IR 05000286/2020010

Evaluation of Changes, Tests and Experiments Baseline Inspection Report 05000286/2020010

ML20260H020
Person / Time
Site:	Indian Point
Issue date:	09/16/2020
From:	Mel Gray Engineering Region 1 Branch 1
To:	Vitale A Entergy Nuclear Operations
Gray M
References
IR 2020010
Download: ML20260H020 (17)

Text

September 16, 2020

SUBJECT:

INDIAN POINT ENERGY CENTER, UNIT 3 - EVALUATION OF CHANGES, TESTS AND EXPERIMENTS BASELINE INSPECTION REPORT 05000286/2020010

Dear Mr. Vitale:

On July 31, 2020, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Indian Point Energy Center (IPEC), Unit 3, and discussed the results with you and other members of your staff on August 31. The results of this inspection are documented in the enclosed report.

No findings or violations were identified during this inspection.

The inspectors reviewed your June 22, 2020, safety evaluation and supporting hazards analysis associated with the 42-inch diameter Algonquin Incremental Market Project (AIM) natural gas pipeline installed near the IPEC facility. The inspectors concluded the structures and equipment required to safely shutdown Indian Point, Unit 3, and ensure safe storage of spent fuel at the facility will not be affected by a rupture of the nearby AIM natural gas pipeline. Additionally, the inspectors determined that assumptions in your previous safety evaluation, dated April 7, 2015, related to the time needed to close pipeline valves to isolate a ruptured section and the length of pipe isolated were not used to determine the impact of hazards associated with the AIM pipeline on safety-related structures and equipment. Finally, the inspectors found that a license amendment was not required for operation of the AIM pipeline near the IPEC facility. This letter, its enclosure, and your response (if any) will be made available for public inspection and copying at www.nrc.gov/reading-rm/adams.html and at the NRC Public Document Room in accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding.

Sincerely, X /RA/

Signed by: Melvin K. Gray Mel Gray, Chief Engineering Branch 1 Division of Reactor Safety Docket No. 05000286 License No. DPR-64

Enclosure:

As stated

Inspection Report

Docket Number: 05000286 License Number: DPR-64 Report Number: 05000286/2020010 Enterprise Identifier: I-2020-010-0057 Licensee: Entergy Nuclear Operations, Inc.

Facility: Indian Point Energy Center, Unit 3 Location: Buchanan, NY 10511-0249 Inspection Dates: July 14, 2020 to July 31, 2020 Inspectors: J. DeBoer, Reactor Inspector Y. Li, Senior Mechanical Engineer K. Mangan, Senior Reactor Inspector Approved By: Mel Gray, Chief Engineering Branch 1 Division of Reactor Safety Enclosure

SUMMARY

The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees performance by conducting an inspection of evaluation of changes, tests and experiments baseline inspection at Indian Point Energy Center, Unit 3, in accordance with the Reactor Oversight Process. The Reactor Oversight Process is the NRCs program for overseeing the safe operation of commercial nuclear power reactors. Refer to https://www.nrc.gov/reactors/operating/oversight.html for more information.

List of Findings and Violations

No findings or violations were identified.

Structures and equipment required to safely shutdown Indian Point, Unit 3, and ensure safe storage of spent fuel at the facility will not be affected by a rupture of the nearby AIM natural gas pipeline. The evaluation showed the structures and equipment will not be affected because they are outside the exclusion distances for hazards associated with a pipeline rupture and therefore would not be damaged.

Assumptions in the safety evaluation and supporting hazards analysis, dated April 7, 2015, related to the time needed to close pipeline valves to isolate a ruptured location of the pipe and the length of pipe isolated were only discussed in the evaluation of a vapor cloud fire hazard.

The assumptions were used to determine the potential distance a vapor cloud could reach as it is diluted to below flammability limits. However, the specific hazard was determined to have no impact on safety-related structures and equipment because of the buoyant nature of the vapor cloud, the heat flux from a fire would be short-lived and not affect equipment; and there would be no pressure transient.

A license amendment was not required for the change to the facility related to the operation of the AIM pipeline near the IPEC facility. A license amendment was not required because the change to the facility met the criteria described in Title 10 of the Code of Federal Regulations (10 CFR) 50.59.

Additional Tracking Items

None.

INSPECTION SCOPES

Inspections were conducted using the appropriate portions of the inspection procedures (IPs) in effect at the beginning of the inspection unless otherwise noted. Currently approved IPs with their attached revision histories are located on the public website at http://www.nrc.gov/reading-rm/doc-collections/insp-manual/inspection-procedure/index.html. Samples were declared complete when the IP requirements most appropriate to the inspection activity were met consistent with Inspection Manual Chapter (IMC) 2515, Light-Water Reactor Inspection Program - Operations Phase. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel to assess licensee performance and compliance with Commission rules and regulations, license conditions, site procedures, and standards.

