Victoria Loepp, Sean McLaughlin, Aras Worthington, Guy Schwartz, Jody Colombie, Jim Regg From: Daniel, Ryan <Ryan.Daniel@bp.com> Sent: Wednesday, March 13, 2019 11:45 AM To: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov>; Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov>; Loepp, Victoria T (DOA) <victoria.loepp@alaska.gov> Cc: Worthington, ArasJ <Aras.Worthington@bp.com> Subject: BPXA Request for Clarification: AOGCC Other Order 149 Good morning Mel, Thanks for meeting this morning to review the questions BPXA raised with respect to Other Order 149, specifically bullets 1, 5, 8 below. I have made some generalized scope notes on each bullet and request a clarification from the AOGCC Engineering Commissioner that the scope as proposed meets the literal intent of Order 149 as published. On clarification, BPXA will proceed and submit detailed sundry's for each well. Please call with any questions Other Order 149 Points for clarification: Colombie, Jody J (DOA) From: Rixse, Melvin G (DOA) Sent: Wednesday, March 13, 2019 12:44 PM To: Colombie, Jody J (DOA) Subject: FW: BPXA Request for Clarification: AOGCC Other Order 149 Jody, I presume this goes into docket OTH-18-064. Mel From: Daniel, Ryan <Ryan.Daniel@bp.com> Sent: Wednesday, March 13, 2019 11:45 AM To: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov>; Schwartz, Guy L (DOA) <guy.schwa rtz@alaska.gov>; Loepp, Victoria T (DOA) <victoria.loepp@alaska.gov> Cc: Worthington, Aras J <Aras.Worthington@bp.com> Subject: BPXA Request for Clarification: AOGCC Other Order 149 Good morning Mel, Thanks for meeting this morning to review the questions BPXA raised with respect to Other Order 149, specifically bullets 1, 5, 8 below. I have made some generalized scope notes on each bullet and request a clarification from the AOGCC Engineering Commissioner that the scope as proposed meets the literal intent of Order 149 as published. On clarification, BPXA will proceed and submit detailed sundry's for each well. Please call with any questions Other Order 149 Points for clarification: 1. Rig interventions are required in 2019 to recover production tubing, production casing, outer casing, surface casing, and conductor on at least two of the 3 -casing -string wells with 20" surface casing set in permafrost, one of which must be DS 02-02A. The remaining well or wells will be determined by AOGCC in consultation with BPXA. BPXA propose the following decompletion actions on Wells 02-02 and 04-01 (3 string wells). Contingent wells 02-05, 04-04, 04-05, and 1-02 will remain available, and will be P&A'd on successful decompletion of the target wells. o Establish well barriers in well to support decompletion o Cut and pull tubing from XYZ MD. Log ID of 9/5/8" casing ID with mutli-finger caliper or equivalent. o Cut and pull 9 5/8" casing from XYZ MD. Log ID of 13 3/8" casing ID with mutli-finger caliper or equivalent. o Cut and pull 13 3/8" casing from XYZ MD. Log ID of 20" surface casing ID with mutli-finger caliper or equivalent. o Detailed Sundry applications will be submitted accordingly for each well, along with post wellwork reports. o Note: Based on operdtional risk, and the objective of determining the surface casing condition it is not necessary or advisable to cut and pull the 20" or Conductor. Data on the condition of the SC can be acquired from inside the well using calipers or equivalent. 5. Rig interventions will be required on at least two separate wells with 2 -casing -string designs within the Prudhoe Bay Field to understand effects of wellbore surface casing subsidence. These wells will be selected by AOGCC in consultation with BPXA for inclusion in either the 2019 or 2020 P&A schedule. BPXA propose the following decompletion actions on Wells V -XYZ and L -XYZ (2 string wells). These wells may/may not be planned for P&A post decompletion but this decision would remain subject to review of the data obtained at that time. Some candidate wells may still have future utility depending on which wells are selected, and BPXA would like to retain the option to recomplete them. o Establish well barriers in well to support decompletion o Pull tubing (kill string) from XYZ MD. Log ID of 7 (or 7 5/8")" casing with mutli-finger caliper or equivalent. o Cut and pull 7 (or 7 5/8")" casing from XYZ MD. Log ID of 10 %" casing with mutli-finger caliper or equivalent. o Detailed Sundry applications will be submitted accordingly for each well, along with post wellwork reports. o Note: Based on operational risk, and the objective of determining the surface casing condition it is not necessary or advisable to cut and pull the outer string or conductor. Data on the condition of the SC can be acquired from inside the well using calipers or equivalent. In addition, these wells may not be P&A candidates and could be recompleted. 8. Previously approved sundries for the 14 wells identified with risk of failure of the surface casing on the 3 - casing -string wells are rescinded. All 14 wells must be secured with tested downhole plugs and kill weight brine to isolate the reservoir. AOGCC must be afforded the opportunity to witness these downhole plugs and reports are required upon completion of the plugging operations on each well. Additional abandonment operations will be considered after reviewing the above required decompletions of 2- and 3 - casing -string design wells. BPXA request approval to proceed on P&A well work on wells not suitable for decompletion (previous workovers) These include 01-02, 01-04, 01-05, 02-03, 02-04, 02-06, 04-02, 04-03. This leaves wells 02-05, 04- 04, 04-05, and J-02 as contingent decomplete options. BPXA also request approval to move forward on the lower cement plug (reservoir abandonment) on these contingent decomplete wells to reduce risk. Thanks Ryan Ryan J C Daniel Well Engineering Team Leader GWO Alaska Wells Integrity & Compliance BP Exploration (Alaska) Inc. Office +1907 564 5430 Mobile +1907 748 1140 '. {`rudlioc 4 PROUD v Rorwnrq Thr Post f.,bN Af A.l Fw.,. 17 •e Anchala Klein Regional Vice President, GWO February 26, 2019 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Direct 907 564 5460 Main 907 561 5111 Fax 907 564 40 14 Re: Docket Number: OTH-18-064 Anchala.Kleln@bp.com Mechanical integrity of Prudhoe Bay wells Post Hearing Submissions Dear Commissioners: BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 Via Hand Delivery A VtLJ FEB 2 6 2019 A®CCC BP Exploration (Alaska) Inc. (BPXA), operator of the Prudhoe Bay Unit, encloses the following in response to questions and requests received by us during the February 13, 2019 hearing on the referenced matter: • Report of Metallurgical Examination of 1-5-13 Casing Samples • Slides presented by BPXA's Thomas Mccarty • Slide displayed by BP during the hearing with a list of 23 wells Answers to questions received from the commission that BP was unable to answer during the hearing BPXA respectfully requests that the commission receive this filing and include it in the record for this matter. Sincerely, Anchala Klein Vice President, GWO Alaska Region Enclosures Metallurgical Examination of L5-13 Casing Samples Final Report SES Document No.: 1254670-MT-RP-01_RevO 13 September 2018 Prepared for: BP Alaska Anchorage, AK Contact. Prepared by:->��Leo V--�— ega, PE Principal Reviewed by: D. Scott Harding, PhD, PE Staff Consultant Stress Engineering Services, Inc. 13800 Westfair East Drive Houston,Texas 77041-1101 Phone: 281-955-2900 Web: www.stress.corn Texas Registered Engineering Firm F-195 SP Alaska Metallurgical Examination of 1.5-13 Casing Samples — Final Report 13 September 2018 Limitations of This Report This report is prepared for the sole benefit of the Client, and the scope is limited to matters expressly covered within the text. In preparing this report, SES has relied on information provided by the Client and, if requested by the Client, third parties. SES may not have made an independent investigation as to the accuracy or completeness of such information unless specifically requested by the Client or otherwise required. Any inaccuracy, omission, or change in the information or circumstances on which this report is based may affect the recommendations, findings, and conclusions expressed in this report. SES has prepared this report in accordance with the standard of care appropriate for competent professionals in the relevant discipline and the generally applicable industry standards. However, SES is not able to direct or control operation or maintenance of the Client's equipment or processes. Engineering Services, Inc. Page iii SES Doc. No.: 1254670 -MT -RP -01 RevO BP Alaska 13 September 2018 Metailurgical Examination of LS -13 Casing Samples — Final Report Executive Summary Stress Engineering Services, Inc. (SES) was contracted by BP Alaska to perform a metallurgical examination of the Lisburne Unit Well LS -13 casing samples that were extracted after they leaked during a Mechanical Integrity Test of the Inner Annulus (MIT -IA) on March 30, 2017. SES was asked to examine and evaluate the pipe -in -pipe casing samples removed from the well and to determine, if possible, the cause(s) of this leak. SES performed visual examination, magnetic particle testing, fractography, metallography, mechanical testing, and chemical analysis of the sample material; results of these analyses are documented in this report. On February 22, 2018, SES received a 16 -ft section of pipe -7n -pipe casing from BP Alaska that included the starting head and multiple casing sections—a 20" x 30" Insulated Conductor, a 13W' Surface Casing, a 9%" Production Casing, and a 475" tubing. The insulated conductor and cement were removed from the assembly to expose the surface casing. After a leak site was discovered on the surface casing, SES proceeded with additional cuts to expose the production casing and tubing. A second leak site was discovered on the production casing. Both of the cracks were associated with a deformed region with an appearance similar to an inward buckling or collapse. No apparent crack origins) were observed on either of the casings; however, the presence of shear lips at the external surface and secondary cracks at the internal surface indicated the fracture origins favored the internal surface. Metallurgical analyses indicated there were no apparent contributions to the crack initiation from material defects, or service related mechanisms such as corrosion or fatigue. Further, damage from drilling equipment was not indicated as a primary cause for the reported leak. The asymmetrical (one-sided) deformation (in essence, a partial collapse) observed on the surface casing and production casing is unusual in appearance and not consistent with a full collapse caused by excessive pressure in the annulus, where both sides collapse uniformly. The presence of a bulge in the 20" conductor was coincident with the inward deformation of the surface and production casing; this indicates that the acting force or pressure event occurred within the 20" X 13%" annulus. The timeline for when the bulge and inward deformation occurred could not be determined during this investigation; however, SES believes that the fractures were promoted by the observed deformation and that the fracture of the production casing (and subsequent leaks) occurred after the initial pre-test pressurization to 560 psi on or about March 26, 2017, and most likely during the MIT -IA test on March 30, 2107 when a pressure loss was observed from 2,087 psi to 104 within 17 seconds according to BP logs. In summary, an event occurred that caused an inward deformation of the surface and production casing that when pressurized, most likely during the March 30, 2017 MIT -IA pressure test, the casing cracked at two locations which led to the observed leak on March 30, 2017. Pa a tv SES Doc, No.: 1254670 -MT -RP -01 Rev0 Engineering Services, Inc. 8 RP Alaska Metallurgical Examination of LS -13 Casing Samples — Final Report 13 September 2018 Table of Contents Limitationsof This Report ................................................................................................................. ExecutiveSummary ........................................................................................................................... iii I. Background.................................................................................................................................1 iv 2. Metallurgical Examination............................................................................................................2 2.1 As -Received Sample .............. 2.2 Sectioning and Visual Examination .............. 2.3 Wet Fluorescent Magnetic Particle Testing(WFMT)..................................................................14 2.4 Fracture Surface Examination ....................... 2.5 Metallography............................................... 2.6 Tensile Tests............................................................................................................................... 19 2.7 Charpy I m pact Tests ........................................... 25 2.8 Chemical Analysis............................................................................ 25 3. Discussion..................................................................................................................................27 26 4. Conclusions...............................................................................................................................27 Appendix A: 1-5-13 Well Casing Section Detail.......................................................................... List of Tables Table 1: Longitudinal Tension Test Results................................................................................................25 Table 2: Transverse Full -Size Charpy Impact Tests (Temperature = 32 `F) ...................................... Table 3: IDES Analysis of Surface and Production Casing ................... ................................................. 26 Engineering Services, Inc. Page v SES Doc. No.: 1254670-MT-RP-01RevO OP Alaska 13 September 2018 Metallurgical Examination of LS -13 Using Samples— Final Report List of Figures Figure 1: As -received sample from the 1-5-13 well site............................................................ ................. 2 Figure 2: Ends of L5-13 sample as received with starter head (a) and cut casing/tubing ends (b). 3 Foam (F), gravel (G), and cement (C) were evident in the annuli ..................................... Figure 3: Photograph of water jet making a circumferential cut in the conductor casing at the starterhead.................................................................................................................................4 Figure 4: Views of the 20" casing after the foam was removed. Note change in diameter at approximately the mid -length and a bulged region at center [indicated by arrows and r superimposedline in(c)] ............................................................................................................ _ Figure 5: Photograph of the surface casing after the 20" casing was removed. Inward deformation I is evident on the surface casing............................................................................................ Figure 6: Photograph of the cement and mixed product inside the outer annulus nearthe bulged I region................................................................................................................................ . Figure 7: Photographs of the inwardly deformed region of the surface casing (a and b) and close- up of an approximately 15 -inch long through -wall crack (arrow in c) at a crease on the casing....................... ...................................................................... Figure 8: Close-up view of external surface of the crack on the production casing. Note the protruding communication cable at center. Numbered scale divisions are inches/cm.............8 Figure 9: Photograph of the internal surface of the surface casing showingthe crack and circumferentially oriented grooves. Grooves were also present at other locations on the 9 surface casing. Numbered scale divisions are inches/cm.................................................... Figure 10: Photographs of the internal surface of the production casing showing the crack. A few circumferentially oriented grooves were evident at this location and away from the crack. 10 Numbered scale divisions are inches...................................................................................... Figure 11: Cross-section of the production and surface casing showing inward deformation. Wall thinning on the production casing is indicated by solid arrows. The positions of the cracks 11 on the surface and production casing are indicated by dashed arrows ................................ Figure 12: Crack -like indications on external surface of the surface casing along the crease on both sides of the crack (at center of image and up to red paint marks). Reference scale is 1 foot 12 long .............................. ............................................ ........ Figure 13: WFMT indications (arrows) adjacent to the primary fracture on the external surface of 12 the production casing. Numbered scale divisions are inches ............................................ Figure 14: WFMT indications (arrows) adjacent to the primary fracture on the Internal surface of the 13 production casing. Numbered scale divisions are inches cm .................. Figure 15: Representative fractures of the surface (a) and production (b) casing. Note secondary cracks at the internal surfaces. No distinct fracture origin was apparent in either fracture. 14 Major numbered scale divisions are inches._ ........................................................... •••I••••-••. Figure 16: SEM image of the production casingfracture showing adherent deposits. Magnific..ation: 15 ......................... Engineering Services, Inc. Page vi SES Doc. No.: 1254670 -MT -RP -01 RevO BP Alaska Metallurgical Examination of LS -13 Casing Samples — Final Report 13 September 2018 Figure 17: SEM image showing cleavage in mid -wall section of the production casing fracture. Surface pitting is also evident. Magnification: 1,000X..............................................................15 Figure 18: Internal surface at the wear grooves of the surface casing showing circumferential directionality. Magnification: 100X ................. Figure 19: Fracture surface of the surface casing. Magnification:lOX......................................................17 Figure 20: Dimpled fracture at secondary cracks at the internal surface of the surface casing. Magnification: 3,000X ........................................ Figure 21: Dimpled fracture at mid -wall of the production casing. Magnification: 5,000X ...................... 79 Figure 22: Figure 23: Macro -section of surface casing showing 459 shear lips and a jagged and relatively flat fracture across the mid-section. Secondary cracks are evident at the internal and external surfaces (arrows). Scale divisions are 1/10 inch.......................................................................20 Photomicrograph of the surface casing at the internal surface showing a shallow region of plastically deformed grains (arrows) and a secondary crack adjacent (dashed arrow) to the primary fracture. Etchant: 2% Nita]; original magnification: SOX.......................................20 Figure 24: Photomicrograph at the mid -wall section of the surface casing fracture. Etchant: 2% Nital; original magnification: 50X ................. .---- .__ Figure 25: Transgranular surface cracks at the crease on the external surface of the surface casing. Etchant: 2% Nital; original magnification: SOX ...................................................... Figure 26: Macrograph of section at the crease in the surface casing opposite the primary fracture. Shallow cracks at the internal and external surfaces are indicated by arrows. Unetched; scale divisions are 1/10 inch................................................................................................. Figure 27: Macrograph of section from the production casing showing the primary fracture. Scale divisions are 1/10 inch....................................................................... ................................... Figure 28: Photomicrograph showing a typical secondary crack adjacent to the primary fracture on the production casing. Etchant: 2% Nital; original magnification: 300X .............................. Figure 29: Photomicrograph showing plastically deformed region (arrow) at the internal surface of the production casing. Etchant: 2% Nital; original magnification: 20OX.................. .21 .21 22 22 23 24 Figure 30: Photomicrograph of the mid -wall fracture region in the production casing showing faint evidence of grain elongation (arrow). Etchant: 2% Nital; original magnification: 200X...........24 Figure 31: Photomicrograph of the production casing fracture near the external surface showing faint evidence of grain elongation. Etchant: 2% Nital; original magnification: 20OX...............25 Engineering Services, Inc. Page vii SES Doc. No.: 1254670-MT- RP-01_RevO aP Alaska 13 September 2018 Metallurgical Examination of LS -13 Casing Samples —Final Report 1. Background Stress Engineering Services, Inc. (SES) was contracted by BP Alaska to perform a metallurgical examination of casing samples that were extracted from the L5-13 drill site in Alaska after a leak was discovered during a Mechanical Integrity Test of the Inner Annulus (MIT -IA) on March 30, 2017. The LS -13 well was drilled in 1984 and came on line as a producer in 1987. BP reported that this well had originally been cemented by the rig from the bottom up and that some of the cement had "fallen back" within the conductor (20" x 13%" annulus). In 2013, this well was converted to an injector well. During its service life, this well was pressure -tested on multiple occasions and passed an MIT -IA in 1984, 2012, 2013, and 2015. As mentioned, the well failed an MIT -IA on March 30, 2017. A pressure test performed approximately 4 days before that date reported that the well held a pressure of 560 psi. During the subject MIT -IA, a pressure test to approximately 2,087 psi was achieved when the internal annulus (IA) experienced a pressure loss and the outer annulus (OA) experienced a slight pressure increase from 350 to 550 psi when a leak was discovered. After a series of procedures was performed to secure the well site, including cleaning out the annulus to a depth of approximately 14 feet and pouring in a mix of materials that included lost -circulation material (LCM), the annulus was topped with 128 gallons of LockCem'" cement mix to plug the leak. Sections of casing containing the leak site were subsequently extracted from the well and shipped to SES's Metallurgical Laboratory in Houston, Texas. On February 22, 2018, SES received a section of pipe -in -pipe casing that included the starting head and casing measuring approximately 16 feet in length. The pipe -in -pipe arrangement (Appendix A) included :ES 20" x 30" Insulated Conductor, a 13%" Surface Casing, a 9%" Production Casing, and a 4h" Tubing. performed visual examination, magnetic particle testing, fractography, metallography, mechanical testing, and chemical analysis of the sample material to determine the cause of the failure. Results of SES's analyses are documented in this report. Engineering Services, Inc. Page 1 SES Doc. No.: 1254670-MT-RP-01_RevO aP Alaska Metallurgical Examination of 15-13 Casing Samples — Final Report 13 September 2018 2. Metallurgical Examination During the metallurgical investigation of the pipe -in -pipe casing samples, SES performed a series of examinations to identify the leak site(s) and to determine the mechanism(s) that led to the reported leak. The size of the samples received presented a challenge for selecting the best method to extract the pipe -In -pipe samples without disturbing potential leak sites. As a consequence, initial sectioning steps represented the most time-consuming task. The metallurgical tests are described in detail in the following sections. 2.1 As -Received Sample The LS -13 sample received at SES on February 22, 2018 is shown in Figure 1. Both ends were Sealed with plastic sheeting for added protection during transit. SES removed a portion of the plastic sheeting to expose the annuli at the cut end opposite the starting head and found that they were filled with foam, cement, or gravel. The protective covers were removed from both ends. One end included the starter head and the other consisted of the cut ends of the casing (Figure 2). Foam was observed within the 20" x 30" insulated conductor annulus. SES tested for the presence of asbestos; the results were negative. Figure 1: As -received sample from the LS -13 well site. Engineering Services, Inc. Page 2 SES Doc. No.: 1254670-MT-RP-01Rmo BP Alaska 13 September 2018 Metallurgical Examination of LS -13 Casing Samples — Final Report (a) (b) Figure 2: Ends of LS -13 sample as received with starter head (a) and cut casing/tubing ends (b). Foam (F), gravel (G), and cement (C) were evident in the annuli. Doc. No.: 1254670-MT-RP-Ol_RevO Engineering Services, Inc. Page 3 SES BP Alaska Metallurgical Examination of L5-13 Casing Samples — Final Report 13 September 2018 2.2 Sectioning and visual Examination SES reviewed options for removing the insulated conductor and casing material from the sample assembly. Given the flammability of the foam, it was determined that flame -cutting was not feasible. SES decided to employ a high-pressure water jet (hydroblast) cutting method to remove the 20" x 30" insulated conductor casing. Water jetting was first used to make a circumferential cut at the starter head (Figure 3) followed by two longitudinal sections to split the conductor casing in half. These longitudinal cuts were placed diametrically opposite to each other to enable removal of the 30" casing to expose the foam. Once the foam was removed, the 20" casing was observed to vary in diameter. Near the starter head, the diameter was the nominal 20" diameter that transitioned to the larger diameter along the mid -length of the sample (Figure 4). A slight bulge was also evident at approximately two-thirds of the length from the starter head. A second set of circumferential and longitudinal cuts removed the 20" casing, which exposed the cement within the conductor/surface casing annulus. Removal of the cement within the annulus revealed an asymmetrical, inwardly deformed surface casing (Figure 5). The annulus material at the deformed region contained material other than cement, including yellow ribbon tape (Figure 6). The material was consistent with the reported LCM and LockCe MTM material used to repair the leak. After the cement was removed, the entire inwardly deformed region on the surface casing was revealed. Its length was approximately 7 feet. A longitudinally oriented, through -wall crack measuring approximately 15 inches was evident along one of the creased sides (Figure 7). Figure 3: Photograph of water jet making a circumferential cut in the conductor casing at the starter head. Engineering Services, Inc. Page 4 SES Doc, No.: 1254670-MT-RP.01 RevO 3P Alaska 13 September 2018 Metallurgical Examination of L5-13 Casing Samples - Final Report 41 LU (c) Figure 4: Views of the 20" casing after the foam was removed. Nate change in diameter at approximately the mid -length and a bulged region at center [indicated by arrows and superimposed line in (c)]. Pae 5 SES Doc. No.: 1254670 -M7 -RP -01 Revo Engineering Services, Inc. g BP Alaska Metallurgical Examination of LS -13 Casing Samples — Final Report 13 September 2018 Figure 5: Photograph of the surface casing after the 20" casing was removed. Inward deformation is evident on the surface casing. Figure 6: Photograph of the cement and mixed product inside the outer annulus near the bulged region. Engineering Services, Inc. Page 6 SES Doc. No.: 1254670-M7-RP-01_RevO BP Alaska 13 September 2018 Metallurgical Examination of 1.5-13 Casing Samples— Final Report (a) 2 O'1 Figure 7: Photographs of the inwardly deformed region of the surface casing (a and b) and close-up of an approximately 15 -inch long through -wall crack (arrow in c) at a crease on the casing. Engineering Services, Inc. Page 7 SES Doc. No.: 1254670 -M7 -RP -01 Revo BP Alaska Metallurgical Examination of L5-13 Casing Samples — Final Report 13 September 2018 The area surrounding the longitudinal crack on the surface casing was cleaned and examined using wet fluorescent magnetic -particle testing (WFMT) methods. The results of this inspection are documented in Section 2.3. SES sectioned the casing samples to provide manageable sizes for subsequent examination. As such, the casing was flame -cut approximately 5 feet below the starter head. The remaining section containing the inwardly deformed region of the surface casing was sectioned into three approximately equal pieces using a band saw while maintaining sample orientation. Each of the three sections was then split longitudinally to expose the inside pipe -in -pipe arrangement for subsequent examination. Following these cuts, the cement was removed to reveal the production casing. A second through -wall crack measuring approximately 12 inches was observed on the production casing (Figure 8) at approximately the same elevation as the crack on the surface casing. A coaxial communication cable protruded through the crack on the production casing. No cracks were evident on the tubing. Figure 8: Close-up view of external surface of the crack on the production casing. Note the protruding communication cable at center. Numbered scale divisions are inches/cm. The internal and external surfaces of the split surface and production casing were cleaned with water, dried, and visually examined. The internal surface of the surface casing exhibited a series of shallow, intermittently spaced, and circumferentially oriented grooves. A representative view of these marks is shown in Figure 9. The low spots on the grooves indicated a directional pattern (such as may have been formed by a rotating tool) while the high spots appeared typical for the internal surface of casing that had been in service. No evidence of pitting or wall thinning was observed. Engineering Services, Inc. Page 8 SES Doc. No.: 1254670 -MT -RP -01 RevO BP Alaska 13 September 2018 Metallurgical Examination of 1.5-13 Casing Samples—Final Report Figure 9: Photograph of the internal surface of the surface casing showing the crack ano cirCnmrererrua•ir oriented grooves. Grooves were also present at other locations on the surface casing. Numbered scale divisions are inches/cm. The internal surface of the production casing exhibited a slight pattern of shallow grooving (Figure 10) near the crack in addition to longitudinally oriented wear patterns that thinned the wall. oto uoc.im.. .��+.••�•• Services, Inc. Page 9 BP Alaska Metallurgical Examination of LS -13 Casing Samples — Final Report 13 September 2018 r� STRESS Metallurgical Laboratory ��28ENGINEERING www.stress.com 13800WastlalrEastDrlve -SERVICES INC. 11a1 - TX 77oat 291-9955-2900 Figure 10: Photographs f the internal surface of the production casing showing the crack. A few circumferentially oriented grooves were evident at this location and away from the crack. Numbered scale divisions are inches. The external surface of the surface and production casing were examined and found to be unremarkable. A cross-sectional view of the production and surface casing is shown in Figure 11. This cross-section shows the position of the surface casing with respect to the production casing to indicate the asymmetrical inward deformation of about half of the circumference while the opposite side retained its original circular shape. Wall thinning, as previously noted, was evident at two locations on the internal surface of the production casing. These thinned areas corresponded to longitudinal wear patterns, which suggested that they were introduced by a logging tool. Engineering services, Inc. Page 10 SES Doc. No.: 1254670 -MT -RP -01 RevO BP Alaska 13 September 2018 Metallurgical Examination of L5-13 Casing Samples- Final Report Figure 11: Cross-section of the production and surface casing showing inward deformation. Wall thinning on the production casing is indicated by solid arrows. The positions of the cracks on the surface and production casing are indicated by dashed arrows. 2,3 Wet Fluorescent Magnetic Particle Testing (WFMT) WFMT was performed to further document cracking observed on the surface and production casing samples. The internal and external surfaces of the surface and production casing were cleaned to remove surface residue. Examination of the external surface of the surface casing revealed crack -like indications on both sides of the crease; these indications extended approximately 1 to 1% feet from the ends of the through -wall crack (Figure 12, red brackets). The internal surface also exhibited crack-like indications, althougho 10 h hey did not extend the full length of the crease. These indications extended approximately es on either side of the crack. WFMT was also performed on the circumferential grooves on the internal surface of the surface casing, but no crack -like indications were evident. Engineering Services, Inc. Page 11 SES Doc. No.: 1254670-MT-RP-01_RevO SP Alaska Metallurgical Examination of LS -13 Casing Samples- Final Report 13 September 2018 rigure 12: Crack -like indications on external surface of the surface casing along the crease on both sides of the crack (at center of image and up to red paint marks). Reference scale Is 1 foot long. WFMT was also used to examine the areas adjacent to the crack on both the internal and external surfaces of the production casing. Only a few crack -like indications were present on the external surface; these were confined to an area of about 3 inches on each side of the leak site (Figure 13). On the internal surface, crack -like indications extended approximately 6 inches on both ends of the crack (Figure 14). Figure 13: WFMT indications (arrows) adjacent to the primary fracture on the external surface of the production casing. Numbered scale divisions are Inches. Engineering Services, Inc. Page 12 SES Doc. No.: 1254670-MT-RP-01RevO SP Alaska 13 September 2018 Metallurgical Examination of 1-5-13 Casing samples —Final Report a�' _ Figure 14: WFMT Indications (arrows) adjacent to the primary fracture on the internal surface of the production casing. Numbered scale divisions are inches/cm. 2.4 Fracture Surface Examination SES sectioned the cracks in the surface and production casing at each end to remove the fractures for visual and scanning electron microscopy (SEM) examination. Both fractures shared similar features, which included secondary cracks at irregular edges of the primary fractures, shear lips at the internal and external surfaces, and evidence of necking (localized wall thinning) at the external surfaces. Between the shear lips, the fractures exhibited either flat, textured, or in some areas a "woody" appearance. No distinct fracture origin was apparent in either fracture. A representative fracture surfaces from the surface and production casing, respectively, is shown in Figure 15. The fracture on the surfcecasin was longer (approximately 15 inches) than the fracture on the production casing (approximately 12 inches). The fracture on the production casing was oxidized, but contained fewer adherent deposits as compared to the fracture on the surface casing. Engineering Services, Inc. Page 13 SES Doc. No.: 1254670 -MT -RP -01 RevO BP Alaska Metallurgical Examination of L5-13 Casing Samples—Final Report 13 September 2018 Idl (b) Figure 15: Representative fractures of the surface (a) and production (b) casing. Note secondary cracks at the internal surfaces. No distinct fracture origin was apparent in either fracture. Major numbered scale divisions are inches. SES selected a representative section from each fracture for SEM examination. The sample from the production casing was notably oxidized with few distinguishable features (Figure 16); however, one area near the mid -wall section revealed cleavage fracture (Figure 17), a common brittle fracture appearance. This brittle appearance combined with shear lips at the internal and external surfaces suggest that the material was near its transition (most likely cold) temperature when fracture occurred. Corrosion of the fracture and surface deposits on the fracture indicated post-fracture oxidation and contamination. Engineering Services, Inc. Page 14 SES Doc. No.: 1254670,MT-RP-01RevO BP Alaska 13 September 2018 .......w —eo-al F.amination of LS -13 Casing Samples -Final Report View field: 60 32 mm Det BSt ue 054' V I—.,Strese Engineering Services, Inc SEM HV. 20.00 kV Date(m/d/y) Figure 16: SEM Image of the production casing fracture showing adherent deposits. Magnification: SX. Vlew nese: au o p... --------- Stress Engineering Services, mc. = SEM HV 20.00 kV Date(m/d/y): 05/22J18 Figure 17: SEM image showing cleavage in mid -wall section of the production casing fracture. Surface pitting is also evident. Magnification: 1,000X. Engineering Services, Inc. Page 15 SES Doc. No.: 1254670-MT-RP-01RevO SP Alaska pcal Examination of L5-13 [asin — Final 13 September 2018 Close-up imaging of the circumferential wear patterns at the internal surface revealed that these were formed circumferential shear loading of the surface (Figure 18). SEM HV: 20.00 kV ouV Pm Date(m/d/y): 05/22/18 Stress Engineering Services, Inc Figure 18: internal surface at the wear grooves of the surface casing showing circumferential directionality. Magnification: 100X. The fracture details on the production casing revealed a dimpled structure throughout the fracture surface. Figure 19 shows an overall view of the fracture while Figure 20 and Figure 21 show dimples at secondary cracks on the internal surface and mid -wall, respectively. The presence of shear lips and dimple fracture on the production casing, by comparison to the observed shear and cleavage of the surface casing, indicates fracture of the production casing was likely above the transition temperature of the material. No apparent crack initiation(s) were observed on either of the casings' fractures; however, the extent of shear lips at the external surface and secondary cracks at the internal surface indicates the fracture origins favored the internal surface. Engineering Services, Inc, Page 16 SES Doc. No.: 1254670-MT-RP-01_RevO BP Alaska Of Viewfield: 30.16 mm Det SE Detector 0111151 Stress Engineering Services, Inc. SEM HV: 20.00 kV Date(m/d/y): 05/22/16 Figure 19: Fracture surface of the surface casing. Magnification: 10X. Engineering Services, Inc. Page 17 SES Doc. No.: 1254670-MT-gP-01NevO BP Alaska of LS -13 Casing Samples —Final Report 13 September 2018 _._ r,.. _-1. .. u =Ior 20 pm _ SEM HV: 20,00 kV Date(m/d/y): 05/22r18 Stress Engineering Services, Inc G Figure 20: Dimpled fracture at secondary cracks at the internal surface of the surface casing. Magnification: 3,000X. Engineering Services, Inc. Page 36 SES Doc. No,; 1254670-M1'-RP-OS_RevO BP Alaska 13 September 2018 Metallurgical Examination of L5-13 Casing Samples — Final Report View field: 60.32 pm SEM HV: 20.00 kV PJ 4_41..',.:x.-/; 7D: 25.06 mm Det: SE Detector Date(m/d/y): 05/22/16 10 pm Stress Engineering Services, Inc. Figure 21: Dimpled fracture at mid -wall of the production casing. Magnification: 5,000X. 2.5 Metallography SES selected representative areas and performed metallography on the surface and production casing fractures and at a location approximately 180° from the fracture on the surface casing. A macroscopic view of the section containing the surface casing fracture is shown in Figure 22. This cross-section shows shear lips exiting at the internal and external surfaces along with a relatively jagged and flat fracture across the mid-section. Surface irregularity due to light pitting is more prominent at the external surface. Plastic deformation and several shallow secondary cracks near the primary fracture were observed at the internal surface (Figure 23). The mid -wall showed relatively few and shallow areas of plastic deformation at the fracture (Figure 24). Shallow cracks (Figure 25) were evident at the crease in addition to general surface pitting. Similar surface cracks were observed on the creased region approximately 180' from the primary fracture area (Figure 26). Engineering Services, Inc. Page 19 SES Doc. No.: 1254670-MT-RP-01RevO BP Alaska Metallurgical Examination of LS -13 Casing Samples - Final Report 13 September 2018 rigule «: macro -section of surface casing showing 45° shear lips and a jagged and relatively flat fracture across the mid-section. Secondary cracks are evident at the internal and external surfaces (arrows). Scale divisions are 1/10 inch. Figure 23: Photomicrograph of the surface casing at the internal surface showing a shallow region of plastically deformed grains (arrows) and a secondary crack adjacent (dashed arrow) to the primary fracture. Etchant: 2% Nital; original magnification: SOX. Engineering Services, Inc. Page 20 SES Doc. No.: 1254670-MT-RP-01-Revo BP Alaska 13 September 2018 cvamination of LS -13 Casing Samples—Final Report Figure 24: photomicrograph at the mid -wall m 8^ fcaYon550X �e casing fracture. Etchant: 2%Nital; original of the Figure 25: Transgranular surface cracks at the crease on the external surface of the surface casing. Etchant: 2% Nital; original magnification: 50X. Engineering Services, Inc. Page 21 SES Doc. No.: 1254670 -MT -RP -01 RevO BP Alaska Examination of LS -13 Casing Samples — Final 13 "re"'se in the surface Opposite fracture. Shallow cracks at the internal and external surfaces are indicated by arrows. Unetchedt scale divhe isions are 1/10 inch. A macro section of the production casing fracture is shown in Figure 27. The section shows that the primary fracture exhibits features similar to those described for the surface casing, including shear lips and an irregular mid -wall fracture appearance. Cracks at the internal surface are evident near the primary fracture and surface pitting is more prominent at the external surface. - - --- —e• ter•WI 3C uvn rrom cne production casing showing the primary fracture. Scale divisions are 1/10 inch. itress Engineering Services, Inc. Page 22 SES Doc. No.: 1254670-MT-RP-01Rev0 BP Alaska 13 September 2018 Metallurgical Examination of 1 i-13 Casing Samples — Final Report Evidence of plastic deformation typical of material overload was observed at the internal surface of the production casing in addition to secondary cracks (Figure 28) that were visible to the unaided eye during visual inspection. Shallow areas of material deformation (adiabatic shear) at the internal surface were also noted (Figure 29); this type of feature is typical of intimate contact with another object such as a downhole tool. The fracture surface and crack at the external surface also exhibited areas of plastic deformation (Figure 30 and Figure 31, respectively). Both fractures displayed some level of post-fracture pitting resulting from exposure to the downhole environment. Similarly, both casing samples examined exhibited a tempered martensitic structure. Figure 28: Photomicrograph showing atypical secondary crack adjacent to the primary fracture on the production casing. Etchant: 2% Nital; original magnification: 100x. Pa a 23 SES Doc. No.: 1254670-MT-RP-01_RevO Engineering Services, Inc. g BP Alaska Metallurgical Examination of LS -13 Casing Samples —Final Report 13 September 2018 Figure 29: Photomicrograph showing plastically deformed region (arrow) at the internal surface of the production casing. Etchant: 2% Nital; original magnification: 200X. 100 pm .....