Text

Response to Request for Additional Information in Support of LAR Nos. 306 and 176 Emergency Diesel Generator Allowed Outage Time Extension
	ML043070444
Person / Time
Site:	Beaver Valley ; (DPR-066, NPF-073)
Issue date:	10/29/2004
From:	Pearce L; FirstEnergy Nuclear Operating Co
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	L-04-141
	Download: ML043070444 (82)
	v • d • e

FENOC Beaver Valley Power Station Route 168 FirstEnergy Nuclear Operating Company Shippingport* PA 15077-0004 L. Jrilliant Pearce 724-682-5234 Site Vice President Far: 724-643-8069 October 29, 2004 L-04-141 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555-0001

Subject:

Beaver Valley Power Station, Unit No. 1 and No. 2 BV-1 Docket No. 50-334, License No. DPR-66 BV-2 Docket No. 50-412, License No. NPF-73 Response to Request for Additional Information in Support of LAR Nos. 306 and 176 Emergency Diesel Generator Allowed Outage Time Extension This letter provides the FirstEnergy Nuclear Operating Company (FENOC) response to an NRC request for additional information (RAI) dated September 24, 2004, relating to FENOC letter L-04-072 dated May 26, 2004.

FENOC letter L-04-072 submitted License Amendment Request (LAR) Nos. 306 and 176 for Beaver Valley Power Station (BVPS) Units No. 1 and 2, respectively. These amendment requests proposed changes to the BVPS Unit No. 1 and 2 Technical Specifications which would extend the current Emergency Diesel Generator (EDG) allowed outage time (AOT) to 14 days, remove the surveillance requirement for performing EDG maintenance inspections from the Technical Specifications, and revise the EDG Technical Specification requirements for restoring EDG fuel oil properties to within limits.

The FENOC response to the request for additional information is provided in Attachment A of this letter. Attachment B of this letter provides a discussion of the PRA model differences between BVPS Unit 1 and Unit 2 and their impacts on the EDG AOT Extension. Attachment C provides the BVPS EDG recovery methodology used in the PRA models. No new regulatory commitments are contained in this submittal.

This information does not change the evaluations or conclusions of the No Significant Hazards Consideration presented in FENOC letter L-04-072. If there are any questions concerning this matter, please contact Mr. Larry R. Freeland, Manager, Regulatory Compliance at 724-682-4284.

i-'

Beaver Valley Power Station, Unit No. 1 and No. 2 Response to RAI in Support of LAR Nos. 306 and 176 Emergency Diesel Generator Allowed Outage Time Extension L-04-141 Page 2 I declare under penalty of perjury that the foregoing is true and correct. Executed on October 2Z, 2004.

Since ely, L.

eim arce Attachments:

A.

Responses to Request for Additional Information Related to BVPS-1 and 2 EDG AOT Extension B.

Key Differences in the BVPS PRA Models and Their Impact on the EDG AOT Extension C.

BVPS EDG Recovery Methodology c:

Mr. T. G. Colburn, NRR Senior Project Manager Mr. P. C. Cataldo, NRC Sr. Resident Inspector Mr. S. J. Collins, NRC Region I Administrator Mr. D. A. Allard, Director BRP/DEP Mr. L. E. Ryan (BRP/DEP)

I Attachment A Letter L-04-141 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION RELATED TO FIRSTENERGY NUCLEAR OPERATING COMPANY (FENOC)

BEAVER VALLEY POWER STATION, UNIT NOS. 1 AND 2 (BVPS-1 AND 2)

EMERGENCY DIESEL GENERATOR (EDG) ALLOWED OUTAGE TIME (AOT)

DOCKET NOS. 50-334 AND 50412 The NRC staff has requested the following additional information to complete its review of the FENOC license amendment application to extend the BVPS-1 and 2 EDG AOTs to 14 days:

1. Section 4.3.2 of the license amendment request (LAR) states that the BVPS-1 and 2 probabilistic risk assessment (PRA) models undervent a Westinghouse Owners' Group Peer Review in July 2002. Please provide the following information: (Regulatory Guide (RG) 1.174, Section 2.2.3; RG 1.177, Section 2.3.1)

a. The LAR states that the Peer Review focused primarily on the Unit 2 PRA, but the Review Team was provided with Unit and PRA modeling differences. Please provide a summary of the differences between Unit 1 and 2, and the impact these differences have on the risk assessment of the proposed EDG AOT extension.

Response

The PRA Peer Review team was presented with the PRA modeling differences between the BVPS Units during their review in July 2002. However, following the PRA peer review both the Unit I and Unit 2 PRA models have been updated, and incorporate the PRA Peer Review Category A and Category B findings and observations that were found to have an impact on the models. The Unit 1 PRA model was updated in September 2003 to Revision 3 (BVIREV3), and the Unit 2 PRA model was updated in May 2003 to Revision 3B (BV2REV3B). Attachment B lists the current major PRA modeling differences between the BVPS Units and their expected impact on the 14-day EDG AOT extension.

b. The LAR states that seismic and fire risk are directly included with the internal events and internal flood initiators in the BVPS-1 and 2 PRA models. The Westinghouse Peer Review process utilizes NEI 00-02, which addresses at power, internal events PRAs. For seismic and fire risk, please describe your quality activities to ensure that the PRA is adequate for the present application in terms of scope, level of detail, and technical acceptability and provide a summary of any peer reviews, comparison studies, or similar evaluation of the seismic and fire modeling.

