ML100910252

Request for Additional Information Regarding Severe Accident Mitigation Alternatives for Salem Nuclear Generating Station Units 1 and 2

ML100910252
Person / Time
Site:	Salem
Issue date:	04/12/2010
From:	Eccleston C License Renewal Projects Branch 1
To:	Joyce T Public Service Enterprise Group
Charles Eccleston, NRR/DLR/RPB1,415-8537
References
FOIA/PA-2011-0113
Download: ML100910252 (14)

Text

April 12, 2010 Mr. Tom Joyce President and Chief Nuclear Officer PSEG Nuclear LLC P.O. Box 236 Hancocks Bridge, NJ 08038

SUBJECT:

REQUEST FOR ADDITIONAL INFORMATION REGARDING SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR SALEM NUCLEAR GENERATING STATION, UNITS 1 AND 2

Dear Mr. Joyce:

The U.S. Nuclear Regulatory Commission staff has reviewed the Severe Accident Mitigation Alternatives analysis submitted by Public Service Enterprise Group Nuclear, LLC (PSEG) regarding its application for license renewal of the Salem Nuclear Generating Stations, Units 1 and 2, and has identified areas where additional information is needed to complete its review.

Enclosed is the staff=s request for additional information.

We request that you provide your responses to these questions within 45 days of the date of this letter, in order to maintain the environmental review schedule. If you have any questions, please contact me at 301-415-8537 or by e-mail at charles.eccleston@nrc.gov.

Sincerely, Charles Eccleston, Project Manager /RA/

Projects Branch 1 Division of License Renewal Office of Nuclear Reactor Regulation Docket Nos. 50-272 and 50-311

Enclosure:

As stated cc w/encl: See next page

ML100910252 OFFICE LA:DLR PM:DLR:RPB1 BC:DLR:RPB1 NAME SFigueroa CEccleston BPham DATE 04/12/10 04/12/10 4/12/10 Letter to Tom Joyce from C. Eccleston, dated March , 2010

SUBJECT:

REQUEST FOR ADDITIONAL INFORMATION REGARDING SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR SALEM NUCLEAR GENERATING STATION, UNITS 1 AND 2 DISTRIBUTION:

HARD COPY:

DLR RF E-MAIL:

PUBLIC RidsNrrDlr Resource RidsNrrDlrRpb1 Resource RidsNrrDlrRpb2 Resource RdsNrrDlrRarb Resource RidsNrrDlrRasb Resource RidsNrrDlrRapb Resource RidsOgcMailCenter Resource BPham BBrady CEccleston REnnis CSanders MModes, RI DKern, RI JBrand, RI RConte, RI RBellamy, RI MMcLaughlin, RI

Salem Nuclear Generating Station, Units 1 and 2 cc:

Mr. Robert Braun Mr. Paul Bauldauf, P.E., Asst. Director Station Vice President - Salem Radiation Protection Programs PSEG Nuclear LLC NJ Department of Environmental One Alloway Creek Neck Road Protection and Energy, CN 415 Hancocks Bridge, NJ 08038 Trenton, NJ 08625-0415 Mr. John Perry Mr. Brian Beam Station Vice President - Hope Creek Board of Public Utilities PSEG Nuclear 2 Gateway Center, Tenth Floor P.O. Box 236 Newark, NJ 07102 Hancocks Bridge, NJ 08038 Regional Administrator, Region I Mr. Carl Fricker U.S. Nuclear Regulatory Commission Vice President - Operations Support 475 Allendale Road PSEG Nuclear LLC King of Prussia, PA 19406 One Alloway Creek Neck Road Hancocks Bridge, NJ 08038 Senior Resident Inspector Salem Nuclear Generating Station Mr. Jeffrie J. Keenan, Esquire U.S. Nuclear Regulatory Commission Manager - Licensing Drawer 0509 PSEG Nuclear LLC Hancocks Bridge, NJ 08038 One Alloway Creek Neck Road Hancocks Bridge, NJ 08038 Senior Resident Inspector Hope Creek Generating Station Mr. William Mattingly U.S. Nuclear Regulatory Commission Manager - Salem Regulatory Assurance Drawer 0509 PSEG Nuclear LLC Hancocks Bridge, NJ 08038 One Alloway Creek Neck Road Hancocks Bridge, NJ 08038 Mr. Michael Gallagher Vice President - License Renewal Projects Mr. Michael Gaffney Exelon Nuclear LLC Manager - Hope Creek Regulatory 200 Exelon Way Assurance Kennett Square, PA 19348 PSEG Nuclear LLC One Alloway Creek Neck Road Mr. Ed Eilola Hancocks Bridge, NJ 08038 Plant Manager - Salem PSEG Nuclear LLC One Alloway Creek Neck Road Township Clerk Hancocks Bridge, NJ 08038 Lower Alloways Creek Township Municipal Building, P.O. Box 157 Mr. Larry Wagner Hancocks Bridge, NJ 08038 Plant Manager - Hope Creek PSEG Nuclear LLC One Alloway Creek Neck Road Hancocks Bridge, NJ 08038

