Text

Response to Request for Additional Information (RAI) on Severe Accident Mitigation Alternatives Dated May 21, 2012
	ML12202A056
Person / Time
Site:	Grand Gulf
Issue date:	07/19/2012
From:	Mike Perito; Entergy Operations
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	GNRO-2012/00072
	Download: ML12202A056 (125)
	v • d • e

Ent.rgy Operations, Inc.

P. O. Box 756 Port Gibson. MS 39150 Mlch.el Perito Vice President, Operations Grand Gulf Nuclear Station TeL (601)437-6409 GNRO-2012/00072 July 19, 2012 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555

SUBJECT:

Response to Request for Additional Information (RAI) on Severe Accident Mitigation Alternatives dated May 21,2012 Grand Gulf Nuclear Station, Unit 1 Docket No. 50-416 License No. NPF-29

REFERENCE:

NRC Letter, "Request for Additional Information on Severe Accident Mitigation Alternatives for the Review of the Grand Gulf Nuclear Station, Unit 1, License Renewal Application Environmental Review," dated May 21, 2012 (GNRI-2012/00121) (ML12115A101)

Dear Sir or Madam:

Entergy Operations, Inc is providing, in Attachment 1, the response to the referenced Request for Additional Information (RAI). Attachment 2 includes the Phase I Candidate SAMA Analysis list and Attachment 3 contains Release Mode Frequencies for Analysis Cases requested in RAI's.

This letter contains no new commitments. If you have any questions or require additional information, please contact Christina L. Perino at 601-437-6299.

I declare under penalty of perjury that the foregoing is true and correct. Executed on the 19th day of July, 2012.

Sincerely, MP/jas Attachment(s): (see next page)

GNRO-2012/00072 Page 2 of 2 Attachments(s): 1. Response to Request for Additional Information (RAI)

2. Phase I Candidate SAMA Analysis

3. Release Mode Frequencies for Analysis Cases cc: with Attachment(s)

Mr. John P. Boska, Project Manager Plant Licensing Branch 1-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Mail Stop 0-8-C2 Washington, DC 20555 cc: without Attachment(s)

Mr. Elmo E. Collins, Jr.

Regional Administrator, Region IV U.S. Nuclear Regulatory Commission 1600 East Lamar Boulevard Arlington, TX 76011-4511 U.S. Nuclear Regulatory Commission AnN: Mr. A. Wang, NRR/DORL Mail Stop OWFN/8 G14 11555 Rockville Pike Rockville, MD 20852-2378 U.S. Nuclear Regulatory Commission AnN: Mr. Nathaniel Ferrer NRR/DLR Mail Stop OWFN/ 11 F1 11555 Rockville Pike Rockville, MD 20852-2378 NRC Senior Resident Inspector Grand Gulf Nuclear Station Port Gibson, MS 39150

Attachment 1 to GNRO-2012100072 Response to Requests for Additional Information (RAI) to GNRO-2012/00072 Page 1 of 36 Request

1. Provide the following information regarding the Probabilistic Risk Assessment (PRA) used for the Severe Accident Mitigation Alternative (SAMA) analysis. References to Section E are to Section E of the Environmental Report (ER).

a. Section E.1.1 indicates there have been no major plant changes since August 2006 that would have a significant impact on the results of the SAMA analysis. Define "significant" and how this determination was made.

b. Section E.1.4 provides a summary of the Core Damage Frequency (CDF) and Large Early Release Frequency (LERF) from Grand Gulf Nuclear Station (GGNS) probabilistic safety analysis modeling between 1992-2010. Section E.1.4.2 indicates that the update included plant changes through refueling outage 11, but does not specifically list these changes. Identify the major changes with the greatest influence on the SAMA analysis.

c. Section E.1.4.3 indicates the last plant data update covers the period through August 2006. Provide assurance that there are no equipment reliability degradation issues since this update that would adversely impact the SAMA analysis.

d. On page E.1-23, the ER indicates that the ratio of the 9Sth percentile to the mean is about 2.38. Since point estimates of the CDF and release category frequencies were used rather than mean values, provide the 9S th _, SOth_, and sth-percentile CDF results of the uncertainty analysis as well as the point estimate CDF of the model and truncation used for the uncertainty analysis.

e. Differences exist within the license renewal application among quantitative results for CDF, release category frequencies, and Risk Reduction Worth (RRW). The total CDF was presented as 2.0SE-06 per year, from the sum of contributions by initiator (Table E.1-1) and sum of the release frequencies (Table E.1-8), and 2.92E-06 per year from the sum of the accident classes (Table E.1-7). The applicant's submittal states that the 2.9E-06 value is higher than the others due to non-minimal cutsets, which result from quantifying at the sequence level. Although some difference is expected, the difference of approximately 40% appears to be unusually large for this cause. Further, the sum of the release category frequencies would be expected to be higher since it is also the result of a sequence by sequence quantification. The CDF contribution from various failures implied by RRW values in Table E.1-2 are also significantly different in some cases from those given in Table E.1-1 or Table E.2-2. For example:

Table E.1-1 showed the CDF initiated by loss of offsite power (LOSP) as 140/0 of the total CDF, yet Table E.1-2 indicated a RRW value of 1.6289 for LOSP, which corresponds to a 38.6% contribution.

Case 1 was evaluated by eliminating all cutsets for station blackout (SBO), and the CDF is stated to be reduced by 13.6%. Table E.1-1 indicates that SBO contributes to 36.60/0 of the CDF. Based on the values of RRW, the elimination of basic events "ZSBO" and "ZT1 B" cited for Case 1 supports a 36.3% reduction inCDF.

Case 22 on improved availability of the diesel generator system through heating, ventilation, and air conditioning (HVAC) improvements was stated to be evaluated by eliminating HVAC failure in diesel generator rooms which results in a 9.2% reduction of CDF. Basic event X77-FF-CFSTARTU, "X7? common cause to GNRO-2012/00072 Page 2 of 36 start failures, II has a RRW of 1.2754, which corresponds to a 21.60/0 reduction in CDF.

SAMA Number 63 cited for basic event E51-043-G, IILube oil cooling line hardware failure,1I in Table E.1-2 is evaluated by Case 46. The CDF reduction given in Table E.2-2 was 4.7% . The RRW given for this basic event is 1.0839, which corresponds to a CDF reduction of 7.7%.

In light of these differences among results, further support for the validity of the model quantification (Le., CDF, release category frequencies, and RRW) in the SAMA analysis is needed. Provide reasons for these differences and more details on how the quantification was performed for each situation, including examples related to this request. Describe specific contributions to the approximate 40% difference in CDF, such as some of the non-minimal cutsets or other reasons. Justify use of the lower CDF, rather than the higher CDF, for determining cost risk in the SAMA analysis.

f. Section E.1.4.5 indicates that all of the '8' priority comments have been addressed except for one documentation item related to the internal flood modeling. If any facts and observations (F&Os) were addressed by internal reviews that concluded that changes to the model were not needed or the F&O was incorrect, identify and discuss these F&Os and confirm their disposition remains applicable to the PRA used for the SAMA analysis.

g. Discuss the process and procedures for assuring technical quality of PRA updates since the peer review.

h. Section E.1.4 includes an unnumbered table of changes in contribution to CDF per initiator group for each model revision, beginning on page E.1-70 titled "Contribution to CDF Changes in PRA Models." The percentage contributions shown for R3 EPU (Revision 3, Extended Power Uprate version of the PRA model) are significantly different from those shown in Table E.1-1. Explain the basis for the unnumbered table in Section E.1.4 and the reasons for the differences from Table E.1-1.

Response 1a The Probabilistic Risk Assessment (PRA) Maintenance and Update procedure describes the process for maintaining the PRA models current with the as-built and as-operated plants. It describes the model change request (MCR) database used to track plant changes, procedure revisions, nuclear licensing revisions, and model improvements that impact the PRA models. The MCR database has the following four tier grading system to prioritize the change requests.

GRADE DEFINITION A Extremely important and necessary to assure the technical adequacy or Quality of the PRA.

8 Important and necessary to address, but may be deferred until the next model update.

C Considered desirable to maintain maximum flexibility in risk-informed applications and consistency in the industry, but not likely to significantly affect results or conclusions.

0 Editorial or minor technical item.

A plant change with the potential to alter or create a significant contributor to core damage frequency (CDF) or large early release frequency (LERF) would be an important to GNRO-2012/00072 Page 3 of 36 change and, therefore, would receive a grade 'A' or '8' designation. So, if a change warranted a grade 'A' or '8' designation in the MCR database, it may have a significant impact on the results of the SAMA analysis.

The MCRs initiated after August 1, 2006 were reviewed for impact on the SAMA analysis, with particular attention on the grade A and 8 MCRs.

There was one grade 'A' MCR which was related to the Equipment Out Of Service (EOOS) model. The EOOS model had to be changed to adjust the slider bar used to assess the risk of plant configurations when a low pressure feedwater heater is taken out of service. Since this MCR related only to a temporary condition in the EOOS model, it does not impact the SAMA analysis.

There were twelve grade '8' MCRs. One of the grade '8' MCRs was related to the partial update of the fire PRA model which was not used in the SAMA analysis (see response to RAI 3.a). Six of the grade '8' MCRs were changes to systems that are not risk significant. The impact of the remaining five grade '8' changes would be a reduction in CDF. Thus, they would not cause basic events to become more important or SAMAs to become more beneficial.

Therefore, there have been no major plant changes since August 2006 that would have a significant impact on the results of the SAMA analysis.

Response 1b Influential changes made during the GGNS 2002 (R2) model update were as follows.

Changed modeling to reflect installation of new type of plant service water radial well pumps and support systems.

Added heating, ventilation and air conditioning systems to the model, including addition of the new standby service water pump-house high temperature alarm.

Modeled changes to the backup scram valves and logic in the Anticipated Transient Without Scram (ATWS) portion of the fault tree.

Used more comprehensive human reliability analysis methods.

Used the convolution method for recovery of loss of offsite power (LOSP).

Influential changes made during the GGNS 2010 (R3) model update were the use of updated plant-specific failure and initiating event data, changes to the LOSP modeling to include consequential losses of offsite power, and use of updated industry data in the LOSP recovery analysis.

Response 1c The maintenance rule system health reports indicate no unresolved equipment reliability issues that would adversely impact the SAMA analysis. Also, no unresolved plant data issues were identified during the expert panel reviews of the model updates or during the expert panel review of the Level 2 cutsets.

Therefore, there is reasonable assurance that there are no equipment reliability degradation issues since the August 2006 data update that would adversely impact the SAMA analysis.

Response 1d The uncertainty results were generated using a cutset file with a truncation of 1E-12/Rx-yr and a point estimate of 2.82E-06/Rx-yr. This point estimate is slightly higher than the to GNRO-2012/00072 Page 4 of 36 baseline because a failure flag event for Reactor Core Isolation Cooling (RCIC) has been subsumed in the baseline cutset file. This is not expected to have a significant impact on the uncertainty analysis. The uncertainty results are as follows.

point estimate 2.82E-06/yr mean 3.00E-06/yr 5% 9.31 E-07/yr 500/0 2.19E-06/yr 95% 7.14E-06/yr standard deviation 5.69E-06/yr Response 1e The "lower CDP' utilized for the SAMA analysis is based on the GGNS level 2 model.

The "higher CDP' seen in some of the tables is based on the GGNS level 1 model.

Since the SAMA analysis requires the release frequencies from the level 2 GGNS model, it would not be feasible to perform a SAMA analysis with only a level 1 model.

The total CDF from the level 2 model utilized for the GGNS SAMA analysis is 2.05E-06 when each of the 13 release categories is solved. This model and quantification method were used for the baseline and individual SAMA analysis cases. The initiator contributions from this model and quantification method are presented in Table E.1-1 and the sum of the release frequencies is presented in Table E.1-8. The SSO and ATWS contributions in Table E.1-1 are exceptions. The Table E.1-1 value for ssa was approximated by multiplying the total CDF obtained by quantifying the level 2 model (2.05E-06 per year) by the percentage contribution to CDF from ssa sequences in the level 1 model. The value for ATWS was obtained in the same manner. These approximations are provided to reflect the relative magnitude of the CDF contribution from ssa and ATWS sequences when compared to the total CDF and to the CDF contributions from other types of sequences.

The values in Table E.1-7 and the RRW correlations in Table E.1-2 were obtained from accident sequence level quantification of the level 1 model at a truncation limit of 1E-12/yr. It is acceptable to provide some information from the level 1 model because the values in Table E.1-7 are illustrative in nature and are not used in the SAMA analysis.

Also, the RRW correlations in Table E.1-2 are used to ensure SAMAs have been identified for high-risk contributors, but the exact RRW values are not germane or significant. The note beneath Table E.1-7 is misleading. The total CDF from the level 1 model presented in Table E.1-7 is slightly higher than the single top solution in which non-minimal cutsets are subsumed. ER Table E.1-7 is changed as shown below with strikethrough for deletions and underline for additions.

Note: The total CDF is not the same as the baseline single top solution CDF in Table E-:4-rl- due to non-minimal cutsets created when quantifying at the sequence level.

The results should not be compared directly since one result is from the level 1 model and one is from the level 2 model. The differences in percentage contributions are due to the following.

1. Calculations are approximated in Computer Aided Fault Tree Analysis (CAFTA) using a "min cut upper bound" technique and this approximation to GNRO-2012/00072 Page 5 of 36 carries uncertainties. When handling split fractions or other large probabilities like those in the level 2 model it can increase or decrease contributions.

2. The level 2 model was quantified using a ONE-TOP quantification (Le., all accident sequences contributing to each release category are quantified at one time) whereas the level 1 model was quantified using an accident sequence level quantification (Le., each sequence is quantified individually and resulting cutsets are merged). The accident sequence level quantification can lead to more non-minimal cutsets which may change the percent contributions and affects the overall base "CDF" number.

3. The level 2 LOSP recoveries in the cutsets are different than the level 1 recoveries, which is lowering the percent contribution of an SBO in the level 2 model.

Specific responses to the bullets in the RAI follow.

Table E.1-1, which lists the percent contributions to the level 2 model, shows an LOSP-initiated contribution of 14%. Table E.1-2, which is the RRW correlations of the level 1 GGNS model, indicates a higher LOSP-initiated contribution. This is due to the fact that the level 2 model has different offsite power recoveries which affect the percentage contribution of the LOSP initiator.

Case 1 was evaluated by eliminating the SBO cutsets in the level 2 model, while the RRW CDF contributions listed in Table E.1-2 are based on the level 1 model. Also, the Table E.1-1 SBO value is an approximation as described above.

The RRW of 1.2754 for basic event X77-FF-CFSTARTU, "X77 common cause start failures, II is based on the level 1 model. Case 22 on improved availability of the diesel generator system through heating, ventilation, and air conditioning (HVAC) improvements which results in a 9.20/0 reduction is based on the level 2 model. The GGNS level 1 model and level 2 models are expected to have differences in the risk profile.

The CDF reduction for case 46 given in Table E.2-2 of 4.70/0 was based on the level 2 model. The RRW given for basic event E51-043-G, "Lube oil cooling line hardware failure, II in Table E.1-2 of 1.0839 is based on the GGNS level 1 model. The GGNS level 1 model and level 2 models are expected to have differences in the risk profile.

Response 1f Several F&Os generated during the boiling water reactor owner's group (BWROG) peer review in 1997 were reviewed by Entergy staff who concluded that the F&O level of significance was incorrect or that changes to the model were not needed. The items for which the level of significance was not correct were re-assessed as directly related to documentation in order to better support the model. The six CDF-related items that required no changes are discussed below.

In addition, following Revision 2 of the Level 1 update, a decision was made to develop a Large Early Release Frequency (LERF) model rather than update the Individual Plant Examination (I PE) Level 2 model. The LERF model was developed using the methods described in NUREG/CR-6595, Rev. 1, An Approach for Estimating the Frequencies of Various Containment Failure Modes and Bypass Events, and is directly linked to the Revision 2 Level 1 model. Because of the different method, Level 2 peer review to GNRO-2012/00072 Page 6 of 36 observations were not applicable and were not addressed. The lERF model was completed and issued in December 2003.

For the following F&Os, internal reviews concluded that changes to the model were not needed or the F&O was incorrect. As indicated, the dispositions for these F&Os remain applicable to the PRA model used for the SAMA analysis.

1. Observation 28 (Element IE-1 0)

"The GGNS PSA has developed a thorough list of initiating events. It is desirable to document the process used to develop this list and to ensure that support system initiators are adequately covered."

Observation 28 Disposition This is a documentation enhancement issue. No changes would result in the GGNS PRA model as a result of addressing this issue. Entergy PRA procedures address the initiating events analysis and provide guidance on development of initiating events to consider.

Since this is only a documentation issue, the disposition remains applicable to the PRA used for the SAMA analysis.

2. Observation 81 (Element AS-9)

"SBO Impacts to be Included AC power recovery is included in the PSA for station black out (SBO). For sequences with RCIC available, up to 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months were credited.

However, this requires a number of assumptions that may not hold true. The evaluation of potential SBO impacts to explicitly model in the accident sequence include the following: a) Exceeding HCTl at 30 minutes to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months (depending on the reactor pressure vessel (RPV) pressure) and how that is included in the SBO evaluation is an important sequence specific procedure. (See other AS-9 F&O) b) apparent lack of drywell (OW) temperature indication under SBO sequences (see P.

11 of ENERCON Report MS194/SERISB01). This may require premature emergency depressurization if OW temperature is unknown. c) It is non-conservative to credit RPV repressurization because of loss of direct current (DC) when calculations show DC is available from Division 2 for 11 to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . d) Battery depletion on Division 1 requires RCIC gland seal load shed and inclusion of an HEP for this action. (See also other AS-9 F&O) e) Inability to use high pressure core spray (HPCS) diesel generator (DG) (HPCS DG) for electrical cross tie when RPV level drops below level 2."

Observation 81 Disposition a) The emergency procedures (EPs) have been revised since Revision 1 of the PRA. The new EPs incorporate revised curves for the Heat Capacity Temperature Limit (HCTl). The single curve from the previous EPs was replaced with a family of curves of suppression pool temperature versus reactor pressure for various suppression pool levels. Theses curves allow the operators to control reactor pressure above 60 psi for almost all cases. Therefore, the revised curve allows operators to ensure that RCIC remains operable since it can operate with pressures down to 60 psig. Based on recent calculations, it is reasonable to assume that RCIC can operate for 6 to 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months depending on the suppression pool temperature and battery life.

The success criteria in the PRA used for the SAMA analysis is RCIC operation for 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months under SBO conditions. Therefore, this disposition remains applicable to the PRA used for the SAMA analysis.

to GNRO-2012/00072 Page 7 of 36 b) The revised EPs direct emergency depressurization if the drywell temperature cannot be maintained below 330°F. Even if drywell instrumentation is not available, the pressure associated with a saturated water temperature of 330°F is 103 psia. Since SBO scenarios (with RCIC operating) result in the slow heat-up of containment and the ultimate pressure of the containment is close to 67 psig, these temperatures are not possible for SBO scenarios until there is core damage or the scenario extends for a significant period of time. Analysis indicates that drywell temperature would be 225°F at 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months in a SBO scenario in which RCIC is operating. It is not expected that operators would emergency depressurize and remove the only source of injection (RCIC) during an SBO because they do not know the DW temperature, when they can lower pressure in accordance with other procedures. The emergency response organization would also be in place and would be able to provide guidance before temperature became a concern. Therefore, the issue is not a concern and no change is needed.

This disposition remains applicable to the PRA used for the SAMA analysis.

c) The SBO analysis does not credit re-pressurization. Once RCIC fails, the reactor must be maintained depressurized so that firewater can be use as an injection source. Event tree top X3 is used to model depressurizing the vessel with RCIC (bypassing all trips). This requires Attachment 3 of the EPs which defeats all RCIC isolation and non-mechanical interlocks.

This disposition remains applicable to the PRA used for the SAMA analysis.

d) A realistic analysis of battery life determined that the Division 1 battery life is 6.68 hours7.87037e-4 days 0.0189 hours 1.124339e-4 weeks 2.5874e-5 months with the gland seal compressor operating and 9.55 hours6.365741e-4 days 0.0153 hours 9.093915e-5 weeks 2.09275e-5 months without the compressor operating. Both of these consider only the battery aging factor.

Since RCIC is expected to fail due to high suppression pool water temperature at about the same time the Division 1 battery discharges with the compressor operating, there is no need to add a human failure event for stripping the gland seal compressor since there is no impact. The Division 2 battery is expected to last -11.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months . This division would allow continued depressurization with the safety relief valves (SRVs) up until that time. The Loss of AC Power EP does require the operators to strip the gland seal compressor in an SBO.

This disposition remains applicable to the PRA used for the SAMA analysis.

e) The EP for Loss of Offsite Power has been revised to add steps for defeating logic associated with Level 2 initiation of HPCS that would prevent the cross-tie of the Division 3 DG to the Division 1 or 2 bus.

This disposition remains applicable to the PRA used for the SAMA analysis.

3. Observation 85 (Element AS-9)

"There is a slight problem in the chronology of the event tree headings associated with containment heat removal or venting and low pressure injection. The general transient tree shows the sequence for RCIC operating to ask for RCIC, residual heat removal (RHR), Venting, and then HPCS and Low Pressure Injection. The result is that sequences are assigned to vented containment even if low pressure systems fail. This would certainly not be the case when EOPs are followed. For TQUV sequences, core damage would occur in the sequence at the time of depressurization on HCTL, Le., - 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . Venting would not generally occur until 22.5 psig in containment, Le., about 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Therefore, there are "vented" core to GNRO-2012/00072 Page 8 of 36 damage end states in the PRA that are improperly labeled. Examples include: T-16, T-20, and T-21."

Observation 85 Disposition The transient event tree shows several non-minimal sequences with respect to core damage that are not quantified as follows: T-16 is subsumed by T-13, T-24 is subsumed by T-20, and T- 25 is subsumed by T-21. The end states for T-16, T-24, and T-25 are correct (vented containment) and provide insight into the Level 2 PRA core-damage binning process. Therefore, no changes are needed.

Also, the HCTL limit would not occur at 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , but would occur at a later time (approximately 7 to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months ) with the current EPs. Based on Modular Accident Analysis Program (MAAP) evaluations, 22.5 psig in the containment would not occur until approximately 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . However, the operators would likely initiate venting before that time based on whether they believe that containment pressure can be maintained below 22.4 psig.

This disposition remains applicable to the PRA used for the SAMA analysis.

4. Observation 87 (Element AS-18)

"Sequence #37 - The fire protection injection is used for successful RPV makeup following an SBO without HPCS but successful RCIC and stuck-open relief valve (SORV). This is judged by the Certification Team to result in loss of injection in approximately 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . This means the 8 fire protection hoses must be aligned by this time under SBO conditions. No thermal hydraulic basis could be found to assess the HEP allowed time for the fire water cross tie for this sequence. It is judged that this operator action for this sequence has a much higher HEP than 0.013."

Observation 87 Disposition No changes are needed. RCIC has been determined to be capable of mitigating a" steamline break size of 0.13 sq ft. The flow through a single SRV is 18.43 sq in which is 0.128 sq ft. The RCIC performance analysis also credits control rod drive (CRD) flow at 20 Ib/sec or -144 gpm. This flow rate is not considered large enough to change the conclusions that RCIC alone can handle the SRV) transient. In this analysis, vessel pressure drops to a low of approximately 200 psi and level never drops to within - 80 inches of the top of active fuel (TAF). The analysis also does not assume an unrealistic operator action to prevent isolation of RCIC on high water level. By the time reactor pressure has reached 200 psig, the steam loss through the SORV equates to -300 gpm and RCIC can easily continue to make up the required flow.

Also a GOTHIC model was run to evaluate temperatures in the containment for SBO cases. The only change was to add in a single SORV. This evaluation indicates that reactor pressure drops into the 120 to 150 psi range in the 1.5 to 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months time frame.

It stays in that range out to the length of the evaluation, -9 hours. Suppression pool temperature reaches 200°F at approximately 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The containment pressure rises gradually from atmospheric to -16 psia at 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months and then increases to approximately 30 psia at 8.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months . These results are consistent with those from the RCIC performance analysis. Therefore, RCIC is expected to operate at least 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months under this scenario. After that time, Net Positive Suction Head (NPSH) might become a concern.

to GNRO-2012/00072 Page 9 of 36 The human reliability analysis for firewater alignment assumes a total time of 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months to perform the task. This includes -1.75 hours8.680556e-4 days 0.0208 hours 1.240079e-4 weeks 2.85375e-5 months to perform the alignment tasks and 30 minutes to realize that firewater should be aligned, leaving 45 minutes for diagnosis. The total of 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months is based on a transient event time to boil-off after core has been cooled for 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and no SORV. The time to boil-off with a SORV at 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months following a scram may be shorter. Scenarios involving less time to diagnosis and perform the task were considered in the update of the firewater alignment human error probability (HEP) in Revision 2 of the PRA model.

This disposition remains applicable to the PRA used for the SAMA analysis.

5. Observation 89 (Element AS-18)

"Cutset 11 - LOOP initiator with ECCS suction strainer clogging and fail to recover offsite power within 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months . This must assume RCIC operates for 8 - 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months and HPCS cannot be used from the CST. Are both of these assumptions realistic?"

Observation 89 Disposition The observation is a misinterpretation of the cutset. Failure to recover offsite power within 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months is not in the cutset because RCIC operates for 8-10 hours but because the standby service water crosstie operates until the containment spray initiation signal is generated. The containment spray signal was estimated to occur in the 8 to 10 hour1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months time frame. Also, the model assumes that HPCS and RCIC are initially lined up to the Condensate Storage Tank (CST) and will switch to the suppression pool after the CST is exhausted. HPCS and RCIC are susceptible to common cause failure due to clogging of the Emergency Core Cooling System (ECCS) suction strainer. No changes are necessary.

