Text

Reanalysis of Severe Accident Mitigation Alternatives
	ML12325A174
Person / Time
Site:	Grand Gulf
Issue date:	11/19/2012
From:	Mike Perito; Entergy Operations
To:	; Office of Nuclear Reactor Regulation, Document Control Desk
References
	GNRO-2012/00144
	Download: ML12325A174 (110)
	v • d • e

~Entergy Entergy Operations, Inc.

P. o. Box 756 Port Gibson, MS 39150 Michael Perito Vice President, Operations Grand Gulf Nuclear Station Tel. (601) 437-6409 GNRO-2012/00144 November 19,2012 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001

SUBJECT:

Reanalysis of Severe Accident Mitigation Alternatives Grand Gulf Nuclear Station, Unit 1 Docket No. 50-416 License No. NPF-29

REFERENCE:

1 Entergy Operations Letter, "Response to Request for Additional Information (RAI) on Severe Accident Mitigation Alternatives", dated October 2,2012 (GNRO-2012/00117) (ML12277A082) 2 Entergy Operations Letter, "Response to Request for Additional Information (RAI) on Severe Accident Mitigation Alternatives," dated July 19, 2012 (GNRO-2012/00072) (ML12202A056)

Dear Sir or Madam:

Entergy Operations, Inc. is providing the information requested in reference 1 Response to Request for Additional Information (RAI) on Severe Accident Mitigation Alternatives. Enclosure 1 contains a summary of the submittal. Attachment 1 provides revised pages of the Environmental Report (ER) which were changed by the reanalysis. Attachment 2 provides revised versions of the RAI responses provided in Reference 2 changed by the reanalysis.

Attachment 3 provides a new table of "Release Mode Frequencies for Analysis Cases".

Attachment 4 provides the Response to Clarification RAls 2, 7.b, and 7.d.

This letter contains no new commitments. If you have any questions or require additional information, please contact Jeffery A. Seiter at 601-437-2344.

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

~

MP/jas Enclosure, Attachments and cc: (see next page)

GNRO-2012/00144 Page 2 of2

Enclosure:

1. Summary of Submittal Attachments: 1. Revised License Renewal ER Information to Reflect SAMA Reanalysis

2. Revised Reference 2 RAI Responses to Reflect SAMA Reanalysis

3. Release Mode Frequencies for Analysis Cases

4. Response to Clarification RAls 2, 7.b, and 7.d cc: with Enclosure and Attachments Mr. John P. Boska, Project Manager Plant Licensing Branch 1-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Mail Stop 0-8-C2 Washington, DC 20555 cc: without Enclosure and Attachments Mr. Elmo E. Collins, Jr.

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

Enclosure 1 to GNRO*2012/00144 Summary of Submittal to GNRO-2012/00144 Page 1 of 3 Summary of Submittal As described in the Reference 1 response to clarification RAI 2, investigation into the differences between the level 1 core damage frequency (CDF) and the level 2 CDF revealed that the '0 K' gate in the level 2 model was not fully developed as a means to quantify the intact sequences. To correct the analysis, the Severe Accident Mitigation Alternatives (SAMAs) were reanalyzed using the level 1 CDF as the reference value. In this reanalysis, the impact of each SAMA on the level 1 CDF was used to quantify the impact on the intact release category. (As described below, the new SAMA reference CDF of 2.93E-06/rx-yr was calculated using a revised level 2 rule file.)

The SAMA reanalysis used two alternate inputs described below which were the subject of sensitivity analyses for previous RAI responses. Using the alternate inputs within the reanalysis precludes the need for additional sensitivity analyses to address the RAI concerns.

1. The source term from Modular Accident Analysis Program (MAAP) case GG10500, which was used for the high early (HIE) release category in the sensitivity analysis described in response to RAI 2.d, was used in the reanalysis of the SAMAs. See response to RAI 2.d in Reference 2 and response to clarification RAI # 4 in Reference 1.

2. The NCF (no containment failure) release category, using the source term from MAAP case GG10502D as described in response to RA12.g, was used in the reanalysis of the SAMAs. See response to RAI 2.g in Reference 2 and response to clarification RAI # 5 in Reference 1.

Also, in the SAMA reanalysis, a revised level 2 recovery rule file was used in the quantification of both the total CDF and the individual release mode frequencies. The rule file was revised to address discrepancies (described below) identified during investigation into the C DF value differences. The discrepancies were corrected and an independent review was performed to ensure the recoveries are being appli ed as intended.

The following level 2 rule file discrepancies were addressed in the revised recovery rule file.

1. Event NRS-DHLRT was changed from 1E-7 to 1E-6. In the level 2 rule file, this combination recovery event, representing fail ure to initiate suppression pool cooling and failure to initiate containment spray, did not meet the minimum of 1E-6 established for combination events. The probability for this event is correct in the level 1 rule file.

2. The level 2 loss of offsite power (LOSP) rule applied to loss of coolant accident (LOCA) sequences caused by a stuck open relief valve (recovery event NRC-OSP-PSGO-L2) was changed to align wit h the other level 2 LOSP rules. Two lines of code are required to apply each level 2 LOSP rule to ensure proper application, but the second line had been inadvert ently omitted for the NRC-OSP-PSGO-L2 rule.

3. The level 2 LOSP recovery values were adjusted to remove double-counting of the time from the start of the accident until core damage. Since the cutsets to which a level 2 LOSP recovery is applied already have a level 1 LOSP recovery applied, and the level 1 recovery is calculated from time 0 to the time of core damage, the level 2 recovery should only reflect the time from core damage unti I containment failure.

However, the level 2 LOSP recovery values were calculated from time 0 to the time to GNRO-2012/00144 Page 2 of 3 of containment failure. Thus, new level 2 LOSP recovery values were calculated by dividing the previously-calculated level 2 LOSP value by the level 1 LOSP value.

The new SAMA reference CDF (2.93E-06/rx-yr) was calculated using the level 2 rule file and is slightly higher than the total CDF calculated in the level 1 analysis (2.91 E-06/rx-yr). This slight difference is attributed to the minimal cutset upper bound technique of cutset quantific ation, particularly involving terms that are close to 1. Since the release category frequencies are calculated using the level 2 rule file, and the NCF category frequency is calculated as the difference between the reference CDF and the sum of the release category frequencies, it is appropriate to calculate the reference CDF using the level 2 rule file.

With the revised benefit estimates, additional SAMAs initially appeared to be cos t-beneficial, but were determined not to be cost-beneficial by further analysis as described below.

Analysis case 5 was used to evaluate the change in plant risk from improving the 4.16 kV bus cross-tie ability for SAMA 6, "Improve 4.16-kV bus cross-tie ability," and SAMA 17, "Provide alternate feeds to essential loads directly from an alternate emergency bus." In the original analysis, a bounding analysis was performed for case 5 by eliminating the loss of all three of the 4.16-kV buses (15M, 16AB and 17AC) in the model. In the SAMA reanalysis, some of the conservatism was removed by changing this analysis case to eliminate only failure of the bus with the highest impact. Loss of each of the 4.16-kV buses was removed individually from the model and bus 16A B produced the most conservative result. This analysis case is still bounding because improving the cross-tie feed to a bus would not eliminate all risk from failure of that bus.

Also, the revised analysis case more closely aligns with the im plementation cost estimate of $656,000 for SAMAs 6 and 17. This estimate comes from the Susquehanna SAMA analysis. As described in the Susquehanna SAMA analysis, the implementation cost estimate is for providing a mechanism to bypass the interlocks such that new procedures would allow the operators to cross-tie buses which share a common emergency safeguards transformer, but is not intended to reflect the cost of a modification to allow any em ergency bus to power any other emergency bus.

GGNS plant-specific implementation cost estimates were prepared for several SAMAs which had originally used the minimum hardware modification estimate of $100,000.

Specifically,

~ SAMA 1, "Provide Additional DC Battery Capacity," was estimated to cost

$2,130,887 to implement.

~ SAMA 2, "Replace Lead Acid Batteries with Fuel Cells," was estimated to cost

$4,079,609 to implement.

~ SAMA 9, "Use fire water system as backup source for diesel cooling," was estimated to cost $1,344,116 to im plement.

~ SAMA 11, "Provide a portable generator to supply DC power to the battery chargers during a station blackout," was estimated to cost $1,278,211 to implement.

~ SAMA 12, "Provide a portable generator to supply DC power to individual panels during a station blackout" was determined to not be feasibl e. The size of the generator, the ability to connect to the pane I, and air quality issues inside the plant were prohibitive. However, since SAMA 11 and SAMA 12 both involve portable generators, the SAMA 11 implementation cost estimate was used for SAMA 12 in the cost-benefit com parison.

to GNRO-2012/00144 Page 3 of 3

~ SAMA 14, "Provide a portable EDG fuel oil transfer pump," was estimated to cost

$1,477,188 to implement.

~ SAMA 32, "Diverse EDG HVAC logic," was estimated to cost $1,148,275 to implement.

~ SAMA 63, "Add a redundant RCIC lube oil cooling path," was estimated to cost

$1,803,463 to implement.

Thus, no additional SAMAs were found to be potentially cost-beneficial in the SAMA reanalysis.

The list of three potentially cost-beneficial SAMAs provided in Section 4.21 of the license renewal environmental report (ER), augmented by the addition of one potentially cost-beneficial SAMA in response to RAI 8.a in Reference 2, remains unchanged by the SAMA reanalysis. to thi s letter provides revised versions of the ER information changed by the reanalysis. provides revised versions of the RAI responses provided in Reference 2 changed by the reanalysis. In these attachments, strike-through is used to designate deleted text and underline is used to designate added text. provides a new table of "Release Mode Frequencies for Analysis Cases". This table replaces the same table provided in Attachment 3 of Reference 1 in its entirety. Deleted and added information is not marked in this attachment. provides revised responses from Reference 1 to clarification RAls 2, 7.b, and 7.d which were incomplete. In Attachment 4, strike-through is used to designate deleted text and underline is used to designate added text.

Attachment 1 to GNRO*2012/00144 Revised License Renewal ER Information to Reflect SAMA Reanalysis Note: Only those pages from the Environmental Report (ER) that have changed are included.

Grand Gulf Nuclear Station Page 1 of 83 Applicant's Environmental Report Operating License Renewal Stage Events (IPEEE) for Severe Accident Vulnerabilities, June 1991. A number of plant improvements were identified as described in NUREG-1742, Perspectives Gained from the IPEEE Program, Final Report, April 2002. These improvements were implemented.

The GGNS fire analysis was performed using the EPRI Fire Induced Vulnerability Evaluation (FIVE) method for qualitative and quantitative screening of fire areas.

Unscreened fire zones were then analyzed in more detail using a fire Probabilistic Risk Assessment (PRA) approach. The FIVE method is primarily a screening approach used to identify plant vulnerabilities due to fire initiating events. The end result of GGNS IPEEE fire analysis identified the CDF for significant fire areas. Following this analysis, a number of administrative procedures were revised to improve combustible and flammable material control.

The NRC SER for the IPEEE also lists five potential plant modifications related to external flooding events that were not implemented based on the low probability of external flooding. These modifications were considered "N/A" in the Phase I SAMA screening.

4.21.5.1.3 MACCS2 Model - Level 3 Analysis A Level 3 model was developed using the MACCS2 consequence analysis software code (Version 1.13.1) to estimate the hypothetical impacts of severe accidents on the surrounding environment and members of the public. The principal phenomena analyzed were atmospheric transport of radionuclides; mitigation actions (Le., evacuation, condemnation of contaminated crops and milk) based on dose projection; dose accumulation by a number of pathways, including food and water ingestion; and economic costs. Input for the Level 3 analysis included the core radionuclide inventory, source terms from the GGNS PSA model, site meteorological data, projected population distribution (within 50-mile radius) for the year 2044, emergency response evacuation modeling, and economic data. The MACCS2 input data are described in Section E.1.5 of Attachment E.

4.21.5.1.4 Evaluation of Baseline Severe Accident Consequences Using the Regulatory Analysis Technical Evaluation Handbook Method This section describes the method used to estimate the cost associated with each of the four impact areas for the baseline case (Le., without SAMA implementation). This analysis was used to establish the maximum benefit that a SAMA could achieve if it eliminated all risk due to GGNS at-power internal events.

Off-Site Exposure Costs The Level 3 baseline analysis resulted in an annual off-site exposure risk of 0.6090486 person-rem. This value was converted to its monetary equivalent (dollars) via application of the $2,000 per person-rem conversion factor from the Regulatory Analysis Technical Evaluation Handbook [USNRC 1997]. This monetary equivalent was then discounted to present value using the formula from the same source:

4-48 Grand Gulf Nuclear Station Page 2 of 83 Applicant's Environmental Report Operating License Renewal Stage where

=

APE monetary value of accident risk avoided from population doses, after discounting.

R =monetary equivalent of unit dose, ($/person-rem).

F =accident frequency (events/year).

Dp =population dose factor (person-rem/event).

S =status quo (current conditions).

A =after implementation of proposed action.

r =discount rate (%).

t =license renewal period (years).

f Using a 20-year period, a 7 percent discount rate, assuming FA is zero, and the baseline release frequency of 2.93~E-06/ryresulted in the monetary equivalent value of $13.11610,462. This value is presented in Table 4.21-1.

Off-Site Economic Costs The Level 3 baseline analysis resulted in an annual off-site economic risk monetary equivalent of $1 ,511244. This value was discounted in the same manner as the public health risks in accordance with the following equation:

where Aoe =monetary value of risk avoided from off-site property damage, after discounting.

Po =off-site property loss factor ($/event).

4-49 Grand Gulf Nuclear Station Page 3 of 83 Applicant's Environmental Report Operating License Renewal Stage F = accident frequency (events/year).

S = status quo (current conditions).

A = after implementation of proposed action.

r = discount rate (%).

tf = license renewal period (years).

Using previously defined values; the resulting monetary equivalent is

$16,26413,387. This value is presented in Table 4.21-1.

On-Site Exposure Costs The values for occupational exposure associated with severe accidents were not derived from the PSA model but from information in the Regulatory Analysis Technical Evaluation Handbook [USNRC 1997]. The values for occupational exposure consist of "immediate dose" and "long-term dose." The best-estimate value provided for immediate occupational dose is 3,300 person rem, and long-term occupational dose is 20,000 person-rem (over a 10-year clean-up period). The following equations were used to estimate monetary equivalents:

Immediate Dose where W 10 =monetary value of accident risk avoided from immediate doses, after discounting.

10 = immediate occupational dose.

R = monetary equivalent of unit dose ($/person-rem).

F = accident frequency (events/year).

0 10 =immediate occupational dose (person-rem/event).

S = status quo (current conditions).

4-50 Grand Gulf Nuclear Station Page 4 of 83 Applicant's Environmental Report Operating License Renewal Stage A = after implementation of proposed action.

r = discount rate (%).

tf = license renewal period (years).

The values used in the analysis were as follows:

R = $2,OOOfperson rem.

r =0.07.

0 10 =3,300 person rem faccident.

tf = 20 years.

For the basis discount rate, assuming FA is zero, the bounding monetary value of the immediate dose associated with GGNS' accident risk is 1 - e-rtf WIO = (PsDIOs)R - - -

r 1 - e -(O.07X20)

WIO = 3300 X Fs X $2000 0.07 WIO = ($7.10 X 10 7 ) X Fs

-6 For the baseline release frequency, ~2.93 x 10 fry, W/0 =$449-208 ------

Long- Term Dose where 4-51 Grand Gulf Nuclear Station Page 5 of 83 Applicant's Environmental Report Operating License Renewal Stage

-6 For the release frequency for the baseline, 2-:Q&2.93 x 1a fry, W

LTO

=$93&-907 --

Total Occupational Exposures Combining equations (1) and (2) above, using delta (~) to signify the difference in accident frequency resulting from the proposed actions, and using the above numerical values, the long-term accident-related on-site (occupational) exposure avoided is AOE = ~WIO + ~WLTO ($)

where AOE =on-site exposure avoided.

The bounding value for occupational exposure (ACEs) is AOEB = WIO + W LTO = $+/-4e208 + $~907 = $-78+/-1,115 The resulting monetary equivalent of $+i4-1.J.1Q..is presented in Table 4.21-1.

On-Site Economic Costs Clean-Up/Decontamination The total cost of clean-up/decontamination of a power reactor facility subsequent to a severe accident is estimated in the Regulatory Analysis Technical Evaluation 9

Handbook [USNRC 1997] to be $1.5 x 1a ; this same value was adopted for these analyses. Considering a 1a-year clean-up period, the present value of this cost is CCD) 1 - e -rm PVCD = ( m ( r )

where 4-53 Grand Gulf Nuclear Station Page 6 of 83 Applicant's Environmental Report Operating License Renewal Stage tf =license renewal period (years).

r =discount rate (%).

Based upon the values previously assumed:

9 U

RP PV

= [--E:..](1 r

- e-rtt)2 = $1.580.07 X 10 (1 - e-(0.07)20) 2

= $128.

x 1010 Total On-Site Property Damage Costs Combining the clean-up/decontamination and replacement power costs, using delta

(~F) to signify the difference in accident frequency resulting from the proposed actions, and using the above numerical values, the best-estimate value of averted occupational exposure can be expressed as AOSC = llF(UcD + URP ) = llF($1.16 X 10 10 + $1.28 X 10 10 )

AOSC = llF($2.24 X 10 10 )

Where

~F =difference in annual accident frequency resulting from the proposed action.

-6 For the baseline release frequency, ~2.93 x 10 fry, AOSC = $50,04371,500 The resulting monetary equivalent of $71 ,S005Q,Q43 is presented in Table 4.21-1.

4-56 Grand Gulf Nuclear Station Page 7 of 83 Applicant's Environmental Report Operating License Renewal Stage Table 4.21-1 Estimated Present Dollar Value Equivalent of Internal Events CDF at GGNS Parameter Present Dollar Value ($)

Off-site population dose $13, 116$1Q,49~

Off-site economic costs $16,264$13,387 On-site dose $1,115$+3+-

On-site economic costs $71,500$5Q,Q43 Total $101,995$74,&73 4.21.5.2 Identify SAMA Candidates Based on a review of industry documents, an initial list of SAMA candidates was identified. Since GGNS is a BWR, considerable attention was paid to the SAMA candidates from SAMA analyses for other BWR plants. Attachment E lists the specific documents from which SAMA candidates were initially gathered.

In addition to SAMA candidates from review of industry documents, additional SAMA candidates were obtained from plant-specific sources, such as the GGNS IPE and IPEEE. In the IPE and IPEEE, several enhancements related to severe accident insights were recommended. These enhancements were included in the comprehensive list of SAMA candidates and were verified to have been implemented during preliminary screening or were retained for evaluation (see Table E.2-1 of Attachment E).

In addition, the current GGNS PSA Levels 1 and 2 models were also used to identify plant-specific modifications for inclusion in the comprehensive list of SAMA candidates. The risk-significant events from the PSA Level 1 and Level 2 models were reviewed for similar failure modes and effects that could be addressed through a potential enhancement to the plant. The correlation between candidate SAMAs and the risk significant events are listed in Tables E.1-2 and E.1-4 of Attachment E. The comprehensive list contained a total of 249 SAMA candidates.

The first step in the analysis of these candidates was to eliminate the non-viable SAMA candidates through preliminary screening.

4.21.5.3 Preliminary Screening (Phase I)

The purpose of the preliminary SAMA screening was to eliminate from further consideration enhancements that were not viable for implementation at GGNS. Potential SAMA candidates were screened out if they modified features not applicable to GGNS or if they had already been implemented at GGNS. In addition, where it was determined those SAMA candidates were potentially viable, but similar in nature, they were combined to develop a more comprehensive or plant-specific SAMA candidate.

4-57

Attachment 1 Grand Gulf Nuclear Station Page 8 of 83 Applicant's Environmental Report Operating License Renewal Stage Table 4.21-2 Final SAMAs Internal and Phase Internal External II Result of and Benefit GGNS SAMA Potential COF POR OECR External with Cost 10 SAMA Title Enhancement Reduction Reduction Reduction Benefit Uncert. Estimate 39 Change Increased 17.8%~ 45.6%M#k 50.2°!c>~ $297,180 $891,540 $25,000 procedure to availability of $288,437 $865,312 cross-tie open containment heat cycle cooling removal.

system to enhance

-containment spray system.

Basis for

Conclusion:

Eliminate failure of cooled flow from RHR pump A and B. The implementation cost is a generic procedure modification range estimate.

42 Enhance Reduced risk of 4.40/011.3% 12.60/0~ 13.5%~ $76,972 $230,917 $200,000 procedures to core damage $107,899 $323,696 refill CST from during station demineralized blackouts or water or service LOCAs that render water system. the suppression pool unavailable as an injection source.

Basis for

Conclusion:

Eliminate the failure of high pressure core spray and reactor core isolation cooling suction. The implementation cost is a procedure with engineering and training range estimate.

4-64 Grand Gulf Nuclear Station Page 90f83 Applicant's Environmental Report Operating License Renewal Stage Table 4.21-2 (Continued)

Final SAMAs Internal and Internal External Phase II and Benefit GGNS SAMA Result of Potential COF POR OECR External with Cost 10 SAMA Title Enhancement Reduction Reduction Reduction Benefit Uncert. Estimate 59 Increase operator Increased time 4.5%~ 5.2%~ 5.5%U9k- $53,348 $160,043 $50,000 training for available for recovery $40,452 $121,357 alternating actions for low operation of the low pressure EGGS when pressure EGGS a loss of SSW occurs.

pumps (LPGI and LPGS) for loss of SSW scenarios.

Basis for

Conclusion:

Eliminate failure of the SSW to the LPGS room cooler. The implementation cost is a procedure with training range estimate.