- Figure 30: Photomicrograph of the mid -wall fracture region in the production casing showing faint evidence of grain elongation (arrow). Etchant: 2% Nital; original magnification: 200X. Engineering Services, Inc. Page 24 SES Doc. No.: 1254670 -MT -RP -0I RevO Be Alaska 13 September 2018 Metallurgical Examination of 15-13 Casing Samples —Final Report Figure 31: Photomicrograph of the production casing fracture near the external surface showing faint evidence of grain elongation. Etchant: 2% Nital; original magnification: 200X. 2.6 Tensile Tests Longitudinal tensile tests were performed on 1A -inch wide reduced section specimens machined from representative samples obtained from the surface and production casings. The specimens were removed from remote areas that displayed material deformation. Test results (Table 1) indicated that the surface and production casings exhibited satisfactory yield strength, tensile strength, and elongation as compared to the specified requirements of API SCT grades N80 and L80, respectively. Table 1: Longitudinal Tension Test Results Surface Casing 87.8 102 31.6 AN 5CT N80 81-110 100 min 19 min Production Casing 88.2 108.3 32.4 API SCT L80 80-95 I 93 min 20 min [11 1'k" wide reduced section; 121 at 96 total extension 2.7 charpy Impact Tests Full-size impact tests were performed at 32 'F on three representative transverse specimens each from the surface and production casings. The surface and production casing's average impact toughness of 41 Page 25 SES Doc. No., 1254670 -MT -RP -01 RevO Engineering Services, Inc. g RP Alaska Metallurgical Examination of LS -13 Casing Samples — Final Report 13 September 2018 ft -Ib and 28 ftlb for the surface and production casings, respectively, were found to be satisfactory with respect to the requirements of API 5CT grades N80 and L80 (Table 2), respectively. Table 2: Transverse Full -Size Charpy Impact Tests (Temperature = 32 °F) Surface Impact Energy (ft -lb) Casing Shear Area (%) Production Impact Energy (ft -lb) Casing Shear Area(%) API 5CT N80 API 5CT L80 2.8 Chemical Analysis 42 39 41 41 95 95 100 96 28 28 28 28 100 100 100 100 Minimum absorbed impact energy =17 ft -lb Minimum shear area = 75% Minimum absorbed impact energy =15 ft lb Minimum shear area = 75% Representative specimens from the surface and production casings were analyzed for elemental composition via optical emission spectroscopy (OES). The chemical analysis results met the requirements of API SCT grade L80 (Table 3). Table 3: OES Analysis of Surface and Production Casine �Io 'cywr ernent Engineering Services, Inc. Page 26 SES Doc. No.: 1254670 -MT -RP -01 Revo BP Alaska 13 September 2018 Metallurgical Examination of L5-13 casing Samples— Final Report 3. Discussion SES's investigation determined that the event(s) that led to the leak was not associated with deficiencies in metallurgical properties, material or manufacturing related flaws, or damage mechanisms such as fatigue, corrosion, or other environmentally -assisted cracking mechanisms. The leaks occurred in areas where the casing had previously been inwardly deformed by an unknown event. The cracks (leak paths) were a subsequent response to the pressure event that caused the casings to fracture due to overload. Overload in this context relates to material overload and not over -pressurization of an otherwise sound and undeformed casing. Given the accounts of the events leading up to the failed MIT -IA test, it appears that the IA pressure of up to 2,087 psi initiated the fracture of the production casing. As a result, a pressure drop in the IA caused a pressure increase in the OA when the test fluid (diesel) leaked into the OA. The pre-existing deformed region of the surface casing was subsequently overloaded, thus leading to its fracture. Both cracks were located at approximately the same and elevation and exhibited nearly identical fracture characteristics. A subtle distinction in fracture appearance was noted during SEM examination— cleavage fracture was observed at the mid -wall section of the surface casing as compared to dimple rupture at the mid -wall of the production casing. This difference indicated that the surface casing was more intimate with a colder surface when fracture occurred as compared to a relatively warmer surface on the production casing or greater plastic constraint. A bulge was noted in the 20" conductor casing that corresponded to the partial inward deformation of both the surface and production casing. It is apparent that a pressure or force within the 20" X 13'%" annulus exceeded the collapse pressure of the surface casing and (by intimate contact) the collapse pressure of the production casing, while also exceedingthe yield strength of the 20" conductor casing. The collapse resistance of 13%" N80 casing with a wall thickness of 0.514 inch is 2,670 psi per API Technical Report 50/60 10400:2007, Table Ll. Material specifications for the 20" casing were not provided; however, per the same API specification, the yield strength for an open-ended 20" pipe body with 0.500 inch wall thickness ranges between 2,400 to 2,840 psi. Therefore, the predicted collapse resistance and yield range are approximately the same, which supports the reported observations of a simultaneous collapse/bulge event. 4. Conclusions Based on the analyses completed during this project, SES concluded the following: 1. The leaks occurred at two fractures, one on the surface casing and one on the production casing. The location where the leaks occurred was coincident with inwardly deformed regions of both of these casings. 8 Engineering Services, nc. Page 27 SES Doc. No.: 1254670 -MT -RP -O3 Rev0 I 8P Alaska Metallurgical Examination of LS -13 Casing Samples —Final Report 13 September 2018 2. Swelling or bulging of the 20 -inch conductor was evident at the same location where the inwardly deformed casing occurred. A notable bulge was more pronounced near the location where the leak occurred. AN Technical Report SC3/ISO 10400:2007 indicates that the collapse resistance and yield strength of this casing are approximately the same, thus supporting this observation. 3. The inward collapse of the casings was asymmetrical with the sides of the casing opposite the collapse remaining relatively intact as a semicircle. In SES's experience, casing collapse usually impacts both sides of the affected casing collapse in a symmetrical manner, i.e., collapse on both sides of the casing. In such collapse cases, it is also common for the collapsed region to extend the full length of the casing joint. In the LS -13 casing samples, the asymmetrical "collapse" was localized to a region approximately 7 feet long. The deformed area on the production casing was also within the deformed region of the surface casing. The localized and asymmetric deformation appears to have been caused by an event that imparted a localized internal force at the 20" x 13%" annulus rather than from a sudden change in internal pressure that would have created an unstable event that would have led to a full, symmetric collapse. 4. Although partially obscured by post-fracture deposits and oxidation, the appearance of the fractures in both casings was similar. Both samples displayed secondary cracks at the internal surface with plastic deformation (shear lips) at the internal and external surfaces as well as relatively flat fractures at the mid -wall. These features are consistent with an overload fracture that occurred on collapsed material (such as that for a pressure test). One such pressure event reportedly occurred during the March 30, 2017 MIT -IA test when the IA lost pressure at 2,090 psi. S. Mechanical tests and chemical analysis results of the surface and production casing material were within the specified material requirements. Engineering Services, Inc. Page 28 SES Doc.N 11254670 -MT -RP -01 Rev0 BP Alaska 13 September 2018 Metallurgical Examination of 15-13 Casing Samples — Final Report Appendix A: 1.5-13 Well Casing Section Detail Engineering Services, Inc. Page 29 SES DOC. No.: 1254670-M7-RP-01—RevO OP Alaska Metallurgical Examination of LS -13 Casing Samples - Final Report 13 September 2018 All annuli filled with 15.9 Ib/gal Glass G cement. except for 20" x 30" Insulated conductor. Total estimated weigh = 3000 - 4500 lbs Pipe failures on 9-5/8" and 13-3/8" x 30" Insulated Conductor 13-3/8" Surface Casing 72# N-80 ID 12.347' 9-5/8" Production Casing 47# L-80 ID 8.681" 4-112" Tubing 12.64 L-80 ID 3.958" Engineering Services, Inc. Page 30 SES Doc. No.: 1254670-MT-RP-01_RevO Presentation to AI am L.4�ti'~�:- Gas 07 -February -2019 • PBU Well 02-03 Investigation Findings— relevance to 02-02 • Early PBU Well Design —02-02 and 02-03 • Wellhead Movement model global —r.. ....... by The sequence of upward wellhead movement and contact between the Xmastree and well house caused a loss of primary containment F1 When Well 02-03's Xmas tree and wellhead suddenly moved upwards, the pressure gauge on the top of the &riser collided with the well house roof and the gauge assembly sheared off causing the upper LOPC F2 When Well 02-03's Xmas tree and wellhead suddenly moved upwards, the swab valve handle impacted the well house structure imparting a side loading on the tubing head adaptor upper flange. Asa result, the flange studs stretched causing the lower LOPC F3 Permafrost subsidence imparted a downward load on the 30" conductor and 20"surface casing string of Well 02-03: a) causing the 20" casing to fail below the wellhead; and b) allowing the internal casing strings, production tubing, the wellhead, and the Xmastree to move upwards. ":.....,e... ,,,,,,,,,,,,,,, Loss of primary containment required both wellhead movement and contact between the Xmas tree and well house Leak on S-risa post incident with I\r plug 6tted(Upper teak) - s. �.10 Hydrate around kak sde on fi.,e between the tubing head adaptor and the Xmas tree lower master valve lbower teak) 02-03 Range Leak Figure 2: keM pp � 02-03 SRser by Figure 4: Well]01 Impact 02-02 9Nab valve 5 02-03 and 02-02 have a three -string casing design with surface casing set within the permafrost Permafrost melt causesformation subsidence that applies a downward force on the surface casing The applied force could result in a parted 20" (parting is unlikely with a two -string casing design) The inner casing strings are in compression to counter the subsidence force If the 20, parts, then the inner stringswill the wellhead up �io�'� NEetian relieve compression by pushing 9mplified Schematicfor 02-03 30" conductor at 115 ft 20" surface casing at 1,219 ft base of permafrost 13-3/8" casing at 2,688 ft 9-51F at 10,809 ft deep sidetrack not shown II I subsdenee by formation loads permafrost base formation loads permafrost base The surface casing depth affects the amount of force applied at the wellhead For the small subset of wells with casing set within the permafrost, subsidence forces return to the wellhead For casing set beneath the permafrost, subsidence forces are distributed between the wellhead and the formation below permafrost For the same subsidence force, setting the surface casing beneath the permafrost results in less wellhead loads sWO =a by Seel slightly stretches with applied force, like a very stiff spring Initial string tensions post -construction. When two or more strings are coupled together, an applied force on one string is balanced by forces applied to the other string(s). Sringsbuild compression due to heating Permafrost subsidence applies downward force on 20", pulling wellhead down 20" parts, allowing inner stringsto push wellhead up Wellhead growth is dependent on two primary variablesfree length of the 20in and the parting force of the 20in casing WallO woelMlon unt1. c a aaw nhfata v.oe�ame 2. nimit %lnOd9axV 1,24111118 WRoute 10 Illvsxabon of Axial Load on Well 2 03 global wells mJnnizntion wNl0nyro0Yt110n ••�• axu nvonea 4. wall ax 1-d-, r--'— LAW - calms Dslum WRoute 10 Illvsxabon of Axial Load on Well 2 03 global wells mJnnizntion The preliminary findings indicate the failure mechanism in 02-02 wassimilar to 02-03 02-02 has a similar 3 string casing design with the surface casing set in the permafrost. The models developed for 02-03, were used as a starting point for 02-02 9milar to 02-03, neither pressure nor thermal loads could generate a 20" axial force sufficient to part the casing on well 02-02 Upper limitsfor pressure loadswere estimated from formation pressures Thermal loading was considered from production in adjacent wells The model predicts 20" casing failure prior to inner string yield or budding The parting load for 20" casing washalf of the yield strength of the combined 13-3/8", 9-5/8" and 5-1/2" inner casings. The sequence of permafrost subsidence causing a parted 20" and subsequent upward wellhead movement fits the model initially developed after 02-03. WO s�oeei wen, o.nen�zeeion by �, . �_ 1 1<> The resultant upward movement in the wellhead after 20" casing failure can be modelled 70 Dependent on multiple variables including the parting 60 load and the free length of the 20in casing E 50 E Sensitivities for both temperature and pressure effects o 40 i were also investigated. 3 30 02-02 wellhead movement does fit within reasonable 20 well parameters. :110 0' n WH Movement vs. 20 in. Parting Load Blue Line Relates Model Movement to 20 in. Parting Load Red Lines Translate Net 20 in. Gap to Applied Force L = 300 ft L=500ft 1,000 2,000 3.000 4,000 20 in. Parting Load (kips) Model Sensitivity to 20 in. Parting Load W plabnl wells w9FlnizFltfon _„ �....��. ' In well 02-02, a gap of 47 inches was measured between the parted sections of 20" casing. The difference between the measured gap and the estimated upward movement is the amount of casing stretch at the time of failure The applied force corresponding to this stretch is on the order of 1,000 to 2,000 kips, depending on model assumptions 38 inch upward movement Inner 13-3/8" casing --. • Upper 20" piece } 47 inch gap • Lower 20" casing I iu by To: Alaska Oil and Gas Conservation Commission From: BP Exploration (Alaska), PBU Operator on February 7, 2019 Wells with Surface Casing Shoe in Permafrost SC Depth (ft SC Size Flowline Wellhouse Well Name MD) (inches) Disconnected? Removed? Notes Identified following the DS02 03 incident in 2017 1 01-02 698 20 y y 2 01-04 1508 20 y y 3 01-05 1216 20 y y 4 02-02 1464 20 y y 5 02-03 1219 20 N/A N/A P&A in 2018 6 02-04 1207 20 y y 7 02-05 1205 20 y y 8 02-06 1223 20 y y 9 04-01 1184 20 y y 10 04-02 1191 20 y y 11 04-03 914 20 y y 12 04-04 1158 20 y y 13 04-05 964 20 y y 14 1-02 938 Identified follnwino rho ..,nn -1 20 y --..... y 22 F-04 2000 18 5/8 y y 23 01-03 1950 20 y y * Excludes Observation Wells ** SC size for these wells reference gravel string &p 928 1793 133/8 13 3/8 l V y No y No Reservoir P&A in Sep 2018 2 casing strin well 973 20 No No 20x13, 13x9 fully cememted 562 13 3/8 No No 2 casing string well; gravel string * 1879 13 3/8 No Nc 2 casin stripell;gravel strin 1310 13 3/S No2 casin strip well;ravelstrg 1309 133/8 No No 2 casin strin well; ravel strip Added as a nrprautinn d::o to cr ek^....,,.,:_:---- 22 F-04 2000 18 5/8 y y 23 01-03 1950 20 y y * Excludes Observation Wells ** SC size for these wells reference gravel string &p 2017 List of Three Casing String Wells Well SC Depth SC Size Name (ft MD (inches) Notes 1 01-02 698 20 SC Shoe above base of permafrost 2 01-04 1508 20 SC Shoe above base of permafrost 3 01-05 1216 20 SC Shoe above base of permafrost 4 02-02 1464 20 SC Shoe above base of permafrost 5 02-03 1219 20 SC Shoe above base of permafrost 6 02-04 1207 20 ISC Shoe above base of permafrost 7 02-05 1205 20 SC Shoe above base of permafrost 8 02-06 1223 20 SC Shoe above base of permafrost 9 04-01 1184 20 SC Shoe above base of permafrost 10 04-02 1191 20 SC Shoe above base of permafrost 11 04-03 914 20 SC Shoe above base of permafrost 12 04-04 1188 20 SC Shoe above base of permafrost 13 04-05 964 20 SC Shoe above base of permafrost 14 J-02 938 20 SC Shoe above base of permafrost 15 01-03 1950 20 In 2017, labeled well as the SC shoe below BPF 16 B-01 2308 20 SC shoe below base of permafrost 17 B-04 2274 20 SC shoe below base of permafrost 18 D-01 2447 20 SC shoe below base of permafrost 19 D-04 2298 20 SC shoe below base of permafrost 20 D-05 2317 20 SC shoe below base of permafrost 21 F-Ol 2304 20 SC shoe below base of permafrost 22 N-01 2088 20 SC shoe below base of permafrost 23 C-03 1 2524 185/8 SC shoe below base of permafrost BPXA POST HEARING SUBMISSION RESPONSE TO COMMISSION'S FOLLOW-UP QUESTIONS FEBRUARY 13, 2019, HEARING OTH-18-64 BP Exploration (Alaska) Inc. (BPXA) submits the following to the Alaska Oil and Gas Conservation Commission (AOGCC) in response to requests for information received from AOGCC staff. How many wells had workovers to repair casing damage prior to field startup in 1977? 30 wells were found to have casing damage requiring RWO activities to repair prior to field startup in April 1977, based on BP's review of AOGCC records. Please see Attachment 1 for the list of wells. How many Non -rig P&A's have been completed since 2017 with an AOGCC waiver or variance? Would a rig have been necessary to complete those P&A's without a variance? Following is a list of these wells and BP's comments: 3: In relation to BP's written submission, topic 5.4 (What criteria are used for accepting diagnostic test results when a well exhibits sustained casing pressure?), what are the criteria used to determine operability of wells with Sustained Casing Pressure (SCP)? The criteria for accepting diagnostic test results and determining operability of injector wells with SCP are addressed in the applicable Administrative Approvals under the Area Injection Order, which can be unique for each well. The Administrative Approval for an individual well dictates the specific requirements for operability. Wells not meeting the requirements of the Administrative Approval are made not operable and shut-in. Determining operability of production wells with SCP is generally limited to wells with annulus pressure build up rates less than 285psi/day. This rate is calculated based off the wells most active repressurization state, be it online, BP Response to AOGCC Follow-up Questions February 26, 2019 Page 1 Reservoir Surface Cement? Rig necessary to complete Well Abandonment? 20 AAC 25.112(d) P&A without a variance? 20 AAC 25.112(c) 02-03 Variance No variance No 15-13 Variance No variance No 18-34 Variance No variance No 18-25 Variance No variance No 3: In relation to BP's written submission, topic 5.4 (What criteria are used for accepting diagnostic test results when a well exhibits sustained casing pressure?), what are the criteria used to determine operability of wells with Sustained Casing Pressure (SCP)? The criteria for accepting diagnostic test results and determining operability of injector wells with SCP are addressed in the applicable Administrative Approvals under the Area Injection Order, which can be unique for each well. The Administrative Approval for an individual well dictates the specific requirements for operability. Wells not meeting the requirements of the Administrative Approval are made not operable and shut-in. Determining operability of production wells with SCP is generally limited to wells with annulus pressure build up rates less than 285psi/day. This rate is calculated based off the wells most active repressurization state, be it online, BP Response to AOGCC Follow-up Questions February 26, 2019 Page 1 offline, upon well startup or shut-in. Exceptions to the buildup rate threshold exist on some wells where the repressurization stops prior to the annulus reaching the normal operating limit. Wells not meeting these requirements are made not operable and shut-in. 4: BPXA to provide a copy of the L5-13 metallurgical report. Please see report provided with this submission. 5: BPXA to provide a copy of the material used in the oral testimony presentations. Please see Material provided with this submission. BP Response to AOGCC Follow-up Questions February 26, 2019 Page 2 Attachment 1: AOGCC Peamd Num FpInnal . Sw Name - Well Name 107011 PBST01 PRUDHOE BAY STATE NO 01 1OB087 PR271111 PUT RIVER 27 -II -14 189093 J-02 PUT RIVER 10-11-13 189057 NKUPST NORTH KUPARUI( STATE O 01 189078 M41 DRILLPAD M NO 01 109082 01-01 DRILLSITE OI NO 01 IWO" PR1B1015 PUT RIVER 18-10-15 16807 J -02A DRILLPAD J NO 02A (AKA J O MRD) IMM SEEILEEW2 SOUTHEAST EILEEN STATE 002 169119 0142 DRILLSITE01 NO 02 188121 D41 MLLPAD D NO 01 170005 D03mitt.PAD D NO 03 170006 DA5 DRILLPAD O NO 05(AUa BP 2411-1]) 170018 0103 DRILLSITE 01 O03 170M01 DRILLSITE 01 O01 III= 170028 02-0241 DRILLSITE 02 NO 01 170035 02-02 DRILLSITE 02 O 02 17070 0145 DRILLSITE OI O OSST 170011 0241 DRILLSITE 02003 +70012 0141 DRILLSITE 02 01 1700500245 NO M DRILLSITE 02 NO OS 11765N42 65 DRILLPAD N 002 170058 F42 F42 DRILLPADF 002 111002 F4A DRILLPAD F NO 01 171001 4 DRILLPAD N O 01 171009 F. F6 DRILLPAD F O 171012 F48 DRILLPAD F O W OB 171013 DRILIPAD NO 08 171018 W 03 PAD H O03 DRILLH 173011 C0 Cos oRluvAo c NO os In ."I, using an prior m Nem BP Response to AOGCC Follow-up Questions Page 3 M b -0O.tglit RWO pspa[e roN wdk a'rorv(reeailg oil one mW" Imm 8521 (11131. Nid Imubk Wll(12 W5) dads t ka (1X3), sweepmp ]" co6apne 2130' R103, c pee arc rR' x 3' peva mNapp Nom 9(1-88'. <o0apx hm 271-383', ddbpee Irm 3b-315', apR Irm179SEO-ITa:1Mht ® 1168 81 7 -018O OAO81) Y8" cV G BBPDcalapaed cW Q 12 1� (121151. bad apps ®t120' It1/t6), poxmle split ®1200-1201'. spN 8 egg slupN 0 1432.1440'tlw slants poasNk Nokf�10]�0- 482' Possiek Iwles and 1510 1531- caOePsedB(ti/22 WBee D Ipa rn, 0. w010 Bow 1xt. aadeace a damage M PmEu<Ipn1 �.,�. eHw.ered It vt]l101" 111/68-1131188 RST mi&tl brougd coNpsetl camp ham W3'to 611' and a dadn"a ed Ban 8111' 1011)g. Aft., Dinh Slem Txt N6, bak p &5IB' February 26, 2019 16 Rixse, Melvin G (DOA) From: Rixse, Melvin G (DOA) Sent: Thursday, February 21, 2019 10:19 AM To: Hibbert, Michael; Sternicki, Oliver R Cc: 'Daniel, Ryan'; Guy L Schwartz (DOA) (guy.schwartz@alaska.gov); James B Regg (DOA) (jim.regg@alaska.gov); Worthington, Aras J; Jody 1 Colombie (DOA) Qody.colo mbie@ alaska.gov) Subject: FW: 3 String P & A's and DS 2-02A Status Michael, Oliver, Please seethe email AOGCC (Guy Schwartz) sent to Ryan Daniel and Aras Worthington last week. This may have not formally made it around to you. BPXA has approval to set reservoir plugs, displace tubing and annuli to 9.8 KWF, and pressure test the tubing and annuli against the plugs and production packer for all 12 remaining wells with 3 string casing designs. Wells include: 01-02, 01-04, 01-05, 02-04, 02-05, 02-06, 04-01, 04-02, 04-03, 04-04, 04-05, J-02. BPXA has approval to set a balanced cement plug, not to exceed 2000' MD in length across the reservoir (or adjacent to the reservoir), in the above wells where the reservoir plug cannot pass a pressure test. The remainder of the abandonment on the approved sundries for the 12 wells is postponed until the AOGCC Commissioners' Ruling on Docket OTH-18-064 is provided to BPXA. Also, as stated below, DS02-02 final cementing within the existing surface casing will be postponed until the final Ruling on Docket OTH-18-064. It is the intent of AOGCC to secure the reservoir, but to not limit the ability to perform forensic work (to be determined in 0TH -18-064) on subsidence induced failure. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 fomarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231) or (Melvin Rixse@alaska.aov). cc. Docket 0TH -18-064, Ryan Daniel, Guy Schwartz, Jim Regg, Aras Worthington, Jody Colombie From: Schwartz, Guy L (DOA) Sent: Thursday, February 14, 2019 11:08 AM To: aras.worthington@bp.com; Daniel, Ryan <Ryan.Daniel@bp.com> Cc: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov>; Regg, James B (DOA) <jim.regg@alaska.gov> Subject: 3 String P & A's and DS 2-02A Status Aras/Ryan: Following the hearing yesterday the AOGCC is strongly considering requiring the rig de -completion of at least two 3 - string wells on the P & A list (AOGCC Order OTH-18-062) Based on where DS2-02A is currently with a cement cap at 2300 ft and (tubing x IA) this well would be our first choice for a rig de -complete in order to better understand the dynamic forces acting on the inner strings. Also this would provide additional data to help validate the BP's current stress model for 3 -String completions. In order to facilitate a Rig de -completion the final surface plug on D52 -02A is postponed until further notice from the AOGCC. The other wells on the P &A list may continue operations under the approved sundries up to the point where a tested reservoir plug is in place and KWF is loaded in the well. Any additional cement plugs in DS 2-05 are also suspended until further notice from the AOGCC. Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending if to you, contact Guy Schwartz at (907-793-1226) or (Guv.schwartz@alaska.gov). 15 Colornbie, Jody J (DOA) From: Rixse, Melvin G (DOA) Sent: Tuesday, February 19, 2019 10:56 AM To: Colombie, Jody J (DOA) Subject: FW: AOGCC hearing OTH-18-064 BPXA follow-up question Jody, I answered these questions from BP casually last Friday. Now that I think about it, this probably needs to go into the docket. Can you confirm? Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 N to you, contact Mel Rixse at (907-793-1231) or (Melvin.Rixse(aalaska.aov). From: Rixse, Melvin G (DOA) Sent: Friday, February 15, 2019 6:22 PM To:'Sternicki, Oliver R' <Oliver.Sternicki@bp.com> Cc: Guy L Schwartz (DOA) (guy.schwartz@alaska.gov) <guy.schwartz@alaska.gov> Subject: RE: AOGCC hearing OTH-18-064 BPXA follow-up question Oliver, Answers below. Is this question limited to the group of wells with casing set in permafrost? No Is this question limited to 2 string casing designs? No Is this question limited to 3 string casing designs? No Is this all wells drilled prior to field startup in 1977? Yes Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231) or (Melvin.RixseCalalaska.F: I. From: Sternicki, Oliver R <Oliver.Sternicki@bp.com> Sent: Friday, February 15, 2019 6:11 PM To: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov> Subject: Re: AOGCC hearing OTH-18-064 BPXA follow-up question Mel, No, he has not responded yet. I was going to give him a call on Monday since I didn't hear from him today. Thanks, Oliver Get Outlook for i05 From: Rixse, Melvin G (DOA) <melvin.rixsec@alaska.gov> Sent: Friday, February 15, 2019 16:26 To: Sternicki, Oliver R Subject: RE: AOGCC hearing OTH-18-064 BPXA follow-up question Oliver, Did Guy Schwartz answer these question for you? Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231) or (Melvin.RizsePalaska.gov). From: Sternicki, Oliver R <Oliver.Sternicki@bp.com> Sent: Thursday, February 14, 2019 12:23 PM To: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov> Subject: AOGCC hearing OTH-18-064 BPXA follow-up question Mel, I'm standing in for Ryan while he is on vacation the next few weeks and will be coordinating the response to the follow- up questions agreed to at the end of the yesterdays hearing. We need some clarification on a question posed by Commissioner Foerster. The question posed was: How many wells had workovers to repair damage prior to field start-up in 1977? Clarification questions: Is this question limited to the group of wells with casing set in permafrost? Is this question limited to 2 string casing designs? Is this question limited to 3 string casing designs? Is this all wells drilled prior to field startup in 1977? Let me know if you need more context to my clarification request. Regards, Oliver Sternicki WO Well Integrity Engineer BID Exploration Alaska Office: 1 (907) 564 4301 Cell: 1 (907) 350 0759 of Iver. stern icki(a)bp. com 14 1113/1019 R 0. WQU YI OWECH CALIN MWWOFMR HOEBAYWELLS O kaHo.OTH- ALASKA OIL AND GAS CONSERVATION COMMISSION In the Matter of the Inquiry into the ) Mechanical Integrity of Prudhoe Bay ) Wells Operated by BP Exploration ) Alaska, Incorporated. ) Docket No.: 0TH 18-064 VOLUME II PUBLIC HEARING February 13, 2019 10:00 o'clock a.m. BEFORE: Hollis French Daniel T. Seamount Cathy Foerster Cowmen M to < LLC Phoma: 90'1-243-0 135 Gnstma m., Ste. 2., Anch, AIC 99501 F. 90]-243-14]3 Enm& sehik@u i.nn AOGCC V13!1019 FFMO.MQMYB OM4ECHAMCA lI GRFFYOFPRMHOEBAYW LLS Docket W OTHA64 Page 9 1 1 TABLE OF CONTENTS 2 Opening remarks by Chairman French 10 3 Remarks by Ms. Klein 14 4 Remarks by Mr. Cismoski 20 5 Remarks by Mr. McCarty 33 6 Remarks by Mr. Daniel 59 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CoMWer MM LLC Phone: 901-W-06 6 8 135 Chriemnen Dc, Ste. 1., And AK 99501 Fe , 907443-1473 E.iI sehilefto net AO C 3/132019 ITMO: INQOIRYINTOM4ECHAMCALINTEGMWOFPRODHOEBAYW LLS Docket No. OTH-O& Page 10 1 P R O C E E D I N G S 2 (On record) 3 CHAIRMAN FRENCH: It's 10:00 o'clock, I'll call 4 the hearing to order. It's February 13, 2019. We're 5 at 333 West Seventh Avenue, Anchorage, Alaska, this is 6 the headquarters of the Alaska Oil and Gas Conservation 7 Commission. To my right is Commissioner Cathy 8 Foerster, to my left is Commissioner Dan Seamount, I'm 9 Hollis French, I'm the Chair of the Commission. 10 We're here today on docket number 0TH 18-064 11 regarding the mechanical integrity of Prudhoe Bay 12 wells. The Oil and Gas Conservation Commission, AOGCC, 13 on its own motion has set this hearing to assess the 14 mechanical integrity of Prudhoe Bay wells operated by 15 BP Exploration Alaska, Incorporated. This is a 16 continuation of the February 7, 2019 hearing. 17 Computer Matrix will be recording the 18 proceedings, you can get a copy of the transcript from 19 Computer Matrix Reporting. 20 There's a sign -in sheet upon which many, many 21 people have indicated their presence and their interest 22 in testifying. As I sit here and look at the page 23 right now I see one, two, three, people signed up to 24 testify although there may be someone online that wants 25 to testify. Cor wer Ma LLC Phots:%7-243-0608 135 Cklal n Dr., Ste. 2., Anck AR 99501 F. 909-243-1473 F.I. sehik(dgci.nn AOGCC LIM019 ITMOINQMYWOWECHANICALINTEGR OFPRODHOEBAYN LS Docks No. 0TH -W Page 11 1 Does that seem right to the people here, three 2 people to testify? 3 MS. KLEIN: Four. 4 CHAIRMAN FRENCH: Oh, I beg your pardon. I 5 missed a -- oh, I see you. Beg your pardon, yeah. 6 Four people to testify all on behalf of BP. 7 During the hearing the Commissioners will ask 8 questions. We may also take a recess to consult with 9 staff to determine whether additional information or 10 clarifying questions are necessary. If a member of the 11 audience has a question that he or she feels should be 12 asked please submit that question in writing to Jody, 13 the person who came up a few minutes ago and we 14 discussed the time, she will provide the question to 15 the Commissioners and if we feel that asking the 16 question will assist us in making our determinations we 17 will ask it. 18 For those testifying please keep in mind that 19 you must speak into the microphone for those in the 20 audience and the court reporter to hear you. The main 21 point is to touch the little button that turns the mic 22 on so that you see a green light. If you don't see a 23 green light you're not broadcasting. Before you begin 24 speaking just look and see if the green light's on on 25 the mic, that's the most common problem. Please CoMuta M nx, LLC Phone: 907-203-0668 135 Chcia.n Dc, Ste. 2., Asch. AK 99501 Fax: 901-203-1073 F=il: eahileftdnet AOGCC 2/132019 RMO. WQOIRYIMOWECHAMCALI GMWOFPROHHOE BAY WELLS M&O W. OTH Page 12 1 remember to reference your slides so that someone 2 reading the public record can follow along. For 3 example refer to slides by their numbers if numbered or 4 by their titles if they are not numbered. 5 We have a few ground rules and mainly it's 6 that, you know, your testimony should be relevant to 7 the purpose of the hearing. If it strays off topic we 8 may ask you to get back on topic. Please don't testify 9 in the form of cross examination, the three of us will 10 be the ones asking the questions. And finally 11 testimony -- I can't imagine this happening so I'm just 12 not even going to say it. 13 Anything to add for the good of the order? 14 (No comments) 15 CHAIRMAN FRENCH: I don't hear or see anything. 16 I'll now swear in the witnesses. Why don't you 17 all four come in, I'll swear you all in at once. 18 Whoever -- I'll let you go in the order you wish to go. 19 When you begin testifying I'll -- you know, you've been 20 sworn in, but we'll stop when you first testify tell me 21 do you want to be recognized as an expert, if you do 22 we'll do a little inquiry into that, you know, in what 23 field and then we'll go on. 24 Just have a seat. Thanks. Raise your right 25 hands. Computer Matrix, LLC Phone: 907.2434/568 135 C im.. Or., Ste 2., Anch. AK 99501 F. 907-243-1473 Emmil: s de@,i.nn ao6Cc 2/13/2019 UMO-WQMY1 OWECHAMCALINIYGBFFYOFFKUDHOEBAYWELL" D ka No -OM -064 Page 13 1 1 (Oath administered) 2 IN UNISON: Yes. 3 CHAIRMAN FRENCH: All affirmative responses. 4 I'll turn it over to you. Who's going to go first? 5 MS. KLEIN: I will. 6 CHAIRMAN FRENCH: Yes, ma'am. And for the 7 record please state your name, spell your last name. 8 MS. KLEIN: Sure. So my name is Anchala Klein. 9 I am the VP for wells for BP. My name's spelled A -N -C- 10 H -A -L-A R -A -M -A -S -A -M -Y, my middle name, Klein, K -L -E- 11 I -N. 12 CHAIRMAN FRENCH: Okay. And, Ms. Klein, do you 13 want to be recognized today as an expert? 14 MS. KLEIN: I do not. 15 CHAIRMAN FRENCH: And will you be opening the 16 proceeding? 17 MS. KLEIN: I will. 18 CHAIRMAN FRENCH: Let's just go to that and 19 then we'll take up the question of the expertise of the 20 other witnesses as we get to them. 21 MS. KLEIN: Sure. Yeah. 22 CHAIRMAN FRENCH: Please proceed. 23 ANCHALA KLEIN 24 previously sworn, called as a witness of behalf of BP 25 Exploration Alaska, Incorporated, testified as follows Computer Matrix, LLC phone:907-243-0668 135 Christman Dr., SM 2., Anuh. AK 99501 Fax. 907-243-1473 Email: sehile(e�gci.na AOGCC 3/13/3019 I O: MQUMYMTOWECHAMCA 1. EGMWOFPRUDHOEBAYW Wi Docket N , MH -0 Page 14 1 on: 2 DIRECT EXAMINATION 3 MS. KLEIN: Good morning, Chair French, 4 Commissioners and AOGCC staff. My name's Anchala Klein 5 as I just stated and I am..... 6 CHAIRMAN FRENCH: Can you bring the mic a 7 little closer to your..... 8 MS. KLEIN: Certainly. How's that? 9 CHAIRMAN FRENCH: Better. Thanks so much. 10 MS. KLEIN: Okay. I am the BP Exploration 11 Alaska vice president for wells. 12 BP appreciates the opportunity to appear and 13 speak to the Commission about the integrity of our 14 Prudhoe Bay wells. Last Thursday we heard Commissioner 15 Seamount say that this was -- hearing's very important 16 to the AOGCC and I would like to add that it's also 17 very important to BP that we are here. 18 BP has provided written responses to the 19 questions received from the Commission and we're happy 20 to answer any additional questions that the Commission 21 may have about the information or the submission that 22 we provided. 23 I'm joined here by a team of BP experts that 24 will be testifying with me. Doug Cismoski, BP Alaska 25 wells manager for interventions and integrity. Doug Cmiputer Metrix, LLC Phm, 901-243-0666 135 Christman Dr., Ste. 2., Anch. A 99501 Fax 90]-3A3-14]3 Email. sahile*ci.iwt AOGCC 2/13/2019 I O: INQUIRYI OM4ECHAMCA WEGMR OFPRUDHOEBAYt LLS Docks No. 0TH " 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Page 15 will review the results of BP's assessment of the sudden wellhead rise risk and actions BP has taken to address this risk. Thomas McCarty. Thomas is BP global wells engineering authority. Thomas will address the causes and contributing factors for the two well incidents on drill site 2. And Ryan Daniel. Ryan is BP Alaska's wells integrity and compliance team leader. Ryan will address BP science management and the impacts on integrity at Prudhoe Bay. The recent drill site 2, well 2 incident occurred on December the 7th, 2018. The well was offline at the time and as we've reported, hydrocarbons vented inside the wellhouse, no people were injured, no wildlife was harm and no oil impacted the tundra. Well 2-02 had been shut-in prior to the event, the flowline had been disconnected and a well plug had been set. CHAIRMAN FRENCH: And I'm not going to interrupt your very often, but can you just remind me when that well was shut-in? MS. KLEIN: That well was shut-in in 2006, but we have..... CHAIRMAN FRENCH: later..... We'll talk about it more CoWutu Metrix, LLC Phone: 90]-W4 S 135 Chriaemen Dr, Ste, 2., AMh AK 99501 F. 9W-243-1473 Email: eehilefgci ce 2n3no19 IT 0, MHOEBAYW LL3 Docket N. =-064 Page 16 1 1 MS. KLEIN: Sure. 2 CHAIRMAN FRENCH: .....just a general 3 reference. Please proceed. 4 MS. KLEIN: This well was one of a small number 5 of wells identified by BP with a three casing string 6 design and a well construction to the 2-03 well that 7 failed in 2017. 8 CHAIRMAN FRENCH: And what was the month of the 9 2017 incident, if you have it handy? 10 MS. KLEIN: It was April, 2017. 11 CHAIRMAN FRENCH: April, 2017. Thank you. 12 MS. KLEIN: An investigation was launched after 13 the 2-02 incident, the most recent incident, and is 14 currently ongoing. However BP's preliminary review is 15 that one, the failure mechanism for both wells was 16 similar and two, the actions taken weren't sufficient 17 to prevent reoccurrence. 18 My colleagues and the written test submission 19 will be -- that's been provided will provide for the 20 details. 21 BP does regret this outcome and has and will 22 take additional steps to prevent any further 23 reoccurrence. This includes the remaining wells that 24 were constructed in a similar fashion have remained 25 shut-in and their flowlines and wellhouses removed to C.Wwe wtnn LLC Phone: 90-/-243-0666 135 MO.. a, Ste. 2., M,h, A 99501 Fe%: 907-243-1473 F il: eehile4ei.Mt AO C 2/13/2019 1IMO-INQMYM OM4ECHAMCALMTEGB OFMMHOEBAYWELLS Docket No. 0T -064 Page 17 1 prevent a loss of primary containment. These wells are 2 monitored daily. Plans are being immediately 3 progressed and approvals are being sought to plug and 4 abandon these remaining wells. BP Alaska proposed to 5 plug and abandon an additional four wells with 6 similarities to 2-02 in 2020. And an independent, 7 geotechnical study has been commissioned on drill site 8 2. 9 BP Alaska does have an active well integrity 10 and subsidence monitoring program. And although the 11 failure mechanisms seen on 2-02 is limited to a small 12 group of wells with a specific design we are still 13 learning about subsidence in Prudhoe Bay. 14 I'll now hand over to our team of BP experts to 15 talk about the two well events at drill site 2, the 16 actions BP has taken to address the risk and its 17 subsidence management and well integrity at Prudhoe 18 Bay. 19 Thank you, Chair, and Commissioners. And if 20 permissible I'd like to hand over to Doug Cismoski to 21 review the results of BP's assessments of the sudden 22 wellhead rise risk and actions BP has taken to reduce 23 this risk. 24 CHAIRMAN FRENCH: Mr. Cismoski, good morning. 25 MR. CISMOSKI: Good morning. Carn,mmee Mmnx, LLC Phone: 901-243-0668 135 Chrietemen Dr., Ste. 2., M h. AK 99501 Fac 901-243-1413 Email: s ile@gci. net AOGCC NIM019 ITMO: WQOIRYI OWECH CALIWEGR OFPRUDHOEBAYWELLS Docket Tb. DTH - Page 18 1 CHAIRMAN FRENCH: Would you like to be 2 recognized as an expert? 3 MR. CISMOSKI: I would like to be recognized as 4 an expert witness representing BP Alaska. 5 CHAIRMAN FRENCH: And in what field or what 6 subject if you understand my question. 7 MR. CISMOSKI: Yes, sir. I'm a 44 year Alaska 8 resident and a BP Alaska wells manager for 9 interventions and integrity. My responsibilities 10 include the operation and engineering of..... 11 CHAIRMAN FRENCH: If you could, we -- I don't 12 want to interrupt you, but just tell me what field, do 13 you want to be recognized as a wells manager or -- you 14 see my question. Sorry. I just..... 15 MR. CISMOSKI: I'd like to be recognized as an 16 expert in the field of well interventions, well 17 integrity engineering and well operations. 18 CHAIRMAN FRENCH: We'll consider that. Please 19 tell us your resume. Go ahead. Thank you. 20 MR. CISMOSKI: Being a 44 year Alaska resident 21 and BP Alaska wells manager for intervention and 22 integrity. Our responsibilities include the operation 23 and engineering of non -rig related well work, well 24 integrity and well support activity at Prudhoe Bay. I 25 hold a bachelor of science degree in mechanical CoMuter Metria, LLC Plmne: 907-243U 135 C3niatersen a., Ste. 2., Anch. AK 99501 F. 907-243-1473 Email: mittle(@pt net 10(A(- &13W9 LIMO-INQMYIN OM4ECH CAL EGR OFMMHOEBAYW LM Oockn No. OT -064 Page 19 1 engineering from the University of Colorado, I have 26 2 years of post graduate industry experience in the 3 design and execution of well enhancement and repair 4 activity. I've worked for ARCO and BP Alaska for my 5 entire career with 12 years in the field being onsite 6 in the planning and execution of well work. 7 Specifically I have experience in service work and 8 slick line, electric line, coil tubing and pumping 9 equipment. I'm also a registered professional 10 petroleum engineer, license number 10696 with the state 11 of Alaska since 2002. 12 I respectfully request that the Commission 13 recognize me as an expert witness in this field of 14 interventions, integrity engineering operations in 15 these proceedings. 16 CHAIRMAN FRENCH: I'm going to take -- I'm 17 going to repeat what you just said as a motion and I 18 will just say for the record I just said what you said 19 is -- you understand my -- you understand the motion? 20 (No comments) 21 CHAIRMAN FRENCH: Is there any objection to Mr. 22 Cismoski being recognized as an expert in the fields he 23 just -- he just listed? 24 COMMISSIONER FOERSTER: I have none. 25 CHAIRMAN FRENCH: Commissioner Seamount. Cou user Minix LLC Phone: 90]-243 S 135 Chd9n Or., Ste, 2., Mch. AK 99501 F. 907-243-14n Email: se N(40.w AO GCC 1/13/2019 ITMO: INQMYMTOM4ECMMCALINTEGMTYOFPRMHOEBAY WELLS Bockw No. M -W Page 20 1 COMMISSIONER SEAMOUNT: I have none. 2 CHAIRMAN FRENCH: You are now an expert in our 3 eyes. Please proceed. 4 MR. CISMOSKI: Thank you. 5 DOUG CISMOSKI 6 previously sworn, called as a witness on behalf of BP 7 Exploration Alaska, Incorporated, testified as follows 8 on: 9 DIRECT EXAMINATION 10 MR. CISMOSKI: As mentioned I'll be reviewing 11 the actions taken after the drill site 2-03 incident. 