Attachment A to L-04-141 Page 2

Response

The quality activities that were performed for the BVPS seismic and fire PRA models are twofold. First, the seismic and fire PRA models were reviewed internally by both the utility personnel and the IPEEE contractors (PLG and Stevenson & Associates).

Secondly, the NRC and their contractors (Brookhaven and Sandia National Laboratories) also reviewed the PRA models during the BVPS IPEEE submittal review, and found the results to be reasonable and capable of identifying the most likely severe accidents and vulnerabilities from external events.

Additionally, the seismic and fire PRA models are integrated with the internal events PRA models, so the plant response modeling (fault trees and event trees) following the external initiating events have been updated as part of the PRA model update process identified in the response to RAI question l.a. During this update, the seismic PRA models were also revised to incorporate the uniform hazard spectrum (UHIS) shape resolution of the NRC RAI on the IPEEE evaluation, dated July 8, 1998.

It should also be mentioned that the fire PRA model at Unit 2 identified a fire at the opposite train EDG as a major risk contributor to the 14-day EDG AOT sensitivity studies. Therefore, FENOC considers that the external events PRA models are adequate to fully address the seismic and fire risk associated with this risk-informed application.

2. FENOC provided a summary of the BVPS-2 Peer Review Findings and Observations (F&Os) in a previous letter (PearceIUSNRC, Beaver Valley Power Station, Unit No. 2, BV-2 Docket No. 50-412, License No. NPF-73, Response to a Request for Additional Information in Support of License Amendment Requests [sic] No. 180, dated October 24, 2003, Serial L-03-160). Please provide additional information related to the EDG AOT extension request as follows: (RG 1.174, Section 2.2.3; RG 1.177, Section 2.3.1)

a. Corrective Action 02-09042-13 resolved an F&O involving comparative failure probabilities between EDGs and related circuit breakers. Please provide the original and updated failure probabilities for the affected component failure modes, for both BVPS-1 and 2 PRA models.

Response

Corrective Action 02-09042-13 resolved a Peer Review F&O on the Unit 2 EDG failure probabilities. This error was due to overestimating the demands and run hours during the data update process for the period reviewed. In response to this corrective action and Corrective Action 02-09037-03, the success data (demands and hours of operation) for all Unit 2 components that used Bayesian updating of their failure rates were checked against the Maintenance Rule estimated success data, and were revised as needed if discrepancies were found. This process was also applied to the Unit I components. The review of Unit I success data was performed prior to the data update process, so the differences in the original and updated failure rates are due to Bayesian updating using actual plant data.

Attachment A to L-04-141 Page 3 The following are the Unit I and Unit 2 failure rates associated with the EDGs for both the original (prior) and the updated (current) PRA models.

Unit I Original EDG Failure Rates (BVIREV2 PRA model)

ZTDGSI = 6.0922E-03; EDG - failure during first hour ZTDGS2 = 1.7774E-03; EDG -failure to run after first hour ZTDGSS = 1.2669E-02; EDG -failure to start on demand Updated EDG Failure Rates (BVIREV3 PRA model)

ZTDGSI = 3.7780E-03; EDG - failure during first hour ZTDGS2 =.1605E-03; EDG - failure to run after first hour ZTDGSS = 9.9193E-03; EDG -failure to start on demand Unit 2 Original EDG Failure Rates (BV2REV3A PRA model)

ZTDGSI = 9.9991E-04; EDG - failure during first hour ZTDGS2 = 4.7558E-04; EDG - failure to run after first hour ZTDGSS = 8.4234E-04; EDG - failure to start on demand Updated EDG Failure Rates (BV2REV3B PRA model)

ZTDGSI = 3.3320E-03; EDG -failure during first hour ZTDGS2 = 7.2520E-04; EDG -failure to run after first hour ZTDGSS = 2.7771E-03; EDG -failure to start on demand

b. Corrective Action 02-09042-15 involved BVPS-1 EDG unavailability during outages and the impact on credit for the station blackout (SBO) cross-tie to supply BVPS-2. The resolution states that BVPS-l EDG unavailability during shutdown was subsequently included. Has BVPS-2 EDG unavailability during shutdown been included in the BVPS-1 PRA modeling of the SBO cross-tie from BVPS-2?

Response

Corrective Action 02-09042-15 resolved a Peer Review F&O by including the Unit I EDG shutdown unavailability to the Unit 2 electric power cross-tie model used during a Station Blackout. During the Unit I PRA model update, the associated Unit 2 EDG shutdown unavailability was included in the Unit 1 electric power cross-tie model used during Station Blackout events.