4-65 Grand Gulf Nuclear Station Page 10 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.1-1 GGNS EPU Model CDF Results by Major Initiators Initiating Event Group Total IE Group Probability %CDF Large Loss of Coolant Accident

'LOCA) 9.70E-081.45e Q7 3.30%~

Feedwater Line Break Outside of Containment 2.76E-102.7ee 1Q O.OO%OJX)

Plant Service Water (PSW) Flooding Initiator 1.42E-091.QQe QQ O.OO%OJX)

Reactor Vessel Rupture 1.00E-081.QQe Q8 0.30%~

Intermediate LOCA 1.40E-082.Q3e Q8 0.50%4-:00 Small LOCA 3.19E-101.33e 11 O.OO%OJX)

Small-Small LOCA 6.97E-112.47i 11 O.OO%OJX)

Standby Service Water (SSW)

Flooding Initiator 1.74E-11e.55e 12 O.OO%OJX)

Loss of Off-Site Power Initiator 1.16E-062.87e Q7 39.50%44-00 Loss of 500 kV Power (Preferred) (1) 5.44E-105.12i 11 O.OO%OJX)

Loss of Power Conversion System

'PCS) Initiator 2.47E-072.31 e Q7 8.40%~

Closure of Main Steam Isolation Valves (MSIVs) (Initiator) 1.24E-078.81 e Q8 4.20%~

PCS Available Transient 5.91 E-07e.32e Q7 20.20%~

Loss of Condensate Feed Water Pumps 2.33E-072.2Qe Q7 8.00%+0:-70 Inadvertent Open Relief Valve 7.96E-09Q.78e QQ 0.30%~

Loss of Alternating Current (AC)

Division 1 Initiator 2.68E-081.7Qe Q8 0.90%Q.:.QQ Loss of AC Division 2 Initiator 6.20E-083.82e Q8 2.10%~

Loss of Turbine Cooling Water I/TBCW) 9.88E-098.QQe QQ 0.30%Q.A.Q Loss of Component Cooling Water InitiatinQ Event 1.13E-0ge.87e 1Q O.OO%OJX)

Loss of Control Rod Drive (CRD) 2.98E-092.2Qe QQ 0.10%Q.A.O Loss of Direct Current (DC) Division 1 Initiator 9.10E-102.22e 1Q O.OO%OJX)

Loss of DC Division 2 Initiator 6.22E-101.3QE 1Q O.OO%OJX)

Loss of Instrument Air 1.35E-071.3ee Q7 4.60%&:90 Loss of PSW Initiating Event 1.98E-091.5Qi QQ 0.10%Q.A.O E.1-3 Grand Gulf Nuclear Station Page 11 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.1-1 GGNS EPU Model CDF Results by Major Initiators Initiating Event Group Total IE Group Probability %CDF Loss of Service Transformer 11 8.25E-08Q.2Qe QS 2.80%4:W Loss of Service Transformer 21 1.23E-071.QQE Q7 4.20%&:3Q Interfacing System Loss of Coolant

~ccident (ISLOCA) in Shutdown Cooling Suoolv Header (Pen 14) 2.03E-102.Q3E 1Q O.OO%~

iTotal CDF 100.0%1 QQ.QQ 2.93E-062.0&& 06 irotal Anticipated Transient without = 4.40E O.15%QA.&

Scram (ATWS) (2) 3.QSE QQ trotal Station Blackout (SBO) (2) (TB) = 1.07E 36.65%~

7.51E Q7

1. Loss of all 500 kV lines (preferred offsite power), for which the 115 kV line IS stili available to power the Emergency Safety Feature (ESF) loads following manual realignment of the vital buses.

2. SSO and ATWS may occur following multiple initiators; thus their contributions to CDF are listed separately.

E.1-4 Grand Gulf Nuclear Station Page 12 of 83 Applicant's Environmental Report Operating License Renewal Stage The Large Early Release Frequency (LERF) is an indicator of containment performance from the Level 2 results because the magnitude and timing of these releases provide the greatest potential for early health effects to the public. The frequency calculated is approximately 1.0~E-7/ry.

LERF represents a fraction (-&:-44%) of all release end states. Table E.1-4 provides a correlation between the Level 2 RRW risk significant events (severe accident phenomenon, initiating events, component failures, and operator actions) down to 1.005 identified from the GGNS Probabilistic Risk Assessment (PRA) LERF model and the SAMAs evaluated in Section E.2.

E.1-24 Grand Gulf Nuclear Station Page 13 of 83 Applicant's Environmental Report Operating License Renewal Stage Figure E.1-1 GGNS Radionuclide Release Category Summary Note: See Tables E.1-5 and E.1-6 for a definition of the release categories.

E.1-38 Grand Gulf Nuclear Station Page 14 of 83 Applicant's Environmental Report Operating License Renewal Stage lilA" 1,OOE*08* 0% lV, 4,44£*09, 0%,

V, Ifr~ L12!HJ8., 1%

9,oiE\10, lE:~~ _ _-----~

~

I, !lA. ,2,45E"01, 8:1{;'

Figure E.1-2 Summary of GGNS Core Damage Accident Sequences Plant Damage States Note: Core Damage Accident Sequences Plant Damage State definitions can be seen in Table E.1-7.

E.1-39

Attachment 1 Grand Gulf Nudear Station Page 15 of83 Applicant's Environmental Report Operating License Renewal Stage Table E.1- 4 Correlation of Level II Risk Significant Terms to Evaluated SAMAs (Based on Large Early Release Frequency)

Event Name Probability RRW Event Description Disposition a21-LF-FGCTISO 1.00E+00 1.01 OQ4.;OO lContainment isolation [This term is a flag. No SAMAs need to be aligned.

~ lSignal present

~X2-PH-CZF-NOTSU ~.46E-01 1.0530~ lContainment success Irhis term is a split fraction. No SAMAs need to be aligned.

~ Iduring severe phenomena(CZ=F,CL II)

!CX2-PH-CZS-NOTSU ~.82E-01 1.02004-:-G-i lContainment success Irhis term is a split fraction. No SAMAs need to be aligned.

~ Iduring severe phenomena (CZ=S, CL II)

!CX--PH-CTCOND-F- ~.00E-01 15.468~ Probability cont. fails rrhis term represents a failure to control hydrogen or hydrogen

~ ~iven H2 late ignition gnition. Phase II SAMAs 44 and 45 for reducing the hydrogen Idetonation potential were evaluated.

~X-PH-H2-DEFGF- 1.00E+00 7.8700+:+1- Hydrogen deflagration Irhis term represents a failure to control hydrogen or hydrogen ae pccurs globally *gnition. Phase II SAMAs 44 and 45 for reducing the hydrogen aetonation potential were evaluated.

/eX-PH-H2INVENF- 1.00E+00 7.8700+:+1- Sufficient hydrogen This term represents a failure to control hydrogen or hydrogen ae ~enerated to cause gnition. Phase II SAMAs 44 and 45 for reducing the hydrogen pverpressure detonation potential were evaluated.

CX-PH-LOOP-30MIN 8.00E-01 1.63704-:-79 ~C power not recovered This term represents a failure to recover offsite power. Phase II

~ 'n 30 min SAMAs 1, 2, 3, 11, 12 and 15 for extending available recovery ime by improving DC power were evaluated.

E.1-40

Attachment 1 Grand Gulf Nudear Station Page 16 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.1- 4 Correlation of Level II Risk Significant Terms to Evaluated SAMAs (Based on Large Early Release Frequency)

Event Name Probability RRW Event Description Disposition CX-PH-STEAM-F- ~.00E-01 [7.8700~ Containment not inerted Irhis term represents a failure to control hydrogen or hydrogen

~ by steam *gnition. Phase II SAMAs 44 and 45 for reducing the hydrogen

~etonation potential were evaluated.

~Z2-PH-10-NOTSU ~.60E-01 1.0290~ Orywell does not fail dUE Irhis term is a split fraction. No SAMAs need to be aligned.

~ ~o severe phenomena (IGA=F, CLS 10)

~Z4-PH-IGF-NOTSU ~.08E-01 1.00804-:-00 Orywell does not fail dUE Irhis term is a split fraction. No SAMAs need to be aligned.

~ Ito severe phenomena (IGA=F)

ICZ5-PH-IBE-NOTSU ~.13E-01 1.0780~ Orywell does not fail dUE rrhis term is a split fraction. No SAMAs need to be aligned.

~ o severe phenomena (CLASS IBE)

~Z-PH-2-NOTSU ~.87E-01 1.021 Q4.;.Q4 Orywell does not fail dUE IThis term is a split fraction. No SAMAs need to be aligned.

rp. ~o severe phenomena (CLASS II)

~Z-PH-CROMEL TF- 1.00E+00 1.09004-:40 ~ontrol rods melt prior to Irhis term represents a possible reactivity excursion due to control

~ ~el rods rods melting before the fuel rods. Phase II SAMAs 20, 21, 22, and

~8 for improving high pressure injection capability were

~valuated.

E.1-41

Attachment 1 Grand Gulf Nuclear Station Page 17 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.1- 4 Correlation of Level II Risk Significant Terms to Evaluated SAMAs (Based on Large Early Release Frequency)

Event Name Probability RRW Event Description Disposition CZ--PH-DWFAIL-F- ~.00E-01 5.3980&:-37 ~onditional probability rrhis term represents a failure to control hydrogen or hydrogen Q3 ~rywell fails given gnition. Phase II SAMAs 44 and 45 for reducing the hydrogen

~eflagration ~etonation potential were evaluated.

CZ--PH-FUELRODF- 1.00E-02 1.0900.:kW Fuel rod integrity is rrhis term represents timely restoration of emergency core cooling

~ maintined during the IlO arrest the core melt progression in-vessel. Phase II SAMAs reflood ~O, 21,22, and 28 for improving high pressure injection capability

~ere evaluated.

~Z-PH-SLCLWL-F- 1.00E+00 1.0900.:kW Failure to inject SLC rrhis term represents a failure of a human action to inject SLC with

~ With boron for low water ~oron for low water level. Phase II SAMAs 20 and 52 for evel 'mproving high pressure injection and SLC capability were

~valuated.

E12-FO-HECS-N 1.00E+00 1.0720~ Operator fails to actuate rrhis term represents a failure of a human action to actuate P containment spray ~ontainment spray. Phase II SAMAs 46,47, and 60 for improving

~ontainment vent capability were evaluated.

E12-FO-HEECCS-G 1.00E+00 1.00604-:-00 Operator fails to initiate Irhis term represents a failure of a human action to initiate low 93 LP ECCS pressure ECCS. Phase II SAMAs 20,21,22, and 28 for improving

~igh pressure injection capability were evaluated.

l:12-FO-HESPC-M 1.00E+00 1.072~ Operator fails to rrhis term represents a failure of a human action to manually align G4- manually align for Jor suppression pool cooling. Phase II SAMAs 46 and 47 for

~uppression pool "mproving containment vent capability were evaluated.

~ooling E.1-42

Attachment 1 Grand Gulf Nuclear Station Page 18 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.1- 4 Correlation of Level II Risk Significant Terms to Evaluated SAMAs (Based on Large Early Release Frequency)

Event Name Probability RRW Event Description Disposition l:61-FO-H2-GB-X 1.00E+00 1.00804-:-00 Failure to obtain grab IThis term represents a failure of a human action obtain grab 74 ~ample in SAPs ~ample in SAPs. Phase II SAMAs 44 and 45 for installing a passive hydrogen control system were evaluated.

E61-FO-IG-L1-X 1.00E+00 1.3170~ Failure to initiate igniters IThis term represents a failure of a human action to initiate igniters

~ ~efore transition to SAP ~efore transition to SAP. Phase II SAMAs 44 and 45 for installing

~ passive hydrogen control system were evaluated.

E61-FO-MSH13-X 1.00E+00 1.3040~ pperator fails to IThis term represents a failure of a human action to energize the

~ ~nergize hydrogen ~ydrogen igniters. Phase II SAMAs 44 and 45 for installing a igniters passive hydrogen control system were evaluated.

EV 1.00E+00 1.1520-1-:Gi Early declaration of This term is a flag to represent an early declaration of a general

~ general emergency emergency. No SAMAs need to be aligned.

G-IGNITION ~.38E-01 1.93704-:+4 Ignition source available This term represents a failure to control hydrogen or hydrogen

~ at the incorrect time "gnition. Phase II SAMAs 44 and 45 for reducing the hydrogen detonation potential were evaluated.

HI-PH-H2IGSBOF- 2.50E-01 1.63704-:+9 Random hydrogen IThis term represents a failure to control hydrogen or hydrogen 8e 'gnition given no AC *gnition. Phase II SAMAs 44 and 45 for reducing the hydrogen power ~etonation potential were evaluated.

IGA-PH-ID1-NOTSU 4.97E-01 1.0210+:@ Igniters successful IThis term is "a split fraction. No SAMAs need to be aligned.

~ :{CLASS ID)

IGNITERS-FAIL 1.00E+00 1.07404-:-08 Igniters are operating ifhis term is a flag. No SAMAs need to be aligned.

23 E.1-43

Attachment 1 Grand Gulf Nuclear Station Page 19 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.1- 4 Correlation of Level II Risk Significant Terms to Evaluated SAMAs (Based on Large Early Release Frequency)

Event Name Probability RRW Event Description Disposition IGNITERS-SUC 1.00E+00 1.036Q4.:.Q3 Ingiters are operating IThis term is a flag. No SAMAs need to be aligned.

~

M41-FO-AWCNT-Q 1.00E+00 1.06004-:-00 K:>perator fails to vent Irhis term represents a failure of a human action to vent 93 ~ontainment ~ontainment. Phase II SAMA 46 for a passive containment vent

~as evaluated.

NRC-L2-DEPB&IG ~.38E-05 1.00504-:-00 Failure to connect ADS IThis term represents a failure of a human action to emergency a9 bottles and initiate H2 k:Jepressurize, igniter initiation in level 1, and igniter initiation in gniters evel 2. Phase II SAMAs 44 and 45 for installing a passive hydrogen control system were evaluated.

NRC-OSP-DSG3 ~U7E-02 1.00504-:-M Fail to recover OSP IThis term represents a failure to recover offsite power. Phase II 53 given U2

3 FTR

No SAMAs 1, 2, 3, 11, 12 and 15 for extending available recovery SSW PHV failures ime by improving DC power were evaluated.

NR5-ALTPW&DEP 1.00E-06 1.00504-:-00 Failure to align alternate This term represents a failure of a human action to align alternate

~ power and depressurize power and depressurize. Phase II SAMAs 1, 2, 3, 11, 12, and 15 for extending available recovery time by improving DC power were evaluated.

~R5-DHRLT 1.00E-Q706 1.06704-:-00 Failure to initiate SPC This term represents a failure of a human action to initiate SPC 93 ~nd containment spray and containment spray. Phase II SAMA 60 for improved containment heat removal were evaluated.

E.1-44

Attachment 1 Grand Gulf Nudear Station Page 20 of83 Applicant's Environmental Report Operating License Renewal Stage Table E.1- 4 Correlation of Level II Risk Significant Terms to Evaluated SAMAs (Based on Large Early Release Frequency)

Event Name Probability RRW Event Description Disposition NRS-L2-DEP&IG 8.32E-06 1.07204-:-07 Failure to depressurize ((his term represents the operator to fail the following initiation:

f1e and start H2 igniters Emergency depressurization, igniter initiation in level 1, and gniter initiation in level 2. Phase II SAMAs 44 and 45 for nstalling a passive hydrogen control system were evaluated.

NRS-L2-DEP&IG&FW ~.53E-06 1.0680~ Failure to depressurize rrhis term represents the operator to fail the following initiation:

69 and start H2 igniters and Emergency depressurization, igniter initiation in level 1, igniter restart FW pumps nitiation in level 2, and failure to restart FW. Phase II SAMAs 44 and 45 for installing a passive hydrogen control system were evaluated.

NRS-L2-DEP&IG&PCS 1.43E-06 1.02504-:@ Failure to depressurize This term represents the operator to fail the following initiation:

43 ~nd start H2 igniters and Emergency depressurization, igniter initiation in level 1, igniter

~Iign PCS nitiation in level 2, and align PCS. Phase II SAMAs 44 and 45 lor installing a passive hydrogen control system were evaluated.

PP--AD-ALTRNT-F- 1.00E+00 1.05904-:09 ~Iternate depress. This is a term to flag not crediting several primary system

+:I- methods not credited depressurization schemes. No SAMAs need to be aligned.

OP-OP-DEPRESSH- 9.68E-01 1.0550~ PP fails to depress This term represents a failure of a human action to depressurize

~ given OP failed in LVL1 given that the operator failed in the level 1 model or a loss of DC.

or loss of DC Phase II SAMAs 1, 2, 3, 11, 12, and 15 for extending available ecovery time by improving DC power were evaluated.

PP-PH-OP1-NOTSU [7.11 E-01 1.13604-:4-3 Successful RPV This term is a split fraction. No SAMAs need to be aligned.

~ depressurization (Class lA, IE)

E.1-45

Attachment 1 Grand Gulf Nuclear Station Page 21 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.1- 4 Correlation of Level II Risk Significant Terms to Evaluated SAMAs (Based on Large Early Release Frequency)

Event Name Probability RRW Event Description Disposition PP--PH-OP6-NOTSU 9.75E-01 1.151 0-1-:-03 Successful RPV This term is a split fraction. No SAMAs need to be aligned.

(>> depressurization (Class II)

OP-PH-PRESBK-F- a.00E-01 1.0590~ Pressure transient does This term represents a high pressure vessel breach scenario

~ not fail mechanical where mechanical stress failures of the primary system pressure

~ystems boundary failed to depressurize the RPV. There are no applicable SAMAs for this scenario.

PP--PH-SORV--F- ~.50E-01 1.0590~ ~RVs do not fail open This term represents a high pressure vessel breach scenario

~ ~uring core melt where the SRVs failed to stick open and allow depressurization.

progression There are no applicable SAMAs for this scenario.

OP-PH-TEMPBK-F- 7.00E-01 1.0590~ High prim sys temp does rrhis term represents a high pressure vessel breach scenario

++ not cause fail of RCS ~ere the RPV pressure boundary did not rupture due to high press. bound 'nternal RPV pressure and temperature. There are no applicable

~AMAs for this scenario.

P41-CF-MV-DGIN-R 1.85E-04 1.00604-:00 CCF of DG inlet isol rrhis term represents a failure EDG cooling water due to isolation 9& MOVs F018A-A AND ~alve failures on the EDG. Phase II SAMAs 5,8,9, and 10 for F018B-B to open ~dding an additional generator and increasing the reliability of

~DG cooling water were evaluated.

P64-PH-RX-EXO-F- 1.00E+00 1.2580~ FPS (Paths 1-8) Irhis term is a flag. No SAMAs need to be aligned.

~ inadequate for 1000gpm

~or Rx node I07C-f"E:' n~o 7

.... I",

A'l~ n'l

'" n",nA ~"I:' ~&

1- -

I..........

n:**

n*, ....

0 n:.. ") 111

- * - \ .....

' l \ I::nr"~ 40.............

Thi ... 40~._

1IC'l\a"I\~J:: 0

.... 1""._...-

n ... n

"" f""i1 ...........& 40&.. ....

... ")~ ............ A&..... *

~

1\" ..................

. - 1""-

~n,..

'1"" _ . ';:' - - -

D&..~., ..,.....

* * * ~_~:40~ ......... ,..~ * .,.~ ** .,.~.,. ** ,~.~ ~ ** ~I" ..... 40........

'>;1 , .................- 1""'" ** _ ..........' ...- - .....' -

E.1-46

Attachment 1 Grand Gulf Nuclear Station Page 22 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.1- 4 Correlation of Level II Risk Significant Terms to Evaluated SAMAs (Based on Large Early Release Frequency)

Event Name Probability RRW Event Description Disposition RP-OP-L2-CROOH- 1.00E+00 1.0900~ pperator restores [This term represents a failure of a human action to restore coolant

~ ~oolant injec. after ctrl njection after the control rods are melted. Phase II SAMAs 20,21, rods are melted ~2, and 28 for improving high pressure injection capability were

~valuated.

RXF 1.00E+00 1.1560~ Failure of RX (OP=F or Irhis is a flag indicating that the RPV is at high pressure with low 44- ~Iasses IBE, II, 11I0, and pressure injection systems not available or viable. No SAMAs IV) need to be aligned.

RX--PH-RX20NOTSU 1.09E-01 1.0170~ K:;ore melt arrested Irhis term is a split fraction. No SAMAs need to be aligned.

~ *n-vessel (OP=S, Class 10)

~-RX-FRECINJH- ~.00E-01 1.2580~ Operator fails to recover This term represents a failure of a human action to recover

~ injection before RPV .njection before the RPV melt. Phase II SAMAs 20, 21, 22, and melt 28 for improving high pressure injection capability were evaluated.

~P-PH-BKFLOW-F- 1.00E-01 1.03604-:-Q3 No backflow if SPMU This term represents a suppression pool bypass after a core mel1

~ Fails and vessel breach. Phase II SAMA 43 for installing a filtered ven1 was evaluated.

SP-PH-BKIGA-F- 1.00E+00 1.0740~ No backflow if SPMU This term represents a suppression pool bypass after a core mel1 29 ~ails and vessel breach. Phase II SAMA 43 for installing a filtered ven1 was evaluated.

~P--VB-SEALS-F- 1.00E-02 1.0200~ rremperature induced This term represents a suppression pool bypass after a core mel1

~ ~ailure of all vacuum ~nd vessel breach. Phase II SAMA 43 for installing a filtered ven1 breaker seals was evaluated.

E.1-47

Attachment 1 Grand Gulf Nuclear Station Page 23 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.1- 4 Correlation of Level II Risk Significant Terms to Evaluated SAMAs (Based on Large Early Release Frequency)

Event Name Probability RRW Event Description Disposition

~P-VB-SEALSNWF- ~.00E-02 1.021~ Temp induced failure of This term represents a suppression pool bypass after a core mel1

~ all vacuum breaker and vessel breach. Phase II SAMA 43 for installing a filtered ven1

~eals (RX=F, SI=F) was evaluated.

WVV-VVW-L2-FAIL- 1.00E-02 1.022 Q4.:.Q..1. Containment breach IThis term is a split fraction. No SAMAs need to be aligned.

~ below the wtr line (Class I, IIA, liT, III, IV)

WVV-VVW-L2-NOT-- ~.90E-01 1.3150~ Containment breach This term is a split fraction. No SAMAs need to be aligned.

~ above the wtr line (Class I, IIA, liT, III, IV)

~OND-LERF 1.00E+00 1.0050 Conditional LERF Irhis term reoresents the conditional LERF orobabilitv durina a class V seauence. Phase II SAMAs 48 50 and 51 to reduce the ISLOCA freauencv were evaluated.

CZ--PH-EX-OPS-F- 5.00E-01 1.0050 WATER PRESENT IN Ex-vessel steam exolosions are oossible contributors to drvwell tTHE PEDESTAL AT failure due to the oedestal water accumulation orior to vessel RPVBREACH breach. This term reoresents the orobabilitv that water is oresent n the oedestal at RPV breach. Phase II SAMAs 20 21. 22 and 28 Jor imorovina or addina hiah oressure iniection were evaluated.

CZ-PH-EXVSLSTF- 1.00E-02 1.0050 EX-VESSEL STEAM Fx-vessel steam exolosions are oossible contributors to drvwell EXPLOSION FAILS OW ailure due to the oedestal water accumulation orior to vessel Dreach. This term reoresents the orobabilitv that an ex-vessel steam exolosion fails the drvwell when oedestal water accumulation occurs orior to vessel breach. Phase II SAMAs 20 121 22 and 28 for imorovina or addina hiah oressure iniection were evaluated.

NRC-DGCF4&FW 4.02E-01 1.0090 Failure to Recover DG This term reoresents a failure of a human action to recover DG

~CF or start FW in 4 hardware failure or start FW in 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . Phase II SAMAs 5 and 8 b2Yr§ o install an additional diesel or aas turbine aenerator were evaluated.

E.1-48

Attachment 1 Grand Gulf Nuclear Station Page 24 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.1- 4 Correlation of Level II Risk Significant Terms to Evaluated SAMAs (Based on Large Early Release Frequency)

Event Name Probability RRW Event Description Disposition P53-FO-HEREINF-T 1.00E+00 1.0100 OPERATOR FAILS TO IThis term reoresents the ooerator failina to re-initiate instrument REINITIATE IA AS PER air to air ooerated valve F001 which suoolies air to aroup 2 PROCEDURE W--omoonents. Phase II SAMAs 34 and 35 for imorovina instrument air reliabilitv were evaluated.

1R21-FO-HEBOPTRM 1.00E+00 1.0060 K>PERATOR FAILS TO Irhis term reoresents ooerator failure to alian alternate power to IALiGN ALTERNATE he BOP buses. This event onlv shows uo in the LERF cutsets POWER TO BOP With initiators %TST11 and %TST21. Phase II SAMA 18 for BUSSES brotectina transformers was evaluated.

