NUREG-1742 

Vol. 2

Perspectives Gained 

From the Individual 

Plant Examination of 

External Events 

(IPEEE) Program 

Tables 

Final Report 

U.S. Nuclear Regulatory Commission 

Office of Nuclear Regulatory Research 

Washington, DC 20555-0001
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I I
NUREG-1742 

Vol. 2 

Perspectives Gained 

From the Individual 

Plant Examination of 

External Events 

(IPEEE) Program 

Tables 

Final Report 

Manuscript Completed: September 2001 

Date Published: April 2002 

Division of Risk Analysis and Applications 

Office of Nuclear Regulatory Research 

U.S. Nuclear Regulatory Commission 

Washington, DC 20555-0001 

,) REcG&
ABSTRACT 

On June 28, 1991, the U.S. Nuclear Regulatory Commission (NRC) issued Supplement 4 to Generic Letter 

(GL) 8 8-20, "Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities, 

10 CFR 50.54(f)," and NUREG-1407, "Procedure and Submittal Guidance for the Individual Plant 

Examination of External Events (IPEEE) for Severe Accident Vulnerabilities." Specifically, the NRC 

requested that each licensee perform an IPEEE to identify and report to the NRC all plant-specific 

vulnerabilities to severe accidents caused by external events. The external events to be considered in the 

IPEEE included seismic events; internal fires; and high winds, floods, and other (HFO) external initiating 

events including accidents related to transportation or nearby facilities and plant-unique hazards. All of the 

currently operating U.S. nuclear power plants have completed their assessments and submitted their analyses 

for NRC review. 

The objective of the NRC's IPEEE submittal reviews was to ascertain whether the licensees' IPEEE 

processes were capable of identifying severe accident vulnerabilities to such external events, and 

implementing cost-effective safety improvements to either eliminate or reduce the impact of those 

vulnerabilities. However, the reviews did not attempt to validate or verify the results of a licensee's IPEEE. 

The primary purpose of this report is to document the perspectives gleaned from the technical reviews of the 

IPEEE submittals. These include a description of the overall IPEEE process and findings; conclusions 

regarding the dominant risk contributors for the major areas of evaluation (i.e., seismic events, fires, and HFO 

events); an overview of plant improvements made by licensees as a result of the IPEEE program; a 

description of the overall strengths and weaknesses in the licensees' implementation ofthe IPEEE evaluation 

methodologies; and an assessment of the overall effectiveness in meeting the IPEEE objectives, including 

the extent to which licensees have met the intent of Supplement 4 to Generic Letter 88-20. Volume I of this 

report includes general IPEEE perspectives while Volume 2 includes detailed tables with plant-specific 

information relevant to the IPEEE program.

iii
Table of Contents 

A B STR A C T ........................................................................ iii 

L ist of T ables ...................................................................... vii 

1. IN TRO D U CTION ............................................................... 1- 1 

2. SEISM IC TA BLES .............................................................. 2 - 1 

3. FIR E TA B LE S .................................................................. 3 - 1 

4. HIGH WINDS, FLOODS, AND OTHER EXTERNAL EVENTS TABLES .................. 4- 1 

5. UNRESOLVED SAFETY ISSUES AND GENERIC SAFETY ISSUES TABLES ............ 5- 1

V
List of Tables

Table 2.1: Seismic review categories and evaluation approaches ............................ 2 - 2 

Table 2.2: Seismic CDF for plants performing a seismic PRA .............................. 2 - 5 

Table 2.3: Dominant risk contributors reported in seismic PRAs ............................ 2 - 7 

Table 2.4: Seismic outliers and improvements for PRA plants ............................. 2 - 12 

Table 2.5: Seismic containment performance for PRA plants .............................. 2 - 18 

Table 2.6: Plant capacity results from IPEEE SMA ...................................... 2 - 23 

Table 2.7: Seismic outliers and improvements for SMA plants ............................. 2 - 25 

Table 2.8: Containment performance for SMA plants .................................... 2 - 36 

Table 2.9: Relay evaluation ........................................................ 2 - 40 

Table 2.10: Soil evaluation ......................................................... 2 - 52 

Table 2.11: Non-seismic failures and human actions ..................................... 2 - 62 

Table 2.12: Seismic-fire interaction and seismic-flood interaction .......................... 2 - 72 

Table 2.13: Flux m apping system s ................................................... 2 - 87 

Table 3.1: Summary of basic plant information .......................................... 3 - 2 

Table 3.2: Sum mary of fire CDFs ..................................................... 3 - 5 

Table 3.3: Significant fire area CDFs .................................................. 3 - 8 

Table 3.4: Licensees' statements on, and definitions of, fire vulnerabilities .................... 3 - 33 

Table 3.5: Fire-related plant improvements ............................................. 3 - 49 

Table 3.6: Comparison of a set of past fire PRAs with respective IPEEE submittals.............3 - 80 

Table 4.1: Methodologies and results for the HFO external events ............................ 4 - 2 

Table 5.1: GSI-57, Fire protection systems impact on safety-related equipment ................. 5 - 2 

Table 5.2: Probable maximum precipitation data provided in IPEEE submittals ................. 5 - 5 

Table 5.3: Plant im provem ents ...................................................... 5 - 10 

Table 5.4: GSI-147, Fire-induced alternate shutdown/control room panel interactions ........... 5 - 11 

Table 5.5: GSI-148, Smoke control and manual fire-fighting effectiveness .................... 5 - 15 

Table 5.6: GSI-156, Systematic evaluation program ...................................... 5 - 23 

Table 5.7: GSI-172, Multiple system responses program ............................... 5 - 28 

Table 5.8: Sandia fire risk scoping study issues ......................................... 5 - 33

vii
1. INTRODUCTION

On June 28, 1991, the U.S. Nuclear Regulatory Commission (NRC) issued Supplement 4 to Generic Letter 

(GL) 88-20, "Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities, 

10 CFR 50.54(f)." That supplement described the objectives and overall logistics of the Individual Plant 

Examination of External Events (IPEEE) program, which addresses externally initiated events. In particular, 

the external events considered in the IPEEE program include seismic events; internal fires; and high winds, 

floods, and other (HFO) external initiating events involving accidents related to transportation and nearby 

facilities. The IPEEE program was intended as a means for licensees to identify potential vulnerabilities to 

severe accidents initiated by external events, and to conceive cost-effective improvements to ensure that 

plants do not pose any undue risk to public health and safety. 

Along with Supplement 4 to GL 88-20, the NRC issued NUREG-1407, "Procedure and Submittal Guidance 

for the Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities," in 

June 1991. In NUREG-1407, the NRC provided guidelines for conducting IPEEEs. Specifically, the 

guidance pertained to evaluations concerning the following external initiators: seismic events; internal fires; 

and high winds, floods, and other (HFO) external events, including accidents related to transportation or 

nearby facilities and plant-unique hazards. Subsequent to the publication of NUREG- 1407, the NRC issued 

Supplement 5 to GL 88-20 on September 8, 1995, to notify licensees of modifications to the recommended 

scope of the seismic portion of the IPEEE for certain plant sites in the eastern United States (EUS). 

The NRC received 70 IPEEE submittals covering all operating U.S. nuclear reactors. (Some submittals 

covered more than one unit at multi-unit sites with similar or almost identical plant designs.) The staff of the 

NRC's Office of Nuclear Regulatory Research completed 69 Staff Evaluation Reports (SERs) which 

document the staff's overall conclusions for each of the IPEEE reviews.1 Additional details on the plant

specific IPEEE review findings are presented in Technical Evaluation Reports (TERs) for each of the 69 

IPEEE submittals.2 Each TER discusses the strengths and weaknesses of the licensee's IPEEE submittal, 

particularly with reference to the guidelines established in NUREG-1407. The TERs also typically present 

(1) an overview of the licensee's IPEEE process and insights; (2) the review process employed for evaluation 

of the seismic, fire, and HFO events; (3) the dominant contributors to core damage frequency for fire, 

seismic, and HFO events; (4) licensee-identified vulnerabilities; (5) plant improvements made or planned as 

a result of the licensee's IPEEE process; and (6) an overall evaluation of the strengths and weaknesses of the 

IPEEE submittal. This report provides insights and perspectives gleaned from the reviews of all of the 

licensees' submittals. 

' One plant, Haddam Neck, was permanently shut down, so the staff suspended work on 

reviewing that plant's IPEEE submittal. 

2 The TERs in the seismic and fire areas were written by NRC contractors (i.e., Energy Research, 

Inc. (ERI), Brookhaven National Laboratory (BNL), and Sandia National Laboratories (SNL)). TERs in 

the HFO area were written by ERI (26 submittals) and RES staff (the balance of the submittals). Readers 

interested in specific plants can obtain the plant-specific SERs and TERs through the NRC's Agencywide 

Documents Access and Management System (ADAMS). (Include the plant name and "IPEEE" in the 

Title Contains block of the ADAMS Find window.) SERs that were issued prior to November 1999 are 

available to the public, for a fee, by contacting the NRC Public Document Room (PDR) librarian at (800) 

397-4209 or by e-mail to pdr@nrc.gov.

1-1
In developing this report, the staff sought to address each distinct, significant topic considered in NUREG

1407, including seismic events, fires, and HFOs, as well as the relevant IPEEE-related aspects of generic 

safety issues (GSIs) and unresolved safety issues (USIs). Volume 1 of this report includes general IPEEE 

perspectives, while Volume 2 includes detailed tables with plant-specific information relevant to the IPEEE 

program. 

In Volume 1, Chapter 1 covers the general background and objectives of the IPEEE program, while Chapter 

2 discusses the perspectives derived from the seismic portion of the IPEEE submittals, and includes 

comments regarding licensees' seismic probabilistic risk assessments (PRAs) and seismic margin assessments 

(SMAs). It also discusses information provided in seismic IPEEE submittals relevant to specific GSIs and 

USIs. 

Chapter 3 discusses the perspectives derived from the fire portion of the IPEEE submittals, and includes 

comments regarding licensees' fire PRAs and fire-induced vulnerability evaluation (FIVE) studies. It also 

discusses fire-related findings concerning specific GSIs and USIs, as well as issues arising from the fire risk 

scoping study conducted by Sandia National Laboratories (SNL). 

Chapter 4 presents findings derived from the HFO portion of the IPEEE submittals. Each major category of 

HFO initiator is discussed, including high winds and tornadoes, external floods, and accidents related to 

transportation or nearby facilities. It also discusses HFO-related findings concerning specific GSIs and USIs. 

Chapters 2 through 4 each provide summaries of applicable walkdown findings, human action perspectives, 

containment performance perspectives, plant improvements, generic versus plant-specific perspectives, as 

well as observations of specific strengths and weaknesses relevant to the evaluation of each particular type 

of external initiator. 

Chapter 5 describes each of the external-event related unresolved and generic safety issues and provides the 

staff's conclusions regarding the resolution of these issues for each plant. 

The staff anticipates that this report will be used by readers with different backgrounds. Some terms used 

in this report may have different definitions depending on the technical context in which they are used. 

Therefore, a glossary is provided at the beginning of Volume 1 to aid the reader in understanding the specific 

meaning of each term used in this report. 

Volume 2 of this report, which includes detailed plant-specific tables, is organized as follows: Section 2 

covers seismic events; Section 3 fire; Section 4 high winds, floods, and other external events; and Section 

5 IPEEE-related unresolved safety issues and generic safety issues. 

1-2
2. SEISMIC TABLES

This section contains 13 plant-specific tables of summary information obtained from the seismic portions of 

the IPEEE. Table 2.1 contains the seismic review category and evaluation approach used. Tables 2.2 through 

2.6 provide information about those plants that performed a seismic PRA. Table 2.2 contains the core 

damage frequency (CDF). Table 2.3 identifies the licensee-identified dominant risk contributors. Table 2.4 

lists the licensee-identified plant improvements along with the screening used during the walkdown and 

walkdown findings. Table 2.5 shows the containment type and the results of the licensee's seismic 

containment evaluation, including quantitative and qualitative results and identified plant improvements. 

Those licensees that did not perform a seismic PRA performed a seismic margin assessment. Tables 2.6 

through 2.8 provide information about those plants that performed a seismic margin assessment. Table 2.6 

identifies the format of the analysis, the basis for the earthquake spectral shape, and the licensee's identified 

high confidence of low probability of failure (HCLPF) value. Table 2.7 lists the licensee-identified plant 

improvements along with the screening used during the walkdown and findings. Table 2.8 shows the 

containment type and the results of the licensee's seismic containment evaluation, including quantitative and 

qualitative results and identified plant improvements. 

Table 2.9 contains plant-specific information concerning the potential of low-ruggedness relays to chatter 

(open and close their contacts repeatedly) during a seismic event. This table describes the licensee's 

approach to evaluating relay chatter, implications of the relay chatter, and plant improvements. 

Table 2.10 lists the soil and foundation characteristics for each plant site. Based on the plants' classification 

in NUREG-1407, licensees were to perform different levels of assessment of the earthquake effect on the 

ground (foundation) and plant facilities. The licensees' results are presented in this table. The earthquake 

effects on operator actions, as identified in the licensees' submittals, are shown in Table 2.11. 

Other potential effects of earthquakes include seismically induced fires or floods. The results of the 

licensees' assessments of these two possibilities are shown in Table 2.12. The potential for an earthquake 

to cause the in-core flux mapping system to fail in such a manner as to result in a loss of coolant accident 

(LOCA) is applicable only to Westinghouse plants. The results of the licensees' evaluation of the flux 

mapping system are shown in Table 2.13.

2-1
Table 2.1: Seismic review categories and evaluation approaches

Plant Seismic review category Seismic LPEEE evaluation approach

Arkansas Nuclear One 1 

Arkansas Nuclear One 2 

Beaver Valley 1 

Beaver Valley 2 

Braidwood 1 &2 

Browns Ferry 2&3 

Brunswick 1 &2 

Byron 1&2 

Callaway

Calvert Cliffs 1&2 

Catawba 1 &2 

Clinton 

Columbia Generating* 

Comanche Peak l&2 

Cooper 

Crystal River 3 

D.C. Cook 1&2 

Davis-Besse 

Diablo Canyon l&2 

Dresden 2&3 

Duane Arnold 

Farley 1 &2 

Fermi 2 

FitzPatrick 

Fort Calhoun I 

Ginna

3 (0.3g full-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope)

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

5 (0.5g full-scope) 

1 (reduced-scope) 

2 (0.3g focused-scope) 

1 (reduced-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

7 (Seismic PRA) 

2 (0.3g focused-scope) 

I (reduced-scope) 

1 (reduced-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope)

0.3g full-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

Seismic PRA 

Seismic PRA 

0.3g focused-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

Seismic PRA (using surrogate element at 

0.3g) 

Existing Seismic PRA 

0.3g focused-scope EPRI SMA 

Seismic PRA (using surrogate element at 

0.5g) 

reduced-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

reduced-scope EPRI SMA 

Seismic PRA 

reduced-scope EPRI SMA 

Existing Seismic PRA 

0.3g focused-scope EPRI SMA 

reduced-scope EPRI SMA 

reduced-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

0.3g focused-scope NRC SMA 

0.3g focused-scope NRC SMA (using 

surrogate element at 0.5g) 

Modified focused-scope EPRI SMA

2-2
Table 2.1: Seismic review categories and evaluation approaches (Continued)

Plant Seismic review category Seismic IPEEE evaluation approach

Grand Gulf 1 

H.B. Robinson 2 

Haddam Neck 

Hatch 1&2 

Hope Creek 

Indian Point 2 

Indian Point 3

Kewaunee

La Salle 1&2 

Limerick 1&2 

McGuire 1&2 

Millstone 2 

Millstone 3

Monticello

Nine Mile Point 1 

Nine Mile Point 2 

North Anna 1 &2 

Oconee 1,2,&3 

Oyster Creek 

Palisades 

Palo Verde 1,2,&3 

Peach Bottom 2&3 

Perry 1 

Pilgrim 1

1 (reduced-scope) 

3 (0.3g full-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

3 (0.3g full-scope) 

3 (0.3g full-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

3 (0.3g full-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

5 (0.5g full-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

4 (Seismic PRA)

reduced-scope EPRI SMA 

0.3g full-scope EPRI SMA 

Seismic PRA (using surrogate element at 

0.3g) 

0.3g focused-scope EPRI SMA 

Seismic PRA 

Update of Existing Seismic PRA (using 

surrogate element at 0.5g) 

Seismic PRA (using surrogate element at 

0.3g) 

Seismic PRA (using surrogate element at 

0.3g) 

Existing Simplified Seismic PRA (SSMRP) 

reduced-scope EPRI SMA 

Existing Seismic PRA 

0.3g focused-scope EPRI SMA 

Existing Seismic PRA 

Modified focused/Expanded reduced-scope 

EPRI SMA 

0.3g focused-scope EPRI SMA 

SPRA & focused EPRI SMA (using 

surrogate element at 0.5g) 

0.3g focused-scope EPRT SMA 

Seismic PRA (using surrogate element at 

0.3g) 

Seismic PRA 

Seismic PRA (using surrogate element at 

0.5g) 

0.3g full-scope EPRI SMA 

Modified focused-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

Seismic PRA (using surrogate element at

2-3
Table 2.1: Seismic review categories and evaluation approaches (Continued)

Plant Seismic review category Seismic IPEEE evaluation approach 

0.5g)

Point Beach 1&2 

Prairie Island 1 &2 

Quad Cities 1&2 

River Bend 

Salem 1&2 

San Onofre 2&3 

Seabrook 

Sequoyah 1&2 

Shearon Harris I 

South Texas Project 1&2 

St. Lucie 1&2 

Summer 

Surry 1&2 

Susquehanna 1&2 

TMI 1 

Turkey Point 3&4 

Vermont Yankee 

Vogtle 1&2 

Waterford 3 

Watts Bar 1 

Wolf Creek

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

1 (reduced-scope) 

2 (0.3g focused-scope) 

7 (Seismic PRA) 

4 (Seismic PRA) 

3 (0.3g full-scope) 

2 (0.3g focused-scope) 

1 (reduced-scope) 

1 (reduced-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

1 (reduced-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope) 

1 (reduced-scope) 

2 (0.3g focused-scope) 

2 (0.3g focused-scope)

Seismic PRA (using surrogate element at 

0.3g) 

0.3g focused-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

reduced-scope EPRI SMA 

Seismic PRA 

New Seismic PRA 

Existing Seismic PRA 

0.3g full-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

Existing Seismic PRA 

Site-specific approach 

0.3g focused-scope EPRI SMA 

Seismic PRA (using surrogate element at 

0.3g) 

0.3g focused-scope EPRI SMA 

Seismic PRA 

Site-specific approach 

0.3g focused-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

reduced-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

reduced-scope EPRI SMA

Number of plants = 71

* Formerly known as Washington Nuclear Project Number 2.

2-4
Table 2.2: Seismic CDF for plants performing a seismic PRA

Mean seismic CDF 

EPRI or HCLPF Surrogate 

Plant other Update LLNIL (g) Spectrum shape element

Beaver Valley 1 

Beaver Valley 2 

Calvert Cliffs 1&2 

Catawba 1 &2 

Columbia* 

D.C. Cook 1&2 

Diablo Canyon 1&2 

Haddam Neck 

Hope Creek 

Indian Point 2 

Indian Point 3 

Kewaunee 

La Salle 1&2 

McGuire 1&2 

Millstone 3 

Nine Mile Point 2

Oconee 1,2,&3 

Oyster Creek 

Palisades 

Pilgrim 1 

Point Beach 1&2 

Salem 1&2 

San Onofre 2&3

Seabrook

9.10E-06 

5.53E-06 

1.60E-05 

2.10E-05 

3.20E-06 

4.20E-05 

2.30E-04 

1.06E-06 

1,30E-05 

5.90E-05 

1.OE-05 

7.60E-07 

1.IOE-05 

9.1OE-06 

2.50E-07

3.47E-05 

3,62E-06 

5.80E-05 

1.40E-05 

4.70E-06 

1.70E-05 

1.20E-05

1.29E-05 

1.03E-05

2.46E-05 

2.33E-05 

1.29E-05

1.00E-05

1 .50E-04 

3.60E-06 

1B50E-05 

4.40E-05 

1.30E-05

1 .20E-06

-- 1989 EPRI - UHS 

-- 1989 EPRI - UHS 

-- LLNL - UHS 

-- Sequoyah Spectra 

-- Site-specific 

0.25 1989 LLNL - UHS 

1.56 LTSP Site-specific 

< 0.05 1989 EPRI- UHS 

-- 1989 EPRI - UHS 

-- 1989 EPRI - UHS 

0.13 LLNL - UHS 

0.23 1989 LLNL - UHS 

-- Not Specified 

-- NUREG/CR-0098 

0.25 Site-specific 

0.50 NUREG/CR-0098

(24 hr), 

0.23 

(72 hr)

4.74E-06 6.36E-06 

8.90E-06 

9.40E-05 

1.30E-05 

9.50E-06

1.30E-04

-- 1989 EPRI - UHS 

-- 1989 EPRI - UHS 

0.22 1993 LLNL - UHS 

0.25 1989 LLNL - UHS 

0.16 1989 LLNL - UHS 

-- 1989 EPRI - UHS 

Approx. Site-specific 

0.67

-- RG 1.60, 0.25g

2-5

No 

No 

Yes 

No 

Yes 

No 

No 

Yes 

No 

Yes 

Yes 

Yes 

No 

No 

No 

Yes

Yes 

No 

Yes 

Yes 

Yes 

No 

No

No
Table 2.2: Seismic CDF for plants performing a seismic PRA (Continued)

Mean seismic CDF 

EPRI or HCLPF Surrogate 

Plant other Update LLNL (g) Spectrum shape element 

South Texas Project 1.90E-07 2.20E-05 -- River Bend Hazard No 

1 &2 Spectra 

Surry 1&2 8.20E-06 0.16 1989 EPRI - UHS Yes 

TMI 1 3.21E-05 8.43E-05 -- 1989 EPRI - UHS No 

Number of plants = 27 

* Formerly known as Washington Nuclear Project Number 2.

2-6
Table 2.3: Dominant risk contributors reported in seismic PRAs

Plant Seismic failures Random failures Operator actions 

Beaver Valley 125V dc ERFS station battery (0.064 None reported. RCS depressurization using 

HCLPF), atmospheric steam dump valves; 

offsite power grid (0.119), Station crosstie connecting the 

auxiliary building (0.223), 4 kV buses of BV-I and BV-2. 

125V dc block walls (0.193), 

containment instrument air (0.126), 

RW pump intake structure (0.245) 

Beaver Valley 125V ERFS station battery (0.064 None reported. RCS depressurization using 

2 HCLPF), atmospheric steam dump valves; 

offsite power grid (0.119), Station crosstie connecting the 

125V dc station battery 2-5 (0.079), 4 kV buses of BV-1 and BV-2. 

station air compressor 2SAS-C2 

(0.126), 

turbine building block wall (0.126), 

auxiliary building (0.223), 

SWS pumps intake structure 

(0.245). 

Calvert Cliffs Surrogate element (leading None reported. Alignment of the battery supplied 

1 &2 contributor), vital 120V ac buses to their backup 

offsite power, buses. 

service water system (leading to Recovery from spurious auxiliary 

failure of 3 EDGs due to loss of feed actuation system by opening 

cooling), the AFW block valves and locally 

self cooled emergency diesel controlling AFW flow. 

generators. Manually open the steam admission 

valve that failed closed on loss of 

power at the 125Vdc bus. 

Local manual control of AFW 

flow. 

In a station blackout with the SG 

overfilled, drain the AFW steam 

supply header and start the turbine 

driven AFW pump. 

Catawba 1&2 Offsite power Diesel generators 

DG battery chargers 

DG oil tanks 

ac switchgear 

Inverters 

ac and dc panels

2-7
Table 2.3: Dominant risk contributors reported in seismic PRAs (Continued) 

Plant Seismic failures Random failures Operator actions 

Columbia Offsite power, EDG, Establish suppression pool cooling; 

Generating* switchgear room cooling, dc distribution Initiate LPCI injection after failure 

diesel generator controls, system, of automatic actuation. 

surrogate element. HPI, 

long term heat 

removal. 

D.C. Cook Offsite Power Turbine-Driven 

1&2 auxiliary building AFW Pump 

Block Walls 

250V dc Panels 

RPS Panels 

Ice Condenser 

(turbine building Pedestal) 

(4 kV Switchgear) 

(Cable Trays) 

Diablo Offsite Power Diesel Generators Reduce component cooling water 

Canyon 1&2 230 kV Transformer Station Pressurized safety (CCW) heat Loads 

4 kV Switchgear (Chatter) relief valves Crosstie Units 1 and 2 

DG Control Panel (SRVs) (Reclose) Switch Containment Sump 

Recirculation 

Haddam Neck AFW pipe 

Main feedwater (MFW) 

heaters 

Cont. Air recirc. Fans 

Battery bank 

Hope Creek Offsite power, Reactor Manual recovery action given 

lE 120V ac instrumentation panels, depressurization failure of all four divisions of lE 

1E 125V dc distribution panels, system, 120V ac instrumentation 

high pressure injection. EDG. distribution panels. 

Indian Point 2 turbine building frame Emergency diesel 

Unit 1 superheater stack generators 

CCW surge tank 

fuel storage building 

Cable trays 

480V MCCs 

service water pumps 

CCW heat exchangers 

Intake Structure (sliding) 

Offsite Power

2-8
Table 2.3: Dominant risk contributors reported in seismic PRAs (Cor1 tinued)

Plant Seismic failures Ra1ndom failures Operator acton 

Indian Point 3 Offsite Power, RLTR shutdown None reported. 

Switchgears for EDG, cooling, 

service water pumps, Emergency Diesel 

RHR heat Exahangers, Generators. 

Control Room supervisory panel, 

RHR pumps, 

CCW Surge tank and heat 

exchangers, and 

Surrogate element. 

Kewaunee Offsite Power Switch CST to SW for AFW 

Surrogate Element 

La Salle l&2 Offsite Power Diesel Generators None 

Condensate Storage tank 

McGuire i&2 Offsite Power Diesel Generators Align SW to Pond 

120V dc 

Millstone 3 Offsite Power Diesel Generators 

Diesel Generator Oil Coolers AFW system 

(anchor bolts) 

Roof Diaphragm (Control Bldg) 

Wall Footing (EDG Bldg) 

Shear Wall (ESF Bldg) 

Pumphouse Sliding (Soil) 

Nine Mile Surrogate Element 

Point 2 Nitrogen Accumulators 

Offsite Power 

Oconee Offsite power, Standby Align the SSF ASW system for 

1,2,&3 Jocassee Dam (0.15g HCLPF, Shutdown Facility operation. 

leading to failure of SSF and other (SSF). 

systems), 

Keowee Dam (0.20 HCLPF, leading 

to failure of emergency ac power 

from Keowee Hydro Unit and other 

systems), 

SSF components surrogates (0.3), 

auxiliary building components 

surrogates (0.24).

2-9
Table 2.3: Dominant risk contributors reported in seismic PRAs (Continued) 

Plant Seismic failures Random failures Operator actions 

Oyster Creek turbine building, Isolation Alignment of fire protection system 

Reactor Building, Condenser to isolation condenser makeup, 

switchgear room fans, makeup, offsite power recovery via 

Condensate Storage tank, failure of EMRVs combustion turbines. 

battery room fans, to close. 

offsite power. 

Palisades Diesel Fire Pump Day tanks Diesel Generators, Initiate Once-Through Cooling 

Diesel Fire Pump Control Panel AFW Pump, Initiate AFW Make-up 

Station transformer Automatic AFW Flow Control 

Main Steam Isolation Valves Depressurization 

(MSIVs), interaction Valves (ADVs) 

DG Pump Oil tank 

Bus Undervoltage Relay 

Pilgrim 1 Motor control centers (MCCs) SBO Diesel Procedure 

Bus Reset SBO-Related Relay 

Panels Initiate Suppression Pool Cooling 

CCW Pumps 

Residual heat Removal (RHR) 

Pumps 

SW Pumps 

CCW Surge tanks 

Block Wall 

Control Rod 

Structural Failures 

CSTs, interaction 

Point Beach Cable Trays Shutdown from Remote Panel 

1&2 Surrogate Element Align SW to AFW Suction 

4 kV Transformers 

480V Load Centers 

Block Walls 

Salem 1&2 Offsite power, Emergency Diesel Establish alternate ESF room 

service water system, generators ventilation. 

battery train failure due to block 

wall failure, 

control room ceiling. 

2- 10
Table 2.3: Dominant risk contributors reported in seismic PRAs (Continued)

Plant Seismic failures Random failures Operator actions 

San Onofre Offsite Power DG, Condensate Make-up 

2&3 Switchyard Relays (Chatter) DG Supply Fans, T-D AFW Pump Control Valves 

480V Switchgear DG Fuel Transfer Reset Relays 

MCCs Pumps, 

auxiliary building Turbine-Driven 

Emergency Chillers AFW Pump, 

Emergency Sump Valve Bellows Battery Chargers, 

Safety Equipment Building Motor-Driven 

CCW heat exchangers AFW Pumps, 

SWC Valve Relays (Chatter) Emergency 

Primary Make-up tank Chillers, 

SWC Discharge Gate CCW heat 

CST exchangers, 

CCW Non-Crit 

Loop Isolation 

Valves, 

CCW Pumps, 

HPSI Pumps 

Seabrook Offsite Power, Emergency Diesel Reset relays. 

4.16 kV Switchgear (chatter), Generators 

RWST, and EDG. (EDG). 

South Texas Offsite Power 

Project 1&2 Diesel fuel oil day tanks 

4.16 kV Switchgear 

Large Chiller-tanks 

CCW surge tank 

AFW Storage tank 

Electrical Cabinets (inverters, chargers) 

Surry 1&2 Offsite power, turbine building, Emergency Diesel Prevent intake canal draining; 

Condensate Storage tank, Generators. stop AFW pumps before cavitation; 

CCW surge tank, align RHR inside containment; 

seismic induced lube oil fire in depressurize RCS using steam 

turbine building. dump valves. 

TMI 1 Offsite power, Class lE ac power Relay chatter recovery. 

Class 1E ac power, train A. 

control room ceiling, 

emergency feedwater, 

EDG air start receiver. 

Number of plants = 27 

* Formerly known as Washington Nuclear Project Number 2.

2-11
Table 2A: Seismic ouftliers and improvements for PRA plants 

Walkdown Type(s) of 

Plant screen lekrl idirg Description of fndings Plan improvements 

Beaver 0.5g HCLPF Potential plant Potential for reinforcement of the None. Improvement not 

Valley I improvement block walls in the Emergency implemented due to the low 

125V dc Battery Room. seismic CDF and because the 

block walls conform to resolution 

of both USI A-46 and IEB 80-11. 

Beaver 0.5g HCLPF Potential plant Failure of the diesel building due None. No improvement on the 

Valley 2 improvement to interaction with the diesel building will be made 

emergency diesel generator. because its HCLPF of 0.28g is 

more than twice the SSE level 

along with a low contribution to 

total CDF. 

Calvert Cliffs 0.3g HCLPF None, except for one No fundamental weakness or The issue of smoke from the fire 

1&2 issue addressing a vulnerability found. being drawn into the control room 

seismically induced ventilation system is addressed in 

fire scenario (smoke one of the improvements for fire 

from a burning fuel concerns (changes in operator 

oil tank). procedures for the ventilation 

system). 

Catawba l&2 Structures: 2.5g Outliers: - Reactor Building and Fixes were made to three minor 

median Reactor Building Containment Internal Structures spatial interaction concerns, and 

Equipment: 2.0g Containment could not be screened out. were deemed not be risk 

median Internal Structures - Walkdown identified minor significant. 

Anomalies: spatial interaction concerns. - DG battery rack modifications. 

Minor spatial - Instrument relocated. 

interaction concerns. - Valve replaced (Table 3-3 of 

IPEEE) 

Columbia 0.5g HCLPF Items where plant Issues/outliers identified: missing Minor corrections, including 

Generating* generic screening improvements could anchorage nuts or washers in two replacing missing anchorage nuts 

threshold used. be made. air handling units in the Division or washers to design anchorage 

1 diesel generator room, configuration, 

inadequate connection between proper connection between 

cabinets of E-SM-7 and E-SM- cabinets and tie-down of batteries, 

7/75/2, proximity of the hangers the strengthening of MCC base 

of three MCCs and two connections, and procedures (to 

instrument racks, lack of restraint open door) for alternate switchgear 

of the batteries for the diesel room cooling. 

driven fire pumps, weak MCC 

base connections, lack of 

alternate switchgear room 

cooling.

2- 12
Table 2.4: Seismic outliers and improvements for PRA plants (Continued)

Walkdown Type(s) of 

Plant screen level findings Description of findings Plaut isnprovemnt 

D.C. Cook Not reported Several anomalies and Block walls; poor fire- Three design-related 1&2 housekeeping extinguisher mountings; improvements (mounting/support 

concerns interaction with fire protection of instrument rack, Halon bottles, 

pilot lines; interaction of and emergency service water 

fluorescent lights in control (ESW) piping) and 13 

room; missing/broken anchorages housekeeping-related fixes 

on some MCCs; questionable (replacing or tightening nuts/bolts 

support of a 17-ton CO2 tank; or clamps, rust protection, etc.) 

potential for earthquake-induced were made. 

hydrazine spill. 

Diablo Not reported None. None. No IPEEE plant improvements. 

Canyon l&2 Earlier programs: 

- LTSP improvements 

- DC PRA-based improvements 

- Ongoing improvements. 

Haddam 0.3g HCLPF, 0.8 Identified vulnerabili- Numerous conditions, including Numerous meaningful plant Neck spectral ties, including 30 poor anchorage/support, improvements have been proposed acceleration seismic and 8 seismic- interaction concerns, housekeep- (Table 7.1-1 of IPEEE submittal). 

fire risk outliers ing concerns, and relay chatter. 

Hope Creek 0.5g HCLPF or A number of compo- No fundamental weakness or None. 

1.5g median nents could not be vulnerability was found 

screened out (Table 3- (Screened-in components were 

4, mostly of interac- evaluated for seismic fragilities, 

tion and anchorage- table 3-5). 

support concerns). 

About 100 LRRs were 

identified and later 

screened. 

Indian Point 0.5g PGA HCLPF, Unscreened include: Fragilities were calculated for component cooling water Surge 2 1.5g PGA Median - 20 item categories unscreened components; 15 tank Anchor Bolts were 

identified from earlier components were ultimately strengthened. 

SPRA, included in quantifying the 

- 11 item categories seismic PRA model. 

from USI A-46, 

- 17 additional item 

categories from 

IPEEE walkdowns 

Indian Point 0.8g peak spectral "Seismic No unique plant vulnerabilities Installation of new actuation 

3 acceleration level, vulnerabilities" were found. However, the control panel for CO2 system 

or 0.38g HCLPF submittal does refer to a "seismic suggested. 

vulnerability" in which a seismic The SRT identified several 

event may induce a spurious "seismic vulnerabilities" regarding 

operation of the EDG room CO2 seismically induced fire, but there 

system and subsequent shutdown was no discussion regarding their 

of the EDG ventilation system. resolution. 

This has been addressed with a 

temporary modification.

2- 13
Table 2.4: Seismic outliers and improvements for PRA plants (Continued)

Walkdown Type(s) of 

Plant screen level findings Description of findings Plant improvements 

Kewaunee 0.3g HCLPF; 0.8g Open Missing fasteners on DG Resolution of USI A-46 concerns 

spectral issues/anomalies; no excitation and control cabinets; has led to some equipment 

acceleration vulnerabilities or risk- poor anchorage of station service enhancements, one procedural 

significant concerns, transformers; potential interaction implementation, an administrative 

of relay racks; other equipment control, and several housekeeping 

anchorages concerns; mercoid improvements. (Submittal Table 

switches 3-4) 

La Salle l&2 Not reported Outlier, anomalies not CST was found to be an outlier. None, but the submittal notes that 

reported. some plant improvements have 

been made since 1985. 

McGuire l&2 Structures: 2.5g Anomalies: Minor Walkdown identified 6 spatial - Spacers installed on DG 

median spatial interaction interaction concerns, two batteries/racks. 

Equipment: 2.Og concerns and equipment mounting/support - Grating trimmed near steam vent 

median maintenance concerns. concerns, and one maintenance valves. 

concern. - MCCs bolted together. 

- Guidelines developed for 

movable equipment. 

- Panel modified to clear 8-in pipe. 

- Arc barriers tightened in main 

control boards. 

- Grout installed below saddle 

support of CCW heat exchanger. 

- Missing bolts installed on surge 

tank. 

- Corrosion on anchor bolts of 

AFW/CST cleaned and bolts 

recoated (Table 3-3 of IPEEE). 

Millstone 3 Not reported Outliers; anomalies Diesel generator oil cooler bolts None for IPEEE; however, diesel 

not reported. identified as an outlier. generator oil cooler bolts were 

previously replaced with stronger 

bolts. 

Nine Mile 0.5g HCLPF, 1.2g Anomalies/open Three concerns were cited: Rack over a motor operated valve 

Point 2 spectral issues potential for overhead rack to (MOV) was secured; rail stops 

acceleration impact an MOV; potential were installed to prevent 

interaction of hoist assemblies movement of hoist assemblies on 

mounted on electric cabinets; and electrical cabinets. 

fire water piping in control 

building.

2-14
Table 2.4: Seismic outliers and improvements for PRA plants (Continued)

Walkdown Type(s) of 

Plant screen level findings Description of findings Plant improvements 

Oconee 0.3g HCLPF Recommended While seismic events are the most Plant improvements listed in Table 

1,2,&3 enhancements significant external event 6-1, including 142 low

contributors to core damage risk, ruggedness relays (LRRs) & issues 

"there are no unduly significant related to anchorage, support and 

sequences (vulnerabilities) from restraint. Plans are to complete 

external events." resolution of all outliers, including 

the relays identified in Table 3-2 

of the 1997 Supplemental Report, 

by the end of 2002. It is the 

licensee's intention to assure the 

final fragilities for these relays to 

be at or above PRA modeled 

values by testing, analysis, or 

replacement modifications. 

Oyster Creek 0.3g HCLPF. Potential plant The seismic IPEEE identified no Two potential plant modifications: 

modifications plant vulnerabilities (i.e., a failure check for tightness of bolts on 

will result in a CDF of 1.OE- Forked River Combustion Turbine 

6/ry). Liquefaction-induced tin-fan coolers, and provide battery 

failures were identified as most spacers for Combustion Turbine 

risk significant contributors, battery compartments. 

Palisades 0.3g HCLPF and Outliers and Fifty-two (52) conditions were None. 

0.5g HCLPF anomalies, encountered, including instances 

of poor anchorage, unqualified 

(and unanalyzed) block walls, 

and interaction concerns. 

Pilgrim 1 1.Og median Outliers and Various concerns were identified Stiffening of SBO diesel muffler 

(EPRI NP-6041- anomalies, in USI A-46/IPEEE evaluations, support; fix a seismic interaction 

SL SMA Column but not fully reported in IPEEE hazard due to potential failure of a 

2 screening submittal. main transformer bushing and 

criteria) adjacent lightning arrester, and fix 

potential weakness of friction-clip 

restraints connecting A8 bus to its 

concrete foundation. 

Point Beach 0.3g HCLPF and Outliers Various concerns were identified Fix anchorage deficiencies on 

1&2 0.5g HCLPF in USI A-46 evaluation, and cable trays and some equipment 

apply to IPEEE. Weaknesses in (for USI A-46); resolve concerns 

RWST and CST encountered associated with Westinghouse 

(and modeled in SPRA fragility Model ITH relays (for USI A-46); 

analyses). and add two diesel generators and 

their support systems (for IPE). 

Salem 1&2 A median capacity Plant improvements No definition of vulnerability Replacement of low-ruggedness 

of 1.5g and an was found. The submittal does relays (LRRs) and reinforcement 

HCLPF of 0.5g state that as a result of the seismic of block walls in switchgear room. 

were used as part PRA analysis, no vulnerabilities Procedural change to ensure long 

of the screening have been identified. However, a term alternate ventilation for 

criteria, few plant improvements were rooms in the auxiliary building. 

assumed and credited in the risk 

quantification.

2- 15
Table 2.4: Seismic outliers and improvements for PRA plants (Continued) 

Walkdown Type(s) of 

Plant screen level findings Description of findings Plant improvements 

San Onofre Components with Approximately 30 Issues potentially affecting - Improved reliability of cross 2&3 median capacity anomalous conditions functionality (3 items). connecting EDGs between units. 

greater than lOg S were observed, most 

sub a (1-10 Hz) of which were Anchorage anomalies (3 items). - Strengthened supports of an were screened out; resolved through ammonia tank to eliminate a spill 

components with additional Load path anomalies (9 items). hazard. 

median capacity consideration. 

between 8-1 Og S Seismic lI/I interaction concerns - Removed a floor grating sub a (1-10 Hz) (9 items). surrounding AFW valve actuators were screened out to eliminate an interaction hazard. 

if their seismically Commodity clearance concerns induced failure (6 items). - Removed a concrete plug rate was less than surrounding the Unit 2 DG fuel oil 

the I OE-7, and Fragilities were computed for transfer piping to improve the 

components with over 150 components. seismic capacity of the pipe and to 

median capacity provide a consistent configuration 

up to 8g S sub a among units. 

(1-10 Hz) were included in the - Fastened together adjacent SPRA electrical cabinets/panels to help quantification prevent interactions and relay 

process. chatter. 

- Stabilized light fixtures that may 

interact with electrical cabinets. 

Seabrook A median capacity None. There are no fundamental None. 

of 2.Og PGA weaknesses or vulnerabilities 

with regard to severe accident 

risk. 

South Texas Not reported Not reported Not reported None reported 

Project 1&2

2-16
Table 2.4: Seismic outliers and improvements for PRA plants (Continued)

Walkdown Type(s) of 

Plant screen level findings Description of findings Plant improvements 

Surry 1&2 0.3g HCLPF Outliers and low- Issues/outliers identified include Issues/outliers involving loose or 

ruggedness loose or missing fasteners, missing fasteners, anchorage 

components anchorage concerns, outliers for concerns, and outliers for cable 

cable and conduit raceways, and conduit raceways have been 

issues related to seismic induced mostly resolved. About 60 items 

fire/flood evaluations, related to electrical and 

housekeeping/conduct of mechanical equipment have been 

maintenance issues, control room resolved via field modifications. 

ceiling review, and items related An operating procedure, 0-AP

to electrical and mechanical 12.01, was revised to require 

equipment. opening of the condenser waterbox 

vacuum breakers to conserve 

intake canal inventory. 

Issues/outliers on seismic induced 

fire/flood evaluations, 

housekeeping/conduct of 

maintenance, control room ceiling, 

a few minor modifications for 

cable tray and conduit supports, 

and further evaluation and 

enhancement for 36 mechanical 

and electrical components 

indicated in Table 6.1-1 will be 

resolved by the end of the 

refueling outage currently 

scheduled to commence in 

September 2000. 

TMI I 1.Og medium Low-ruggedness Identified issues/outliers Replacement of LRRs, Control 

relays and other including: some relays not being Room ceiling modification, and 

issues/outliers for able to pass any seismic fixing anchorage/restraint 

improvements (mostly screening criteria; EDG air problems. Due to small 

related to receivers seismic restraint; contribution to CDF, 

anchorage/support/ control room ceiling; restraining improvements not planned for 

restraint), of the penetration pressurization rewelding the load center gusset 

tank PP-T-IA; Load Centers 1P, welds, upgrading the supports for 

I R, IS, and IT gusset weld; the fuel oil tanks and batteries for 

supports for the fuel oil tanks and the diesel-driven fire pumps, and 

batteries for the diesel-driven fire upgrading decay heat service heat 

pumps; anchorage for the decay exchangers. 

heat service heat exchangers. 

* Formerly known as Washington Nuclear Project Number 2.

2- 17
Table 2.5: Seismic containment performance for PRA plants

Containment Plant 

Plant type Quantitative findings Qualitative findings improvements 

Beaver Valley Subatmospheric Level 2 analysis, releases Seismic-induced failures do not None. 

containment; steel- dominated by small release play a significant role in the 

lined reinforced- from early containment results. 

concrete failure and bypass (88% of 

CDF). 

Beaver Valley Subatmospheric Level 2 analysis, releases Seismic-induced failures do not None. 

2 containment; steel- dominated by small release play a significant role in the 

lined reinforced- from early containment results. 

concrete failure and bypass (58% of 

CDF). 

Calvert Cliffs Large dry type; Included containment Containment penetrations and the None. 

1&2 steel-lined isolation failure (due to isolation valves bound all other 

prestressed-concrete seismic event) in the event failures and were screened at 0.5g 

tree. Containment structural HCLPF. 

failure was screened out. 

CDF for early large failure is 

1.41E-6. 

Catawba l&2 Ice Condenser, None. - Reactor building, containment None. 

Pressure internal structures did not screen 

Suppression Type, out. 

with Steel Primary - Cabinets, panel boards, and 

Containment and a MCCs (for containment isolation 

Reinforced system) did not screen out. 

Concrete Shield - No fragility analysis for ice 

Building. condenser. 

Columbia Mark II None. A walkdown was conducted to None. 

Generating* ensure containment performance 

function and the ability to isolate 

containment. No unique 

containment vulnerabilities were 

identified. 

D.C. Cook Ice Condenser; Direct/structural No significant anomalies were None. 

1&2 steel-lined containment failure leads to cited. 

reinforced-concrete 1% of seismic CDF; 

frequencies of early releases 

otherwise not quantified. 

Diablo Canyon Large dry type; Large early release None. No related IPEEE 

l&2 steel-lined frequency: 3% of seismic improvements. 

reinforced-concrete CDF. 

Small early release 

frequency: 16% of seismic 

CDF.

2-18
Table 2.5: Seismic containment performance for PRA plants (Continued)

Containment Plant 

Plant type Quantitative findings Qualitative findings improvements 

Haddam Neck Large dry type; None. Vulnerabilities found in Adams Licensee's resolution to 

steel-lined filter units and CAR fans, diesel these items is unclear. 

reinforced-concrete fire pump batteries and diesel fire 

pump fuel oil tank, and exhaust 

penetration P39 (CP system). 

Hope Creek Mark I; steel Failure of instrument Containment structural integrity, None. 

containment distribution panels penetrations, and associated 

IA(B,C,D)J482 may lead to isolation valves, cables, etc., were 

core damage and screened out. 

containment isolation failure 

(about 5% of total CDF). 

Indian Point 2 Large dry type; About 65% of the seismic Containment fan coolers did not None. 

steel-lined CDF results in plant damage screen out and were included in 

reinforced-concrete states with initial loss of the SPRA model. 

containment pressure 

suppression and heat 

removal functions. If these 

functions are not regained, 

long-term over pressure 

failure of the containment 

could result. None of these 

sequences leads directly to 

early containment failure or 

bypass. 

Indian Point 3 Large dry type; Containment event tree was A walkdown was performed to None. 

steel-lined developed for containment identify vulnerabilities that could 

reinforced-concrete failure frequencies (figure result in early containment failure, 

3.1.6.1). Summary and none were found. 

information was not 

provided. Results were said 

to be similar to those 

derived for IPE study. 

Kewaunee Large dry type; Mean frequency of No significant anomalies were None. 

free-standing steel containment failure: 6.2E- cited. 

containment vessel, 6/ry (EPRI hazard). 

surrounded by a 

reinforced-concrete Containment HCLPF (large 

shield building, early failures): 0.3g. 

with an annular 

space in between 

the two

2-19
] 

Table 2.5: Seismic containment performance for PRA plants (Continued) 

Containment Plant 

plant type Quantitative findings Qualitative findings improvements 

La Salle 1&2 Mark II, with None reported. None reported. None. 

inerted, primary 

containment of 

post-tensioned 

reinforced concrete 

with steel liner; 

secondary 

containment is the 

reinforced concrete 

reactor building. 

McGuire 1&2 Ice Condenser; None. None. (No fragility analysis was None. 

steel-lined performed for ice condenser.) 

reinforced-concrete 

Millstone 3 Subatmospheric Not reported. Containment recirculating system None. 

containment; steel- heat exchangers are outliers. 

lined reinforced

concrete 

Nine Mile Mark II; reinforced- Crediting operator actions to No significant anomalies were None. 

Point 2 concrete close valves outside cited. 

containment, less than 2% of 

the CDF is associated with 

early containment failure or 

bypass. 

Oconee 1,2,&3 Large dry type; None. Walkdown on containment None. 

steel-lined performance was conducted. 

prestressed-concrete Equipment and structures required 

for containment performance and 

potential failure modes and conse

quence have been examined. 

Oyster Creek Mark I; steel None. Seismic structural capacity of the None. 

containment drywell and the performance of 

containment isolation following a 

seismic event were evaluated and 

were found to be higher than 1.0g. 

Containment bypass was 

considered based on important 

bypass sequences from internal 

event IPE and was found to be of 

no concern. 

Palisades Large dry type; pre- Dominant seismic No significant anomalies were None. 

stressed, post- containment failure mode cited. 

tensioned was found to be relocation 

reinforced con-crete of core debris to the 

structure lined with auxiliary building, having a 

a 1/4-inch carbon frequency of 2.3E-6/ry. 

steel layer.

2 - 20
Table 2.5: Seismic containment performance for PRA plants (Continued)

Containment Plant 

Plant type Quantitative findings Qualitative findings improvements 

Pilgrim I Mark I; pressure Frequency of early No discussion provided. None. 

suppression type, containment failure: 

steel containment 1.6E-5/ry (EPRI mean 

hazard), 3.2E-5/ry (1993 

LLNL mean hazard). 

Point Beach Large dry type, Frequency of early large None, although the quantitative None. 

1&2 with pre-stressed, release: analysis indicates that the 

post-tensioned 1.3E-5/ry automatic containment isolation 

reinforced concrete (the submittal relies on function has low seismic 

structure, manual containment capability. 

isolation to reduce this by a 

factor of 10.) 

Salem l&2 Large dry type; None. Walkdowns and capacity None. 

steel-lined calculations were performed and 

reinforced-concrete no vulnerabilities were found 

regarding any aspect of 

containment performance. 

San Onofre Large dry type, pre- - Success, no containment No significant anomalies None. 

2&3 stressed reinforced failure within 48 hours, less pertaining to early containment 

concrete. than 0.1% volatiles released: failure or unique conditions for 

9.IE-6/ry (53% of seismic seismic events were cited. 

CDF). 

- Late containment failure, 

release up to 0.1% volatiles: 

7.5E-6/ry (43% of seismic 

CDF). 

- Containment bypassed, 

less than 0.1% volatiles 

released: 

2.6E-7/ry (1.5% of seismic 

CDF). 

- Late containment failure, 

more than 10% volatiles 

released: 

2.4E-8/ry (0.2% of seismic 

CDF). 

- Early/isolation failure, 

prior to or at time of vessel 

failure, up to 10% volatiles 

released: 

3.9E-7/ry (2.3% of seismic 

CDF). 

Seabrook Large dry type; None documented. No significant anomalies were None. (However, 

steel-lined cited. relevant IPE 

reinforced-concrete improvements have been 

cited.)

2-21
Table 2.5: Seismic containment performance for PRA plants (Continued)

2 - 22

Containment Plant 

Plant type Quantitative findings Qualitative findings improvements 

South Texas Large dry type, None. None reported. None, although earlier 

Project l&2 with a steel-lined, (as part of the Level-2 

post-tensioned PSA effort) 

reinforced-concrete enhancements were 

structure. made to selected 

containment isolation 

valves. 

Surry l&2 Subatmospheric None. Containment integrity, None. 

containment; steel- containment isolation, and 

lined reinforced- containment cooling systems were 

concrete examined and no concerns were 

noted with respect to containment 

performance. 

TMI I Large dry type; None. Evaluations were performed for None. 

steel-lined containment structure seismic 

prestressed-concrete capacity (with the lowest median 

capacity estimated at greater than 

11 g) and the fragility of 

containment isolation valves and 

signals (with ESAS relays with a 

median fragility of 0.89g the 

weakest component). 

* Formerly known as Washington Nuclear Project Number 2.
Table 2.6: Plant capacity results from IPEEE SMA

Plant Format of SMA HCLPF (g) Spectral shape

Arkansas Nuclear One 1 

Arkansas Nuclear One 2 

Braidwood l&2 

Browns Ferry 2&3 

Brunswick l&2 

Byron l&2 

Callaway 

Clinton 

Comanche Peak 1&2 

Cooper 

Crystal River 3 

Davis-Besse 

Dresden 2&3 

Duane Arnold 

Farley 1&2 

Fermi 2 

FitzPatrick 

Fort Calhoun 1 

Ginna 

Grand Gulf I 

H.B. Robinson 2 

Hatch l&2 

Limerick l&2 

Millstone 2 

Monticello 

Nine Mile Point 1 

Nine Mile Point 2 

North Anna l&2 

Palo Verde 1,2,&3 

Peach Bottom 2&3 

Perry I 

Prairie Island l&2

0.3g full-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

reduced-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

reduced-scope EPRI SMA 

reduced-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

reduced-scope EPRI SMA 

reduced-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

0.3g focused-scope NRC SMA 

0.3g focused-scope NRC SMA 

0.3g focused-scope EPRI SMA 

reduced-scope EPRI SMA 

0.3g full-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

reduced-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

Modified focused/Expanded 

reduced-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

SPRA & focused EPRI SMA 

0.3g focused-scope EPRI SMA 

0.3g full-scope EPRI SMA 

Modified focused-scope EPRI SMA 

0.3g focused-scope EPRI SMA 

0.3g focused-scope EPRI SMA

0.3 NUREG/CR-0098, Rock 

0.3 NUREG/CR-0098, Rock 

0.3 NUREG/CR-0098, Rock 

0.26 NUREG/CR-0098, Rock 

0.30 NUREG/CR-0098, Soil 

0.3 NUREG/CR-0098, Rock 

0.30 NUREG/CR-0098, Soil 

0.3 Multiple Analysis Method (MAM), Soil 

-- Plant SSE (RG 1.60), 0.12g, Rock 

0.3 NUREG/CR-0098, Soil 

-- Housner, Soil/Marshland 

0.26 NUREG/CR-0098, Rock 

0.2 NUREG/CR-0098, Rock 

-- DBE Spectra, Rock/Soil 

-- Plant SSE (NUREG/CR-0098), Soil 

0.3 NUREG/CR-0098, Rock 

0.22 NUREG/CR-0098, Rock 

0.25 NUREG/CR-0098, Soil 

0.2 RG 1.60, 0.25g, Rock 

-- Design Basis Response Spectra, Soil 

0.28 NUREG/CR-0098, Soil 

0.30 NUREG/CR-0098, Soil 

0.15 Plant SSE (Newmark), 0.15 g, Rock 

0.25 NIUREG/CR-0098, Rock 

0.12 NUREG/CR-0098 (for screening); Plant 

SSE (Housner, 0.12g) (for evaluation), Soil 

0.27 NUREG/CR-0098, Rock 

0.23 NUREG/CR-009q8, Rock 

0.16 NUREG/CR-0098, Rock/Soil 

0.3 NUREG/CR-0098, Soil 

0.2 NUREG/CR-0098, Rock 

0.30 NUREG/CR-0098, Rock/Class A backfill 

0.28 NUREG/CR-0098, Soil

2 - 23
Table 2.6: Plant capacity results from IPEEE SMA (Continued) 

Plant Format of SMA HCLPF (g) Spectral shape 

Quad Cities 1&2 0.3g focused-scope EPRI SMA 0.09 original/0.24 NUREG/CR-0098, Rock 

planned 

River Bend reduced-scope EPRI SMA -- Design Ground Response Spectra, Soil 

Sequoyah l&2 0.3g full-scope EPRI SMA 0.27 NUREG/CR-0098 

Shearon Harris I 0.3g focused-scope EPRI SMA 0.29 NUREG/CR-0098, Rock 

St. Lucie 1&2 Site-specific approach -- Plant SSE, 0. 1Og, Structural Fill 

Summer 0.3g focused-scope EPRI SMA 0.22 NUREG/CR-0098, Rock/Soil 

Susquehanna l&2 0.3g focused-scope EPRI SMA 0.21 NUREG/CR-0098, Rock/Soil 

Turkey Point 3&4 Site-specific approach -- Plant SSE (Housner), 0.15g, Rock 

Vermont Yankee 0.3g focused-scope EPRI SMA 0.25 NUREG/CR-0098, Rock 

Vogtle l&2 0.3g focused-scope EPRI SMA 0.3 NUREG/CR-0098, Soil 

Waterford 3 reduced-scope EPRI SMA -- Design Basis Response Spectra, Soil 

Watts Bar 1 0.3g focused-scope EPRI SMA 0.3 NUREG/CR-0098, Rock/Soil 

Wolf Creek reduced-scope EPRI SMA 0.2 NUREG/CR-0098 Median, Rock (for 

screening); Plant SSE (for evaluation) 

Number of plants = 45

2 - 24
Table 2.7: Seismic outliers and improvements for SMA pRants

Plant screen Anomalies & outliers Controlling outliers HCLPF capacities (g) Plant ilmprovemens 

Arkansas 0.3g HCLPF A significant number of Anchorage for the The licensee indicated An A-46 plant. The IPEEE 

Nuclear One 1 outliers were identified and a Emergency Diesel that the 0.3g screening program identified some 

list of "opportunities for plant Generator Fuel tanks criteria would be met. IPEEE-only 

improvement" involving (0.2g, shear of bolt). improvements. 

spatial interaction and Outliers associated with "Opportunities for plant 

inadequate anchorage is the Cable Tray & improvement" identified 

provided. Conduit Raceway and to resolve 10 spatial 

Relay review portions interactions and anchorage 

are being tracked for concerns (see Table 7-1 of 

resolution as part of the IPEEE submittal). The 

USI A-46 Program for method of resolution and 

ANO-1. schedule for 

implementation is not 

specifically identified. The 

licensee indicated that the 

0.3g screening criteria 

would be met. 

Arkansas 0.3g HCLPF A significant number of Anchorage for the The licensee indicated An A-46 plant. The IPEEE 

Nuclear One 2 outliers were identified and a Emergency Diesel that the 0.3g screening program identified some 

list of "opportunities for plant Generator Fuel tanks criteria would be met. IPEEE-only 

improvement" involving (0.2g, shear of bolt). improvements. 

spatial interaction and Outliers associated with "Opportunities for plant 

inadequate anchorage is the Cable Tray & improvement" identified 

provided. Conduit Raceway and to resolve 10 spatial 

Relay review portions interactions and anchorage 

are being tracked for concerns (See Table 7-1 of 

resolution as part of the IPEEE submittal). The 

USI A-46 Program for method of resolution and 

ANO-2. schedule for 

implementation is not 

specifically identified. The 

licensee indicated that the 

0.3g screening criteria 

would be met. 

Braidwood l&2 0.3g HCLPF Outliers that are largely Control room ceiling > 0.3g Equipment maintenance 

interaction concerns. diffusers (made of and modifications (e.g., 

aluminum; if dislodged secure control room 

by a seismic event, may ceiling diffusers to T-bars, 

pose a personnel hazard); as appropriate). 

seismic interaction 

between closely spaced 

electrical cabinets which 

contain essential relays. 

Browns Ferry 0.3g HCLPF Issues related to maintenance, Two transformers in the 0.26g. Any unresolved An A-46 plant. Design 

2&3 housekeeping, and seismic diesel generator building outliers as a result of modifications made to 

interaction that required work for Units I and 2 (which the USI A-46 program resolve two valve 

orders to satisfy SRT field will eventually be will be modified; thus, operators. Any unresolved 

issues; items requiring repairs replaced as part of the the resulting outliers as a result of the 

or modifications, long-term asbestos configurations will have USI A-46 program will be 

material removal HCLPF capacities modified for the A-46 

program at BFN). Two much greater than 0.3g. program. 