12 Prudhoe Bay is a mature field with approximately 1,800 13 wells and 47 gravel pad drill sites. Based on modeling 14 conducted after the 2-03 incident in 2017, BP Alaska 15 determined that wells prone to a sudden rise like scene 16 on 2-03 were limited to wells constructed in a similar 17 manner. That is of a stiff or rigid three casing 18 string design with the surface casing shoe in the 19 permafrost. 20 Our current basis of design for Prudhoe wells 21 consists of a two casing string well with the surface 22 casing shoe at approximately 3,000 feet, well below the 23 base of the permafrost. 24 To date we've identified 23 wells that appear 25 to be like 02 and 2-03 inclusive. Cowuw Manx, LLC Phone: 907-2430668 135 Min. M,, Ste. 2., Mch. AK 99501 Fu: 907-243.1473 E.d %Adii(a ag nu AOGCC V1312019 RMO: MQMYMTOM4ECMMCA MTEGMnOFMMHOEBAYWELLS Mcket No. Q1H Page 21 1 And, Ryan, would you be able to portray that 2 table, please. 3 CHAIRMAN FRENCH: Now just..... 4 MR. CISMOSKI: On the chart..... 5 CHAIRMAN FRENCH: .....just to get us oriented 6 tell us the title if you would of this document..... 7 MR. CISMOSKI: Yes, sir. 8 CHAIRMAN FRENCH: .....and when it was prepared 9 and when it was delivered to us here at AOGCC? 10 MR. CISMOSKI: On the slide, on the -- that's 11 being project now is a table of the 23 wells that we've 12 identified to have surface casing shoes in the 13 permafrost with the exception of observations. The 14 list -- these list of wells came to you in a variety of 15 forms over the last year. 16 CHAIRMAN FRENCH: For example in your written 17 responses that were delivered back on the 6th of 18 February? 19 MR. CISMOSKI: That has -- that has this -- 20 includes the entire list. 21 CHAIRMAN FRENCH: I understand. I..... 22 MR. CISMOSKI: Yes. 23 CHAIRMAN FRENCH: It's just you've put it in a 24 new Power Point for this morning? 25 MR. CISMOSKI: Yes, sir. Comate, Matti; LLC Plt m 9IY!-241-06fi6 135 C ,itemen Oq Ste. 2., Att h A 99501 Fuc W -W-1473 Emil: s ile(dsci.net AOGCC 2/132019 R O: INQUIRYIWOM4ECHANICALI GMR OFMR HOEBAYWELLS Docket No. OM -064 Page 22 1 CHAIRMAN FRENCH: I understand. 2 MR. CISMOSKI: Immediately following the drill 3 site 2-03 incident as part of the incident 4 investigation BP Alaska conducted a search of Prudhoe 5 wells with three annuli and used a depth of 1,850 feet 6 as an assumed base of permafrost. This resulted in a 7 list of 14 wells, including 2-03. And that referring 8 to the chart that's being projected that's titled 9 Wells with Surface Casing Shoe in the Permafrost, are 10 those first 14 wells on the -- on the table. 11 Nine of these wells were in operation at the 12 time and they were shut-in and retrievable mechanical 13 plugs set. Four of these wells had mechanical plugs 14 set due to existing mechanical issues. Well 2-02 was 15 one of these four. 16 CHAIRMAN FRENCH: And when was the plug set if 17 I can ask? 18 MR. CISMOSKI: A plug was originally set soon 19 after shut-in in the 2006 time frame. 20 CHAIRMAN FRENCH: Shut it in, set a plug, you 21 know, basic..... 22 MR. CISMOSKI: There -- yes. 23 CHAIRMAN FRENCH: Sure. 24 MR. CISMOSKI: And there were times -- and a 25 plug was reset in 2-02 I believe in February of '17. C.a de, Mmn, I r• Phone: %7-243-0668 135 Chri9erasm Dr., Ste, 2., Meh. A 99501 Fax 907-243-1473 Email: ea Ieft.,net AOGCC 2/13=9 ITMO: MQMY]M0WECHAMCALIMEMn0FMMH0EBAY WELI4 Docks W. OiH Page 231 1 CHAIRMAN FRENCH: Again a new plug? 2 MR. CISMOSKI: Again a new plug. 3 CHAIRMAN FRENCH: Thank you. 4 MR. CISMOSKI: The remaining wells, 5 approximately 1,750 plus, are of the two casing string 6 design. And my colleague, Mr. McCarty, will explain in 7 detail the importance of this distinction. 8 A manual search of drilling records in early 9 2018 for wells with three casing strings and the 10 surface casing set in the permafrost indicated an 11 additional seven wells that appeared to be constructed 12 like well 2-03. All of these wells were shut-in if not 13 already, all these wells were evaluated in detail and 14 BP Alaska approached the AOGCC for operability approval 15 for five. Those seven wells are labeled in the chart 16 with surface casing shoe in permafrost 15 through 21. 17 CHAIRMAN FRENCH: You're still referencing the 18 same slide? 19 MR. CISMOSKI: I'm referencing the same slides, 20 yes, sir. 21 Okay. Four of these five wells were 22 constructed with a gravel string to prevent 23 unconsolidated gravel compromising the surface hole 24 section while drilling. The major difference in these 25 wells as explained in our'submission is they are not Congerer Metrix LLC Mw 907-213-0 135 Chrietemm D,, Ste. 2.. Ma AK 99501 FU 90]-243-14]3 Emil. nhile&ci net aOG(t VIM019 ITMO:MQMYIN OM4ECHAMCALIHTEGMTYOFPRU HOEBAYWELLS Docket No, DTH- 0 Page 24 1 attached at the wellhead, but -- the 20 inch and the 13 2 and three -eights are not attached to the wellhead and 3 these wells are effectively a two casing string design. 4 Again Mr. McCarty will expand on this 5 distinction. 6 CHAIRMAN FRENCH: And the gravel string and 7 what that is and all, yeah, I understand. 8 MR. CISMOSKI: The fifth well is a three casing 9 string well that through cementing operations in 1990 10 has attached the surface casing intermediate and 11 production casings, so basically all three strings, to 12 each other through the permafrost. 13 COMMISSIONER FOERSTER: Which well is that? 14 MR. CISMOSKI: J-01. 15 COMMISSIONER FOERSTER: Okay. 16 MR. CISMOSKI: On the same chart we were 17 referencing before it's well number 17 with -- with the 18 notes at the end of the 20 by 13 and 13 by 9 fully 19 cemented. 20 COMMISSIONER FOERSTER: Okay. Thank you. 21 MR. CISMOSKI: Of the other two wells that we 22 did not approach the AOGCC for operability, one had a 23 cement plug set up of the reservoir in September of 24 2018, that is Mary 1, well number 15 on that list. And 25 the other was a two casing string well with the surface Comuter Meana, LLC Phone: 907.2Q3 B 135 Christensen Dr., Ste. 2., Mch. A W501 Fix: 907-243-14T1 Email: mhile@gci.net AO C 2/13/2019 1 O WQMYI OWECHAMCALMFEGR OFPRODHOEBAYWELLS Wcket No. OTH W Page 25 1 casing shoe in the permafrost, Echo 28. The two casing 2 string well remains shut-in with the plug set. 3 After the well 2-02 incident BP Alaska further 4 evaluated two additional wells' surface casing shoe 5 depth, Echo 4 and 01-03. Wells 22 and 23 on the same 6 table that's being projected. 7 Well 01-03 was identified following the 2-03 8 incident in 2017 as a well with the surface casing shoe 9 below the permafrost. Note the surface casing shoe 10 depth is at 1,950 feet and we used 1,850 after the 2-03 11 incident. 12 CHAIRMAN FRENCH: I'm sorry, could you just 13 flesh that out a little, the -- with the depths. 14 MR. CISMOSKI: Well 01-03 is labeled on the 15 table that I reference before at 1,950 feet. 16 CHAIRMAN FRENCH: Line 23? 17 MR. CISMOSKI: Line 23. 18 CHAIRMAN FRENCH: Right. 19 MR. CISMOSKI: And if you..... 20 COMMISSIONER FOERSTER: 22. 21 MR. CISMOSKI: .....recall after the..... 22 CHAIRMAN FRENCH: I'm sorry? 23 COMMISSIONER FOERSTER: It's 22. 103 is number 24 22, isn't it? Or -- oh, you got it different than I 25 do. Fine. Computer M.,l, LLC Phone: %7-243-0 135 Chri amen Dr., Ste. 2., Aitch. AK 99501 F. 90]-243-10]3 Email: tthtd.(24gci. cwt i AOGCC N13Q019 ITMO. INQWRYINTOWECH CALINTEGMTYOFPRUDHOEBAYWELLS Docket No. OTH-W4 Page 26 1 CHAIRMAN FRENCH: Yeah, not on that slide. 2 COMMISSIONER FOERSTER: Okay. Sorry. 3 CHAIRMAN FRENCH: All on the same line. Okay. 4 MR. CISMOSKI: Sure. 5 CHAIRMAN FRENCH: Thanks. 6 MR. CISMOSKI: Yeah, 1,950 feet. 7 CHAIRMAN FRENCH: And I'm sorry, just for 8 absolute clarity is that in -- is that -- is that in 9 the permafrost or below it? 10 MR. CISMOSKI: That's uncertain which is why 11 we've added to this list. 12 CHAIRMAN FRENCH: Not..... 13 MR. CISMOSKI: It is close enough to the base 14 of permafrost and Mr. Daniel will explain more about 15 our understanding of that. 16 CHAIRMAN FRENCH: Where -- I mean, that's -- I 17 mean, it's a question, like where exactly does the 18 permafrost stop, right..... 19 MR. CISMOSKI: Yes. 20 CHAIRMAN FRENCH: .....and Mr. Daniel speak to 21 that? I mean, not now just you -- we'll get to that? 22 MR. DANIEL: Yes, sir. We can certainly look 23 into that in more detail. 24 CHAIRMAN FRENCH: Thank you. 25 MR. CISMOSKI: Well F-04 was identified in 2018 ConitmetM vt, LLC Phone: 907-243-0668 135 angemnt Dr.. Ste. 2.. Anch AK "MI Fes'. 907.243-1473 Emil: mileftei net :10610 2/13/2019 1 O: MQMYMTOM4ECHAMCAL GMIT OFPRMHOEBAYW LLS M,W No. MMt 4 Page 27 1 during a manual search, but again initially identified 2 as a surface casing shoe below the permafrost. However 3 both wells' shoes, surface casing shoes, are relatively 4 close to the permafrost base and BP Alaska shut these 5 wells in, plug se, removed wellhouses and flowlines in 6 late December, 2018. 7 We also looked at options to reduce the 8 probability of loss of primary containment. These 9 options, this was after the 2-03 incident in 2017, 10 these options included removal of flowlines, completely 11 decouple the 20 inch from the 13 and three-eighths 12 casing. We could have fixed the entire 20 inch casing 13 to the 13 and three-eighths with cement or permanently 14 abandoned the wells. After an operability assessment 15 was conducted BP Alaska determined wells of this type 16 should not be operated. A work list was created and 17 added to our well tie in team to remove the S riser and 18 flowline exiting the back of the wellhouse. The 19 assessment determined that the risk of a sudden rise 20 was unpredictable as the loading cannot be assumed to 21 be linear over time. BP Alaska also expanded the well 22 integrity monitoring plan since the 2-03 incident which 23 Mr. Daniel will also explain in detail. 24 BP Alaska conducted 217 full bore drifts in 25 2018 to assess potential tubing buckling, shallow CoMuter M4tl LLC PM. : 907-243 8 135 Chri fm en Or., Ste. 2., Anch. AK 99501 Fu W.243-1473 Enail. v ile(,4gci net AOOCC V132019 UMO: WQU YI OWECHA CAL EO OFPROBHOEBAYWELLS Hack. H9. 0TH Page 28 1 obstruction or potential casing impingement. 2 CHAIRMAN FRENCH: You said 217? 3 MR. CISMOSKI: Full bore drifts. 4 CHAIRMAN FRENCH: Full bore drifts. A wireline 5 run? 6 MR. CISMOSKI: Yes, sir. 7 CHAIRMAN FRENCH: I understand. 8 MR. CISMOSKI: BP Alaska also surveyed a base 9 flange elevation of every well in the field. 10 Further an assessment of clearances in all 11 Prudhoe wellhouses was conducted in the latter half of 12 2017. These assessments evaluated the top of the 13 uppermost platform handrail to the plane of the roof 14 line, the swab flange to the plane of the roof, the S 15 riser pipe to the plane of the roof and we verified if 16 jewelry was attached at the top of the S riser. 17 CHAIRMAN FRENCH: When you say jewelry? 18 MR. CISMOSKI: Small fittings that usually 19 instruments are attached to or small valves. 20 CHAIRMAN FRENCH: Thank you. 21 MR. CISMOSKI: Since the 2-02 incident in 22 December of 2018, all wellhouses have been removed on 23 18 wells and S risers have been removed from the recent 24 -- from the recent additions. Signs are in place on 25 all of these wells to warn workers of potential C. ry wWt., LLC Plttne: 907-243-0668 135 Mitt.. Or., Ste 2., Anch AR "MI Fu 907.243-1473 Email. uhik(a;8di AOGCC 2113/2019 I O: WQMYIWOM4ECHAMCA lM EGWWOFPR00HOEBAYWELLS 09ckn N9.OM- Page 29 1 unexpected rises, scaffolding is being erected around 2 these wells to allow crews to work safely and assure no 3 contact potential exists between a well and scaffolding 4 -- scaffle were the well to rise. 5 The Commission has also asked for information 6 about metallurgical analysis for wells 2-02, 2-03 and 7 L5-13. While no metallurgical study was done on 2-03, 8 our plan is to submit well 2 -- 2-02 20 inch casing 9 section for metallurgical analysis. In this last 10 incident the casing appears to have parted in the main 11 body and not at a coupling like what happened with 2- 12 03. The analysis on 2-02 may indicate if the casing 13 strength was compromised which would inform our 14 hypothesis of the subsurface subsidence imparting the 15 required load to fail this casing. 16 CHAIRMAN FRENCH: And, sir, I don't mean to 17 keep interrupting you, but I just -- for my 18 understanding when you say the casing parted which 19 string was it? 20 MR. CISMOSKI: It's the 20 inch, the surface 21 casing, the shallow surface casing. 22 CHAIRMAN FRENCH: And this is on 2-02 or 2-03? 23 MR. CISMOSKI: 2-02 parted in the body. 24 CHAIRMAN FRENCH: 2-02? 25 MR. CISMOSKI: Yes. Ca�ater Metrix LLC Plro 907-243 g 135 pvinensen M, Sm 2„Anck AR 99501 F. 907-243-1473 Email.s ikftci.nel AOGCC YIM019 RMO: INQN YI OM4ECMMCA lIN GR OFPRUDBOEBAYW LLS Docks W. O]13A64 Page 30 1 CHAIRMAN FRENCH: 2-02. Okay. Surface casing. 2 Got it. Thanks. 3 MR. CISMOSKI: And just to clarify, 2-03 also 4 parted, the 20 inch parted, but at a coupling. 5 CHAIRMAN FRENCH: I understand. Thank you. 6 MR. CISMOSKI: Okay. During the plug and 7 abandonment of L5-13 BP Alaska recovered the failed 8 casing strings and had a third party conduct a 9 metallurgical analysis for defects. BP Alaska received 10 their report in September of 2018. The failure of L5- 11 13 is not like wells 2-02 or 2-03 and does not appear 12 to be related to subsidence. This well failed a 13 pressure test validating the well's mechanical 14 integrity. The failures appear to be associated with 15 cracks near a deformed region of both casing strings. 16 This deformity appear to be related to localized inward 17 buckling or collapse, possibly from ice. 18 COMMISSIONER FOERSTER: Possibly from what? 19 MR. CISMOSKI: Ice. 20 COMMISSIONER FOERSTER: Okay. 21 MR. CISMOSKI: The metallurgical analysis 22 indicated no apparent material defects or service 23 related mechanisms such as corrosion or fatigue. In 24 addition wear from drilling equipment was not indicated 25 as the primary cause for failure. And there is more Coweter Metrix, LLC Phone: 907-243-0 135 Mivemen Dr., Ste. 2., AMA. A 99501 FU 907-243-1473 Email: sahik(dgci.net AOGCC 2/132019 ITMO: WQUIRYINTOM4ECHAMCALINTEG OFPBUGHOEBAYW LLS Docket No. OTH-0 Page 31 1 information that was submitted with our written 2 submission. 3 With the Commission's approval I'd like to now 4 pass on to my colleague, Mr. McCarty, to explain the 5 causes and contributing factors for the two incidents, 6 2-03 and 2-02. 7 CHAIRMAN FRENCH: Mr. McCarty. Good morning. 8 MR. McCARTY: Good morning. 9 CHAIRMAN FRENCH: Would you like to be 10 recognized as an expert? 11 MR. McCARTY: Yes. 12 CHAIRMAN FRENCH: And in what field? 13 MR. McCARTY: In the field of well 14 construction. 15 CHAIRMAN FRENCH: Please tell us about your 16 qualifications. 17 MR. McCARTY: Okay. Good morning, 18 Commissioners and AOGCC staff. My name is Thomas 19 McCarty. I'm the global wells engineering authority 20 working for the safety and operational risk division of 21 BP. I lead a central team of technical experts that 22 provide independent engineering assurance of well 23 related risks globally. I support the delivery of 24 relevant engineering practices and provide assurance on 25 conformance with engineering practices. I have a BS in Cot ule,M ftm LLC Phone: 9o9-243-0 135 Chriuenun @, Ste. 2., Mch. A 99501 Fex: 907-243-1493 Email: s ile(ajgci.net AOGPC 2/13/1019 HMO: INQMYIWOWECH MCALBPFEORITYOFPROOHOEBAYWELLS Dodd N. MH -064 Page 32 1 mechanical engineering from the University of Colorado. 2 My industry exposure includes over 21 years of the 3 upstream experience largely in the delivery of wells 4 with experience leading people in a variety of regions 5 and countries across where BP operates. My career has 6 been focused on wells engineering and operations 7 primarily in wells construction with experience across 8 offshore, onshore and remote operations including 9 Alaska. I started my career in Alaska in 1998 and 10 spent nine years in a variety of a roles including both 11 production, wells engineering and operations at Prudhoe 12 Bay. I then moved into a variety of international 13 assignments focused on well construction delivery which 14 included Azerbaijan, North Africa and Trinidad prior to 15 taking on my current role. I've been in my current 16 role since mid 2017. 17 CHAIRMAN FRENCH: Did you say you cut your 18 teeth at Prudhoe Bay? 19 MR. McCARTY: Absolutely. 20 CHAIRMAN FRENCH: And did you guys go to school 21 at the same time? 22 MR. McCARTY: I was just after Doug. 23 CHAIRMAN FRENCH: Did you know each other? 24 MR. McCARTY: No. 25 CHAIRMAN FRENCH: Kind of none of my business. Conpmerh nx L. Phone'. 907-243-0668 135 Christensen Dr., Ste. 2.,M h. A 99501 F. 907343-1473 Email: saM1e@gcinn AO C 2/132019 ITMO: INQUAY1 OM4ECHANICALINTEGR OFPRUGHOEBAYWELLS Docks N ,Om -064 Page 33 1 I don't have any objection to your being recognized as 2 an expert in that field. 3 Commissioner Foerster. 4 COMMISSIONER FOERSTER: Nor do I. 5 UNIDENTIFIED VOICE: Hello. 6 CHAIRMAN FRENCH: Please proceed. 7 THOMAS McCARTY 8 previously sworn, called as a witness on behalf of BP 9 Exploration Alaska, Incorporated, testified as follows 10 on: 11 DIRECT EXAMINATION 12 MR. McCARTY: Let's move on to I believe slide 13 number 2 in the presentation. 14 I'll first talk about the Prudhoe Bay well 2-03 15 investigation findings that was as a result of the 16 event that occurred in April, 2017. 17 UNIDENTIFIED VOICE: Hello. 18 CHAIRMAN FRENCH: Hello. We're taking 19 testimony. If -- and you're listening in, that's fine. 20 If you want to testify later we'll take that when we 21 get to it, but we are in the middle of a hearing. If 22 you put your phone on mute that might be better. 23 Please proceed. 24 MR. McCARTY: I'll talk about the early Prudhoe 25 Bay unit well design including well 2-02 and 2-03. And comutw meth LLC M. 909.243-0668 135 MiAe en U.,$1e. 2., Anch. A 99501 F. 907-243-1493 E.L sehile@gi Mt AOGCC 2/132019 1 M0. INQHIRYM OWECIIANICALI GRRYOFFRGDHOE BAY WELLS Docket No. Oi OM Page 34 1 then I'll talk a little bit about the wellhead movement 2 model which parts of my team developed after the 2-03 3 event. 4 Going on to the next slide. I'll present the 5 2-03 relevant investigation findings. The first 6 finding was that when well 2-03's christmas tree and 7 wellhead suddenly moved upwards the pressure gauge on 8 top of the S riser contacted the wellhouse roof and the 9 gauges simple sheared off causing an upper LOPC. The 10 second finding was when wells 2-03 christmas tree and 11 wellhead assembly moved upwards the swab valve handle 12 impacted the wellhouse structure imparting sideloading 13 on the tubing head adaptor and the upper flange. As a 14 result the flange stud stretched causing the lower 15 LOPC. So in well 2-03 there were actually two leak 16 points. 17 CHAIRMAN FRENCH: The gauge assembly? 18 MR. McCARTY: On the top of the S riser. 19 CHAIRMAN FRENCH: I understand. And then..... 20 MR. McCARTY: And the flange below -- above the 21 tubing head adapter. 22 CHAIRMAN FRENCH: And you said LOPC? 23 MR. McCARTY: Loss of primary containment. 24 CHAIRMAN FRENCH: I see. Okay. So that's what 25 you call a leak? C n,wet 14%tm LLC Mne:9 -243-0 13 135 CWietemen U., Ste. 2., Md AK 99501 F.. 9W-243-1073 E..1 mi, dcdga na AOGCC VIM019 RMO: INQUIRYINTOMOECH CALINTEGR OFPRUDHOEBAYWELLS Docket No, OTH-060 Page 35 1 MR. McCARTY: Correct. 2 CHAIRMAN FRENCH: Okay. Got it. 3 COMMISSIONER FOERSTER: It would be good for 4 the record and for people who are interested in it, if 5 you -- and I know it's hard, but if you try to say the 6 words instead of use the acronym. 7 MR. McCARTY: Definitely. Okay. Understood. 8 Thank you. 9 The third finding was around the permafrost 10 subsidence which imparted a downward load on the 30 11 inch conductor and 20 inch surface casing which caused 12 one, the 20 inch casing string to fail below the 13 wellhead and two, allowing internal casing strings, 14 production tubing, the wellhead and the christmas tree 15 to move upwards. 16 Based on the preliminary findings the cause of 17 the 2-02 event was the tensile failure of the 20 inch 18 surface casing which allowed an upward force generated 19 by the inner casing strings to lift the wellhead. The 20 failure was determined to have been due to downward 21 load imparted by subsidence of the permafrost 22 formations on the surface casing resisted by the 23 compression of the inner casing strings. A similar 24 failure mechanism occurred on well 2-03 in April, 2017. 25 Similar to the 2-03 event as well 2-02 wellhead C.Wotnf Matrix, LLC Plane:9 -203-0668 135 Ch st. Dr., Ste. 2, An& AK 99501 F. 907-203-1473 Emall: a ilo ftd.nn1 AOOCC 2/132019 ITMO: INQMY1 OM4ECH CALINTEORFFYOFPRODHOEBAYWELLS Docks No. 0TH -064 Page 36 1 lifted the christmas tree contacted the roof of the 2 wellhouse shelter putting a side load on the flange 3 connection between the lower manual valve and the 4 tubing head adapter causing the release. 5 CHAIRMAN FRENCH: And when you say the lower 6 manual valve are you referring to a valve in line with 7 the tree or one of the -- one of the wing valves, you 8 know what I mean? 9 MR. McCARTY: A valve in line with the tree. 10 CHAIRMAN FRENCH: Okay. Not the master valve? 11 MR. McCARTY: The master valve. 12 CHAIRMAN FRENCH: Oh, it is the master valve. 13 Okay. Okay. 14 MR. McCARTY: There was no S riser on well 2-02 15 at the time. 16 CHAIRMAN FRENCH: It wasn't connected? 17 MR. McCARTY: Pardon me. 18 CHAIRMAN FRENCH: It wasn't connected to 19 anything? 20 MR. McCARTY: Correct. 21 CHAIRMAN FRENCH: All right. 22 MR. McCARTY: That was disconnected prior to 23 that event. 24 CHAIRMAN FRENCH: Okay. 25 MR. McCARTY: The preliminary findings show Covuter Mercia LLC PWm 907-243-0 135 Chrinewv Dr., Ste 2., Mch. AK 99501 F. 907-243-1473 Emil, sahik @tlCi,W r AOGCC 2113/2019 F O: INQDIRYINTOM4ECHANICALINTEGR OFPRIIDHOEBAYW LLS Docket N9.OTH-064 Page 37 1 that the failure mechanism is limited to the wells with 2 a three string casing design with the surface casing 3 shoe set in the permafrost. 4 This next slide..... 5 COMMISSIONER FOERSTER: Would you say that -- 6 make that statement again, that last one you made? 7 MR. McCARTY: The failure mechanism is limited 8 to wells with a three string casing design with a 9 surface casing set in the permafrost. 10 This next slide, slide number 4, titled 11 contacted with the wellhouse 2-03 and 2-02. A loss of 12 primary containment required both wellhead movement and 13 contact between the christmas tree and the wellhouse. 14 CHAIRMAN FRENCH: And just regarding these 15 photographs, are these also in the document you sent us 16 February 6 or are these new? And I -- it's not a huge 17 deal if they aren't, I'm just trying to make sure that, 18 you know, what information we're getting and when we're 19 getting it. 20 MR. McCARTY: The two pictures on the left of 21 2-03 were part of the 2-03 report. 22 COMMISSIONER FOERSTER: I think the easiest 23 thing since the court reporter is going to need..... 24 CHAIRMAN FRENCH: (Indiscernible - simultaneous 25 speech) question. Thank you. CaWuter Metrix, LLC Phone: 90'1-243-0668 135 Chrimmen Dr, Ste 2., Mch, AR 99501 Fax 907-243.1473 Emai1 . sehA6,e,c, ner i AOGCC 3/13/2019 ITMO: MQMY11Y1'0M4ECHAMCALIMEGMTY0FPRMH0E BAY WELLS Docktt H9. MH -W Page 38 1 COMMISSIONER FOERSTER: .....since we need to 2 have a record it's standard procedure for anything that 3 is shown as an exhibit become part of the record. So 4 if you could provide us your presentation materials. 5 CHAIRMAN FRENCH: Actually -- yeah, better yet 6 just tell us -- tell us about these photographs. 7 MR. McCARTY: Sure. 8 CHAIRMAN FRENCH: We'll worry about it later if 9 we knew about it. 10 MR. McCARTY: We can provide it..... 11 CHAIRMAN FRENCH: Yeah. Yeah. 12 MR. McCARTY: .....you know, requested. So the 13 photo on the left shows the 2-03 flange leak. There 14 was a -- you can see it in the middle of the photo 15 there were hydrates that formed at the -- as a result 16 of the release. That was due to the bending (ph) 17 moment on the tree and the wellhead when the swab valve 18 contacted the roof of the wellhouse. 19 The middle photo shows the S riser on well 2- 20 03. It shows a plug where the gauge was originally, 21 this plug was installed in the response to the event. 22 CHAIRMAN FRENCH: And who installed that plug? 23 MR. McCARTY: We had a third party well control 24 company install the plug. 25 CHAIRMAN FRENCH: Do you remember, was it C9�meeM ,LLC Phone: 90'/-243U 135 Chri .n Dr., Ste, 2., Anch. AK 99501 Fu 907443-0493 Em 1: eehile@pi.nel AOOCC 1 someone from Texas? 2/132019 I] O: INQUIRYIWOM4ECH CALI GMYOFPRUDHOEBAYWELLS Wdd N9. OM -064 Page 39 2 MR. McCARTY: I'll have to defer to Mr. 3 Cismoski on that. 4 MR. CISMOSKI: Boots and Coots Well Control. 5 CHAIRMAN FRENCH: That was my memory was Boots 6 and Coots. I just love saying that. So -- thanks. 7 MR. McCARTY: The third photo shows the swab 8 valve on well 2-02 where it contacted the roof of the 9 wellhouse. This was very similar to what happened on 10 well 2-03. There was only one leak point in well 2-02. 11 In both cases, 2-02 and 2-03, contact with swab valve 12 and the wellhouse roof caused a bending moment at the 13 flange between the master valve and the tubing head 14 adapter. As a result the seal in the flange was 15 compromised resulting in a LOPC. 16 I'll move on to the next slide labeled three 17 string design. Both 2-03 and 2-02 have similar three 18 string casing designs with the surface casing set in 19 the permafrost. The three inner strings, five and a 20 half inch, nine and five-eighths and 13 and three - 21 eighths, are more rigid than the two string casing 22 design that is much more common across Prudhoe Bay 23 unit. 24 There's a simplified schematic for well 2-03 on 25 the upper right-hand corner which shows the -- the CoWuw Ma LLC Phone: %7-243-0668 135 Chriddoen Dr., Ste. 2. Anch, AK 99501 F. %7-243-1473 Email: s ile@r i.nd AOGCC 21132019 R O: 3NQD YlN OM4ECHAMCALR GR OFPRODHOEBAYWELLS Docket No. Ol33 Page 40 1 typical construction of those early wells. As wells 2 are brought online near well bore formation 3 temperatures increase resulting in permafrost thaw, ice 4 in a formation is replaced with water which is lower in 5 volume which can allow a drop in pore pressure and 6 compaction in the formation. This result in subsidence 7 which applies a downward force on the surface casing 8 that does not have a casing seat set below the 9 permafrost. 10 The downward force from subsidence could result 11 in a parted 20 inch casing. The three inner casing 12 strings are in compression and counter that subsidence 13 force. That's shown in the lower picture on the right. 14 The compression force is acting upwards from the three 15 inner strings and the 20 inch force applied downwards. 16 This is a system connected at the wellhead of these 17 four strings. 18 The relative stiffness of the inner strings 19 build compression to counter the subsidence force and 20 enables the 20 inch to part prior to inner strings 21 yielding or buckling. Twenty inch pipe body minimum 22 yield strength is around a million pounds which is 23 around a third of the combined 3.3 million yield 24 strength for the 13 and three-eighths, nine and five - 25 eighths and five and a half inch inner strings. For a CownterM m LLC Phone: 90)-243-0668 135 Chriueneen Dr., Ste. 2., Mch. A 99501 Fee 90)-243-14)3 Email: mhile@gci.nn iOGCC VM019 RMO: INQMYIWOMOECHANICAW GR OFPRU HOEBAYW LLS Oocha No. OMH Page 41 1 more typical 10 and three-quarter by seven inch by four 2 and half inch two string design across PBU, the surface 3 casing minimum yield strength is around a thousand -- 4 around a million pounds versus 971,000 pounds for the 5 combined inner strings. In the two string design the 6 inner strings would yield or buckle prior to achieving 7 a downward force necessary to part the 10 and three - 8 quarter surface casing. When the 20 inch parts on the 9 three string design the rigid inner strings will 10 relieve compression by pushing up the wellhead. 11 We'll move on to the next slide, titled surface 12 casing set within the permafrost. The surface casing 13 depth affects the amount of force applied at the 14 wellhead. For the small subset of wells with the 15 casing set within the permafrost subsidence forces 16 return to the wellhead. That's shown by the picture on 17 the left -- the diagram on the left. For casings set 18 beneath the permafrost subsidence forces are 19 distributed between the wellhead and the formation 20 below the permafrost. For the same subsidence force 21 setting the surface casing beneath the permafrost 22 results in less wellhead loads. For the majority of 23 wells in PBU the casing is set beneath the permafrost, 24 the subsidence forces are distributed. In this 25 instance the well with the surface casing set below the Cor wer Matrix LLC Phone: 907-243-0 8 135 Chrine Or., Ste. 2., Anch. AK 99501 Fee: 909293 -Mn Er 1. eahileftci net AOOCC 2/132019 RMO, MQUIRYIWOM4ECHAMCALINTEMR OFPRUDHOEBAYWELIS Docket No. OMN Page 42 1 permafrost would see less relative loading at the 2 wellhead. 3 Move on to the next slide. I'll describe the 4 slide title as wellhead movement, I'll talk about the 5 wellhead movement model that was developed to describe 6 the failure mechanism. 7 Steel slightly stretches with applied force 8 like a very stiff spring. If you look at the diagrams 9 on the right I'll go through them in sequence. The red 10 line indicates the original base flange elevation which 11 is fixed. 12 CHAIRMAN FRENCH: And when would those 13 measurements be taken for example to establish the 14 baseline? 15 MR. McCARTY: We would have taken a baseline 16 measurement as part of the monitoring. I think my 17 colleague can address that in terms of when the initial 18 baseline evaluation was taken on well 2-02. 19 COMMISSIONER FOERSTER: So if you did it as 20 part of your monitoring it was sometime in the last 10 21 or 15 years, 20 years so it wasn't in -- it isn't a 22 true initial baseline. It's kind of like if I get my 23 bone density tested now it's probably already kind of 24 going to crap? 25 CHAIRMAN FRENCH: We all hope not. CoMNer M . , LLC Phone: 90'1-2A3 B 135 Oninensen Dr, Ste, 2., Anch. A W501 Fax'. 90W-241-1473 Eml,s il<agci.net AOGCC 2/13Q019 ITMO: MQMYMTOWECHAMCALMTEGW OFPRMHOEBAYWF.LIS M,W Ho. OTB -061 Page 43 1 MR. McCARTY: Right. And for the purposes..... 2 CHAIRMAN FRENCH: We all hope not. Let's just 3 stop and..... 4 MR. McCARTY: Right. For purposes of this 5 model it's a starting point when the well was 6 constructed. 7 COMMISSIONER FOERSTER: Okay. 8 MR. McCARTY: Ryan can speak later about..... 9 CHAIRMAN FRENCH: We'll talk about it, I -- we 10 were just..... 11 MR. McCARTY: Yeah. 12 CHAIRMAN FRENCH: .....you can see our kind of 13 general question is..... 14 MR. McCARTY: Yeah. 15 CHAIRMAN FRENCH: .....like, you know, did you 16 measure the day, you know, the rig pulled off of it or 17 in the future. 18 MR. McCARTY: Right. 19 COMMISSIONER FOERSTER: Uh-huh. 20 MR. McCARTY: Okay. Thank you. The diagram on 21 the upper left labeled number 1 shows the initial 22 string tension post construction when two or more 23 strings are coupled together an applied force on one 24 string is balanced by forces applied on the other 25 strings. In wells 2-02 and 2-03 these four strings are CoWwer Mmrm LLC Phone: 907-293-0668 135 Christensen Dt., Ste. 2,M& AK 99501 F. 90]293-19]3 E.L snhile(�gci.net \OCCC 3/13/2019 ITMO, MQMYMTOWECH M]NTEMI OF PROOHOE BAY WELLS DocketNo. omH Page 44 1 connected at the wellhead. 2 In figure number 2 strings build compression 3 due to heating whenever they're brought online or wells 4 nearby have a heating affect. 5 Number 3, the permafrost subsidence applies a 6 downward force on the 20 inch surface casing, pulling 7 the wellhead down relative to the initial base flange 8 elevation. This also applies tension in the 20 inch 9 with a compression in the combined loads on the inner 10 strings. 11 And number 4, as the 20 inch parts this would 12 allow the inner strings to leave compression and push 13 the wellhead christmas tree upwards. Wellhead growth 14 is dependent on two primary variables, free length of 15 the 20 inch at the time that it parted and the parting 16 force of the 20 inch casing. 17 CHAIRMAN FRENCH: And if you would just fill me 18 in on what free length means, you mean just the total 19 length or the -- is that a different idea? 20 MR. McCARTY: Free length would be the length 21 of the 20 inch casing that's above the top of cement 22 and not held by the formation. We don't know exactly 23 what the free length of the 20 inch casing was on 2-02 24 when it failed. But it would be the..... 25 CHAIRMAN FRENCH: Can you give me a ball park, Comte" Maim, LLC FMne: 907-243-0 S 135 Mineven Ile., Ste. 2., MCR A W501 Fu: 97-243-1473 Emil a Ae(ggci.net AO C 21122019 IMO, INQMYWOM4ECMMCALI GWWOFMMHOEBAYWELL$ Dockd No. OTH W Page 45 1 is it a hundred feet, 500 feet? 2 MR. McCARTY: The top of the cement in well 2- 3 02 was at 930 feet. The models are consistent with a 4 free length between -- a free point between 300 and 600 5 feet. 6 CHAIRMAN FRENCH: That -- that's -- thank you. 7 Very good. 8 MR. McCARTY: I'll pause here if there's any 9 other questions about the mechanical model. 10 CHAIRMAN FRENCH: Not..... 11 COMMISSIONER FOERSTER: I'm going to save my 12 questions until the end if I..... 13 CHAIRMAN FRENCH: .....not at this time. 14 MR. McCARTY: I'll move on to the next slide, 15 wellhead movement model, well 2-02. The preliminary 16 findings indicate the failure mechanism in 2-02 was 17 similar to 2-03. 2-03 has a sim -- 2-02 has a similar 18 three string casing design with a surface casing set in 19 the permafrost. The models originally developed for 2- 20 03 after that incident were used as a starting point 21 for 2-02. Similar to 2-03 neither pressure nor thermal 22 loads could generate a 20 inch axial force sufficient 23 to part the casing on well 2-02. Upper limits for 24 pressure loads were estimated from formation pressures. 25 Thermal loading was considered from production in C Mwa Mdriz LLC N . 90]-243 S 135 Chridmvm Dc, Ste. 2., MA AK W501 Fez 907-24344/3 Emeil: sehile(�gci.nn AOGCC 21132019 ITMOINQTARYINTOM4ECH CALINTEGMYOFPRMHOEBAYWELLS Docket No. OMH Page 46 1 adjacent wells on well 2-02. If you'll recall 2-02 was 2 shut-in at the time of the incident. 3 The model predicts 20 inch casing failure prior 4 to inner string yielding or buckling. This is due to 5 the relative rigid inner strings on the three string 6 design. The parting load for 20 inch casing was half 7 the yield strength of the combined 13 and three - 8 eighths, nine and five-eighths and five and a half inch 9 inner strings. 10 The sequence of permafrost subsidence causing a 11 parted 20 inch and subsequent upward wellhead movement 12 fits the model initially developed for -- after 2-03. 13 COMMISSIONER FOERSTER: Okay. Let me interrupt 14 you for a second. So you developed a model for 2-03, 15 did you apply the model to the other three string wells 16 after 2-03? 17 MR. McCARTY: We looked at other wells, mainly 18 well 04-03 because initially we were looking at whether 19 or not it was safe to bring that well back online. As 20 part of that we result -- we made the determination 21 that the risk of bringing the well back online was not 22 suitable. 23 COMMISSIONER FOERSTER: But -- okay. But you 24 didn't -- did -- my question is did you apply the model 25 to all of the three string casing wells that you were Cmrpmer Mani LLC Phone. 907-343-0668 135 Ch emen Dr., Ste. 2., M AK 99501 Fax 907443-1473 Email'. eahileftei.net AOGCC 2/132019 RMO. INQMY W0 WECHAMCALIMfEGRM0FPRUDHOEBAY WELLS Dockn No.OM-069 Page 47 1 concerned about? 2 MR. McCARTY: No, we didn't look at every 3 single three string design. 4 COMMISSIONER FOERSTER: You just looked at the 5 one? 6 MR. McCARTY: We looked at 2-03, 2-02, after 7 the post incident. 8 COMMISSIONER FOERSTER: You looked at 2-02 9 after 2-02 happened? 10 MR. McCARTY: Correct. 11 COMMISSIONER FOERSTER: Okay. But -- all 12 right. Let me ask my question one more time. After 13 02-03 what wells did you apply the model to 14 immediately? 15 MR. CISMOSKI: Commissioner Foerster, may I 16 answer. We looked at well..... 17 CHAIRMAN FRENCH: Remind us who you are because 18 there's going to be a transcript. We know who you are, 19 but..... 20 MR. CISMOSKI: I'm Doug Cismoski. I'd like 21 to..... 22 CHAIRMAN FRENCH: Yes. Yes, sir. 23 MR. CISMOSKI: .....answer your question if I 24 may 25 COMMISSIONER FOERSTER: Please. Corryuter Metrix, LLC Phone :907-243A668 135 Chrittemmn Dr., Ste. 2., Arch, AK 99501 F. 907-243-1473 Email: eahik(42gel.mt AOGCC L13/2019 R O QMYI OWECHAMCALI GR OFMMHOEBAYWELLS Mae %,Om_ - Page 48 1 MR. CISMOSKI: We did apply the model to well 2 04-03, that operability study that I was referencing in 3 my -- in my testimony..... 4 COMMISSIONER FOERSTER: Uh-huh. 5 MR. CISMOSKI: .....is -- is that -- applying 6 that model specifically to that well and looking at 7 various sensitivities that Thomas was alluding to with 8 free lengths, maximum movement, so on and so forth. We 9 did not apply it to the other wells after we determined 10 that from the op -- as a result of the operability 11 study we could not operate these wells safely. 12 COMMISSIONER FOERSTER: And at that time you 13 had no reason to believe or you -- well, you -- you 14 didn't -- you weren't concerned that wells that were 15 shut-in needed the model applied to them? 16 MR. CISMOSKI: No, ma'am. We determined that 17 because of the loading and some of the unpredictability 18 of how that -- how the permafrost is affecting the 19 casing that we couldn't predict when particular casing 20 strings were going to fail we decided not to operate 21 those wells. 22 COMMISSIONER FOERSTER: So if you couldn't 23 predict when they would fail does that mean that the 24 model couldn't tell you that or..... 25 MR. CISMOSKI: Right. The model..... Cometer Ma LLC Ph.:90'1-243-0668 135 Chri men Dr., Ste, 2., Anch, AK 99501 Fu: 90]-243-14]3 E.1 a ilmfta.nm AOGCC NIM019 ITMO: MQOIRYINTOM4ECH CALMTEORITYOFPRODHOEBAYWELLS DocW No. 0TH -064 Page 49 1 COMMISSIONER FOERSTER: So the model couldn't 2 predict failure in the other wells? 3 MR. CISMOSKI: The model could predict 4 mechanical failure, but it's how that load is applied 5 to the well is what we cannot predict. 6 COMMISSIONER FOERSTER: Okay. Okay. Thank 7 you. 8 MR. CISMOSKI: And we also did apply the 9 modeling to those -- to the five study wells that we 10 came to this Commission for operability, we -- we did 11 work on those wells and the model..... 12 COMMISSIONER FOERSTER: Right after the 02-03 13 event? 14 MR. CISMOSKI: Prior -- prior to the 02-02 in 15 the fall of 2018 when we asked or requested for -- to 16 have those five wells that I mentioned earlier be 17 operable. 18 COMMISSIONER FOERSTER: So you ran the model on 19 those five wells? 20 MR. CISMOSKI: On -- yes, ma'am. 21 COMMISSIONER FOERSTER: Okay. Thank you. 22 Sorry for the interruption. 23 MR. McCARTY: Going to the next slide, slide 24 titled wellhead movement model, well 2-02. This gives 25 you an idea of the model itself, it -- it can't predict ComputerM ,m LLC Phone:9-343A66B 135 Christensen a., Ste. 3., Anch. AR 99501 Fax: 90]-343-14]3 Emeileahile@Sd.net AOGCC 2/132019 ITMO: INQIARYMOM4ECH CALINTEGRITYOFPRODHOEBAYWELLS Mad No. OTM- Page 50 1 when a failure's going to occur, it can predict the 2 expected upward movement of the wellhead and tree after 3 the 20 inch fails. And it's -- it depends on a lot of 4 different variables. The key variables as I mentioned 5 earlier are parting load of the 20 inch and the free 6 length of the 20 inch casing. So if you look at the 7 chart on the right it shows upward wellhead movement in 8 inches and on the X axis it shows 20 inch parting load 9 in kips. Where the blue line intersects the red or 10 maroon type lines is where you would expect to see the 11 upward movement. So for instance if it parted -- if 12 the 20 inch parted at the max yield you would expect 13 the upward movement to be around 40 inches. You can 14 model that from the original length and the change in 15 the length using -- and it's directly related to the 16 force applied and the modulus of elasticity. 17 CHAIRMAN FRENCH: But while we're on that point 18 I'll just ask is that how far that 02-03 moved? 19 MR. McCARTY: 02-03, off the top of my head I 20 don't recall exactly how far it moved, but it's in the 21 range of the model. 22 CHAIRMAN FRENCH: I thought -- I thought it 23 moved like three feet and then kind of came back down 24 is my memory and I'm seeing someone kind of go like, 25 yeah. Compute Mmrm LLC Phone: 907-243 8 135 Mwauen Dc, Ste. 2., Mch. A 99501 Fu: 907-243-1473 Email: oet AOCC 2/132019 RMO: MQMYIWOM4ECHAMCA IM GR OFPRUDHOEBAYWEUS Docket W. OlH{ 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Page 51 MR. McCARTY: The 2-02 well raised..... CHAIRMAN FRENCH: Three feet is 36 inches..... MR. McCARTY: Yeah. CHAIRMAN FRENCH: .....so maybe I'm, you know..... thing. MR. McCARTY: Yeah. CHAIRMAN FRENCH: Okay. We're saying the same MR. McCARTY: 2-02 raised 38 inches. CHAIRMAN FRENCH: Okay. Fair enough. MR. McCARTY: So it's around the same -- same..... CHAIRMAN FRENCH: Saying the same thing. MR. McCARTY: .....movement. CHAIRMAN FRENCH: Yeah. MR. McCARTY: And, you know, given the reasonable well parameters, the model fits that type of wellhead movement that you'd expect. Going to the next slide. We found some additional information from well 2-02. We were able to record the 47 inch gap in the 20 inch casing after the fact. Given the 47 inch gap the difference between the measured gap and the estimated upward movement of the amount of casing stretch at the time of failure is -- is equal to the amount of casing stretch at the time of CoMwerM rit, LLC Phone: 907-243-0 135 Christmas U., Ste. 2., Mch. AR 99501 Fu 9Ol-243-1473 E.] sahile(rggci nn AOGCC 2/13/2019 RMO: INQMYINiOM4ECH CAL EG YOFPRUDHOEBAYWELLS Docket No. OTH Page 52 1 failure. I sort of misread that. The difference 2 between the measured gap and the estimated upward 3 movement is the amount of casing stretch at the time of 4 failure. That's important because the force 5 corresponding to this type of stretch is on the order 6 of 1 million to 2 million pounds depending on the model 7 assumptions. The biggest unknown variable for the 8 million to 2 million pound range is the depth where the 9 formation grips the surface casing. I've mentioned the 10 free length of the casing previously. We know this 11 occurs or there would be no downward force, we just 12 don't know where exactly it occurs. One million to 2 13 million pounds corresponds to a free point between 300 14 and 600 feet versus the top of cement of 930 feet. 15 CHAIRMAN FRENCH: So just for the -- just to 16 flesh this out and it doesn't have to take very long, 17 if you move the -- move the free point it changes the 18 thrust or changes the predicted thrust, I mean..... 19 MR. McCARTY: The free point -- depending on 20 where the free point is that would change the length of 21 the free casing. 22 CHAIRMAN FRENCH: And that changes..... 23 MR. McCARTY: And that initial length..... 