Starting on March 20, 2020, in response to the National Emergency declared by the President of the United States on the public health risks of the coronavirus (COVID-19), resident and regional baseline inspections were evaluated to determine if all or portion of the objectives and requirements stated in the IP could be performed remotely. If the inspections could be performed remotely, they were conducted per the applicable IP. In the cases where it was determined the objectives and requirements could not be performed remotely, management elected to postpone and reschedule the inspection to a later date. For this inspection, it was determined the objectives could be met by having several team members travel to the Indian Point Energy Center to perform independent walkdowns onsite and of portions of the nearby Algonquin Incremental Market Project natural gas pipeline. The balance of the inspection was conducted remotely.

REACTOR SAFETY

71111.17T - Evaluations of Changes, Tests, and Experiments Sample Selection (IP Section 02.01)

The inspectors reviewed the following evaluations, screenings, and/or applicability determinations for 10 CFR 50.59 from July 14-16, 2020 at IPEC followed by in-office review through July 31, 2020.

(1) 14-2002-00-EVAL/14-3002-00-Eval, Installation of a New 42 Natural Gas Pipeline South of IPEC, Revision 3 Background Entergy staff prepared a safety evaluation (SE) to document their conclusions regarding the potential impacts of the nearby 42-inch diameter Algonquin Incremental Market (AIM) project natural gas pipeline on the Indian Point Energy Center (IPEC). The SE addresses NRC requirements in 10 CFR 50.59 related to determining whether a licensee amendment is required for a change to the facility, which, in this instance involved the installation and operation of the AIM pipeline near IPEC. To support their conclusions documented in the SE, Entergy staff developed a hazards analysis (HA) to evaluate the effects resulting from a postulated pipeline rupture near the site. The HA evaluated the effects of pipeline hazards on IPEC safety-related and important-to-safety structures, systems, and components (SSCs). Entergy staff completed their SE and supporting HA and concluded a license amendment was not required. Their HA specifically concluded that no safety-related SSCs would be adversely affected by hazards associated with a postulated AIM pipeline rupture.

In 2014, NRC inspectors completed an inspection of Entergys SE/HA (SE/HA 14-2002-00-EVAL/14-3002-00-Eval, Revision 0) and documented the results in NRC Inspection Report 05000247/2014004 and 05000286/2014004 (ML14314A052). The inspectors concluded the change to the facility (installation and operation of the AIM pipeline near IPEC) could be made without a license amendment. The inspectors also found that Entergy staff adequately evaluated the potential hazards associated with the pipeline on the safe operation of Indian Point, Units 2 and 3. Subsequent to the inspection, Entergy staff revised their SE/HA to address finalized details of the AIM Project and provided SE/HA 14-2002-00-EVAL/14-3002-00-Eval, Revision 1 to the NRC in correspondence dated April 8, 2015 (ML15104A660).

NRC staff performed additional reviews of the SE/HA and documented their evaluation in an NRC Expert Evaluation Team report dated April 8, 2020 (ML20100F635). The team found that the Indian Point reactors remain safe following the installation and operation of the AIM pipeline. However, the team determined that:

Entergy used a best-case timeframe and valve spacing for isolating the ruptured pipeline, meaning that a less-than-realistic amount of gas was assumed and analyzed.

Entergy should be asked to assess the importance of these assumptions to its original conclusions and update its analysis, if needed.

Specifically, the Expert Evaluation Team observed Entergy used a best-case isolation timeframe of approximately three minutes to isolate the rupture location and assumed three miles of AIM pipe remained pressurized to feed the rupture location in their SE/HA. In a letter dated April 23, 2020 (ML20113F066) the NRC requested Entergy to update their SE/HA as necessary and assess the validity and materiality of these assumptions and to reconcile any differences in the results in their records.

Entergy staff completed these actions and provided the revised SE/HA (14-2002-00-EVAL/14-3002-00-Eval, Revision 3) to the NRC in a letter dated June 24, 2020 (ML20178A486). Entergy staff determined their assumptions regarding isolation timeframe and valve isolation warranted revision to approximately 8 minutes to isolate a postulated pipe break and following pipe isolation, up to 11 miles of pipe length would continue to feed the rupture location. However, Entergy staff indicated revising the assumption related to isolation time and length of pipeline only affected their vapor cloud hazard evaluation because Entergy staff utilized pressures at the initial stages of the pipe rupture in their analyses of other hazards.