Note: Basic events that are correlated in Table E.1-2 are not listed again in Table E.1-4 if they are equivalent basic events.

E.1-49 Grand Gulf Nuclear Station Page 25 of83 Applicant's Environmental Report Operating License Renewal Stage Table E.1-7 Summary of GGNS Core Damage Accident Sequences Plant Damage States Accident Class Subclass Definition CAFTA Designator Model (per Rx Yr)

Class 1 A Accident sequences involving loss of inventory makeup in which the reactor pressure remains 1.12E-06 high.

B =

Accident sequences involving a station blackout and loss of coolant inventory makeup. (Class IBE 9.60E-07

=

IBE is defined as "Early" Station Blackout events with core damage at less than 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . Class IBL 8.57E-OOIDI:: -

IBL is defined as "Late" Station Blackout events with core damage at greater than 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .) 9.71e Q7 186 S.2Qe QS C ~ccident sequences involving a loss of coolant inventory induced by an ATWS sequence with < 1E-12

~ontainment intact.

D ~ccident sequences involving a loss of coolant inventory makeup in which reactor pressure has 3.19E-073.17e Q7

~een successfully reduced to 200 psi.

E ~ccident sequences involving loss of inventory makeup in which the reactor pressure remains (Grouped with Class high and DC power is unavailable. (Grouped with Class IA.) IA)

Class II A Accident sequences involving a loss of containment heat removal with the RPV initially intact; 2.45E-072.44e Q7 core damage; core damage induced post containment failure.

L Accident sequences involving a loss of containment heat removal with the RPV breached but 9.67E-109.S4e 1Q no initial core damage; core damage induced post containment failure.

T Accident sequences involving a loss of containment heat removal with the RPV initially intact; 1.12E-081.37e QS core damage induced post high containment pressure.

V ~Iass IIA and liT except that the vent operates as designed; loss of makeup occurs at some < 1E-12 ime following vent initiation. Suppression pool saturated but intact.

E.1-52 of GNRO-2012/0144 Grand Gulf Nuclear Station Applicant's Environmental Report Page 26 of 83 Operating License Renewal Stage Table E.1-7 Summary of GGNS Core Damage Accident Sequences Plant Damage States Accident Class Subclass Definition CAFTA Designator Model (per Rx Yr)

Class III (LOCA) A ~ccident sequences leading to core damage conditions initiated by vessel rupture where the 1.00E-08

~ontainment integrity is not breached in the initial time phase of the accident.

B ~ccident sequences initiated or resulting in small or medium LOCAs for which the reactor 6.39E-11

~nnot be depressurized prior to core damage occurring.

C ~ccident sequences initiated or resulting in medium or large LOCAs for which the reactor is at 1.67E-071.eQe Q7 ow pressure and no effective injection is available.

D Accident sequences which are initiated by a LOCA or RPV failure and for which the vapor < 1E-12 suppression system is inadequate, challenging the containment integrity with subsequent ailure of makeup systems.

Class IV (ATWS) A Accident sequences involving failure of adequate shutdown reactivity with the RPV initially 4.44E-094.Qee QQ "ntact; core damage induced post containment failure.

L Accident sequences involving a failure of adequate shutdown reactivity with the RPV initially (Grouped with Class breached (e.g., LOCA or stuck-open relief valve (SORV>>; core damage induced post IVA)

~ontainment failure.

Class V -- ~nisolated LOCA outside containment. 4.93E-104.Q1e 1Q

!Total CDF 2.93E-D62.82E 0&

. Ie to~ soll:Jtlon

. CDF in Table E.~ ~ . .mal ClJtsets CFeat e 9 utRen Note: lRe total C OF is note tRe same as tRe baseline slAfiI level. 9lJe to non mlAl

~l:Jantifyinfil at tRe 6e~l:JenC E.1-53 Grand Gulf Nuclear Station Page 27 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.1- 8 Summary of Containment Event Tree Quantification Release Category Release Frequency (MagnitudelTimina) (Per ry)

HIE 1.04E-071.Q5~ Q7 HII 1.21 E-081.23~ Q8 H/L 9.21 E-088.73~ Q8 M/E 3.70E-073A9~ Q7 Mil 1.81 E-071.73~ Q7 MIL 3.03E-072.71 ~ Q7 LIE 4.05E-094.Q4~ Qg Lli 3.55E-083.34~ Q8 LlL 4.44E-071.32~ Q7 LUE 2.19E-092.QQe Qg LUI 2.12E-092.11 ~ Qg LUL 7.05E-096.83~ Qg Negligible (NCF) 1.37E-068.73e Q7 CDF 2.93E-063.05& 0&

Nomenclature:

Timing (time between General Emergency Declaration and initial release):

Late (L) - Greater than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Intermediate (I) - 4.0 to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Early (E) - Less than 4.0 hours0 days 0 hours 0 weeks 0 months Magnitude:

Negligible (NCF) - Much less than 0.1 % Csi release fraction Low-Low (LL) - Less than 0.1 % Csi release fraction Low (L) - 0.1 % to 1% Csi release fraction Medium (M) - 1% to 10% Csi release fraction High (H) - Greater than 100k Csi release fraction E.1-55 Grand Gulf Nuclear Station Page 28 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.1- 9 GGNS Release Category Source Terms Sheet 1 of 2 Release Mode (CET Frequency Warning Time Elevation Release Start Release Release Energy End State) (/Year) (sec) (m) (sec) Duration (sec) (W)

HIE 1.04E-07~ 16560~ 7.5E+053-:0 aE-Q7 1264999 32 936004491- 03 &1-0+

HII 1.21E-0844 12 32 37707 221493 4.3E+05 3E-Q3 H/L 9.21 E-083:+ 992 32 112096 111104 9.1E+04 3E-Q3 MlE 3.70E-0734 957 32 59664 199536 2.9E+06 9E-O+

MIl 1.81 E-074-:-7 12 32 90866 168334 4.3E+05 3E-Q7 MIL 3.03E-07~ 992 32 116944 142256 9.1E+04 4E-07 UE 4.05E-094:-0 787 32 1279 4733 2.4E+06 4E-09 UI 3.55E-08&3 1264 32 1997 257203 4.3E+05 4E-Q3 UL 4.44E-07.:k3 966 32 107078 152122 8.3E+05

~

LUE 2.19E-0~ 1266 32 1996 257204 2.9E+06 QE-G9 LUI 2.12E-0~ 1265 32 1996 257204 4.3E+05 4-Q9 LUL 7.05E-0~ 1266 32 186290 72910 9.1E+04 3E-09 NCF 1.37E-06 1266 32 1996 257204 2.9E+06 E.1-57 Grand Gulf Nuclear Station Page 29 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.1-9 GGNS Release Category Source Terms Sheet 2 of 2 Release Mode (CET Release Fraction End State)

NG I Cs Te Sr Ru La Ce Ba HIE 1.0E+OQ..t.:G 1.8E-Ot~ 1.1 E-01&:4E 1.8E-01&:&E 4.2E-O~ 7.3E-07&:&E 2.3E-OZ~ 4.7E-06&:-QE 3.8E-O.§4-:9E

~ ~ -Q3 ~ -G4 -0& -0& -G4 -G4 HII 1.0E+OO 2.2E-01 7.6E-02 1.3E-01 9.8E-06 1.1E-05 5.4E-07 9.6E-06 1.0E-05 H/L 1.0E+OO 1.7E-01 4.7E-02 1.5E-01 5.9E-06 5.7E-07 6.7E-07 7.3E-06 3.6E-06 MlE 8.8E-01 1.8E-01 5.2E-02 1.1 E-01 1.5E-03 9.7E-04 1.4E-04 1.7E-03 1.2E-03 Mil 1.0E+OO 3.6E-02 1.5E-01 1.1E-01 3.6E-06 1.1E-05 2.6E-07 4.5E-06 9.9E-06 MIL 1.0E+OO 8.4E-02 5.0E-02 4.9E-02 2.2E-07 6.2E-07 1.6E-08 2.0E-07 1.3E-06 UE 9.1E-01 2.1E-03 2.1E-03 2.1E-03 1.2E-05 3.9E-04 2.6E-07 1.5E-06 6.4E-05 UI 1.0E+OO 8.3E-02 2.5E-02 6.9E-02 1.7E-04 4.2E-05 4.4E-06 1.3E-04 9.2E-05 UL 1.0E+OO 7.2E-03 4.5E-03 4.3E-02 4.4E-06 1.4E-06 5.0E-07 6.1E-06 4.8E-06 LUE 2.1E-02 5.3E-06 5.4E-07 1.9E-06 2.6E-09 2.3E-07 2.0E-10 1.1E-09 6.5E-08 LUI 1.9E-02 1.7E-06 2.6E-07 3.0E-06 1.6E-09 2.2E-07 1.2E-10 6.6E-10 4.7E-08 LUL 9.6E-01 1.0E-02 1.7E-02 1.0E-02 1.5E-06 1.8E-06 1.3E-07 1.2E-06 1.0E-06 NCF 2.1E-02 5.3E-06 5.4E-07 1.9E-06 2.6E-09 2.3E-07 2.0E-10 1.1E-09 6.5E-08 E.1-58 Grand Gulf Nuclear Station Page 30 of 83 Applicant's Environmental Report Operating License Renewal Stage Contribution to CDF Changes in PRA Models Contributing Initiator R1 R2 R3 R3EPU Group RPV Rupture not modeled not modeled 0.4% 0.3%

Loss of Service not modeled not modeled 6.5% 7.1%

Irransformer 1 ...

Special Initiators Include loss of AC bus, DC bus, service water, closed cooling water, or instrument air.

E.1.4.5 Level 2 Model Update As part of the License Renewal process, the SAMA was audited by the NRC and RAls were identified. One RAI identified the difference in values used for CDF between the L2 model and the SAMA analysis. In trying to resolve this question. a detailed review of the recovery rule file was completed. The details of the changes to the Level 2 recovery rule file can be seen in Engineering Report Number ECH-NE-12-00096 [E.1-19J.

E.1.4.i§ PSA Model Peer Review The 1997 (Rev. 1) Level 1 and LERF model was peer reviewed prior to the 2002 PRA Revision 2 using Boiling Water Reactor (BWR) Owners Group (BWROG) process. The review team used the "BWROG PSA Peer Review Certification Implementation Guidelines," Revision 3, January 1997. Facts and Observation sheets documented the certification teamls insights and potential I

level of significance. All of the IA priority PRA peer review comments have been addressed and incorporated into the GGNS PRA model as appropriate. All of the 'B' priority comments have been addressed except for one documentation item related to the internal flood modeling.

Following the Integration and Quantification Task of the Rev. 2 and Rev. 3 model updates, an expert panel of GGNS personnel met to review model quantification results (top 100 cutsets).

Various departments (Training, Operations, Engineering and Nuclear Safety) within the GGNS organization were invited to participate. Each ofthe top 100 cutsets was reviewed indiVidually. In addition, cutsets from accident sequences representing approximately 99 percent of the total core damage frequency were also reviewed if there were no cutsets from these sequences in the top 100. The focus of the review was to identify poor assumptions, over-simplifications, incorrect credit for human actions, sequence timing errors, system modeling errors, and incorrect event probabilities. The reviews resulted in modifications to the model and to the credit given for human actions.

As part of the EPU Level 2 PRA model development, an expert panel review of the preliminary cutsets was performed. The expert panel consisted of members of the Entergy PRA staff and the contractor staff who were developing the Level 2 portion of the PRA model. The purpose of this expert panel review was to provide an assessment of a preliminary Level 2 PRA model and its resulting cutsets. This feedback was then used to correct the model and ensure that the final model incorporated the lessons learned from the initial model development.

E.1-71 Grand Gulf Nuclear Station Page 31 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.1- 12 Estimated GGNS Core Inventory (Becquerels)1 Nuclide Inventory Nuclide Inventory Te-127 4.96E+17 Pu-241 8.44E+17 Te-127m 6.70E+16 Am-241 9.44E+14 Te-129 1.45E+18 Cm-242 2.50E+17 Te-129m 2.16E+17 Cm-244 1.58E+16 1

From GGNS specific data for a power level of 4408 MWth [E.1-2].

E.1.5.2.9 Source Terms Eleven release categories, corresponding to internal event sequences, were part of the MACCS2 input. Section E.1.2.2.6 provides details of the source terms for postulated internal events. A linear release rate was assumed between the time the release started and the time the release ended.

E.1.5.3 RESULTS Risk estimates for one base case and two sensitivity cases were analyzed with MACCS2.

Sensitivity Case 1 assumes an evacuation time delay that is increased from 3.25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months (base) to 6.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months . Sensitivity Case 2 assumes a lower average evacuation speed; the speed was reduced from 4.87 mls (base) to 2.435 m/s.

Table E.1-13 shows estimated base case mean risk values for each release mode. The estimated mean values of PDR and offsite DEeR for GGNS are G:489O.609 person-rem/yr and $1~1 .511/yr, respectively.

E.1-78 Grand Gulf Nuclear Station Page 32 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.1- 13 Base Case Mean PDR and OECR Values for Postulated Internal Events Characteristics of Population Dose Offsite Population Offsite Release Mode Economic Dose Risk Economic Cost (PDR) Cost Risk (OECR)

ID Frequency (person-sv) (1) person-rem ($) (person- $/yr (per year) rem/yr) (2)

1. 04E-0~&+3E- 6.02E+0~ 6.02E+0~ 1.61E+0~ 6.23E-02**3:eQ 1.67E+02~

H/EWb Q3 +03 .ga ....09 ~ -10M 1.21 E-Oo" .~5= 5.10E+0~ 5. 1OE+052-:29E 1.37E+09343E 6.17E-0~".A"= 1.66E+01~

H/IMte 0+ +03 .ga -1003 ~ -10M 9.21E-0~ 4. 12E+03&:4Qe 4. 12E+05&:-+Qe 1.04E+094-:J+E 3.80E-02~ 9.58E+01+:98E H/LWI- Q3 +03 .ga ....09 Q3 -10M 3.70E-0734ge- 4.66E+03 4.66E+05 1.31E+09 1.72E-Ot~ 4.84E+02~

M/E 0+ M ~

1.81E-07~ 6.70E+03 6.70E+05 1.81E+09 1.21E-Ot~ 3.28E+02~

MIl 0+ M ~

3.03E-07~ 3.86E+03 3.86E+05 1.04E+09 1.17E-01" .~5= 3.15E+02~

MIL 0+ M ~

4.05E-onA .~A= 9.92E+02 9.92E+04 7.32E+07 4.01 E_(\AA .~~= 2.96E-01".~5=

LIE 09 Q4 M 3.55E-0°'1.2 A= 3.26E+03 3.26E+05 7.48E+08 1.16E-02" .~~= 2.66E+01~

Lli Q3 ~ -10M 4.44E-07~ 1.75E+03 1.75E+05 1.66E+08 7.76E-02".2~= 7.36E+01~

LlL 0+ ~ -10M 2.19E-092.QQE 3.62E+00 3.62E+02 4.63E+05 7.93E-OZ~ 1.01 E_O'1n."D~

LUE 09 0+ Q4 2.12E-092.11 E 1.80E+00 1.80E+02 4.59E+05 3.81 E-07'1 .ec~ 9.71 E-OAn.~e=

LUI 09 0+ Q4 7.05E-09~ 2.90E+03 2.90E+05 4.81E+08 2.04E-0'1" .~e= 3.39E+00~

LUL 09 Q3 0lo0O 1.37E-06 3.62E+00 3.62E+02 4.63E+05 4.97E-04 6.36E-01 NCF Totals 6.094:8iE-01 ~1.51E+03

=

1. Conversion Factor: 1 sv 100 rem.

2. Value is the product of the release mode frequency and the population dose.

Results of sensitivity analyses indicate that a delayed evacuation or a lower evacuation speed would not have any significant effects on the offsite consequences or risks determined in this study. Table E.1-14 summarizes offsite consequences in terms of population dose (person-sv) and offsite economic cost ($) for the base case and the sensitivity cases.

Comparison of the consequences indicates a deviation of less than 1% between the base case and the sensitivity case results. The results of the sensitivity show that the parameters are not sensitive to change thus the sensitivitv results in Table E.1-14 were not updated with the new rule file [E.1-19J.

E.1-79 Grand Gulf Nuclear Station Page 33 of 83 Applicant's Environmental Report Operating License Renewal Stage E.1-16 USNRC to R. Hutchinson (GGNS), "Generic Letter 88-20, Individual Plant Examination (IPE) - Internal Events - Grand Gulf Nuclear Station (TAC M74415)," Correspondence No. GNRI-96/00067, letter dated March 7, 1996.

E.1-17 GGNS Calculation No. XC-N1111-01007, "GGNS Level 1 PSA," Revision 2, October 17, 2002.

E.1-18 GGNS Calculation No. PRA-GG-09-001, "Identification of Risk Implications due to Extended Power Uprate at Grand Gulf," May 2010.

E.1-19 Engineering Report No: ECH-NE-12-00096. "-GGNS L2 Recoverv Rule File". Rev. O.

2012.

E.1-82 Grand Gulf Nuclear Station Page 34 of 83 Applicant's Environmental Report Operating License Renewal Stage the PSA model [basic events ZSBO and ZT1 B were set to zero], which resulted in an internal and external benefit (with uncertainty) of approximately $346,9681,120,643, This analysis case was used to model the benefit of Phas e II SAMAs 1, 2, 11, 12, and 15.

Case 2: Improve Charger Reliability This SAMA analysis case was used to evaluate the change in plant risk from improving the diversity of the DC battery charging capability by adding an additional battery charger or providing a means to lower battery charger failure. A boundi ng analysis was performed by setting the failure of chargers contribution to zero in the level 1 PSA model. The following basic events were removed from the model:

11DA-007-D 11DA-Q08-D 11DB-007-E 11DB-008-E 11DC-007-F 11DC-008-F 11DD-007-X 11DD-008-X 11DE-007-X 11DE-008-X L21-CO-CB11A02-D L21-CO-CB11 A03-D L21-CO-CB11 B02-E L21-CO-CB11 B03-E L21-CO-CB11 D02-X L21-CO-CB11 D03-X L21-CO-CB11 E02-X L21-CO-CB11 E03-X L51-LP-BC-1 A4-D L51-LP-BC-1 A5-D L51-LP-BC-1 B4-E L51-LP-BC-1 B5-E L51-LP-BC-1 D4-X L51-LP-BC-1D5-X L51-LP-BC-1 E4-X L51-LP-BC-1 E5-X L51-MA-BC-1 A4-D L51-MA-BC-1 A5-D L51-MA-BC-1 B4-E L51-MA-BC-1 B5-E L51-MA-BC-1 D4-X L51-MA-BC-1 D5-X L51-MA-BC-1 E4-X L51-MA-BC-1 E5-X P81-CO-CB11C02-F P81-CO-CB11 C03-F P81-CO-CB70104-F P81-FO-HE1C5-F P81-LP-BC-1 C4-F P81-LP-BC-1 C5-F P81-MA-BC-1 C4-F P81-MA-BC-1 C5-F R20-CF-CB-BKR R20-CO-CB15102-X R20-CO-CB15202-X R20-CO-CB15306-D R20-CO-CB15602-D R20-CO-CB16102-X R20-CO-CB16202-X R20-CO-CB16306-E R20-CO-CB16602-E R20-CO-CB31116-F This resulted in an intemal and exter nal benefit (with uncertainty) of approximately

$4Q,79336,219. This analysis case was used to model the benefit of Phase II SAMAs 3 and 13.

Case 3: Add DC System Cross-Ties This analysis case was used to evaluate the change in plant risk from providing DC bus cross-ties. A bounding analysis was performed by eliminating failure of DC power gates in the PSA model (with the following gates removed from the model: 11 DA-001, 11 DA-001-SBO, 11DA-001T, 11DA-001X, 11DA-001Y, 11DA-001Z, 11DB-001, 11DB-001-SBO, 11DB-001T, 11 D8-001 X, and 11 DB-001 Z), which resulted in an internal and extemal benefit (with uncertainty) of approximately $219,169170,976. This analysis case was used to model the benefit of Phase II SAMA4.

E.2-4 Grand Gulf Nuclear Station Page 35 of 83 Applicant's Environmental Report Operating License Renewal Stage Case 4: Increase Availability of On-Site AC Power This analysis case was used to evaluate the change in plant risk from improving the backup sources for the Vital AC buses 15AA, 16AB, and 17AC. A bounding analysis was performed by eliminating failure of DG11, DG12, and DG13 to their AC buses (15AA, 16AB, and 17AC, respectively) in the Level 1 model (with the following gates set to zero: D G11-001L, DG11-001T, DG11-001X, DG11-001X-HPCS, DG11-001X-ONSP, DG11-001XP, DG11-001XZ, DG12-001L, DG12-001T, DG12-001X, DG12-001XP, DG12-001XZ, DG13-001N, DG13-001X, DG11-06, DG12-06, SB01-DG13-001X, and SB02-DG13-001X), which resulted in an internal and external benefit (with uncertai nty) of approximately $448,1891.282.117. This analysis case was used to model the benefit of Phase II SAMAs 5 and 8.

Case 5: Improve AC Power This analysis case was used to evaluate the cha nge in plant risk from improving the 4.16-kV bus cross-tie ability. A boundi ng analysis was performed by el iminating the loss of each of the 4.16-kV buses individually from the PSA model and eliminating only the failure of the bus with the highest impact. For this case. bus 16AB produced the most conservative result. Gates 16AB-001. 16AB-001D. 16AB-001-HPCS. 16AB-001L. 16AB-0010NSP.

16AB-001P,16AB-001T, 16AB-001U. and 16AB-001Z were removed from the model-:-+Ais-aAal'Jsi 5 ease '....as t:Jsed te model tt:!e t3eAefit of et:!ase II S,o.M,o.s 6 aAd 17tt:!e 4.16 k'l t3t:Jses iA tt:!e PS,o. modol [witt:! tt:!o fellowi A~ ~atos romovod from tt:!o modol: 15,0.,0. 001, 151\1\ 0010, 151\-/\ 001 t=4PCS, 151\,0. 0016,15/\1\ 001P, 151\,0. 001T, 15,0.,0. 001U, 15.4./\ 001Z, 161\8 001, 16,0.8 0010,16,0.8001 t=4PCS, 16,0.8 0016, 16,0.8 0010NSP, 16,0.8 001P, 16,0.8 001T, 16,0.8 001U, 16,0.8 001Z, 17,o.C 001, 17,o.C 001 OGX, aAd 17,o.C 001N], which resulted in an internal and external benefit (with uncertainty) of approximately $532,571443.507. This analysis case was used to model the benefit of Phase II SAMAs 6 and 17.

Case 6: Reduce Loss of Off-Site Power During Severe Weather This SAMA analysis evaluated the change in plant risk from installing an additional buried off-site power source. A bounding analysis was performed by removing LOSP due to severe weather from the LOSP initiating event frequencies [% T1 and %T1 P were multiplied by 19/24]. This resulted in an internal and external benefit (with uncertainty) of approximately $78,261252,665.

This analysis case was used to model the benefit of Phase II SAMA 7.