24 CHAIRMAN FRENCH: .....what it takes to move 25 it. See what I mean, what's the relationship? CoWuter Matrix LLC Phone: %7-243-0668 135 Mist. p, Ste 2., Arch. A1C 99501 Fax: %7-243-1473 Email: sahile@gi.Ml AOGCC V=019 ITMO: INQGIRYIN WECHAMCALDITEGR OFPRODHOEBAYWELLS Docket No. OTH-066 Page 53 1 MR. McCARTY: It's linear. That free length is 2 linear to the amount of the change in length that you'd 3 expect from wellhead movement. 4 CHAIRMAN FRENCH: It looks like Mr. Cismoski 5 might want to say something on that. 6 MR. CISMOSKI: If I may, I can..... 7 CHAIRMAN FRENCH: Please. 8 MR. CISMOSKI: .....maybe add a little more 9 context. 10 CHAIRMAN FRENCH: Yeah. Yeah. 11 MR. CISMOSKI: For my mind strain is typically 12 a function of the amount of force that's put on there 13 and the strain is typically measured for change in 14 length over the total length. And so for the same 15 amount of strain if your total length is longer or more 16 then that change in length is more than..... 17 CHAIRMAN FRENCH: You've got a work -- you got 18 -- you two have a much better working understanding of 19 this than I will ever have, I just want to for my 20 purposes, you know, as you move up and down that where 21 -- where would you get the biggest number and where 22 would you get the smallest number, does that make sense 23 in thrust? 24 MR. McCARTY: As your -- if we go back to that 25 previous slide, if you see the red..... CoWmer Mmnz, LLC Phone: 907-243-0668 135 Ch w men Dr., Ste. 2., Ana A 99501 Fax: 9W-243-1473 Email a ahlle@),o.nd AOGCC N13/2019 ITMO: r Docks No. O3A Con,,uwr Mm LLC Phone: 907-243-0068 135 Christernen Dr., Sle. 2., Anch, AK 99501 F. 907-243-1073 Eno il: sehd,@,u not Page 54 1 CHAIRMAN FRENCH: And we're on slide number? 2 MR. McCARTY: Slide number nine..... 3 CHAIRMAN FRENCH: Nine. 4 MR. McCARTY: .....wellhead movement model. 5 CHAIRMAN FRENCH: Uh-huh. 6 MR. McCARTY: If you look at the diagram the 7 lines going downward from left to right..... 8 CHAIRMAN FRENCH: Uh-huh. 9 MR. McCARTY: .....the red and maroon 10 lines..... 11 CHAIRMAN FRENCH: Uh-huh. 12 MR. McCARTY: .....those are different free 13 lengths in the model. So if a free length of 300 feet, 14 that's the -- the uppermost line..... 15 CHAIRMAN FRENCH: I see it. 16 MR. McCARTY: .....it would take a larger force 17 to part the shorter free length. 18 CHAIRMAN FRENCH: Now I'm getting it. And what 19 would be that force in your model? 20 MR. McCARTY: It would be around just over 2 21 million pounds. 22 CHAIRMAN FRENCH: So the range is somewhere -- 23 the end -- the top of the range is somewhere around 2 24 million pounds? 25 MR. McCARTY: Right. Con,,uwr Mm LLC Phone: 907-243-0068 135 Christernen Dr., Sle. 2., Anch, AK 99501 F. 907-243-1073 Eno il: sehd,@,u not MCI((2/132019 "0: INQMYIMOhWECHAMCALI GR OFPRMHOEBAYNT Docks No. OM -064 Page 55 1 CHAIRMAN FRENCH: Fair enough. Thank you so 2 much. 3 COMMISSIONER FOERSTER: I have a question. 4 CHAIRMAN FRENCH: Commissioner Foerster. 5 COMMISSIONER FOERSTER: Did you notice any 6 permanent deformation on any of the inner strings? 7 MR. McCARTY: On well 2-02 the five and a half 8 inch tubing parted. 9 COMMISSIONER FOERSTER: Okay. But how about 10 the inner casing strings? 11 MR. McCARTY: They haven't been recovered yet. 12 COMMISSIONER FOERSTER: Have those wells been 13 P&A'd. 14 MR. McCARTY: 2-03 has been P&A'd, 2-02 is in 15 the process. 16 COMMISSIONER FOERSTER: Okay. And when you 17 P&A'd 02-03 did you recover any of the inner strings? 18 MR. McCARTY: I'll defer to Doug on this one. 19 MR. CISMOSKI: This is Doug Cismoski. We did 20 recover -- we didn't notice any deformity, but again it 21 was hard to see because we recovered it all as one 22 assembly then we removed the upper casing strings on 23 one so we just had a very finite amount to observe. 24 COMMISSIONER FOERSTER: And you do plan on 25 recovering the inner strings from 02-02 as well..... CowulerM rm LLC Phom 9 -243-0668 135 Chrietemen Dr., Ste. 2., Mch. AIC 99501 F. 90' -M-14]3 Er L 4ehi1,@,d. AOGCC L13=9 1TM0: MQMYIMOMOECHAMCALMTEGMWOFPROOHOEBAY WELLS Docket M.OTH W Page 56 1 MR. CISMOSKI: Yes, ma'am. 2 COMMISSIONER FOERSTER: .....and looking at 3 them? Okay. So you're going to a rig decomplete for 4 that well? 5 MR. CISMOSKI: No, ma'am, we were..... 6 COMMISSIONER FOERSTER: How are you going to 7 recover..... 8 MR. CISMOSKI: .....we are attempting to be 9 decomplete, but we would only be able to recover that 10 -- those casing strings above our cut. So from the 11 depth of three feet -- three or four feet below 12 original tundra grade and up would be the casing 13 strings..... 14 COMMISSIONER FOERSTER: So you..... 15 MR. CISMOSKI: .....that we could recover. 16 COMMISSIONER FOERSTER: .....so all you're 17 going to get is a few feet of the -- of the string? 18 MR. CISMOSKI: Yes. 19 COMMISSIONER FOERSTER: Would you be able to 20 get more data if you did -- had more pipe? 21 MR. CISMOSKI: As Thomas mentioned the five and 22 a half parted at near surface, I don't remember the 23 exact depth, but it was somewhere in the realm of 10 24 feet measured from the hanger so I think we can recover 25 that break with the -- with the wellhead removal. COWUW Matrix, LLC Phone: %7-243-0668 135 Chrinenmo @., Ste. 2., Mch. A 99501 F. 90]-243-14]3 Email: sahile(r a,nn AOGCC LIM019 FFMO: MQMYMOM4ECHANICA lI EGRFFYOFPRMHOEBAYW LS Docks No. OM -064 Page 57 1 COMMISSIONER FOERSTER: Okay. That was -- that 2 was the depth of the break on the 02-03? 3 MR. CISMOSKI: This was the 02-02. 4 COMMISSIONER FOERSTER: Okay. Well, so it 5 broke at -- very shallow also? 6 MR. CISMOSKI: The 20 inch casing broke at the 7 depth he mentioned as well as the five and a half 8 tubing on the 02-02. 9 COMMISSIONER FOERSTER: Okay. Thank you. 10 MR. McCARTY: That's all I was intending to 11 present today. At this point in time I'd like to hand 12 over to my colleague, Ryan Daniel. 13 CHAIRMAN FRENCH: Mr. Daniel. Well known to 14 the Commission, and greetings, good morning. 15 MR. DANIEL: Good morning, Chair French, thank 16 you for the greeting. I wish to be recognized as a 17 well intervention engineering and well integrity 18 management expert. May I proceed? 19 CHAIRMAN FRENCH: Please. 20 MR. DANIEL: So good morning, Chair French, 21 Commissioners and AOGCC staff. My name is Ryan Daniel. 22 I wish to be recognized by the Commission as an expert 23 witness representing BP Alaska for the purposes of 24 testimony provided during this hearing. I am the VP 25 Alaska wells intervention and integrity engineering Cor uler Mattie, LLC Phone'. 907-243-0668 135 Chriatauen @., Sle. 2., Anch. AK "MI F. 907-243.1473 Email: eehile utdnel AIX C 2/132019 FF MO: INQMYIN OM4ECNAMCALINTEGMWOFPRLIDNOEBAYW LLS Docket No. OMH Page 58 i team leader. My responsibilities include well 2 intervention engineering, life cycle well integrity 3 management and compliance for PBU's approximately 1,800 4 wells portfolio in Alaska. My role also includes 5 responsibility for regulatory -- for the regulatory 6 interface with AOGCC for drilling, wells engineering 7 activities and well operations regulatory compliance. 8 I hold a bachelor of engineering degree in mechanical 9 engineering from Canterbury University in Christchurch, 10 New Zealand. I have 30 years of postgraduate industry 11 experience in well interventions and well integrity 12 management. I have worked for BP in Alaska for the 13 last 12 years in all aspects of well engineering and 14 well operations with a focus on lifecycle well 15 integrity management. Prior to joining BP I worked for 16 Schlumberger Oilfield Services and held a number of 17 roles in global locations including South Africa, 18 Italy, Australia, New Zealand, Houston and lastly 19 Alaska. I initially specialized in well interventions, 20 well line and perforating and subsequently held a 21 number of leadership roles in operations management, 22 downhole tool development, engineering and sustaining. 23 I've been resident in Alaska for 14 years and am a 24 naturalized U.S. citizen. 25 I respectfully request that the Commission Con uter Manx LLC Phone: 907-243-0 135 Ch W emm Dc. Ste. 2., Aech, AK 99501 F. 907-243-1473 E.L xalule(ulgci.nn AOGCC 2/13/2019 ITMO: INQIRRYINTOWECHAMCALEYFEGR OF PRMHOE BAY WELLS D dd No. OTH-064 Page 59 1 recognize me as an expert witness in the field of well 2 interventions engineering and well integrity management 3 in these proceedings. 4 CHAIRMAN FRENCH: Is there any objection? 5 COMMISSIONER FOERSTER: None. 6 CHAIRMAN FRENCH: Commissioner Seamount. 7 COMMISSIONER SEAMOUNT: No objection. 8 CHAIRMAN FRENCH: That would have been the most 9 shocking thing we learn today if there had been one. 10 So please proceed. 11 MR. DANIEL: Thank you, Commissioner Seamount. 12 RYAN DANIEL 13 previously sworn, called as a witness on behalf of BP 14 Exploration Alaska, Incorporated, testified as follows 15 on: 16 DIRECT EXAMINATION 17 MR. DANIEL: I'm going to go through two 18 topics. So in our written submission we've sort of 19 divided up the topics one through five which were 20 requested by the AOGCC prior to the hearing. So the 21 topics I'm going to be speaking to today are topic four 22 and I'll provide a bit of introduction and background 23 pertinent to this hearing. 24 So subsidence is a naturally occurring 25 geological phenomenon which can impart geological loads Computer Mmnn LLC Phone: %7-243-0668 135 Chum.. 0,. Ste, 2., A h. AR 99501 Paz 907-243-1473 Emdf. sahik(r1i,Bci.nq AOGCC 2/132019 I O: MQWRYI OWECHAMCA MEGRHYOFPRMHOE BAY WELLS Docket Ho, 0TH -064 Page 60 1 onto well casings. As previously discussed BP Alaska 2 has determined that wells prone to sudden rise like 3 that seen on drill site 02-03 were limited to wells 4 constructed in a similar manner with the three string 5 casing stiff design that my colleagues, Doug Cismoski 6 and Thomas McCarty just spoke to earlier. And 7 particularly when these surface casings are landed in 8 the permafrost. The current basis of design for 9 Prudhoe Bay wells consists of two casing string well 10 designs with the surface casing landed well below the 11 base of the permafrost. 12 I'll answer Commissioner Foerster's question 13 from five or 10 minutes okay, I think actually it was 14 Chair French as well, in terms of the base of 15 permafrost and the determination of where that is. So 16 there really is no hard line. The base of permafrost 17 is the zone where the temperature changes from, you 18 know, above 32 degree fahrenheit to below 32 degrees 19 fahrenheit. And you can infer through logs you might 20 have a slightly different result from a temperature 21 log, this is a sonic log, et cetera. So in an 22 abundance of caution the two wells, well specifically 23 01-03 and Franko 4, we deemed them too close to that 24 transition zone therefore they're included in this list 25 and we'll speak more about how we wish to proceed and CoWutu Minix, LLC Phone: 901-213-0668 135 Chdetensen Dc, Ste. 2., Mch. AK 99501 F. 907-243-1413 Email: sehilef8ci net AOGCC VIM019 UMO INQWtYW OWECHAMCALIMEGRI3YOFPRI HOEBAYWELL3 ' Dockn Nc. OTH-06d Page 61 1 P&A those two. 2 Does that answer your question, Commissioner. 3 CHAIRMAN FRENCH: It does. Although I'll just 4 say for the listening public is it true that the deeper 5 you go the hotter it gets in general? 6 MR. DANIEL: Yes, the geogradient, the 7 temperature increases with depth and it depends where 8 you are on your..... 9 CHAIRMAN FRENCH: Thank you. 10 MR. DANIEL: Okay. So let's return here. The 11 casing loading from permafrost thaw onto two casing 12 string well designs is dissimilar to that of the older 13 three string well design like 02-02 and 02-03. 14 Modeling suggests that string failure modes associated 15 with geological loads onto two casing string well 16 designs are subject to changes in (indiscernible) 17 depths resulting in casing compression and potential 18 buckling. So this is unrelated to the tensile failures 19 at surface which we've just had a look at on the two 20 previous presenters. 21 The wellhead and landing ring separation is not 22 used as an indicator of casing (indiscernible) strain 23 by BP Alaska. The conductor is generally free to move 24 independently from the wellhead and therefore the 25 casing. Well.monitoring indicators can be used to C.n W. Metrix, LLC Phom 907-243 B 135 Christman Dr., Sm. 2., Mch. AK "MI Fax:909-243-1473 Email'. sAjte(&gci w AO C 2/132019 I 0, WQMYWOM4ECHAMCAL EGR OFPROOHOEBAYWELL$ noekd Nn. OMH Page 621 1 predict potential (indiscernible) strain such as 2 wellhead elevation movement. It is important to use 3 this as only one data point and not a full 4 characterization of (indiscernible) strain on a well. 5 Other well characteristics such as surface 6 casing string size, completion type and other factors 7 can indicate wells more or less resistive to buckling. 8 These leading indicators along with anomalies observed 9 on the same pad and attributed to permafrost thaw are 10 used to assess the relative risk of compressional 11 strain and potential buckling. 12 So based on the information we've provided in 13 the written submission, I'm going to provide a quick 14 overview of the results from six key drill sites or 15 pads that we have identified. But it's important to 16 note the majority of Prudhoe Bay well pads have minimal 17 observable subsidence as measured on the wellhead base 18 flange. And these measurements, and this was a 19 question that was also posed by the Commissioners, we 20 started measuring base flange elevation with high 21 accuracy in 2011 in the Prudhoe Bay unit. 22 CHAIRMAN FRENCH: And how were you measuring it 23 before then? 24 MR. DANIEL: So typically at the start of a 25 field build out the wells are identified on pad and C.Wwer Metrix, LLC Phone: 901-2430668 135 Christensen Or., Ste. 2., Anch. AK 99501 F. 901-243-1413 E.1 uhik(e�gci.nn AOOCC L13R019 ITMO. MQMYINTOM4ECNANICALINTEGMTYOFPRMHOESAY WELLS Docket N. OTH-064 Page 63 1 they really only had X, Y coordinates to the wellhead 2 center. The well was actually either relative to 3 ground level or part of the rig structure or the drill 9 floor or kelly bushing level. This is insufficient 5 accuracy looking back at legacy wells to determine 6 incremental time lapse -- time lapse subsidence. So 7 we've really only had high quality corrected GPS 8 probably since the, you know, middle 2000s and we 9 started deploying it in Prudhoe Bay in 2011 and 10 selectively across the field based on risk. So each 11 well within Prudhoe Bay unit today has at least one if 12 not multiple based on risk wellhead elevation surveys 13 and that we can track over a period of time, that's why 19 we call it time lapse, the differential movement which 15 is really the subsidence indicator at surface. 16 COMMISSIONER FOERSTER: So you are kind of 17 comparing your baseline to me getting my baseline bone 18 density last year. 19 MR. DANIEL: Absolutely, Commissioner Foerster. 20 COMMISSIONER FOERSTER: Okay. 21 MR. DANIEL: So I can't tell you what happened 22 before 2011, we could postulate that perhaps it is 23 linear, but perhaps it is not so I wouldn't want to 29 speculate on that, but I do have hard data from 2011. 25 CHAIRMAN FRENCH: Proceed. We'll -- thanks. CoWuter Mutnx LLC Phorc: 907-243-0668 135 MUM= Dr., Ste. 2., A ch. AR 99501 Fu: 90]-243-14]3 Em 1: eehileftd= r AOGCC 2/13/1019 IT MO: INQMRYIN OM4ECHAMCALIN GR OFFRM3HOEBAYWELLS Docks No. OM -064 Page 64 1 MR. DANIEL: So just to restate the majority of 2 Prudhoe Bay well pads have minimal observable 3 subsidence as measured on the well base flange between 4 2011 and we shot more surveys 2014. And after the 02- 5 03 event we ran across the whole field again in 2018 6 and reshot every wellhead datum so there was a big 7 survey done in 2018. 8 COMMISSIONER FOERSTER: So you did every well 9 in the field in..... 10 MR. DANIEL: Every..... 11 COMMISSIONER FOERSTER: .....2011 and 2018? 12 MR. DANIEL: We started doing the wells on the 13 west end in 2011, we completed the eastern operating 14 area wells in 2014, that was the first round on the 15 EOA. And we redid all the wells in 2018. 16 COMMISSIONER FOERSTER: Okay. Thank you. 17 MR. DANIEL: So some key results here from a 18 number of pads which do have observable subsidence 19 here. So there are six pads with drill sites which we 20 now monitor more closely and would be deemed at a 21 higher relative risk of subsidence buckling failure. 22 These are L pad and just as a bit of a quantitative 23 figure here, we see a range -- a median annual 24 displacement of about .16 of a foot. You can start to 25 see the minute scale of the measurements here on the Con user Matrix LLC Mone W7-243-0668 135 Chr ite Dr.. Ste. 2., M h. A "501 Fax 907-243-1473 E.I. seh&@,. net AOOCC 2/132019 ITMO: INQMYIWOM4ECHANICALINTEGR OFPRU HOEHAYW LLS Docks No. OTH-069 Page 65 1 wellhead datum. And this is..... 2 CHAIRMAN FRENCH: Mr. Daniel, I'll just stop 3 you. I know you're an English person and I'm an 4 English person, but .16 of a foot seems like a funny 5 way to measure something. 6 MR. DANIEL: With all due respect, Chair 7 French, the amounts of movement are relatively small, 8 but when you actually look at the net displacement over 9 time, for example let's look at L pad or V pad, you can 10 see the annual incremental movement adding up to about 11 a foot or a foot and a half. So the pad that we see 12 today with the most observable surface subsidence 13 measurable movement is actually Victor pad and it is .2 14 of a foot. Basically moving down .2 of a foot. So the 15 mark..... 16 CHAIRMAN FRENCH: Per year? 17 MR. DANIEL: .....that we measured..... 18 CHAIRMAN FRENCH: Per year? 19 MR. DANIEL: Per year, correct. 20 CHAIRMAN FRENCH: Thank you. 21 MR. DANIEL: And just as one other sort of 22 quantitative indicator, so again I can't really 23 determine what happened prior to 2011 with any 24 accuracy, but I can see between 2011 and 2018 that some 25 wells on Victor pad have actually moved a nit between CoWmer Metria LLC Plmne: 907-243-0666 135 Cltrimeamn Or., Ste 2, inch. AR 99501 Fee: 907-243-14n Email sehile(?/gci nM AOGCC 3/132019 FFMO'INQMYI OM4ECHAMCALIWEGMWOFPRUDHOEBAYWELLS Docks No. OM -OW Page 66 1 about one and a half and we've got a couple of wells 2 out there just under two feet. So while the annual 3 rate is pretty small it's fairly linear and it adds up 4 over time. 5 So just to highlight the wells here. So I was 6 requested to provide information on wells with higher 7 relative risk which we provided in the testimony, the 8 written submission. So L pad around .16 of a foot per 9 year and this is a subsidence rate. V pad which is the 10 pad that we see has the highest rate is .2 of a foot. 11 Whiskey pad, .08, Z pad, .08. And we've identified two 12 other pads that are out of the west end area that are 13 still more interesting to us in terms of subsidence 14 risk because we are seeing a small amount of movement. 15 H pad, .07 of a foot. And all of these are moving in 16 the downward direction, these are all subsidence rates. 17 CHAIRMAN FRENCH: Sir, did you say .7? 18 MR. DANIEL: .07. 19 CHAIRMAN FRENCH: Oh, .07. Yeah. 20 MR. DANIEL: .07 of a foot. 21 CHAIRMAN FRENCH: Big difference. 22 MR. DANIEL: In drill site 2.03. So you can 23 see that the measurements are very -- very small on an 24 annual basis, but they do add up over time therefore we 25 feel the best way to understand and manage the risk is Con vw M rm LLC Phone: 901-243 8 135 Chriam n Dr., Ste. 3., Mch. AK 99501 FU, 907-3tlJ413 Em 1: s le(%gci.nn AOGCC VM019 R O: MQMRYMTOM4ECMMCA MEGMYOFPROBHOEBAYWELLS U dd % omH Page 67 1 to assess the (indiscernible) frequency based on risk. 2 If there are no further questions I may move 3 on. 4 CHAIRMAN FRENCH: Please. 5 COMMISSIONER FOERSTER: Why -- wait, before you 6 go. Why are you estimating it because you have really 7 precise tools and measurements now? 8 MR. DANIEL: Sorry, Commissioner Foerster, I 9 did not understand the question. 10 COMMISSIONER FOERSTER: Oh, never mind, I'll 11 ask it later. 12 MR. DANIEL: So I mentioned that measuring the 13 base flange elevation of a well is one data point. 14 Well downhole surveillance leading indicators basically 15 through tubing drifts, are run through the wells to 16 confirm access to the reservoir. The drift tools used 17 -- the drift tools are sized to the well tubing size 18 which is basically the string ID and typically 20 foot 19 long. The technique provides a better indication of 20 axial displacement in the tubing. If a shallow tubing 21 anomaly is observed follow-up diagnostics are performed 22 which may include tubing calipers, mechanical integrity 23 testing, pressure tests and well barrier diagnostics. 24 So wells with known drift anomalies. 25 Today we have five wells, Whiskey 200 is a CoWWer MMiM LLC Phone:9 -243 8 135 Christensen @., Ste. 2., Mch, AR W501 F. 901343-1413 Erml =1ti1e@Bci w AOGCC 2/132019 RMO: INQOIBYIN OM4ECHANICA lI GBFFYOFFBOOHOEBAYW LLS Oockn No. OMH Page 68 1 tubing compression that's been identified not actually 2 through drifting, through a caliper log. This is 3 actually not associated with the permafrost because the 4 tubing is buckled down to a five, 6,000 feet or so. It 5 is not at high risk. 6 We have three other Lema pad wells which we're 7 performing caliper diagnostics on. Some of these may 8 be related to production deposits, schmoo (ph) 9 paraffin, et cetera. We're actually going to run some 10 calipers on those wells and determine whether or not 11 these deposits can be removed or whether there is 12 actually something else going on there. 13 We've got one well on Sierra pad. Again we 14 suspect it's paraffin. In many cases we do have 15 paraffin build-ups in our wells so when you have a 16 drift anomaly it's not an automatic aw, this well has 17 subsidence. Generally the production chemistry changes 18 in cross section, et cetera, and changes in temperature 19 and velocity can lead to accumulation of paraffins, 20 waxes, this sort of thing. And for injectors the solid 21 material called schmoo. 22 So in the last probably two to three years 23 we've identified three wells which we've actually 24 determined did have shallow subsidence related 25 buckling. These wells are Victor 119, Victor 201 and Cotryuter M n, LLC Phone: 9-7A3-Ofi68 135 Chrinensen Or., Ste, 2., A h. A 99501 F. 907-2A-1473 Erred: a ikftamm AOGCC VIM019 FIMO: INQMY1 OM4ECH CALI GMn OFPRGOHOEBAYW LLS Docks No. GTN -0" Page 69 1 well 02-37. So 02-37 was a well that we determined had 2 a shallow tubing obstruction and we've plugged and 3 abandoned that well and eliminated the risk in 2018. 4 Victor 201 was plugged and abandoned in 2017 and Victor 5 119 was part of our 2018 planned plug and abandonment 6 program. 7 So since 2016 we've conducted 460 subsidence 8 through tubing drifts across the field. 9 COMMISSIONER FOERSTER: Does that cover all the 10 wells on the -- on the pads that you were most 11 concerned about? 12 MR. DANIEL: Yes, it does, Commissioner 13 Foerster. 14 COMMISSIONER FOERSTER: Thank you. 15 MR. DANIEL: These are risk targeted drifts and 16 we have..... 17 COMMISSIONER FOERSTER: Thank you. 18 MR. DANIEL: .....basically we increased the 19 frequency of drifting based on factors including 20 construction of the well, its location and other wells 21 on the pad that have maybe subsidence indicators like 22 base flange elevation changes. 23 So at this stage if there are no more questions 24 on subsidence per se, I've given you a quick highlight 25 of some downhole work we've done to identify drift Co"uterM rix LLC PMne: 90'1-24N156H 135 Ch gv n Or, Sm 2., Mch. AK 99501 F. 90]-243-14]3 F.I. sahile(ajgci net r AOGCC 3/132019 IWO. INQMYIWOWECHANICALIWEGMWOFPRODHOEBAYW S Docks NoOiH-064 Page 70 1 anomalies and basically progressed those through the 2 diagnostics process leading towards either establishing 3 the well barriers are sound or taking more definitive 4 action in the case of P&A'ing three of the wells. 5 We've talked about the wellhead elevation surveys and 6 how these are used to basically screen wells. Where 7 we're seeing wellhead elevation change at a reasonably 8 high increment or rate and when I say high these are 9 fairly small numbers, .1, .2 of an inch per year. We 10 also raise the relative risk of those pads and wells 11 and conduct downhole drifts. So we feel that 12 management strategy is sound, it's also based on North 13 Slope and industry best practice. 14 If there are no more questions pertaining to 15 subsidence with the -- with Chair French's approval I'd 16 like to talk about section 5 which is on -- we're onto 17 well integrity actually and sustained case and pressure 18 management. 19 CHAIRMAN FRENCH: As Commissioner Foerster -- 20 we're managing our time and your time and want to be 21 respectful, we will have questions about subsidence and 22 other matters, but let's keep going and then we'll take 23 a break and go from there. 24 MR. DANIEL: Thank you, Chair French. The two 25 questions I noted down, so I think we've answered both CoMmer Metnr, LLC P . %7-343-0668 135 Odttemm Dr., Ste, 2., A h, A 99501 Fax 901-343-14'13 Email: sehile(dgci.net AOGCC 2/132019 I O. INQOIRYIWOM4ECHAMCAL EOR OFPROOHOEBAYWHLL$ Docket No, 01EH-1164 Page 71 1 of them and I think it was Commissioner Foerster's so 2 tell me if it wasn't -- if we haven't answered your 3 question on base flange elevation measurements, when 4 did they start..... 5 COMMISSIONER FOERSTER: You did. 6 MR. DANIEL: .....as related to your bone 7 density comment. 8 COMMISSIONER FOERSTER: I'm worried more about 9 subsidence than bone density today. 10 MR. DANIEL: Commissioner, I'm in the same 11 camp. 12 So let's move on. I've got an introduction on 13 the Prudhoe Bay well integrity measurement system. 14 So BPX -- so BP Alaska has a robust and time 15 proven well integrity management system in Prudhoe Bay. 16 It is based on global industry standards, best 17 practices and local learnings. The system has been 18 continuously improved over multiple years with the most 19 recent example being field wide implementation of 6,000 20 wireless, well annulus pressure and temperature 21 transmitters. This leading edge technology will 22 improve safety and decrease environmental risk by 23 reducing the response time to well pressure anomalies 24 and events. Typically what used to take 24 hours for a 25 single manual tubing inner or outer annulus well Cowma Metro, LLC Phone: 907-243-0668 135 Cheietmsm R., Ste. 2., Mch. A 99501 Fen. 90]-243-14]3 Emailethile ftci net IOG(( 2-32019 RMO: INQMYIWOM4ECH CALIWEORFFYOFPRMHOEBAYW LLS Docket No.OTH- Page 721 1 reading can now be automated every minute in all 2 weather conditions. This provides an effective well 3 operating pressure limit notification with alarm alert 4 capability to the control room inboard operator. 5 BP Alaska's well integrity management system 6 incorporates practices from API 90 which as most of you 7 know is sustained casing pressure management and other 8 industry standards and complies with Alaska Oil and Gas 9 Conservation Commission regulations and orders that 10 prescribe safe flow management practices to effectively 11 mitigate sustained casing pressure. 12 Prudhoe Bay unit is a giant mature field with 13 approximately 1,800 wells, 47 gravel pads, seven 14 primary processing facilities, two gas plants, two 15 seawater treatment plants, PBU facilities handle 16 average daily production volumes of 7.4 billion 17 standard cubic feet of gas per day, 1.1 million barrels 18 of water per day and 280,000 barrels of oil per day. 19 Obviously this year a little lower due to decline. 20 Prudhoe Bay facilities also handle, this is the 21 other half of the equation which most people don't see, 22 average daily injection volumes of 6.6 billion standard 23 cubic feet of lean gas per day, 1.5 million barrels of 24 produced water and seawater including gas cap water 25 injection and 230 million standard cubic feet of C.Ww, Mmn; LLC Phone: 90-243-0 135 Chrivemen Dr., Ste. 2., Arch. AK 99501 F. 909-43-1493 Email: Wfil.@gci.net AOOCC 2/13/2019 "0INQMYWOWECFIANICAIdNTEGRITYOFPRODHOEBAYW LLS Docket No. OM -W Page 73 1 miscible injectant. And these figures are from 2017. 2 The wells are managed and monitored throughout 3 their respective lifecycle by dedicated professional 4 teams to minimize health and safety risks, prevent 5 environmental damage and ensure regulatory compliance. 6 BP Alaska as Prudhoe Bay unit operator conducts 7 multiple rig and non -rig intervention well work drops 8 annually to maintain well stock health, operational 9 availability. This well work builds on BP Alaska's and 10 successful industry leading track record of successful 11 well interventions at giant field scale which has 12 delivered worldclass safety in hydrocarbon recoveries. 13 For some numbers or statistics from our 14 portfolio of wells we have -- and these figures are 15 plus or minus, 1,274 producers, 36 big bore gas 16 injectors, 362 other injector wells which include water 17 injectors and miscible injectant wells, 21 waste 18 disposal wells and 76 suspended wells. In an average 19 year in well integrity activities, well integrity 20 management in Prudhoe Bay, sees us responding to 400 21 reporting well integrity reported voluntarily 22 anomalies. These are reported by operations and the 23 wells group on observation or by daily or other 24 exception reports or indicators. We've conducted 25 typically three to three and a half thousand C.Wwa Main, LLC Phone'. 907-243-0668 135 Chrioeo en Dr., Ste. I. Anch. "99501 F. 901-24344]3 Email: while n;en nes AOGCC 2/132019 ITMO. MQOIRYMT0M4ECHAMCAL3 GR1W0FPRMH0E BAY WELLS Docks No. om-064 Page 74 1 inspections from well diagnostic technicians to 2 validate well readings and evaluate anomalies. We 3 placed 120 wells under evaluation so I'm not sure the 4 Commission is aware, but we have a pretty simple 5 approach to determining whether a well is operable or 6 not. And we'll go into it a little bit more and talk 7 about barriers. 8 But we have three types of wells, we have 9 operable wells which meet our goal barrier requirements 10 and requirements by the Commission, intensive 11 compliance and are okay to flow. We have nonoperable 12 wells which don't meet our requirements to flow or that 13 of the Commission. And we have a small class of wells 14 called under eval wells which are wells we're looking 15 at the barrier system. And my team and colleagues on 16 the Slope use a number of diagnostic tools to determine 17 whether the well barriers are healthy and whether that 18 well can actually be put on production safely as an 19 operable well or injection. 20 So 120 wells placed under evaluation for 21 anomaly confirmation. Of that number approximately 65 22 percent of these wells are returned to production 23 within 28 days on confirmation of well barrier 24 diagnostics. We conducted 128 downhole pressure tests 25 for well barrier confirmation based on regulatory CoWuter Matrix, LLC Phone: %7-2A3-0 155 Chrinensen M., Ste. 2., Mch. AR 99501 F. "7.243-1473 Email: s ile(4gci.net AOGCC 2/13/2019 RMO: MQHIRYIWOM4ECHANICALIWEGMI OFPRHDHOEBAYW LLS Dock. No. OM -064 Page 75 1 compliance requirements. We've conducted another 339 2 pressure tests of well downhole barriers for internal 3 conformance. And these are just some notional numbers 4 on a given year. We've also conducted 350 wellhead 5 jobs, diagnostics, packer repairs, this sort of thing 6 and 250 API valve shot jobs. And often these are valve 7 repairs, surface safety valve, ring valve, jewelry, et 8 cetera. 9 What I'd like to do now with your permission is 10 really go to the high point of the section 5 which in 11 my view is -- let me just flip over to it here in the 12 -- in the written submission. 13 CHAIRMAN FRENCH: And if you're referring to 14 section 5 you mean on the document dated February 6, 15 2019? 16 MR. DANIEL: That is correct. 17 CHAIRMAN FRENCH: Thank you. 18 MR. DANIEL: And it's actually section 5.8, 19 page number 27. So the Commission asked us how will BP 20 Alaska reassess plug and abandonment plans for long 21 term shut-in wells and suspended wells that have no 22 future utility in light of the two failed wells. So 23 I'd like to turn over actually to the -- the next page 24 is page number 28 on the written submission of February 25 6 and I'm looking at table and it's -- the high level Cowgate, M.ri,I Phone:9 -243-0668 135 Chri...m Dr., Ste. 2., Aneh. AK 99501 F. 90]-243-14]3 E rW]: sehikC%,i.0 AOGCC 3/132019 ITMO: WQOIRYINTO WECHAMCALINTEGWTYOFPROOHOEBAY WELL$ Docks No. MH{ Page 76 1 heading is (a). So BP Alaska along with the Prudhoe 2 Bay co-owners have submitted a three year plan and 3 these are wells that typically have been long term 4 shut-in. Some of these wells have barrier impairments 5 and we have prioritized these wells for plug and 6 abandonment. So we have proposed to the Commission, 7 we've not had a response yet, that in 2019 we will P&A 8 a list of eight wells, same in 2020 and on into 2021. 9 So this is part of an ongoing agreement we've reached 10 with the Commission under 0TH -16-038. And this is 11 really a key part of our risk elimination process, 12 removing long term shut-in wells that have no future 13 utility and starting with the wells that have the 14 highest perceived risk of loss of primary containment. 15 So this table of plug and abandonment activity 16 is independent from the list and let's actually flip 17 over a page or two and I'll identify it shortly. That 18 we want to go onto page 29. So under a very recent 19 order post the 02-02 incident, the order or the docket 20 number is 0TH 18-062. The AOGCC ordered the 14 wells 21 which include 02-03 and 02-02 to be plugged and 22 abandoned in the 2019 calendar year. We're progressing 23 on all of these wells. The well engineering programs 24 have been submitted for review by the Commission. The 25 majority -- I think we're just waiting for one now, and CoMutw Mmrix, LLE Phone: 907-243-0668 135 Chriaems Dr., Ste, 2., Anch, AK 99501 Fax 907-243-1473 Email sahilefto nn AOGCC NIM019 ITMO'. INQMY IWO 1,14ECHAMCALINTEGRITYOFPRMHOE BAY WELLS Docket No. OTH Page 77 1 we're actually moving forward with well operations to 2 plug and abandon these wells. 3 BP Alaska along with Prudhoe Bay co-owners also 4 propose abandoning four additional wells in 2020. And 5 it's a proposal, we have not received confirmation from 6 the Oil and Gas Commission yet. These four wells are 7 Franko 4, Mario 1, Echo 28 and 01-03. And these are 8 all wells that..... 9 CHAIRMAN FRENCH: And where are those listed? 10 I'm sorry. 11 MR. DANIEL: This is on page 29 and the table 12 heading is under (b). 13 COMMISSIONER FOERSTER: Right. 14 CHAIRMAN FRENCH: I see. Oh, thank you so 15 much. Commissioner Foerster's pointed it out, I see 16 them right there. Thank you so much. 17 COMMISSIONER FOERSTER: And these are 18 additional wells beyond the ones that we've ordered you 19 to plug in the 2019 year? 20 MR. DANIEL: Correct, Commissioner Foerster. 21 These are additional wells. As my colleague, Mr. 22 Cismoski, pointed out we have completed an internal 23 review, we've run our modeling on the structural side 24 of the five wells and we've submitted a request to 25 operate these wells mid 2018 to the AOGCC. The AOGCC C.Metel Metrix, LLC M. 901 -WA 68 135 MiAnnxn 1k, Ste. 2., Anch. AR 99501 I. 907-243-14'13 Entail'. while tta net i 2/13/2019 R O: MQMYM OMOECH CALIIYIEGMT OFMR HOEBAYWELLS D ckm No. O OH Page 78 1 reviewed our five study well report and authorized 2 these wells for operation. So if you take those five 3 wells out of the original 23, what we have on the 2019 4 and 2020 P&A list is 100 percent of the at risk wells 5 that may or may not fail with the surface tensile mode 6 failure as described by my colleague, Mr. McCarty. 7 COMMISSIONER FOERSTER: Are there any on the 8 2020 list that you see as a higher risk, but you're 9 only putting them off because you wanted to comply with 10 our requirements on the other ones first? 11 MR. DANIEL: No, Commissioner Foerster. So if 12 I could just pop through them briefly. We'll start 13 with Mario 1. That well actually has already been 14 suspended and has a deep reservoir plug, very, very low 15 probability of loss of primary containment. Well 16 Franko 4 and well 01-03 are both wells with the surface 17 casing set right at the base of the permafrost. We see 18 these also as a lower -- lower probability of upwards 19 movement similar to 02-03 and 02-02. If you recall the 20 surface casing on those wells and the other 12 that 21 looked like it, the surface casing shoe is set between 22 1,000 and 1,200 feet, not at 18 or 1,900 feet. So 01- 23 03, Franko 4, are basically right through the 24 permafrost, but they're not in structurally sound rock 25 beneath the permafrost. And the last well, Echo 28, CoMuterM v, LLC P ne: 907-243-0668 135 CkWel en M, Ste. 2., Anch. AK 99501 Fez 907-2434473 Email. while r(i,Sci nei AOGCC 2/138019 FFMO: MQMRYMiOM4ECHAMCA WEGMYOFPRMHOEBAYWELM Mae M. omH Page 79 1 this is a two string well. Again we see very low 2 likelihood and it's more likely that 02 -- Echo 28 3 would suffer compressional buckling failure not tensile 4 differential failure at surface. I think the wells 5 we've nominated for 2020 are lower risks than the wells 6 we have and the Commission obviously agreed with us and 7 ordered us to plug and abandon the 14 wells in 2019. 8 COMMISSIONER FOERSTER: Thank you. That 9 answers my question. 10 MR. DANIEL: I'll pause there, Chair French. 11 If the Commission have any questions on topics four or 12 five I'd be happy to take them. 13 CHAIRMAN FRENCH: Again just for planning 14 purposes, I'm looking at the clock and I'm going to see 15 -- I'm going to say 11:30 we're going to just take a 16 little concentration break kind of no matter what. So 17 why don't you continue..... 18 COMMISSIONER FOERSTER: How much longer do you 19 have? 20 MR. DANIEL: That's really it, Commissioner 21 Foerster. It's really open to questions now from the 22 Commission. 23 CHAIRMAN FRENCH: Well, then excellent. 24 COMMISSIONER FOERSTER: I have -- I have 25 several questions, but I want to have -- take a break Con uter MYnx LLC Phone 9 -243 g 135 Christensen Dr., Ste. 2., Mch. AK 99501 F. 90]-243-14]3 Em 1:s ileftci.nu AOGCC 21132019 I 0. INQOIRYIWOWECHAMCALMTEGR YOFPRODHOESAYWELLS Docket No. OM&l Page 80 1 so that my staff can eliminate the stupid ones and I 2 don't want to waste you guys' time with those and make 3 me look stupid. So I'm going to wait. 4 CHAIRMAN FRENCH: That does raise the stakes 5 for the rest of those questions. 6 COMMISSIONER FOERSTER: Yes, it does. 7 CHAIRMAN FRENCH: But I generally am the one 8 who asks the simple questions because -- anyway let's 9 do this. Let's use our Iphones because that clock back 10 there is not so good. My Iphone says 11:26. Let's 11 take 20 minutes. We'll come back at 11:46 or 11:45. 12 Everybody got it, 11:45. 13 Thanks so much. We're on recess. 14 (Off record) 15 (On record) 16 CHAIRMAN FRENCH: We'll go back on the record. 17 I have some good news and I have some bad news. The 18 good news is we're going to break now for lunch and 19 come back at 1:00 o'clock and then we'll come back at 20 1:00 o'clock. 21 COMMISSIONER FOERSTER: The good news is we're 22 going to break and come back at 1:00, the bad news is 23 (indiscernible - simultaneous speech)..... 24 CHAIRMAN FRENCH: Well, I -- you know, I'm not 25 sure who that's bad news, for. I think this is a Congener Matrix LLC Phone: 901-213-0 135 Christensen Dr., Ste. 2., Mch, AK 99501 Fee: 901-U34413 Email eehile&d.ei AOGCC 2/132019 1 M0 WQMY1 OM4ECHANICALINTEGMTYOFPRMHOEBAYWELLS Docket N. OTH-064 Page 81 1 productive hearing so I guess I just thought at the 2 last minute I would not call that bad news. But we 3 will break now, come back at 1:00 and then Commissioner 4 Foerster will lead some questions on the engineering 5 details. 6 So that's what -- that's the schedule. See you 7 all at 1:00 o'clock. 8 (Off record) 9 (On record) 10 ACTING CHAIR SEAMOUNT: Okay. We're going to 11 reconvene this meeting. Chair French had to leave 12 unexpectedly so lucky you, you get me to chair this 13 meeting. And unlucky you Commissioner Foerster gets to 14 ask the questions since I'm just a geologist and we 15 have more than enough engineers in here. 16 So take it away, Cathy. 17 COMMISSIONER FOERSTER: Well, first I want the 18 record to reflect that one can never have enough 19 engineers. 20 But before we start questions, Commissioner 21 French wanted me to disclose to BP that while he was 22 walking to lunch he was in front of a couple of BP 23 people and he heard them say drill site 02-03 and 24 that's essentially all he heard them say, but if BP 25 feels that that might have been him eavesdropping, C.Vtd r Mnm LLC Phone: 909-243-0668 135 Chrinens Dr., Ste. 2., Mch. A W501 Fax 907.243.1473 Em 1: v ileftd.nn AOGCC 2/132019 ITMO. IHQMYB OM4ECH CALIHTEGMn OFPRODHOEBAYWELLS DocketPb. OT W Page 82 1 getting ex parte information, it's your call. And I 2 guess what that -- he didn't tell -- you know, that's 3 all he told us. So if you guys want us to recuse him 4 from the decision or, you know, if you have another 5 opinion on how you'd like us to respond to that, it's 6 totally up to you guys. 7 MR. DANIEL: Commissioner Foerster, do we have 8 to make a decision at this time or can we speak to the 9 Commission after the hearing? 10 COMMISSIONER FOERSTER: Well, I think you've 11 got an attorney that is..... 12 MR. DANIEL: We do. 13 COMMISSIONER FOERSTER: .....is bouncing in his 14 chair. Please approach. And introduce yourself. 15 MR. WYATT: Commissioner, I'm Chris Wyatt, 16 attorney for BP. So is it all right if I talk to my 17 clients in private? 18 COMMISSIONER FOERSTER: Oh, sure. Let's take a 19 five minute recess. 20 ACTING CHAIR SEAMOUNT: How much time do you 21 need. 22 MR. WYATT: Five minutes should be sufficient. 23 ACTING CHAIR SEAMOUNT: Five minutes or..... 24 COMMISSIONER FOERSTER: We'll take a five 25 minute recess. Co.ryotet Metm LLC Phone:9 -243-0 135 Christensen IN, Ste. 2., Anch. A W501 F. 907-243-1473 E.d s Aeft, e..net r AOGCC L13=9 13 0:WQMYWOMIECH CALIH GR OFPRHDHOEEAYWELLS Docker W. MAM Page 83 1 COMMISSIONER ACTING CHAIR SEAMOUNT: We can take a five 2 minute recess or..... matter or not. 3 MR. KLEIN: COMMISSIONER FOERSTER: Everybody stay put 4 except you guys..... objection. 5 COMMISSIONER MR. WYATT: Can we step out? right. You can't be 6 COMMISSIONER FOERSTER: Yeah, you guys can step 7 out. 8 ACTING CHAIR SEAMOUNT: Yeah, you guys can step 9 out where it's quiet and..... 10 COMMISSIONER FOERSTER: And if our larger 11 conference room is not in use and you want it to be 12 private go in there. 13 MR. WYATT: Thank you. 14 (Off record) 15 (On record) 16 ACTING CHAIR SEAMOUNT: Back on the record at 17 1:06. 18 COMMISSIONER FOERSTER: So the question is does 19 BP want Commissioner French to recuse himself from this 20 matter or not. 21 MR. KLEIN: Commissioner, we don't believe 22 these people were BP employees so we are -- have no 23 objection. 24 COMMISSIONER FOERSTER: Okay. Thank you. All 25 right. You can't be too careful. C.nwer Matrix LLC PMne. 901-X3-0 135 annensen m., Ste. 2., Anch. AK W501 Fax: 90]-263-1413 Email: s Ae(a) dnet AOGCC VM019 RMO: INQOIBYMTOM4ECHANICAL EGR OFPRODHOEBAYWELIB Docket No. OM --0 • ' i 1 So I do have several questions and I was 2 relieved that my staff was sucking up and said none of 3 them were stupid so I'm going to ask them all. And 4 they're going to be in no particular order, they're 5 going to be kind of in the order that I thought of 6 them. So there may be a little jumping around so 7 please forgive me. And whoever is the best to answer 8 them just -- since the court reporter won't have a 9 picture of this just as you start to answer a question 10 remember to say this is Doug Cismoski or -- okay. 11 So could you describe the details of what you 12 did in your operability study? 