Attachment A to L-04-141 Page 4 For the Unit I emergency diesel generators, a shutdown unavailability of 2.1% was obtained based on data from October 1997 through September 2001. This value was then combined with the assumed on-line maintenance unavailability values to determine the total Unit I emergency diesel generator unavailability, which was then used in the Unit 2 BV2REV3B electric power cross-tie model.

For the Unit 2 emergency diesel generators, a shutdown unavailability of 1.9% was obtained based on data from March 1999 through February 2002. This value was then combined with the assumed on-line maintenance unavailability values to determine the total Unit 2 emergency diesel generator unavailability, which was then used in the Unit 1 BV1REV3 electric power cross-tie model.

c. For any F&Os unique to BVPS-1, provide a summary of the F&O and its resolution.

Please provide confirmation that all Category A and B F&Os on BVPS-1 were resolved prior to the risk assessment of the proposed EDG AOT extension or provide a justification that the resolution is not a significant issue related to the requested EDG AOT change.

Response

The peer review was conducted in July 2002, by the Westinghouse Owner's Group, with the final documentation of the review issued in December 2002. This peer review primarily focused on the Unit 2 PRA model, but also provided a cursory review of the Unit I PRA model and methodology. The majority of F&Os identified in the response to the BVPS Unit 2 Slave Relay Surveillance Test Interval Extension RAI (identified in letter L-03-160 referenced above) were also applicable to Unit 1, and there were some instances where the F&O applied strictly to Unit 2. However, the PRA Peer Review Team did not identify any F&Os that were only unique to Unit 1.

After the peer review, the preliminary Category A and B observations were entered into the BVPS Corrective Action Program, and those that potentially impacted the model were dispositioned, and incorporated into the updated Unit 1 PRA model (BVIREV3).

This updated PRA model was then used to quantify the sensitivity cases developed for the Unit I 14-day EDG AOT extension.

Condition Report 02-09041 was generated to resolve all of the Unit I Category A F&Os, and contained three Corrective Actions. All three of these Corrective Actions have been implemented and the Condition Report is closed.

Condition Report 02-09045 was generated to resolve all of the Unit 1 Category B F&Os, and contains thirty-five Corrective Actions. All of the Corrective Actions that were identified as potentially impacting the PRA model have been implemented and are closed. The only remaining Corrective Action that is still open against this Condition Report is Corrective Action 02-09045-23. This corrective action however, is strictly a documentation issue suggesting to include a discussion of the potential impact of floods on systems that are shared between the two units, to the initiating event notebook.

I Attachment A to L-04-141 Page 5 Furthermore, the impact of this F&O on the electric power cross-tie was deemed to be minimal by the PRA Peer Review Team, since multiple River Water/Service Water pumps would remain available to support the EDG cooling requirements, when considering the alternate intake structure pumps.

3. The LAR states that the electric power recovery model "... credits more scenarios with recovery of the fast bus transfer breakers, emergency diesel generators, and the offsite grid."

Please describe the model or method used to recover EDGs, including whether this involves repair of emergency diesel generators during the accident sequence. Please explain how the non-repair probabilities were derived. How was the EDG recovery model adjusted to account for the increasing the EDG AOT to 14 days? (RG 1.174, Section 2.2.2; RG 1.177, Section 2.3)

Response

The methodology for recovering the EDGs used in the electric power recovery model is presented in Attachment C. This methodology includes both recovering an EDG due to hardware-related failures during either the startup sequence or the subsequent operation, and diesel generator unavailability due to maintenance at the time of the initiating event.

It is inherent in the EDG recovery analysis that approximately 20 percent of the single diesel unavailability is assumed to be attributed to preexisting maintenance scenarios. This is captured in the 5h percentile model for the single diesel recovery, which reduces the cumulative frequency of recovery for one diesel by 20 percent. For the 95th percentile, however, a more optimistic view is taken and it is assumed that this fraction of unavailability is recoverable. This will include, for example, restoring the diesel to service after minor maintenance or testing. Finally, because most maintenance events require at least partial reassembly of the diesel generator before it can be started, it is assumed for the 50t percentile that the maintenance contribution to unavailability is also unrecoverable within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months after the initiating event, but is recoverable after 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

These EDG recovery curves are assumed to be unaffected by the increased AOT extension time, as the EDG 20 percent non-recoverable value is considered to be bounding.

In addition, the time-dependent calculations for the integrated electric power failure and recovery model are performed using a Monte Carlo computer simulation program (STADIC).

This model computes the following:

Conditional probability of onsite power system (diesel generator) failure in a mission time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months with failure to recover diesel generators or offsite electric power before core damage (designated by the variable QLP in the STADIC code).

Conditional probability of onsite power system failure in a 24-hour period without including recovery (designated by the variable QTM in the STADIC code). This part of the analysis uses the cutsets generated by the AC electric power fault trees and accounts for EDG unavailability in the maintenance alignments.