Inspection Scope The inspectors reviewed Entergys revised SE and supporting HA to determine whether the change (installation and operation of the AIM pipeline near IPEC) to the facility as described in the UFSAR, had been reviewed and documented in accordance with NRC regulatory requirements in 10 CFR 50.59. In addition, the inspectors evaluated whether Entergy was required to obtain a license amendment prior to implementing the change.

The inspectors reviewed Entergys SE/HA (Revision 3) for each of the hazards described in the UFSAR that could occur following a postulated AIM pipe rupture. The inspectors reviewed Entergys evaluation of a vapor cloud fire at the rupture location; vapor cloud explosion at the rupture location; remote vapor cloud fire; remote vapor cloud explosion; and impact of projectiles/missiles created by a failure. The inspectors reviewed Entergys inputs, methodologies, and calculations developed to determine if these hazards would affect the safety of IPEC Unit 3 and if assumptions used by Entergy staff were appropriate.

The inspectors also reviewed the SE/HA (Revision 1) provided to the NRC in 2015 to determine whether the assumptions made by Entergy regarding pipe isolation timeframe and length of pipe isolated were material to the evaluation and conclusions documented in the SE submitted to the NRC. Specifically, the inspectors evaluated the effect of these assumptions on the impact to IPEC safety-related and important-to-safety SSCs. The inspectors also reviewed the information documented in the SE/HA submitted to the NRC (SE/HA 14-2002-00-EVAL/14-3002-00-Eval, Revision 1) to assess if the requirements of 10 CFR 50.9 were met related to complete and accurate information.

The inspectors interviewed Entergy staff and their contractors, and reviewed supporting information including calculations, analyses, the UFSAR, and plant drawings to assess the adequacy of the SE and supporting HA. Additionally, the inspectors walked down sections of the AIM project pipeline associated with the SE/HA and potentially affected SSCs within and adjacent to the owner-controlled area. The inspectors independently reviewed on a sampling basis calculational methodologies and technical input to assess whether the methodologies and inputs used by Entergy staff were technically supported. The inspectors noted that Entergy staff developed exclusion distances, that is, the distance from a postulated AIM pipe rupture location beyond which damage to structures or equipment is not postulated for heat and overpressure effects. In reviewing methodologies, the inspectors considered whether methods and inputs were consistent with NRC regulatory guidance related to external hazards. Finally, the inspectors considered the appropriateness of the software used to characterize the hazards resulting from a postulated AIM pipe rupture near IPEC, including review of the inputs and software verification and validation information.

The inspectors compared the SE to the requirements in 10 CFR 50.59, and considered the guidance and methods described in Nuclear Energy Institute (NEI) 96-07, Guidelines for 10 CFR 50.59 Evaluations, as endorsed by NRC Regulatory Guide 1.187, Guidance for Implementation of 10 CFR 50.59, Changes, Tests, and Experiments, to determine the adequacy of the SE.

INSPECTION RESULTS

Observations 71111.17T No findings or violations were identified.

Key Observations and Conclusions The inspectors concluded the structures and equipment required to safely shutdown Indian Point, Unit 3, and ensure safe storage of spent fuel at the IPEC, will not be affected by a rupture of the nearby AIM natural gas pipeline. Specifically, the inspectors found that Entergy staff correctly determined that all safety-related SSCs credited for the safe shutdown of Unit 3 and SSCs associated with the safe storage of spent fuel at IPEC were beyond the exclusion distances calculated in their SE/HA. Additionally, the inspectors determined that the methodologies used by Entergy to evaluate each hazard were appropriate and the assumptions used as inputs to the methodology and calculations were in accordance with regulatory and/or industry guidance.

The inspectors reviewed the assumptions in Entergys safety evaluation and supporting hazards analysis, dated April 7, 2015, related to the time to close pipeline isolation valves and length of pipe isolated. The inspectors identified these assumptions were only discussed in the evaluation of a vapor cloud fire hazard. The inspectors determined these assumptions were used by Entergy to calculate the distance a vapor cloud would extend until the concentration was diluted below flammability limits. However, the inspectors found the results were not used to determine the impact of a vapor cloud fire hazard on safety-related structures and equipment. The inspectors found that Entergy staff determined this hazard would not impact safety-related structures and components because of the buoyant nature of the cloud; the heat flux from a vapor cloud fire would be short lived and not affect equipment; and there would be no pressure transient. Therefore, the inspectors determined the valve closure time and pipe length assumptions were not used by Entergy staff to reach conclusions regarding impacts to IPEC structures and equipment. As a result, the inspectors did not identify a violation of 10 CFR 50.9. The inspectors assessment of Entergys evaluation of the vapor cloud fire is discussed below in Hazards Due to Vapor Cloud Fire.