Salem Nuclear Generating Station, Units 1 and 2 cc:

Mr. Paul Davison Director - Nuclear Oversight PSEG Nuclear LLC One Alloway Creek Neck Road Hancocks Bridge, NJ 08038 Ms. Christine Neely Director - Regulator Affairs PSEG Nuclear LLC One Alloway Creek Neck Road Hancocks Bridge, NJ 08038 Mr. Ali Fakhar Manager, License Renewal Salem PSEG Nuclear LLC One Alloway Creek Neck Road Hancocks Bridge, NJ 08038 Mr. James Stavely Manager, License Renewal Hope Creek PSEG Nuclear LLC One Alloway Creek Neck Road Hancocks Bridge, NJ 08038 Mr. Earl R. Gage Salem County Administrator Administration Building 94 Market Street Salem, NJ 08079 Mr. Edward J. Keating Environmental Manager PSEG Nuclear LLC One Alloway Creek Neck Road P.O. Box 236, Mail Code N21 Hancocks Bridge, NJ 08038 Ms. Nancy L. Ranek License Renewal Environmental Lead Exelon Nuclear LLC 200 Exelon Way, KSA/2-E Kennett Square, PA 19348

Request for Additional Information Regarding the Analysis of Severe Accident Mitigation Alternatives for Salem Nuclear Generating Station (SGS), Units 1 and 2

1. Provide the following information regarding the Level 1 Probabilistic Safety Assessment (PSA) used for the Severe Accident Mitigation Alternatives (SAMA) analysis:

a. Section E.2.1 provides varying levels of detail describing the PSA model changes made since the IPE Level 1 model. For PRA Model Versions 2.0 and 3.0, provide additional description of the model changes that most impacted the change in CDF. For PRA Model Versions 3.2, 3.2A, and 4.0, identify the model changes listed in Section E.2.1 that most impacted the change in CDF.

b. Section E.2.1.3 explains that although early versions of the SGS PRA modeled both Unit 1 and 2, only Unit 1 was modeled starting with PRA model of record Revision 3.0 (June 2002). Explain the differences in configuration between Unit 1 and 2 and how configuration and administrative changes that could potentially produce significantly different CDFs for the two units were tracked. In the response, identify any of the Unit 2 differences that would potentially show up on the Level 1 or 2 importance lists and assess SAMAs to address these differences.

c. Section E.2.3 states that in November 2008 a PWR Owners group team performed a peer review of Revision 4.1, but that the peer review comments had not yet been received. It is our understanding that the peer review report is now available. Provide a summary of the scope of the peer review (e.g., Level 1, Level 2, internal flooding), a description of the significant review comments and their resolution, and an assessment of the potential impact of any unresolved comments on the results of the SAMA analysis.