Attachment A to L-04-141 Page 6 The ratio of QLP/QTM gives the electric power non-recovery factor. Since the conditional probability of the onsite power system failure in a 24-hour period, including EDG unavailability, is factored into both the numerator and denominator, the additional unavailability of EDG due to the 14-day AOT extension will get cancelled out.

Therefore, based upon the above justifications, the electric power recovery model used in support of the 14-day EDG AOT extension will not be impacted.

4. Section 3.3 of the LAR discusses the SBO cross-tie circuitry in the context of station blackout, stating that the BVPS-l and 2 normal 4KV buses can be cross-tied to allow an EDG from one unit to power SBO loads at both units. Please provide the following information: (RG 1.174, Section 2.2.2; RG 1.177, Section 2.3)

a. What is the basic human error probability and importance (e.g., Fussell-Vesely) for the operator action to cross-tie the buses? How is dependency among operator actions within a given scenario/sequence addressed when failure to cross-tie is part of the sequence?

Describe the operator training content and periodicity for this action. Has the cross-tie capability ever been demonstrated?

Response

The electric power cross-tie model used in the PRA models includes both the plant hardware (e.g., busses and breakers) and operator actions necessary to successfully power both units from a single emergency diesel generator. The operator action human error rates (HER) and Fussell-Vesely (FV) importance associated with the cross-tie include the following:

ZHEXTI - Operator Fails to Perform Cross-Tie During SBO Unit I HER = 1.28E-02 FV = 1.61 E-03 Unit 2 HER = 3.57E-02 FV = 8.13E-04 ZHEXT2 - Operator Fails to Perform Cross-Tie During SBO & SLOCA or SGTR Unit 1 HER = 1.29E-01 FV = 3.67E-06 Unit 2 HER = 4.12E-02*

FV = 2.27E-07 ZHEXT3 - Operator Fails to Perform Cross-Tie During MLOCA, LLOCA & EXLOCA Unit 1 HER = 1.0 FV = Not Applicable Unit 2 HER = 1.0 FV = Not Applicable ZHEXT4 - Operator Fails to Manually Align SBO Breakers

Attachment A to L-04-141 Page 7 Unit 1 HER = 5.30E-02 FV = 2.18E-06 Unit 2 HER = 5.30E-02 FV = 2.52E-07

Note: The low HER value associated with Unit 2 operator action ZHEXT2 is due to a maximum value of 5.OE-01 being used in calibration tasks during the success likelihood index methodology (SLIM) process, as opposed to a typical value of 1.0. This was due to multiple other actions being assessed in the same HER grouping, which were thought to be bounded by a human error rate of 0.5 at the time that the IPE was performed. BVPS plans on reanalyzing all human action error rates using the EPRI HRA Calculator during the next PRA model update, at each unit.

The cross-tie is only queried if both emergency AC busses have failed and if the necessary hardware is available to support it. The PRA models do not credit the cross-tie if the initiating event is the a loss of an emergency AC bus and the failure of the opposite train normal 4KV bus required to establish the cross-tie. The logic behind this reasoning is that since the initiating event is the loss of an emergency AC bus power, that train is not available to support the cross-tie because the bus could be failed. In addition, since the cross-tie is established through the normal 4KV busses, their failure too could be due to the failure of the bus.

When the cross-tie is attempted but fails, then the operator actions that become important are those in response to a longer term (greater than 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months ) station blackout. As such, it is important for the operators to establish a long term supply of auxiliary feedwater (AFW) by either aligning dedicated auxiliary feedwater (DAFW) at Unit 1 or makeup to the primary plant demineralized water storage tank (PPDWST) at Unit 2, to cooldown and depressurize the Reactor Coolant System (RCS), and to try to restore offsite power and recover the EDGs. The event trees are constructed so that the dependencies on these operator actions are evaluated with the prior knowledge of what has failed.

For example at Unit 1, with the both trains of emergency AC power unavailable and the cross-tie failed, the PRA event trees evaluate the remaining top events with the knowledge that both trains of emergency AC power are not available (i.e., all top events with only AC powered pumps are guaranteed failed). Since AC power is not available, makeup to the PPDWST is not possible, so operator actions to align the DAFW pump are questioned. However, if AFW was successful, it is known that this operator action only needs to be completed before the PPDWST depletes, and is evaluated as such. Likewise, operator actions to cooldown and depressurize the RCS are evaluated to require local actions since AC power is not available to remotely operate the SG atmospheric steam dump valves. Moreover, if a consequential Power Operated Relief Valve (PORV) LOCA is also present during the SBO, then it is also known that core uncovery will occur quicker than with just a Reactor Coolant Pump (RCP) seal LOCA, so the time to restore offsite power and recover the EDGs is shorter. All of these operator actions are evaluated with the knowledge that the cross-tie has failed and that a station blackout is in progress.