Valve Operators 

exceeding the GIP Limit 

for height and weight.

2 -25
Table 2.7: Seismic outliers and improvements for SMA plants (Continued) 

NWalkdown 

Plant screen Anomalies & outliers Controlling outliers HCLPF capacities (g) Plant improvements 

Brunswick l&2 0.3g HCLPF Joint USI A-46/IPEEE seismic Several outliers were All outliers have Being made under USI A

evaluation effort has identified identified, but none had HCLPF capacities 46 resolution. a number of housekeeping, calculated HCLPF exceeding 0.3g. 

maintenance, and interaction capacities less than 0.3g. Note: the IPEEE findings 

concerns, and equipment assume USI A-46 

outliers. improvements (which are 

still to be resolved). 

Byron l&2 0.3g HCLPF Outliers that are largely Control room ceiling > 0.3g Equipment maintenance of 

interaction concerns. diffusers (made of modifications. For 

aluminum; if dislodged example: the control room 

by seismic event, may ceiling diffusers were pose a personnel hazard); secured to T-bars as miscellaneous appropriate; maintenance 

interactions (with lights, on the valves with 

bins, carts, etc.) for inadequate clearance was 

motor control centers requested; loose internal 

(MCCs), switchgears, "shipping" bolts on batteries, and inverters; transformers were valves with inadequate tightened; anchored heat 

clearance; loose internal tracing cabinet was "shipping" bolts on welded to foundation pad; 

transformers; MCCs, I&C cabinets, 

Unanchored heat trace battery chargers, and 

cabinet located in the breakers that were not tied 

vicinity of MCC; some together were tied 

MCCs, instrument and together. 

control cabinets, battery 

chargers, and breakers 

were not tied together 

posing an impact issue. 

Callaway 0.3g HCLPF 21 anomalies/open issues were Outliers had calculated All outliers have - Remounted hand-held 

identified; some outliers were HCLPF capacities HCLPF capacities extinguishers. identified, exceeding 0.3g. exceeding 0.3g. - Trimmed floor grating. 

- MCCs bolted to walls. 

- Missing shear pins 

installed on AFW pump. 

- Procedures and signs for 

storage of transient 

equipment. 

- Procedure for securing 

chain hoists. 

Clinton 0.3g HCLPF None. None. 0.3g No plant improvements 

are needed. 

Comanche Peak SSE Some minor anomalies and No SSE outliers were Not applicable. Follow-up actions to 

l&2 maintenance concerns were identified. resolve: 

identified. 

- Unanchored non-plant 

equipment near safety 

equipment in control 

room. 

- Insufficient clearance 

between an MCC and 

cable tray support.

2-26
Table 2.7: Seismic outliers and improvements for SMA plants (Continued)

Walkdown 

Plant screen Anomalies & outliers Controlling outliers HCLPF capacities (g) Plant improvements 

Cooper 0.3g HCLPF Several outliers (mostly For IPEEE: The At least 0.3g A-46 plant. Most issues 

interaction issues) identified in vibration-isolated air resolved under A-46. 

combined A-46AIPEEE handling systems (with Upgrade of "seismic 

walkdown; some items with an estimated HCLPF vulnerabilities" in fire 

HCLPF less than 0.3g capacity of 0.21g, suppression system two 

removed from SSEL electric drive pumps, one 

after additional system diesel driven pump. Water 

analysis); Four seismic storage tanks). 

vulnerabilities in the fire 

suppression systems two 

electric drive pumps 

depend on offsite power, 

the fuel oil tank of the 

diesel driven pump have 

low seismic capacity, all 

pumps are housed in a 

block wall structure, and 

the water storage tanks 

are flat bottom tanks 

supported on a ring 

foundation), 

Crystal River 3 SSE No additional outliers other None from IPEEE. Not applicable. All outliers were resolved 

than the existing USI A-46 and no additional 

outliers improvements were made 

beyond the USI A-46 

program. 

Davis-Besse 0.2g No plant vulnerabilities Based on HCLPF 0.26g A-46 plant. Outliers have 

beyond the findings of the calculated for a limited been identified for 

A-46 program were identified number of items: resolution under the A-46 

in the IPEEE. masonry walls near 480V program. In addition, 

essential MCC (0.26g); restraint of two flammable 

BWST (0.28g). compressed gas bottles on 

auxiliary building. 

Dresden 2&3 0.3g HCLPF Besides A-46 outliers there are Buckling of condensate 0.20g An A-46 plant. No plan to 

no significant concerns storage tank (0.20g); make improvements 

identified as a result of the Diesel Fuel Oil Storage beyond those required for 

seismic margins assessment. Day tank (0.26g resolution of A-46; no 

controlled by adjacent plan to improve items that 

masonry wall); Torus meet or exceed the design 

Suppression Chambers basis requirement of Q.20g 

(0.28g controlled by PGA (and thereby meet 

torus shell stress); and Dresden's intention to 

about 20 electrical ensure that all IPEEE 

equipment anchorage components have a 

capacities are also listed seismic capacity that 

between 0.20g and 0.30g complies with design 

PGA. requirements).

2- 27
Table 2.7: Seismic outliers and improvements for SMA plants (Continued)

S~~Walkdown 

Plant screen Anomalies & outliers Controlling ouiliers HCLPF capacities (g) Plant improvements : 

Duane Arnold DBE 109 outliers were identified for Seismic qualification of Not applicable. Outliers that could not be 

combined A-46 and IPEEE a masonry wall; potential resolved by calculation, 

fall of control room e.g., anchorage outliers in 

ceiling elements onto the A-46 evaluation report 

critical equipment; were resolved by plant 

anchorage adequacy; two maintenance action or 

air handlers in the HPCI modification. 

room which were 

identified as flood/spray The concerns regarding 

outliers; and gas storage the three gas storage 

bottles that were bottles were resolved by 

inadequately restrained, providing adequate 

restraint or removing the 

bottles from the area. 

Farley 1&2 SSE A total of 117 outliers were List of outliers is in Not applicable. Actions of resolution 

identified in A-46/IPEEE Appendix A. Outliers involve: 

include LRRs and anchor - installing restraining 

bolts. wires for overhead lights; 

- replacing anchor bolts; 

- bolting panels to walls or 

bolting cabinets together; 

- installing missing 

screws; and 

- performing additional 

detailed analysis. 

Fermi 2 0.3g HCLPF Minor hardware deficiencies The plant was found to 0.3g after completion of - Improved maintenance 

(largely associated with be seismically rugged in a few plant training to minimize minor 

maintenance activities) that upon completion of modifications, hardware deficiencies; 

the few plant - improved operator 

modifications and training and simulator 

corrective maintenance training to handle seismic

activities discussed induced scenarios; 

below, all structures, - replacement of four (4) 

systems, and components low-ruggedness relays; 

required for the two - bolting relay panels 

identified safe shutdown together to reduce chatter 

paths met the seismic probability; 

capacity requirements of -strengthening of seismic 

the 0.3g RLE. support for an air dryer; 

and 

- two (2) instrument 

panels. 

FitzPatrick 0.3g HCLPF Seismic-induced structure The failure of emergency 0.17g A-46 plant. Strengthen 

failures diesel generator building block walls in EDG 

and electric bay block building; and close 

walls (0.17g); hydrogen line in the event 

the failure of the of earthquake (procedure). 

containment atmosphere 

dilution (CAD) building 

with a HCLPF of 0.22g.; 

failure of the hydrogen 

line in the turbine 

building was identified.

2-28
Table 2.7: Seismic outliers and improvements for SMIA plants (Continued)

Walkdown 

Plant screen Anomalies & outliers Controlling outliers HCLPF capacities (g) Plant improvements 

Fort Calhoun 1 0.3g HCLPF Several outliers were Relays 0.01g Replacement of bad actor 

identified. MCCs (anchorage) 0.05g relays; improvement of 

Service building 0.10g MCC anchorages; raw 

Fire pumps 0.1g water system tie-in to the 

Turbine building. 0.10g emergency feedwater 

DG air receiver 0.17g storage tank (EFWST); 

RWS heat exchangers 0. 17g and others 

CST 0.17g 

MCCs (anchorage) 0.24g 

Liquefaction 0.25g 

Transformer 0.25g 

MCCs (anchorage) 0.27g 

RWS pump 0.29g 

Ginna 0.3g HCLPF 52 items of equipment could All components meet 0.2g. None. No further work 

not be screened out; their existing licensing will be performed by 

approximately 90 items of basis. RG&E with respect to 

equipment were identified as seismic issues outside of 

being vulnerable to block those related to USI A-46 

walls; the Reactor Makeup closeout. Under various 

Water tank and the Monitor programs (e.g., SEP), 

tank, if failed, can cause the RG&E has conducted 

interruption of one or more of extensive reevaluations of, 

the systems selected for the and made upgrades to, 

second success path (for small Ginna's structures, 

LOCA). systems, and equipment, 

using a 0.2g Regulatory 

Guide (RG) 1.60 spectrum 

as seismic input. 

Grand Gulf 1 SSE One potential vulnerability to The grouted condition for Not required for Pipe support at penetration 

a seismic event was identified the penetration of the reduced-scope. was modified to coincide 

and corrected. Standby service water with a design basis piping 

(SSW) piping in the analysis assumption. A 

Control Building, which number of "design 

had the potential to enhancements" were 

induce significantly high implemented, including 

seismic stresses in the issuance of a new 

piping between the standard, GGNS-08-17, to 

buildings, was not address seismic 

accounted for in the housekeeping problems; 

stress analysis of the securing of "S" hooks on 

piping systems. lighting fixtures; 

installation of missing 

clips and screws on 

several items; and revision 

to several design basis 

calculations.

2-29
Table 2.7: Seismic outliers and improvements for SMA plants (Continued)

Walkdown 

Plant screen Anomalies & outlers Controlling outliers HCLPF capacities (g) Plant improvements 

H.B. Robinson 2 0.3g HCLPF 33 issues/anomalies related to MOV RHR-750 0.28g Concerns for 32 

interactions, maintenance, or MOV RHR-751 0.28g components were 

housekeeping were identified; addressed by maintenance 

47 components were identified actions; enhancements for 

as outliers. 34 components required 

repairs or modifications; 

16 issues involving 

electrical raceways 

involved maintenance of 

modifications; many of 

these concerns are being 

resolved under USI A-46. 

Note: the IPEEE assumes 

USI A-46 improvements 

(which are still to be 

resolved). 

Hatch l&2 0.3g HCLPF A number of outliers, mostly Outliers are listed in 0.3g after certain A-46 plant. A number of 

related to interaction and Table 2 of Appendix I components were outliers were identified 

anchorage issue. (HCLPF would be at modified to raise their and resolved through 

least 0.3g after HCLPF capacities, modifications, repairs, or 

modification). complete replacement in 

order to raise their HCLPF 

capacity to 0.3g. For 

example, control room 

light fixtures were tied up 

to prevent falling; 

anchorage of diesel 

generator relay panel 

motor control centers were 

modified. 

Limerick l&2 SSE (but the Some maintenance and None identified. Not evaluated. Tracking of housekeeping 

0.3g HCLPF housekeeping anomalies were and maintenance issues 

screening observed. 

tables were 

mostly used)

2-30
Table 2.7: Seismic outliers and improvements for SMA plants (Continued) 

W'alkdown 

Plant screen Anomalies & outliers Controlling outliers HCLPF capacities (g) Plant improvements 

Millstone 2 0.3g HCLPF "Vulnerabilities"/outliers. A Seismic capacity of 0.25g for turbine A-46 plant. Improvements 

list of opportunities for safety turbine building (0.25g), building (after made in order to close 

enhancements is in Table 7.1-1 125 VDC emergency Bus improvements for items include: 

of the submittal, and updated (0.26g), Spent fuel Pool components with lower modification of the 

in Attachment 8 of RAI Cooling heat Exchanger HCLPF values). RBCCW Surge tank 

response. (0.26g), 480V buses support, repair of isolation 

(0.28g), RBCCW heat control panel mount 

Exchanger (0.29), and housing, modification to 

equipment related to the anchorage of some battery 

open issues (inverter, racks, and bolt 

0.051 g due to block wall modification of some 

failure; batteries, 0.13g; instrument panels. Other 

125 Vac instrument items were resolved by 

panel, 0.17g; RSST verifying component 

Feeder Breaker, 0.19g; adequacy by calculation oT 

Chilled Water Surge by correcting 

tank, 0.22g. housekeeping problems. 

Open items include: the 

limiting anchorage for the 

RSST Feeder Breaker's 

enclosure expansion, the 

limiting anchorage of the 

Chilled Water Surge tank, 

and the unreinforced status 

ofablock\wall. In 

addition, the three issues 

associated with fire

seismic interaction remain 

open according to 

Attachment 8. These are: 

adequacy of the seismic 

capacity of the Unit 1 

diesel fire pump fuel tank, 

seismic capacity of a long 

run of the fire header 

system piping, and the 

block wall construction of 

the fire pump house. 

Monticello 0.3g HCLPF 21 categories of outliers (39 The controlling outliers Fragilities calculations Three USI A-46 

components, in total) were were not identified, were performed for 4 improvements: 

identified. components, indicating 

HCLPF capacities Fastening of U-bolts on 

exceeding 0.3g. diesel generator starting 

air receivers. 

Other outliers were 

assumed to have Eliminating the potential 

HCLPF capacities impact of an HVAC duct 

equal to the SSE. on a relay panel. 

Upgrading light fixtures in 

the control room to have a 

means of anchorage 

independent of the T-bar 

supports.

2-31
Table 2.7: Seismic outliers and improvements for SMA plants (Continued) 

Walkdown 

Plant screen Anomalies & outliers Controlling outliers HCLPF capacities (g) Plant improvements 

Nine Mile Point 0.3g HCLPF A number of outliers were Battery boards I I and 12 0.27g A-46 plant. A list of 

identified (on anchor/support (0.27g); containment improvement initiatives to 

and interaction), spray raw water pumps be resolved in refueling 

(0.29g); all others (0.3g outage 14 was provided. It or better). includes installation of 

control room panel top 

cross ties, and 

improvements ofwelds 

and anchoring of power 

boards and control room 

cabinets. 

Nine Mile Point 0.5g HCLPF See Table 2.4. Nitrogen bottles 0.23g See Table 2.4. 

2 

HFA Model 154 Relay 0.45g 

North Anna 1&2 0.3g HCLPF A number ofoutliers - tank Emergency Condensate 0.I6g A-46 plant. Problems with 

overturning moment capacity, Storage tanks (0.16g); 58 items of electrical and 

anchorage, and relay capacity. RWST tank (0.18g); 120 mechanical equipment, 

Vac bus (0.19g); including 3 tanks, have 

Refueling Water been resolved via field 

Chemical Addition tank modification. In addition, 

Unit 1 (0.19g), Unit 2 several minor deficiencies 

(0.24g); Boric Acid tanks for cable and conduit 

(0.21g); Control Room raceways were resolved. 

air conditioners (0.2 1g); The remaining unresolved 

Sequence of Events issues, consisting of 

Recorders (0.22g); 4kV seismic induced fire/flood 

Emergency Bus (0.23g); evaluations, housekeeping 

Reactor trip Breakers issues, control room (0.24g); heating and ceiling review, etc., are ventilation chiller Units scheduled to be resolved 

(0.27g); SG blowdown by the end of the North 

containment isolation Anna Unit I refueling 

valves (0.28g); CCW outage, scheduled to start 

pumps (0.29g). in April 2000. 

Palo Verde 0.3g HCLPF None identified. However, the None. 0.3g. Some modifications were 1,2,&3 submittal notes that the carried out to improve 

walkdown identified a limited plant seismic capacity. number of actions which need For example, the 

be taken to improve plant anchorage on the 

seismic capacity, but the bookshelves behind the 

submittal provides no listing of control cabinets in Unit 3 

these actions. (not 2) was improved. 

Peach Bottom 0.3g HCLPF At least 168 components or RHR heat exchangers 0.20g Numerous USI A-46 

2&3 conditions could not be (anchorage) and/or IPEEE 

screened out, based on over 45 Block walls in reactor 0.20g improvements are planned 

outlier issues/concerns building to address anchorage, identified. HP SW pumps serving 0.21g equipment support, and 

RHR HX (interaction) 0.23g housekeeping and 

Fans 0AK32, 0BK32, maintenance concerns. 

and OCK32 

tanks 2BE24, 2CE24, 0.24g 

3BE24, 3CE24, and 

(anchorage). Five other component 

categories have HCLPF 

capacities less than 0.3g

2-32
Table 2.7: Seismic outliers and improvements for SMA plants (Continued)

Walkdown 

PlIa nt screen Anomalies & outliers Controlliflg outliers HCLPF capacities (g) Plant imaprovemnents, 

Perry 1 0.3g HCLPF Four outliers were not None. 0.3g. Four outliers that did not 

screened out for further screen out are 1) 

analysis (they were all spatial maintenance test bench, 2) 

interaction issues, and good operations electrical 

housekeeping was considered locker, 3) switchgear 

sufficient to resolve these trolleys, and 4) control 

concerns). room furniture. They 

involve spatial interaction 

and are considered 

housekeeping items and n 

plant modifications were 

needed. 

Prairie Island 0.3g HCLPF Outlier requiring minor component cooling water 0.28g A-46 plant. Correction of 

1&2 maintenance activity (This heat exchangers (0.28g); spatial interactions 

outcome takes credit for all others (0.3g or involving unrestrained 

outlier resolution of 22 greater). scaffolding and ladders 

components under the A-46 were carried out (through 

program). maintenance activities). 

Quad Cities 1&2 0.5g HCLPF 107 items of equipment and 8 Failure of cable tray 0.09g, 010g, 0.1 lg, An extensive number of 

and 0.3g electrical raceway systems systems (inadequate 0.16g, 0.22g plant improvements or 

HCLPF were identified as USI A-46 anchorage or frame other actions are being 

outliers, capacity), undertaken to resolve 

Racks (anchorage). 0.1 ig identified USI A-46 

Switchgear (anchorage). 0.13g, 0.22g, 0.23g, outliers. These 

0.24g, 0.28g improvements pertain 

Silencers (anchorage). 0.18g, 0.22g primarily to enhancing 

Chargers (anchorage). 0.22g anchorage/support 

Cubicle coolers 0.23g capacity and reducing or 

(anchorage). eliminating the potential 

MCC, Switchgear, 0.24g for adverse interactions. 

Transformers 

(anchorage). 

In total, 24 categories of 

components (comprising 

about 58 items of 

equipment) were 

ultimately determined to 

have HCLPF capacities 

less than the 0.3g. 

River Bend SSE None identified. None. Not required for None. 

reduced-scope. 

Sequoyah 1&2 0.3g HCLPF A design-related deficiency, RHR heat exchangers 0.27g - Replacement of MCC 

four anomalous conditions, anchorages; 

and were identified. 

- upgrade of RHR heat 

exchanger anchorages; and 

- corrective changes to 

eliminate interactions.

2- 33
Table 2.7: Seismic outliers and improvements for SMA plants (Continued)

Walkdown Plant screen Anomalies & outliers Controlling outliers HCLPF capacities (g) Platimprovemens 

Shearon Harris 1 0.3g HCLPF 13 issues related to RHR heat exchangers 0.29g Repair and modification 

maintenance, housekeeping (0.29g); all others (0.3g work was scheduled to be 

and seismic interaction that or greater). completed by the end of 

required work orders; six items refueling outage RFO-7 

were found to require repairs (Tables 5.3 and 5.4 of the 

or modifications; five submittal). Alternative 

instruments are powered from instruments or actions 

sources that may not be have been identified and 

available after a seismic event; site abnormal operating 

and an interaction issue was procedures are being 

found regarding the potential updated to address the 

for a first aid storage cabinet alternate instruments. A 

to fall on a Halon bottle Halon bottle located in a 

located in the stairwell of the stair well was relocated to 

RAB 286 ft. avoid damage from a 

falling first aid storage 

cabinet. 

St. Lucie l&2 SSE Unit 1: 11 anchorage None reported having Several significant 

concerns; low capacity of HCLPF capacity less improvements to 

CCW surge tank platform; and than SSE anchorages; maintenance 

three interaction concerns actions; and 

Unit 2: two interaction implementation of a strict 

concerns; four maintenance housekeeping policy 

issues 

Summer 0.3g HCLPF Outliers related to interaction The plant HCLPF should 0.3g for plant. Bolting together adjacent 

concerns, missing lateral be 0.3g or greater with electrical cabinets at 17 

support, and the use of ceramic the exception of the earth locations throughout the 

components in the neutral dams and embankment plant to remove interaction 

grounding resistor, that have an HCLPF of concerns, providing lateral 

0.22g (and with no cost support for the isolation 

effective solutions to fix valve where the support 

it). was missing, and 

performing analysis to 

show adequate HCLPF 

value for the neutral 

grounding resistor that use 

ceramic components. 

Susquehanna 0.3g HCLPF Some anomalies and Interactions: Trolleys removed from 

l&2 maintenance concerns were HPCI pump discharge 0.21g switchgear cabinets. (Two 

noted; numerous outliers were valve anomalies and three 

identified. Suppression pool inlet 0.21g housekeeping concerns are 

valve being tracked.) 

Automatic transfer 0.25g 

switch MCC 0.26g 

Turkey Point SSE 26 anchorage/support CST 0.11 g Plant actions, analyses, or 

3&4 concerns, 12 interaction RWST 0.1 Ig enhancements were 

hazards, two functional Diesel Oil tank 0.21 g undertaken to resolve all 

concerns, and some seismic Note: These capacities outliers as part of USI A

housekeeping issues were are for the upgraded 46. 

identified condition.

2-34
Table 2.7: Seismic outliers and improvements for SMA plants (Continued)

NWalkdlown 

Plant screen Anomalies & outliers Controlling outliers HCLPF capacities (g) Plant improvements 

Vermont Yankee 0.3g HCLPF A number ofoutliers were Condensate Storage tank 0.25g A-46 plant. A-46/IPEEE 

identified in A-46/IPEEE, (0.25g); Diesel Fuel Oil outliers were resolved to 

mostly related to interaction Storage tank (0.29g). All meet A-46 criteria; reroute 

and anchorage/support others (will meet or the fuel line tubing of the 

concerns, and the use of some exceed the 0.3g review- diesel fire pump fuel tank; 

old batteries (more than 10 level earthquake upon enhance the support of the 

years old). resolution of A-46 fire system standpipe. The 

outliers). CST will not be upgraded 

because there is no simple 

cost effective 

enhancement method. 

Vogtle 1&2 0.3g HCLPF Twenty-four open items for None. 0.3g Open items were 

each unit, mostly interaction scheduled to be resolved 

issues. by August 1, 1996. They 

included a gap between 

the battery rack end rails 

ahd batteries, potential 

interactions between the 

diesel generators and 

crane controller, etc. 

Waterford 3 SSE No outliers that are operability None. Not required for All loose items in Control 

issues at the plant; three reduced-scope. Room were corrected 

unresolved issues, not (removed or restrained the 

considered significant to lockers and file cabinets in 

seismic risk, but related to the control room, removed 

conforming with standard book shelves in the 

practice in seismic design vicinity ofsafety-related 

(loose items in the Control cabinets, and relocated or 

Room; station air pipe not restrained other loose 

meeting clearance items in the vicinity of 

requirements; and storage of safety-related cabinets). 

temporary equipment). Inadequate clearance 

issues were resolved; 

reasons why the existing 

clearance is acceptable 

were documented. Proce

dure to prevent hazardous 

seismic interactions for 

transient combustibles was 

instituted. 

Watts Bar I 0.3g HCLPF None, other than some minor None. 0.3g or greater No plant improvements 

maintenance and housekeeping related to the seismic 

issues which were disposition- analysis were identified or 

ed, and for which work re- carried out. 

quests were written as needed. 

Wolf Creek 0.3g HCLPF Five categories of equipment RWST The outliers were all Resolutions of three 

(a few did not satisfy the screening turbine building assigned an HCLPF housekeeping issues and 

components criteria. Four, 60-cell batteries capacity of 0.20g, based four equipment installation 

were screened and racks on judgment. concerns are planned or 

at 0.5g Miscellaneous equipment 12 LSELS/ESFAS have been implemented. 

HCLPF) installation and housekeeping cabinets 

concerns were identified. Strainers and screens. A performance improve

ment request related to 

placement of transient 

equipment was issued.

2-35
Table 2.8: Containment performance for SMA plants 

HCLPF 

Plant Containment type Walkdown findings/outliers capacity (g) Plant improvements 

Arkansas Nuclear Large dry type; steel-lined No major vulnerabilities that will Not reported. Inadequate support for the RB 

One 1 prestressed-concrete compromise containment performance Cooling units was identified 

for the RLE were identified. and additional anchorage for 

these units has been installed. 

Arkansas Nuclear Large dry type; steel-lined No vulnerabilities that will Not reported. None. 

One 2 prestressed-concrete compromise containment performance 

were identified. 

Braidwood 1&2 Large dry type; steel-lined The walkdown did not identify any Nor reported. None. 

prestressed-concrete early containment failure 

vulnerabilities. 

Browns Ferry 2&3 Mark I; steel containment No vulnerabilities in the containment Not reported. None. 

isolation system, relays, containment 

isolation valves, or containment 

penetrations due to an RLE event were 

identified. 

Brunswick l&2 Mark I; reinforced-concrete, No outliers or anomalies were HCLPF capacity None. (However, may be 

steel-lined wetwell reported against large early affected by USI A-46 plant 

failure is at least improvements.) 

0.3g 

Byron l&2 Large dry type; steel-lined The walkdown did not identify any Not reported. None. 

prestressed-concrete early containment failure 

vulnerabilities. 

Callaway Large dry type with steel- No outliers or anomalies were HCLPF capacity None. 

lined, post-tensioned reported against early failures 

reinforced concrete is at least 0.3g 

Clinton Mark III; reinforced- The containment and components are Not reported. None. 

concrete drywell, steel-lined seismically rugged for the RLE. 

reinforced-concrete wetwell 

Comanche Peak Large dry type, with steel- No outliers or anomalies were Not applicable. None. 

1&2 lined reinforced concrete reported. 

structure. 

Cooper Mark I; steel containment No concerns specifically pertaining to Components were None. 

early containment failure were included in the SSEL 

identified, or screened for 0.3 g 

PGA RLE. 

Crystal River 3 Large dry type; steel-lined The walkdown did not identify any Not reported. None. 

prestressed-concrete early containment failure 

vulnerabilities. 

Davis-Besse Large dry type; steel No containment vulnerabilities were Not reported. None. 

containment found

2-36
Table 2.8: Containment performance for SMA plants (Continued)

HCLPF 

Plant Containm ent type W alkdown findings/outliers capacity (g) Plant improvements 

Dresden 2&3 Mark I; steel containment The walkdown did not identify any Not reported. None. 

vulnerabilities associated with early 

containment failure due to a postulated 

seismic event. 

Duane Arnold Mark I; steel containment Important equipment essential to Not reported. None. 

containment performance was 

included in the SSEL and reviewed by 

the SRT during the walkdown. 

Farley l&2 Large dry type; steel-lined No concerns specifically pertaining to Not reported. None. 

prestressed-concrete early containment failure were 

identified. 

Fermi 2 Mark I; steel containment No vulnerabilities in the containment Not reported. None. 

isolation system, relays, containment 

isolation valves, or containment 

penetrations were identified. 

FitzPatrick Mark I; steel containment The licensee found no containment HCLPF capacity None. 

vulnerabilities. against early failures 

is at least 0.3g 

Fort Calhoun I Large dry type; steel-lined Not reported; a quantitative Level 2 Not reported. No improvements were made 

prestressed-concrete analysis was performed, indicating specifically to address 

that the conditional probability of containment performance. 

large early release, given seismic core 

damage, is about 1%. 

Ginna Large dry type; steel-lined The review did not identify any Not reported. None. 

prestressed-concrete features which would give rise to an 

early containment failure concern. 

Grand Gulf 1 Mark I1; reinforced- The submittal states that containment Not reported. None. 

concrete drywell, steel-lined isolation was factored into the SSEL. 

reinforced-concrete wetwell However, no specific information is 

provided. 

H.B. Robinson 2 Large dry type, of Potential interfacing systems LOCA Reported HCLPF None. The potential ISLOCA 

prestressed concrete with a (ISLOCA) inside containment due to capacity against concem was evaluated as being 

steel liner. MOV failures, large-early failure of adequate for the RLE. 

at least 0.3g. 

Hatch l&2 Mark I; steel containment No outliers or anomalies were HCLPF capacity None. 

reported. against early failures 

is at least 0.3g PGA. 

Limerick l&2 Mark It; reinforced-concrete No outliers or anomalies were Not reported, None. 

drywell, steel-lined reported. although' all 

reinforced-concrete wetwell components 

essentially screened 

at 0.3g HCLPF. 

Millstone 2 Large dry type; steel-lined No safety-related concerns were Not reported. None. 

prestressed-concrete found.

2-37
Table 2.8: Containment performance for SMA plants (Continued)

HCLPF 

Plant Containment type Walkdown findings/outliers capacity (g) Plant improvements 

Monticello Mark I; steel containment No concerns or additional seismic Not reported. None. 

outliers were reported. 

Nine Mile Point 1 Mark 1; steel containment No containment vulnerabilities were Not reported. None. 

found. 

Nine Mile Point 2 Mark II See Table 2.5. HCLPF capacity None. 

against large early 

release was not 

reported. 

North Anna 1&2 Subatmospheric No vulnerabilities were noted in the Not reported. None. 

containment; steel-lined containment walkdown. 

reinforced-concrete 

Palo Verde 1,2,&3 Large dry type; steel-lined Only one minor concern with Not reported. None. 

prestressed-concrete containment penetration was observed 

and resolved by analysis. 

Peach Bottom Mark I; steel containment None in addition to those encountered Not reported. No additional plant 

2&3 in evaluation of success paths improvements beyond those 

(components to avert early already identified for success 

containment failure were included in path equipment. 

success paths). 

Perry I Mark III; reinforced- No vulnerabilities in the containment Not reported. None. 

concrete drywell, steel isolation system, relays, containment 

wetwell isolation valves, or containment 

penetrations due to an RLE event were 

identified in the IPEEE. 

Prairie Island 1&2 Large dry type; steel No concerns specifically pertaining to Not reported. None. 

containment early containment failure were 

identified. 

Quad Cities l&2 Mark I; steel containment No concerns specifically pertaining to None reported. None, beyond those already 

early containment failure were identified for success path 

identified. equipment. 

River Bend Mark III; reinforced- No concerns specifically pertaining to Not reported. None. 

concrete drywell, steel early containment failure were 

wetwell identified. 

Sequoyah 1&2 Ice Condenser; steel Walkdown revealed no anomalies or HCLPF capacity None. 

containment outliers, against large-early 

failure of at least 

0.3g. 

Shearon Harris 1 Large dry type; steel-lined An interaction concern was raised, Not reported. None. The interaction issue 

reinforced-concrete which involved a platform in the identified in plant walkdown 

equipment hatch at 286 ft elevation, was evaluated and determined 

not to be detrimental to the 

containment integrity.

2-38
Table 2.8: Containment performance for SMA plants (Continued)

HCLPF 

Plant Containment type Walkdown findings/outliers capacity (g) Plant improvements 

St. Lucie 1&2 Steel vessel surrounded by a No evaluation was conducted. No evaluation was None. 

reinforced-concrete conducted. 

biological shield, with an 

annular space in between. 

Summer Large dry type; steel-lined No concerns specifically pertaining to Not reported. None. 

prestressed-concrete. early containment failure were 

identified. 

Susquehanna 1&2 Mark II; reinforced-concrete None. (No comprehensive walkdown Insufficient None. 

drywell, steel-lined of containment safeguards; only evaluation to 

reinforced-concrete wetwell piping/valves and containment determine. 

structure were considered.) 

Turkey Point 3&4 Large dry type of steel-lined No evaluation was conducted. No evaluation was None. 

post-tensioned reinforced- conducted. 

concrete. 

Vermont Yankee Mark I; steel containment The containment performance Not reported. None. 

evaluation does not identify any 

vulnerabilities associated with early 

containment failure due to a postulated 

seismic event. 

Vogtle 1&2 Large dry type; steel-lined No concerns specifically pertaining to Not reported. None. 

prestressed-concrete early containment failure were 

identified. 

Waterford 3 Large dry type; steel No concerns specifically pertaining to Nor reported. None. 

containment early containment failure were 

identified. 

Watts Bar 1 Ice condenser; steel No vulnerabilities were noted in the Not reported. None. 

containment containment walkdown. 

Wolf Creek Large dry type, steel-lined, Containment cooling and isolation HCLPF capacity None. 

reinforced, post-tensioned systems were included in equipment against early failure 

concrete list; no outliers were identified. of at least 0.3g. 

Missing bolts on one seated beam 

connection (later found to be 

addressed in existing plant design 

documents). 

Instances were found where conduits 

interfere with the seismic isolation gap 

between the containment steel liner 

and the operating floors within the 

reactor building. These were judged 

to be sufficiently spaced so as not to 

be a significant concern.

2-39
Table 2.9: Relay evaluation 

Low-ruggedness relays Related plant 

Plant Treatment identified Safety implications improvements 

Arkansas USI A-46 and IPEEE relay There were 48 relay outliers None of the identified Relay outliers are being 

Nuclear One 1 evaluation performed as a result of the relay outliers represented any tracked for resolution as 

simultaneously. full capacity screening process. 92 relays adverse operability part of the USI A-46 

versus demand screening, in have unknown capacities and issues. program. 

accordance with the GIP, require further research. No 

was performed on all relays. "bad actor" relays were 

identified. 

Arkansas USI A-46 and IPEEE relay There were 10 relay outliers None of the identified Relay outliers are being 

Nuclear One 2 evaluation performed as a result of the relay outliers represented any tracked for resolution as 

simultaneously. full capacity screening process. 198 relays adverse operability part of the USI A-46 

versus demand screening, in have unknown capacities and issues. program. 

accordance with the GIP, require further research. No 

was performed on all relays. "bad actor" relays were 

identified. 

Beaver Valley I Relays were not included in None in IPEEE. None Relays, including "bad 

the PRA model. The actor" relays are 

licensee screened out from resolved via the 

the analysis any relay USI A-46 program. 

actuating devices which 

depend on offsite power. 

Beaver Valley 2 Relays were not modeled in Two LRRs were found within The two LRRs will not None. 

the PRA, as they were the IPEEE scope. impact the plant 

deemed to pass the 0.3g response following a 

review-level earthquake seismic event. 

criterion. 

Braidwood 1&2 Relay chatter evaluation None of the relays were of the None. Inadvertent None. 

consists of identifying low- low-ruggedness type as listed actuation of the CO, 

ruggedness relays that may in Appendix E of EPRI NP- fire protection system 

affect SSEL equipment 7148-SL; a non-safety related (using a mercury relay) 

functions, using the list in mercury relay for the CO2 fire does not impact the 

EPRI-NP-7148-SL, protection system was operation of the EDGs. 

Appendix E. identified as a poor performer. 

Browns Ferry The identification None identified for IPEEE. None for IPEEE. None. 

2&3 procedures followed the GIP Relays which have not been Problem with IPEEE

for the A-46 relays and were screened will be labeled as specific relays and their 

expanded for IPEEE. outliers in the A-46 program, resolutions were not 

with additional review or identified. 

resolution to be performed. 

Brunswick l&2 USI A-46 relay evaluation, Several identified, four in The IPEEE-only relays Concerns are being 

expanded to IPEEE-only IPEEE-only circuitry (for were found acceptable addressed under 

circuitry. containment performance). based on consequence USI A-46. 

review; others are being 

addressed in USI A-46.

2 - 40
Table 2.9: Relay evaluation (Continued)

Low-ruggedness relays Related Plain 

Plant Treatment identified Safety implici•• i ons ixipý-ove ien•ts 

Byron 1 &2 The relay study focused on None. The very few outliers None. Nonsafety relays None. 

identifying low-ruggedness identified, were found either were also included in 

relays by looking through not to affect safe shutdown or the study. An example 

the database to find relays to have been of nonsafety relays is 

generically known to be of modified/designed to conform the relays controlling 

low-ruggedness to the higher acceleration the ventilation dampers 

(Westinghouse COM-5 and level specifications. (and also CO2 

SSC-T relays), discharge) in the diesel 

generator rooms. CO2 

discharge will not affect 

the operation of the 

diesel generators. The 

closing of the ventila

tion dampers will be 

dealt with by operator 

procedures created to 

provide instructions to 

the operators on how to 

restore ventilation to 

the diesel generators. 

Callaway Documentation-based Some low-ruggedness relays Relay chatter was None. 

evaluation to identify low- were identified. determined to be 

ruggedness relays and acceptable with respect 

determine consequences of to safe shutdown of the 

chatter, spot-check of relay plant. 

installations, 

Calvert Cliffs The relay chatter was not The A-46 program found no None None 

1&2 included in the seismic bad actor relays. 

IPEEE analysis. 

Catawba l&2 Low-ruggedness evaluation; One, in a diesel generator Modeled in seismic None. 

relay chatter and recovery maintenance and testing PRA. 

actions modeled in SPRA. circuit. 

Clinton EPRI-NP-7148-SL was used 22 low-ruggedness relays: None. Walkdowns were None. 

for the screening. A circuit model numbers: GE CEH, performed to verify 

analysis was then performed GE HGA, W SSC. seismic adequacy of the 

for relays that were screened identified LRRs. In 

in. addition, the plant 

seismic qualification 

test records indicated 

that these relays are 

capable of withstanding 

the CPS SSE without 

compromise of 

structure or electrical 

function.

2-41
I 

Table 2.9: Relay evaluation (Continued) 

Low-ruggedness relays Related plant Plant Treatment identified Safety implications improvements 

Columbia Relays were screened using None reported. Relay chatter modeled None. 

Generating* a generic screening criterion in PRA, and no that is consistent with the recovery was modeled 

guidelines in Appendix Q of in the logic model. 

EPRI NP-604 1. 

Comanche Peak None, and none required None, not applicable. Not applicable. None. 

l&2 (non-USI A-46 reduced

scope plant). 

Cooper USI A-46 and IPEEE None identified. None. None. 

evaluation. The screening 

techniques used were similar 

to those utilized for the more 

strict USI A-46 relay review. 

Crystal River 3 Not required for reduced- None for IPEEE. None. None. 

scope IPEEE plant. Relay 

evaluation was performed as 

part of the plant's USI A-46 

program, completed before 

the initiation of the IPEEE 

evaluation. 

D.C. Cook l&2 USI A-46 relay evaluation, A number of low-ruggedness Being addressed under Licensee plans to expanded to IPEEE-only relays were identified, none in USI A-46. replace low-ruggedness circuitry. IPEEE-only circuitry, relays affecting safety 

equipment. 

Davis-Besse Relay evaluation performed None for IPEEE. No relays None. In the case of the None. as part of A-46 program, beyond the ones identified in pump motor circuits, expanded for IPEEE. the A-46 program were where low-ruggedness 

identified as low-ruggedness. Westinghouse ITH 

relays are employed for 

ground fault detection 

in the 4 kV high 

pressure injection and 

makeup pump motor 

circuits, these relays are 

not of the lockout type 

and, therefore, the 

tripped pump can be 

simply restarted from 

the control room. 

Diablo Canyon Relay evaluation in LTSP. None in IPEEE. Modeled in seismic None. 

1 &2 PRA. 

Dresden 2&3 Joint A-46/IPEEE program. All relays have been Walkdown of a group Resolution of a group 

evaluated except for those of relays associated of relays associated 

associated with the Isolation with the Isolation with the Isolation 

Condenser system Condenser system is Condenser system is 

(approximately 65% of the still needed, as the plant still pending. 

relays). status permits.

2 - 42
Table 2.9: Relay evaluation (Continued)

Low-ruggedness relays Related plant Plant Treatment identified Safety implications improvements 

Duane Arnold Not required for reduced- None. None. None. 

scope plant. USI A-46 

evaluation. 

Farley 1&2 Not required for reduced- None. None. None. 

scope plant. A USI A-46 

relay evaluation was 

performed per the SQUG 

GIP for Unit 1. Although 

not required, an evaluation 

of relay chatter is being 

performed for Unit 2 as a 

prudent measure. 

Fermi 2 The relay study focused on Six low-ruggedness relays During a severe seismic Four LRRs for the plant 

identifying low-ruggedness were identified in the review event, it is expected that electrical systems were relays, in accordance with of plant electrical systems. Of many spurious alarms identified for 

the guidance in NUREG- these, four were identified for will be received in the replacement, and a new 

1407 for focused-scope replacement; two were control room due to low seismic simulator 

plants not included in the evaluated to have no effect on seismic ruggedness training event has been 

USI A-46 program. The the operability of systems. relay chatter. Although established for spurious licensee reviewed all safety- 214 low-ruggedness relays this may not have a alarms in the control 

related systems to identify were identified in the review direct effect on safe room due to low 

low-ruggedness relays. of plant control systems, and plant shutdown, it may seismic ruggedness 

an evaluation of the conse- cause some confusion relay chatter. 

quences of relay chatter indi- in the control room. 

cated that none of these relays This item will also be 

would cause a control system included in the new 

malfunction and, therefore, seismic simulator 

none needed to be replaced. training event. 

FitzPatrick USI A-46 relay evaluation None for IPEEE. No "bad None for IPEEE. All of None. 

expanded for IPEEE. actor" relays were identified the USI A-46 relay 

in the EDG building in the outliers have already 

scope of the IPEEE program. been resolved. 

Fort Calhoun 1 USI A-46 relay evaluation, Six low-ruggedness relays in The low-capacity relays The six low-ruggedness 

expanded to IPEEE-only diesel generator lock-out were assessed as relays are being 

circuitry, circuitry were identified; no limiting the plant replaced as part of USI 

IPEEE-only low-ruggedness HCLPF capacity to A-46 resolution. 

relays were found. 0.01g. 

Ginna Relay chatter review was not None. None. None. 

performed in the seismic 

IPEEE because no low

ruggedness relays were 

found during the resolution 

of the USI A-46 relays. 

Grand Gulf I For reduced-scope plants, Not applicable. Not applicable. Not applicable. 

which are not included in the 

USI A-46 program, a relay 

chatter evaluation is not 

necessary per NUREG-1407.

2 - 43
Table 2.9: Relay evaluation (Continued)

Low-ruggedness relays Related plant 

Plant Treatment identified Safety implications improvements 

H.B. Robinson USI A-46 relay evaluation, No low-ruggedness relays All relays were found None. 

2 expanded to partially address were identified affecting the acceptable based on 

IPEEE-only circuitry. SSEL. capacity screening 

and/or consequence 

assessment. 

Haddam Neck USI A-46 relay evaluation, Several installations of Addressed in USI A-46 The submittal states that 

expanded to IPEEE-only Westinghouse COM-5 relays; and SPRA model. relay chatter is a risk 

circuitry. mercoid relays in actuation outlier to be resolved; 

circuitry for fire protection changes to abnormal 

systems. operating procedures 

(AOPs) have been 

proposed. 

Hatch l&2 USI A-46 relay chatter List is included in the The identified low- None. 

evaluation expanded for submittal. ruggedness relays were 

IPEEE. resolved by 

determining that either 

malfunction of the relay 

is acceptable or 

operator actions can be 

used to reset relays or 

restore systems to 

operation. Therefore, 

all low-ruggedness 

relays identified as part 

of the USI A-46 or 

IPEEE evaluation for 

both units were 

resolved at a HCLPF 

level of at least 0.3g 

PGA. 

Hope Creek Relay chatter was not Approximately 100 The identified None. 

incorporated into the PRA potentially low-ruggedness potentially LRRs were 

model. Screening review at relays (LRR) were identified. all screened out 

the 0.3g level was (because they are not 

performed. associated with safe 

shutdown or 

containment 

performance; they have 

high seismic capacity, 

or chatter is 

acceptable). 

Indian Point 2 USI A-46 relay evaluation, In IPEEE-only circuitry, four Recoverable loss of None for IPEEE-only 

expanded to IPEEE-only Westinghouse SC over- offsite power. (A low circuitry. 

circuitry. current relays used for capacity against 

protection of the station seismically induced loss 

auxiliary transformer, of offsite power is 

already assigned in the 

seismic PRA.)

2 - 44
Table 2.9: Relay evaluation (Continued)

Low-ruggedness relays Related plant 

Plant Treatment identified Safety implications improvements 

Indian Point 3 Based on IPE study and the 12 relays related to the Modeled in the PRA EDG room CO2 system. 

A-46 program, as well as emergency diesel generator model. Chatter was 

examination of the impact of system. assumed regardless of 

chattering of each relay. the level of ground 

motion and recovery 

actions were not 

credited. 

Kewaunee USI A-46 relay evaluation, 12 (Westinghouse SC) low- Being addressed in USI Low-ruggedness relays 

expanded to IPEEE-only ruggedness relays identified, A-46. are to be replaced or 

circuitry, none in IPEEE-only circuitry, circuitry re-worked. 

La Salle 1&2 Not documented. None reported. Not documented. None reported. 

Limerick l&2 Relay evaluation following Five chatter-prone relays were The relays were None. 

EPRI NP-6041-SL identified, evaluated and found to 

guidelines. be acceptable. 

McGuire l&2 Low-ruggedness evaluation; Low-ruggedness relays found Low-ruggedness relays None. 

relay chatter and recovery in alarm circuitry. affect alarm circuitry 

actions modeled in SPRA. only; other relay chatter 

effects are modeled in 

the seismic PRA. 

Millstone 2 USI A-46 program expanded No low-ruggedness relays None for IPEEE. None, 

to include IPEEE were identified as part of the 

components. USI A-46 program. 

Millstone 3 Potentially vulnerable relays Not documented in IPEEE Modeled in SPRA. The licensee updated 

were identified; relay chatter submittal report. AOPs to enhance 

and recovery actions recovery from 

modeled in SPRA. earthquake-induced 

relay chatter. 

Monticello USI A-46 relay evaluation, An extensive list of known All but four of the low- Four low-ruggedness 

expanded to IPEEE-only low-ruggedness GE/HGA ruggedness relays were relays are being 

circuitry. relays, and potential low- found acceptable based dispositioned under 

ruggedness relays, was on configuration or USI A-46. 

reported. (The list includes functional analysis. 

both USI A-46 and IPEEE The remaining four 

relays.) low-ruggedness relays 

are all within the scope 

of USI A-46.

2 - 45
Table 2.9: Relay evaluation (Continued)

Low-ruggedness relays Related plant 

Plant Treatment identified Safety implications improvements 

Nine Mile Point USI A-46/IPEEE evaluation. LRRs were identified and LRRs were evaluated Replace mercury relays 

discussed in the submittal for impact on the safe and modify procedures 

individually, shutdown of the plant. (scheduled to be 

Some LRRs were found implemented by the end 

not to have any impact; of RFO15). 

others were found to 

have a very low 

probability of causing 

problems or to be easily 

restored from the 

control room, or they 

will be evaluated for 

either replacement or 

for improved operator 

procedures, if 

applicable. 

Nine Mile Point Detailed relay evaluation at All relays screened out at Based on a relay None. 

2 0.5g HCLPF. 0.5g, except one (HFA screening and 

Model- 54) which was consequence 

determined to have an HCLPF assessment, the licensee 

capacity of 0.45g. concludes relay chatter 

will not limit the plant 

HCLPF to be below 

0.5g. 

North Anna USI A-46 relay evaluation. None. No relay chatter review None for IPEEE. None. 

1&2 performed because no low

ruggedness relays were found 

at NAPS during the 

evaluation of USI A-46 

relays. A relay chatter 

evaluation was thus not 

performed in the seismic 

IPEEE. 

Oconee 1,2,&3 USI A-46 and IPEEE The overhead power path Modeled in the PRA. Capacity issues for 59 

evaluation, relays were found to have low relays have been 

fragilities, and 142 other low- resolved by analysis 

ruggedness relays were listed and/or testing, six 

for further analysis or relays have been 

replacement. actually replaced with 

an additional 14 relays 

awaiting 

implementation. 

Several other relay 

modification design 

packages are in 

progress, and additional 

relay testing is being 

conducted. Complete 

resolution by 2002.

2 - 46
Table 2.9: Relay evaluation (Continued) 

Low-ruggedness relays Related plant 

Plant Treatment identified Safety implications improvements 

Oyster Creek USI A-46 and IPEEE evalu- Low capacity relays which do Modeled in PRA. No None. 

ation. Relay evaluation was not meet the USI A-46 recovery was modeled 

performed per the guidelines requirements will be replaced. in the logic model. 

of EPRI NP-7148-SL. 

Palisades USI A-46 relay evaluation, A number of low-ruggedness Being addressed in Concerns are being 

expanded to IPEEE-only relays were identified, none in USI A-46; SPRA dispositioned under 

circuitry. IPEEE-only circuitry, modeling is unclear. USI A-46. 

Palo Verde The relay capacities were None identified. (There is a None. None. 

112,&3 examined using two sources: concern on the new Impell 

(1) GERS in EPRI-NP-7147- SASSI analysis. However, it 

SL, and (2) the plant seismic may not have a significant 

qualification test records. effect on conclusion.) 

The relay evaluation was 

documented in accordance 

with EPRI-NP-7148. 

Peach Bottom USI A-46 relay evaluation, A number of low-ruggedness Being addressed in USI Concerns are being 

2&3 expanded to IPEEE-only relays were identified from A-46. dispositioned under 

circuitry, the USI A-46 evaluation; no USI A-46. 

additional low-ruggedness To address seismic-fire 

relays were encountered in interaction concerns, 

IPEEE-only circuitry. mercoid switches are 

The seismic-fire interaction being replaced, and 

assessment identified mercoid procedural controls are 

switches in the fire water being implemented to 

system, and potentially mitigate any effects of 

vulnerable relays in the spurious relay operation 

Cardox system. in the Cardox system. 

Perry 1 The relay evaluation Low-ruggedness relays are RPS system was None. 

consisted of locating low GE HFA relay type used in screened out. Of the 

seismic ruggedness relays in HPCS DG control circuitry sixteen HPCS DG 

accordance with Appendix E and RPS Motor Generator Set relays, 11 are chatter 

of EPRI NP-7148-SL. control circuitry. acceptable, five require 

operator action after the 

RLE. Four of the five 

relays can be reset in 

the HPCS DG room. 

Operator notified of a 

malfunction of the fifth 

relay by annunciators 

and can then manually 

reset tripped breaker. 

Also, at least 25 min. 

available to perform the 

required operators' 

actions per existing 

Alarm Response 

Instructions before RPV 

water at TAF.

2 - 47
L 

Table 2.9: Relay evaluation (Continued) 

PSant Treatv enw 46 resltyion 

Pilgrim BUSI A-46 relay evaluation, Not specified. Being addressed in Concerns are being use of relay generic USI A-46; SPRA addressed under equipment 

spectrum (GERS), ruggedness and modeling of relay USI A-46. chatter assumes USI A

SPRA review. 46 resolution. 

Point Beach USI A-46 relay evaluation, A number of Westinghouse Being addressed in Concerns are being 1&2 expanded to partially address ITH relays. USI A-46; no SPRA addressed under 

IPEEE-only circuitry. modeling of relay USI A-46. 

chatter. 

Prairie Island USI A-46 evaluation None for IPEEE. None for IPEEE. None. 

1&2 conducted following SQUG 

procedures, expanded for 

IPEEE. 

Quad Cities USI A-46 relay evaluation, No low-ruggedness relays None for IPEEE-only As part of USI A-46 l&2 expanded to partially address were reported as existing essential relays. outlier resolution, a IPEEE-only circuitry, within the list of essential "bad actor" mercoid 

IPEEE-only relays. switch (PE-1) is being 

replaced. 

River Bend Not required for IPEEE. A Not applicable. Not applicable. None. 

reduced-scope plant not 

included in USI A-46 

program. 

Salem l&2 The licensee did not Approximately 100 None. All relays were None. Some of the 

incorporate relay chatter into potentially low-ruggedness screened out because identified LRRs have 

the PRA model. Instead, a relays were identified. Some LRRs are not associated already been replaced screening review at the 0.3g of the identified LRRs have with safety shutdown or with higher seismic 

level (which was the plant's been replaced with higher containment capacity relays. review level earthquake) was seismic capacity relays, performance; relay performed, including the 4 kV Phase chatter is acceptable; 

A/B/C diesel generator the LRRs have high 

differential relays. seismic capacity. 

San Onofre 2&3 Rigorous treatment, Several lower capacity relays Relay chatter and No relays were consisting of(l) that whose chatter was associated operator replaced. Some 

identification and unacceptable or required recovery were modeled cabinets are to be 

classification of essential operator actions were in the seismic PRA. fastened together to 

relays; (2) relay walkdown; identified for fragility Seismic fragilities for reduce the potential for 

and (3) SPRA modeling of calculations, several relays were relay chatter. 

relay chatter, including developed. Relay fragility evaluations and chatter has been 

consideration of operator identified as a dominant 

recovery actions. risk contributor. The 

licensee performed a 

cost benefit analysis, 

and found that 

changing the relays in 

DG circuitry was not 

cost effective.

2 - 48
Table 2.9: Relay evaluation (Continued)

Low-ruggedness relays Related plant 

Plant Treatment identified Safety implications improvements 

Seabrook Fragilities of electrical relays 88 relays that have a factor of Group 1 relays are None. 

were addressed in original safety less than four above the protective relays on 

SSPSA, using generic test SSE (0.25g) were classified in diesel generator control 

and analysis data. These two groups and included in panels. The most 

fragilities were updated in the seismic PRA significant impact of 

1986 based on actual quantification. chatter of these relays is 

component qualification the shutdown of the 

reports, diesel generators. 

Should this happen, the 

operators would 

immediately be alarmed 

and are expected to 

follow existing 

emergency operating 

procedures to manually 

restart the diesel. 

Group 2 relays have 

higher fragility values. 

The most significant 

impact of chatter of 

Group 2 relays is to trip 

off loads on the 

emergency buses. 

These are also 

considered recoverable, 

but the diagnosis and 

response to multiple 

relay chatter would be 

more difficult. 

Sequoyah l&2 Full relay chatter evaluation, Several low-ruggedness relays Consequence analysis None. 

including capacity screening were identified, none of indicates no effects on 

and consequence assessment. which were determined to SSEL. 

cause malfunction of SSEL 

equipment. 

Shearon Harris EPRI-NP-7148-SL was used Fifty-one relays were Forty-five relays, either None. 

for the relay screening. identified to be potentially rugged or non-essential. 

low-ruggedness relays that Inadvertent relay trip of 

required a chatter evaluation, the remaining six 

relays, all GE model 

12PVD21B1A, is not a 

concern based on 

further relay chatter 

study. 

South Texas None, and none required None, not applicable, Modeled in SPRA. None. 

Project l&2 (non-USI A-46 reduced

scope plant); however, relay 

chatter is modeled in SPRA.

2 - 49
Table 2.9: Relay evaluation (Continued) 

Low-ruggedness relays Related plant Plant Treatment identified Safety implications improvements 

St. Lucie l&2 No evaluation required for Not reported. Licensee concluded None. 

Unit 2 (non-USI A-46, there were no reduced-scope plant); For deleterious effects of 

Unit 1, USI A-46 evaluation chatter of bad actor 

searched for bad actor relays, relays. 

verified mountings of relays. 

Summer The relay evaluation looked Two bad actor relays were None. None. 

for "bad actor" relays from found to provide alarm 

the IPEEE list of such relays. functions only and, therefore, 

were of no concern. 

Surry 1&2 Relay chatter was not None for IPEEE. Identified None for IPEEE. LRRs None for IPEEE. Under 

considered in the seismic under A-46 program: are being replaced; and A-46, the LRRs are IPEEE because, according to Westinghouse SV model the mercury relays planned to be replaced 

the submittal; a detailed relays, used in the EDG would be able to via station-approved evaluation was performed in circuits as field flashing withstand a spurious Design Change 95-017. 

the A-46 program. relays; and mercury relays, CO2 release coincident 

used in the fire protection with an EDG start. 

circuit for the EDG rooms. 

Susquehanna Identification of low- Four locations of low- Effects of chatter None. 

1&2 ruggedness relays; ruggedness relays were deemed acceptable. 

walkdown verification; identified. 

evaluation of chatter effects. 

TMI 1 Relays screened out or 87 relays were evaluated for Relay chatter and All relays that cannot 

evaluated using criteria in fragility evaluation using the recovery actions were pass any seismic 

EPRI NP-7147, "Generic generic data from GERS. modeled in the PRA. screening criteria will 

Ruggedness of Relays" be replaced during 

(GERS). upcoming refueling 

outages. 

Turkey Point USI A-46 evaluation Not reported. Licensee concluded None. 

3&4 searched for bad actor relays, there were no verified mountings of relays. deleterious effects of 

chatter of bad actor 

relays. 

Vermont USI A-46 evaluation Two low-ruggedness relays. No effect on plant safe None. 

Yankee expanded for IPEEE. shutdown. 

Vogtle 1&2 The principal method used None. None. None. 

for screening was to review 

the VEGP Equipment 

Qualification Data Packages 

(EQDPs) which are design 

documents containing test 

results of the VEGP 

Equipment Qualification 

(EQ) program. 

Waterford 3 Not required for reduced- Not applicable. Not applicable. None. 

scope plant.

2- 50
Table 2.9: Relay evaluation (Continued)

2-51

Low-ruggedness relays Related plant 

Plant Treatment identified Safety implications improvements 

Watts Bar I EPRI NP-7147-SL was used None. None. None. 

to establish the low

ruggedness relays at WBN. 

Wolf Creek Computerized identification One model of low-ruggedness The relay model of None. 

of low-ruggedness relays; relay (GE HGA) was found to concern is not used in a 

review of electrical exist in the safe shutdown low-ruggedness 

schematics; no walkdown equipment list (SSEL). configuration in SSEL 

verification. equipment. 

Formerly known as Washington Nuclear Project Number 2.
Table 2.10: Soil evaluation

Soil/foundation 551 or SOil response Other soil failure 

Plant Characteristics analysis Soil liquefaction modes 

Arkansas Nuclear Rock Rock site. The rock-founded Not applicable. None. 

One I structures at ANO- I were 

modeled with base springs 

representing the "soil" stiffness. 

Arkansas Nuclear Rock Structures founded on rock. The Not applicable. None. 

One 2 rock-founded structures at ANO-2 

were modeled as fixed-based 

structures. 

Beaver Valley I Soil/rock. Structures Scaling of existing design analysis The minimum safety factors against None. 

founded on mat results using the ratios of the liquefaction as developed in the 

foundations with medium UHS to the design original design analysis were 

approximately 60 to 100 spectrum (NUREG/CR-0098). reviewed to screen out the soil 

ft of overburden soils liquefaction following RLE. 

(sands) to bedrock. 

Beaver Valley 2 Soil/rock. Structures Scaling of existing design analysis The minimum safety factors against None. 

founded on mat results using the ratios of the liquefaction as developed in the 

foundations with medium UHS to the design original design analysis were 

approximately 60 to 100 spectrum (NUREG/CR-0098). reviewed to screen out the soil 

ft of overburden soils liquefaction following RLE. 

(sands) to bedrock. 

Braidwood 1&2 Founded either Structures founded on rock. The No soil evaluation performed. None. 

completely or partly on seismic analysis is based on a 

bedrock direct generation technique using 

a random vibration approach. 

Browns Ferry 2&3 Rock Structures founded on rock. IRS Not applicable. None. 

for the IPEEE were developed by 

scaling the A-46 IRS, based on the 

guidelines in EPRI NP-6041. 

Brunswick 1&2 76 ft soil; 50 ft of Results of design SSI analysis, No IPEEE evaluation. No IPEEE evaluation. 

structural fill over 26 ft scaled and modified for frequency 

dense sands. shift. 

Byron 1&2 Rock Structures founded on rock. The Not applicable. None. 

seismic analysis is based on a 

direct generation technique using 

a random vibration approach. 

