ML11263A030
| ML11263A030 | |
| Person / Time | |
|---|---|
| Site: | Salem, Hope Creek  |
| Issue date: | 09/20/2010 |
| From: | Bo Pham NRC/NRR/DLR/RARB |
| To: | Leslie Perkins License Renewal Projects Branch 2 |
| References | |
| FOIA/PA-2011-0113 | |
| Download: ML11263A030 (36) | |
Text
/
Pham, Bo From: Pham, Bo Sent: Monday, September 20, 2010 11:46 AM To: Perkins, Leslie
Subject:
Fw: Salem/Hope Creek Chapter 5 SAMA input Attachments: SalemHope Creek SAMA Chapter 5.docx Leslie, let's meet up tomorrow to see what you've been able to do with chapter 5?
Thanks.
Sent from NRC blackberry Bo Pham From: Ghosh, Tina To: Perkins, Leslie Cc: Gallucci, Ray; Howe, Andrew; Pham, Bo; Harrison, Donnie Sent: Fri Sep 17 14:47:03 2010
Subject:
Salem/Hope Creek Chapter 5 SAMA input
Dear Leslie,
Attached please find the Salem/Hope Creek SAMA input for Chapter 5.
As I discussed with Bo on the phone just a few minutes ago, this Ch. 5 input is quite a bit longer than the other SAMA Ch. 5 inputs because we are discussing 2 separate plant analyses (versus one), but also because there are additional details in this input that we traditionally have not included in the chapter 5 SAMA summary (we have new staff working on the SAMA reviews, slightly new approach; if you take a look at any of the recently published SEIS's, you'll see what we previously included in the standard Ch. 5 SAMA write-up).
Bo said that you can shorten the Ch. 5 input if needed, and I agreed that DRA/APLA staff can review any changes made.
Let me know if you have any questions.
Best regards, Tina From: Pham, Bo Sent: Friday, September 17, 2010 1:21 PM To: Harrison, Donnie Cc: Gallucci, Ray; Howe, Andrew; Perkins, Leslie; Ghosh, Tina
Subject:
RE: ACTION: Hope Creek SAMA Transmittal Memo
- Donnie, I think you're working from home today. I believe Leslie has received the Appendices for both Salem & Hop, Creek from Tina yesterday.
Are you providing us the Chapter 5 write-up today?
Thanks.
26
5.2 Severe Accident Mitigation Alternatives 10 CFR Section 51.53(c)(3)(ii)(L) requires that license renewal applicants consider alternatives to mitigate severe accidents if the staff has not previously evaluated Severe Accident Mitigation Alternatives (SAMAs) for the applicant's plant in an environmental impact statement (EIS) or related supplement or in an environmental assessment.. The purpose of this consideration is to ensure that plant changes (i.e., hardware, procedures, and training) with the potential for improving severe accident safety performance are identified and evaluated. SAMAs have not been previously considered for the Salem (Nuclear) Generating Station (SGS) or Hope Creek Generating Station (HCGS) operated by PSEG Nuclear, LLC (PSEG); therefore, the remainder of Section 5.2 addresses those alternatives.
5.2.1 Overview of SAMA Process This section presents a summary of the SAMA evaluations for SGS and HCGS conducted by PSEG and the NRC staffs reviews of those evaluations. The NRC staff performed its reviews with contract assistance from Pacific Northwest National Laboratory (PNNL). The NRC staff's reviews are available in full in Appendices F and G; the SAMA evaluations are available in full in PSEG's environmental reports (ERs) for SGS and HCGS (PSEG 2009a, PSEG 2009b).
PSEG's efforts to identify potential SAMAs for both SGS and HCGS focused primarily on areas associated with internal initiating events, but also included explicit consideration of potential SAMAs for fire and seismic events. The initial lists of SAMAs generally addressed the accident sequences considered to be important to core damage frequency (CDF) from functional, initiating event, and risk reduction worth (RRW) 1 perspectives at both SGS and HCGS, and included selected SAMAs from prior SAMA analyses for other plants.
5.2.1.1 Phase-I Screening Specifically, PSEG reviewed the following for both SGS and HCGS: (1) the most significant basic events from the current, plant-specific PRAs and insights from the SGS and HCGS PRA Groups; (2) potential plant improvements identified in, and original results of the SGS and HCGS Individual Plant Examinations (IPEs) and IPEs for External Events (IPEEEs) (PSEG 1993, PSEG 1994, PSEG 1995, PSEG 1996, PSEG 1997); (3) SAMA candidates identified for license renewal applications for six other U.S. nuclear sites; and (4) generic SAMA candidates from NEI 05-01 (NEI 2005) to identify SAMAs that might address areas of concern identified in the SGS and HCGS PRAs. As a result of these reviews, PSEG generated initial sets of 27 and 23 candidate SAMAs (Phase-I SAMAs) for SGS and HCGS, respectively. Each list was further reviewed to qualitatively screen out candidate SAMAs that were: (1) not applicable at SGS, or HCGS, due to design differences; (2) already implemented at SGS, or HCGS; (3) capable of achieving results already realized at SGS, or HCGS, by other means; or (4) estimated to have.
implementation costs that would exceed the dollar value associated with completely eliminating RRW is the factor by which the CDF would decrease ifthe basic event were always assumed to succeed (i.e., basic event probability of failure set to 0).
all severe accident risk at SGS, or HCGS. As a result, two candidate SAMAs were screened out at each site, leaving 25 and 21 Phase-I SAMAs for SGS and HCGS, respectively.
For both SGS and HCGS, PSEG provided a tabular listing of the Level-1 PRA basic events sorted according to their RRW (PSEG 2009a, PSEG 2009b) since SAMAs impacting these basic events would have the greatest potential for reducing risk. PSEG used a RRW cutoff of 1.01 for SGS and 1.006 for HCGS, corresponding to 1% and 0.6% changes in CDF, respectively, given 100% reliability of the SAMA. These equate to approximate benefits of
$164,000 for SGS (after the benefits have been multiplied by a factor of 2 to account for SGS external events) and $100,000 for HCGS (after the benefits have been multiplied by a factor of 6.3 to account for HCGS external events). The latter value is the minimum implementation cost associated with a procedure change at HCGS. For SGS, PSEG also provided and reviewed the Level-2 PRA basic events, down to a RRW of 1.01, for the release categories contributing over 94% of the population dose-risk. As a result of these reviews, PSEG identified an additional 19 SAMAs for SGS and 11 for HCGS.
5.2.1.1.1 Salem (Nuclear) Generating Station (SGS)
For SGS, the NRC staff requested PSEG to extend the review of the Level-1 and 2 basic events down to a RRW threshold corresponding to the assumed cost of a procedural change at SGS, i.e., approximately $50,000 (NRC 2010a). In response to the request for additional information (RAI), PSEG extended the review down to an RRW of 1.006, which equates to a benefit of about
$47,000. The review identified three additional SAMAs, for which detailed evaluations were conducted in Phase II. (PSEG 2010a, PSEG 2010c)
For SGS, the NRC staff asked PSEG to clarify the appropriateness of determining importance factors, and SAMAs, for initiators with an assigned probability of 1.0 (NRC 201 Oa). In addition, the NRC staff asked PSEG to clarify the significance of determining importance factors, and SAMAs, for two specific split fraction events identified in the importance listing. PSEG explained why they considered these events to be representative of the initiating event's contribution to CDF and therefore considered appropriate for risk ranking. PSEG concluded that the RRW calculated for these events correctly measures the risk significance of the initiating event modeled in this manner. (PSEG 2010a, PSEG 201 Oc) 5.2.1.1.2 Hope Creek Generating Station (HCGS)
For HCGS, the NRC staff requested PSEG to extend the review of the Level-1 basic events down to a RRW of 1.005 to account for a revised external events multiplier of 6.8 (see Section 5.2.2.4) (NRC 201 Ob). This extended review identified one additional SAMA, for which detailed evaluation was conducted in Phase II. (PSEG 201 Ob, PSEG 201 Od)
For the important Level-1 initiating events at HCGS, PSEG stated that "This initiator event is a compilation of industry and plant specific data. (No specific SAMA identified)". The NRC staff requested that PSEG provide assurance for each that there is no dominant contributor for which a potential SAMA to reduce the initiating event frequency or mitigate the impact of the initiator
would be viable (NRC 2010b). In response to this RAI, PSEG discussed each of the initiators and the previously identified SAMAs that would reduce its importance by mitigating other failures in the associated core damage sequences. In addition, PSEG indicated that HCGS-specific failures contributing to the initiating event frequencies that pose a unique vulnerability are typically captured and corrected within existing procedures and can result in procedure changes, plant modifications and training enhancements to reduce further recurrence (PSEG 2010c, PSEG 2010d). Based on this discussion and a review of the latest ten years of HCGS Licensee Event Reports, the NRC staff concludes that it is unlikely that further HCGS data review will identify any additional cost beneficial SAMAs beyond those already identified. (PSEG 201 Ob, PSEG 201 Od)
The NRC staff requested clarification on initiators modeled via a fault tree approach rather than being based on initiating event data. For an event involving the station service water system, the NRC staff requested clarification on the source and applicability of two SAMAs identified as related to this event (NRC 2010b, NRC 2010d). In response, PSEG (1) identified and evaluated a new SAMA, "Installation of Station Auxiliaries Cooling System Standby Diesel-Powered Pump;" and (2) discussed the applicability of the two SAMAs related to, and other SAMAs that would mitigate, loss of station service water (PSEG 201 Oa, PSEG 201 Oc). Based on this discussion, the NRC staff concludes that these events are adequately addressed in the HCGS SAMA analysis.
For a significant number of the HCGS Level-1 events reviewed, no SAMAs were identified because "... based on low contribution to L[evel] 1 risk and engineering judgment, the anticipated implementation costs of hardware mod[ification]s associated with mitigating this event would likely exceed the expected cost-risk benefit" (PSEG 2009b). In response to an NRC staff RAI, PSEG provided a revised assessment of each of these events that showed that each was either already addressed by an existing SAMA or that no effective SAMAs could be identified (PSEG 2010b, PSEG 2010d). The NRC staff also requested PSEG to specifically consider four newly proposed SAMAs to address basic events on the HCGS Level-1 importance list for which no SAMA was identified (NRC 2010b). These four SAMAs were related to miscalibration of a temperature controller, relay room flood barriers, spray shielding for a motor-operated valve (MOV), and passive containment ventilation. For each, PSEG concluded that the SAMA was not necessary or not feasible (PSEG 201 Ob, PSEG 2010d).
5.2.1.2 Phase II Screening PSEG reviewed the cost-beneficial Phase-Il SAMAs from prior SAMA analyses for other reactor sites, including one General Electric BWR and five Westinghouse PWR sites for SGS, and one Westinghouse PWR and five General Electric BWR sites for HCGS. PSEG's review determined that all of these Phase-Il SAMAs for SGS, and all but two of the Phase-Il SAMAs for HCGS, were (1) already represented by a SAMA identified from the SGS and HCGS Level-1 (and Level-2, for SGS) importance list reviews; (2) already addressed by other means at SGS and HCGS; (3) of low potential for risk reduction at SGS or HCGS; or (4) not applicable to the SGS or HCGS design. Therefore, no additional SAMAs were identified for SGS, but two SAMAs were added for HCGS.
5.2.1.2.1 SGS For SGS, the NRC staff noted that PSEG's review of these other analyses appeared to have overlooked additional cost-beneficial SAMAs identified during the staff's review of these same SAMA analyses and requested PSEG to provide an assessment of any additional cost-beneficial SAMAs identified during these reviews for applicability to SGS (NRC 2010a). In response to the RAI, PSEG reviewed the cost-beneficial SAMAs identified in the NRC-issued NUREG-1437 reports for each of the six nuclear sites and concluded the cost-beneficial SAMA (1) was already identified and evaluated in the ER; (2) was already implemented at SGS; or (3) would not reduce SGS risk (PSEG 2010a, PSEG 2010c). No additional SAMAs were identified from this review.
SGS Individual Plant Examination (IPE)
PSEG considered the potential plant improvements described in the IPE in the identification of plant-specific candidate SAMAs for internal events (PSEG 1993, PSEG 1995). Review led to no additional SAMA candidates since the three improvements identified in the IPE have already been implemented at SGS (PSEG 2009a). In addition, PSEG performed a Phase II evaluation of a sensitivity case to "Install Portable Diesel Generators to Charge Station Battery and Circulating Water Batteries." PSEG SAMA 5A, which is in addition to the Phase II evaluations performed for the 25 SAMAs discussed above that were not screened during the Phase I evaluation.