This disposition remains applicable to the PRA used for the SAMA analysis.

6. Observation 97 (Element TH-8)

"MAAP indicates that HCTL at 1000 psig (-120°F) is reached in 2 to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . 185°F is reached in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . Both of these are reached before the 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months assumed battery life is exhausted in the SBO analysis. The requirement to maintain RCIC for 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months would appear to be compromised by this assumption. The ability to reach 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months does not appear to be justified."

Observation 97 Disposition The HCTL will allow operation of RCIC until the suppression pool temperature approaches 200 to 210°F. Based on MAAP analysis, this temperature will occur in approximately 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months which is the battery life during SBa scenarios. Therefore, no change to the model is required.

See the disposition to Observation 81.a which indicates that the success criteria in the PRA used for the SAMA analysis is "RCIC operation for 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months under SBO conditions". Therefore, this disposition remains applicable to the PRA used for the SAMA analysis.

Response 19 As mentioned in response to RAI 1.a, the PRA Maintenance and Update procedure describes the process for maintaining the PRA models current with the as-built and as-operated plants. It describes the MeR database used to track plant changes, procedure revisions, nuclear licensing revisions, and model improvements that impact the PRA models.

to GNRO-2012/00072 Page 10 of 36 This procedure is in place for PRA model maintenance in order to ensure that the model remains current with the as-built, as-operated plant and to ensure that industry standards, experience, and technology are appropriately incorporated into the models.

This procedure gives specific instructions for identifying model change requests, documenting those requests, and incorporating those requests into the PRA model.

The PRA analysts performing model updates are experienced, trained professionals and each change is reviewed by a second, experienced, trained PRA analyst. In addition, as described in ER Section E.1 .4.5, expert panel reviews are used to enhance the technical quality of the PRA updates. Changes from the expert panel review for an update are immediately incorporated into that update of the model.

Finally, the methods used for the GGNS PRA updates have been applied to other Entergy PRA models (Arkansas Nuclear One (ANO)-1 , ANO-2, Waterford 3, and River Bend Station). Each of those sites has undergone a successful RG 1.200 peer review.

Therefore, the GGNS PRA models are of sufficient technical quality for use in the SAMA analysis.

Response 1h The table on page E.1-70 titled "Contribution to CDF Changes in PRA Models" is part of the PRA model revision history section and lists the percentage contribution of the initiators from the level 1 internal events model. Table E.1-1 provides the contributions of the major initiators for the level 2 model that was utilized for the SAMA analysis.

The percentages are based on two separate models, one is a level 1 model and one is a level 2 model. As described in the response to RAI 1.e, differences are to be expected between the initiator contributions.

Request

2. Provide the following information relative to the Level 2 analysis:

a. Provide a brief history of the Level 2 Probabilistic Safety Assessment and key modeling changes that may have influenced the release category frequencies. Identify steps taken to assure technical adequacy.

b. Section E.2.2.6 provides a summary of how a value for each release-to-environment mass fraction was obtained from the representative Modular Accident Analysis Program (MAAP) calculation per Containment Event Tree (CET) sequence. Table E.1-8 results of the CET quantification and identifies total annual release frequency per Level 2 release category. Provide further information on:

i. Criteria used for assignment of release categories to each CET endpoint ii. Process to determine the representative sequence for quantifying the release fractions for each release category iii. How the weighting of release fractions discussed on page E.1-54 affects the evaluation of benefit for potential SAMAs.

c. Identify and describe the representative sequences for each release category. If the representative sequence for each release category is the one with the highest frequency but is not the one with the highest source term, justify this selection for determining the to GNRO-2012/00072 Page 11 of 36 benefit of potential SAMAs, particularly for impacts to the sequences with higher source terms that may be greater than the impact to the representative sequence.

d. Section E.1.2 defines release category (RC) based on the magnitude of Csi (Cesium iodide) release with High (H) being> 10% , Medium (M) being between 1% and 10 %,

etc. The release fractions given in Table E.1-9 are not necessarily consistent with these definitions. For example, the RC High/Early (H/E) frequency is given as the LERF yet the Cs release fraction is less than 10% . Provide the rationale for the release fraction selection and discuss its impact on the validity of the SAMA benefit analysis.

e. Figure E.1-1 indicates that negligible releases (NCE or NCF for no containment failure) account for 44% of the total CDF. Identify the CET end states that comprise this release category and how the frequency for this release category was determined.

f. In Table E.1-9 (Sheet 1 of 2), some release timings do not agree with the Release Mode timing categories. For example, the start of release minus the warning time is 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months for Release Mode Medium/Early (M/E), but the timing for an early (E) release is defined to be less than 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The start of release minus the warning time is 12 minutes for Release Modes Low/Intermediate (UI) and Low-Low/Intermediate (LUI), but the timing for an intermediate (I) release is defined to be between 4 and 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Discuss the reasons for this lack of agreement, including the plant damage states and CET end states that contribute to these Release Modes, and the impact on the SAMA assessment.

g. Table E.1-9 (Sheet 2 of 2) does not include source terms for the NCF release category, and it is not included in the consequence analysis. For this category, Table E.1-5 indicates a release fraction of 0 for cesium iodide and describes it as negligible. With a frequency for NCF many times higher than the other categories, design basis leakage without containment failure might lead to atmospheric releases similar to or even higher than those given for Low-Low/Early (LUE) and Low-Low/Intermediate (LUI) release categories in Table E.1-9. Provide further support for exclusion of the NCF release category from the consequence analysis and confirm that design basis leakage is considered in developing the source terms for the LUE and LUI release categories.

h. At the time of the Grand Gulf extended power uprate submittal, there was a peer review comment related to failure to model vacuum breakers, low suppression pool level, and personnel hatch seal, which had not been addressed in the Level 2 model. Provide the resolution status of this peer review comment. If not treated in the current Level 2 model for license renewal, justify the current modeling with respect to this issue and describe its impact on the SAMA assessment.

Response 2a As indicated in the response to RAI1.f, following Revision 2 of the Level 1 update, a decision was made to develop a Large Early Release Frequency (LERF) model rather than update the IPE Level 2 model. The LERF model was developed using the methods described in NUREG/CR-6595, Rev. 1, An Approach for Estimating the Frequencies of Various Containment Failure Modes and Bypass Events, and is directly linked to the Revision 2 internal events model. The LERF model was completed and issued in December 2003 and was updated along with the Level 1 model in the R3 and EPU revisions of the model.

to GNRO-2012/00072 Page 12 of 36 The steps to ensure the technical adequacy of the Level 2 model are the same as those for the Level 1 model described in the response to RAI 1.g. In other words, the PRA analysts performing model updates are experienced, trained professionals and each change is reviewed by a second, experienced, trained PRA analyst. In addition, expert panel reviews are used to enhance the technical quality of the PRA updates and changes from the expert panel review for an update are immediately incorporated into that update of the model.

Prior to the SAMA analysis, a new Level 2 model was created to derive the radionuclide release categories and frequencies that characterize the severe accident spectrum.

This Level 2 analysis consists of the following.

Characterization of containment capability under severe accident challenges

Detailed containment event trees (CETs)

Quantification of the functional nodes using system logic and phenomena associated with severe accident progression

Quantification of accident sequences from initiating event in Level 1 through radionuclide release and explicit treatment of dependencies

Binning of accident sequence release frequencies based on timing and magnitude The new Level 2 model may also be used for the determination of those accident sequences with the potential for radionuclide releases that are both large and early, leading to the Large Early Release Frequency (LERF).

The following tasks were undertaken to create the new Level 2 model.

Restructuring the old LERF event trees to add the following nodes.

- SI: Debris Cooling

- HR: Containment Heat Removal Via Residual Heat Removal (RHR)

- VC: Containment Heat Removal Via Vent

- SP: Suppression Pool Bypass

- CZ: Drywell Intact

- WW: Wetwell Airspace Breach

- CSS: Containment Spray Operates

Updating the EOPs and severe accident guidelines (SAGs) used in the HRA to the latest version

Direct linking of the Level 1 accident sequences to the Level 2 to allow explicit accounting of dependencies by the CAFTA code calculation

Modifying the end states to include radionuclide release end states other than LERF (High/Early)

Incorporating plant specific MAAP 4.0.6 radionuclide release calculations for the EPU configuration

Incorporating the Grand Gulf emergency action levels, evacuation estimates, and MAAP 4.0.6 accident sequence timing into the definition of LERF Technical adequacy was assured by taking the following steps.

to GNRO-2012/00072 Page 13 of 36

The developing contractor performed a self-assessment of the Level 2 model against the American Society of Mechanical Engineering (ASME)/American Nuclear Society (ANS) PRA Standard implemented in accordance with R.G.

1.200 to provide assurance that the LERF calculation and the associated processes are of Capability Category II, such that there is high confidence in the quality of the Level 2 PRA.

A technical acceptance review was performed by Entergy with comments resolved by the contractor.

An expert panel review of the Level 2 cutsets was performed as further assurance of the quality of the Level 2 PRA. The expert panel consisted of members of the Grand Gulf engineering, PRA and operations departments.

Response 2b

i. The spectrum of possible radionuclide release scenarios is represented by a discrete set of categories or bins which represent a group of severe accidents that have similar characteristics.

The release categories are defined based on two parameters: timing and severity.

Timing and magnitude of the release for each sequence is based on MAAP 4.0.6 calculations of the sequence chronology. The classification of release magnitude is also based on MAAP 4.0.6 calculations. The inputs for determining the plant specific characteristics of the radionuclide release bins are the plant model, the MAAP 4.0.6 plant specific calculations, the Emergency Plan, e.g., the Emergency Action Levels (EALs), the magnitude of releases that can contribute to public health effects, and the evacuation timing.

The assignment of timing to the release bins is dependent on both the Level 1 accident sequence and the status of the CET functional events. Combining the results of the MAAP calculations, the EALs, and the evacuation leads to the assessment of the timing of the General Emergency (GE) declaration relative to the radionuclide release timing. This evaluation is used to characterize "early" radionuclide releases as any release initiated less than four (4) hours following the declaration of a General Emergency.

Each of the accident sequence classes from the Levell can have a strong influence on the timing of a release. For example, treatment of ATWS events generally leads to the assertion that the radionuclide release will be initiated relatively early in the accident sequence. Level 2 effects can also modify the timing determination. Using these dependencies, the radionuclide release categories at the end of every sequence can be defined.

The rules for assigning release magnitude categories are described below.

There are several fundamental variables; level 1 accident sequence, initial containment failure mode, Reactor Pressure Vessel (RPV) pressure at RPV breach, water availability, and auxiliary building effectiveness. An evaluation of these variables, to a large degree, determines the release magnitude.

There are energetic failures of the containment drywell at approximately the time of RPV failure. It is assumed based on a spectrum of MAAP analyses that a sufficient fraction of Csi is airborne to result in the ejection of a large Csi release.

Therefore, sequences involving CZ functional node failures are ranked as high (H) release categories.

to GNRO-2012/00072 Page 14 of 36 Containment isolation failure is treated conservatively in the assignment of radionuclide release end states, sequences are assigned a moderate (M) release in the case of isolation failure even though the failures could be relatively small, the failures could be from the wetwell airspace, and the failures could be into closed or filtered systems (e.g., Standby Gas Treatment System (SGTS)). Nevertheless, the large failure to isolate that bypasses the auxiliary building is assumed to lead to a high release.

Containment isolation failure has a varying potential for release depending on the status of the containment sprays.

Events during which the containment flood contingency is successfully implemented and completed are determined by MAAP calculations to be sufficiently well represented by other severe accident sequences such that they do not require separate characterization in the CETs. With effective mitigation by debris cooling the release is classified as low.

Scenarios involving wetwell airspace failure or wetwell vent (with no other containment failures) are treated as scrubbed releases when there is no suppression pool bypass (this includes adequate subcooled water above the horizontal vents), and are assigned a severity class of low-low (LL). (Non-LERF).

Suppression pool bypass is modeled in two ways in the CET; first, as a method of potential containment challenge during blowdown (CX node) and second, it is modeled as either a leakage failure (e.g., the vacuum breaker in the wetwell to drywell interface) or as the horizontal vents become uncovered that allows some radionuclides to bypass the suppression pool. The impact of bypassing the suppression pool is modeled as an increase of a factor of 10 in the radionuclide release using GGNS specific analyses for guidance.

Containment sprays, RPV injection post RPV breach, or containment flooding are all effective mitigation measures to reduce or eliminate containment failures.

These mitigation measures are explicitly included in the Level 2 PRA. Their effects on the source term have been quantified using the MAAP code.

It is also necessary to estimate the source term for severe accidents for which the containment remains substantially intact. Estimates of source terms by members of Nuclear Regulatory Commission staff indicate that for scenarios where the containment remains intact, but leaking at its maximum technical specification leakage rate, that the escape fraction of Csi would be 2E-4 for the initial one hour of the release. Therefore, with no reactor building filtration or holdup effectiveness, the leakage escape fraction could translate into a release fraction of 0.0048 to the environment over 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months (Le., the low (L) category). If the reactor building remains effective in removing some of the radionuclides through condensation, inertial deposition, or gravitational settling, then the release fraction is estimated to be between .0001 and .001, Le., the low-low (LL) category. Additionally, if SGTS is operational, a very small Csi release is expected. This leads to a non-LERF determination for cases with containment intact.

The enclosure building effectiveness is not credited in the quantified model.

The wetwell water space failures are assumed to occur at a location that results in loss of sufficient water to create a direct bypass of the suppression pool for all releases from the RPV after RPV breach. This is assumed to result in a release path that is similar to an unmitigated release failure path.

to GNRO-2012/00072 Page 15 of 36 ii. The predominant accident class (based on frequency) that contributes to each of the radionuclide release categories was identified. Once the accident class was identified, the timings and magnitudes of the releases from the results of the various Level 2 MAAP runs for that accident class were reviewed to select an appropriate sequence to represent the release category.

iii. The discussion about weighting of release fractions discussed on page E.1-54 was intended to provide further explanation of how the representative sequences for determining the release fractions were selected. No actual weighting or summing of the sequence release data was performed.

As described above, accident classes that contribute to each of the radionuclide release categories were weighed to determine the predominant accident classes.

Then, from the predominant accident class, a MAAP sequence that best represents the timing and release characteristics of the bin was selected to represent the release category. The timing and magnitude data from this representative MAAP sequence was then directly used in the Level 3 analysis.

Response 2c As described below, a MAAP run from the predominant release category was selected for the consequence analysis for each release category. With the exception of the MAAP run selected for the HIE release category (see below), the representative sequence has a source term release within, or greater than, the release severity range specified for the release category in ER Table E.1-5.

The MAAP run selected for the HIE release category is from the predominant release category, but does not meet the > 10% Csi severity level specified for high releases in ER Table E.1-5. The response to RAI 2.d discusses this further and justifies this selection.

Release category HIE Predominant accident class is IBE, accident sequences involving a station blackout and loss of coolant inventory makeup. (Class IBE is defined as "Early" Station Blackout events with core damage at less than 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .)

MAAP run 10# GG1 0503 - SBO with containment isolation failure, no injection, 5 SRVs at TAF, no suppression pool cooling (SPC) or containment spray, no igniters, and no upper pool dump.

Release category H/I Predominant accident class is IIIC, accident sequences initiated or resulting in medium or large LOCAs for which the reactor is at low pressure and no effective injection is available.

MAAP Run 10# GG10516 - Large LOCA with containment isolation successful, no injection, no SRVs, no SPC or containment sprays, igniters initially on, and no upper pool dump.

Release category HIL Predominant accident class is 10, accident sequences involving a loss of coolant inventory makeup in which reactor pressure has been successfully reduced to 200 psi.

MAAP Run 10# GG10505 - Loss of makeup at low pressure with containment isolation successful, no injection, 7 SRVs at TAF, no SPC or containment spray, no igniters, and with upper pool dump.

to GNRO-2012/00072 Page 16 of 36 Release category M/E Predominant accident class is II, accident sequences involving loss of containment heat removal.

MAAP Run 10# GG10510 - Loss of offsite power with containment isolation successful, MSIVs closed, Low Pressure Core Spray (LPCS) available, 7 SRVs at HCTL or TAF, no SPC or containment sprays, no igniters, and no upper pool dump.

Release category Mil Predominant accident class is IIIC, accident sequences initiated or resulting in medium or large LOCAs for which the reactor is at low pressure and no effective injection is available.

MAAP Run 10# GG105161G - Large LOCA with containment isolation successful, no injection, no SRVs, no SPC or containment sprays, igniter failure, and no upper pool dump.

Release category MIL Predominant accident class is 10, accident sequences involving a loss of coolant inventory makeup in which reactor pressure has been successfully reduced to 200 psi.

MAAP Run 10# GG10506 - Loss of makeup at low pressure with containment isolation successful, no injection, 7 SRVs at TAF, no SPC or containment spray, igniters available, and with upper pool dump.

Release category UE Predominant accident class is IV, accident sequences involving failure of adequate shutdown reactivity.

MAAP Run 10# GG10517 - ATWS event with standby liquid control failure, feedwater available, high pressure injection available, 2 SRVs at HCTL or TAF, SPC at 95°F suppression pool temperature, no containment sprays, no igniters, and with upper pool dump.

Release category UI Predominant accident class is lA, accident sequences involving loss of inventory makeup in which the reactor pressure remains high.

MAAP Run 10# GG10501C - Loss of makeup at high pressure with containment isolation failure, no injection, no SRVs, no SPC or containment spray, igniters on at 11.9% H2 , and with upper pool dump.

Release category UL Predominant accident class is IBE, accident sequences involving a station blackout and loss of coolant inventory makeup. (Class IBE is defined as "Early" Station Blackout events with core damage at less than 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .)

MAAP Run 10# GG1 0504 - SBO with containment isolation successful, no injection, 5 SRVs at TAF, no SPC or containment spray, no igniters, and no upper pool dump.

Release category LUE Predominant accident class is lA, accident sequences involving loss of inventory makeup in which the reactor pressure remains high.

MAAP Run ID# GG10502D - Loss of makeup at high pressure with containment isolation successful, low pressure injection available, no SRVs, no SPC, with to GNRO-2012/00072 Page 17 of 36 containment sprays and RHR heat exchangers available, no igniters, and with upper pool dump.

Release category LUI Predominant accident class is lA, accident sequences involving loss of inventory makeup in which the reactor pressure remains high.

MAAP Run 10# GG10500F - Loss of makeup at high pressure with containment isolation successful, low pressure injection successful, no SRVs, with suppression pool cooling and RHR heat exchangers available, no containment sprays, igniters initiated at TAF, and with upper pool dump.

Release category LUL Predominant accident class is lA, accident sequences involving loss of inventory makeup in which the reactor pressure remains high.

MAAP Run 10# GG10502A - Loss of makeup at high pressure with containment isolation successful, no injection, no SRVs, no SPC, with containment sprays and RHR heat exchangers available, no igniters, and no upper pool dump.

Response 2d As stated in ER Section E.1.2.2.7, "input to the Level 3 GGNS model from the Level 2 model is a combination of radionuclide release fractions, timing of radionuclide releases, and frequencies at which the releases occur." This combination of information is used in the selection of input to the Level 3 analysis shown in Table E.1-9.

The predominant accident class for the HIE release category is class IBE, followed by accident classes 10 and lAo Because the IBE accident class is the predominant accident class for the release category, a representative accident sequence was chosen from the IBE accident class. This accident sequence, GG10503, reflects an early SBO with loss of coolant inventory and represents the earliest possible release within the accident class.

While this MAAP run represents the predominant accident class IBE, the release fractions are consistent with an M/E release scenario due to the Csl fraction of 2%.

However, as part of the evaluation and binning of the scenarios in the Level 2 analysis, MAAP case GG10503 was increased from a medium release scenario (as defined by an IB with failure of containment isolation) to a high release scenario. This increase to a high release was due to the failure of the drywell which had not been previously accounted for in the nodal analysis. This increase is consistent with the energetic combined failure of both the containment and drywell used to alter the release magnitude categories of these sequences using the rules from Appendix 0.4 of the Level 2 calculation. Thus, the accident sequence GG10503 was conservatively assigned to release category HIE.

An alternate MAAP case from a non-dominant accident class, but with larger radioactive releases was evaluated as a sensitivity to assess the impact of the HIE selection. Table 0.3-0 of the Level 2 calculation suggests using MAAP Run 10# GG10500 to represent the HIE category. A description of GG10500 and its source term information are provided below. The sensitivity case using GG 10500 resulted in no change in the cost-beneficial status of SAMAs.

MAAP run 10# GG10500 - SBO with containment isolation initially successful, no injection, no SRVs, no suppression pool cooling (SPC) or containment spray, no igniters, and with upper pool dump.

to GNRO-2012/00072 Page 18 of 36 general emergency declaration 0.75 hr warning time 1264.28 sec energy release 7.50E+05 W elevation of release 32m release start 93600 sec release end 259200 sec release duration 165600 sec NG release fraction 1.00E+00 I release fraction 1.78E-01 Cs release fraction 1.13E-01 Te release fraction 1.82E-01 Sr release fraction 4.23E-06 Ru release fraction 7.33E-07 La release fraction 2.26E-07 Ce release fraction 4.66E-06 Sa release fraction 3.79E-06 Response 2e The Figure E.1-1 label for negligible releases contains a typographical error. NCE should be identified as NCF. See change to ER figure E.1-1 below with strikethrough for deletions and underline for additions.

Negligible (NCeE) 8.73E-07 44%

The CET endstates labeled "OK" are those that make up the NCF release category, which is defined as a radiological release that is less than or equal to the containment design base leakage, or no containment failure.

The frequency for this release category was determined by quantifying the "OK" gate in the CAFTA fault tree which consists of all the CET endstates labeled "OK".

Response 2f Table E.1-9 contains the specific MAAP Level 2 information used in the MACCS2 code analysis. The release timings shown in Table E.1-9 are obtained from the MAAP results as follows.

'Warning Time (sec)" reflects the time from the start of the accident to core uncovery.

"Release Start (sec)" reflects the time from the start of the accident to containment failure or to exceed core temp> 1800 of in cases with containment isolation failures.

The release timing classifications in Table E.1-5 reflect the time from the declaration of a general emergency to the start of the release and pertain to the release category bin to GNRO-2012/00072 Page 19 of 36 assignments. The general emergency declaration time (from the start of the accident) for each release category is provided below.

Time to Declaration of Release Category General Emeraencv (hrs)

HIL 0.75 HIE 0.75 HII 0.50 M/E 18.50 Mil 0.50 MIL 0.75 UE 0.58 UI 0.75 UL 0.50 LUE 0.75 LUI 0.75 LUL 0.75 As detailed in ER Section E.1.2.2.6, the binning of each CET sequence into the release categories is provided in the level 2 analysis using inferred timing from both the Level 1 and Level 2 analyses. For the examples cited in the question, a discussion of the timing for the selected MAAP run as it pertains to the timing criteria from Table E.1-5 is provided below.

Release category (CET endstate) M/E, predominant plant damage state 11-Class II sequences are long-term loss of containment heat removal sequences with the Reactor Coolant System (RCS) intact so the time to core damage and release is longer than for other release categories (-19.8 hrs). Although a general emergency could be declared in Class" sequences when the containment design pressure is exceeded regardless of RCS integrity or fuel condition, Class" sequences are conservatively assumed to result in declaration of a general emergency when the core temperature exceeds 1800 of (-18.5 hrs).

The difference between this and the time of release is 1.3 hrs which is consistent with the early release definition of < 4 hrs from the time of declaration of a general emergency.

Release category (CET endstate) UI, predominant plant damage state IA - Class IA scenarios involve loss of inventory makeup at high pressure and may have unsuccessful containment isolation allowing for earlier releases. It is conservative to use a MAAP case with early release timing for an intermediate release category.

Release category (CET endstate) LUI, predominant plant damage state IA-Class IA scenarios involve loss of inventory makeup at high pressure and may have unsuccessful containment isolation allowing for earlier releases. It is conservative to use a MAAP case with early release timing for an intermediate release category.

More information on the binning of sequences into release modes is provided in the responses to RAls 2.b and 2.c. A conservative approach was applied to the timing evaluation in the SAMA analysis.

to GNRO-2012/00072 Page 20 of 36 Response 2q The NCF release category, defined as a radiological release that is less than or equal to the containment design basis leakage, was excluded from the SAMA analysis by the assumption that it had a negligible impact on the consequence analysis. This design basis leakage was not included in the LUE and LUI release categories.

To confirm the assumption that the NCF category contribution is negligible, a sensitivity analysis was conducted to determine the increase in offsite consequences from including this contribution.

MAAP run GG10502D is an intact accident scenario with radionuclide releases consistent with design leakage rates. This MAAP scenario was selected to represent the LUE release category in the consequence analysis. Since the Csi release fraction for severe accidents in which the containment remains substantially intact would fall into the low-low (LL) category, MAAP case GG10502D was used in the NCF sensitivity evaluation. A description of MAAP run GG10502D may be found in the response to RAI 2.c and the source term information is the same as that for category LUE in ER Table E.1-9.

The impact of including an NCF release category was evaluated by adding the source term for MAAP scenario GG10502D, as the 13th release category in the MACCS2 analysis, with a frequency of 8.73E-07/year. The addition of the NCF release category resulted in a 0.07% increase in the PDR and a 0.03% increase in the OECR. This increased the maximum benefit from $74,673 to. $74,684.

Therefore the impact of the NCF release category is negligible to the consequence analysis and introduced no new cost beneficial SAMAs.

Response 2h This peer review comment has been resolved in the Level 2 model used for the SAMA analysis. Failure of the vacuum breakers is modeled in CET node CZ (drywell remains intact) and node SP (no suppression pool bypass). Low suppression pool level is also modeled in CET node SP.