The inspectors determined that a license amendment was not required for the change to the facility related to the operation of the AIM pipeline near the IPEC facility. The inspectors found that Entergy adequately addressed 10 CFR 50.59 criteria in their SE. As a result, the inspectors did not identify a violation of 10 CFR 50.59.

Evaluation Criteria The inspectors determined that the SE/HA evaluated changes made to Indian Point Unit 3 as described in the revision to the UFSAR, Chapter 2. The inspectors reviewed the revision to the UFSAR which added a description of the installation of the AIM pipeline near the facility and listed the SE/HA as a reference in UFSAR Chapter 2. The inspectors determined Entergy staff evaluated the following hazards that could result from a postulated rupture of the AIM pipeline to determine if a license amendment was required:

• jet fire

• vapor cloud (or flash fire),

• an over-pressurization event,

• hypothetical vapor cloud explosion, and

• potential missiles The inspectors found that Entergys SE/HA evaluated each hazard for their effects on safety-related and important-to-safety SSCs. Safety-related SSCs are those SSCs that are relied upon to remain functional during and following design basis events to assure:

• The integrity of the reactor coolant pressure boundary;

• The capability to shut down the reactor and maintain it in a safe shutdown condition; or

• The capability to prevent or mitigate the consequences of accidents which could result in potential offsite exposures.

Additionally, the inspectors found that Entergy staff evaluated the potential impact on SSCs associated with the safe storage of spent fuel at IPEC Unit 2 and Unit 3. The inspectors observed that all safety-related SSCs and those associated with the safe storage of spent fuel are located within the IPEC Security Owner Controlled Area (SOCA).

The inspectors determined Entergys SE/HA postulated a rupture of the buried AIM pipe at the point where the pipeline location is closest to the SOCA. The rupture was assumed to be a double ended break with natural gas (methane) flowing freely from both pipe ends. The hazards evaluated were heat damage due to fire characterized in terms of heat flux (kw/square meter), over-pressure due to a possible explosion characterized in terms of peak pressure (psi), and damage due to potential pipe projectiles (i.e. missiles) characterized in terms of missile distance traveled.

The inspectors observed that for heat and overpressure effects, Entergys HA developed exclusion distances, that is, the distance from a postulated AIM pipe rupture location beyond which damage to structures or equipment is not postulated. The inspectors noted the limit of 12.6 kw/square meters selected for heat flux represented damage where plastic melts or piloted ignition of wood occurs. The inspectors noted that the heat flux required to damage concrete structures that enclose safety-related equipment at the Indian Point site were significantly higher than this heat flux limit. The inspectors considered this limit to be appropriate because it considered the impact on equipment or instrumentation located outside of buildings and the limit was consistent with industry guidance for evaluation of the effects of a jet fire. The inspectors observed that the limits selected for a peak positive overpressure condition was 1 psi, which would involve effects such as glass shattering. The inspectors noted this limit was consistent with NRC Regulatory Guide 1.91, Evaluation of Explosions Postulated to Occur at Nearby Facilities and on Transportation Routes Near Nuclear Power Plants, Revision 2 (ML12170A980).

Events and Hazards Evaluation The inspectors reviewed Revision 1 of Entergys SE/HA completed in 2015 and Revision 3 completed in 2020 for each potential hazard on IPEC associated with a rupture of the nearby AIM pipeline. The inspectors reviewed assumptions, methodologies, inputs and conclusions developed by Entergy staff for the potential hazards described in the UFSAR. In addition to the overall conclusions of the SE/HA for each hazard, the inspectors evaluated the assumptions related to valve isolation time and pipe isolation length assumed in both SE/HA as it related to the materiality of these assumptions to the SE conclusions. Finally, the inspectors determined that the most likely hazards from an AIM pipe rupture involved a jet fire and missile hazard and the other hazards evaluated were of very low probability. However, the inspectors noted all potential hazards were evaluated by Entergy staff and the team reviewed Entergys evaluations of each hazard.

In review of the 2020 SE/HA, the inspectors found that Entergy staff incorporated additional conservatisms and refinements into their analyses that resulted in an increase in the calculated exclusion distances for heat flux and overpressure hazards. However, the inspectors found that safety-related equipment remained beyond these exclusion distances for all hazards and, therefore, remained capable of performing as intended following a postulated pipeline rupture. The inspectors review confirmed these conservatisms and refinements were appropriate and not related to assumptions involving valve isolation time or length of pressurized pipe feeding the fault in the event of an AIM pipe rupture. Finally, the inspectors determined these changes did not impact NRC prior inspection conclusions that had determined Entergys SE was sufficient to show that a license amendment was not required for the change to the facility associated with the presence of the nearby AIM pipeline.