13 MR. CISMOSKI: This is Doug Cismoski, I can 14 answer..... 15 COMMISSIONER FOERSTER: Okay. 16 MR. CISMOSKI: .....hopefully I can answer that 17 question. So the operability study conduct -- 18 consisted of some of the detail modeling that Thomas 19 McCarty had referred to for what we had done for 02-03 20 and then subsequently 4-02. 21 COMMISSIONER FOERSTER: Okay. So you modeled 22 the well that had failed and you modeled one other 23 well? 24 MR. CISMOSKI: The one other well was..... 25 COMMISSIONER FOERSTER: The drill site 4? CoMwer Matrix,L Phone: 907-243-0668 135 Chriga Dr., Ste, 2., Anch. AK 99501 Fee: 90]-243-14)3 Email sahile(a�gdnet 2/13/2019 RMO: INQMYIF OWECHANICALINTE MYOFPRMHOEBAYWELLS Docket No, 0311-064 Page 85 1 MR. CISMOSKI: .....drill site 4..... 2 COMMISSIONER FOERSTER: Okay. 3 MR. CISMOSKI: .....for that operability study. 4 There were some -- looking at the cementing operations 5 from one of the wells constructed in detail, there were 6 a lot of uncertainty about where top of cement was in 7 -- in the annuli just based on the completion. Because 8 of that uncertainty we really couldn't determine or 9 make a call to say that the surface casing was affixed 10 with any certainty to the thirteen and three-eighths. 11 This was the 20 by 13 that we're talking about. And so 12 because of that and because of the modeling results it 13 still appeared that there was a risk of that well 14 rising suddenly. We looked at ways to mitigate that, 15 we couldn't find any comparable mitigation. There was 16 a workover done in the early 2000s that even though the 17 wellhead was moved off of -- the starting head was 18 moved off the 20 inch back to the -- either the nine or 19 the 13, I can't recall, but we still did a top job 20 which was pumping cement from surface and affixed the 21 20 inch to the 13 and three-eighths which effectively 22 for the intents of this modeling basically affixed that 23 casing back at the wellhead height. So that's what we 24 did, we still had that type of a well scenario and 25 because of the uncertainties we looked at it. So Cmrymer Win , LLC Mn.: 90]343-0668 135 Chrietenten Dr., Ste. 2., Anch. AK 99501 Fax 90]3A3-14)3 E.il: to tile([... 1 AOGCC 2/132019 UMO:MQMYI OM4ECH CALINTEGMnOFMMHOEB"Y LLS Docket No.O HA Page 86 1 there's really no way we can keep our -- keep our work 2 crews or people safe. 3 COMMISSIONER FOERSTER: So the probability is 4 that it was just one the drill site 4 well? 5 MR. CISMOSKI: As a -- as a type well, as a 6 typical well of this nature. 7 COMMISSIONER FOERSTER: Okay. 8 ACTING CHAIR SEAMOUNT: What was the acronym 9 for the operability study? 10 MR. CISMOSKI: Risk assessment. 11 ACTING CHAIR SEAMOUNT: Risk assessment? 12 MR. CISMOSKI: We did a level two risk 13 assessment. 14 ACTING CHAIR SEAMOUNT: What are the initials. 15 COMMISSIONER FOERSTER: So between the time -- 16 between now and the time that you plug the 13 wells 17 that are in the 2019 program, your -- you got signs up 18 and scaffolding around all of them, right, is there -- 19 is there anything else that you're doing to assure that 20 they pose no risk? 21 MR. CISMOSKI: For those remaining wells that 22 are not operable so wells 1 through 17 and wells number 23 22 and 23..... 24 COMMISSIONER FOERSTER: Uh-huh. 25 MR. CISMOSKI: .....we're removed the C.�Wt , Metrix LLC Phme: %7-243.0668 135 C9nistemn p., Ste. 2., Anch. A 99501 F. 907-243-1473 Emil: whileO End AOGCC 2/13/2019 ITMO:MQVMYD OM4ECNAMCALI GR OFPRODHOEBAYWELLS Docks No. 0TH -064 Page 87 1 wellhouses, removed the flowlines, have mechanical set 2 plugs installed in most of these and I'm excluding the 3 operations that are ongoing on 02-02 and 02-03 is 4 actually cemented all the way to surface. And we've 5 got scaffolding being erected around the majority of 6 those wells. The intent is to get them -- get the 7 scaffolding around all the wells to allow us access to 8 the tree valves so we can work on them as well as 9 allowing for potential movement upward of the tree. 10 But that last bit of work is still in progress. 11 COMMISSIONER FOERSTER: Okay. And you say you 12 have mechanical plugs in all of the wells? 13 MR. CISMOSKI: Yes. 14 COMMISSIONER FOERSTER: Okay. 15 MR. CISMOSKI: Yes, we do. 16 COMMISSIONER FOERSTER: Did you have -- didn't 17 you have a mechanical plug in the 02-02 well when it 18 failed? 19 MR. CISMOSKI: Yes, we did. 20 COMMISSIONER FOERSTER: Okay. So do you have 21 any assurances that these plugs will do anything to 22 prevent the problem that occurred in the 02-02 well? 23 MR. CISMOSKI: Yeah, the -- in the case of 02- 24 02, that particular plug was definitely a pretty good 25 restriction to flow, in there was a mechanical Comwer MelnK LLC Phone. 90-l-243-0668 135 OnMerenn Dr., Ste 2., Anch. A W501 F. 907-243-1413 Ennui: sehile(dgci.rot AOGCC 2/13/2019 MO: MQOIRYMTOWECHAMMIL GMW OF PRODHOE BAY WELLS Docks W. DTH Page 88 1 restriction to flow. There are in some cases with our 2 wells and depending on what's wrong with the wells, you 3 can't always positively pressure test the plug. For 4 example setting a plug in the tubing below the packer 5 with a tubing leak for example or couple that tubing 6 leak with a small production casing leak at depth. 7 When we apply that pressure at surface we can't get a 8 positive pressure test on there, but through the trend 9 -- through tending and through monitoring of it we can 10 determine that it's obstructing the flow or, you know, 11 obstructing the flow of the reservoir to surface. In 12 the case of 02-02 we believe we had a plug of that 13 nature in there and in reality there was two plugs in 14 there. There was a cast iron bridge plug set in the 15 cold tipping drilling liner back in 2006, but upon 16 bleed off with that, it didn't bleed off and stay down 17 in pressures so we suspected that the liner lap on that 18 coil drilling completion was leaking. So thus we stuck 19 a -- set an inflatable bridge plug in the packer bore 20 and that was the plug that we had in 02-02 when it -- 21 when it released. 22 COMMISSIONER FOERSTER: So why do you think 23 with that p lug in there it released? 24 MR. CISMOSKI: We think that either there's a 25 production casing leak that's allowing that small CoMutw Matte LLC PMne: 901-243-0668 135 Chrirte m Dr., Ste. 2., A h."99501 F. 901-243-1413 Emil: ¢ ileggci.nn AOGCC VIM019 IIMO: INQMYIWOMAECHAMCAL EGR OFPRODHOEBAYWELLS Page 89 1 communication or the production packer itself could be 2 leaking. 3 COMMISSIONER FOERSTER: So you put plugs in 4 these other wells, do you have assurances that those 5 scenarios don't exist in those wells? 6 MR. CISMOSKI: We have..... 7 MR. DANIEL: Commissioner Foerster, if I may. 8 So we're progressing ahead..... 9 COMMISSIONER FOERSTER: Don't forget to 10 introduce yourself by name. 11 MR. DANIEL: Sorry. Ryan Daniel. If I could 12 just answer part of that question. So we're moving 13 ahead now with the 90 day requirements which we 14 recently received approval for the 13 wells within the 15 list on the wall to my right. We're moving ahead with 16 plans to circulate out to kill weight fluid in these 17 wells and establish zero surface pressure condition in 18 both the tubing and annulus which effectively, you 19 know, mitigates any LOPC reservoir leak to surface. 20 COMMISSIONER FOERSTER: Okay. Thank you. So 21 drill site 2-02 and 03 both had casing repairs in the 22 early to mid '70s between the time they were drilled 23 and the time that they were brought on production. Did 24 any of the other three string wells have repairs like 25 that early in life? CowutcM it L1 Phone: W7-243-11666 135 Migm n Dr., Ste. 2., Annh. AK W501 Fu: 907-303-1473 Emeil'. sehik(a)gti.net AOGCC 2113@019 ITMO: INQUIRYM OM4ECH CALF GMWOFMMHOEBAYWELLS D d No. orH- Page 90 1 MR. CISMOSKI: This is Doug Cismoski. Some 2 did, but I cannot tell you at this time which wells 3 they were specifically that had that type of activity. 4 COMMISSIONER FOERSTER: Okay. Do you know what 5 the purpose of the workovers was, what -- what you were 6 trying to fix or achieve? 7 MR. CISMOSKI: Yeah. Yeah, looking at the 8 records at least for 02-02 and 02-03 and some of the 9 other wells that I can't recall right now which ones 10 they were, it appeared that right after drilling those 11 wells in -- around the 1970 time frame the annuli 12 weren't freeze protected and they froze and thus 13 collapsed the inner strings so these workovers were 14 intended to do basically production and intermediate 15 casing repairs. 16 COMMISSIONER FOERSTER: So I'm a little 17 confused. If there was no production -- well, never 18 mind. I answered my own question. 19 Okay. Were there any two string wells that 20 were repaired before production start up, two casing 21 string wells? 22 MR. CISMOSKI: I don't know that. 23 COMMISSIONER FOERSTER: Would somebody for BP 24 keep a record of the questions that will require 25 follow-up because we'll leave the record open for some CoMurer Mattix LLC Phone: 907.243-0 135 Chr .a n Dr., Sl . 2., M& A1C 99501 Fav: 907-243-1403 Email: mhikftci.na AOGCC 2/1313019 R O: MQMYI OM4EC3 CA TWEGB OFMMHOEBAYWELLS Wck> No. OM " Page 91 1 period of time so that you can answer the questions 2 that you're not able to do today. 3 So what is the status of the final report on 4 the 02-02 failure? 5 MR. McCARTY: Final report's under -- under 6 review and we're just trying to make sure it's of the 7 highest quality and it'll be available within a matter 8 of weeks. 9 COMMISSIONER FOERSTER: And we will get a copy 10 of that? That was a question, not a statement. 11 MR. McCARTY: Yes. 12 COMMISSIONER FOERSTER: Okay. Okay. So I'm 13 going to go back to the 02-02 and 02-03. You did your 14 modeling and you told me that your modeling was 15 supported by your -- what you got from the pieces of 16 casing that you were able to extract, but you based 17 your modeling -- it seemed like a little bit of 18 circular logic to me. Isn't it possible that there 19 could have been damage or impacts below what you were 20 able to recover that might have changed the input 21 assumptions for your model, you know, if you base your 22 model on what you assume is going to happen and then 23 you only pull out stuff that fits that assumption isn't 24 it possible that you could be missing something? 25 MR. McCARTY: It's always possible to miss Com ulu Matrix, LLC Phone: 907-243-0668 135 Chriue Or., &e. 2, Mch, AK 99501 Fez 909-243-1473 Email: aah.le(a} p, m AOGCC 2/132019 1 M0. MQMYMTOM4ECHAMCALMTEGMTYOFPROBHOEBAYWELLS Docket N9.OTM060 Page 92 1 something. I think the fact that on 02-03 the 2 shallowest connection parted and we got a look at that 3 connection and it didn't seem to be damaged. And then 4 on 02-02 we've seen the -- within the 20 inch string 5 itself it looks like a ductile failure near the 6 wellhead. Because the failure's so close to the 7 wellhead it doesn't appear to be any additional 8 information with regards to that 20 inch that would 9 change our findings. 10 ACTING CHAIR SEAMOUNT: Nathan, did you get the 11 name of the person who just answered that question? 12 REPORTER: Yes. 13 ACTING CHAIR SEAMOUNT: Okay. 14 COMMISSIONER FOERSTER: All right. 15 MR. CISMOSKI: This is Doug Cismoski. If my 16 answer -- add a little bit to that. 17 COMMISSIONER FOERSTER: Sure. 18 MR. CISMOSKI: That is the -- also the purpose 19 for the metallurgical analysis that we want to perform 20 when we recover that bit of casing. That was the 21 intent behind understanding if there's any defect or 22 anything that would have caused why it failed at that 23 particular depth. If the casing comes up, you know, 24 with no..... 25 COMMISSIONER FOERSTER: Okay. My question was COWUter Matrix, LLC Phone: 901-243-0668 135 Chrirtensen M. Ste. 2., Anch, AK 99501 F. 907-243-1473 Email: s ile@oinet 0 AOGCC 2/132019 ITMO: Docks M.O -064 Page 93 1 a little bit different. Might there be damage or 2 impacts below what you recovered that could provide 3 insights into what's really going on was my -- that was 4 my real question. 5 MR. DANIEL: Commissioner Foerster, this is 6 Ryan Daniel. If I may add, this is one of the reasons 7 we intend to conduct a detailed geotechnical review of 8 drill site 2 to better understand the failure mode. 9 The well engineering modeling that Thomas and his team 10 have provided gives us a very credible failure modal 11 scenario, but there are some unknowns in the actual 12 permafrost subsidence making us -- our hope at least is 13 that a detailed geotechnical review would add weight to 14 that or perhaps may come up with some other avenues 15 that you have suggested. 16 COMMISSIONER FOERSTER: So tell me more about 17 your geotechnical review, what data are you going to be 18 gathering and analyzing in that geotechnical review? 19 MR. DANIEL: At this stage we're going out to 20 an experienced geotechnical company with the terms of 21 reference. It's too early to say what the key focus 22 areas are. But it's sufficient to say that the review 23 will look at the permafrost loading across the surface 24 casing strings, will look at some of the lithological 25 factors involved as well. So there are a number of Cowuter MatnK LLC Phone: W-243-0668 135 Cluistemm Dr., Ste 2., Asch. AK 99501 F. 907-243-14T3 Email:s ikr(Pdnet AOGCC L13=9 I 0. INQMYIWOM4ECHAMCAL GMn OFPRU HOEBAYWELLS Do&d No. OM -064 Page 94 1 different, you know, risk areas or contributing factors 2 to permafrost thaw subsidence for wells. At load 3 casing through strain, the strain is you've heard from 4 Mr. Cismoski can be localized or it can be evenly 5 distributed across a long surface casing string. In 6 the latter case you do not get buckling or deformation 7 unless you approach your compression yields, but if 8 it's more localized and it's very hard to pin down 9 unless you see so you can order a fix in tubing through 10 drifting or complete decompletion. 11 COMMISSIONER FOERSTER: What's the timing for 12 that study? 13 MR. DANIEL: We're still working with the 14 technical representatives on that. We hope to engage 15 this year and have a product. I wouldn't commit to an 16 end date at this stage. 17 COMMISSIONER FOERSTER: So when do you plan to 18 start the study? 19 MR. DANIEL: We're in the progress now of 20 engaging a geotechnical company as an external 21 representative, you know, as a cold eyes review 22 basically of the subsidence loading factors that may or 23 may not have lead to the 02-02 and 02-03 incidents. 24 COMMISSIONER FOERSTER: So are you in the 25 design phase of the project? Conpoler Nl V LLC Ponne: 907-243-0668 135 Chrielemen Dr., Ste, 2., Anch. AK 99501 F. %7-24344n Email: sehileft m aOGR' 2/132019 RMO: INQUIRYINTOWECHANICAL EGRFFI'OFPRUDHOE BAY WEDS Docka No, OTH-064 Page 95 1 MR. DANIEL: Yes, we are. And we're also 2 assessing what data we have to provide the company that 3 performs the external geotechnical review. 4 COMMISSIONER FOERSTER: But you're not 5 precluding them from gathering additional data? 6 MR. DANIEL: Absolutely not. 7 COMMISSIONER FOERSTER: Okay. How many of the 8 P&As that you've done in the last year or two have met 9 all of the state regulatory requirements without 10 getting waivers or variances? 11 MR. DANIEL: Commissioner, can you be a bit 12 more specific on waivers and variances. Are you 13 speaking with regard to plug and abandonment above junk 14 or obstructions in the wellbore or is there some other 15 factor you're alluding to? 16 COMMISSIONER FOERSTER: I'm alluding to any 17 waivers or variances that you had to receive prior to 18 performing the non -rig P&As on the wells that you did 19 in the last two years. 20 MR. DANIEL: This is Ryan Daniel from BP again. 21 All our plug and abandonment well programs are reviewed 22 and approved internally and reviewed and approved and 23 permitted by the AOGCC staff engineers. So we haven't 24 conducted any plug and abandonment operations that the 25 AOGCC were not aware of or have approved 100 percent. Coww" Wum LLC Phone: 90'l-VB3 68 135 Chrineruen Dr., Ste. 2., Anch. AK WnI F. 909-243.1473 Em d eehilefto no AOGCC VM019 IIMO: INQMYIN WECHANICALI GR OFPRMHOEBAYWEWS Docks No. OTH-WC Page 96 1 COMMISSIONER FOERSTER: We didn't. I -- I'm 2 sorry, I didn't not assume -- intend to imply that you 3 were not following our regulations. We do grant 4 waivers and variances from those regulations and then 5 -- and you're still in full compliance. But my 6 question was how many of your P&As required variances 7 or waivers in order to stay in compliance? S MR. DANIEL: Commissioner, I would need to look 9 at the individual cases. I cannot comment from memory 10 at this stage. I'll be happy to report back and 11 discuss it in more detail. 12 COMMISSIONER FOERSTER: Okay. And when you do 13 that would you also answer the question of those how 14 many of them would have not required a waiver or 15 variance if you had done a rig decomplete. Okay? 16 MR. DANIEL: Yes, ma'am. 17 COMMISSIONER FOERSTER: Okay. I'm trying -- I 18 wrote these things bouncing around and I'm trying to 19 keep some train of continuity and logic to the order in 20 which I ask them so please bear with me. 21 So the 13 wells are more that you say you're 22 going to plug in -- what is it, 17 wells in 2019 and 23 '20 that you're going to plug? 24 MR. DANIEL: Ryan Daniel for BP. We have 25 proposed 20 wells. Con wer Matrix, LLC Phone: 907-243-0668 135 Chriueasen Dr., Ste. 2., Asch. AK "MI F. 907-243-1473 Email: sahik(nJgci aet 20GCC 1/13/2019 ITMO: MOMYIWOMOECHAMCALIMEGMI OFMMHOEBAY WELLS Docks Na. omH Page 97 1 COMMISSIONER FOERSTER: Twenty wells. Are any 2 of those going to be rig decompletes? 3 MR. DANIEL: At this stage we think not, but 4 any well can lead to surprises and we have two rigs now 5 that we can potentially use if we need it. Typically 6 what we've found is, you know, it's actually a low risk 7 operation typically even in a complex P&A with junk in 8 the hole to use surface coil which has full pressure 9 control capability versus a rig which would rely on the 10 hydrostatic overbalance. Our preference right now is 11 using non -rig methods, but if we need to use a rig, 12 yeah, we certainly will. 13 COMMISSIONER FOERSTER: Okay. Conoco's done a 14 lot of decompletions, casing repairs, et cetera, 15 because of permafrost subsidence. Has BP collaborated 16 with Conoco to compare best practices? 17 MR. DANIEL: Ryan Daniel from BP. Yes, 18 Commissioner, we have. We maintain a very close 19 working relationship with ConocoPhillips both in terms 20 of well work, intervention, integrity and lately 21 subsidence. 22 COMMISSIONER FOERSTER: So BP is taking a very 23 different approach than Conoco has on casing repairs 24 versus waiting for something to break and then 25 responding to it or am I missing something? Cor user Marcia LLC Fhoae: 907-203-0668 135 Chrieleasea Or., Ste, 2., Asch. A 99501 Fax'. 907-243-1M E.1, sahilefta w AOGCC L13M19 R O:MQMYMOM4ECH CA MEGMWOFPBODHOEBAYW LLS DocW No. OTHA64 Page 98 1 MR. DANIEL: Commissioner, Ryan from BP again. 2 If I understood the question you're seeing a difference 3 between our approaches. My view is that we have the 4 same approach, we're using the same methodologies. I 5 do not want to speak on behalf of ConocoPhillips, but 6 BP Alaska, when we move forward and determine a well 7 has subsidence related buckling we have a large well 8 stock, we review whether we need the wells in that 9 particular area, whether they have huge utility. And 10 in the case of the three I spoke to previously we moved 11 ahead and plugged and abandoned them to eliminate the 12 risk rather than choose to repair them. We did not 13 need to repair those wells and plugging and abandoning 14 was actually the most appropriate solution. 15 COMMISSIONER FOERSTER: What wells were 16 included in your wellhead elevation survey? It was 17 covered in 4.4 of your response to us. 18 MR. DANIEL: Ryan Daniel from BP again. The 19 wellhead date and time lapse survey which we performed 20 in 2018, we actually covered all drill sites and pads 21 and all wells. This survey built on previous surveys 22 which were conducted in 2014. We've had multiple 23 wellhead surveys, particularly on the west end wells, 24 starting in 2011. 25 COMMISSIONER FOERSTER: So on one of the wells Computer Mmnx LLC Phots: 90]-243-0668 135 Christensen Dr., Sm 2., Arch A 99501 F. 909-243-1473 Emnil'. sehile(ft. d AOGCC NIM019 FFMO: INQMYMOM4ECHANICA lI EORITYOFPRUDHOEBAYWE Docks No. MH Page 99 1 and I forget which one, the -- not only did the casing 2 part, but the tubing also parted. Do you remember 3 which well that was? 4 MR. CISMOSKI: Are you referring to the -- to 5 the wells in the last instance, 02-02 and 02-03? 6 COMMISSIONER FOERSTER: Yeah. 7 MR. CISMOSKI: 02-02 the tubing parted. 8 COMMISSIONER FOERSTER: Okay. 9 MR. CISMOSKI: This is Doug Cismoski. 10 COMMISSIONER FOERSTER: Thank you, Doug. Does 11 the fact that the tubing parted have any implications 12 on what might have been going on with the casing, like 13 was the casing already in compression when the tubing 14 was run or any other -- any other -- could the stresses 15 on the casing contributed to what happened to the 16 tubing? 17 MR. McCARTY: Prior to the event there was no 18 record of whether or not there was any failure in the 19 tubing. So the preliminary findings are that the 20 tubing failed as a result of the upward wellhead 21 movement. what we don't know is the status of the 22 tubing at the time, it could have been damaged or it 23 could have been failed as a result of the upward 24 movement. The compression that the inner strings are 25 in prior to the 20 inch parting would have allowed the Computer Metnx, LLC Phone: 901-243-0668 135 Chrinensen Dr., Ste. 2, Anch. A 99501 Fax: "7.243-1473 Email. saMk(dgb.net AOGCC 2/132019 1] 0. MQMYIMOM4ECHAMCAL EGMYOFPROOHOEHAYWELLS Wokd M. MT W Page 100 1 upper wellhead movement. During that time the tubing 2 may have parted. 3 COMMISSIONER FOERSTER: The -- I hear a lot of 4 possibly, probably, we assume, based on what we know so 5 far. With all of the uncertainty and the high stakes 6 is there any additional data gathering and are there 7 any additional studies that you have considered? 8 MR. DANIEL: Commissioner Foerster, Ryan Daniel 9 from BP. If I may answer that. We actually plan to 10 decomplete, pull tubing and caliper a couple of the 11 west end wells this year. We may extend that based on 12 what we find. What we're looking for here is to try 13 and understand the strain distribution that we can see 14 evident from surface in terms of vertical displacement, 15 how is that manifesting itself within the -- within the 16 casing string of the wells. So we don't really know 17 that until we can remove the casing. So we're actually 18 going to use a pulling unit or a small rig and pull out 19 tubing on two wells later this year. And try and 20 better understand particularly for the west end pads 21 and V pad in particular, where that strain distribution 22 is going. 23 COMMISSIONER FOERSTER: Any other studies or 24 data gathering? 25 MR. DANIEL: Our ongoing subsidence monitoring Cowuler Manx,LLC Phone. 907-2A3 B 135 Chrisrenxn Dr., Sle 2,M& A "501 F. W-242.1472 Em J s ilenagd.rot AOGCC 2/132019 "0: INQLUYMOWECHAMCALBJTEGRIIYOFMR HOEBAYWE Dockd No.M-061 Page 101 1 and surveillance program, we're not backing off that at 2 all. We will continue to update the relative risk and 3 the frequency with which we do drifts, the techniques 4 with which we run drifts and calipers and the frequency 5 with which we do time lapse. As you pointed out before 6 we work very closely with our colleagues particularly 7 in ConocoPhillips and we share our lessons learned and, 8 yeah, improve our ability to diagnose, respond and 9 understand subsidence related well barrier threats. 10 COMMISSIONER FOERSTER: So back to the tubing 11 part. Have you done any modeling to account for the 12 tubing part or are you just going with that assumption? 13 MR. McCARTY: We haven't modeled the tubing 14 part. 15 COMMISSIONER FOERSTER: Okay. Is that because 16 you feel pretty sure that you know what the answer is 17 or it doesn't have implications or what is the..... 18 MR. McCARTY: On the three string wells with 19 the surface casing set in the permafrost? 20 COMMISSIONER FOERSTER: On any wells. 21 MR. McCARTY: I'm just referring to the three 22 string wells with the surface casing set in the 23 permafrost. 24 COMMISSIONER FOERSTER: That's what you've done 25 your mod -- that's all you've done your modeling on? Comuter Mat LLC F ft.9 -243 6 8 135 Chrivensen Dr., Sm. 2., Mch, A 99501 F. 909-243-1473 Emeil:s ilefgci.nel AOGCC 3/132019 R O Q=Y3 OWECFIAMCALI GR Page 102 1 1 MR. McCARTY: Yeah. On those wells we're 2 confident that the 20 inch was going to part prior to 3 the three inner strings. 4 COMMISSIONER FOERSTER: But you did have one 5 with the tubing part, but you're confident that that 6 tubing part was just because of the upper movement, is 7 that what you're saying? 8 MR. McCARTY: Yes. 9 COMMISSIONER FOERSTER: Okay. All right. 10 There -- there's some discussion of a slick joint 11 design in some of the wells. And I understand it was 12 supposed to help with the permafrost and the 13 subsidence, is that doing what it was designed to do? 14 MR. DANIEL: Commissioner, Ryan Daniel from BP. 15 If I may answer that. Some of the very early Prudhoe 16 Bay wells of which we have a few here on this list of 17 14, were originally built with slip joints and an 18 adjustable wellhead system that allowed you to move 19 jack screws to basically open up the space between the 20 surface casing and the inner strings between the 20 21 inch and the 13 and three-eighths. These never proved 22 reliable and they were discontinued very early in field 23 build out. 24 COMMISSIONER FOERSTER: Have you looked at them 25 to see if they could be contributing to the problem? Co�ota Matrix 1.LC Phone: 900-243-0668 05 Chrietemen Dr, Ste 2., Anch. AK 99501 Fax 907-2434473 Email:s ilc@,.W AOOCC 21132019 1 0: Dock% No, OiH416a Page 103 1 1 MR. DANIEL: I have not. That would be 2 speculation on my part. I know they exist in a number 3 of our wells and they're documented in the well files, 4 I'm not aware of any attributional causality in terms 5 of what we're seeing right now. 6 COMMISSIONER FOERSTER: But you haven't -- you 7 haven't done anything to test that? 8 MR. DANIEL: Negative. 9 MR. McCARTY: The 20 inch parted shallow, you 10 know, near the wellhead. 11 COMMISSIONER FOERSTER: And you didn't get any 12 deep metallurgy to -- or any deep jewelry to see what 13 else might be going on deeper, I've already heard that. 14 Okay. 15 So you guys are pretty fastidious about 16 evaluating mechanical integrity of your injectors. Do 17 you have any plans to increase the mechanical integrity 18 analysis of your producers? 19 MR. DANIEL: Commissioner Foerster, Ryan from 20 BP again. We have a very robust and effective well 21 integrity program currently that manages the health of 22 both our injectors and our producers. We use different 23 techniques on our producers, the primary technique we 24 use is a tubing inflow fluid level test to test the 25 barriers and ensure we have two barriers on those Corn,u.r maLLC Phone: 907-143-0668 135 Cmi%emen U., Ste. 2., Aach. A1C 99501 Pax:9 -243-1473 Email: salula@,ci net AOGCC YIM019 ITMO: INQMY1 OM4ECHANICALINTEGMWOFPRMHOE BAY WELLS Meket No. OMOM Page 104 1 wells. When we see anomalies typically through wells 2 that will approach or exceed our normal operating 3 limits which are as you are aware we're very 4 conservative. We then work to diagnose the wells. 5 Typically for producer wells in the field we see the 6 most anomalies during either shut down or start up and 7 then we manage those, verify the barriers and depending 8 on what we see if we run valves, we'll run a plug and 9 we'll do pressure testing which is a positive test. 10 Typically is the valves pass on an inflow test we will 11 assist that the barriers are healthy, both the primary 12 and secondary barrier are healthy. 13 COMMISSIONER FOERSTER: So when you do tubing 14 pulls or is that an opportunity to do additional 15 testing on the integrity of your casing? 16 MR. DANIEL: Yes, Commissioner. 17 COMMISSIONER FOERSTER: Do you do that? 18 MR. DANIEL: Yes, Commissioner. This is 19 required under -- you know, either in the drill 20 programs, it's also required by regulation before we 21 actually get off a well the production casing is tested 22 for both producers and injectors. 23 COMMISSIONER FOERSTER: Not just when they're 24 drilled, but during -- when the tubing's replaced? 25 MR. DANIEL: When the tubing is replaced, when Cmryuter Metrix, LLC P1mne: 90'1-34341fifig 135 artemna Dr.. Ste. 2., Anch. AK W501 F. %7-243-1473 Emil: while( gci.net AOGCC LIM019 ITMO. INQMYINTOM4ECHAMCALINTEGMYOFPRODHOEBAY WELLS Docks No. OTH-064 Page 105 1 the wells are completed..... 2 COMMISSIONER FOERSTER: Okay. 3 MR. DANIEL: .....correct. 4 COMMISSIONER FOERSTER: So have you done 5 anything when you pull the tubing as far as doing 6 drifts to see if there deformation? 7 MR. DANIEL: Ryan from BP again. Yes, 8 Commissioner Foerster. Depending on where the well is 9 in the field, even back prior to 2011 we have run 10 calipers on some wells. It's more if we see something, 11 if we have issues with running a work string into the 12 well we'll caliper it, but it's more on a case by case 13 basis, but it is pretty problematic on the west end. 14 COMMISSIONER FOERSTER: So it's just if you -- 15 if you identify a problem you'll..... 16 MR. DANIEL: Yes. 17 COMMISSIONER FOERSTER: .....but you don't do 18 it as a diagnostic or a predictive..... 19 MR. DANIEL: Correct. It's not -- it's not 20 systematic on every..... 21 COMMISSIONER FOERSTER: Okay. 22 MR. DANIEL: .....single rig workover. 23 COMMISSIONER FOERSTER: Okay. 24 MR. CISMOSKI: Commissioner Foerster, this is 25 Doug Cismoski, I'd like to add to that. Coemuter Mmnx LLC Phone: 907-243-0668 135 Mivmaen M,, Ste. 2., Mch, AK 99501 F. 901-2431473 Email: s Ae@Wknet AO C 2/132019 1i 0. MQBIRYIMOM4ECHAHICALMiEGWWOFPRMHOEBAYWELLS Docket Ho, OMH Page 106 1 COMMISSIONER FOERSTER: Okay. 2 MR. CISMOSKI: That for workovers when we do 3 the tubing swaps two things I'think kind of occur. I 4 can't -- I do agree with my colleague it's not -- can't 5 guarantee that it's on every well, but as a matter of 6 course we will scrape the casing prior to running the 7 new production packer. And so with the larger OD 8 casing scraping as well as the new production packer 9 that is ran with the tubing, we have a pretty good idea 10 of the drift diameter then through that production 11 casing. 12 COMMISSIONER FOERSTER: Thank you. So one of 13 the questions that we asked you to respond to was 14 question number 5.4. And you answered the question 15 that was asked, but that really wasn't -- you told us 16 what the criteria was, but we were really looking for 17 more quantitative. We didn't want to know we looked to 18 see if there's a pressure event, but we want to know if 19 it's greater than this we respond to it or we wanted 20 more quantitative numb -- we wanted numbers not just we 21 checked the pressure kind of answers. So could you 22 give us a -- for the things that you do, for the 23 criteria that you list, could you say what are the -- 24 you know, when you're out of range, when you're out of 25 acceptable range on those criteria, could you respond Cowutee Mehr LLC Ph .. 907-343-0 8 135 Dr., Ste, 2., M& AK 99501 F. 907-243-1473 Email: n ik(n V,net aOG(( 2/13/2019 ITMO: INQOIRYINTOM4ECHANICALINTEORITYOFPRMHOEBAY WELLS Docks No.OM- Page 107 1 -- you don't have to do it right now, but could you get 2 back to us and ans -- give us a little deeper answer to 3 that question? 4 MR. DANIEL: Ryan from BP. Certainly, 5 Commissioner Foerster. 6 COMMISSIONER FOERSTER: Thank you. Looking at 7 the L5-13, you mentioned that there was a metallurgical 8 report done. we do not have or cannot find a copy of 9 that report. Could you supply one of those to us? 10 MR. CISMOSKI: This is Doug Cismoski. Yes, we 11 certainly can provide a copy of the L5-13 report. 12 COMMISSIONER FOERSTER: Okay. 13 MR. CISMOSKI: Just to be clear, you're asking 14 for the metallurgical analysis..... 15 COMMISSIONER FOERSTER: Yes. 16 MR. CISMOSKI: .....right? Yes. 17 COMMISSIONER FOERSTER: If -- and any other 18 reports you have relative to that well since you asked 19 for clarification. I wasn't aware that there were 20 others, but if there are others..... 21 MR. CISMOSKI: Yeah. 22 COMMISSIONER FOERSTER: .....we certainly would 23 appreciate..... 24 MR. CISMOSKI: I think we have..... 25 COMMISSIONER FOERSTER: .....having those as COWNG Melrm LLC Phone: 907-243-0 135 C Wmem Dr., Sm. 2„ Anch, A 99501 F. 907-243-1473 Emvl: sehile(dgdnd nOIX T' VM019 I O. MQMYI OhWECHANICA MEOR OFPRU HOEBAYWELLS MOa No. OTW004 Page 108 1 well. 2 MR. CISMOSKI: Yes, I'll verify, but I think we 3 shared the investigation report, but we'll verify and 4 we'll get those to you. 5 Thank you. 6 COMMISSIONER FOERSTER: Okay. Thank you. And 7 you might just before doing a bunch of unnecessary 8 xeroxing you might just touch bases with Guy or Jim or 9 Mel, whoever you've been working with, to make sure 10 that any other reports you find they don't already have 11 a copy of. 12 So -- oh, you said that the L5-13 did not 13 appear to be related to subsidence. Did you determine 14 a cause for the buckling? 15 MR. CISMOSKI: Not definitely. This is Doug 16 Cismoski. Not -- not definitively, Commissioner. The 17 way the casing looked when we took it apart, it -- and 18 it's hard to describe with words, but if you can kind 19 of imagine a round circumstance, the area that was 20 deformed was rather localized so it would be like my 21 fingers kind of coming together like that while the 22 rest of the casing stayed round. Typically if it was 23 from like an over pressure scenario or something like 24 that you end up seeing the pipe just kind of flatten 25 out. And in this case because the deformity was kind Computer Minix, LLC Phone: W7-243-0 135 Chrige Dr., Ste, 2., Arch. AR W501 Fix -.907.243-1473 Email: net AOGCC 2/132019 I O_INQU YMfOM4ECH CAL EGMYOFPRMHOEBAYWELLS Docke No. OMN Page 109 1 of localized the only thing that's really kind of come 2 to our minds is just ice as -- as the freezable fluid, 3 you know, expands, and forms just that local ice. But 4 that's speculation on my part, there's nothing part of 5 the production history that -- that -- where we could 6 see or determine that, you know, the annulus was froze. 7 COMMISSIONER FOERSTER: So you don't have 8 anything definitive on that failure, just -- it's just 9 an educated guess? 10 MR. CISMOSKI: It is an educated guess, yeah. 11 CHAIRMAN FRENCH: So were there -- okay. The 12 tubing was -- was damaged, you think it was from ice. 13 Were the other strings in that well damaged also? 14 MR. CISMOSKI: I'm sorry I wasn't clear. The 15 -- in this particular case for L5-13 during the 16 pressure test the -- we were pressure testing the inner 17 annulus, we were testing the tubing via production 18 casing..... 19 COMMISSIONER FOERSTER: Okay. 20 MR. CISMOSKI: .....and that test failed and 21 resulted in fluid coming to surface. So then the -- 22 and the fluid came to surface via the surface casing by 23 conductor. So both the production casing and the 24 surface casing failed at approximately the same depth. 25 From the analysis that localized deformity, that inward Cutty w Mmnx LLC P .: 909-243-0 135 Chnnemen Dr, Ste, 2., Mck "99501 F.. 907-243-1493 E.] eehilefta.nn AOGCC 2/132019 UMO: WQMYINOWECHANICALINUGMWOFMR HOEBAYWELLS Dockn No. OTH Page 110 1 piece was present was seen on the 13 and three-eighths 2 and the nine and five, can't recall what was shown on 3 that, but it was the two casing strings where we had 4 this..... 5 COMMISSIONER FOERSTER: The two casing strings 6 buck..... 7 MR. CISMOSKI: .....where we had this 8 deformity. I can't comment on the..... 9 COMMISSIONER FOERSTER: .....had the buckling, 10 not the tubing? 11 MR. CISMOSKI: .....I don't recall on the 12 tubing. 13 COMMISSIONER FOERSTER: Okay. That was a 14 question. The tubing also was buckled and so you think 15 there was ice in both or all of those strings? 16 MR. CISMOSKI: In the outer and inner annulus, 17 yes. 18 COMMISSIONER FOERSTER: Okay. Okay. Let's 19 see. 20 MR. DANIEL: Commissioner Foerster, if I may. 21 There's one other point which I think will help the 22 Commission better understand 1.5-13. The 20 inch 23 outside the 13 and three eight actually was -- and this 24 is actually a conductor, was actually deformed in a 25 positive manner so it basically swelled opposite this Computer Matrix, LLC Phone:9 -V34m$ 135 Christman U., Ste, 2., Anch, A 99501 Fax: 907-243-1473 Emit. ahi1e@,cinn AOGCC 2/132019 ITMO: INQUIRYB OMIEC CALINTEGRITYOFMMMOEBAYWELLS mad No. OTR -0 Page 111 1 area. And I would agree with my colleague right now 2 the most critical scenario is internal freeze back at 3 some point in the life of the well due to a 4 nonfreezable fluid residing in that spot over 10, 15 5 feet or so if it was even more localized than that. So 6 the internal strings, the nine and five -eight and 13 7 and three -eight, the 13 and three -eights was impinged 8 onto the nine and five -eights, both were heavily 9 deformed. And then the 20 inch conductor was actually 10 expanded. So this adds credibility that there was some 11 sort of mechanism there that had an internal freeze 12 back or something similar that cause that deformation 13 that ultimately led to cycling and fracture which we 14 saw on the pressure test..... 15 COMMISSIONER FOERSTER: Was it..... 16 MR. CISMOSKI: .....the rupture. 17 COMMISSIONER FOERSTER: .....freezing or 18 similar, what other things come to mind? 19 MR. CISMOSKI: Right now, Commissioner, 20 freezing would be the only thing that comes to mind. 21 COMMISSIONER FOERSTER: Okay. I've got some 22 good news. This next set is I think going to be my 23 last line of questioning and it deals with subsidence. 24 So first question. How did you come up with 25 your original RKBs, rotary kelly bushings for the -- Corryuter Metrix, LLC Plane:9 -2[3-0668 135 Cinotensen m., St. 2., Mch. A 99501 F. 90]-21310)3 Email . sahib r(ligdoet VKc 2/l3a019 EMO: MQMYMOM4ECHAMCALE GR OFPRU HOEBAYWELLS ]odd Ho. OTH-0 Page 112 1 for the..... 2 MR. DANIEL: Commissioner, Ryan from BP. So 3 the first round of surface datum measurements actually 4 is the definitive measurement we use as the starting 5 point. So 2011 was when we first started looking at 6 some of the west end wells, that is actually our start 7 point, clearly not the start point for any form of 8 subsidence. One can only speculate that ever since we 9 turned the wells on there has been some form of 10 movement near with thaw bulb subsidence, but from the 11 perspective of your question the zero or what you've 12 referred to as RKB which is really our wellhead base 13 flange datum, that's our starting point. 14 COMMISSIONER FOERSTER: Okay. But when the 15 well was drilled there was an RKB, it shows up on every 16 log of every well that's ever drilled. So that's what 17 I'm asking. How was that number determined because 18 there was a number determined at the very start for all 19 these wells? 20 MR. DANIEL: Ryan from BP. Yes, Commissioner, 21 that is -- that is true, but the accuracy of those 22 measurements and the repeatability of those 23 measurements is nothing like what we can do with 24 corrected (indiscernible) GPS today with a registered 25 surveyor. So we actually start fresh and use the CoMtmM rm LLC P3wne: 901-243-0 135 Chrigimm Or., &e. 2., Mch. AKW501 Fu 901-243-148 Emil : nhile(?�R i nn AOGCC 2/132019 ITHO: MQMYIWOWECHAMCALI GMYOFPRMHOEBAYWF.LLS Docket No, OTH-OU Page 113 1 initial measurement as a datum starting point. As I 2 say 2011 is our datum starting point. Each of the 3 wells as you say in the well file has an RKB 4 measurement respective to MSL, mean sea level, or GL. 5 We're not utilizing that, that was a construction 6 datum. We're using the base flange elevation datum, 7 the high accuracy one that we do at the start of our 8 surveys. 9 COMMISSIONER FOERSTER: So how were those 10 original ones measured? 11 MR. DANIEL: It varied through the course of 12 history. As I pointed out when the initial wells were 13 drilled on the build out of Prudhoe Bay prior to TAPS 14 opening many of them were just relative to a pig in a 15 corner of the pad and they were an X, Y at ground 16 level. As surveying technology and everything improved 17 the wells are surveyed, but the accuracy is no where 18 near what we can do now with corrected GPS. 19 In terms of if you want to look at history and 20 time lapse, you could, but there -- there's going to be 21 a large error there or an uncertainty in the 22 measurement if you were to compare day one with day 23 zero, start of production, using an old methodology 24 with the new methodology using GPS from 2011, I think 25 that's the point of your question is it not? Con W. Herrin, LLC Phone: 90'1-243L 8 135 Chrieteo en Dr., Ste, 2., Aneh. AK 99501 Fax 907-243-1473 Erred. sehik(a)gci.net AOGCC 2/13=9 1i 0: MQMYIWOM4ECHAMCALIMEGMWOFMMHOEBAYW LLS Decks No, DTR -0" Page 114 1 COMMISSIONER FOERSTER: I'll come back -- I'll 2 circle back around because I have another set of 3 questions that kind of explain where I'm -- maybe 4 explain where I'm going with this I hope. 5 So you're using 2011 as your ground, but a lot 6 of the pads at Prudhoe Bay were drilled in the late 7 '60s, early '70s, and the wells all came online in the 8 later '70s. And with 35 years of production wouldn't 9 you suspect that there might be a lot of subsidence 10 that you haven't captured? 11 MR. DANIEL: Ryan from BP. I think that would 12 be speculation from my perspective. Based on what I 13 can see with our all head surface datum surveys across 14 -- across the field, across PBU, we only have a small 15 number of pads and the wells on those pads respectively 16 which have observable base flange elevation changes 17 since the start of surveying. So as I said the west 18 end wells were first shot in 2011 and what we're 19 looking for is a relative movement post 2011. EOA, we 20 shot our first round of surface datums in 2014, four 21 years later we went back and reshot them. We're seeing 22 very, very little surface wellhead elevation change 23 across the majority of the Prudhoe Bay field. That's 24 actually really good, but I'm not discluding that, you 25 know, I pointed out in my testimony that's only one C.ryWer Matrix, LLC Phene: 907-243416b8 135 Christensen R., Ste. 2., Arch. A 99501 Fax %7.243.14n Email . sahik&a w AOGCC 2/132019 1 0: INQMYMOM4ECH CA ]I GR OFMUDHOEBAYWELLS Docket No. OM -064 Page 115 1 datum point. So there are other factors there. We do 2 run drifts on perceived higher relative risk wells 3 based on well construction. There's a variance on well 4 construction across the field depending on where the 5 wells are, which pad, which era they were drilled in. 6 These are all part and parcel of our ongoing 7 surveillance monitoring program and we continually 8 assess and improve in conversations with Conoco and 9 others how we understand subsidence in our well stock. 