Based on this information, the NRC staff concludes that the set of SAMAs evaluated in the ER, together with those identified in response to NRC staff RAIs, addresses the major contributors to internal event CDF at SGS.
SGS IPE for External Events (IPEEE)
Although the SGS IPEEE did not identify any fundamental vulnerabilities or weaknesses related to external events, PSEG reviewed five suggested improvements (PSEG 1996, PSEG 2010a, PSEG 201 Oc). As a result of this review, two improvements related to fire events, three improvements related to seismic events, and three improvements related to high winds/floods/other (HFO) external events were identified. All but one each of the seismic-related and HFO-related improvements have been implemented at SGS. For the seismic improvement, PSEG concluded that it was not necessary and no SAMA is suggested. For the HFO improvement, PSEG concluded that, while the suggested change was prudent, it would not reduce plant risk and no SAMA is suggested (PSEG 2010a, PSEG 2010c)
In the SGS ER, PSEG also identified three post-IPEEE site changes to determine if they could impact the IPEEE results and possibly lead to a SAMA. From this review, one plant change was determined to have an impact on fire CDF, but no additional SAMAs were identified. In a further effort to identify external event SAMAs, PSEG reviewed the top 10 fire areas contributing to fire CDF based on the results of the IPEEE and interim SGS fire PRA models. These areas are all of the SGS fire areas having a maximum benefit equal to or greater than the approximate
$50,000 value of implementing a procedure change at a single unit at SGS. As a result of this review, PSEG identified five Phase-I SAMAs to reduce fire risk, including both procedural and hardware alternatives (PSEG 2009a). The NRC staff concludes that the opportunity for fire-related SAMAs has been adequately explored and that it is unlikely that there are additional potentially cost-beneficial, fire-related SAMA candidates at SGS.
For seismic events, PSEG reviewed the top seven seismic sequences contributing to seismic CDF based on the results of the IPEEE seismic PRA model. Again, the approximate $50,000 maximum benefit threshold was assumed. As a result of this review, PSEG identified three additional Phase-I SAMAs to reduce seismic risk (PSEG 2009a). The NRC staff concludes that the opportunity for seismic-related SAMAs has been adequately explored and that it is unlikely that there are additional potentially cost-beneficial, seismic-related SAMA candidates at SGS.
At SGS, the HFO external events lie below the IPEEE threshold screening frequency, or meet the 1975 Standard Review Plan (SRP) design criteria, and are not expected to represent vulnerabilities. Nevertheless, PSEG reviewed the IPEEE results and subsequent plant changes for each of these external hazards and determined that either (1) the maximum benefit from eliminating all associated risk was less than the approximate $50,000 maximum benefit threshold value; or (2) only hardware enhancements that would significantly exceed the maximum value of any potential risk reduction were available. As a result of this review, PSEG identified no additional Phase-I SAMAs to reduce HFO risk (PSEG 2009a). The NRC staff concludes that the licensee's rationale for eliminating other external hazards enhancements from further consideration is reasonable for SGS.
SGS - Other Potential SAMAs The NRC staff questioned PSEG about potentially lower cost alternatives to some of the SAMAs evaluated for SGS (NRC 2010a). In response to the RAIs, PSEG addressed the suggested lower cost alternatives and determined that they were either not feasible or were not cost-beneficial (PSEG 201 Oa, PSEG 2010c). The NRC staff notes that the set of SAMAs submitted is not all-inclusive, since additional, possibly even less expensive, design alternatives can always be postulated. However, the NRC staff concludes that the benefits of any additional modifications are unlikely to exceed the benefits of the modifications evaluated and that the alternative improvements would not likely cost less than the least expensive alternatives evaluated, when the subsidiary costs associated with maintenance, procedures, and training are considered.
The NRC staff concludes that PSEG used a systematic and comprehensive process for identifying potential plant improvements for SGS, and that the set of potential plant improvements identified by PSEG is reasonably comprehensive and, therefore, acceptable.
This search included reviewing insights from the plant-specific risk studies, and reviewing plant improvements considered in previous SAMA analyses. While explicit treatment of external events in the SAMA identification process was limited, it is recognized that the prior implementation of plant modifications for fire and seismic risks and the absence of external event vulnerabilities reasonably justifies examining primarily the internal events risk results for this purpose.
The potentially cost-beneficial SAMAs do not relate to adequately managing the effects of aging during the period of extended operation; therefore, they need not be implemented as part of license renewal pursuant to 10 CFR Part 54. SGS's SAMA analyses and the NRC's review are discussed in more detail in Sections 5.2.3 through 5.2.5.
5.2.1.2.2 HCGS The two additional SAMAs for HCGS addressed automatic alignment of a portable station generator and increasing boron concentration or enrichment in the Standby Liquid Control (SLC)
System. PSEG performed a cost-benefit evaluation for a new SAMA related to the first. PSEG dismissed the second as being of potentially negligible benefit given the low risk-importance and automatic actuation of SLC at HCGS (PSEG 2010b, PSEG 2010d).
HCGS Individual Plant Examination (IPE)
PSEG considered the potential plant improvements described in the HCGS IPE in the identification of plant-specific candidate SAMAs for internal events (PSEG 1994). This review led to no additional SAMA candidates since the three improvements identified in the IPE have already been implemented at HCGS. (PSEG 2009b).
Based on this information, the NRC staff concludes that the set of SAMAs evaluated in the ER, together with those identified in response to NRC staff RAIs, addresses the major contributors to internal event CDF at HCGS.
HCGS IPE for External Events (IPEEE)
The HCGS IPEEE did not identify any fundamental vulnerabilities or weaknesses related to external events, and two improvements related to HFO events that were identified have been implemented at HCGS (PSEG 1997, PSEG 2009b). In the ER, PSEG also identified three post-IPEEE site changes to determine if they could impact the IPEEE results and possibly lead to a SAMA. From this review no additional SAMAs were identified for HCGS (PSEG 2009b).
In a further effort to identify external event SAMAs, PSEG identified the top 10 fire scenarios contributing to fire CDF based on the results of the updated HCGS fire PRA model and reviewed the top 8 fire scenarios for potential SAMAs. These 8 scenarios are the only HCGS fire scenarios having a benefit equal to or greater than the approximate $100,000 value of implementing a procedure change at HCGS. As a result of this review, PSEG identified six Phase-I SAMAs to reduce fire risk, including both procedural and hardware alternatives (PSEG 2009b). The NRC staff concludes that the opportunity for fire-related SAMAs has been adequately explored and that it is unlikely that there are additional potentially cost-beneficial, fire-related SAMA candidates at HCGS.
For seismic events, PSEG reviewed the top 10 seismic sequences contributing to seismic CDF based on the results of the 2003 HCGS seismic analysis and initially reviewed the top 2 seismic
sequences for potential SAMAs. Again, the approximate $100,000 maximum benefit threshold was assumed. As a result of this review, PSEG identified three Phase-I SAMAs to reduce seismic risk (PSEG 2009b). In response to an NRC staff RAI, PSEG revised the review of seismic sequences to account for the increased maximum benefit of each sequence resulting from the use of an alternate set of seismic hazard curves. This resulted in two additional seismic sequences having a benefit equal to or greater than the $100,000 threshold. As a result of the review of these sequences, three additional SAMAs were identified related to 125V DC and 120 V AC distribution panels (PSEG 201 Oc, PSEG 201 Od). The NRC staff concludes that the opportunity for seismic-related SAMAs has been adequately explored and that it is unlikely that there are additional potentially cost-beneficial, seismic-related SAMA candidates.
At HCGS, the HFO external events lie below the IPEEE threshold screening frequency, or meet the 1975 Standard Review Plan (SRP) design criteria, and are not expected to represent vulnerabilities. Nevertheless, PSEG reviewed the IPEEE results and subsequent plant changes for each of these external hazards and determined that either (1) the maximum benefit from eliminating all associated risk was less than the approximate $100,000 maximum benefit threshold; or (2) only hardware enhancements that would significantly exceed the maximum value of any potential risk reduction were available. As a result of this review, PSEG identified no additional Phase-I SAMAs to reduce HFO risk (PSEG 2009b). The NRC staff concludes that the licensee's rationale for eliminating other external hazards enhancements from further consideration is reasonable for HCGS.
HCGS - Other Potential SAMAs The NRC staff questioned PSEG about lower cost alternatives to some of the SAMAs evaluated for HCGS (NRC 2010b). In response to the RAIs, PSEG addressed the suggested lower cost alternatives (PSEG 201 Ob, PSEG 2010d). The NRC staff notes that the set of SAMAs submitted is not all-inclusive, since additional, possibly even less expensive, design alternatives can always be postulated. However, the NRC staff concludes that the benefits of any additional modifications are unlikely to exceed the benefits of the modifications evaluated and that the alternative improvements would not likely cost less than the least expensive alternatives evaluated, when the subsidiary costs associated with maintenance, procedures, and training are considered.
The NRC staff concludes that PSEG used a systematic and comprehensive process for identifying potential plant improvements for HCGS, and that the set of potential plant improvements identified by PSEG is reasonably comprehensive and, therefore, acceptable.
This search included reviewing insights from the plant-specific risk studies, and reviewing plant improvements considered in previous SAMA analyses. While explicit treatment of external events in the SAMA identification process was limited, it is recognized that the prior implementation of plant modifications for fire and seismic risks and the absence of external event vulnerabilities reasonably justifies examining primarily the internal events risk results for this purpose.
The potentially cost-beneficial SAMAs do not relate to adequately managing the effects of aging during the period of extended operation; therefore, they need not be implemented as part of license renewal pursuant to 10 CFR Part 54. HCGS's SAMA analyses and the NRC's review are discussed in more detail in Sections 5.2.3 through 5.2.5.
5.2.2 Estimates of Risk PSEG submitted assessments of SAMAs for SGS and HCGS as part of the ERs (PSEG 2009a, PSEG 2009b). For each, two distinct analyses are combined to form the basis for the risk estimates used in the SAMA analysis: (1) the plant-specific Level-1 and Level-2 PSA models, which are updated versions of the IPEs (PSEG 1993, PSEG 1994, PSEG 1995); (2) a supplemental analysis of offsite consequences and economic impacts (essentially a Level-3 PSA model) developed specifically for the SAMA analysis. The most recent plant-specific Level-1 and Level 2 PSA models consisted of the following Internal Events PSAs: (1) for SGS, Salem PRA, Revision 4.1, September 2008, model of record (MOR); (2) for HCGS, the HC108B update. Neither of these includes external events.
5.2.2.1 SGS Internal Events The SGS CDF is approximately 4.8 x 10-5 per year for internal events as determined from quantification of the Level 1 PRA model at a truncation of 1 x 10-11 per year. When determined from the sum of the containment event tree (CET) sequences, or Level 2 PSA model, the release frequency (from all release categories, which consist of intact containment, late release, and early release) is approximately 5.0 x 10- per year, also at a truncation of 1 x 10-11 per year.
The latter value was used as the baseline CDF in the SAMA evaluations (PSEG 2009a). The CDF is based on the risk assessment for internally initiated events, which includes internal flooding. PSEG did not explicitly include the contribution from external events within the SGS risk estimates; however, it did account for the potential risk reduction benefits associated with external events by multiplying the estimated benefits for internal events by a factor of 2. This is discussed further in Section 5.2.2.2.
The breakdown of CDF by initiating event provided in Table 5-1 indicates that events initiated by losses of control area ventilation, offsite power, or service water are the dominant contributors to the CDF. PSEG identified that Station Blackout (SBO) contributes 8 x 10-6 per year, or 17 percent, to the total internal events CDF (PSEG 2010a).
Table 5-1. Core Damage Frequency for Internal Events at SGS CDF 1 % Contribution Initiating Event (per year) to CDF2 Loss of Control Area Ventilation 1.8 x 10-5 37 Loss of Off-site Power (LOOP) 8.1 x 10-6 17 Loss of Service Water 6.6 x 10-6 14
Internal Floods 4.5 x 10-6 9 Transients 4.0 x 10-6 8 Steam Generator Tube Rupture (SGTR) 2.7 x 10-6 6 Loss of Component Cooling Water (CCW) 1.0 x 10-6 2 Anticipated Transient Without Scram (ATWS) 7.4 x 10-7 2 Loss of 125V DC Bus A 6.9 x 10-7 1 Others (less than 1 percent each) 3 1.8 x 10-6 4 Total CDF (internal events) 4.8 x 10-5 100
'Calculated from Fussel-Vesely risk reduction worth (RRW) provided in response to NRC staff RAI i.e (PSEG 201 Oa).