The inspectors review of Entergys revised analysis for each hazard and conclusions are discussed in the following.

Hazards Due to Jet Fire In review of information in Entergys SE/HA, the inspectors observed that a jet fire is the most likely hazard and focused their review on this hazard. The inspectors noted that a deterministic double ended AIM pipe rupture near IPEC was assumed which would result in a jet fire if there is an ignition source. The team noted an ignition could be produced by pipe fragments or rock sparks or an electrical spark from nearby equipment (If there is no ignition source a jet fire would not occur). The inspectors found that Entergy staff considered the hazard associated with a jet fire hazard involved heat flux and not an overpressure condition. The inspectors determined this was consistent with industry literature. The inspectors noted that in SE/HA Revision 3, Entergy staff revised assumptions resulting in the heat flux exclusion distance increasing by 279 feet. The inspectors determined safety-related SSCs in the SOCA remained beyond this distance. The inspectors determined the increased distance resulted from Entergy staff utilizing an updated version of software (BREEZE) which added the capability to angling the jet fire flame towards IPEC rather than modeling a jet fire as a vertical jet as was done in SE/HA Revision 1.

The inspectors concluded the change resulted in a more conservative result than SE/HA Revision 1 and was appropriate. The inspectors also noted there were other conservatisms in the SE/HA because the calculated heat flux was based on average gas flow rated calculated in the first minute of the release and Entergy staff did not reduce the release rate (which would result in lower heat flux generated) over time. Notwithstanding this assumption the team identified that the flow would decrease significantly within the first minute of a rupture resulting in a heat flux less than that calculated in the SE/HA. The inspectors found that valve closure and pipe length isolation assumptions were irrelevant to this hazard analysis. The inspectors further noted the SE/HA assumed unfavorable atmospheric and wind directions (towards the plant) and did not account for terrain and elevation effects that may reduce the heat flux exclusion distance.

Hazards Due to Vapor Cloud Fire The inspectors reviewed Entergys SE/HA related to hazards associated with a vapor cloud (or flash) fire. The inspectors noted that Entergy staff determined a vapor cloud fire is a transient fire from a delayed ignition of a vapor cloud resulting in a limited duration heat flux hazard. The inspectors found that Entergys SE/HA Revision 1 concluded that because a fire in a vapor cloud is of short duration and results in no significant overpressure, the integrity of SSCs exposed to cloud fires will not be challenged. Additionally, Entergy staff noted that if a vapor cloud was ignited by a remote ignition source it would burn back to the rupture location resulting in a jet fire. Entergy staff concluded that the jet fire hazard would cause higher heat flux to SSCs within the jet fire exclusion distance than a vapor cloud fire and the effects of a jet fire heat flux had been evaluated.

Additionally, Entergy staff concluded that the potential for the hazard to impact SSCs is extremely low due to the buoyant nature of methane. Specifically, following the release of methane gas from the postulated pipe rupture, the concentration of the methane gas would be reduced below the five percent lower flammability limit due to turbulent mixing prior the cloud reaching safety-related SSCs. The inspectors also noted the Entergy staffs analysis stated that, while a vapor cloud could travel very considerable distances depending on conditions, the buoyant nature of methane generally precludes the formation of a persistent ground level flammable vapor cloud.

The inspectors review of SE/HA Revision 1 found Entergys evaluation of the vapor cloud fire included a table (Table 8 - Consequences of Cloud Fires) that presented information including the results of a calculation that determined the potential distance a vapor cloud could reach as it is diluted to below flammability limits. The inspectors determined this evaluation was completed using software employing AFTOX methodology for vapor cloud dispersion analysis and assumed the methane to be neutrally buoyant. The inspectors noted SE/HA Revision 1 footnote 23 to Table 8 describes various mass flow rates used in the calculation and one of the flow rates was determined based on an assumption that the pipeline isolation valves would be closed in three minutes. The inspectors determined that the flowrates described in the footnote were used as an input in the AFTOX calculation to determine the length of the vapor cloud discussed above. However, the inspectors found that this analysis of the vapor cloud, including the consideration of valve closure time, was not material to the SE/HA Revision 1 because the information developed in the AFTOX calculation was not used by Entergy staff to establish any exclusion distance related to heat flux, over-pressure, or missile projection in regard to the potential adverse impact of a cloud fire on safety-related SSCs or hazard effects on important-to-safety SSCs.