Describe any other internal and external reviews of the Level 1 (including internal flooding) and Level 2 PRA model, significant review comments and their resolution, and the impact of unresolved comments on the results of the SAMA analysis.

d. Section E.2.2 states that the PRA model of record Revision 4.1 was used for the SAMA analysis reflects SGS plant data and incorporation of plant modifications up through December 2006. Identify any changes to the plant (physical and procedural modifications) since December 2006 that could have a significant impact on the results of the PSA and/or the SAMA analyses. Provide a qualitative assessment of their impact on the PSA and on the results of the SAMA evaluation.

e. Figures E.2-1 and E.2-2 provide the contribution to CDF by Level 1 initiator. Provide a table showing the actual numerical values for the CDF contribution for each initiator that sums to the total internal events CDF (4.77 x 10-5/yr).

f. Provide the numerical value for the CDF contribution from SBO and identify the initiators that contribute to SBO.

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

a. Section E.2.2.2.1 states that starting with model of record Revision 3.0 (i.e. 2002) only LERF was calculated. Table E.3-7 shows non-LERF Release Categories (e.g. LATE-

b. CHR-NOAFW) produce significant dose consequences. Describe how the frequencies for the non-LERF Release Categories were estimated in support of the SAMA analysis.

c. Page E-27 states that the Salem Level 2 model was essentially abandoned and then recreated and used in PRA Model Version 4.1 for the SAMA analysis. Section E.2.2.2.1 states that starting with Revision 3 of the PRA model only LERF was calculated. Clarify the Level 2 model development history, including when (after which PRA version) the Level 2 model was abandoned, and in which PRA version the Level 2 model was recreated.

d. Section E.2.2.3 states that Containment Event Tree (CET) top events represent questions that are answered based on previous work for Salem Level 2, recent accident progression research, and similar analyses for other nuclear plants. It is apparent, however, from later discussion that fault tree modeling was also used as a basis (e.g.

fault tree YCI-GCI1100 was used to address Containment Isolation top event). It is not clear what the basis for the branch probabilities was for top events RCS Depressurization and Containment Heat Removal. Clarify the basis for addressing the branch point probabilities for these top events.

e. Section E.2.2.4 provides the rationale for and describes the process of identifying appropriate parameters to bin Plant Damage States (PDSs). However, the third paragraph of Section E.2.2.4.1 states that This permits the somewhat artificial boundary between the Level 1 event trees and the containment event trees (i.e. the PDS) to be eliminated from this analysis. Clarify the meaning of artificial and eliminated and how PDSs are considered in the SAMA analysis.

f. Identify the version of MAAP used in the SAMA analysis.

g. Section E.2.2.7.1 states that for the LATE release categories the most likely initiators and sequences were chosen to represent the category, while for the LERF release categories both the likelihood and the consequences were considered in selecting representative sequences. Justify why the consequences were not also considered in identifying the representative sequence for LATE releases since, as indicated in Table E.3-7, LATE-CHR-NOAFW accounts for more than 50 percent of the Dose-Risk and more than 30 percent of the OECR. In addition, clarify what is meant by most likely initiators and sequences and provide an example of how this is applied for release category LERF-CFE.

h. Page 3-4 reports that the licensed thermal power for SGS Unit 1 is 3,459 MWt, which equates to a net electrical output of 1,195 MWe when operating at 100 percent power.

Page E-59 states that the current licensed power is 3468 MWt, but that the core inventory is based on a thermal power level of 3632 MWt (5 percent above the licensed power level). Provide the rationale for using 3632 MWt in determining the core inventory used in the SAMA analysis.

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

a. Section E.5.1.5.1.3 identifies that PSEG has replaced CO2 fire suppression systems with water sprinkler systems in several areas at Salem since the IPEEE. For each of the

b. dominant fire areas, explain what additional measures, if any, have already been taken (since the IPEEE) to reduce fire risk. Include in the response specific improvements to fire detection systems, enhancements to fire suppression capabilities, changes that would improve cable separation, and improvements to processes/procedures for monitoring and controlling the quantity of combustible materials in critical areas.