2 Based on Internal Events CDF contribution and total Internal Events CDF.
3 CDF value derived as the difference between the total Internal Events CDF and the sum of the individual internal events CDFs calculated from RRW.
The Level-2 Salem PRA model that forms the basis for the SAMA evaluation is essentially a complete revision of the original IPE Level-2 model and conforms to current industry guidance.
It utilizes a single CET where the Level-1 core damage sequences are binned into accident classes as the interface between the Level-1 and Level-2 CET analysis. The CET is linked directly to the Level-1 event trees. The result of the Level-2 PRA is a set of 11 release or source term categories, with their respective frequency and release characteristics, namely the timing of the release, the initiating event, whether feedwater is available, and the containment failure mode. The frequency of each release category was obtained by summing the frequency of the individual accident progression CET endpoints binned into the release category. Source terms were developed for each of the 11 release categories using the results of Modular Accident Analysis Program (MAAP Version 4.0.6) computer code calculations (PSEG 201 Oa).
The offsite consequences and economic impact analyses use the MACCS2 code to determine the offsite risk impacts on the surrounding environment and public (NRC 1998). Inputs for these analyses include plant-specific and site-specific input values for core radionuclide inventory, source term and release characteristics, site meteorological data, projected population distribution (within a 50-mile radius) for the year 2040, emergency response evacuation modeling, and economic data. The core radionuclide inventory corresponds to the end-of-cycle values for SGS operating at 3632 MWt, which is 5% above the current licensed power level of 3,459 MWt. The magnitude of the onsite impacts (in terms of clean-up and decontamination costs and occupational dose) is based on information provided in NUREG/BR-0184 (NRC 1997).
In the ER, PSEG estimated the dose to the population within 80-kilometers (50-miles) of the SGS site to be approximately 0.78 person-Sievert (Sv) (78 person-roentgen equivalent man (rem)) per year. The breakdown of the total population dose by containment release mode summarized in Table 5-2 shows that containment bypass events (such as SGTR-initiated large
early release frequency (LERF) accidents) and late containment failures without feedwater dominate the population dose risk at SGS.
Table 5-2. Breakdown of Population Dose by Containment Release Mode for SGS Population Dose Percent Containment Release Mode (Person-Rem1 Per Year) Contribution 2 Containment over-pressure (late) 42.9 55 Steam generator rupture 31.9 41 Containment isolation failure 2.3 3 Containment intact 0.2 <1 Interfacing system LOCA 0.6 <1 Catastrophic isolation failure 0.4 <1 Basemat melt-through (late) negligible negligible Total 3 78.2 100
'One person-rem = 0.01 person-Sv 2
Derived from Table E.3-7 of the ER 3Column totals may be different due to round off.
5.2.2.2 SGS External Events Since the current SGS PRA does not include external events, PSEG used the SGS IPEEE to identify the highest risk accident sequences and the potential means of reducing the risk posed by those sequences (PSEG 1996). The SGS IPEEE includes a seismic PRA, a fire PRA, and a screening analysis for other external events. While no fundamental weaknesses or vulnerabilities to severe accident risk in regard to the external events were identified, several potential enhancements were identified. In a letter dated May 21, 1999, (NRC 1999a) NRC staff concluded that the submittal met the intent of Supplement 4 to Generic Letter 88-20, and that the licensee's IPEEE process is capable of identifying the most likely severe accidents and severe accident vulnerabilities.
Seismic The SGS IPEEE seismic analysis utilized a seismic PRA that included: a seismic hazard analysis, a seismic fragility assessment, a seismic systems analysis, and quantification of seismic CDF. The seismic hazard analysis estimated the annual frequency of exceeding different levels of ground motion based on both the Electric Power Research Institute (EPRI 1989) and Lawrence Livermore National Laboratory (LLNL) (NRC 1994) hazard assessments.
The seismic fragility assessment utilized the walkdown and screening procedures in EPRI's seismic margin assessment methodology (EPRI 1991). Fragility calculations were made for
about 100 components and, using a screening criterion of median peak ground acceleration (pga) of 1.5 g which corresponds to a 0.5 pga high confidence low probability of failure (HCLPF) capacity, a total of 27 components remained after screening. The seismic systems analysis defined the potential seismic induced structure and equipment failure scenarios that could occur after a seismic event and lead to core damage. The SGS IPE event tree and fault tree models were used as the starting point for the seismic analysis but an explicit seismic event tree (SET) was used to delineate the potential successes and failures that could occur due to a seismic event. Quantification of the seismic models consisted of considering the seismic hazard curve with the appropriate structural and equipment seismic fragility curves to obtain the frequency of the seismic damage state. The conditional probability of core damage given each seismic damage state was then obtained from the IPE models with appropriate changes to reflect the seismic damage state. The CDF was then given by the product of the seismic damage state probability and the conditional core damage probability.
The seismic CDF resulting from the SGS IPEEE was calculated to be 9.5 x 10-6 per year using the LLNL seismic hazard curve. In the ER, PSEG provided a listing and description of the top seven seismic core damage contributors, representing about 95% of the seismic CDF as shown in Table 5-3. The NRC staff agrees that the seismic CDF of 9.5 x 10-6 per year is reasonable for the SAMA analysis.
Table 5-3. Dominant Contributors to the Seismic CDF at SGS
% Contribution Sequence CDF (per to Seismic ID Seismic Sequence Description year) CDF 17 OP: Seismically-Induced LOOP 2.9x 10-6 31 caused by failure of the switchyard ceramic insulators 33 OP-DAB: Seismically-Induced LOOP 2.0 x 10-6 21 and failure of battery trains A and B 31 OP-SW: Seismically-Induced LOOP 1.3 x 10-6 14 and failure of the service water system 35 OP-IC: Seismically-Induced LOOP and 1.2 x 10-6 13 failure of instrumentation and control capability and equipment in the main control room 34 OP-DAB-DG: Same as 33 OP-DAB 7.7x 10-7 8 and failure of battery train C 17F OP-FW: Same as 17 OP and failure of 5.4 x 10-7 6 containment fan coolers 21F OP-FW-FC: Same as 17F OP-FW and 2.9 x 10-7 3 failure of auxiliary feed water (AFW) I Fire
The SGS IPEEE fire analysis employed EPRI's fire-induced vulnerability evaluation (FIVE) methodology (EPRI 1993) followed by a PRA quantification of the unscreened compartments.
The fire evaluation was performed on the basis of fire areas which are plant locations completely enclosed by 2-hour rated fire barriers and meeting the FIVE fire barrier criterion related to preventing propagation. The four stages of a FIVE analysis were employed: (1) screening of all plant fire areas to determine whether a fire could cause a plant shutdown or trip, or lead to loss of safe shutdown equipment, as well as estimating whether an area's associated fire frequency in combination with the conditional core damage probability (CCDP) was less than the 1 X 10-6 per year; (2) . evaluating the remaining fire areas (38 survived the screening) by modeling fire growth and propagation to determine the fire damage state for each fire area; (3) evaluating of Sandia Fire Risk Scoping Study issues (NRC 1989), including containment performance; and (4) assessing the functional effects on the plant for each fire damage state by developing explicit fire event trees to probabilistically assess unscreened areas. Final quantification utilized FIVE fire data and refined CCDPs from the IPE internal events PRA. The resulting fire-induced CDF for SGS was calculated to be 2.3 x 10s per year.
Subsequent to the IPEEE, SGS replaced the CO 2 suppression systems with water sprinkler systems in the 460V Switchgear Rooms, 4160V Switchgears Rooms, and Lower Electrical Penetration Area. In addition, the results of cable wrap tests suggested that the cable wrap would not perform as expected in some areas of the plant and, subsequent to the IPEEE, was removed and replaced. Because of the suppression system changes made to the three areas identified, PSEG did not consider the IPEEE results for these areas valid. PSEG reassessed the fire CDF for these areas using PRA insights from an interim SGS fire model. These insights increased the total fire CDF to 3.8 x 105 per year, which was used in the SAMA analysis. The dominant fire core damage contributors, representing about 99 percent of the fire CDF, are listed in Table 5-4. The largest contributors to fire CDF are fires in the 460V Switchgear Rooms, Relay Room, and Control Rooms.
Table 5-4. Important Fire Areas and Their Contribution to Fire CDF at SGS CDF1 % Contribution Fire Area Description (per year) to Fire CDF 460V Switchgear Rooms 1.3 x 10-5 34 Relay Room 7.2 x 10-u 19 Control Rooms, Peripheral Room, and 7.0 x 10- 18 Ventilation Rooms 4160V Switchgear Room 3.4 x 10 9 Lower Electrical Penetration Area 3.2 x 10- 8 Upper Electrical and Piping Penetration Areas 1.3 x 10- 3 Reactor Plant Auxiliary Equipment Area (84B) 1.1 x 107- 3 Turbine and Service Buildings 6.4 x 10' 2 Service Water Intake 4.2x 10-' 1 Reactor Plant Auxiliary Equipment Area (1OOC) 2.9 x 10V 1 1CDF reported for the 460V Switchgear Rooms and 4160V Switchgear Rooms is from the interim SGS fire model. All other CDFs are from the IPEEE.
Despite the potential for conservatisms in the fire analysis, PSEG used the modified IPEEE fire CDF of 3.8 x 10-5 per year in the SAMA analysis rather than some reduced value. Considering the conservatisms in the IPEEE fire analysis as currently understood, and the response to the NRC staff RAIs, the NRC staff concludes that the fire CDF of 3.8 x 10-5 per year is reasonable for the SGS SAMA analysis.
Other The SGS IPEEE analysis of HFO external events followed the progressive screening method defined in NUREG-1407 (NRC 1991). While SGS is not considered a 1975 SRP plant, aspects of its licensing basis do conform to the 1975 SRP criteria because SGS is co-located with Hope Creek Generating Station (HCGS), which does meet the 1975 SRP criteria (PSEG 1996). For those events that are based on the location of the site, and not plant-specific features, the 1975 SRP criteria was used for the HFO screening analysis. Progressively more quantitatively based methods were employed for those events that could not be shown to conform to the 1975 SRP criteria. The IPEEE concluded that all HFO events either complied with the 1975 SRP criteria or that their predicted CDF was below the IPEEE screening criteria (i.e. < 1 x 10-6 per year). For the SAMA analysis, PSEG assumed a CDF contribution of 1 x 10.6 per year for each of high winds, external floods, transportation and nearby facilities, detritus, and chemical releases for a total HFO CDF contribution of 5 x 10-6 per year (PSEG 2009a).
The NRC staff asked about the status and potential impact on the SAMA analysis of a liquefied natural gas (LNG) terminal planned for Logan Township, New Jersey, upstream on the Delaware River from the SGS site (NRC 2010a). In response to the RAI, PSEG indicated that (1) the LNG terminal remains in the planning stage, such that no construction has begun; and (2) the state of Delaware has denied applications for several required environmental permits and approvals (PSEG 2010a). PSEG concluded that, based on the regulatory process and controls for assuring the safety and security of LNG ships, the safety record of LNG ships, and the uncertainty of the planned terminal, consideration of potential SAMAs associated with the possible future terminal is not warranted for SGS. The NRC staff agrees with this conclusion.
Based on the aforementioned results, the external events CDF is approximately equal to the internal events CDF (based on a seismic CDF of 9.5 x 10-6 per year, a fire CDF of 3.8 x 10-5 per year, an HFO CDF of 5.0 x 10-6 per year, and an internal events CDF of 5.0 x 10-5 per year used in the SAMA analysis). Accordingly, the NRC staff concurred with SGS's conclusion that the total CDF (from internal and external events) would be approximately 2 times the internal events CDF. In the SAMA analysis submitted in the ER, PSEG doubled the benefit that was derived from the internal events model to account for the combined contribution from internal and external events. The NRC staff agrees with the licensee's overall conclusion concerning the multiplier used to represent the impact of external events and concludes that the licensee's use of a multiplier of 2 to account for external events is reasonable for the purposes of the SAMA evaluation.
The NRC staff concludes that the methodology used by PSEG to estimate the offsite consequences for SGS provides an acceptable basis from which to proceed with an assessment
of risk reduction potential for candidate SAMAs. Accordingly, the NRC staff based its assessment of offsite risk on the CDF and offsite doses reported by PSEG.
6.2.2.3 HCGS Internal Events The HCGS CDF is approximately 5.1 x 10.6 per year as determined from quantification of the Level 1 PRA model at a truncation of 1 X 10-12 per year. When determining from the sum of the containment event tree (CET) sequences, or Level 2 PRA model, a higher truncation of 5 x 10.11 per year was used and the resulting release frequency (from all release categories, which consist of intact containment, late release, and early release) is approximately 4.4 x 10-6 per year. The latter value was used as the baseline CDF in the SAMA evaluations (PSEG 2009b).