10 I would like to actually point out one 11 clarification that we haven't landed yet. That's the 12 relationship between surface subsidence and the sort of 13 weathered or active flare which is prevalent across all 14 of the Arctic and the permafrost, we're actually 15 specifically speaking about well subsurface subsidence 16 here. So I just wanted to clarify that point. And 17 there is a statement which I'd like to just go through 18 here. So the theory of global warming as it applies to 19 well subsidence is still largely unknown and we don't 20 believe it to be a factor in the two recent incidents 21 we've talked about this morning, 02-02 and 02-03. The 22 design of these early wells is the most critical cause 23 of the mechanical failure of the two wells on drill 24 site 2. I just want to try and differentiate what's 25 happening in the well downhole relative to thaw bulbs Conmwer Metrix, LLC Phone: 907-W4 68 135 Chna.. Dr., Ste. 2., An& A 99501 Fu 907-243-14]3 Enuil. eahile( .. AOGCC 2H32019 aMO INQMYIMOM4ECH CALIMEGRTPYOFPRI HOEEAYWELLS Docket No. OTHA Page 116 1 subsidence over time is different than what you may see 2 or observe on the ground around the well. One of..... 3 COMMISSIONER FOERSTER: We get that. 4 MR. DANIEL: .....one of the key points is if 5 we can measure and then go back and have a look at the 6 wellhead elevation on every well in Prudhoe Bay at some 7 frequency, this gives us an understanding of how that 8 well is moving deeper, you know, the surface casing is 9 moving. And then the next question is what is the 10 strain distribution in that casing, is it localized, is 11 it uniform. If it's uniform, you know, the wells can 12 move substantially at surface with little or no impact 13 to well barrier integrity. If the strain is localized 14 for example just throwing out a number, five or 600 15 feet, then it's a more serious issue, it may lead to 16 compressional buckling and we observe that through our 17 drifts. 18 COMMISSIONER FOERSTER: Okay. So back to the 19 answer to the question. My -- you know I asked might 20 there be -- have been lots of subsidence in -- before 21 you start -- in the 35 years before you started, 22 (indiscernible) is 35 years, before you started 23 measuring. So if I took my notes correctly L, V and W 24 are three of your worst pads for subsidence? 25 MR. DANIEL: Starting with V, L, Z and W, yes, Comwer Metrix, LLC Phoney 907-243-0 135 Christensen Dr., Ste. 2., Anch. AK 99301 Fax, 97-243-1473 Email sahile@gcinet %OGCC 2/132019 ITKIO: INQMYI OM4ECHAMCALINTEO YOFPRODHOEBAYWELLS IMcket No. DTH -OM Page 117 1 Commissioner. 2 COMMISSIONER FOERSTER: Okay. So L, V and W 3 are -- are three of your newest pads, aren't they? 4 MR. DANIEL: Yes, they are. 5 COMMISSIONER FOERSTER: And when were they 6 developed? 7 MR. DANIEL: Approximately 20 years ago. 8 COMMISSIONER FOERSTER: Okay. So you've been 9 -- you've been gathering data for about seven years and 10 they're three of your worst subsidence actors -- bad 11 actors. So I'm -- might that be telling you that early 12 time subsidence is an issue, you know, might -- you 13 know, the subsidence -- the rate of subsidence decrease 14 as -- you know, you make a big mess and then there's 15 less mess to be made so you see less and less of it 16 over time, very untechnically stated, but I think you 17 get my point. My -- my -- a large subsidence event 18 occur in the first 20 or 30—years and cre7cre-asing 19 subsidence event over -- you know, occurrence or impact 20 over time. Might that be what's going on here? 21 MR. DANIEL: Commissioner, that would still be 22 speculative on my part, but based on our knowledge of 23 subsidence in Prudhoe Bay, you're right, we're seeing 24 more observable base flange elevation movement on the 25 west end pads. These wells are also constructed CoMutu Matrix, LLC PMna: %7-243-0668 135 aristmen Dr., Ste. 2., Anch. AK 99501 F. 907-243-1473 Email: sehile@gci.net AOGCC 2/132019 rt O: INQMYI OM4ECH CALL GWWOFPRMHOEBAYWELLB Docks M.om-064 Page 118 1 slightly differently and are lighter weight of wells in 2 the central core of Prudhoe Bay. But there are other 3 factors beyond well construction techniques that lend 4 to the thaw bulb subsidence area and the key one really 5 is lithology. So this is a big driver, this is part of 6 what we want to look at with the geotechnical review on 7 drill site 2 and it's certainly something that my 8 colleagues and I are speaking very frequently about 9 with ConocoPhillips. 10 COMMISSIONER FOERSTER: Okay. That -- now I'm 11 going to tie it back to the RKB. If it is possible 12 that the early time subsidence impacts are larger than 13 the later time then is it now also possible that the 14 pads that you're saying aren't a problem, aren't having 15 big subsidence impacts, aren't having them because they 16 already had them? 17 MR. DANIEL: So I understand your question, 18 however I think based on what we understand today after 19 managing subsidence in Prudhoe Bay for a number of 20 years and my colleagues in Conoco, we see subsidence 21 being fairly linear. But there are a lot of drivers 22 that lend the -- lend to the theory of the rate of 23 subsidence when it develops. I think you're stating or 24 postulating that perhaps the subsidence is over and 25 done on the east end of Prudhoe Bay. I can't refute C.try w Matrix, LLC Phone: 907-243-0668 135 Chriw.e @., Ste. 2., Md A 99501 F. 99]-243-14]3 E.d a ile('4e .net ACH�C 1/132019 DMO: MQMYM OWECH CALIMEGRITYOFPRUDHOEBAYI ELLS Dead W omi Page 119 1 that, I can't measure it. What I can tell you is that 2 we don't see that much buckled tubing on EOA and we 3 don't see observable wellhead movement. And 4 historically we have not had to do a lot of surface 5 work on surface pipelines, flowlines, in this sort of 6 equipment around the wells that would lend credibility 7 to them, you know, slowly subsiding over the last 42 8 years. 9 COMMISSIONER FOERSTER: So if you were able to 10 take those original RKBs and make some sense out of 11 them, might that give you some indications of what was 12 happening early on? 13 MR. DANIEL: Yes, Commissioner, they may give 14 you some indication, but the margin for error in those 15 early measurements, and many of those wells have been 16 worked over multiple times, datums have certainly 17 shifted, I think the uncertainty in the measurements 18 don't -- don't lend themselves to creating a really 19 good answer. I think the latest generation of GPS time 20 lapse and, you know, I can only wish that I had it back 21 42 years ago, but we didn't, but we have started early 22 on and we are reshooting on a risk basis the field 23 today so we can track progression. The fact that over 24 the last four years we see almost no subsidence in the 25 EOA is noted that that's a really good thing. Co"uter Metria, LLC Pl m 907-243-0 135 Christens. Dr., Ste. 2, Mch. AK 99501 F. 907-243-1473 Emsilt. sa 1.ftdnet AOGCC I 2/132019 ITMO: INQUIRYI OM4ECHAMCALIWEGR YOFPRUDHOEBAYWELLS Dodo No. 0T 1-0 Page 120 1 And I want to point out one after defect here. 2 So drill site 2, this loading that we see in the two 3 wells that have sustained a tensile failure, the 4 wellhead basically don't change at surface so when 5 you're -- even if we went around and shot those 6 wellhead datums you're not actually able to observe 7 anything until that wellhead failure occurs. But this 8 failure is totally restricted in our view to the small 9 subset of wells that we have on the projector here. 10 And by the end of 2020 all those wells will be P&A'd, 11 eliminating the risk. 12 COMMISSIONER FOERSTER: I think that's just 13 wrapped up about everything I wanted to ask about, but 14 we do need to leave the record open. 15 How long do you think the record..... 16 ACTING CHAIR SEAMOUNT: Well, I have a few 17 questions. 18 COMMISSIONER FOERSTER: Oh, great. Sorry. 19 ACTING CHAIR SEAMOUNT: And I was going to say 20 that because I'm the chair. But anyway -- chairman. 21 Anyway does anybody have any idea how far out from the 22 wellbore's these thaw bulbs go, I mean, do they go just 23 a few feet out or do they encompass the entire pad? 24 MR. DANIEL: Ryan from BP. Again I don't have 25 a lot of hard evidence or facts, Chair Seamount, it's Conpoler Matrix LLC Phone: 907-243-0668 135 ariatemen p. Ste. 2., Anch, AK 99501 Fu: 907-243-1473 Emeil: sehi4(IDg<i.net AO C 21132019 1 0, MQMYI OM4ECHAMCAL TEGR OFPRQOHOEBAYWELLS IMCkO No. OT M Page 121 1 certainly tens of feet. A thaw bulb would certainly 2 over time be bigger at the base of the permafrost than 3 it would be visible at surface on the bridging layer. 4 We are still as an industry learning to better 5 understand and map permafrost thaw subsidence and 6 understand its impact and how it can load or strain 7 casing and how we can best mitigate that long term. 8 ACTING CHAIR SEAMOONT: And do you have any 9 idea which lithologies are affected most, is it higher 10 permeability or lower permeability or are you still 11 looking -- looking at that? 12 MR. DANIEL: So the short answer is in Prudhoe 13 Bay it's predominantly Gubik. I am not a geologist, I 14 don't profess to have expertise in this area. We do 15 have geologists that can provide a more detailed answer 16 than I can provide today. But in areas, particularly 17 the west end of Prudhoe Bay has a higher silt to sand 18 ratio that plays into it. And there are certain strata 19 within the Gubik that are more prone to subsidence. 20 But a lot comes down to the ice content, free ice 21 versus, you know, overall ice content. The type of 22 permafrost, there are two or three types of permafrost 23 lithology. And it actually varies widely from pad to 24 pad across the area and it can even vary widely from 25 one end of the (indiscernible) to the other so it's Cmryuter Mmdx LLC Phone: 90' 1343-0668 1350 HAi en@, Ste. 2., Arch. AK 93501 Fax: 907-243-1473 Email:s ile@gdnet AOGCC 2/132019 F O'INQMRYIN OWECHAMCA WEGR OFPRMHOE BAY WELLS Docket No. OMH-0 Page 1221 1 difficult to define and have a one size fits all 2 approach. As I say the best approach that my 3 colleagues have identified so far and we're 4 implementing is a risk base approached based on 5 observation, surveillance and monitoring. 6 ACTING CHAIR SEAMOUNT: Okay. When did freeze 7 protection start at Prudhoe Bay? 8 MR. CISMOSKI: This is Doug Cismoski. I can't 9 answer that, I don't know. When I started in the field 10 in '92 it was a prevalent practice, but I can't tell 11 you when it started. 12 ACTING CHAIR SEAMOUNT: I think you said that 13 well, what, before 1977 were not freeze protected? 14 MR. CISMOSKI: What I recall saying was those 15 wells that we looked at for -- that was on that list of 16 the three casing strings ones that had workovers done 17 between drilling and field start up, those wells that 18 observed those workovers were because those annuli were 19 not freeze protected. 20 ACTING CHAIR SEAMOUNT: Okay. And do you know 21 how many wells those were? 22 MR. CISMOSKI: That I'll have to get back to 23 you on. 24 ACTING CHAIR SEAMOUNT: And were you able to go 25 back in and freeze protect those wells? CoMuter WtriX LLC PhD M: 907-243-0668 135 Chrietmem Dr., Ste. 2., Mch. AK 99501 Fez: 907-243-1473 E.] sehik(r�gci rot AOGCC V13M19 ITMO: MQMYIWOM<ECH CALIN MMTYOFMMHOEBAYWELLS OMha No.OMH Page 123' 1 MR. CISMOSKI: Yes, sir. I speculate we were 2 able to because of the workovers done between the time 3 it was drilled and field start up and thus the wells 4 were operable at start up and remained so for a period 5 of time. 6 ACTING CHAIR SEAMOUNT: Okay. I understand you 7 don't do three string completions any more; is that 8 correct? 9 MR. CISMOSKI: That is correct. 10 ACTING CHAIR SEAMOUNT: Was that about the time 11 when you started freeze protecting the wells, when you 12 went to the two strings? 13 MR. CISMOSKI: I can't answer that. 14 ACTING CHAIR SEAMOUNT: Okay. Is there anyone 15 else that wants to testify today? 16 (No comments) 17 ACTING CHAIR SEAMOUNT: Hearing none, we should 18 probably repeat the questions we're leaving the record 19 open for to make sure that we're all in communication. 20 Does anybody have that list? 21 MR. DANIEL: Chair Seamount, I can go through 22 the list of notes I took. I have a question from 23 Commissioner Foerster on wells that required a waiver 24 for plug and abandonment and specifically either non - 25 rig or rig based on the technique that was chosen to Coww"Minix LLC Phone: 907-243 & 135 Chriad U., Ste 2., Arch. A 99501 F. 907-243.1073 Em 1. tehlle(a CL Mt AOGCC 1 execute the work. 2113/2019 IWO: MQMYIWOWECH IMIWEGRI] OFMMHOE BAY WELLS Quad W. OTH W Page 124 2 COMMISSIONER FOERSTER: No, the question was if 3 they were non -rig would they -- would a rig decomplete 4 have required variance. 5 MR. DANIEL: Correct. 6 COMMISSIONER FOERSTER: Yeah. 7 MR. DANIEL: I have a second question here. 8 The number of two string wells repaired prior to start 9 up. I think it also came from Commissioner Foerster. 10 I have another question here pertaining to the 11 range of criteria used for sustained case and pressure 12 management operability determination. Question, around 13 5.4 in the written submission. We can provide 14 additional detail there, but principally it enshrines 15 what we've got in conservation order 492 and our well 16 integrity operating practice and the operating limits 17 that we have set for our wells. We'll provide an 18 answer for that in writing. 19 And I have probably the last one is a copy of 20 the L5-13 report from the external company that 21 analyzed the metallurgical remnants from the cut. 22 Those are all the questions I have. 23 COMMISSIONER FOERSTER: That's all I have too. 24 MR. DANIEL: Thank you. 25 ACTING CHAIR SEAMOUNT: Okay. How long should Comuw Mdrix LLC H1911e: 907-243-0 8 135 06a.. Ur.. St. 2., Mck AK 99%1 Fax 90]-243-11]3 E.il: sahile(a gcind AOGCC 2/132019 ❑MO: MQO YIWOM4ECHAMCALIIYFEGMI OFPRMHOEBAYWELLS mad No. 011+064 CoMuler Mama LLC Phone: 907-343-0668 135C ettvd Or., Ste 3.. Mch AK WMI Fax: 907-243-1473 E.R. mhile(dgd.nn Page 125 1 we leave the record open for to get those answers? 2 MR. DANIEL: I think -- this is Ryan from BP, 3 Chair Seamount if we could propose two weeks, how does 4 that sound? 5 ACTING CHAIR SEAMOUNT: Is that 14 working days 6 or 14 total? 7 MR. DANIEL: It's -- either way, I mean, just 8 -- just two weeks, 14 -- 14 days. 9 ACTING CHAIR SEAMOUNT: Samantha, what's that 10 date come to? 11 MS. CARLISLE: February 27. 12 ACTING CHAIR SEAMOUNT: February 27th. 13 CHAIRMAN FRENCH: Let's make it the 26th. 14 ACTING CHAIR SEAMOUNT: Okay. We'll leave the 15 record open until February 26. 16 Is there any reason to take a recess? 17 COMMISSIONER FOERSTER: I think we can adjourn. 18 ACTING CHAIR SEAMOUNT: Does any of the staff 19 think we ought to take a recess? 20 (No comment) 21 ACTING CHAIR SEAMOUNT: Okay. Now the question 22 now is do I adjourn..... 23 COMMISSIONER FOERSTER: Yes. 24 ACTING CHAIR SEAMOUNT: .....or continue? 25 COMMISSIONER FOERSTER: You adjourn. CoMuler Mama LLC Phone: 907-343-0668 135C ettvd Or., Ste 3.. Mch AK WMI Fax: 907-243-1473 E.R. mhile(dgd.nn dOOCC 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 21132019 RMOI MQMYMTOM4ECHAMCAL EGR OFPRODHOEB"Y LI Docket M.OM-064 Page 126 ACTING CHAIR SEAMOONT: Okay. This hearing is adjourned. Thank you very much for your participation. Oh, wait. What time is it. It's 2:09. We're adjourned. (Hearing adjourned) (END OF PROCEEDINGS) Coi uta Matrix, UC Phone: 907-243-066% 135 ChrtAm w Dr., &e. 2., Mch. AK 99501 F. %7-243-1413 Em laahile�,gci.nn AOGCC 2/138019 OWO:MQMYI OM4ECMMCALWEGPM OF PRUDHOE BAY WELLS Docks %, OTH 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 TRANSCRIBER'S CERTIFICATE I, Salena A. Hile, hereby certify that the foregoing pages numbered 08 through 127 are a true, accurate, and complete transcript of proceedings in Docket No.: OTH 18-064, transcribed under my direction from a copy of an electronic sound recording to the best of our knowledge and ability. ComuterM nz LLC Phone: W-243 S 135 Ov me n M.. Ste. 2., Mch. A 99501 F. 907 -243 -Mn Er il: m ile ftdnd STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Docket Number: OTH-18-064 Mechanical Integrity of Prudhoe Bay Wells February 13, 2019 at 10:00 am NAME AFFILIATION Testify (yes or no) �Zc zy� �insi o��rcriy N o rllue4, �4PrAI'C L R P A 0 D"(, r CI -)M05k 1 L P3CIVC6AAN OL A(( y� a /7'/ ^ e /rii / / / Y U NAME AFFILIATION Testify (yes or no) `of rio r��thv �l(rlk� S /PINIt/ A/D NO Ak 13 AOGCC 2n12019 ITMO: INQMYB OM4ECHAMCALINTEGMTYOFPRGOHOEBAYWELTS Oocka No. OTH-064 ALASKA OIL AND GAS CONSERVATION COMMISSION In the Matter of the Inquiry into the ) Mechanical Integrity of Prudhoe Bay ) Wells Operated by BP Exploration ) Alaska, Incorporated. ) Docket No.: 0TH 18-064 VOLUME I PUBLIC HEARING February 7, 2019 10:00 o'clock a.m. BEFORE: Daniel T. Seamount Co"uta Matrix, LLC Phots: 90]-243-0668 135 C to n Oc., Su. 2., Anch AK 99501 Fax:9 -243-1473 Email:s ikftmm AOGCC VM019 O'MO: WQUIRYI OM4ECHANICALMEGR OFPRUDHOEBAYWEUS Dodd No. OM -064 Page 2 1 TABLE OF CONTENTS 2 Opening remarks by Acting Chair Seamount 03 3 N 5 6 7 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Coulee Mah ,LLC Phone: 907-243-0668 135 Chdttonsen Dr., Stw 2., AncE. AK 99501 Fax: 907-243-1473 Emil: n ikGu gciMd AOGCC 2M019 "0 MQUMYMTOM4ECMMCALMTEGI OFPRUDHOEBAYWELLS D.c No. OMF Page 3 1 P R O C E E D I N G S 2 (On record) 3 ACTING CHAIR SEAMOUNT: Okay. I'd like to call 4 this hearing to order. Today is February 7th, 2019, 5 the time is 10:00 o'clock. The location is 333 West 6 Seventh Avenue, Anchorage, Alaska. That is the offices 7 of the Alaska Oil and Gas Conservation Commission. I'd 8 like to introduce the bench which is myself, Dan 9 Seamount, I'm one of the Commissioners. You can see 10 that we have two Commissioners missing, we need two 11 Commissioners to make a quorum so we don't have enough 12 to make a quorum today. 13 But this is docket number 0TH 18-064 which is 14 mechanical integrity of Prudhoe Bay wells. The Alaska 15 Oil and Gas Commission has on its motion set this 16 hearing to assess the mechanical integrity of Prudhoe 17 Bay wells operated by BP Exploration Alaska, 18 Incorporated. And we did get this statement from BP 19 today that we will put into the record. 20 Computer Matrix will be recording the 21 proceedings, you can get a copy of the transcript from 22 Computer Matrix Reporting. 23 Now this matter is extremely important to us 24 and I have to apologize that we don't have a quorum for 25 a meeting today. But due to circumstances completely Com tesMaz x,LLC M.: 135 CM1nst n R., Ste 2., An AK 99501 F. 901-243-1473 Emeil: saM1ikQygcim� AOOCC n=9 ITMO: MQMYMTOM4£CHANICALMTEORITYOFPROOHOEBAY WELLS D &d No. OTH-064 Page 4 1 unforeseen and out of our control at this time the 2 matter that was set for today's hearing cannot be held 3 today. I notice there's a lot of people that are -- 4 that planned to testify and we'd like to -- well, we 5 have to continue this meeting and I'm wondering 6 especially for the people that are planning to testify 7 would Monday, February 11, 2019 at 10:00 a.m. be 8 acceptable. 9 And please identify yourself. 10 MR. DANIEL: Good morning, Commissioner 11 Seamount. My name is Ryan Daniel, I work for BP 12 Alaska. 13 Yes, I think the llth of February will work for 14 my team. 15 ACTING CHAIR SEAMOUNT: Okay. Great. Thank 16 you very much. So I guess we'll set that matter for 17 that time. I don't know if that agrees with 18 everybody's schedule, but at least we'll have testimony 19 and a transcript coming out after Monday's hearing. 20 Are there any questions or comments? You don't 21 have to give presentations today because you're going 22 to have to do the same thing -- exactly the same thing 23 tomorrow or, I mean, on Monday and I know what that's 24 like because I went to Juneau, I had to give the exact 25 same three hour presentation three times. It gets Con tams , LI.0 PM.: M -2434M 135 Cimia,m= a., Ste. 2., Arch AK 99501 Fav: 907-243-1473 Email:v iLftcLm AOGCC 2/712019 R O: NQMYB OM4EC MCALMEGRITYOFPRMHOEBAYW LU Docket M. OTR -0 Page 5 1 exhausting. 2 MR. DANIEL: Sorry, Commissioner, I've just 3 been asked if we could reschedule the meeting for 4 Wednesday, if that will work. 5 ACTING CHAIR SEAMOUNT: How does Wednesday look 6 on our calendar. 7 MS. CARLISLE: Wednesday is open for the AOGCC. 8 ACTING CHAIR SEAMOUNT: Wednesday? 9 MS. CARLISLE: Yes. 10 ACTING CHAIR SEAMOUNT: Okay. We'll do it for 11 Wednesday, February 13th at 10:00 a.m. 12 MR. DANIEL: Thank you, Commissioner. 13 ACTING CHAIR SEAMOUNT: Do you guys like 10:00 14 or 9:00? 15 MR. DANIEL: 9:00 is fine. 16 ACTING CHAIR SEAMOUNT: I like 10:00 because I 17 live way out in Eagle River and I never know what that 18 traffic's going to do. 19 MR. DANIEL: 10:00 is good as well, 20 Commissioner. 21 ACTING CHAIR SEAMOUNT: Okay. We'll do it 22 Wednesday at 10:00 a.m., February 13th. 23 Any other questions or comments? 24 (No comments) 25 ACTING CHAIR SEAMOUNT: I'm sorry you all had Co11 wMa ,LLC P1ro :907-243-0 135 Clvi == De., Ste. 2., Arch AK "MI Fu: 907-243-1473 E.iP. saFile!ubcine� AOGCC 2/1/2019 ITMO: MQMYMTOMOCHAMCALMTEGRDYOFPRMHOEEAY WELLS Do&d No. OTH-064 Page 6 1 to come here, I thought we told your boss' boss' boss 2 that only one person needed to attend. But I'm glad 3 that the presenters attended so we can get that 4 scheduled. 5 MR. DANIEL: So thank you, Commissioner, on 6 behalf of BP Alaska. 7 ACTING CHAIR SEAMOUNT: Well, thank you for 8 coming -- for everybody coming down. It was nice 9 seeing you all. And with that there's coffee out there 10 and you can mingle as long as you want, just don't 11 bother Megan. 12 And where's Tab. I don't think we adjourn, 13 we're just continuing this. All right. So we continue 14 it on Wednesday. 15 (Off record) 16 (PROCEEDINGS TO BE CONTINUED) 17 SM. 19 20 21 22 23 24 25 Con to Matrix, LLC Ph m %7-243-0668 135 Chri¢ n Dr., Sm. 2., AMh, AK 99501 Fu: 90]-243-14]3 Email: s i4Qgmw AOGCC 2 J2019 RMO: WQD YW OM4ECHAMCALMTEOR OFPRMHOEBAYW LU Do&d No. OTH-064 Page 7 1 TRANSCRIBER'S CERTIFICATE 2 I, Salena A. Hile, hereby certify that the 3 foregoing pages numbered 02 through 07 are a true, 4 accurate, and complete transcript of proceedings in 5 Docket No.: 0TH 18-064, transcribed under my direction 6 from a copy of an electronic sound recording to the 7 best of our knowledge and ability. 8 9 10 PATR TCNI T- HTT-97 (T -van SGrllger) 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Comuw Matra, LLC PMne: 90]-243-0668 135 Cheis. D .., Sa. 2., Arch AK 99501 Fax: 907343-1473 Email: a HeCaVi w STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Docket Number: OTH-18-064 Mechanical integrity of Prudhoe Bay wells February 7, 2019 NAME AFFILIATION I hbH YIN? -41 - /a [N AS tit,(/f-r- A N COALA Ktkf Al �J�0-A Mc Le Act C) �� A/6�4j 61 �F A'(A CINEk- (AA (t-tr PL/o fi n„✓ rC,O�x�Pc /U0 L l n (A (h L J' c4 Na 12 Anchala Klein Regional Vice President, GWO February 6, 2019 Hollis French Commission Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Direct 907 Anchorage, Main 907 58611 5111111 AK 99501 Fax 907 564 4014 Anchala.Kiein@bp.com Re: Docket Number: OTH-18-064 Mechanical Integrity of Prudhoe Bay wells Hearing set for February 7, 2019 Dear Chair French: BP Exploration (Alaska)Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 Via hand Delivery FEB 0 6 2019 AOGCoC BP Exploration (Alaska) Inc. (BPXA), operator of the Prudhoe Bay Unit, encloses its written submission in response to questions received from the commission in connection with the referenced hearing. BPXA respectfully requests that the commission receive this filing and include it in the record for this matter. D I will appear at the hearing along with our subject matter experts and offer testimony addressing the topics covered in the submission. Sincerely, i Anchala Klein Regional Vice President, Wells BP Exploration (Alaska) Inc. Enclosure RESPONSE TO ALASKA OIL AND GAS CONSERVATION COMMISSION'S QUESTIONS BP Exploration (Alaska) Inc. (BPXA) submits the following to the Alaska Oil and Gas Conservation Commission (AOGCC) in response to requests for information received from AOGCC staff. TOPIC 1: PRESENT THE RESULTS OF SUDDEN WELLHEAD RISE/WELLHOUSE COLLISION ASSESSMENTS 1.1 Wellhead/S-riser/flowline impacts with the well house. Through modeling, BPXA determined that the mechanical failure mechanism of the DS02-03 well was limited to those three -string casing design wells with the surface casing (SC) shoe set above the base of the permafrost. Wells with SC Landed within the nermafrnet* Identified following the DS02-03 Incident in 2017: 1 01-02 SC Depth SC Size Flowline Wellhouse Reservoir P&A in Sep 2 Well Name (ft MD) (inches) Disconnected? Removed? Notes Identified following the DS02-03 Incident in 2017: 1 01-02 698 20 Yes Yes Reservoir P&A in Sep 2 01-04 1508 20 Yes Yes 2018 3 01-05 1216 20 Yes Yes 2 casing string well 4 02-02 1464 20 Yes Yes 20x13 and 13x9 annuli 5 02-03 1219 20 N/A N/A P&A in 2018 6 02-04 1207 20 Yes Yes 2 casing string well; 7 02-05 1205 20 Yes Yes ravel strip 8 02-06 1223 20 1 Yes Yes 2 casing string well; 9 04-01 1184 20 Yes Yes ravel strip 10 04-02 1191 20 Yes Yes 11 04-03 914 20 Yes Yes 12 04-04 1188 20 Yes Yes 13 04-05 964 20 Yes Yes 14 J-02 938 20 Yes Yes Identified tollowing the manual well file search in Q1 2018 BP Response to AOGCC Questions February 6, 2019 Page 1 Reservoir P&A in Sep 15 M-01 928 133/8 Yes Yes 2018 16 E-28 1793 133/8 No No 2 casing string well 20x13 and 13x9 annuli 17 J-01 973 20 No No are fully cemented 2 casing string well; 18 S-122 562 13 3/8** No No ravel strip 2 casing string well; 19 W-209 1879 13 3/8** No No ravel strip BP Response to AOGCC Questions February 6, 2019 Page 1 Added as a precaution due to SC shoe proximity to the permafrost base in Q4 2018 N23 01-03 1950 20 Yes Yes 2 casing string well; 20EW-216 [21E F-04 1310 E318 No No gravel string * Excludes Observation Wells **Gravel String 2 casing string well; 1309 -- No No gravel string Added as a precaution due to SC shoe proximity to the permafrost base in Q4 2018 N23 01-03 1950 20 Yes Yes F-04 2000 185/8 Yes Yes * Excludes Observation Wells **Gravel String An operability study was conducted on well DSO4-03, the highest valued well from a production utility standpoint, that was shut-in after the DS02-03 incident. This study concluded that the risk of returning 04-03 to production could not be mitigated to an acceptable level, due primarily to the unpredictability of the subsidence loading of the casing strings. 1.2 Metallurgical studies conducted on recent well failures: PBU 02-03B; PBU 02- 02A; PBU L5-13 (injector failure during required mechanical integrity testing (MIT). Metallurgical studies have not been completed on PBU 02-03B and PBU 02-02A. Metallurgical Study of L5-13 SC Failure A forensic metallurgy company submitted their findings on the metallurgical examination of well L5-13 in September of 2018, and following are excerpts from their report: The insulated conductor and cement were removed from the assembly to expose the surface casing. After a leak site was discovered on the surface casing, [we] proceeded with additional cuts to expose the production casing and tubing. A second leak site was discovered on the production casing. Both of the cracks were associated with a deformed region with an appearance similar to an inward buckling or collapse. No apparent crack origin(s) were observed on either of the casings; however, the presence of shear lips at the external surface and secondary cracks at the internal surface indicated the fracture origins favored the internal surface. Metallurgical analyses indicated there no apparent contributions to the crack initiation from material defects, or service related mechanisms such as corrosion or fatigue. Further, damage from drilling equipment was not indicated as a primary cause for the reported leak. Based on the analyses completed during this project, the forensic metallurgy company concluded the following: BP Response to AOGCC Questions February 6, 2019 Page 2 1. The leaks occurred at two fractures, one on the surface casing and one on the production casing. The location where the leaks occurred was coincident with inwardly deformed regions of both of these casings. 2. Swelling or bulging of the 20 -inch conductor was evident at the same location where the inwardly deformed casing occurred. A notable bulge was more pronounced near the location where the leak occurred. API Technical Report 5C3/ISO 10400:2007 indicates that the collapse resistance and yield strength of this casing are approximately the same, thus supporting this observation. 3. The inward collapse of the casings was asymmetrical with the sides of the casing opposite the collapse remaining relatively intact as a semicircle. In [our] experience, casing collapse usually impacts both sides of the affected casing collapse in a symmetrical manner, i.e., collapse on both sides of the casing. In such collapse cases, it is also common for the collapsed region to extend the full length of the casing joint. In the L5-13 casing samples, the asymmetrical production casing was also within the deformed region of the surface casing. The localized and asymmetric deformation appears to have been caused by an event that imparted a localized internal force at the 20" x 13-3/8" annulus rather than from a sudden change in internal pressure that would have created an unstable event that would have led to a full, symmetric collapse. 4. Although partially obscured by post-fracture deposits and oxidation, the appearance of the fractures in both casings was similar. Both samples displayed secondary cracks at the internal surface with plastic deformation (shear lips) at the internal and external surfaces as well as relatively flat fractures at the mid -wall. These features are consistent with an overload fracture that occurred on collapsed material (such as that for a pressure test). One such pressure event reportedly occurred during the March 30, 2017 MIT -IA test when the IA lost pressure at 2090 psi. Mechanical tests and chemical analysis results of the surface and production casing material were within the specified material requirements. TOPIC 2: BPXA RISK ASSESSMENT ACTIONS TO PREVENT REOCCURRENCE 2.1. What Options were evaluated and what physical actions were taken? Table of actions: As a result of the DS02-03 investigation, BP identified 14 wells with a mechanical design susceptible to a subsidence -induced failure similar to that observed on well 02-03 (3 -string casing design with SC shoe set above base permafrost). The following table of actions were taken to prevent reoccurrence. BP Response to AOGCC Questions February 6, 2019 Page 3 BP designated these wells as Not Operable, meaning the wells are not allowed to be placed in production in their current condition. BP set mechanical plugs in those wells that did not already have one installed. These wells were: • 01-02 • 01-04 • 01-05 • 02-04 • 02-06 • 04-02 • 04-03 • 04-05 • J-02 The following wells had mechanical plugs in place at the time of the D502-03 incident: • 02-02 • 02-05 • 04-01 • 04-04 Well DS02-03 was plugged and abandoned with the wellhead removed and marker plate welded on the casing stub. Flowlines, where present, were removed from these wells. An operability study was completed in September 2017 to determine if any of these wells could be safely returned to operation. The following options were evaluated: 1. Return the wells to production after taking actions to mitigate risk of loss of primary containment (LOPQ or personal injury; 2. Return the wells to production or injection after eliminating the risk of subsidence - induced SC failure by one of the following methods (only applicable to 6 of the wells): a. completely decouple the 20" from the 13-3/8" casing, or b. affix the entire 20" to the 13-3/8" casing with cement; or 3. Permanently abandon the wells. In addition, BPXA reviewed options for re -drilling reservoir targets for wells that were not returned to operation. Afterward, BPXA undertook the following actions: • The 13 remaining wells with SC set in permafrost remained shut in, classified as Not Operable, with downhole plugs set in the tubing; • An unsuccessful attempt to decouple the SC from the wellhead was made on well 04-01; • The reservoir targets in two of the wells 04-03 and 01-05 were redrilled from new surface locations (grassroots wells); and BP Response to AOGCC Questions February 6, 2019 Page 4 • The 13 wells have been placed on a list for permanent abandonment. In first quarter 2018, after a manual search through the records, BPXA identified 7 additional wells with mechanical characteristics that might be susceptible to a subsidence -induced SC failure like that observed in 02-03. BP undertook a study to evaluate the risks of bringing five of these wells with different cementing configuration than DS02-03 and DS02-02 wells ("5 Study Wells") back in operation.' The study resulted in recommendations that supported returning the 5 Study Wells back to operation and approval was subsequently received from the AOGCC.z A summary of the actions taken to prevent reoccurrence in these seven wells follows: • M-01 Reservoir cement P&A performed in 2018. • E-28 Mechanical Plug set in tubing. Two string design with SC hoe set above base permafrost. Modelling predicts that sudden wellhead rise is unlikely in 2 -string design. • J-01 Approved to be returned to production. • S-122 Approved to be returned to injection. • W-209 Approved to be returned to injection. • W-214 Approved to be returned to injection. • W-216 Approved to be returned to injection. After the 02-02 incident, an additional 2 wells were identified with SC shoes too close to base of permafrost to definitively say that the casing was fixed to stable formation below the permafrost. A summary of the actions taken to prevent reoccurrence in these two wells follows: • F-04 Mechanical Plug set in the tubing • 01-03 Mechanical Plug set in the tubing See Table in section 1.1 for status of flowlines and wellhouses of all the wells mentioned in section 2.1. 2.2. What risk acceptance criteria were used in these evaluations? BPXA modeled the tubular design of the three -string casing design wells with SC set in the permafrost and concluded that the wells can experience a 20" SC failure, due to permafrost subsidence loading similar to 02-03, resulting in vertical wellhead movement. Equipment changes could be implemented to significantly reduce the risk of a loss of primary containment, such as raising the wellhouse to prevent a tree/flowline collision ' See Study of Five (5) PBU wells with SC set in the permafrost, filed in October 16, 2018, with the AOGCC in support of BPXA's application to return five wells to operation. ' See BPXA's application filed with the AOGCC on October 16, 2018. BP Response to AOGCC Questions February 6, 2019 Page 5 and the installation of a subsurface safety valve (SSSV). However, ensuring the safety of personnel working on or around these wells raised concerns over the wells' life. Multiple workable solutions were identified for the scenarios listed above, but most solutions mitigated, but did not eliminate, the risk to personnel of a rapidly rising wellhead/tree. Implementing numerous, special conditions of operability over the life of the wells is in itself a risk. At the conclusion of BPXA's assessment of the three -string casing design wells, BPXA decided that all the wells should be abandoned unless the risk of failed casing and the resultant rapid vertical wellhead/tree movement can be eliminated. Of these wells, there were six wells (02-02, 02-05, 04-01, 04-04, 04-05, J-02) where options were identified to eliminate the risk of failed casing. These six wells had not been modified by major rig workovers and retained their original wellbore construction. Three of these wells (02-02, 02-05, 04-04) were already planned for abandonment, independent of the 02-03 event, or lacked remaining resources to justify wellwork. The remaining three wells (04-01, 04-05, J-02) were identified as potential candidates for wellbore modifications to eliminate the risk of failure. Options identified included decoupling the 20" from the inner wellbore at surface, thereby allowing the 20" to move independently, or the option of executing a significant rig workover to completely couple the 20" to the 13-3/8" by cementing the entire annulus. Either option would have eliminated the risk of failure. BPXA did not identify any viable options for eliminating the failure risk for the remaining wells that had undergone a major rig workover in the past (e.g., 04-03). 2.3. Has BPXA expanded well integrity monitoring plans to incorporate [earnings from the DS02-03B investigation? If so, what is the plan's effectiveness? Provide details. Please refer to the discussion in Topic 5, section 5.5, which has a similar question. TOPIC 3: BPXA HAS IDENTIFIED 3 STRING CASING WELLS WITH SHOES IN PERMAFROST AT RISK OF FAILURE SIMILAR TO DS02-03 AND DS02-02 3.1 Present the findings of the DS02-03B investigation. The DS02-03 report documents the findings from that investigation. Information regarding three -casing string wells with SC set within the permafrost is summarized here. The investigation team found the cause of the event to be the tensile failure of a coupling 50-1/2 inches below the wellhead in the 20" SC, which allowed upward forces generated in the inner casing strings to lift the wellhead. The investigation team concluded that the failure of the 20" SC was caused by a downward load imparted by subsurface subsidence BP Response to AOGCC Questions February 6, 2019 Page 6 of the permafrost formations on the SC, resisted by the compression of the inner casing strings. Upward forces created by thermal expansion and wellbore pressures on the inner strings contributed to the failure, but modelling showed these loads to be insufficient, in isolation, to cause the 20" casing failure. The investigation team examined permafrost subsidence on the Alaskan North Slope and sought expert opinion on this topic. The team then considered the potential implications of subsurface permafrost subsidence and hypothesized a mechanism by which well 02-03 casing failure occurred. The investigation team concluded that subsurface permafrost subsidence was most likely caused by the melting of the permafrost during production of reservoir fluids. These hot produced reservoir fluids caused the permafrost zone to melt non -uniformly near the wellbore. Melt water has a lower volume than the frozen water and dissipates through permeable zones. As permafrost melts the overburden formations subside. These subsiding formations could cause a high enough downward load on the 20" SC, resisted by the strength and stiffness of the 13 3/8" intermediate casing, 9 5/8" production casing, and the 51/2" production tubing, to account for the failure below the wellhead. When the 20" SC failed, it released the energy held in the intermediate and production casing strings, which lifted the wellhead and Xmas tree. This mechanism is dependent on two conditions: a) Permafrost subsidence transferring a load to the well; and b) A well design that includes intermediate casing, otherwise called a "three -string casing design." The three -string casing design includes an intermediate casing in combination with the production casing (collectively called the "inner strings") which is stiffer and more resistant to buckling than a two -string casing design. A two -string casing design has no intermediate casing and is therefore more flexible. Despite this mechanism being complex with many forces at play, the investigation team concluded that permafrost subsidence loading most likely caused this event. Following are the findings from the DS02-03 Investigation Report: F1. When Well 02-03's Xmas tree and wellhead suddenly moved upwards, the pressure gauge on the top of the S -riser collided with the well house roof and the gauge assembly sheared off causing the upper LOPC. F2. When Well 02-03's Xmas tree and wellhead suddenly moved upwards, the swab valve handle impacted the well house structure imparting a side loading on the tubing head adaptor upper flange. As a result, the flange studs stretched causing the lower LOPC. BP Response to AOGCC Questions February 6, 2019 Page 7 I F3. Permafrost subsidence imparted a downward load on the 30" conductor and 20" surface casing string of Well 02-03: a) causing the 20" casing to fail below the wellhead; and b) allowing the internal casing strings, production tubing, the wellhead, and the Xmas tree to move upwards. F4. Surveys had been conducted since the 2014 baseline survey, with the locations selected based upon perceived subsidence risk. These did not include DS 2 and other drill sites with perceived low subsidence. F5. Permafrost subsidence loading on the surface casing and its impact on three -string casing design has not previously been recognized by industry as a potential failure mode for the surface casing. F6. The investigation team: a) could not identify evidence that permafrost subsidence loads have resulted in the same mode of failure of PBU two string casing designs; and b) has not carried out modelling to establish the potential for this mode of failure for two string casing designs. F7. The investigation team found no reports indicating that three -string casing design wells with the surface casing seat below the permafrost had exhibited upward movement of the wellhead. F8. The downward load created on the conductor and surface casing string by permafrost subsidence has not been factored into the PBU well basis of design. 3.2 Are there any untested hypotheses that necessitated assumptions in formulating conclusions? What are they? What is your level of confidence in your assumptions? The untested hypothesis is that permafrost subsidence could generate a downward force sufficient to part the 20" SC. The evidence of parted casing demonstrates that downhole forces were indeed sufficient. An independent detailed geotechnical study of DS02 is being initiated. 3.3 What work is being done to understand the implications of variations in rock properties within the permafrost zone and differential freeze/thaw? There are no specific work fronts ongoing for DS2. However, monitoring and surveillance are ongoing across PBU as mentioned in section 4. 