Callaway Some structures founded FLUSH finite element SSI No IPEEE evaluation; however, the Capability of buried 

on rock; others are analysis for power block licensee concludes the fill materials piping (between power 

founded on structural fill structures. are not susceptible to liquefaction, block and other 

or stabilized backfill structures) was 

having a depth of determined to exceed 

anywhere from 19 ft to 54 the RLE. 

ft over bedrock. 

Calvert Cliffs 1&2 Soil Probabilistic SSI analyses were The soil liquefaction analyses were None. 

performed for the containment performed by S&A. The results 

structure, auxiliary building, concluded that, although liquefaction 

intake structure, turbine building, would occur for the new EDG 

and new EDG building. building at a median PGA of 0.27g, 

it would not cause a realistic hazard. 

It is also concluded that the seismic

induced foundation settlement is 

negligibly small.

2- 52
Table 2.10: Soil evaluation (Continued)

Soil/foundation SSI or soil response Other soil failure 

Plant Characteristics analysis Soil liquefaction modes 

Catawba 1&2 Category I structures: None (deemed negligible). No concerns identified. No concerns identified. 

Rock or concrete fill 

extending to rock. Some 

components founded on, 

or buried in, soil. 

Clinton Soil Using a so-called Multiple A focused-scope plant that is not None. 

Analysis Method by EQE which required to perform soil evaluations. 

includes direct comparisons of 

free-field motions, comparisons of 

deconvoluted motions to the 

structure foundation level, and 

simplified soil-structure 

interaction (SSI) analyses for 

comparisons of floor response 

spectra. 

Columbia Soil New probabilistic SSI analyses A soil liquefaction analysis and a None. 

Generating* were performed. seismic soil settlement analysis were 

performed. It is concluded that both 

the liquefaction potential and seismic 

incurred settlement are negligible at 

the site. 

Comanche Peak Rock site predominantly. Not reported. No IPEEE evaluation required. No IPEEE evaluation 

1 &2 required. 

Cooper Soil. Bedrock elevation An SSI analysis was performed No soil evaluation was conducted None. 

was taken as 822', ground for the control and reactor (based on Supplement 5 to 

surface as 902', and the buildings using a substructuring GL 88-20). 

top of the water table as approach following the general 

880'. procedure outlined in Appendix E 

ofNP-6041. 

Crystal River 3 Soil (marshland) A reduced-scope plant, using the Soil evaluation not required None. 

SSE design basis ground spectra (reduced-scope plant). 

of the Housner type with a PGA 

of 0.ig as the IPEEE review level 

earthquake (RLE). 

D.C. Cook 1&2 Soil site; a slope SSI margin factors developed. No concerns identified. Soil pressure failure 

(approximately 2:1) found to dominate 

bounds the plant site to containment building 

the east. fragility; no other 

concerns identified. 

Davis-Besse The site consists mostly A re-analysis of plant structures No soil evaluation was performed None. 

of marshland. The station was conducted by EQE (based on Supplement 5 to 

structures are located International, utilizing 3-D GL 88-20). 

approximately in the structural models and accounting 

center of the site and are for foundation embedment effects, 

built on a bedrock for 0.3g PGA with a NUREG/CR

foundation. 0098 median rock spectral shape. 

A scale factor of 0.697 was used 

for all spectral values. 

Diablo Canyon Rock sites; some None described. No concerns identified. No concerns 

1&2 components founded on, identified; effects 

or buried in, soil. modeled in fragilities.

2- 53
Table 2.10: Soil evaluation (Continued) 

Soil/foundation SSI or soil response Other soil failure 

Plant Characteristics analysis Soil liquefaction modes 

Dresden 2&3 Rock Structures founded on rock. SME Not applicable. None. 

in-structure response spectra were 

developed using a 3-dimensional 

horizontal model of the major 

structures. 

Duane Arnold Rock/soil. Structures DBE analysis (for reduced-scope Not required for reduced-scope plant. A site with shallow 

supported on bedrock or plant). soil conditions, 

lean concrete over accounted for in the 

bedrock or on 30 to 50 development of the 

feet of overburden soil or IRS. 

compacted fill soil. 

Farley l&2 Soil SSE analysis (for reduced-scope Soil evaluation analyses not required New SSI analyses 

plant) for reduced-scope plant. conducted for the DG 

and SW intake 

structures supported on 

cast-in-place caissons. 

Fermi 2 Rock. Major Category I Structures founded on rock. Not applicable. None. 

structures supported on Performed new dynamic analysis 

bedrock, for IPEEE. 

FitzPatrick Rock Buildings founded on bedrock. Not applicable. None. 

The structural response analyses 

were performed using the direct 

generation method. 

Fort Calhoun 1 65-75 ft of sandy soil Soil springs in lumped-mass Liquefaction HCLPF=0.25g for soil Soil failures are 

over bedrock; structures model. outside the vicinity of Category I dominated by are supported on pipe structures; controls capacity of diesel liquefaction. 

piles. fuel oil storage tanks and raw water 

system piping. 

Ginna Rock Safety-related buildings founded Not applicable. None. 

on rock. Same spectra as those 

used in USI A-46. However, a 

safety factor of 1.5 was used to 

justify meeting the IPEEE seismic 

demands. 

Grand Gulf I Soil SSE analysis (reduced-scope Soil failure analyses are not None. 

plant). necessary for reduced-scope plant. 

H.B. Robinson 2 Very deep (460 ft) soil New, multiple SSI analyses using Some data points indicated Embankment failure 

site, dense below 50 ft CLASSI conducted for five Class liquefaction at isolated location, and wave-induced 

depth; some structures are I structures, which the licensee concluded was strains in buried 

supported on piles to a acceptable, (However, after a Step 2 piping, were 

depth of 50 ft; the review of the licensee's IPEEE, considered and judged 

circulating water intake liquefaction remained as an issue by the licensee not to 

structure is founded on requiring further investigation, which be significant. 

50-ft depth. eliminated the concern.) 

Haddam Neck Predominantly a rock SSI conducted for new DG and No concerns identified. No concerns identified. 

site; the new DG and switchgear buildings. 

switchgear buildings are 

founded on shallow soil; 

diesel fuel oil tanks and 

piping are buried.

2- 54
Table 2.10: Soil evaluation (Continued)

Soil/foundation SSI or soil response Other soil failure 

Plant Characteristics analysis Soil liquefaction modes 

Hatch 1&2 Soil. Plant site underlain New SSI analyses performed for The soil evaluation addressed issues Stability of the soil 

by approximately 4000 ft Control building, Reactor related to liquefaction potential and slopes in the river 

of relatively buildings, Diesel Generator ground settlement, and found that the intake area was unconsolidated Mesozoic building, and Intake building. The RLE should be reduced to 0.28g to evaluated and was and Cenozoic sands, substructuring approach was meet the requirement for the mini- found unlikely to 

gravel, clay marls, applied and uncertainties mum values of the factor of safety. experience a serious 

claystone, sandstones, associated with soil properties It would not have any detrimental stability problem and limestone, were addressed, effect because it would occur at a following an RLE. 

depth where HCLPF is controlled by 

the impact of ground settlement and 

differential settlement on buried 

structures and pipe penetrations. 

Hope Creek Soil. Soil improvement A new SSI analysis using a The liquefaction potential was None. 

conducted on the site by probabilistic approach to account assessed using a probabilistic 

replacing the loose for the variabilities in soil and approach. The lateral spreading due 

hydraulic fill with structural properties. The SSI to liquefaction of slopes becomes 

engineered backfill, effects and the spectral shape of significantly large at a peak 

underlying which is the the UHS are considered to be the acceleration of about 0.35g. 

Kirkwood formation main contributors for the building 

consisting of fine to response reduction. 

medium grained sands 

having blow counts 

ranging from 20 to 70 

blow counts per foot. 

Indian Point 2 Rock site; some piping is Design-basis fixed-base structural A specific evaluation for liquefaction Potential failure of 

laid in trenches that were models were used; SSI effects and slope failures was performed diesel fuel oil tanks, 

excavated in rock and were deemed negligible, according to EPRI NP-6041. No due to hold-down strap backfilled. concerns were identified. failure and failure of 

grouted rock anchors, 

was modeled in the 

seismic PRA. 

Indian Point 3 Rock. The site consists of The structures are founded on Not applicable. None. 

a hard limestone bedrock. New floor response 

formation which provides spectra were developed using the a solid bed for the plant so-called direct generation 

foundation, method. 

Kewaunee Clay-sand soil deposited Elastic half-springs used to model Assessed as being very unlikely. Screened out based on to a depth of 76 ft. soil behavior. high seismic capacity. 

La Salle l&2 No information provided. No information provided. No information provided. No information 

provided. 

Limerick l&2 Rock site. None reported. None. None. 

McGuire l&2 Category I structures: None (deemed negligible). No concerns identified. No concems identified, 

Rock or concrete fill 

extending to rock. 

Some components 

founded on soil/backfill. 

Millstone 2 Rock IRS generated using either a direct Not applicable. None. 

generation method or a scaling 

method to convert the SSE IRS to 

the RLE IRS.

2- 55
Table 2.10: Soil evaluation (Continued)

Soillfoundation S51 or soil response Other soil failure 

Plant Characteristics analysis Soil liquefaction modes 

Millstone 3 Soil site (specific Not described. No concerns identified for power Included in fragility 

characteristics were not block; soil adjacent to SW evaluations. 

described); beach and pumphouse assumed to fail, but 

glacial outwash sands determined not to impair function. 

adjacent to SW 

pumphouse. 

Monticello Moderately deep soil site. New SSI analyses of turbine and No soil evaluation performed. No soil evaluation 

reactor building were performed performed. 

for USI A-46, using existing 

structural dynamics models (with 

minor modifications). The results 

of these analyses were scaled 

from the SSE to RLE. For the 

control building, new SSI results 

were computed directly for the 

RLE. Three different soil profiles 

(best estimate, upper, and lower 

bound) were used. 

Nine Mile Point 1 Rock Safety-related buildings founded Not applicable. None. 

on rock. The RLE IRS were 

developed by scaling up the 

upgraded ground spectrum (which 

is a NUREG/CR-0098 50% 

spectral shape and is anchored to 

0.13g) to 0.3g RLE using a 

scaling factor of 2.31 (i.e., 

0.3/0.13). 

Nine Mile Point 2 Rock site. None. No concerns identified. None. 

North Anna 1&2 Structures founded on Structures were modeled using NAPS is a focused-scope plant that None. 

rock: Containment lumped-mass beams and stiffness is not required to perform soil 

structure and internals; matrix elements with 6 degrees of evaluation. 

reactor Safeguards freedom at each node. For 

Structure; Main Steam structures founded on soil 

Valve House, Unit 1; foundations, the building models 

AFW Pumphouse. were used together with the proper 

Structures founded on impedance and scattering 

soil: Main Steam Valve functions for the soil-structure 

House, Unit 2; service interaction (SSI) effects, and SSI 

water Pumphouse; analyses were performed for the 

service water best estimate and lower and upper 

Valvehouse; Auxiliary bounds of soil properties. 

Bldg., Intake Structure. 

Also, Service/Turbine 

Bldg. is founded partially 

on rock and partially on 

soil.

2-56
Table 2.10: Soil evaluation (Continued)

Soil/foundation SSI or soil response Other soil failure 

Plant Characteristics analysis Soil liquefaction modes 

Oconee 1,2,&3 Rock/soil. The site has a All major safety-related structures Soil liquefaction was addressed by None. 

shallow soil layer over at Oconee are founded on reviewing the existing geotechnical 

bedrock. All major bedrock, the shallow overburden studies, and concluded that no 

structures are founded on soil was not modeled. Scaling of concerns were found for liquefaction. 

rock, except for the existing results using the UHS 

transformer CT-4, scaling factor (ratio of the UHS to 

blockhouse, borated NUREG/CR-0098 spectrum). 

water storage tank, main 

startup transformer, 

condenser circulating 

water piping, relay house, 

and switchyard. 

Oyster Creek Soil A new set of soil-structure The likelihood of soil liquefaction None. 

interaction analyses was for varying water table conditions 

performed. The analyses are based was evaluated and expressed in terms 

on the SSMRP-type approach, and of probabilities of occurrence 

the variabilities in both the ground conditional on the occurrence of a 

motions and structural properties given ground acceleration. It is 

are considered in multiple time estimated that soil liquefaction is 

history analyses. expected to occur at a peak ground 

acceleration of 0.40 g at the 

locations of the EDGB and the fire 

protection piping. 

Palisades 150-160 ft of soil (dense New 3D nonlinear SSI analyses; No concerns identified. Screened out soil 

fine sands, over very also SHAKE computer code used displacements and 

dense fine sands, over for ground response analyses. settlements. 

hard silty clay and glacial 

till) over shale bedrock. 

Palo Verde 1,2,&3 Soil A new set of soil-structure The potential for liquefaction of None. 

interaction (SSI) analyses was cohesionless soils that underlie the 

performed at PVNGS for the 0.3g site was evaluated and the results of 

RLE. the analysis showed factors of safety 

against liquefaction of approximately 

2.5 and higher for a peak ground 

acceleration of 0.3g. Earthquake

induced settlements were also 

addressed and found to be negligible 

Peach Bottom Predominantly a rock No SSI analyses; fixed-base, No concerns identified. Failures of buried 

2&3 site; there are some lumped-mass dynamic models equipment and piping 

buried piping and were employed, were screened out. 

equipment at the plant. 

Perry 1 Safety-related buildings The RLE In-structure Response Exempt from performing soil None. 

are founded on rock, Spectra (IRS) are generated by evaluation. 

except for the diesel scaling the DBE IRS. 

generator building, which 

is founded on compacted 

Class A backfill. 

Pilgrim 1 30 to 50 feet of heavily New 3D SSI analyses. No concerns identified. Soil settlements and 

compacted fill materials foundation rocking of 

above 30 to 50 feet of CST were modeled in 

very dense glacial fragility calculations. 

outwash deposits 

underlain by bedrock.

2-57
Table 2.10: Soil evaluation (Continued)

1SoiFfoundation SSI or soil response Other soil failure 

Plant Characteristics analysis Soil liquefaction modes 

Point Beach l&2 100 ft of soil (stiff to very New 3D nonlinear SSI analyses. Assessed as being very unlikely. Soil settlements and 

stiff glacial deposits) over displacements 

fractured dolomite affecting components 

bedrock. were screened out. 

Prairie Island l&2 Soil Soil-structure interaction (SSI) No soil evaluation was conducted None. 

analysis performed using the (based on Supplement 5 to 

computer programs CLASSI and GL 88-20). 

SHAKE. 

Quad Cities l&2 Predominantly a rock No SSI analyses were performed. No concerns identified. Effects of differential 

site; there are some movements were 

buried piping and qualitatively screened 

equipment at the plant. out; retaining wall for 

intake/discharge 

building was screened 

out based on a factor 

of safety of 1.2 beyond 

the design basis. 

River Bend Soil SSE analysis (for reduced-scope Soil failure analyses not necessary. None. 

plant). 

Salem l&2 The SGS is built on an New SSI analyses were performed The liquefaction potential was The liquefaction of 

artificial island, and most for the containment building assessed using a probabilistic slopes due to lateral 

of the Seismic Category I including internal structures, approach. An HCLPF of 0.72 was spreading appears to 

structures are founded on auxiliary building, and the service estimated and used to evaluate the be initiated at about a 

a common lean concrete water intake structure, fragility of buried piping. peak ground 

mat poured within the Variabilities in stiffnesses and acceleration of 0.35g. 

confines of a cellular damping of both structures and It is not clear whether 

coffer dam. soil were considered in the this information is 

analyses based on a Latin used for evaluation of 

Hypercube Simulation. buried piping. 

San Onofre 2&3 Very deep (over 900 ft) New soil-structure-interaction SSE analyses were used as basis to Potential ground 

soil site, consisting of (SSI) dynamic response screen out (at an acceleration of 5.4g failure of sands in the 

stiff, well-graded sands. calculations, based on S-sub a (1-10 Hz)), potential plant area was 

During plant probabilistic characterization of liquefaction of filled cavities screened out based on 

construction, about 70 ft soil properties, were performed adjacent to, or beneath, structures, consideration of soil 

of native soils (terrace using existing 3D dynamic stick properties. 

deposits) were excavated, models. Potential development of blockages 

and plant structures were in offshore conduit caused by conduit Results of slope 

founded directly on the separation and inflow of liquefied response analyses were underlying stiff sand soils was screened out since water used to screen out 

deposit/formation, velocity in the conduits was concerns that failure of 

determined to be sufficiently high to cut slopes in native 

remove any potential sand blockage, terrace deposits could 

cause excessive 

ground movements at 

adjacent critical plant 

facilities. 

Seabrook Rock or concrete filled to Structures are founded on either Since seismic Category I structures None. 

rock rock or concrete filled to rock. are founded on either rock or 

Both response spectrum and concrete filled to rock, the soil 

modal time-history analyses were liquefaction potential is not an issue 

performed for the Category I for Seabrook. 

structures.

2- 58
Table 2.10: Soil evaluation (Continued)

SoilYfoundation SSI or soil response Other soil failure 

Plant Characteristics analysis Soil liquefaction modes 

Sequoyah l&2 Rock site predominantly; New, probabilistic evaluations of Assessed as having low Compaction/settlement 

some structures are response, including SSI effects, susceptibility, and failures due to 

founded on shallow soil using stick models. slope instability were 

(clays and silts over shale considered, but not 

bedrock). assessed as being 

important. 

Shearon Harris 1 Rock All seismic category I structures Not applicable. Two dams, which are 

at SHNPP founded on rock. IRS located in the 

scaled up from SSE to RLE, using Buckhom Creek 

the method for scaling IRS as watershed to impound 

outlined in EPRI NP-6041-SL cooling water for 

SHNPP, were 

evaluated for RLE, and 

found to have an 

HCLPF of 0.31g. 

South Texas Very deep soil deposit. SSI finite element analysis. No analysis required (reduced-scope No analysis required 

Project 1&2 plant). (reduced-scope plant). 

St. Lucie 1&2 Category I structures: Soil modeled using translational No analysis required (reduced-scope No analysis required 

founded on Category I and rotational springs, plant). (reduced-scope plant). 

fill, underlain by 

cemented sands and 

sandy limestones. 

Summer Rock/soil. Most of the structures are founded Summer is a focused-scope plant that A HCLPF calculation 

on rock. For structures and is not required to perform soil was performed for the 

components founded on soil, the evaluation, earth dams and 

defined RLE spectrum was embankment that 

increased to an effective PGA of impound cooling water 

0.5g by a factor of 1.67. Soil for the plant and are 

conditions were applied to the treated as Seismic 

service water pump house Category I structures. 

(SWPH) and condensate storage The HCLPF capacity 

tank (CST). is 0.22g for the earth 

dams and 

embankment. 

Surry 1&2 Soil. The site is bordered New floor spectra were obtained No soil evaluations were performed None. 

by the James River on by SSI analyses. The Latin (based on Supplement 5 of GL 88

either side of the Hypercube sampling technique 20). 

peninsula, and was used to account for the 

characterized as a deep uncertainties in frequencies, 

soil site. damping, and soil properties. 

Susquehanna l&2 All Category I structures SSI model used for ESSW No concerns identified. No concerns identified 

are founded on rock, pumphouse; flexible-base model with settlements, 

except the essential used for reactor building; fixed- instability, sliding, or 

station service water base model used for other distortion of buried 

(ESSW) pumphouse and structures, pipe. 

the spray pond

2- 59
Table 2.10: Soil evaluation (Continued) 

Soil/foundation 551 or soil response Other soil failure 

Plant Characteristics analysis Soil liquefaction modes 

TMI I Soil Structural response analysis A soil liquefaction analysis and a None. 

performed by EQE. seismic soil settlement analysis were 

performed. These analyses concluded 

that, should soil liquefaction occur, 

foundation-bearing strength failures 

are not expected, but ground 

settlement on the order of 0.5 to 1.0 

inch could be expected. For the 

structures founded on compacted 

backfill, including the DG building, 

the borated water storage tank, the 

condensate storage tanks, and the 

turbine building, the analysis 

concludes that it is unlikely that such 

a small soil settlement would lead to 

significant structural damage. 

Turkey Point 3&4 Rock site predominantly. None described. No analysis required (reduced-scope No analysis required 

plant). (reduced-scope plant). 

Vermont Yankee Rock. All of the Seismic Structures founded on bedrock. Not applicable. A stability analysis of 

Category I structures are The RLE In-structure Response the Vernon Dam 

founded either on mat Spectra (ISRS) were generated by showed a factor of 

foundations bearing scaling up the design basis ISRS. safety equal to 1.12 for 

directly on bedrock, or on the overturning mode 

a grillage of grade beams against 0.3g RLE. 

over a series of reinforced 

concrete piers on 

bedrock. 

Vogtle l&2 Deep soil site; the depth Scaling of the design basis Not required to perform soil None. 

of bedrock below the earthquake analysis results. evaluations. However, since the 

plant site is VEGP site has a deep soil profile 

approximately 950 ft. (950 ft) and is situated on the bank of 

the Savannah River, liquefaction 

should be an important safety issue. 

The licensee has performed soil 

evaluations for the site, including 

liquefaction potential, stability of 

slopes, and ground settlement. The 

method proposed by EPRI for soil 

evaluations in EPRI NP-604 I-SL 

was used. The results presented 

appear to be reasonable and the 

factor of safety against soil 

liquefaction potential at the RLE is 

approximately 1.5. 

Waterford 3 Soil Design basis analysis for SSE (for Soil failure analyses are not None. 

reduced-scope plant). necessary for reduced-scope plants. 

Watts Bar I Rock/Soil. All of Seismic Scaling of existing ARS to the Exempted from performing soil None. 

Category I buildings at RLE. The DGB is supported on evaluation. 

WBN are founded on soil, and its seismic response 

rock, except for the should involve the soil-structure 

Diesel Generator interaction (SSI) effect. The 

Building which is submittal did not discuss how the 

supported on a soil SSI effect was considered in the 

foundation, spectral scaling.

2- 60
Table 2.10: Soil evaluation (Continued)

2-61

SoiVfoundation SSI or soil response Other soil failure 

Plant Characteristics analysis Soil liquefaction modes 

Wolf Creek Predominantly a rock FLUSH finite element analysis for No evaluation performed. Relative displacement 

site; Seismic Category I power block structures, of buried piping 

structures are founded on between the power 

shallow soil columns over block and the 

bedrock. The soil emergency service 

overburden is less than 16 water pumphouse was 

feet. evaluated. A review 

of design documents 

led to the judgment 

that the interaction of 

the piping with the 

associated structures 

can be accommodated 

at the RLE. 

* Formerly known as Washington Nuclear Project Number 2.
Table 2.11: Non-seismic failures and human actions

Human actions 

Treatment in Impacts of ground unique to seismic 

Plant systems modeling Screening criteria motion of HEPs events 

Arkansas Success path selection; The overall core damage frequency The potential adverse Local manual operations 

Nuclear One I safe shutdown systems (CDF) from a 0.3 PGA event is environmental conditions, such related to the operation of 

chosen in the IPEEE are of assessed and found to be as the potential for failure of the steam-driven EFW 

minimal complexity and insignificant, and a review of the plant structures and equipment, pump and those related to 

effort to operate, and are equipment selected in the SPLDs the potential for local failure of the local starting of the 

consistent with the normal does not show any concern of architectural features, and the emergency diesel generator 

ANO-1 Emergency nonseismic failures, potential for adverse seismic are credited in the IPEEE. 

Operating Procedures. spatial interactions in the 

vicinity of safe shutdown 

equipment, are also considered. 

Arkansas Success path selection. The The overall core damage frequency An assessment of the overall Local manual operations 

Nuclear One 2 safe shutdown systems (CDF) from a 0.3 PGA event is CDF from a 0.3g PGA event, credited in the IPEEE are 

chosen in the IPEEE are of assessed and found to be including the consideration of those related to the 

minimal complexity and insignificant. A review of the potentially adverse operation of the steam

effort to operate, and are equipment selected in the SPLDs environmental conditions, such driven EFW pump and 

consistent with the normal does not show any nonseismic as loss of lighting, show those related to the local 

ANO-2 Emergency failure concerns. insignificant CDF. starting of the emergency 

Operating Procedures. diesel generator. 

Beaver Valley 1 IPE model Not applicable. The human error probability None reported. 

(HEP) values from the internal 

PRA model were used up to an 

acceleration level of 0.5g. 

Above an acceleration level of 

0.5g the HEPs were set to 1.0. 

Beaver Valley 2 IPE model Not applicable. The human error probability None reported. 

(HEP) values from the internal 

PRA model were used up to an 

acceleration level of 0.5g. 

Above an acceleration level of 

0.5g the HEPs were set to 1.0. 

Braidwood l&2 Success path selection. The A review of the success paths and Important operator actions The switchover of the 

selected success paths systems selection does not reveal involved in the selected success AFW suction from the 

utilized equipment and any concern with using single-train paths are evaluated and found CST to the ESW. 

operator actions consistent systems with recognized poor to be consistent with current 

with current plant availability problems on the success plant procedures for which the 

operating procedures that path. operators are regularly trained. 

were evaluated in the 

Braidwood station IPE. 

Browns Ferry 2 Success path selection. To None reported. The success path Operator actions required for Manual RPV 

minimize the number of depends on a single train of the the success paths and their depressurization and low 

components to be RHR system, which does not have failure probabilities obtained pressure system initiation 

evaluated, only low any reported reliability problem. from the plant probabilistic risk are required for the success 

pressure injection systems assessment are discussed. paths selected in IPEEE. 

are selected in the success 

paths.

2 - 62
Table 2.11: Non-seismic failures and human actions (Continued)

Human actions 

Treatment in Impacts of ground unique to seismic 

Plant systems modeling Screening criteria motion of HEPs events 

Brunswick l&2 Success path selection; Random failures having probability None modeled. Chatter recovery. 

location and timing of exceeding 0.001 and existing in a 

required operator actions significant cutset were screened in; 

were reported. no screening was performed for 

human actions, although the 

success paths were chosen to 

maximize operator familiarity and 

redundancy. 

Byron 1&2 Success path selection. The A review of the success paths and Important operator actions The switch over of the 

selected success paths systems selection does not reveal involved in the selected success AFW suction from the 

utilized equipment and any concern with using single-train paths are evaluated and found CST to the ESW. 

operator actions consistent systems with recognized poor to be consistent with current 

with current plant availability problem on the success plant procedures for which the 

operating procedures that path. operators are regularly trained. 

were evaluated in the 

Byron Station IPE 

Callaway Success path selection. Random or human failures having None modeled. Not documented. 

probability exceeding 0.001, if 

failure impacts multiple trains or 

systems, or 0.01, if failure impacts 

only a single train and system, were 

screened in. 

Calvert Cliffs IPE model. Not applicable. Considering how different None reported. 

1 &2 performance shaping factors 

(PSFs) are affected at different 

g levels. Recovery actions were 

not modeled. 

Catawba 1&2 IPE model. Not applicable. None. Relay chatter recovery. 

Clinton Success path selection. None reported. There are sufficient There are no immediate None reported. 

redundancy and reliability in both operator actions required for 

success paths selected in the the success paths. Operator 

IPEEE. actions can be performed in the 

main control room. They are 

not time critical and are 

proceduralized and trained 

upon. 

Columbia IPE model. Not applicable. Human error was considered in None reported. 

Generating* the analysis by increasing the 

human error probability (HEP) 

values used in the IPE study by 

roughly a factor of 10 to 

account for the extreme stress 

during a seismic event. No 

credit was taken in any of the 

accident sequences for 

recovery actions. 

Comanche Peak Success path selection. Qualitative screening: success None. None reported. 

1&2 paths involve dual-train systems 

and actions are familiar to 

operators.

2 - 63
Table 2.11: Non-seismic failures and human actions (Continued) 

Human actions Treatment in Impacts of ground unique to seismic 

Plant systems modeling Screening criteria motion of HEPs events 

Cooper Success path selection. Nonseismic related failures were A review of all actions in the Manual RCS 

Only low pressure systems evaluated using the data from the PSA model was performed in depressurization is required are selected. High pressure internal event PSA. the IPEEE to consider their for both success paths. injection systems are not importance to the expected included in the SSEL. This plant post-seismic reliability. 

is based on the reasoning The increased level of stress to 

that depressurization may the operators and the potential 

be operationally desirable disruption in the Control Room 

during a postulated RLE (e.g., falling ceiling tiles and 

scenario, items falling off of shelves) 

after an SME was taken into 

consideration. 

Crystal River 3 Success path selection. Nonseismic failures are addressed Through a validation process, None reported. 

by the selection of two success operators ensure that the plant 

paths and the redundant procedure steps can be 

components in the systems selected performed and are adequate to 

in the success paths. manage the emergency 

situation. 

D.C. Cook l&2 IPE model. Not applicable. None documented. None documented. 

Davis-Besse Success path selection. The licensee states that according There is no discussion of The restarting of the HPI 

to the EPRI methodology, each important human actions, or the makeup pump, after success path should have an There does not seem to be any it trips due to relay chatter. 

unavailability of less than 0.001. credit given to any type of 

recovery action, except for the 

restarting of the HPI or the 

makeup pump, after it trips due 

to relay chatter. 

Diablo Canyon IPE model with unique Not applicable. HEPs increased based on Relay chatter recovery and 

l&2 seismic impacts introduced spectral acceleration, others. 

in seismic event tree. 

Dresden 2&3 Success path selection. None reported. The selected The success paths selected in Operator actions will be 

Isolation condenser is used success path for some of the safety the IPEEE are generally required for the proposed for decay heat removal functions relies on a single train of consistent with those the seismically 

because the cooling water a safety system. It is not expected operators are likely to perform qualified/verified makeup to the LPCI heat to cause a significant nonseismic under accident conditions, path to the isolation 

exchangers is lost failure concern because of the condenser. 

following a dam failure, reliability of the LPCI system. 

Duane Arnold Success path selection. None reported. Some discussion of operator None reported. 

High pressure injection actions is presented in the 

systems are not included as DAEC IPEEE, including safe shutdown systems. actions that were disallowed. 

Farley 1 &2 Success path selection. There is sufficient diversity because Equipment which requires None reported. 

both a small LOCA and a LOOP operator actions was included are considered in both paths, and in the seismic evaluation. No 

feed-and-bleed cooling is credit was given for recovery 

considered as an alternative to the of offsite power loss. 

steam generator cooling.

2- 64
Table 2.11: Non-seismic failures and human actions (Continued) 

Human actions 

Treatment in Impacts of ground unique to seismnic 

Plant systems modeling Screening criteria motion of H~EPs events 

Fermi 2 Success path selection. There is sufficient redundancy and The selection of the success None reported. 

Both HPCI and RCIC diversity in systems/components paths takes into consideration 

systems are included in the selected for the success paths. Both plant procedures and training, 

preferred success path for HPCI and RCIC systems are as well as instrumentation and 

RCS inventory control, included in the preferred success indication available following a 

path for RCS inventory control. seismic event. 

FitzPatrick Success path selection. The The screening of nonseismic A model is developed which None reported. 

initial component list was failures was conducted by assigning correlates the human error developed based on the threshold values of IOE-2 to IOE-4, probability (HEP) to the peak 

recent IPE study and the depending on the redundancy of the acceleration level. 

A-46 component list. component. 

Fort Calhoun t IPE model. Not applicable. HEPs increased based on Not reported. 

spectral acceleration. 

Ginna Success path selection. Nonseismic failures are addressed The effects of the potentially None reported. 

by the redundant components in the adverse environmental 

systems selected in the success conditions during a seismic 

paths. All of the equipment relied event on operator actions have 

upon is the normal equipment set been addressed. 

used in the plant emergency 

operating procedures. 

Grand Gulf 1 Success path selection. The The NUREG/CR-4826 screening The success paths are based on None reported. 

selection was based on approach for single-train/multiple- highly successful operational 

operational and systems train systems is used. sequences. 

considerations originally 

developed for the IPE. 

H.B. Robinson 2 Success path selection; Random failures having probability None modeled. Chatter recovery. 

location and timing of exceeding 0.001 and existing in a 

required operator actions significant cutset were screened in; 

were reported. no screening was performed for 

human actions, although the 

success paths were chosen to 

maximize operator familiarity and 

redundancy. 

Haddam Neck IPE model. Not applicable. HEPs increased for seismic Response to seismic 

events; operator fragility curves failures of upstream dams. 

were developed. 

Hatch 1&2 Success path selection. Nonseismic failures are addressed Qualitative discussions on None reported. 

HPCI is the only high by the redundant components in the operator actions and event 

pressure system included systems selected in the success timing for some events are 

in the success path. paths. provided in the submittal. 

Hope Creek IPE model. Not applicable. The human actions were Recovery of 1E 120Vac 

modeled such that the internal instrumentation 

PRA human error probabilities distribution panel; recover3 

(HEPs) were raised by a factor of long-term cooling in the 

of 10. switchgear room; operator 

shutdown from the remote 

shutdown panel.

2-65
Table 2.11: Non-seismic failures and human actions (Continued)

Human actions 

Treatment in Impacts of ground unique to seismic 

Plant systems modeling Screening criteria motion of HEPs events 

Indian Point 2 IPE model, modified for Not applicable. Due to assumed None. 

increased mission times unavailabilities, some IPE 

and assumed human actions were excluded 

unavailabilities due to the from the model. IPE HEPs 

seismic event. were used for actions required 

after I hour; for actions 

required within I hour, simple 

amplification factors were 

applied to IPE HEPs. 

Indian Point 3 IPE model with Not applicable. For post-initiator events, the None reported. 

consideration of a 72-hour human failure probabilities are 

mission time. assumed to have the same 

values as those used in the IPE 

for seismic levels less than or 

equal to the DBE, twice the 

IPE values for seismic hazard 

levels between 0.15g (DBE) 

and 0.5g, and 10 times the IPE 

values for a seismic hazard 

level at 0.5g. Beyond 0.5g, a 

failure probability of 0. 1 is 

used for in-control-room 

human actions and 1.0 for 

actions outside the control 

room. Restoration of offsite 

power is not considered in the 

IPEEE. 

Kewaunee IPE model. Not applicable. HEPs increased for seismic None documented. 

events, as based on simplified 

operator error fragilities. 

La Salle 1&2 IPE model. Not applicable. None documented. None documented. 

Limerick 1&2 Success path selection. No screening; success paths were None. None reported. 

chosen considering redundancy and 

operator familiarity. 

McGuire 1&2 IPE model. Not applicable. None. Relay chatter recovery. 

Millstone 2 Success path selection. The Nonseismic failure is not an issue Requirements regarding None reported. 

final SSEL includes almost because of the availability of nonseismic failures and human 

all components modeled in multiple success paths using actions are consistent with the 

the MP2 Internal Event redundant and diverse systems. description of NUREG-1407. 

PRA. The components in 

the SSEL that were 

determined to potentially 

not be able to meet the 

RLE with high confidence 

were also determined not 

to be required for safe 

shutdown. 

Millstone 3 IPE model. Not applicable. None documented. Relay chatter recovery.

2- 66
Table 2.11: Non-seismic failures and human actions (Continued)

Human actions 

Treatment in Impacts of ground unique to seismic 

Plant systems modeling Screening criteria motion of HEPs events 

Monticello Success path selection; No screening was performed. None modeled. None documented. 

location and timing of Random failure of the Division I 

required operator actions diesel generator and its supports is 

were reported; random a single point of failure in one 

failure rates for key success path. 

equipment were reported. 

Nine Mile Point Success path selection. The The components in the success path Very few operator actions are Credit is given for some 

success path chosen with the highest nonseismic credited, and most of them are relay chatter recoveries. 

emphasizes simplicity in unreliability are the diesel long term (i.e., several hours). Otherwise, very few 

the frontline systems and generators. The combined operator actions are minimizes the number of unreliability of the diesel generators credited, and most of them 

support systems and is still low (<5%). are long term (i.e., several 

operator actions that hours). Examples are needed to be evaluated. recovery of diesel 

The two success paths generator room cooling, 

consist of redundant trains and intermittent operation 

of the same equipment. (including raw water flow 

path alignment) of the 

containment sprays. 

Nine Mile Point IPE model. None. Not specified. Not specified. 

2 

North Anna t&2 Success path selection. Components and systems that were The emergency and abnormal Manual valve operations if 

identified in the IPE report as procedures include reliance on offsite power is lost and 

important for core damage risk operator actions for safe procedural action by 

reduction, significant for risk shutdown following a seismic operators in case of 

achievement, or with high event, possible loss of 

probability of failure were walked annunciator lights during 

down and evaluated. strong motion of an 

earthquake. 

Oconee 1,2,&3 IPE model. Not applicable. The effect of the earthquake on Not reported. 

HEPs has been considered in 

the analysis. 

Oyster Creek IPE model. Not applicable. No recovery actions were None reported. 

credited except for the near 

offsite power recovery, via the 

combustion turbines. 

Otherwise, the same human 

error probability (HEP) values 

used in the IPE were used here. 

Palisades IPE model. Not applicable. HEPs increased for seismic None documented. 

events, as based on simplified 

operator error fragilities that 

account for location and timing 

of actions.

2- 67
Table 2.11: Non-seismic failures and human actions (Continued)

Humnan actions 

Treatment in Impacts of ground unique to seismic 

Plant systems modeling Screening criteria motion of HEPs events 

Palo Verde Success path selection. Nonseismic failures were addressed It was concluded in the IPEEE None reported. 

1,2,&3 Because of the lack of the in the IPEEE (by the reliability that the operators are trained 

PORVs for feed and bleed demonstrated in the IPE of the and can be relied upon to 

operation, the Palo Verde systems selected in the success achieve cold shutdown 

analysis considered an paths). following a loss of offsite 

additional system, called power event, and there is high 

the N Train AFW system, confidence that these actions 

which is not seismically would be performed within the 

qualified in both success available time. 

paths. 

Peach Bottom Success path selection; None applied. Success paths were None modeled. None documented. 

2&3 location and timing of chosen to ensure that any required 

required operator actions human actions are familiar to the 

were reported; random operators, and to ensure redundancy 

failure rates for key in equipment. Success paths were 

equipment were reported. developed to rely upon procedures 

that (a) are available from the main 

control room. and (b) operators are 

trained in. 

Perry I Success path selection. The Nonseismic failures are addressed Plant procedures and The restoration of the 

existing Perry probabilistic by the redundant components in the indications (e.g., annunciators HPCS DG should the low

risk assessment (PRA) was systems selected in the success in the control room) are ruggedness relay cause it to 

used as the basis for paths. available for required operator trip and the 

identifying the systems and actions. There is also sufficient implementation of 

components for the IPEEE. time for these actions, containment venting for 

success path; and manual 

depressurization of the 

RPV and implementation 

of containment over 

pressurization protection 

using either the RHR 

system or containment 

venting. 

Pilgrim I IPE model. Not applicable. HEPs increased for seismic Relay chatter recovery. 

events, as based on simplified 

operator error fragilities that 

account for location of actions. 

Point Beach l&2 IPE model, with unique Not applicable. HEPs increased for seismic Some actions modeled, but 

seismic effects modeled in events, as based on simplified none related to relay 

the entry seismic event operator error fragilities that chatter recovery. 

tree. account for location of actions. 

Prairie Island Success path selection. The success paths were chosen Operator actions required for Operator actions are 

1&2 based on the screening criterion the critical safety functions, the required to reduce the 

applied to nonseismic failures and time in which the action must system flow of the cooling 

human actions. Nonseismic failure be completed, and the location water system to below the 

probabilities of the systems selected in the plant in which the action capacity of the emergency 

in the SSEL are presented. must take place are discussed intake line if the normal 

in the submittal. path from the Mississippi 

River through the outer 

Screenhouse is blocked or 

if Lock/Dam # 3 fails.

2-68
Table 2.11: Non-seismic failures and human actions (Continued)

Human actions 

Treatment in Impacts of ground unique to seismic 

Plant systems modeling Screening criteria motion • of EPs events 

Quad Cities l&2 Success path selection; No quantitative criteria were None modeled. None documented. 

location, timing, and applied. 

expected reliability of 

required operator actions 

were reported. The 

treatment of random 

equipment failures was not 

reported. 

River Bend Success path selection. Both HPCS and RCIC systems are Operator actions required for None reported. 

included in the success path for the success paths are discussed 

high pressure injection. Nonseismic in the submittal. Important 

failures are addressed by the operator actions include RCS 

redundant components in the depressurization using ADS 

systems selected in the success and initiation of the SPC mode 

paths. of the RHR system. These 

actions are included in the 

plant procedures and are likely 

to be performed by control 

room operators. 

Salem 1&2 IPE model. Not applicable. Most human error probabilities None reported. were kept at the same values as 

in the IPE model. No power 

recoveries were allowed within 

the first 24 hours. 

San Onofre 2&3 IPE model with unique Not applicable. A severe earthquake ground Relay chatter recovery; 

seismic impacts introduced motion was assumed in start redundant SWC 

in seismic event tree. developing HEPs. pump; align fire truck to 

Performance shaping factors CCW make-up, given 

were developed based on failure of primary make-up 

required timing of action. tank; respond to high-temp 

alarm in the 

SWGR/distribution room; 

and open SWC emergency 

discharge line to seawall, 

given gate failure. 

Seabrook IPE model Not applicable Not specifically discussed in None reported. 

the submittal. No credit is 

given for recovery actions for 

loss of offsite power, diesel 

generators, or ATWS. 

Sequoyah l&2 Success path selection. No screening; success paths were None modeled. Relay chatter recovery. 

chosen considering redundancy and 

operator familiarity.

2- 69
Table 2.11: Non-seismic failures and human actions (Continued) 

Human actions 

Treatment in Impacts of ground unique to seismic 

Plant systems modeling Screening criteria motion of HEPs events 

Shearon Harris I Success path selection. The equipment train reliability is The development of the None reported. 

qualitatively considered and only success path evolved from 

the most reliable alternative is studying available plant 

chosen for the systems selected in equipment functions as well as the success paths. the plant's normal and 

emergency operating 

procedures, and was reviewed 

and agreed upon by plant 

operations personnel. 

South Texas IPE model. Not applicable. Not specified. Relay chatter recovery. 

Project l&2 

St. Lucie 1&2 Operating procedures were None. None modeled. None considered. 

reviewed in developing 

success paths. 

Summer Success path selection. The Nonseismic failures were The system selection process is None reported. 

two success paths share discussed, but not in sufficient consistent with plant operator 

many of the same systems. detail. Diversity in the success path utilization of procedures, 

systems (between the two success training, and available 

paths) is limited, instrumentation indicators to 

not affect the seismic margin 

evaluation. 

Surry 1&2 IPE model. Not applicable. Adjusted to account for Conserve intake canal 

additional stresses after an inventory, initiate RHR 

earthquake. with loss of instrument air, 

initiate steam dump by 

opening the steam dump 

valves and stop the AFW 

pumps to prevent pump 

damage after the suction is 

dry following a seismic 

event. 

Susquehanna Success path selection. No screening; failure probabilities None modeled. None reported. l&2 are reported as being consistent 

with screening values used in the 

Maine Yankee SMA; HPCI and 

RCIC have a high combined failure 

probability of 0.0024 per demand; 

manual starting of residual heat 

removal service water (RHRSW) 

pumps is a key action. 

TMI i IPE model. Not applicable. Recovery is not allowed for Loss of onsite ac power 

systems failed by seismic due to relay chatter is 

causes. The effects of human considered in the seismic 

action failure rates are model, and recovery from 

evaluated in sensitivity studies, relay chatter is added to the 

seismic model. 

Turkey Point Operating procedures were None. None modeled. None considered. 

3&4 reviewed in developing 

success paths.

2-70
Table 2.11: Non-seismic failures and human actions (Continued)

Human actions 

Treatment in Impacts ofground unique to seismic 

Plant systems modeling Screening criteria motion of HEPs events 

Vermont Yankee Success path selection. The selected success path for some Existing plant operating and None reported. 

of the safety functions relies on a emergency procedures were single train of a safety system. used during the development of 

There is not a significant this SSEL. Every effort was 

nonseismic failure concern because made to minimize any actions 

of the reliability of the selected or equipment use not covered 

systems, by existing procedures. 

Vogtle l&2 Success path selection. Nonseismic failures are addressed The selected success paths None reported. 

by the redundant components in the were reviewed by plant 

systems selected in the success operations personnel to ensure 

paths. that they are compatible with 

plant operations procedures and 

operator training. 

Waterford 3 Success path selection. The selected success path for some Required operator actions are None reported. 

There is a heavy reliance of the safety functions relies on a likely to be carried out because 

on secondary cooling for single train of a safety system. the requirements of the systems 

success, probably due to There is not a significant for the safety functions are 

the limitation of the nonseismic failure concern because developed from a review of 

available systems. For of the reliability of the selected plant procedures. In addition, 

example, feed and bleed systems. no out-of-control-room 

cannot be performed at operator actions are required to 

Waterford because of the accomplish a safe shutdown 

lack of pressurizer PORVs, using the success paths. 

and the CVCS pumps do 

not have sufficient capacity 

to mitigate a small LOCA 

condition. 

Watts Bar 1 Success path selection. Nonseismic failures are addressed Operator actions required to None reported. 

by the diversity and redundancy in achieve the success paths are 

the equipment selected in the SSEL those normally included in the 

for the success paths. operator training program and 

trained on by operators. This 

allows human error failures to 

be screened out using the 

guidelines identified in 

NUREG/CR-4826. 

Wolf Creek Success path selection; No screening; success paths were Qualitative assessment None identified. 

location and timing of chosen to make use of high- indicated that the reliability of 

required operator actions reliability equipment; all operator one human action (required 

were reported. actions are performed in the control within 5 minutes) might be 

room, except one (30 minutes are impaired by the RLE ground 

available to perform this action), motion event. However, the 

safety impact was judged to be 

small. 

* Formerly known as Washington Nuclear Project Number 2.

2-71
Table 2.12: Seismic-fire interaction and seismic-flood interaction

Seismic-fire Seismic-flood Related plant 

Plant Evaluation approach observations/outliers observations/outliers improvements 

Arkansas Walkdown for seismic- Potential safety concerns Potential failure of None. 

Nuclear One fire and seismic-flood with hydrogen pipe rupture dams evaluated and 

concerns. (in the turbine generator found adequately 

and the makeup tank) and considered in the 

flammable liquids development of the 

identified and dismissed. Probable Maximum 

Flood, per the Standard 

Review Plan (SRP). 

Arkansas Walkdown for seismic- Potential safety concerns Potential failure of None. 

Nuclear One fire and seismic-flood with hydrogen pipe rupture dams evaluated and 

2 concerns. (in turbine generator and found adequately 

volume control tank) and considered in the 

flammable liquids development of the 

identified and dismissed. Probable Maximum 

Flood, per the SRP. 

Beaver Valley Seismic walkdown and Seismically induced fires The failure of the None. 

frequency consideration. screened out based on Conemaugh Dam, 

comparison with the considered the worst 

frequency of initiation of case scenario was 

internal fires. Fire evaluated and found 

suppression equipment not not to be a problem for 

found to be a seismic the site. 

concern by walkdown. 

Beaver Valley Seismic walkdown and Seismically induced fires The failure of the None. 

2 frequency consideration. screened out based on Conemaugh Dam, 

comparison of equipment considered the worst 

HCLPF with the frequency case scenario was 

of initiation of internal evaluated and found 

fires. Fire suppression not to be a problem for 

equipment not found to be the site. 

a seismic concern by 

walkdown. 

Braidwood Walkdown for seismic- Potential issues with No concerns identified. None. 

1&2 fire and seismic-flood respect to seismic-induced 

concerns. fire hazards, such as gas 

bottles with insufficient 

constraints and locations of 

flammable storage 

cabinets, were identified 

and resolved except for the 

issue related to 

"unanchored hydrogen 

local control panel."

2 - 72
Table 2.12: Seismic-fire interaction and seismic-flood interaction (Continued)

Seismic-fire Seismic-flood Related plant 

Plant Evaluation approach observations/outliers observations/outliers improvements 

Browns Ferry Walkdowns to identify No concerns identified. Potential outliers for None for IPEEE. 

2&3 sources of combustion seismic-induced spray 

and possible interactions, and flooding hazards 

from non-Class I 

systems and 

components were 

identified and resolved 

(which principally 

included maintenance 

of deficient hardware 

and support 

modifications or new 

installations). 

Brunswick Walkdown for seismic- Potential interactions Potential concerns with Procedure to secure 

1&2 fire and seismic-flood involving water piping for overhead water lines CO2 cylinders when 

concerns. the fire protection system, and CST were not in use; the 

as well as mobile/cart ultimately screened out. submittal also cites 

mounted CO2 cylinders, several past 

improvements made 

to enhance fire 

protection system 

seismic capability. 

Byron 1&2 Walkdown for seismic- No significant concerns. No concerns identified. None. 

fire and seismic-flood Potential issues were 

concerns, identified and resolved 

except for the following 

issues: overturning of 

storage cabinets for oil, 

grease, and lubricants; 

interaction between 

hydrogen piping and a 

clothing bin on wheels; 

and poorly restrained gas 

bottles (resolution not 

discussed). 

Callaway Walkdown for seismic- No concerns identified. Relay chatter effects on'None. 

fire and seismic-flood fire pumps, and 

concerns. sprinkler head 

breakage, could lead to 

localized flooding; but 

they were determined 

not to affect SSEL 

equipment.

2 - 73
Table 2.12: Seismic-fire interaction and seismic-flood interaction (Continued) 

Seismic-fire Seismic-flood Related plant 

Plant Evaluation approach observations/outliers observations/outliers improvements 

Calvert Cliffs Walkdown for seismic- No concerns identified. No concerns identified. None. 

1&2 flood concerns. Both fire 

and flood initiators are 

screened at 0.3g, with 

some fire-inducing 

components also screened 

at 0.5g. 

Catawba 1&2 Walkdown for seismic- None. None. None. 

fire and seismic-flood 

concerns. 

Clinton Walkdown for seismic- No risks were found. No risks were found. None. 

fire and seismic-flood 

concerns. 

Columbia Walkdown for seismic- No unusual or unique Seismic-induced floods Actions were taken 

Generating* fire concerns. vulnerabilities. However, are screened out in the to address the 

some problems were submittal. The external support problem for 

identified and addressed floods are screened out the batteries of the 

(e.g., inadequate support based on the worst case diesel driven fire 

for the batteries of the Grand Coulee Dam pumps. 

diesel driven fire pumps failure. The internal 

and the possibility of floods are screened out 

inadvertent Halon based on comparison of 

actuation), the effects and 

frequencies of the loss 

of offsite power 

scenarios, or based 

upon the ruggedness of 

the piping. 

Comanche Walkdown for seismic- None. None. None. 

Peak 1&2 fire and seismic-flood 

concerns. 

Cooper Walkdown for seismic- Four "seismic Seismic-induced None. 

fire and seismic-flood vulnerabilities" were failures of upstream 

concerns. identified in the fire dams were addressed. 

suppression systems (two No unacceptable 

electric driven pumps, the conditions concerning 

diesel driven pump, and seismically-induced 

the water storage tanks) flooding were noted. 

and included in the IPEEE 

Issue Resolution Plan; 

however, no specific 

corrective action was 

identified.

2 - 74
Table 2.12: Seismic-fire interaction and seismic-flood interaction (Continued)

Seismic-fire Seismic-flood Related plant 

Plant Evaluation approach observations/outliers observations/outliers improvements 

Crystal River Not addressed. The Not addressed in IPEEE. Not addressed in None. 

3 licensee states that the IPEEE. 

GL 88-20, Supplement 4, 

does not require that a 

seismic/fire interaction 

review be performed for a 

"reduced-scope" plant 

like CR-3. 

D.C. Cook Walkdown for seismic- Potential breakage of glass Same as for seismic- None. 

l&2 fire and seismic-flood fuses in pilot lines; fire. 

concerns. subsequently screened out 

because no potential was 

identified for sprinkler 

head breaks. 

Davis-Besse Walkdown for seismic- Two small flammable No concerns identified. The anchorage 

fire and seismic-flood compressed gas bottles in problem of two 

concerns. the auxiliary building were small flammable 

found to have inadequate compressed gas 

anchorage, bottles in the 

auxiliary building 

was being resolved. 

Diablo Walkdown for seismic- None. None. Addressed earlier in 

Canyon 1&2 fire and seismic-flood LTSP and 

concerns. Seismically Induced 

Systems Interaction 

Program (SISIP). 

Dresden 2&3 Walkdown for seismic- Potential issues with Some concerns were Resolutions to the 

fire and seismic-flood respect to seismic-induced identified and resolved potential problems 

concerns. fire hazards identified and (e.g., tanks behind identified in the 

resolved (e.g., the effect of switchgear). evaluation are 

the failure of the hydrogen presented in Tables 

seal oil panel and 3.3 and 3.4 of the 

hydrogen monitors on the submittal. 

integrity of the hydrogen 

lines).

2- 75
Table 2.12: Seismic-fire interaction and seismic-flood interaction (Continued)

Seismic-fire Seismic-flood Related plant 

Plant Evaluation approach observations/outliers observations/outliers improvements 

Duane Arnold Walkdown screening Three additional outliers Two air handlers in the The air handler 

evaluations performed in were identified for HPCI room were concern was 

conjunction with the equipment having nearby identified as resolved by analysis 

IPEEE SSEL equipment gas storage bottles that flood/spray outliers which showed 

walkdown, were not adequately because nearby piping adequate clearance 

restrained for seismic could potentially between sprinkler 

loadings, impact fire protection heads and other 

sprinkler piping and piping, and the 

break off the sprinkler bottle concern was 

heads, whose spray resolved by 

could damage the air providing adequate 

handler motors. restraint or 

removing the 

bottles. 

Farley 1&2 As part of the seismic No seismic-fire interaction No flooding concerns None. 

capacity walkdown, all issues exist at a seismic were identified because 

potential internal flooding capacity of at least SSE piping has a high 

sources, mainly piping level . seismic capacity, and 

and tanks, were evaluated all tanks were well 

by the SRT in areas anchored. 

containing SSEL 

equipment. 

Fermi 2 Walkdown for seismic- No concerns identified. No concerns identified. None. 

fire and seismic-flood 

concerns. 

FitzPatrick Walkdown for seismic- A vulnerability to fire or No concerns identified. Procedure AOP- 14, 

fire and seismic-flood explosion as a result of the "Earthquake," was 

concerns. seismic-induced failure of modified. A note 

the hydrogen line in the was added to AOP

turbine building was 14 stating that the 

identified. hydrogen supply 

piping in the turbine 

building is 

susceptible to 

failure during 

seismic events and 

that the piping can 

be isolated by 

closing 89A

H2HAS-1, the 

hydrogen supply 

isolation valve.

2- 76
Table 2.12: Seismic-fire interaction and seismic-flood interaction (Continued)

Seismic-fire Seismic-flood Related plant 

Plant Evaluation approacb observations/outliers observations/outliers improvements 

Fort Calhoun Walkdown for seismic- Various concerns Low seismic capacity Fuel oil tank to be 

fire and seismic-flood identified in turbine of shutdown heat adequately 

concerns. building; in the intake exchangers; flooding of anchored; a sight 

building, a fuel oil tank junction boxes in glass tube is to be 

supplying fire water Room 23; external replaced; anchorage 

pumps has low capacity flooding due to seismic of storage cabinet; 

(HCLPF of about 0.05g). dam break. additional anchor 

bolts on shutdown 

heat exchangers; 

waterproofing of 

junction boxes; 

external flooding 

addressed by severe 

accident 

management 

guidance. 

Ginna Issues examined by the Several issues were A concern was system The seismic-fire 

SRT during the seismic identified. They are related failure due to issues were resolved 

capability walkdown, to the lack of anchorage seismically induced as a part of Ginna's 

for the house heating flooding from failure of IPEEE fire analysis 

boiler (which could shift the Reactor Makeup by either design 

and damage the attached Water tank and the evaluations or 

natural gas line) and the Monitor tank. These design changes. 

failure of block walls tanks will be 

(which are used as fire considered outliers and 

barriers throughout the will be examined to 

plant). The two reactor determine the correct 

coolant pump oil course of action. 

collecting tanks in the 

containment basement 

were not reviewed during 

the seismic walkdown 

because the containment 

was inaccessible. 

Grand Gulf 1 Included in the SSEL for No concerns identified. No concerns identified. None. 

the IPEEE. 

H.B. Walkdown for seismic- Some issues pertaining to None reported, None reported, 

Robinson 2 fire and seismic-flood panel interactions and 

concerns, poorly anchored electrical 

cabinets were identified.

2- 77
Table 2.12: Seismic-fire interaction and seismic-flood interaction (Continued)

Seismic-fire Seismic-flood Related plant 

Plant Evaluation approach observations/outliers observations/outliers improvements 

Haddam Neck Walkdown for seismic- Eight vulnerabilities or risk None reported. Issues have been 

fire and seismic-flood outliers were identified, resolved or propos

concerns; SPRA ed for resolution 

modeling of flooding due (See Table 7.1-1 of 

to dam failure. IPEEE submittal). 

Hatch 1&2 Issues reviewed as a part No concerns identified. No concerns identified. None. 

of the seismic walkdown. 

Hope Creek Walkdown for seismic- The only seismic capacity There is no discussion None. 

fire concerns and concerns are: (1) FPS of seismic-induced 

analysis. water pump house - flooding concerns. 

assumed to fail, and (2) 

FPS water tanks - no credit 

taken after a seismic event 

(median acceleration 

capacity of 0.73g, HCLPF 

of 0.26g). 

Indian Point 2 Walkdown for seismic- Questionable anchorage of None reported. None. 

fire and seismic-flood the reactor coolant pump 

concerns; no modeling of lube oil collection tank; 

seismically induced fire subsequently determined 

or flood sequences in to be adequate. Concern 

seismic PRA. with hydrogen bottles 

stored near alternate 

shutdown panel; no action 

taken because alternate 

shutdown panel is not 

credited in the seismic 

PRA, 

Indian Point 3 Walkdown for seismic- The seismic No concerns identified. No discussion is 

fire and seismic-flood "vulnerabilities" identified provided in the 

concerns, are: (1) the CO 2 system submittal on 

whose rupture poses little improvements for 

risk; (2) the low seismic the identified 

fragility level of the two seismic-fire 

350,000-gallon fire water "vulnerabilities." 

tanks; (3) the availability 

of the FPS pumps which 

are housed in the FPS 

pump house with masonry 

block walls; and (4) the 

marginal lateral support 

capacity of the fuel tank 

for the diesel pump.

2- 78
Table 2.12: Seismic-fire interaction and seismic-flood interaction (Continued)

Seismic-fire Seismic-flood Related plant 

Plant Evaluation approach observations/outliers observations/outliers improvements 

Kewaunee Walkdown for seismic- Potential damage to fire Same as for seismic- None. 

fire and seismic-flood water capability and fire, 

concerns. sprinklers/lines; mercoid 

fire pump jockey switches 

and Cardox pressure 

switches. 

La Salle 1&2 None documented. None. None. None. 

Limerick I &2 Walkdown for seismic- Sight glass tubes on lube No additional. None. 

fire and seismic-flood oil make-up tanks do not 

concerns, have isolation valves; 

mercoid switches in two 

fire protection systems. 

These concerns were 

determined not to be 

significant. 

McGuire 1&2 Walkdown for seismic- None. None. None. 

fire and seismic-flood 

concerns. 

Millstone 2 Walkdown for seismic- Identified three issues: No concerns identified. Resolutions of 

fire and seismic-flood adequacy of the seismic seismic-fire outliers 

concerns. capacity of the Unit 1 include additional 

diesel fire pump fuel tank, evaluation to ensure 

seismic capacity of a long seismic adequacy or 

run of the fire header hardware 

system piping, and the modification. 

block wall construction of 

the fire pump house. 

Millstone 3 None documented. None. None. None. 