Although this is about 16% less that the internal events CDF of 5.1 x 10-6 per year obtained from the Level-1 model, the NRC staff considers that its use will have a negligible impact on the results of the SAMA evaluation because the external event multiplier and uncertainty multiplier used in the SAMA analysis have a much greater impact on the SAMA evaluation results than the small difference arising from the model quantification approach.
The CDF is based on the risk assessment for internally-initiated events, which includes internal flooding. PSEG did not explicitly include the contribution from external events within the HCGS risk estimates; however, it did account for the potential risk reduction benefits associated with external events by multiplying the estimated benefits for internal events by a factor of 6.3. This is discussed further in Section 5.2.2.4.
The breakdown of CDF by initiating event is provided in Table 5-5 indicates that events initiated by loss of offsite power, loss of service water and other transients (manual shutdown and turbine trip with bypass) are the dominant contributors to the CDF. Anticipated transient without scram (ATWS) sequences account for 3% of the CDF, station blackout accounts for 12% of the CDF (PSEG 2010b).
Table 5-5. Core Damage Frequency for Internal Events at HCGS CDF % Contribution Initiating Event (per year) to CDF1 Loss of Offsite Power 9.3 x 10- 7 18 Loss of Service Water (SW) 8.1 x 10-7 15 Manual Shutdown 7.7 x 10-7 15 Turbine Trip with Bypass 6.2 x 10-7 12 Small Loss of Coolant Accident (LOCA) - Water 2.8 x 10-7 5 (Below Top of Active Fuel)
Small LOCA - Steam (Above Top of Active Fuel) 2.3 x 10-7 4 Loss of Condenser Vacuum 2.0 x 10- 7 4 Fire Protection System Rupture Outside Control Room 1.9 x 10-7 4 Isolation LOCA in Emergency Core Cooling System 1.1 x 10-7 2 (ECCS) Discharge Paths Main Steam Isolation Valve (MSIV) Closure 1.1 x 10-7 2 Internal Flood Outside Lower Relay Room 9.7 x 10-8 2 Loss of Feedwater 8.8 x 10- 8 2
Loss of Safety Auxiliaries Cooling System 7.9 x 10-8 2 Reactor Auxiliaries Cooling System (RACS) Common 7.6 x 10-8 1 Header Unisolable Rupture Unisolable SW A Pipe Rupture in RACS Room 5.7 x 10-8 1 Unisolable SW B Pipe Rupture in RACS Room 5.7 x 10-8 1 Others (less than 1% each) 4.1 x 10-7 8 Total CDF (internal events) 5.1 x 10-6 100 1
Column totals may be different due to round off.
The Level 2 HCGS PRA model that forms the basis for the SAMA evaluation is essentially a complete revision to the IPE model. The Level 2 model utilizes three containment event trees (CETs) containing both phenomenological and systemic events. The Level 1 core damage sequences are binned into accident classes that provide the interface between the Level 1 and Level 2 CET analysis. The CETs are linked directly to the Level 1 event trees and CET nodes are evaluated using supporting fault trees. The result of the Level 2 PRA is a set of 11 release or source term categories, with their respective frequency and release characteristics, namely the timing of the release, the magnitude of the release, and whether or not the containment remains intact or fails. The frequency of each release category was obtained by summing the frequency of the individual accident progression CET endpoints binned into the release category. Source terms were developed for each of the 11 release categories using the results of Modular Accident Analysis Program (MAAP 4.0.6) computer code calculations.
The offsite consequences and economic impact analyses use the MACCS2 code to determine the offsite risk impacts on the surrounding environment and public (NRC 1998). Inputs for these analyses include plant-specific and site-specific input values for core radionuclide inventory, source term and release characteristics, site meteorological data, projected population distribution (within a 50-mile radius) for the year 2046, emergency response evacuation modeling, and economic data. The core radionuclide inventory corresponds to the end-of-cycle values for HCGS operating at 3917 MWt, which is 2% above the current extended power uprate (EPU) licensed power level of 3,840 MWt. The magnitude of the onsite impacts (in terms of clean-up and decontamination costs and occupational dose) is based on information provided in NUREG/BR-0184 (NRC 1997).
In the ER, PSEG estimated the dose to the population within 80-kilometers (50-miles) of the HCGS site to be approximately 0.23 person-Sievert (Sv) (22.9 person-roentgen equivalent man
[rem]) per year. The breakdown of the total population dose by containment release mode summarized in Table 5-6 shows that releases from the containment within the early time frame (0 to less than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> following event initiation) and intermediate time frame (4 to less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following event initiation) dominate the population dose risk at HCGS.
Table 5-6. Breakdown of Population Dose by Containment Release Mode for HCGS Population Dose Percent Containment Release Mode (Person-Rem1 Per Year) Contribution Early Releases (< 4hrs) 11.9 52 Intermediate Releases (4 to <24 hrs) 9.9 43
Late Releases (t24 hrs) 1.1 5 Intact Containment <0.1 negligible Total 22.9 100 10ne person-rem = 0.01 person-Sv 5.2.2.4 HCGS External Events PSEG does not maintain a current HCGS external events PRA that explicitly models seismic and fire initiated core damage accidents that can be linked with the current Level 2 and 3 PRA.
However, the models developed for seismic and fire events in the IPEEE were partially updated in 2003 to utilize revised initiating event frequencies and conditional core damage probabilities based on the 2003A internal events PRA Model. These results were used to identify SAMAs that address important fire and seismic risk contributors. While no fundamental weaknesses or vulnerabilities to severe accident risk in regard to the external events were identified, two potential enhancements were identified. In a letter dated July 26, 1999 (NRC 1999), the NRC staff concluded that PSEGs IPEEE process is capable of identifying the most likely severe accidents and severe accident vulnerabilities (NRC 1999b).
Seismic The seismic hazard analysis estimated the annual frequency of exceeding different levels of ground motion. Seismic CDFs were determined for both the EPRI (EPRI 1989) and the Laurence Livermore National Laboratory (LLNL) (NRC 1994) hazard assessments. The seismic fragility assessment utilized the walkdown procedures and screening caveats in EPRI's seismic margin assessment methodology (EPRI 1991). Fragility calculations were made for about 90 components and, using a screening criterion of median peak ground acceleration (pga) of 1.5 g which corresponds to a 0.5 pga high confidence low probability of failure (HCLPF) capacity, a total of 17 components remained after screening. The seismic systems analysis defined the potential seismic induced structure and equipment failure scenarios that could occur after a seismic event and lead to core damage. The HCGS IPE event tree and fault tree models were used as the starting point for the seismic analysis. Quantification of the seismic models consisted of convoluting the seismic hazard curve with the appropriate structural and equipment seismic fragility curves to obtain the frequency of the seismic damage state. The conditional probability of core damage given each seismic damage state was then obtained from the IPE models with appropriate changes to reflect the seismic damage state. The CDF was then given by the product of the seismic damage state probability and the conditional core damage probability.
The seismic CDF resulting from the HCGS IPEEE was calculated to be 3.6 x 10-6 per year using the LLNL seismic hazard curve and 1.0 x 10,6 per year using the EPRI seismic hazard curve.
Subsequent to the IPEEE, PSEG updated the seismic PRA utilizing conditional core damage probabilities from the 2003A PRA model modified to reflect the seismic human reliability assessment that was performed to support the IPEEE,(PSEG 2009b). The resulting seismic CDF using the EPRI seismic hazard curves rose slightly to 1.1 x 10-6 per year. In the ER, PSEG provided a listing and description of the top ten seismic core damage contributors. The dominant seismic core damage contributors with a CDF of 1 x 10-8 per year or more are listed in
Table 5-7. The NRC staff agrees that the seismic CDF of 1.1 x 10-6 per year is reasonable for the SAMA analysis, provided the sensitivity of the results to assuming the LLNL-based seismic CDF of 3.6 x 10-6 per year is considered. (see Section 5.2.2.4)
Table 5-7. Dominant Contributors to the Seismic CDF at HCGS Based on EPRI Seismic Based on LLNL Seismic Hazard Curves Hazard Curves Contribution Contribution Basic CDF (per to Seismic CDF (per to Seismic Event ID Seismic Sequence Description year) CDF year) CDF
%IE- Seismic-Induced Equipment 60 70 SET36 Damage State SET-36 (Impacts - 6.7 x 10-7 2.5 x 10-6 120V PNL481)
%IE- Seismic-Induced Equipment 27 9 SET18 Damage State SET-18 (Impacts - 3.1 x 10-7 3.3- 10-7 LOOP)
%IE- Seismic-Induced Equipment 6.8 x 10-8* 6 4.4 x 10-7 12 SET37 Damage State SET-37 (Impacts -
125V)
%IE- Seismic-Induced Equipment 4.6 x 10-8 4 1.6 x 10-7 5 SET35 Damage State SET-35 (Impacts -
120V PNL482, RSP)
%IE- Seismic-Induced Equipment 2.1 x 10-8 2 5.4 x 10-8 2 SET38 Damage State SET-38 (Impacts -
1E panel room Ventilation)
- In response to an RAI, PSEG indicated that the value reported in the ER page E-99 for this contributor was in error and should be that given in the IPEEE - 6.8 x 10-8 per year.
Fire The HCGS IPEEE fire analysis employed EPRI's fire-induced vulnerability evaluation (FIVE) methodology (EPRI 1993) followed by a PRA quantification of the unscreened compartments.
The fire evaluation identified 209 fire compartments meeting the FIVE criteria for the entire plant.
Quantitative screening utilized a threshold fire ignition frequency and conservatively determined screening conditional core damage probabilities (CCDPs) from the internal events PRA screening out (at a CDF of less than 1 x 1 -6 per year) of all but 38 fire compartments. The analysis for the unscreened areas resulted in a fire induced CDF of 8.1 x 10-5 per year. A walkdown and verification process was employed to verify that the assumptions and calculations were supported by the physical condition of the plant. The HCGS IPEEE did not identify any vulnerabilities due to internal fires or any potential improvements to reduce internal fire risk.
Subsequent to the IPEEE, PSEG updated the fire PRA to incorporate more recent fire initiating event frequencies based on information in the 2002 NRC fire database and conditional core damage probabilities from the 2003A PRA model, referred to as the 2003 HCGS External
Events Update. The resulting fire CDF is 1.7 x 10-5 per year.
In the ER, PSEG provided a listing and description of the top ten fire core damage contributors.
The important fire core damage contributors with a CDF of 1 X 10-7 per year or more are listed in Table 5-8. As can be seen from these results the fire risk at HCGS is dominated by panel fires in the control room.
Table 5-8. Important Contributors to Fire CDF at HCGS Basic Event CDF % Contribution ID Fire Area Description per year to Fire CDF
%IE-FIRE03 Control Room Fire Scenario Small Cab_3 (Loss of 5.3x 10-6 31 Emer. Bat.)
%IE-FIRE02 Control Room Fire Scenario Small Cab_2 (Loss of 4.4 x 10-6 25 SSWS)
%IE-FIRE01 Control Room Fire Scenario Small CabI (Loss of 3.8 x 10-6 22 SACS)
%IE-FIRE28 Compartment 5339 Fire Scenario 5339 2 7.5 x 10-7 4
%IE-FIRE37 DG room (D) Fire Scenario 5304 2 7.0 x 10-7 4
%IE-FIRE20 DG room (C) Fire Scenario 5306 2 6.7 x 10-7 4
%IE-FIRE38 Compartment 3425/5401 Fire Scenario 5401 1 5.9 x 10-7 3
%IE-FIRE06 Control Room Fire Scenario Large Cabil (MSIV 5.1 x 10-7 3 Closure)
Despite the potential for conservatisms in the fire analysis, PSEG used the modified IPEEE fire CDF of 1.7 x 10.5 per year in the SAMA analysis rather than some reduced value. Considering the conservatisms in the IPEEE fire analysis as currently understood, and the response to the NRC staff RAIs, the NRC staff concludes that the fire CDF of 1.7 x 10s5 per year is reasonable for the HCGS SAMA analysis.
Other The HCGS IPEEE analysis of HFO external events indicated that each of the events identified in NUREG-1407 (NRC 1991) had a core damage contribution of less than the screening criterion of 1 X 10-6 per year. This was done by either showing compliance with the 1975 Standard Review Plan criteria or by a bounding analysis that demonstrated that the CDF contribution was less than the screening criterion. For the SAMA analysis, PSEG assumed a CDF contribution of 1 x 10-6 per year for each of high winds, external floods, transportation and nearby facilities, detritus, and chemical releases, for a total HFO CDF contribution of 5 x 10- per year (PSEG 2009b).