Case 7: Provide Backu p Emergency Diesel Generator (EDG) Cooling This analysis case was used to evaluate the change in plant risk from increasing EDG reliability by adding a backup source of diesel cooling. A bounding analysis was performed by eliminating failure of SW cooling to the EDGs [the following gates were eliminated: DGA-001 L, DGA-001T, DGA-001X, DGA-001X-HPCS, DGA-001X-ONSP, DGA-001XP, DGA-001XZ, DGB-001L, DGB-001T, DGB-001X, DGB-001XP, DGB-001XZ, DGC-001N, and DGC-001X], which resulted in an internal and external benefit (with uncertainty) of approximately $49,545233.526. This analysis case was used to model the benefit of Phase II SAMAs 9 and 10.

Case 8: Increase EDG Reliabil ity This analysis case was used to evaluate the change in plant risk from providing a portable EDG fuel oil transfer pump. A bounding analysis was performed by eliminating failure of EDGs to run in the PSA model [the following basic events ~ere set to zero: P75-FR-DG-DG11-A, P75-FR-DG-E.2-5 Grand Gulf Nuclear Station Page 36 of 83 Applicant's Environmental Report Operating License Renewal Stage DG12-B, P75-CF-3DGR-Z, and P75-CF-DGR-Z], which resulted in an internal and external benefit (with uncertainty) of approximately $91,044136.525. This analysis case was used to model the benefit of Phase II SAMA 14.

Case 9: Improve DG reliability This analysis case was used to evaluate the change in plant risk from providing a diverse swing diesel generator air start compressor. A bounding analysis was performed by eliminating the common cause failure (CCF) contribution of failure to start EDGs in the PSA model [the following CCF events were set to zero: P75-CF-3DGS-Z and P75-CF-DGS-Z], which resulted in an internal and external benefit (with uncertainty) of approximately $~23.552. This analysis case was used to model the benefit of Phase II SA MA 16.

Case 10: Reduce Plant-Centered Loss of Off-Site Power This analysis case was used to evaluate the change in plant risk from protecting transformers from failure. A bounding analysis was performed by removing the initiating contribution of plant and switchyard centered events in the PSA model. The LOSP notebook does not discriminate transformer failures between switchyard-centered or plant-centered so all plant-centered and switchyard-centered LOSP events were removed from the LOSP frequency [% T1 and %T1 P were multiplied by 9/24], which resulted in an internal and external benefit (with uncertainty) of approximately $229,888749.487. This analysis case was used to model the benefit of Phase II SAMA 18.

Case 11: Redundant Power to Torus Hard Pipe Vent (THPV) Valves This analysis case was used to evaluate the change in plant risk from providing redundant power to the direct torus vent valves. A bounding anal ysis was performed by el iminating failure of power to containment vents in the PSA model, which resulted in an internal and external benefit (with uncertainty) of approximately $32,29755.713. This analysis case was used to model the benefit of Phase II S AMA 19.

Specifically, the following gates were set to zero or removed:

15P21-001 PROB 0 16P41-001 PROB 0 1DA1-001 deleted from M41-002, M41-002X, and VC-L2-AC-POWER 1DB1-001 deleted from M41-002, M41-002X, and VC-L2-AC-POWER Case 12: High Pressure Injection System This analysis case evaluated the change in plant risk from plant modifications that would increase the availabil ity of high pressure core spray (installing a high press ure injection system independent of AC power or a passive high pressure core injection system). A bounding analysis was performed by eliminating failure of HPCS in the PSA model [gates U 1, U1-RX, and U1-SI were removed from the model], which resulted in an internal and external benefit (with E.2-6 Grand Gulf Nuclear Station Page 37 of 83 Applicant's Environmental Report Operating License Renewal Stage uncertainty) of approximately $1,784,7361.866.900. This analysis case was used to model the benefit of Phase II S AMAs 20 and 61 .

Case 13: Extend RCIC Operation This analysis case was used to evaluate the change in plant risk from raising the RCIC back pressure trip setpoint. A bounding analys is was performed by eliminating failure of trip due to pressure in the PSA model [gate E51-400 was set to zero], which resulted in an internal and external benefit (with uncertainty) of ~appFo)(imately$30,093. This analysis case was used to model the benefit of Phase II SAMA 21.

Case 14: Improve ADS System This analysis case was used to evaluate the change in plant risk from modifying the automatic depressurization system (ADS) components to improve reliability by adding larger accumulators.

A bounding analysis was performed by eliminating failure of ADS valves in the PSA model [gates 821-00181 and 821-003 were set to zero], which resulted in an internal and external benefit (with uncertainty) of approximately $929.843897,317. This analysis case was used to model the benefit of Phase II SAMA 22.

Case 15: Improve ADS Signals This analysis case was used to evaluate the change in plant risk from adding signals to open safety relief valves automatically in an MSIV closure transient. A bounding analysis was performed by eliminating failure of the SRV to open in the PSA model [the following gates were set to zero: OP-DEPRESS-OP1, 821-00181, 821-001A, 821-006 and basic event 821-CF-SF-K], which resulted in an internal and external benefit (with uncertainty) of approximately $185.722388,150. This analysis case was used to model the benefit of Phase II SAMA23.

Case 16: Low Pressure Injection System This analysis case was used to evaluate the change in plant risk from adding a diverse low pressure injection system. A bounding analysis was performed by eliminating failure of LPCI and low pressure core spray (LPCS) in the PSA model [the following gates were set to zero: V2, V2-RX, V2-SI, V3, V3-RX, V3-SI, and V3-S80], which resulted in an internal and external benefit (with uncertainty) of approximately $686.697689,896. This analysis case was used to model the benefit of Phase II S AMA 24.

Case 17: Emergency Core Cooling System (ECCS) Low Pressure Interlock This analysis case was used to evaluate the change in plant risk from installing a bypass switch to allow operators to bypass the low reactor pressure interlock circuitry that inhibits opening the LPCI or core spray injection valves following sensor or logic failures that prevent all low pressure injection valves from opening. A bounding analysis was performed by eliminating ECCS permissives and interlock failure in the PSA model [the following gates were set to zero:

E12-110, E12-190, 821-012A, 821-013A, 821-026A, and 821-027A], which resulted in an internal E.2-7 Grand Gulf Nuclear Station Page 38 of 83 Applicant's Environmental Report Operating License Renewal Stage and external benefit (with uncertainty) of approximately $3Q,Q930. This analysis case was used to model the benefit of Phase II S AMA 25.

Case 18: RHR Heat Exchangers This analysis case was used to evaluate the change in plant risk from implementing modifications to allow manual alignment of the fire water system to RHR heat exchangers. A bounding analysis was performed by eliminating failure of SSW to provide cooling to the RHR heat exchangers [the following gates were removed from the model: P41-RHRHXA-SBO, P41-RHRHXB-SBO, P41-RHRHXA and P41-RHRHXB], which resulted in an internal and external benefit (with uncertainty) of approximately $616.449819,889. This analysis case was used to model the benefit of Phase II SAMA 26.

Case 19: Emergency Service Water System Reliability This analysis case was used to evaluate the change in plant risk from installing an additional service water pump. A bounding analysis was performed by eliminating failure of service water pumps in the PSA model [the following basic events were set to zero: P41-CF-MCP001 R-R, P41-CF-MCP001 S-R, P41-CF-MVDISNA-R, P41-CF-MVDISNB-R, P41-CF-MVDISNC-R, P41-CF-MVF001AB, P41-CF-MV-F001AB, P41-CF-MVF005AB, and P41-CF-ST-SUCT-R],

which resulted in an internal and external benefit (with uncertainty) of approximately

$141,501113,7Q8. This analysis case was used to model the benefit of Phase II SAMA 27.

Case 20: Main Feedwater System Reliability This analysis case was used to evaluate the change in plant risk from installing a motor-driven feedwater pump. A bounding analysis was performed by setting failure to inject from feedwater to zero in the PSA model [gate N21-002 was set to zero], which resulted in an internal and external benefit (with uncertainty) of approximately $401,780488,149. This analysis case was used to model the benefit of Phase II SA MA 28.

Case 21: Increase Availability of Room Cooling This analysis case was used to evaluate the change in plant risk from providing a redundant HVAC train to rooms dependent on room cooling. A bounding analysis was performed by eliminating failure of room cooling to the safeguard switchgear battery rooms, standby service water pump rooms, LPCS pump rooms, and HPCS pump rooms in the PSA model [the following gates were set to zero: T51-060, Z77-300, T51-080, HVC-1000X, HVC-1000XP, HVC-1000XZ, HVC-1000-HPCS, HVC-1000X-HPCS, HVC-1000X-ONSP, HVC-1000X-SBO, and HVC-2000X],

which resulted in an internal and external benefit (with uncertainty) of approximately

$579,724528,2QQ. This analysis case was used to model the benefit of Phase II SAMA 29.

Case 22: Increase Availability of the DG System through HVAC Improvements This analysis case was used to evaluate the change in plant risk from enhanci ng diesel generator room cooling. A bounding analysis was performed by eliminating failure of cooling of E.2-8 Grand Gulf Nuclear Station Page 39 of 83 Applicant's Environmental Report Operating License Renewal Stage three diesel generator rooms in the PSA model [gates HVC-001X, HVC-010X, and HVC-020X were set to zero]. This resulted in an internal and external benefit (with uncertainty) of approximately $710.643227,963. This analysis case was used to model the benefit of Phase II SAMAs 30, 32, and 33.

Case 23: Increase Reliab ility of HPCI and RCIC Room Cooling This analysis case was used to evaluate the change in plant risk from creating the ability to switch HPCI and RCIC room fan power supply to DC in an SBO event. Since RCIC pump continued operation is not dependent on room cooling, a bounding analysis was performed by eliminating failure of power to the HPCS pump room cooler in the PSA model [gate 17B01-001 was removed from gate T51-080], which resulted in an internal and external benefit (with uncertainty) of approximately $3Q,Q93Q. This analysis case was used to model the benefit of Phase II SAMA 31.

Case 24: Increase Reliab ility of Instrument Air This analysis case was used to evaluate the change in plant risk from improving the reliability of the instrument air system. A bounding analysis was performed by eliminating failure of the instrument air system in the level 1 PSA model [the following gates were set to zero: P53-001 ,

P53-001AX, P53-001X, P53-101, P53-001A, P53-101X, P53-102, P53-102X, and initiator

%TIA], which resulted in an internal and external benefit (with uncertainty) of approximately

$428,345413,527. This analysis case was used to model the benefit of Phase II SAMAs 34 and 35.

Case 25: Backup Nitrogen to SRV This analysis case was used to evaluate the change in plant risk from installing permanent nitrogen bottles as backup gas supply. A bounding analysis was performed by eliminating operator failure to install bottles in the PSA model [basic event B21-FO-HEBOTTLES was set to zero], which resulted in an internal and external benefit (with uncertainty) of approximately

$140.775121,841. This analysis case was used to model the benefit of Phase II SAMA 36.

Case 26: Improve Availability of SRVs and MSIVs This analysis case was used to evaluate the change in plant risk from improving SRV and MSIV pneumatic components. A bounding analysis was performed by eliminating failure of non-ADS SRVs in the PSA model [gate B21-004 and basic events B21-FO-HEDEP2-1 and B21-CF-SF-K were set to zero], which resulted in an internal and external benefit (with uncertainty) of approximately $935,1639Q1,893. This analysis case was used to model the benefit of Phase II SAMA37.

Case 27: Improve Suppression Pool Cooling This analysis case was used to evaluate the change in plant risk from installing an independent method of suppression pool cooling. This would allow the suppression pool to be a n alternate cooling source for the RHR heat exchanger. A bounding analysis was performed by eliminating E.2-9 Grand Gulf Nuclear Station Page 40 of 83 Applicant's Environmental Report Operating License Renewal Stage the failure of flow to the RHR heat exchangers in the PSA model [gates P41-RHRHXA, P41-RHRHXB, P41-RHRHXA-SBO, and P41-RHRHXB-SBO were removed from the model],

which resulted in an internal and external benefit (with uncertainty) of approximately

$616.596615,669. This analysis case was used to model the benefit of Phase II SAMA 38.

Case 28: Increase Availab ility of Containment Heat Removal This analysis case was used to evaluate the change in plant risk from increasing the availability of containment heat removal. A bounding analysis was performed by eliminating failure of cooled flow through the injection line in the PSA model [gates E12-686, E12-686X, E 12-686Y, E12-686Y-SBO, E12-686-SBO, E12-686X-SBO, E12-665, E12-665-SBO, E12-620, E12-620X, E12-620Y, E12-620-SBO, E12-620X-SBO, E12-620Y-SBO, E12-604, and E12-604-SBO were set to zero], which resulted in an internal and external benefit (with uncertainty) of approximately

$891.540865,312. This is similar to analysis case 29; however, the containment spray injection valves are not set to zero. This analysis case was used to model the benefit of Phase II SAMAs 39 and 41.

Case 29. Decay Heat Removal Capability-Drywell Spray This analysis case was used to evaluate the change in plant risk from improving drywell spray capability by installing a passive drywell spray system. Enhancements of decay heat removal capability decrease the probabi Iity of loss of containment heat removal. A bounding analys is was performed by setting the events for loss of RHR spray to zero in the PSA model [the following gates were set to zero: W3, W3X, #W3X, W3-SBO, W3X-SBO, W3Y, and W3Y-SBO], which resulted in an internal and external benefit (with uncertainty) of approximately $891.888865,649.

This analysis case was used to model the benefit of Phase II SAMA 40.

Case 30: Increase Availability of the CST This analysis case was used to evaluate the change in plant risk from providing a means of replenishing CST water from the firewater, demineralized water, or service water system. A bounding analysis was performed by eliminating the CDF contribution from HPCS and RCIC suction [gates P11-F021 and E22-041 were set to zero], which resulted in an internal and external benefit (with uncertainty) of approximately $230.917323,696. This analysis case was used to model the benefit of Phase II SAMA 42.

Case 31: Filtered Vent to Increase Heat Removal Capacity for Non-ATWS Events This analysis case was used to evaluate the change in plant risk from installing a filtered containment vent. A bounding analysis was performed by reducing the baseline accident progression source terms by a factor of 2 (excluding noble gases) to reflect the additional filtered capability. Reducing the releases from the vent path resulted in an internal and external benefit (with uncertainty) of approximately $353.952242,759. This analysis case was used to model the benefit of Phase II SAMA 43.

E.2-10 Grand Gulf Nuclear Station Page 41 of 83 Applicant's Environmental Report Operating License Renewal Stage Case 32: Reduce Hydrogen Ignition This SAMA analysis case was used to evaluate the change in plant risk from installing a passive hydrogen control system or from providing post-accident containment inerting capability. A bounding analysis was performed by eliminating failure of hydrogen igniters in the PSA model

[gate E61-001 was set to zero], which resulted in an internal and external benefit (with uncertainty) of approximately $187.571427,3ee. This analysis case was used to model the benefit of Phase II SAMAs 44 and 45.

Case 33: Controlled Containment Venting This analysis case was used to evaluate the change in plant risk from enabling manual operation of all containment vent valves via local controls or from providing passive overpressure relief. A bounding analysis was performed by eliminating failure of air-operated valves to open in the PSA model [gates M41-002, M41-002-SS0, and M41-002X were set to zero], which resulted in an internal and external benefit (with uncertainty) of approximately $63.62393,240. This analysis case was used to model the benefit of Phase II SAMAs 46 and 47.

Case 34: ISLOCA This analysis case was used to evaluate the change in plant risk from reducing the probability of an ISLOCA by increasing the frequency of valve leak testing or improving IS LOCA identification or coping. A bounding analysis was performed by setting the ISLOCA initiators to zero in the PSA model [initiators %VJ:PCIC, %VLPCS, and %VSDC were set to zero], which resulted in an internal and external benefit (with uncertainty) of approximately $385234-. This analysis case was used to model the benefit of Phase II SAMAs 48, 50, and 51.

Case 35: MSIV Design This analysis case was used to evaluate the change in plant risk from improving MSIV design to decrease the likelihood of containment bypass scenarios. A bounding analysis was performed by eliminating failure of the MSIVs to close or remain closed in the PSA model [gates DL-M SIV, IS-MSIV, and IS-MSIV-INIT were removed from the model], which resulted in an internal and external benefit (with uncertainty) of approximately $1Q.30,093. This analysis case was used to model the benefit of Phase II SAMA 49.

Case 36: Standby Liquid Control (SLC) System This analysis case was used to evaluate the change in plant risk from increasing boron concentration in the SLC system. A bounding analysis was performed by eliminating the contribution due to failure to initiate SLC and failures of alternate boron injection in the PSA model

[gate SLC was removed from the model and basic event ASI was set to zero], which resulted in an internal and external benefit (with uncertainty) of approximately $1,77131,849. This analysis case was used to model the benefit of Phase II SAMA 52.

E.2-11 Grand Gulf Nuclear Station Page 42 of 83 Applicant's Environmental Report Operating License Renewal Stage Case 37: SRV Reseat This analysis of case was used to evaluate the change in plant risk from installing more reliable SRVs. A bounding analysis was performed by eliminating the initiator for the SRVs inadvertently being open and the basic events for stuck open SRVs in the PSA model [initiator %T3C, basic events P1 and P2 were set to zero], which resulted in an internal and ex temal benefit (with uncertainty) of approximately $139.37387,324. This analysis case was used to model the benefit of Phase II S AMA 53.

Case 38: Add Fire Suppression This analysis case was used to evaluate the change in plant risk from adding automatic fire suppression systems to the dominant fire zones. The dominant fire zones reported in the IPEEE are the control room and control building switchgear rooms. The control room has Halon suppression in the control room floor sections. Many of the switchgear rooms have automatic CO 2 suppression systems. The Div I switchgear room in the control building that is a large contributor in the IPEEE is zone OC202 in compartment CC202, which has a partial automatic sprinkler system.

For the main control, an automatic suppression system would not provide a significant safety benefit. The sensing devices used for fi res include both fuse elements that melt given high temperature and smoke detectors. These types of actuation devices would only actuate after the fire has progressed to a point that would cause evacuation of the control room. Even if the auto suppression system actuated prior to evacuation, the consequences of actuation would require evacuation. Additional Halon or CO 2 systems would asphyxiate any personnel remaining in the main control room and water would dam age the control equipment. Given that the main control room fire risk is dominated by failure to shut down the reactor from outside the control room, extremely limited benefit is judged to exist for auto suppression systems in the main control room.

Thus, this SAMA evaluates improving the reliability and effectiveness of the suppression systems in the switchgear rooms. A bounding analysis was performed as described below, which resulted in an internal and external benefit (with uncertainty) of approximately $97,840102,345.

This analysis case was used to model the benefit of Phase II SAMA 54.

This analysis case (Adding automatic fire suppression systems to the critical switchgear rooms) is an external events SAMA, which would not mitigate internal event risk. Many of the switchgear rooms have automatic CO 2 suppression systems. The Div I switchgear room in the control building that is a large contributor in the IPEEE is zone OC202, which has a partial automatic sprinkler system. This SAMA would improve the reliability and effectiveness of those system s. A bounding analysis was performed by assuming the SAMA would eliminate the contribution to fire CDF from fires in critical switchgear room OC202. Since the total fire CDF is 2.74E-05/yr

[Table E.1-10] and the critical switchgear room fire CDF is 9.37E-07/yr, fires in the critical switchgear rooms contribute 3.42% of the total fire CDF.

E.2-12 Grand Gulf Nuclear Station Page 43 of 83 Applicant's Environmental Report Operating License Renewal Stage The internal events model cannot be used to asses s the benefit from this external event SAMA.

However, the consequences resulting from fire-induced core damage and internal event-induced core damage would be comparable. Since we have already estimated the maximum benefit from removing all internal event risk, the maximum benefit of removing all fire risk was estimated by reducing the maximum internal event benefit by the ratio of the total fire CDF to the internal event CDF. Since this SAMA analysis case would eliminate 3.42% of the total fire risk, the benefit for this SAMA analysis case was estimated to be 3.42% of the total fire benefit as shown below.

Given, Maximum internal benefit is $74,673101,995 [Table 4.21-1]

Total fire CDF = 2.74E-05/rx-yr [Table E.1-10]

Internal events CDF = 2.Q&E.93E-06/rx-yr Maximum fire benefit = Maximum internal benefit x Total fire CDFllnternal events CDF Maximum fire benefit = $74,673 x (2.74E-05/2.93G&E-06)= $997,669953,687 SAMA case 38 benefit = 3.42% x (Maximum fire benefit) = 0.0342 x $997,669953,687 SAMA case 38 benefit = $34,11632,613 Applying the uncertainty factor of 3, SAMA case 38 benefit with uncertainty = $34,11632.613 x 3 = $102,34697,840 Case 39: Reduce Risk from Fires that Require Control Room Evacuation The alternate shutdown system (ASDS) panel is designed to use division 1 safety and support systems to safely shutdown the pi ant. This analysis case was used to evaluate the change in plant risk from upgrading the ASDS panel to include additional system controls for the other division. A bounding analysis was performed as described below, which resulted in an internal and external benefit (with uncertainty) of approximately $402,011420,621. This analysis case was used to model the benefit of Phase II SAMA 55.

This SAMA analysis case is an external events SAMA, which would not mitigate internal event risk. A bounding analysis was performed by assuming the SAMA would eliminate the contribution to fire CDF from fires in the control room. Since the total fire CDF is 2.74E-05/yr and the control room fire CDF is 3.85E 06/yr, fires in the control room contribute 14.05% of the total fire CDF.

The internal events model cannot be used to asses s the benefit from this external event SAMA.

However, the consequences resulting from fire-induced core damage and internal event-induced core damage would be comparable. Since we have already estimated the maximum benefit from removing all internal event risk, the maximum benefit of removing all fire risk can be estimated by reducing the maxi mum internal event benefit by the ratio of the total fire CDF to the internal event CDF. Since this SAMA analysis case would eliminate 14.05% of the total fire risk, the benefit for this SAMA analysis case was estimated to be 14.05% of the total fire benefit as shown below.

E.2-13 Grand Gulf Nuclear Station Page 44 of 83 Applicant's Environmental Report Operating License Renewal Stage

Given, Maximum internal benefit is $74,673101,995 [Table 4.21-1]

=

Total fire CDF 2.74E-05/rx-yr [Table E.1-10]

=

Internal events CDF 2.93~E-06/rx-yr Maximum fire benefit =Maximum internal benefit x Total fire CDF/lnternal events CDF Maximum fire benefit =$74,673101,995 x (2.74E-05/2.93~E-06) =$997,599953,687 SAMA case 39 benefit =14.05% x (Maximum fire benefit) =0.1405 x $997,599953,687 SAMA case 39 benefit =$140,174 134,004 Applying the uncertainty factor of 3, SAMA case 39 benefit with uncertainty =$140174 134,004 x 3 =$420,521 402,011 Case 40: Large Break LOCA This analysis case was used to evaluate the change in plant risk from installing a digital large break LOCA protection system. A bounding ana lysis was performed by setting the large LOCA initiator to zero in the PSA model [initiator %A was set to zero], which resulted in an internal and external benefit (with uncertainty) of approximately $214.031 948,372. This analysis case was used to model the benefit of Phase II SA MA 56.

Case 41: Trip/Shutdown Risk This analysis case was used to eval uate the change in plant risk from implementing Generation Risk Assessment (trip and shutdown risk modeling) in plant activities. It is assumed that this would reduce the frequency of plant trips and shutdowns. A bounding analysis was performed by reducing all initiating event frequencies except pipe breaks, floods, and LOSP by 10% [the following initiating events were reduced: %T2, %T2M, %T3A, %T3B, %T3C, %TAC1, %TAC2,

%TBCW, %TCCW, %TCRD, %TDC1, %TDC2, %TIA, %TPSW, %TST11, and %TST21], which resulted in an internal and external benefit (with uncertainty) of approximately $197.486187,117.