c. Section E.5.1.5 presents a table that summarizes the status of three potential plant improvements based on the results of the IPEEE processes. The IPEEE SER identifies five additional potential plant improvements as follows: (1) a procedural change to ensure long term alternate ventilation for the Auxiliary Building, (2) the replacement of identified low ruggedness relays with higher seismic capacity relays, (3) a procedural change to enhance cooling in the switchgear and control areas in the event of a fire, (4) improved hold downs for the hydrogen tanks to protect against tornadoes, and (5) modifications to the plant circulating water intake structure to protect against detritus (blockage). (Section 5.1.6.4 seems to indicate that Item (4) has been implemented and Section E.5.1.6.7 seems to indicate that Item (5) has been implemented.) Confirm that all of these items have been implemented. If not, provide an evaluation of a SAMA that addresses those improvements that have not been implemented.

d. Section E.4.6.2 mentions the interim SGS fire model (SCIENTECH 2003) that was used to provide insights for three fire areas in which fire suppression systems were changed since the IPEEE. Provide the background/history of the development of this model and a brief description of the model. Clarify in the response whether the model is an evolution of the IPEEE model or a completely new model, whether the model was integrated with the Level 1 model or is a stand-alone model, to what PRA standards the model was developed, and why the model has not been implemented at Salem.

e. A liquefied natural gas terminal has been approved for construction in Logan Township, NJ. Discuss the status of this facility and the potential impact of the transportation of LNG to this facility on SGS during the license renewal period.

4. Provide the following information concerning the MACCS2 analyses:

a. Section E.3.2 states that SECPOP2000 census data from 1990 to 2000 were used to determine the population growth factor, and that the population growth was averaged over each ring and applied uniformly to all sectors within each ring. Using an average growth over a ring mixes growth rates from significantly different regions. For example; portions of Kent County, Delaware, Chester County, Pennsylvania, and Cumberland County New Jersey will lie on similar rings. Between years 2000 and 2003, they had population growths of 6.1%, 5.5% and 2.0%, respectively (http://www.epodunk.com/top10/countyPop/coPop8.html, http://www.epodunk.com/top10/countyPop/coPop39.html, and http://www.epodunk.com/top10/countyPop/coPop31.html). Provide an assessment of the potential impact on PDR and OECR if a wind-direction weighted growth estimate for each sector were used.

b. Section E.3.2 does not discuss transient population. Clarify whether transient population was considered in the analysis. If a transient population was not considered, provide a justification/rationale for not including it.

c. Section E.7.3.4 describes a population sensitivity case in which the 2040 population was uniformly increased by 30 percent in all sectors of the 5-mile radius. Section E.3.2 states that SECPOP2000 census data from 1990 to 2000 were used to determine the 10 year population growth factor. It is unclear if the 30 percent sensitivity case bounds the population growth rate if updated population growth estimates are used (see RAI 4a).

Provide an assessment of the impact on PDR and OECR using currently available population growth estimates for the surrounding counties and states.

d. Section 3.1.2 identifies the allowable fuel burnup and enrichment for SGS. Confirm that this is consistent with the core inventory used in the SAMA analysis.

5. Provide the following with regard to the SAMA identification and screening process:

a. It appears that the SAMA identification process eliminated many potential SAMAs by using the generic list of SAMAs in NEI 05-01 only to identify types of changes to address items identified through the importance list review (rather than starting with the generic list and eliminating SAMAs using the screening criteria). Justify that the Phase I SAMA identification and screening process produced a comprehensive sufficiently complete set of SAMAs for consideration, given that 17 of the 27 Phase 1 SAMAs were ultimately determined to be potentially cost-beneficial.

b. Section E.5.1.1 explains that PSEG used a review threshold RRW of 1.01 for the Level 1 and 2 importance list reviews, which corresponds to a single unit averted cost-risk of about $164,000. This section also explains that the assumed cost of procedural changes in the SAMA analysis was $50,000 to $100,000 for the site and that the offsite economic cost-risk reduction corresponding to $50,000 would be 1.003. The section also acknowledges that performing a RRW review to the level of 1.003 would likely generate additional unique SAMAs, some of which could be cost beneficial. Provide a review of basic events down to an RRW of 1.003 and an evaluation of any new SAMAs that arise from this review.