Operator actions to establish the SBO cross-tie and energize SBO loads from the opposite unit are described in separate attachments to the BVPS Emergency Operating Procedures

Attachment A to L-04-141 Page 8 for Loss of All Emergency 4KV AC Power (ECA-0.0). The plant operators that would be responsible for establishing the SBO cross-tie are trained on these attachments during their initial training. Periodic training is conducted on these attachments at a frequency of once every three years. The training content consist of procedure review and a walkdown of the attachments in the plant.

In January, 1993 Emergency Operation Procedures walkthrough validations were performed by the BVPS Unit 1 and Unit 2 Operations personnel to demonstrate that the SBO cross-tie could be established and required SBO loads powered from the opposite unit within one hour, consistent with the BVPS SBO analysis. In addition a SBO cross-tie functional test was performed in May, 1993. This test consisted of energizing a Unit I station chiller unit on the ID non-emergency 4KV bus through the SBO cross-tie from the Unit 2 2A non-emergency 4KV bus. While the test only passed a portion (approximately 28 amps) of the maximum current through the cross-tie that could be expected under SBO condition, the tests also measured voltage drops across the cross-tie cable to verify the design capability for the SBO loads. A similar functional test was again performed in October, 1997 by energizing a Unit 1 station chiller on the IA non-emergency 4KV bus through the SBO cross-tie from the Unit 2 2D non-emergency 4KV bus.

b. How is the smaller capacity of the BVPS-1 EDGs compared to BVPS-2's (2850kW versus 4535kW) addressed in the PRA modeling?

Response

The emergency diesel generator capacities used in the PRA electric power cross-tie model are addressed by their respective loss of all AC power (station blackout) emergency operating procedure (ECA-0.0). These procedures first attempt to restore the EDGs and offsite power before establishing the cross-tie. Once the cross-tie is established, these procedures instruct operators to restore AC power to the motor control centers (MCCs) to control AFW throttle valves, SG atmospheric steam dump valves, and re-power battery chargers to restore both 1 25V DC power and 1 20V AC vital bus power.

These actions allow AFW and steam release to be controlled from the control room for long term decay heat removal and continued cooldown and depressurization of the RCS, which minimize the effects of RCP seal LOCAs.

Since only a limited set of equipment can be powered from the electric power cross-tie, the PRA models do not credit the cross-tie for mitigating excessive, large, or medium LOCAs, as this would require the use of additional ESF equipment to be powered from the EDG. However, if needed, a High Head Safety Injection (HHSI) pump can be powered to mitigate the effects of a small LOCA (e.g., large RCP seal LOCA, or PORV LOCA) or SGTR. If a HHSI pump is to be used, a Unit I river water pump must also be powered from the cross-tie, or the diesel driven fire pump must be aligned to the river water header, to support lube oil cooling of the HHSI pump. At Unit 2, the river water header would have to be cross-tied to the service water header to support the Unit 2 HHSI pump. This is due to the smaller Unit 1 EDG capacity, which cannot support the

I Attachment A to L-04-141 Page 9 additional load of a Unit 2 service water pump without load shedding. However, the PRA model assumed that the failure probability of the Unit I river water pumps was essentially the same as the Unit 2 service water pumps, so this cross-tie between the Unit's cooling water systems was not modeled. That is to say, that the Unit 2 PRA assumes that AC power is available to operate a service water pump if the electric power cross-tie is successful. The diesel driven fire pump is also modeled in the Unit 2 service water PRA model to support the HHSI pump if needed.

It is also assumed in the PRA models that during severe accident conditions at the blackouted unit (e.g., RCP seal LOCA without makeup to the RCS) enough loads could be shed on the remaining EDG to allow for alternate core damage mitigating loads to be started. This would be the case for both the smaller capacity 2850 kW Unit 1 EDG or the 4535 kW Unit 2 EDG. These actions would have to be directed by the Technical Support Center (TSC) and analyzed on a case-by-case basis, since they are not currently accounted for in the station blackout procedure (ECA-0.0). However, the PRA models assume that these actions are successful when implementing the electric power cross-tie, if called upon to mitigate core damage.

Moreover, sensitivity cases were performed by modifying the PRA models to only credit emergency AC power available to the SBO loads identified in ECA-0.0, if the cross-tie is successful. The electric power recovery model was also modified to credit the restoration of offsite power and repair of the EDGs if the cross-tie was successful. The results of these sensitivity cases are as follows:

Case LAR RAI Delta Submittal Sensitivity Unit I - Case 1 CDF 2.34E-05 2.42E-05 8.36E-07 Unit 1 - Case 2 CDF 2.36E-05 2.46E-05 L.OOE-06 Unit 1 - Delta CDF 2.08E-07 3.72E-07 1.63E-07 Unit 2 - Case 1 CDF 3.27E-05 3.34E-05 7.08E-07 Unit 2 - Case 2 CDF 3.42E-05 3.511E-05 9.04E-07 Unit 2 - Delta CDF 1.45E-06 I 1.65E-06 1.96E-07 The Unit 1 Delta CDF = 3.72E-07, or an increase of just 1.63E-07 above the LAR submitted cases. The Unit 2 Delta CDF = 1.65E-06, or an increase ofjust 1.96E-07 above the submitted cases.