Monticello Walkdown for seismic- Sliding of turbine lube oil Several non-safety None. 

fire and seismic-flood tank located in MCC- tanks were found to 

concerns. 133/feedwater pump area, have low seismic 

was identified as a resistance, but these 

potential concern; but were determined to be 

based on a qualitative isolated, or far from, 

assessment, the licensee success path 

judged that additional equipment. 

analysis was unwarranted. 

Nine Mile Walkdown for seismic- No concerns identified. No concerns identified. None. 

Point I fire and seismic-flood 

concerns.

2- 79
Table 2.12: Seismic-fire interaction and seismic-flood interaction (Continued)

Seismic-fire Seismic-flood Related plant 

Plant Evaluation approach observations/outliers observations/outliers improvements 

Nine Mile Walkdown for seismic- None. None. None. 

Point 2 fire and seismic-flood 

concerns. 

North Anna Walkdown for seismic- A potential issue is Two issues identified: Issues to be resolved 

1&2 fire and seismic-flood seismic-induced fires from (1) inadequate support by the end of the 

concerns, the lube oil heat for feedwater heaters in NAPS Unit 1 

exchanger, hydrogen turbine building, and refueling outage 

piping, and hydrogen (2) the flooding currently scheduled 

bottles. potential for the casing to commence in 

cooling tanks, located April 2000. 

next to the auxiliary 

feedwater pump house. 

Oconee Walkdown for seismic- Issues identified in The fault tree models Possible 

I,2,&3 fire and seismic-flood seismic-fire review used in the seismic improvements, such 

concerns. More detailed resulted in procedural and analysis include the as replacement of 

analysis for items not physical improvements, effect of both internal sprinkler heads, are 

screened by walkdown. and external flooding discussed in Section 

sources. 4.9. 

Oyster Creek The seismic-fire-flood The conclusion is that no No discussion in the None. 

interactions were not sources of seismic induced submittal is provided 

directly considered in the fire initiation at regarding any seismic

seismic PRA, but were "reasonable levels of flood interactions, 

qualitatively screened in earthquake beyond the whether internal or 

the fire analysis section, design basis" were external. 

with some ambiguity as identified. Words such as 

to which earthquake "nominal" earthquake 

levels were included in appear elsewhere in this 

the walkdown and the section. It is not clear 

evaluation, whether the licensee 

considered the same 

ground acceleration levels 

as in the seismic study for 

this evaluation. It appears 

that this was mostly a 

qualitative evaluation. 

In the area of inadvertent 

fire suppression actuation, 

it is noted that electrical 

equipment is usually well 

protected by shields or is 

sealed.

2-80
Table 2.12: Seismic-fire interaction and seismic-flood interaction (Continued)

Seismic-fire Seismic-flood Related plant 

Plant Evaluation approach observations/outliers observations/outliers improvements 

Palisades Walkdown and SPRA Hydrogen piping through Seismic-induced None. 

modeling of seismic-fire turbine building is not flooding in the turbine 

and seismic-flood seismically designed and building and 

concerns, passes through block walls screenhouse were 

and cable trays which pose identified for SPRA 

a rupture hazard; there modeling; circulating 

exist a number of water pipe failures in 

unanchored flammable screenhouses were later 

liquid storage cabinets screened out. 

throughout the turbine 

building. 

Palo Verde Seismically-induced No concerns identified. One flooding concern None. 

1,2,&3 fires/floods addressed in was found and this was 

the plant walkdown, judged not to be a 

problem by the seismic 

review team. 

Peach Bottom Walkdown for seismic- Mercoid switches No problems - Replace four 

2&3 fire and seismic-flood encountered in fire encountered other than mercoid switches in 

concerns. protection systems. potential inadvertent fire water manual 

actuation of fire pull stations with 

Unanchored CO2 tanks in protection systems due non-mercoid 

Cardox room of the DG to spurious behavior of switches. 

building, mercoid switches. - Establish 

procedures to 

No spacers between mitigate spurious 

batteries, and lack of end relay operation in 

rails, on CO2 battery racks. Cardox panels. 

- Add restraints to 

Cardox tank 

protecting diesel 

generator areas. 

- Evaluate the 

potential and effects 

of CO2 release in the 

turbine building, 

due to failure of 

Cardox tanks. 

Perry I Walkdown for seismic- The one concern is the No concerns idmntified. None. 

flooding, seismic-fire seismic capacity of the 

concerns. FPS diesel driven pump's 

fuel oil tank located in the 

ESW pumphouse was 

identified and dismissed by 

HCLPF evaluation.

2-81
Table 2.12: Seismic-fire interaction and seismic-flood interaction (Continued) 

Seismic-fire Seismic-flood Related plant Plant Evaluation approach observations/outhers observations/outliers improvements 

Pilgrim I Walkdown for seismic- Truck lock in turbine Interaction potential None, but the 

fire and seismic-flood building contains hydrogen between CST 105B and licensee stated that 

concerns. and lube oil piping runs, cryogenic nitrogen consideration 

and a hydrogen control storage tank, modeled should be given to 

station; switchgear room as leading to loss of isolation of 

"B" also contains lengths CST as water source combustible sources 

of piping which contain for HPCI and RCIC. following an 

lube oil. earthquake. 

Point Beach Walkdown for seismic- None, RWST could fail and None. 

l&2 fire and seismic-flood disable RHR pumps. 

concerns. 

Prairie Island Seismic walkdown. No concerns identified. No concerns identified. None. 

Quad Cities Walkdown for seismic- Several concerns Fire piping risers in the Six mercoid relays l&2 fire and seismic-flood pertaining to seismically- cable spreading room were replaced in the 

concerns. induced fires, inadvertent may break via Cardox system 

seismic actuation of fire interaction with protecting the 

suppression systems, and adjacent multi-tier emergency diesel 

seismically induced failure cable trays. Piping generators; oxygen 

of fire protection attached to cubicle cylinders in the 

capability were noted, coolers (located in common turbine 

comers of the reactor building mezzanine 

building) was observed floor are now 

to have inadequate chained top and 

flexibility to bottom to a newly 

accommodate installed cylinder 

movement of the rod- rack. 

hung units. 

Cubicle coolers are 

being addressed 

under USI A-46, 

and HCLPF 

capacities for these 

components have 

been determined. 

River Bend Walkdown for seismic- No vulnerabilities were No vulnerabilities were None. fire and seismic-flood reported. identified. 

concerns. 

Salem 1&2 Walkdown for seismic- Several concerns were No concerns identified. None. 

fire and seismic-flood identified and dismissed However, there was no 

concerns. after additional mitigating discussion of any 

considerations, external flooding by 

river water, etc., caused 

by seismic events.

2 - 82
Table 2.12: Seismic-fire interaction and seismic-flood interaction (Continued) 

Seismic-fire Seismic-flood Related plant 

Plant Evaluation approach observations/outliers observations/outliers improvements 

San Onofre Walkdown for seismic- No concerns identified. As a potential flooding The licensee's 

2&3 fire and seismic-flood source, CCW seals evaluation also 

concerns; detailed were not screened out, examined the 

qualitative evaluation, and were included in potential for 

the core damage model. seismically induced 

The licensee concluded toxic material 

that there is no releases, and 

significant risk of core identified a plant 

damage due to improvement to the 

seismically induced anchorage of an 

flooding, ammonia storage 

tank. 

Seabrook Walkdown for seismic- No concerns identified. No seismically-induced None. 

fire and seismic-flood flooding scenarios were 

concerns. A seismic- identified that would 

induced flooding analysis have the potential to 

was conducted in 1991 as fail other risk-important 

part of the update of the equipment or systems. 

seismic PRA. 

Sequoyah Walkdown for seismic- Potential of four light Potential for sprinkler None. 

1&2 fire and seismic-flood transformers in the head breakage, but not 

concerns, auxiliary building to in the vicinity of SSEL 

impact SSEL-related equipment. 

cables. (Transformers 

were subsequently 

assessed as having an 

HCLPF capacity of 0.37g.) 

Shearon Walkdown for seismic- No risks were found. No issues were None. 

Harris 1 fire and seismic-flood identified. 

concerns. 

South Texas None documented. None. None. None. 

Project 1&2 

St. Lucie l&2 Documentation review; None. None. None. 

no discussion of a 

seismic-fire walkdown.

2 - 83
Table 2.12: Seismic-fire interaction and seismic-flood interaction (Continued)

Seismic-fire Seismic-flood Related plant 

Plant Evaluation approach observations/outliers observations/outliers improvements 

Summer Walkdown for seismic- Identified some minor No concerns were None. 

fire and seismic-flood concerns, which were identified for 

concerns. either resolved by seismically-induced 

evaluation (e.g., no impact external flooding. 

on SSEL equipment) or by Although internal 

simple corrective actions seismic-induced 

(e.g., better housekeeping flooding hazard was 

with regard to unsecured not specifically 

flammable gas bottles). discussed, it was 

Seismic actuation of fire considered adequately 

suppression systems and addressed by the 

seismic degradation of fire original design basis of 

suppression systems were the plant and the 

not evaluated in IPEEE. individual plant 

examination program. 

Surry 1&2 Walkdown for seismic- Some concerns identified Some concerns were None. 

fire and seismic-flood and dismissed after further identified and 

concerns and PRA evaluation. The potential dismissed after further 

modeling of seismic- fire arising from a concern evaluation. Some tanks 

induced fire concerns. of anchorage of lube oil in the turbine building 

tanks in the turbine were identified which 

building, which may lead could slide causing a 

to the loss of plant service severance of 

water, was modeled in the connections. The 

seismic event tree. concern was dismissed 

because the resulting 

flooding scenario 

would be enveloped by 

the internal flooding 

analysis. The question 

of whether such 

scenarios which could 

lead to a large condi

tional core damage 

probability should be 

modeled above the 

RLE is not addressed. 

Susquehanna Walkdown for seismic- Fire pumps in non- Non-seismically- None. 

l&2 fire and seismic-flood seismically-designed designed fire water 

concerns. structure; CO 2 supply tank system. The submittal 

is not seismically notes that the potential 

anchored; batteries for fire for inadvertent 

pumps do not have actuation of fire water 

spacers; unanchored small system is low. 

electrical cabinets.

2 - 84
Table 2.12: Seismic-fire interaction and seismic-flood interaction (Continued)

Seismic-fire Seismic-flood Related plant 

Plant Evaluation approach observations/outliers observations/outliers improvements 

TMI 1 Walkdown for seismic- No significant concerns Potential failure of the None. 

fire and seismic-flood identified. Some concerns piping and heat 

concerns. regarding the availability exchangers in the heat 

of the fire protection exchanger vault area 

system following a seismic was identified and was 

event were identified, dismissed because the 

walkdown team 

determined that the 

area annunciation was 

adequate to allow the 

plant operators to 

respond long before 

flooding became a 

concern. 

Turkey Point Documentation review; None. None, None. 

3&4 no discussion of a 

seismic-fire walkdown. 

Vermont Walkdown for seismic- Identified a few "improve- No concerns identified. Modification to 

Yankee fire and seismic-flood ment opportunities" related locally reroute the 

concerns, to seismic resistance of the fuel line tubing for 

H2 piping in the turbine the diesel fire pump 

building, the lack of fuel tank; 

positive attachment Improvement to 

between the diesel-driven enhance the support 

fire pump fuel tank and its of the fire system 

supports, the lack of standpipe. 

anchorage of Buses 1 and 

2 to the structure, and the 

support of the fire system 

northwest standpipe in the 

reactor building. 

Vogtle 1&2 Walkdown for seismic- No concerns identified. No concerns identified. None. 

fire and seismic-flood 

concerns. 

Waterford 3 Walkdown screening As a result of the seismic- As a result of the None. 

evaluations were induced fire walkdown, no seismic-induced flood 

performed in conjunction vulnerabilities were walkdown, no 

with the IPEEE SSEL identified. vulnerabilities were 

walkdown. Potential identified. 

seismic induced fire/flood 

sources were identified. 

Verification walkdowns 

were performed by the 

SRT.

2- 85
Table 2.12: Seismic-fire interaction and seismic-flood interaction (Continued) 

Seismic-fire Seismic-flood Related plant 

Plant Evaluation approach observations/outliers observations/outilers improvements 

Watts Bar I Walkdown for seismic- No safety issues were The submittal did not None. 

induced flooding and identified, contain much 

seismic-induced fire discussion on the 

issues. seismically induced 

flooding issues, except 

the mention that the 

potential for seismic

induced floods was 

evaluated by the SRT 

as a part of walkdown 

procedures. 

Wolf Creek Addressed as part of the None identified. None identified. None, 

SSEL walkdown; no 

walkdown was performed 

to evaluate seismic-fire or 

seismic-flooding effects 

outside the direct 

influence on SSEL 

equipment. 

Formerly known as Washington Nuclear Project Number 2.

2- 86
Table 2.13: Flux mapping systems

GI-13 1 Related plant 

Plant applicable Previous upgrade LPEEE findings improvements 

Arkansas No Not applicable Not applicable Not applicable 

Nuclear One 1 

Arkansas No Not applicable Not applicable Not applicable 

Nuclear One 2 

Beaver Valley Yes Analysis performed in Adequacy of system None. 

1 1989 for SSE verified by an SMA 

analysis with a review 

level earthquake of 0.3g. 

Beaver Valley Yes Issue resolved prior to Plant is not vulnerable to None. 

2 initial plant startup a small LOCA from this 

issue. Its contribution to 

CDF was considered 

negligible and not 

quantified in IPEEE. 

Braidwood No Not applicable Not applicable Not applicable 

1&2 

Browns Ferry No Not applicable Not applicable Not applicable 

2&3 

Brunswick No Not applicable Not applicable Not applicable. 

1&2 

Byron 1&2 No Not applicable Not applicable Not applicable 

Callaway Yes In 1987, the hold-down None; flux mapping No additional 

assembly of the flux system was inaccessible improvements for 

mapping system was due to radioactive IPEEE. 

upgraded by increasing exposure concerns; no 

the size and strength of analysis for events that 

bolts and plates of the are beyond the design 

assembly. basis. 

Calvert Cliffs No Not applicable Not applicable Not applicable 

1&2 

Catawba 1&2 Yes Restraints added during No analysis for events No additional 

construction. that are beyond the improvements for 

design basis. IPEEE. 

Clinton No Not applicable Not applicable Not applicable

2- 87
Table 2.13: Flux mapping systems (Continued) 

GI-131 Related plant 

Plant applicable Previous upgrade JPEEE findings improvements 

Columbia* No Not applicable Not applicable Not applicable 

Comanche Yes None; however, in None None. 

Peak 1&2 previous licensing 

spatial interaction 

program activities, it 

was determined that the 

flux mapping system 

was designed and 

constructed to preclude 

interactions at SSE 

loads. 

Cooper No Not applicable Not applicable Not applicable 

Crystal River No Not applicable Not applicable Not applicable 

D.C. Cook Yes Hold-down straps 0.32g HCLPF capacity No additional 

1 &2 attached to the top of assessed based on improvements for 

the cart were redesign- walkdown and review of IPEEE. 

ed and modified; a the modified 

lower lateral restraint to configuration. 

the flux mapping cart 

was installed at an 

elevation just above the 

seal table. 

Davis-Besse No Not applicable Not applicable Not applicable 

Diablo Yes SISIP-related No analysis for events No additional 

Canyon 1 &2 modifications to that are beyond the improvements for 

improve the seismic design basis. IPEEE. 

structural integrity of 

the frame assemblies. 

Dresden 2&3 No Not applicable Not applicable Not applicable 

Duane Arnold No Not applicable Not applicable Not applicable 

Farley l&2 Yes The flux mapping No issue identified in None. 

system cart hold-down IPEEE walkdown. 

bolts were replaced to 

comply with the 

Westinghouse 

recommendation. 

Fermi 2 No Not applicable Not applicable Not applicable

2- 88
Table 2.13: Flux mapping systems (Continued)

GI-13 1 Related plant 

Plant applicable Previous upgrade LPEEE findings improvements 

FitzPatrick No Not applicable Not applicable Not applicable 

Fort Calhoun No Not applicable Not applicable Not applicable 

Ginna Yes Not described in System was examined by None. 

submittal. the A-46/IPEEE SRT 

during the containment 

walkdown, and was 

found not to be 

seismically vulnerable. 

Grand Gulf 1 No Not applicable Not applicable Not applicable 

H.B. Yes Four hold-down Seismic review team No additional 

Robinson 2 restraints were determined the flux improvements for 

fabricated of steel mapping system to be IPEEE. 

angle, welded to the adequate for RLE loads. 

cart, and bolted to the 

structure. 

Haddam Neck Not directly, None; flux mapping Walkdown verified None. 

since cart is cart is already bolted to adequacy of 

not movable, the platform. configuration. 

Hatch 1&2 No Not applicable Not applicable Not applicable 

Hope Creek No Not applicable Not applicable Not applicable 

Indian Point 2 Yes The flux monitoring Screened out at 0.5g No additional 

cart had previously HCLPF. improvements for 

been braced in two IPEEE. 

directions. 

Indian Point 3 Yes Not discussed in Support and restraint of None. 

submittal. the movable portion of 

the system were 

inspected during 

containment walkdown 

and seismic-induced 

damage to the seal table 

was judged not credible. 

Kewaunee Not directly, None; lateral resistance Walkdown found that a Administrative control 

since flux of flux mapping system chain hoist above the flux was implemented to 

mapping cart has already been mapping cart might better secure chain 

is not determined to be interact with the 10 path hoist. 

movable. adequate. assembly.

2- 89
Table 2.13: Flux mapping systems (Continued) 

GI-131 Related plant 

Plant applicable Previous upgrade IPEEE findings improvements 

La Salle 1 &2 No Not applicable Not applicable Not applicable 

Limerick 1&2 No Not applicable Not applicable Not applicable 

McGuire 1 &2 Yes Previous seismic No analysis for events No additional 

analyses have indicated that are beyond the improvements for 

installed restraints are design basis. IPEEE. 

adequate. 

Millstone 2 No Not applicable Not applicable Not applicable 

Millstone 3 Yes A modification was None described. No additional 

implemented to limit improvements for 

relative displacement IPEEE. 

between the flux 

mapping equipment 

and the seal table. 

Monticello No Not applicable. Not applicable Not applicable 

Nine Mile No Not applicable Not applicable Not applicable 

Point 1 

Nine Mile No Not applicable. Not applicable Not applicable 

Point 2 

North Anna Yes A provision for The system was None. 

1&2 restraining this system examined during 

during plant operation walkdown. Review of the 

is outlined in the station restraint/anchorage 

procedure IMPC-C-1- showed HCLPF value 

IC-07. The equipment greater than 0.3g. 

is restrained with floor

mounted brackets 

which are located on 

either side of the 

equipment. 

Oconee No Not applicable Not applicable Not applicable 

1,2,&3 

Oyster Creek No Not applicable Not applicable Not applicable 

Palisades No Not applicable Not applicable Not applicable 

Palo Verde No Not applicable Not applicable Not applicable 

1,2,&3

2 - 90
Table 2.13: Flux mapping systems (Continued)

GI-131 Related plant 

Plant applicable Previous upgrade 1PEEE findings improvements 

Peach Bottom No Not applicable Not applicable Not applicable 

2&3 

Perry 1 No Not applicable Not applicable Not applicable 

Pilgrim 1 No Not applicable Not applicable Not applicable 

Point Beach Not directly, None. IPEEE submittal notes None. 

1 &2 since flux that the flux mapping 

mapping cart system is identical to 

is not Kewaunee's, which was 

movable, found to be adequate. 

Prairie Island Yes Not discussed in The moveable in-core None. 

1 &2 submittal. flux mapping systems 

were "found to have 

sufficient seismic 

capacity to the SSE level 

of the USAR" by the 

licensee. No further 

information is provided. 

Quad Cities No Not applicable Not applicable Not applicable 

1&2 

River Bend No Not applicable Not applicable Not applicable 

Salem 1&2 Yes Not discussed in No seismic vulnerabilities None. 

submittal. identified in walkdown. 

San Onofre No Not applicable Not applicable Not applicable 

2&3 

Seabrook Yes GSI- 131 was addressed The presence of hold- None. 

by installation of hold- down bolts was verified 

down bolts for the flux during the seismic 

mapping cart. walkdown. Therefore, 

GSI-131 is considered 

closed by the licensee. 

Sequoyah Yes Restraints have been Seismic review team No IPEEE 

1 &2 installed on the flux determine the flux improvements. 

mapping cart. mapping system to be 

adequate for RLE loads.

2-91
Table 2.13: Flux mapping systems (Continued)

GI-131 Related plant 

Plant applicable Previous upgrade LPEEE findings improvements 

Shearon Yes Issue identified in 1984 The installation was None. 

Harris 1 and resolved by visually verified by using 

installing wheel stops the Harris Surrogate Tour 

on the Flux Mapping system, and the licensee 

Control Trolley to stated that the installed 

prevent seismic wheel stops have 

interaction between the sufficient design margin 

trolley and the ICFM to be screened out for the 

tubing or fittings. RLE. 

South Texas Yes None described. IPEEE submittal notes None. 

Project 1&2 that there are no 

vulnerabilities or risk 

outliers associated with 

this issue. 

St. Lucie 1&2 No Not applicable Not applicable Not applicable 

Summer Yes A plant modification The submittal does not None. 

was carried out after a mention this issue, but 

review of this issue in states that the in-core 

1985. The detectors are generally 

modification restrained "inherently rugged," that 

the 10-path rotary walkdown of this 

transfer and valve equipment is not 

support assembly from required, but that seismic 

seismic movement via evaluation should be 

four floor mounted conducted. In response to 

steel tubes. an RAI the licensee 

simply stated that by the 

"rule of the box" the in

core flux mapping system 

is considered a part of the 

"reactor internals," and 

that according to 

Supplement 5 of GL 88

20, reactor internals are 

considered generically 

rugged. An email reply 

by the licensee to a 

subsequent 

communication resolved 

the issue.

2 - 92
Table 2.13: Flux mapping systems (Continued)

GI-131 Related plant 

Plant applicable Previous upgrade L1PEEE findings improvements 

Surry 1&2 Yes A station procedure System examined through None. 

already in place to walkdowns. It was 

restrain the system concluded that the 

during the operation of restraint/anchorage for 

the plant. the system had a HCLPF 

capacity greater than 0.3g 

and this issue is 

considered to be closed 

by the licensee. 

Susquehanna No Not applicable Not applicable Not applicable 

1&2 

TMI 1 No Not applicable Not applicable Not applicable 

Turkey Point Yes In 1989, lateral restraint No evaluation. None. 

3&4 was added to the 

movable support 

assembly of the flux 

mapping system, and 

was evaluated as being 

adequate. 

Vermont No Not applicable Not applicable Not applicable 

Yankee 

Vogtle 1&2 Yes VEGP has installed a This system was walked None. 

stiffener and four down as part of the 

anchor assemblies. IPEEE evaluation and no 

issues were identified. 

Waterford 3 No Not applicable Not applicable Not applicable 

Watts Bar 1 Yes Not discussed in The flux monitoring cart None. 

submittal. was verified during the 

IPEEE walkdowns to 

have been restrained 

adequately and was 

determined to be capable 

of withstanding the RLE.

2 - 93
Table 2.13: Flux mapping systems (Continued)

2 - 94

GI1431 Related plant 

Plant applicable Previous upgrade IPEEE findings improvements 

Wolf Creek Yes None. The seismic review team None. 

questioned the lateral 

restraint of wide-flange 

beams that support the 

frame containing the 

movable flux mapping 

system (excessive lateral 

movement of the beams 

could dislodge the 

frame), but noted that 

when the cart is 

positioned above the seal 

table, steel angles (that 

are welded to the beams) 

can be bolted to the 

movable frame, and 

hence, would prevent the 

frame from being 

dislodged. Assuming that 

the operators utilize this 

provision and secure the 

frame, the seismic review 

team screened out the 

flux mapping system at 

an HCLPF capacity of 

0.3g. 

Formerly known as Washington Nuclear Project Number 2.
3. FIRE TABLES

This section contains five tables of summary information obtained from the fire portions of the IPEEEs. Table 

3.1 contains basic plant information for each plant. The table includes the plant type, plant class, containment 

class, present gross capacity, location (by State), and the dates the construction permit and operating license 

were issued. 

Table 3.2 presents the plant-wide fire core damage frequency (CDF) information. The table includes the fire 

PRA methodology used at each plant, the CDF reported in the IPEEE, any revised CDFs after all RAIs were 

addressed, and the internal events CDF. Table 3.3 lists the fire areas that contributed to a plant's overall CDF 

and their corresponding CDFs. 

Tables 3.4 and 3.5 list the vulnerabilities and improvements, respectively, identified by the various plants. 

Included in the list of vulnerabilities is the definition of "vulnerability" used by a plant. The improvements 

table includes whether the improvement was a result of the fire analysis, a seismic/fire analysis, or some other 

program or action. Information regarding the current status of the improvement is also provided.

3-1
U VYIXr

Table 3.1: Summary of basic plant information

U . . 1 1 D A IrD 1 - - • , ._ -- .ý - . . I 1 1 Z . I Uy IV ifiy / W•;L .3-1U(D i una41imnnt o rw rl

Beaver Valley 2 PWR West 3-loop Subatmospheric 833 Pennsylvania 05/03/1974 08/14/1987 Braidwood 1 PWR West 4-loop Large Dry 1120 Illinois 12/31/1975 07/02/1987 Braidwood 2 PWR West 4-loop Large Dry 1120 Illinois 12/31/1975 05/20/1988 Browns Ferry 1 BWR BWR 3/4 Mark I 1065 Alabama 05/10/1967 12/20/1973 Browns Ferry 2 BWR BWR 3/4 Mark I 1065 Alabama 05/10/1967 08/02/1974 Browns Ferry 3 BWR BWR 3/4 Mark I 1065 Alabama 07/31/1968 08/18/1976 Brunswick 1 BWR BWR 3/4 Mark I 821 North Carolina 02/07/1970 11/12/1976 Brunswick 2 BWR BWR 3/4 Mark I 821 North Carolina 02/07/1970 12/27/1974 Byron 1 PWR West 4-loop Large Dry 1120 Illinois 12/31/1974 02/14/1985 Byron 2 PWR West 4-loop Large Dry 1120 Illinois 12/31/1974 01/30/1987 Callaway PWR West 4-loop Large Dry 1150 Missouri 04/16/1976 10/18/1984 Calvert Cliffs I PWR CE Large Dry 865 Maryland 07/07/1969 07/31/1974 Calvert Cliffs 2 PWR CE Large Dry 865 Maryland 07/07/1969 11/30/1976 Catawba 1 PWR West 4-loop Ice Condenser 1129 South Carolina 08/07/1975 01/17/1985 Catawba 2 PWR West 4-loop Ice Condenser 1129 South Carolina 08/07/1975 05/15/1986 Clinton BWR BWR 5/6 Mark III 950 Illinois 02/24/1976 04/17/1987 Columbia* BWR BWR 5/6 Mark II 1100 Washington 03/19/1973 04/13/1984 Comanche Peak 1 PWR West 4 -loop Large Dry 1150 Texas 12/19/1974 04/17/1990 Comanche Peak 2 PWR West 4-loop Large Dry 1150 Texas 12/19/1974 04/06/1993 Cook 1 PWR West 4-loop Ice Condenser 1020 Michigan 03/25/1969 10/25/1974 Cook 2 PWR West 4-loop Ice Condenser 1060 Michigan 03/25/1969 12/23/1977 Cooper BWR BWR 3/4 Mark I 778 Nebraska 06/04/1968 01/18/1974 Crystal River 3 PWR B&W Large Dry 821 Florida 09/25/1968 01/28/1977 Davis-Besse PWR B&W Large Dry 906 Ohio 03/24/1971 04/22/1977 Diablo Canyon 1 PWR West 4-loop Large Dry 1073 California 04/23/1968 11/02/1984 Diablo Canyon 2 PWR West 4-loop Large Dry 1087 California 12/09/1970 08/26/1985 Dresden 2 BWR BWR 2/3 Mark I 794 Illinois 01/10/1966 12/22/1969 Dresden 3 BWR BWR 2/3 Mark I 794 Illinois 10/14/1966 03/02/1971 

Duane Arnold BWR BWR 3/4 Mark I 538 Iowa 06/22/1970 02/22/1974 Farley I PWR West 3-loop Large Dry 829 Alabama 08/16/1972 06/25/1977 Farley 2 PWR West 3-loop Large Dry 829 Alabama 08/16/1972 03/31/1981 Fermi 2 BWR BWR 3/4 Mark I 1093 Michigan 09/26/1972 07/15/1985 

FitzPatrick BWR BWR 3/4 Mark I 816 New York 05/20/1970 10/17/1974 Fort Calhoun PWR CE Large Dry 488 Nebraska 06/07/1968 08/09/1973 Ginna PWR West 2-loop Large Dry 470 New York 04/25/1966 07/01/1970 

Grand Gulf 1 BWR BWR 5/6 Mark III 1250 Mississippi 09/04/1974 11/01/1984 Haddam Neck PWR West 4-loop Large Dry 582 Connecticut 05/26/1964 06/30/1967 Hatch 1 BWR BWR 3/4 Mark I 797 Georgia 09/30/1969 10/13/1974 Hatch 2 BWR BWR 3/4 Mark I 806 Georgia 12/27/1972 06/13/1978 Hope Creek 1 BWR BWR 3/4 Mark I 1031 New Jersey 11/04/1974 07/25/1986 Indian Point 2 PWR West 4-loop Large Dry 939 New York 10/14/1966 09/28/1973 Indian Point 3 PWR West 4-loop Large Dry 965 New York 08/13/1969 04/05/1976 Kewaunee PWR West 2-loop Large Dry 540 Wisconsin 08/06/1968 12/21/1973 LaSalle 1 BWR BWR 5/6 1-Mark II 1078 Illinois 09/10/1973 03/13/1982

3-2

I

RPtv•J ¥GLLVJ Q, I4" DO- 4
Table 3.1: Summary of basic plant information (Continued)

Limerick 2 BWR BWR 3/4 Mark II 1055 Pennsylvania 06/19/1974 08/25/1989 

McGuire 1 PWR West 4-loop Ice Condenser 1129 North Carolina 02/23/1973 07/08/1981 

McGuire 2 PWR West 4-loop Ice Condenser 1129 North Carolina 02/23/1973 05/27/1983 

Millstone 2 PWR CE Large Dry 858 Connecticut 12/11/1970 09/30/1975 

Millstone 3 PWR West 4-loop Subatmospheric 1150 Connecticut 08/09/1974 01/3.1/1986 

Monticello BWR BWR 3/4 Mark I 542 Minnesota 06/19/1967 02/18/1971 

Nine Mile Point 1 BWR BWR 2/3 Mark I 613 New York 04/12/1965 08/22/1969 

Nine Mile Point 2 BWR BWR 5/6 Mark II 1062 New York 06/24/1974 07/02/1987 

North Anna 1 PWR West 3-loop Subatmospheric 907 Virginia 02/19/1971 04/01/1978 

North Anna 2 PWR West 3-loop Subatmospheric 907 Virginia 02/19/1971 08/21/1980 

Oconee 1 PWR B&W Large Dry 846 South Carolina 11/06/1967 02/06/1973 

Oconee 2 PWR B&W Large Dry 846 South Carolina 11/06/1967 10/06/1973 

Oconee 3 PWR B&W Large Dry 846 South Carolina 11/06/1967 07/19/1974 

Oyster Creek BWR BWR 2/3 Mark I 650 New Jersey 12/15/1964 12/01/1969 

Palisades PWR CE Large Dry 805 Michigan 03/14/1967 12/31/1969 

Palo Verde 1 PWR CE Large Dry 1270 Arizona 05/25/1976 06/01/1985 

Palo Verde 2 PWR CE Large Dry 1270 Arizona 05/25/1976 04/24/1986 

Palo Verde 3 PWR CE Large Dry 1270 Arizona 05/25/1976 11/25/1987 

Peach Bottom 2 BWR BWR 3/4 Mark I 1055 Pennsylvania 01/31/1968 12/14/1973 

Peach Bottom 3 BWR BWR 3/4 Mark I 1035 Pennsylvania 01/31/1968 07/02/1974 

Perry 1 BWR BWR 5/6 Mark III 1205 Ohio 05/03/1977 11/13/1986 

Pilgrim 1 BWR BWR 3/4 Mark I 670 Massachusetts 08/26/1968 09/15/1972 

Point Beach 1 PWR West 2-loop Large Dry 485 Wisconsin 07/19/1967 10/05/1970 

Point Beach 2 PWR West 2-loop Large Dry 485 Wisconsin 07/25/1968 03/08/1973 

Prairie Island 1 PWR West 2-loop Large Dry 503 Minnesota 06/25/1968 04/05/1974 

Prairie Island 2 PWR West 2-loop Large Dry 500 Minnesota 06/25/1968 10/29/1974 

Quad Cities 1 BWR BWR 3/4 Mark I 789 Illinois 02/15/1967 12/14/1972 

Quad Cities 2 BWR BWR 3/4 Mark I 789 Illinois 02/1-5K1967 12/14/1972 

River Bend I BWR BWR 5/6 Mark III 936 Louisiana 03/25/1977 11/20/1985 

Robinson 2 PWR West 3-loop Large Dry 718 South Carolina 04/13/1967 09/23/1970 

Salem I PWR West 4-loop Large Dry 1106 New Jersey 09/25/1968 12/01/1976 

Salem 2 PWR West 4-loop Large Dry 1106 New Jersey 09/25/1968 05/20/1981 

San Onofre 2 PWR CE Large Dry 1070 California 10/18/1973 09/07/1982 

San Onofre 3 PWR CE Large Dry 1080 California 10/18/1973 09/16/1983 

Seabrook 1 PWR West 4-loop Large Dry 1148 New Hampshire 07/07/1976 03/15/1990 

Sequoyah 1 PWR West 4-loop Ice Condenser 1141 Tennessee 05/27/1970 09/17/1980 

Sequoyah 2 PWR West 4-loop Ice Condenser 1136 Tennessee 05/27/1970 09/15/1981 

Shearon Harris 1 PWR West 3-loop Large Dry 900 North Carolina 01/27/1978 01/12/1987 

South Texas 1 PWR West 4-loop Large Dry 1250 Texas 12/22/1975 03/22/1988 

South Texas 2 PWR West 4-loop Large Dry 1250 Texas 12/22/1975 03/28/1989 

St. Lucie 1 PWR CE Large Dry 839 Florida 07/01/1970 03/01/1976 

St. Lucie 2 PWR CE Large Dry 839 Florida 05/02/1977 06/10/1983 

Summer PWR West 3-loop Large Dry 895 South Carolina 03/21/1973 11/12/1982 

Surry 1 PWR West 3-loop Subatmospheric 788 Virginia 06/25/1968 05/25/1972 

Surry 2 PWR West 3-loop Subatmospheric 788 Virginia 06/25/1968 01/29/1973

3-3
Table 3.1: Summary of basic plant information (Continued)

Three Mile Island PWR B&W Large Dry 819 I Pennsylvania 05/18/1968 04/19/1974

Turkey Point 3 PWR West 3-loop Large Dry 666 Florida 04/27/1967 07/19/1972 

Turkey Point 4 PWR West 3-loop Large Dry 666 Florida 04/27/1967 04/10/1973 

Vermont Yankee BWR BWR 3/4 Mark I 522 Vermont 12/11/1967 02/28/1973 

Vogtle 1 PWR West 4-loop Large Dry 1158 Georgia 06/28/1974 03/16/1987 

Vogtle 2 PWR West 4-loop Large Dry 1158 Georgia 06/28/1974 03/31/1989 

Waterford 3 PWR CE Large Dry 1104 Louisiana 11/14/1974 03/16/1985 

Watts Bar 1 PWR West 4-ioop Ice Condenser 1154 Tennessee 0 1/23/1973 02/07/1996 

Wolf Creek 1 PWR West 4-loop Large Dry 1150 Kansas 05/31/1977 06/04/1985

, Formerly Known as Washington Nuclear Project Number 2.

3-4

I

I S° • I ..... ... .. I . .. .
Table 3.2: Summary of fire CDFs

Pk14 %F IV V LIv I It. I /L U _t.9t/L.L'_VJ ýt.v IL.Uj 

ANO 2 FIVE + not reported 4.51E-05 3.40E-05 

Beaver Valley 1 PRA 1.75E-05 1.75E-05 2.14E-04 

Beaver Valley 2 PRA 1.05E-05 1.05E-05 1.92E-04 

Braidwood 1 FIVE, PRA 2.50E-06 3.90E-06 2.74E-05 

Braidwood 2 FIVE, PRA 2.40E-06 3.80E-06 2.74E-05 

Browns Ferry 1 not analyzed, see Unit 2 

Browns Ferry 2 FIVE, PRA 6.78E-06 9.80E-06 4.80E-05 

Browns Ferry 3 FIVE, PRA 4.38E-06 7.40E-06 

Brunswick 1 not analyzed, see Unit 2 

Brunswick 2 FIVE, PRA 3.39E-05 3.62E-05 2.70E-05 

Byron 1 FIVE, PRA 2.40E-06 4.20E-06 3.09E-05 

Byron 2 FIVE, PRA 2.50E-06 5.30E-06 3.09E-05 

Callaway FIVE, PRA 8.88E-06 8.88E-06 5.85E-05 

Calvert Cliffs 1 FIVE, PRA 7.30E-05 7.20E-05 2.40E-04 

Calvert Cliffs 2 FIVE, PRA 1.1OE-04 1.1OE-04 2.40E-04 

Catawba 1 PRA 4.70E-06 4.63E-06 5.80E-05 

Catawba 2 not analyzed, see Unit 1 

Clinton PRA 3.26E-06 3.64E-06 2.66E-05 

Columbia Generating* FIVE, PRA 1.76E-05 5.50E-05 1.75E-05 

Comanche Peak 1 FIVE, PRA 2.09E-05 2.09E-05 5.72E-05 

Comanche Peak 2 not analyzed, see Unit 1 

Cook 1 PRA 1.61E-07 3.76E-06 6.26E-05 

Cook 2 not analyzed, see Unit 1 

Cooper FIVE, PRA 6.87E-06 6.87E-06 7.97E-05 

Crystal River 3 FIVE, PRA 4.19E-05 4.19E-05 1.53E-05 

Davis-Besse FIVE, PRA 1.67E-05 2.97E-05 6.60E-05 

Diablo Canyon 1 PRA 2.73E-05 2.73E-05 8.80E-05 

Diablo Canyon 2 not analyzed, see Unit 1 

Dresden 2 FIVE, PRA 1.69E-05 1.69E-05 1.85E-05 

Dresden 3 FIVE, PRA 3.08E-05 3.08E-05 1.85E-05 

Duane Arnold FIVE + 1.05E-05 1.05E-05 7.84E-06 

Farley 1 FIVE, PRA 1.66E-04 1.66E-04 1.30E-04 

Farley 2 FIVE, PRA 1.28E-04 1.28E-04 1.30E-04 

Fermi 2 FIVE, PRA 1.70E-05 2.15E-05 5.70E-06 

FitzPatrick FIVE, PRA 2.OOE-05 2.56E-05 1.92E-06 

Fort Calhoun FIVE, PRA 2.74E-05 2.74E-05 1.36E-05 

Ginna FIVE, PRA 6.40E-05 3.34E-05 8.38E-05 

Grand Gulf 1 FIVE, PRA 8.76E-06 8.89E-06 1.72E-05 

Haddam Neck FIVE + 6.08E-05 6.08E-05 1.90E-04 

Hatch 1 PRA 7.50E-06 7.80E-06 2.23E-05 

Hatch 2 PRA 5.40E-06 5.80E-06 2.36E-05 

Hope Creek 1 FIVE + 8.10E-05 8.1OE-05 4.63E-05

3-5
Table 3.2: Summary of fire CDFs (Continued)

lIlUnIUl 

Kewau

ruIl

FIVE, PRA I 9.81E-05 I 1.80E-04 I 6_65P-As

LaSalle 1 not analyzed, see Unit 2 

LaSalle 2 PRA j 3.21E-05/ry I 3.211E-05/ry [ 4.74E-05 

Limerick 1 FIVE not reported not reported 4.30E-06 

Limerick 2 not analyzed, see Unit 1 

McGuire I PRA 2.32E-07 [ 6.74E-07 4.OOE-05 

McGuire 2 not analyzed, see Unit 1 

Millstone 1 no IPEEE submittal 

Millstone 2 FIVE + 6.30E-06 6.30E-06 3.42E-05 

Millstone 3 FIVE + 4.80E-06 4.80E-06 5.61E-05 

Monticello FIVE + 7.90E-06 7.90E-06 2.60E-05 

Nine Mile Point 1 FIVE, PRA 2.OOE-05 2.OOE-05 5.50E-06 

Nine Mile Point 2 FIVE, PRA 1.40E-06 1.40E-06 3.1 OE-05 

North Anna 1 FIVE, PRA 3.91E-06 3.91E-06 7.16E-05 

North Anna 2 FIVE, PRA 4.08E-06 4.08E-06 7.16E-05 

Oconee 1 not analyzed; see Unit 3 

Oconee 2 not analyzed, see Unit 3 

Oconee 3 PRA 5.80E-06 5.96E-06 2.30E-05 

Oyster Creek FIVE, PRA 7.70E-06 1.56E-05 3.90E-06 

Palisades FIVE 3.31E-05 3.31E-05 5.07E-05 

Palo Verde 1 FIVE+ 8.67E-05 8.67E-05 9.OOE-05 

Palo Verde 2 not analyzed, see Unit I 

Palo Verde 3 not analyzed, see Unit 1 

Peach Bottom 2 FIVE not reported 7 not reported 5.53E-06 

Peach Bottom 3 not analyzed, see Unit 2 

Perry 1 FIVE, PRA 3.27E-05 3.27E-05 1.30E-05 

Pilgrim 1 FIVE, PRA 2.20E-05 2.20E-05 5.80E-05 

Point Beach 1 FIVE + 5.11E-05 5.28E-05 1.15E-04 

Point Beach 2 not analyzed, see Unit I 

Prairie Island 1 FIVE, PRA 4.93E-05 [ 4.93E-05 5.05E-05 

Prairie Island 2 not analyzed, see Unit 1 

Quad Cities 1 FIVE, PRA 5.40E-03 6.60E-05 1.20E-06 

Quad Cities 2 FIVE, PRA 5.20E-03 7.31E-05 1.20E-06 

River Bend I PRA + 2.25E-05 2.25E-05 1.55E-05 

Robinson 2 FIVE, PRA 2.22E-04 9.23E-05 3.20E-04 

Salem 1 FIVE, PRA 2.30E-05 2.30E-05 5.20E-05 

Salem 2 FIVE, PRA 2.40E-05 2.40E-05 5.50E-05 

San Onofre 2 FIVE, PRA 1.60E-05 1.60E-05 3.OOE-05 

San Onofre 3 not analyzed - see unit 2 

Seabrook 1 FIVE 1.20E-05 1.20E-05 6.60E-05 

Sequoyah 1 FIVE, PRA not reported 1.56E-05 1.70E-04

3-6

I

nee
Table 3.2: Summary of fire CDFs (Continued)

-- -- -- I - I ar I fl flfl'

Shearon Harris 1 PRA +

South Texas Project 1 PRA not reported 5.06E-07 4.30E-05 

South Texas Project 2 not analyzed, see Unit 1 

St. Lucie 1 FIVE + 1.87E-04 1.87E-04 2.30E-05 

St. Lucie 2 FIVE + 1.87E-04 1.87E-04 2.62E-05 

Summer FIVE, PRA 4.04E-04 8.52E-05 2.OOE-04 

Surry 1 FIVE, PRA 6.28E-06 6.28E-06 1.25E-04 

Surry 2 FIVE, PRA 6.28E-06 6.28E-06 1.25E-04 

Susquehanna 1 FIVE, PRA, (est.) < 1E-9/cycle 3.60E-08 8.96E-08 

qualitative 

Susquehanna 2 not analyzed, see Unit 1 

Three Mile Island 1 FIVE, PRA 2.16E-05 2.16E-05 4.49E-05 

Turkey Point 3 FIVE 1.94E-04 1.94E-04 3.73E-04 

Turkey Point 4 not analyzed in full; no unit fire CDF given; for most areas see Unit 3 

Vermont Yankee FIVE, PRA 3.80E-05 5.60E05 4.30E-06 

Vogtle 1 PRA 1.01E-05 L.O1E-05 4.90E-05 

Vogtle 2 not analyzed, see Unit 1 

Waterford 3 FIVE, PRA 7.OOE-06 7.OOE-06 1.80E-05 

Watts Bar 1 FIVE, PRA not reported 6.90E-06 8.OOE-05 

Wolf Creek 1 FIVE, PRA 7.59E-06 7.59E-06 4.20E-05

* Formerly known as Washington Nuclear Project Number 2.

3-7

I .1 U•-U5 i .LiUr'I-U3 /.UUVI-U3
Table 3.3: Significant fire area CDFs

Plant Sign~ifiant fire areas CJ)F . 

ANO 1 Turbine room/hall/building 8.92E-06 

South battery room 6.50E-06 

Emergency diesel generator corridor 6.43E-06 

Electrical equipment room/auxiliary relay room 3.88E-06 

Main control room/control room 3.81E-06 

South switchgear room 3.72E-06 

Cable spreading room 3.01E-06 

Pipe room 2.48E-06 

Lower south electrical penetration room 2.02E-06 

North switchgear room 1.99E-06 

Controlled access exit 1.45E-06 

ANO 2 Turbine room/hall/building 1.77E-05 

Cable spreading room 5.94E-06 

Diesel corridor 5.90E-06 

Switchgear room 3.59E-06 

Electrical equipment room/auxiliary relay room 3.32E-06 

Intake structure 2.85E-06 

Lower south electrical/piping penetration room 2.72E-06 

Main control room/control room 1.88E-06 

auxiliary building EXT or super-compartment 1.16E-06 

Switchgear room 5.30E-07 

Beaver Valley 1 Cable spreading room 4.70E-06 

Cable vault or cable tunnel 4.27E-06 

Primary auxiliary building general area E 2.44E-06 

Switchgear room 1.42E-06 

Control room, process instrument room 1.22E-06 

Control room, general area 9.58E-07 

Total contribution from scenarios screened during spatial interactions phase 8.1 OE-07 

Turbine building, general area 3.8 1E-07 

Control room, communication equipment and relay panel room 2.70E-07 

Turbine generator area 2.34E-07 

Emergency switchgear 1AE room 1.89E-07 

Reactor containment area 1.83E-07 

Emergency switchgear 1DF room 1.19E-07 

Primary auxiliary building general area D 1.05E-07 

West cable vault area 4.36E-08 

Auxiliary feed water pumps room 4.3 1E-08 

Control room, HVAC equipment room 4.3 1E-08 

East cable vault area 2.37E-08 

Pipe tunnel penetration A cubicle 1.01E-08 

Turbine oil reservoir, coolers, and oil conditioner 9.08E-09 

Hydrogen seal oil unit 7.69E-09 

Safeguard building pipe tunnel general area 5.18E-09 

Turbine building to pipe tunnel area 8.94E-10 

Beaver Valley 2 Main control room/control room 1.86E-06 

Cable vault or cable tunnel 1.32E-06 

Normal switchgear room 1.1OE-06 

West cable vault area, elevation 735' 6.54E-07

3-8

I
Table 3.3: Significant fire area CDFs (Continued)

Plant Significant fire areas CDF 

West cable vault area, elevation 755' 6.12E-07 

Total contribution from scenarios screened during spatial interactions phase 6.01E-07 

Switchgear room 5.40E-07 

Switchgear room 5.1OE-07 

Communication, instrumentation, and relay room 4.75E-07 

North safeguards area (including RSS cubicles) 3.49E-07 

Diesel generator building No. 1 3.25E-07 

Diesel generator building No. 2 3.08E-07 

East cable vault area, elevation 735' 3.OOE-07 

MCC 2-E03 cubicle, PAB 2.95E-07 

South safeguards area (including RSS cubicles) 2.62E-07 

Battery room 2-5 2.52E-07 

Primary auxiliary building general area, elevation 760' 2.09E-07 

Electrical equipment room/auxiliary relay room 1.94E-07 

Cable spreading room 1.28E-07 

East and west communications rooms 1.19E-07 

Primary auxiliary building general area, elevation 718', 735' 4.89E-08 

Battery room 2-2 2.68E-08 

Reactor containment area 1.91E-08 

Service building cable tray area 1.62E-08 

Pipe tunnel 7.52E-09 

Main steam valve room 1.51E-09 

Turbine room/hall/building 6.05E-10 

Braidwood 1 Unit 1 LCSR nonsegregated bus duct area 1.52E-06 

Unit 1 auxiliary electrical equipment room 7.OOE-07 

auxiliary building general area elevation 426' 6.1OE-07 

Div 11 miscellaneous electrical equipment room 5.40E-07 

auxiliary building general area elevation 401' 2.70E-07 

Cable vault or cable tunnel 1.01E-07 

Main control room/control room 6.32E-08 

Switchgear room 5.90E-08 

Turbine room/hall/building 5.86E-08 

Switchgear room 1.60E-08 

Auxiliary building general area elevation 383' 1.90E-09 

Auxiliary building general area elevation 364' 1.30E-09 

Div 12 miscellaneous electrical equipment room 2.80E-10 

Auxiliary building general area elevation 346' 1.50E-10 

Braidwood 2 Unit 2 LCSR nonsegregated bus duct area 1.60E-06 

Div 21 miscellaneous electrical equipment room 7.OOE-07 

Unit 2 auxiliary electrical equipment room 7.OOE-07 

Auxiliary building general area elevation 401' 4.OOE-07 

Auxiliary building general area elevation 426' 2.OOE-07 

Main control room/control room 6.32E-08 

Cable vault or cable tunnel 5.91E-08 

Switchgear room 5.90E-08 

Turbine room/hall/building 5.86E-08 

Switchgear room 1.60E-08

3-9
Table 3.3: Significant fire area CDFs (Continued)

P•-ant Si-nificant tfreareas .. F 

Auxiliary building general area elevation 383' 4.20E-10 

Div 22 miscellaneous electrical equipment room 2.90E-10 

Auxiliary building general area elevation 346' 1.50E-10 

Auxiliary building general area elevation 364' 5.10E-1 1 

Browns Ferry 1 Not analyzed 

Browns Ferry 2 Main control room/control room 3.05E-06 

Unit 2 reactor building 1.50E-06 

Yard 7.95E-07 

Turbine room/hall/building 7.30E-07 

Unit 2 battery, battery board rooms 5.53E-07 

4kV shutdown board, room B 4.97E-07 

Control bay 593' 4.73E-07 

Intake pump station 4.72E-07 

4kV shutdown board, room C and 250 V battery room 4.51E-07 

Cable spreading room 4.48E-07 

4kV shutdown board, room D 4.15E-07 

4kV shutdown board, room A and 250 V battery room 2.54E-07 

Unit 3 reactor building 1.06E-07 

Unit I reactor building 5.19E-08 

Pipe tunnel LO.E-10 

Browns Ferry 3 Main control room/control room 3.05E-06 

Yard 7.95E-07 

Turbine room/hall/building 7.30E-07 

Control bay, 593' 4.72E-07 

Intake pump station 4.50E-07 

Cable spreading room 4.48E-07 

Shutdown board room F 4.43E-07 

Unit 3 reactor building 3.64E-07 

Unit I reactor building 2.22E-07 

Shutdown board room E 1.99E-07 

4Kv shutdown board rooms 3EA, 3EB 1.24E-07 

Unit 2 reactor building 1.OOE-07 

Pipe tunnel L.OOE-10 

Brunswick 1 Not analyzed, see Unit 2 

Brunswick 2 Main control room/control room 1.93E-05 

North central area (20') 4.72E-06 

Cable spreading room 1.56E-06 

Unit 1 cable spreading room (23') 1.56E-06 

NW area (20') 1.28E-06 

Switchgear room 1.1OE-06 

Switchgear room 1.07E-06 

Byron 1 Auxiliary building general area 426' 8.43E-07 

Auxiliary building general area 346' 7.40E-07 

Auxiliary building general area 401' 6.36E-07 

Laundry room, auxiliary building 4.60E-07 

Switchgear room 3.70E-07 

Auxiliary building general area 383' 2.57E-07

3- 10

I
Table 3.3: Significant fire area CDFs (Continued)

Plant Significant fire areas CJW 

Switchgear room 2.1OE-07 

Div. I I miscellaneous electrical equipment room (MEER) 1.80E-07 

Unit I LCSR nonseq. bus duct area, cable spreading room 1.30E-07 

Cable vault or cable tunnel 1.13E-07 

Auxiliary building general area 364' 9.50E-08 

Main control room/control room 8.17E-08 

Div. 12 MEER 5.1OE-08 

U- I AEER, auxiliary building 1.1OE-08 

U- I & U-2 turbine building, elevation 451' 6.1OE-09 

Turbine room/hall/building 3.90E- I 1 

Byron 2 U-2 upper cable spreading room (UCSR) Rm 3.3B-2 1.30E-06 

Auxiliary building general area 426' 9.91E-07 

Auxiliary building general area 346' 7.40E-07 

Auxiliary building general area 401' 6.45E-07 

Switchgear room 5.40E-07 

Auxiliary building general area 383' 2.61E-07 

Switchgear room 1.70E-07 

Div. 21 MEER, auxiliary building 1.60E-07 

Cable vault or cable tunnel 1.15E-07 

U-2 LCSR nonseg. bus duct area, cable spreading room 1.08E-07 

Auxiliary building general area 364' 9. 1OE-08 

Main control room/control room 8.17E-08 

Div. 22 MEER 5.1OE-08 

U- 1 & U-2 turbine building, elevation 451' 6.1OE-09 

U-2 AEER 4.90E-09 

Turbine room/hall/building 3.90E-11 

Callaway Main control room/control room 2.65E-06 

Switchgear room 2.26E-06 

Safety-related ac switchgear room (C- 10) 1.29E-06 

Cable spreading room 6.78E-07 

Auxiliary building area, elevation 2000' 5.32E-07 

Control room ac units room 4.08E-07 

Turbine room/hall/building 3.13E-07 

Switchgear room 2.27E-07 

Auxiliary building area, elevation 1988' 1.51E-07 

Auxiliary building area, elevation 1974' 8.61E-08 

Auxiliary building area, elevation 2026' 7.59E-08 

Cable chase (C-30) 6.37E-08 

Cable chase (C-33) 6.02E-08 

Communications corridor lower level 5.58E-08 

Cable chase (C-23) 2.42E-08 

Service water valve area L.OOE-10 

Calvert Cliffs 1 Main control room/control room 2.45E-05 

Turbine room/hall/building 1.66E-05 

Unit 1 cable spreading room 6.72E-06 

_Switchgear room 4.28E-06

3-11
Table 3.3: Significant fire area CDFs (Continued)

I -- -

Significant tire areas

Transformers, tanks, and Independent structures

I CDF

3.53E-06

Battery room 21 3.52E-06 

Battery room 11 2.98E-06 

5' Multi-compartment area (fire area 11) 2.83E-06 

Switchgear room 1.54E-06 

Cable chases 1A, 1B, 2A, 2B 9.67E-07 

Unit I east piping penetration rooms 6.82E-07 

Unit 2 cable spreading room 6.8 1E-07 

Unit 1 AFW pump room 4.76E-07 

Unit I ECCS pump rooms and recirculation tunnel 4.49E-07 

2A diesel generator room 4.OOE-07 

Unit 2 27' switchgear room 2.22E-07 

Cask and equipment loading area-truck bay 1.86E-07 

1 B diesel generator room 1.39E-07 

Cross-zone fire initiators 1.26E-07 

69' multi-compartment area (fire area 11) 1.22E-07 

Unit 2 45' switchgear room 1.19E-07 

Unit 2 service water, component cooling, and radiation exhaust rooms 1.1 3E-07 

Unit 2 purge air room 1.12E-07 

2B diesel generator room 1.02E-07 

Unit 1 69' electrical room 9.18E-08 

minus 10'/ minus 15' hallways 8.58E-08 

Unit 1 east electric penetration room 7.1OE-08 

Unit 1 west electric penetration room 6.78E-08 

Battery room 12 5.78E-08 

Battery room 22 5.18E-08 

27' multi-compartment area (fire area 11) 4.62E-08 

Unit 1 RWT pump room 4.39E-08 

Unit 2 ECCS pump rooms 4.22E-08 

Unit I charging pump rooms 3.48E-08 

Unit 1 service water pump room 3.47E-08 

Unit 2 west electric penetration room 3.43E-08 

Unit 1 main vent fan room 2.37E-08 

Hallways outside the control room 1.87E-08 

Reactor coolant waste evaporator room 1.56E-08 

Intake structure 1.22E-08 

Reactor coolant waste tank rooms 1.05E-08 

Unit 2 AFW pump room 8.88E-09 

Unit 1 radiation exhaust equipment room 3.99E-09 

Unit 2 main steam piping area 3.65E-09 

Unit 2 east electrical penetration room 3.27E-09 

Unit 1 west piping penetration rooms 2.62E-09 

auxiliary building stair tower AB-2 2.29E-09 

Control room HVAC room 1.91E-09

Calvert Cliffs 2

Unit I purge air room -- - - - - - I

No information provided.