c. Table E.5-1 describes SAMA 8, installing a high pressure pump powered with portable diesel generator, as a way to reduce the risk associated with Event AFS-MDP-FS-DF04:

Dependent failure of 3 AFW Pumps (Steam binding). The table indicates that the contribution from this particular failure could potentially be reduced by operating with the AF11/21 valves closed but that a more comprehensive enhancement would be a portable diesel driven pump (i.e. SAMA 8). Section E.6.8.3 presents an estimated unit cost for SAMA 8 of $2.5M and concludes that SAMA 8 is not cost beneficial. The cost of operating with the AF11/21 valves would appear to be much lower than $2.5M. Provide a cost-benefit evaluation of a SAMA to operate with the AF11/21 valves closed as a lower cost alternative to SAMA 8.

d. Table E.5-1 identifies several events beginning with the symbol % as either initiators or flags for initiators, and proposes SAMAs for both kinds of events. Clarify why SAMAs were proposed for flags for initiators. If the initiator flags are meant to be surrogates for the actual initiator clarify why a value of 1.0 is the appropriate probability on which to base the importance analysis.

e. Table E.5-1 identifies two events that are split fractions (i.e. RCS-SLOCA-SPLIT: Split fraction for seal LOCA after cooling with a probability of 1.0, and MFI-UNAVIALABLE:

Split fraction for MFW unavailable with a probability of 0.3). Describe the significance of the SAMAs proposed for these events.

f. PSEGs review of Phase 2 SAMAs from prior SAMA submittals appears to have overlooked additional potentially cost-beneficial SAMAs identified during the NRC staffs review of the referenced plants, for example, Point Beach SAMA 169, provide portable generators to be hooked up to turbine driven AFW after battery depletion, and use of a gagging device to remotely close a stuck open safety valve on a ruptured steam generator at Prairie Island For these and any other additional cost-beneficial SAMAs, provide an assessment of their applicability to SGS, and a cost-benefit evaluation for any SAMA determined to be applicable.

g. SAMA 20, which involves installing a fire safe system to provide makeup to the RCS and steam generators, would reduce the risk associated with fire area 1FA-AB-84A:

460V Switchgear Rooms at a cost of $13M. SAMA 23, which involves providing separation between power divisions by installing barriers or wrap, would reduce the risk associated with fire area, 1FA-AB-64A: 4160 Switchgear Room at a far lower cost of

$975K. Provide an evaluation of a SAMA to install improved fire barriers to provide separation between the three divisions as a lower cost alternative to SAMA 20.

h. SAMA 8, which involves providing an engine driven, high pressure makeup pump for the steam generators, would reduce the risk associated with fire area 1FA-AB-84B: Reactor Plant Aux Equip Area at a cost of $2.5M. Provide an evaluation of a SAMA to install improved fire barriers to provide separation between the AFW pumps.

i. Table E.5-3 describes the source of SAMA 24 as the SGS IPEEE (Fire). However, neither Section E.5.1.5 nor E.5.1.6 identify this SAMA from the review of the plant changes identified in the SGS IPEEE or from the review of the SGS IPEEE fire model, respectively. While the source of this SAMA appears to be the review of fire area 12FA-SW-90A/90B: Service Water Intake, SAMA 24 is assumed to only provide benefits in internal events. Clarify the source for SAMA 24 and the PRA model changes made to evaluate this SAMA.

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

a. Section E.6 introduction states that plant personnel developed SGS specific costs to implement each of the SAMAs. Provide a description of: the process PSEG used to develop the SAMA implementation costs, the level of detail used to develop the cost estimates (i.e., general cost categories), and how the calculations are documented.

b. For certain Phase I SAMAs listed in Table E.5-3, the information provided does not sufficiently describe the associated modifications and what is included in the cost estimate. Provide a more detailed description of both the modification and the cost estimate for SAMAs 3, 5, 8, 13, 20, and 23.

c. SAMAs 1 and 17 are similar in that each involves opening doors to provide ventilation and using portable fans to enhance natural circulation if required. However, the

estimated implementation costs are significantly difference ($475K and $200K, respectively). Provide an explanation of the reasons for the differences in the cost estimates for these SAMAs.