This analysis case was used to model the benefit of Phase II SAMA 57.

Case 42: Increase Availab ility of SSW Pump House Ventilation System This analysis case was used to evaluate the change in plant risk from increasing the traini ng emphasis and providing additional control room indication on the operational status of the SSW pump house ventilation system. This will allow operators to manually open the pump house dampers, which can provide adequate ventil ation such that pump failures would not occur. A bounding analysis was performed by eliminating failure of SSW Pump House Ventilation in the PSA model [the following gates were removed from the model: HVC-1000X, HVC-1000XP, HVC-1000XZ, HVC-1000-HPCS, HVC-1000X-HPCS, HVC-1 OOOX-ONSP, HVC-1000X-SBO, and HVC-2000X], which resulted in an internal and external benefit (with uncertainty) of approximately $50,36245,212. This analysis case was used to model the benefit of Phase II SAMA58.

E.2-14 Grand Gulf Nuclear Station Page 45 of 83 Applicant's. Environmental Report Operating license Renewal Stage Case 43: Increase Recovery Time of ECCS upon Loss of SSW This analysis case was used to evaluate the change in plant risk from upgrading procedures and increasing operator training for alternating operation of the low pressure ECCS pumps (LPCI and LPCS) for loss of SSW scenarios. A bounding analysis was performed by eliminating failure of the SSW to the LPCS room cooler in the PSA model [gate P41-LPCS was removed from the model], which resulted in an internal and external benefit (with uncertainty) of approximately

$160,043121,357. This analysis case was used to model the benefit of Phase II SAMA 59.

Case 44: Additional Containment Heat Removal This analysis of case was used to eval uate the change in plant risk from installing an additional method of removing heat from the containment. A bounding analysis was performed by eliminating failure of suppression pool cooling and containment spray systems in the PSA model

[the following gates were removed from the model: RH--SY-SPCSYS-F-, E12-199, E12-199X, E12-199XX, E12-199X-SBO, E12-199Y, E12-199Y-SBO, E12-199-SBO, E12-199-CSS, E12-600, E12-600X, E12-600XX, E12-600X-SBO, E12-600Y, E12-600Y-SBO, and E12-600-SBO], which resulted in an internal and external benefit (with uncertainty) of approximately $907.437894,382. This analysis case was used to model the benefit of Phase II SAMA60.

Case 45: Improve RHR Heat Exchanger Availability This SAMA analysis case was used to evaluate the change in plant risk from adding a bypass around the RHR HX inlet and outlet valves. A bounding analysis was performed by eliminating failure of RHR HX Cooler inlet and outlet valves in the PSA model [the following basic events were set to zero: P41-CC-MVF014A-L, P41-CC-MVF014B-L, P41-CC-MVF068A-L, P41-CC-MVF068B-L, P41-CF-MVF14AB-L, and P41-CF-MVF68AB-L], which resulted in an internal and external benefit (with uncertainty) of approximately $113.252124,019. This analysis case was used to model the benefit of Phase II SAMA 62.

Case 46: Improve RCIC Lube Oil Cooling This analysis case was used to evaluate the change in plant risk from adding a redundant RCIC lube oil cooling path. A bounding analysis was performed by eliminating the failure to cool RCIC lube oil in the PSA model [gate E51-043-G was set to zero], which resulted in an internal and external benefit (with uncertainty) of approximately $204.681 92,883. This analysis case was used to model the benefit of Phase II SA MA 63.

E.2.4 Sensitivity Analyses Two sensitivity analyses were conducted to gauge the impact of assumptions upon the analysis.

The benefits estimated for each of these sensitivities are presented in Table E.2-3.

A description of each sensitivity case follows.

E.2-15

Attachment 1 Grand Gulf Nuclear Station Page 46 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation Analysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty

1. DC Power Eliminates all SSO ~"'2.eOL !')7.3%~e.5OL ~~2.e~L $373.548 - $1.120.643 -

cutsets $115,656 $346,968 1 - Provide additional GGNS olant soecific $2.130.887$& Not cost DC battery capacity ~CNS estimate. QQ,QQQ effective 2 - Replace lead-acid K3GNS olant soecific $4.079.609$4,- Not cost batteries with fuel ~CNS estimate. QQQ,QQQ effective cells ir'tl.IC' a... ....... .." LL.

11 - Portable $1.278.211$+ Not cost 1- . - . . _ - _ ...............

"",..",,+

generator for direct 1 - - - - - . , ' **- - - - f,..r

+a... .....

14,QQQ effective

... +......

~urrent (DC) power:

I II"""" . - - '..... ~ ..... , '.... -..... * ....

............ 1. +h.....

Irhis SAMA involves -,._~~ ......

,.,.':'~f"+:',..

~he use of a portable - " . - - ...... 1"""'" - - _ . -

4-......... *.........1.. .,.

generator to supply ~ ............. _....... n ... ""-1""1""'" -

DC power to the .... - .. _. _. ,.... "

....,............1 h,.."..., ,"" ...... +h,....

battery chargers ,._- -". -"

a... ..............

......... ~

during a station ~-' ._. --_. _ hi............ ,.., .... h

_.~

,...................1. 4-a... ....

.. _-~'

blackout. L

...... ""-1""1""'" .............. _. ...... , ~

-- -- - ,..11 .... --

h **+ ...,..+ hi ...........

_.~

"'- ..........1..................1

--~'

h +,..

'r"r'l - 1""-' ,.......

II",..... + L .* .\

1'-- ,-. -_.- '/

E.2-30

Attachment 1 Grand Gulf Nuclear Station Page 47 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation

~nalysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty ICi ......'" ...................... "' ...

(cont.) 1- ,.-- -- ~- ----

I....... ~

- '--";:1 p- ,- ---

~ ....... ..............- -,...

~

, ... """..... I " , r """i+h"""r 1"'-"""---, ....- ,..."'.c

".r...",...", ~ ...'"

I. . .

~

...................... - - """'u

,"' I " , r ... ...

i...

: 1 - " - _ ..- .....

Th .....

'r'r*... -. -,

GGNS olant soecific cost estimate, GGNS C A "J11 A 1 1 ..."'...+

.h""" ...... r.-."""

...... f':!.f':!.""IC ICII."J1111. 01') ..."' ... ~

1- ....... - ..............

1""'........ , ...........

12 - Portable GGNS olant soecific $1.278.211$7 Not cost Senerator for direct ~CNS estimate. 14,000 effective

~urrent (DC) power:

Irhis SAMA involves the use of a portable generator to supply DC power to the individual panels during a station blackout.

E.2-31

Attachment 1 Grand Gulf Nuclear Station Page 48 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation

~nalysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty 15 - Use DC IGGNS olant soecific $1,428,000 Not cost generators to provide ~GGNS SAMA 11 effective I............ C'Aa.,tA "'1')

power to operate the 1'0""'" - ....... , -

." ,,1.. ....." _ _ _

Iswitchyard power 1'""".... "'."'"

!control breakers while ~-

Ia 480-V AC generator ......

d'"7"'.11 nnn T .... i ...

-Y,"""""" ........

iC'A a.,t A *

!could supply the air r- .........._"",. ,.,... , ........

!compressors for

~ .......

..... ~ ",+ .""",...+

.~

breaker support.

~~"'.:"';'::;:::I";*

I*.*. ---- . . . ' -- ..... _.... .......-

... r:. ............. ~

A II /I A

_I.. ...... 1.... 1.._ ....." 1___"

i1 ........... iI I')

~""'" . . ." '.... V T

,...................... ~ .......... ~ ~........ C' A" A A

2. Improve Charger Failure of chargers 0.7%44% 2.0%~ 2.1%~ $12,073 - $36,219 -

Reliability contribution to zero. $13,598 $4Q,793 3 Add battery leNS estimate. $90,000 Not cost

!charger to existing DC effective lSystem 13 Proceduralize leNS estimate. $50,000 Not cost battery charger effective high-voltage Ishutdown circuit inhibit E.2-32

Attachment 1 Grand Gulf Nuclear Station Page 49 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation

~nalysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty

~. Add DC System Eliminate failure of 3.6%~ 8.4%~ 9.0%~ $56,992 - $170.976 -

Cross-ties DC power gates. $73,Q56 $219,169 4 Provide DC bus eNS estimate. $300,000 Not cost

!cross-ties effective

14. Increase Eliminated failure of ~:t"".5-0' 31.4%') .... ~0£ 25.6%'" e.5°~ $427.372 - $1.282.117 -

~ vailability of DG11, DG12, and $149,396 $448,189

~n-Site AC Power DG13 to their AC Busses 5 Provide an CNS estimate. $20,000,000 Not cost additional diesel effective generator 8 Install a gas eNS estimate. $2,000,000 Not cost urbine generator with effective amado protection

~.Improve AC Eliminated the loss 01 7.5%2OA2k 29.5% ,)l::. .6 0£ 23.5% ')1) .~~(. $144.502 - $433.507 -

- ~

Power ~he 4.16-kV buses $177,524 $532,571 16 Improve 4.16-kV leNS estimate. $656,000 Not cost bus cross-tie ability effective E.2-33

Attachment 1 Grand Gulf Nuclear Station Page 50 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation

~nalysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty 17 Provide alternate Modification of the $656,000 Not cost

~eeds to essential ~C system to allow effective

~oads directly from an alignment of alternate

~Iternate emergency feeds to the 4kV bus oads is greater in scope than an AC crosstie modification.

SAMA 6, Improve 4.16-kV bus cross-tie ability, is estimated to cost $656,000. Thus, lhis is a lower bound estimate for SAMA 17.

6. Reduce Loss of Eliminate the weathel 8.4%3A% 6.0%3-:+% 4.8%3A% $84.222 - $252.665 -

Pff-5ite Power !centered loss of $26,Q87 $78,261 During Severe Ioff-site power lWeather initiating event.

17 Install an leNS estimate. $2,485,000 Not cost

~dditional, buried effective pff-site power source.

E.2-34

Attachment 1 Grand Gulf Nuclear Station Page 51 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation Analysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty

~. Provide Backup Eliminated failure of 7.6%~ 6.4%U% 4.6%~ $77.842 - $233.526 -

EDG Cooling SW cooling to the $16,515 $49,545 EDGs 9 Use fire water GGNS olant soecific $1.344.116-W Not cost system as backup ~l=taFEh,*laFe MOO effective source for diesel

,~ . .................

cooling 1---" ._-_.

10 Add new backup eNS estimate. $2,000,000 Not cost

$ource of diesel effective

~ooling

8. Increase EDG Eliminated failure of 4.0%~ 4.3%4-:9% 4.0%4M4 $45,508 - $136.525 -

Reliability EDGs to run $30,348 $91,044 14 Provide a GGNS olant soecific $1.477.188 Not cost portable EDG fuel oil ~CNS estimate. $100,000 effective

~ransfer pump E.2-35

Attachment 1 Grand Gulf Nuclear Station Page 52 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation

~nalysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty

~. Improve DG Eliminated the 0.8%~ 0.6%~ 0.4%~ $7,851 - $23,552 -

Reliability common cause $2,181 $6,542 ailure (CCF)

~ontribution of failure

~o start EDGs 16 Provide a diverse Hardware $100,000 Not cost swing diesel modification range effective generator air start ~stimate.

~ompressor

10. Reduce Removed the 1760.1< 1 n 70L 25.0%9-:4% ~"""'V 13.9%~ $249,829 - $749,487 -

Plant-Centered Loss ~ontribution of plant- $76,556 $229,668 pf Off-5ite Power and switchyard-centered events 18 Protect CNS estimate. $780,000 Not cost ransformers from effective ailure E.2-36

Attachment 1 Grand Gulf Nuclear Station Page 53 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation

~nalysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty

11. Redundant Eliminated failure of <O.1%~ 5.4%~ 6.0%~ $18,571 - $55,713 -

Power to Torus Hard power to containmen1 $1Q,766 $32,297 Pipe Vent (THPV) vents

~alves 19 Provide ~NS estimate. $714,000 Not cost redundant power to effective kiirect torus hard pipe

~ent valves to improve the reliability of the Cfirect torus vent valves and enhance the containment heat removal capability.

E.2-37

Attachment 1 Grand Gulf Nuclear Station Page 54 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation

~nalysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty

12. High Pressure 53 7 01c"7"7 Eliminated failure of ~ ... -

OOL 62.2%a~ .e~L 58.0%a~.~0/.:. $622,300 - $1,866.900 -

Injection System ~he HPCS $594,912 $1,784,736

~O Install an Recent BWR cost $8,800,000 Not cost independent active or estimates for this effective passive high pressure SAMA are -$2M at injection system Duane Arnold, -$4M at Susquehanna,

-$5M at Vermont Yankee, and -$29M lat Columbia.

SAMA 24, Add a

~iverse low pressure injection system, is

~stimated to cost

~8,800,000. Since a high pressure system would cost at least as much as a low pressure system, this

~stimate is appropriate.

E.2-38

Attachment 1 Grand Gulf Nuclear Station Page 55 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation

~nalysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty

~1 Install a backup Plant-specific cost $6,409,949 Not cost water supply and ~stimate. effective pumping capability that is independent of normal and emergency AC power

13. Extend RCIC Eliminated failure of <0.1%~ <0.1 %4-:-9% <0.1%~ ~- ~ $30,093 Operation ~rip due to pressure $10,031

~1 Raise HPCII CNS estimate. $200,000 Not cost RCIC backpressure effective

~rip set points [HPCI backpressure trip setpoint has already been raised. This SAMA will evaluate raising the RCIC backpressure trip set point).

E.2-39

Attachment 1 Grand Gulf Nuclear Station Page 56 of83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation Analysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty

14. Improve ADS Eliminated failure of ~A,5.9~/- 12 7%'1 a '10L ----:.-

- - - - : . - ' ......... I ...... .., ' ..

131%'1a nOL $309,948 - $929,843 -

$ystem ADS valves $2QQ,106 $8Q7,317

~2 Modify automatic Plant-specific cost $1,176,850 Not cost

~epressurization estimate. effective system components

+0 improve reliability

[This SAMA will add arger accumulators

..hus increasing reliability during S80s].

15. Improve ADS Eliminated failure of 6.0%~ 4.5%~ 4.2%~ $61.907 - $185,722 -

$ignals ..he SRV failing to $12Q,383 $388,190 open 23 Add signals to K;NS estimate. $1,500,000 Not cost open safety relief effective valves automatically in an MSIV closure

~ransient.

E.2-40

Attachment 1 Grand Gulf Nuclear Station Page 57 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation

~nalysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty

16. Low Pressure Eliminated failure of 11.4% 'l'l.~OL ,Jl 5.4% 'l~.50L Jl

' O.5% ~e.3°/;; $228,899 - $686.697 -

r---- r----

Injection System ~he LPC I and LPCS $229,965 $689,896 24 Add a diverse low ~NS estimate. $8,800,000 Not cost pressure injection effective system.

17. ECCS Low Eliminated ECCS <0.1%~ <0.1%~ <0.1%~ iQ..: $1 Q,Q31 iQ..: $3Q,Q93 Pressure Interlock permissives and interlock failure

~5 Install a bypass eNS estimate. $1,000,000 Not cost

$witch to allow effective pperators to bypass

he low reactor pressure interlock circuitry that inhibits opening the LPCI or core spray injection valves following sensor or logic failures hat prevent all low pressure injection

~alves from opening.

E.2-41

Attachment 1 Grand Gulf Nuclear Station Page 58 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation

~nalysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty

18. RHR Heat 125°A"'or::.OL 30.9% '17. J! OL t34.1%"l.~.~0<,

Eliminated failure of ~-..oT.-.oT $205.483 - $616.449 -

'V

- o---

$205,223 $615,669 Exchangers SSW to provide cooling to the RHR heat exchangers

~6 Implement Pilgrim estimate. $1,950,000 Not cost modifications to allow effective manual alignment of

~he fire water system

~o RHR heat

~xchangers.

19. Emergency Eliminated failure of 3.5%~ 6.0%~ 6.3%~ $47.167 - $141,501 -

Service Water service water pumps $37,903 $113,708 System Reliability 27 Add a service eNS estimate. $5,900,000 Not cost water pump to effective increase availability of

~ooling water

~O. Main Feedwater Eliminated failure to 7.5%~ 22.2%"n. r::.OI 23 7 0A "n ....

aOI,V $133.927 - $401.780 -

lSystem Reliability inject from feedwater

- ~

$162,050 $486,149

~8 Add a leNS estimate. $1,650,000 Not cost motor-driven feed effective Iwater pump E.2-42

Attachment 1 Grand Gulf Nuclear Station Page 59 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation Analysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty 121. Increase Eliminated failure of r17.9%1')1').~o, ----

15.1%"I7.8~Lr16.0%"1 r---- ----

e.~OL $193.241 - $579.724 -

~ vailability of Room room cooling to $175,400 $526,200 Cooling LPCS, HPCS, SSW

~nd safeguard

~witchgear battery rooms 29 Provide a eNS estimate. $2,202,725 Not cost redundant train or effective means of ventilation 122. Increase Eliminated failure of 23.9%~ 166'*" n aOI_ 12.3%&&%

~._._v $236.881 - $710.643 -

~ vailability of the diesel generator $75,988 $227,963 DG System Through rooms HVAC HVAC Improvements 30 Add a diesel ~NS estimate. $1,304,700 Not cost building high effective temperature alarm or redundant louver and

~hermostat.

32 Diverse EDG GGNS Dlant sDecific $1.148.27S$3 Not cost HVAC logic "'ost r""",.. ~"

~'--_ .. . __ ......

_... n ...,.....,..

. II 00,000 effective C'AlAA ... A ,.._ .... '1"1 i",.

'r ...

...r.....

r-" ._... ---r--'

i .... _ ...""' ...."

E.2-43

Attachment 1 Grand Gulf Nuclear Station Page 60 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation Analysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty 33 Install additional ~NS estimate. $6,000,000 Not cost an and louver pair for effective EDG heating,

[ventilation, and air

~onditioning

~3.lncreased Eliminated failure of <O.1%~ <O.1%~ <O.1%~ ~ $10,031 ~ $30,093 reliability of HPCI power to the HPCS

.nd RCIC room pump room cooler.

cooling (RCIC pump continued operation is not dependent on room cooling.)

31 Create ability to ~NS estimate. $300,000 Not cost

~witch HPCI and Similar to SAMA 4, effective RCIC room fan power provide DC bus supply to DC in an cross-ties.

SSO event.

E.2-44

Attachment 1 Grand Gulf Nuclear Station Page 61 of83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation Analysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty 124. Increase Eliminated failure of ..:..:...:..:.. ..-

106% "I A no/ 17.1%')n.2°' 18.7%')01 .2°~ $142.782 -

~ ~

$428.345 -

Reliability of lhe instrument air $137,842 $413,527

.nstrument Air 34 Modify eNS estimate. More $1,200,000 Not cost procedure/hardware ..han just procedure. effective to provide ability to align diesel power to more air compressors 35 Replace service ~NS estimate. $1,394,598 Not cost and instrument air effective compressors with more reliable

~ompressors which have self-contained

~ir cooling by

$haft-driven fans 125. Backup Nitrogen Eliminated operator 5.9%~ 0.1%~ O.O%~ $46.925 - $140.775 -

toSRV failure to install air $4Q,614 $121,841 bottles 36 Install nitrogen Plant-specific cost $1,722,706 Not cost bottles as backup gas ~stimate. effective

~upply for safety relief

~alves.

E.2-45

Attachment 1 Grand Gulf Nuclear Station Page 62 of83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation

!Analysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty 12&. Improve 33 7 0A A~ "'01 12 90A"a A O/~ 13.3%"e."0<:, $311,721 -

Eliminated failure of ~-Y". ..:............._. I

$935,163 -

~vailability of SRVs non-ADS SRVs $300,631 $901,893

.nd MSIVs

~7 Improve SRV and leNS estimate. $1,500,000 Not cost MSIV pneumatic effective components.

127. Improve 125%"or:.ol- 30.9%,)?JI~I- ~

Eliminated the failure ~-....-.-....-'V -

34 1% ')n nOI

......... ,v $205,532 - $616,596 -

Suppression Pool pf flow to the RHR $205,223 $615,669 Cooling heat exchangers 38 Install an CNS estimate. $5,800,000 Not cost independent method effective pf suppression pool cooling.

28. Increase Eliminated failure of 17.8% ')~:e~<:. ~5".e°l- 50.2%.5J1 .70<:' ~

$297.180 - $891,540 -

IAvailability of ~ooled flow from $288,437 $865,312 Containment Heat RHR pump A and B Removal 39 Procedural Procedural range $25,000 Retain IChange to cross-tie !estimate.

Iopen cycle cooling lSystem to enhance

\Containment spray lSystem E.2-46

Attachment 1 Grand Gulf Nuclear Station Page 63 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation IAnalysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty

~1 Use the fire water Similar to Phase II $1,950,000 Not cost

~ystem as a backup SAMA 26, implement effective

~ource for the drywell modifications to allow

~pray system manual alignment of

~he fire water system ko RHR heat

!exchangers.

~9. Decay Heat Eliminated failure of 17.8%~.eo'1.<I5.6%1:-1.e OL 50.2%I:A .7~L $297,296 - $891,888 -

- $288,55Q $865,649 Removal Capability RHR spray Drywell Spray 40 Install a passive eNS estimate. $5,800,000 Not cost kirywell spray system effective

~o provide redundant kirywell spray method.

~O. Increase 4.4%~ ~~e.eOL 13.5%-17.~01,;; $230,917 -

IAvailability of the Eliminated failure of HPCS and RCIC

$76,972 -

$1Q7,899 $323,696 K:ST ~uction

~2 Enhance Procedure with $200,000 Retain procedures to refill !engineering and CST from If.raining range kiemineralized water estimate.

pr service water Isystem.

E.2-47

Attachment 1 Grand Gulf Nuclear Station Page 64 of83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation

~nalysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty

~1. Filtered Vent to Reduced the 0.0% 31.6%'la.A~L ~'1~.~0';. $117.984 - $353.952 -

Increase Heat baseline accident $8Q,92Q $242,759 Removal Capacity progression source for Non-ATWS Il.erms by a factor of 2 Events

~3 Install a filtered eNS estimate. $1,500,000 Not cost

~ontainment vent to effective provide fission product scrubbing

~2.Reduce Eliminated failure of O.O%~ 18.8%'ln.,?~1 ~

19 9% 'In ._v

'l01 $62,524 - $187,571 -

Hydrogen Ignition hydrogen igniters $142,455 $427,365 44 Provide Plant-specific cost $2,665,123 Not cost post-accident ~stimate. effective containment inerting

~apability.

145 Install a passive Plant-soecific cost $760,000 Not cost hydrogen control !estimate.MOAtiGelio effective Isystem.

I/~AlAA -In\

1""""

,.u.......

~

4- 4-.... :...