5. Is the BVPS non-safety-related diesel generator credited in the PRA models? If "yes," please provide the basic human error probability and importance (e.g., Fussell-Vesely) of this credit for BVPS-1 and 2. (RG 1.174, Section 2.2.2; RG 1.177, Section 2.3)

Attachment A to L-04-141 Page 10

Response

Both the Unit 1 and Unit 2 PRA models credit the non-safety related Emergency Response Facility (ERF) diesel generator. At Unit 1, the ERF diesel generator supports the dedicated auxiliary feedwater pump, which serves as a backup to the turbine-driven AFW pump during SBO events (see Attachment B). At Unit 2, all of the station air compressors and containment air compressors are supported by the ERF diesel generator following a loss of offsite power. The ERF diesel generator automatically starts and loads following a loss of offsite power, without any operator intervention required. As such, there are no human error probabilities associated with the ERF diesel generator. The 4KV and 480V ERF substation power supplies are modeled by Top Event BK, which includes both the feeds from offsite power and the ERF diesel generator along with its support equipment (batteries, fuel oil, cooling, ventilation, and programmable controller panels). The Top Event BK split fraction probabilities and Fussell-Vesely importance for both Unit I and Unit 2 are provided below:

Unit I PRA model BK1 - ERF (Black) Diesel Supply, Offsite Power Available Probability = 1.48E-04 FV= 1.56E-05 BK2 - ERF (Black) Diesel Supply, Loss of Offsite Power Probability = 8.74E-02 FV = 2.35E-03 Unit 2 PRA model BKI - ERF (Black) Diesel Supply, Offsite Power Available Probability = 2.22E-04 FV = 1.02E-03 BK2 - ERF (Black) Diesel Supply, Loss of Offsite Power Probability = 7.57E-02 FV = 3.75E-04

6. Please show how the additional 184.4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months (BVPS-1) and 126.33 hours3.819444e-4 days 0.00917 hours 5.456349e-5 weeks 1.25565e-5 months (BVPS-2) of EDG unavailability were derived, including breakdown by surveillance testing, preventive maintenance (PM) and corrective maintenance (CM). Explain why BVPS-1 and 2 numbers are different.

Response

Table 1, that follows this response, provides the listing of surveillances and tests conducted on the diesel generators that cause the diesel generator to be unavailable for both Units I and

2. The unavailability times were tracked and monitored by the System Engineer. These surveillances and tests are currently performed and will continue to be performed at-power with the extended AOT, with the duration of diesel generator unavailability expected to remain the same as the current AOT. Table 2, that follows this response, provides the surveillance, preventive and corrective maintenance that is normally performed at-power and during outages. These maintenance time durations were based on actual plant experience during at-power and previous outages.

Attachment A to L-04-141 Page 11 For Unit 1:

The total EDG unavailability with the current EDG AOT for surveillances, tests and repair activities is equal to (37.67 hrs/yr per EDG + 29.92 hrs/yr per EDG) or 67.6 hrs/yr per EDG.

The total EDG unavailability with the extended EDG AOT for surveillances, tests, maintenance and repair activities is equal to (37.67 hrs/yr per EDG + 214.32 hrs/yr per EDG) or 251.99 hrs/yr per EDG.

With the proposed AOT extension, the mean Unit I EDG unavailability was estimated to increase from 67.6 hrs/yr per EDG to 251.99 hrs/yr per EDG (or an increase of about 184.4 hrs/yr per EDG).

For Unit 2:

The total EDG unavailability with the current EDG AOT for surveillances, tests and repair activities is equal to (10.5 hrs/yr per EDG + 19.97 hrs/yr per EDG) or 30.47 hrs/yr per EDG.

The total ED.G unavailability with the extended EDG AOT for surveillances, tests, maintenance and repair activities is equal to (10.5 hrs/yr per EDG + 146.21 hrs/yr per EDG) or -156.8 hrs/yr per EDG.

With the proposed AOT extension, the mean Unit 2 EDG unavailability was estimated to increase from 30.47 hrs/yr per EDG to 156.8 hrs/yr per EDG (or an increase of about 126.33 hrs/yr per EDG).

The reasons for different unavailability hours assigned between Unit I and Unit 2 are:

During the Unit I River Water System surveillance testing the EDG was considered unavailable, while the Unit 2 EDG can be maintained available during the Service Water System testing.

Based on the EDG operating history data the Unit I EDG experienced more repairs, and therefore, more corrective maintenance unavailability hours then the Unit 2 EDG.

The Unit 1 and Unit 2 EDGs were manufactured by different companies, and therefore, have different maintenance programs.