The inspectors review of SE/HA Revision 3 identified that Entergy staff revised their analysis clarifying their conclusions regarding hazards associated with a vapor cloud fire. The inspectors noted that Entergy staff continued to consider that this hazard is an extremely low probability due to the buoyant nature of methane; a cloud fire resulted in no significant overpressure; and, because the fire would be of short duration, the associated heat flux would not cause damage to SSCs. Entergy staff stated that while the size of a methane vapor cloud and the duration of its passage will be affected by the duration of the release, no new calculations were required because no significant overpressures result from a cloud fire and, because the fire generally lasts for less than a minute, the integrity of structures or equipment engulfed in or exposed to the flame will not be challenged.

The inspectors found that Entergy staff considered the potential for formation and movement of a vapor cloud during the turbulent jet (sonic flow conditions) phase of a pipe rupture and following the transition of the pipe break flow to subsonic, non-turbulent flow conditions which occurs after pipeline valve closure. The inspectors found that Entergy staff determined that during the momentum driven turbulent jet phase of the release, sonic flow causes rapid mixing of the methane with the surrounding atmosphere resulting in a reduction of methane concentration to below the flammability limit at the boundaries of the turbulent jet. As a result, methane leaving the jet and forming a cloud would be at a concentration below the methane lower flammable limit and would not ignite. After valve closure when flow is reduced to subsonic conditions, Entergy staff concluded that turbulent mixing would no longer be present, however field evidence was cited to suggest that the methane would be buoyant during this phase of the release. As a result, the vapor cloud would rise up and away from safety-related SSCs resulting in a reduction of methane concentration to below the lower flammability limit.

The inspectors noted the additional discussion in SE/HA Revision 3 regarding the hazard further clarified the evaluation of the hazards associated with a cloud fire but the discussion presented in the revised SE/HA did not materially change the basis for the conclusion that a cloud fire would not impact safety-related SSCs, and was consistent with the SE/HA Revision 1 conclusions. Additionally, the inspectors walkdown of the AIM pipe near IPEC showed that the terrain did not support an assumed vapor cloud of methane to remain at ground level and transport downhill towards the facility considering methanes buoyant property over the range of expected ambient temperatures. The inspectors also found that the behavior and hazards associated with a vapor cloud discussed in the SE/HA were consistent with discussions found in NUREG/CR 1640, Nuclear Fuel Cycle Facility Accident Analysis Handbook, Chapter 5, March 1998 (ML072000468) and industry guidance (See References to this report). Finally, inspectors noted that the analysis of the hazard performed by Entergy staff evaluated cloud formations before and after the pipeline isolation valves were closed; however, the inspectors found that when the valve were closed and the length of pipe isolated was not material to the analysis.

Over-Pressure Hazard - Explosion in Turbulent Jet The inspectors determined Entergy staff evaluated the hazards resulting from a postulated explosion in the momentum driven turbulent jet created following a pipe break when choke (supersonic) flow conditions characterized the release flow. Entergy staff assumed choke flow conditions would occur until action is taken to isolate the ruptured pipe. The inspectors noted that the released methane mixes turbulently with air reducing the methane concentration to within methane flammability limits (5-15 percent) and the turbulence supports flame acceleration and as a consequence involved a potential explosion hazard. The inspectors found that Entergy staff used standard recognized methods to calculate the mass of flammable methane within the volume of the momentum driven jet cone formed and anchored at the pipe break location. Entergy staff assumed that methane mass not within this volume would be below the flammability limit and would not contribute to a fire or explosion. The inspectors found that calculations of this methane mass were based on gas flowrate prior to any actions to isolate the pipe rupture location and therefore the evaluation of the explosion hazard was not impacted by valve isolation time or length of pipe isolated.

The inspectors reviewed Entergy staff calculations supporting their SE/HA Revision 3 that resulted in the exclusion distance increasing by 121 feet for this overpressure hazard. The inspectors found that the increased distance was a result of a larger assumed flowrate used to determine the mass of methane present in the turbulent jet. The inspectors observed that the revised flow rate was a result of Entergy staff using the maximum operating pressure of the pipe to calculate the choke flow through the break. The inspectors found that previous revisions of the SE/HA determined the flow based on the average pipeline pressure over the first minute following a postulated pipe rupture. The higher assumed flow resulted in an increase to the calculated turbulent jet volume and methane mass available for detonation.

The inspectors found this approach to be more conservative than the previous calculations. In order to determine the 1 psi exclusion distance for this hazard the inspectors determined that Entergy used the TNT-Equivalent methodology. The inspectors noted that this methodology was used for all revisions of the SE/HA, but Revision 3 assumed the larger mass of methane in order to determine the exclusion distance. The inspectors found this methodology was consistent with Regulatory Guide 1.91 and appropriate to evaluate this hazard. Additionally, the inspectors observed that Entergys calculated mass of methane used in the calculation was conservative because the pressure assumption used in SE/HA Revision 3 and the approach used in previous revisions of the calculation assumed the pipe rupture gas flowrate remained constant for the event when evidence shows the pipeline pressure and the resulting flow drops off sharply over time.