......... ....... ,.........4-

~

"~,,

n

.tI'7an nnn E.2-48

Attachment 1 Grand Gulf Nuclear Station Page 65 of83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation

~nalysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty

~3. Controlled Eliminated failure of 1.3%~ 3.1%&:4% 3.5%~ $21.208 - $63,623 -

~ontainment ~ir-operated valves to $31,Q8Q $Q3,24Q

~enting open

~6 Provide passive eNS estimate. $1,000,000 Not cost overpressure relief by effective changing the lContainment vent

~alves to fail open and improving the strength pf the rupture disk 147 Enable manual Oyster Creek (SAMA $150,000 Not cost operation of all 84) estimated that it effective containment vent would cost $150,000 valves via local o add handwheels in

!Controls IIohe reactor building tc ppen AOVs in the

!Current vent path.

~4.ISLOCA Removed alllSLOCA 0.0%< Q.1% 0.1%< Q.1% 0,1%< Q.1% lm...-$77- $385~

initiators 148 Increase [CNS estimate. $100,000 Not cost

~requency of valve effective leak testing to reduce ISLOCA frequency E.2-49

Attachment 1 Grand Gulf Nuclear Station Page 66 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation

~nalysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty 50 Revise EOPs to ~NS estimate. $50,000 Not cost improve ISLOCA effective identification 51 Improve operator ~NS estimate. $112,000 Not cost raining on ISLOCA effective

~oping

~5. MSIV Design Eliminated failure of O.O%~ O.1%~ O.O%~ l§... ,.

~-tnn')-t

.... ,......... llQ.... $3Q,QQ3 the MSIVs to close or remain closed

~9 Improve MSIV ~NS estimate. $1,000,000 Not cost

~esign to decrease effective

~he likelihood of

~ontainment bypass

~cenarios.

E.2-50

Attachment 1 Grand Gulf Nuclear Station Page 67 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation Analysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty

36. SLC System Eliminated failure to 0.1%~ 0.1%-h-7% 0.1%-h-7% $590 - $1,771 -

initiate SLC and $1Q,616 $31,849 failures of alternate boron injection (ASI) 52 Increase boron CNS estimate. $50,000 Not cost concentration in the effective 6LC system [Reduced time required to achieve shutdown provides increased margin in the accident imeline for successful initiation of SLC]

37. SRV Reseat Eliminated the 4.2%~ 3.9%~ 4.1%~ $46.458 - $139,373 -

initiator for SRVs $29,1Q8 $87,324 inadvertently being

~pen and basic

~vents for stuck open SRVs E.2-51

Attachment 1 Grand Gulf Nuclear Station Page 68 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation Analysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty 53 Increase safety CNS estimate. $2,200,000 Not cost relief valve (SRV) effective reseat reliability to

~ddress the risk

~ssociated with

~ilution of boron

~aused by the failure of the SRVs to reseat

~fter standby liquid

~ontrol (SLC) injection

38. Add Fire Eliminated fire CDF n/a n/a n/a $32.613 - $97.840 -

Suppression(1 ) rrom the critical $34,115 $1Q2,345 switchgear rooms.

~4 Add automatic eNS estimate. $375,000 Not cost

~re suppression effective

~ystems to the

~ominant fire zones E.2-52

Attachment 1 Grand Gulf Nuclear Station Page 69 of83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation Analysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty

39. Reduce Risk Eliminate fire CDF nfa nfa nfa $134,004 - $402,011 -

from Fires that ~rom the main control $14Q,174 $42Q,521 Require Control room.

Room Evacuation(1) 55 Upgrade the CNS estimate. $786,991 Not cost

~SDS panel to include effective

~dditional system controls for opposite division.

40. Large Break 3.3%742k ~~e.50L 14,5%"'7.5°~ $71,344 - $214,031 -

LOCA Eliminated Large Break LOCA

$319,124 $948,372 56 Provide digital Duane Arnold $2,000,000 Not cost arge break LOCA estimated that this effective protection to identify modification would

~ymptomsfprecursors cost at least $2M.

of a large break LOCA (a leak before break)

E.2-53

Attachment 1 Grand Gulf Nuclear Station Page 70 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation Analysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty

41. Trip/Shutdown Reducing all initiating 5.7%M% 6.1%fih.7% 6.5%~ $65.829 - $197.486 -

Risk events except pipe $6:2,37:2 $187,117 breaks, floods, and LOSP by a factor of

~JO%

57 Generation Risk eNS estimate. $500,000 Not cost Assessment effective implementation into plant activities (tripl shutdown risk modeling).

142. Increase Eliminated failure of 1.5%~ 1.6%~ 1.6%~ $16.787 - $50.362 -

~ va iI ability of SSW SSW Pump House $15,Q71 $45,:21 :2 Pump House Ventilation Wentilation System 58 Increase the Hardware $100,000 Not cost raining emphasis and modification range effective provide additional ~stimate.

control room indication on the pperational status of

~SW pump house

~entilation system.

E.2-54

Attachment 1 Grand Gulf Nuclear Station Page 71 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation

~nalysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty

43. Increase Eliminated failure of 4.5%4:4% 5.2%M% 5.5%M% $53.348 - $160.043 -

recovery time of SSW to the LPCS $40,452 $121,357 ECCS upon loss of room cooler SSW 59 Increase operator Procedure with $50,000 Retain

~raining for alternating training range pperation of the low estimate.

pressure ECCS pumps (LPCI and LPCS) for loss of SSW scenarios.

44. Additional Eliminated failure of 17.8%,)7.5~L .47.1 %~3.2~L --:..........J!..........

51 9% r::.a "01 $302.479 - $907,437 -

~ - IV Containment Heat ~uppression pool $298,121 $894,362 Removal ~ooling and

~ontainment spray

~ystems

~O Install an Plant-specific cost $4,352,023 Not cost additional method of estimate. effective heat removal from containment.

E.2-55

Attachment 1 Grand Gulf Nuclear Station Page 72 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 2 Summary of Phase II SAMA Candidates Considered in Cost-Benefit Evaluation

~nalysis Case (bold) Assumptions CDF PDR OECR Internal and Internal and GGNS Cost Conclusion SAMA Number and Reduction Reduction Reduction External External Estimate Title Benefit Benefit with Uncertainty 145. Improve RHR Eliminated failure of 2.0%~ 6.4%~ 7.0%&-3% $37.751 - $113.252 -

Heat Exchanger RHR HX Cooler inlet $41,34Q $124,Q1Q Availability ~nd outlet valves 62 Add a bypass Plant-specific cost $2,831,652 Not cost around the RHR HX ~stimate. effective inlet and outlet valves 146. Improve RCIC Eliminated the failure 7.4%~ 3.1%~ 2.5%~ $68.227 - $204.681 -

Lube Oil Cooling to cool RCIC lube oil $3Q,8Q4 $Q2,983

~3 Add a redundant Plant-specific cost $1,803.463 Not cost path. .

RCIC lube oil cooling estimate

...I.

$1QQ,QQQ effective

.r _ ..

~-

1. These analysis cases only impact external events and have been evaluated differently as shown in Section E.2.3.

E.2-56 Grand Gulf Nuclear Station Page 73 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 3 Sensitivity Analysis Results Analysis Case (bold) Internal and Sensitivity Case 1, Sensitivity Case 2, GGNS Cost SAMA Number and Title External Benefit, Internal and Internal and Estimate 20 yrs Remaining, External Benefit, External Benefit, 7% Discount Rate 33 yrs Remaining, 20 yrs Remaining, 7% Discount Rate 3% Discount Rate

1. DC Power $373 548 ~~ ~ 5,e5e $576,161 - $888,203 $144,423

$171,775 1 Provide additional DC battery capacity 1$2 130 887~ 5~~, ~~~

2 - Replace lead-acid batteries with fuel cells $4,079,609$1,000,0 00 11 - Portable generator for direct current (DC) 1$1 278 211~"7~~,~~~

power: This SAMA involves the use of a portable

~enerator to supply DC power to the battery

~hargers during a station blackout.

12 - Portable generator for direct current (DC) 1$1 278 211~"7'" ~,~~~

power: This SAMA involves the use of a portable generator to supply DC power to the individual panels during a station blackout.

15 - Use DC generators to provide power to operate $1,428,000

he switchyard power control breakers while a 480-V AC generator could supply the air compressors for breaker support.

~. Improve Charger Reliability $12.073 $13,598 $16,847 $19,619 $26.499 $17,276

~ Add battery charger to existing DC system $90,000 13 Proceduralize battery charger high-voltage $50,000 shutdown circuit inhibit

3. Add DC System Cross-Ties $56,992 $73,056 $80.817 $105,875 $126.695 ~!?~,5?"7 E.2-57 Grand Gulf Nuclear Station Page 74 of83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 3 Sensitivity Analysis Results Analysis Case (bold) Internal and Sensitivity Case 1, Sensitivity Case 2, GGNS Cost SAMA Number and Title External Benefit, Internal and Internal and Estimate 20 yrs Remaining, External Benefit, External Benefit, 7% Discount Rate 33 yrs Remaining, 20 yrs Remaining, 7°k Discount Rate 3°k Discount Rate 14 Provide DC bus cross-ties $300,000

14. Increase Availability of On-Site AC Power 1$427 372 $~~9,3ge $658,057 - $1.014.787 -

$221,380 $186,814

~ Provide an additional diesel generator $20,000,000 8 Install a gas turbine generator with tornado $2,000,000 protection

5. Improve AC Power 1$144 502 ~~??,5~A $199.125 - $314,037 $222,495

$262,069

~ Improve 4.16-kV bus cross-tie ability $656,000 17 Provide alternate feeds to essential loads $656,000 Ctirectly from an alternate emergency bus

~. Reduce Loss of Off-5ite Power During Severe $84.222 $26,087 $130.037 $38,786 $200.424 $32,554 Weather 7 Install an additional, buried off-site power source. $2,485,000

7. Provide Backup EDG Cooling $77,842 $16,515 $119.534 $24,490 $184.429 $20,642 9 Use fire water system as backup source for $1.344.116100,000

~iesel cooling 10 Add new backup source of diesel cooling $2,000,000 E.2-58 Grand Gulf Nuclear Station Page 75 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 3 Sensitivity Analysis Results Analysis Case (bold) Internal and Sensitivity Case 1, Sensitivity Case 2, GGNS Cost SAMA Number and Title External Benefit, Internal and Internal and Estimate 20 yrs Remaining, External Benefit, External Benefit, 7% Discount Rate 33 yrs Remaining, 20 yrs Remaining, 7% Discount Rate 3°k Discount Rate

~. Increase EDG Reliability $45,508 $~O,~48 $68,544 $44,~28 $106, 156 $~8,279 14 Provide a portable EDG fuel oil transfer pump $1.477.188 100,000

9. Improve DG reliability $7,851 $2,181 $12.238 $3,249 $18,828 $2,718 16 Provide a diverse swing diesel generator air $100,000 start compressor

10. Reduce Plant-Centered Loss of Off-8ite $249,829 $78,558 $386,025 - $594,886 $95,522

~ower $113,849 18 Protect transformers from failure $780,000

11. Redundant Power to Torus Hard Pipe Vent $18,571 $10,788 $22,288 $15,502 $36,250 $13,894

~THPV) Valves 19 Provide redundant power to direct torus hard $714,000 pipe vent valves to improve the reliability of the direct torus vent valves and enhance the containment heat removal capability.

12. High Pressure Injection System $622 300 ~ -- .,- ,-

.... I:.QA n1" $931 ,595 - $1 ,444,539 -

$733,845

$901,578 20 Install an independent active or passive high $8,800,000 pressure injection system E.2-59 Grand Gulf Nuclear Station Page 76 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 3 Sensitivity Analysis Results Analysis Case (bold) Internal and Sensitivity Case 1, Sensitivity Case 2, GGNS Cost SAMA Number and Title External Benefit, Internal and Internal and Estimate 20 yrs Remaining, External Benefit, External Benefit, 7% Discount Rate 33 yrs Remaining, 20 yrs Remaining, 70/0 Discount Rate 3% Discount Rate

~1 Install a backup water supply and pumping $6,409,949

~apability that is independent of normal and

~mergency AC power

13. Extend RCIC Operation ~ $10,031 ~ $14,448 ~ $12,757 21 Raise HPCI/RCIC backpressure trip set points $200,000 HPCI backpressure trip setpoint has already been

'raised. This SAMA will evaluate raising the RCIC backpressure trip set point].

14. Improve ADS System 1$309948 It,)oo,10e $487,897 - $749.210 $360,320

$469,925 22 Modify automatic depressurization system $1,176,850

~omponents to improve reliability [This SAMA will add larger accumulators thus increasing reliability

~uring S80s].

15. Improve ADS Signals $61,907 $129,383 $95,021 $205,503 $146.622 $154,719 123 Add signals to open safety relief valves $1,500,000 Flutomatically in an MSIV closure transient.

16. Low Pressure Injection System $228 899 ~~~~,~e5 $313,538 - $495,104 $292,574

$331,005 24 Add a diverse low pressure injection system. $8,800,000

17. ECCS Low Pressure Interlock ~ $10,031 ~ $14,448 ~ $12,757 E.2-60 Grand Gulf Nudear Station Page 77 of83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 3 Sensitivity Analysis Results Analysis Case (bold) Internal and lSensitivity Case 1, Sensitivity Case 2, GGNS Cost SAMA Number and Title External Benefit, Internal and Internal and Estimate 20 yrs Remaining, External Benefit, External Benefit, 7% Discount Rate 33 yrs Remaining, 20 yrs Remaining, 7% Discount Rate 3°/c. Discount Rate

~5 Install a bypass switch to allow operators to $1,000,000 bypass the low reactor pressure interlock circuitry

~hat inhibits opening the LPCI or core spray injection

~alves following sensor or logic failures that preven1

~lIlow pressure injection valves from opening.

18. RHR Heat Exchangers ~')nk 1$205 483 .,.- -,---

')')'1 $289.487 - $454.437 $263,557

$290,595 26 Implement modifications to allow manual $1,950,000 alignment of the fire water system to RHR heat exchangers.

19. Emergency Service Water System Reliability $47,167 $37,903 $68.446 $54,031 $106,797 -$-~e,~-i

~7 Add a service water pump to increase $5,900,000

~vailability of cooling water 120. Main Feedwater System Reliability 1$133 927 ~~e~,~5~ $186,239 - $293,153 $202,163

$241,055 128 Add a motor-driven feed water pump $1,650,000 121. Increase Availability of Room Cooling 1$193,241 $-i75,1CC $293,599 - $453,934 $216,342

$265,739

~9 Provide a redundant train or means of $2,202,725

~entilation

~2. Increase Availability of the DG System $236,881 $75,988 $366,748 - $564,963 $94,669

~hrough HVAC Improvements $113,283 E.2-61 Grand Gulf Nuclear Station Page 78 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 3 Sensitivity Analysis Results Analysis Case (bold) Internal and lSensitivity Case 1, Sensitivity Case 2, GGNS Cost SAMA Number and Title External Benefit, Internal and Internal and Estimate 20 yrs Remaining, External Benefit, External Benefit, 7% Discount Rate 33 yrs Remaining, 20 yrs Remaining, 7°k Discount Rate 3°k Discount Rate

~O Add a diesel building high temperature alarm or $1,304,700

"edundant louver and thermostat.

~2 Diverse EDG HVAC logic $1,148,275300,000 33 Install additional fan and louver pair for EDG $6,000,000 heating, ventilation, and air conditioning 123. Increased Reliability of HPCI and RCIC ~ $10,031 ~ $14,448 ~ $12,757

~oom Cooling

~1 Create ability to switch HPCI and RCIC room $300,000 fan power supply to DC in an SSO event.

~4. Increase Reliability of Instrument Air $142 782 C1'~""7 ,-

.... ""',,,,,OAI") $207,764 - $323,995 $173,951

$201,172 34 Modify procedure/hardware to provide ability to $1,200,000 lalign diesel power to more air compressors 35 Replace service and instrument air $1,394,598

~ompressors with more reliable compressors which have self-contained air cooling by shaft-driven fans

~25. Backup Nitrogen to SRV $46,925 $40,614 $69,723 $62,050 $105,630 $49,828

~6 Install nitrogen bottles as backup gas supply fOI $1,722,706 lSafety relief valves.

12&. Improve Availability of SRVs and MSIVs 1$311 721 ~2~~,e2~ $490,501 - $753,264 $362,190

$472,257 E.2-62 Grand Gulf Nuclear Station Page 79 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 3 Sensitivity Analysis Results Analysis Case (bold) Internal and $ensitivity Case 1, Sensitivity Case 2, GGNS Cost SAMA Number and Title External Benefit, Internal and Internal and Estimate 20 yrs Remaining, External Benefit, External Benefit, 7% Discount Rate 33 yrs Remaining, 20 yrs Remaining, 7% Discount Rate 3% Discount Rate 37 Improve SRV and MSIV pneumatic $1,500,000 components.

27. Improve Suppression Pool Cooling $205 532 $~05 ,~~~ $289.567 - $454.559 $263,557

$29Q,595 38 Install an independent method of suppression $5,800,000 pool cooling.

128. Increase Availability of Containment Heat $297 180 ~"OO.A -

.... ---, ')7 $417.314 - $655.543 $369,722 Removal $4Q9,794 39 Procedural change to cross-tie open cycle $25,000

~ooling system to enhance containment spray system 41 Use the fire water system as a backup source $1,950,000 or the drywell spray system

29. Decay Heat Removal Capability Drywell S297 296 ~~ee,55~ $417.478 - $655.800 $369,866 Spray $4Q9,953

~O Install a passive drywell spray system to $5,800,000 provide redundant drywell spray method.

~O. Increase Availability of the CST $76.972 $1Q7,899 $107.295 $156,536 $168.805 $136,643

~2 Enhance procedures to refill CST from $200,000

~emineralized water or service water system.

31. Filtered Vent to Increase Heat Removal $117.984 ~e~,~~~ $141,057 $96,745 $229.628 $113,Q74 Capacity for Non-ATWS Events E.2-63 Grand Gulf Nuclear Station Page 80 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 3 Sensitivity Analysis Results Analysis Case (bold) Internal and $ensitivity Case 1, Sensitivity Case 2, GGNS Cost SAMA Number and Title External Benefit, Internal and Internal and Estimate 20 yrs Remaining, External Benefit, External Benefit, 7°J'o Discount Rate 33 yrs Remaining, 20 yrs Remaining, 70/0 Discount Rate 3% Discount Rate

~3 Install a filtered containment vent to provide $1,500,000

~ssion product scrubbing

~2. Reduce Hydrogen Ignition $62,524 $142,466 $74,751 $209,206 $121,687 $179,104 144 Provide post-accident containment inerting $2,665,123

~apability.

145 Install a passive hydrogen control system. $760,000

33. Controlled Containment Venting $21,208 $31,080 $29.982 $44,274 $47.032 $39,779 46 Provide passive overpressure relief by $1,000,000

~hanging the containment vent valves to fail open

~nd improving the strength of the rupture disk i4 7 Enable manual operation of all containment $150,000 Ivent valves via local controls

~4.ISLOCA J.ill...--$-77 illi...~ mL-$9&

148 Increase frequency of valve leak testing to $100,000 reduce ISLOCA frequency

~O Revise EOPs to improve ISLOCA identification $50,000 51 Improve operator training on ISLOCA coping $112,000

35. MSIV Design ~ $10,031 ~ $14,448 ~ $12,767 E.2-64 Grand Gulf Nuclear Station Page 81 of83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 3 Sensitivity Analysis Results Analysis Case (bold) Internal and $ensitivity Case 1, Sensitivity Case 2, GGNS Cost SAMA Number and Title External Benefit, Internal and Internal and Estimate 20 yrs Remaining, External Benefit, External Benefit, 7% Discount Rate 33 yrs Remaining, 20 yrs Remaining, 7% Discount Rate 30/0 Discount Rate 149 Improve MSIV design to decrease the likelihood $1,000,000 of containment bypass scenarios.

36. SLC System $590 $1Q,616 $935 $15,376 $1.434 $13,458 52 Increase boron concentration in the SLC $50,000 system [Reduced time required to achieve

~hutdown provides increased margin in the accident

~imeline for successful initiation of SLC]

~7. SRV Reseat $46.458 $2Q,1Q8 $70,303 $42,416 $108,781 $36,767

~3 Increase safety relief valve (SRV) reseat $2,200,000 reliability to address the risk associated with dilution of boron caused by the failure of the SRVs to reseat after standby liquid control (SLC) injection

38. Add Fire Suppression (1) N/A N/A N/A 54 Add automatic fire suppression systems to the $375,000

~ominant fire zones

~9. Reduce Risk from Fires that Require Control N/A N/A N/A

~oom Evacuation (1) 65 Upgrade the ASDS panel to include additional $786,991 system controls for opposite division.

40. Large Break LOCA $71,344 ~2o(e,~~~ $96,872 $463,652 $153,256 $38Q,827 E.2-65 Grand Gulf Nuclear Station Page 82 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 3 Sensitivity Analysis Results Analysis Case (bold) Internal and $ensitivity Case 1, Sensitivity Case 2, GGNS Cost SAMA Number and Title External Benefit, Internal and Internal and Estimate 20 yrs Remaining, External Benefit, External Benefit, 7% Discount Rate 33 yrs Remaining, 20 yrs Remaining, 7% Discount Rate 3°k Discount Rate 56 Provide digital large break LOCA protection to $2,000,000

'dentify symptoms/precursors of a large break LOCA (a leak before break)

~ 1. Trip/Shutdown Risk $65,829 $62,372 $98,663 $94,Q32 $152,952 $77,17Q 57 Generation Risk Assessment implementation $500,000

'nto plant activities (trip/shutdown risk modeling).

~2.lncrease Availability of SSW Pump House $16,787 $15,Q71 $25,193 $21,998 $39,045 $19,Q17 Wentilation System 58 Increase the training emphasis and provide $100,000 additional control room indication on the operational status of SSW pump house ventilation system.

43. Increase Recovery Time of ECCS upon Loss $53,348 $4Q,452 $79,555 $58,438 $123.453 $51,357 of SSW 59 Increase operator training for alternating $50,000 pperation of the low pressure ECCS pumps (LPCI

~nd LPCS) for loss of SSW scenarios.

144. Additional Containment Heat Removal 1$302479 ~')aQ,i'H $423,675 - $665,888 $382,Q38

$423,739 60 Install an additional method of heat removal $4,352,023 from containment.

45. Improve RHR Heat Exchanger Availability $37,751 $41,34Q $52,253 $58,2QQ $82,330 $53,263 62 Add a bypass around the RHR HX inlet and $2,831,652 outlet valves E.2-66 Grand Gulf Nuclear Station Page 83 of 83 Applicant's Environmental Report Operating License Renewal Stage Table E.2- 3 Sensitivity Analysis Results Analysis Case (bold) Internal and $ensitivity Case 1, Sensitivity Case 2, GGNS Cost SAMA Number and Title External Benefit, Internal and Internal and Estimate 20 yrs Remaining, External Benefit, External Benefit, 7°k Discount Rate 33 yrs Remaining, 20 yrs Remaining, 7% Discount Rate 3% Discount Rate 146. Improve RCIC Lube Oil Cooling $68,227 $3Q,8Q4 $107,553 $48,447 $165.113 $37,264 63 Add a redundant RCIC lube oil cooling path. $1,803,4631 QQ,QQQ

1. These analysis cases only impact external events and have been evaluated differently as shown in Section E.2.3.

E.2-67

Attachment 2 to GNRO*2012/00144 Revised Reference 2 RAI Responses to Reflect SAMA Reanalysis to GNRO-2012/00144 Page 1 of 9 RAI1e Differences exist within the license renewal application among quantitative results for CDF, release category frequencies, and Risk Reduction Worth (RRW). The total CDF was presented as 2.05E-06 per year, from the sum of contributions by initiator (Table E.1-1) and sum of the release frequencies (Table E.1-8), and 2.92E-06 per year from the sum of the accident classes (Table E.1-7). The applicant's submittal states that the 2.9E-06 value is higher than the others due to non-minimal cutsets, which result from quantifying at the sequence level. Although some difference is expected, the difference of approximately 40% appears to be unusually large for this cause. Further, the sum of the release category frequencies would be expected to be higher since it is also the res ult of a sequence by sequenc e quantification. The CDF contribution from various failures implied by RRW values in Table E.1-2 are also significantly different in some cases from those given in Table E.1-1 or Table E.2-2. For example:

Table E.1-1 showed the CD F initiated by loss of offsite power (LOSP) as 14% of the total CDF, yet Table E.1-2 indicated a RRW value of 1.6289 for LOSP, which corresponds to a 38.6% contribution.