In the Level 2 model used for the SAMA analysis, hatch seal failures due to high temperatures were negligible when compared with hatch failures due to either overpressurization or buckling (equipment hatch). Thus, hatch seals were not assessed as potential failure locations. Addition of this failure mode to the model would not impact the SAMA assessment.

Therefore, vacuum breaker failures, low suppression pool level and personnel hatch seal failures were appropriately considered in the Level 2 model used for the SAMA analysis.

Request

3. Provide the following information with regard to the treatment and inclusion of external events in the SAMA analysis:

a. Section E.1.3.2 states that Table E.1-1 0 presents the results of the current GGNS Individual Plant Examinations for External Events (IPEEE) fire analysis. Explain what is meant by "current" as it relates to IPEEE. If the IPEEE analysis has been revised or new fire analyses performed, describe the revision and present its results.

to GNRO-2012100072 Page 21 of 36

b. Section 4.21.5.4 indicates that seismic risk is negligible in the estimation of external events multiplier. The August 2010 report, "Generic Issue 199 (GI-199), entitled Implications of Updated Probabilistic Seismic Hazard Estimates in Central and Eastern United States on Existing Plants, shows a decrease in the GGNS seismic CDF when the 2008 United States Geological Survey (USGS) seismic hazards curve is used compared to the seismic CDF resulting from the 1994 Lawrence Livermore National Laboratory hazard curves but an increase compared to the seismic CDF based on the Electric Power Research Institute (EPRI) hazard curves. For the simplified approach to estimate the CDF from a seismic margins analysis using the latest published USGS seismic hazards information, GGNS seismic CDF may be about or slightly less than 10-5/year.

Discuss the impact of the aforementioned considerations on the SAMA analysis.

c. Section 3.2.1 discusses conservatisms in the GGNS IPEEE fire analysis. Recent research and guidance reported in NUREG/CR-6850, specifically in the areas of hot short probabilities, fire ignition frequencies, and non-suppression probabilities, indicate that the fire analysis methodologies utilized for the Individual Plant Examinations (IPEs) may underestimate fire risk. Provide assurance that consideration of this information is not expected to impact the selection of cost beneficial SAMAs for GGNS. Discuss the impact on the evaluation of potential SAMAs for fire risk contributors in addition to the use of the external events multiplier.

d. For SAMAs 240-244, Table E.2-1 states:

liThe IPEEE showed the risk from external flooding at GGNS is minor. Thus this potential modification is assumed not to be cost beneficial, which follows the same assumption in the NRC safety evaluation report. II The GGNS IPEEE (p. 116) includes the following:

"Applying the new criteria, the bulk of the precipitation would occur over a shorter time frame, and markedly higher rainfall intensities would result. As a result, the GGNS site is not expected to be completely protected against external flooding without making some site modifications. Evaluation reveals that the following site drainage/flood protection improvements would allow for adequate protection of the site against external flooding due to the revised criteria. However, they are not necessarily the only combination of potential changes for consideration.

Given the small probability of occurrence for the PUTP, as described in the preceding paragraph, the relative cost and benefit for potential improvements will be considered prior to implementation of any physical improvements. II While the staff review of the IPEEE as documented in the IPEEE SER did not require implementation of the items listed as SAMAs 240-244, this alone does not imply that they should be eliminated from further consideration. In light of the second sentence from the GGNS IPEEE above, provide a discussion of the cost benefit analysis concerning external flood modifications and its influence on conclusions of the SAMA analysis.

Response 38 Table E.1-10 presents the results of the GGNS IPEEE fire analysis, which are current because they have not been superseded.

to GNRO-2012/00072 Page 22 of 36 A partially updated fire analysis was performed using Revision 2 of the internal events model and crediting additional equipment for safe shutdown following a fire. The original IPEEE fire modeling and control room analysis were not changed. This update resulted in lower CDF values for the analyzed compartments but was not used to develop the external events multiplier for SAMA.

Thus, conservatism was added to the SAMA analysis by using the IPEEE fire results to develop the external events multiplier.

Response 3b As discussed in ER Section 4.21.5.4, a multiplier of 11 was used on the averted cost estimates for internal events to represent the SAMA benefits from both internal and external events. This multiplier was selected based on the available external events information for fire, seismic and other. Specifically, the IPEEE showed that

high winds, floods, and other external events contribute less than 1E-06 per year,

seismic events are not dominant contributors to external event risk, and

the sum of the unscreened fire zone CDF values is approximately 8.92E-06 per year, while the sum of the screened and unscreened fire zone CDF values is approximately 2.74E-05 per year.

Section 3.1.2.4 of NEI 05-01, Rev. A indicates that a plant that used the seismic margins assessment (SMA) method for the IPEEE may select a multiplier based on the sum of the unscreened fire zone CDF and may even use a reduction factor on the baseline fire results to account for conservatisms in that analysis.

For GGNS, the sum of the unscreened fire zone CDF values is approximately 8.92E-06 per year, which results in a multiplier of 5 when compared to the internal events CDF. In addition, a partially updated fire analysis resulted in lower CDF values for the analyzed compartments (see response to RAI 3.a), supporting use of a smaller multiplier.

Nevertheless, to ensure a bounding analysis, an external events multiplier of 11 was used in the SAMA analysis.

If the GGNS seismic CDF was assumed to be 1E-05 based on the simplified estimate of CDF using the latest published United States Geological Survey (USGS) seismic hazards information, adding that to the sum of the unscreened fire zone CDF values would result in an external CDF of 1.89E-05 per year and a multiplier of 10.

Therefore, the external events multiplier of 11 used in the SAMA analysis more than compensates for a postulated increase in seismic CDF due to the latest published USGS seismic hazards information.

Response 3c The RAI indicates that NUREG/CR-6850 indicates the fire analysis methodologies utilized for the Individual Plant Examinations (IPEs) may underestimate fire risk.

However, we believe that use of NUREG/CR-6850 methods may result in an overestimate of the fire risk. See Roadmap for Attaining Realism in Fire PRAs, NEI, December 2010 at ADAMS ML110210990 which concludes, "Based on the results and insights from industry fire PRAs, it has been identified that the methods described in NUREG/CR-6850/EPRI TR-1011989 contain excess conservatisms that bias the results and skew insights. While the prior FAQ process made some incremental progress in addressing areas of excessive conservativism, many more remain in need of to GNRO-2012100072 Page 23 of 36 enhancement." Thus, we do not believe that the results of the initial NUREG/CR-6850 analyses should be used to draw conclusions about the IPEEE fire risk estimates.

Nevertheless, the SAMA analysis includes conservatisms that compensate for the fact that the IPEEE fire risk estimate contains uncertainty and could be an underestimate.

Most notably, as discussed in the response to RAI 3.b, a conservative external events multiplier of 11 was used in the SAMA analysis. This multiplier is more than double what would have been calculated using the sum of the unscreened fire zone CDF values from the IPEEE. In addition, GGNS is a newer, more spacious plant with better cable separation than older plants and the partially updated fire analysis mentioned in the response to RAI 3.a resulted in lower CDF values for the analyzed compartments.

Therefore, this multiplier is judged to adequately compensate for the impact of any lack of conservatism indicated by NUREG/CR-6850.

Two potential SAMAs were evaluated to address fire risk contributors. The conclusion that these SAMAs are not cost-beneficial is also expected to be unaffected by NUREG/CR-6850 information.

1. SAMA 54, to add automatic fire suppression systems to the dominant fire zones was evaluated via analysis Case 38 which is described in more detail below. The bounding analysis in Case 38 indicates that removing all CDF (9.37E-7/yr) from the division 1 switchgear room fires would result in a benefit of about $102,000. This SAMA was estimated to cost at least $375,000 to implement.

This analysis case is very conservative because it assumes that improving the reliability of the critical switchgear room suppression system would remove all CDF contribution from fires in the critical switchgear room. Also, it uses the sum of the unscreened and screened fire area CDF values from the IPEEE. Given these conservatisms and the large margin between the benefit and implementation cost, consideration of NUREG/CR-6850 information is not expected to change the conclusion for this SAMA.

Analysis Case 38 This analysis case (adding automatic fire suppression systems to the critical switchgear rooms) is an external events SAMA, which would not mitigate internal event risk. Many of the switchgear rooms have automatic CO 2 suppression systems. The Div I switchgear room in the control building that is a large contributor in the IPEEE is compartment CC202, which has a partial automatic sprinkler system. This SAMA would improve the reliability and effectiveness of that system. A bounding analysis was performed by assuming the SAMA would eliminate the contribution to fire CDF from fires in the critical switchgear room CC202. Since the total fire CDF is 2.74E-05/yr and the critical switchgear room fire CDF is 9.37E-07/yr, fires in the critical switchgear rooms contribute 3.420/0 of the total fire CDF.

The internal events model cannot be used to assess the benefit from this external event SAMA. However, the consequences resulting from fire-induced core damage and internal event-induced core damage would be comparable.

Since we have already estimated the maximum benefit from removing all internal event risk, the maximum benefit of removing all fire risk was estimated by reducing the maximum internal event benefit by the ratio of the total fire CDF to the internal event CDF. Since this SAMA analysis case would eliminate 3.42% of the total fire risk, the benefit for this SAMA analysis case was estimated to be 3.420/0 of the total fire benefit as shown below.

to GNRO-2012/00072 Page 24 of 36 Given, Maximum internal benefit is $74,673 Total fire CDF (including screened zones) = 2.74E-05/rx-yr Internal events CDF = 2.05E-06/rx-yr Maximum fire benefit = Maximum internal benefit x Total fire CDF/lnternal events CDF Maximum fire benefit = $74,673 x (2.74E-05/2.05E-06)= $997,559 SAMA case 38 benefit = 3.420/0 x (Maximum fire benefit) = 0.0342 x $997,559 SAMA case 38 benefit =$34,115 Applying the uncertainty factor of 3, SAMA case 38 benefit with uncertainty = $34,115 x 3 = $102,345

2. SAMA 55, to upgrade the alternate shutdown system panel to include additional controls for the opposite division was evaluated via analysis Case 39. The bounding analysis in Case 39 indicates that removing all CDF from control room fires (3.85E-6/yr) would result in a benefit of about $421,000. This SAMA was estimated to cost at least $786,991 to implement.

In analysis case 39, a bounding analysis similar to case 38 was performed by assuming the SAMA would eliminate the contribution to fire CDF from fires in the control room (compartment CC502). Since the total fire CDF is 2.74E-05/yr and the control room fire CDF is 3.85E-06/yr, fires in the control room contribute 14.05% of the total fire CDF.

This analysis case is also very conservative because it assumes that upgrading the alternate shutdown system (ASDS) panel would remove all CDF contribution from fires in the control room. Also, it uses the sum of the unscreened and screened fire area CDF values from the IPEEE. Given these conservatisms and the large margin between the benefit and implementation cost, consideration of NUREG/CR-6850 information is not expected to change the conclusion for this SAMA.

In conclusion, consideration of the research and guidance reported in NUREG/CR-6850 is not expected to impact the selection of cost-beneficial SAMAs for GGNS.

Response 3d The external flood modifications recommended in the IPEEE were not considered further in the SAMA analysis because the IPEEE was conducted in 1995 and many changes to the site have taken place since that time. For example, a mechanical-draft cooling tower was added to supplement the existing natural draft cooling tower. The old Bechtel administration building was removed. Also, security-related changes were made following the September 11, 2001 destruction of the World Trade Center, including installation of vehicle barriers, guard houses, chain-link fences, and jersey barriers (to prohibit intruder access). These changes have impacted the topography and drainage characteristics of the site.

Also, the site was re-evaluated during the 2011 Mississippi River flood and was determined to be adequately protected against external flooding. During a three month period of inspection (3/28/11 - 6/27/11) NRC resident and region inspectors performed a review of the flooding procedures and site actions for seasonal extreme flooding of the Mississippi River. As part of this evaluation, the inspectors checked for obstructions that could prevent draining, checked that the roofs did not contain obvious loose items that could clog drains in the event of heavy precipitation, and determined that barriers to GNRO-2012/00072 Page 25 of 36 required to mitigate flooding were in place and operable. Additionally, the inspectors performed an inspection of the protected area to identify any modifications to the site that would inhibit site drainage or that would allow ingress past a barrier during a probable maximum precipitation event. No recommendations for improved flood protection were identified. Thus, the specific changes recommended in the IPEEE are no longer recommended to improve flood protection.

In addition, the following calculation shows that modifications similar to those in SAMAs 240-244 are not potentially cost-beneficial.

The maximum benefit from internal events, with a CDF of 2.05E-06/rx-yr is $74,673 and the probability of inundation of the GGNS site reported in the IPEEE is only 2.1 E-08/rx-yr. Thus, the maximum benefit that could be realized from these improvements is $765

($2,295 with the uncertainty multiplier) and each individual SAMA would not eliminate 100% of the total external flooding risk. Since site drawings and documentation would have to be updated to reflect each modification, the implementation cost for each proposed external flood SAMA would exceed the potential benefit. Therefore, external flood SAMAs 240 through 244 are not potentially cost-beneficial and the SAMA analysis conclusions are unchanged.

Request

4. Provide the following information relative to the Level 3 analysis:

a. In Section E.1.5.2.1, it was stated that "Louisiana and Mississippi state tourism data was used to calculate a transient to permanent population ratio to increase each county's projected population to account for visitors." Clarify how transient population was used in the SAMA analysis.

b. Section E.1.5.2.6 indicated meteorological data from 2009 were selected for the analysis because they resulted in the highest release quantities. Describe the source of precipitation data, modeling of precipitation events, and precipitation influence on calculated doses. Quantify the amount of missing meteorological data, which were estimated using data substitution.

c. Table E.1-12 lists radionuclides in the GGNS core and provides the core inventory for each radionuclide. Table E.1-9 presents release fraction groups used in the Level 3 analysis for calculating radiological doses. Confirm that all radionuclides in the core inventory were used in the radiological dose calculations or explain any differences.

d. Indicate if any changes in future fuel management practices or fuel design are planned or being considered that would change the core inventory presented in Section E.1.5.2.8.

Response 48 The websites for the state tourism agencies were accessed to obtain the most recent tourist (transient) information. The latest available tourist information for Louisiana was 2008 data, while 2009 data was the latest available for Mississippi. Fine geographical-level tourism data (e.g. tourist per year per county) is not collected by states for the area within the 50-mile radius of GGNS. Louisiana and Mississippi collect these data at the state level only.

to GNRO-2012/00072 Page 26 of 36 To calculate the annual visitor days, the reported annual visitor numbers were multiplied by the average stay values. The annual visitor days was then divided by 365 to calculate the transient population in person days. A ratio of the transient population over the permanent population was calculated to produce the transient/permanent ratio.

Assuming an even distribution of transients across each state the transient/permanent ratio is the same for each county or parish in each respective state. The transient/permanent ratio was assumed to be constant with time because it is an economic value proportional to population changes. The transient/permanent ratios were multiplied by the permanent population of the county or parish for 2044 to produce the estimated transient population for the county or parish. For the SAMA analysis, the transient population for the 50-mile region was summed with the permanent population.

Response 4b The primary meteorological system was the data source for the precipitation data. The GGNS raw meteorological data files provided hourly precipitation values in the format X.XX inches. These values were converted to the MACCS2 input format by multiplying each value by 100 to provide precipitation in hundredths of an inch. For example, an hourly precipitation value of 1.05 inches was converted to 105 hundredths of an inch.

Zero precipitation was assumed if a data hour was missing precipitation data; this provides conservative results from the MACCS2 model.

The modeling of precipitation events is governed by the boundary weather conditions specified below.

Boundary Weather Conditions:

Boundary Weather Mixing Layer Height:

M2BNDMXH001 = 862.5 m (based on GGNSMET2009.inp)

Boundary Weather Stability Class Index:

M21BDSTB001 = 4 (neutral, D-Stability) (based on GGNSMET2009.inp)

Boundary Weather Wind Speed:

M2BNDWND001 =2 mls (based on GGNSMET2009.inp)

Number of Rain Distance Intervals for Binning (modeling choice):

M4NRNINT001 =5 Endpoints of Rain Distance Intervals for Binning (modeling choice):

M4RNDSTS001 = 8.05 16.10 32.21 48.31 80.52 km Number of Rain Intensity Breakpoints (modeling choice):

M4NRINTN001 = 2 Rain Intensity Breakpoints for Weather Binning (modeling choice):

M4RNRATE001 = 99.9,100. mmlhr Number of Samples per Bin (modeling choice):

M4NSMPLS001 =8 The selection of meteorological data from 2009 was performed by running MACCS2 with the meteorological input file for each year 2005 through 2009 and calculating the total population dose and offsite economic cost. Thus, the precipitation influence on calculated doses was not determined, but the total annual meteorological input on calculated doses was determined.

Of the 8,760 consecutive hourly meteorological input data records in the 2009 data set, 95 hours0.0011 days 0.0264 hours 1.570767e-4 weeks 3.61475e-5 months were missing lower wind data, 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months was missing precipitation data, and 131 hours0.00152 days 0.0364 hours 2.166005e-4 weeks 4.98455e-5 months were missing temperature difference data. This means that less than 3% of the records required some form of data substitution.

to GNRO-2012/00072 Page 27 of 36 Specifically, the 2009 data set had the following missing data blocks.

Month 1 Day 3 Time 15:00 through Month 1 Day 7 Time 13:00 (95 hours0.0011 days 0.0264 hours 1.570767e-4 weeks 3.61475e-5 months ).

Ninety-five hours of lower wind direction data were missing. The upper wind direction data were used to substitute for the lower wind direction data.

Month 6 Day 29 Time 14:00 (1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months ). One hour of precipitation data was missing. To be conservative, zero was used to substitute the missing precipitation values.

The following hours had missing temperature difference data. Data from Jackson Airport National Weather Service was used as a substitute (NCDC 2005-2009).

Month 2 Day 13 Time 17:00 through Month 2 Day 14 Time 12:00 (20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months ).

Month 3 Day 13 Time 17:00 through Month 3 Day 15 Time 8:00 (40 hours4.62963e-4 days 0.0111 hours 6.613757e-5 weeks 1.522e-5 months ).

Month 3 Day 16 Time 1:00 through Month 3 Day 16 Time 15:00 (15 hours1.736111e-4 days 0.00417 hours 2.480159e-5 weeks 5.7075e-6 months ).

Month 5 Day 11 Time 23:00 through Month 5 Day 12 Time 11 :00 (13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months ).

Month 10 Day 4 Time 23:00 through Month 10 Day 5 Time 15:00 (17 hours1.967593e-4 days 0.00472 hours 2.810847e-5 weeks 6.4685e-6 months ).

Month 12 Day 10 Time 10:00 through Month 12 Day 10 Time 12:00 (3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months ).

Month 12 Day 15 Time 0:00 through Month 12 Day 15 Time 9:00 (10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months ).

Month 12 Day 31 Time 3:00 through Month 12 Day 31 Time 13:00 (11 hours1.273148e-4 days 0.00306 hours 1.818783e-5 weeks 4.1855e-6 months ).

Response 4c All of the nuclides contained in the core inventory, shown in environmental report Table E.1-12, are included in the Level 3 analysis. All of the nuclides are in the MACCS2 input file and correspond to parameters CORINV001 through CORINV060. Each of the nuclides is grouped into one of nine MACCS2 nuclide groups as designated by the parameters ISOTPGRP001 through ISOTPGRP060. The nine nuclide groups, shown in Table E.1-9, are called NG (Xe/Kr), I, Cs, Te, Sr, Ru, La, Ce and Sa.

Response 4d As indicated in the environmental report, the core fission product inventory given in Table E.1-12 is from calculations supporting the extended power uprate to 115% (4408 MWt) of the original licensed thermal power. This fission product inventory also considers the extension to 24 month refueling cycles. No additional changes in fuel management practices or fuel design are planned or being considered that would impact the core fission product inventory.

Request

5. Provide the following information with regard to the selection and screening of Phase I SAMA candidates:

a. Provide the complete Phase I candidate SAMA list as described in Section E.2.1, SAMA List Com pilation.

b. Describe basic event 821-FO-HEDEP2-1, "0 perator fails to manually depressurize vessel with non-ADS valves, given in Table E.1-2. Comment on the potential for II improvements in procedures and training to reduce this event.

to GNRO-2012100072 Page 28 of 36

c. A number of basic events in Table E.1-2 fail the High Pressure Core Spray (HPCS) or the Reactor Core Isolation Cooling (RCIC) and have relatively high RRWs in particular those involving HPCS valves, E22 F004 and E22 F012-C, and the RCIC steam supply valves. In all but one case, the potential SAMAs cited for these basic events involve costly major modifications. Describe the above cited valves and considerations of lower cost alternatives for reducing the impact of these HPCS or RCIC failures.

d. Basic events N21-FO-HEPCS-G, "Human error: Failure to properly align the PCS for injection," NRC-FO-FWSACT, "Failure to align FPW for long term injection," and P53-FOHECOOLlAS, "0perator fails to align SSWB to lAS compressor upon loss of TBCW," have high failure probabilities (1.0, 0.57, and 1.0, respectively). Discuss the potential for improved procedures and training (or possibly staging necessary equipment) to reduce these failure probabilities.

Response 5a The complete Phase I candidate SAMA list is included in Attachment 2 to this letter Response 5b Table E.1-2 shows a failure probability of 1.0 for this event, but this does not mean that this action is never successful. Rather, a failure probability of 3.2E-04 is applied to cutsets containing B21-FO-HEDEP2-1 via event NRS-DEP-SHORT in the recovery rule file. Therefore, these two events represent the same failure. The RRW values for B21-FO-HEDEP2-1 and NRS-DEP-SHORT in Table E.1-2 are not the same because some cutsets containing B21-FO-HEDEP2-1 are recovered by events like NRS-PCS-DEP and NRS-PCSL8&DEP which account for dependencies between B21-FO-HEDEP2-1 and other manual actions.

The action represented by B21-FO-HEDEP2-1 and NRS-DEP-SHORT involves manual depressurization with SRVs as directed by the EOPs. Emergency depressurization is directed on RPV water level below -192 inches, on unsafe heat capacity temperature limit, on containment temperature above 185°F, on drywell temperature above 330°F, on unsafe pressure suppression pressure, and on suppression pool level below 14.56 feet or above 24.4 feet. This operator action is based on depressurization due to low RPV water level for a transient event.

The failure probability is based on the cause-based analysis, not on timing, but the EOP steps for emergency depressurization are already graphically distinct. The steps are branch points that send the EOP user to a different procedure step and are colored and shaped differently than other EOP steps. The operators are trained on emergency depressurization as part of regular simulator training.

Thus, improvements in procedures or training would not noticeably reduce the probability of this event.

Response 5c Valve 1E22F004 is the isolation valve in the HPCS line to the reactor vessel. It is a 12" Anchor Darling gate valve with a Limitorque motor operator.

Valve 1E22F012-C is the isolation valve in the HPCS minimum flow line to the suppression pool. It is a 4" Anchor Darling gate valve with a Limitorque motor operator.

Valves E51 F063 and E51 F064 are the inboard and outboard steam supply valves to the RelC turbine. They are William Powell 10" gate valves with Limitorque motor operators.

to GNRO-2012/00072 Page 29 of 36 Consideration has been given to lower cost alternatives to reduce the impact of these HPCS and RCIC failures. All 144 SAMAs from NEI 05-01 Rev. A, Table 13 were considered SAMA candidates in Phase I. In addition, all of the cost beneficial SAMAs from several BWR SAMA analyses were considered SAMA candidates in Phase I, including those from James A. FitzPatrick Nuclear Power Plant, Vermont Yankee Nuclear Power Station, Pilgrim Nuclear Power Station, Oyster Creek Nuclear Generating Station, Monticello Nuclear Generating Plant, Brunswick Steam Electric Plant, Units 1 and 2, Duane Arnold Energy Center, Susquehanna Steam Electric Station, and Cooper Nuclear Station.

Phase I SAMA 85, which is already installed, evaluated developing guidance to allow local, manual control for RCIC operation. In addition a number of other Phase I SAMAs evaluated improvements for other methods of core cooling.

Response 5d As described below, procedures and training are already in place for these actions and appropriate equipment is staged. Further procedure improvement, training, or staging would not reduce the failure probabilities.

N21-FO-HEPCS-G Table E.1-2 shows a failure probability of 1.0 for N21-FO-HEPCS-G, but as with B21-FO-HEDEP2-1 in the response to RAI 5.b, this does not mean that this action is never successful.

A failure probability of 8.3E-04 is applied to cutsets containing N21-FO-HEPCS-G via event NRS-FO-FDWRINJ in the recovery rule file. The RRW values for N21-FO-HEPCS-G and NRS-FO-FDWRINJ are not the same because some cutsets containing N21-FO-HEPCS-G are recovered by events like NRS-PCS&DEP and NRS-PCS&CS which account for dependencies with other manual actions.

The action represented by N21-FO-HEPCS-G and NRS-FO-FDWRINJ is to reduce feedwater flow to the reactor by tripping one of the two feedwater pumps and controlling RPV level until the startup level control system is placed in service as directed by the EOPs. The operators are trained to trip one of the feedwater pumps and control RPV level as part of regular simulator training. This action is taken in the control room and staged equipment is not needed. Thus, improvements in procedure, training, or staging would not noticeably reduce the failure probability for this event.

NRC-FO-FWSACT Table E.1-2 shows a failure probability of 0.57 for NRC-FO-FWSACT. This recovery event is applied to cutsets containing basic event P64-FO-HE-G in short-term SBO sequences (diesel fails to continue to run). In longer SBO sequences, recovery event NRC-FO-FWS8HR with a failure probability of 0.011 is applied to cutsets containing basic event P64-FO-HE-G.

The action represented by these events is to align the Fire Protection Water system for injection per EOP Attachment 26. EOP Attachment 26 provides eight pathways to align Fire Protection Water into the RPV. All eight paths are needed to provide sufficient injection to the RPV to prevent a late core melt.