Hazards Due to Hypothetical Remote Vapor Cloud Explosion - Tree Beltline The inspectors determined Entergy staff considered the potential for an explosion resulting from a vapor cloud that could develop in a belt of trees identified by Entergy as the limiting location. Entergy staff determined that the trees may provide enough congestion to cause a deflagration combustion of a gas cloud in the trees to produce sufficient turbulence such that flame acceleration results in a detonation hazard to be hypothetically possible. Entergy staff considered this event to be hypothetical and noted that a remote vapor cloud explosion has not occurred following a methane pipeline rupture. In SE/HA Revision 1 Entergy staff evaluated this hazard and concluded the resulting overpressure was less than that calculated for the turbulent jet explosion hazard. The inspectors found that Entergy staff assumed a concentration of methane within the tree volume based in methane flow at the beginning of the event and employed the TNT Equivalency Method to calculate the exclusion distance.

The inspectors determined Entergy staff revised their analysis based on their determination that during initial pipe rupture conditions a momentum driven turbulent jet explosion is the potential explosion hazard. As a result, Entergy staff postulated a vapor cloud explosion in a congested tree belt area only after isolation valve closure when a turbulent jet flow from the rupture abates. The inspectors found that as a result, less methane was determined to be present in the tree belt for the evaluation of the resulting explosion hazard than previous revisions of the SE/HA. Entergy staff utilized the SLAB vapor dispersion model to calculate the mass of methane available within the congested area and employed the TNO Multi-Energy Explosion Model to calculate the overpressure exclusion distance. The inspectors evaluated the use of this model versus the TNT Equivalent Model used in SE/HA Revision 1 and determined that the TNO Multi-Energy methodology resulted in conservative results for evaluation of the resultant overpressure condition for far field effects when compared to the TNT Equivalent model. The inspectors also reviewed industry guidance and determined that the Multi-Energy methodology was appropriate for the evaluation of this event. The inspectors found the changes to the calculated mass of methane and the use of the TNO Multi-Energy methodology to be appropriate and consistent with industry guidance.

The inspectors found that changes made by Entergy staff in SE/HA Revision 3 to their mass assumptions and methodology resulted in an increase of 505 feet in the exclusion distance for this hazard. The team noted that this revised distance resulted in this scenario becoming the limiting event for explosion hazards; however, the use of this exclusion distance still showed that safety-related equipment remained unaffected. The inspectors also noted that Entergy staff used conservative assumptions within the TNO Multi-Energy methodology to calculate the exclusion distance and, if more realistic assumptions were used for ignition strength, obstacle density, and confinement, the calculated exclusion distance would likely be less than the calculated turbulent jet explosion exclusion distance. Finally, the inspectors noted that this hazard analysis assumed that the pipeline isolation valves were closed; however, the analysis did not evaluate or assume a timeline for when the valves would be closed. Likewise the pipe length isolated was not a factor.

Hazards Due to Potential Missiles The inspectors reviewed Entergys 2015 SE/HA Revision 1 and 2020 SE/HA Revision 3 and determined there were no changes to the missile hazard analysis. Additionally, the inspectors determined the analysis results were independent of valve closure time or pipe length isolated.

SSCs Impacted by AIM Pipeline Hazards The inspectors found that Entergys SE/HA also considered whether the hazards resulting from a postulated AIM pipeline failure could affect SSCs located outside the SOCA that, while not safety-related, are considered important-to-safety. The inspectors noted that Entergy staff identified several SSCs important-to-safety that were located within the exclusion distances calculated in the SE/HA and had evaluated if the SSC would be adversely affected and the potential effect on the safe operation of the facility. The inspectors review determined that Entergy staff identified all SSCs important-to-safety within the exclusion distances and adequately evaluated the impact of a potential loss of these SSCs caused by the hazards associated with a postulated AIM pipeline rupture. The inspectors noted these SSCs included the electrical switchyard, city water tank, FLEX building, the Emergency Operations Facility (EOF), meteorological tower, and two steam generator concrete storage buildings known as mausoleums. The inspectors found that Entergys SE/HA adequately considered whether these SSCs would remain functional notwithstanding heat flux or overpressure effects, or, if non-functional, whether there was back-up capability.

The inspectors also reviewed Entergys assessment of the increased probability of a loss-of-offsite-power (LOOP) event due to a loss of the switchyard from a postulated pipeline rupture.