Attachment Page 12 A to L-04-141 Table 1 - Unit 1 Impact of Increased AOTs on Mean Test Downtimes With Current AOT With Extended AOT3 Current Impact of (C)

Downtime AOT Downtime or per Test Test Change on per Test Test New (N)

Test Activity Activity Test Activity Activity Test Activity Activity Frequency (hr)

Unavail.1 Downtime 2 (hr)

Unavail.'

Monthly C

13/yr 2 hr per DG 26 hr/yr X

2 hr per DG 26 hr/yr Surveillances (Monthly) per DG per DG Fast Start Ckt C

0.67/yr 4 hr per DG 2.67 hr/yr xl 4 hr per DG 2.67 hr/yr Test (18 Month per DG per DG frequency)

RW System C

18/yr 0.50 hr per 9 hr/yr xI 0.50 hr per 9 hr/yr Surveillances (18 events event per DG event per DG longer than 15 minutes over 12 months)

Total l _

37.67 37.67 hr/yr per hr/yr per DG DG Method used to determine test time with extended AOT: No increase in test time with extended AOT Notes:

1. Test Activity Unavailability = Test Frequency x Downtime per Test Activity

2.

Note above the method(s) used for determining the repair and maintenance times with the extended AOT. If a factor increase is used (such as 2X), add the factor to this column.

3.

Downtime per Test Activity (with extended AOT) - Impact of AOT Change on Test Downtime x Downtime per Test Activity (with current AOT)

Attachment A to L-04-141 Page 13 Table I - Unit 2 Impact of Increased AOTs on Mean Test Downtimes With Current AOT With Extended AOT 3 Current Impact of (C)

Downtime AOT Downtime or per Test Test Change on per Test Test New (N)

Test Activity Activity Test Activity Activity Test Activity Activity Frequency (hr)

Unavail.1 Downtime2 (hr)

Unavail.1 Monthly C

13/yr 0.5 hr per 6.5 hr/yr xl 0.5 hr per 6.5 hr/yr Surveillances (Monthly)

DG per DG DG per DG Quarterly Sl-C 4/yr I hr per DG 4 hr/yr XI I hr per DG 4 hr/yr GO Test (Quarterly) per DG per DG Total 10.5 hr/yr 10.5 hr/yr per DG per DG Method used to determine test time with extended AU F: No increase in test time with extended A) I Notes:

1. Test Activity Unavailability = Test Frequency x Downtime per Test Activity

2.

Note above the method(s) used for determining the repair and maintenance times with the extended AOT. If a factor increase is used (such as 2X), add the factor to this column.

3.

Downtime per Test Activity (with extended AOT) = Impact of AOT Change on Test Downtime x Downtime per Test Activity (with current AOT)

Attachment A to L-04-141 Page 14 Table 2 - Unit 1 Impact of Increased AOTs on Mean Maintenance Downtimes Maintenance With Current AOT With Extended AOTl Activity (Note Current Impact of as either (C)

Downtime AOT Downtime Scheduled (S) or per Maint.

Maint.

Change on per Maint.

Maint.

or Repair New (N)

Maint.

Activity Activity Maint.

Activity Activity (R))

Activity Frequency (hr)

Unavail.1 Downtime 2 (hr)

Unavail.1 24 Month N

0.50/yr 144 hr per 72.0 hr/yr Surveillance (24 month DG per DG At-Power (S) frequency) 6 Year N

0.167/yr 168 hr per 28.1 hr/yr Surveillance (6 year DG per DG At-Power (S) frequency) 12 Year N

0.083/yr 168 hr per 13.9 hr/yr Surveillance (12 year DG per DG At-Power (S) frequency)

Routine Mid-C 0.67/yr 16 hr per 10.72 xi 16 hr per 10.72 cycle (18 month DG hr/yr per DG hr/yr per Maintenance frequency)

DG DG At-Power (S)

At-Power C

3/yr 12.8 hr 19.2 hr/yr 14 59.7 hr 89.6 hr/yr Repairs (R),

(6 events in 2 (77 hrs total per DG X-per DG Corrective years) for the 6 3

Maintenance events)

Total 29.92 214.32 br/yr per hr/yr per DG DG 1i4D+IOA{

l t i.t.rrn~nD wage r +;no

.X t

J+1. _Jvn-A

?.

l?

At.et.nd t

IA J,.em A

r Vof USWU Ux Gus r 11W Wr.LJ I A Ant, A ^T Un iviethod used Lo dexernunt repair tume W lln Vmxlenaea AU I; nupair ulme ab:sLImea 10 De; IIeae IVD~U y LIe ICl I L In 14M I'aUy AU% I 10 the current 3 day AOT Method used to determine scheduled maintenance time with extended AOT: Estimated times from scheduled maintenance performed during refueling outages Notes:

I.

Maintenance Activity Unavailability = Maintenance Frequency x Downtime per Maintenance Activity

2.

Note above the method(s) used for determining the repair and maintenance times with the extended AOT. If a factor increase is used (such as 2X), add the factor to this column.

3.

Downtime per Maintenance Activity (with extended AOT) - Impact of AOT Change on Maintenance Downtime x Downtime per Maintenance Activity (with current AOT).