The procedure indicates that all actions are taken on the same elevation of the auxiliary building and that the necessary tools and components are available nearby. Operators are trained on this EOP action via simulated walk-throughs. Thus, improvements in to GNRO-2012/00072 Page 30 of 36 procedure, training, or staging would not noticeably reduce the failure probability for this event.

P53-FO-HECOOLIAS Table E.1-2 shows a failure probability of 1.0 for P53-FO-HECOOLlAS, but as with B21-FO-HEDEP2-1 in the response to RAI 5.b, this does not mean that this action is never successful.

A failure probability of 2.2E-04 is applied to cutsets containing P53-FO-HECOOLIAS via event NRS-FO-SSWIA in the recovery rule file. The RRW values for P53-FO-HECOOLIAS and NRS-FO-SSWIA in Table E.1-2 are essentially the same. P53-FO-HECOOLIAS is not included in any combination recoveries, but a few cutsets containing this event may have a different recovery applied by the rule file, resulting in the small difference between the two RRW values.

The action represented by P53-FO-HECOOLIAS and NRS-FO-SSWIA is to manually align SSW to cool the instrument air and service air compressors following a loss of TBCW. The operators would start SSW train B and open the crosstie valves to TBCW.

The action is directed by the EOPs and SSW system operating instructions. The operators are trained in this action as part of regular simulator training. This action is taken mostly in the control room and staged equipment is not needed. Thus, improvements in procedure, training, or staging would not noticeably reduce the failure probability for this event.

Request

6. Provide the following information with regard to the Phase II cost-benefit evaluations:

a. For many potential SAMAs, cost is taken from the Cooper Nuclear Station or other SAMA analyses. Although this may be valid for some potential SAMAs such as adding major systems/components, its validity is less certain for modifications to plant electrical or other systems for which the GGNS design may differ from the referenced plant (e.g.,

SAMA Numbers 4,6,26,34,47,54, and 55). Discuss steps taken to assure that the cited cost estimates are either valid for GGNS or underestimate the anticipated cost at GGNS.

b. Provide the release category frequencies for each Phase II SAMA.

c. The descriptions for Case 6, Reduce Loss of Off-Site Power During Severe Weather, and Case 10, Reduce Plant-Centered Loss of Off-Site Power, indicate that LOSP initiating event frequencies were multiplied by 19/24 and 9/24 to account for severe weather and plant-centered causes of LOSP, respectively. This appears to imply that severe weather caused 5 of a total of 24 LOSP events while plant centered failures caused 15 of 24 LOSP events. Provide the basis for these values.

d. SAMA Number 14 {Provide a portable EDG [Emergency Diesel Generator] fuel oil transfer pump} was evaluated by Case 8 to eliminate failure of EDGs to run. The list of basic events set to zero does not include P81-FR-DG-G13-C, "DG13 fails to run."

Considering values of RRW, inclusion of this basic event might increase the CDF reduction to 5% and could make this potential SAMA cost beneficial. Discuss why DG13 was not included in the assessment, including its impact on the SAMA analysis.

to GNRO-2012/00072 Page 31 of 36

e. Explain how eliminating failure of hydrogen igniters in Case 32 leads to a 15.90/0 reduction in CDF.

f. The description for Case 41, Trip/Shutdown Risk, indicates that certain initiating event frequencies were reduced by 10%. Table E.2-2 states they were reduced by a factor of

2. Confirm the amount of reduction.

g. With reference to the final paragraph of Section 4.21.5 of the ER, describe briefly the GGNS corrective action process incorporating the condition reports which have been initiated to implement the potentially cost-beneficial SAMAs.

Response 68 Engineering judgment by project engineers familiar with the costs of modifications at Entergy plants was used to determine if the cited cost estimates from Cooper Nuclear Station (CNS) or other SAMA analyses were valid for GGNS. If the project engineers' rough conceptual estimate of the modification was larger than the other plant's estimate, the other plant's estimate was adopted without further detailed cost analysis.

Some contributing factors to the higher rough estimates include the fact that GGNS is a spacious plant compared to many of the plants from which estimates were obtained, meaning that lengths of pipes and cable runs are longer, thus costing more. Also, many of the CNS estimates were actually from other plants and were, therefore, estimated several years ago. The method and charges used today to obtain capital money make most modifications more costly.

Therefore, the cited cost estimates (including those for SAMAs 4,6,26,34,47,54, and

55) underestimate the anticipated cost at GGNS.

Response 6b The release category frequencies for each analysis case are included in Attachment 3 to this letter. Environmental report Table E.2-2 indicates the Phase II SAMA(s) associated with each analysis case.

Response 6c There are twenty-four LOSP events from 1996 to August 2006, from the references below that are applicable to the GGNS at-power model (EPRI category IV events were excluded for the at-power model). Five of those events were weather related, while fifteen of them were plant- or switchyard-related failures, and four were grid-related failures. The classification of these events is based on the methods described in NUREG/CR-6890 (see below) and is consistent with the LOSP references given below.

Analysis Case 10, Reduce Plant-Centered Loss of Off-Site Power, conservatively removes the contribution from switchyard-related failures in addition to plant-centered failures because the LOSP data does not discriminate between plant and switchyard transformer failures. Since SAMA 18 is not cost beneficial with this conservative benefit estimate, the exact number of plant-centered transformer failures was not determined.

LOSP event references -

1. SECY-2001-0133, July 2001 , "Status Report on Study of Risk-I nformed Changes to the Technical Requirements of 10 CFR Part 50 (Option 3) and Recommendations on Risk-Informed Changes to 10 CFR 50.46 (ECCS Acceptance Criteria)."

to GNRO-2012/00072 Page 32 of 36

2. NUREG/CR-6890, December 2005, "Reevaluation of Station Blackout Risk at Nuclear Power Plants."

3. EPRI TR-110398, April 1998, "Losses of Off-Site Power at U.S. Nuclear Power Plants - Through 1997," Final Report.

4. EPRI TR-1000158, July 2000, "Losses of Off-Site Power at U.S. Nuclear Plants-Through 1999," Final Report.

5. EPRI TR-1009889, April 2004, "Losses of Off-Site Power at U.S. Nuclear Plants

- Through 2003," Final Report.

6. EPRI TR-1 013239, March 2006, "Losses of Off-Site Power 2005," Final Report.

Response 6d DG13 was not included in the assessment because it does not have a common fuel oil transfer pump with DG1 and DG2. The purpose of the SAMA is to eliminate the common cause failure of the DG's due to the fuel oil transfer pump failure. Since the only diesels that have a common cause failure are the DG 1&2 class 1E diesels, and since the fraction of EDG fail-to-run events that is due to fuel transfer pump failures is less than 1, eliminating failure of those diesels to run conservatively bounds the impact of providing a portable backup fuel transfer pump for those diesels.

If DG 13 was included in the assessment, either two portable fuel transfer pumps would be needed, or the pump would have to be moved to fill the additional day tank. This would result in an implementation cost increase.

Therefore, inclusion of DG13 in this assessment would not change the analysis conclusion.

Response 6e Case 32 is a bounding analysis which sets the level 2 gate for failure of the hydrogen igniters to FALSE in the fault tree (gate E61-001). Setting this gate to FALSE effectively eliminates all cutsets that contain hydrogen ignition failure from the level 2 analysis.

Thus, although failure of the hydrogen igniters does not contribute to core damage, removal of these cutsets from the analysis changes the CDF remaining in the analysis.

Response 6f The description of Case 41, which indicates that certain initiating event frequencies were reduced by 10% , is correct. Table E.2-2 inadvertently contains wording from a draft analysis.

The assumption for analysis case 41 in Table E.2-2 of the ER is revised to read as follows. Deletions are shown with strikethrough and additions with underline.

Reducing all initiating events except pipe breaks, floods, and LOSP by a #astor 0#

a. 10%.

Response 69 The GGNS corrective action process is described in Section B.0.3 of the license renewal application.

"GGNS quality assurance (QA) procedures, review and approval processes, and administrative controls are implemented in accordance with the requirements of 10 CFR Part 50, Appendix B. Conditions adverse to quality, such as failures, to GNRO-2012/00072 Page 33 of 36 malfunctions, deviations, defective material and equipment, and nonconformances, are promptly identified and corrected. In the case of significant conditions adverse to quality, measures are implemented to ensure that the cause of the nonconformance is determined and that corrective action is taken to preclude recurrence. In addition, the root cause of the significant condition adverse to quality and the corrective action implemented are documented and reported to appropriate levels of management.

GGNS QA procedures, review and approval processes, and administrative controls are implemented in accordance with the requirements of 10 CFR Part 50, Appendix B. The GGNS Quality Assurance Program applies to GGNS safety-related structures and components. Corrective actions and administrative (document) control for both safety-related and nonsafetyrelated structures and components are accomplished in accordance with the established GGNS Corrective Action Program (CAP) and Document Control Program. The confirmation process is part of the CAP and includes the following:

Reviews to assure that corrective actions are adequate.

Tracking and reporting of open corrective actions.

Review of corrective action effectiveness.

Any follow-up inspection required by the confirmation process is documented in accordance with the CAP. 11 The condition description for CR-GGN-2011-07358 states the following.

liThe GGNS Severe Accident Mitigation Alternative (SAMA) analysis for License Renewal has identified three procedure changes which are potentially cost-beneficial enhancements for mitigating the consequences of a severe accident at GGNS.

The attached document provides more information about these three severe accident procedure enhancements which should be evaluated for implementation. The document describes the benefit of the enhancements in terms of decreased core damage frequency, decreased population dose risk, and decreased offsite economic cost risk that could be achieved by implementing each of the procedure changes. The SAMA analysis used conservative assumptions to determine these benefits using GGNS-specific PRA models.

It is recommended that GGNS Operations Department should review the attached document, evaluate the enhancements, and follow-up to implement the enhancements if it is agreed that they are desirable. It is recommended that the review and follow-up be performed via a condition report, which would allow assignment of actions as necessary to confirm the SAMA analysis benefit results, to determine the best method of implementation for each of the enhancements, and to revise the appropriate procedures. 11 Request

7. Provide the following information with regard to the sensitivity and uncertainty analyses:

As provided in Section E.1.1, an uncertainty multiplier of 3 was applied to the cost-benefit analysis for potential SAMAs as a conservative selection to account for differences in the th 95 -percentile CDF to the mean CDF. With uncertainty applied, Table E.2-2 indicates that to GNRO-2012/00072 Page 34 of 36 three potential SAMAs (Numbers 13, 14, and 63) are within $10,000 of the stated cost estimate. Comment on the representativeness of the stated cost estimates compared to actual costs at GGNS and provide estimates of cost margin for these potential SAMAs.

Response 7 SAMA 13 - Proceduralize battery charger high-voltage shutdown circuit inhibit This SAMA has a benefit of $40,793 and an implementation cost estimate of $50,000.

The implementation cost estimate is at the low end of the GGNS range for a procedure change with engineering or training required ($50k - $200k per ER Section E.2.3).

Therefore, the implementation cost is likely to be larger at GGNS. Therefore, the expected margin between the benefit and actual implementation cost estimates is greater than $10,000.

Also, the benefit was calculated by assuming that this procedure change would remove all core damage contribution from battery charger failure. The procedure change would direct the operators to disable the charger high-voltage trip circuit when the batteries have failed, allowing the chargers to continue to supply power. This procedure change could not possibly remove all core damage contribution from charger failure because the chargers will still have a random failure probability and the human action will also have a failure probability.

Since the estimated cost of implementation exceeds the benefit, SAMA 13 is not cost-beneficial.

SAMA 14 - Provide a portable EDG fuel oil transfer pump This SAMA has a benefit of $91,044 and an implementation cost estimate of $100,000.

The implementation cost estimate is at the low end of the range for hardware changes.

This modification would require piping changes to the safety-related diesel fuel oil system to permit hook-up of the portable pump. Therefore, the design and implementation of this modification would cost more than $200,000. Thus, the margin between the benefit and actual implementation cost estimates is greater than $10,000.

Since the estimated cost of implementation exceeds the benefit, SAMA 14 is not cost-beneficial.

SAMA 63. Add a redundant RCIC lube oil cooling path This SAMA has a benefit of $92,683 and an implementation cost estimate of $100,000.

The implementation cost estimate is at the low end of the range for hardware changes.

This modification would require piping changes to a safety-related system. Therefore, the design and implementation of this modification would cost more than $200,000.

Thus, the margin between the benefit and actual implementation cost estimates is greater than $10,000.

Since the estimated cost of implementation exceeds the benefit, SAMA 63 is not cost-beneficial.

Request

8. For certain SAMAs considered in the GGNS Environmental Report, there may be lower-cost alternatives that could achieve much of the risk reduction. In this regard, provide an evaluation of the following SAMAs:

a. Phase II SAMA Numbers 30, 32, and 33 for adding or enhancing Emergency Diesel Generator (EDG) HVAC hardware were considered for basic events involving EDG to GNRO-2012/00072 Page 35 of 36 HVAC failures. SAMA Numbers 30 and 33 involve expensive hardware modifications.

Evaluate the possibilities of opening doors and use of portable fans and ducts. SAMA Number 32 calls for adding diverse EDG HVAC logic. Consider procedures for operators to manually initiate EDG HVAC if the existing automatic logic fails. If no alarms are expected for any of these failures, procedures for the plant auxiliary operators to check on any automatic start of the EDG could allow HVAC failures to be discovered and might eliminate the need for alarms.

b. For SAMA Number 25 (Install a bypass switch to allow operators to bypass low reactor pressure interlock circuitry), consider providing directions to use jumpers to bypass the interlock.

c. For SAMA Number 35, consider the use of other air compressors (service air) that might be connected to the instrument air system instead of providing new compressors.

d. For Case 39 concerning control room fires, consider improving control room fire detection system response for a limited number of key cabinets.

Response 8a Phase I SAMAs 125, 126 and 127 were considered for procedure changes for operators to open doors or use portable fans and ducts following loss of EDG HVAC. It was postulated that these SAMAs would require a high temperature alarm as evaluated in Phase" SAMA 30.

However, as suggested in this RAI, the loss of AC power procedure does indicate that a running diesel generator should be periodically monitored locally. The EDG operating procedure indicates that an hourly check-sheet should be completed if the diesel is to run for more than one hour. Thus, an operator should be in the DG room once each hour and would be able to notice that the ventilation was not working. Thus, if the automatic start logic for the EDG HVAC system fails, it could be manually started. Or, if the EDG HVAC system fails, the doors could be opened or portable fans could be used.

The benefit with uncertainty for analysis case 22, which eliminates failure of cooling for the three diesel generator rooms, is $227,963. The GGNS range for a procedure change with engineering or training required is $50k - $200k per ER Section E.2. Since the cost of the procedure change is less than the potential benefit, a SAMA is retained to revise procedures to direct that the operator monitoring a running diesel ensure the ventilation system is running, or take action to open doors, or use portable fans.

A condition report to implement this potentially cost-beneficial SAMA has been initiated within the corrective action process.

Response 8b SAMA 25 was evaluated assuming that the new bypass switch would eliminate all possible ECCS permissive and interlock failures, resulting in a benefit with uncertainty of

$30,093.

Due to the logic, at least two interlocks would have to fail and require bypass to permit opening one train of low pressure injection valves (more if a common cause failure occurred) and at least four interlocks would have to be bypassed to permit opening both trains of valves. With this level of complexity, it is expected that human reliability analysis would show that an action to use jumpers to bypass the interlocks would fail to GNRO-2012/00072 Page 36 of 36 with a probability of 1.0. Since the benefit would not be realized, this SAMA would not be cost-beneficial.

Response 8e A modification has been performed to join the service air and instrument air systems.

Also, procedures exist to use two portable air compressors to supply instrument air if necessary (see Phase I SAMAs 133 and 134). Although they are not reflected in the model used for the SAMA analysis, these SAMAs have already been implemented.

Response 8d The control room underfloor area (containing cable) is protected by an automatic halon system which uses smoke detectors. The remainder of the control room has smoke detectors in every cabinet except P680, which is the console at which the operator sits.

Also, the control room is continuously occupied, which provides the capability of prompt detection and suppression as defined in NUREG/CR-6850. Although very early warning" or "incipienf' detection systems have been developed that can warn of impending fires, these systems do not provide a significant improvement in continuously manned areas such as the control room.

Thus, improving control room fire detection system response would not provide significant benefit and would not be cost-beneficial.

Attachment 2 to GNRO-2012100072 Phase I Candidate SAMA Analysis

Attachment 2 to GNRO-2012/00072 Page 1 of 81

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Phase I SAMATitle Source Result of Potential Screening Disposition Improvement SAMA Reference Enhancement Results Category 10 of SAMA number 1 Provide additional NE105-01 Extended direct Retain This SAMA would extend AC and DC DC battery capacity. [1] current (DC) power high pressure coolant power availability during a injection (HPCI) and reactor station blackout core isolation cooling (560). (RCIC) operability and allow more credit for alternating current (AC) power recovery.

The GGNS batteries are designed to provide an adequate amount of energy for all required emergency loads following the loss of AC power for four hours with Divisions I and II and for two hours with Division III.

2 Repiace lead-acid NE105-01 Extended DC power Retain This SAMA would extend ACand DC batteries with fuel [1] availability during an HPCI and RCIC operability power cells. 560. and allow more credit for AC power recoverv.

to GNRO-2012/00072 Page 2 of 81 3 I Add additional I NEI 05-01 I Improved availability I Retain The Engineered Safety AC and DC battery charger or [1] of DC power system. Features (ESF) DC power power portable, diesel- system is divided into three driven battery divisions: Div I, Div II and charger to existing Div III. Each division is a DC system. 125V DC system consisting of two battery chargers, a bank of batteries and appropriate distribution panels. For Div III, normally one charger supplies the loads. For Div I and Div II, two chargers normally supply the loads. This SAMA is being retained to add a new permanent charger.

4 I Improve DC bus load I NE105-01 I Extended DC power #3 - Plant DC load-shedding AC and DC shedding. [1] availability during an Already procedures are in place to power S80. installed increase the probability of successful load shed under S80 conditions.

5 I Provide DC bus NE105-01 Improved availability Retain The DC buses at GGNS do AC and DC cross-ties. [1 ] of DC power system. not contain cross-ties. power to GNRO-2012/00072 Page 3 of 81 Provide additional NE105-01 Increased availability #3 - The 120V AC essential AC and DC DC power to the [1 ] of the 120 V vital AC Already instrument power system power 120/240V vital AC bus. installed consists of redundant distribution panels fed through system.

transformers connected to separate ESF motor control centers.

The Unit 1 Class 1E 120V AC uninterruptible power system (UPS) is separated into four divisions with one inverter and one distribution panel assigned to each division. The class 1E UPS system consists of four class 1E inverters with four class 1E alternate sources.

The inverter is the normal source of power to the UPS distribution panel. Should the inverter develop trouble the static transfer switch will automatically transfer the load to the alternate source.

The 1201240V AC uninterruptible power system consists of six inverters for Unit 1. Normally, the non-Class 1E uninterruptible AC power system receives its power from an inverter static switch arrangement.

Due to this multiple redundancy, the probabilistic risk assessment (PRA) model does not require the UPS buses as a deoendencv.

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7 Add an autom atic NE105-01 Increased availability #3 - The 120V UPS contains an AC and DC feature to transfer [1 ] of the 120 V vital AC Already inverter static switch power the 120V vital AC bus. installed arrangement which bus from norm al to automatically transfers the standby power. load to the alternate source.

8 Increase training on NE105-01 Improved chances of #3 - 04-1-02-1 H13-P601 AC and DC response to loss of [1 ] successful response Already provides instructions for power two 120V AC buses to loss of two 120V installed actions to take if 120VAC which causes AC buses. logic A, B, C, or D power is inadvertent actuation lost. It references Off-signals. Normal procedures 05 02-111-2, Loss of one or both reactor protection system (RPS) buses and 05-1 111-5, Automatic Isolations.

GLP-OPS-R2100 provides training on loss of AC power.

to GNRO-2012/00072 Page 5 of 81 9 I Reduce DC NE105-01 Improved containment #2 - Similar The 125 VDC System I AC and DC dependence [1] depressurization and item is supplies power to the high power between high- high-pressure addressed pressure core spray pressure injection injection following DC under other (HPCS) initiation logic, system and ADS. failure. proposed valve position indication, SAMAs valve control logic and the HPCS pump breaker control power.

The 125 VDC System supplies power to the Div. I and Div. 2 automatic depressurization system (ADS)/safety relief valve (SRV) logic and SRV pilot solenoid valves.

Distribution panel 1DA1 provides power to Div. 1 and distribution panel 1DB1 provides power to Div. 2.

SAMAs 27 and 28 will analyze adding a portable generator to supply power to the DC system which will reduce the DC dependence between high-pressure core spray and ADS.

10 Provide an additional NE105-01 Increased availability Retain GGNS currently has two AC and DC diesel generator. [1 ] of on-site emergency emergency diesel power AC power. generators (EDGs) and one High Pressure Core Spray Diesel Generator.

to GNRO-2012/00072 Page 6 of 81

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11 Revise procedure to NE105-01 Extended diesel #3 - Many trips, including all AC and DC allow bypass of [1 ] generator operation. Already engine trips except engine power diesel generator installed overspeed and generator trips. differential, are automatically bypassed on emergency diesel generator (EDG) emergency start.

Off-Normal event procedure, Loss of AC Power provides guidance on bypassing diesel qenerator trips.

12 Improve 4.16-kV bus NE105-01 Increased availability Retain The 4160V system is highly AC and DC cross-tie ability. [1 ] of on-site AC power. diverse and reliable. Each power of the ESF buses has the capability of sharing the same ESF transformer feed. The division 3 DG 13 may be cross-tied to either division 1 bus 15AA or division 2 bus 16A8 during an S80. These instructions are contained in the GGNS Loss of AC Power Off-Normal Event Procedure 05-1-02-1-4.

See SAMA 33. This SAMA is being retained to increase the reliability of the cross-tie between division 3 to either division 1 or division 2.

13 Create AC power NE105-01 Increased availability #1 - N/A GGNS is a single unit site. AC and DC cross-tie capability [1 ] of on-site AC power. power with other unit (multi-unit site).

to GNRO-2012/00072 Page 7 of 81 14 Install an additional, NEI 05-01 I Reduced probability of I Retain The Grand Gulf to Port I AC and DC buried off-site power [1] loss of off-site power. Gibson 115 KV line does power source. not cross over or under any of the 500 KV offsite power supply lines, except on the east side of the 500 KV switchyard at Grand Gulf.

At this point the 115 KV line is installed underground so that a failure of the 500 KV line cannot cause a failure of the 115 KV power line.

Neither of the Grand Gulf 500 KV lines nor the Grand Gulf to Port Gibson 115 KV line are on any common towers or common right-of way.

15 Install a gas turbine NE105-01 Increased availability I Retain GGNS already has a AC and DC generator with [1 ] of on-site AC power. redundant and diverse power tornado protection. The use of gas fuel for emergency AC power a turbine generator system, with the three would provide EDGs, but has no gas diversity plus turbine generators.

additional redundancy.

16 Install tornado NE105-01 Increased availability I #1 - N/A GGNS does not have a gas AC and DC protection on gas [1 ] of on-site AC power. turbine generator. When power turbine generator. SAMA 15 is evaluated the tornado protection will also be evaluated.

to GNRO-2012/00072 Page 8 of 81

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/> . >..*****.i .*.*i ii . i>ii* ...*.*i> *.i>../ii *............ **>i. iii> i . . * > i i * ..> i i i i i . i i . i . * >i>*.*.i>>ii .. > >>J 17 Install a steam-driven NE105-01 Increased availability #1 - N/A See section AA.9.1 of AC and DC turbine generator [1 ] of on-site AC power. advanced boiling water power that uses reactor reactor (ABWR) severe steam and exhausts accident mitigation design to the suppression alternative (SAMDA) [28].

pool. SAMA would require excessive modifications that would not be feasible for an existing plant.

18 Improve NE105-01 Increased availability #3 - The PRA model does not AC and DC uninterruptible power [1 ] of power supplies Already require the UPS buses as a power supplies. supporting front-line installed dependency. See SAMA 6.

equipment.

19 Create a cross-tie for NE105-01 Increased diesel #1 - N/A GGNS is a single unit site. AC and DC diesel fuel oil (m ulti- [1 ] generator availability. power unit site).

20 Develop procedures NE105-01 Increased diesel #3 - The fuel oil storage tank AC and DC for replenishing [1 ] generator availability. Already has a capacity of 75,000 power diesel fuel oil. installed gallons, which is sufficient to operate the diesel generator for seven days while supplying post-loss of coolant accident (LOCA) maximum load demands.

The storage tank has an above ground fill connection with an in-line basket strainer to remove particles from the incoming fuel oil. The system operating procedure for the diesel generator (DG) system contains steps to refuel the DG fuel oil with a tanker and to transfer DG fuel oil from Div 3 to the Div 1 or 2 storaqe tanks.

to GNRO-2012/00072 Page 9 of 81

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21 Use fire water NE105-01 Increased diesel Retain Each EDG is cooled by its AC and DC system as a backup [1 ] generator availability. independent jacket water power source for diesel cooling system. The cooling. Standby Service Water System is the primary source of water for cooling the EDG jacket water.

22 Add a new backup NE105-01 Increased diesel Retain Each EDG is cooled by its AC and DC source of diesel [1 ] generator availability. independent jacket water power cooling. cooling system. The Standby Service Water System is the primary source of water for cooling the EDG jacket water.

See SAMA 21.

23 Develop procedures NE105-01 Increased probability #3 - No new procedure is AC and DC to repair or replace [1 ] of recovery from Already required. GGNS has power failed 4 KV breakers. failure of breakers that installed already implemented transfer 4.16 kV non- procedures to replace emergency buses 4160V breakers.

from unit station service transformers.