3- 12

P'lanlt

1.15E-09

I

I
Table 3.3: Significant fire area CDFs (Continued)

Plant Signiflcant fre areas ..... __ 

Catawba 1 "Short room" near KC pumps 3.74E-06 

Control room and cable room 9.40E-07 

Cable vault or cable tunnel 6.96E-07 

Main control room/control room 1.52E-07 

Switchgear room 2.28E-08 

Turbine room/hall/building 1.52E-08 

Diesel generator room A 1.00E-08 

Nuclear service water pump room 1.OOE-08 

Switchgear room 1.OOE-08 

Turbine driven auxiliary feedwater pump room < 1.0E-08 

Vital I & C room < 1.OE-08 

Catawba 2 Not analyzed, see Unit 1 

Clinton Main control room/control room 1.20E-06 

781' auxiliary building, Div 1 safety switchgear room 7.11E-07 

781' & 790' control, DC/UPS equipment area 4.84E-07 

678' & 699' screenhouse, general access and pipe tunnel areas 3.38E-07 

762' auxiliary building, Div 1 non-safety switchgear room 2.95E-07 

781' auxiliary building, Div 2 safety switchgear room 2.OOE-07 

781' control, Div 3 switchgear area 1.36E-07 

762 auxiliary building, Div 2 non-safety switchgear room 1.27E-07 

762' control, component cooling water equipment area 6.85E-08 

800' control, operations kitchen/restroom/storage areas 3.72E-08 

719' control, entire level excluding stairwells 2.04E-08 

737' fuel building, general access area 1.11E-08 

781' radwaste, general access area 4.75E-09 

781' control, Div 2 cable spreading area 3.97E-09 

781' control, Div 1 cable spreading room 1.39E-09 

737' & 751' control, general access and lab HVAC areas 1.14E-09 

755'& 781' fuel building, entire area of both elevations 1.13E-09 

737' control, chemistry laboratory areas 5.36E- 10 

712' fuel building, general access area 4.28E-10 

707'6" auxiliary building, hallway 3.25E-10 

737' auxiliary building, general access area 1.79E-10 

Columbia Electrical equipment room/auxiliary relay room 1.05E-05 

Generating* Main control room/control room 8.40E-06 

Div. 2 electrical equipment room 7.67E-06 

Remote shutdown room 6.67E-06 

Div. 2 battery room 5.06E-06 

Switchgear room 4.64E-06 

Turbine general corridor 3.67E-06 

Reactor building 501' 2.4 1E-06 

Reactor building 471' 2.40E-06 

Reactor building 522' 1.18E-06 

Div. 1/2 electrical/battery room corridor 1.14E-06 

Div. 1 battery room 7.98E-07 

NW reactor building 471' 4.87E-07 

Equipment hatch 3.77E-07

3- 13
Table 3.3: Significant fire area CDFs (Continued)

Plant Significant fire areas CD . Switchgear room (switchgear room #1) 3.36E-07 

NW reactor building 501' 2.90E-07 

Turbine generator building west 441' 1.06E-07 

NE reactor building 471' 7.35E-08 

Comanche Peak 1 Main control room/control room 9.04E-06 

Train A electrical equipment area, safeguards building, elevation 810' 1.74E-06 

Train B electrical equipment area, safeguards building. elevation 852' 1.45E-06 

UPS & distribution room - train B, E, & C building, elevation 792' 1.34E-06 

810' safeguards building corridor 1.26E-06 

UPS & distribution room - train A, E, & C building, elevation 792' 1.25E-06 

AA021 7.99E-07 

Multi-compartment analysis 7.25E-07 

SB004 7.1OE-07 

Cable spreading room 4.69E-07 

SGOIO 3.72E-07 

SI012 3.72E-07 

EA057 3.16E-07 

EQ149 2.50E-07 

ER150 2.49E-07 

AA153 2.33E-07 

SK017 1.87E-07 

SBO15 7.32E-08 

SE016 5.36E-08 

EA043 1.04E-09 

Comanche Peak 2 Not analyzed, see Unit 1 

Cook I 44S - auxiliary building S - both units 3.80E-07 

16 - lAB diesel generator room - U1 3.50E-07 

15 - I CD diesel generator room - Ul 3.04E-07 

40B - 4 kV CD switchgear room 1.86E-07 

53 - U1 Control room 1.81E-07 

42D - EPS AB battery room 1.68E-07 

40A - 4 kV AB switchgear room 1.32E-07 

41 - engineering safety system & MCC room (& under floor) - U 1 1.12E-07 

29B - ESW pump PP-lW - Ul 1.07E-07 

29E - MCC for ESW pumps - U1 1.07E-07 

_91 - turbine room SE portion - U1 1.02E-07 

Cook 2 Not analyzed, see Unit 1 3.80E-07 

Cooper Switchgear room 2.72E-06 

Main control room/control room 1.71E-06 

Service water pump room 1.33E-06 

Switchgear room 1.11E-06 

Cable spreading room 8.23E-07 

Reactor building, elevation 903'6" 8.16E-07 

Div II dc switchgear room 7.90E-07 

Train B RPS room 7.30E-07 

Div. II battery room 6.73E-07 

RHRSW booster and service air compressor 5.58E-07

3- 14

I
Table 3.3: Significant fire area CDFs (Continued)

Plant Significant fire areas D 

Auxiliary relay room 3.66E-07 

Electrical equipment room/auxiliary relay room 3.66E-07 

Cable expansion room 3.45E-07 

Div. I dc switchgear room 3.36E-07 

Non-critical switchgear room 3.32E-07 

Reactor building, elevation 932'6" 2.73E-07 

Div. I battery room 1.77E-07 

Turbine room/hall/building 1.41E-07 

Train A RPS room 6.52E-08 

Seal water pump area 4.86E-08 

Crystal River 3 Battery charger room 3A 1.49E-05 

Switchgear room 7.3 1E-06 

Switchgear room 6.79E-06 

480V ES switchgear room BUS 3A 3.79E-06 

Battery charger room 3B 2.72E-06 

Hallway and remote shutdown room 2.66E-06 

CRD and communication equipment room 1.58E-06 

Inverter room 3B 1.45E-06 

Main control room/control room 5.70E-07 

Central hallway 3.86E-07 

480V ES switchgear room BUS 3B 1.76E-07 

Cable spreading room 9.90E-08 

North hallway and nuclear sample room 7.98E-09 

Turbine building mezzanine floor 4. 96E-1 1 

Turbine building basement floor 4. 84E-11 

RWSW pump room 4.21E-11 

Turbine EFW, pump penetration area, fan room 1.07E-11 

North hallway 1.05E-11 

Davis-Besse High voltage switchgear room B 8.20E-06 

High voltage switchgear room A 6.46E-06 

Main control room/control room 6.40E-06 

Low voltage switchgear room 6.OOE-06 

Liquid radwaste equipment area 2.60E-06 

Turbine room/hall/building 2.30E-07 

Diablo Canyon 1 Cable spreading room 9.99E-06 

Main control room/control room 8.97E-06 

Fire initiators FS1, FS5, & FS6 which consist of various scenarios initiating in 8.30E-06 

various fire zones. 

Diablo Canyon 2 Not analyzed, see Unit 1 

Dresden 2 Main control room/control room 7.15E-06 

Unit 2 north trackway/switchgear area 5.38E-06 

Unit 2 second floor reactor building 1.65E-06 

Unit 2 mezzanine 6.74E-07 

Control room backup ventilation 5.86E-07 

Electrical equipment room/auxiliary relay room 5.36E-07 

_Unit 2/3 turbine building corridor 2.52E-07

3- 15
Table 3.3: Significant fire area CDFs (Continued)

Cribhouse upper 2.45E-07 

Unit 3 west corridor and trackway 1._17E-07 

Unit 2 torus basement 1.10E-07 

Unit 2 battery room 5.89E-08 

Unit 2 reactor building ground floor 4.69E-08 

Unit 3 mezzanine floor 3.95E-08 

Unit 2 reactor building switchgear area 1.37E-08 

Unit 2/3 standby gas treatment system and TBCCW heat exchanger 5.29E-09 

Unit 3 battery charger room 4.48E-09 

Dresden 3 Main control room/control room 7.11E-06 

Unit 3 west corridor and trackway 6.85E-06 

Unit 3 mezzanine floor 4.23E-06 

Unit 3 second floor reactor building 3.54E-06 

Electrical equipment room/auxiliary relay room 2.53E-06 

Cable vault or cable tunnel 2.12E-06 

Turbine building corridor 8.36E-07 

Unit 3 reactor building ground floor 7.16E-07 

Unit 2/3 standby gas treatment system and TBCCW heat exchanger 5.32E-07 

Unit 2 north trackway/switchgear area 4.94E-07 

Unit 3 cond. PP area 4.85E-07 

Control room backup ventilation 4.59E-07 

Vent room over NE switchgear 2.39E-07 

Cribhouse upper 2.38E-07 

Unit 3 DG 2.19E-07 

Unit 3 traveling in-core probe room 1.1OE-07 

Unit 3 reactor building switchgear area 2.06E-08 

Unit 2 battery room 1.59E-08 

Unit 3 torus basement 7.57E-09 

Unit 3 battery charger room 1.07E-09 

Cable spreading room 

Switchgear room 

Switchgear room 

Turbine room/hall/building 

Duane Arnold Switchgear room 5.61E-06 

Switchgear room 4.92E-06 

Main control room/control room 5.02E-07 

_Cable spreading room 2.33E-07 

Hatch 1 Cable spreading room 1.93E-06 

Switchgear room 1.45E-06 

Switchgear room 1.38E-06 

Main control room/control room 7.1OE-07 

4kV switchgear room IF 7.04E-07 

Common area housing units 1 & 2 main control rooms 3.1OE-07 

East cableway 2.05E-07 

Reactor building north working floor on elevation 130 ft. (Control rod drive area) 2.03E-07 

Station battery room IA - Division I 1.49E-07 

Vertical cable chase 1.04E-07

3- 16

I
Table 3.3: Significant fire area CDFs (Continued)

Plant- Sig•ificant fire areas CDF 

Annunciator room 9.94E-08 

West 600V switchgear room IC - Division I 5.76E-08 

Control building north and south corridor on elevation 130 ft. 5.73E-08 

West dc switchgear room 1 A - Division I 4.26E-08 

Computer room 4.23E-08 

Cable spreading room (fires initiated in cables of adjacent unit) 1.80E-08 

Control building, vertical cableway (fires initiated in cables of adjacent unit) 1.50E-08 

Turbine building, west cableway (fires initiated in cables of adjacent unit) 8.80E-10 

Hatch 2 Switchgear room 1.1OE-06 

Switchgear room 8.88E-07 

Cable spreading room 8.55E-07 

Main control room/control room 7.1 OE-07 

4kV switchgear room 2F 4.66E-07 

Common area housing units 1 & 2 main control rooms 3.1 OE-07 

West 600V switchgear room 2C - Division I 2.89E-07 

East cableway 1.89E-07 

Station battery room 2A - Division I 1.40E-07 

Reactor building south working floor on elevation 130 ft. (Control rod drive area) 9.5 1E-08 

Reactor building north working floor on elevation 130 ft. (Control rod drive area) 7.03E-08 

Computer room 5.70E-08 

Turbine room/hall/building 4.80E-08 

Reactor building north torus chamber 4.62E-08 

Control building working floor and corridor on elevation 112 ft. 4.49E-08 

Vertical cable chase 4.39E-08 

West dc switchgear room 2A - Division I 4.16E-08 

Reactor building south torus chamber 3.98E-08 

Control building, vertical cableway (fires initiated in cables of adjacent unit) 3.20E-08 

Cable spreading room (fires initiated in cables of adjacent unit) 1.60E-08 

Turbine building, west cableway (fires initiated in cables of adjacent unit) 6.40E-09 

Fermi Main control room/control room 7.36E-06 

Switchgear room 4.51E-06 

Electrical equipment room/auxiliary relay room 2.77E-06 

Turbine room/hall/building 2.72E-06 

Switchgear room 2.54E-06 

Third floor auxiliary room - major Div. I portion 1.90E-06 

NE quadrant reactor building rooms 1.45E-06 

Second floor reactor building 1.00E-06 

Cable vault or cable tunnel 4.08E-07 

Cable spreading room 1.05E-07 

Fort Calhoun Main control room/control room 7.90E-06 

AFW and air compressor area 6.01E-06 

Turbine room/hall/building 3.97E-06 

Upper electrical penetration area 3.62E-06 

Auxiliary building lower corridor and adjoining rooms 2.05E-06 

Switchgear room 7.84E-07 

Transformer yard area 6.18E-07 

Intake structure 5.96E-07

3- 17
Table 3.3: Significant fire area CDFs (Continued)

Plant Significant fire areas CDF 

Group I MCC area 5.66E-07 

Lower electrical penetration area 5.30E-07 

Ground level general area - auxiliary building 3.14E-07 

Charging pump area - auxiliary building 2.45E-07 

Switchgear room 2.27E-07 

Cable spreading room 7.42E-08 

Grand Gulf Main control room/control room 3.85E-06 

Switchgear room 9.30E-07 

Auxiliary building corridors, 139'-0" elevation 6.70E-07 

Auxiliary building corridors, 119' -0" elevation 6.19E-07 

Switchgear room 6.08E-07 

Auxiliary building corridors, 93' -0" elevation 5.74E-07 

Division 2 switchgear room - control building, 111' -0" elevation 4.06E-07 

Turbine room/hall/building 3.24E-07 

Lower cable room - control building, 148' -0" elevation 2.82E-07 

Hot machine shop - control building, 93' -0" elevation 2.42E-07 

HVAC equipment room - control building, 133' -0" elevation 2. 1OE-07 

Division 3 (HPCS) diesel generator building 1.72E-07 

Turbine building, 113' -0" elevation 7.1OE-09 

Haddam Neck Switchgear room 2.59E-05 

Main control room/control room 1.40E-05 

Primary auxiliary building 1.17E-05 

Diesel generator room B 6.50E-06 

Cable spreading room 9.44E-07 

Intake structure 7.13E-07 

Diesel generator room A 4.50E-07 

Turbine room/hall/building 1.088E-07 

Switchgear room 1.03E-07 

Hope Creek Main control room/control room 2.5 1E-05 

Switchgear room 1.30E-05 

Diesel generator room (channel A) 5.30E-06 

Reactor building, CRD pump area 4.15E-06 

Diesel generator room (channel C) 4.1OE-06 

Diesel generator room (channel B) 3.70E-06 

Auxiliary building 137' elevation, electrical access area 3.07E-06 

Switchgear room 3.OOE-06 

Auxiliary building, upper control equipment room/computer room 2.68E-06 

Auxiliary building 102' elevation, electrical access room 2.67E-06 

Diesel generator room (channel D) 2.60E-06 

Auxiliary building124' elevation, electrical access area 2.07E-06 

Reactor building, 102' elevation-north side and Division I SACS area 1.77E-06 

Auxiliary building, lower (control) electric equipment room 1.73E-06 

Turbine building., access and unloading area 1.23E-06 

Reactor building, motor-control center (MCC) area 1.12E-06 

Turbine building., electrical equipment mezzanine 7.79E-07 

Radwaste building, middle section of the 3rd floor 7.20E-07 

Reactor building, RACS pump & heat exchanger area 6.34E-07

3 - 18

I
Table 3.3: Significant fire area CDFs (Continued)

Plant Significant fire areas.. .. 

Auxiliary building, DG area HVAC equipment room 5.30E-07 

Switchyard blockhouse 3.OOE-07 

Control room/equipment room/mezzanine 2.90E-07 

Auxiliary building, Class I E inverter room 2.16E-07 

Reactor building, RHR pump DP202 room 1.58E-07 

Auxiliary building, electrical access area (Div. I) 8.94E-08 

Cable spreading room 5.86E-08 

Auxiliary building, DG combustible air intake room 5.64E-08 

Reactor building, 102' elevation-inside cylinder - south side (Div. II) 4.06E-08 

Reactor building, torus water cleanup room/motor-control center (MCC) 3.01E-08 

Electrical equipment room/auxiliary relay room 1.811E-08 

Reactor building, RHR heat exchanger room (BP202 & heat exchanger BE205) 1.52E-08 

Reactor building, core spray DP206 room 1.211E-08 

Reactor building, RHR pump A202 & HX AE205 room (and vestibule) 1.07E-08 

Auxiliary building, electrical access area/corridor 9.177E-09 

Auxiliary building, HVAC equipment room 9.00E-09 

Reactor building, 102' elevation-inside cylinder - north side (Division I) 8.1 OE-09 

Aux building, auxiliary Electrical access area & common area in RW building 5.001E-09 

Auxiliary building, DG combustible air intake room 1.57E-09 

Indian Point 2 Main control room/control room 7.07E-06 

Cable spreading room 4.28E-06 

Switchgear room 3.84E-06 

Electrical penetration area 1.11E-06 

Primary water makeup area 1.05E-06 

Electrical tunnel/pipe penetration area 9.19E-07 

Cable vault or cable tunnel 9.62E-08 

SW intake 7.46E-09 

Auxiliary feedwater pump room 6.15E-09 

CCW pump room 2.19E-09 

Drumming and storage station 1.53E-09 

Indian Point 3 Switchgear room 3.51E-05 

Cable spreading room 6.83E-06 

Switchgear room 4.49E-06 

Main control room/control room 3.65E-06 

Diesel generator 31 room 2.13E-06 

Diesel generator 33 room 1.93E-06 

Upper electrical tunnel 7.14E-07 

Diesel generator 32 room 3.38E-07 

Lower electrical tunnel 2.78E-07 

Auxiliary feedwater pump room 2.28E-07 

'rurbine room/hall/building 3.78E-08 

PAB corridor 3.17E-08

3-19
Table 3.3: Significant fire area CDFs (Continued)

I -- -

Signxuucant ure areas

.ep Ua.U I rUoIoI

Relay room 5.40E-06 

Main control room or control room 3.OOE-06 

Reactor building westside (elevation. 272) and southwest quadrant (elevation. 1.35E-06 

300) 

Trains "A & C" EDG switchgear room south (elevation. 272) 1.32E-06 

Reactor building east crescent (elevation. 227 & 242) 1.02E-06 

West cable tunnel 7.21E-07 

Turbine building/relay room 6.26E-07 

Trains "B & D" EDG switchgear room north (elevation. 272) 6.05E-07 

South cable tunnel/relay room 5.52E-07 

"A" train battery room 2 4.62E-07 

North cable tunnel/relay room 4.62E-07 

Relay room/administration building, office area, records area, computer rooms & 3.80E-07 

technical support center (elevation. 286) 

Turbine room or hall or building 3.73E-07 

"B" train battery room 3 3.30E-07 

Turbine building/east cable tunnel 2.89E-07 

Administration building, Machine shop, locker rooms, stores & lunch 2.54E-07 

room/reactor building eastside (elevation. 272'), southeast quadrant (elevation. 

300'), entire floor at elevation 326, 344, & 369 

"A" train battery charger room 1 2.40E-07 

"B" train battery charger room 4/"A" Train Battery Charger Room 1 2.24E-07 

East cable tunnel 2.24E-07 

Reactor building northeast & northwest quadrants (elevation. 300') 2.19E-07 

Motor generator set room & fan room/reactor building, northeast & northwest 2.06E-07 

quadrants (elevation. 300') 

Reactor building westside (elevation. 272) and southwest quadrant (elevation. 1.52E-07 

300') 

Administration building, machine shop, locker rooms, stores & lunch room/cable 1.37E-07 

spreading room 

Reactor building, east crescent (elevation. 227 & 242)/reactor building. Eastside 1.11E-07 

(elevation. 272), southeast quadrant (elevation. 300'), entire floor at elevations 

326, 344, & 369 

"B" train battery charger room 4 1.04E-07 

Reactor building west crescent (elevation 227 & 242) 9.52E-08 

Battery rooms corridor (elevation 272) 8.50E-08 

Standby gas filter room/reactor building, eastside (elevation. 272), southeast 3.72E-08 

quadrant (elevation. 300'), entire floor at elevations 326, 344, & 369 

Reactor building eastside (elevation. 272'), southeast quadrant (elevation. 300'), 2.25E-08 

entire floor at elevations 326, 344 & 369 

Relay room/reactor building, eastside (elevation 272), southeast quadrant 1.33E-08 

(elevation 300'), entire floor at elevations 326, 344, & 369 

Relay room/turbine building 1.33E-08 

Turbine building, west electric bay (elevation. 272') 6.61E-10

Turbine building, east electric bay (elevation. 272') 2.37E-10

J.

3 - 20

'ant

loiZi CDP £ J.I,,•IL f*J*Ld[ l•*,aJ• 6.57E-06

I
Table 3.3: Significant fire area CDFs (Continued)

Plant Significant fire areas CDF 

Farley 1 Auxiliary building 4160V switchgear room, train A 5.43E-05 

Train A electrical penetration room 2.90E-05 

Main control room/control room 2.68E-05 

Service water pump room 1.40E-05 

Component cooling water heat exchanger/pump room 1.27E-05 

Auxiliary building 4160V switchgear room, train B 8.38E-06 

Diesel building train A switchgear room 7.83E-06 

Low-voltage switchyard 4.12E-06 

Train B electrical penetration room 2.53E-06 

Cable spreading room 2.02E-06 

Turbine room/hall/building 1.47E-06 

Auxiliary building train B dc switchgear room 9.49E-07 

Auxiliary building train A dc switchgear room 5.50E-07 

Lower equipment room 3.66E-07 

Auxiliary building, 121' hallway 3.42E-07 

Auxiliary building, elevation 155' 2.5 1E-07 

Diesel building train B switchgear room 3.39E-08 

Farley 2 Auxiliary building 4160V switchgear room, train A 5.26E-05 

Main control room/control room 2.68E-05 

Service water Pump Room 1.40E-05 

Auxiliary building 4160V switchgear room, train B 8.28E-06 

Diesel building train A switchgear room 7.83E-06 

Component cooling water heat exchanger/pump room 7.70E-06 

Cable spreading room 4.43E-06 

Low-voltage switchyard 4.12E-06 

Auxiliary building, elevation 155' 6.3 1E-07 

Turbine room/hall/building 6.01E-07 

Lower equipment room 4.65E-07 

Diesel building train B switchgear room 3.39E-08 

Boric acid area (auxiliary building, elevation 100') 3.26E-08 

Chemical drain tankroom 1.43E-08 

Kewaunee Diesel generator room B 6.15E-05 

Auxiliary feedwater pump A room 5.27E-05 

Main control room/control room 3.20E-05 

Auxiliary feedwater pump B room and 480V switchgear buses 61 and 62 room 2.97E-05 

Switchgear room 3.33E-06 

Electrical equipment room/auxiliary relay room 3.21E-07 

Auxiliary building, refueling water storage tank area, corridor 2.8 1E-09 

Switchgear room 1.41 E-09 

La Salle 1 Not analyzed, see Unit 2 

La Salle 2 Main control room/control room 1.39E-05 

Switchgear room 8.51 E-06 

Switchgear room 5.15E-06 

Auxiliary equipment room 2.63E-06 

Turbine building corridor 6.20E-07 

Electrical equipment room/auxiliary relay room 5.73E-07

3 -21
Table 3.3: Significant fire area CDFs (Continued)

Plant Significant fire areas CDF 

Cable shaft area 5r.42E-07 

Cable spreading room 1.63.E-07 

Auxiliary building rad chem offices 3.58E-08 

Lim 1 BOP cable area north 7.3 1pE-09 

Limerick 1 No information provided. 

Limerick 2 No information provided. 

McGuire I Vital I & C room 6.47E-07 

Control room or cable room 8.13E-08 

Turbine room/hall/building 2.72E-08 

Main feed pump 2.02E-08 

Main control room/contol room 1.00E-08 

Switchgear room 1.00E-08 

Switchgear room 1 .OE-08 

McGuire 2 Not analyzed, see Unit 1 

Nine Mile Point 1 Turbine building elevation 261', south 1.30E-05 

Cable spreading room 2.OOE-06 

Main control room/control room 1.40E-06 

Auxiliary control room 1.1OE-06 

Turbine building, elevation 250', south & west 1.OOE-06 

Nine Mile Point 2 Main control room/control room 1.40E-06 

North Anna 1 Switchgear room 3.28E-06 

Cable vault or cable tunnel 4.5 1E-07 

Main control room/control room 1.69E-07 

Auxiliary building 1.24E-08 

North Anna 2 Switchgear room 3.28E-06 

Cable vault or cable tunnel 4.51 E-07 

Auxiliary building 1.811E-07 

Main control room/control room 1.69E-07 

Oconee 1 Not analyzed, see Unit 3 

Oconee 2 Not analyzed, see Unit 3 

Oconee 3 Turbine room/hall/building 5.80E-06 

Cable shaft 1.56E-07 

Oyster Creek Cable spreading room 8.60E-06 

Switchgear room 5.10E-06 

Turbine building basement (south end) 1.90E-06 

Main control room/control room 3.30E-07 

Switchgear room 3.1OE-07 

Palisades Cable spreading room 1.11E-05 

Main control room/control room 8.1OE-06 

Switchgear room 4.89E-06 

Switchgear room 2.51E-06 

Turbine building (east side) 2.15E-06 

West engineered safeguards 1.11 E-06 

Turbine building (south side) 8.64E-07 

Auxiliary building 590' corridor (south finger) 6.73E-07 

Intake structure - service water system 4.59E-07

3 - 22
Table 3.3: Significant fire area CDFs (Continued)

Plant Significant fire areas C.. 

Battery room No.2 2.77E-07 

Auxiliary feedwater pump room 1.92E-07 

Battery room No. 1 1.62E-07 

590' auxiliary building (all not included other zones) 1.60E-07 

Diesel generator 1-2 room 1.32E-07 

Diesel generator 1-1 room 9.54E-08 

Turbine building (west side) 7.28E-08 

Electrical equipment room/auxiliary relay room 5.83E-08 

Engineering safeguards panel room 3.35E-08 

Auxiliary building 590' corridor (middle finger) 2.26E-08 

Spent fuel pool equipment room 2.19E-08 

East engineered safeguards 2.04E-08 

Manholes Nos. 1, 2, 3 1.1E-08 

Component cooling pump room 9.20E-09 

Charging pump room 5.36E-09 

Palo Verde 1 Switchgear room 2.07E-05 

Turbine room/hall/building 1.47E-05 

Main control room/control room 1.07E-05 

Switchgear room 9.73E-06 

Corridor building., 120 ft. elevation 9.36E-06 

Train B containment electrical penetration room 7.14E-06 

Channel A dc equipment room 6.74E-06 

Channel B dc equipment room 3.97E-06 

Train A containment electrical penetration room 3.62E-06 

Electrical equipment room/auxiliary relay room 9.15E-07 

Palo Verde 2 Not analyzed, see Unit 1 

Palo Verde 3 Not analyzed, see Unit 1 

Peach Bottom 2 Turbine building U3 wing area (see comment) 3.70E-06 

Reactor building U2 north (see comment) 3.20E-06 

Reactor building U3 north (see comment) 2.70E-06 

4kV switchgear room (34) (see comment) 2.50E-06 

4kV switchgear room (32) (see comment) 2.20E-06 

Turbine building 13.2kV switchgear area (see comment) 1.40E-06 

Peach Bottom 3 Not analyzed, see Unit 2 

Perry Main control room/control room 1.06E-05 

Switchgear room 1.05E-05 

Switchgear room 3.38E-06 

Unit 1 turbine power complex switchgear room 3.28E-06 

Control complex, elevation 574' 0" 2.03E-06 

Fuel handling building, elevation 620' 1.63E-06 

Turbine room/hall/building 1.30E-06 

Pilgrim Switchgear room 6.1OE-06 

Switchgear room 3.1OE-06 

Vital motor generator set room 2.40E-06 

Turbine building heater bay 2.1OE-06 

Train "B" RBCCW/TBCCW pump and heat exchanger room 2.OOE-06

3 - 23
Table 3.3: Significant fire area CDFs (Continued)

Plant Significant fire areas CDF 

Main Control room/control room 1.60E-06 

Main transformer 1.50E-06 

Train "A" RBCCW/TBCCW pump and heat exchanger room 9.80E-07 

Reactor building west, elevation 21 9.70E-07 

Cable spreading room 9.50E-07 

Point Beach 1 Gas-fired turbine generator area 2.04E-05 

Diesel generator room G02 5.84E-06 

Diesel generator room GO 1 5.52E-06 

Monitor tank room auxiliary operator's station 4.95E-06 

Main control room/control room 4.58E-06 

Switchgear room 3.70E-06 

Cable spreading room 2.68E-06 

Switchgear room 2.51E-06 

MCC 2B-32 room outside charging pump rooms 1.07E-06 

Electrical equipment room/auxiliary relay room 3E-07 

Point Beach 2 Not analyzed, see Unit I 

Prairie Island 1 Main control room/control room 3.22E-05 

"B" train hot shutdown panel & air compressor/AFW room 8.23E-06 

Switchgear room 2.24E-06 

Switchgear room 1.74E-06 

Auxiliary building mezzanine floor Unit 1 1.45E-06 

Auxiliary building ground floor Unit 2 1.28E-06 

Cable spreading room 1.08E-06 Turbine room/hall/building 1.08E-06 

Prairie Island 2 Not analyzed, see Unit 1 

Quad Cities 1 Turbine room/hall/building 2.03E-05 

Main control room/control room 1.OOE-05 

Auxiliary transformer 11 and reserve auxiliary transformer 12 6.64E-06 

Unit 1 mezzanine floor 4.56E-06 

Cable vault or cable tunnel 3.25E-06 

Switchgear room 3.18E-06 

Unit 2 cable tunnel 3.16E-06 

Unit 2 turbine building ground floor 2.64E-06 

Auxiliary electric room 2.38E-06 

Unit 1/2 mezzanine floor 2.04E-06 

Cable spreading room (only or upper) 1.84E-06 

Unit I dc panel room 1.75E-06 

Unit I reactor building mezzanine level 1.51E-06 

Unit 1/2 turbine building ground floor 1.21E-06 

Unit 1 torus 1.09E-06 

Unit 2 upper basement 2.80E-07 

Unit 2 mezzanine floor 6.54E-09 

Unit 1 traveling in-core probe room 5.47E-09 

Unit 1 condensate pump room 2.06E-09 

Unit 1 MSIV room 1.06E-09 

Old computer room 4.91E-10

3 - 24
Table 3.3: Significant fire area CDFs (Continued)

Plant__ Sigifiant fire areas CDF 

Unit 1 reactor building main floor 4.28E-l 0 

Unit 1 upper basement 2.43E-1 1 

Quad Cities 2 Turbine room/hall/building 2.28E-05 

Cable vault or cable tunnel 1.12E-05 

Main control room/control room 1.OOE-05 

Unit 2 mezzanine floor 3.43E-06 

Unit 1/2 turbine building ground floor 3.25E-06 

Switchgear room 3.20E-06 

Unit 2 dc panel room 2.23E-06 

Cable spreading room 1.05E-06 

Unit 2 torus area 9.17E-07 

Unit 2 reactor building mezzanine floor 8.49E-07 

Auxiliary electric room 4.83E-07 

Old computer room 4.16E-07 

Unit 2 southeast comer room 3.04E-07 

Unit 1 reactor building mezzanine level 1.32E-07 

Unit I turbine building ground floor 1.07E-07 

Unit 2 reactor building ground floor 1.54E-08 

Unit 1/2 mezzanine floor 7.84E-09 

Unit 1 mezzanine floor 1.53E-09 

Unit 2 condensate pump room 6.71E-10 

Ginna Main control room 7.95E-06 

Turbine building mezzanine level 4.61E-06 

Turbine building basement level 3.90E-06 

Battery room IA, control building 2.27E-06 

Control building relay room 2.14E-06 

Transformer yard 1.94E-06 

Auxiliary building, basement level 1.90E-06 

Battery room 1B, control building 1.67E-06 

Diesel generator room lB 1.50E-06 

Containment 1.44E-06 

Auxiliary building, mezzanine level 1.20E-06 

Screen house basement level 1.OOE-06 

Auxiliary building, operating level 9.69E-07 

Intermediate building basement level north 4.OOE-07 

Cable vault/cable tunnel 2.70E-07 

Air handling room 1.34E-07 

Technical support center 3.34E-08 

River Bend Main control room/control room 4.87E-06 

Switchgear room 4.75E-06 

Control room ventilation room (elevation 116') 4.56E-06 

ACU west room 3.31E-06 

HPCS & HPCS hatch area 2.23E-06 

Cable vault or cable tunnel 1.48E-06 

Auxiliary building, west side crescent area 1.26E-06

3 - 25
Table 3.3: Significant fire area CDFs (Continued)

Plant Significant f.re areas CDF . Robinson Electrical equipment room/auxiliary relay room 2.38E-05 

Yard transformers 1.99E-05 

Cable spreading room 1.50E-05 

Auxiliary building hallway (ground floor) 1.11E-05 

Main control room/control room 6.86E-06 

Service water pump area 4.37E-06 

Emergency diesel generator "B" room 3.92E-06 

Turbine room/hall/building 3.85E-06 

Battery room 2.61E-06 

Diesel generator "A" room 8.53E-07 

Salem I Electrical equipment room/auxiliary relay room 7.20E-06 

Main control room/control room 7.OOE-06 

Switchgear room 1.70E-06 

Switchgear room 1.70E-06 

Lower electrical penetration area 1.40E-06 

Upper electrical and piping penetration area 1.30E-06 

Reactor plant auxiliary equipment area, auxiliary building elevation 84' 1.1 OE-06 

Turbine room/hall/building 6.40E-07 

Service water intake 4.20E-07 

Reactor plant auxiliary equipment area, auxiliary building elevation 100' 2.90E-07 

Service water duct, manhole 2.1OE-07 

CO2 equipment room 6.OOE-08 

Reactor plant auxiliary equipment area, auxiliary building elevation 45' 9.40E-09 

Reactor plant auxiliary equipment area, auxiliary building elevation 45' 9.30E-09 

Mechanical penetration area 7.30E-09 

Reactor plant auxiliary equipment area, auxiliary building elevation 64' 5.10E-09 

Hallway of the auxiliary building elevation 100' 1.50E-09 

Salem 2 Electrical equipment room/auxiliary relay room 7.20E-06 

Main control room/control room 7.OOE-06 

Switchgear room 1.70E-06 

Switchgear room 1.70E-06 

Lower electrical penetration area 1.40E-06 

Upper electrical and piping penetration area 1.30E-06 

Reactor plant auxiliary equipment area, auxiliary building elevation 84' 1.1OE-06 

Turbine room/hall/building 6.40E-07 

Service water intake 4.20E-07 

Reactor plant auxiliary equipment area, auxiliary building elevation 100' 2.90E-07 

Service water duct, manhole 2.1 OE-07 

CO, equipment room 6.OOE-08 

Reactor plant auxiliary equipment area, auxiliary building elevation 45' 9.40E-09 

Reactor plant auxiliary equipment area, auxiliary building elevation 45' 9.30E-09 

Mechanical penetration area 7.30E-09 

Reactor plant auxiliary equipment area, auxiliary building elevation 64' 5.1 OE-09 

Hallway of the auxiliary building elevation 100' 1.50E-09 

San Onofre 2 Switchgear room 3.30E-06 

Switchgear room 2.90E-06

3 - 26
Table 3.3: Significant fire area CDFs (Continued)

Plant Significant fire areas CDF 

Turbine room/hall/building 2.20E-06 

Electrical penetration, 2-PE-63-3B 1.70E-06 

Electrical penetration, 3-PE-63-3B 1.60E-06 

Electrical penetration, 2-PE-45-3A 1.00E-06 

Switchgear room, 2-AC-85-71 9.40E-07 

Diesel generator room, 2-DG-30-155 9.30E-07 

Diesel generator room, 2-DG-30-158 9.30E-07 

Electrical equipment room/auxiliary relay room 9.20E-07 

San Onofre 3 Not analyzed, see Unit 2 

Seabrook Main control room/control room 4.30E-06 

Primary auxiliary building 3.20E-06 

Turbine room/hall/building 1.60E-06 

Switchgear room 1.40E-06 

Service water pumphouse 1.10E-06 

Switchgear room 8.20E-07 

Electrical tunnel room B 2.20E-08 

Electrical tunnel room A 5.40E-09 

Sequoyah I Corridor 9.78E-07 

Main control room/control room 9.33E-07 

Turbine room/hall/building 6.78E-07 

Corridor 5.53E-07 

Unit 2 auxiliary instrument room 3.83E-07 

Unit 1 auxiliary instrument room 3.76E-07 

Cable spreading room (only or upper) 3.67E-07 

Electrical equipment room/auxiliary relay room 3.66E-07 

480-V board room lB 3.58E-07 

250-V battery board room 1 & 2 and corridor 2.54E-07 

480-V board room 2B 2.50E-07 

480-V shutdown board room 1B2 1.90E-07 

480-V shutdown board room 2A2 1.77E-07 

Computer room 1.58E-07 

6.9KV shutdown board room B 1.54E-07 

Mechanical equipment room 8.21E-08 

Auxiliary control room 8.01E-08 

250-V battery room No. 1 5.69E-08 

480-V shutdown board room 1A2 4.45E-08 

Personnel and equipment access room 4.38E-08 

6.9KV shutdown board room A 1.95E-08 

480-V shutdown board room IAI 1.07E-08 

Sequoyah 2 Corridor 9.78E-07 

Main control room/control room 9.33E-07 

Turbine room/hall/building 6.78E-07 

Corridor 5.53E-07 

Unit 2 auxiliary instrument room 3.83E-07 

Unit 1 auxiliary instrument room 3.76E-07 

Cable spreading room (only or upper) 3.67E-07

3 - 27
Table 3.3: Significant fire area CDFs (Continued)

Plant Significa.ntfire areas CDF 

Electrical equipment room/auxiliary relay room 3.66E-07 

480-V board room lB 3.58E-07 

250-V battery board room 1 & 2 and corridor 2.54E-07 

480-V board room 2B 2.50E-07 

480-V shutdown board room 1B2 1.90E-07 

480-V shutdown board room 2A2 1.77E-07 

Computer room 1.58E-07 

6.9KV shutdown board room B 1.54E-07 

Mechanical equipment room 8.21E-08 

Auxiliary control room 8.01E-08 

250-V battery room No. 1 5.69E-08 

480-V shutdown board room 1A2 4.45E-08 

Personnel and equipment access room 4.38E-08 

6.9KV shutdown board room A 1.95E-08 

480-V shutdown board room 1A1 1.07E-08 

Shearon Harris Main control room/control room 4.301E-06 

Switchgear room 4.OOE-06 

Switchgear room 3.10E-06 

1-A-4-COMB (No other compartment identification could be found.) 1.30E-06 

South Texas 1 Individual contributors are not identified in submittal 

South Texas 2 Not analyzed, see Unit 1 

Saint Lucie 1 Main control room/control room 7.49E-05 

Cable spreading room (only or upper) 6.96E-05 

Switchgear room 4.30E-05 

Saint Lucie 2 Main control room/control room 5.90E-05 

Cable spreading room 5.64E-05 

FA-121/32/33/51W 2.67E-05 

FA-O 1.34E-05 

Switchgear room 4.48E-06 

Surry 1 Switchgear room 4.18E-06 

Switchgear room 1.93E-06 

Turbine room/hall/building 3.30E-07 

Cable spreading room 2.75E-07 

Electrical equipment room/auxiliary relay room 2.42E-07 

Main control room/control room 8.23E-08 

Cable vault or cable tunnel 8.18E-08 

Surry 2 Switchgear room 4.18E-06 

Switchgear room 1.93E-06 

Turbine room/hall/building 3.30E-07 

Cable spreading room 2.75E-07 

Electrical equipment room/auxiliary relay room 2.42E-07 

Main control room/control room 8.23E-08 

Cable vault or cable tunnel 8.18E-08 

Susquehanna 1 Sum of 15 areas (cable chases in control structure, plus two compartments in 2.6E-08 

reactor building) 

_Main control room/control room 4.1E-09

3 - 28

I
Table 3.3: Significant fire area CDFs (Continued)

Plant Significant fire areas CDF 

Cable spreading room (lower) 2.6E-09 

1-2B Unit 1 reactor building 1.7E-09 

Battery charger rooms 1.OE-09 

Cable spreading room (upper) 2.81E-10 

Susquehanna 2 Not analyzed, see Unit 1 

Three Mile Island West inverter room 5.81E-06 

Switchgear room 4.96E-06 

East inverter room 4.94E-06 

Switchgear room 3.94E-06 

Main control room/control room 3.12E-06 

Electrical equipment room/auxiliary relay room 2.59E-07 

Turkey Point 3 Main control room/control room 1.90E-04 

Cable spreading room 2.80E-06 

Reactor control rod equipment room, Unit 3 2.70E-06 

Unit 3 intake cooling water structure 7.80E-07 

Turkey Point 4 For most areas, refer to corresponding Unit 3 fire area 

Reactor control rod equipment room, Unit 4 2.70E-06 

Unit 4 intake cooling water structure 7.80E-07 

Vermont Yankee Cable vault or cable tunnel 1.50E-05 

Switchgear room 9.OOE-06 

Switchgear room 7.0OE-06 

Main control room/control room 5.70E-06 

Reactor building., elevation 252', zone RB3 (north) 5.1OE-06 

Reactor building., elevation 252', zone RB4 (south) 3.30E-06 

Cable vault battery room, elevation 262' 3.20E-06 

Reactor building, elevation 252', separation zone Div. S1 & S2 trays 1.30E-06 

Turbine room/hall/building 1.1OE-06 

Reactor building., torus room, elevation 213', zone RB2 (south) 7.40E-07 

Reactor building, elevation 280', zone RB5 (north) 7.300E-07 

Reactor building, elevation 303' 4.90E-07 

Emergency diesel generator room B 4.60E-07 

Emergency diesel generator room A 4.50E-07 

Relay and metering house, 345kv switchyard 4.00e-07 

Reactor building., elevation 280', zone RB6 (south) 3.50E-07 

Reactor building., elevation 280', recirculation MG set fire 3.40E-07 

Intake structure, service water pump room fire 3.1OE-07 

Startup transformer fire/propagation to turbine building 2.80E-07 

Advanced off gas building fire 1.40E-07 

Reactor building., torus room, elevation 213', zone RB I (north) 1.30E-07 

Main/auxiliary transformer fire w/propagation to turbine building 6.80E-08 

Reactor building, lower RCIC comer room, elevation 213' at NW comer 6.70E-08 

Radwaste corridor fire 5.20E-08 

Reactor building., upper RCIC comer room, elevation 232' at NW comer 4.50E-08 

Reactor building, elevation 318' 1.90E-08 

EDG fuel oil storage tank and transfer pump house fire 1.20E-08 

_Reactor building, southeast ECCS comer room, elevations 213' & 232' 1.00E-08

3 - 29
Table 3.3: Significant fire area CDFs (Continued)

Plant Significant fire areas CDF 

Reactor building, HPCI room, elevation 213' 9.OOE-09 

Reactor building, northeast ECCS comer room, elevations 213' & 232' 3.80E-09 

Intake structure, circulating water pump room fire 1.60E-09 

Reactor building., elevation 345' 1.50E-09 

Discharge structure fire 9.40E- 10 

Summer Main control room/control room 3.44E-05 

Switchgear room 2.44E-05 

Electrical equipment room/auxiliary relay room 1.28E-05 

Intermediate building, IB-21.1 9.10E-06 

Service water pumphouse, SWPH-1 8.15E-06 

Turbine room/hall/building 7.09E-06 

Service water pumphouse, SWPH-3 5.96E-06 

Service water pumphouse, SWPH-5.1/5.2 5.14E-06 

Switchgear room 2.75E-06 

Intermediate building, IB-22.1 1.91E-06 

Cable spreading room 1.08E-06 

Intermediate building, IB-25.1.2 [412' elevation general area] 8.49E-07 

A diesel generator room, DG-1.1/1.2 6.98E-07 

B diesel generator room, DG-2.1/2.2 6.19E-07 

Intermediate building, IB-25.1.3 [412' elevation general area] 5.82E-07 

Control building, CB-1.1, 412' elevation 3.87E-07 

Intermediate building, IB-25.1.5 [412' elevation general area] 3.43E-07 

Auxiliary building, AB-1.29 [auxiliary building switchgear room] 2.15E-07 

HVAC chilled water pump rooms, IB-7.2 4.34E-08 

Intermediate building, IB-3 [battery charger room A] 1.79E-08 

Control building, CB-1.2, 425' elevation 9.33E-09 

Intermediate building, IB-25.2 [turbine drive efw pump room] 3.47E-09 

Intermediate building, IB-23 HVAC water chiller equipment room A] 2.64E-09 

Intermediate building, IB-9 [HVAC water chiller equipment room B] 2.62E-09 

Auxiliary building, AB-1.7 [charging pump room A] 2.62E-09 

Auxiliary building, AB-1.5 [charging pump room B] 2.35E-09 

Vogtle 1 Additional detailed analysis fire risk contribution (additional information not 2.19E-06 

provided) 

Fire risk contribution of scenarios screened from spatial interactions quantitative 1.78E-06 

screening (additional information not provided) 

Main control room/control room 1.61E-06 

Switchgear room 1.21E-06 

Switchgear room 7.14E-07 

Lower cable spreading room - train A 5.59E-07 

Train B electrical penetration area 5.51E-07 

Level A east-west corridor and cable chase 5.29E-07 

Train A electrical mezzanine 3.73E-07 

Upper cable spreading room - train B 3.46E-07 

Train b electrical raceway room 2.29E-07 

Electrical equipment room/auxiliary relay room 4.59E-09 

Vogtle 2 Not analyzed, see Unit 1

3 -30

f
Table 3.3: Significant fire area CDFs (Continued)

Plant Significant fire areas CDF 

Waterford 3 Main control room/control room 2.OOE-06 

Essential chillers room (H&V mechanical room) 1.90E-06 

Switchgear room (switchgear "A" room, switchgear "B" room, & switchgear 1.50E-06 

"AB" room) 

Emergency diesel generator B 5.90E-07 

Electrical penetration area A 4.30E-07 

Turbine room/hall/building 3.30E-07 

Electrical equipment room/auxiliary relay room 1.60E-07 

Cable spreading room 9.90E-08 

Reactor auxiliary building, -4' corridor and passageways 5.50E-08 

Reactor auxiliary building, 35' and 4' general areas 2.OOE-08

Auxiliary control instrument room 2A

125V vital battery room IV 7.94E-07 

Main control room/control room 7.O1E-07 

Electric driven fire pump room B 6.88E-07 

Decontamination room 5.52E-07 

Corridor 5.31E-07 

ERCW pump room B 5.28E-07 

6.9kV and 480V shutdown board room A 5.22E-07 

480V board room lB 5.13E-07 

ERCW pump room A 5.05E-07 

Screen wash pump and electric driven fire pump room A 4.72E-07 

Auxiliary instrument room 1 4.39E-07 

Corridor 4.24E-07 

Auxiliary instrument room 2 4.17E-07 

480V shutdown board room lB 4.16E-07 

480V board room 2B 4.11E-07 

125V vital battery room III 4.04E-07 

480V electric board room 4.03E-07 

480V board room 2A 3.94E-07 

6.9kV and 480V shutdown board room B 3.78E-07 

125V vital battery I 3.68E-07 

480V board room 1A 3.15E-07 

480V transformer room 2B 2.93E-07 

ERCW strainer room A 2.60E-07 

ERCW strainer room B 2.49E-07 

Corridor 2.44E-07 

125V vital battery board I room 2.38E-07 

480V transformer room 1A 1.88E-07 

Mechanical equipment room 1 .86E-07 

Mechanical equipment room 1.83E-07 

480V transformer room 2A 1.81E-07 

125V vital battery board room III 1.74E-07 

480V shutdown board room 2A 1.66E-07 

Diesel generator lA-A room 1.64E-07

1li~el•, generator 2A-A room

3 -31

Watts Bar I

1 2 Diesel enerator 2A-A room 1 .ol•r-,- /
Table 3.3: Significant fire area CDFs (Continued)

3 -32

Plant Significant fire arma CDF 

Plant computer room 1.64E-07 

Diesel generator 1B-B room 1.52E-07 

Diesel generator 2B-B room 1.52E-07 

125V vital battery board room IV 1.31E-07 

125V vital battery II 1.25E-07 

Cable spreading room 1.25E-07 

24V and 48V battery board and charger room 1.20E-07 

250V battery board room 2 1.15E-07 

250V battery board room 1 1.11E-07 

Mechanical equipment room 1.06E-07 

Turbine room/halllbuilding 8.60E-08 

Electrical equipment room/auxiliary relay room 2.62E-08 

Wolf Creek Switchgear room (train A ESF switchgear room, north (3301)) 2.58E-06 

Switchgear room (train B ESF switchgear room, south (3302)) 2.12E-06 

Main control room/control room 1.43E-06 

Electrical penetration room, north (room 1410) 5.36E-07 

Auxiliary building, elevation 2000', general area(rooms 1301, 1313, 1314, 1315, 3.43E-07 

1318, 1320 and 1321) 

Electrical equipment room/auxiliary relay room 2.40E-07 

Auxiliary building, elevation 2026', general area (rooms 1401, 1402, 1406 and 2.08E-07 

1408) 

Reactor trip switchgear room (1403) 1.95E-07 

Electrical penetration room, south (room 1409) 1.80E-07 

Cable spreading room (lower cable spreading room CDF = 3.9E-08; upper cable 7.60E-08 

spreading room CDF = 3.7E-08) 

* Formerly known as Washington Nuclear Project Number 2.

1!
Table 3.4: Licensees' statements on, and definitions of, fire vulnerabilities

Plant Statement on vulnerabilities Plant definition of vulnerability 

Arkansas No vulnerabilities were The core damage frequency results and the failures 

Nuclear Unit 1 identified. [IPEEE, page 4-2] associated with the unscreened zones do not represent 

any vulnerabilities for ANO based on the following: 1) 

All zones have a CDF that is well below the 1.OE-04 

criteria set by the NRC's safety goal policy (NEI 91-04, 

Severe Accident Issue Closure Guidelines), 2) No new 

or unusual failures were identified, 3) Per the guidance 

of NEI's Severe Accident Closure Guidelines (see page 

17), no further modifications nor procedure 

enhancements are required. [IPEEE, pages 4-3] 

Arkansas No vulnerabilities were see Unit 1 

Nuclear Unit 2 identified. [IPEEE, page 4-2] 

Beaver Valley No specific vulnerabilities Duquesne Light Company's (DLC's) approach to 

Unit 1 were identified with respect to identifying vulnerabilities was as follows. If the overall 

external events. CDF and early release frequencies were consistent with 

[IPEEE, page 1-3] study results from other similar plants that have been 

accepted by the U.S. NRC, then there are no 

vulnerabilities requiring enhancement. However, the 

most important contributors to risk at the plant should 

still be evaluated to see if cost-effective improvements 

can be made. [IPEEE, page 7-1] 

Beaver Valley See Unit 1 See Unit 1 

Unit 2 

Big Rock Point n/a n/a 

Braidwood No vulnerabilities were A definition is implied by the following statement from 

Unit 1 identified. [IPEEE, pages 8-1 the IPEEE: "Each individual fire compartment has a 

through 8-3] Core Damage Frequency (CDF) of less than 1.OE-06 

per reactor year. FIVE states that fire compartments 

with a CDF of less than 1.OE-06 are not risk significant. 

Therefore, no fire vulnerabilities exist for Braidwood 

Station." [IPEEE, page 8-1] 

Braidwood See Unit 1 See Unit 1 

Unit 2 

Browns Ferry See Unit 2 See Unit 2 

Unit 1 

Browns Ferry No vulnerabilities were A definition is implied by the following statement from 

Unit 2 identified. [IPEEE, page 1-2] the IPEEE: "There are no potential vulnerabilities to 

internal fires, high winds, external floods, or 

facilities/transportation accidents identified which 

reduce the plant's safety margins." [IPEEE, page 7-1]

3 -33
Table 3.4: Licensees' statements on, and definitions of, fire vulnerabilities (Continued) 

Plant Statement on vulnerabilities Plant definition of vulnerability 

Browns Ferry No fire vulnerabilities were No definition of vulnerability was provided. However, 

Unit 3 identified. [IPEEE, page 7-6] one may be implied by the following statement: "In 

keeping with the requirements of Supplement 4 to 

Generic Letter 88-20 (NUREG-1407) and the guidance 

provided by the EPRI FIVE documentation, this 

evaluation has confirmed that there are no fire-induced 

vulnerabilities associated with the continued operation 

of Browns Ferry Unit 3." [IPEEE, page 7-1] 

Brunswick See Brunswick Unit 2 

Unit 1 

Brunswick The licensee found no The licensee states: "Rather than attempt to define 

Unit 2 significant vulnerabilities. vulnerabilities, CP&L uses the criteria in NEI 91-04 

'Severe Accident Issue Closure Guidelines' for 

deciding on the appropriate resolution for each 

significant accident sequence." [IPEEE, page 1-8] 

"Core damage sequences were grouped on the basis of 

location (e.g., fire area/compartment) and the group 

frequency compared to the closure guidelines which are 

provided in Tables 1 and 2 of the NEI document. These 

tables provide guidance as to the nature of appropriate 

action, ranging from effective hardware fixes (if the 

CDF of the group is greater than L.OE-04 or >50% of 

the total CDF), to no action required (if the group CDF 

is less than 1.OE-06)." [IPEEE, page 2-4] 

Byron Unit 1 No vulnerabilities that warrant A definition is implied by the following statement from 

modifications were identified. the IPEEE: "Each individual fire compartment has a 

[IPEEE, pages 1-3 to 6] Core Damage Frequency (CDF) of less than 1.OE-06 

per reactor year. FIVE states that fire compartments 

with a CDF of less than 1.OE-06 are not risk significant. 

Therefore, no fire vulnerabilities exist for Byron 

Station." [IPEEE, page 1-3] 

Byron Unit 2 See Byron Unit 1 

Callaway No vulnerabilities were Callaway used the NEI 91-04 severe accident closure 

identified. [IPEEE, page 1-10] guidelines to evaluate the need for plant improvements. 

Each fire area or compartment above the FIVE 

screening threshold (1.OE-06/year) was compared to 

the NEI closure guidelines listed in Table 1 of 

NEI 91-04. [IPEEE, page 1-8] 

Calvert Cliffs No vulnerabilities were A specific definition of vulnerability was not provided 

Unit 1 identified. [IPEEE, page 8-1] in the IPEEE.

3 -34
Table 3.4: Licensees' statements on, and definitions of, fire vulnerabilities (Continued) 

Plant Statement on vulnerabilities Plant defminion of vulnerability 

Calvert Cliffs See Calvert Cliffs Unit 1 

Unit 2 

Catawba Unit 1 The basic finding of the The IPEEE states: "The major findings from this 

evaluations in the IPEEE was examination are that there are no unduly significant 

that there are no fundamental sequences (vulnerabilities) from external events." 

weaknesses or vulnerabilities [IPEEE, page 1-3] 

with regard to severe accident 

risk at Catawba Nuclear 

Station. [IPEEE, page 1-4] 

Catawba Unit 2 See Catawba Unit 1 

Clinton No vulnerabilities were An explicit definition of vulnerability was not given. 

identified. 

Columbia Vulnerabilities are not An explicit definition of vulnerability is not provided. 

Generating* discussed in the IPEEE. 

Comanche Peak No vulnerabilities were Licensee states: "the relatively low core damage 

Unit 1 identified. [IPEEE, page 1-3] frequency and its uniform distribution among various 

contributors demonstrate that no plant-specific 

vulnerability to severe accidents exists at CPSES from 

fires." [IPEEE, page 1-4, 8-2] 

Comanche Peak See Comanche Peak Unit 1 

Unit 2 

Cook Unit 1 No vulnerabilities were An explicit definition of vulnerability was not given. 

identified. 

Cook Unit 2 See Unit 1 

Cooper No significant vulnerabilities An explicit definition of vulnerability was not given. 

were discovered during the 

CNS IPEEE evaluation. 

[IPEEE Introductory Letter] 

Crystal River No plant vulnerabilities were An explicit definition of vulnerability was not given. 

Unit 3 identified. 

Davis-Besse No vulnerabilities were No explicit definition of vulnerability was provided. 

identified. [IPEEE, page 1-2] 

Diablo Canyon No vulnerabilities were "A vulnerability refers to any component, system, 

Unit 1 identified and there were no operator action, or accident sequence that contributes 

cost-effective design changes more than 50 percent to the CDF or has a frequency 

identified that could that exceeds 1E-04 per year .... Any containment 

significantly reduce overall bypass or large early release that exceeds IE-05 per 

plant risk. [IPEEE, page 1-4] year is considered a containment performance 

vulnerability." [IPEEE, page 1-6]

3 -35
Table 3.4: Licensees' statements on, and definitions of, fire vulnerabilities (Continued) 

Plant Statement on vulnerabilities Plant definition of vulnerability 

Diablo Canyon See Diablo Canyon Unit 1 

Unit 2 

Dresden Unit 2 No vulnerabilities were An explicit definition of vulnerability in the context of 

identified. fire was not given. The revised IPEEE highlighted nine 

insights related to fire risk (see Insights). [IPEEE, page 

1-6] A definition may be implied in the statement that 

there were no other external events identified that have 

any significant impact on the core damage frequency at 

Dresden. [IPEEE, page 1-7] 

Dresden Unit 3 See Dresden Unit 2 

Duane Arnold The plant did not identify any An explicit definition of vulnerability was not given. 

vulnerabilities. However, However, the following is presented in the IPEEE, "In 

potential plant improvements Section 7.2 a discussion of significant hazards is given. 

or procedural strategies were Hazards that were identified by comparison with the 

identified as part of the NUREG-1407 core damage frequency screening 

JPEEE. [IPEEE, page 7-1] criterion of 1E-06/yr or by comparison to the 

NUREG/CR-5088 Fire Risk Scoping Study issues are 

included in this discussion." [IPEEE, page 7-1] 

Farley Unit 1 No fire vulnerabilities were Potential vulnerabilities were dispositioned consistent 

identified. with NEI 91-04, Revision 1 for the fire analyses, see 

ImpMatrix. 

[IPEEE, Introductory Letter; IPEEE, page 4-57] 

Farley Unit 2 See Unit 1 

Fermi Unit 2 No vulnerabilities were A definition of vulnerability may be implied by the 

identified. following statement: "The EPRI Fire-Induced 

[IPEEE, pages 8-2, 4, 5] Vulnerability Evaluation (FIVE) technique is used for 

the fire portion of the Fermi 2 IPEEE. This technique identifies fire initiators by compartment and then uses a 

multi-step screening process to ascertain if the 

probability of going to core damage is less than 

1.OE-06/yr for each identified fire compartment. This 

screening effort includes a walkdown to verify 

assumptions credited in the screening process. Those 

compartments that do not screen out are then evaluated 

as potential vulnerabilities." [IPEEE, page 1-5] 

FitzPatrick No vulnerabilities were An explicit definition of vulnerability was not given. 

identified. 

[IPEEE, pages 1-7 to 1-11 ]

3 -36

I!
Table 3.4: Licensees' statements on, and definitions of, fire vulnerabilities (Continued) 

Plant Statement on vulnerabilities Plant definition of vulnerability 

Fort Calhoun The submittal states that based Fire areas that did not screen out were assessed based 

on the analyses of external on the guidance provided in NEI 91-04 (Severe 

events, no event sequence has Accident Issue Closure Guidelines (Rev. 1), NEI 91-04, 

been identified which is Dec. 1994). NET 91-04 provides a fire IPEEE closure 

considered to be a severe approach for plants that implemented a fire PRA based 

accident vulnerability, on a mean CDF per fire compartment or mean 

[IPEEE, page 1-5] containment bypass frequency per fire compartment 

considering both the actual CDF magnitude and relative 

contribution of any one compartment to total fire CDF. 

[IPEEE, pages 4-79 to 81] 

Ginna No major fire vulnerabilities An explicit definition of vulnerability was not given. 

were identified. 

[IPEEE, Introductory Letter] 

Grand Gulf No vulnerabilities with regard Vulnerability screening was based on application of the 

Unit 1 to Seismic, Fire, or HFO NEI 91-04 Severe Accident Closure Guidelines. None 

events were found. of the compartments were found to meet this test. 

[IPEEE, page 8] [IPEEE, page 116] 

Haddam Neck The IPEEE cover letter states An explicit definition of vulnerability was not given. 

that "the major vulnerabilities However, the identification of vulnerabilities was 

associated with internal fires apparently based on the consideration of "risk outliers" 

had already been identified [IPEEE cover letter and pages 1-2 and 7-11 

and resolved as a result of the 

CY Fire PRA performed in 

1986 and Appendix R related 

modifications." It goes on to 

state that "additional insights 

were gained from performing 

the IPEEE analysis." [IPEEE, 

cover letter and page 1-2]. 

Hatch Unit 1 The major finding from the The term vulnerabilities, as used in the IPEEE, refers to 

IPEEE is that the plant has no "those components, systems, operator actions, and/or 

fundamental weaknesses or plant design configuration that contribute significantly 

vulnerabilities to severe to an unacceptably high severe accident risk." 

accident risk in regard to the [IPEEE, page 7-2] 

external events related to 

seismic, fire, high winds, 

floods, transportation and 

nearby facility accidents, and 

other external hazards. 

[IPEEE, page 8-1] I 

Hatch Unit 2 See Unit 1

3 -37
Table 3.4: Licensees' statements on, and definitions of, fire vulnerabilities (Continued) 

Plant Statement on vulnerabilities Plant definition of vulnerability 

Hope Creek No external event accident A vulnerability is defined as "a scenario which 

Unit 1 vulnerabilities were identified. contributes inordinately to the HCGS core damage 

[IPEEE, page 1-13] frequency (CDF), as compared to other plants of 

similar type and vintage (as available from published 

risk assessment results), thus representing a substantial 

design weakness of the plant." [IPEEE, page 2-1 ] The 

evaluation of severe accident vulnerabilities was 

accomplished by reference to the Severe Accident Issue 

Closure Guidelines NEI 91-04. Core Damage 

sequences were grouped by categories (e.g., fire

induced loss of core cooling) and the group frequency 

compared to the closure guidelines which are provided 

in NEI, 1994, Tables 1 and 2. [IPEEE, page 2-7] 

Indian Point No vulnerabilities were The IPEEE states: "In this study the external event 

Unit 2 discovered during the IPEEE induced sequences have been categorized and evaluated 

but several opportunities for in accordance with the guidelines provided in the 

improvement were identified Nuclear Energy Institute (NEI) Severe Accident 

which are being incorporated Closure Guidelines (NEI 91-04)." [IPEEE, page 9-3] 

or evaluated. [IPEEE, pg. 1-6] 

Indian Point No vulnerabilities were An explicit definition of vulnerability was not given. 