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

Case 22 on im proved availability of the diesel generator system through heating, ventilation, and air conditioni ng (HVAC) improvements was stated to be evaluated by eliminating HVAC failure in diesel generator rooms which results in a 9.2% reduction of CDF. Basic event X77-FF-CFSTARTU, "X77 common cause start failures," has a RRW of 1.2754, which corresponds to a 21.6% reduction in CDF.

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

In light of these differences among results, further support for the validity of the model quantification (i .e., CDF, release category frequencies, and RRW) in the SAMA analysis is needed. Provide reasons for these differences and more details on how the quantificati on was performed for each situation, incl uding exam pies related to this request. Describe specific contributions to the approxim ate 40% difference in CD F, such as some of the non-m inimal cutsets or other reasons. Justify use of the lower CDF, rather than the higher C DF, for determining cost risk in the SAMA analysis.

Revised Response to RAI1e The CDF values in tables E.1-1. E.1-7 and E.1-8 are the same in the revised SAMA analysis (see Attachment 1 of this letter).

Tho "Iowor CDF" bltili20E1 for tho SAMA aRalysis is basoE1 OR tAO GG~~S levol 2 FRoE1ol. Tho "highor COP" SOOR iR SOFRO of tho tablos is baseE1 OR tho GGNS 10'1011 FRoE1ol. SiRso tho SAMA aRalysis ro~blires tho releaso fro~bloRsios froFR tho 10'101 2 GGNS FRoE1ol, it wObllE1 Rot bo feasible to f)orforFR a SAMA aRalysis with oRly a 10'101 1 FRoE1el.

TAO total CDF fraFR tAO level 2 moEielbltilizeEi for the GGNS SAMA aRalysis is 2.0eE Oe WAOR oash of tho 13 roleas 0 sategories is solveE1. This FRoE1el aRE1 ~blaRtifisatioR FR othoE1 wore blsoE1 for the basoliRe aRE1 iREiivi E1b1al SJ\MA aRalysis sasos. The iRitiator sORtribbltioRs frOFR tAis FRoE1ol aRE1 ~blaRtifisatioR FRethoE1 are f)reseRteE1 iR Table E.1 1 aRE1 the SblFR of the release fre~bleRsies is f)rosoRtoE1 iR Tablo e.1 8. Tho SBO aRE1 ATWS sORtribbltioRs iR Tablo e.1 1 aro oxsof)tioRs.

The Table E.1 1 valble for S 80 'oVas af)f)roxiFRateE1 by FRblltif)lyiRg the total CDF obtaiRcE1 by to GNRO-2012/00144 Page 2 of9 ql:JantifyinJ the le'l el 2 model (2.05E 06 per year) by the persentaJe sontribl:Jtion to COF from SQO seql:Jenses in the level 1 model. The vall:Je for AT\A/S '....as ebtained in the same manner.

These approximations are pro'/ided to reflest the relative maJnitl:Jde of the COF sontribl:Jtion from SQO and AWlS seql:Jenses when sompared to the total COF and to the COF sontribl:Jtions from otRer types of seql:Jenses.

The vall:Jes in Table E.1 7 and the RR-\O/ sorrelations in Table E.1 2 *....ere obtained from assident seql:Jense level ql:Jantifi sation of tt:\e level 1 model at a trl:Jnsation limit at 1E 12/yr. It is asseptable to provide some information from the level 1 modelbesal:Jse the vall:Jes in Table E.1 7 are iIIl:Jstrative in natl:Jre and are not l:Jsed in the SAMl\ analysis. Also, tt:\e RRW sorrelations in Table E.1 2 are l:Jsed to enSl:Jre SAMAs have been identified for hiJt:\ risk sontribl:Jtors, bl:Jt the mmst RR'N vall:Jes are not Jermane or siJnifisant. The note beneath Table E.1 7 is misleadinJ.

The total CDF from tt=le level 1 model presented in Table E.1 7 is sliJhtly hiJher tt=lan the sinJle top soll:Jtion in whish non minimal Sl:Jtsets are sl:Jbsl:Jmed. ER Table E.1 7 is shanJed as shown below with strikethrol:JJt=l for deletions and l:Jnder line for additiens.

~Jote: The total CDF is not tt=le same as the baseline sinale toe soll:Jtion CDF in Table E.1.1 dl:Je to non minimal Sl:Jtsets sreated when ql:Jantifyi nJ at the seql:Jense level.

The resl:Jlts SRol:Jld not be sompared direotly sinse one resl:J1t is frem tt=le level 1 model and one is from the le'lel 2 medel. The differenses in persent8Je sontribl:Jtions are dl:Je to the followinJ.

1. Calsl:Jlations are approximated in CAFTA l:JSinJ a "min Sl:Jt l:Jpper bOl:Jnd" teshniql:Je and this approximation sarries l:Jnsertainties. 'Nhen handli nJ split frastions or other larJe probabilities like those in the level 2 model it oan insrease or deorease sontribl:Jtions.

2. The level 2 model was ql:Jantified l:JsinJ a ONE TOP ql:Jantifisation (i.e., all assident seql:Jenses sontribl:JtinJ to eash release sateJory are ql:Jantified at one time) whereas the level 1 model was ql:Jantified l:JSinJ an assident seql:Jense level ql:Jantifisati on (i.e.,

east=l seql:Jense is ql:Jantified i ndividl:Jally and resl:JltinJ Sl:Jtsets are merJed). The assident seql:Jense level ql:Jantifi sation san lead to m ore non minimal Ol:Jtsets wt=lioh may st:\anJe tRe persent sontribl:Jtions and affests the overall base "CDF" nl:Jmber.

3. The level 2 LOSP resoveries in tt=le Sl:Jtsets are different than the le'/el1 resoveries, whioh is 10werinJ the persent sontribl:Jtion of an S80 in the level 2 model.

Specific responses to the bullets in the RAI follow.

Table E.1-1, which lists the percent contributions to the level 2 model, shows an LOSP-initiated contribution of 39.5%. which compares favorably with the RRW value presented for LOSP~. Table E.1-2, which is the RRW correlations of the level 1 GGNS model, indicates a slightly different Ai§Aef- LO SP-initiated contribution. This is due to the fact that the level 2 model has different offsite power recoveries which affect the percentage contribution of the LO SP initiator.

Case 1 was evaluated by eliminating the SSO cutsets in the level 2 model and results in a CDF reduction of 37.1% which compares favorably with the SSO contribution of 36.6% in Table E.1-1. The, wRile the RRW CDF contributions listed in Table E.1-2 are based on the level 1 model. Also, the Table E.1 1 S80 vall:Je is an approximation as dessribed above.

The RRW of 1.2754 for basic event X77-FF-CFSTARTU, "X77 common cause start failures," is based on the level 1 model. Case 22 on im proved availabil ity of the diesel generator system through heating, ventilation, and air conditioning (HVAC) improvements which results in a 23.9% ~ reduction is based on the level 2 model. The GGNS level 1 model and level 2 models are expected to have differences in the risk profile.

to GNRO-2012/00144 Page 3 of9

The CDF reduction for case 46 given in Table E.2-2 of 7.4% 4:-79k was based on the level 2 model. The RRW given for basic event E51-043-G, "Lube oil cooling line hardware failure," in Table E.1-2 of 1.0839 is based on the G GNS level 1 model.

The GGNS level 1 model and level 2 models are expected to have differences in the risk profile.

RAI2e Figure E.1-1 indicates that negligible releases (NCE or NCF for no containment failure) account for 44% of the total CDF. Identify the CET end states that comprise this release category and how the frequency for this release category was determined.

Revised Response to RAI 2e The Figure E.1-1 label for negligible releases contains a typographical error. NCE should be identified as NCF. or Intact Containment. See change to ER figure E.1-1 below with strikethrough for deletions and underline for additions.

Intact Containment Negligible (NCF NCE) 1.37E-06 8.73E 07 47% 44%-

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

The frequency for this release category was determined by ql:JaRtifyiRg the" OK" gate iR the CI\FTI\ fal:Jlt tree whish seRsists of all the C ET eRdstates labeled" OK" subtracting the sum of the other 12 release categories from the total level 1 CDF.

RAI3b Section 4.21.5.4 indicates that seism ic risk is negligible in the estimation of external events multiplier. The August 2010 report, "Generic Issue 199 (GI-199), entitled Implications of Updated Probabilistic Seismic Hazard Estimates in Central and Eastern United States on Existing Plants, shows a decrease in the GGNS seismic CDF when the 2008 United States Geological Survey (USGS) seismic hazards curve is used compared to the seismic CDF resulting from the 1994 Lawrence Livermore National Laboratory hazard curves but an increase compared to the seism ic CDF based on the Electric Power Research Institute (EPRI) hazard curves. For the simplified approach to estimate the CDF from a seismic margins analysis using the latest published US GS seismic hazards information, GGNS seismic CDF may be about or slightly less than 10*s/year. Discuss the impact of the aforementioned considerations on the SAMA analysis.

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

high winds, floods, and other external events contribute less than 1E-06 per year, to GNRO-2012/00144 Page 4 of 9

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

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

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

For GGNS, the sum of the unscreened fire zone CDF values is approximately 8.92E-06 per year, which results in a multiplier of.4 & when com pared to the internal events CDF. In addition, a partially updated fire analysis resulted in lower CDF values for the analyzed com partments (see response to RAI 3.a), supporting use of a smaller multiplier. Nevertheless, to ensure a bounding analysis, an external events multiplier of 11 was used in the SAMA analysis.

If the GGNS seismic CDF was assumed to be 1E-05 based on the sim plified estimate of CDF using the latest publis hed United States Geological Survey (USGS) seismic hazards information, adding that to the sum of the unscreened fire zone CDF values would result in an external CDF of 1.89E-05 per year and a multiplier of Z4G.

Therefore, the external events mUltiplier of 11 used in the SA MA analysis more than compensates for a postulated increase in seismic CDF due to the latest published USG S seismic hazards information.

RAI3c Section 3.2.1 discusses conservatisms in the GGNS IPEEE fire analysis. Recent research and guidance reported in N UREG/CR-6850, specifically in the areas of hot short probabilities, fire ignition frequencies, and non-suppression probabilities, indicate that the fire analysis methodologies utilized for the Individual Plant Examinations (IPEs) may underestimate fire risk.

Provide assurance that consideration of this information is not expected to im pact the selecti on of cost beneficial SAMAs for GGNS. Discuss the impact on the evaluation of potential SAMAs for fire risk contributors in addition to the use of the external events multiplier.

Revised Response to RAI 3c The RAI indicates that NURE G/CR-6850 indicates the fire analysis methodologies utilized for the Individual Plant Examinations (IPEs) may underestimate fire risk. However, we believe that use of NUREG/CR-6850 methods may result in an overestimate of the fire risk. See Roadmap for Attaining Realism in Fire PRAs, NEI, December 2010 at ADAMS ML110210990 which concludes, "Based on the results and insights from industry fire PRAs, it has been identified that the methods described in NUREG/CR-6850/EPRI TR-1011989 contain excess conservatisms that bias the results and skew insights. While the prior FAQ process made some incremental progress in addressing areas of excessive conservativism, many more remain in need of enhancement." Thus, we do not believe that the results of the initial NUREG/CR-6850 analyses should be used to draw conclusions about the IPEEE fire risk estimates.

Nevertheless, the SAMA analysis includes conservatisms that compensate for the fact that the IPEEE fire risk estimate contains uncertainty and could be an underes timate. Most notably, as discussed in the response to RAI 3.b, a conservative external events multiplier of 11 was used in the SAMA analysis. This multiplier is more than double what would have been calc ulated using the sum of the unscreened fire zone CDF values from the IPEEE. In addition, GGNS is a to G NRO-2012/00144 Page 5 of9 newer, more spacious plant with better cable separation than older plants and the partially updated fire analysis mentioned in the res ponse to RAI 3.a resulted in lower CDF values for the analyzed com partments. Therefore, this multiplier is judged to adequately compensate for the impact of any lack of conservatism indicated by NUR EG/CR-6850.

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

1. SAMA 54, to add automatic fire suppression systems to the dominant fire zones was evaluated via analysis Case 38 which is described in more detail below. The bounding analysis in Case 38 indicates that removing all CDF (9.37E-7/yr) from the division 1 switchgear room fires would result in a benefit of about $98.000 102,000. This SAMA was estimated to cost at least $375,000 to implement.

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

Analysis Case 38 This analysis case (adding automatic fire suppression systems to the critical switchgear rooms) is an external events SAMA, which would not mitigate internal event risk. Many of the switchgear rooms have automatic CO 2 suppression systems. The Div I switchgear room in the control building that is a large contributor in the IPEEE is compartment CC202, which has a partial automatic sprinkler system. This SAMA would improve the reliability and effectiveness of that system. A bounding analysis was performed by assuming the SAMA would eliminate the contribution to fire CDF from fires in the critical switchgear room CC202. Since the total fire CDF is 2.74E-05/yr and the critical switchgear room fire CDF is 9.37E-07/yr, fires in the critical switchgear rooms contribute 3.42% of the total fire CDF.

The internal events model cannot be used to assess t he benefit from this external event SAMA. However, the consequences resulting from fire-induced core damage and internal event-induced core damage would be comparable. Since we have already estimated the maximum benefit from removing all internal event risk, the maximum benefit of removing all fire risk was estimated by reducing the maximum internal event benefit by the ratio of the total fire CDF to the internal event CDF. Since this SAMA analysis case would eliminate 3.42% of the total fire risk, the benefit for this SAMA analysis case was estimated to be 3.42% of the total fire benefit as shown below.

Given, Maximum internal benefit is $101.99574,873

=

Total fire CDF (including screened zones) 2.74E-05/rx-yr Internal events CDF = 2.93 ~E-06/rx-yr Maximum fire benefit =Maximum internal benefit x Total fire CDF/lnternal events CDF Maximum fire benefit =$101.995 74,873 x (2.74E-05/2.93 ~-06) =$953,687 QQ7,aaQ to G NRO-2012/00144 Page 6 of 9 SAMA case 38 benefit =3.42% x (Maximum fire benefit) =0.0342 x $953.687 997,559 SAMA case 38 benefit =$32.613 ~4, 115 Applying the uncertainty factor of 3, SAMA case 38 benefit with uncertainty =$32.613 34,115 x 3 =$97.840 102,345

2. SAMA 55, to upgrade the al temate shutdown sys tem panel to include additional cont rols for the opposite division was evaluated via analysis Case 39. The bounding analysis in Case 39 indicates that removing all CDF from control room fires (3.85E-6/yr) would result in a benefit of about $402.000 421,000. This SAMA was estimated to cost at least $786,991 to implement.

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

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

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

RAI3d For SAMAs 240-244, Table E.2-1 states:

"The IPEEE showed the risk from external flooding at GGNS is minor. Thus this potential modification is assumed not to be cost beneficial, which follows the same assumption in the NRC safety evaluation report."

The GGNS IPEEE (p. 116) includes the followi ng:

"Applying the new criteria, the bulk of the precipitation would occur over a shorter time frame, and markedly higher rainfall intensities would result. As a result, the GGNS site is not expected to be com pletely protected against external flooding without making some site modifications. Eval uation reveals that the foil owing site drainage/flood protection improvements would allow for adequate protection of the site against exter nal flooding due to the revised criteria. However, they are not necessarily the only combination of potential changes for consideration. Given the small probability of occurrence for the PUTP, as described in the preceding paragraph, the relative cost and benefit for potential improvements will be considered prior to implementation of any physical improvements."

While the staff review of the IPEEE as documented in the IPE EE SER did not require implementation of the items listed as SAMAs 240-244, this alone does not im ply that they should be eliminated from further consideration. In light of the second sentence from the GGNS to GNRO-2012/00144 Page 70f9 IPEEE above, provide a discussion of the cost benefit analys is concerning external flood modifications and its influence on conclusi ons of the SAMA analysis.

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

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

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

The maximum benefit from internal events, with a CDF of 2.93 ~-06/rx-yr is $101.995 74,673 and the probability of inundation of the G GNS site reported in the IP EEE is only 2.1 E-08/rx-yr. Thus, the maximum benefit that could be realized from these improvements is

$731 79&($2.193 ~with the uncertainty multiplier) and each individual SAMA would not eliminate 100% of the total external flooding risk. Since site drawings and docum entation would have to be updated to reflect each modification, the implementation cost for each proposed external flood SAMA would exceed the potential benefit. Therefore, external flood SAMAs 240 through 244 are not potentially cost-beneficial and the SAMA analysis conclusions are unchanged.

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

As provided in Section E.1.1, an uncertainty multiplier of 3 was applied to the cost-benefit analysis for potential SAMAs as a conservative selection to account for differences in the th 95 -percentile CDF to the mean CDF. With uncertainty applied, Table E.2-2 indicates that three potential SAMAs (Numbers 13,14, and 63) are within $10,000 of the stated cost estimate.

Comment on the representativeness of the stated cost estimates compared to actual costs at GGNS and provide estimates of cost margin for these potential SAMAs.

to G NRO-2012/00144 Page 8 of 9 Revised Response to RAI 7 SAMA 13 - Proceduralize battery charger high-voltage shutdown circuit inhibit This SAMA has a benefit of $36,21940,793 and an implementation cost estimate of $50,000, The implementation cost estimate is at the low end of the GGNS range for a procedure change with engineering or training required ($50k - $200k per ER Section E,2,3), Therefore, the implementation cost is likely to be larger at GGNS, Therefore, the expected margin between the benefit and actual impl ementation cost estimates is greater than $10,000, Also, the benefit was calculated by assum ing that this procedure change would remove all core damage contribution from battery charger failure, The procedure change would direct the operators to disable the charger high-voltage trip circuit when the batteries have fai led, allowi ng the chargers to continue to supply power, This procedure change could not possibly remove all core damage contribution from charger failure because the chargers will still have a random failure probability and the human action will also have a failure probability, Since the estimated cost of implementation exceeds the benefit, SAMA 13 is not cost-beneficial.

SAMA 14 - Provide a portable EDG fuel oil transfer pump This SAMA has a benefit of $136,52 5 91,044 and a refined, plant- specific aR implementation cost estimate of over $1,000,000, $100,000, The imJ=)lemeRtatieR Gest estimate is at the low eRd of the FaRle fuF hOFdwaFe GhoRles, This modification would requi re pipi ng changes to the safety-related diesel fuel oil sys tem to permit hook-up of the portable pum p, TheFefuro, the desilR oRd im J=)lemeRtatiOR of this modifiootioR would Gost mOFe thOR $200,000. Thus, the margin between the benefit and actual implementation cost estimates is greater than $10,000, Since the estimated cost of implementation exceeds the benefit, SAMA 14 is not cost-beneficial.

SAMA 63, Add a redundant RCIC lube oil cooling path This SAMA has a benefit of $204,681 92,683 and a refined, plant- specific aR implementation cost estimate of almost $2,000,000, $100,000, Tho im J=)lemeRtatioR eost estimate is at the 10'011 eRd of the FaRlo fuF haFdwaFe GhaRles, This modification would require piping changes to a safety-related system. TheFefuFO, the desilR oRd imJ=)lemeRtotioR of this modifieatioR would east mOFe thaR $200,000, Thus, the margin between the benefit and actual implementation cost estimates is greater than $10,000.

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

RAI8a For certain SAMAs considered in the GGNS Environmental Report, there may be lower-cost alternatives that could achieve much of the risk reduction. In this regard, provide an eval uation of the following S AMAs:

Phase II SAMA Numbers 30,32, and 33 for adding or enhancing Emergency Diesel Generator (EDG) HVAC hardware were considered for basic events involving EDG HVAC failures. SAMA Numbers 30 and 33 involve expensive hardware modifications, Evaluate the possibilities of opening doors and use of portable fans and ducts, SAMA Number 32 calls for adding diverse EDG HVAC logic, Consider procedures for operators to manually initiate EDG HVAC if the existing automatic logic fails, If no alarms are expected for any of these failures, procedures for to G NRO-2012/00144 Page 90f9 the plant auxiliary operators to check on any automatic start of the EDG could allow HVAC failures to be discovered and might eliminate the need for alarms.

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

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

The benefit with uncertainty for analysis case 22, which eli minates failure of cooling for the three diesel generator rooms, is $710,643 227,9i3. The G GNS range for a procedure change with engineering or training required is $50k - $200k per ER Section E.2. Since the cost of the procedure change is less than the potential benefit, a S AMA is retained to revi se procedures to direct that the operator monitoring a running diesel ensure the ventilation system is running, or take action to open doors, or use portable fans.

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

RAI8b For certain SAMAs considered in the GGNS Environmental Report, there may be lower-cost alternatives that could achieve much of the risk reduction. In this regard, provide an eval uation of the following S AMAs:

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

Revised Response to RAI 8b SAMA 25 was evaluated assum ing that the new bypass switch would el iminate all possible ECCS permissive and interlock failures, resulting in a benefit with uncertainty of $Q 3Q,Q93.

Due to the logic, at least two interlocks would have to fail and require bypass to permit opening one train of low pressure injection valves (more if a common cause failure occurred) and at least four interlocks would have to be bypassed to perm it opening both trains of valves. With this level of complexity, it is expected that human reliability analysis would show that an action to use jumpers to bypass the interlocks would fail with a probability of 1.0. Since no tAe benefit would Ret- be realized, this SAMA would not be cost- beneficial.