d. SAMAs 21and 22 are similar in that each involves installing fire barriers to prevent the propagation of a fire between cabinets. SAMA 21 modifies 48 cabinets at a cost of

$3.23M while SAMA 22 modifies 3 consoles at a cost of $1.6M, which is only about half the cost of SAMA 21. Provide an explanation for this apparent discrepancy.

e. SAMAs 10 and 11, which appear to only involve procedure modifications, are each estimated to have an implementation cost of $100K (per unit). Section E.5.1.1 states that the minimum expected implementation cost is assumed to be a procedure change at

$50K to $100K for the site. Justify the implementation cost estimates of $100K for SAMAs 10 and 11, and confirm that the cost estimates are for a single unit.

f. The benefit and net value calculations for SAMAs 1, 5, and 8 are not consistent with the methodology described. For example, the SAMA 1 Non-Fire Averted Cost-Risk on page E-117 includes the full external event multiplier of 2 as described in Section 4.6.3 (which includes fire CDF). A calculation for fire averted cost-risk is then added to the previous calculation (apparently double counting the fire risk). Furthermore, while the SAMA 1 Net Value table on page E-119 shows a cost of implementation of $475K, the Net Value calculated assumes an implementation cost of only $100K. Clarify these discrepancies and provide revised analyses if necessary.

g. The tables on pages E-121, E-125, E-150, E-151, and E-190 for SAMAs 2, 4, 18, 19, and 5A (providing the change in CDF, PDR, and OECR by release category) are inconsistent with the SAMA quantification results and appear to be incorrect. Provide corrected tables, and any other corrections if necessary.

h. The cost of implementation of SAMA 3, as shown in Table E.5-3, is $525K. However, the SAMA analysis in Section E.6.3 uses an implementation cost of $4.175M. Clarify which is correct and provide a revised analysis if necessary.

i. For SAMA 5, the likelihood of offsite power nonrecovery was changed to 0.01 for grid and site/switchyard-related causes and to 0.03 for weather-related causes. Provide the baseline probabilities for these nonrecovery events.

j. Clarify the PRA model changes made for SAMA 17. Provide the initial and revised probability values used for failure of the EDG control room HVAC fans.

k. Page 3-4 reports that the licensed thermal power for SGS Unit 1 is 3,459 MWt, which equates to a net electrical output of 1,195 MWe when operating at 100 percent power.

Page E-67 states that a power level of 1115 MWe was used to calculate long-term replacement power costs for the SAMA analysis, which is non-conservative with respect to the licensed power level. Clarify this discrepancy.

7. PSEGs cost-benefit analysis showed that 12 of the SAMA candidates (SAMAs 1, 2, 4, 5A, 6, 9, 10, 11, 12, 14, 17, and 24) were potentially cost-beneficial in the baseline analysis and that an additional five SAMAs (SAMAs 3, 5, 7, 8, and 27) were potentially cost-beneficial

based on the results of the sensitivity analysis. Address the following relative to these potentially cost-beneficial SAMAs:

a. PSEG states on page E-194 that all 17 of these potentially cost-beneficial SAMAs will be considered for implementation using the existing Salem action-tracking and design change processes. Page 4-46 states that these potentially cost-beneficial SAMAs will be considered for implementation through the established Salem Plant Health Committee processes. Describe these two processes and how they are used to evaluate potentially cost-beneficial SAMAs.

b. In view of the significant number of potentially cost-beneficial SAMAs, it is likely that several of these SAMAs address the same risk contributors. As such, implementation of an optimal subset of these SAMAs could achieve a large portion of the total risk reduction at a fraction of the cost, and render the remaining SAMAs no longer cost-beneficial. In this regard: identify those SAMAs that PSEG considers highest priority for implementation, provide a revised cost-benefit analysis assuming these high priority SAMAs are implemented, and identify those SAMAs that would no longer be cost-beneficial given implementation of the high-priority SAMAs. Also, provide any specific plans/commitments regarding implementation of the high priority SAMAs.