Unit 3 identified as a result of the 

IPEEE. [IPEEE, pages 1-7, 8] 

Kewaunee No major plant changes were An explicit definition of vulnerability was not given. 

deemed necessary based on 

the results of the Kewaunee 

IPEEE. However, some 

equipment outliers were 

identified. [IPEEE, page 7-2] 

LaSalle Unit 1 See Unit 2

3 -38
Table 3.4: Licensees' statements on, and definitions of, fire vulnerabilities (Continued)

Statement on vulnerabilities 4. 4.

The detailed review (of the 

NRC's Risk Methods 

Integration Evaluation 

Program (RMIEP) analysis) 

process conducted by 

Commonwealth Edison 

determined that no 

vulnerabilities regarding 

severe accident issues were 

indicated in the results of the 

RMIEP analysis of LaSalle 

County Station Unit 2. 

[IPEEE, Executive Summary]

Plant definitio I~f vulnerability

A definition of vulnerability is implied in the following 

statement: "The RMIEP results are well within the 

safety goals established by the Nuclear Regulatory 

Commission." [IPEEE, Executive Summary]

Limerick Unit 1 No vulnerabilities were A fire vulnerability was defined as any fire 

determined to exist at LGS. compartment that is well above the compartment 

[IPEEE, page 2-3] screening criterion of 1E-06. [IPEEE, page 7-1] 

Limerick Unit 2 See Limerick, Unit 1 

Maine Yankee The IPEEE concludes that An explicit definition of vulnerability was not given. 

vulnerabilities with regard to 

severe accident risk at Maine 

Yankee have been 

satisfactorily addressed either 

through installed or planned 

plant modifications and that 

the remaining risk from severe 

accidents is acceptably low. 

[IPEEE, page 1-10] 

McGuire Unit 1 The IPEEE concluded that An explicit definition of vulnerability was not given. 

there are no vulnerabilities to 

severe accident risk from 

external events. 

[IPEEE, pages 1-3 and 8-1] 

McGuire Unit 2 see Unit 1 

Millstone N/A 

Unit 1

3 -39

Plant

LaSalle Unit 2
Table 3.4: Licensees' statements on, and definitions of, fire vulnerabilities (Continued) 

Plant Statement on vulnerabilities Plant definition of vulnerability 

Millstone The IPEEE states: "Through An explicit definition of vulnerability was not given 

Unit 2 the evaluations performed, beyond the equating of "vulnerabilities" with "outliers" 

several plant vulnerabilities in the cited quotation from Section 1 of the submittal. 

(outliers) to severe external However, the threshold for identification of 

events were identified." vulnerabilities appears to have been low in comparison 

[IPEEE, page 1-2]. The to other licensees. For example, the cited table of plant 

referenced table [Table 7.1-1 ] vulnerabilities [Table 7.1-1] is entitled "Opportunities 

identified one fire and three for Improvement." 

seismic/fire interaction items. 

Millstone "No major severe accident No definition of vulnerability is given. 

Unit 3 vulnerabilities requiring 

immediate corrective action 

have been identified or are 

outstanding." [IPE page 7] 

Monticello No external event accident A vulnerability in the context of fire was defined as any 

vulnerabilities were identified. direct-to-core-damage fire sequences as implied by the 

[Revised IPEEE, page iv, v] following statement: "The principal finding of the fire 

portion of the IPEEE is that there is no area in the plant 

in which a fire would lead directly to the inability to 

cool the core. Without additional random equipment 

failures unrelated to damage caused by the fire, core 

damage will not occur. As a result, this study concludes 

that there are no vulnerabilities due to fire events at the 

Monticello Nuclear Generating Station." 

[IPEEE, page v] 

Nine Mile Point No vulnerabilities were An explicit definition of vulnerability was not provided. 

Unit 1 identified. However, a definition may be inferred from the 

following statement: "The results of the IPEEE 

analysis suggest that operation of NMP1 poses no 

undue risk to the public and the containment evaluation 

indicated that the NMP 1 containment does not have any 

unusual characteristics that result in poor containment 

performance." [IPEEE page 1 -1] 

Nine Mile Point NMP2 did not discuss An explicit definition of vulnerability was not provided. 

Unit 2 vulnerabilities. However, a definition may be inferred from the 

following statement: "For the same reasons described 

above (i.e., relatively new plant designed to the latest 

conservative requirements), the detailed analysis of 

seismic and fire hazards found the risks to be relatively 

low. Core damage frequency for each hazard was 

assessed to be on the order of 1E-06/yr or less." 

[IPEEE, page 1-6]

3 - 40
Table 3.4: Licensees' statements on, and definitions of, fire vulnerabilities (Continued) 

Plant Statement on vulnerabilities Plant defin.ition of vulnerability 

North Anna The analysis results showed An explicit definition of vulnerability was not provided. 

Unit 1 that North Anna is not However, a definition was clearly implied in the 

vulnerable to non-seismic following statement: "The NUMARC severe accident 

external events or fires. closure guidelines promulgated in NUMARC 91-04 

[IPEEE, Introductory letter] have been used to evaluate plant improvements. Since a 

fire PRA was performed the appropriate guidelines are 

those presented in Table 1 of the document. 

(NUMARC, 1991)." [IPEEE, page 4-94] 

North Anna See Unit 1 

Unit 2 

Oconee Unit 1 See Unit 3 

Oconee Unit 2 See Unit 3 

Oconee Unit 3 The IPEEE concludes that An explicit definition of vulnerability was not given. 

there are no fundamental One may be implied in the statement that there were no 

weaknesses or vulnerabilities plant changes identified that would significantly reduce 

with regard to severe accident the risk from external events. [IPEEE, page 1-3] 

risk at Oconee. 

[IPEEE, page 1-6; 8-1] 

Oyster Creek The IPEEE concludes that The term vulnerability is defined as any core damage 

there are no vulnerabilities sequence that exceeds 1E-04 per reactor-year, or any 

with regard to severe accident containment bypass sequence or large early 

risk from external. containment failure sequence that exceeds 1E-06 per 

[IPEEE, pages 1-6, 1-9] reactor-year. [IPEEE, pages 1-9, 3-142] 

Palisades There were no other external An explicit definition of vulnerabilities was not 

events identified that have an presented. However, one was implied by the following 

impact on the core damage statement: "The functional reporting requirements 

frequency at Palisades. presented in GL 88-20 and NUREG- 1407 are: 1) 

[IPEEE, Revision 1, page 8-2] Functional sequences with a CDF greater than 1E

06/yr. 2) Functional sequences that contribute 5% or 

more to total CDF. 3) Sequences determined by 

Palisades to be important contributors to CDF or 

containment performance." [IPEEE, page 3-50, 4-72] 

Palo Verde Unit The IPEEE concludes that no A fire vulnerability was said to exist if core damage 

1 vulnerabilities to fire initiating sequences were identified which were in excess of the 

events exist at Palo Verde. screening criterion of 1E-06/reactor-year and which 

[IPEEE, page 1-3] resulted in containment failure sequences that were 

either unique or unbounded by similar sequences 

contained in the internal events IPE. [IPEEE, page 7-3] 

Palo Verde Unit See Unit 1 

2 1

3 -41
Table 3.4: Licensees' statements on, and definitions of, fire vulnerabilities (Continued) 

Plant Statement on vulnerabilities Plant definition of vulnerability 

Palo Verde Unit See Unit 1 

3 

Peach Bottom The IPEEE concludes that no A fire vulnerability is a fire compartment that 

Unit 2 vulnerabilities to seismic, significantly exceeds the FIVE screening criteria and 

fires, high winds or floods or provides a major accident risk. [IPEEE, page 7-1] "others" were found to exist. 

[IPEEE, page 7- 1] 

Peach Bottom See Unit 2 

Unit 3 

Perry Unit 1 There were no vulnerabilities An explicit definition of vulnerability was not provided. 

identified during the 

performance of the IPEEE. 

[IPEEE, page 7-2] 

Pilgrim Unit 1 The IPEEE concludes that The IPEEE used the same definition of vulnerability as 

Pilgrim Station does not that cited in the IPE. Section 5 of the Internal Events 

contain any significant IPE uses the following criteria to determine if any plant 

vulnerabilities or "outliers" in vulnerabilities exist: 1) Are there any new or unusual 

the fire risk. means by which core damage or containment failure 

[IPEEE, pages 7-3 and 7-4] occur as compared to those identified in other PRAs? 2) 

Do the results suggest that the Pilgrim core damage 

frequency would not be able to meet the NRC's safety 

goal for core damage? [IPEEE, page 7-1 ] 

Point Beach The IPEEE concludes that no An explicit definition of vulnerability in the fire context 

Unit 1 significant fire concerns were was not provided. One may be implied by the following 

discovered in the Point Beach statement: "Since the resulting fission product release 

Nuclear Plant Fire Analysis. frequency due to seismic events is judged to be 

[IPEEE, Section 8.2, page 4] <1E-06/year, it is concluded that PBNP has no severe 

accident vulnerabilities due to a seismic event." 

[IPEEE, Section 8.1, page 2] However, an equivalent 

statement was not found for fire or HFO events. 

Point Beach See Unit 1 

Unit 2

3 - 42

I
Table 3.4: Licensees' statements on, and definitions of, fire vulnerabilities (Continued) 

Plant Statement on vulnerabilities Plant definition of vulnerability 

Prairie Island The IPEEE concluded that An explicit definition of vulnerability was not provided. 

Unit 1 there are no significant A definition may be implied in that the IPEEE fire 

vulnerabilities to severe analysis concluded that the overall core damage 

accidents that exist at Prairie frequency is low. [IPEEE, Revision 1, page 3] A 

Island that would be definition may also be implied in the screening criteria 

attributable to seismic, fire, or "used to identify sequences to be discussed" as follows: 

other external events. "The criteria are identical to the functional reporting 

[IPEEE, Revision 1, page v] requirements presented in GL 88-20 as required by 

NUREG-1407: 1) functional sequences with a CDF 

greater than 1E-06/year, 2) functional sequences that 

contribute 5% or more to total CDF, and 3) sequences 

determined by the utility to be important contributors to 

CDF or containment performance." 

[IPEEE, Revision 1, page B-91] 

Prairie Island See Unit 1 

Unit 2 

Quad Cities The original IPEEE submittal No explicit definition of vulnerability is stated. The 

Unit 1 stated that, with regard to fire, discussion of each of the five items implies that a 

"Five potential vulnerabilities vulnerability was a condition that contributed to the 

have been identified by the high CDF value estimated in the original analysis. 

IPEEE" [original IPEEE, page [IPEEE Section 7.2.2, page 7-3] 

7-3]. The revised analysis 

concluded that no fire 

vulnerabilities remained. 

Quad Cities See Unit 1. 

Unit 2

3 - 43
Table 3.4: Licensees' statements on, and definitions of, fire vulnerabilities (Continued) 

Plant Statement onvulnerabilities Plant definition of vulnerability 

River Bend The IPEEE concludes that The exact definition of a vulnerability in the context of 

Unit 1 there were no vulnerabilities fire was not entirely clear. It appears that the overall 

due to internal fires. fire results were initially compared against the 

[IPEEE, page 151] vulnerability criteria established by the NEI 91-04 

Severe Accident Issue Closure Guidelines. [see the fire 

IPEEE, page 1-5]. However, the IPEEE also cites that 

the licensee's IPE analysis had considered and rejected 

the NEI guidelines. It would appear that in the end, a 

set of criteria consistent with the IPE criteria was 

applied. In particular: "Instead (of the NEI criteria) the 

vulnerability screening criteria for River Bend is based 

on the NRC's Safety Goal Policy Statement. The 

criteria for River Bend is that if the total core damage 

frequency or the core damage frequency of any 

functional accident sequence exceeds 1.OE-04 per year, 

a vulnerability associated with the overall plant or 

sequence is assumed to exist. In addition, the 

contribution that exceeds the criteria must be 'real' and 

not an artifact of conservative modeling or analysis 

assumptions." 

Robinson Unit No vulnerabilities were The IPEEE states: "The evaluation of severe accident 

2 identified. vulnerabilities was accomplished by reference to the 

Severe Accident Issue Closure Guidelines, NUMARC 

91-04, Severe Accident Issue Closure Guidelines 

(NUMARC, 1991). Core damage sequences were 

grouped primarily on the basis of location (e.g., fire 

area/compartment) and also on the nature of the 

sequence (non-LOCA, LOCA, fire-induced 

containment bypass), and the group frequency 

compared to the closure guidelines which are provided 

in Tables 1 and 2 of the NUMARC Document. These 

tables provide guidance as to the nature of appropriate 

action, ranging from effective hardware fixes (if the 

CDF of the group is greater than 1.OE-04 or greater 

than 50% of the total CDF), to no action required (if the 

group CDF is less than 1.OE-06)." 

[IPEEE, page 2-3]

3 - 44

I
Table 3.4: Licensees' statements on, and definitions of, fire vulnerabilities (Continued) 

Plant Statement on vulnerabilities Plant definition of vulnerability 

Saint Lucie The IPEEE concludes that No definition of vulnerability is given. 

Unit 1 "there are no vulnerabilities to 

severe accident risk from 

external events." 

[IPEEE Section 1.4, page 7] 

and that "no scenario or event 

sequence has been identified 

which is considered to be a 

severe accident vulnerability." 

[IPEEE Section 8, page 123] 

Saint Lucie See Unit 1. 

Unit 2 

Salem Unit 1 The IPEEE concludes that A vulnerability is defined as "a contribution to 

"SGS has no significant unusually high risk, as compared to other plants of 

vulnerabilities to external similar type and vintage (as available from published 

events." [IPEEE, page 8-6] risk assessment results), which represents a substantial 

design weakness of the plant" [IPEEE, page 2-1]. 

Furthermore, the evaluation of severe accident 

vulnerabilities was accomplished by reference to the 

NEI Severe Accident Issue Closure Guidelines 

NEI 91-04 (NEI, 1994). [IPEEE, page 2-4] 

Salem Unit 2 See Unit 1 

San Onofre No fire vulnerabilities are The IPEEE states: "A vulnerability in a PWR is a plant 

Unit 2 identified. feature which contributes a disproportionately large 

percentage to either core damage or significant release 

probabilities which are in turn significantly higher than 

those of an average PWR. This definition is applicable 

for the seismic, internal fire, and other hazards 

analysis" [IPEEE, page 2-3]. The submittal also 

intimates that a vulnerability is a condition that might 

expose the plant to non-conservatisms outlined in 

SECY-93-143. [IPEEE, page 4-121] 

San Onofre See Unit 2. See Unit 2. 

Unit 3 

Seabrook The IPEEE concludes that An explicit definition of vulnerability is not provided. 

Unit 1 there are no vulnerabilities to 

severe accident risk from 

external events. 

_[IPEEE, page 1-5]

3 -45
Table 3.4: Licensees' statements on, and definitions of, fire vulnerabilities (Continued) 

Plant Statement on vulnerabilities Plant definition of vulnerability 

Sequoyah No vulnerabilities were The term vulnerabilities refers to "those components, 

Unit 1 identified. systems, operator actions, and/or plant design 

configurations that contribute significantly to an 

unacceptably high severe accident risk." 

[IPEEE page 1-9] 

Sequoyah See Unit 1 

Unit 2 

Shearon Harris "The IPEEE has demonstrated A vulnerability was defined as any core damage 

Unit 1 that the SHNPP has no sequence that exceeds 1E-4/ry or any containment 

significant vulnerabilities to bypass sequence or large early containment failure 

external events." [page 8-5] sequence that exceeds 1E-6/ry. 

South Texas The IPEEE does not identify An explicit definition of vulnerability is not provided. 

Project Unit 1 and vulnerabilities. However, for fire, the IPEEE states that the various fire 

sequences considered are "not important to plant risk." 

[IPEEE page 9.5-1] 

South Texas See Unit 1 

Project Unit 2 

Summer No vulnerabilities are An explicit definition of vulnerability is not provided. 

identified. The IPEEE states: "SCE&G's IPEEE Fire Evaluation 

demonstrates that, in concert, the existing VCSNS 

Appendix R and FPER Evaluation, selected shutdown 

systems, Fire Emergency Procedures, and VCSNS's 

overall Fire Protection and Equipment Maintenance 

Programs are sufficient to maintain the Virgil C. 

Summer Nuclear Station at a negligible vulnerability to 

a fire initiated core damage event." 

[IPEEE, Fire Portion, page 3] 

Surry Unit 1 No fire vulnerabilities are An explicit definition of vulnerability was not provided 

identified. in the IPEEE submittal. However, use of the 

NEI 91-04 Severe Accident Issue Closure Guidelines, is 

implied. 

Surry Unit 2 See Surry Unit 1 

Susquehanna No fire vulnerabilities were No explicit definition provided although a definition is 

Unit 1 identified. implied in that the IPEEE states that "...the PRA 

demonstrates that defense in depth against core damage 

exists for any fire. That is, no fire with a single 

independent equipment failure results in core damage." 

[IPEEE page 4-74] 

Susquehanna See Unit 1. 

Unit 2 1

3 - 46

I
Table 3.4: Licensees' statements on, and definitions of, fire vulnerabilities (Continued) 

Plant Statement on vulnerabilities Plant definition of vulnerability 

Three Mile The IPEEE states that there The term vulnerability is defined as any core damage 

Island Unit 1 are no vulnerabilities to severe sequence that exceeds 1.OE-04 per reactor-year, or any 

accident risk from external containment bypass sequence or large early 

events, containment failure sequence that exceeds 1.OE-06 per 

[IPEEE, page 1-4] reactor-year. [IPEEE, page 1-9] 

Turkey Point The IPEEE states that there No definition of vulnerability is given. 

Unit 3 are no vulnerabilities to severe 

accident risk from external 

events. [IPEEE, pages 8, 62] 

Turkey Point See Unit 3. 

Unit 4 

Vermont No vulnerabilities were No definition is provided. 

Yankee identified. 

Vogtle Unit 1 The IPEEE concludes that An explicit definition of vulnerability was not provided. 

"VEGP has no fundamental 

weaknesses or vulnerabilities 

to severe accident risk in 

regard to the external events 

related to seismic, fire, high 

winds, floods, transportation 

and nearby facility accidents, 

and other external hazards." 

[IPEEE, page 1-2] 

Vogtle Unit 2 See Unit 1 

Waterford The IPEEE concludes that The lack of fire vulnerabilities was based on three 

Unit 3 there are no fire vulnerabilities points: 1) no individual fire scenario has a CDF greater 

at Waterford. than 2E-6 (i.e., less than 1E-4); (2) no individual fire 

[IPEEE, page 1-4] scenario contributes more than 31% of the total core 

damage frequency due to fires; and (3) no unusual and 

significant failures were found. [IPEEE page 1-4]. 

Watts Bar The submittal states that "The An explicit definition of vulnerability was not provided. 

Unit 1 IPEEE program did not 

uncover any serious fire 

vulnerabilities" 

[IPEEE, page 4]. 

Wolf Creek The IPEEE concludes that no An explicit definition of vulnerability was not provided. 

Unit 1 event sequence has been 

identified which is considered 

to be a severe accident 

_vulnerability. [IPEEE, pg. 8-3]

3 - 47
Table 3.4: Licensees' statements on, and definitions of, fire vulnerabilities (Continued) 

Plant Statement onvulnerabilities Plant definition of vul"erabilit 

Zion Unit 1 No fire vulnerabilities are An explicit definition of vulnerability was not provided. 

identified. The submittal states that risk vulnerabilities are 

identified in accordance with the guidance provided in 

GL 88-20, Supplement 4, and NUREG- 1407. 

Vulnerabilities are in the form core damage and 

containment failure frequency for the fire PRA. 

[IPEEE, page 2-3] 

Zion Unit 2 See Unit 1 

* Formerly known as Washington Nuclear Project Number 2.

3 - 48

I
Table 3.5: Fire-related plant improvements 

Implev•entation Status of 

Bssfor Improvement Improvement 

Description of fire-related plant improvrements cited in the IPEEE submittal WPEEE IPEEE Have Plan to Being Not 

Plant (regardless of status or source) Fire SeismiclFire Other imp]. JInpi. Evalu. Reject Stated 

ANO l&2 None cited. 

Beaver Valley 1 Cable Tunnel (CV-3) Fire CDF Key Contributor: reroute river water pump power cable. X X 

Beaver Valley 1 Cable spreading room (CS-1) Fire (SW comer) Key CDF Contributor: refine emergency X X 

switchgear room heat up analysis to provide additional time margin. 

Beaver Valley 1 Primary auxiliary building General Area E (PA- 1E) Fire Key CDF Contributor: reroute CCR X X 

pump or high head safety injection (HHSI) suction MOV cables. 

Beaver Valley 1 Cable Spreading Room (CS-1) Fire (NE comer) Key CDF Contributor: reroute river water X X 

or auxiliary river water pump power and control cables. 

Beaver Valley 1 Normal Switchgear Room (NS-1) Fire (South Wall) Key CDF Contributor: reroute river water X X 

pump control cables or Auxiliary river water pump power cables. 

Beaver Valley 2 Control Room (CB-3) Fire Key CDF Contributor: provide operator credit for recovery of X X 

auxiliary feedwater from outside the control room. 

Beaver Valley 2 Cable Tunnel (CT-1) Fire Key CDF Contributor: install qualified fire barriers between fire X X 

areas Communication, Instrumentation, and Relay Room (CB-1), Cable Spreading Room 

(CB-2), and Cable Tunnel (CT-1). 

Beaver Valley 2 Normal Switchgear Room (SB-4) Fire Key CDF Contributor: install an automatic CO2 fire X X 

suppression system. 

Beaver Valley 2 West Cable Vault Area Elevation 735' (CV- 1) Fire Key CDF Contributor: reroute purple train X X 

service water pump/MOV power and control cables. 

Beaver Valley 2 West Cable Vault Area Elevation 755' (CV-3) Fire Key CDF Contributor: reroute orange train X X 

CCP/thermal barrier cooling MOV and service water power and control cables. 

Big Rock Point Modifications performed in response to Fire Protection and Appendix R Modifications: fire SRP (Section X 

doors added or replaced in the machine shop, access control to turbine building stairway and 9.5.1) & 

electrical equipment room. In addition, a fusible link closure device was added to the third Appendix R 

floor hallway to the turbine building, to IOCFR50 

Big Rock Point Modifications performed in response to Fire Protection and Appendix R Modifications: SRP (Section X 

smoke and or fire detectors were added to the emergency diesel generator room, screenhouse, 9.5.1) & 

control room, electrical equipment room, condensate pump room, control rod drive Appendix R 

accumulator area, core spray pump room, shutdown heat exchanger room, and the reactor to 10CFR50 

recirculating water pump room. 

Big Rock Point Modifications performed in response to Fire Protection and Appendix R Modifications: fire SRP (Section X 

hose reels were installed in the interior cable penetration area and the reactor cooling water 9.5.1) & 

pump and heat exchanger room. Sprinklers were added in the reactor recirculating water Appendix R 

pump room. A valve hose connection manifold was added to the discharge of the diesel fire to IOCFR5O 

uIriln
Table 3.5: Fire-related plant improvements (Continued)

IV1UUIMUaunis perIormeu in response to lire Protection and Appendix R Modifications: fire 

barriers or fire stops were added to the following locations, as applicable. Typical openings sealed include: (1) Locations where cable trays penetrate walls, ceilings, and floors. (2) Locations where conduit or pipe provide an opening between a wall, ceiling, or floor. (3) Large openings in walls or between walls where concrete fill is not applicable or desirable. 

(4) Openings between vent ducts and walls, floors, or ceilings.

NKr (Nection 

9.5.1) & 

Appendix R 

to 10CFR50

Big Rock Point Modifications performed in response to Fire Protection and Appendix R Modifications: SRP (Section X Electrical switchgear was modified to protect the energized equipment from the effects of fire 9.5.1) & protection sprinkler spray. Modifications included: (1) Sealing non-ventilation openings and Appendix R hardware mountings, (2) Installing shields over ventilation louvers, and (3) Installing shields to 1 OCFR50 

to totally cover transformers. 

Big Rock Point Modifications performed in response to Fire Protection and Appendix R Modifications: SRP (Section X installation of self-contained battery lighting units for vital safe-shutdown areas and access 9.5.1) & 

ways. Appendix R to 1OCFR50 

Big Rock Point Modifications performed in response to Fire Protection and Appendix R Modifications: SRP (Section X smoke and heat removal unit installed above vent duct chase on roof of the electrical 9.5.1) & equipment room. Appendix R to 1OCFR50 

Big Rock Point Modifications performed in response to Fire Protection and Appendix R Modifications: fire SRP (Section X dampers were installed in large vent ducts where they penetrate fire barriers. A manual smoke 9.5.1) & damper was installed in control room ducts. Appendix R 

to IOCFR50 

Big Rock Point Modifications performed in response to Fire Protection and Appendix R Modifications: SRP (Section X design and installation of the alternate shutdown system. Included is the design of the 9.5.1) & electrical system and the alternate shutdown building. Appendix R 

to 1OCFR50 Big Rock Point The fire penetration, barriers and doors were inspected during the performance of the X X T545-01 Procedure, Fire Door and Fire Damper Inspection: fire barriers were identified and 

labeled in response to this notice and also identified on applicable plant drawings. Initial 

inspection identified some deficiencies which have been corrected. 

Big Rock Point Requirement that the safe shutdown circuits are physically independent of, or can be isolated X X from, the control room in the event of a fire affecting equipment control from the control room: circuit separation was accomplished with the installation of the alternate shutdown 

system (ASD). There are two methods identified for safe shutdown cooling after a fire. One method involves the reactor depressurization system (RDS) in conjunction with the core spray system (CSS). The second method involves using the Emergency Condenser Systems 

__(ECS).

0O
Table 3.5: Fire-related plant improvements (Continued)

Braidwood 1 & 2 None cited. 

Browns Ferry 1, 2, 3 None cited. 

Brunswick l&2 None cited. 

Byron 1&2 None cited 

Callaway The main control room has an overall core damage frequency of 2.65E-06/ry: NEI closure X X 

guidelines recommend that severe accident management guidelines (SAMG) be put in place 

with emphasis on prevention/mitigation of core damage. (Note: The NEI recommendation 

is not needed. The NRC found the design and procedures associated with the control room 

to be acceptable during an extensive NRC review prior to Callaway's receipt of its Operating 

License. Since that time, no substantive changes have been made to the control room design 

or procedures.) 

Callaway The main control room has an overall core damage frequency of 2.65E-06/ry: the SAMG X X 

effort at Callaway will develop responses to spurious actuations which can result from a 

control room fire. Emphasis will be on those actions that need to be accomplished outside the 

control room to mitigate spurious actuations caused by a fire confined to a cabinet (e.g., loss 

of seal injection due to a hot short in the control circuitry associated with the seal injection 

line containment isolation valves). These actions outside the control room will permit the 

control room operators to safe shut down the plant from the control room. 

Callaway For two safety-related ac switchgear rooms with CDFs of 2.26E-06/yr and 1.29E-06/yr, NEI X X 

closure guidelines recommend that SAMG be put in place. (Note: There are no obvious 

recovery actions that will reduce core damage frequency. The fire areas are equipped with 

area-wide suppression which is effective. These is also a great deal of uncertainty in the fire 

ignition frequencies and the extent of damage to key components. In addition, the overall 

SAMG effort will focus on recovery of failed equipment. Emphasis will be on those actions 

that need to be accomplished outside the control room. The overall Callaway SAMG effort 

is sufficient to reduce the impact of a fire in either of these fire areas.) 

Calvert Cliffs Smoke infiltration into the main control room via ventilation intake: applicable procedures X X 

will be revised to direct the MCR operator to place the MCR and cable spreading rooms 

(CSRs) into recirculation if it appears likely that smoke could be drawn into the MCR 

ventilation intake. Operator training was also initiated.
Table 3.5: Fire-related plant improvements (Continued)

Implementation Status of 

Basis for Improvement Improvement Description of lire-related plant improvements, cited in thme IPEEE submittal IPEEE IPEEE Have Plant to Being _ FNot Plant (regardless of status or source) Fire Seismic/Fire Other Impi. Imp]. Evalu. Reject Stated Calvert Cliffs Inadvertent isolation ofthe switchgearroom and CSR ventilation: improvement in procedural X x direction and training for the operators was initiated. The procedures will direct that the cable 

spreading rooms and switchgear ventilation systems be restored following an inadvertent 

actuation. Measures were also being taken to place these ventilation systems in recirculation 

for fires outside the cable spreading room and switchgear rooms if smoke from a fire external 

to them has potential for getting into the ventilation intakes. In addition, the switchgear room ventilation systems were to be evaluated for a method to ensure effective recovery from 

inadvertent actuation of Halon. A realistic switchgear room heat-up model was to be 

developed and was expected to show that there is considerable time available to recover the 

loss of ventilation. An evaluation based on the new heat-up model will determine if 

modifications or procedure changes are required to: (1) either prevent the loss of ventilation 

or (2) restore ventilation. 

Calvert Cliffs Fire barriers and components, such as fire dampers, fire penetration seals and fire doors, were X X 

not included in the plant surveillance and maintenance program: incorporate them into an appropriate control and/or inspection program. 

Calvert Cliffs Hot work in cable chases at power: procedure change has been initiated adding restrictions X 

to hot work in cable chases. 

Catawba 1 & 2 A fire in a Diesel generator load sequencer could cause load shed of a 4160 volt bus: a X X 

procedure enhancement has been made by placing additional instructions in the pre-fire plant for the ETB switchgear area. Catawba I & 2 Sufficient redundancy for fires: replace reciprocal air compressors with centrifugal X 

compressors and the cables for the newly installed instrument air compressors are to be 

routed. 

Catawba 1 & 2 Auxiliary shutdown panel NEMA 4 cabinets are missing door bolts: reinstall bolts. X X Clinton Response to generic letter 92-08, "Thermo-Lag 330-I Fire Barriers": cables routed from Generic X Division 2' inverter through the Division 1 cable spreading room and then through the Letter Division 3 switchgear room have been rerouted. 92-08 (Fire) Columbia The recovery of the critical ac buses SM-7 and SM-8 was shown to be significant in reducing X X 

Generating* fire induced CDF: this recovery action is proceduralized and it has been recommended that 

specific training scenarios be included in the operator training. 

Comanche Peak 1&2 None cited. 

Cook l&2 None cited. 

Cooper Fires in board C and vertical board F in the MCR were identified as completely disabling the X X 

control of switchyard breakers: licensee indicated that they were examining additional 

(unspecified) features that would allow for control of the switchyard breakers either from the 

switchyard itself or from an alternate area, or have a preplanned recovery/repair action in 

place.

t'
Table 3.5: Fire-related plant improvements (Continued)

/5C Ii1 UIn c av phuiip lIvuua b t.u* L lavm a,11 vi t ) -lt Fv JUlIFlO3 -uIa. -I V u U- tI vA-L.-vml tA 

fire water pumps, especially if the fire suppression system fails: licensee is examining the 

feasibility of providing the SW system with water supplies that are diverse from the pumps 

in the SW pump room.

Crystal River 3 Two transient fire storage areas, sources were in a specific location and were significant X X 

contributors to total core damage risk due to fire: place administrative limits on. 

Davis-Besse Inadequate mounting of two cylinders containing compressed flammable gas were identified: X X 

licensee will take actions to address this. 

Davis-Besse The licensee noted that four plant compartments had calculated bounding core damage X X 

frequency values above the screening criterion of 1E-6/ry after completion of the fire 

analysis: The Severe Accident Closure Guidelines were reviewed to ascertain the relative 

importance of these estimations. The Closure Guidelines indicate that for fire compartments 

that fall in this CDF range (1E-06 to 1E-05), the licensee should ensure that severe accident 

management guidelines will be in place with emphasis on prevention/mitigation of core 

damage or vessel failure, and containment failures. Licensee will review the fire response 

procedures associated with these areas to ensure that specified actions are optimized with 

respect to maintaining overall plant risk as low as reasonably achievable. 

Diablo Canyon Control room fire located in cabinets that could result in loss of CCW or auxiliary saltwater X X 

(ASW) systems: modify control room evacuation procedure to require the reactor coolant 

pumps to be tripped. 

Diablo Canyon Diesel generator 1-3 could only support the vital ac F bus of one unit if needed during a plant X X 

transient: add a sixth emergency diesel generator which allows each vital ac bus to be 

supported and increases the availability of backup power for vital ac bus F. Installation of 

the sixth diesel is calculated to have reduced the contribution of loss of offsite power events 

to the overall core damage frequency and to have reduced the likelihood of ASW or CCW 

system failures leading to a loss of RCP seal cooling. 

Diablo Canyon A single failure of the motor-operated discharge damper could have failed the 480V X X 

switchgear ventilation system: make a design change. 

Diablo Canyon Ensure the RCP seal cooling is maintained to prevent RCP seal LOCAs: revise operating X X 

procedure. 

Diablo Canyon Improve the reliability and availability of the plant process protection system: upgrade Eagle X X 

21 Process Protection System and eliminate resistance temperature detector (RTD) bypass to 

reduce plant downtime and radiation exposures to plant personnel. 

Diablo Canyon Instrument inverter fails: replace instrument invertors with invertors of increased capacity, X X 

increase reliability by including automatic backup switching (static switch). 

Dresden 2&3 None identified. I I I

(A
Table 3.5: Fire-related plant improvements (Continued)

iwo air nanolers in tne I-L.I room were iwentitied as flood/spray outliers because nearby 

piping could potentially impact fire protection sprinkler piping and break off the sprinkler 

heads, spray from the sprinkler heads could damage the air handlers' motors: evaluate 

further. (Calculation determined that it is adequate as-is.)

Duane Arnold Unrestrained nitrogen gas bottles near MCC could fall over and cause missiles or fires: secure X X 

bottles. 

Duane Arnold Gas bottles stored adjacent to chiller could fall over during a seismic event and initiate a fire X X 

or missile: remove bottles from area. 

Duane Arnold Unavailability of one train of the river water system due to maintenance in the essential X X 

switchgear rooms: optimization of the river water system maintenance outage time and 

staging or readying of fire hoses. 

Duane Arnold A rupture of fire protection pipe (2" or 4" in diameter) located in the HVAC room above the X X 

control room could cause flooding of the HVAC shaft which could cause subsequent collapse 

of the ductwork in the shaft and establish a substantial flow rate into the essential switchgear 

rooms via the HVAC ductwork leading to direct failure of the key electrical equipment 

controlling safe shutdown or flooding of the control building basement rooms, and 

subsequent failure of the key electrical equipment: modify piping design to eliminate the 

flooding sequences by converting the two fire protection pipes in the HVAC room into "dry 

pipe systems each of which have a manually controlled valve located outside the HVAC 

room for control of water to each pipe system." 

Duane Arnold Cables for Division II equipment (required for the remote shutdown of the plant) pass through X X 

cable spreading room: reroute cables. 

Farley The RCP seals require cooling from either component cooling water (CCW) to the RCP X X 

thermal barrier heat exchanger, or seal injection flow from the charging pumps. Loss of both 

of these sources for a prolonged period is expected to cause RCP seal failure resulting in a 

LOCA. Loss of the operating (on-service) train of CCW, which can be caused by failures 

within CCW or support systems, such as the SW system, or the electrical distribution system, 

results in loss of RCP seal cooling almost immediately. It also results in loss of cooling to 

the running charging pump, which will cause charging pump failure and, thus, loss of seal 

injection flow in a relatively short time: implement procedure enhancements to improve 

operator response capability for fire events which can lead to a loss of RCP seal cooling. 

Install high temperature O-rings for Units 1 and 2 RCPs during maintenance overhauls. 

Expected to provide a substantial reduction in CDF to fire scenarios involving electrical 

I switchgear rooms or electrical penetration rooms.
Table 3.5: Fire-related plant improvements (Continued)

Farley If cooling from the on-service CCW train fails, but the standby train is available, the X X 

operators can establish seal cooling by manually starting the standby CCW train and 

manually aligning the miscellaneous CCW header (which provides RCP thermal barrier heat 

exchanger cooling) to that train. This action was estimated to require at least 20 minutes, 

which was judged to be too long to ensure RCP seal integrity without injection. However, 

RCP seal injection can be maintained for a prolonged period by starting the standby charging 

train and aligning charging pump suction to the RWST to maintain a cool water source. This 

requires operation of the normally operating charging pump, without cooling for a short time, 

while the alternate alignment is made: revise appropriate abnormal operating procedure 

(AOP) to include instructions directing the FNP operators to perform one of several 

sequences of steps, depending on available equipment, to maintain RCP seal cooling in the 

event of fires in the electrical switchgear. The pertinent steps include aligning charging pump 

suction to the RWST, and isolating RCP seal return flow to minimize heat-up of the injection 

flow due to the addition of pump heat in the charging pump mini-flow line. 

Farley CCW to the RCP thermal barrier heat exchangers is provided from the miscellaneous header, X X 

which is aligned to the on-service CCW train A (supported by train-dedicated CCW pump 

C and swing CCW pump B). If the on-service CCW pump A fails due to loss of train A SW 

support and the standby train CCW pump A fails, it is possible to restore CCW cooling to the 

standby train B charging pump by realigning swing CCW pump B to discharge through the 

train B CCW heat exchanger. Realignment of the swing CCW pump B from train A to train 

B normally requires that both the electric+A352cal power alignment and the mechanical 

alignment be changed. The total time to complete this action was estimated to be at least 20 

minutes, which was judged to be too long to ensure RCP seal integrity without injection or 

thermal barrier cooling. However, with both trains of electrical power available, it is possible 

to restore CCW flow to the train B charging pump by allowing the swing pump to be powered 

by train A while it is mechanically align to the train B CCW heat exchanger: revise 

appropriately AOP, as necessary, including the addition of a caution statement for response 

to fire in the SWIS to inform the operators that electrical realignment of the swing CCW 

pump may be delayed if required by plant conditions. The pertinent steps include aligning 

the discharge flow from swing CCW pump B to the train B CCW heat exchanger.

Farley Fires in the electrical penetration rooms can result in inadvertent movement of the normally X X 

open, motor-operated SW supply valve to the CCW heat exchanger. This can result in loss 

of RCP thermal barrier cooling if the SW supply to the on-service CCW heat exchanger 

inadvertently closes: add steps to the appropriate AOP to instruct operators to locally verify 

that the SW supply valve to the on-service CCW heat exchanger is open in the event of a fire 

in the electrical penetration room associated with the on-service train.
Table 3.5: Fire-related plant improvements (Continued)

Implementation Status of 

Basis for Improvemjent Improvement 

Description of lire-related plant improvements cited in the IPREE submitalts IPEEE IPREEE Have Plan to Being Not 

Plant (regardless of status or source) Fire Seism.ic/Fire Other Imp. Imp). Evalu. Reject Stated 

Farley Room cooling is required for continued operation of the motor driven AFW (MDAFW) X X 

pumps following an initiating event. Room cooling for the MDAFW pumps is supplied by 

train-oriented room coolers, which require the support of the SW system and the 600V 

emergency ac distribution system: add steps to appropriate AOP to direct operators to initiate 

action to monitor pump room temperatures and establish temporary ventilation if MDAFW 

pump operation is required following a fire in the SWIS or auxiliary building fire area. 

Fermi An unscreened compartment leads to the fire insight that dominating contributors are cabinets X X 

used for dedicated shutdown whose loss would isolate the affected equipment from the main 

control room thereby causing loss of equipment function: even though adequately covered 

by current operator training, additional fire brigade drills in the vicinity of these cabinets are 

planned to increase the brigade's awareness of the need to quickly isolate and extinguish such 

fires. 

FitzPatrick Reduce the contribution of reactor building fires to the CDF: addition of keylock bypass X X 

switches to allow opening of valves IOMOV-25A/B and 14MOV-12A/B. Also, plant fire 

procedure AOP-28 directs the operators to use the switches if necessary and includes a 

tabulation of potentially unavailable equipment in each fire zone. 

FitzPatrick Fire-induced core damage resulting from fires in the cable spreading room: evaluate whether X X 

the heat detectors which automatically initiate C0 2 suppression in the cable spreading room need to be relocated from the bottom of the ceiling beams (approximately 2 ft below the 

ceiling) to the ceiling, placing detectors on both sides of ceiling beams. This action could 

potentially achieve a 66% reduction in the dominant contributor of fire-induced core damage 

resulting from fires in the cable spreading room. 

FitzPatrick Contribution of fires attributable to transient combustibles: revised AP14.02, "Combustible X X 

and Flammable Material Control," to impose strict limitations on the use of unattended 

combustible materials in the Cable Spreading Room. (Details requirements for the use and 

storage of combustible and flammable materials within the power block and applicable 

adjacent areas. Under the provisions of this procedure, transient combustibles in the cable 

spreading room require the approval of a qualified individuals on the fire protection staff.) 

Fort Calhoun Hydrogen piping, fuel oil, seal oil tank, & flammable storage area in turbine building, CDF X X 

of a O.1g event causing turbine building failure due to hydrogen fire/explosion was 

determined to be 6.87E-08/ry. (Low CDF, no further evaluation done.) 

Fort Calhoun Flammable liquid cabinets are located throughout the plant: move cabinets out of critical area X X 

or determine if cabinets can be anchored. 

Fort Calhoun A control room fire occurs that does not require control room evacuation: revise AOP-6 to X X 

instruct operators to de-energize the PORVs. 

Fort Calhoun Control room fire initiates an interfacing LOCA system: if feasible, remove power from X X 

HCV-347 and HCV-348.
Table 3.5: Fire-related plant improvements (Continued)

Implementation Status of 

Basis for lImprovemient Improvement 

Description of lire-reated plant improvements cited in the IPEEE submittal IPE1EE IPEEE Have Plan to Being Not 

Plant (regardless of status or source) Fire Seismie/Fire Other lInpl. Impi. Evalu. Reject Stated 

Ginna Fuses will be installed on control circuits routed in the screen house associated with the X X 

functioning of 41 60V ac circuit breakers: the fuses will be designed to open if grounding 

occurs, as is postulated to occur for screen house fires, permitting the over current protective 

function of the circuit breakers to remain intact. 

Ginna Perform local recovery of the pressurizer heaters if control of the heaters is lost from the X X 

control room (the pressurizer heaters are one means of providing long-term RCS circulation): 

enhancement to an operating procedure. 

Ginna A spurious opening of MOV 857B fails RHR closed cycle cooling: insertion of a warning in X X 

the alternate shutdown procedure ER-FIRE. 1 was being considered to indicate that this valve 

may need to be closed locally. 

Ginna Transient combustibles storage in the auxiliary building basement: installation of additional X X 

sealed containers for combustibles storage was being considered. 

Ginna Spurious opening of MOVs 850A and 850B due to hot shorts can lead to draining of the X X 

RWST volume into the containment sump: methods to reduce this potential were being 

considered in combination with a similar modification of MOV 85713. 

Ginna Assist operators in switching to sump recirculation, particularly for fire scenarios in which X X 

the Control Room is evacuated: installation of a local pressure gauge to permit RWST level 

measurements to be obtained in the event that electrical RWST level sensors are damaged by 

fire. 

Ginna House heating boiler was found to be inadequately anchored and thus could shift during an X X 

earthquake causing damage to the attached natural gas line: implement design change to 

anchor the boiler. 

Ginna Several locations were identified where block wall failures could result in the release of X X 

combustibles - an oxygen line in the auxiliary building, a hydrogen line and valve station in 

the intermediate building, and hydrogen cylinders in the turbine building: the oxygen line 

does not pose a significant risk because it is only connected after an accident, the hydrogen 

line is not a risk since it is not valved on during power operation. The hydrogen cylinders do 

not pose a risk since the hydrogen is diluted with nitrogen and any release would thus result 

in a low hydrogen concentration. 

Ginna Failure of block walls potentially causing the actuation of two fire suppression systems: the X X 

inadvertent actuation of a deluge system in the relay room would not have a significant 

impact since the relay cabinets are closed on top and the cable penetrations are sealed. 

Actuation of a deluge system in the intermediate building would only spray the turbine-driven 

AFW pump. Seismic actuation of a pre-action system in the same area was dismissed because 

of the existence of fusible link sprinkler heads in the system. 

Ginna Failure of block walls between the service and intermediate buildings and between the turbine X x 

and intermediate buildings during an earthquake could impact the fire protection of safety

_______________related equipment: licensee says the potential for fires initiated in these areas is small.
Table 3.5: Fire-related plant improvements (Continued)

Implementation Status of 

Basis for Improvement Improvement 

Description of fire-related plant improvements cited in the IPEEE submittal IPEEE IPEEE Have Plan to Being Not 

Plant (regardless of status or source) Fire Seismic/Fire Other Impl. Impl. Evalta. Reject Stated 

Ginna PSA identified a fire scenario in the DG B vault, located beneath the DG B room, in which Fire, PSA X 

both trains of ac electric power could be affected. Basically, a worst-case fire could fail the 

B electrical train and fail offsite power and all control power to Bus 18 of the A electrical 

train (DG A would still remain available). This, in turn, would result in the loss of all SW: 

ACTION report 99-948 was generated to evaluate the scenario. The result of the ACTION 

report was to recommend consideration of procedural changes to instruct plant personnel to 

manually close the required Bus 18 breakers to prevent leaving the plant in a station blackout 

condition. 

Grand Gulf None identified. 

Hatch Regulatory issues associated with the use of Thermo-Lag fire retardant: cable rerouting X X 

modification. 

Haddam Neck Relatively high probability of diesel B unavailability: develop procedure for connecting air X X 

cooled DG. 

Haddam Neck Potential coincidental loss of dc bus A and BX due to their spatial proximity: develop X X 

procedure to deal with the loss of dc buses A and BX. 

Haddam Neck Cable vault and cable spreading area - large consequences of a fire in an area where there is X X 

a high concentration of cables of both trains A & B: change training philosophy to increase 

sensitivity to and awareness of transient combustibles and maintenance activities in the cable 

spreading area and cable vault to same level as for control room and switchgear rooms. 

Haddam Neck Cable spreading area cable separation concerns: installation of additional sprinkler heads on X X 

trays where numerous cable sprays are stacked above each other. 

Haddam Neck Trains A & B control cable separation in the control room and cable spreading area: improve X X 

AOP 3.2.57 for recovery from control room, switchgear room A and cable spreading area 

fires. Also, for the cable spreading area revise procedures for 'A' charging pump so that it can 

be credited for fire scenario in cable spreading area. 

Haddam Neck Trains A & B cable separation in PAB corridor (trays CI and C7) for charging pump X X 

supports: re-route either charging pump B main or auxiliary lube oil pump cables. 

Haddam Neck Vertical unanchored waste oil tank in the waste oil area can topple over flammable liquid X X 

containers in that area: installation of additional anchorage to prevent toppling. 

Haddam Neck End of bottle of Carbon Dioxide fire suppression system for containment cable vault requires X X 

restraint modification (N 94-12): modify end bottle restraint to adequately restrain bottle. 

Haddam Neck Batteries to the diesel fire pump require restraining: installation of anchorage to prevent X X 

battery movement. 

Haddam Neck Lack of electrical separation in switchgear room A: built a new switchgear building with Fire PSS, X 

cable separation between trains A and B for most of the safe shutdown systems. Feb. 1986 

Haddam Neck Dependence of both ECCS trains on a single motor control center: built new Switchgear Fire PSS, X 

building that includes the capability to shutdown from the alternate shutdown panel. Feb. 1986

00
Table 3.5: Fire-related plant improvements (Continued)

"Elautudil IMK rour -+Oi/45UV onl tilea transformers: replace with dry transformers. 

Hatch 1 & 2 None identified. 

Hope Creek None identified. 

Indian Point 2 None identified. 

Indian Point 3 Eliminate susceptibility of multiple EDG exhaust fans (and thus multiple EDGs) to fire within a single fire zone: realign the power feeds to the EDG exhaust fans and auxiliaries. 

Indian Point 3 Reduce the susceptibility of the plant to switchgear room fires: recommend that the area wide, total flooding CO 2 fire suppression system within the switchgear room be restored to 

automatic actuation. 

Kewaunee None Identified 

LaSalle l&2 A RCIC "sneak circuit" could cause the isolation of RCIC each time a loss of offsite power 

occurred. Under these conditions a false, loss-of-power induced high RCIC room temperature signal was generated and the in-board ac-powered isolation valve received a signal to close. 

However, the valve could not close because it had no ac power. When ac was restored to the 

valve, a relay race ensued, and the relay associated with room high temperature was energized before the loss of power contact opened. The valve would shut, isolating RCIC 

because it "sensed" RCIC room high temperature before it "sensed" a loss of power. This 

event could occur during station blackout, loss of offsite power or due to a loss of a train of ac power: changes were made to LaSalle Procedure LOA-AP-07, "Loss of Auxiliary Electrical Power," to identify the sequence of events which will result in the non-recoverable 

isolation ofthe RCIC inboard steam isolation valve. In addition, the operators receive training during every training cycle targeted specifically at the "sneak circuit" concern. LaSalle l&2 RCIC room temperature isolation logic, in cases where train A ac power has failed but train 

B ac power is available, isolates if no other emergency core cooling system is working: change the RCIC room temperature isolation logic so that, in cases where train A ac power has failed but train B ac power is available, RCIC does not isolate if no other emergency core cooling system is working.

XX

II
Table 3.5: Fire-related plant improvements (Continued)

Implementation Status of 

Basis for Improvement Improvement 

Description of fire-rclated plant improvements cited in the IPEEE submittal TPEEE, lPlEEE Have Plan to~ Being Not 

Plant (regardless of status or source) Fire Seismic/Fire Other Impi. Impi. Evain. Reject Stated 

LaSalle 1&2 For long-term containment heat removal accidents and ATWS sequences, decay heat can be X X 

removed by venting the containment. The use of a rubber boot connecting the vent pipe to 

the standby gas treatment system results in steam being released into the reactor building 

which creates a severe environment for components. This severe environment can affect the 

ability of the systems to perform their functions. The degree of this impact will depend on the 

environment produced and the qualification of the equipment subject to the severe 

environment: the IPE submittal does not contain specific criteria for resolution of the DHR 

vulnerability issue. (Procedures exist to use the fire protection system's water supply as an 

alternate water supply for vessel injection. The EOPs provide several different means of 

vessel depressurization. Revision 4 of the BWR Owners Group Emergency Procedures 

Guidelines has been implemented. A hardened vent path does exist.) ___ _____ _____ 

Limerick 1 &2 Plant improvements that allow fire areas to be screened out: designate fire compartments 1 X X 

(corridor areas, recombiner rooms, backwash tank and pump rooms, recombiner access area, 

water analyzer rooms), 7 (4 kV switchgear corridor), 22 (Unit 1 cable spreading room) and 

23 (Unit 2 cable spreading room) as transient combustible-free zones. 

Limerick 1 &2 Plant improvements that allow fire areas to be screened out: Replace wood scaffolding with X X 

metal scaffolding and revise procedures to prevent further use of wood scaffolding. ____ ______ _____ 

Limerick 1&2 Plant improvements that allow fire areas to be screened out: the combustion control procedure X X 

will be revised to provide more conservative combustible control guidelines in safety-related 

areas within the reactor enclosures. 

Limerick 1&2 Plant improvements that allow fire areas to be screened out: additional doors will be X X 

administratively controlled by the Hazard Barrier Procedure as "fire" doors to limit the 

amount of air available for cumbustion. The existing doors are fire rated. 

Limerick 1&2 Thermo-Lag issue: plant changes not specified. X X 

Limerick 1&2 Fixed combustibles present a fire risk impact in fire compartments 2 (13.2 kV switchgear X X 

room), 20 (U~nit 1 static inverter room), and 26 (remote shutdown panel room): increase fire 

brigade drill activities and brigade awareness in these areas. These fire compartments were 

reviewed against the NEI 9 1-04 closure guidance and procedural changes were deemed 

_______________appropriate. __________ 

Maine Yankee Recommended enhancements as a result of the fire analysis: Abnormal Operating Procedures, X X 

"Plant Shutdown Plan for Fire in Containment, Spray Pump Area, Steaml/Feed Valve House, 

Containment Electrical Penetration In South Elevation 46'," will be updated to indicate: (1) 

that the potential exists for steam generator low pressure (SGLP) isolation in the event of a 

fire in the main steam and feedwater valve house, and (2) to indicate that there is the potential 

to hot short open containment penetrations 64, 65, and 66 to manually isolate the main steam 

______________drains, if open. [IPEEE, pg. 4-239] ________ _____

0
Table 3.5: Fire-related plant improvements (Continued)

Implementation Status of 

Basis for Improvement Improvement 

Description of fire-related plant improvements cited in the IPEE~E submittal IPEEE lPEEE Have Plan to Being Not 

Plant (regardless of status or source) Fire Seismic/Fire Other Imp... Imp]. Evain. Rej"et Stated 

Maine Yankee Recommended enhancements as a result of the fire analysis: AOP, "Plant Shutdown Plan for X X 

Fire in Control Room, Control Room Cable Chase, Protected Cable Vault, Protected Cable 

Tray Room, and Protected Switchgear Room," will also be updated to: (1) indicate that the 

potential exists for an SGLP trip isolation (dual loss of vital buses), in the event of a fire in 

the protected cable tray room and the protected switchgear room, and (2) to indicate that there 

is the potential to hot short open containment penetrations 23, 24, 39, 60, 64, 65, 66, and 92 

and that valves are available to manually isolate these leak paths. 

Maine Yankee Recommended enhancements as a result of the fire analysis: AOP, "Plant Shutdown Plan for X X 

Fire in Reactor - MCC - Elevation 21' and 33' Containment Electrical Penetration Room 

North Elevation 46'," will be updated to warn the operator about the possibility that 

disconnecting power to MCC-7B and MCC-8B would result in removing power to HPSI 

suction valves from the RWST. If a such open PORV results in a safety injection signal, and 

the HPSI suction valves are closed and de-powered, the HPSI pumps could fail due to the loss 

of suction. The problem can be avoided if the HPSI suction valves are opened prior to 

removing power from MCC-7B and MCC-8B. 

Maine Yankee Recommended enhancements as a result of the fire analysis: AOP, "Plant Shutdown for Fire X X 

in Turbine Hall or Circulating Water Pump House," will specifically indicate that the 

protected switchgear room could be affected because of a loss of HVAC due to a fire in the 

turbine building and the need for temporary measures to maintain cooling. 

Maine Yankee Station operating practice is to isolate the hydrogen supply at the tube trailer after filling the X X 

generator and volume control tank (VCT): in order to provide more positive control, the 

station administrative procedure was updated to reflect this requirement. 

Maine Yankee Fires (and potentially floods) in the control room, cable vault, protected cable tray room, X X 

protected SWGR and EFW pump room have the potential to cause multiple hot shorts or 

power failures to both in-board and out-board containment isolation valves: incorporate 

guidance into Severe Accident Management Guidelines being developed. 

Maine Yankee AFW availability is functionally important to mitigation of various external events: take X X 

actions to improve AFW availability. 

McGuire l&2 None identified 

Millstone 1 N/A 

Millstone 2 Oil fires involving main condenser vacuum pump, transformer, main feedwater pump or X X 

turbine generator located in the turbine building: reroute turbine driven auxiliary feedwater 

(TDAFW) control cable to remove it from turbine building fire area.
Table 3.5: Fire-related plant improvements (Continued)

Implementation Status of 

Basis for Improvement Improvement 

Description of fire-related plant improvements cited in the IPEEE submittal WPEEE IPlEEE Have Plan to Being Not 

Plant .(regardless of status or source) Fire Seismic/Fire Other Inmpl. Impi. Evain. Reject Stated 

Millstone 2 Fire disabling the "B" turbine building component cooling water pump, "A" and "C" turbine X X 

building component cooling water pumps, or the turbine generator: eliminate dependence of 

service water (SW) and the "C" SW pump power cable for emergency diesel generator 

cooling by installation of a permanent cross tie pipe between fire protection and SW to the 

EDG cooling connection. This modification ensures that ac power will remain available in 

the event that a fire disables all three pumps by eliminating EDG dependence upon service 

water. 

Millstone 2 Large quantities of transient combustibles (protective clothing) in open storage racks placed X X near concentration of cable trays: reduce quantity; store in enclosed fire-related lockers, 

and/or remove from area. 

Millstone 2 MP2 relies on the MPl fire suppression system for fire protection. The seismic capacity of X X 

the MP1 diesel fire pump fuel tank may not be adequate. Fires generated as a result of 

earthquakes are common. Fire pumps driven using offsite power cannot be depended upon 

since most earthquakes result in a loss of offsite power: perform additional evaluation to ensure seismic adequacy. If determined to be inadequate, perform modification to improve 

seismic ruggedness. 

Millstone 2 A long run of fire water header system piping along the turbine building's north wall appears X -- x to have a very low seismic capacity because the pipe run is inadequately attached to its 

supports: attach pipe to its supports adequately. 

Millstone 2 The block wall construction of the fire pump house (shared by MPland MP2) may not X X 

provide adequate seismic ruggedness: evaluate ruggedness and, if ruggedness is low, enhance 

the structure. 

Millstone 3 None identified 

Monticello None identified 

Nine Mile Point 1&2 Fire and high winds can lead to SBO scenarios where recovery is not likely for much longer X X 

than the 8 hours currently considered for SBO mitigation: enhance operator training on procedure N1-SOP-14, "Alternate Instrumentation," to include station blackout mitigation 

without dc power. 

Nine Mile Point 1&2 Cables associated with both divisions of emergency ac, dc, and various front-line systems X X 

(i.e., feedwater) are located in the southeast corner of the turbine building (elevation 261V), a number of combustibles are in this immediate vicinity. These combustibles included: five 

drums filled with oily rags, paint cans, bags of trash, electronic equipment, and aerosol spray cans: storage of combustibles in this area should be curtailed or more tightly controlled. 

Nine Mile Point 1&2 Instrument air is required to align containment vent and containment spray in the torus X X 

cooling mode. Containment vent valves could be opened with handwheels. Containment 

spray valves currently fail as is (normally open) on loss of instrument air and have no handwheels for manual operation: add manual handwheels to valves so operators could align ______________ torus cooling without instrument air.

i'~
Table 3.5: Fire-related plant improvements (Continued)

The criteria suggest that a relatively insignificant event could lead to evacuation. This creates 

uncertainty with regard to what conditions really lead to evacuation, yet the control room is 

the preferred location for plant recovery. Once the remote shutdown procedure is entered, one 

interpretation would be that the control room is evacuated, yet a more likely situation may 

be to use the remote shutdown panel to enhance plant recovery. Giving up control of reactor 

inventory in the control room when only long term heat removal needs recovery from outside 

the control room is not considered an appropriate strategy. Given that the remote shutdown 

panel is being used due to control room conditions, it is likely to be outside the event-driven 

remote shutdown procedures and utilization of the EOPs is not explicitly addressed: 

Operations decided to make the following revisions: (1) to ensure that the control room 

would be evacuated only under extreme conditions, the symptoms indicative of conditions 

requiring entry to N2-SOP-78 "Remote Shutdown" have been revised and the procedure 

explicitly states the senior shift supervisor determines whether the control room is 

uninhabitable. (2) Although the SOP mentions the use of the RHR in a "pseudo" LPCI mode, 

there is no explicit guidance. Revision of the procedure is being considered. (3) A satellite 

master copy of N2-EOP-RPV has been placed in the remote shutdown rooms to ensure the 

operators have adequate guidance when the control room is evacuated.