24 In training, NE105-01 Reduced human error #3 - Restoring power from AC and DC emphasize steps in [1 ] probability during off- Already offsite sources after SBO is power recovery of off-site site power recovery. installed proceduralized. Operators power after a SBO. at GGNS are trained to the Loss of AC Power off-normal event procedure.

25 Develop a severe NE105-01 Improved off-site #3 - GGNS has a procedure for AC and DC weather conditions [1 ] power recovery Already severe weather conditions power procedure. following external installed to reduce the impact on weather-related loss of off-site power.

events.

to GNRO-2012/00072 Page 10 of 81

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i <iii< i< .<. ****..* . . . < i.. i.* <ii ...........i 26 Bury off-site power NE105-01 Improved off-site #3 - The Grand Gulf to Port AC and DC lines. [1 ] power reliability during Already Gibson 115 KV line does power severe weather. installed not cross over or under any of the 500 KV offsite power supply lines, except on the east side of the 500 KV switchyard at Grand Gulf.

At this point the 115 KV line is installed underground so that a failure of the 500 KV line cannot cause a failure of the 115 KV power line.

Neither of the Grand Gulf 500 KV lines nor the Grand Gulf to Port Gibson 115 KV line are on any common towers or common right-of way.

27 Portable generator Brunswick Increased time Retain GGNS does not currently AC and DC for direct current [7] SAMA 1 available for AC utilize any portable DC power (DC) power: This power recovery. chargers in case of loss of SAMA involves the the normal plant chargers use of a portable or station blackout. This generator to supply SAMA is being retained to DC power to the add a portable generator to battery chargers feed the battery chargers.

during a station blackout.

28 Portable generator Brunswick Increased time Retain GGNS does not currently AC and DC for direct current [7] SAMA 1 available for AC utilize any portable DC power (DC) power: This power recovery. chargers in case of loss of SAMA involves the the normal plant chargers use of a portable or station blackout. This generator to supply SAMA is being retained to DC power to the add a portable generator to individual panels supply an individual panel during a station or bus.

blackout.

to GNRO-2012/00072 Page 11 of 81

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i i 29 Provide alternative Brunswick Increased time #2 - Similar See SAMA28. AC and DC feeds to panels [7] SAMA 1 available for AC item is power supplied only by DC power recovery addressed bus 2A-1: This under other SAMA involves the proposed installation of SAMAs alternate DC feeds, which may reduce plant risk through diversification of the power supplies.

30 Proceduralize battery Brunswick Extended DC power Retain GGNS does not have a AC and DC charger high-voltage [7] SAMA availability. procedure in place to power shutdown circuit 25 disable the charger high-inhibit: This SAMA voltage trip circuit when the involves disabling the batteries are disconnected charger high-voltage from the DC circuit.

trip circuit when the batteries are disconnected from the DC circuit, thereby preventing the trip and allowing the chargers to remain online.

31 Provide a portable Brunswick Extended diesel Retain GGNS has two diesel oil AC and DC EDG fuel oil transfer [7] SAMA generator operation. transfer pumps. Each power pump: This SAMA 29 transfer pum p can supply provides additional fuel from the dedicated means of supplying main storage tan k to the the EDG day tank in DGs day tank. Each DG the event a common has its own separate fuel oil cause failure system (including main prevents operation of tanks with fuel oil transfer the existing pumps. pump).

to GNRO-2012/00072 Page 12 of 81 Use DC generators Brunswick Improved recovery of Retain GGNS has three offsite power to provide power to [7] SAMA offsite power after sources; two 500 kV lines station batteries have (Franklin and Baxter Wilson operate the 34 substations) and one 115 kV switchyard power been depleted.

line (Port Gibson substation).

control breakers while a 480-V AC Two 125 volt batteries in the generator could 500 kV switchyard supply the supply the air control power for the 500 kV com pressors for breakers. Each battery has its breaker support. own charger with redundant AC power supplies. The 115 kV breaker control power comes from the plant balance-of-plant (BOP) DC batteries.

The AC power in the 500 kV switchyard is depicted in UFSAR Figure 8.2-4. There is a primary AC source and two backup sources. Two of the three AC sources are derived from separate ESF buses which can be fed from the diesel generator. The other supply originates from the 13.8 kV bus in the 115 kV switchyard.

The switch yard breakers are two generations of Mitsubishi SF6 breakers. Vendor manual 460004000 for the Mitsubishi breakers indicates that air pressure is used for opening the breakers, but spring force is used for closing the breakers.

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Yi*.. *.*. **Y*.****/Y . Y*.* . * * .* * .*. *.*. * * .* * .*.*. .*i.. **i*.. *.* * .*i* . . . . . . i 33 Proceduralize all Brunswick Improved availability #3 - The 4160V system is highly AC and DC potential 4-kV AC [7] SAMA 6 of 4-kV power system. Already diverse and reliable. Each power bus cross-tie actions. installed of the ESF buses has the capability of sharing the same ESF transformer feed. The Division 3 DG13 may be cross-tied to either division 1 bus 15AA or division 2 bus 16AB during an SBO. These instructions are contained in the GGNS Loss of AC Power off-normal event procedure 05-1-02-1-4.

34 Provide a diverse Brunswick Reduces the common Retain Each EDG has a dedicated AC and DC swing diesel [7] SAMA cause failure to start starting air system which power generator air start 16 term of EDG starting consists of a motor driven compressor. air compressors. air compressor and diesel driven air com pressor.

There is no cross-tie or swing compressor installed.

35 Provide alternate Brunswick Increased availability Retain Alternate feed breakers to AC and DC feeds to essential [7] SAMA of on-site AC power. essential loads are not power loads directly from an 18 installed.

alternate emergency bus.

36 Enhance DC power Monticello Increases time #2 - Similar See SAMA27 AC and DC availability by [6] SAMA 2 available for AC item is power providing a direct power recovery. addressed connection from the under other diesel generator, the proposed security diesel, or SAMAs another source to the 250 V battery chargers or other required loads.

to GNRO-2012/00072 Page 14 of 81

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37 Modify procedures Oyster Increased availability #3 - See SAMA 33. AC and DC and training to allow Creek [5] of on-site AC power. Already power operators to cross-tie SAMA 91 installed emergency AC Buses 1C and 1D under emergency conditions that require operation of critical equipment.

38 Provide portable DC Oyster Improved availability #2 - Similar See SAMA 28. AC and DC battery charger Creek [5] of DC power system. item is power capable of supplying SAMA addressed 125-V buses in order 109/125A under other to preserve isolation proposed condenser and SAMAs electromagnetic relief valve operability along with adequate instrumentation.

39 Increase combustion Oyster Increased availability #1 - N/A GGNS does not have a gas AC and DC turbine building Creek [5] of on-site AC power turbine generator. When power integrity to withstand SAMA 130 during severe SAMA 15 is evaluated the higher winds so that weather. tornado protection will also combustion turbines be evaluated.

would be capable of withstanding a severe weather event.

40 Modify procedures to Oyster Increased availability #1 - N/A GGNS does not have AC and DC allow switching of the Creek, [5] of on-site AC power. combustion turbines. power com bustion turbines SAMA 132.

to buses while running.

to GNRO-2012/00072 Page 15 of 81 i ...... *****i~/ ...** *.. _ ** a"A ..... ... . . < i i ....... i i i i **il

< ii // i<ii .......... i .... i < '._'<i . . . . i.* * * .*........** * *.*/* *. . .*.*. .*.*. ii*i.. . .*............*.i.*.. . . . . .*.. . .*.* .*. . *.* *. ****.. * *.* .i/**.*. .*.i..*. * .<.*. * . . . . . *..**.i............................. ****.ii.*.. *.* * *. *.*.*. < ii 41 Protect transformers Oyster Loss of off-site power Retain This SAMA will evaluate AC and DC from failure. Creek [5] (LOOP) frequency protecting the transformers power SAMA 138 increased by 1 x 10E- from explosive failure.

2 per year to Building a wall between the incorporate im pact of transformers is not feasible postulated because the structure transformer would need to be quite explosions. substantial and would interfere with normal access to equipment. Thus this SAMA will evaluate protecting the offsite supply circuitry by excavating a bus duct and relocating the associated cables.

42 Install key-locked Pilgrim [4] Increased availability #2 - Similar See SAMA 12. AC and DC control switches to SAMA 30 of on-site AC power. item is power enable AC bus addressed cross-ties and modify under other procedures to proposed enhance the SAMAs reliability of the AC power system.

43 Modify plant Pilgrim [4] Improved reliability of #1 - N/A See SAMA 5. The DC AC and DC procedures to use SAMA 34 DC power system. buses at GGNS do not power DC bus cross-ties to contain cross-ties.

enhance the reliability of the DC power system.

44 Provide redundant Pilgrim [4] This SAMA would Retain GGNS containment vent AC and DC power to the direct SAMA 56 improve the reliability valve line fails closed on a power torus vent valves. of the direct torus vent loss of one of the four (two valves and enhance 120VAC, two 125 VDC) the containment heat power supplies. Adding removal capability. redundant power supplies to each valve would increase the availability of the containment venting.

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45 Modify plant Pilgrim [4] This SAMA would #1 - N/A GGNS does not have a AC and DC procedures to allow SAMA 57 increase capability to hydroturbine fuel oil transfer power use of the diesel fire provide makeup to the pump.

pum p hydroturbine in fire pump day tank to the event that EDG A allow continued fails or fuel oil operation of the diesel transfer pump is fire pump, without unavailable. dependence on electrical power.

46 Modify plant Pilgrim [4] Com pletely elim inate #3 - See SAMA 33. AC and DC procedures to allow SAMA 58 loss of 4.16 kV bus A5 Already power alternately feeding events. Installed 81 loads via 83 when A5 is unavailable post-trip, and alternately feeding 82 loads via 84 when A6 is unavailable post-trip.

47 Use the security Pilgrim [4] Improved availability #1 - N/A GGNS does not have a AC and DC diesel generator to of DC power system. security diesel generator. power extend the life of the GGNS utilizes the non-1 E 125 VDC batteries. battery backup and the Div 1 and 2 diesel generators for back-up power for the security systems.

48 Use a portable diesel Vermont Improve DC power #2 - Similar See SAMA27. AC and DC generator to extend Yankee [3] reliability item is power the life of the 125 addressed VDC batteries. under other proposed SAMAs 49 Use a portable Vermont Improve DC power #2 - Similar See SAMA28. AC and DC generator to provide Yankee [3] reliability item is power power to individual addressed 125VDC MCCs upon under other loss of a DC bus. proposed SAMAs to GNRO-2012/00072 Page 17 of 81

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50 Provide additional Fitzpatrick SAMA would ensure #2 - Similar See SAMA 1. AC and DC DC battery capacity [2] SAMA longer battery item is power to ensure longer 26 capability during an addressed battery capability S80, which would under other during the station extend HPCI/RCIC proposed blackout event, operability and allow SAMAs which would extend more time for AC HPCIIRCIC power recovery.

operability and allow more time for AC power recovery.

51 Modify plant Fitzpatrick Extended DC power #2 - Similar See SAMA 1. AC and DC equipment to provide [2] SAMA availability during an item is power 16-hour S80 30 S80. addressed injection. under other proposed SAMAs 52 Modify plant Fitzpatrick Extended DC power #2 - Similar See SAMA 1. AC and DC equipment to extend [2] SAMA availability during an item is power DC power availability 36 S80. addressed in an S80 event. under other proposed SAMAs 53 Modify plant Fitzpatrick Increased time #1 - N/A There are no portable AC and DC procedures to allow [2] SAMA available for AC generators at GGNS that power use of a portable 61 power recovery. could supply the battery power supply for chargers. See SAMA 27, battery chargers which will evaluate obtaining a portable generator to power the battery chargers.

54 Use of a portable Fitzpatrick Improve DC power #2 - Similar See SAMA27. AC and DC generator to extend [2] reliability item is power the coping time in addressed loss of AC power under other events (to power proposed battery charQers). SAMAs to GNRO-2012/00072 Page 18 of 81

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55 Provide a portable (Cooper [33] Increased time #2 - Similar See SAMA 28. AC and DC generator to supply SAMA 14) available for AC item is power DC power to power recovery. addressed individual panels under other during a SSO, proposed increasing the time SAMAs available for AC power recovery.

56 Install minimal Susquehan Improved availability #2 - Similar See SAMA 12. AC and DC hardware changes na [32] of 4-kV power system. item is power and modify SAMA2a addressed procedures to under other provide crosstie proposed capability between SAMAs the 4 kV AC emergency buses.

57 Improve cross-tie Susquehan Improved availability #2 - Similar See SAMA 12. AC and DC capability between 4 na [32] of 4-kV power system. item is power kV AC emergency SAMA 2b addressed buses, i.e., between under other A or D emergency proposed buses and S or C SAMAs emergency buses (a more flexible crosstie option than SAMA 2a).

58 Modify portable Susquehan Improve DC power #1 - N/A GGNS does not have a AC and DC station diesel na [32] reliability portable station diesel power generator to SAMA5 generator.

automatically align to 125 V DC battery chargers.

to GNRO-20 12/00072 Page 19 of 81 Tabla 1 PhaltA I ~4U4 4nalvAi.

59 Procure an additional Susquehan Improve DC power I #2 - Similar See SAMA 27. AC and DC portable 480 V AC na [32] reliability item is power station diesel SAMA6 addressed generator to power under other battery chargers in proposed scenarios where AC SAMAs power is unavailable.

60 Install an NE105-01 Improved prevention Retain GGNS has multiple high Core cooling independent active [1 ] of core melt pressure injection sources: systems or passive high sequences. Condensate, HPCS, control pressure injection rod drive (CRD), and RCIC.

system.

61 Provide an additional NE105-01 Reduced frequency of #3 - At GGNS, HPCS (Division Core cooling high pressure [1 ] core melt from small Already 3) has its own independent systems injection pump with LOCA and SSO installed diesel generator.

independent diesel. sequences.

62 Raise HPCIIRCIC NE105-01 Increased HPCI and Retain The current RCIC back Core cooling backpressure trip set [1 ] RCIC availability pressure trip setpoint is 25 systems points. when high psig. This SAMA is being suppression pool retained to raise the RCIC temperature exists. backpressure trip set-points. HPCS does not utilize steam as a motive force.

63 Revise procedure to NE105-01 Extended RCIC #3 - Emergency/Severe Core cooling allow bypass of [1 ] operation. Already accident procedures systems RCIC turbine installed reference 05-S-01-EP-1 exhaust pressure (Emergency/Severe trip. Accident Procedure Support Documents) which contains guidance in attachments 1 and 3 to defeat RCIC interlocks.

Attachment 3 contains guidance which allows bypass of the turbine exhaust pressure trip.

to GNRO-2012/00072 Page 20 of 81

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64 Revise procedure to NE105-01 Extended HPCI and #3 - Emergency operating Core cooling allow intermittent [1 ] RCIC operation. Already procedure (EOP) flow systems operation of HPCI installed charts direct intermittent and RCIC. reactor pressure vessel (RPV) flooding as necessary due to plant conditions. This includes the use of HPCI and RCIC.

65 Revise procedure to NE105-01 Increased probability #3 - The EOPs allow the Core cooling control torus [1 ] that injection pumps Already operators to control the systems temperature, torus will be available to installed primary containment level, and primary inject coolant into the pressure, torus containment vessel. temperature, and torus pressure to increase level. Procedures contain available net positive limits which will increase suction head (NPSH) available net positive for injection pumps. suction head (NPSH) for injection pumps.

66 Revise procedure to NE105-01 Increased availability #3 - This operator action is Core cooling manually initiate [1 ] of HPCI and RCIC Already taken in response to systems HPCI and RCIC given auto initiation installed provide an alternate high given auto initiation signal failure. pressure injection capability failure. during small or medium LOCAs and transients.

GGNS EOPs assure initiation of those automatic actions important for controlling reactor coolant.

to GNRO-2012/00072 Page 21 of 81 67 I Modify automatic NEI 05-01 I Reduced frequency of I Retain The GGNS SRVs use a I Core cooling depressurization [1] high pressure core solenoid air valve to systems system com ponents damage sequences. operate a pneumatic to improve reliability. piston/cylinder and linkage assem bly to open the valve.

When operating in relief mode, two pilot solenoid valves, attached to each valve, are opened to supply air to each SRV pneumatic actuator. Energizing either pilot solenoid will admit air to the actuator and open the associated SRV. The pilot solenoid valves are powered from separate divisions of 125 VDC power. Accumulators for each ADS SRV contain sufficient air for two actuations if instrument air is unavailable. This SAMA is being retained to add larger accum ulators to the 8 ADS SRVs, thus increasing reliability durinQ SBOs.

68 I Add signals to open NE105-01 Reduced likelihood of I Retain GGNS has no signals to I Core cooling safety relief valves [1 ] SRV failure to open in open SRVs automatically in systems automatically in an a main steam isolation an MSIV closure transient.

MSIV closure valve (MSIV) closure transient. transient reduces the probability of a medium LOCA.

to GNRO-2012/00072 Page 22 of 81 i

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69 Revise procedure to NE105-01 Improved prevention #3 - This operator action is Core cooling allow manual [1 ] of core damage Already taken in response to systems initiation of during transients, installed depressurize the reactor to emergency small and medium allow the low pressure depressurization. LOCAs, and injection systems to provide anticipated transient coolant makeup to the without scram reactor pressure vessel (ATWS). during transients, small and medium LOCAs, and ATWS. This operator action has already been implemented at GGNS.

70 Revise procedure to NE105-01 Extended HPCI and #3 - EOPs allow operators to Core cooling allow operators to [1 ] RCIC operation. Already inhibit ADS. systems inhibit automatic installed vessel depressurization in non-ATWS scenarios.

71 Add a diverse low NE105-01 Improved injection Retain GGNS has diverse, multiple Core cooling pressure injection [1 ] capability. low pressure injection systems system. sources, including low pressure core spray (LPCS) and the low pressure coolant injection (LPCI) mode of residual heat removal (RHR).

72 Increase flow rate of NE105-01 Improved suppression #3 - The suppression pool Core cooling suppression pool [1 ] pool cooling. Already cooling mode operation of systems cooling. installed the RHR system is already sized to accommodate flow to remove all decay heat assumed for reactor shutdown.

to GNRO-2012/00072 Page 23 of 81 73 I Provide capability for NE105-01 Improved injection #3 - GGNS has two diesel I Core cooling alternate injection via [1] capability. Already driven 1500 gpm fire pumps systems diesel-driven fire installed that can be used for pump. alternate injection.

Emergency Procedure 05-S-01-EP-1, attachment 26 provides instructions for injection into the RPV with the fire protection water system.

74 Provide capability for NE105-01 Improved injection #3 - Step 3.4 of off-normal event I Core cooling alternate injection via [1 ] capability. Already procedure 05-1-02-111-1, systems reactor water installed Rev. 32, Inadequate Decay cleanup (RWCU). Heat Removal, indicates that procedure 04-1 G33-1, Reactor Water Cleanup, should be used for AWCU alternate shutdown cooling operation if RHR shutdown cooling and ADHAS capability has been completely lost.

Section 5.3 of 04-1-01-G33-1 provides instructions for using RWCU for reactor vessel cooling.

75 Revise procedure to NE105-01 Improved injection #3 - Use of CAD for vessel Core cooling align EDG and allow [1 ] capability. Already injection is covered in the systems use of essential CR0 installed existing EOPs. The normal for vessel injection. AC power to essential CRD equipment is from the onsite emergency power sources. On loss of offsite power the EDGs provide the required power for CRD injection.

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/1 76 Revise procedure to NE105-01 Improved injection #3 - The use of the condensate Core cooling allow use of [1 ] capability. Already pumps for injection is systems condensate pumps installed covered in the EOPs.

for injection. Condensate transfer is an alternate injection system using the condensate transfer pumps.

77 Revise procedure to NE105-01 Improved injection #3 - The use of the emergency Core cooling allow use of [1 ] capability. Already core cooling system systems suppression pool installed (ECCS) jockey pumps for jockey pum p for alternate injection is injection. covered in the EOPs.

78 Revise procedure to NE105-01 Regains the main #3 - Existing EOPs direct this Core cooling re-open MSIVs. [1 ] condenser as a heat Already including bypass of MSIV systems sink. installed isolation interlocks as necessary.

79 Improve ECCS NE105-01 Enhanced reliability of #3 - The suppression pool Core cooling suction strainers. [1 ] ECCS suction. Already suction strainer is designed systems installed to prevent passage of any particles larger than 0.1" into the RHR and RCIC pumps and subsequently into the reactor vessel. In response to NRC Bulletin 96-03, Potential Plugging of Emergency Core Cooling Suction Strainers by Debris in Boiling Water Reactors, a large passive strainer was installed for the ECCS and RCIC pumps.

80 Revise procedure to NE105-01 Improved injection in #1 - N/A 05-S-01-PSTG states that Core cooling align LPCI or core [1 ] loss of suppression NPSH will be available for systems spray to CST on loss pool cooling the ECCS pumps as long of suppression pool scenarios. as the suppression pool cooling. water level is above the suction strainers.

to GNRO-2012/00072 Page 25 of 81

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.<* *i .>i .* > i i i >< . .*. . * .> *. . i .* . . > .i> >> .i>.> i *..... >*. >iii*.*.*.* . i . >>>il 81 Remove LPCI loop NE105-01 Enables use of LPCI #1 - N/A The GGNS RHR system Core cooling select logic. [1 ] A loop for injection in does not have LPClioop systems the event of a B select logic.

injection path failure.

82 Replace two of the NE105-01 Reduced common #3 - HPCS is operated from Core cooling four electric safety [1 ] cause failure of the Already offsite power or the systems injection pumps with safety injection installed separate diesel power diesel-powered system. This SAMA supply, RCIC is steam pumps. was originally driven, and LPCI is electric intended for the driven. The injection pumps Westinghouse-CE are already diverse in System 80+, wh ich power and common cause has four trains of failures of the pumps are safety injection. not risk significant.

However, the intent of this SAMA is to provide diversity within the high- and low-pressure safety injection systems.

83 Install an inter-unit (Brunswick Improved prevention #1 - N/A GGNS is a single unit site. Core cooling CRD cross-tie as a [7] SAMA of core melt systems potential means of 13) sequences.

recovering from a loss of CRD at a Qiven unit.