Although the HCGS IPEEE did not identify any vulnerabilities due to HFO events, two improvements to reduce risk were identified. For high winds, a walkdown was performed to evaluate high wind hazards. As a result, a missile shield was installed in front of a door into the Technical Support Center. For external floods, a walkdown confirmed that there were no severe accident vulnerabilities. HCGS was found to be adequately protected from the postulated occurrence of the probable maximum hurricane surge with wave run-up coincident with the 10%
exceedance high tide. HCGS was also found to comply with the latest probable maximum
precipitation criteria. A review of transportation and nearby facility accidents confirmed that there were no severe accident vulnerabilities. During the review it was discovered that in a single year there had been some unauthorized shipments of explosives on the Delaware River in the vicinity of the HCGS. The U.S. Coast Guard (USCG), which controls such shipments, was future. '
contacted and procedures were put in place to prevent such shipments in the The NRC staff asked about the status and potential impact on the SAMA analysis of a liquefied natural gas (LNG) terminal planned for Logan Township, New Jersey, upstream on the Delaware River from the SGS site (NRC 2010a). In response to the RAI, PSEG indicated that (1) the LNG terminal remains in the planning stage, such that no construction has begun; and (2) the state of Delaware has denied applications for several required environmental permits and approvals (PSEG 2010a). PSEG concluded that, based on the regulatory process and controls for assuring the safety and security of LNG ships, the safety record of LNG ships, and the uncertainty of the planned terminal, consideration of potential SAMAs associated with the possible future terminal is not warranted for SGS. The NRC staff agrees with this conclusion.
As indicated in the ER (PSEG 2009b), a multiplier of 6.3 was used to adjust the internal event risk benefit associated with a SAMA to account for external events. This multiplier was based on a total external event CDF of 2.3 x 10-5 per year, which is the sum of the updated fire CDF of 1.7 x 10.5 per year, the updated seismic CDF of 1.1 X 10-6 per year, and the HFO CDF of 5 x 10-6 per year. The external event CDF is thus approximately 5.3 times the internal events CDF of 4.4 X 10-6 per year. The total CDF is thus 6.3 times the internal events CDF (PSEG 2009b).
As indicated above, in response to an NRC staff RAI, PSEG determined the seismic CDF based on the LLNL hazard curve to be 3.6 x 10-6 per year (PSEG 201 Ob). If this is utilized instead of the value using the EPRI hazard curve, the total external events CDF is 2.6 x 10- per year and the external events multiplier is 6.8. The impact of this revised multiplier on the SAMA assessment is discussed further in Section 5.2.5.2. The NRC staff agrees with the licensee's overall conclusion concerning the multiplier used to represent the impact of external events.
The NRC staff concludes that the licensee's use of a multiplier of 6.3 to account for external events is reasonable for the purposes of the SAMA evaluation, provided the sensitivity of the results to a multiplier of 6.8 is considered.
The NRC staff concludes that the methodology used by PSEG to estimate the offsite consequences for HCGS provides an acceptable basis from which to proceed with an assessment of risk reduction potential for candidate SAMAs. Accordingly, the NRC staff based its assessment of offsite risk on the CDF and offsite doses reported by PSEG.
5.2.3 Potential Plant Improvements PSEG's process for identifying potential plant improvements (SAMAs) for SGS and HCGS is described in Section 5.2.1. Here the specific SAMAs that were identified are discussed.
To the original list of 25 SGS SAMA candidates that survived Phase-I screening, four were added as a result of the NRC staffs review to generate the list of 29 SGS candidate SAMAs for cost/benefit screening (Phase-Il) in Table 5-9. The additional four consisted of SAMA 5a, added as a sensitivity case to SAMA 5 to provide a comprehensive, long term mitigation strategy for SBO scenarios, and SAMAs 30 through 32.
Table 5-9 Candidate SAMAs for Cost/Benefit Screening at SGS 1 - Enhance Procedures and Provide Additional Equipment to Respond to Loss of Control Area Ventilation 2 - Re-configure SGS 3 to Provide a More Expedient Backup AC Power Source for SGS I and 2 3 - Install Limited EDG Cross-Tie Capability Between SGS 1 and 2 4 - Install Fuel Oil Transfer Pump on "C" EDG & Provide Procedural Guidance for Using "C" EDG to Power Selected "A" and "B" Loads 5 - Install Portable Diesel Generators to Charge Station Battery and Circulating Water Batteries and Replace PDP with Air-Cooled Pump 5A - Install Portable Diesel Generators to Charge Station Battery and Circulating Water Batteries 6 - Enhance Flood Detection for 84' Auxiliary Building and Enhance Procedural Guidance for Responding to Service Water Flooding 7 - Install "B" Train Auxiliary Feedwater Storage Tank (AFWST) Makeup Including Alternate Water Source 8 - Install High Pressure Pump Powered with Portable Diesel Generator and Long-term Suction Source to Supply the AFW Header 9 - Connect Hope Creek Cooling Tower Basin to SGS Service Water System as Alternate Service Water Supply 10 - Provide Procedural Guidance for Faster Cooldown Loss of RCP Seal Cooling 11 - Modify Plant Procedures to Make use of Other Unit's PDP for RCP Seal Cooling 12 - Improve Flood Barriers Outside of 220/440VAC Switchgear Rooms 13 - Install Primary Side Isolation Valves on the Steam Generators 14 - Expand AMSAC Function to Include Backup Breaker Trip on Reactor Protection System (RPS)
Failure 15 - Automate RCP Seal Injection Realignment upon Loss of Component Cooling Water (CCW) 16 - Install Additional Train of Switchgear Room Cooling 17 - Enhance Procedures and Provide Additional Equipment to Respond to Loss of EDG Control Room Ventilation 18 - Redundant Service Water (SW) Turbine Header Isolation Valve 19 - Install Spray Shields on Residual Heat Removal (RHR) Pumps 20 - Fire Protection System to Provide Make-up to RCS and Steam Generators (SGs) 21 - Seal the Category II and III Cabinets in the Relay Room 22 - Install Fire Barriers between the 1CC1, lCC2, and 1CC3 Consoles in the CRE 23 - Install Fire Barriers and Cable Wrap to Maintain Divisional Separation in the 4160V AC Switchgear Room 24 - Provide Procedural Guidance to Cross-tie SGS 1 and 2 Service Water Systems 27 - In addition to the Equipment Installed for SAMA 5, Install Permanently Piped Seismically Qualified Connections to Alternate AFW Water Sources 30 - Automatic Start of Diesel-Powered Air Compressor 31 - Fully Automate Swap-over to Sump Recirculation 32 - Enhance Flood Detection for 100-foot Auxiliary Building and Enhance Procedural Guidance for Responding to Internal Floods To the original list of 21 HCGS SAMA candidates that survived Phase-I screening, two were added as a result of the NRC staffs review to generate the list of 23 SGS candidate SAMAs for
cost/benefit screening (Phase-Il) in Table 5-10. The additional two consisted of SAMAs 41 and 42, added as a sensitivity case to SAMA 5 to provide a comprehensive, long term mitigation strategy for SBO scenarios, and SAMAs 30 through 32.
(a)
Table 5-10 Candidate SAMAs for Cost/Benefit Screening at HCGS 1 - Remove Automatic Depressurization System (ADS) Inhibit from Non-ATWS Emergency Operating Procedures 3 - Install Back-up Air Compressor to Supply AOVs 4 - Provide Procedural Guidance to Cross-Tie RHR Trains 5 - Restore AC Power with Onsite Gas Turbine Generator 7 - Install Better Flood Protection Instrumentation for Reactor Auxiliaries Cooling System (RACS)
Compartment 8 - Convert Selected Fire Protection Piping from Wet to Dry Pipe System 10 - Provide Procedural Guidance to use B.5.b Low Pressure Pump for Non-Security Events 15 - Alternate Design of Core Spray System (CSS) Suction Strainer to Mitigate Plugging 16 - Use of Different Designs for Switchgear Room Cooling Fans 17 - Replace a Supply Fan with a Different Design in Service Water Pump Room 18 - Replace a Return Fan with a Different Design in Service Water Pump Room 30 - Provide Procedural Guidance for Partial Transfer of Control Functions from Control Room to the Remote Shutdown Panel 31 - Install Improved Fire Barriers in the Main Control Room (MCR) Control Cabinets Containing the Primary Main Steam Isolation Valve (MSIV) Control Circuits 32 - Install Additional Physical Barriers to Limit Dispersion of Fuel Oil from Diesel Generator (DG)
Rooms 33 - Install Division II 480V AC Bus Cross-ties 34 - Install Division I 480V AC Bus Cross-ties 35 - Relocate, Minimize and/or Eliminate Electrical Heaters in Electrical Access Room 36 - Provide Procedural Guidance for Loss of All 1E 120V AC Power 37 - Reinforce 1 E 120V AC Distribution Panels 39 - Provide Procedural Guidance to Bypass Reactor Core Isolation Cooling (RCIC) Turbine Exhaust Pressure Trip 40 - Increase Reliability/Install Manual Bypass of Low Pressure (LP) Permissive 41 - Installation of Passive Hardened Containment Ventilation Pathway 42 - Installation of SACS Standby Diesel-Powered Pump Quantitative evaluation of these is discussed in the next two sections.
5.2.4 Evaluation of Risk Reduction and Costs of Improvements PSEG's process for evaluating the potential plant improvements (SAMAs) for SGS and HCGS that survived Phase-1 screening is described in Section 5.2.2. Here the estimated risk reductions and costs of improvements for the specific SAMAs that were identified are discussed.
5.2.4.1 SGS Results
For the 29 SAMAs that survived Phase-I screening for SGS, the estimated risk reductions (and total benefits) and costs of improvements are listed in Table 5-11.
Table 5-11. Estimated Risk Reductions (and Total Benefits) and Costs of Improvements for SGS SAMAs
% Risk Reduction Total Benefit ($)
Population Baseline Baseline With BaseineWith Cost Cos ($
CDF Dose (internal + Uncertainty(c)
SAMA External) 1 - Enhance Procedures and Provide 34 30 4.8M 12M 475K Additional Equipment to Respond to Loss of Control Area Ventilation 2 - Re-configure SGS 3 to Provide a 10 10 1.6M 4.OM 875K More Expedient Backup AC Power Source for SGS 1 and 2 3 - Install Limited EDG Cross-Tie 16 15 2.4M 6.OM 4.2M Capability Between SGS 1 and 2 4 - Install Fuel Oil Transfer Pump on "C" 16 15 2.4M 6.OM 585K EDG & Provide Procedural Guidance for Using "C"EDG to Power Selected "A" and "B" Loads 5- Install Portable Diesel Generators to 16 11 3.1M 7.6M 3.3M Charge Station Battery and Circulating Water Batteries and Replace PDP with Air-Cooled Pump 5A(b) - Install Portable Diesel Generators 10 10 2.4M 6.0M(b) 770K to Charge Station Battery and Circulating Water Batteries 6 - Enhance Flood Detection for 84' 6 1 300K 750K 250K Auxiliary Building and Enhance Procedural Guidance for Responding to Service Water Flooding 7- Install "B" Train Auxiliary Feedwater 7 1 410K 1.0M 470K Storage Tank (AFWST) Makeup Including Alternate Water Source 8 -Install High Pressure Pump Powered 15 6 1.6M 4.1M 2.5M with Portable Diesel Generator and Long-term Suction Source to Supply the AFW Header 9 - Connect Hope Creek Cooling Tower 13 11 1.7M 4.3M 1.2M Basin to SGS Service Water System as Alternate Service Water Supply 10 - Provide Procedural Guidance for 1 <I 110K 280K 100K Faster Cooldown Loss of RCP Seal Cooling 11 - Modify Plant Procedures to Make 13 12 2.OM 5.0M 1OOK use of Other Unit's PDP for RCP Seal Cooling 12 - Improve Flood Barriers Outside of 3 3 550K 1.4M 475K 220/440VAC Switchgear Rooms
13 - Install Primary Side Isolation Valves 6 30 5.2M 13M 18M on the Steam Generators 14 - Expand AMSAC Function to Include 19 <.1 530K 1.3M 485K Backup Breaker Trip on Reactor Protection System (RPS) Failure 15 -Automate RCP Seal Injection 1 <1 42K 69K 210K Realignment upon Loss of Component Cooling Water (CCW) 16 - Install Additional Train of 1 1 180K 450K 2.5M Switchgear Room Cooling 17- Enhance Procedures and Provide 3 3 510K 1.3M 200K Additional Equipment to Respond to Loss of EDG Control Room Ventilation 18 - Redundant Service Water (SW) <1 <1 140K 350K 635K Turbine Header Isolation Valve 19 - Install Spray Shields on Residual 1 0 34K 84K 350K Heat Removal (RHR) Pumps 20- Fire Protection System to Provide 21 7 5.1M 12.7M 13M Make-up to RCS and Steam Generators (SGs) 21 - Seal the Category II and III Cabinets NOT ESTIMATED 870K 2.2M 3.2M in the Relay Room 22 - Install Fire Barriers between the NOT ESTIMATED 330K 830K 1.6M lCCl, 1CC2, and ICC3 Consoles in the CRE 23 - Install Fire Barriers and Cable Wrap NOT ESTIMATED 300K 750K 975K to Maintain Divisional Separation in the 4160V AC Switchgear Room 24 - Provide Procedural Guidance to 9 4 700K 1.8M 175K Cross-tie SGS 1 and 2 Service Water Systems 27 - In addition to the Equipment 16 11 3.1M 7.7M 4.2M Installed for SAMA 5, Install Permanently Piped Seismically Qualified Connections to Alternate AFW Water Sources 30Qa)- Automatic Start of Diesel-Powered 1 <1 40K 83K 1OOK Air Compressor 31(a) - Fully Automate Swap-over to 1 <1 27K 56K 100K Sump Recirculation 32(a) - Enhance Flood Detection for 100- 1 <1 50K 100K 250K foot Auxiliary Building and Enhance Procedural Guidance for Responding to Internal Floods (a) SAMAs 30, 31, and 32 were identified and evaluated in response to an NRC staff RAI (PSEG 2010a). The RAI response stated that the percent risk reduction was developed using SGS PRA Model Version 4.3 and that the implementation costs for SAMAs 30 and 31 are expected to be significantly greater than the $100K assumed in the SAMA evaluation.