North Anna l&2 ESGR room fire analysis results require action according to the NUMARC severe accident X X 

closure guidelines: Based on the frequency criterion, only Severe Accident Management 

Guidelines (SAMG) procedures are required to be developed to mitigate severe accident 

scenarios resulting from fires in this area. These procedures are being developed and 

implemented on a schedule independent of the IPEEE. The fire results have been transmitted 

to the group developing these procedures so appropriate enhancements can be incorporated. 

North Anna 1&2 Action plan for structural steel fireproof coating in the cable spreading room: follow up on X X 

Appendix R commitments. 

North Anna 1&2 Action plan for foam installation concerns pointed out in Information Notice 88-56: revision X X 

of station procedure. 

North Anna 1&2 Action plan for Appendix R fire dampers: develop a new periodic test. X X 

North Anna 1&2 Action plan for periodic tests: incorporate barrier mark numbers and show all fire barrier X X 

penetrations on controlled drawings for use in periodic tests. 

North Anna 1&2 Thermo-Lag is used in a limited fashion in the North Anna containments to provide radiant X X 

energy shielding between redundant equipment and cables separated by less than 20 ft. The 

redundant components protected in this way are the RHR pump motors, fuel building cable 

penetration, two transmitters, a conduit (from transmitters to penetration) and a conduit 

(neutron flux indication): Thermo-Lag in Unit 2 has either been sheathed with stainless steel 

or replaced with a new radiant energy shield of Marinite board sheathed with stainless steel. 

Unit 1 is to complete the same modifications.
Table 3.5: Fire-related plant improvements (Continued)

INVLllO-)flhhiL Ir-lsfl tMU L- JtUUUU1 Vfhlht.VIIIIIW. WLfaIVV I IUUUflIh LU PIUVIUP JU IvII 

comparison of the instrumentation in the remote monitoring panel and the auxiliary shutdown 

panel with the main control room instrumentation to identify possible instrumentation 

malfunctions during MCR, emergency switchgear room, or cable vault &tunnel fires.

North Anna 1&2 Non-seismic IPEEE and fire procedures enhancements: revise procedures to direct operators X X 

to use the auxiliary shutdown panel's alternate control circuits to operate specific equipment 

if automatic actuation and the main control room control switch fails. 

North Anna l&2 Non-seismic IPEEE and fire procedures enhancements: revise procedures to preferentially X X 

operate non-failed equipment from the main control room unless the MCR is evacuated. 

North Anna l&2 Non-seismic IPEEE and fire procedures enhancements: revise procedures to identify the X X 

significance of auxiliary feedwater and charging pump controls for recovery actions from the 

auxiliary shutdown panel. 

North Anna l&2 Non-seismic IPEEE and fire procedures enhancements: revise procedures to remove the X X 

control circuit fuses and locally close the 4160V breakers necessary to re-establish feedwater 

flow in the event of no running condensate, main feedwater or auxiliary feedwater pumps due 

to possible control circuit failures. 

North Anna 1&2 Non-seismic IPEEE and fire procedures enhancements: revise procedures to remove the X X 

control circuit fuses and locally close the 4160V breakers necessary to re-establish 

charging/HHSI flow in the event of no running charging pumps due to possible control circuit 

failures. 

North Anna 1&2 Non-seismic IPEEE and fire procedures enhancements: revise procedures to de-energize the X X 

pressurizer PORV control circuits added to other procedures as action to be taken if the 

pressurizer PORV control switch does not close the valve and the block valve can not be 

closed. 

North Anna l&2 Modification which significantly enhances the ability of the plant to respond to fires, Appendix R X 

especially those originating in the MCR: alternative monitoring capability has been provided Program 

for the primary system process parameters that need to be monitored for safe shutdown. The (Fire) 

auxiliary monitoring panels located in the fuel building provide the indications (but not 

control) for each unit. The instrument loops that are used for the auxiliary monitoring panels 

are routed via the fuel building penetrations, which are independent of the normal instrument 

circuit routing to the control room. The power source for the instrumentation can be supplied 

from either unit and is therefore independent of the normal instrument power supplies. The 

auxiliary monitoring panels together with auxiliary shutdown panels have been designed to 

provide alternative shutdown capability for the primary and secondary process monitoring 

variables independent of the cable vault and tunnel, emergency switchgear/instrument rack 

room, and control room.
Table 3.5: Fire-related plant improvements (Continued)

lImplemnentation Status of 

Basis for Improvement Imiprovemnent 

Description of fire-related plant improvement, cited in the IPEEE submittal IPEEE U>EEE Have Plan to Bieing Not 

Plant (regardless of status or sourc) Fire Seismic/Fire Other Imnpk lIpl. lEvalu. Reject Stated 

North Anna l&2 Modification which significantly enhances the ability of the plant to respond to fires, Appendix R X 

especially those originating in the MCR: The auxiliary shutdown panel, located in the Program 

emergency switchgear room of each unit, is an alternate means of control to bring the plant (Fire) 

to a hot standby condition. In the case of the MCR becoming inaccessible due to a fire, the 

plant may be safety controlled and monitored from the auxiliary shutdown panel and 

auxiliary monitoring panels for an extended period of time. Emergency diesel generators 1H 

and 2H are provided with local control isolation independent of the MCR. The control panels 

are located in the diesel generator room and in the emergency switchgear room. The control 

panels provide isolation from the control room along with local control, indication, and 

metering capabilities for the emergency diesel generator and the 4160V emergency bus 

breakers. 

North Anna l&2 Modification which significantly enhances the ability of the plant to respond to fires, Appendix R X 

especially those originating in the MCR: spurious operations, the high/low pressure boundary Program 

interface at the pressurizer PORV and block valves were reviewed. The pressurizer PORVs (Fire) 

are normally shut; the block valves are normally open and can be shut to isolate flow through 

the PORVs. These valves are located inside the containment. It may be postulated that a 

single fire could cause both the PORVs to operate spuriously and disable the block valves in 

an open position, resulting in a fire-initiated loss of coolant. The 125V dc high/low pressure 

circuits for the pressurizer PORVs have been modified to include the following: (1) motive 

power to the 125V dc solenoids is routed in dedicated rigid steel conduits from the solenoid 

(inside containment) to the MCR, (2) flex steel conduit is used at the solenoid valve, 

penetration areas, and through the floor sleeve at the emergency switchgear room to the 

MCR, (3) Procedures are in place requiring the circuits listed on the Summary Evaluation 

Table to be de-energized in the event of a fire. (4) A new isolation switch is provided in the 

emergency switchgear room to ensure the circuit can be de-energized from either the existing 

switch in the MCR or the emergency switchgear rooms. 

North Anna l&2 Generic issue for reactor coolant pump seal failure during normal operation: procedural IPE Fire X 

changes to ensure that adequate instructions are available to provide backup seal injection Analysis 

and thermal barrier cooling by adding steps to ECA-0.0 which refer the operators to the seal 

cooling abnormal procedure. 

North Anna 1&2 Generic issue for reactor coolant pump seal failure during off-normal conditions: licensee has IPE Fire 

committed to supply backup diesel generator capability. This added equipment will ensure Analysis 

the provision of seal injection during off-normal conditions. 

Oconee 1-3 Recommendation for improvement: water spray and smoke control observations and X X 

precautions should be placed in the next revision of the Oconee pre-fire plan. 

Oconee 1-3 Recommendation for improvement: the combustible storage locker nearthe SSF diesel should X X 

be mounted so that the combustible materials cannot spill around the diesel during a seismic 

event.
Table 3.5: Fire-related plant improvements (Continued)

Implementation Status of 

Basis fo~r Imnprovemient Improvement 

Plant 

Description oftlire-rclated plant improvements cited in thte IPIEE submittal JiPEEE IPEEE Have Plan to Being Not (regardless of status or source) 

Oconee - Fire Seismic/Fire~ Other Iupl. Impi. Evain. Reject Stated 1-3 Recommendation for improvement: the wall between the HPI pump room, the LPI and X . reactor building spray rooms and the spent fuel pool cooling pump room should be sealed to 

limit smoke migration. 

Oconee 1-3 Recommendation for improvement: open-head water sprinklers in the cable rooms, X X 

equipment rooms, and cable shafts should be replaced with a closed-head design. Oconee 1-3 Recommendation for improvement: a water-based suppression system should be evaluated X 

for the turbine bearings. Oconee 1-3 Recommendation for improvement: the pre-fire plan update should include an expansion of X the pre-fire plan to include all fire zones. Oconee 1-3 Recommendation for improvement: fire detectors sholind be i ledn •he . .,,. U ;IA.'

side of the maintenance support building elevator to activate the elevator fire lockout feature.

Recommendation for improvement: flammable storaee cahbnets should hk rAtid'h, A,.,nf.A

I I.

-OTI ~b' r, . I .' I I I

Recommendation for improvement: members of the Keowee workforce should be advisors 

to the fire brigade.

Oconee 1-3 Recommendation for improvement: the Unit 2 equipment room smoke purge fan should be X .. removed (it has been determined that this fan serves no fire protection function). 

Oconee 1-3 Recommendation for improvement: fire protection drawings should be updated. X 

Oconee 1-3 -on 

Recommendation 

both sides for improvement: the door to the CT-4 blockhouse should have a fire link X (currently there is one on one side). 

Oconee 1-3 Recommendation 

physical for improvement: evaluate appropriate procedures coupled with potential X changes to improve the seismic adequacy of the turbine building oil sump barrels 

and lube oil drums located in the Powdex Area. 

Oyster Creek Continued transient combustible control and good housekeeping are essential elements of a X X successful fire protection program: continue good housekeeping practices and continue 

attention to the control of transient combustibles. 

Oyster Creek The hiprh pressuire CO. sv~tn A N ..- A ,, . i- U.---. - --. .

I. _________

Uyster C.reeK

. 2 J n ne Uy turbe buiulng coulo potentially become missiles following a seismic event resulting in the potential loss ofturbine bearing No. 10 and turbine generator exciter fire suppression: consider upgrading the anchorage of the CO2 system.

X

X

X 

X

X

X 

x

Oconee -p12 i

The small oil filter of the turbine generator hydrogen seal oil unit is supported only by a vertical stanchion, and no lateral support is provided. The small diameter piping to and from 

the filter forms an approximately 8' cantilever which was found be inflexible: consider additional suppmort of the oil filter.

(

f I

A1 X

tc

(')•tmPP 1.2 V

{ conce 1.-7 X
Table 3.5: Fire-related plant improvements (Continued)

Luunng Le SCISiiliml-LiU ll•WLIMlUIl Wdj&UVWII5 2IWI -IMlI - I-L --- - t 

embedded eye hook. During a seismic event, interaction of the Arrowhead Demineralizer 

trailer with the station blackout transformer fire suppression system could result in 

inadvertent suppression system actuation: anchorage was re-installed, which prevents the 

trailer from becoming a missile in high wind scenarios.

Oyster Creek Following a seismic event the high pressure generator purge CO2 rack outside the turbine X X 

building could overturn and result in missiles. The low pressure CO2 tank could be disabled 

by these missiles due to its close proximity to the high pressure CO2 storage racks: high 

pressure CO2 rack and anchorage have been replaced. 

Oyster Creek Following a seismic event, actuation of the fire protection drop-weight-actuated deluge valves X X 

could result in diversion of fire suppressant from actual fire events or fire suppressant spray 

effects on safety-related equipment: although walkdowns verified that electrical panels and 

safety equipment are generally well sealed or spray protected, new deluge valves with less 

potential for seismic actuation would provide additional margin from fire suppressant effects 

and flow diversion. 

Oyster Creek Consider operator and fire brigade training on fire analysis scenarios from the most X X 

significant Oyster Creek fire areas (fire areas for which a detailed evaluation is performed): 

particular emphasis should be placed on the unscreened fire areas (the cable spreading room 

and the "A" 480V ac switchgear room). 

Palisades Fire analysis identified several significant operator actions that impact fire core damage X X 

frequency: operator training will be conducted on all operator actions credited in the IPEEE 

that were not credited in the IPE, including the fire-risk-significant operator actions. 

Palo Verde 1-3 The essential air cooling unit (ACU) for the train B dc equipment rooms does not have a Appendix R X 

remote disconnect switch to disconnect it from the control room in the event of a control (Fire) 

room fire: until this switch is installed, instructions exist to lift leads, if necessary, to operate 

the ACU. 

Palo Verde 1-3 Fire panel control circuits that actuate dampers for cooling air flow in the train A and train B Appendix R X 

essential switchgear rooms were not designed for train separation; i.e., a fire in train B (Fire) 

switchgear room could cause a loss of cooling to train A switchgear and dc equipment rooms: 

perform modification that will separate the damper actuation circuitry and reconfigure the fire 

damper control panels. 

Palo Verde 1-3 Certain safe shutdown and non-safe shutdown control circuits in each train have common Appendix R X 

fuse protection, with non-safe shutdown circuits routed through a common area. This could (Fire) 

lead to a single fire causing loss of control power to safe shutdown circuits of both trains: 

contingency plans are in place to address this concern, in the event that a fire occurs prior to 

the time that a design change is implemented to install additional fuses.
Table 3.5: Fire-related plant improvements (Continued)

Implementation Status oif 

Basis for Improvement Improvement 

Plant 

Description of fire-related plant imnprovements cited in the JPEEE submittal IPlEEE IPE E Have Plan toI Being Not (regardless of status or source) Fire Seismic/Fire Other hnpl. Imnpl. JEvain. Reject Stated Palo Verde 1-3 A fire in the Unit 1 control room, upper cable spreading room or corridor building cable shaft X X has the potential to cause a major disruption to the Palo Verde switchyard and, in turn, lead 

to a loss of offsite power to all three Palo Verde Units (Units 2 and 3 would remain on line connected to the two remaining offsite transmission lines): perform a grid stability analysis under the worst case scenario of tripping Unit 1 and loss of three of the five offsite 

transmission lines. 

Palo Verde 1-3 A fire in the Unit 1 control room, upper cable spreading room or corridor building cable shaft X X has the potential to cause a major disruption to the Palo Verde switchyard and, in turn, lead 

to a loss of offsite power to all three Palo Verde Units (Units 2 and 3 would remain on line connected to the two remaining offsite transmission lines): developed a procedure to 

disconnect the Unit 1 switchyard control circuits, re-establish alignment of the transmission 

lines and re-energize the startup transformers to restore offsite power availability to the Palo 

Verde units; this was integrated into the interface procedures used between the SRP power dispatch office, the APS energy control center, and the Palo Verde Unit I control room, which has primary responsibility for site interface with the switchyard. Palo Verde 1-3 FIVE pilot project completion in 1991 resulted in: development of a computer-based training X X course to inform plant staff ofthe project findings. In addition, enhancements were made to 

the annual site access training received by all personnel having unescorted access to the protected area regarding fire prevention and identification of those fire-sensitive areas, including those non-Appendix R compartments where offsite power conductors and control 

circuits are located. 

Peach Bottom 2&3 Reactor Unit 2 RHR pump fire area: revise procedure to allow venting of Unit 2 containment. X X Peach Bottom 2&3 Control room/CSR, 4 kV switchgear rooms (34 (shared area), 35(shared area), 32(shared X X area)), reactor Unit 2 reactor building north, reactor Unit 3 cooling water, reactor Unit 2 recirculation motor generator set: enhance control of transient combustibles in area and 

increase fire brigade awareness of the area and its hazards. 

Peach Bottom 2&3 Reactor Unit 2 cooling water fire area: enhance control of transient combustibles in area and X X increase fire brigade awareness of area. Create operator action to regain dc batter charger. Peach Bottom 2&3 Reactor Unit 3 recirculation motor generator set fire compartment: upgrade fire compartment X X 

to provide separation from other fire areas. Increase fire brigade awareness of area and its hazards. Enhance control of transient combustibles in fire area. Create operator action to 

locally operate valve. 

Peach Bottom 2&3 RW miscellaneous areas, reactor Unit 3 reactor building north, turbine building Unit 2 wing X X area and turbine building Unit 3 lube oil tank: upgrade fire compartment barriers to provide separation from other fire areas. Increase fire brigade awareness of area and its hazards. 

Enhance control of transient combustibles in fire area.

00
Table 3.5: Fire-related plant improvements (Continued)

Implementation Status of 

Basis for Improvement Improvement 

Description of fire-related plant improvements cited in the IPEEE submittal IPEEE IPEEE Have Plan to Being Not 

Plant (regardless of status or source) Fire Secismic/Fire Othter Impi, Impi. Evalu. RejectiStated 

Peach Bottom 2&3 4kV switchgear corridor: upgrade fire compartment barriers to provide separation from other X X 

fire areas. Increase fire brigade awareness of area and its hazards. Create transient 

combustible free zone. 

Peach Bottom 2&3 Reactor Unit 2 torus and reactor Unit 3 torus fire compartment: create new combustible free X X zone (Thermo-Lag change). Increase fire brigade awareness of area and its hazards. 

Peach Bottom 2&3 Reactor Unit 2 core spray: create operator actions to allow operation of valve at MCC. X X 

Peach Bottom 2&3 Reactor Unit 2 reactor building south: enhance control of transient combustibles in fire area. X X 

Increase fire brigade awareness of area and its hazards. Revise procedure to allow venting of 

Unit 3 containment. 

Peach Bottom 2&3 Reactor Unit 3 core spray and battery room fire compartment: revise procedure to allow X x 

venting of Unit 3 containment. 

Peach Bottom 2&3 Reactor Unit 3 reactor building south. revise procedure to allow venting of Unit 3 X X 

containment. Create operator action to allow valve operation at MCC. Enhance control of 

combustibles in fire area. 

Peach Bottom 2&3 Battery room fire compartment (shared area): enhance control of transient combustibles in X X 

the fire area. Increase fire brigade awareness of area and its hazards. Create operator action 

to allow valve operation at MCC. 

Peach Bottom 2&3 4kV switchgear room 33 (shared area): enhance control of transient combustibles in fire area. X X 

Increase fire brigade awareness of area and its hazards. Create operator action to swap to 

alternate power supply and operate valve at MCC. 

Peach Bottom 2&3 4kV switchgear room 38 (shared area): enhance control of transient combustibles in fire area. XX 

Increase fire brigade awareness of area and its hazards. Create operator action to manually 

align switchgear to diesel. 

Peach Bottom 2&3 4 kV switchgear room 38 (shared area): enhance control of transient combustibles in fire area. X X 

Increase fire brigade awareness of area and its hazards. Create operator action to swap to 

alternate power supply. 

Peach Bottom 2&3 4 kV switchgear room 39 (shared area): enhance control of transient combustibles in fire area. X X 

Increase fire brigade awareness of area and its hazards. Revise procedure to allow venting of 

Unit 2 containment. 

Peach Bottom 2&3 Turbine building: Unit 2 lube oil 50L (shared area), Unit 3 lube oil 50P (shared area), X X 

Unit 2/Unit 3 pipe tunnels 50R-3 (shared area), Unit 2 lube oil tank 50R-5 (shared area), 

Unit 2 lube oil equipment 50R-7 (shared area), Unit 3 lube oil equipment 50R-8 (shared area), 

Unit 2 RFPT C lube oil 50R-10 (shared area), Unit 3 RFPT C lube oil 50R-l1 I(shared area): 

upgrade fire harriers to provide separation from other fire areas.
Table 3.5: Fire-related plant improvements (Continued)

Implementation Status of 

Basis for Improvement Intprovement 

Description of fire-related plant improvements citedl in thre IPEEE submittal IPEEE IPEEE Have Plan to Being Not 

Plant (regardless of status or source) Fire Seismic/F~ire Other Isnpl. Imp). JEvalu. Re~ject Stated 

Peach Bottom 2&3 Turbine building: Unit 3 wing area 50R-2&4 (shared area) and 13.2kV switchgear area 50R- X X 

9a (shared area): upgrade fire compartment barriers to provide fire separation from other fire 

areas. Increase fire brigade awareness of area and its hazards. Enhance control of transient 

combustibles in fire area. Modify offsite power control to retain offsite power in fire area. 

Peach Bottom 2&3 Reactor building A (shared area) and B (shared area): upgrade fire compartment barriers to X X 

provide separation from other fire areas. Create transient combustible free zone. 

Peach Bottom 2&3 Turbine building Unit 2/Unit 3 remainder: upgrade fire compartment barriers to provide X X 

separation from other fire areas. Increase fire brigade awareness of area and its hazards. 

Enhance control of transient combustibles in fire area. Modify offsite power control to retain 

offsite power in fire area. Automate existing fire suppression system on elevation 116'. 

Peach Bottom 2&3 Mercury switches in water suppression system manual pull stations (4): replace with non- X X 

mercury switches. 

Peach Bottom 2&3 CO 2 system panel Cardox relays (4): establish procedural controls to mitigate results of X X 

spurious relay operation. 

Peach Bottom 2&3 DG Cardox tank 0OS101: Add restraints to restrict motion during seismic event. X X 

Peach Bottom 2&3 CO 2 tanks 20S 101, 30S 101, and 20S 112: perform an engineering evaluation to determine the X x impact of a seismically induced CO2 release on plant equipment in the turbine building. 

Perry None identified 

Pilgrim None identified 

Point Beach l&2 Control room/cable spreading room fire procedure: Abnormal Operating Procedure for fire X X 

in the control room is being revised to add verification that additional valves which were 

identified as part of the Point Beach IPEEE process are closed for containment isolation. 

Point Beach l&2 Evaluation of smoke detectors in the control room: the control room smoke detectors are X X 

located below a grated ceiling. Smoke would not accumulate to the level of the detectors 

until the section of the control room above the ceiling is filled with smoke. An engineering 

evaluation on this condition is being conducted.

t.• ! 

--O
Table 3.5: Fire-related plant improvements (Continued)

Add fire wrap or other barrier material to the exposed length of cable 1DCB-1 above cable 

tray 1 SG-LB22 in FA 32: an issue has been identified involving a fire in FA 32 (Unit 1 side 

AFW pump/instrument air compressor room) could affect the control power for both 

safeguards 4160V buses. A large lube oil spill fire on 121 IA compressor (fire suppression 

system fails) could result in the failure of cables 1DCA-1 and 1DCB-1, which run in the 

overhead near the compressor. Cable 1DCA-1 (control power to Bus 15) is not fire wrapped 

in this area. Cable 1DCB-l(control power to Bus 16) has a radiant energy shield (thermal 

board) for the portion of the cable that runs through tray 1 SG-LB22. However, above the air 

compressor, 1DCB-1 then exits the tray and runs up through a penetration in the ceiling to 

enter the Bus 16 room. No wrap or other barrier protects the cable in this region. Fire 

modeling predicts that a fire "jet layer" will exist above a height of 16 feet above the floor 

in this room. All unprotected equipment for a radial distance of 14 feet from the fire must be 

@v~t, tn fai~l dlii tn the fire in this reeion_

Prairie Island 1&2 In many fire core damage sequences (fire may be initiated in a number of fire areas), the 121 X x 

cooling water pump and a roof exhaust fan are available, but since (in these sequences) the 

fan and pump are powered from the opposite train, the fan is not running. This leads to failure 

of the 121 CL pump due to lack of sufficient ventilation: add instructions to Fire Safety 

Procedure F5 Appendix D for the operator to locally start an available roof exhaust fan to 

reestablish safeguards screenhouse ventilation. (Subsequent review revealed that procedures 

already exist to accomplish this task for fires that cause loss of power from MCC IAB1 or 

IAB2.) 

Prairie Island 1 &2 On an air compressor large oil spill fire the assumption is that the fire causes spurious closure X X 

of MV-32027 prior to loss of power from MCC IA2. The cooling water supply valve 

MV-32027 could also be opened. This operator action is credited in the SSA: add 

instructions to Fire Safety Procedure F5 Appendix D for the operator to manually open a 

suction supply valve to the 12 AF pump on a fire in FA 32 (Unit I side AFW pump/IA 

compressor room). Alternative 

- fire wrap the length of conduit for cable IA2-6A that runs 

in FA 32. (Upon review of the procedure, it was noted that direction is included in F5 

Appendix D to de-energize MCC IA2 and manually operate as necessary the suction motor 

valves for 12 MDAFWP for a fire in FA-32. No credit for this recommendation (or for the 

operator action at all) was given in the final quantification. It was decided to conservatively 

remove credit for this action.) 

Prairie Island l&2 Need for shutdown outside the control room: ensure that existing training for manual fire X X 

suppression in the mitigation of fires in the control room and relay room (fire brigade to relay 

room) includes a discussion of the risk significance of this action in the prevention of a core 

damage accident. 

Prairie Island 1&2 Action to prevent a core damage accident: ensure that existing training for the operator task X X 

to shut down the plant from outside the control room per F5, Appendix B includes a 

discussion of the risk significance of this action in the prevention of a core damage accident.
Table 3.5: Fire-related plant improvements (Continued)

Action to prevent a core damage accident due to internal fires: ensure that existing training 

for the operator task to perform bleed and feed cooling of the RCS includes a discussion of 

the risk significance of this action in the prevention of a core damage accident due to internal 

fires.

Prairie Island l&2 Operator task to perform dc panel switching in the battery room and relay room for a fire in X X 

FA 59: ensure that training (lesson plans,. out plant checkoffs, etc., as appropriate) exists for 

this operator task. Training should include information relative to the importance of this 

action to stopping loss of inventory through the RCS vent solenoid valves. (A job performance measure was also created to address this issue.) Prairie Island 1&2 Verify cable separation in the G panel due to the potential for a large fire internal to the panel X X 

to cause the loss of offsite and onsite power: power would then have to be restored from the 

diesel generators from outside the control room. The current panel design configuration 

meets criteria that support prevention of this scenario for most fires. This recommendation 

is made only to provide added assurance of this critical assumption with respect to its impact on plant risk due to fires. (A visual inspection was performed on the G panel and 

confirmation was made on the proper design separation between trains. In addition, through the plant design change process, proper separation of cables throughout the plant was verified.) 

Prairie Island l&2 During walkdown activities conducted as part of the IPEEE improvement process (Fire Risk X X 

Scoping Study issues task) ERIN Engineering determined that a potentially weak anchorage exists for the main CO2 storage tank in the Unit I turbine building. This is a concern for the 

seismic-fire interactions review, in that this tank is required for fire suppression in the relay room. Suppression in the relay room is important due to the critical equipment for plant safe 

shutdown located in this room: upgrade the anchorage for the main Cardox tank for relay room automatic fire suppression. 

Prairie Island l&2 During the walkdown activities conducted as part of the IPEEE improvement process (Fire X X Risk Scoping Study issues task) ERIN Engineering determined that a potentially weak 

anchorage exists for the diesel driven fire water pump batteries and fuel oil day tank in the 

plant screenhouse. This is a concern for the seismic-fire interactions review, in that a seismic 

event of sufficient magnitude to cause the loss of offsite power (cause loss of the motor

driven fire water pumps) could also render the diesel fire pump unavailable: upgrade the 

anchorage for the diesel driven fire water pump batteries and fuel oil day tank.
Table 3.5: Fire-related plant improvements (Continued)

The increased risk from the (non-qualified) cables at Quad Cities results from the fact that 

they can be damaged more quickly by an exposure fire than cables qualified to the provision 

of IEEE 383. And once ignited, they burn more intensely with both higher heat release rate 

and mass loss rates. The use of possible additional fire protection features to overcome the 

inherent liabilities of non-qualified cable will be fully evaluated. It is possible that simple 

steps, such as additional suppression or detection, new fire barriers, or radiant heat shields, 

sealing the top of electrical and switchgear cabinets, or other yet-to-be-identified solutions, 

may provide sufficient additional margin to reduce the contribution of non-qualified cables 

to an acceptable level.

Quad Cities I & 2 Human factors (number of steps in QARPs). When a severe, uncontrolled fire requires the X X 

plant operators to enter the QARPs to achieve safe shutdown, the process is more complex 

and does not have the options available in normal shutdown procedures. Five operators can be required to perform more than 20 separate steps, all coordinated by the Licensed Reactor 

Operator using portable radios. Two potential solutions to the human factors contribution to 

the CDF are immediately apparent. The first is to evaluate possible upgrades to the QARPs. 

As a minimum, they should be more clearly written in line with Human Factors. The second 

potential solution is to evaluate the use of additional transfer/isolation switches. The prudent 

installation and use of such transfer/isolation switches may substantially reduce the actual 

number of manual actions currently required by the QARPs. 

Quad Cities 1 & 2 Use of opposite unit equipment. Because so many fire scenarios assume damage to and X X 

unavailability of redundant trains of equipment, most fire scenarios direct the operators to the 

QARPs and use of opposite equipment to achieve safe shutdown. This contributes to the 

CDF because of three interrelated issues: equipment availability, multi-unit LCOs, and 

contribution to QARP complexity. Quad Cities will evaluate the availability of alternative 

(not shared) equipment in the unit of concern that has not previously been identified and that 

may be used and credited without reliance on equipment in the opposite unit. Quad Cities 

will also evaluate the need for additional protection of specific cables and components of the 

shutdown trains. 

Quad Cities 1 & 2 Both divisions of safe shutdown cables are located in the same fire compartment; e.g., cable X X 

tunnels, cable spreading room, etc. The evaluation of additional protection for specific cables 

and components of the shutdown trains, and the evaluation of availability of alternative 

equipment discussed above will also address the concerns of lack of separation between 

redundant divisions where such lack of separation exists.
Table 3.5: Fire-related plant improvements (Continued)

Because of lack of specific information, the QARPs assume that all equipment in the fire area 

of concern is damaged and consequently all potential spurious actuations occur. The 

response from the QARPs is to strip all control circuits from potentially involved buses which 

further increases the number of required manual actions. As part of QARP revisions, Quad 

Cities will consider the selective stripping of control circuits from identified buses rather than 

the indiscriminate stripping of all circuits simply on the basis that they are all assumed to be 

damaged. The e/valuation of transfer/isolation switches and the evaluation of protection of 

specific equiptsent/cables will also address specific concerns with spurious actuations during 

a fire.

River Bend None identired. 

Robinson Fire originating in Battery Room "A-16" in motor control center (MCC) cabinets MCC "A" X X 

or MCC ",B," combined with failure to perform manual fire suppression, which leads to a loss 

of Train /"A" and "B" direct current (dc) power: seal open conduits emerging from the top of 

MCC "A" and MCC "B" to avert the formation of a hot gas layer from a fire in the battery 

room sufficient to prevent effective fire suppression. 

Robinson Fire in a ruptured transformer in the switchyard that results in a loss of offsite power and X X 

subsequent loss of the dedicated shutdown (DS) diesel generator: revise procedure used by 

the fire brigade to include instructions to the fire brigade to emphasize protection of the DS 

conduit by aiming water streams on the DS conduit to counter the damaging effects of radiant 

heat. 

Robinson Eight fire scenarios consist of a fire in a reactor turbine generator board (RTGB) panel, X X 

located in the control room, that is suppressed within the RTGB cabinet or that propagates 

to other RTGB cabinets. Another fire scenario is a fire that originates in a control room 

location other than an RTGB panel that results in an evacuation of the control room: evaluate 

and select early warning fire detection systems that utilize air sample technology to detect 

fires in the pre-incipient stage of combustion for the RTGB cabinets in the control room. 

Salem 1 & 2 There are two sets of cables supplying offsite power to the 4kV vital buses and these are X X 

routed through one elevation of the turbine and service buildings before entering the auxiliary 

building. The two sets provide a redundant source of power to the vital 4kV buses. Thus, if 

one set is damaged by fire, the second set could provide power to all three buses. In the 

turbine building, there is an area in which the two redundant sets of cables are separated by 

less than 10 feet: Transient combustible controls similar to those in place for the auxiliary 

building, penetration areas and service water intake structure will be put into effect for this 

area of the turbine building. Daily walkdowns will be performed for the elevation on which 

the cables are routed to ensure that combustibles do not accumulate beneath the cables, and 

fire watches will be posted if any normally active suppression systems are disabled. 

Procedures are being revised to ensure these activities are accomplished through periodic 

monitoring.
Table 3.5: Fire-related plant improvements (Continued)

-- ILt "t -1- --- v.Ltt~ti3 j ul 1-, tvUVImnUti V-1-11 nl I Uflt a V1lt ai UilalUIclIIb lul 

providing cooling to the switchgear and control areas of the Salem Generating Station in the 

event that the normal HVAC systems cannot meet the areas' requirements. Review of 

operator action, with respect to external events concerns indicates that a more current and 

substantial basis is required for crediting these actions: revised heat-up calculations for these 

areas to address a wider spectrum of accident scenarios and provide a more detailed response 

methodology were being done. Additionally, based on those calculations, anew, stand-alone 

procedure is to be developed to address loss of HVAC to these areas.

San Onofre 2 For fire compartment 2-AC-30-20A (control room and cabinet area), implementation of an X X 

administrative change to Procedure S023-13-2, "Shutdown from Outside the Control Room," 

would allow operators to use offsite power in the event that the reserve auxiliary transformers 

are not inadvertently tripped by fire-induced damage to panel 2/3CR-63. 

San Onofre 2 For fire compartments 2-DG-30-155 and 2-DG-30-158 (diesel generator rooms), X x implementation of an administrative change to S023-13-21 (fire) would allow operators to 

recover power to the 4 kV switchgear by disconnecting power to the diesel generator feeder 

breaker and reclosing the offsite power breaker on the switchgear. 

San Onofre 2 For fire compartments 2-AC-50-44, 2-AC-50-45, 2-AC-50-46, 2-AC-50-47 (distribution X X 

rooms), 2-AC-50-35 and 2-AC-50-40 (switchgear rooms), implementation of an 

administrative change to alarm response procedure S023-15-60.A1 (annunciator panel 60A, 

emergency HVAC) would allow operators to use air duct and gas-driven fans to prevent room 

heat-up. 

San Onofre 3 The applicability of fire improvements to Unit 3 is not clear. The procedures modified X X 

apparently apply to both units (as noted by the S023 designation). However, the fire 

compartments appear to be part of Unit 2. It is noted, however, that the units share a common 

control room and the other compartments might also be shared. 

Seabrook Turbine building relay room: install fire detection. X X 

Seabrook Combustible materials stored near the west wall of the turbine building: expand water X X 

suppression along the west wall. 

Seabrook In Appendix A of Fire Response Procedure OS1200.01, indicate that PCC can be impacted X X 

by a PAB fire: modify the fire response procedure. Also, in Fire Procedure OS1200.02(b), 

response should incorporate an instruction for verifying PORV status. 

Seabrook Highlight important fire areas: place tighter restrictions on the amount of combustible X X 

material allowed in important fire risk areas, e.g., the control room, CSR, PCC Pump Area, 

and SW Pump Area. 

Seabrook Reduce the incidence of RCP seal LOCAs: install high temperature O-rings. IPE X 

Seabrook Reduce offsite release risk: make improvements to the RCS depressurization procedures. IPE X 

Seabrook Reduce offsite release risk: use administrative controls to reduce the time that containment IPE X 

purge valves are allowed to be open.
Table 3.5: Fire-related plant improvements (Continued)

Implementation Status of 

Basis for Improvement Improvement Description ofpirerelated plant improvements cited in the submittal .ELE EEE IPEEE WHave Plan to Being - Not Plant (regardless of satus or source) F~ire Seismsic/Fire Other Impl. Imp]. iEvalu. Reject Stated 

Sequoyah l&2 None identified. 

Shearon Harris 1 A potential LOCA can be mitigated by the closing of the appropriate PORV block valve from X X 

the alternate control panel. The procedure will be revised to specifically check the status of 

the pressurizer PORVs after transfer to the alternate control panel to require closure of a block 

valve if necessary to isolate a failed open relief valve. 

South Texas 1&2 None identified. 

St. Lucie 1 & 2 For fires and possibly other events, it is unlikely, but possible, for one unit to be "black" X X 

while the other unit still has offsite power and continues to operate. In screening 6 areas, it was assumed power could be fed from the other unit. FPL will perform an engineering evaluation to determine cost effective methods for reduction of CDFs for the 6 areas. Although the focus will be on use of the power crosstie, other alternatives will be considered. 

FPL will also provide a schedule for implementation of any procedure revisions or other 

alternatives resulting from the evaluation. 

St. Lucie I & 2 For each turbine generator building switchgear room, fire modeling showed fires (fixed or X X 

transient combustibles) would not propagate throughout the room. However, a transient spill (and fire) could occur between the two trains affecting both A2 and B2 4.16kV buses, 

resulting in loss ofoffsite power. There are (usually open) roll-up doors in the concrete block 

walls between the "A"and "B" trains which would prevent spread of such a spill. The FIVE 

analysis assumed such a spill (affecting both buses) would not occur in screening this area. FPL will revise Fire Protection procedures to maintain the west roll-up door in each unit 

turbine generator building switchgear room closed. 

St. Lucie 1 & 2 The Unit 2 "B" switchgear room (compart C) also contains the 2A5 480 V load center. This X X 

meets Appendix R criteria since 2A5 is separated from 2B5 by a wall and powers no Appendix R safe shutdown equipment. However, it does power equipment used in the PSA 

and this area will not screen assuming loss of"B" train and 2A5. Fire modeling showed fires 

(fixed and transient combustibles) would not propagate throughout the room. The FIVE 

analysis assumes that the "B" train is lost but does not assume the 2A5 Load Center is 

simultaneously lost. (An analysis was done which verified loss of adjacent 2A5 and 2B5 

Load Centers would screen.) Also, 2A5 and most control power enters the load center from 

underneath (a separate fire compartment). However, one control cable is routed through the room such that it could be affected by a fire in/around the "B" switchgear. Even with action on this cable, compartment C does not screen but the conditional damage frequency is 

reduced by a factor of five from 2.28E-06/ry to 4.51E-07/ry. FPL will perform an engineering evaluation to determine cost effective methods for reduction of core damage 

frequencies for this area. Although focus will be on the cable mentioned above, other 

alternatives will be considered. FPL will provide a schedule for any resulting modifications 

I _ _ Ior procedural enhancements.

all
Table 3.5: Fire-related plant improvements (Continued)

Implementation Status of 

Basis for Improvement Improvement 

Description of fire-related plant improvements cited in the WPEEE submittal IPEEE IPREEF Have Plan to Being Not 

Plant (regardless of status or source) Fire SeismiclFire Other Impi. Imp]. lEvain. Reject Stated 

Summer Several potential procedural enhancements were identified during the detailed HRA X x 

evaluation: a note or caution to not isolate offsite power to the safe shutdown bus before the 

diesel generator is ready to load would reinforce fire emergency procedure (FEP) training on 

this point._______________ 

Summer Several potential procedural enhancements were identified during the detailed HRA X X 

evaluation: specific steps to operate the breakers required to restore offsite power, if the diesel 

generator fails after being loaded, would reduce the HEP for this evolution that is currently 

_______________performed using a generic procedure attachment for breaker operation. ___ _____ 

Summer Several potential procedural enhancements were identified during the detailed 1-RA X X 

evaluation: a step to ensure that the turbine driven EFW pump is shut down would reduce the 

chance of a potential pump start going unnoticed. This start is not normally expected to occur 

but is possible if the sequence of actions being taken by two independent operators is 

reversed. 

Summer The details of the 1998 VCSNS Fire Induced Vulnerability Addendum confirmed operator X - ___ -X 

knowledge that use of the FEPs in an inappropriate scenario will increase the CCDP: these 

details will be used to enhance operator training by providing scenario analyses that 

quantitatively illustrate this point. They will also provide a better basis for the SRO's 

judgement of when FEP use is appropriate._____________ 

Summer The details of the 1998 VCSNS Fire Induced Vulnerability Evaluation Addendum can be X X 

used to enhance fire brigade member training: they are currently trained on which 

components are important for functions required to achieve and maintain safe shutdown but 

this will be enhanced with information on the areas in which s~evere uncontrolled fires could 

require use of the FEPs.______ 

Sunry 1&2 Prevent breakers from automatically reopening due to control circuit failures caused by fires: X X 

revise fire contingency action procedures to allow removal of control circuit fuses ofauxiliary 

feedwater, main feedwater, and condensate pumps for 41 60V breakers between offisite power 

and the emergency buses. 

Surry 1&2 Consider using main feedwater or condensate if auxiliary feedwater has failed: revise fire X X 

_______________contingency action procedures____ 

hydrogen piping near an elbow. The piping appeared to be flexible which may cause 

relatively large displacements of occur: flexibility of tubing will be further reviewed and if 

needed, a modification will be performed.____ ______ ______ ___ ___
Table 3.5: Fire-related plant improvements (Continued)

XXlUO-I-I~Pll. UUVL U111lllItllUILllut; 1U es reiateu to nyurogen cyiinaers in me turoine 

building: address via procedure. A carbon dioxide bottle in the emergency service water 

pump house was not clamped properly: address via housekeeping procedure. In the turbine 

building, adjacent to the skid containing 1(2)-LO-FL-1, was an unanchored oil drum resting on the floor and a small container containing oil which is supported approximately 5' offthe 

floor by four angles: unanchored drum is also a housekeeping issue and will be addressed 

programmatically. Further review will be performed on the smaller container

Susquehanna 1&2 The improvements are mainly procedural. They include restrictions on combustible materials X X 

storage, ban on smoking inside buildings, special covers for barrels, and opening of the floor 

drain in the Lower Cable Spreading Room to allow sprinkler system water to drain. 

Three Mile Island 1 None identified. 

Turkey Point 3&4 None identified. 

Vermont Yankee Ensure that limit switches and torque switches would not be bypassed assuming a fire- Appendix R X 

induced hot short for control room and cable vault fire events: reconfigure control circuits of 

the Appendix R motor-operated valves (MOVs). With these modifications, a hot short may cause an MOV to inadvertently transfer position; however, the motor operator will remain 

protected via the limit and torque switches. Thus, the MOV itself is not damaged and 

remains available for later manipulation at the alternate shutdown panel. 

Vermont Yankee A hot short of the power cables for the SRVs causing spurious opening of an SRV: the power Appendix R X 

cables for two of the four SRVs were re-routed to provide spatial separation. The control 

cables for each SRV are enclosed in dedicated, grounded steel conduit in the reactor building 

and cable vault. Based on this modification, a hot short is judged to be very remote. Also, the 

ADS bypass switch in the control room is protected with a 1 hour rated fire barrier to prevent 

completion of a spurious ADS signal. 

Vermont Yankee RCIC failure (the preferred injection source), the licensee would de-pressurize the RPV from Appendix R X 

the ASD panel and use an LPCI pump for low pressure injection: enhance alternate shutdown 

controls to include remote control of two SRVs for pressure control and/or initiation of RPV 

de-pressurization. 

Vermont Yankee Simplify initiation of alternate shutdown: use the vernon tie as the preferred alternate Appendix R X 

shutdown ac power source instead of EDG- 1A. 

Vermont Yankee Improvements made to plant procedures: including the alternate shutdown and fire response Appendix R X 

procedures, fire barrier surveillance requirements procedures and natural phenomena 

procedures. 

Vermont Yankee Expeditious control of alternate shutdown equipment without having to physically replace Appendix R X 

individual control circuit fuses which may have blown due to fire-induced circuit damage: 

install back-up fuses in the circuits of the Appendix R safe shutdown equipment. These 

backup fuses are automatically switched into the circuits whenever the alternate shutdown 

selector switches are operated.

oc
Table 3.5: Fire-related plant improvements (Continued)

vUiiuuiit i uIMUC rnnance ure inuepenuence oetween me turoine Duiling ana tfe radwaste corridor: install a 3 hour fire rated door between these fire areas. 

Vermont Yankee Potential fire damage interaction for Switchgear room fires: improve and separate the RHR 

system minimum flow valve pump interlocks and RHR Room cooler start circuits. 

Vermont Yankee Improvement opportunity, north wall lower NE comer room: include the top 6" of the north 

wall in the lower NE ECCS comer room (just under floor elevation 232' 6") in the plant fire 

barrier inspection program. 

Vermont Yankee Improvement opportunity, vertical cable tray fire stops: enhance inspection and maintenance 

of vertical cable tray stops at each floor in the reactor building, to limit fire spread from one 

elevation to another. 

Vermont Yankee Improvement opportunity, periodic fire prevention inspections: perform periodic fire 

prevention inspections of the reactor building and control building on a more frequent 

(monthly) basis. 

Vermont Yankee Improvement opportunity, Vernon Tie breaker cables: relocate or otherwise protect the 

control cables for the Vernon Tie breakers 3V, 4V, and 3V4 in the east and west switchgear 

rooms from fires that are likely to damage offsite power control cables. 

Vogtle l&2 None identified. 

Waterford 3 In the essential chiller room, a fire on chiller A or chilled water pump A could damage cables 

associated with chiller train B: although the design meets the requirements of Appendix R, 

due to the availability of the AB train during this scenario, the robustness of the plant to fire 

hazards in this fire area could be improved by adding fire wrap to the B chilled water cables 

in the vicinity of the A chiller. 

Watts Bar 1 None identified 

Wolf Creek I None identified

* Formerly known as Washington Nuclear Project Number 2.

I. 1

X

X

X

X

X

I I
Table 3.6: Comparison of a set of past fire PRAs with respective IPEEE submittals

Electrical tunnels, 

switchgear room

1.8E-05 Main control room, 

cable spreading room, 

switchgear room, 

electrical penetration 

area, primary makeup 

area

IPEEE did not use 1982 

study. The 1982 study 

CDF does not include 

plant modifications since 

completion of the study.

Indian Point 3 1982 6.3E-05 Switchgear room, 5.6E-05 Switchgear rooms, IPEEE did not use 1982 

electrical tunnel, cable cable spreading room, study. The 1982 study 

spreading room main control room, CDF does not include 

diesel generator rooms plant modifications since 

completion of the study. 

Limerick 1983 2.3E-05 Equipment rooms, Not Main control room, IPEEE submittal does 

switchgear room, Reported remote shutdown not use CDF explicitly. 

assess area, main panel room, auxiliary Final screening of main 

control room, cable equipment room, control room & auxiliary 

spreading room 2 switchgear room, equipment room is based 

static inverter room on 1983 fire PRA. 

Millstone 3 1983 4.8E-06 Main control room, 4.8E-06 Charging pumps, 

instrument rack room, CCW pumps, cable 

cable spreading room spreading room, MCC 

& rod control areas, 

main control room, 

instrument rack room 

Seabrook 1983 1.7E-05 Main control room, 1.2E-05 Main control room, IPEEE submittal is a new 

instrument rack room, primary auxiliary analysis but 

cable spreading room building, turbine acknowledges 1983 

building, switchgear study and compares the 

room, service water differences in the method 

pump house and data employed. 

Oconee 1984 1.OE-05 6.0E-06 turbine building, cable Original study was 

shaft updated in 1990 and used 

for preparing IPEEE. 

TMI-I 1987 8.6E-05 MCC area, switchgear 2.2E-05 Inverter rooms, Used 1987 study as a 

room, electrical switchgear rooms, starting point and 

cabinet area main control rooms, modified it for IPEEE. 

auxiliary relay room 

South Texas 1989 <1.2E-06 Main control room 5.1E-07 IPEEE submittal partly 

based on the 1989 study. 

Diablo 1990 2.9E-05 Cable spreading room, 2.7E-05 Cable spreading room, Original study was Canyon main control room main control room updated for IPEEE. 

Peach Bottom 1990 2.0E-05 Main control room, Not turbine building, 1990 study done by SNL 

2 switchgear rooms, Reported reactor building, for U.S.NRC. Licensee 

cable spreading room switchgear rooms conducted its own study 

for IPEEE. Licensee did 

not report a fire CDF.

3 - 80

Indian Point 2 1982 2.OE-04

I
Table 3.6: Comparison of a set of past fire PRAs with respective IPEEE submittals (Continued) 

Completion PRA CDF PRA important IPEEE IPEEE important 

Plant date' (/ry)' contributors' CDF (/ry) contributors Comments 

Surry 1 1990 1.LE-05 Switchgear room, 6.3E-06 Switchgear rooms, 1990 study done by SNL 

main control room, turbine building, cable for U.S.NRC. Licensee 

auxiliary building, spreading room, conducted a new fire 

cable vault or tunnel electrical equipment analysis for IPEEE. 

room, main control 

room, cable vault 

LaSalle 2 1993 3.2E-05 Main control room, 3.2E-05 Main control room, 1990 SNL for U.S.NRC 

switchgear rooms, switchgear rooms, study referenced. 

equipment rooms, equipment rooms, 

turbine building, cable turbine building, cable 

shaft shaft 

1. The list of fire PRAs and related information is taken from NUREG/CP0 162, "Research Needs in 

Fire Risk Assessment," Proceedings of 25' U.S. Nuclear Regulatory Commission Water Reactor 

Safety Information Meeting, Bethesda, Maryland, October 20-22, 1997, Volume 2, pages 93-116. 

2. IPEEE did not use the 1983 study.

3 -81
4. HIGH WINDS, FLOODS, AND OTHER EXTERNAL EVENTS TABLES 

This section contains a summary table of the methodologies and results for the IPEEE HFO events. Included 

in the table are (1) an identification of the methodologies used for the different severe accident event 

categories, (2) the core damage frequency contributions for those cases where PRA information was reported, 

(3) HFO-related plant improvements, and (4) comments regarding the plant HFO results and review.

4-1
Table 4.1: Methodologies and results for the HFO external events

Compliance with SRP 

(qualitative progressive 

screening per NUREG

1407) 

Beaver Compliance with SRP

Valley 1 

Beaver 

Valley 2 

Braidwood 

Browns 

Ferry 2&3

Compliance with SRP

Compliance with SRP 

(est. chemical release 

(hazard) frequency 

<7E-7/year) 

Compliance with SRP 

(est. chemical release 

(hazard) frequency 

<7E-7/year) 

Compliance with SRP 

Compliance with SRP

Not estimated

Not estimated 

Not estimated

Not estimated 

Not estimated

Added scuppers to parapet 

walls of auxiliary building to 

relieve roof load during heavy 

rainfall 

None identified; backup 

cooling water intake structure 

was added prior to IPEEE as 

further protection against 

barge accidents

None reported

None reported 

None reported

None reported

The licensee stated that, 

based on their estimates of 

the various HFO 

contributions to CDF, the 

plant's HFO-related events 

were dominated by chemical spills and releases 

from onsite and offsite 

(chemical factory within 5 

miles & nearby railroad) 

though < I1E-6/ry 

Dominated by chemical 

spill (like Unit 1); CDF 

contribution from 

lightning strikes is 

bounded by LOOP and 

other trip events in IPE

Compliance with SRP 

Compliance with SRP 

Compliance with SRP
Table 4.1: Methodologies and results for the HFO external events (Continued)

Compliance with SRP High Winds: 

4E-6 

Floods: 

2E-7

Development of severe 

accident management 

guideline for high winds 

under consideration

Byron 1&2 Compliance with SRP Compliance with SRP Not estimated None reported 

Callaway Compliance with SRP Compliance with SRP Not estimated None reported 

Calvert Compliance with SRP Compliance with SRP Not estimated (1) Emergency procedures 

Cliffs 1&2 (EP) revised to prepare 

portable ventilation fans and 

generator for adequate 

ventilation in switchgear 

rooms during hurricanes; 

(2) restrictions added to 

prevent air flights over 

protected plant areas 

Catawba Tornadoes: PRA Compliance with SRP Tornadoes: None reported 

Others: compliance 3E-6 

with SRP (-11% total 

external CDF)

Brunswick 

l&2

PRA
Table 4.1: Methodologies and results for the HFO external events (Continued)

Compliance with SRP Compliance with SRP Not estimated None reported During flooding 

walkdown, identified & 

repaired a potential leak 

path on a hatch over 

shutdown service water 

pipe tunnel and noted 

that sump pumps in 

service water pump room 

could fail due to MCC 

flooding in non-safety 

screen house; however, 

such failures are 

preventable using 

existing procedures

Columbia Compliance with SRP Compliance with SRP Not estimated Procedures were modified to Formerly known as 

ensure that C-Van containers Washington Nuclear 

are not stacked in close Project Number 2 

proximity to safety-related 

buildings 

Commanche Tornadoes: PRA Compliance with SRP Tornadoes: None reported 

Peak 1&2 Others: compliance 4E-6 

with SRP (-15% of 

total external 

CDF) 

Cooper Compliance with SRP Compliance with SRP Not estimated Protection of DG exhaust 

from tornadoes

Clinton

I
Table 4.1: Methodologies and results for the lIFO external events (Continued)

Compliance with SRP Compliance with SRP Not estimated None reported

J. 4 1 1*

Compliance with SRP Compliance with SRP Not estimated (1) A potential condition adverse 

to quality report (PCAQR) was 

initiated to address onsite hazards 

from hazardous materials; (2) 

revise description of hazards 

from chemical stored or 

transported onsite in USAR; (3) 

controlled materials program 

revised so that new onsite 

materials will be evaluated for 

control room habitability; (4) 

PCAQR initated for monitoring 

roof drains & standing water on 

aux building roof (643 ft 

elevation)

Cook 1&2 Compliance with SRP Compliance with SRP Not estimated None reported 

Diablo Compliance with SRP Compliance with SRP Not estimated None reported 

Canyon 

Dresden Compliance with SRP Compliance with SRP Not estimated Installed scuppers in roof 

2&3 parapets of turbine, reactor, & 

crib house buildings

Crystal 

River 3

Davis

Besse

!ft
Table 4.1: Methodologies and results for the YIFO external events (Continued)

High winds: PRA 

Floods: Compliance 

with SRP

Compliance with SRP High winds: 

on the order 

of 1E-6

(1) Concrete barriers installed 

around propane tank near DG 

rooms to protect against 

vehicle impact & explosion

fire; (2) increase distance 

between enlarged H2 storage system and safety equipment

s m s e 

Farley 1 Compliance with SRP Compliance with SRP Not estimated None reported 

Fermi 2 Compliance with SRP Compliance with SRP Not estimated To prevent ice formation in 

service water pumps causing 

common mode failure of DG, the 

licensee (1) implemented 

procedures to check on this 

condition, (2) installed permanent 

temperature monitoring 

equipment, (3) installed 

fiberglass curtain to reduce wind 

chill effects, & (4) modified 

terminations of cold weather 

lines to reduce chilling effect 

FitzPatrick Compliance with SRP Bounding analysis < lE-6 AOP enhanced to (1) warn of 

potential DG loss of air supply 

and (2) instructions how to 

prevent the loss of air supply

Duane 

Arnold
Table 4.1: Methodologies and results for the HIFO external events (Continued)

High winds: 

Compliance with SRP 

Floods: 

Compliance with SRP, 

with bounding 

deterministic and 

simplified PRA

Compliance with SRP Dam break

induced 

flooding:6E-7 

Other periodic 

flooding:3E-6

Provisions provided for 

flooding: portable pumps; 

new, detailed procedures; 

upgraded doors; sandbags; 

and sealing conduits

Bounding events were 

(1) dam break induced 

flooding and 

(2) periodic flooding 

from intense rainstorms

Ginna Compliance with SRP Compliance with SRP Not estimated Added roof scupper to reduce 

roof ponding 

Grand Gulf Compliance with SRP Compliance with SRP Not estimated (1) increased maintenance on 

drains, (2) revised plant flood 

mitigation procedures, and (3) 

add inspection of roof drains, 

overflows, and drainage 

system 

Haddam High winds: PRA Bounding PRA High winds: (1) Added air cooled DG 

Neck Floods: bounding PRA 6E-5 (before IPEEE); (2) 

Floods: 5E-6 arrangement to have fuel 

Lightning: delivered <24 hours of high 

8E-6 winds; (3) Procedures to 

Snow & ice: install flood door <8 hours 

7E-6 during flooding conditions; 

Others: <lE-6 and (4) procedure to remove 

snow & ice during winter 

storms

Ft Calhoun
Table 4.1: Methodologies and results for the HFO external events (Continued)

Compliance with SRP Compliance with SRP Not estimated Added guideline for company 

pilots to not fly over nuclear 

facility structures

Hope Compliance with SRP Compliance with SRP < 1E-6 (1) installed tornado missile 

Creek shield at technical support 

center door, (2) had Coast 

Guard stop shipments of 

explosives on river near plant 

Indian PRA for certain events, Compliance with SRP Tornadoes: (1) Added surveillance of 

Point 2 compliance with SRP 2E-5 control building drain flapper 

for others Extra tropical valve flow, (2) add weather 

Cyclones: stripping to doors transformer 

1E-5 area to switchgear room, (3) 

Flooding: add screens on 480V 

7E-6 switchgear room equipment 

hub drains 

Indian Compliance with SRP Hydrogen: PRA Hydrogen Considering installation of H2 Licensee estimated HFO 

Point 3 Others: compliance explosions: supply line excess flow valve CDF dominated by H2 

with SRP Slightly from line ruptures in turbine explosions in turbine 

greater than or auxiliary buildings building causing severe 

I E-6 damage to DG fire panel, 

6.9KV switchgear, and 

other cables, leading to 

SBO

Hatch 1 &2

oc
Table 4.1: Methodologies and results for the IFO external events (Continued)

Compliance with SRP Compliance with SRP Not estimated None reported Underground diesel oil 

storage tank vents are 

susceptible to tornado

generated missiles. Was 

to be resolved in 1996.