84 Install a direct drive Monticello Improved prevention #3 - See SAMA 61. Core cooling diesel injection pump [6] SAMA 4 of core melt Already systems as additional high sequences. Installed pressure injection system.

to GNRO-20 12/00072 Page 26 of 81

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85 Develop guidance to Monticello Increased availability #3 - RCIC control is available in I Core cooling allow local, man ual [6] SAMA of RCIC given auto Already the Control Room and at systems control for RCIC 37 initiation signal failure. Installed the Remote Shutdown operation. Panel.
Attachment VI of the RCIC system operating procedure (04-1-01-E51-1) provides instructions for emergency RCIC manual start/shutdown which provides guidance to allow local, manual control of RCIC.
86 Dedicated alternate Monticello Improved injection #2 - Similar See SAMA 71. Core cooling low-pressure [6] SAMA 9 capability and item is systems injection/drywell containment heat addressed spray system removal. under other proposed SAMAs 87 Modify procedures Oyster Reduced operator #1 - N/A GGNS does not have Core cooling and training to Creek [5] error associated with isolation condensers, thus systems operate the isolation SAMA 99 operating isolation this SAMA is not applicable.
condensers with no condensers when DC support systems power is unavailable.
available.
88 Revise procedure to Oyster Reduced seal LOCA #3 - GGNS has a procedure to Core cooling provide direction for Creek [5] probability. Already trip recirc pum ps and systems cooldown following SAMA 106 installed reactor on a total loss of loss of reactor component cooling water building closed (CCW).
cooling water by reducing RPV pressure.
to GNRO-2012/00072 Page 27 of 81
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.... . . . . . . . . . . . . *.. i>>.>i.i.*i.)*******.*..*.>> . >i >iii i . i .*. >.ii i . . . i..i> ii 89 Modify procedures to Vermont Eliminate probability #2 - Similar Table 2 of GFIG-OPS- Core cooling allow operators to Yankee [3] of ECCS low pressure item is E1200 indicates that it's not systems defeat the low SAMA 65 permissives failing. addressed physically possible to reactor pressure under other bypass the interlocks.
interlock circuitry that proposed SAMA 90 will evaluate inhibits opening the SAMAs adding a bypass switch low-pressure coolant along with modifying the injection (LPCI) or procedures.
core spray injection valves following sensor or logic failures that prevent all low pressure injection valves from openinQ.
90 Install a bypass Vermont Eliminate probability Retain Both the LPCI Injection Core cooling switch to allow Yankee [3] of ECCS low pressure shutoff valves and LPCS systems operators to bypass SAMA 66 permissives failing. injection shutoff valve have the low reactor low pressure perm issives pressure interlock that do not allow valve circuitry that inhibits opening unless RPV is opening the LPCI or below 476 psig. There is core spray injection no EOP action to bypass valves following this permissive.
sensor or logic failures that prevent all low pressure injection valves from opening.
91 Develop procedures Cooper [33] Extended RCIC #3 - See SAMA 63. Core cooling to allow bypass of SAMA 25 operation. Already systems the reactor core installed isolation cooling (RCIC) turbine exhaust pressure trip, extending the time available for RCIC operation.
to GNRO-2012/00072 Page 28 of 81
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92 Improve training on Cooper [33] Reduced failure of #3 - GGNS has two diesel Core cooling alternate injection via SAMA 78 operator to align fire Already driven 1500 gpm fire pumps systems the fire water system, protection system for installed that can be used for increasing the injection alternate injection.
availability of Emergency Procedure 05-alternate injection. S-01-EP-1, attachment 26 provides instructions for injection into the RPV with the fire protection water system. GLP-OPS-EP07 indicates that the operators are trained on use of the fire water system for RPV injection.
93 Increase the Duane Elim inate probability #2 - Similar See SAMA 90. Core cooling reliability of the low Arnold [31] of ECCS low pressure item is systems pressure ECCS RPV SAMA 166 permissives failing. addressed low pressure under other permissive circuitry. proposed Install manual SAMAs bypass of low pressure permissive.
94 Modify procedures to Susquehan Improved fire #1 - N/A Susquehanna was Core cooling stagger RPV na [32] protection system recommending "staggering" systems depressurization SAMA3 injection capability. depressurization of each of when fire protection the two units so that fire system injection is water would be able to be the only available used at its full flow-rate on make-up source. one unit at a time. Since GGNS is a single unit site and full fire water flow is available, this would not be necessary.
to GNRO-2012/00072 Page 29 of 81 1'8bIe1 *'_L ... . iCCiC/ . . .* * * .
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C 'i.*i.. <ii*.. . / i . i . i i C/i ..... ***.. * .*.* i i . . . . .*.*. . .* cc / i / / i i i . / ? } .. / i /i.*<C . . i 95 Change procedures NE105-01 Continued operation #1 - N/A The standby service water Cooling water to allow cross [1 ] of both residual heat pump motor bearings are connection of motor removal service water cooled by SSW from the cooling for RHRSW (RHRSW) pumps on discharge of the respective pumps. failure of one train of pump. The motors are service water (SW). cooled whenever the respective SSW pum p is running and does not depend on any other source of cooling.
96 Add redundant DC NE105-01 Increased availability #3 - GGNS UFSAR section Cooling water control power for SW [1 ] ofSW. Already 8.3.1 states that "each pumps. installed division of class IE and BOP circuit breaker control circuitry is provided with separate and redundant DC control power".
97 Replace ECCS pum p NE105-01 Elimination of ECCS #3 - All GGNS ECCS pump Cooling water motors with air- [1 ] dependency on Already motors are air-cooled.
cooled motors. component cooling installed system.
98 Provide self-cooled NE105-01 Elimination of ECCS #3 - LPCS and HPCS pumps do Cooling water ECCS seals. [1 ] dependency on Already not depend on other component cooling installed systems for seal cooling.
system.
to GNRO-2012/00072 Page 30 of 81 Ii. >iii
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99 Enhance procedural NE105-01 Reduced frequency of #3 - Plant service water Cooling water guidance for use of [1 ] loss of com ponent Already normally supplies CCW, cross-tied cooling water and installed chillers and AC units, component cooling service water. turbine building closed or service water cooling water (TBCCW),
pumps. alternate decay heat removal, switchgear room coolers and other misc loads. This system can be backed up by one of the standby service water loops. The SSW Cross-Tie system must be man ually aligned from the control room by handswitches HS-M640 and HS-M641 on panel H13-P601-17C or by handswitch H22-HS-M241 on the remote shutdown panel.
100 Implement NE105-01 Improved ability to Retain GGNS has two Cooling water modifications to allow [1 ] cool RH R heat independent RHR heat manual alignment of exchangers. exchangers with two the fire water system independent SSW loops.
to RHR heat Manual alignment of the fire exchangers. water system to RH R heat exchangers is not implemented.
Fire water may be used for vessel injection through 9 different paths.
101 Add a service water NE105-01 Increased availability Retain The GGNS SSW system Cooling water pump. [1 ] of cooling water. utilizes two service water pumps and one HPCS service water pump.
to GNRO-2012/00072 Page 31 of 81
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102 Enhance the screen NE105-01 Reduced potential for #1 - N/A GGNS utilizes a closed Cooling water wash system. [1 ] loss of SW due to loop natural draft cooling clogging of screens. tower system for condenser cooling. Standby service water utilizes forced draft cooling towers with a supply basin large enough for 30 days of decay heat removal. This basin is supplied from wells.
Plant Service Water (PSW) takes suction from the radial wells, which don't have a screen wash system.
103 Enhance alternate Monticello Reduced valve failure #3 - SSW cross-tie and fire Cooling water injection reliability by [6] SAMA probability. Already water cross-ties are including the residual 11 Installed included in the heat removal service maintenance rule program.
water and fire water Page 12 of GLP-MM-MRP cross-tie valves in indicates that the operators the maintenance record the OOS times and program. Attachment III of 01-S-18-6 indicates that these cross-ties are included in EOOS.
104 Revise procedures to Cooper [33] Improved ability to #2 - Similar See SAMA 100. Cooling water allow manual SAMA 30 cool RH R heat item is alignment of the fire exchangers. addressed water system to the under other RHR heat proposed exchangers, SAMAs providing improved ability to cool the RHR heat exchangers in a loss ofSW.
to GNRO-2012/00072 Page 32 of 81 I.*.*.*.ii.**. ......... . *.. i**ii ( \ i . > >i\ i. i.i.\.***..*.*i i *...* .....>
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105 Revise procedures to Cooper [33] Continued use of the #1 - N/A GLP-GPST-P4300 Cooling water allow the ability to SAMA 68 power conversion indicates that PSW is the cross-connect the system after service heat sink for the TBCCW circulating water water is lost. heat exchangers. GLP-pumps and the SW GPST-N7100 indicates that going to the turbine a loss of PSW would result equipment cooling in a loss of makeup water system heat to the cooling tower and exchangers, allowing subsequent loss of NPSH continued use of the to the circulating water power conversion pumps.
system after SW is lost.
106 Revise procedures to Cooper [33] Improved RHRSW #1 - N/A GGNS does not utilize Cooling water allow use of the SAMA 79 system service water booster RHRSW system pumps.
without a SW booster pump, increasing availability of the RHRSW system.
107 Provide an alternate Duane Improved inventory for #1 - N/A GGNS has a water capacity Cooling water source of water for Arnold [31] the service water of 15 million gallons in the the RHRSW/ESW SAMA 156 systems. SSW cooling tower basins.
pit. This is ample water inventory for any accident.
The system can operate for at least 30 days without requiring any makeup water.
108 Install a digital NE105-01 Reduced chance of #3 - GGNS has installed a Feedwater feedwater upgrade. [1 ] loss of main Already digital feedwater upgrade. and feedwater following a Installed condensate plant trip.
to GNRO-2012/00072 Page 33 of 81
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109 Create ability for NE105-01 Increased availability #3 - The B.5.b procedure Feedwater emergency [1 ] of feedwater. Already referenced in the NRC and connection of Installed inspection report condensate existing or new water (Procedure 05-S sources to feedwater STRATEGY, Alternate and condensate Strategy) provides systems. instructions for adding fire water to the condenser hotwell and to the CST.
Also, NRC Temporary Instruction 2515/183 Inspection Report of 5/13/11 (Fukushima follow-up ML11133A249) indicates that GGNS operators are sufficiently trained on all B5b strategies.
110 Install an NE105-01 Extended inventory in #1 - N/A 170,000 gal. is reserved in Feedwater independent diesel [1 ] CST during an SBO. the CST for HPCS and and for the condensate RCIC. After this is depleted, condensate storage tank makeup HPCS and RCIC swap to pumps. the suppression pool. Since these pumps can pump saturated water, there is no dependency on suppression pool cooling.
HPCS has its own independent diesel.
to GNRO-2012/00072 Page 34 of 81
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.i. / i < . << . <<< <<< <...**..* <<.<<."".kl......" .............. L *.*Cii . . * .<ci<<< . * .*.*.*..<iC<i Ci <<.*.*CiCC ii<<1 111 Add a motor-driven NE105-01 Increased availability Retain GGNS has turbine driven Feedwater feedwater pump. [1 ] of feedwater. feedwater pumps. GGNS and also has HPCS which is a condensate motor driven pump with a dedicated diesel generator power supply, and RCIC which is a turbine driven pump, available for high pressure injection if normal power becom es unavailable.
112 Add emergency level Monticello Elim inate all risk for #3 - GLP-OPS-N1900 indicates Feedwater control sensor and [6] SAMA Class 2 sequences Already that the hotwell level control and control valve to the 40 due to fires that installed system automatically condensate hotwell. require operator- maintains the main based hotwell condenser hotwells at -3' makeup. from the bottom of the hotwells, either by introducing water (hotwell makeup) from, or rejecting water (hotwell reject) to, the CST.
113 Develop a procedure Monticello Increased availability #3 - See SAMA 109. Feedwater to refill the CST with [6] SAMA of feedwater. Already and fire water system. 28 installed condensate 114 Provide for the ability Cooper [33] Increased availability #3 - See SAMA 109. Feedwater to establish an SAMA 33 of feedwater. Already and emergency installed condensate connection of existing or new water sources to feedwater and condensate systems, increasing availability of feedwater.
to GNRO-2012/00072 Page 35 of 81
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115 Provide reliable NE105-01 Increased availability #3 - The safety related portions Heating, power to control [1 ] of control room Already of the control room heating Ventilation, building fans. venti lation. installed ventilation and air and air conditioning (HVAC) conditioning system are required to be operable during a loss of offsite power.
116 Provide a redundant NE105-01 Increased availability Retain Consideration should be Heating, train or means of [1 ] of com ponents given to LPCS pump room, Ventilation, venti lation. dependent on room SSW pump room, and air cooling. safeguard switchgear and conditioning battery room, and HPCS room. DG building HVAC is addressed in SAMAs 118, 123, 124, and 125. Other areas are not dependent on room or area cooling.
117 Enhance procedures NE105-01 Increased availability #3 - Consideration should be Heating, for actions on loss of [1 ] of com ponents Already given to LPCS pump room, Ventilation, HVAC. dependent on room installed SSW pump room, and air cooling. safeguard switchgear and conditioning battery room, and HPCS room. SSW, safeguard switchgear battery, LPCS, and HPCS rooms already have procedures to provide alternate room cooling for loss of HVAC. EDG building HVAC is addressed in SAMAs 118, 123, 124, and 125. Other areas are not dependent on room or area coolinQ.
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118 Add a diesel building NE105-01 Improved diagnosis of Retain The GGNS EDG building Heating, high temperature [1 ] a loss of diesel has temperature elements Ventilation, alarm or redundant building HVAC. but no alarm. This SAMA is and air louver and being retained to consider conditioning thermostat. adding a diesel building high temperature alarm.
119 Create ability to NE105-01 Increased availability Retain RCIC is not dependent on Heating, switch HPCI and [1 ] of HPCI and RCIC in room cooling for the 24 Ventilation, RCIC room fan an SSO event. hour accident mission time. and air power supply to DC conditioning in an SSO event. HPCS is dependent on room cooling for the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months accident mission time.
120 Enhance procedure NE105-01 Extended availability #1 - N/A The GGNS RHR pumps do Heating, to trip unneeded [1 ] of required RHR or not depend on room Ventilation, RHR or core spray core spray pumps due cooling. There is only one and air pum ps on loss of to reduction in room low pressure core spray conditioning room ventilation. heat load. pump. The HPCS pump depends on room cooling, but there is only one pump in the room.
121 Stage backup fans in NE105-01 Increased availability #1 - N/A The GGNS ESF switchgear Heating, switchgear rooms. [1 ] of ventilation in the room does not depend on Ventilation, event of a loss of HVAC for 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months success. and air switchgear ventilation. conditioning 122 Add a switchgear NE105-01 Improved diagnosis of #1 - N/A The GGNS ESF switchgear Heating, room high [1 ] a loss of switchgear room does not depend on Ventilation, temperature alarm. HVAC. HVAC for 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months success. and air conditioning to GNRO-2012/00072 Page 37 of 81 T_....1_1 _ .. .---::A.- .. *Il.:A.<,'::a: .. ...:.-~. -_.:
123 Diverse EDG HVAC Brunswick Increased availability Retain The two ventilation supply Heating, logic: This SAMA [7] SAMA of EDG room fans, one for each room, Ventilation, involves installation 15 ventilation. are interlocked to and air of a diverse set of automatically start but may conditioning fan actuation logic, be started man ually if which would reduce required.
the reliance of operators to perform a fan start on loss of the autom atic actuation logic.
124 Install additional fan Monticello Increased availability Retain Each diesel generator room Heating, and louver pair for [6] SAMA 6 of EDG room has two heating and Ventilation, EDG heating, ventilation. ventilation systems to and air ventilation, and air provide cooling for conditioning conditioning. equipment performance. A small fan coil unit is used during normal power operation to maintain the area temperature. A large ventilation supply fan starts automatically when the diesel generator starts. The two ventilation supply fans, one for each room, are interlocked to automatically start with an automatic EDG start, but may be started manually if required.
125 Operator procedure Vermont Increased availability #2 - Similar Procedure changes by Heating, revisions to provide Yankee [3] of the EDG system. item is themselves would not do Ventilation, additional space addressed much good if the operators and air cooling to the EDG under other don't have a high temp conditioning room via the use of proposed alarm in the diesel rooms.
portable equipment. SAMAs Thus, the alarms would have to be added sim ilar to SAMA 118.
to GNRO-2012/00072 Page 38 of 81 T.hl.1 ftL * - ........
126 I Develop a procedure Fitzpatrick This SAMA would I #1 - N/A GGNS does not have an Heating, to open the door to [2] SAMA improve the reliability EDG building high Ventilation, the EDG buildings 62 of the EDGs following temperature alarm. See and air upon the high high temperatures in SAMA 118 to add a diesel conditioning temperature alarm. the EDG buildings. building high temperature alarm.
127 I Revise procedures to Cooper [33] Increased availability #2 - Similar See SAMA 125. Heating, provide additional SAMA 40 of the EDG system. item is Ventilation, space cooling to the addressed and air EDG room via the under other conditioning use of portable proposed equipment, SAMAs increasing availability of the EDG.
128 I Provide cross-unit NE105-01 Increased ability to #1 - N/A GGNS is a single unit site. Instrument Air connection of [1 ] vent containment Supply uninterruptible using the hardened com pressed air vent.
supply.
129 I Provide ability to NE105-01 Increased availability Retain The Unit 1 instrument air Instrument Air align diesel power to [1 ] of instrument air after com pressor is powered Supply more air a LOOP. from critical 4.16 kV bus compressors. 16AB. The other com pressors are powered from non-critical buses.
Thus, only the instrument air com pressor will receive diesel power following a loss of offsite power. This SAMA is being retained to provide procedural guidance following a loss of offsite power to align diesel power to the other air compressors.
to GNRO-2012/00072 Page 39 of 81 130 Replace service and NE105-01 Elimination of Retain The air com pressors and Instrument Air instrument air [1 ] instrument air system the aftercoolers require Supply compressors with dependence on cooling water from the more reliable TSCCW and service turbine building cooling com pressors wh ich water cooling. water system to cool down have self-contained the compressed air. The air cooling by shaft SSW is a backup to the driven fans. TSCCW svstem to GNRO-2012/00072 Page 40 of 81
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.*ii 131 Install nitrogen NE105-01 Extended SRV Retain The purpose of this SAMA bottles as backup [1 ] operation time. is to provide a redundant Supply gas supply for safety pneumatic source that does relief valves. not depend on a mechanical device such as an air compressor. The GGNS ADS SRV pneumatics are supplied by 4 large air receivers supplying smaller redundant accumulators, two for each valve. Two receivers provide pneumatic supply for steam lines A and C and the other two provide for steam lines Band D. This redundancy in itself is comparable to other BWRs that have a single Nitrogen tank as a primary supply and nitrogen bottles as a backup. In addition to the above, GGNS has nitrogen bottles that can be connected to the ADS pneumatic system that will provide a backup to the ADS receivers. This SAMA was retained to provide a permanent Nitrogen bottle connection and automatic tie in to the instrument air (IA) system.
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132 Improve SRV and NE105-01 Improved availability Retain The SRVs and MSIVs have Instrument Air MSIV pneumatic [1 ] of SRVs and MSIVs. accum ulators installed for Supply components. air. This SAMA is being retained to improve the non-ADS SRVs by replacing them or adding accumulators. SAMA 67 is being retained to add larger accum ulators to the 8 ADS SRVs.
133 Provide an alternate Brunswick Increased availability #3 - GGNS has two portable air Instrument Air means of supplying [7] SAMA of instrument air. Already com pressors capable of Supply the instrument air 19 installed delivering a minimum of header: This SAMA 1200 SCFM at 130 psig.
involves procurement SOl 04-1-01-P51-1 of an additional provides instructions to portable compressor supply air to the service air to be aligned to the and IA systems.
supply header to reduce the risk associated with loss of instrument air.
134 Provide an alternate Cooper [33] Increased availability #3 - GGNS has two portable air Instrument Air means of supplying SAMA 45 of instrument air. Already com pressors capable of Supply the instrument air installed delivering a minimum of header, increasing 1200 SCFM at 130 psig.
availability of SOI04-1-01-P51-1 instrument air. provides instructions to supply air to the service air and IA systems.
to GNRO-2012/00072 Page 42 of 81
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135 Install an NE105-01 Increased availability Retain An independent Containment independent method [1 ] of containment heat suppression pool cooling Phenomena of suppression pool removal. system could consist of a cooling. heat exchanger approximately the size of the RHR Heat Exchanger, a circulating pump, piping to tie in to RHRSW for cooling water, motor operated valves, power and instrument cabling.
136 Revise procedure to NE105-01 Improved containment #3 - This operator action is Containment initiate suppression [1 ] pressure control and Already taken in response to Phenomena pool cooling during containment heat installed provide containment heat transients, LOCAs removal capability. removal during transients, and ATWS. LOCAs, and ATWS. EP-3 will initiate suppression pool cooling.
137 Change procedure to NE105-01 Increased availability Retain GGNS has an RHRSSW Containment cross-tie open cycle [1 ] of containment heat crosstie that can be aligned Phenomena cooling system to removal. for vessel injection flow or enhance drywell containment spray header spray system. flow. However, containment spray header flow is not proceduralized. This SAMA will investigate using the SSW system to backup containment spray.
138 Enable flooding of NE105-01 Reduced probability of #1 - N/A Mark I issue only. Containment the drywell head [1 ] leakage through the Phenomena seal. drywell head seal.
139 Create a reactor NE105-01 Enhanced debris cool #3 - GGNS has procedures in Containment cavity flooding [1 ] ability, reduced core Already place to flood the reactor Phenomena system. concrete interaction, Installed cavity in the event of a and increased fission severe accident.
product scrubbing.
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140 Install a passive NE105-01 Improved drywell Retain GGNS does not contain a Containment drywell spray [1 ] spray capability. passive drywell spray Phenomena system. system.
141 Use the fire water NE105-01 Improved drywell Retain GGNS has several Containment system as a backup [1 ] spray capability. firewater injection paths, Phenomena source for the drywell but none that could supply spray system. the containment sprays.
142 Enhance procedures NE105-01 Reduced risk of core Retain In addition to the dem in Containment to refill CST from [1 ] damage during station water storage tank, Phenomena dem ineralized water blackouts or LOCAs inventory is also available or service water that render the in the refueling water system. suppression pool storage tank (RWST) and unavailable as an the upper containment pool.
injection source. Current procedures govern transfer of inventory from the demin water storage tank and suction transfer to the RWST; however, these are not for SBOs or LOCAs.
143 Enhance procedure NE105-01 Reduced chance of #1 - N/A The GGNS ECCS pumps Containment to maintain ECCS [1 ] pump failure due to are designed to Phenomena suction on CST as high suppression pool successfully operate with long as possible. temperature. suction from a saturated suppression pool.
144 Modify containment NE105-01 Reduced forced #3 - In the severe accident Containment flooding procedure to [1 ] containment venting. Already management guidance Phenomena restrict flooding to installed (SAMGs) the only viable below the top of method to attain adequate active fuel. core and core debris cooling is submergence as per Boiling Water Reactor Owners Group (BWROG) guidelines. The core and core debris are submerged when the containment is flooded to above top of active fuel.
to GNRO-2012/00072 Page 44 of 81 i ..*..
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.i*.*ii ***.*.. *i<i * * . . .*.. i.*..* *.*.*.*. * .*.*. . . . *.*.* *.* * . .* ii . . *.. i** .i\. i i << < i < i i . *.*'1"'lia..... "'***..... iii\iiiii *.<iii <ii.iii< .ii i ii/ i/iiii . .* . . i i i . i ..*.. ....... ........ ... . i . . . . .* *. . . .* .* .*.* . i..*.* . . * * * * * * . .*/****.. .*./.. . * *. . .*. i/i*.....*.. *.*****.i*i . . . . /. . . i..*.* * ./ .*./i** . . . *.* . .*. . . . . . . . . . . i*****.**i.. . . . . . //;..*. *i/.*.*/.i 147 Enhance fire water NE105-01 Improved fission #1 - N/A Current fire water and Containment system and standby [1 ] product scrubbing in standby gas treatment Phenomena gas treatment severe accidents. systems do not have system hardware sufficient capacity to handle and procedures. the loads from severe accidents that result in a bypass or breach of the containment. Loads produced as a result of RPV or containment blow down would require large filtering capacities. These filtered vented systems have been previously investigated and found not to provide sufficient cost benefit.
148 Modify plant to NE105-01 Increased scrubbing #3 - The GGNS containment Containment perm it suppression [1 ] of fission products by Already vent system is a "scrubbed Phenomena pool scrubbing. directing vent path installed path", because it vents from through water in the the containment. Fission suppression pool. products in the drywell atmosphere are "scrubbed" by bubbling through the suppression pool when the containment vent path is used.
149 Enhance NE105-01 Improved likelihood of #3 - GGNS EOPs and severe Containment containment venting [1 ] successful venting. Already accident guidelines (SAGs) Phenomena procedures with installed provide the guidance for respect to timing, containment venting.
path selection, and Supporting procedures technique. provide details for each path.
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150 Control containment NEI 05-01 I Reduced probability of #1 - N/A GGNS has determined that I Containment venting within a [1] rapid containment venting containment when Phenomena narrow band of depressurization thus the primary containment pressure. avoiding adverse pressure limit (PCPL) is impact on low reached will not fail the pressure injection ECCS pumps taking systems that take suction from the suction from the torus. suppression pool due to NPSH loss. Therefore, control of containment venting within a narrow band of pressure is not necessary.
151 Improve vacuum NE105-01 Decreased #3 - GGNS has 4 vacuum I Containment breaker reliability by [1 ] consequencesofa Already breaker flow paths. Two 10 Phenomena installing redundant vacuum breaker Installed inch paths are associated valves in each line. failure to reseat. with the Combustible Gas Control Drywell Purge system. Each path has a motor operated valve in series with two check valves. The two remaining paths merge into the 10 inch drywell vacuum relief line that is part of the Post-LOCA Vacuum Relief System. Each of these paths have a motor operated valve in series with a check valve.
152 Enhance air return NE105-01 Reduced probability of #1 - N/A GGNS is not an ice Containment fans (ice condenser [1 ] containment failure in condenser plant. Phenomena plants). SSO sequences.
153 Provide post- NE105-01 Reduced likelihood of Retain GGNS utilizes a non- Containment accident containment [1 ] hydrogen and carbon inerted containment. Phenomena inerting capability. monoxide gas combustion.
to GNRO-2012/00072 Page 47 of 81
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154 Create a large NE105-01 Increased cooling and #1 - N/A Core retention devices Containment concrete crucible [1 ] containment of molten have been investigated in Phenomena with heat removal core debris. Molten previous studies. IDCOR potential to contain core debris escaping concluded, "core retention molten core debris. from the vessel is devices are not effective contained within the risk reduction devices for crucible and a water degraded core events".
cooling mechanism Other evaluations have cools the molten core shown the worth value for a in the crucible, core retention device to be preventing melt- on the order of $7000 through of the base (averted cost-risk) mat. compared to an estimated implementation cost of over
$1 million.
155 Create a core melt NE105-01 Increased cooling and #1 - N/A See disposition on SAMA Containment source reduction [1 ] containment of molten 154. Phenomena system. core debris.
Refractory material would be placed underneath the reactor vessel such that a molten core falling on the material would melt and combine with the material. Subsequent spreading and heat removal from the vitrified com pound would be facilitated, and concrete attack would not occur.
to GNRO-2012/00072 Page 48 of 81 156 Strengthen NEI 05-01 Reduced probability of I #1 - N/A This SAMA is for a new I Containment primary/secondary [1] containment over- plant; it is not practical to Phenomena containment (e.g., pressurization. back fit this modification add ribbing to into a plant, which is containment shell). already built, and operating.
In addition, GGNS is a Mark III containment.
157 Increase depth of the NE105-01 Reduced probability of I #1 - N/A It is not practical to back fit I Containment concrete base mat or [1 ] base mat melt- this modification into a Phenomena use an alternate through. plant, which is already built concrete material to and operating. The cost of ensure melt-through implementation would far does not occur. outweigh the benefit of this modification.
158 Provide a reactor NE105-01 Increased potential to I #1 - N/A The GGNS containment I Containment vessel exterior [1 ] cool a molten core can be flooded as noted in Phenomena cooling system. before it causes the disposition for SAMA vessel failure, by 139. This SAMA has been submerging the lower analyzed at Pilgrim Nuclear head in water. Power Station, Vermont Yankee Nuclear Power Station, and James A.
FitzPatrick Nuclear Power Plant and has been determ ined to be not cost beneficial. The highest averted cost risk was
$640,000 with an estimated implementation cost of $2.5 million.
159 Construct a building NE105-01 Reduced probability of I #1 - N/A GGNS uses containment I Containment to be connected to [1 ] containment over- sprays and vents to reduce Phenomena primary/secondary pressurization. containment pressure. The containment and cost of converting to a sub-maintained at a atmospheric containment, vacuum. let alone the cost of the new building, would likely far outweigh any gains.
to GNRO-2012/00072 Page 49 of 81
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160 Institute sim ulator NE105-01 Improved arrest of #3 - The technical support Containment training for severe [1 ] core melt progress Already center and Control Room Phenomena accident scenarios. and prevention of installed would be manned in a containment failure. severe accident evolution to provide additional support by personnel familiar with SAGs.
161 Improve leak NE105-01 Increased piping #3 - Leakage is detected by Containment detection [1 ] surveillance to identify Already monitoring drywell temp, Phenomena procedures. leaks prior to installed pressure, sump flow rates complete failure. and temperatures, RPV Improved leak levels, and drywell detection would atmosphere radiation and reduce LOCA fission product levels.
frequency.
162 Install an NE105-01 Reduced hydrogen #3 - GGNS has two Hydrogen Containment independent power [1 ] detonation potential. Already Recombiners, each Phenomena supply to the installed powered from a different hydrogen division. They are backed recom biners control up by hydrogen igniters and system using either a drywell purge system.
new batteries, a non-safety grade portable GGNS has a portable generator, existing generator used to supply station batteries, or temporary power to one existing AC/DC division of hydrogen igniters independent power during B.5.b events. The supplies, such as the B.5.b procedure referenced security system in the NRC inspection diesel. report provides instructions for providing alternate power to the hydrogen recombiners. Also, lesson plan GLP-OPS-B5BH2 provides ops training on this action.
to GNRO-2012/00072 Page 50 of 81 a fta .... a __ a.
163 Install a passive NE105-01 Reduced hydrogen Retain GGNS incorporates a Containment hydrogen control [1 ] detonation potential. Hydrogen Ignition system, a Phenomena system. Hydrogen Recombiner System, and a Drywell Purge system. None of these systems are passive.
A passive system would be a Nitrogen overpressure system.
164 Erect a barrier that NE105-01 Reduced probability of I #1 - N/A To im plem ent the barrier Containment would provide [1 ] containment failure. would outweigh the gains. Phenomena enhanced protection The containment walls of the containment already provide a sufficient walls (shell) from am ount of protection and to ejected core debris implement this modification following a core melt would not be feasible for an scenario at high existing plant.
pressure.
165 Use fire-fighting Brunswick Improved drywell #2 - Similar I See SAMA 141. Containment water as a backup [7] SAMA spray capability. item is Phenomena for containment 36 addressed spray: This SAMA under other would provide proposed redundant SAMAs containment spray function without the cost of installing a new system.
166 Provide passive Monticello Increased decay heat Retain I Since having containment Containment overpressure relief [6] SAMA removal capability. isolation valves that fail Phenomena by changing the 16 open on loss of power is containment vent not desirable this SAMA is valves to fail open being evaluated to convert and improving the the existing torus vent to a strength of the passive design. The rupture disk. containment vent currently does not have a rupture disc.
to GNRO-2012/00072 Page 51 of 81
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167 Install alternate path Oyster Increased decay heat #2 - Similar GGNS has only one vent Containment to the torus hard pipe Creek [5] removal capability. item is path. Phenomena vent via the wet well SAMA10 addressed using a rupture disk. under other Sim ilar to SAMA 166.
proposed SAMAs 168 Enable manual Oyster Improved availability Retain The containment vent Containment operation of all Creek [5] of the containment valves at GGNS must have Phenomena containment vent SAMA 84 vent valves. instrument air to be valves via local operated. They also require controls. jumpering an interlock.
169 Control containment Pilgrim [4] Reduced probability of #1 - N/A GGNS has determined that Containment venting within a SAMA 53 rapid containment venting containment when Phenomena narrow pressure depressurization thus PCPL is reached will not fail band. avoiding adverse the ECCS pum ps taking impact on low suction from the pressure injection suppression pool due to system s that take NPSH loss. Therefore, suction from the torus. control of containment venting within a narrow band of pressure is not necessary.
170 Control containment Vermont Reduced probability of #1 - N/A GGNS has determined that Containment venting within a Yankee [3] rapid containment venting containment when Phenomena narrow pressure SAMA 63 depressurization thus PCPL is reached will not fail band. avoiding adverse the ECCS pum ps taking impact on low suction from the pressure injection suppression pool due to systems that take NPSH loss. Therefore, suction from the torus. control of containment venting within a narrow band of pressure is not necessary.
to GNRO-2012/00072 Page 52 of 81
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171 Install additional NE105-01 Reduced interfacing #3 - For successful ISLOCA Containment pressure or leak [1 ] system s loss of Already isolation, plant operators Bypass monitoring coolant accident installed have numerous indications instruments for (ISLOCA) frequency. for identifying an ISLOCA-detection of type breach in the control ISLOCAs. room. These indications include: reactor building pressure differential, high and low pressure alarms, system pressure indicators, reactor building water level, reactor building temperature, reactor building local radiation, system pressure, and torus high level alarm.