Attachment 3 to GNRO*2012/00144 Release Mode Frequencies for Analysis Cases

Attachment 3 to GNRO-2012/00144 Page 1 of 4 Table 1 Release Mode Frequencies for Analysis Cases Release Modes Analysis Cases HIE HII HIL MlE MIl MIL UE UI UL LUE LUI LUL CDF MAXBENEFIT 1.04E-07 1.21E-08 9.21E-08 3.70E-07 1.81E-07 3.03E-07 4.05E-09 3.55E-08 4.44E-07 2.19E-09 2.12E-09 7.05E-09 2.93E-06

1. DC Power 5.47E-08 8.37E-09 8.53E-08 2.92E-07 1.72E-07 2.66E-07 4.04E-09 3.32E-08 1.82E-08 2.11E-09 2.11E-09 6.95E-09 1.84E-06

2. Improve Charger Reliabllitv 1.01E-Q7 1.21E-Q8 8.73E-08 3.63E-Q7 1.79E-Q7 2.93E-07 4.05E-Q9 3.55E-Q8 4.44E-Q7 2.17E-09 2.12E-09 7.05E-09 2.91E-06

3. Add DC System Cross-ties 9.22E-08 1.20E-08 5.52E-08 3.54E-Q7 1.73E-07 2.63E-Q7 4.05E-09 3.50E-08 4.42E-07 2.17E-09 2.11E-09 6.97E-09 2.82E-06

4. Increase Availability of On-Slte AC Power 5.36E-08 8.10E-09 7.99E-08 2.88E-07 1.68E-07 2.23E-07 4.04E-09 3.02E-08 1.73E-08 2.10E-Q9 2.08E-09 6.61E-09 1.70E-06

5. Improve AC Power 5.84E-08 1.12E-08 7.96E-08 3.10E-07 1.71E-07 2.09E-07 4.03E-09 3.24E-08 1.83E-08 2.11E-09 2.09E-09 6.88E-09 2.71E-06

6. Reduce Loss of Off-Slte Power During Severe Weather 9.29E-08 1.12E-08 9.06E-08 3.53E-07 1.78E-07 2.94E-07 4.04E-09 3.49E-08 3.57E-07 2. 17E-09 2.11E-09 7.01E-09 2.68E-06

7. Provide Backup EDG Cooling 9.20E-08 1.12E-08 8.86E-08 3.41E-07 1.76E-07 3.25E-07 4.04E-09 3.33E-08 3.28E-07 2.16E-09 2.12E-09 6.94E-09 2.71E-06

8. Increase EDG Reliability 1.01E-07 1.17E-Q8 9.02E-08 3.49E-07 1.80E-07 2.88E-07 4.05E-09 3.44E-08 4.10E-07 2.19E-09 2.09E-09 6.86E-09 2.81E-06

9. Improve DG Reliabllltv 1.02E-Q7 1.20E-08 9.21 E-08 3.69E-07 1.81E-07 3.03E-07 4.05E-09 3.55E-08 4.35E-07 2.19E-09 2.12E-09 7.05E-09 2.91E-06

10. Reduce Plant-Centered Loss of Off-Site Power 7.26E-08 9.54E-09 8.76E-08 3.20E-07 1.73E-07 2.75E-07 4.04E-09 3.38E-08 1.86E-07 2.13E-09 2.11 E-09 6.96E-09 2.20E-06

11. Redundant Power to Torus Hard Pipe Vent

!(THPV) Valves 1.04E-07 1.21E-08 8.73E-08 3.29E-07 1.81E-07 2.73E-07 4.05E-09 3.55E-08 4.43E-07 2.19E-09 2.12E-09 6.95E-09 2.93E-06

12. High Pressure Injection System 6.04E-08 4.92E-09 5.40E-09 2.91 E-07 6.35E-08 2.52E-08 3.95E-09 2.29E-09 1.30E-09 6.31E-10 3.65E-12 1.01E-10 1.36E-06

13. Extend RCIC Operation 1.04E-07 1.21E-08 9.21E-08 3.70E-07 1.81E-07 3.03E-07 4.05E-09 3.55E-08 4.44E-07 2.19E-09 2.12E-09 7.05E-09 2.93E-06

14. Improve ADS System 8.65E-08 1.19E-08 8.83E-08 3.31E-07 1.80E-Q7 2.21E-07 4.04E-09 4.80E-09 4.28E-07 8.68E-10 6.86E-11 5.51E-10 1.95E-06

15. Improve ADS Signals 1.02E-07 1.08E-08 9.29E-08 3.68E-07 1.71E-07 2.92E-07 4.40E-09 2.39E-09 4.27E-07 1.99E-09 3.65E-12 6.80E-09 2.75E-06

Attachment 3 to GNRO-2012/00144 Page 2 of4 Table 1 Release Mode Frequencies for Analysis Cases Release Modes Analysis Cases HIE HII HIL MlE Mil MIL UE LII UL LUE LUI LUL CDF

16. Low Pressure Injection System 8.04E-08 6.34E-09 1.10E-08 3.36E-07 7.52E-08 1.34E-07 3.97E-09 3.55E-08 1.85E-08 2.19E-09 2.12E-09 7.05E-09 2.60E-06

17. ECCS Low Pressure Interlock 1.04E-Q7 1.21E-Q8 9.21E-08 3.70E-07 1.81E-07 3.03E-07 4.05E-09 3.55E-08 4.44E-07 2.19E-09 2.12E-09 7.05E-09 2.93E-06

18. RHR Heat Exchangers 1.00E-07 6.13E-09 8.03E-08 2.31E-07 5.04E-08 2.38E-07 3.86E-09 3.19E-08 4.50E-07 2.13E-09 2.03E-09 6.66E-09 2.56E-06

19. Emergency Service Water System Reliability 1.01E-07 1.08E-08 9.11E-08 3.44E-07 1.57E-07 2.97E-07 4.00E-09 3.51 E-08 4.30E-07 2.17E-09 2.11E-09 7.02E-09 2.83E-06

20. Main Feedwater System Reliability 7.56E-08 1.20E-08 2.37E-08 3.16E-07 1.68E-07 1.72E-07 3.83E-09 2.39E-08 4.37E-07 1.84E-09 1.31E-09 4.52E-09 2.71E-06

21. Increase Availability of Room Cooling 9.18E-08 1.14E-08 6.36E-08 3.48E-07 1.64E-07 1.85E-07 4.04E-09 2.57E-08 4.37E-07 1.77E-09 1.51E-09 5.02E-09 2.41E-06 22.

Increas e Availability of the DG System Through HVAC Improvements 7.02E-Q8 9.41E-Q9 9.08E-08 3.36E-07 1.78E-07 2.76E-07 4.05E-09 3.50E-08 1.58E-07 2.14E-Q9 2.11 E-Q9 7.03E-09 2.23E-06

23. Increased Reliability of HPCI And RCIC Room Cooling 1.04E-07 1.21E-08 9.21 E-08 3.70E-07 1.81E-07 3.03E-07 4.05E-09 3.55E-08 4.44E-07 2.19E-09 2.12E-09 7.05E-09 2.93E-06

24. Increase Reliability of Instrument Air 9.90E-08 1.09E-08 8.44E-08 2.50E-07 1.68E-07 2.33E-07 4.02E-09 2.42E-08 4.38E-07 2.05E-09 1.46E-09 4.94E-09 2.62E-06

25. Backup Nitroaen to SRV 1.06E-07 1.26E-08 9.51E-08 3.74E-07 1.83E-07 3.11E-07 4.05E-09 3.90E-08 4.46E-07 2.42E-09 2.47E-09 8.21E-09 2.76E-06

26. Improve Availability of SRVs and MSIVs 8.64E-08 1.19E-08 8.82E-08 3.29E-07 1.80E-07 2.20E-07 4.04E-09 4.71E-09 4.27E-Q7 7.40E-10 6.86E-11 5.51E-10 1.94E-06

27. Improve Suppression Pool Cooling 1.00E-07 6.13E-09 8.03E-08 2.31E-07 5.04E-08 2.38E-07 3.86E-09 3.19E-08 4.50E-07 2.13E-09 2.03E-09 6.66E-09 2.56E-06

28. Increase Availability of Containment Heat Removal 8.13E-08 5.62E-09 5.52E-08 1.40E-07 3.25E-08 2.02E-07 3.86E-09 3.41E-08 4.49E-07 1.91E-09 2.12E-09 6.91E-09 2.41E-06

Attachment 3 to GNRO-2012/00144 Page 30f4 Table 1 Release Mode Frequencies for Analysis Cases Release Modes Analysis Cases HIE HII H/L MlE MIl MIL UE UI UL LUE LUI LUL CDF

29. Decay Heat Removal Capabillty-Drywell Spray 8.13E-08 5.62E-09 5.52E-08 1.40E-07 3.25E-08 2.02E-07 3.86E-09 3.41E-08 4.49E-07 1.91E-09 2.12E-09 6.91E-09 2.41E-06

30. Increase Availability of the CST 9.83E-08 7.04E-09 8.21E-08 3.60E-07 1.07E-07 2.76E-07 3.97E-09 3.16E-08 4.41E-07 2.05E-09 1.84E-09 6.15E-09 2.80E-06

31. Filtered Vent to Increase Heat Removal Capacity For Non-ATWS Events 1.04E-07 1.21E-08 9.21E-08 3.70E-07 1.81E-07 3.03E-07 4.05E-09 3.55E-08 4.44E-07 2.19E-09 2.12E-09 7.05E-09 2.93E-06

32. Reduce Hydrogen Ignition 5.33E-08 1.18E-08 2.13E-08 2.96E-07 1.67E-07 2.85E-07 3.99E-09 3.56E-08 4.25E-07 1.94E-09 2.12E-09 6.50E-09 2.93E-06

33. Controlled Containment Venting 1.03E-07 1.21E-08 9.21E-08 3.33E-07 1.80E-07 3.03E-07 4.05E-09 3.55E-08 4.44E-07 2.19E-09 2.12E-09 7.05E-09 2.89E-06 34.ISLOCA 1.03E-07 1.21E-08 9.21E-08 3.70E-Q7 2.12E-09 7.05E-09 2.93E-06 1.81E-07 3.03E-07 4.05E-09 3.55E-08 4.44E-07 2.19E-09

35. MSIV Design 1.04E-07 1.21E-08 9.21E-08 3.70E-07 1.81E-07 3.03E-07 4.05E-09 3.55E-08 4.44E-Q7 2.19E-09 2.12E-09 7.05E-09 2.93E-06

36. SLC System 1.04E-07 1.21E-08 9.21E-08 3.70E-07 1.81E-07 3.03E-07 2.33E-09 3.55E-08 4.44E-07 2.02E-09 2.12E-09 7.05E-09 2.93E-06

37. SRV Reseat 1.02E-07 1.13E-08 9.13E-08 3.54E-07 1.64E-07 3.00E-07 4.05E-09 3.55E-08 4.34E-07 2.17E-09 2.12E-Q9 7.05E-09 2.81E-06

38. Add Fire Suppression (1)

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

40. Large Break LOCA 1.03E-07 6.38E-09 9.21E-08 3.68E-07 6.65E-08 3.03E-07 3.87E-09 3.55E-08 4.44E-Q7 2.13E-09 2.12E-09 7.05E-09 2.83E-06 41.

Trip/Shutdown Risk 9.75E-08 1.18E-Q8 8.33E-08 3.40E-07 1.77E-07 2.76E-07 3.66E-09 3.21E-08 4.40E-07 1.93E-09 1.89E-09 6.30E-09 2.76E-06

Attachment 3 to GNRO-2012/00144 Page 4 of4 Table 1 Release Mode Frequencies for Analysis Cases Release Modes Analysis Cases HIE HII H/L MlE MIl MIL UE UI UL LUE LUI LUL CDF

42. Increase Availability of SSW Pump House Ventilation System 1.03E-07 1.20E-08 8.93E-08 3.69E-07 1.80E-07 2.86E-07 4.05E-09 3.51E-08 4.42E-07 2.19E-09 2.11E-09 7.00E-09 2.89E-06 143. Increase Recovery Time of ECCS Upon Loss of SSW 1.03E-07 1.19E-08 8.57E-08 3.69E-07 1.73E-07 2.45E-07 4.05E-09 3.55E-08 4.44E-07 2.19E-09 2.12E-09 7.05E-09 2.80E-06

44. Additional Containment Heat Removal 8.13E-08 5.62E-09 4.99E-08 1.40E-07 3.12E-08 1.87E-07 3.86E-09 3.16E-08 4.49E-07 1.91E-09 2.03E-09 6.51 E-09 2.41E-06

45. Improve RHR Heat Exchanger Availability 1.03E-07 1.04E-08 9.21E-08 3.38E-07 1.48E-07 3.03E-07 3.99E-09 3.55E-08 4.44E-07 2.17E-09 2.12E-09 7.05E-Q9 2.87E-06

46. Improve RCIC Lube Oil Cooling 9.71E-08 1.21E-08 9.12E-08 3.63E-07 1.80E-07 2.97E-07 4.05E-09 3.46E-08 2.04E-09 2.11E-09 6.98E-09 2.71E-06

,.. , 3.99E-07 These analysis cases only impact external events and have been evaluated as explained in response to RAI 3.e

Attachment 4 to GNRO*2012/00144 Response to Clarification RAls 2, 7.b, and 7.d to GNRO-2012/00144 Page 1 of 4 Clarification RAI 2 The initial response to RAI 1.e does not provide adequate information to explain the approximate 40% difference between the core damage frequency (CDF) from the Level 1 and Level 2 quantifications, specifically the requested, "Describe specific contributions to the approximate 400/0 difference in CDF, such as some of the non- minimal cutsets or other reasons." Relative to the three reasons given for the differences in results, elaborate on the following:

a. While there are uncertainties in the minimal cut set upper bound technique for cutset quantification, particularly when it involves terms that are close to 1, to the best of our knowledge, this always results in an overestimate of the true result and is most significant for large early release frequency (LERF) or other Level 2 calculations that usually have a large number of events involving values close to 1. Therefore, the minimal cut set upper bound technique for cutset quantification would not appear to be a contributor to the Level 2 C DF result being less than the Level 1 CD F. Please explain.

b. While it is expected that the Level 1 sequence by sequence calcul ation would result in non-minimal cutsets, the third paragraph of the RA I response in correcting the footnote to Table E.1-7 states, "The total CDF from the level 1 model presented in Table E.1-7 is slightly higher than the single top solution in which non- minimal cutsets are subsumed." This indicates that the elimination of non-minimal cutsets is not a major factor in the Level 2 result being lower. Could quantification of the One..

TOP Level 1 CDF model or alternatively combining all the Level 1 sequence cutsets and minimizing and then quantifying possibly justify what is termed "slightly" in the above quotation?

c. The response states "The level 2 LOSP recoveries in the cutsets are different than the level 1 recoveries, which is lowering the percent contribution of an S80 in the level 2 model." It is not clear what is meant by this. There should be a consistent evaluation of the recovery of the loss of offsite power (LOSP) in the two models. If it is meant that there is less credit for LOSP recovery in the Level 2 model because core damage has occurred, this should not impact the CDF. Please explain.

The difference in results from the two models leads to confli cting and inconsistent infor mation in the SAMA submittal. For example, Table E.1-1 says that the CDF contribution from LOSP is 14% of the CDF but the contribution from station blackout (S80) is 36%. Except for the relatively small contribution to LOSP from a consequential LOSP, the S80 contribution is a subset of LOSP contribution. Further, the Case 1 result, which is based on the same Level 2 model as the LOSP contribution discussed previously, indicates that S80 contributes 13.6% of the CDF. Again, the S80 contribution should be somethi ng less than the LOSP contribution.

Provide further support for the Level 2 model giving a valid result for the total CDF and explain differences from the Level 1 results using specific examples of these reasons incl uding requantification using different tec hniques or assumptions. Provide assurance that the Level 2 model result is not missing important sequences and/or c utsets.

to GNRO-2012/00144 Page 2 of4 Revised Response to Clarification RAI 2 At issue is the difference between the level 1 COF of approximately 2.92E-06/rx-yr and the level 2 COF of approximately 2.05E-06/rx-yr used as the reference value in the SAMA analysis. The total COF from the level 2 model utilized for the SAMA analysis is 2.05E-06/rx-yr when each of the 13 release categories (HIE, HII, HIL, M/E, MIl, MIL, LIE, LlI, LlL, LLlE, LLlI, LLlL, and 0 K) is solved. However, further investigation into this issue revealed that the 0 K gate in the level 2 model was not fully developed as a means to quantify the intact sequences. T he steps taken to assure the technical adequacy of the level 2 model, (including the self assessment, technical acceptance review and expert panel cutset review), which were applied to the other release categories, were not applied to the OK gate in the fault tree. The OK gate was only used as a place-holder for the residual core damage sequences that successfully avoid a release larger than the design basi s leakage and was not intended for quantification. Rather, the intact sequences must be quantified by subtracting the sum of the other 12 release categories from the total level 1 COF. However, these facts were not clearly documented in the level 2 analysis, nor were they identified during the technical transfer meeting. Thus, the SAMA analysis incorrectly used the 2.05E-06/rx-yr reference value obtained via quantification of all 13 release categories in the level 2 model. A condition report has been initiated within the corrective action process to document this error and ensure the OK gate in the level 2 model is not quantified in future applications of the level 2 model.

To correct the analysis, the SAMAs were OFe BeiA) re-analyzed using the level 1 COF as the reference value. Also, the impact of each SAMA on the level 1 COF was is BoiA) used to quantify the impact on the intact release category.

The SAMA reanalysis also used two alternate inputs which were the subject of sensitivity analyses for previous RAI responses. Using the alternate inputs within the reanalysis precludes the need for additi onal sensitivity analyses to address the RAI concerns.

1. The source term from Modular Accident Analysis Program (MAAP) case GG10500.

which was used in the sensitivity analysis described in response to RAI 2.d. was used in the reanalysis of the SAM As. See response to RAI 2.d in Reference 2 and response to clarification RAI # 4 in Reference 1.

2. The NCF (no containment failure) release category. using the source term from MAAP case GG 105020 as described in response to RAI 2.g. was used in the reanaly sis of the SAMAs. See response to RAI 2.g in Reference 2 and response to clarification RAI # 5 in Reference 1.

Also. in the SAMA reanalysis. a revised level 2 recovery rule file was used in the quantification of both the total COF and the individual release mode frequencies. The rule file was revised to address discrepancies (described below) identified during investigation into the C OF value differences. The discrepancies were corrected and an independent review was performed to ensure the recoveries are being appli ed as intended.

The following level 2 rule file discrepancies were addressed in the revised recovery rule file.

to G NRO-2012/00144 Page 3 of 4

4. Event NRS-DHLRT was changed from 1E-7 to 1E-6. In the level 2 rule file. this combination recovery event. representing fail ure to initiate suppression pool cooling and failure to initiate containment spray. did not meet the minimum of 1E-6 established for combination events. The probability for this event is correct in the level 1 rule file.

5. The level 2 LOSP rule applied to LOCA sequences caused by a stuck open relief valve (recovery event NRC-OSP-PSGO-L2l was changed to align with the other level 2 LOSP rules. Two lines of code are required to apply each L2 LOSP rule to ensure proper application. but the second line had been inadvertently om itted for the NRC-OSP-PSGO-L2 rule.

6. The level 2 LOSP recovery values were adjusted to remove double-counting of the time from the start of the accident until core damage. Since the cutsets to which a level 2 LOSP recovery is applied already have a level 1 LOSP recoverv applied. and the level 1 recovery is calculated from time 0 to the time of core damage. the level 2 recovery should only reflect the time from core damage unti I containment failure.

However. the level 2 LOSP recovery values were calculated from time 0 to the time of containment failure. Thus. new level 2 LOSP recovery values were calculated by dividing the previously-calculated level 2 LOSP value by the level 1 LOSP value.

The new SAMA reference CDF (2.93E-06/rx-yrl was calculated using the level 2 rule file and is slightly higher than the total CDF calculated in the level 1 analysis (2.91 E-06/rx-yrl. This slight difference is attributed to the minimal cutset upper bound technique of cutset quantific ation.

particularly involving terms that are close to 1. Since the release categorv frequencies are calculated using the level 2 rule file. and the NCF category frequency is calculated as the difference between the reference CDF and the sum of the release category frequencies. it is appropriate to calculate the reference CDF using the level 2 rule file.

This reanalysis sOl.lls not be sompletes in the reql.lires response time of 46 says. Thl.ls, the revises res\:Jlts ,..,ill be provises in a follow l.Ip letter by November 17,2012. \Nhen the resl.Ilts of the reanalysis are J3rovises, l.IJ3sates vers ions of the ER tabl es ans J3FO t/i Ol.lS Rl\1 FOSJ3onSes that are imJ3astes by the reanalysis will also be J3rovises.

Clarification RAI 7b SAMA 36, enhance DC power availability by providing a direct connection from the diesel generator, the security diesel, or another source to the 250 V battery chargers or other required loads, is said to be addressed by SAMA 27. This SAMA makes use of a portable generator.

Consider a SAMA that would provide the necessary connections but without the expense of a new portable generator, or explain why this is not feasible.

Revised Response to Clarification RAI 7b The DC power system provides control and switchi ng power for alternating current (AC)-

powered components and also provides a source of power for emergency components in station-blackout (S80) situations. In an S80, all off-site and normal on-site AC power has been lost so the emergency diesel generators are not available. Since GGNS does not have a to G NRQ-2012/00144 Page 4 of4 security diesel generator or another source of power, a portable generator is the only remaining option to enhance DC power availability in SBQ situations.

The benefit of providing a direct connection from the diesel generator to the chargers or other required loads in a non-SBQ situation is bounded by the benefit of anal ysis case 2. This analysis case found that the benefit (with uncertainty) of eliminating failure of the battery chargers is $36.219. The cost of providing a direct connection from a diesel generator to the chargers or other required loads is estimated to cost more than $100,000 (minimum hardware modification cost estimate). Thus, the proposed SAMA is not cost-beneficial.

CORsiEler=atioR of a Sl\Ml\ to pFO\'iEio a EliFOst sORRostioR fFOm aR ome~eRsy Eliesel §leReFatoF to the shaF§lOFS OF otheF FOql.liFeEi 10aEis iR a ROR &80 sitl.latioR is impasteEi by tt:le FoaRalysis boi R§I pFo\'iEleEi iR FespoRso to slaFifisatioR RAI 4 aREI, therofoFe, will bo Elissl.lsseEi iR that FospoRse .

Clarification RAI7d SAMA 74, provide capability for alternate injection via the reactor water cleanup (RWCU), is dispositioned as already installed on the basis or procedures that direct use of the RWCU for alternate shutdown cooli ng. The purpose of this SAMA is improved injection capability not heat removal. Consider the use of the RWCU system for injection, or explain why this is not feasible.

Revised Response to Clarification RAI7d The benefit of a SAMA to provide capability for alternate injection via RWCU is bounded by analysis case 12 which eliminated failure of HPCS. The benefit with uncertainty of analysis case 12 is $1,866,900.

Extensive modifications would be required to use the RWCU system for alternate injection.

Piping modifications and a source of water would be needed since the only existi ng RWCU suction source is the reactor pressure vessel itself. Key-locked switches would have to be installed to permit bypassing existing RWCU interlocks to permit use for injection. Also, the system has power dependencies with the other alternate injection systems which would have to be modified to obtai n significant benefit.

The scope of this modification is between what was considered in Phase II SAMA 61, "Install a backup water supply and pumping capability that is independent of norm al and emergency AC power" and Phase II SAMA 41, "Implement modifications to allow manual alignment of the fire water system to RHR heat exchangers." These SAMAs have implementation costs of

$6.409,949 and $1,950,000, respectively. Since the benefit is less than the estimated implementation cost. a modification to use the RWCU system for alternate injection would not be cost-beneficial.

CORsiEleFatioR of a Sl\Ml\ to l.Ise the RVVCU system foF alteFRate iRjestioR is im pasteEi by the FOaRalysis beiR§I pFo\'iEleEi iR FOSpORSO to slaFifisatioR R/\I 2 aREI, theFOfoFe, will bo Elissl.lsseEi iR that FespoRse.

GNRO-2012/00144, Reanalysis of Severe Accident Mitigation Alternatives

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GNRO-2012/00144, Reanalysis of Severe Accident Mitigation Alternatives

Text

SUBJECT:

REFERENCE:

Dear Sir or Madam:

Enclosure:

Conclusion:

Conclusion:

Conclusion:

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