LaSalle Compliance with SRP Compliance with SRP Aircraft None reported Licensee did not provide 

or probabilistic or probabilistic impact: sufficient information to 

bounding analysis bounding analysis 5E-7 resolve several IPEEE 

Turbine- issues, including an 

generated HFO-related issue (i.e., 

missiles: external flooding and site 

1E-7 drainage) 

Tornadoes: 

3E-7 

Limerick Compliance with SRP Compliance with SRP Not estimated None reported 

McGuire PRA PRA Tornadoes: None reported Some minor plant fixes 

2E-5 (e.g., replacement of 

corroded nut and missing 

bolt) were made during 

earlier PRA development 

walkdown

Kewaunee
Table 4.1: Methodologies and results for the HFO external events (Continued)

Methodology 

Plnt Hghwnd &foosOthers CDF (fry) UFO-related improvements Comments 

Millstone 2 Compliance with SRP Compliance with SRP Not estimated Added roof scuppers; considering 

(1) protection of cooling ducts 

and dampers in control and DG 

rooms from high wind, (2) 

closure time for flood gates, (3) 

flood protection for service water 

pump motor, and (4) revising plant grading to reduce potential site flooding 

Millstone 3 PRA PRA "insignificant None reported contributors" 

Monticello Tornadoes: bounding Compliance with SRP Tornadoes: None reported PRA <1E-6 

Others: compliance with 

SRP 

Nine Mile PRA and compliance Compliance with SRP Tornadoes & Provision for specific operator Point 1 with SRP high winds: training in the use of two 

2E-6 different instrument rooms 

Tornado mis- together in the event of 

siles impact- tornadoes 

ing DG doors: 

4E-7 

Flooding from 

heavy rainfall: 

6E-7
Table 4.1: Methodologies and results for the HFO external events (Continued)

Compliance with SRP Compliance with SRP < 1E-6 None reported

North Compliance with SRP Compliance with SRP Not estimated None reported 

Anna l&2 

Oconee PRA PRA Tornadoes: (1) Additional training (study) by 

1E-5 plant personnel regarding tornado 

Flooding: events, (2) additional evaluation 

7E-6 of sheltering plans for plant 

personnel during tornadoes, (3) 

gas explosion protection 

modification to each letdown 

storage tank room's ventilation 

exhausts, (4) additional operator 

guidance to prevent H2 buildup in 

letdown storage tank rooms if 

ventilation becomes unavailable 

Oyster High winds: PRA Compliance with SRP High winds & None reported 

Creek Floods: compliance tornadoes: 

with SRP < 1E-6 

(staff estimate) 

Palisades Compliance with SRP Compliance with SRP Not estimated Added seiche protection 

barrier to protect DG fuel oil 

transfer pumps during heavy 

rainfall

Nine Mile 

Point 2
Table 4.1: Methodologies and results for the HFO external events (Continued)

High winds: PRA 

Floods: compliance 

with SRP

Compliance with SRP Tornadoes: 

Unit 1: 2E-7 

Unit 2: 4E-7 

Unit 3: 3E-9

None reported

Peach Compliance with SRP Compliance with SRP < 1E-6 None reported 

Bottom 

Perry NUREG/CR-4839 NUREG/CR-4839 Not estimated None reported 

(RMIEP) (RMIEP) 

Pilgrim High winds & local Aircraft crashes: Not estimated None reported 

intense precipitation: calculated low 

calculated low hazard hazard frequency 

frequency Others: compliance 

Floods: compliance with SRP 

with SRP 

Point PRA and compliance Compliance with SRP High winds: DG exhaust stacks were 

Beach 1&2 with SRP (low frequency of 3E-7 modified to accommodate 

occurrence) Floods: higher wind loads 

3E-6 

Prairie Compliance with SRP Compliance with SRP Not estimated None reported 

Island 1&2 

Quad Compliance with SRP Compliance with SRP Not estimated None reported 

Cities 1&2 

River Bend Compliance with SRP Compliance with SRP Not estimated None reported

Palo Verde

N)
Table 4.1: Methodologies and results for the HFO external events (Continued)

High winds: PRA 

Floods: compliance 

with SRP

Compliance with SRP Tornado/wind

induced 

missiles: 2E-6 

Other wind 

effects: 8E-6

Emergency procedures 

enhanced to (1) ensure 

walkdown of DG fuel oil 

transfer pumps following 

severe wind conditions and 

(2) isolate oil leakage & 

provide make up, if needed

Unique site features 

which enhance recovery 

of fuel oil to the DGs 

include a number of 

cross-connections and 

ability to pump oil 

directly from a fuel truck

Salem 1&2 Compliance with SRP, Compliance with Not estimated (1) Improved service & Licensee reported 

supplemented with SRP, supplemented auxiliary building penetration improvement reduced 

bounding PRA with bounding PRA seals, (2) improved H 2 tank estimated contribution to 

hold downs, (3) CWS intake CDF from flooding by 

structure modification to approximately three 

protect against detritus orders of magnitude (from 

(blockage) about 1 E-4 to about 1 E-7) 

San Onofre Compliance with SRP, Compliance with SRP < 1E-6 None reported 

supplemented by 

quantitative hazard 

screening 

Seabrook PRA PRA Floods: 1E-6 (1) Modified SWS pump 

Transportation: house roof to allow scuppers 

1E-6 to function properly, (2) 

Others:<lE-6 modified several exterior 

doors to withstand pressure 

differential from high wind 

Sequoyah Compliance with SRP Compliance with SRP Not estimated None reported

Robinson

! Uo
Table 4.1: Methodologies and results for the HFO external events (Continued)

Methodology 

Plant High winds & floods Others CDF (fry) HFO-related improvements Comments 

Shearon Compliance with SRP Compliance with SRP Not estimated None reported 

Harris 

South High winds: compliance Chemical releases: Chemical None reported 

Texas 1&2 with SRP (low hazard PRA release from 

frequency) Others: compliance nearby chem

Floods: PRA with SRP ical facilities: 

8E-6 

St. Lucie Compliance with SRP Compliance with SRP Not estimated Revised administrative 

1 &2 procedure regarding severe 

weather preparations based on 

lessons learned from 

Hurricane Andrew 

Summer Compliance with SRP Compliance with SRP Not estimated None reported 

Surry 1 &2 PRA and compliance PRA and compliance Not provided (1) Modified parapet to reduce Licensee used 

with SRP (low hazard with SRP (low hazard ponding, (2) heavy rainfall NUREG/CR-4550 results 

frequency) frequency) procedures modified to allow for some cases and 

water to flow out of turbine bounding quantitative 

building and restrict water analyses for others 

flow into the main control 

room 

Susquehanna Compliance with SRP Compliance with SRP Not estimated None reported 

1&2
Table 4.1: Methodologies and results for the IFO external events (Continued)

High winds: 

7E-7 

Floods: 8E-5 

Chemical: 

2E-7 

Aircraft: 4E-7

(1) Unspecified modification 

and (2) added special 

procedures to mitigate river 

flooding consequences

J. 4. 4 t

Compliance with SRP Compliance with SRP < 1E-6 (1) Refurbish existing flood 

wall and stop logs, 

(2) EDG fuel oil transfer 

pump elevated to protect 

against hurricane surge, 

(3) EP revised to improve 

protection against severe 

storms, 

(4) two nearby fossil plant 

stacks strengthened and 

procedures and other plant 

modifications as a result of 

lessons learned from 

Hurricane Andrew

Three Mile 

Island 1

PRA PRA

Turkey 

Point 1&2
Table 4.1: Methodologies and results for the HIFO external events (Continued)

Compliance with SRP Compliance with SRP Not estimated (1) Underground conduit to 

switchgear rooms sealed from 

external flooding,

(2) enhanced procedures to 

provide guidance following 

tornado or hurricane and to 

address site flooding, 

(3) evaluating possible OP 

revision for dam-failure

induced site flooding to 

protect switchgear room, 

(4) diesel fuel oil transfer 

pump house wall penetration 

sealed against external 

flooding

Vogtle Compliance with =SRP Compliance with SRP (Not estimated None reportedI

Compliance with SRP Compliance with SRP Not estimated (1) Pump added to cooling 

tower basin to mitigate excess 

ponding, 

(2) Pump was added to the 

surveillance testing program

Vermont 

Yankee

Waterford

L

Vogtle Compliance with SRP Compliance with SRP Not estimated None reported

I
Table 4.1: Methodologies and results for the HFO external events (Continued)

Compliance with SRP Compliance with SRP Not estimated A shield plate installed to 

protected auxiliary building 

opening against tornado

generated missiles

Wolf Compliance with SRP Compliance with SRP Not estimated None reported 

Creek I I

-'I

Watts Bar
5. UNRESOLVED SAFETY ISSUES AND GENERIC SAFETY ISSUES 

TABLES 

This chapter contains tables with plant-specific information related to the unresolved safety issues (USIs) and 

generic safety issues (GSIs) discussed in Chapter 5 of Volume 1. Table 5.2 in Volume 1 lists all the plants 

and gives the staff's overall assessment of the verification of each generic issue. The tables in this chapter 

supplements Chapter 5 of Volume 1 by identifying significant plant-specific information related to the 

generic issues and sub-issues. For example, Table 5.4 on GSI-147 identifies plant-specific features related 

to this issue, and, in the few cases where there was inadequate information to verify all aspects of this generic 

issue, the table identifies the missing information. 

The information in these tables was derived from the NRC's Staff Evaluation Reports and the supporting 

Technical Evaluation Reports. These tables address GSI-57, "Fire Protection System Impact on Safety

Related Equipment" (Table 5.1); the effects of a revised probable maximum precipitation (PMP) in rainfall 

and flood elevation (Table 5.2) and related plant improvements (Table 5.3) as part of GSI-103, "Design for 

Probable Maximum Precipitation"; GSI-147, "Fire-Induced Alternate Shutdown/Control Room Panel 

Interactions" (Table 5.4); GSI-148, "Smoke Control and Manual Fire-Fighting Effectiveness" (Table 5.5); 

GSI-156, "Systematic Evaluation Program" (Table 5.6); GSI-172, "Multiple System Responses Program" 

(Table 5.7); and the Sandia "Fire Risk Scoping Study" (Table 5.8).

5-1
Table 5.1: GSI-57, Fire protection systems impact on safety-related equipment

Arkansas 1 & 2 Yes Yes

Beaver Valley 1 & 2 Yes Yes 

Braidwood 1 & 2 Yes Yes 

Browns Ferry 2 & 3 Yes Yes 

Brunswick 1 & 2 Yes Yes 

Byron 1 & 2 Yes Yes 

Callaway Yes Yes 

Calvert Cliffs 1 & 2 Yes Yes 

Catawba 1 & 2 Yes Yes 

Clinton Yes Yes 

Columbia* Yes Yes 

Comanche Peak Yes Yes 

Cooper Yes Yes 

Crystal River 3 Yes Yes 

D. C. Cook I & 2 Yes Yes 

Davis-Besse Yes Yes 

Diablo Canyon 1 & 2 Yes Yes 

Dresden 2 & 3 Yes Yes 

Duane Arnold Yes Yes 

Farley 1 Yes Yes 

Fermi 2 Yes Yes 

FitzPatrick Yes Yes 

Fort Calhoun Yes Yes 

Ginna Yes Yes 

Grand Gulf Yes Yes

5-2

I
Table 5.1: GSI-57, Fire protection systems impact on safety-related equipment (Continued)

Licensee considered 

Plant name Suppression diversion Suppression activation 

Hatch 1 & 2 Yes Yes 

Hope Creek Yes Yes 

Indian Point 2 Yes Yes 

Indian Point 3 Yes Yes 

Kewaunee Yes Yes 

LaSalle No No 

Limerick 1 & 2 Yes Yes 

Millstone 2 Yes Yes 

Millstone 3 Yes Yes 

Monticello Yes Yes 

McGuire 1 & 2 Yes Yes 

Nine Mile Point 1 Yes Yes 

Nine Mile Point 2 Yes Yes 

North Anna 1 & 2 Yes Yes 

Oconee 1, 2, & 3 Yes Yes 

Oyster Creek Yes Yes 

Palisades Yes Yes 

Palo Verde 1, 2, & 3 Yes Yes 

Peach Bottom 2 & 3 Yes Yes 

Perry Yes Yes 

Pilgrim Yes Yes 

Point Beach 1 & 2 Yes Yes 

Prairie Island 1 & 2 Yes Yes 

Quad Cities 1 & 2 Yes Yes

5-3
Table 5.1: GSI-57, Fire protection systems impact on safety-related equipment (Continued)

* Formerly known as Washington Nuclear Project No. 2 (WNP-2).

5-4

Licensee considered 

Plant name Suppression diversion Suppression activation 

River Bend Yes Yes 

Robinson 2 Yes Yes 

Salem 1 & 2 Yes Yes 

San Onofre 2 & 3 Yes Yes 

Seabrook Yes Yes 

Sequoyah 1 & 2 Yes Yes 

Shearon Harris Yes Yes 

South Texas 1 & 2 Yes Yes 

St. Lucie 1 & 2 Yes No 

Summer Yes Yes 

Surry I & 2 Yes Yes 

Susquebanna 1 & 2 Yes Yes 

Three Mile Island 1 Yes Yes 

Turkey Point 1 & 2 Yes No 

Vermont Yankee Yes Yes 

Vogtle 1 & 2 Yes Yes 

Waterford 3 Yes Yes 

Watts Bar 1 Yes Yes 

Wolf Creek Yes Yes
Table 5.2: Probable maximum precipitation data provided in IPEEE submittals*

Byron 

Callaway 

Calvert Cliffs 1 & 2' 

Catawba 

Clinton 

Columbia**

___________________ 4.

11.7/6 9.2/6 441

5-5

714

433.3

Comanche Peak 6 /1 2 / 5 rain 810 794.7 

Cooper 9.7 /1 18.2 /1 906.5 < 906.5 

D.C. Cook I & 2 

Davis-Besse 17.5 /24 585 579 

Diablo Canyon [ 4/ 1 1 48 ft mean 

lower low 

-Iwater level6 

Dresden 2 &3ll 

Duane Arnold 

Farley 158 144 

Fermi 2 10.2 /1 17.3 /1 586.9 586.9
Table 5.2: Probable maximum precipitation data provided in IPEEE submittals (Continued) 

Flood protection elevation 

Rain fall (inches hours) (feet above mean sea level) 

Plant name Design basis Revised Protection to Maximum flood 

FitzPatrick 4 / 1 16 / 1 10 ft above 

Lake 

Ontario's 

maximum 

probable 

flood level 

Fort Calhoun 18 /1 15 ft above 25 ft above grade 

, grade' 

Ginna 165/ 

Grand Gulf 16.4 /1 28.2 /1 133 116 

Hatch I & 2 > 24.8 /N.S. 24.8 /N. S. 1108 113 

Hope Creek [ 35.49 35.4 

Indian Point 2 & 3 1 5.5 14 

Kewauneel° 605 596 ] 

LaSalle I & 2 32 /24 No change 

Limerick 1 & 2 l ll217 216.4" 

Millstone 2 17.3 /1 28 25.1 

Millstone 3 

Monticello 7.7 sai depth.) 9 /0.25 12 939.2 939.2 

McGuire I & 2 

Nine Mile Point 1 29.8 /1 <261.7 261.75 _ 

Nine Mile Point 2 262.5 

North Anna I & 2 ] 45/118.6 / 114 271 267 

Oconee 1, 2, & 3 ] 26.6 /48 

Oyster Creek 

5-6
Table 5.2: Probable maximum precipitation data provided in IPEEE submittals (Continued)

Palisades 7.7 (tatic depth) 7.7 (static an depth~wt 594.7 593.5 

Palo Verde 1, 2, & 3 957.5, 960.5, l 

Peach Bottom 2 & 3 135 133.8

Perry 

Pilgrim 

Point Beach 1 & 2 

Prairie Island 1 & 2 

Quad Cities 1 & 2 

River Bend 

Robinson 2 

Salem 1 & 2 

San Onofre 2 & 3

620 608 

23 14.7+15

588.216

17/1 

3/1

706.7"7

59616

*1

706.7 

8 ft above plant

Seabrook 

Sequoyah 1 & 2 

Shearon Harris2" 

South Texas 1 & 221 

St Lucie 1 & 222 

Summer 

Surry 1 & 2 

Susquehanna 1 & 2

6/1 1 24.1 /24 1 19.5 I 17.2

5-7

[
Table 5.2: Probable maximum precipitation data provided in IPEEE submittals (Continued) 

Turkey Point 3 & 4 6 (static depth)e 6 (static depth)23 18s 3 18 

Vermont Yankee 16.4/1 254 254 

Vogtle I & 2 18 (letatic pthptht) 15 p1 220 165 

Waterford 3 w r o29.25 

Watts Bar 1 mea l a e 

Wolf Creek215 

* A blank entry means that the information was not specified in the IPEEE submittal. N.S. - Not Specified. 

** Formerly known as Washington Nuclear Project No. 2 (WNP-2) 

F Brunswick: the recurrence frequency for this flood level is 1667 years. t Byron: plant grade is 870 ft mean sea level (MSL) but there is a 1-ft-high curb at building entrances. 

3 Calvert Cliffs: roof drains are inspected monthly by two groups of engineers. 4 Clinton: "approximately the same level up to which the plant's safety-related equipment is 

protected by waterproofing." 5 Crystal River 3: mean low water level. 

6 Diablo Canyon:pms isid thei i nta ture akre expc intake pump house, dam failures could cause 

higher water levels for short durations. 7 Fort Calhoun: it take 3.9 days after the failure of the Oahe earthen dam for the water to crest at 

the plant. Thereafter core damage is assumed by the licensee. At issuance of plant operating 

license, design basis flood was 2 ft MSL with the plan at whih i ft MSL. t9.5 Army Corps of Engineers has increased the anticipated flood level to 15 ft MSL with a 1000 recurrence 

frequency. Licensee has sealed potential flood water entry locations against the 15 ft MSL flood. 8 Hatch: the flood level is I110 ft MSL with wave runup to 113 ft MSL. The licensee stated that 

sump pumps inside the intake structure are expected to prevent leakage around the doors from 

flooding safety-related components. 9 Hope Creek: there are doors and batches below this elevation that require administrative action to 

be closed before the river flooding reaches an elevation "at which important systems could be 

compromised." 10 Kewaunee: the roof is designed for 7.7 inches of standing water while the maximum water depth 

(because of a ledge) is 3 inches. 

11 Limerick: this is from the revised PMP; the Schuykill River water level is far below plant grade. 

5-8
Table 5.2: Probable maximum precipitation data provided in IPEEE submittals (Continued) 

12 Monticello: licensee reviewed the structures and determined they could withstand the ponding 

from the PMP; the 1000 year flood level is 921 ft MSL; above 930 ft MSL the licensee must 

employ other measures, e.g., sand bags and portable pumps. 

13 Nine Mile Point 1: after IPEEE review, the licensee made a critical electrical termination below 

261.75 ft MSL, which would result in loss of offsite power and diesel generator failure. The 

licensee estimated the core damage frequency (CDF) associated with a PMP event to be 6E-7 per 

reactor-year. In the SER, the staff considered this estimate to be overly optimistic and estimated 

the CDF to be 3E-6 per reactor-year and concluded that this was not a severe accident 

vulnerability. 

14 North Anna: roof ponding is a potential problem for the turbine building. Further review will 

determine if scuppers need to be cut into the parapets to relieve roof loading. 

15 Pilgrim: this does not include wave runup. The probability of this flood was determined to be 

less than 10 6/ry. 

16 Point Beach: sand bags are used to provide protection above grade level (588.2); elevations are 

related to International Great Lakes Datum (IGLD) and not MSL. Probabilistically, the floods are 

as follows: 588.2 IGLD is 3.69x1 0-2/ry, 593.1 IGLD is 2.53xl0-/ry, and 596 IGLD is 2.8xl 0-6

/ry. 

17 Prairie Island: below this elevation, openings are protected by use of stop logs. 

18 San Onofre: the site flooding was determined to be worse from thunderstorms than from frontal 

storm flood levels; thus, the PMP was determined from thunderstorms. 

19 Sequoyah: penetrations below this elevation have water-tight seals or the equipment not protected 

to this elevation is designed for submerged operation. 

20 Shearon Harris: declared the plant in compliance by virtue of meeting the 1975 SRP guidance, as 

identified in NUREG- 1407. 

21 South Texas: "A new PMP evaluation ... was not required because the impact of the new PMP 

criteria has been evaluated previously as part of the operating license (OL) process in 1989." 

22 St Lucie: no roof ponding in excess of 2 inches is possible, except for the shield building, which 

has an 18-inch parapet. 

23 Turkey Point: maximum water accumulation on the roof is 6 inches; above 6 inches the water 

spills off the roof. Greater precipitation rates only decrease the time until water spills off the 

roof. A dike protects the plant to 18 feet. The PMF with storm surge will top the wall and 

inundate the critical safety-related equipment (emergency switchgear); the PMF frequency is 

estimated to have an upper bound of 1 04'/ry and a lower bound of 1 06 /ry. 

24 Watts Bar: the plant is required to shut down if flood levels exceed 728 feet. No other 

information was provided in the SER or TER. 

25 Wolf Creek: is protected from flooding by dikes, drainage, and site grading.

5-9
1L 

Table 5.3: Plant improvements

5- 10

Improvements completed or to be 

Plant name completed Improvements under review 

Arkansas I None identified Scuppers may be needed to prevent 

overloading roofs of buildings with 

safety-related equipment. 

Dresden 2 & 3 Installed roof scuppers in reactor and turbine None identified 

buildings and the crib house 

Ginna Modify control building roof or add None identified 

additional scupper to limit roof ponding 

Millstone 2 Installed roof scuppers, confirmed service Functionality of the backwater 

water pumps protected by walkdown, time valves 

needed to close flood gates determined to be 

adequate 

North Anna None identified turbine building roof loading; if 

necessary, scuppers will be cut into 

the parapets by 12/31/99 

Salem 1 & 2 Installed penetration seal between buildings None identified 

Surry 1 & 2 (1) turbine building parapet being modified None identified 

to prevent roof failure. (2) An active design 

change program is addressing the causes of 

water intrusion into the buildings. 

Three Mile Develop flood mitigating guidelines in event None identified 

Island of severe Susquehanna River flooding; 

"flood-related plant improvements to 

mitigate the consequences of' floods >310 ft 

MSL

I
Table 5.4: GSI-147, Fire-induced alternate shutdown/control room panel interactions

Arkansas 1 & 2

+

Beaver Valley 1 & 2

Braidwood 1 & 2

Browns Ferry 2 & 3

Brunswick 1 & 2

I

4

4

.4

Byron 1 & 2

Does not have remote shutdown panels; shut down is accomplished by local 

operator actions using equipment isolated from the control room; seeks to 

maintain availability of both shutdown trains

Callaway 

Calvert Cliffs 1 & 2 Procedure requires shedding and manual restart of most electrical loads -- if 

manual restart is unsuccessful, a SISBO will result; alternate shutdown is 

credited only for MCR abandonment, which also includes large turbine 

building fires and various fires in the yard 

Catawba 1 & 2 Independent standby shutdown system in plant yard 

Clinton Capability for safe shutdown using either Division 1 or Division 2 equipment; 

annual training to shut down from the remote shutdown panel 

Columbia Remote and alternate remote shutdown panels 

Generating* 

Comanche Peak FIVE guidance used 

Cooper 

Crystal River 3 

D. C. Cook 1 & 2 FIVE guidance used 

Davis-Besse 

Diablo Canyon 1 & 2 FIVE guidance used 

Dresden 2 & 3 

Duane Arnold The evaluation of hot shorts, as documented in the submittal, is not as robust 

as at other facilities and may represent a weakness in the plant's protection 

Farley 1

5-11
Table 5.4: GSI-147, Fire-induced alternate shutdown/control room panel interactions (Continued) 

Plant name Comments 

Fermi 2 Black-start combustion turbine-generator set provides power to the remote 

shutdown panel and equipment in the event of a loss of offsite power. 

FitzPatrick Independent safe shutdown facility with required diesels locally isolated and 

controlled 

Fort Calhoun FIVE guidance used 

Ginna Eight staff members are required for alternate shutdown; two primary 

shutdown stations manned continuously, six support stations manned as 

needed, and several valve locations manned for short period for manual 

operation 

Grand Gulf 

Hatch 1 & 2 The submittal did not contain adequate information related to spurious 

signal/hot short issue, which could compromise recovery. 

Hope Creek Independent safe shutdown facility and a remote shutdown system 

Indian Point 2 FIVE guidance used 

Indian Point 3 Appendix R diesel generator and separate 480 volt switchgear reduces risk 

Kewaunee FIVE guidance used 

LaSalle 

Limerick 1 & 2 FIVE guidance used 

Millstone 2 Self-induced station blackout (SISBO); core uncovery -1.5 hours; to get 

power from Unit 1 requires - 2 hours; operator actions to regain control of 

plant take 2 to 2.5 hours, which is less than the required 3 hours; probability 

that operators will not follow procedures and initiate SISBO if ECCS starts is 

0.5; only the hot short causing a PORV to open was considered 

Millstone 3 

Monticello 

McGuire 1 & 2 FIVE guidance used - these issues are assumed to have been considered by 

licensee 

Nine Mile Point 1 Emergency condensers automatically initiate themselves (even in control 

room fires) and need no attention for 1-2 hours 

Nine Mile Point 2 FIVE guidance used

5-12

I
Table 5.4: GSI-147, Fire-induced alternate shutdown/control room panel interactions (Continued)

North Anna 1 & 2 The submittal did not address potential for spurious actuation causing 

component damage which could compromise recovery. FIVE guidance used; 

addressed spurious actuation that might lead to a LOCA or ISLOCA.

Oconee 1, 2, & 3 Safe shutdown facility is physically and electrically independent 

Oyster Creek No credit taken for alternate shutdown panel as the control room fire CDF was 

conservatively estimated to be 3.3E-7 per ry 

Palisades Spurious actuation (hot shorts) was not addressed 

Palo Verde 1, 2, & 3 Alternate shutdown capability is in the Train B cable spreading room 

Peach Bottom 2 & 3 

Perry PRA also includes potential for total loss of shutdown system functions even 

with successful transfer of control to remote shutdown panel 

Pilgrim Necessary to control the plant from the 14 alternate shutdown panels 

Point Beach 1 & 2 FIVE guidance used 

Prairie Island 1 & 2 FIVE guidance used; CDF from failure to shutdown outside the control room 

was 5.3E-6/ry (-11% of total CDF); if shutdown from outside control room 

had a failure probability of 1.0, fire CDF would increase by a factor of 3 

Quad Cities 1 & 2 FIVE guidance used 

River Bend 

Robinson 2 FIVE guidance used 

Salem 1 & 2 

San Onofre 2 & 3 FIVE guidance used 

Seabrook "None of the four specific areas [electrical independence, prevention of loss of 

control and/or power, prevention of spurious signals/hot short, or prevention 

of the total loss of system function] ... are addressed in the submittal." 

Sequoyah 1 & 2 

Shearon Harris "Generally immune to the effects of control system interactions" 

South Texas 1 & 2 

St. Lucie 1 & 2 FIVE guidance used

5 -13
Table 5.4: GSI-147, Fire-induced alternate shutdown/control room panel interactions (Continued)

Summer

Surry 1 & 2 In addition to the alternate shutdown panel (ASP), remote monitoring panels 

in the Unit 1 cable spreading room monitors shutdown of both units 

independent of normal instrument circuits; circuits were modified to (1) 

ensure DG & ASP isolation from control room and (2) greatly reduce 

likelihood of spurious PORV actuations 

Susquehanna 1-2 FIVE guidance used 

Three Mile Island 1 

Turkey Point 3 & 4 FIVE guidance used 

Vermont Yankee 

Vogtle 1 & 2 

Waterford 3 

Watts Bar 1 Auxiliary control room and shutdown boards are located in the auxiliary building 

Wolf Creek

* Formerly known as Washington Nuclear Project No. 2 (WNP-2) 

5- 14

I
Table 5.5: GSI-148, Smoke control and manual fire-fighting effectiveness

Not credited FIVE guidance used FIVE guidance used FIVE guidance used

Beaver Valley Credited Addressed Discussion limited to Results of actual training exercised 

training/procedures for provided, including timing 

fires in each fire area 

Braidwood Credited Addressed Portable ventilation FIVE guidance used 

used 

Browns Ferry Credited only for the Addressed Not addressed except Effects of misdirected manual fire 

2 & 3 control bay, control for identification of a suppression activities were not addressed 

room, & cable smoke ejector for the 

spreading room control room 

Brunswick Credited only for Addressed Not addressed 

1&2 control room 

Byron 1 & 2 Credited Addressed Portable ventilation FIVE guidance used 

used 

Callaway Credited FIVE guidance used Not addressed 

Calvert Cliffs Credited only for FPRAIG guidance used Addressed Ability of operators to perform actions in 

control room control room were probabilistically 

evaluated to determine degradation due to 

fire impacts 

Catawba Not specified Addressed Addressed 

Clinton Credited only for Addressed Addressed 

control room

Arkansas
Table 5.5: GSI-148, Smoke control and manual fire-fighting effectiveness (Continued)

Plant name Manual flre-fighting Effectiveness Smo~ke control Comments 

Columbia Not credited FIVE guidance used Procedures in place to Fire brigade trained in smoke removal and Generating use ventilation potential for misdirected suppression Station* (including portable) for 

smoke removal 

Comanche Not credited Addressed Addressed 

Peak 

Cooper Credited only in the Addressed Addressed Training under live smoke conditions, control room and the including use of self-contained breathing non-essential apparatus (SCBA) equipment and 

switchgear room ventilation techniques 

Crystal River 3 Credited Addressed Addressed 

D.C. Cook Credited Addressed Addressed 

Davis-Besse Credited only for the Addressed Addressed FIVE guidance used; negative effects of 

control room and for misdirected manual fire suppression transient fires efforts not discussed 

Diablo Canyon Credited only for FIVE guidance used FIVE guidance used Only uses wet-pipe fire protection system 1 & 2 control room fires 

Dresden 2 & 3 Credited only for Addressed Addressed 

control room fires 

Duane Arnold Credited only for FIVE guidance used Not addressed Effects of smoke-induced misdirected 

control room fires manual fire suppression activities were not 

addressed
Table 5.5: GSI-148, Smoke control and manual fire-fighting effectiveness (Continued)

Credited only for 

control room fires

FIVE guidance used Discussion limited to 

use of SCBA equipment

Credit for manual fire fighting not 

identified in other plant areas; no 

discussion on impacts of fire or 

suppression activities on other equipment

Fermi 2 "Generally" not Addressed Addressed Not addressed is the potential for fire 

credited suppression activities to adversely impact 

other equipment 

FitzPatrick Credited only for the FIVE guidance used Addressed Manual suppression times estimates 

control bay, control usually longer than damage times in 

room, and cable discussed scenarios 

spreading room 

Fort Calhoun Credited only for FIVE guidance used FIVE guidance used 

control room fires 

Ginna Credited Addressed Addressed Average time from fire alarm until drill 

was over was 13 minutes 

Grand Gulf Credited Addressed Addressed Training with actual fire events with 

smoke control in configurations 

representative of plant conditions, training 

in potential toxic and corrosive 

characteristics of combustion products 

Hatch I & 2 Credited Addressed Addressed Not addressed is the potential for fire 

suppression activities to adversely impact 

other equipment; fire non-suppression 

factor used in PRA included detection, 

brigade notification and response, and fire 

control times

Farley
Table 5.5: GSI-148, Smoke control and manual fire-fighting effectiveness (Continued)

Not credited Addressed Addressed

Indian Point 2 Credited Addressed Smoke impact Effects of smoke-induced misdirected 

considerations and manual fire suppression activities were not 

recovery probability addressed 

modified 

Indian Point 3 "Minimally" credited FIVE guidance used FIVE guidance used FIVE guidance used; effects of smoke

induced misdirected manual fire 

suppression activities were not addressed 

Kewaunee Not credited Not addressed Not addressed Effects of smoke-induced misdirected 

manual fire suppression activities were not 

addressed 

LaSalle I & 2 Credited Not addressed Potential negative No SCBA equipment, no discussion on 

effects of smoke not response time, training, potential for 

addressed misdirected suppression causing damage, 

or of any fire pre-plans 

Limerick 1&2 Credited in some fire Partially addressed Not addressed Effects of smoke-induced misdirected 

scenarios manual fire suppression activities and 

manual fire-fighting effectiveness were 

not addressed 

Millstone 2 Credited Addressed Closed Weakness: treatment in the IPEEE 

submittal of the effects of smoke-induced 

misdirected manual fire suppression 

activities; strength: extensive fire brigade 

training, including contractor-operated simulator and unannounced fire drills

i Hope Creek

t,.0

Drills use live smoke (SCBA)
Table 5.5: GSI-148, Smoke control and manual fire-fighting effectiveness (Continued)

I Millstone 3 Closed Closed Closed I

Monticello Credited only for Addressed Addressed FIVE guidance used; except in the control 

control room fires room, fire was assumed to damage all 

cables and equipment before suppression 

McGuire 1 &2 Not specified Addressed by walkdown Addressed by walkdown 

Nine Mile Not specified Addressed Addressed Effects of smoke-induced misdirected 

Point 1 manual fire suppression activities were not 

addressed; discussion of fire identification 

(including potentially affected equipment), 

available equipment, procedures, training 

(including SCBA gear with live smoke), 

smoke removal, drills, and records 

Nine Mile Credited only for Addressed Addressed 

Point 2 control room fires 

North Anna Credited Addressed (FIVE) Addressed FIVE guidance used; effects of smoke

induced misdirected manual fire 

suppression activities were not addressed; 

operator effectiveness in a smoke-filled 

environment was not adequately addressed 

Oconee Credited Addressed Addressed Effects of smoke-induced misdirected 

1, 2, & 3 manual fire suppression activities were not 

addressed 

Oyster Creek Not credited Addressed Partial Effects of smoke-induced misdirected 

manual fire suppression activities were not 

addressed
Table 5.5: GSI-148, Smoke control and manual fire-fighting effectiveness (Continued)

Palisades Credited only for fires 

in control room, cable 

spreading room, and 

two vital switchgear 

rooms

Addressed Addressed

Palo Verde Not credited Addressed Addressed 

Peach Bottom Credited for several FIVE guidance used; 30 FIVE guidance used 

2 & 3 fire areas minutes to control a fire 

Perry Credited if time to Addressed Addressed 

damage greater than 

detection/suppression 

time 

Pilgrim Credited Addressed Addressed 

Point Beach Credited Addressed Addressed 

Prairie Island Credited only for Addressed Addressed 

control room, relay 

room, and auxiliary 

feedwater pump room 

fires 

Quad Cities Not credited FIVE guidance used FIVE guidance used Negative effects of misdirected manual 

fire suppression efforts not discussed 

River Bend

if 

k-)
Table 5.5: GSI-148, Smoke control and manual fire-fighting effectiveness (Continued)

FIVE guidance used FIVE guidance used Thorough discussion of available 

equipment, procedures, communication, 

training (including SCBA gear), drills, and records

Salem 1 & 2 Not specified FIVE guidance used FIVE guidance used Dedicated fire department for Salem 

San Onofre Considered in the FIVE guidance used FIVE guidance used 

2 & 3 submittal but not 

credited in any of the 

fire compartments 

assessed 

Seabrook Credited on a case-by- FIVE guidance used Open Negative effects of misdirected manual 

1 & 2 case basis fire suppression efforts and potential of 

breach of fire barriers were not discussed 

Sequoyah Credited Addressed Addressed 

Shearon Harris Credited for some fire FIVE guidance used FIVE guidance used Negative effects of misdirected manual 

scenarios fire suppression efforts not discussed 

South Texas Closed Closed Closed 

St. Lucie 1 & 2 Not credited Not addressed Not addressed 

Summer Not credited FIVE guidance used FIVE guidance used 

Surry 1 & 2 Not specified FIVE guidance used FIVE guidance used 

Susquehanna Not credited Closed Closed

Robinson 2 Credited
Table 5.5: GSI-148, Smoke control and manual fire-fighting effectiveness (Continued)

Three Mile 

Island 1

Not credited Addressed Addressed

Turkey Point Not credited Not addressed Not addressed 

Vermont Not specified Addressed Addressed FIVE guidance used 

Yankee 

Vogtle 1 & 2 Credited Addressed Addressed Negative effects of misdirected manual 

fire suppression efforts and effects of 

compromised barriers during fire-fighting 

activities were not discussed 

Waterford 3 Credited only for Plant fire brigade trained Self-contained breathing Negative effects of misdirected manual 

welding/cutting- in accordance with plant apparatus available; fire suppression efforts not discussed 

initiated fire scenarios training procedures, impact of smoke on 

and one control room which meets Appendix R operator's ability to 

fire scenario requirements. Fire safely shut down the 

brigade members are plant considered 

educated on toxic and 

corrosive characteristics 

of combustion products 

Watts Bar Not specified FIVE guidance used Self-contained breathing 

apparatus and portable 

ventilation equipment 

provided at key plant 

locations 

Wolf Creek Not specified FIVE guidance used FIVE guidance used

* Formerly known as Washington Nuclear Project No. 2 (WNP-2).

t'J
Table 5.6: GSI-156, Systematic evaluation program

Hydrology Design codes, Dam Settlement 

& withstand Industrial Tornado Severe criteria, and integrity, site & Seismic Shutdown 

Plant name floods hazards missiles weather loadings flooding liquefaction design I&C 

Arkansas 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Beaver Valley 1 & 2 1975 SRP plant 

Braidwood I & 2 1975 SRP plant 

Browns Ferry 3 Yes Yes Yes Yes Yes Yes N.E. Yes 

Brunswick 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Byron 1 & 2 1975 SRP plant 

Callaway 1975 SRP plant 

Calvert Cliffs 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Y 

Catawba 1 & 2 1975 SRP plant 

Clinton 1975 SRP plant 

Columbia Generating* 1975 SRP plant 

Comanche Peak 1975 SRP plant 

Cooper Yes Yes Yes Yes Yes YYes es Yes Yes 

Crystal River 3 1975 SRP plant 

D.C. Cook 1 & 2 Yes Yes Yes Yes Yes I Yes Yes Yes Yes 

Davis-Besse 1975 SRP plant 

Diablo Canyon 1 & 2 1975 SRP plant
Table 5.6: GSI-156, Systematic evaluation program (Continued)

IHydrology Design codes, Dam Settlement 

& withstand Industrial Tornado Severe criteria, and integrity, site & Seismic Shutdown 

Plant name floods hazards missiles weather loadings flooding liquefaction design I&C 

Dresden 2 & 3 Yes Yes Yes Yes Yes Yes N.A. Yes Yes 

Duane Arnold Yes Yes Yes Yes Yes Yes N.E. Yes Yes 

Farley 1 1975 SRP plant 

Fermi 2 1975 SRP plant 

FitzPatrick Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Fort Calhoun Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Ginna Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Grand Gulf 1975 SRP plant 

Hatch 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Hope Creek 1975 SRP plant 

Indian Point 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Indian Point 3 Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Kewaunee Yes Yes Yes Yes Yes Yes Yes Yes Yes 

LaSalle 1975 SRP plant 

Limerick 1 & 2 1975 SRP plant 

Millstone 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Millstone 3 1975 SRP plant
Table 5.6: GSI-156, Systematic evaluation program (Continued)

Monticello Yes Yes Yes Yes Yes Yes Yes Yes Yes

McGuire 1 & 2 1975 SRP plant 

Nine Mile Point1 Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Nine Mile Point 2 1975 SRP plant 

North Anna 1 & 2 1975 SRP plant 

Oconee 1, 2, & 3 Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Oyster Creek Resolved by NUREG-0822 (January 1983) and NUREG-0822, Supplement 1 (July 1988) 

Palisades Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Palo Verde 1, 2, & 3 1975 SRP plant 

Peach Bottom 2 & 3 Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Perry 1975 SRP plant 

Pilgrim Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Point Beach 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Prairie Island 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Quad Cities 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes 

River Bend 1975 SRP plant 

Robinson 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes

t./i
Table 5.6: GSI-156, Systematic evaluation program (Continued)

Salem 1 & 2 1975 SRP plant

San Onofre 2 & 3 1975 SRP plant 

Seabrook 1975 SRP plant 

Sequoyah 1 & 2 1975 SRP plant 

Shearon Harris 1975 SRP plant 

South Texas 1 & 2 1975 SRP plant 

St. Lucie 1 & 2 1975 SRP plant 

Summer 1975 SRP plant 

Surry 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes 

Susquehanna 1 & 2 1975 SRP plant 

Three Mile Island 1 Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Turkey Point 3 & 4 Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Vermont Yankee Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Vogtle 1 & 2 1975 SRP plant 

Waterford 3 1975 SRP plant 

Watts Bar 1 1975 SRP plant 

Wolf Creek 1975 SRP plant
Table 5.6: GSI-156, Systematic evaluation program (Continued)

N.A. Not Applicable; soil related issues do not apply to rock sites. 

N.E. Not Evaluated; Generic Letter 88-20, Supplement 5, states that soil failures need not be evaluated by focused-scope plants. 

* Formerly known as Washington Nuclear Project No. 2 (WNP-2).
Table 5.7: GSI-172, Multiple system responses program

Effects of Seismic Seismic Hydrogen Systems' Flood and Spatial Seismic Relay common Beyond 

Plant name activation' aCtiVation 2 fires' ruptures' depend' moisture6 interactions' flooding' chatter' cause15 SSE"I 

Arkansas 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Beaver Valley 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Braidwood 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Browns Ferry 3 Yes Yes Yes Yes Yes Yes Yes Yes Yes No Yes 

Brunswick 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Byron 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Callaway Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Calvert Cliffs 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Catawba 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Clinton Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Columbia* Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Comanche Peak Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Cooper Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Crystal River 3 Yes Yes Yes Yes Yes Yes Yes No Yes No Yes 

D.C. Cook 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Davis-Besse Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Diablo Canyon 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Dresden 2 & 3 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes

00
Table 5.7: GSI-172, Multiple system responses program (Continued)

k)

Duane Arnold Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Farley I Yes Yes Yes Yes Yes No Yes Yes Yes No N.E. 

Fermi 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

FitzPatrick Yes Yes (not Yes Yes Yes Yes Yes Yes Yes Yes Yes 

credible < 

0.3 g) 

Fort Calhoun Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Ginna Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Grand Gulf Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Hatch Hope I & 2 Yes Yes Partial Partial Partial Yes Yes Yes Yes Yes Yes Creek Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

H ope 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Indian Point 3 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Kewaunee Yes Yes Yes No Yes Yes Yes No Yes Yes Yes 

LaSalle No Yes No No No Partial No No Yes Yes Yes 

Limerick 1 & 2 Yes Yes Yes Yes Yes Yes Yes Partial Yes Partial Yes 

Millstone 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Millstone 3 Yes Yes Yes 12 Yes12 Yes Yes Yes12 Yes1 2 Yes Yes Yes 

Monticello Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes
Table 5.7: GSI-172, Multiple system responses program (Continued)

Effcts of. Seismic Seismic H.drogen Systems' Flood and Spatial Seismic Relay CoLmon Beyond 

Plant name activation' activation2 fires' ruptures' depend5 moisture' interactions' flooding' chatter' causelo SSE" 

McGuire 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Nine Mile Point 1 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Nine Mile Point 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

North Anna 1 & 2 Yes No Yes Yes Yes Yes Yes Yes Yes Partial Yes 

Oconee 1, 2, & 3 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Oyster Creek Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Palisades Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Palo Verde 1, 2, & 3 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Peach Bottom 2 & 3 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Perry Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Pilgrim Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Point Beach 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Prairie Island 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Quad Cities 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

River Bend Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Robinson 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Salem 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes

San Onofre 2 & 3 Yes Yes

Ye ______ ~ e _i_ ~ __ es ~- _I_ Yes _ __j_3_ _ 1 _ V__ _ I __ e __ (es Yes Ye• Yes Yes Vat V•c g• x.r^• •k2
Table 5.7: GSI-172, Multiple system responses program (Continued)

Effects of Seismic Seismic Hlydrogen Systems' Flood and Spatial Seismic Relay Common Beyond 

Plant name activation' activation2 fires' ruptures' depend' moisture' interactions' flooding' chatter' causelo SSE, 

Seabrook Yes Yes Partial Partial No Yes Yes Yes Yes Yes Yes 

Sequoyah 1 & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Shearon Harris Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

South Texas I & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

St. Lucie 1 & 2 No No Yes Yes Yes Yes No No Yes No N.E. 

Summer Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Surry 1 & 2 Yes Yes Yes Yes** Yes Yes Yes Yes Yes Yes Yes 

Susquehanna I & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Three Mile Island 1 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Turkey Point 3 & 4 Yes No Yes Yes Yes Yes Yes No Yes No Yes 

Vermont Yankee Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Vogtle I & 2 Yes Yes Yes Yes Yes Yes Yes Yes Yes No Yes 

Waterford 3 Yes Yes Yes No Yes Yes Yes Yes N.A. Yes N.A. 

Watts Bar 1 Yes Yes Yes Yes No No Yes Yes Yes Yes Yes 

Wolf Creek Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes 

* Formerly known as Washington Nuclear Project No. 2 (WNP-2). 

** Surry: two issues (excessive flexibility of stainless steel tubes carrying hydrogen and poor restraint of hydrogen cylinders) are identified for 

future resolution. 

N.E. No evaluation needed for reduced-scope plants (NUREG- 1407, Section 3.2.4.5)

I
Table 5.7: GSI-172, Multiple system responses program (Continued) 

Effects of fire protection system actuation on non-safety related and safety-related equipment. 2 Seismically induced for suppression system actuations. 

3 Seismically induced fires. 

4 Effects of hydrogen line ruptures. 

5 Non-safety related control system/safety-related system dependencies. 6 Effects of flooding and/or moisture intrusion on non-safety related and safety-related equipment. 7 Seismically induced spatial and functional interactions. 

8 Seismically induced flooding. 

9 Seismically induced relay chatter. 

10 IPEEE-related aspects of common cause failures related to human actions. 

11 Evaluation of earthquake magnitudes greater than the safe shutdown earthquake. 12 Millstone 3: resolved by walkdown based on composition of walkdown team and expertise of licensee's independent reviewer.
Table 5.8: Sandia fire risk scoping study issues

Arkansas 1 & 2 Yes Yes Yes Yes Yes FIVE guidance used

Beaver Valley 1 & 2 Yes Yes Yes Yes Yes 

Braidwood 1 & 2 Yes (FIVE) Yes Yes (FIVE) Yes Yes FIVE guidance used, 

(FIVE) seismic/fire walkdowns, fire 

sources (flammable storage 

cabinets and oil drums) 

were identified but 

acceptable because no 

ignition or target identified 

Browns Ferry 2 & 3 Yes Yes Yes No (FIVE) Yes Assumed effects of smoke 

(FIVE) bounded by fire effects; 

effects of fire suppressants 

on equipment not addressed; 

operator effectiveness 

addressed by procedures, 

training, & equipment 

(SCBA) 

Brunswick 1 & 2 Yes Yes Yes Yes Yes Seismic walkdowns, 

(FIVE) addressed effects of 

combustion products

(I
Table 5.8: Sandia fire risk scoping study issues (Continued)

Byron 1 & 2 Yes Yes Yes Yes Yes FIVE guidance used, 

seismic/fire walkdowns, fire 

sources (flammable storage 

cabinets, gas bottles, oil 

drums, switchgear) were 

identified but acceptable 

because no target identified, 

non-rated barrier failures 

considered in multi-

.1VL11uL~itntlltnt arialysis 

Callaway Yes Yes Yes Yes Yes Seismic walkdown, many 

new procedures implemented

Calvert Cliffs 1 & 2 Yes Yes Yes, FPRAIG 

guidance used

Yes Yes

L _____ I t _______ L _________

Seismic walkdowns 

performed; past inadvertent 

activations did not affect 

equipment operability; 

modifications made (install 

conduit and cabinet seals, 

holes in junction box 

bottoms, and water shields) 

as part of GSI-57 before 

IPEEE and credited in IPEEE

IPEEE

!
Table 5.8: Sandia fire risk scoping study issues (Continued)

Catawba 1 & 2 Yes Yes Yes Yes Yes Independent standby 

shutdown system in plant 

yard

Clinton Yes Yes Yes Yes Yes Seismic walkdown; 

Thermo-Lag (to be modified 

or replaced during next two 

refueling outages); 

seismically designed to 

same quality as other 

systems in the same area. 

Columbia Generating Yes Yes Yes Yes Yes Seismic & fire walkdowns, 

Station* (NFPA) meets inspection standards 

of NFPA 80 & 90A 

Comanche Peak Yes Yes Yes Yes Yes Seismic walkdowns 

Cooper Yes Yes Yes Yes Yes Fire protection systems 

installed in accordance with 

NFPA standards 

Crystal River 3 Yes Yes Yes Yes Yes 

D.C. Cook 1 & 2 Yes Yes Yes Yes Yes Remote shutdown through local shutdown indication 

panels located in several 

spots in the auxiliary 

building
Table 5.8: Sandia fire risk scoping study issues (Continued)

Davis-Besse Yes Yes Yes Yes Yes Effects of smoke-induced 

misdirected manual fire 

suppression activities were 

not addressed; proposed 

action to correct seismic 

mounting of two small 

flammable compressed gas

Diablo Canyon 1 & 2 Yes Yes Yes Yes Yes Not addressed: combustion 

products effects on 

equipment, relays freezing 

from CO2, and inadvertent 

discharge 

Dresden 2 & 3 Yes Yes Yes Yes Yes Seismic walkdowns; multi

compartment fires 

evaluated; fire barriers and 

10% of the penetration seals 

are inspected every 18 months 

Duane Arnold Yes Yes No Yes Yes No credit is taken for 

manual fire fighting (except in the control room) 

Farley 1 Yes Yes Yes (FIVE) Yes Yes 

I_____ I__ (FIVE) IIT
Table 5.8: Sandia fire risk scoping study issues (Continued)

Yes Yes No Yes Yes Effects of smoke-induced 

misdirected manual fire 

suppression activities were 

not addressed

FitzPatrick Yes Yes Yes (FIVE) Yes Yes Remote shutdown is from 

four panels in different parts 

of the plant; instrumentation 

is on a shutdown panel and 

several instrumentation 

racks; training is with live

fire and smoke environment 

gear; FIVE guidance used 

Fort Calhoun Yes Yes Yes Yes Yes Explicitly considered 

survival from combustion 

products, fire suppression 

actuation, operator actions, 

flames, and hot gas layer; 

probability of barrier failure 

included in fire PRA

Fermi 2
Table 5.8: Sandia fire risk scoping study issues (Continued)

Yes Yes Yes Yes Fire wrap on charging pump 

A provides "significant" 

(unspecified) risk reduction 

- "apparently" not Thermo

Lag; no failures of fire 

doors, fire dampers, or 

penetration seals that were 

not promptly detected

Grand Gulf Yes Yes Yes Yes Yes Thermo-Lag being upgraded 

to ensure hourly fire endurance rating 

Hatch 1 & 2 Partial Partial Partial Yes Partial Inadequate information to 

resolve issues (left to right): 

anchorage of electrical 

cabinets not on safe 

shutdown equipment list, 

failure of active barriers, 

effects of misdirected spray, 

and hot shorts 

Hope Creek Yes Yes Yes Yes Yes Inspection procedures 

include fire barrier penetration seals 

Indian Point 2 Yes Yes No Yes Yes FIVE guidance used

Ginna Yes

00
Table 5.8: Sandia fire risk scoping study issues (Continued)

Indian Point 3 Yes Yes Partial Yes Yes FIVE guidance used; effects 

of smoke-induced 

misdirected manual fire 

suppression activities were 

not addressed

Kewaunee Yes Yes No Yes Yes Effects of smoke-induced 

misdirected manual fire 

suppression activities were 

not addressed 

LaSalle 1 & 2 No No No No Yes Thermo-Lag is cited by 

name 

Limerick 1 & 2 Yes Yes Yes Yes Yes FIVE guidance used 

Millstone 2 Yes Yes Yes Yes Yes FIVE guidance used; 

Thermo-Lag is cited by 

name; separate walkdowns 

to address FRSS issues; 

27% of events result in 

damaged equipment from 

water spray; weaknesses: 

diesel fire pump fuel tank 

could tip in a seismic event, 

block walls in fire water 

pump houses, support for a 

long run of fire water pipe
Table 5.8: Sandia fire risk scoping study issues (Continued)

Yes Yes Yes Yes Yes Walkdown performed in 

1985 by licensee & 

independent reviewer

Monticello Yes Yes Yes Yes Yes FIVE guidance and seismic 

walkdowns used; fire barrier 

inspection procedures; 

brigade training includes 

drills and communications; 

survivability includes 

effects of combustion 

products 

McGuire 1 & 2 Yes Yes Yes Yes Yes Standby shutdown system 

mitigates adverse effects of 

failure of redundant trains 

caused by breach of fire 

barriers

Millstone 3

4ýk 0 
Table 5.8: Sandia fire risk scoping study issues (Continued)

Nine Mile Point 1 Yes Yes No Yes Yes Effects of smoke-induced 

misdirected manual fire 

suppression activities were 

not addressed; walkdowns 

reviewed fire protection 

systems for compliance with 

NFPA codes and standards; 

all Appendix R doors are 

inspected daily and all seals 

were inspected in 1989

1990; all barriers in 

inspection and maintenance 

program

Nine Mile Point 2 Yes Yes Yes Yes Yes FIVE guidance used 

North Anna 1 & 2 Yes Yes Yes Yes Yes FIVE guidance used 

Oconee 1, 2, & 3 Yes Yes No Yes Yes Effects of smoke-induced 

misdirected manual fire 

suppression activities were 

not addressed 

Oyster Creek Yes Yes No Yes Yes Effects of smoke-induced 

misdirected manual fire 

suppression activities were 

not addressed
Table 5.8: Sandia fire risk scoping study issues (Continued)

Palisades Yes Yes Yes

Palo Verde 1, 2, 3 Yes Yes Yes Yes Yes FIVE and fire compartment 

interaction analysis (FCIA) 

guidance used 

Peach Bottom 2 & 3 Yes Yes Yes Yes Yes Seismic walkdown 

performed; no adverse 

impact of mercury relay 

switches on safety systems; 

weakness: CO2 system's 

tank anchorage & batteries; 

improvements to be 

completed by 12/31/00 

Perry Yes Yes Yes Yes Yes Seismic walkdown 

performed; fire barrier 

inspection frequencies 

identified 

Pilgrim Yes Yes Yes Yes Yes FIVE guidance used; fire 

protection systems installed 

in accordance with NFPA codes and standards 

Point Beach 1 & 2 Yes Yes Yes Yes Yes FIVE guidance used; 

seismic and fire walkdowns 

performed

Yes Yes
Table 5.8: Sandia fire risk scoping study issues (Continued)

Prairie Island 1 & 2 Yes Yes Yes Yes Yes FIVE guidance used

Quad Cities 1 & 2 Yes Yes Yes Yes Yes FIVE guidance used 

River Bend 

Robinson 2 Yes Yes Yes Yes Yes FIVE guidance used; 

seismic and fire walkdowns 

performed 

Salem 1 & 2 Yes Yes Yes Yes Yes FIVE guidance used; 

seismic and fire walkdowns 

performed 

San Onofre 2 & 3 Yes Yes Yes Yes Yes Seismic walkdown, seismic 

Category 11/1 analysis 

performed; several analyses 

conducted on effects of fire 

suppression system 

actuation on equipment

(.,r
Table 5.8: Sandia fire risk scoping study issues (Continued)

Yes Yes No FIVE guidance used for 

some issues; the submittal 

did not address manual fire

fighting breaching fire 

barriers, failure of fire 

barriers, alternate shutdown 

electrical independence, loss 

of control or power before 

transfer, spurious 

actuations, and total loss of 

system function.

Sequoyah I & 2 Yes Yes Yes Yes Yes FIVE guidance used. 

Shearon Harris Yes Yes No Yes Yes FIVE guidance used; effects 

of smoke-induced 

misdirected manual fire 

suppression activities were 

not addressed 

South Texas 1 & 2 Yes Yes Yes Yes Yes 

St. Lucie 1 & 2 No Yes No No Yes Nothing in the TER 

indicates these issues should 

be open 

Summer Yes Yes Yes Yes Yes FIVE guidance used

Seabrook Yes Partial
Table 5.8: Sandia fire risk scoping study issues (Continued)

Surry 1 & 2 Yes Yes Yes Yes

_________ I- I I I I

Susquehanna 1 & 2 Yes Yes Yes Yes

___________ I _______ J______ J_________ J _________ J

Yes

Yes

FIVE guidance used; 

identified items to be 

resolved are (1) hydrogen 

line modifications, (2) 

anchorage & storage issues 

for CO 2 and hydrogen 

cylinders, and (3) anchorage 

of oil drums and other 

storage containers

Seismic and fire 

walkdowns; -200 member 

fire brigade; strength: 

independent, black-start, 

portable diesel generator to 

support shutdown; 

weaknesses: (1) pumps in 

non-seismically designed 

building, (2) CO2 tank not 

seismically supported, (3) 

batteries (to start diesel 

pump) had no spacers 

between cells or end stops 

on battery racks, and (4) 

small, unsupported metal 

cabinets are free to tip over
Table 5.8: Sandia fire risk scoping study issues (Continued)

Three Mile Island I Yes

Turkey Point 3 & 4 Yes

Yes

Yes

Yes

No

Vermont Yankee Yes Yes Yes

4. _______ I. _________

Yes Yes

No I Yes

training I 

1

Yes Yes

Seismic walkdown; a 0.1 

factor was applied to 

account for damage to all 

equipment in a fire zone, 

including redundant 

equipment; Thermo-Lag 

installation is used 

All unescorted personnel 

must undergo fire watch training

Seismic-fire interactions 

identified three weaknesses: 

two to be evaluated (112 

piping & fuel oil tank 

supports) and one to be 

upgraded (anchorage of 

buses 1 and 2 to prevent 

sliding)

4-

= I I

!
Table 5.8: Sandia fire risk scoping study issues (Continued)

Vogtle 1 & 2 Yes Yes Partial Yes Yes Effects of smoke-induced 

misdirected manual fire 

suppression activities and 

potential barrier breaches 

were not addressed; 

comments: seismic 

walkdown; curbing around 

equipment containing 

significant quantities of 

flammable liquids; fire 

protection systems installed 

to category 111 criteria; 

failure rates are 0.13/door

yr, 0.001 1/damper-yr, 

0.003/seal-yr, unavailability 

of door is estimated to be 

5.94E-5

Waterford 3 Yes Yes Yes Yes Yes Seismic and fire 

walkdowns; all penetration 

seals inspected in 1988 

Watts Bar 1 Yes Yes Yes Yes Yes FIVE guidance used; 

seismic walkdowns; fire 

protection systems installed 

to category II/I criteria
Table 5.8: Sandia fire risk scoping study issues (Continued)

Fire walkdown; fire 

protection systems piping 

adequately supported 

against SSE in safety

related areas; emergency 

lighting installed; SCBA; 

training includes 

encountering toxic and 

corrosive combustion 

products; control room fire 

PRA included effects of 

smoke for abandonment; 

remote shutdown uses Train 

B

* Formerly known as Washington Nuclear Project No. 2 (WNP-2).

00

- I _______________ L _____________ J. ____________________ I ____

0
NRC FORM 335 U.S. NUCLEAR REGULATORY COMMISSION 1. REPORT NUMBER 

(2-89) (Assigned by NRC, Add Vol., Supp., Rev., 

NRCM 1102, and Addendum Numbers, If any.) 

3201, 3202 BIBLIOGRAPHIC DATA SHEET 

(See instructions on the reverse) 

2. TITLE AND SUBTITLE NUREG-1742, Vol. 2 

Perspectives Gained from the Individual Plant Examination of External Events (IPEEE) 

Program 3. DATE REPORT PUBLISHED 

MONTH I YEAR 

Tables April 2002 

Final Report 4. FIN OR GRANT NUMBER 

5. AUTHOR(S) 6. TYPE OF REPORT 

Technical 

7. PERIOD COVERED (Inclusive Dates) 

8. PERFORMING ORGANIZATION - NAME AND ADDRESS (If NRC, provide Division, Office or Region, U.S. Nuclear Regulatory Commission, and mailing address; if contractor, 

provide name and mailing address.) 

Division of Risk Analysis and Applications 

Office of Nuclear Regulatory Research 

U.S. Nuclear Regulatory Commission 

Washington, D.C. 20555

9. SPONSORING ORGANIZATION - NAME AND ADDRESS (If NRC, type "Same as above'; if contractor, provide NRC Division, Office or Region, U.S. Nuclear Regulatory C~ommission, 

and mailing address.)

Same as above

10. SUPPLEMENTARY NOTES 

Alan I NA " k; N ' IDricrD-f 'ln •Nfl~n r

11. ABSTRACT (200 words or less) 

The NRC requested by Generic Letter 88-20, Supplement 4, and NUREG-1407, that each licensee perform an IPEEE to 

identify and report all plant-specific vulnerabilities to severe accidents caused by external events. The external events 

considered included seismic events; internal fires; and high winds, floods, and other external initiating events including 

transportation or nearby facility accidents and plant-unique hazards. All currently operating U.S. nuclear power plants have 

completed their assessments. 

The objective of the NRC's IPEEE submittal reviews was to ascertain whether the licensees' IPEEE processes were capable of 

identifying severe accident vulnerabilities to such external events, and implementing cost-effective safety improvements to 

either eliminate or reduce the impact of those vulnerabilities. The reviews did not attempt to validate or verify the licensees' 

results. 

The purpose of this report is to document the perspectives gleaned from the technical reviews of the IPEEE submittals. These 

include a description of the overall IPEEE process and findings; conclusions regarding the dominant risk contributors for the 

major areas of evaluation; an overview of plant improvements; a description of the overall strengths and weaknesses in the 

licensees' implementation of the IPEEE evaluation methodologies; and an assessment of the overall effectiveness in meeting 

the IPEEE objectives.

12. KEY WORDS/DESCRIPTORS (List words or phrases that will assist researchers in locating the report.) 13. AVAILABILITY STATEMENT 

IPE, IPEEE, Probabilistic Risk Assessment, severe accident, seismic, fire, flood, tornado, earthquake, unlimited 

hurricane, Generic Letter 88-20, NUREG-1407, external events, Fire Induced Vulnerability Evaluation, 14. SECURITY CLASSIFICATION 

unresolved safety issue, generic safety issue (Tiis Page) 

unclassified 

(This Report) 

unclassified 

15. NUMBER OF PAGES 

16. PRICE

NRC FORM 335 (2-89)

CIH . U H, -J ti
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NUCLEAR REGULATORY COMMISSION 

WASHINGTON, DC 20555-0001 

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PENALTY FOR PRIVATE USE, $300