(b) Value estimated by NRC staff using information provided in the ER.
(c) Using a factor of 2.5.
The costs of implementing these candidate SAMAs did not include the cost of replacement power during extended outages required to implement the modifications (PSEG 2009a). The NRC staff reviewed the bases for the applicant's cost estimates. For certain improvements, the NRC staff also compared the cost estimates to estimates developed elsewhere for similar improvements, including estimates developed as part of other licensees' analyses of SAMAs for operating reactors.
The ER stated that plant personnel developed SGS-specific costs to implement each of the SAMAs. The NRC staff requested more information on the process PSEG used to develop the SAMA cost estimates (NRC 2010a). PSEG explained that the cost estimates were developed in a series of meetings where each SAMA was validated against the plant configuration, a budget-level estimate of its implementation cost was developed, and, in some instances, lower cost approaches that would achieve the same objective were developed. Seven general cost categories were used in development of the budget-level cost estimates: engineering, material, installation, licensing, critical path impact, simulator modification, and. procedures and training.
For costs that could be shared between the two SGS units, the total estimated cost was evenly divided between the two units to develop a per unit cost. Based on the use of personnel having significant nuclear plant engineering and operating experience, the NRC staff considers the process PSEG used to develop budget-level cost estimates reasonable.
In response to an RAI requesting a more detailed description of the changes associated with SAMAs 3, 5, 8, 13, 20, and 23, PSEG provided additional information detailing the analysis and plant modifications included in the cost estimate of each improvement (PSEG 2010a). The staff reviewed the costs and found them to be reasonable, and generally consistent with estimates provided in support of other plants' analyses.
The NRC staff requested PSEG provide justification for the differences in the cost estimates between the two SAMAs in each following pairings, given their apparent similarities: (1) SAMA 1, "Enhance Procedures and Provide Additional Equipment to Respond to Loss of Control Area Ventilation," having a cost of $475K, and SAMA 17, "Enhance Procedures and Provide Additional Equipment to Respond to Loss of Emergency Diesel Generator (EDG) Control Room Ventilation," having a cost of $200K; (2) SAMA 21, "Seal the Category II and III Cabinets in the Relay Room," and SAMA 22, "Install Fire Barriers between the lCC1, 1CC2, and 1CC3 Consoles in the CRE;" (3) SAMA 10, "Provide Procedural Guidance for Faster Cooldown Loss of RCP Seal Cooling," and SAMA 11, "Modify Plant Procedures to Make use of Other Unit's Positive Displacement Pump (PDP) for RCP Seal Cooling."
Based on the PSEG responses, the NRC staff considers the bases for the estimated costs for these SAMA pairings reasonable and that the cost estimates provided by PSEG are sufficient and appropriate for use in the SAMA evaluation for SGS.
5.2.4.2 HCGS Results For the 23 SAMAs that survived Phase-I screening for HCGS, the estimated risk reductions (and total benefits) and costs of improvements are listed in Table 5-12.
Table 5-12. Estimated Risk Reductions (and Total Benefits) and Costs of Improvements for
% Risk Reduction Total Benefit ($)
Population Baseline Baseline With Cost ($)
CDF Dose (Internal + Uncertainty(cl SAMA External) _____
1 - Remove Automatic Depressurization 26 29 5.3M 14.9M 200K System (ADS) Inhibit from Non-ATWS Emergency Operating Procedures 3 - Install Back-up Air Compressor to 16 16 3.3M 9.4M 700K Supply AOVs 4 - Provide Procedural Guidance to 12 21 4.4M 12.4M 1OOK Cross-Tie RHR Trains 5(") - Restore AC Power with Onsite Gas 9 11 2.2M 6.3M 2.05M Turbine Generator 7 - Install Better Flood Protection 4 2 330K 930K 3.07M Instrumentation for Reactor Auxiliaries Cooling System (RACS) Compartment 8 - Convert Selected Fire Protection 4 1 300K 860K 600K Piping from Wet to Dry Pipe System 10 - Provide Procedural Guidance to use 1 1 200K 570K 1OOK B.5.b Low Pressure Pump for Non-Security Events 15 - Alternate Design of Core Spray 2 1 130K 360K 1.0M System (CSS) Suction Strainer to Mitigate Plugging 16 - Use of Different Designs for 2 1 130K 370K 400K Switchgear Room Cooling Fans 17 - Replace a Supply Fan with a 5 5 960K 2.7M 600K Different Design in Service Water Pump Room 18 - Replace a Return Fan with a 5 5 960K 2.7M 600K Different Design in Service Water Pump Room 30 - Provide Procedural Guidance for NOT ESTIMATED 8.6M 24M 100K Partial Transfer of Control Functions from Control Room to the Remote Shutdown Panel 31 - Install Improved Fire Barriers in the NOT ESTIMATED 360K 1.0M 1.2M Main Control Room (MCR) Control Cabinets Containing the Primary Main Steam Isolation Valve (MSIV) Control Circuits 32 - Install Additional Physical Barriers NOT ESTIMATED 480K 1.4M 800K to Limit Dispersion of Fuel Oil from Diesel Generator (DG) Rooms 33 - Install Division II 480V AC Bus NOT ESTIMATED 450K 1.3M 1.32M Cross-ties 34 - Install Division I 480V AC Bus NOT ESTIMATED 430K 1.2M 1.32M Cross-ties
35 - Relocate, Minimize and/or Eliminate NOT ESTIMATED 410K(b) 1.2M~b) 270K Electrical Heaters in Electrical Access Room 36 - Provide Procedural Guidance for NOT ESTIMATED 240K 680K 270K Loss of All 1 E 120V AC Power 37 - Reinforce 1 E 120V AC Distribution NOT ESTIMATED 430K 1.2M 500K Panels 39 - Provide Procedural Guidance to 10 <1 130K 380K 120K Bypass Reactor Core Isolation Cooling (RCIC) Turbine Exhaust Pressure Trip 40- Increase Reliability/Install Manual 1 1 210K 610K 620K Bypass of Low Pressure (LP) Permissive 41 - Installation of Passive Hardened 15 30 6.2M 18M >25M Containment Ventilation Pathway ___
42 - Installation of SACS Standby 2 1 270K 760K 6.2M Diesel-Powered Pump _
(a) Revised assumptions, risk reduction, and baseline benefits for SAMA 5 were provided in response to an NRC staff RAI (PSEG 2010b, PSEG 2010d). The baseline with uncertainty estimate was estimated by the NRC staff using information provided in the ER and in response to the RAI.
(b) The baseline benefit for SAMA 35 was provided by PSEG in response to an NRC staff RAI (PSEG 201 Ob).
The baseline with uncertainty estimate was estimated by the NRC staff using information provided in the ER and in response to the RAI.
(c) Using a factor of 2.84.
The costs of implementing these candidate SAMAs did not include the cost of replacement power during extended outages required to implement the modifications, nor did they include contingency costs for unforeseen difficulties (PSEG 201Gb). The cost estimates provided in the ER did not account for inflation, which is considered another conservatism. The NRC staff reviewed the bases for the applicant's cost estimates. For certain improvements, the NRC staff also compared the cost estimates to estimates developed elsewhere for similar improvements, including estimates developed as part of other licensees' analyses of SAMAs for operating reactors.
The ER stated that plant personnel developed HCGS-specific costs to implement each of the SAMAs. The NRC staff requested more information on the process PSEG used to develop the SAMA cost estimates (NRC 201 Ga). PSEG explained that the cost estimates were developed in a series of meetings where each SAMA was validated against the plant configuration, a budget-level estimate of its implementation cost was developed, and, in some instances, lower cost approaches that would achieve the same objective were developed. Seven general cost categories were used in development of the budget-level cost estimates: engineering, material, installation, licensing, critical path impact, simulator modification, and procedures and training.
Based on the use of personnel having significant nuclear plant engineering and operating experience, the NRC staff considers the process PSEG used to develop budget-level cost estimates reasonable.
The NRC staff requested additional clarification on the estimated costs for the following two SAMAs, which seemed high for what are described as procedure changes and operator training
(NRC 201 Ob): (1) SAMA 5, "Restore AC Power with Onsite Gas Turbine Generator," with an implementation cost of $2.05M; (2) SAMA 36, "Provide Procedural Guidance for Loss of All 1 E 120V AC Power," with an implementation cost of $270K,. PSEG further described SAMA 5 as a safety-related permanent plant modification that provides the necessary equipment to connect a dedicated transformer at Salem Unit 3 to HCGS, which is significantly more costly than, and is in addition to, the procedure changes (PSEG 2010a). PSEG explained that SAMA 36 modification involves the development of a group of procedures, not just the revision of existing procedures or the development of a single procedure. In addition, there is a significant effort involved with determining a success path to achieve safe shutdown, to update the simulator to include all necessary components to implement the success path, to test the success path, and to implement the new procedures. Based on this additional information, the NRC staff considers the estimated costs for these two SAMAs to be reasonable and acceptable for purposes of the SAMA evaluation.
The NRC staff asked PSEG for additional information on the following two SAMAs: (1) SAMA 10, "Provide Procedural Guidance to use B.5.b Low Pressure Pump for Non-Security Events;"
(2) SAMA 16, "Use of Different Designs for Switchgear Room Cooling Fans." For SAMA 10, PSEG responded that the $1 00K cost estimate, corresponding "only" to a procedure change, assumes that an existing pump already installed at HCGS will be made available to implement this SAMA (PSEG 2010b). For SAMA 16, PSEG provided additional information detailing the cost estimate of this improvement (PSEG 201 Ob). The staff reviewed the additional information for both of these SAMAs and found it to be reasonable, and generally consistent with estimates provided in support of other plants' analyses.
The NRC staff noted that HCGS SAMA 31, "Install Improved Fire Barriers in the Main Control Room (MCR) Control Cabinets Containing the Primary Main Steam Isolation Valve (MSIV)
Control Circuits," is similar to SGS SAMAs 21 and 22 in that each involves installing fire barriers, but has an estimated cost of $1.2M to modify one cabinet that is similar to the estimated cost of
$1.6M for SGS SAMA 22 to modify three Control Room consoles, but significantly less per cabinet than that for SGS SAMA 21 to modify 48 Relay Room cabinets (NRC 2010a, NRC 2010b). PSEG responded that SAMA 31 is more complicated than SGS SAMA 21 because it requires making ventilation modifications due to the significant heat loads in addition to adding fire barrier materials. PSEG also explained that both HCGS SAMA 31 and SGS SAMA 22 assumed the same material and installation cost per console ($400K) and the same engineering cost ($800K), but that the engineering cost was evenly divided between the two units at SGS to arrive at a cost per unit. The NRC staff considers the basis for the differences in cost estimates reasonable.