3.4. Discuss priorities for preventing recurrence of DS02-03B and DS02-02A. BP Response to AOGCC Questions Page 8 February 6, 2019 The priorities for abandoning the remaining shallow SC wells (i.e., the wells with a three - string casing and cementing configuration like DS02-03 and DS02-02) are based first on whether or not the downhole plug is holding (without re -pressurization) and second on whether or not the well has undergone a significant RWO to remove the original wellhead and place additional cement in some of the annuli, thereby reducing the likelihood or severity of a SC failure. The prioritized list follows (02-02 is in progress of being P&A'd): 1. Wells with rapid re -pressurization 02-05 2. Wells with slow re -pressurization a 04-01 a 04-05 3. Wells with downhole plugs and original wellhead is in place a 04-04 J-02 4. Remainder (plugs downhole and a change in original wellhead) 01-02 a 01-04 a 01-05 a 02-04 a 02-06 a 04-02 a 04-03 3.5 How did the DS02-02A failure confirm or change assumptions and priorities? The DS02-02 failure confirmed assumptions regarding the DS02-03 well failure sequence. Like the DS02-03 well, the DS02-02 well is a three -string casing design with 20" SC set within the permafrost. The parted 20" casing supports the hypothesis that permafrost subsidence can apply a force sufficient to overload the outer string. The subsequent upward wellhead movement fits within the analytical model used to assess the wellhead movement for DS02-03. An additional datum measured for DS02-02 was the distance between the parted surfaces of 20" casing. This gap represents the combination of upward movement plus the casing stretch corresponding to the axial force at the time of failure. Though a precise calculation of parting force could not be made from the post -failure observations, the potential range of forces indicated by wellhead movement does align with a reasonable range of parting loads for 20" 94 ppf H40 casing. Thus, the post -failure analysis of the DS02-02 well confirms the model used to explain the wellhead movement of the DS02-03 well. BP Response to AOGCC Questions February 6, 2019 Page 9 3.6 Since the DS02-03 failure, 5 wells were approved to be placed back online. What impact does the failure of DS02-02A have on these wells? The five wells have SC set in the permafrost but have casing configurations that differ from wells DS02-03 and DS02-02. The failure at DS02-02 does not indicate a different level of risk for operating the five wells. Wells other than DS02-03 and DS -02-02, including the five approved to be placed back online, have been analyzed for the potential of permafrost subsidence causing a parting of the SC, allowing a subsequent upward wellhead movement. The work has consistently followed a pattern. When subsidence loads are transferred solely to the wellhead (e.g., when SC is set in the permafrost), then the casing parting and subsequent upward wellhead movement scenario cannot be excluded. Conversely, when subsidence loads can be partially transferred to a competent formation below the base of the permafrost, then the described failure scenario is not credible. Figure 1 illustrates two basic SC configurations. The sketch on the left shows SC set within the permafrost. Subsidence -induced forces imparted to the SC could be fully transferred through the casing to the wellhead. If the inner strings can support a force sufficient to part the SC, then subsequent upward wellhead movement is possible. The sketch on the right shows the case where formation loads act on a casing that extends to a competent formation below permafrost. In this case, subsidence loads transfer through the casing are distributed between the wellhead and the formation below permafrost, thereby reducing the potential for a parting load. An industry publication used Alaska North Slope field measurements to conclude that casing compressive and tensile strains from subsidence are about 0.7% to 0.9%, an amount that is insufficient to part oilfield casing.3 A continuous SC set beneath the permafrost is unlikely to experience the failure scenario of parted casing and subsequent upward wellhead movement. Figure 1 - Load Transfer for Casing Set Within (left) and Through (right) Permafrost formation loads permafrost base formation loads permafrost base ] Mitchell, R.F. and M.A. Goodman, Permafrost Thaw -Subsidence Casing Design. SPE 6060, 1978. BP Response to AOGCC Questions February 6, 2019 Page 10 The five referenced wells can be grouped into two configurations: two -string casing designs with an outer gravel string to enable drilling through the permafrost, and three - string casing designs. Wells W-209, W-214, W-216 and S-122 are all two -string casing designs with an additional outer gravel string. • W-209 has a 13-3/8" gravel string set at 1,879 ft MD and a 9-5/8" fully -cemented SC set at 4,176 ft MD • W-214 has a 13-3/8" gravel string set at 1,310 ft MD and a 9-5/8" fully -cemented SC set at 3,714 ft MD • W-216 has a 13-3/8" gravel string set at 1,309 ft MD and a 9-5/8" fully -cemented SC set at 4,021 ft TVD • S-122 has a 13-3/8" gravel string set at 562 ft MD and a 9-5/8" fully -cemented SC set at 3,658 ft MD Figure 2 illustrates the typical configuration for the four wells. The presence of the gravel string raised the question of similarity with three -string casing designs with the outer string set within permafrost. However, there are three distinct differences that change how permafrost subsidence loads can act on the wells: The wellhead is initially resting on a landing ring attached to either the gravel string or the conductor. Absent cement, a downward force on the 13-3/8" gravel string would cause separation at the wellhead. In contrast, a downward force on the 20" SC caused a downward force on the wellhead for wells DS02-03 and DS02-02. However, in all four wells, the cement design places cement through the entire 9-5/8" x 13-3/8" annulus. In this condition, permafrost subsidence loads acting on the gravel string are transferred over the length of the 9-5/8" rather than at a single point (i.e., the wellhead). The 9-5/8" casing is fully -cemented and extends below the permafrost. As a result, permafrost subsidence loads that are applied to the 9-5/8" get distributed between the wellhead and the formation below the base of permafrost. Figure 2 — Typical Casing Configuration for W-209, W-214, W-216, and S-122 BP Response to AOGCC Questions February 6, 2019 Page 11 13-3/8" gravel string, partially -cement permafrost base 9-5/8" casing, fully -cemented 7" casing, partially -cemented The failure sequence of permafrost subsidence parting the outer casing and a subsequent upward wellhead movement is not credible for the four two -string casing wells with additional gravel strings. The fifth well, J-01 B, is a three -string casing design. It has 20" SC set within the permafrost at 973 ft MD and a 13-3/8" intermediate casing set at 4,258 ft MD. The 13-3/8" casing has two stages of cement, with the upper stage squeezed from the top down to a port collar at 1,615 ft. The 9-5/8" production casing also had a top-down cement job down to 2,000 ft, verified by an ultrasonic inspection log. Though this is a three -string casing design with SC set within the permafrost, it differs from wells DS02-03 and DS02-02 in two distinct ways: The annulus between the 20" and 13-3/8" is fully -cemented. Permafrost subsidence loads applied to the 20" are transferred over the length of the cemented annulus rather than solely to the wellhead. The top of the 9-5/8" x 13-3/8" annulus is coupled together with 2,000 ft of cement. Permafrost subsidence loads transferred to the 13-3/8" get distributed over the length of the cemented annulus, allowing a portion of the force to get transferred to formation below the permafrost. The down -squeeze placement technique and the 9-5/8" cement evaluation log provide assurance that permafrost subsidence loads will not part the reinforced 20" SC. The failure sequence of permafrost subsidence parting the outer casing and a subsequent upward wellhead movement is not credible for well J-01 B. TOPIC 4. WHAT IS THE CURRENT STATE OF SUBSIDENCE THROUGHOUT PBU? 4.1 AOGCC has observed wellhead/landing ring separation on some PBU pads. SP does not use wellhead/landing ring separation as an indicator of casing axial strain. The conductor is generally free to move independently from the wellhead, therefore BP Response to AOGCC Questions February 6, 2019 Page 12 casing. However, a measurement of wellhead/landing ring separation was taken as part of the 2018 wellhead elevation survey, field wide when the condition was observed and accessible. There are 20 pads and 95 wells with observed and measured well ring separation with the distribution described in the following sections: 4.2 What is the status of the following pads? L 6 wells at L pad where landing ring separation is observed and measurable V 38 wells at V pad where landing ring separation is observed and measurable S 2 wells at S pad where landing ring separation is observed and measurable DS2 2 wells at DS2 where landing ring separation is observed and measurable 4.3 Other pads we should know about? There are 48 Wells at 16 other drill sites where landing ring separation is observed and measurable. 4.4 What elevation surveys have been completed? BP has taken wellhead datum measurements field wide. Wellhead Elevation Survey Survey Year Pad/DS 2011 L, S, V, W, Z 2012 A, AGI, B, C, D, L1, L2, L3, L4, L5, NK, E, F, G, H, J, K, LGI, M, N, NGI, P, P1, P2, Q, R, T, U, WGI, X, Y, V 2013 Z, L, S, W, Z, V 2014 A, 1, 2, 3, 4, 5, 6, 7, 9, 11, 12, 13, 14, 15, 16, 17, 18, East Dock, Pad 3, PWDW, V 2015 G, L 2016 P1, R, S, W, Z,A,R 2017 L, V, 2, 2018 A, AGI, B, C, D, L1, L2, L3, L4, L5, NK, E, F, G, H, J, K, L, LGI, M, N, NGI, P, P1, P2, Q, R, S, T, U, V, W, WGI, X, Y, Z, A, 1, 2, 3, 4, 5, 6, 7, 9, 11, 12, 13, 14, 15, 16, 17, 18, East Dock, Pad 3, PWDW 2019 L, V BP Response to AOGCC Questions February 6, 2019 Page 13 Wellhead datum elevations are measured at a consistent, marked location from survey to survey. In general, these measurements indicate the greatest amount of change to be on west end pads. 4.5 Compared against what baseline? The first PBU elevation baseline survey was performed in the field in 2011, with additional elevation surveys annually. See Table 1. Wellhead datum elevations are surveyed and stamped by a Professional Land Surveyor. The basis of elevation for each site is surveyed using differential leveling techniques and multiple, independent GNSS observations on three primary control points. 4.6 What integrity risk is identified with significant wellhead elevation change? Wellhead elevation change is one data point used to describe the potential for axial strain. It is not a full characterization of risk, as this movement does not describe whether the potential for strain is localized in a discrete location of the casing or whether the potential for strain is uniform and more spread out across the casing. 4.7 How many wells currently have failed integrity tests induced by subsidence? There are no operated wells that have failed integrity tests induced by subsidence. "Failed integrity tests" here means failed pressure integrity tests of the well barrier envelope. 4.8 Of the failed integrity tests, what is the failure mechanism? Please refer to section 4.7. a. Tubing or casing buckling? Please refer to section 4.7. DS 02-37 was a well completed with a one string casing design and shallow tubing buckling was confirmed with a caliper at approximately 570 feet MD. This well was plugged and abandoned in 2018 and the wellhead will be removed in 2019. BP Response to AOGCC Questions February 6, 2019 Page 14 b. "Sudden wellhead elevation rise" (BPXA term for 02-03B and 02-02A failures) and implications of those failures? Please refer to section 4.7. c. Any other subsidence induced failure mechanism to discuss? The primary failure mechanism postulated for wells subject to permafrost thaw is potential compressional buckling. 4.9 What does BPXA's active surveillance program involve? BPXA's subsidence related surveillance program involves active, ongoing surveillance and includes: • Pad level categorization of subsidence risk is driven by: o The rate of wellhead elevation displacements o Depth of SC o Completion size and configuration o Well anomalies identified that correlate to subsidence on the same pad o Repair or P&A of well identified that correlates to subsidence on the same pad Pads are categorized by criteria (based on empirical data gathered from historical surveillance) to assess relative risk, as follows: o 1: highest frequency of targeted surveillance (current plan is to perform pad -wide annual drifts and annual wellhead surveys) o 2: medium frequency of targeted surveillance (current plan is to perform pad -wide drifts every three years and wellhead surveys every three years) o 3: medium -low frequency of targeted surveillance (current plan is to perform pad -wide drifts every five years and wellhead surveys every five years) o Low: lowest frequency of targeted surveillance (opportunistic drifts and wellhead surveys every five years) BP Response to AOGCC Questions February 6, 2019 Page 15 • Pad relative risk level drives the frequency of targeted surveillance operations. Surveillance operations involve: o Repeat wellhead elevation surveys o Full diameter, 20' through tubing drifts 0 3D calipers o Gamma ray logs • Well level surveillance o If anomalies are observed during routine well operations or through surveillance operations, a surveillance plan is developed that involves the following actions, depending on the situation presented: • Pressure integrity tests • Drifts on a specified frequency Calipers on a specified frequency • Retrievable mechanical plug of the well Repair of the well anomaly • Plug and abandonment of the well 4.10 Drifts. Pads noted to have increased wellhead displacements, have increased surveillance with through tubing drifts to ensure tubing access into the well. Full diameter, longer drifts are run for surveillance as these larger size drifts give better indication of anomalies that might be present in the tubing. 20 -foot drifts are selected in lieu of shorter drift sizes to give better indication of sinusoidal or helical buckling. Wells without drift anomalies give a level of assurance that a mechanical plug can be set in the well. Wells with shallow drift anomalies are further evaluated with pressure integrity tests and calipers. Wells with higher relative risk, as discussed in the previous section, receive increased surveillance frequency. Well pads noted to have increased frequency of tubing drift surveillance: • L BP Response to AOGCC Questions February 6, 2019 Page 16 • V • W • H • Z 2 Since 2016, BPXA has performed approximately 460 subsidence drifts across the field. 4.11 Gyros. BP does not conduct subsidence surveillance by use of gyros as uncentered, 3D calipers provide better data analysis for understanding of subsidence evaluation. 4.12 Calipers. A tubing caliper is run if the well is noted to have shallow subsidence drift anomalies. Calipers can indicate restrictions and other anomalies at a measured depth in tubing or casing. If a well is noted to have a drift anomaly, it can then be logged with a multi -finger caliper for further diagnosis. The multi -finger caliper tool should have minimum 24 arms, which should be used in standard setup for common tubing sizes. The caliper tools are selected based on their maximum extension of the tool to tubing ID. Subsidence calipers are run to below the permafrost, typically to 2,500 TVD. 4.13 Tubing and Casing monitoring in other ways? Please refer to the well integrity discussion in Topic 5. TOPIC 5: SUSTAINED CASING PRESSURE (SCP) AND LONG TERM SHUT-IN (LTSI) WELL MANAGEMENT SCP/Well Barrier Integrity 5.1. Does BPXA have concerns regarding barrier integrity on producers and injectors with SCP? BP Response to AOGCC Questions February 6, 2019 Page 17 BPXA has a robust and time proven well integrity management system in PBU that is based on global industry standards, best practices, and local learnings. The system has been continuously improved over multiple years, with the most recent example being the field wide implementation of — 6000 wireless well annulus pressure and temperature transmitters. This leading-edge technology will improve safety, and decrease environmental risk, by reducing response time to well pressure anomalies and events. Typically, what used to take 24 hours for a single manual tubing, inner, outer annulus well pressure reading can now be automated every minute in all weather conditions. This provides an effective well operating limit alarm/alert capability to the board operator. BPXA's well integrity management system incorporates practices from API 90-2 and other industry standards (and complies with AOGCC regulations and orders) that prescribe safe well management practices to effectively mitigate SCP. BPXA imposes additional well barrier integrity assurance requirements on wells identified with SCP to mitigate the potential repress urization risks and reconfirm conformance with the well integrity operating practice (WIOP) and regulatory compliance annually. Likewise, the AOGCC require additional reporting monthly on wells with administrative approvals (AA), and under evaluation wells (UE), and periodic scheduled mechanical integrity pressure testing. It should be noted however that any well can develop SCP repressurization symptoms during its lifecycle, particularly during start-up or shut -down operations. A known well with manageable SCP may also have a deterioration in well barrier health, therefore monitoring frequency, response timing and well Integrity diagnostics are key mitigation factors that BPXA has in place to safely manage field wide SCP risk. 5.2. Describe BPXA's barrier philosophy and give examples. The definition of a well barrier typically refers to or states, "An envelope of one or more dependent well barrier elements (WBEs) that prevent fluids from flowing unintentionally from the formation or well into another formation or to the surface." Well barriers are classified as primary or secondary, based on proximity to the well fluids. As a guiding principle, well barriers are designed, selected, constructed and maintained such that no single failure of a well barrier will result in an uncontrolled flow of fluids to the environment. The definition of a well barrier element (WBE) typically refers to or states "A pressure and flow containing component that relies on other component(s) to create a well barrier and is verified to conform to specific acceptance criteria." BPXA adopted the global BP well barrier practice on Sep 30th, 2014. This Internal practice utilizes normative and informative references based on multiple API and ISO standards BP Response to AOGCC Questions February 6, 2019 Page 18 including Norsok D-10 and API 90 which are the most well-known and well-respected industry guidelines for well integrity management. PBU wells have a primary and secondary barrier which is aligned with AOGCC regulations. BPXA has implemented the two -barrier philosophy in the Alaska well integrity management data system application called AKIMS. The application tracks, documents, reports and communicates well integrity status and is used to effectively manage the well barrier health, compliance and conformance for all —1800 PBU wells on a 24/7/365 basis. The well integrity history for each well is recorded in detail and may include notes on well barrier mechanical status, pressure testing history, well work history, annuli pressure history, production and injection history, etc. Identified and applicable well barrier anomalies which may be categorized as Failures, Impairments, Other and Regulatory (FIOR). The AKIMS application allows well integrity engineers (WIEs) to record FIOR categories based on —60 specific well barrier conditions. This may lead to a well being reviewed for WIOP conformance and compliance, and reclassified (Operable, Not Operable or Under Evaluation) for production/injection operations as applicable based on the well barrier health. Wells that do not meet the well barrier operability requirements undergo additional review, well work diagnostics, monitoring, pressure testing, and repair work as applicable. These wells may then be classified as either "Under Evaluation" for a limited period of time (28 days) or remain Not Operable and Offline. For example, a failure of the tubing is automatically mapped to the well primary barrier, a failure of the production casing is mapped to the well secondary barrier, SCP on the A annulus may be mapped to the primary or secondary barrier depending on diagnosis. This barrier centric engineering approach allows BPXA to maintain a detailed barrier view of PBU wells health and utilizing AKIMS ensures systematic application of the two -barrier philosophy. BP Response to AOGCC Questions February 6, 2019 Page 19 5.3. Provide evidence that BPXA has performed/or performs critical reviews of the existing well integrity program to validate the program's effectiveness, where improvements have been made, and changes that are needed. BPXA conducted a Well Integrity Operating effectiveness audit of its well integrity management system in the first quarter of 2018. This audit was conducted by BP Group audit, with auditors external to the Alaska region. PBU co-owners ConocoPhillips Alaska, Inc. and ExxonMobil Alaska Production Company were also invited to attend in an observer capacity. e BPXA undertook corrective actions based on the audit. BP Response to AOGCC Questions February 6, 2019 Page 20 Surface Tree ,Annulus valve System Primary evM Barrier Tltia :i thn IBSt w,::l Nov, anvabpo Net prevents Ilov trarr a wxce Wellhead (with casing hanged ' Secondarywall Bamer .�w Th:e i3 the secontl ael Ua:•,:ei c..elco: Uh : preverS /lav I:cn, a so -x Surface Controlled Suosurface Sa'ety Valve iSCSSV) Casing (production casing) �t Wall banier element Completion Strirg C. Apreswre anti S:os ccrta r,_p "'Ii cCTOcoewls) to CfEal2 a .. Annulus Cement (production casing) 'rix nanlo envp ate Production Packer Casing (production casing) - .,- Lirer Top Packer Common well barrier element - - Cas YVR'J OAn.x ^�(an'Hrtt lent' 3 gnTiYl M31 pa::vcan the prm-y aro scwnda.., r+en.f" — Annulus Cement (liner) 5.3. Provide evidence that BPXA has performed/or performs critical reviews of the existing well integrity program to validate the program's effectiveness, where improvements have been made, and changes that are needed. BPXA conducted a Well Integrity Operating effectiveness audit of its well integrity management system in the first quarter of 2018. This audit was conducted by BP Group audit, with auditors external to the Alaska region. PBU co-owners ConocoPhillips Alaska, Inc. and ExxonMobil Alaska Production Company were also invited to attend in an observer capacity. e BPXA undertook corrective actions based on the audit. BP Response to AOGCC Questions February 6, 2019 Page 20 BPXA conducted a federal Safety and Environmental Management Systems (SEMS) audit of the well integrity management system in 2013. • BPXA undertook corrective actions based on the audit. BPXA conducts well engineering and well operations assurance reviews of well integrity, performed by external (to the region) subject matter experts. • BPXA undertook corrective actions based on the assurance reviews. BPXA conducts well engineering and well operations self -verification. • BPXA undertook corrective actions based on the self -verification reviews. BPXA conducts reviews of key well integrity compliance and conformance indicators based on field wide monitoring data and well status. Examples include the Area Management Report for well operations, and the Well Integrity Diagnostics Report and Injection Diagnostic Report for well integrity. In addition, the WIOP and well integrity training materials have been updated periodically to include new compliance and conformance requirements, lessons learned, and to incorporate best practices. Likewise, the well integrity data management system AKIMS, well subsidence management programs, and other specific engineering programs, example Gas lift valve reliability, etc., have all been undertaken in the last few years. Examples of continuous improvement programs: • WIOP Rev 4 dated Dec 2016, Rev 5 planned for revision this year. • Well Integrity reference manual, updated 2018. • AOGCC training module, updated 2018. • Annular fluid expansion awareness training module, updated 2017. • WIOP Training for Well Operators training module, updated 2017. • WIOP Training for Engineers training module, updated 2017. • AKIMS/Palantir Well Integrity data system, updated 2015-2018. • CO -736 annulus cement program, updated 2017-2019. • Gas lift valve and Injection valve improvement programs, updated 2016-2018. • Well Subsidence downhole surveillance drift program, updated 2016-2018. BP Response to AOGCC Questions February 6, 2019 Page 21 • Well Subsidence time-lapse surface elevation survey programs, updated 2011- 2019. • Well Operating Limits Project installation of —6000 wireless annuli pressure and temperature transmitters on all wells field wide, enabling a step change in well integrity monitoring and anomaly response, and decreasing exposure to human and environmental factors 2014-2019. These examples provide evidence that the BPXA well integrity management system in PBU is both effective, fit for purpose, and is being frequently updated to decrease safety and environmental risk, and improve operating effectiveness and well reliability. 5.4. What criteria are used for accepting diagnostic test results when a well exhibits SCP? BPXA has developed standardized approaches for well diagnostics and SCP management. These are consistent with industry standards, best practice and comply with the AOGCC regulations and orders. In summary, BPXA uses the long standing and proven safe repressurization rate criteria of two (2) bleeds per week (maximum) based on a wells annuli Normal Operating pressure Limit "NOL" as the principal determinate for a well that "may" be operable. Many other factors such as well history, start-up/shutdown dynamics, production or injection service type, fluid types, intermittent or continuous repressurization, are used on a case by case basis by experienced WIEs to assess whether a well with potential SCP is "manageable" under the NOL when online, and therefore remains safe to operate. Daily well monitoring by the drill site operator (DSO), and review by WIEs of reported anomalies (i.e., SCP symptoms may change) verifies a well remains within its approved normal operating limit, or is shut-in. An effective suite of well integrity diagnostic methods has been developed over many decades to assess well barrier condition and specific SCP symptoms (repressurization). These may include the tubing integrity fluid level (TIFL) evaluation, A and B annulus repressurization tests (i.e., DART), and MIT pressure tests, as applicable. For example, Injector wells that are approved to be "Operable" with potential for known SCP repressurization, have the primary (tubing) and secondary (A annulus) barriers verified by an MIT -IA or equivalent. Regulatory reporting, revised monitoring and testing frequency requirements may also be applicable. A typical example is an AOGCC administrative approval (AA) for Underground Injection Control (UIC) compliance on injector wells. Example of SCP - A annulus pressure and a TIFL diagnostics decision tree The most common well integrity anomaly is high A annulus (lA) pressure. The first step in evaluating high A annulus pressure is to conduct a TIFL evaluation. The following flowchart provides guidelines for further evaluation once the well fails a TIFL. BP Response to AOGCC Questions February 6, 2019 Page 22 PASS LOL 4 -- Establl.b LlR ♦ - MIT, Pruor Fail? -- - -- secure well. gassily No as Not Operable 4 Pa1tlow.lu.10 Failed TIFL Evaluation Procedure Revised: 08 March 2018 YES Run nipple MIT -IA, Pass or PASSOkay to ona.r B pec Fail? POP noble The BPXA Mechanical Integrity Testing procedure provides acceptance criteria for pressure testing when it is necessary for the evaluation process. Pressure test criteria BPXA has implemented standardized pressure testing criteria based on global industry standards, best practices, and local learnings that meet or exceeds AOGCC requirements. BP Response to AOGCC Questions February 6, 2019 Page 23 Was we9 shut in pan ror Bleed Annulus Well Fais Coq TIFL, Canwell be brought online that No TAR or 0ssues Pressure, Warn Yes reGausee, as Under Eval torwarm TIFL? w0uq reaNtl weIMOM? two TIFL once able to PGP No Fallow warm TIFL '. YES Decggn Tree EC... jYStlry NO Secure well. dassity _ hIperi d4 NOf OpardMe You Pull and Reset GLV.. Set TTP. ConMm haniamiab MIT PASS LOL 4 -- Establl.b LlR ♦ - MIT, Pruor Fail? -- - -- secure well. gassily No as Not Operable 4 Pa1tlow.lu.10 Failed TIFL Evaluation Procedure Revised: 08 March 2018 YES Run nipple MIT -IA, Pass or PASSOkay to ona.r B pec Fail? POP noble The BPXA Mechanical Integrity Testing procedure provides acceptance criteria for pressure testing when it is necessary for the evaluation process. Pressure test criteria BPXA has implemented standardized pressure testing criteria based on global industry standards, best practices, and local learnings that meet or exceeds AOGCC requirements. BP Response to AOGCC Questions February 6, 2019 Page 23 5.5. How does BPXA assess the combination of SCP and subsidence in their ability to continue operating a well? BPXA is developing and improving well subsidence criteria based on several factors, including surface well head datum survey results (time lapse) and subsurface surveillance of downhole drift anomalies. BPXA has been engaged in engineering work to better understand permafrost -related well subsidence and its impact on PBU well integrity since —2011 and have been utilizing industry and North Slope best practices. • See section 4.10 for example of surveillance drifts conducted by BPXA. See section 4.4 for example of the well base flange elevation surveys conducted by BPXA. See section 4.8 a) for an example of a proactively plugged and abandoned well (02-37) with probable subsidence anomaly. BPXA is developing a programmatic risk-based approach in the AKIMS well integrity data management system to better enable more long-term systematic engineering reviews, reporting and classification management going forward. Assessment of well operability, using well barrier health and subsidence risk factors is currently performed by WIEs on a case by case basis, utilizing well history detailed in AKIMS, and the WIOP operability criteria for well barriers. BP Response to AOGCC Questions February 6, 2019 Page 24 Example of flowchart Subsidence a romaly dea cted WIOP Barrier diagnostics Well Barriers Pass Well Operaba i W10P monitoring and surveillance Well Barriers require additional diagnostics r Data and / Well Banners Pass%/ manual y renew L— — =/ Well Not Operable Wei Work repaircandidate Or other options based on future utility including P&A More detailed information on well subsidence management undertaken by BPXA is provided in discussion of Topic 4: "What is the current state of subsidence throughout PBU." 5.6. How does BPXA downgrade the rating of casing/tubing, and what criteria are used? BPXA uses a standardized engineering methodology to determine tubing/casing safe operating pressure limits due to internal wall thickness loss, pitting due to corrosion and erosion mechanisms. In a typical case, through tubing caliper or ultrasonic imaging data may be available and provides log of wall thickness measurement with depth which is used as in input for the safe operating pressure limit (SOL) calculation. This approach is BP Response to AOGCC Questions February 6, 2019 Page 25 used by WIEs prior to well barrier pressure testing (MITs), and for well diagnostics to validate the SOL, and reduce risk. Example of workflow used to determine SOL w¢. xutE aoW„c,a a1cTr�E aoEiwACK w...E mn av aMz NO113 N MOIM' `$1Mµ1 W!O CEIMOOn WIN IA dI NOL _ 1q PID V1J GMO G2`W FLUID GMO P= k'1.tA xeoo M mo 390 ]1 s3q d128W 0o8H�]B3) 15W oote 2n4 zlzo ztn ,>aMzeoo,M _ Joae 31M sass .r o.ai zn. Aeal �9 I➢ASNZ99D wf '0008 ales SW5011wm wakMro.3651 JSe San !uII J Daa3800 oM j 089y Y121 10.21, M row sses MSi ' U.000 eEx xs9cM,x 'MLL W.LLL VMN HiESfiM RMUCWLa Enwla —ww aam«meMce —sr 1 —. .2 —stemma 0 tmo ao0o yam MID 3 ewo's tmo 9000 e000 0 moo aaao .aao soo0 eo0o too0 e000 x900 mw ano rom -toxo 0 3000 wro eaoo aoao I o luno z000 ]wo woo 5000 6aoo Step 1: Calculate the Safe Operating Limit (Yurst/Collapse) based on caliper type data and the original tubing/casing material properties. The calculation utilizes a standard "Barlow" equation for burst, and API equations for collapse. The SOL is 80% of the safe design limit calculated. Step 2 Calculate the well hydrostatic and surface pressure conditions based on the appropriate scenario being modelled. WIEs review the safe operating limit relative to the calculated well hydrostatics' and applied loading. 5.7. LTSI versus securing wells - what does BPXA use for criteria? BPXA complies with AOGCC regulations with respect to management of LTSI wells. In summary, PBU wells that have not been online in the previous calendar year are reported to AOGCC annually by March 31st of the following year. In 2017 AOGCC and the Operators participated in a workshop to develop a revised standard reporting template BP Response to AOGCC Questions February 6, 2019 Page 26 that includes aspects such as well future utility (if known) and well mechanical status. BPXA submitted the required information in 2018 and reported status on 332 LTSI wells. As an example, the 2018 submission contained Columns R titled "wellbore plug Y/N," and column J is titled "Operational Y/N." Prior to this AOGCC mandated LTSI well reporting revision in 2016, BPXA and the PBU Cc Owners voluntarily agreed with the AOGCC to progress well plug and abandonment activities in PBU on wells with no future utility using a risk-based methodology. This agreement is documented in OTH-16-038 and more information is provided in 5.8 below of the status. BPXA uses the following criteria as the basis for requiring downhole plugs in LTSI wells. • Mechanical (retrievable) or equivalent downhole plugs are preferable. Alternatively, in some cases, closing the SSSV is also acceptable. After the SSSV is closed, the SSSV panel will be locked out, DSO will notifythe WIE and document the closure in the Operator Tools Field Logbook. The SSSV will remain closed until the well is authorized to flow. • The well wing valve will be locked out by DSO, immediately after the plug operation has been completed and remain locked out until the well is authorized to flow. • Operable LTSI wells that have not been active or flowed for greater than two years are prioritized for a downhole plug. • Not Operable LTSI wells are prioritized for a downhole plug, ideally in an overbalance condition to overcome reservoir pressure at surface. Wells with annulus pressures exceeding 500 psi will be given emphasis in terms of risk reduction. Wells that require multiple rig/non-rig steps to remediate the integrity of the well, will have the plug reestablished between steps. 5.8. How will BPXA reassess P&A plans for long term shut-in wells and suspended wells that have no future utility in light of the two failed wells? BPXA will comply with both the A) 2016 AOGCC agreement OTH-16-038 for submission of an annual LTSI P&A plan, and B) the OTH-18-062 supplemental order for an additional 12 wells in 2019 in light of the two failed wells. Both of these plug and abandonment (P&A) programs are well risk reduction/elimination based. Program A) ordered by 0TH -16-038 specifically addresses risk from L TSl wells. BP Response to AOGCC Questions February 6, 2019 Page 27 Program B) ordered by OTH-18-062 addresses the higher "emergent" risk (newly identified) of the 02-03 and 02-02 well subsidence failure modes (pending 02-02 investigation). This risk is limited to wells that share the 02-03 and 02-02 design and construction similarities of which 14 wells have been identified and prioritized accordingly. BPXA will P&A these wells in the 2019 calendar year. The two programs combined address 20 wells in 2019 and decreases well stock portfolio risk on L TSl/No future utility wells. A. By letter dated Dec 15th, 2016, OTH-16-038. BPXA agreed to submit a three-year level loaded P&A program based on well mechanical condition and the associated risk of impaired/failed well barriers. Proposed list of PBU P8rA candidates for 2019-2021 (AOGCC Order OTH-16-038) Well 2017 2018 2019 2020 2021 Comments 1 J-26 V-119 D-27 13-33 Y-12 Non Rig 2 R-01 L4-11 G-03 S-23 WGI-01 Non Rig 3 C-38 04-07 L4-12 H-04 15-35 Non Rig 4 18-34 K-13 M-05 OWDW-NW 09-07 Non Rig 5 05-18 F-07 P-23 OWDW-SE 02-30 Non Rig 6 02-03** H-34 U-02 OWDW-C 14-03 Non Rig 7 L5-13** 18-25 A-41 H-12 E-14 Non Rig 8 02-37 Non Rig 10 V-201* B-02* 18-28* 05-17* 13-05* Rig *As technical and engineering capabilities improve with time and experience, BPXA may be able to P&A more wells with Non rig techniques. **Integrity related failures with subsequent P&A required ***P&A priorities and wells identified in the 3 -Yr plan may change and are dependent on factors such as the mechanical integrity of wells and/or identified repair alternatives. 2017 P&As status update L2-26 Cap installation, AOGCC witness, & backfill complete 02-03 Cap installation, AOGCC witness, & backfill complete L5-13* Cap installation, AOGCC witness, & backfill complete. 05-18 Cap installation, AOGCC witness, & backfill complete V-201 Cap installation, AOGCC witness, & backfill complete V-119 Cap installation, AOGCC witness, & backfill complete BP Response to AOGCC Questions February 6, 2019 Page 28 J-26 Cap installation, AOGCC witness, & backfill complete. R-01 Cap installation, AOGCC witness, & backfill complete 18-34* Cement completed. Excavation and WH removal scheduled C-38* Reservoir & tower lateral plug complete. Surface cement plug complete. Excavation, cut, and cap completed. *Denotes Full P&A (cut and cap 3' below original tundra elevation) 2018 P8LAs status update 18-25* Cement completed. Excavation and WH removal scheduled K-13* Lower lateral plug complete. Intermediate cement plug pumped. Sundry 2020 revision for OA cement is approved. DHD tagged repeatedly at 74' OA line Comments drift. Program on WBL. Eline scheduled to perforate. Needs CT. 04-07 CT intermediate plug scheduled B-02 OCA & OOOA surface plug complete. CT intervention to mill through cement scheduled H-34* EL set retainer. CT lower lateral plug completed 1-4-11* Sundry revision approved. Control and balance line cemented. SL pulled plug. M-07* CT lower lateral plug scheduled F-07* Sundry approved. CT lower/intermediate plug complete. SL tagged TOC at 1605'slm. Eline to perforated. Circ out scheduled 02-37* Reservoir plug in place. Sundry approved. Control and balance line cement complete and passed PT. Surface plug scheduled B. By letter dated December 31, 2018, OTH-18-062, BPXA was ordered to P&A 14 wells, following the DS2-03 and DS2-02 gas release incidents, based on Permafrost subsidence risk linked to early well construction. BPXA proposes four additional wells in 2020 to eliminate the risk associated with the DS02-03 type failure mechanism. List of PBU P&A wells for 2019 (AOGCC Order OTH-18-062) Well 2017 2018 2019 2020 2021 Comments 1 01-02' F-04* Non Rig 2 01-04' M-07* Non Rig 3 01-05' E-28* Non Rig 4 02-02**' 01-03* Non Rig 5 02-03**' Non Rig 6 02-04' Non Rig BP Response to AOGCC Questions February 6, 2019 Page 29 7 Reservoir and Intermediate plug completed. CMIT-TxIA Passed. Surface plug sundry approved. The surface cement plug is scheduled. 02-03 02-05+ 01-02 Sundry submitted. Non Rig 8 01-05B Sundry submitted. 02-06+ Sundry submitted. 02-05A Non Rig 9 Sundry submitted. 04-01A 04-01+ 04-02A Sundry submitted. Non Rig 10 04-04A Sundry submitted. 04-02+ Sundry submitted. J -02B Non Rig 11 04-03+ Non Rig 12 04-04+ Non Rig 13 04-05+ Non Rig 14 J-02+ Non Rig *Proposed for 2020 by BPXA **Well Integrity related failures with subsequent P&A required + SC set in permafrost, ordered by AOGCC following two incidents (02-03 and 02-02) Status of PBU P&A wells for 2019 (AOGCC Order OTH-18-062) 02-02 Reservoir and Intermediate plug completed. CMIT-TxIA Passed. Surface plug sundry approved. The surface cement plug is scheduled. 02-03 Cementing complete. Sundry submitted for cut and cap 3 -ft below tundra 01-02 Sundry submitted. 01-04B Sundry submitted. 01-05B Sundry submitted. 02-04A Sundry submitted. 02-05A Sundry submitted. 02-06C Sundry submitted. 04-01A Sundry submitted. 04-02A Sundry submitted. 04-03 Sundry submitted. 04-04A Sundry submitted. 04-05 Sundry submitted. J -02B Sundry submitted. BP Response to AOGCC Questions February 6, 2019 Page 30 11 Colombie, Jody J (DOA) From: Colombie, Jody 1 (DOA) Sent: Tuesday, January 15, 2019 9:49 AM To: 'Daniel, Ryan'; Rixse, Melvin G (DOA) Subject: RE: AOGCC OTH-18-064 BPXA Request for Extension of Public Hearing dated Jan 14th 2019 Ryan: Your request to continue the hearing in Docket Number OTH-18-64 is DENIED and will proceed as scheduled. JodyJ Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7" Avenue Anchorage, AK 99501 (907) 793-1221 Direct (907) 276-7542 Fax From: Daniel, Ryan <Ryan.Daniel@bp.com> Sent: Monday, January 14, 2019 11:11 AM To: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov>; Colombie, Jody 1 (DOA) <jody.colombie@alaska.gov> Subject: AOGCC OTH-18-064 BPXA Request for Extension of Public Hearing dated Jan 14th 2019 Good morning Mel, Jody, Please find attached a letter from BPXA requesting an extension of the hearing noticed in OTH-18-064 and subsequent communications. Please call if you have any questions Thanks Ryan Ryan J C Daniel Well Engineering Team Leader GWO Alaska Wells Integrity & Compliance BP Exploration (Alaska) Inc. Office +1907 564 5430 Mobile +1907 748 1140 10 0• January 14, 2019 Via Electronic Delivery Hollis French Commission Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907)561-5111 RECEP c JAN 14 2019 A®GCC, Re: Docket Number: OTH-18-064 Request for Extension of Public Hearing Currently Scheduled for February 7, 2019 concerning Well Integrity Management Prudhoe Bay Unit Dear Chair French: BP Exploration (Alaska) Inc. (BPXA), as operator of the Prudhoe Bay Unit (PBU), respectfully submits this request for postponement of the above -referenced Public Hearing until March 7, 2019 due to the length and breadth of the subject matter topics that the Commission has requested BPXA address at the hearing. BPXA requires the additional time to gather the requested information and finish our reviews of events surrounding the recent Drillsite 02-02 well event. In the event that the Commission denies this request, BPXA will be prepared to present the information it has available on the currently scheduled hearing date. It will work in good faith with the Commission to provide any additional information requested within an agreed timeframe. Sincerely, ' Ryan Daniel BP Exploration (Alaska)Inc. Colombie, Jody J (DOA) From: Rixse, Melvin G (DOA) Sent: Monday, January 14, 2019 1:34 PM To: Daniel, Ryan Cc: Colombie, Jody J (DOA) Subject: RE: AOGCC OTH-18-064 BPXA Request for Extension of Public Hearing dated Jan 14th 2019 Rya n, Your request for an extension has been received at AOGCC. An AOGCC response is forthcoming. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell CONFIDENTIALITY NOTICE: This a -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 recipie nt(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 Mel Rixse at (907-793-1231( or (Melvin.Rixse@alaska.kovl. cc. Jody Colombie From: Daniel, Ryan <Ryan.Daniel@bp.com> Sent: Monday, January 14, 2019 11:11 AM To: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov>; Colombie, Jody 1 (DOA) <jody.colombie@alaska.gov> Subject: AOGCC OTH-18-064 BPXA Request for Extension of Public Hearing dated Jan 14th 2019 Good morning Mel, Jody, Please find attached a letter from BPXA requesting an extension of the hearing noticed in OTH-18-064 and subsequent communications. Please call if you have any questions Thanks Ryan Ryan J C Daniel Well Engineering Team Leader GWO Alaska Wells Integrity & Compliance BP Exploration (Alaska) Inc. Office +1907 564 5430 Mobile +1907 748 1140 9 Colombie, Jody J (DOA) From: Rixse, Melvin G (DOA) Sent: Friday, January 11, 2019 9:34 AM To: Colombie, Jody 1 (DOA) Subject: FW: Information requested by AOGCC OTH-18-062 letter dated December 13th 2018 in relation to the PBU 02-02 gas release and investigation Attachments: AWGRS Well Events Summary for AOGCC (Data from 14th Dec 2018).pdf From: Daniel, Ryan <Ryan.Daniel@bp.com> Sent: Thursday, December 27, 2018 9:36 AM To: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov>; Schwartz, Guy L (DOA) <guy.schwa rtz@aIaska.gov> Cc: Worthington, Aras 1 <Aras.Worthington@bp.com> Subject: Information requested by AOGCC OTH-18-062 letter dated December 13th 2018 in relation to the PBU 02-02 gas release and investigation Good morning Mel, This email contains information requested by AOGCC, OTH-18-062 letter dated December 13`h 2018 in relation to the PBU 02-02 gas release and investigation. BPXA have identified the following list of wells with the a surface casing set in the permafrost. These wells have "similar designs" to PBU 02-03 and PBU 02-02, although many have been subsequently modified, worked over or sidetracked, or not completed as in the case of the observations wells. LIST of PBU wells with SC set in the Permafrost The original list of 14 PBU wells cited in the 2017-06-12 Well 2-03 release investigation report (attached for your reference). These wells have been shut-in since or prior to the 02-03 incident and are Not Operable. 1. 01-02 2. 01-04 3. 01-05 4. 02-02 P&A work in progress 5. 02-03 P&D'd in 2017 6. 02-04 7. 02-05 S. 02-06 9. 04-01 10. 04-02 11. 04-03 12. 04-04 13. 04-05 14. J-02 In 2018 BPXA have identified an additional eight wells that have the SC set in the PF 15. M-01 Suspended with Reservoir P&A plug 16. E-28 Not Operable 17. J-01 Operable following engineering review 18. S-122 Operable following engineering review 19. W-209 Operable following engineering review 20. W-214 Operable following engineering review 21. W-216 Operable following engineering review In Dec 2018 following the 02-02 incident, two wells that have the SC set at the base of PF (+-50ft) were identified, and made not operable 22. 01-03 SC shoe at base of PF (shut-in Dec 151^ 2018) 23. F-04 SC shoe at base of PF (shut-in Dec 15`h 2018) BPXA have previously identified the following observation wells which are typically a single 20" casing set approx. 900- 1000ft, with no inner strings. 24. J-04 25. PR -011014 26. PR -021014 27. PR -111014 28. PR -131014 29. PR -141014 30. PR -171015 Thanks and Rgds Ryan Ryan J C Daniel Well Engineering Team Leader GWO Alaska Wells Integrity & Compliance BP Exploration (Alaska) Inc. Office +1907 564 5430 Mobile +1907 748 1140 Pr ,P 4..PROUD AjO.Op _- - Pro.rennq 1b Po,[ f.0.n Af.,A., fvma (�,�)M�7 �D�MISO Mn�� 2�pl, T�,— 22WO, N,�213�� IW�� 0� .11 1... �LMONM�— W .T.1 oi� �i7 �=U� �W��LL n E. 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IN ae=orc.1 C; Colombie, Jody J (DOA) From: Daniel, Ryan <Ryan.Daniel@bp.com> Sent: Thursday, January 10, 2019 4:49 PM To: Rixse, Melvin G (DOA) Cc: Colombie, Jody J (DOA) Subject: RE: Topic List for BPXA Public Hearing - Well Integrity Management, Post Failures DS02 - Docket # OTH-18-064 Thanks Mel, BPXA will review. Considering the length of the list I expect we will request an extension to the hearing date. Rgds Ryan From: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov> Sent: Thursday, January 10, 2019 4:13 PM To: Daniel, Ryan <Ryan.Daniel@bp.com> Cc: Colombie, Jody 1 (DOA) <jody.colombie@alaska.gov> Subject: Topic List for BPXA Public Hearing - Well Integrity Management, Post Failures DS02 - Docket # OTH-18-064 BPXA Public Hearing — Well Integrity Management Post Failures at DS02-03 and DS02-02 February 7, 2019 Review of DS02-03 and DS02-02 Sudden Wellhead Rises Present the results of sudden wellhead rise/wellhouse collision assessments o Wellhead/S-riser/flowline impacts with the well house o Metallurgical studies conducted on recent well failures: PBU 02-036; PBU 02-02A; PBU 1-5-13 (injector failure during required MIT) BPXA Risk Assessment Actions to prevent reoccurrence o What options were evaluated and what physical actions were taken? o What risk acceptance criteria were used in these evaluations? o Has BPXA expanded well integrity monitoring plan to incorporate learnings from the DS02-03B investigation? If so, what is the plan's effectiveness? — provide details PBU Subsidence Management and the Impact on Well Integrity - BPXA has identified 3 string casing wells with shoes in permafrost at risk of failure similar to DS02-03 and DS02-02 o Present the findings of the DS02-03B investigation o Are there any untested hypotheses that necessitated assumptions in formulating conclusions? What are they? What is your level of confidence in your assumptions? o What work is being done to understand the implications of variations in rock properties within the permafrost zone and differential freeze/thaw? o Discuss priorities for preventing recurrence of DS02-03B and DS02-02A. o How did the DS02-02A failure confirm or change assumptions and priorities? o Since the DS02-03 failure, 5 wells were approved to be placed back online. What impact does the failure of DS02-02A have on these wells? What is the current state of subsidence throughout PBU? o AOGCC has observed wellhead/landing ring separation on some PBU pads. Of note: What is the status of the following pads? • L V • S • DS2 • Other pads we should know about? o What elevation surveys have been completed? Also: • Compared against what baseline? • What integrity risk is identified with significant wellhead elevation change? o How many wells currently have failed integrity tests induced by subsidence? o Of the failed integrity tests, what is the failure mechanism? • Tubing or casing buckling? • "Sudden wellhead elevation rise' (BPXA term for 02-03B and 02-02A failures) and implications of those failures • Any other subsidence induced failure mechanism to discuss? o What does BPXA's active surveillance program involve? Specifically: • Drifts • Gyro surveys • Calipers • Tubing and casing monitoring in other ways? Sustained Casing Pressure and Long Term Shut-In(LTSI) Well Management - Sustained Casing Pressures/Barrier Integrity o Does BPXA have concerns regarding barrier integrity on producers and injectors with sustained casing pressure? Describe BPXA's barrier philosophy and give examples. o Provide evidence that BPXA has performed/or performs critical reviews of the existing well integrity program to validate the program's effectiveness, where improvements have been made, and changes that are needed. o What criteria are used for accepting diagnostic test results when a well exhibits sustained casing pressure? o How does BPXA assess the combination of sustained casing pressure and subsidence in their ability to continue operating a well. How does BPXA downgrade the rating of casing/tubing, and what criteria are used? LTSI versus securing wells — what does BPXA use for criteria? - How will BPXA reassess P&A plans for long term shut-in wells and suspended wells that have no future utility in light of the two failed wells? For questions regarding the above subject matter, correspond to: Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell mel vin. rixse@alaska. aov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State cf 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 on 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 Mel Rixse at (907-793-1231) or (Melvin Rixse(dalasko.aovl. cc. Jody Colombie 7 E• BP Exploration IAlaskal Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 995196612 (907) 561-5111 BP Exploration (Alaska) Inc. P.O Box 196612, Anchorage, AK 99519-6612 REPORT OF ACCIDENTAL OIL AND/OR GAS RELEASE (30 day report per 20 ACC 25.205 (b)) Date:01 /07/2019 For All Releases To: Chairman Alaska Oil and Gas Conservation Commission 333 W. Th Ave, Suite 100 Anchorage, AK 99501-3539 E0 JAN CIS A0 t.7" t,.,. (., DESCRIPTION OF RELEASE 1. Date and Time: Leak discovered by drill site operator at approximately 1400hrs on 12/7/2016. Leak most likely initiated at 2200hrs on 12/6/2018 based on analysis of Inner anulus pressure monitoring data. 2. Location: Detailed Location Prudhoe Bay Unit Drill Site 2, well 2 3. Volume of oil and/or natural gas released Released: and recovered: Total volume released through leak point est 241 mscf Total volume vented through test separator vent est (Methane release kg to mscf converted using 508mscf 379.3 scfAb-mol, and 20lbs4b-mol molecular Total volume (vented and leaked) est 750mscf weight for CH2) Recovered: The est liquid spill volume is 2 US gallons, confined to misting in the well house. 4. Cause of release: Pending investigation. 5. Responsive actions taken to prevent Leak stopped on 12/9/2018 after retorquing the master additional releases: valve lower flange, approx. 1200hrs 6. Plans, actions, equipment or procedural Pending investigation changes to prevent or minimize risk of future releases: 7. Contact Name and telephone numberY. Ran Daniel 907-748 1140 Signature: x Colombie, Jody J (DOA) From: Rixse, Melvin G (DOA) Sent: Monday, December 31, 2018 11:50 AM To: Daniel, Ryan Cc: Colombie, Jody J (DOA) Subject: RE: Requests to reschedule an AOGCC hearings Rya n, Just to clarify: the public hearing notice is docket q OTH-18-064. AOGCC will have a letter forthcoming (shortly) to clarify what information is to be addressed at the hearing. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Jody Colombie From: Daniel, Ryan <Ryan.Daniel@bp.com> Sent: Monday, December 31, 2018 11:40 AM To: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov> Subject: Re: Requests to reschedule an AOGCC hearings Thanks Mel, Will do, I will probably also request a meeting to review the AOGCC notice and clarify the intent. Can you advise me on the "issues that the commission wants addressed" so we can respond and plan appropriately? Thanks Ryan Get Outlook for iOS From: Rixse, Melvin G (DOA) <melvin.rixse@alaska.aov> Sent: Monday, December 31, 2018 11:32 To: Daniel, Ryan Cc: Colombie, Jody J (DOA) Subject: Requests to reschedule an AOGCC hearings Ryan, Requests to reschedule hearings need to be made to the Commissioners, addressed to the Chair, and sent to the AOGCC's Special Assistant, Jody Colombie at iody.colombie@alaska.aov. An email will suffice. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 forth 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 Mel Rixse at (907-793-1231) or (Melvin. Rixse(aalaska.Rov). cc. Jody Colombie From: Daniel, Ryan <Ryan.Daniel@bp.com> Sent: Friday, December 28, 2018 11:15 AM To: Rixse, Melvin G (DOA) <melvin.rixseC@alaska.eov> Subject: RE: Minutes of the AOGCC meeting with BPXA ... DS2-02 gas leak incident and OTH-18-065 actions Thanks Mel, If there is any opportunity to schedule any hearing before it gets set in stone after Feb 17th that would be great. I am out in New Zealand (on vacation) from Jan 291h to Feb 17th Additionally, I would suggest that BPXA still present our current Well Subsidence Programs in Jan, and at the Commissions discretion schedule a hearing if they required after that? RgdS Ryan From: Rixse, Melvin G (DOA) <melvin.rixse6@alaska.gov> Sent: Friday, December 28, 2018 10:48 AM To: Daniel, Ryan <Ryan.Daniel@bp.com> Cc: Schwartz, Guy L (DOA) <guy.schwa rtz(a@alaska.eov>; Regg, James B (DOA) <jim.regg@alaska.gov>; Loepp, Victoria T (DOA) <victoria.loepp@alaska.gov> Subject: FW: Minutes of the AOGCC meeting with BPXA ... DS2-02 gas leak incident and OTH-18-065 actions Rya n, Thank you for this updated work item list. I do not immediately have anything to add, but more questions and communication will be forthcoming. Subsidence management, as it relates to Prudhoe Bay well integrity, is evolving and AOGCC is working to quickly understand how it should best be addressed. The AOGCC commissioners will be calling a hearing to discuss general Prudhoe Bay Unit well integrity on February 7, 2019. 1 will assist BPXA as much as possible to assure you clearly understand the issues that the commission wants addressed. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell ,CC.NFiDENTIALITY 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 Mel Rixse at (907-793-1231) or (Melvin.RixsePalaska.gov). cc. Guy Schwartz, Jim Regg, Victoria Loepp 5 THE STATE e ®fSKA J. 1. GOVERNOR MIKE DUNLEAVY December 31, 2018 Ryan Daniel Well Engineering Team Leader GWO Alaska Wells Integrity & Compliance BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Alaska Cil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 v .aogcc.alaska.gov RE: Docket Number:OTH-18-062 Prudhoe Bay Unit Well Integrity Assurance for Permafrost Subsidence Risk Dear Mr. Daniel: In light of the recent failure of DS02-02A, BPXA is hereby advised that the sundry matrix is no longer applicable to the following wells: Name Permit to Drill # 1. 01-02 PTD 169-119 2. 01-04 PTD 213-106 3. 01-05 PTD 207-048 4. 02-02 PTD 206-021 5. 02-03 PTD 200-217 6. 02-04 PTD 196-158 7. 02-05 PTD 203-082 8. 02-06 PTD 213-047 9. 04-01 PTD 207-035 10.04-02 PTD 194-121 11.04-03 PTD 171-005 12.04-04 PTD 195-024 13.04-05 PTD 193-186 14. J-02 PTD 204-184 Within 30 days of receipt of this letter, BPXA is to provide the following information for the wells listed above: a. Current well schematic b. Current fluids with density, in the tubing and annuli c. Most recent mechanical integrity tests Docket No. OTH-18-062 December 31, 2018 Page 2 of 2 This request is made pursuant to 20 AAC 25.300. Failure to comply with this request will be an additional violation. The AOGCC reserves the right to pursue an enforcement action in this matter according to 20 AAC 25.535. Within 90 calendar days of receipt of this letter, BPXA is to provide evidence sufficient to demonstrate that the above -listed wells have a secure reservoir plug. Included within this request is evidence that since the date of this letter: a. All plugs are secure and have been re -tagged (include a copy for the well work report); b. All wells have passed a mechanical integrity test; c. The tubing and annuli of all wells contain fluids that will overbalance the reservoir Note that because the sundry matrix is no longer applicable to the wells at issue here, any well work on the above wells requires a sundry approval and advance notification to AOGCC in order to provide an opportunity to witness tag/tests. By the end of 2019, BPXA is to properly plug and abandon all 14 of the above -listed wells. Questions regarding this letter should be directed to Mel Rixse (phone 907-793-1231 or email: melvin.rixse(a)alaska.govl, Senior Petroleum Engineer, AOGCC. Sincerely, Hollis A. French Chair, Commissioner CC. J. Regg M. Rixse E Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number: OTH-18-064 Mechanical integrity of Prudhoe Bay wells. The Alaska Oil and Gas Conservation Commission (AOGCC) on its motion is setting a hearing to assess the mechanical integrity of Prudhoe Bay wells operated by BP Exploration (Alaska), Inc. The AOGCC has scheduled a public hearing on this subject for February 7, 2019, at 10:00 a.m. at 333 West 7a' Avenue, Anchorage, Alaska 99501. Written comments regarding this subject may be submitted to the AOGCC, at 333 West 7°i Avenue, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on the conclusion of the February 7, 2019 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at (907) 793-1221, no later than January 24, 2019. Hollis S. French Chair, Commissioner STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWING ADVERTISING ORDER NO.,CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OF ADVERTISMENT. ADVERTISING ORDER NUMBER 1 p AO-19-019 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O.AGENCY 12/28/2018 PHONE: (907) 279-1433 333 West 7th Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: (907) 276-7542 TO PUBLISHER: Anchorage Daily News, LLC SPECIAL INSTRUCTIONS: PO Box 140147 Anchorage, Alaska 99514-0174 TYPE OF ADVERTISEMENT: W LEGAL f- DISPLAY IV CLASSIFIED I— OTHER (Specify below) DESCRIPTION PRICE OTH-18-064 Initials of who prepared AO: Alaska Non -Taxable 92-600185 :SVRMIT INVOICE MOWN c:APTER'n$IfsG: ::. ORDERNUd�?RT.IFIEDAYPIDAYITbP:::: :CpllBeleng7on:wiTxATYn,'CAEdiPYOp:: A]IYE............ p AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Pave I of 1 Total of All Pa es $ REF Type Number Amount Date Comments I PVN VCO21795 2 AD AO-19-019 3 a FIN AMOUNT SY Art. Template PGM LGR Object FY DIST LIQ I 19 A14100 3046 19 2 3 a 5 Pure c' g t o Purehasing Authority's Signature Telephone Number O. Iving cY name must appear on ail invoices and documents relating to this purchase. 2 e state is registered for lav free transactions under Chapter 32, IRS code. Registration number 92-73-0006 K. Items are for the mxlusive use of the state and not for s e. STRIBUTION:, DIVLSIon Fig¢aVOngmal hO,Coples. Publisher .(faxed)•;:Drvlslon Fisca4 Receiving: Form: 02-901 Revised: 1/2/2019 Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 Carlisle, Samantha J (DOA) From: Colombie, Jody J (DOA) <jody.colombie@alaska.gov> Sent: Friday, December 28, 2018 11:09 AM To: AOGCC_Public_Notices Subject: [AOGCC_Public_Notices] Public Notice Attachments: OTH-18-064 Public Hearing Notice.pdf Re: Docket Number: OTH-18-064 Mechanical integrity of Prudhoe Bay wells. .Iodv.T. Colonibie Special Assistant Alaska Oil and Gas Conservation Commission 333 VVest 7i6.4 venue m,horetge, AK 99501 (907) 793-1221 Direct (907) 2'6-7542 Fax List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.carlisle@alaska.gov Unsubscribe at: http://list.state.ak.us/mailman/options/aogcc_Public_notices/samantha.carlisle%40alaska.gov ANCHORAGE GE D�t"Ly iNIENMECEIVED AFFIDAVIT OF PUBLICATION JAN 0 4 2019 AOGCC Account is 270227 ST OF AK/AK OILAND GAS OMerJI 0001432578 Product ADN -Anchorage Daily News Cost $159.36 Placement 0300 CONSERVATION COMMISSION Position 0301 333 WEST 7TH AVE STE 100 anirunaar-c au eccn+Imao STATE OF ALASKA THIRD JUDICIAL DISTRICT Sarah Jennett being first duly sworn on oath deposes and says that he/she is a representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on December 30, 2018 and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication ist in excess of the rate charbd private indivi�ls. Signed Jennett sworn to tletbre me this 31st day of December,, 1 18 Notary Public i and for The State aska. Third Division Anchorage, Alaska MY COMMISSIPIREJ� STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number: OTH-18-064 Mechanical integrity of Prudhoe Bay wells. The Alaska Oil and Gas Conservation Commission (AOGCC) on its motion is settinS a hearing to assess the mechanical integrity of Prudhoe Bay wells operated by BP Exploration (Alaska), Inc. The AOGCC has scheduled a public hearing on this subject for February 7, 2019, at 10:00 a.m. at 333 West 7th Avenue, Anchorage, Alaska 99501. Written comments regarding this subject may be. submitted to the AOGCC, at 333 West 7th Avenue, Anchors e, Alaska 99501. Comments must be received no later than 4:30 P.M. on the conclusion of the February 7, 2019 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombia, at (907) 793-1221, no later than January 24, 2019. - //signature on file// Hollis S. French Chair, Commissioner Nobly Publ c `j BRITNEY L. THOMPSON aj State of Alaska 1,: 17 Commission �Y i,es rah P3, 2011 3 ME BP Exploration (Alaska) Inc. P.O. Box 196612, Anchorage, AK 99519-6612 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907)561-5111 DEC 111 2018 REPORT OF ACCIDENTAL OIL AND/OR GAS RELEASE tfLK.. (5 day preliminary report per 20 ACC 25.205 (b)) Date:1211412018 For All Releases To: Chairman Alaska Oil and Gas Conservation Commission 333 W. Th Ave, Suite 100 Anchorage, AK 99501-3539 DESCRIPTION OF RELEASE 1. Date and Time: Leak discovered by drill site operator at approximately 1400hrs on 12/7/2018. Leak most likely initiated at 2200hrs on 12/6/2018 based on analysis of Inner anulus pressure monitoring data. 2. Location: Detailed Location Prudhoe Bay Unit Drill Site 2, well 2 3. Volume of oil and/or natural gas released Released: and recovered: Total mass released through leak point est 5776KG Total mass vented through test separator vent est 12160kg Total mass (vented and leaked) est 17936kg Recovered: The est liquid spill volume is 2 gallons, confined to misting in the well house. 4. Cause of release: Part of future investigation. 5. Responsive actions taken to prevent Leak stopped on 12/9/2018 after retorquing the master additional releases: valve lower flange, approx. 1200hrs 6. Plans, actions, equipment or procedural Part of future investigation changes to prevent or minimize risk of future releases: 7. Contact Name and telephone number): Ran Daniel 907-748 40 / Signature: ORIGINAL BP Exploration (Alaska) Inc. P.O. Box 196612, Anchorage, AK 99519-6612 REPORT OF ACCIDENTAL OIL AND/OR GAS RELEASE (5 day preliminary report per 20 ACC 25.205 (b)) Date:12/1412018 For All Releases To: Chairman Alaska Oil and Gas Conservation Commission 333 W. Th Ave, Suite 100 Anchorage, AK 99501-3539 DESCRIPTION OF RELEASE 1. Date and Time: Leak discovered by drill site operator at approximately 1400hrs on 12/7/2018. Leak most likely initiated at 2200hrs on 12/6/2018 based on analysis of Inner anulus pressure monitoring data. 2. Location: Detailed Location Prudhoe Bay Unit Drill Site 2, well 2 3. Volume of oil and/or natural gas released Released: and recovered: Total volume released through leak point est 241 mscf Total volume vented through test separator vent est (Methane release kg to mscf converted using 508mscf 379.3 scf/Ib-mol, and 201ba4b-mol molecular Total volume (vented and leaked) est 750mscf weight for CH2) Recovered: The est liquid spill volume is 2 US gallons, confined to misting in the well house. 4. Cause of release: Part of future investigation. 5. Responsive actions taken to prevent Leak stopped on 12/9/2018 after retorquing the master additional releases: valve lower flange, approx. 1200hrs 6. Plans, actions, equipment or procedural Part of future investigation changes to prevent or minimize risk of future releases: 7. Contact Name and telephone number: Ran Daniel 907-748 1140 Signature: cc: Jim Regg, AOGCC Mel Rixse, AOGCC Jennifer Hunt, AOGCC BPX Environmental TL BPX Air Quality TA BPX Volume Accounting Area Operations Manager East OSTL Production Team Leader Legal I] THE STATE GOVERNOR MIKE DUNLEAVY December 13, 2018 CERTIFIED MAIL — RETURN RECEIPT REQUESTED 7015 0640 0003 5321 5048 Janet Weiss Regional President BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 RE: Docket Number: OTH-18-062 Well Investigation Updates PBU 02-02A (PTD 1971680) Dear Ms. Weiss: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.cilaska.gov On Friday, December 7, 2018, BP Exploration (Alaska), Inc. (BPXA) notified the Alaska Oil and Gas Conservation Commission (AOGCC) that the PBU 02-02A well had an uncontrolled release of well fluids. Well DS02-02A appears to be temporarily managed with flow to surface separation equipment. AOGCC is investigating this incident. Because of the uncontrolled release, BPXA is required to do the following: 1. Submit the report required by 20 AAC 25.205. 2. Provide weekly written updates, including any written reports or findings and progress to date, of BPXA's investigation. 3. Schedule weekly meetings with AOGCC to review the details of the investigation. In addition, because PBU 02-02A appears to have experienced a similar failure event to the PBU 02-03B (PTD 2002170) which had an uncontrolled release of well fluids on April 14, 2017, BPXA is required to provide AOGCC the following to be delivered to the AOGCC office within 10 business days: 1. A list of all wells with similar designs to PBU 02-03B and PBU 02-02A operated by BP on the North Slope. Note: For the wells identified herein, the Sundry matrix will no longer apply. Well work done on those wells must have prior written approval from AOGCC. Docket Number: OTH-18-062 .Page 2 of 2 2. A detailed description of all well work completed on the above listed wells with similar designs since January 1, 2017. AOGCC requests this information pursuant to 20 AAC 25.300. Failure to comply with this request will be a violation. The AOGCC reserves the right to pursue an enforcement action in this matter according to 20 AAC 25.535. Questions regarding this letter should be directed to Mel Rixse, Senior Petroleum Engineer, at 907- 793-1231. Sincerely, Hollis S. French Chair, Commissioner CC. J. Regg M. Rixse Ryan Daniel, BPXA 1 s�rA.r I5 20i7 l.i��_ A0E , May 15, 2017 Via Hand Delivery Cathy P. Foerster Commission Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: 30 -day Report of Accidental Oil and/or Gas Release Flow Station 1, Drill Site 2, Well 3 Prudhoe Bay Unit Dear Chair Foerster: BP Exploration (Alaska) Inc., operator of the Prudhoe Bay Unit, respectfully submits with this letter a 30 -day report of the referenced release, in accordance with commission regulations at 20 AAC 25.205(b). Should the commission have any questions regarding this report please contact Doug Cismoski at 907-564-4303, CismosDA@BP,com. Sincerely, 7 / v t&— Anchala Klein Regional VP Wells BP Exploration (Alaska) Inc. Enclosure: 30 -day Report of Accidential Oil and/or Gas Release BP Exploration (Alaska) Inc. P.O. Box 196612, Anchorage, AK 99519-6612 REPORT OF ACCIDENTAL OIL ANDfOR CAS RELEASE (30 -day report per 20 ACC 25.205(b)) Date: May 15, 2017 For All Releases To: Chairman Alaska Oil and Gas Conservation Commission 333 W. 7`" Ave, Suite 100 Anchorage, AK 99501-3539 Fax: (907)276-7542 DESCRIPTION OF RELEASE ------------------------------ 1. Date and Time: 2. Location: Prudhoe Bay Unit 3. Volume of oil and/or natural gas released and recovered: 4. Cause of release: 4/14/2017 at approximately 0700 am Detailed Location Flow Station 1, Drill Site 2, well 3 (Well 02-03) Released: The latest estimates are: 1.5 barrels of oil (63 US gallons) e 1,779 mscf of gas Recovered: There is no recovered volume available Yet . BP is working with Alaska Clean Seas on clean- up efforts under a plan approved by the Unified Command (BP, EPA, ADEC, NSB) The investigation is on-going, but BP's investigation team has tentatively concluded that the cause was permafrost subsidence resulting in failure of the 20" surface casing. They have hypothesized that the The hot produced reservoir fluids caused the permafrost zone near the wellbore to melt in a non-uniform manner in the vicinity of the well. As the melt water has a lower volume than the frozen water, or dissipates through permeable zones, the overburden formations subsided. E The subsiding formations caused a high enough downward load on the 20" surface casing, resisted by the strength and stiffness of the 13.3/8" intermediate casing, 9.5/8" production casing, and the 5 % production tubing, to account for the failure below the wellhead. This downward load compressed the intermediate and production casing strings, which resulted in substantial energy being stored in them. When the 20" surface casing failed, it released the energy that had accumulated in the intermediate and production casing strings which then lifted the wellhead and Xmas tree. This release resulted in the Xn as tree colliding with the well house roof and subsequent loss of primary containment. 5. Responsive actions taken to prevent BP's investigation team originally thought that Well additional releases: 02-03's McEvoy Gen 1 wellhead design may be causal and, as a precaution, recommended that BP Alaska shut-in the Gen 1 wells, which were still producing oil. BP Alaska followed that recommendation and shut in 3 wells. But BP's investigation team now believes that the causal failure mechanism is as escnbed T'in Section 4 and that the Gen 1 wellhead design was not causal. The investigation team believes that the failure mode described in Section 4 is limited to wells with a 3 -string design, i.e. with an intermediate casing string. The team believes that the wells without intermediate casing have sufficient flexibility for the inner strings to absorb the subsidence forces acting on the surface strings. Modelling completed so far supports this conclusion, but it is not finished yet, although empirical evidence from wells in Alaska supports this hypothesis. 6. Plans, actions, equipment or procedural The investigation team preliminarily recommended changes to prevent or minimize risk of that BP Alaska carry out a risk assessment of the future releases: PBU wells with a 3 -casing string desi—'gn to -- determine if they have sufficient integrity to be considered operable. As a precaution, BP Alaska shut in 5 additional producing wells that had surface casing set in the permafrost until the risk assessment is completed. (The 3 Gen 1 wellhead wells that were initially shut in are also of this 3 - casing string design.) The investigation is on-going and the team has not issued its final recommendations. We will update this report as soon as those final recommendations are issued. 7. Contact (Name and telephone number): Doug Cismoski 5644303 Signature: s cc: Jim Regg, AOGCC Victoria Leopp, AOGCC Jennifer Hunt, AOGCC BPX Air Quality Technical Authority MB 11-6 (Fax: 564-5020) BPX Volume Accounting MB 12-4 (Fax: 564-4094) East Area Operations Manager, 11-62B Production Optimization Team Leader, F-1 To: Alaska Oil and Gas Conservation Commission From: BP Exploration (Alaska), PBU Operator on October 2017 Release Date: April 14, 2017 Release Location: Prudhoe Bay Unit Row Station 1, Drill Site 2, well 3 (Well 02-03B) Initially Filed: May 15, 2017 Review theoretical failure mode Review immediate actions completed Action Plan Update DSO4r03 Findings/ Potential Mitigations a Permafrost consists of lenses of ice with layers of varying formation types interspersed between them forming a consolidated formation. During the operation of oil and gas wells, the hot production fluids cause the permafrost to melt allowing the previoudyfrozen water to be displaced radially away from the wellbore by overburden formation pressure. The displaced water is replaced by the above formation layers causing the ground to subside. lbsidence Loading Near wellbore formation subsidence createsa downward load on the adjacent Casing. Larger casing sizes have more area for this downward load to act upon. ImDactsof Subsidence Loadingon Three ring Well Desi_g,s The diagram to the right helps explain the above loading condition by showing the 5.5" tubing, 9.5/8" production casing, 13-3/8r' intermediate casing, and 20" surfacecasing as concentric springs in across sectional view. The well has not been on production yet. The tubing and inner Casing strings are initially set intension which is transferred via the wellhead to the 20" casing resulting in it being initially in compression. The well is put on production. This causes the tubing and inner casing strings to elongate due to thermal expansion which reversestheir load to a compressive state. _ The 20" Casing is seeing less of a compressive load. The well has been on production and a subsidence load has been applied. The 20" casing has reversed its state to be in tension and is nowtransferring its load via the wellhead to the tubing and inner casing strings causing them to be under an even greater compressional load (the key feature of a three-stringwell design isthe tubing and inner casing stringsdo not buckle under the compressive load seen under the conditions in stage 3). The gradual increase in the compressional loading coupled with the contributory pressure and temperature affects eventually cause a tensile failure of the 20" surface casing. 1. Comdeled Well Bet Pod cion 2. WWI On Production wllh ut Subsidence lo#din ------------- r� 2DDD• rvo Well On Roductinn 3. wltb SUMldenu toepb piled 4. W#1laner Sort,# r"M f U _ _ r_ ____ r bnNr f IrvAlOn � � __ _ _ 1 r�r r , Dalton 2000' ND I n —t. by April 19, 2017- BP made well 02-03 safe by securing with a mechanical plug April 28, 2017- BP to survey DS02 to establish post 2014 levels of subsidence (average subsidence on pad of 1 inch per year since 2014) May 19, 2017 - BP performed reservoir abandonment Received AOGC>✓ approval on 8130117 and internal deviation approved in October 2017 for upper abandonment ,Anne 19, 2017 - Secured 14 wells of similar three string casing construction aswell 02-03 (i.e., surface casing landed in permafrost) Im �.JI Originally targeted completion by 10/31/2017 Completed survey of all PBU well houses for distances between well and associated small fittings to wellhouses and scaffolding by end of September Found only one well has 3 feet or less clearance between the Sriser and the vellhouse Completed model for well DS04-03 (discuss in detail later) Model wells that have future production value Subsidence loading is a complex geo-mechanical problem Can track subsidence but cannot predict failure. Can only predict failure is possible. Risk assessment in progress on well DS04-03 MEN MOO irmsfailure mode is Modeling is complete. casingddes gn with surface casing set inn in progress. thepermafrost. Unable unique tothree-str g to build a case for failure if surface casing is set belowthe permafrost. document edits between revisions). Forces ent Y ni document(B during next scheduled eduled update between revisions) Field wide wellhead datum survey will b conducted cted idencen 2018 to on in inl pare to the 2014 baseline, which will characterize Confirmed Basis of Design requires surface casing to beset below permafrost IJI L Modeling results cannot rule out the potential for 02-03 like event but does suggest it is a very low probability Completed initial risk assessment for operability Need additional mitigations for Workers in wellhouse and around well scaffolding - Need additional mitigation for vvellwork equipment on well Seek internal approval for operation Seek AOGCC approval for operation DS4-03 J 3971 joint 343 56— '. 20"Slip Joint 209'. 343', 456' i 192$yrill 13.3/8" DV Collar 0 1293'�I ZU33ftWQ_ _. ----- 9.5/8" HES ES Cementer 01376' _ 1033 RWU.__..__._—_. 9.5/8",13.3/8" gager ECp tSOZONE packer 01399'MD' Cuing puck 0 1420 - 1424' (Repau dur1�g 2013 RWOI 2033 RW0____——._..-- 5•R" NES% NPde 02255'MD � 1971 '. 9-5/8" DV C�._-- 1 9.5/8" DV Collar 016013' S'h HES%NOpbO _ ,_ �g5/g"x5-X"XESTNTPaCkWdP947OMD(BD91'ND) -I IS=h"HES%NPPIe i@9505'MD 45--h- Pit Plug I 5-X" 114 13CR-80 VAM TOP 9.5/e" Casmg or on DIPS O 100K Overpull 13.318" Cuing set on SIIPS 0 85K Overpuli 20" Casing 3D" Casmg 30"Conductor0114' ICamen 13.3/8" x 20" Top lob 011160' to SurfaM (Completed during 2004 RWO) Esdmrttl TOC 20" ® "500 (0%- 15(% E.mm due to W 750 TOP of Lament 13.3/6 120" 0 -600' - 911' (Sop 2) 10%- 140A ExMa it,. to Washout) — 20" Casing 5hoe 911'MD (911' TVD) 9-5(8" x 33-3/6" Cement to Surface poX Casing Cut & Pull (Complaled during W13 RWO) 1293'IStege 11 E 6mrttl TOC 13-3/8___ e —'- E umalad TOC 9.5/8" 0'2056 - 2348' (Stage 3) 13.318" Casing Shoe 0 2705'MD 12705' ND) tea- E+Omrttl TO[9-S/B"0"2911-3359'IStap 1&211 by 13P To: Alaska Oil and Gas Conservation Commission From: BP Exploration (Alaska), PBU Operator on June 27, 2017 Release Date: April 14, 2017 Release Location: Prudhoe Bay Unit Flow Station 1, Drill Site 2, Well 3 (Well 02-03B) Initially Filed: May 15, 2017 02-03B Incident Overview Incident Details - 02-03B Well Bore Schematic Failure Mode Theory Completed Actions Risk Assessment Actions to be Completed .. Proposed Plan Forward r April 14, 2017 Pad Operator responding to loss of flowline temperature reading as well as a drop in flowline pressure he discovers gas release misting from top of the wellhouse for 02-038. Responders determined: Wellhead and tree had moved upwards three feet. There was a leak below the surface safety valve (lower leak) and on the S -riser (upper leak). Lower leak was later identified to be from the flange between the tubing head adaptor and the master valve. - Upper leak was later identified to be from a sheared fitting for a pressure gauge on the top of the S -riser just past the wing valve. Surface safety valve was closed and isolated the upper leak from the reservoir. Drill Site 02 wells were shut in and common line blowdown to FS1 flare header commenced. An attempt to kill the well was made, which exposed the upper leak. Well kill was delayed to repair the sheared fitting. April 16, 2017 Boots and Coots was mobilized. Source control contingency plans were developed. April 16, 2017 Boots and Coots arrived on the slope and repaired the upper leak. April 17, 2017 Resumed well kill operations and successfully killed well with brine. Lower leak stopped during well kill after surface pressures dropped below 1200 psi or —120 bbls away. April 19, 2017 Isolation plug installed in production liner to mechanically isolate the formation. 3 #Alma II r Iruon.M' * somw s.w v w Me w a av a rt of "Ol • 4711 IiL "".. x dip i� YT co" Y n t Details — Wellhead Moveme! .7. Ap �f y ��_� .J„ -d�.. .-- �ir"�ry^, r••�`� I by r+ , 4 leak point on S -riser Where pressure gauge contacted roof Top view Roof access panel Front of Weil Nouse frame (4 d Clock Position) Leak on post incident with plug fitting (Upper Leak) 0 S -riser Pressure Gauge Jewelry by 0 Tubing Head Adaater by Uncfmr X/. h.- r7l____ Sheared NPT Pitting 9 by 0 10 0I m v N co c 0 N h. ------------------------ _____________ ___"—_ _ rs Dt ; W _ Parking - — — — — — \ rpump Tuck Val w w Area 1, •r' P vas r� p I rn r II - c :�` a / I Vac EnviroVac / I m \ I,� Warm Up r' m J Security-/ Check -In 1, — — f 21 bf I a 1 ; it n 1 i_� 1 II ii If � � I 1 -- W,- VVVVVV ���VY ro'sYP+'aMzar, nz.us 133/B IOL-CWaaO\LP I}3fi`(snL(^NaM wYaM PYN 01101' 9.6/P iIX-Ceup1W]' 9i/P (wnC W aaG PJ W WnNF LLA ]l]l'BeaarRHbSSV NKgOb t56" 96/e" W (eu F IYbV WS1 VN<LS1Y ai i]bl'lewa(wmam 66(B' 11N/ wm.% µ 0677b]Ib'F3Jl'10 yM1[4p6ii8 H0i Baha IYtlN Y' SLK Lerve 4 7.1 MIM"TIWW 995!'BWaa 40N Aon' j(ppba0lB}il'NDI45/B .SN"wuSPBPa^" 1M19'i%"abh"YO 16BS B+W 6%• "R" 11VPS 1Mx' iro"(nB+.a waBq+"swW 16154 YO3M1'a}}/Ib" lRlr W>3/16"ai>/B" 0 12 igWliglm l\W j L 3 ii BP<,.F�naaolss'. 1 � � ` NrwJ loco lP FB(]i' F 1t.1� �� mtlM1 li9/Yf�DY �4yhyp\ly}NUIII\4iVD/ �p� 13-" / L���y J-- �4vuNlct� 110T IIfP1 '. 1 y `v�ss/PFn1P _l a,N uv Bifel.IUU6Niwl �i �IIX a. s�/e tl me✓ 0 12 Subsidence Mechanism: Permafrost consists of lenses of ice with layers of varying formation types interspersed between them forming a consolidated formation. During the operation Of Oil and Gas wells, the hot production fluids cause the permafrost to melt allowing the previously frozen water to be displaced radially away from the wellbore by overburden formation pressure. The displaced water is replaced by the above formation layers causing the ground to subside. Subsidence Loading - Near wellbore formation subsidence creates a downward load on the adjacent casing. Larger casing sizes have more area for this downward load to act upon. The diagram to the right helps explain the above loading condition by showing the 5.5" tubing, 9-5/8" production casing, 13-3/8" intermediate casing, and 20" surface casing as concentric springs in across sectional view. The well has not been on production yet. The tubing and inner casing strings are initially set in tension which is transferred via the wellhead to the 20" casing resulting in it being initially in compression. The well is put on production. This causes the tubing and inner casing strings to elongate due to thermal expansion which reverses their load to a compressive state. The 20" casing is seeing less of a compressive load. The well has been on production and a subsidence load has been applied. The 20" casing has reversed its state to be in tension and is now transferring its load via the wellhead to the tubing and inner casing strings causing them to be under an even greater compressional load (the key feat uof a three -string well design is the tubing and inner casing strings do not buckle re under the compressive load seen under the conditions in stage 3). The gradual increase in the compressional loading coupled with the contributory Pressure and temperature affects eventually cause a tensile failure of the 20" surface casing. 1• Sometatod wen lal na KIM 2. WIL%Vtadutdan wlftAaut Suh"_ � I 'JfiNI11d�NJfr _ I 4- Datum 2000' ND 3. Wall On ptpk 15 M wa:ltlan<a toaAltlt poulNA 4. U/aD After Surfara [asln Ceilun ------------- 5 I I It Datum 2000' ND ' BP made well 02-03 safe by securing with a mechanical plug — completed 4/19/17 BP to survey DS 02 to establish post 2014 levels of subsidence — completed 4/28/17 BP to permanently plug 02-03 and submit plan to AOGCC for approval — completed 5/19/17 Secured wells of similar three string casing construction as well 02-03 —completed 6/19/17 IL -,:5 o VVV, � z f--- t,,—. 4 14 '49 Evaluate options to mitigate potential for breaking S -riser gauge assemblies during an upward movement of the wellhead. Evaluate options to reduce damage to well barrier elements during an upward movement of the wellhead. Define scope of all wells with similar three -string casing designs to: L) Conduct modeling to determine failure modes and loading imparted on wellbore components D) Determine amount of subsidence needed to cause failure based on well design limits. Develop a diagnostics program to track subsidence and predict failure. cji Risk assess wells to determine operability Have BP Tubular Design Team conduct modeling to support: Verify that the failure mode seen in 02-03B is unique to three -string ca two -string casing design. sing design and is not seen in a Guide amendment of BP Casing and Tubing Practice to include the permafrost subsidence load condition. Expand subsidence monitoring plan to incorporate learnings from the 02-03B investiation and verify I effectiveness. y p ans Update GPB Basis of Design to account for permafrost subsidence loading per modeling conducted by the BP Tubular Design Team. 15 t` Action 1 to be completed by BP Slope Team — target completion 10/31/17 2 to be completed by BP Slope Team — target completion 11 /30/17 Action pleted by the BP Well Integrity Team supported by BP Technical Functions Action 3 to be com Team —target completion 11 /30/17 . l Functions Team —target completion 9/30/17 Action 4. a) to be completed by BP Technica Action 4. b) to be completed by BP Technical Functions Team —target completion 12/31/17 Action 5 to be completed by the BP Well Integrity Team — target completion 12/31/17 Action 6 to be completed by BP — target completion 4/30/2018 ventures —target completion end of 7/2017 Share learnings with BP's other Alaska joint Provide next progress update to AOGCC — target completion before end of 10/2017 Final Plug and Abandonment of well 02-03 — target completion 12/31117 16