172 Add redundant and NE105-01 Reduced frequency of #3 - GGNS' present design is Containment diverse limit switches [1 ] containment isolation Already redundant and diverse, with Bypass to each containment failure and ISLOCAs. installed switches controlling the isolation valve. close function. Limit switches enable position display for the containment isolation valves.
173 Increase leak testing NE105-01 Reduced ISLOCA Retain The GGNS inservice Containment of valves in ISLOCA [1 ] frequency. inspection program Bypass paths. includes ISLOCA pathways.
Although ISLOCA is not risk significant, this SAMA is conservatively retained.
to GNRO-2012/00072 Page 53 of 81
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hi>*.*****..*. *.. . . .*i*<> ..i < < .* . .*.../ii.*i< ........... ii*< . <i.i.... i<..<****** .... <....* i *..<./1 174 Improve MSIV NE105-01 Decreased likelihood Retain Redundant MSIVs are Containment design. [1 ] of containment designed to isolate during Bypass bypass scenarios. accidents that could lead to radionuclide release and bypass containment. The MSIV are leak tested to ensure their adequacy. The Maintenance Rule program monitors the performance of the MSIVs providing feedback on dearadation.
175 Install self-actuating NE105-01 Reduced frequency of #3 - The lines which penetrate Containment containment isolation [1 ] isolation failure. Already the primary containment Bypass valves. installed are equipped with automatic isolation logic.
Specific logic groups isolate on reactor and containment parameters significant to the associate group in order to provide automatic valve closure appropriate for a Qiven set of conditions.
176 Locate residual heat NE105-01 Reduced frequency of #1 - N/A ISLOCA is not a significant Containment removal (RHR) [1 ] ISLOCA outside contributor to risk at GGNS, Bypass inside containment containment. so modifications to prevent ISLOCA will have a negligible impact on the risk profile. Locating RHR inside containment is an extensive change, the cost of which would obviously exceed the very small expected benefit. Lower cost alternatives (SAMAs 173,178 and 179) to reduce the risk from ISLOCA are being evaluated.
to GNRO-2012/00072 Page 54 of 81 177
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Containment releases are [1 ] releases. contributor to risk at GGNS, Bypass scrubbed. One so modifications to prevent method is to plug ISLOCA will have a drains in potential negligible impact on the risk break areas so that profile. Plugging drains in break point will be potential break areas would covered with water. require extensive revision of flooding analyses, the cost of which would obviously exceed the very small expected benefit.
Lower cost alternatives (SAMAs 178 and 179) to reduce the risk from ISLOCA are being evaluated.
178 Revise EOPs to NE105-01 Increased likelihood Retain This is more of a Containment improve ISLOCA [1 ] that LOCAs outside Pressurized Water Reactor Bypass identification. containment are (PWR) issue. Although identified as such. A ISLOCA is not risk plant had a scenario significant, this SAMA is in which an RHR conservatively retained.
ISLOCA could direct initial leakage back to the pressurizer relief tank, giving indication that the LOCA was inside containment.
179 Improve operator NE105-01 Decreased ISLOCA Retain GGNS has instruments to Containment training on ISLOCA [1 ] consequences. monitor and alarm Bypass coping. moderate and high energy line leaks outside the primary containment.
Although ISLOCA is not risk significant, this SAMA is conservatively retained.
to GNRO-2012/00072 Page 55 of 81 180 I Create cross-connect NE105-01 Improved availability #3 - The two SLC pump ATWS ability for standby [1 ] of boron injection Already discharge lines are cross liquid control (SLC) during ATWS. installed connected to a common trains. injection line.
Also, GGNS has the capability of injecting boron with RCIC or HPCS.
181 I Revise procedures to NE105-01 Improved availability #3 - SLC initiation and existing ATWS control vessel [1 ] of boron injection Already procedures guard against injection to prevent during ATWS. installed dilution (RWCU isolation).
boron loss or dilution The GGNS design auto-following SLC isolates RWCU on SLC injection. injection by closing the associated RWCU isolation valves. In addition ADS is inhibited when SLC is initiated, to prevent boron dilution.
182 I Provide an alternate NE105-01 Improved probability #3 - GGNS has the capability of ATWS means of opening a [1 ] of reactor shutdown. Already injecting boron with RCIC pathway to the RPV installed or HPCS.
for SLC injection.
183 I Increase boron NE105-01 Reduced time Retain Tech Spec table 3.1.7-1 ATWS concentration in the [1 ] required to achieve and the ops training SLC system. shutdown document (GLP-OPS-concentration C4100) indicate that the provides increased minimum GGNS weight 0/0 margin in the accident of sodium pentaborate in timeline for successful the SLC tank (when it's full) initiation of SLC. is 13.6%.
184 I Add an independent NE105-01 Improved availability #3 - GGNS has the capability of ATWS boron injection [1 ] of boron injection Already injecting boron with RCIC system. during ATWS. installed or HPCS.
to GNRO-2012/00072 Page 56 of 81
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185 Provide ability to use NE105-01 Improved availability #3 - GGNS has the capability of ATWS control rod drive [1 ] of boron injection Already injecting boron with RCIC (CRD) or RWCU for during ATWS. installed or HPCS.
alternate boron injection. In order to use RCIC or HPCS for boron injection, sodium pentaborate is added to the CST. Thus, any system that can take suction from the CST, such as CRD, may be used for alternate boron injection.
186 Add a system of NE105-01 Improved equipment #3 - This is a PWR insight. ATWS relief valves to [1 ] availability after an Already BWRs are already prevent equipment ATWS. installed equipped with adequate damage from pressure control methods pressure spikes even for the worst case during an ATWS. ATWS. The overpressure protection function of the twenty safety/relief valves, eight of which are ADS controlled, in the nuclear pressure relief system is self-actuating with setpoints such that the reactor vessel pressure never exceeds its pressure vessel code limit of 1325 psig during normal operation, abnormal operation, or accident conditions.
to GNRO-2012/00072 Page 57 of 81 Increase safety relief Reduced risk of This SAMA is retained to valve (SRV) reseat dilution of boron due Increase SRV reseat reliability. to SRV failure to reliability. The SRVs used reseat after SLC at GGNS are Dikkers injection. valves and are a later design than the two stage Target Rock valves. They may have better reclosure characteristics and history than the earlier valves. The UFSAR, however, does not mention this hazard.
Transient Group T3c occurs when an SRV sticks open due to an operator error or equipment malfunction allowing steam to be discharged into the suppression pool. The 1997 PRA Update mean freauencv for T3c is 0.012.
to GNRO-2012/00072 Page 58 of 81 ii i . . . . . ii <**.* . .* * . .*.**.*i.iii*. ............... il'able1 i _L ;QA.... .a. .* -" .~ **********iii< . . iiiii ii
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188 Provide an additional NE105-01 Improved redundancy #3 - GGNS has installed ATWS control system for [1 ] and reduced ATWS Already Alternate Rod Insertion rod insertion (e.g., frequency. installed (ARI) for alternate means of AMSAC). injecting the control rods and Recirculation Pump Trip (RPT) to limit pressure excursion immediately following the ATWS event and for the insertion of negative reactivity by increasing the core void level. The ARI and RPT systems are initiated by the sensors and logic, which are separate and diverse from the normal scram instrumentation used for the RPS in accordance with 10CFR-50.62. In addition GGNS has backup scram valves to vent the scram air header.
189 Install an ATWS NE105-01 Increased ability to #2 - Similar See SAMA 146. One ATWS sized filtered [1 ] rem ove reactor heat item is filtered vent could be added containment vent to from ATWS events. addressed to remove fission products remove decay heat. under other for ATWS and non-ATWS proposed scenarios.
SAMAs to GNRO-2012/00072 Page 59 of 81 ii i *.****i *
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i i i i ..... ii .i 190 Revise procedure to NE105-01 Affords operators #3 - Procedures are in place to ATWS bypass MSIV [1 ] more time to perform Already bypass MSIV isolation in isolation in turbine actions. Discharge of installed turbine trip ATWS trip ATWS scenarios. a substantial fraction scenarios. EP-2A directs of steam to the main operators to "Use the main condenser (Le., as condenser as a heat sink, opposed to into the open MSIVs if necessary, primary containment) OK to defeat interlocks."
affords the operator more time to perform actions (e.g., SLC injection, lower water level, depressurize RPV) than if the main condenser was unavailable, resulting in lower human error probabilities.
191 Revise procedure to NE105-01 Allows immediate #3 - GGNS already has ATWS allow override of low [1 ] control of low Already procedures in place to give pressure core pressure core Installed the operators full authority injection during an injection. On failure of over all injection modes, ATWS event. high pressure core including LPCI, during an injection and ATWS event.
condensate, some plants direct reactor depressurization followed by five minutes of automatic low pressure core injection.
to GNRO-2012/00072 Page 60 of 81
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192 I Increase boron Duane Reduced time #2 - Similar See SAMA 183. ATWS concentration or Arnold [31] required to achieve item is enrichment. SAMA 117 shutdown addressed concentration under other provides increased proposed margin in the accident SAMAs timeline for successful initiation of SLC.
193 I Seal penetrations NE105-01 Increased flood #1 - N/A The switchgear rooms are Internal between turbine [1 ] propagation at elevation 111' or higher, Flooding building basement prevention. whereas the turbine and switchgear basement is at the 93' rooms. elevation, one level below the location of the switchgear rooms. Flood damage will be confined to the turbine building until it reaches the 248' level. The lowest penetration is at the 237' level and it is sealed.
194 Improve inspection of NE105-01 Reduced frequency of #1 - N/A Although the main Internal rubber expansion [1 ] internal flooding due condenser has a rubber Flooding joints on main to failure of circulating expansion joint at the condenser. water system condenser neck, it is well expansion joints. above the hotwell water line and not a flood source.
195 Modify swing NE105-01 Prevents flood #1 - N/A There is no effective Internal direction of doors [1 ] propagation. flooding pathway from the Flooding separating turbine GGNS turbine building building basement basement (Elevation 93') to from areas areas containing containing safeguards equipment.
safeguards equipment.
to GNRO-2012/00072 Page 61 of 81 Install an interlock to This is a Monticello-specific Internal open the door to hot SAMA, not applicable to Flooding machine shop and GGNS. The GGNS internal change swing flooding analysis revealed direction of door to two flooding scenarios that plant administration required detailed model building to divert evaluation. These are water from turbine exam ined separately to building 931-foot determ ine if new SAMAs elevation east. could be orooosed.
to GNRO-2012/00072 Page 62 of 81 Improve internal Oyster Reduced internal #3 - GGNS procedure 05-1 Internal flooding procedures. Creek [5] flooding risk. Already VI-1 provides instructions Flooding SAMA 129 installed following flooding due to system rupture. It includes steps to secure pumps, close valves and close watertight doors to protect important equipment from internally initiated floods.
The GGNS internal flooding analysis considers actions to mitigate the impact of the flood scenarios and concludes that, "... no individual flooding scenario has an estimated core damage frequency exceeding 1.21 x 10*
7/reactor year and that the total contribution of internal flooding to the predicted core damage frequency is 7
8.73 x 10- /reactor year. In light of this small contribution, no recommendations are made for additional measures to guard against internal flooding and its conseauences."
to GNRO-2012/00072 Page 63 of 81 T.hl_1 a ....._laA** A* ._-
198 I Increase seismic I NE105-01 Increased availability #3 - GGNS components whose Reduce ruggedness of plant [1] of necessary plant Already seism ic ruggedness could Seismic Risk components. equipment during and installed be im proved were identified after seismic events. in the IPEEE and seismic qualification utility group (SQUG) programs. These items have been addressed in response to those efforts and satisfy the intent of this SAMA.
199 Provide additional NE105-01 Increased availability I #1 - N/A Section 4.8.2.1 of the Reduce restraints for C02 [1 ] of fire protection given GGNS IPEEE indicates that Seismic Risk tanks. a seism ic event. the risk of seism ically-induced fires is low. GLP-GPST-P6400 indicates that the areas with Cardox suppression are cable spreading, switchgear, remote shutdown, and electrical penetration rooms. These areas are unlikely to have significant flammable gas or liquid sources that could result in post-earthquake fire concerns.
to GNRO-2012/00072 Page 64 of 81
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ii 200 Modify safety related NE105-01 Improved availability #3 - The two condensate Reduce condensate storage [1 ] of CSTs following a Already storage tanks were Seism ie/Flood tanks. seism ic event and installed evaluated and walked down Risk reduced potential for to support the GGNS flooding from CSTs IPEEE seismic margins following a seism ic assessment. They were event. determ ined to be properly designed and to satisfy the concerns raised for flat bottom tanks in URI A-40 per NUREG-1233.
The 2 condensate storage tanks are surrounded with a seismically qualified reinforced concrete retaining dike that will hold 650,500 gal. The HPCS suction piping is sized such that the seism ically qualified portion will provide adequate inventory to allow time for the automatic suction swap to the suppression pool and isolation from the CST to occur in the event of a CST rupture.
201 Replace anchor bolts NE105-01 Improved availability #3 - The GGNS diesel generator Reduce on diesel generator [1 ] of diesel generators Already building was walked down Seismic Risk oil cooler. following a seism ic installed by the seismic margins event. review team. Th is team found no seism ic concerns with the diesel generator oil coolers.
to GNRO-2012/00072 Page 65 of 81
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53. Creek [5] core damage specific SAMA, not Seismic Risk SAMA 124 frequency (CDF) applicable to GGNS.
contribution from block wall failure.
203 Replace mercury NE105-01 Decreased probability #1 - N/A During the IPEEE the fire Reduce Fire switches in fire [1 ] of spurious fire protection system was Risk protection system. suppression system analyzed for seism ically-actuation. induced inadvertent actuation of fire suppression systems that could affect (seismic margins assessment) SMA equipment. Corrective actions to preclude adverse effects were implemented for equipment identified as potentially affected.
204 Upgrade fire NE105-01 Decreased #3 - GGNS fire compartment Reduce Fire compartment [1 ] consequences of a Already barriers are maintained to Risk barriers. fire. installed reduce fire propagation.
Surveillance procedures are used to verify the integrity of fire barriers at least once every 18 months. Work was com pleted by 1996 to upgrade existing Thermo-Lag enclosures, and qualify all Appendix R fire barrier enclosures for electrical raceways.
205 Install additional NE105-01 Reduced number of #2 - Similar Similar to SAMA 213. Reduce Fire transfer and isolation [1 ] spurious actuations item is Risk switches. during a fire. addressed under other proposed SAMAs to GNRO-2012/00072 Page 66 of 81 Table. 1 Phase I SABIA Analysis 206 Enhance procedures NE105-01 I Increased probability #3 - GGNS has remote I Reduce Fire to use alternate [1] of shutdown if the Already shutdown capabilities per Risk shutdown methods if control room becomes installed referenced procedures. The the control room uninhabitable. procedures outline the becomes remote shutdown activities uninhabitable. necessary to safely shutdown the plant in the event that the control room becomes uninhabitable.
207 I Enhance fire brigade I NE105-01 Decreased #3 - The fire brigade is trained Reduce Fire awareness. [1] consequences of a Already and maintained per the Risk fire. installed referenced documents and has quarterly requalification and drills.
208 Enhance control of NE105-01 Decreased fire #3 - Procedures to control Reduce Fire combustibles and [1 ] frequency and Already combustible materials, Risk ignition sources. consequences. installed flammable materials, and ignition sources are in place at GGNS.
209 Improve alternate Brunswick Increased probability #2 - Similar GGNS has procedure 04 I Reduce Fire shutdown panel. [7] SAMA of shutdown if the item is 01-C61-1 in place for Risk 30 control room becomes addressed direction. The procedure uninhabitable. under other outlines the remote proposed shutdown activities SAMAs necessary to safely shutdown the plant in the event that the control room becomes uninhabitable.
SAMA 213 will evaluate upgrading the alternate shutdown system ASDS panel to include additional system controls for the opposite division.
to GNRO-2012/00072 Page 67 of 81 Table 1 _L .1 &':!A *
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210 Improved alternate Brunswick Increased probability #3 - GGNS already has an Reduce Fire shutdown training [7] SAMA of shutdown if the Already adequate shutdown panel Risk and equipment. 31 control room becomes installed and procedure (Off Normal uninhabitable. Event Procedure Shutdown from the Remote Shutdown Panel). Operators are trained to this procedure.
211 Add automatic fire Brunswick Reduced fire risk. Retain GGNS has automatic Reduce Fire suppression system. [7] SAMA suppression systems in Risk 32 place such as the wet pipe sprinkler, preaction sprinkler, deluge sprinkler, C02, and halon systems.
The dom inant fire zones reported in the IPEEE are the control room and control building switchgear rooms.
The control room has Halon suppression in the control room floor sections.
Many of the switchgear rooms have automatic C02 suppression systems. The Div I switchgear room in the control bldg that is a large contributor in the IPEEE is zone OC214 has a partial automatic sprinkler system.
This SAMA would improve the reliability and effectiveness of those systems.
to GNRO-2012/00072 Page 68 of 81
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212 Proceduralize the Monticello Reduced fire risk. #3 - GGNS has a fire pumper Reduce Fire use of a fire pumper [6] SAMA Already truck used in various B.5.b Risk truck to pressurize 12 installed strategies. The B.5.b the fire service water procedure referenced in the system. NRC inspection report provides instructions for use of the fire truck. Also, lesson plan GLP-OPS-B5B01 provides ops training on this action.
213 Upgrade the ASDS Monticello Reduced risk from Retain This SAMA is to upgrade Reduce Fire panel to include [6] SAMA fires that require the alternate shutdown Risk additional system 39 control room panels to include additional controls for opposite evacuation. equipment for the opposite division. division at GGNS. The ASDS panel is designed to use division 1 safety and support systems to safely shutdown the plant. It will also include installation of additional transfer and isolation switches (SAMA 205).
214 Add a bus cross-tie Oyster Reduced fire risk. #1 - N/A This is an Oyster Creek- Reduce Fire circuit breaker to Bus Creek [5] specific SAMA, not Risk 182 to reduce the SAMA 1258 applicable to GGNS.
impact of fires in the 480-V AC switchgear room.
215 Relocation of relief Oyster Eliminated dominant #1 - N/A This is an Oyster Creek- Reduce Fire valve cables, Creek [5] contributors to fire specific SAMA, not Risk circuitry, and 125C risk. applicable to GGNS.
components, as well as other modifications, to ensure one train of core spray remains unaffected by fire.
to GNRO-2012/00072 Page 69 of 81 I.iii ...* * .. i .*.*.*. . i . . i ....... i i iii
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216 Revise procedures to Cooper [33] Reduced fire risk. #3 - See SAMA 212. Reduce Fire allow use of a fire SAMA 64 Already Risk pum per truck to installed pressurize the fire water system, increasing availability of the fire water system.
217 Increase fire pump Oyster Increased availability #1 - N/A The IPEEE showed the risk High Winds, house building Creek [5] of fire water during from high winds at GGNS is External integrity to withstand SAMA 134 severe weather. minor and did not identify Floods, and higher winds so that any vulnerability related to Other the fire system would the location of the fire be capable of pumps.
withstanding a severe weather event.
218 Install digital large NE105-01 Reduced probability of Retain GGNS has no leak Other break LOCA [1 ] a large break LOCA detection system utilizing Improvements protection system. (a leak before break). digital technology to integrate the various existing leakage detection schemes.
219 Enhance procedures NE105-01 Reduced #3 - GGNS' EOPs/SAMGs Other to mitigate large [1 ] consequences of a Already provide numerous ways of Improvements break LOCA. large break LOCA installed flooding the RPV and flooding/spraying primary containment.
to GNRO-2012/00072 Page 70 of 81 T:.h"~ ..... L l~fA * *
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220 Install computer NE105-01 Improved prevention #3 - The GGNS Safety Other aided [1 ] of core melt Already Parameter Display System Improvements instrumentation sequences by making installed (SPDS) is a computer system to assist the operator actions more system that aids the operator in assessing reliable. operator in assessing plant post-accident plant status post-accident. Many status. of the parameters displayed are based on inputs from multiple, diverse indications, and the SPDS system displays the results.
221 Improve NE105-01 Improved prevention #3 - GGNS has implemented a Other maintenance [1 ] of core melt Already Predictive Maintenance Improvements procedures. sequences by installed Program to im prove plant increasing reliability of safety, equipment important equipment. availability and reliability through early detection and analysis of equipment problems.
222 Increase training and NE105-01 Improved likelihood of #3 - A "flexible" portion of the Other operating experience [1 ] success of operator Already requalification training is Improvements feedback to im prove actions taken in installed "designed to correct operator response. response to abnormal performance or knowledge conditions. weaknesses identified during plant Scrams or other events, from incident reports, licensee event reports, Operations Analysis group recommendations, industry operating events, significant plant modifications and procedure changes, etc."
to GNRO-2012/00072 Page 71 of 81
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223 Develop procedures NE105-01 Reduced #1 - N/A GGNS addressed the Other for transportation and [1 ] consequences of hazard due to Improvements nearby facility transportation and transportation and nearby accidents. nearby facility facility accidents in the accidents. IPEEE submittal. The assessment concluded that no vulnerabilities exist due to transportation or nearby facility accidents.
224 Increase operator Oyster Increase the chance #3 - EN-TQ-114 states that the Other training on the Creek [5] of recovery on Already PRA model is one of the improvements systems and SAMA 127 systems that are installed inputs used to define the operator actions important from a PRA curriculum.
determ ined to be standpoint.
important from the PRA.
225 Implement GRA (trip Cooper [33] Decreases the Retain GGNS does not have a Other and shutdown risk SAMA 75 probability of generation risk assessment Improvements modeling) into plant trip/shutdown risk (GRA) model.
activities, decreasing the probability of trips/shutdown.
226 The Loss of Offsite IPE [9] Sec Increased availability #3 - The Loss of AC Power Off- Core cooling Power Off-Normal 6 of on-site AC power Already Normal Event Procedure systems Event Procedure will (6.2.1 ) leading to increased installed has been revised to allow be revised to allow availability of ECCS for the level 2 signal to be for the Level 2 signal injection. bypassed in the event that to be bypassed in the the Division 3 diesel event that that the generator must be cross-Division 3 diesel tied to divisions 1 or 2.
generator must be cross-tied to Divisions 1 or 2.
to GNRO-2012/00072 Page 72 of 81
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227 Improve secondary IPE [9] Sec Improved availability #3 - The PSW isolation valves in Other containment isolation 6 of PSW and Already the Auxiliary Building Improvements to allow the capability (6.2.2) Instrument Air such installed penetrations (P44-F116, of bypassing the that the main P44-FI17,P44-FII8, P44-isolation signals and condenser, F1I9, P44-FI20, P44-FI21, re-opening the condensate, and P44-F122 and P44-FI23) valves. feedwater systems can be reopened by manual would not be lost. override after a LOCA to CAD would also not reestablish PSW cooling to be degraded due to a the CCW Heat Exchangers, loss of the preferred Computer Aoom Coolers, cooling source of the Plant Chillers, Steam CCW heat Tunnel Coolers, and exchangers. Drywell Coolers. This should be done only if offsite power is available and after it has been determined that the release of radioactive fission products will not result. 05-S-01-EP-1 contains guidance to restore instrument air to containment loads by defeating containment isolation interlocks and openinQ the valves. 228 Implement IPE [9] Sec Increased ACIC #1 - N/A Provided there is no leak in Core cooling procedural changes 6 availability when main the main steam tunnel, systems to allow for bypass of (6.2.3) steam tunnel high failure of main steam the ACIC turbine trip temperature exists. cooling will not result in a due to main steam main steam tunnel tunnel high tem perature of 185 deg or temperature when greater. Therefore, it will PSW is unavailable not result in an initiation of and no steam line the main steam tunnel high break has occurred. temperature isolation 10Qic. to GNRO-2012/00072 Page 73 of 81 Table 1 Phase I QAUA &-- _ . _ - - " 229 Increase the training IPE [9] Sec Increased availability I Retain In accordance with GDC Heating, emphasis and 6 of the SSW pump 13, damper status is Ventilation, provide additional (6.2.4) house ventilation indicated in the main and air control room system. control room. In addition, conditioning indication on the there is a high temperature operational status of alarm in the main control the SSW pump room. house ventilation system. This will Alarm 04-1-02-1 H13-P870 allow operators to provides an alarm, but the manually open the actions could be expanded pump house to accomplish a more dampers which can robust mitigation of this provide adequate condition. ventilation such that pump failures would not occur. 230 Increase operator IPE[9] Sec 6 Increased time Retain No specific operator Core cooling training for (6.2.5) available for recovery training is in place to systems alternating operation actions for low address this condition. of the low pressure pressure ECCS when ECCS pumps (LPCI a loss of SSW occurs. and LPCS) for loss of SSW scenarios. 231 Revise the IPE [9] Sec Limit one of the major #3 - GGNS contributed this IPE Containment containment flooding 6 contributors to the Already insight to the BWR Owners Phenomena portion of the (6.2.6) source term released. installed Group Severe Accident Emergency Subcommittee. GGNS has Procedures to already implemented the remove or modify the current severe accident step requiring MSIV guidelines on RPV venting. venting. 232 Install a backup IPE [9] Sec Hydrogen Igniter #3 - See SAMA 162. Containment power supply to the 6 Operability During Already Phenomena hydrogen igniters. (6.3.1) Station Blackout. Installed to GNRO-2012/00072 Page 74 of 81
.Q....... . I 233 Install an additional IPE [9] Sec I Increased decay heat Retain GGNS utilizes the Containment method of removing 6 removal capability Containment Spray and Phenomena heat from the (6.3.2) RHR Suppression Pool containment. Cooling for post-accident containment heat removal.
Containment venting is also available to ensure pressure stays below design limits should the other systems fail to reduce containment pressure. 234 Install a backup IPE [9] Sec Alternate Water Retain GGNS has a High Pressure Core cooling water supply and 6 Supply for Core Spray system, which systems pumping capability (6.3.3) Containment is powered from an that is independent SprayNessellnjection independent (division 3) of norm al and power supply; however, a emergency AC backup supply will be power. investigated per the IPE recommendations. 235 Extend the battery IPE [9] Sec Enhanced Reactor #2 - Similar ADS and Non-ADS relief AC and DC depletion time for the 6 Pressure Vessel item is valves are all dependent on power relief valves. (6.3.4) Depressurization addressed DC power and Instrument System Reliability under other Air. Extended DC power to proposed the relief valves will allow SAMAs longer operation during a loss of DC Battery Chargers. Sim ilar to SAMAs 1, 3, and 27. 236 Implement the latest IPE [9] Sec Improved likelihood of #3 - GGNS currently utilizes Other revision of the BWR 6 success of operator Already Revision 2 of the BWROG 1m provements Owners Group (6.3.5) actions taken in Installed emergency procedure EPGs. response to abnormal guidelines (EPGs). conditions.
Attachment 2 to GNRO-2012/00072 Page 75 of 81
* . .*.*.* />> I~A ** .& .** ..! (m/> . . . . *.. > m y i i i m i i i . i / >>
1m/ . . . . . . y........*.mi...**.*. *..* m . .*.m .>Y*..* .*.*.*i. .i*.. . . .*. . . . . . . . . . .*ii*..*.. . . . . *.*.* .......i . >.. . . . >/ .iml'ablAi'l-a. > m y . i / ... i i i i . y i . . . * ..>*ii/i.>i. 237 Increase IPEEE Prevent deterioration #3 - GGNS has increased the Flooding maintenance on Summary of site conditions. Already maintenance on drainage drainage structures. Report [34] installed structures. Maintenance should (Pg.117) include cleaning of culverts, concrete repair and removal of vegetation/debris which could obstruct flow. 238 Plant procedures 05- IPEEE Reduce leakage from #3 - GGNS has revised the Flooding 1-02-VI-1 and 05 Summary flooding through an Already plant flood mitigation 02-VI-2 currently Report [34] open door. installed procedure (Off-normal require plant staff to (Pg. 117) Event Procedure No. 05 insure that plant 02-VI-1 ). doors are closed during severe weather and in the event of plant flooding (Implicitly including former unit 2 doors). Revise one or both of these procedures to explicitly include at-grade former unit 2 doors. 239 Revise procedures to IPEEE Reduce the #3 - GGNS has created an Flooding periodically inspect Summary consequences of a Already inspection procedure for roof drains and Report [34] flood. installed roof drains, roof drainage overflows to ensure (Pg. 117) system, and roof overflows. they are not blocked. to GNRO-2012/00072 Page 76 of 81
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240 Remove the wooden IPEEE Improve site #1 - N/A The IPEEE showed the risk Flooding foot bridge crossing Summary drainage/external from external flooding at the northwest ditch Report [34] flood protection. GGNS is minor thus this near its upstream (Pg. 117) potential modification is end. assumed to not be cost beneficial which follows the same assumption in the SER. NRC Inspectors verified that the plant grade is 132.5 feet above mean seal level and that the maximum expected flood height from the Mississippi River is about 103 feet above mean sea level. Therefore, floodwaters from the Mississippi River are not expected to impact the plant. to GNRO-2012/00072 Page 77 of 81 241 Remove the 15" IPEEE Improve site #1 - N/A The IPEEE showed the risk corrugated metal Summary drainage/external from external flooding at pipe located in the Report [34] flood protection. GGNS is minor thus this small auxiliary ditch (Pg. 117) potential modification is parallel to the assumed to not be cost northwest ditch (at beneficial which follows the the same same assumption in the approximate location SER. as the duct bank crossing the NRC Inspectors verified northwest ditch). Re- that the plant grade is 132.5 grade the area to feet above mean seal level provide a gradual and that the maximum transition between expected flood height from the yard upstream, the Mississippi River is and the about 103 feet above mean auxiliary ditch. sea level. Therefore, floodwaters from the Mississippi River are not expected to impact the lant. to GNRO-2012/00072 Page 78 of 81 Re-hang the security IPEEE Improve site The IPEEE showed the risk fence gates west of Summary drainage/external from external flooding at the control building to Report [34] flood protection. GGNS is minor thus this insure that (Pg. 117) potential modification is approximately 5" assumed to not be cost of gap exists beneficial which follows the between the gate same assumption in the and the road. SER. NRC Inspectors verified that the plant grade is 132.5 feet above mean seal level and that the maximum expected flood height from the Mississippi River is about 103 feet above mean sea level. Therefore, floodwaters from the Mississippi River are not expected to impact the lant. to GNRO-2012/00072 Page 79 of 81 243 ii. ............................: .........*...*..:.. . . Grade down and IPEEE ii. ."'I".h.. 1 ........ Improve site f t L. .....
,I.AII& * ... #1 - N/A .'~'.
The IPEEE showed the risk Flooding remove the access Summary drainage/external from external flooding at road, the raised berm Report [34] flood protection. GGNS is minor thus this parallel to the access (Pg. 118) potential modification is road, and curbs assumed to not be cost adjacent to the beneficial which follows the access road as same assumption in the necessary where SER. they cross Culvert No.1, such that NRC Inspectors verified elevations above the that the plant grade is 132.5 culvert do not exceed feet above mean seal level 132.7 ft. above sea and that the maximum level. expected flood height from the Mississippi River is about 103 feet above mean sea level. Therefore, floodwaters from the Mississippi River are not expected to im pact the plant. to GNRO-2012/00072 Page 80 of 81 Table1 phaAAI~A"A
__ ._--~
244 I Replace the C8x11.5 IPEEE Improve site I #1 - N/A The IPEEE showed the risk Flooding channel forming the Summary drainage/external from external flooding at flood barrier across Report [34] flood protection. GGNS is minor thus this the SSW A (Pg. 118) potential modification is equipment hatch assumed to not be cost opening with another beneficial which follows the member having a same assumption in the minimum depth of SER. approximately 13". NRC Inspectors verified that the plant grade is 132.5 feet above mean seal level and that the maximum expected flood height from the Mississippi River is about 103 feet above mean sea level. Therefore, floodwaters from the Mississippi River are not expected to impact the plant. 245 Modify the piping IPEEE Reduce vulnerability #3 - The grout was removed Reduce systems to account Summary to a seism ic event. Already and the pipe support at the Seismic Risk for the grouted Report [34] installed penetration was modified to condition for the (Pg.119) coincide with the design penetration of the basis piping analysis Standby service assumption. water (SSW) piping in the Control Building. 246 Implement a better GNR12001- Reduce vulnerability #3 - A new standard (GGNS Reduce method to control 0034 NRC to a seism ic event. Already 17) was issued to address Seismic Risk seismic SER [20] installed seism ic housekeeping housekeeping issues, e.g., securing "S" issues. hooks on lighting fixtures and installing missing clips and screws. to GNRO-2012/00072 Page 81 of 81
*> .*.* . *ii*..*. p**.. . . . **.i.. i . . . . iii / . *********.***.***** >**** ...*......... / ...
J"lblfl1. _.L leA** AA . . .
*piii i i i . . ..*.*.*ip * * * .* i ..... i i i i i i 247 Upgrade thermo-lag NUREG Reduced fire risk. #3 - The thermo-lag barriers at Reduce Fire to ensure hourly fire 1742_Vol_2 Already GGNS have been Risk endurance rating. [8] installed improved.
248 Add a bypass around GGNS PRA Decrease the Retain GGNS has RHR heat Cooling Water the SSW inlet and Model probability of failing exchangers that can be outlet isolation valves the RHR HX due to a failed due to a single SSW for the RHR heat failed or plugged inlet or outlet valve. exchangers. isolation valve. 249 Add a redundant GGNS PRA Improve the reliability Retain The GGNS model shows Core Cooling RCIC lube oil cooling Model of RCIC. RCIC lube oil cooling Systems path. valves to be risk significant. Since this cooling path is just part of a much larger RCIC supercomponent, an evaluation should be performed to determine if this is the best reliability improvement for RCIC.
Attachment 3 to GNRO-2012100072 Release Mode Frequencies for Analysis Cases
Attachment 3 to GNRO-2012/00072 Page 1 of 3 Release Mode Frequencies for Analysis Cases Release Modes Analysis Cases HIE HII HIL M/E Mil MIL UE UI UL LUE LUI LUL CDF MAXBENEFIT 1.0SE-07 1.23E-08 8.73E-08 3.49E-07 1.73E-07 2.71 E-07 4.04E-09 3.34E-08 1.32E-07 2.00E-09 2.11 E-09 6.83E-09 2.0SE-06
1. DC Power 4.92E-08 8.48E-09 8.S8E-08 2.67E-07 1.69E-07 2.61 E-07 4.04E-09 3.29E-08 1.8SE-08 1.98E-09 2.11 E-09 6.81 E-09 1.77E-06