The NRC staff noted that the estimated cost of $620K for SAMA 40, "Increase Reliability/Install Manual Bypass of Low Pressure (LP) Permissive," is significantly higher than the estimated cost of $250K for a similar improvement evaluated for the Duane Arnold nuclear power plant license renewal application (NRC 2010b). In response to the RAI, PSEG clarified that SAMA 40 involves the installation of six key-lock switches to bypass various low pressure submissives rather than jumpers, as was assumed in the Duane Arnold application (PSEG 201 Ob). Based on this additional information, the NRC staff considers the estimated cost for HCGS to be
reasonable and acceptable for purposes of the SAMA evaluation.
The NRC staff also noted that the estimated cost of $1.32M each for SAMA 33, "Install Division II 480V AC Bus Cross-ties," and SAMA 34, "Install Division I 480V AC Bus Cross-ties," is significantly higher than the estimated cost of $328K to $656K for a similar improvement evaluated for other nuclear power plant license renewal applications, i.e., Wolf Creek and Susquehanna (NRC 2010b). PSEG explained that these modifications involved the installation of new tie-breakers and cables for the 480V AC bus cross-ties, having a material and installation cost of $400K, and a significant cost for engineering, which was estimated to be $800K (PSEG 2010b). Based on this additional information, the NRC staff considers the basis for the estimated cost to be reasonable.
Based on the PSEG responses, the NRC staff concludes that the cost estimates provided by PSEG are sufficient and appropriate for use in the HCGS SAMA evaluation.
5.2.5 Cost-Benefit Comparison The methodology used by PSEG was based primarily on NRC's guidance for performing cost-benefit analysis, i.e., NUREG/BR-0184, Regulatory Analysis Technical Evaluation Handbook (NRC 1997). The guidance involves determining the net value for each SAMA according to a formula that considers the net value due to the cost of the enhancement and present values for the following four "accident aversion" costs: (1) public exposure; (2) occupational exposure; (3) offsite property damage; (4) onsite property damage. If the net value of the SAMA is negative, i.e., the cost of implementing the SAMA is larger than the benefit associated with the SAMA, it is not considered cost-beneficial. Revision 4 of NUREG/BR-0058 states that two sets of estimates should be developed, one at 3% and one at 7% (NRC 2004). PSEG provided a base set of results for both SGS and HCGS using the 3% discount rate and a sensitivity study using the 7%
discount rate (PSEG 2009a, PSEG 2009b). PSEG also performed additional analyses for both SGS and HCGS to evaluate the impact of parameter choices and uncertainties on the results of the SAMA assessment In the baseline and uncertainty analysis (using the 3% discount rate), PSEG identified 17 and 13 potentially cost-beneficial SAMAs, respectively for SGS and Hope Creek as follows (see Table 5-11 or 5-12 for titles of these SAMAs): (1) SGS - SAMAs 1 through 12, including 5A, 14, 17, 24 and 27; (2) HCGS - SAMAs 1, 3, 4, 8, 10, 17, 18, 30, 32, 35, 36, 37, and 39. PSEG indicated that they plan to further evaluate these SAMAs at SGS and HCGS for possible implementation using existing action-tracking and design change processes (PSEG 2009a, PSEG 2009b).
Specifically, these potentially cost-beneficial SAMAs will be considered for implementation through the established Plant Health Committee (PHC) process at each plant (PSEG 2009a, PSEG 2009b). The PHC is chartered with reviewing issues that require special plant management attention to ensure effective resolution and, with respect to each of the potentially cost-beneficial SAMAs, will decide on one of the following courses of actions: (1) approve for implementation; (2) conditionally approved for implementation pending the results of requested evaluations; (3) not approve for implementation; or (4) table until additional information needed to make a final decision is provided to the PHC.
5.2.5.1 SGS Results
SGS SAMAs identified primarily on the basis of the internal events analysis could provide additional benefits in certain external events. To account for these, PSEG multiplied the internal event benefits for all but one internal event SAMA (SAMA 20, discussed further below) by a factor of 2, which is approximately the ratio of the total CDF from internal and external events to the internal event CDF (PSEG 2009a). Eleven of the 17 SAMAs listed above (1, 2, 4, 6, 9, 10, 11, 12, 14, 17, and 24) were determined to be cost-beneficial based on this multiplier. PSEG did not multiply the internal event benefits by the factor of 2 for three SAMAs that specifically address fire risk (SAMAs 21, 22, and 23) since they would not have a corresponding benefit on the risk from internal events. The NRC staff also noted that PSEG "double counted" the benefits from external events for SAMAs 1 and 8 for fire, and SAMAs 5, 5A, and 27 for seismic.
However, since this over-estimates the benefits from external events and therefore results in conservative estimates of the SAMA benefits, the NRC staff considers the process PSEG used acceptable for the SAMA evaluation.
For SAMA 20, PSEG multiplied the estimated benefits for internal events by a factor of 2.0 to account for external events in the Phase I analysis. In the Phase II analysis, PSEG separately quantified the internal event, fire event, and seismic event benefits and, to account for the additional benefits in other (non-fire/non-seismic) external events, multiplied the internal event benefits by a factor of 1.1, which is the ratio of the total CDF from internal (5.0 x 105 per year) and other external events (5.0 x 10e per year) to the internal event CDF. The estimated SAMA benefits from all these hazard groups were then summed to provide an overall benefit. Since the methodology PSEG used accounts for both internal events and external events, the NRC staff considers the methodology PSEG used for SAMA 20 acceptable for the SAMA evaluation.
PSEG considered the impact that possible increases in benefits from analysis uncertainties would have on the results of the SAMA assessment by presenting the results of an uncertainty analysis of the internal events CDF, which indicates that the 9 5 th percentile value is a factor of 1.64 times the point estimate CDF for SGS. PSEG considered the impact on the Phase II analysis if the estimated benefits were increased by a factor of 1.64 (in addition to the multiplier of 2 for external events). Four additional SAMAs (5, 7, 8, and 27) became cost-beneficial as a result. Additionally, PSEG noted that the 9 5 th percentile value for CDF may be underestimated because uncertainty distributions are not applied to all basic events in the SGS PRA model. To account for this, PSEG used a factor of 2.5 times the point estimate CDF to represent the 95th percentile value, which is stated to be typical of most light water reactor CDF uncertainty analyses. PSEG further considered the impact on the Phase II screening if the estimated benefits were increased by a factor of 2.5 (in addition to the multiplier of 2 for external events).
One additional SAMA became cost-beneficial (SAMA 3). The NRC staff notes that while the factor of 2.5 does not represent an upper bound, it is typical of factors used in prior SAMA analyses, is higher than the factor calculated for other Westinghouse 4-loop plants and used in prior SAMA analysis, and is therefore considered by the NRC staff to be appropriate for use in the SAMA sensitivity analyses.
PSEG provided the results of additional sensitivity analyses in the ER, including use of a 7%
discount rate and variations in MACCS2 input parameters. These analyses did not identify any additional potentially cost-beneficial SAMAs at SGS (PSEG 2009a). The NRC staff noted that the ER reported 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, while 1,115 MWe was used to calculate long-term replacement power costs for the SAMA analysis (NRC 201 Oa).
In response to the RAI, PSEG clarified that 1,115 MWe used in the SAMA analysis was incorrect
and provided a revised replacement power cost estimate of $359,000 using the correct 1,195 MWe, which is an approximate 7% increase over that used in the SAMA analysis (PSEG 201 Oa). The revised Maximum Averted Cost Risk (MACR) of $16.61 M is an increase of only about 0.3% over the MACR used in the SAMA analysis. The NRC staff agrees with PSEG's assessment that this would have a negligible impact on the conclusions of the SAMA analysis At NRC's request, PSEG extended the review of Level-1 and Level-2 basic events down to an RRW of 1.006, which equates to a benefit of about $50,000 (NRC 201 Oa, PSEG 201 Oa). The review identified three additional SAMAs (30, 31 and 32) associated with new basic events added to the importance lists. Based on information provided in the RAI response, the NRC staff estimated a revised external event multiplier of about 3.4 and a revised MACR of about
$7.9M for these three SAMAs, representing a decrease of more than 50% compared to the SGS results reported in the ER. PSEG's analysis had determined that none of the three SAMA candidates was cost-beneficial in either the baseline analysis or the uncertainty analysis. PSEG re-evaluated each potentially cost-beneficial SAMA and determined that five SAMA candidates (3, 5, 11, 14, and 27) would no longer be cost-beneficial (PSEG 2010c). PSEG also qualitatively evaluated each SAMA determined to not be cost-beneficial and confirmed the conclusion that none would become cost-beneficial The NRC staff also asked the licensee to evaluate several potentially lower cost alternatives to SAMAs 8 and 20 (NRC 201 Oa). For SAMA 8, PSEG had concluded that the proposed improvement would not be feasible. For an alternative to SAMA 8, PSEG concluded that the estimated implementation cost would be significantly greater than the maximum potential benefit, such that that the alternative to SAMA 8 would not be cost-beneficial. For SAMA 20, PSEG explained that the configuration of the Fire Area addressed by SAMA 20 is significantly more complex than that for the Fire Area addressed by SAMA 23, such that the cost would be at least an order of magnitude greater. Because the estimated implementation cost is significantly greater than the maximum potential benefit, PSEG concluded that the proposed SAMA would not be cost-beneficial (PSEG 2010a, 2010c).
The NRC staff concludes that, with the exception of the potentially cost-beneficial SAMAs discussed above, the costs of the other SAMAs evaluated would be higher than the associated benefits for SGS.
5.2.5.2 HCGS Results HCGS SAMAs identified primarily on the basis of the internal events analysis could provide benefits in certain external events, in addition to their benefits in internal events. To account for these, PSEG multiplied the internal event benefits for each internal event SAMA by a factor of 6.3 (excluding eight SAMAs that specifically address fire and seismic risk), which is the ratio of the total CDF from internal (4.4 x 10-6 per year) and external events (2.31 x 10.5 per year) to the internal event CDF. Seven of the 13 SAMAs listed above (SAMAs 1, 3, 4, 10, 17, 18, and 39) were determined to be cost-beneficial based on this multiplier. PSEG did not multiply the internal event benefits by the factor of 6.3 for the eight SAMAs that specifically address fire and seismic risk (30 through 37) because these SAMAs are specific to fire or seismic risks and would not have a corresponding benefit on the risk from internal events. Two of these SAMAs (30 and 35) were found to be cost-beneficial.
PSEG considered the impact that possible increases in benefits from analysis uncertainties would have on the results of the SAMA assessment by presenting the results of an uncertainty analysis of the internal events CDF, which indicates that the 9 5 th percentile value is a factor of 2.84 times the point estimate CDF for HCGS. PSEG considered the impact on the Phase II analysis if the estimated benefits were increased by a factor of 2.84 (in addition to the multiplier of 6.3 for external events). Four additional SAMAs became cost-beneficial in PSEG's analysis (SAMAs 8, 32, 36, and 37). PSEG provided the results of additional sensitivity analyses in the ER, including use of a 7% discount rate and variations in MACCS2 input parameters. These analyses did not identify any additional potentially cost-beneficial SAMAs at HCGS (PSEG 2009b).
In response to NRC staff RAIs, PSEG considered additional plant improvements to address basic events for which no SAMAs had been identified in the ER. PSEG determined that of the plant improvements considered, two additional SAMAs (41 and 42) warranted further consideration. However, PSEG's analysis determined that neither of these SAMA candidates was cost-beneficial in either the baseline analysis or the uncertainty analysis.
As indicated in Section 5.2.2.4, PSEG determined that the external events multiplier would be 6.8 if the higher seismic CDF obtained using the LLNL hazard curves were used rather than the EPRI hazard curves. PSEG then reviewed the Level 1 and Level 2 basic events down to an RRW of 1.005 to account for this revised multiplier. In addition, since the maximum benefit of each seismic sequence increased as a result of using the LLNL hazard curves, PSEG reviewed two additional seismic sequences having a benefit equal to or greater than $100,000, the minimum expected SAMA implementation cost at HCGS. These reviews resulted in the identification and evaluation of the following five additional SAMAs: (1) SAMA RAI 5.j-IE1, "Install a Key Lock Switch for Bypass of the Main Steam Isolation Valve (MSIV) Low Level Isolation Logic;" (2) SAMA RAI 5p-1, "Install an Independent Boron Injection System;" (3) a SAMA to "Reinforce 1E 125V DC distribution panels 1AIB/C/D-D-417;" (4) a SAMA to "Reinforce 1E 120V AC distribution panels 1AIB/C/DJ482;" (5) a SAMA to "Reinforce 1 E 120V AC distribution panels to 1.0g Seismic Rating." For the first four SAMAs, PSEG estimated the implementation cost to be greater than the estimated benefit accounting for uncertainties, such that none of these were cost-beneficial.