The inspectors independently compared the LOOP frequency assumed in the station probable risk assessment (PRA) to the frequency associated with the loss of the switchyard due to pipeline rupture. The inspectors found that the increased risk was sufficiently low such that 10 CFR 50.59 criterion

(ii) of no more than a minimal increase in the likelihood of occurrence of a malfunction of a structure, system, or component (SSC) important to safety previously evaluated in the FSAR was met.

Additional Reviews The inspectors considered the appropriateness of the methods used by Entergy staff to assess the hazards to IPEC resulting from the nearby AIM pipeline. The inspectors noted the methodologies involving the use of TNT Equivalency Model, TNO Multi-Energy Explosion Model, and SLAB vapor dispersion model are recognized in NRC regulatory guidance (Regulatory Guide 1.91 and NUREG/CR-6410, Chapter 5) and that the Gas Research Institute jet fire methodology is widely recognized and utilized.

The inspectors reviewed validation and verification information for the suite of these methodologies incorporated into the Breeze Incident Analyst software used by Entergy staff to complete their SE/HA. This validation information included the Gas Research Institute Jet Fire Model, SLAB dispersion model, TNO Multi-Energy Model, and TNT Equivalency Model. The inspectors found the validation tests involving using identical input data for each specific model and comparing the output to verify consistency was sufficient to show the software properly implemented these methods.

EXIT MEETINGS AND DEBRIEFS

The inspectors verified no proprietary information was retained or documented in this report.

• On August 31, 2020, the inspectors presented the evaluation of changes, tests and experiments baseline inspection results to Anthony J. Vitale and other members of the licensee staff.

DOCUMENTS REVIEWED

Inspection Type Designation Description or Title Revision or

Procedure Date

Calculations IP-CALC-04-007 Evaluation of the Unit-2 City Water Storage Tank to Rev. 4

Withstand Tornado Wind Loads

Corrective Action CR-IP3-2020-

Documents 01924

Resulting from

Inspection

Engineering 14-2002-00- Installation of a New 42 Natural Gas Pipeline South of IPEC Rev. 3

Evaluations EVAL/14-3002-

00-Eval

14-2002-00- Installation of a New 42 Natural Gas Pipeline South of IPEC Rev. 1

EVAL/14-3002-

00-Eval

Miscellaneous Guidelines For Evaluating the Characteristics of Vapor Cloud 1994

Explosions, Flash Fires, and BLEVEs, Center For Chemical

Process Safety of the American Institute of Chemical

Engineers

Report of the U.S. Nuclear Regulatory Commission Expert 04/08/2020

Evaluation Team on Concerns Pertaining to Gas

Transmission Lines Near the Indian Point Nuclear Power

Plant (ML20100F635)

SFPE Handbook for Fire Protection Engineering 5th Edition

Vapor Cloud Explosion. In Methods for the Calculation of 2005 3rd

Physical Effects Due to Release of Hazardous Materials Edition

(Liquids and Gases)

Numerical Study For Accidental Gas Releases From High 2006

Pressure Pipelines

Validation of the SLAB Model in BREEZE Incident Analysis - 08/03/2020

Risk Research Group

Validation of the DEGRADIS Model in BREEZE Incident 07/30/2020

Analysis - Risk Research Group

Validation of the TNO Model in BREEZE Incident Analysis - 07/30/2020

Risk Research Group

Inspection Type Designation Description or Title Revision or

Procedure Date

Validation of the TNT Model in BREEZE Incident Analysis - 07/30/2020

Risk Research Group

Validation of the Jet Fire Model in BREEZE Incident Analysis 08/05/2020

Guidance for Protocol for School Site Pipeline Risk Analysis, 2007

Volume 2, California Department of Education

Lee's Loss Prevention in the Process Industry, Volume 1 3rd Edition

GRI-00/0189 A Model For Sizing High Consequence Areas Associated October

With Natural Gas Pipelines 2000

NL-15-030 Revised 10 C.F.R. 50.59 Safety Evaluation and Supporting 04/08/2015

Analyses Prepared in Response to the Algonquin

Incremental Market Natural Gas Project

NL-20-050 Response to U.S. Nuclear Regulatory Commission Region I 06/24/2020

Letter Regarding Algonquin Incremental Market Project

Pipeline

NUREG/CR-6410 Nuclear Fuel Cycle Facility Accident Analysis Handbook March 1998

Regulatory Guide Evaluations of Explosions Postulated to Occur at Nearby Rev. 2

1.91 Facilities and on Transportation Routes Near Nuclear Power

Plants

RR1034 Review of the Event Tree Structure and Ignition Probabilities 2015

Used in HSEs Pipeline Risk Assessment Code MISHAP

RR1113 Review of Vapour Cloud Explosion Incidents, The Health and 2016

Safety Executive

14