2. Improve Charger Reliability 1.02E-07 1.23E-08 8.2SE-08 3.43E-07 1.72E-07 2.60E-07 4.04E-09 3.34E-08 1.31 E-07 1.98E-09 2.11 E-09 6.83E-09 2.02E-06

3. Add DC System Cross-ties 9.37E-08 1.22E-08 S.02E-08 3.33E-07 1.66E-07 2.04E-07 4.04E-09 3.29E-08 1.30E-07 1.99E-09 2.11 E-09 6.7SE-09 1.90E-06

4. Increase Availability of On-Site AC Power 4.79E-08 8.02E-09 8.04E-08 2.62E-07 1.67E-07 2.21 E-07 4.04E-09 3.00E-08 1.74E-08 1.98E-09 2.08E-09 6.47E-09 1.69E-06

5. Improve AC Power 4.71 E-08 8.00E-09 7.90E-08 2.39E-07 1.67E-07 1.97E-07 4.02E-09 2.99E-08 1.71 E-08 1.98E-09 2.08E-09 6.4SE-09 1.63E-06

6. Reduce Loss of Off-Site Power During Severe Weather 9.31 E-08 1.14E-08 8.69E-08 3.31 E-07 1.72E-07 2.68E-07 4.04E-09 3.33E-08 1.08E-07 1.99E-09 2.11 E-09 6.81 E-09 1.99E-06

7. Provide Backup EDG Cooling 9.41 E-08 1.13E-08 9.84E-08 3.23E-07 1.7SE-07 2.78E-07 4.04E-09 3.26E-08 1.03E-07 1.99E-09 2.11 E-09 6.79E-09 2.01 E-06

8. Increase EDG Reliability 9.67E-08 1.17E-08 8.SSE-08 3.24E-07 1.73E-07 2.S7E-07 4.04E-09 3.23E-08 1.21 E-07 2.00E-09 2.09E-09 6.63E-09 1.98E-06

9. Improve DG Reliability 1.04E-07 1.22E-08 8.73E-08 3.48E-07 1.73E-07 2.71 E-07 4.04E-09 3.34E-08 1.29E-07 2.00E-09 2.11 E-09 6.83E-09 2.0SE-06

10. Reduce Plant-Centered Loss of Off-Site Power 6.9SE-08 9.83E-09 8.62E-08 2.96E-07 1.70E-07 2.64E-07 4.04E-09 3.30E-08 6.22E-08 1.98E-09 2.11 E-09 6.80E-09 1.86E-06

11. Redundant Power to Torus Hard Pipe Vent (THPV) Valves 1.0SE-07 1.23E-08 8.62E-08 3.49E-07 1.73E-07 2.S0E-07 4.04E-09 3.34E-08 1.31 E-07 2.00E-09 2.11 E-09 6.81 E-09 2.03E-06

12. High Pressure Injection System 6.18E-08 S.34E-09 1.21 E-09 2.69E-07 S.90E-08 6.66E-09 3.94E-09 S.48E-10 3.47E-10 4.44E-10 O.OOE+OO 2.0SE-11 4.SSE-07

13. Extend RCIC Operation 1.0SE-07 1.23E-08 8.73E-08 3.49E-07 1.73E-07 2.S0E-07 4.04E-09 3.34E-08 1.32E-07 2.00E-09 2.11 E-09 6.83E-09 2.03E-06

14. Improve ADS System 8.79E-08 1.21 E-08 8.3SE-08 3.10E-07 1.73E-07 1.67E-07 4.03E-09 2.69E-09 1.1SE-07 S.61E-10 6.24E-11 3.31 E-10 1.11 E-06

15. Improve ADS Signals 1.03E-07 1.11 E-08 8.81 E-08 3.43E-07 1.6SE-07 2.63E-07 4.39E-09 S.60E-10 1.14E-07 1.77E-09 O.OOE+OO 6.S7E-09 1.62E-06

16. Low Pressure Injection System 8.81 E-08 6.84E-09 9.78E-09 3.27E-07 6.86E-08 1.26E-07 4.33E-09 3.9SE-08 2.14E-08 2.S4E-09 2.6SE-09 8.70E-09 1.S8E-06

17. ECCS Low Pressure Interlock 1.0SE-07 1.23E-08 8.73E-08 3.49E-07 1.73E-07 2.S0E-07 4.04E-09 3.34E-08 1.32E-07 2.00E-09 2.11 E-09 6.83E-09 2.03E-06
Attachment 3 to GNRO-2012/00072 Page 2 of 3 Release Mode Frequencies for Analysis Cases Release Modes Analysis Cases HIE HII H/L MIE MIl MIL UE UI UL LUE LUI LUL CDF
18. RHR Heat Exchangers 1.02E-07 6.35E-09 7.97E-08 2.09E-07 4.72E-08 2.07E-07 3.86E-09 3.14E-08 1.33E-07 1.94E-09 2.03E-09 6.51 E-09 1.67E-06

19. Emergency Service Water System Reliability 1.03E-07 1.10E-08 8.68E-08 3.23E-07 1.50E-07 2.65E-07 3.99E-09 3.32E-08 1.28E-07 1.98E-09 2.10E-09 6.80E-09 1.98E-06

20. Main Feedwater System Reliability 7.94E-08 1.22E-08 1.84E-08 3.18E-07 1.63E-07 1.64E-07 4.18E-09 2.80E-08 1.29E-07 2.23E-09 1.84E-09 6.23E-09 1.65E-06

21. Increase Availability of Room Cooling 9.34E-08 1.16E-08 5.87E-08 3.27E-07 1.57E-07 1.52E-07 4.03E-09 2.36E-08 1.26E-07 1.57E-09 1.50E-09 4.84E-09 1.58E-06 22.1ncrease Availability of the DG System Through HVAC Improvements 7.12E-08 9.63E-09 8.72E-08 3.15E-07 1.71 E-07 2.43E-07 4.04E-09 3.33E-08 5.39E-08 1.99E-09 2.11 E-09 6.82E-09 1.86E-06

23. Increased Reliability of HPCI And RCIC Room Cooling 1.05E-07 1.23E-08 8.73E-08 3.49E-07 1.73E-07 2.50E-07 4.04E-09 3.34E-08 1.32E-07 2.00E-09 2.11 E-09 6.83E-09 2.03E-06

24. Increase Reliability of Instrument Air 1.01 E-07 1.12E-08 7.96E-08 2.31 E-07 1.63E-07 2.04E-07 4.01 E-09 2.23E-08 1.26E-07 1.87E-09 1.46E-09 4.74E-09 1.75E-06

25. Backup Nitrogen to SRV 1.04E-07 1.13E-08 8.55E-08 3.46E-07 1.65E-07 2.50E-07 4.02E-09 3.13E-08 1.30E-07 1.89E-09 2.05E-09 6.54E-09 1.94E-06

26. Improve Availability of SRVs and MSIVs 8.79E-08 1.21 E-08 8.35E-08 3.08E-07 1.73E-07 1.67E-07 4.03E-09 2.68E-09 1.15E-07 5.49E-10 6.24E-11 3.31 E-10 1.10E-06

27. Improve Suppression Pool Cooling 1.02E-07 6.35E-09 7.97E-08 2.09E-07 4.72E-08 2.07E-07 3.86E-09 3.14E-08 1.33E-07 1.94E-09 2.03E-09 6.51 E-09 1.67E-06

28. Increase Availability of Containment Heat Removal 8.89E-08 5.84E-09 5.34E-08 1.45E-07 2.93E-08 1.73E-07 3.85E-09 3.22E-08 1.32E-07 1.84E-09 2.11 E-09 6.82E-09 1.51 E-06

29. Decay Heat Removal Capability -
Drywell Spray 8.89E-08 5.84E-09 5.34E-08 1.45E-07 2.93E-08 1.73E-07 3.85E-09 3.22E-08 1.32E-07 1.84E-09 2.11 E-09 6.82E-09 1.51 E-06
30. Increase Availability of the CST 9.99E-08 7.25E-09 7.72E-08 3.39E-07 1.01 E-07 2.23E-07 3.96E-09 2.95E-08 1.29E-07 1.86E-09 1.83E-09 5.95E-09 1.82E-06

31. Filtered Vent to Increase Heat Removal Capacity For Non-ATWS Events 1.05E-07 1.23E-08 8.73E-08 3.49E-07 1.73E-07 2.71 E-07 4.04E-09 3.34E-08 1.32E-07 2.00E-09 2.11 E-09 6.83E-09 2.0SE-06

32. Reduce Hydrogen Ignition 6.00E-08 1.17E-08 1.60E-08 2.79E-07 1.59E-07 2.32E-07 3.98E-09 3.35E-08 1.13E-07 1.87E-09 2.11 E-09 6.27E-09 1.72E-06 to GNRO-2012/00072 Page 3 of 3 Release Mode Frequencies for Analysis Cases Release Modes Analysis Cases H/E H/I H/L M/E M/I M/L UE UI UL LUE LUI LUL CDF

33. Controlled Containment Venting 1.05E-07 1.23E-08 8.73E-08 3.12E-07 1.72E-07 2.50E-07 4.04E-09 3.34E-08 1.32E-07 2.00E-09 2.11 E-09 6.83E-09 1.99E-06

34. ISLOCA 1.05E-07 1.23E-08 8.73E-08 3.49E-07 1.73E-07 2.71 E-07 4.04E-09 3.34E-08 1.32E-07 2.00E-09 2.11 E-09 6.83E-09 2.05E-06

35. MSIV Design 1.05E-07 1.23E-08 8.73E-08 3.49E-07 1.73E-07 2.50E-07 4.04E-09 3.34E-08 1.32E-07 2.00E-09 2.11 E-09 6.83E-09 2.03E-06

36. SLC System 1.05E-07 1.23E-08 8.73E-08 3.49E-07 1.73E-07 2.50E-07 2.32E-09 3.34E-08 1.32E-07 1.83E-09 2.11 E-09 6.83E-09 2.03E-06

37. SRV Reseat 1.03E-07 1.16E-08 8.61 E-08 3.33E-07 1.58E-07 2.67E-07 4.04E-09 3.34E-08 1.30E-07 1.98E-09 2.11 E-09 6.83E-09 1.99E-06

38. Add Fire Suppression (1) - - - - - - - - - - - - -

39. Reduce Risk from Fires that Require Control Room Evacuation(1) - - - - - - - - - - - - -

40. Large Break LOCA 1.05E-07 6.24E-09 8.73E-08 3.47E-07 5.99E-08 2.70E-07 3.86E-09 3.34E-08 1.32E-07 1.94E-09 2.11 E-09 6.83E-09 1.91 E-06

41. Trip/Shutdown Risk 9.97E-08 1.20E-08 7.84E-08 3.22E-07 1.69E-07 2.44E-07 3.65E-09 3.00E-08 1.29E-07 1.75E-09 1.89E-09 6.10E-09 1.89E-06

42. Increase Availability of SSW Pump House Ventilation System 1.05E-07 1.22E-08 8.45E-08 3.48E-07 1.73E-07 2.49E-07 4.04E-09 3.30E-08 1.31 E-07 2.00E-09 2.10E-09 6.78E-09 2.02E-06

43. Increase Recovery Time of ECCS Upon Loss of SSW 1.05E-07 1.21 E-08 8.09E-08 3.48E-07 1.65E-07 2.12E-07 4.04E-09 3.34E-08 1.31 E-07 2.00E-09 2.11 E-09 6.83E-09 1.97E-06

44. Additional Containment Heat Removal 8.89E-08 5.84E-09 4.91 E-08 1.45E-07 2.88E-08 1.59E-07 3.85E-09 3.13E-08 1.32E-07 1.84E-09 2.03E-09 6.50E-09 1.49E-06

45. Improve RHR Heat Exchanger Availability 1.04E-07 1.06E-08 8.73E-08 3.17E-07 1.41 E-07 2.71 E-07 3.98E-09 3.34E-08 1.32E-07 1.98E-09 2.11 E-09 6.83E-09 1.98E-06

46. Improve RCIC Lube Oil Cooling 9.81 E-08 1.23E-08 8.70E-08 3.41 E-07 1.73E-07 2.67E-07 4.04E-09 3.27E-08 1.20E-07 1.86E-09 2.11 E-09 6.76E-09 1.95E-06 These analysis cases only impact external events and have been evaluated as explained in response to RAI 3.c}}

GNRO-2012/00072, Response to Request for Additional Information (RAI) on Severe Accident Mitigation Alternatives Dated May 21, 2012

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GNRO-2012/00072, Response to Request for Additional Information (RAI) on Severe Accident Mitigation Alternatives Dated May 21, 2012

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