The fifth of these SAMAs assumes that the following occur: (1) SAMA 37, already determined to be cost-beneficial, is implemented; (2) the HCLPF values for the 120V AC panels are further increased to 1 g as a result of the implementation; (3) the third SAMA above to reinforce the 125V DC panels is implemented, although not cost-beneficial by itself; and (4) the HCLPF values for the panels are increased from the current 0.57g to 1.0g as a result of the implementation (PSEG 2010b.PSEG 2010d). Synergistic benefits among of this new proposed SAMA, SAMA 37, and the third SAMA above results in a total benefit of $330K in the baseline analysis, and $940K after accounting for uncertainties. Since the latter estimated benefit exceeds the $900K implementation cost, PSEG determined that this proposed SAMA was potentially cost-beneficial and will be considered for implementation through the established HCGS Plant Health Committee process. Furthermore, because the risk reduction from this new proposed SAMA cannot be obtained without implementation of the proposed SAMA to reinforce the 125V DC panels, the NRC staff concludes that both SAMA 37 and the combined SAMA of reinforcing both the 120 VAC and 125 VDC panels be considered for implementation.
PSEG identified two plant improvements in the ER that were excluded from the SAMA evaluation because they were higher cost than the SAMA selected for evaluation: (1) "Replace the normally open floor and equipment drain MOVs with fail-closed AOVs; and (2) "Auto align 480V AC portable station generator." The NRC staff noted however that the two improvements could have larger benefits than the SAMAs evaluated because they could be more effective or could mitigate additional events (PSEG 2010b). In response to the RAIs, PSEG evaluated the two improvements and concluded for each that the implementation cost was greater than the estimated benefit accounting for uncertainties. Therefore, neither was considered cost-beneficial.
The NRC staff asked the applicant to evaluate the following lower cost alternatives to the SAMAs considered in the ER (NRC 2010b): (1) "Establishing procedures for opening doors and/or using portable fans for sequences involving room cooling failures," on the basis of which PSEG identified new SAMA RAI 7.a-1 to implement the suggested alternative in the Service Water Pump Room as an alternative to SAMAs 17 and 18; (2) "Extending the procedure for using the B.5.b low pressure pump for non-security events to include all applicable scenarios, not just station black outs (SBOs);" (3) "Utilizing a portable independently powered pump to inject into containment." For the first (SAMA RAI 7.a-1), PSEG determined that the estimated benefit is greater than the implementation cost, such that this potentially cost-beneficial SAMA merits further evaluation in parallel with the permanent hardware modifications of cost-beneficial SAMAs 17 and 18. For the second and third, PSEG noted that SAMA 10 already addressed the suggested alternatives (PSEG 201Gb, PSEG 2010d). The NRC staff agrees with PSEG's conclusion.
The NRC staff also questioned the risk reduction potential for SAMAs 5 and 35 (NRC 201 Ga, NRC 201Gb), for which PSEG provided revised estimates of the benefits. As a result, SAMA 5 was determined to be potentially cost-beneficial, such that it will be considered for implementation through the established HCGS Plant Health Committee process. Similarly, PSEG's revised analysis determined that SAMA 35 remained cost-beneficial (PSEG 2010b, PSEG 201 Gd).
The NRC staff concludes that, with the exception of the potentially cost-beneficial SAMAs discussed above, the costs of the other SAMAs evaluated would be higher than the associated benefits for HCGS.
5.2.6 Conclusions For both SGS and HCGS, the NRC staff reviewed the PSEG analyses and concludes that the methods used and the implementation of those methods was sound. The treatments of SAMA benefits and costs support the general conclusion that the SAMA evaluations performed by PSEG are reasonable and sufficient for the license renewal submittals. Although the treatments of SAMAs for external events were somewhat limited, the likelihood of there being cost-beneficial enhancements in these areas was minimized by improvements that have been realized as a result of the IPEEE process, separate analyses of fire events, and inclusion of multipliers to account for non-fire, non-seismic external events.
The NRC staff concurs with PSEG's identification of areas in which risk can be further reduced at both SGS and HCGS in a cost-beneficial manner through the implementation of the identified,
potentially cost-beneficial SAMAs. Given the potential for cost-beneficial risk reductions, the NRC staff agrees that further evaluations of these SAMAs by PSEG are warranted. However, these SAMAs do not relate to adequately managing the effects of aging during the periods of extended operation for SGS or HCGS. Therefore, they need not be implemented as part of license renewal pursuant to Title 10 of the Code of Federal Regulations, Part 54.
5.3 References Electric Power Research Institute (EPRI). 1989. "Probabilistic Seismic Hazard Evaluations at Nuclear Plant Sites in the Central and Eastern United States; Resolution of the Charleston Earthquake Issues." EPRI NP-6395-D, EPRI Project P101-53. Palo Alto, CA. April 1989.
Electric Power Research Institute (EPRI). 1991. "A Methodology for Assessment of Nuclear Power Plant Seismic Margin," Implementation Guide NP-6041, Revision 1. Palo Alto, CA.
August 1991.
Electric Power Research Institute (EPRI). 1993. "Fire Induced Vulnerability Evaluation (FIVE)
Methodology." TR-1 00370, Revision 1, Palo Alto, CA. September 19, 1993.
Nuclear Energy Institute (NEI). 2005. "Severe Accident Mitigation Alternative (SAMA) Analysis Guidance Document", NEI 05-01, Rev. A. Washington, D.C. November 2005.
Public Service Electric and Gas Company (PSEG). 1993. Letter from Stanley LaBruna, PSEG, to NRC Document Control Desk.
Subject:
"Generic Letter 88-20; Individual Plant Examination (IPE) Report, Salem Generating Station, Unit Nos. 1 and 2, Docket Nos. 50-272 and 50-311,"
Hancocks Bridge, New Jersey. July 30, 1993. Accessible at ML080100047.
Public Service Electric and Gas Company (PSEG). 1994. "Hope Creek Generating Station.
Individual Plant Examination." April 1994. Accessible at ML080160331.
Public Service Electric and Gas Company (PSEG). 1995. Letter from E. Simpson, PSEG, to NRC Document Control Desk.
Subject:
"Response to Generic Letter 88-20 Individual Plant Examination for Severe Accident Vulnerabilities - 1 OCFR50.54 (f) Request for Additional Information Salem Generating Station, Unit Nos. 1 and 2 Facility Operating License Nos. DRR-70 and DPR-75 Docket Nos. 50-272 and 50-311," Hancocks Bridge, New Jersey. August 01, 1995. Accessible at ML080100021.
Public Service Electric and Gas Company (PSEG). 1996. Letter from E. C. Simpson, PSEG, to NRC Document Control Desk.
Subject:
"Response to Generic Letter No. 88-20, Supplement 4, Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities, Salem Generating Station Units Nos. 1 and 2, Facility Operating License Nos. DPR-70 and DPR-75, Docket Nos. 50-272 and 50-311," Hancocks Bridge, New Jersey. January 29, 1996.
Accessible at ML080100023.
Public Service Electric and Gas Company. (PSEG). 1997. "Hope Creek Generating Station
Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities."
July 1997. Accessible at ML080160320.
PSEG Nuclear, LLC (PSEG). 2009a. Salem Nuclear Generating Station --- License Renewal Application, Appendix E: Applicant's Environmental Report; OperatingLicense Renewal Stage.
Hancocks Bridge, New Jersey. August 18, 2009. Accessible at ML092400532.
PSEG Nuclear, LLC (PSEG). 2009b. Hope Creek Generating Station - License Renewal Application, Applicant's EnvironmentalReport, OperatingLicense Renewal Stage, August 2009.
Accessible at ML092430484.
PSEG Nuclear, LLC (PSEG). 2010a. Letter from Paul. J. Davison, PSEG, to NRC Document Control Desk.
Subject:
"Response to NRC Request for Additional Information dated April 12, 2010, related to the Severe Accident Mitigation Alternatives (SAMA) review of the Salem Nuclear Generating Station, Units 1 and 2," Hancocks Bridge, New Jersey. May 24, 2010. Accessible at ML101520326.
PSEG Nuclear, LLC (PSEG). 2010b. Letter from Paul J. Davison, PSEG, to NRC Document Control Desk.
Subject:
"Response to NRC Request for Additional Information dated April 20, 2010, related to the Severe Accident Mitigation Alternatives (SAMA) review associated with the Hope Creek Generating Station License Renewal Application," Hancocks Bridge, New Jersey.
June 1, 2010. Accessible at ML101550149.
PSEG Nuclear, LLC (PSEG). 2010c. Letter from Christine T. Neely, PSEG, to NRC Document Control Desk.
Subject:
"Supplement to RAI responses submitted in PSEG Letter LR-N10-0164 dated May 24, 2010, related to the Severe Accident Mitigation Alternatives (SAMA) review of the Salem Nuclear Generating Station, Units 1 and 2," Hancocks Bridge, New Jersey. August 18, 2010. Accessible at ML102320211.
PSEG Nuclear, LLC (PSEG). 201 Od. Letter from Christine T. Neely, PSEG, to NRC Document Control Desk.
Subject:
"Supplement to RAI responses submitted in PSEG Letter LR-N10-0181 dated June 1, 2010, related to the Severe Accident Mitigation Alternatives (SAMA) review of the Hope Creek Generating Station," Hancocks Bridge, New Jersey. August 18, 2010. Accessible at ML102320212.
U.S. Nuclear Regulatory Commission (NRC). 1989. Fire Risk Scoping Study. NUREG/CR-5088. January 1989. Washington, D.C.
U.S. Nuclear Regulatory Commission (NRC). 1991b. "Procedural and Submittal Guidance for the Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities."
NUREG-1407. Washington, D.C. June 1991.
U.S. Nuclear Regulatory Commission (NRC). 1994. Revised Livermore Seismic Hazard Estimates for Sixty-Nine Nuclear Plant Sites East of the Rocky Mountains. NUREG-1488, April 1994. Washington, D.C.
U.S. Nuclear Regulatory Commission (NRC). 1997. Regulatory Analysis Technical Evaluation Handbook. NUREG/BR-0184, Washington, D.C. January 1997.
U.S. Nuclear Regulatory Commission (NRC). 1998. Code Manual for MACCS2.
NUREG/CR-6613, Washington, D.C. May 1998.
U.S. Nuclear Regulatory Commission (NRC). 1999a. Letter from Patrick D. Milano, U.S. NRC to Harold W. Keiser, PSEG.
Subject:
Generic Letter 88-20, Supplement 4, "Individual Plant Examination for External Events for Severe Accident Vulnerabilities," Salem Nuclear Generating Station, Unit Nos. 1 and 2 (TAC Nos. M83669 and M83670). May 21, 1999.
U.S. Nuclear Regulatory Commission (NRC). 1999b. Letter from Richard B. Ennis, U.S. NRC, to Harold W. Keiser, PSEG.
Subject:
"Review of Individual Plant Examination of External Events (IPEEE) Submittal for Hope Creek Generating Station (TAC No. M83630)". April 26, 1999.
U.S. Nuclear Regulatory Commission (NRC). 2001. "Review of Columbia Generating Station Individual Plant Examination of External Events Submittal (TAC No. M83695)." Washington, D.C. February 26, 2001. (ADAMS Accession No. ML010570035)
U.S. Nuclear Regulatory Commission (NRC). 2004. Regulatory Analysis Guidelines of the U.S.
Nuclear Regulatory Commission. NUREG/BR-0058, Revision 4, Washington, D.C. September 2004.
U.S. Nuclear Regulatory Commission (NRC). 2010a. Letter from Charles Eccleston, U.S. NRC, to Thomas Joyce, PSEG.
Subject:
Request for Additional Information, Regarding Severe Accident Mitigation Alternatives for the Salem Nuclear Generating Station, Units 1 and 2. April 12, 2010. Accessible at ML100910252.
U.S. Nuclear Regulatory Commission (NRC). 2010b. Letter from Charles Eccleston, U.S. NRC, to Thomas Joyce, PSEG.
Subject:
Revised Request for Additional Information Regarding Severe Accident Mitigation Alternatives for Hope Creek Generating Station. May 20, 2010.
Accessible at ML101310058.
U.S. Nuclear Regulatory Commission (NRC). 2010c.
Subject:
Summary of Telephone Conference Held on July 29, 2010 between the U.S. Nuclear Regulatory Commission and PSEG Nuclear LLC, Concerning Follow-up Questions Pertaining to the Salem Nuclear Generating Station, Units 1 and 2, and Hope Creek Generating Stations License Renewal Environmental Review. August 13, 3010. Accessible at ML102220012.