Attachment A to L-04-141 Page 15 Table 2 - Unit 2 Impact of Increased AOTs on Mean Maintenance Downtimes Maintenance With Current AOT With Extended AOTa Activity (Note Current Impact of as either (C)

Downtime AOT Downtime Scheduled (S) or per Maint.

Maint.

Change on per Maint.

Maint.

or Repair New (N)

Maint.

Activity Activity Maint.

Activity Activity (R))

Activity Frequency (hr)

Unavail.'

Downtime2 (hr)

Unavail.1 24 Month N

0.5/yr 144 hr per 72 hr/yr Surveillance (24 month DG per DG At-Power (S) frequency) 13 Year N

0.077/yr 264 hr per 20.3 hr/yr Surveillance (13 year DG per DG At-Power (S) frequency)

Routine Mid-C 0.67/yr 16 hr per 10.72 xl 16 hr per 10.72 cycle (18 month DG hr/yr per DG hr/yr per Maintenance frequency)

DG DG At-Power (S)

At-Power C

2/yr 9.25 hr 9.25 hr/yr 14 43.17 hr 43.17 Repairs (R)

(4 events in 2 (37 hrs total per DG x

hr/yr per years) for the 4 DG events)

Total 19.97 146.21 hr/yr per hr/yr per DG DG 1V1vUIUUA UDU II.) Ubr 1II1LI1a IA~ dII LLIuls WILII CAL nT-U~U r

ntIJ1n an~piIII LIIII~4~UII1nU LU U c

I U

ry L>

141101 I

A A7z-tJAI L

the current 3 day AOT Method used to determine scheduled maintenance time with extended AOT: Estimated times from scheduled maintenance performed during refueling outages Notes:

1. Maintenance Activity Unavailability - Maintenance Frequency x Downtime per Maintenance Activity

2.

Note above the method(s) used for determining the repair and maintenance times with the extended AOT. If a factor increase is used (such as 2X), add the factor to this column.

3.

Downtime per Maintenance Activity (with extended AOT) - Impact of AOT Change on Maintenance Downtime x Downtime per Maintenance Activity (with current AOT).

Attachment A to L-04-141 Page 16

7. The LAR states, in the discussion of Tier 1, that "... past corrective maintenance repair durations were increased by the ratio of the proposed AOT increase when estimating corrective maintenance durations under the proposed AOT." Is this increased duration included in the increase in mean EDG unavailability used to calculate the Case 2 risk? How was the difference in treating common cause failure between CM and PM accounted for in Case I and Case 2? (RG 1.174 Section 2.2.1; RG 1.177 Section 2.3.3.1)

Response

The increased duration is included in the increase in mean EDG unavailability used to calculate the Case 2 risk. The response to RAI question # 6 includes Tables 1 and 2, which provide the estimated extended AOT unavailability for surveillances, testing, preventive maintenance, and corrective maintenance unavailability. These unavailability values were calculated based on the estimated yearly average contribution to EDG unavailability for each of the test and maintenance activities. Surveillance and test activities are performed at their required frequencies. Maintenance activities are performed at various maintenance frequencies (from every 18 months to every 13 years).

When increasing the EDG unavailability due to the 14-day AOT extension, only the maintenance repair duration is increased by the ratio, not the frequency at which repairs are made (i.e., EDG failures were assumed to remain the same). As such, the EDG common cause factors remain unchanged when evaluating Case 1 and Case 2.

For Unit 1: Case 2's total EDG unavailability with the extended AOT for surveillances, tests, maintenance and repair activities is 251.99 hr/yr per EDG. Therefore, the expected EDG unavailability with the extended AOT is:

Percent = (37.67 + 21432)hr I yr x Iyr x 100 = 2.88°/

87601w For Unit 2: Case 2's total EDG unavailability with the extended AOT for surveillances, tests, maintenance and repair activities is 156.71 hr/yr per EDG. Therefore, the expected EDG unavailability with the extended AOT is:

Percent = (105 + 1462 I)hirl yr x lyr xlOO=1.79/c 8760hr There is no difference in treating common cause failure between corrective maintenance and preventive maintenance accounted for in Case I and Case 2. Case I models the current EDG unavailability based on the data for current activities. Case 2 models the expected EDG unavailability based on the data for current plus any new activities. Both cases modeled the same maintenance alignments and the same common cause failures.

Attachment A to L-04-141 Page 17

8. Please provide a discussion on the effects of the proposed AOT extension on dominant accident sequences (sequences that contribute more that 5% to risk, for example) to show that the proposed change does not create risk outliers or exacerbate existing risk outliers.

Please provide core damage contributions by initiating event (including seismic and fire) and by sequence type for Cases I and 2. (RG 1.1 74, Section 3.3. 1)

Response

Based on a comparison of the dominant CDF sequences for both Unit I and Unit 2, no new risk outliers were identified, and existing outliers were not exacerbated. Tables 3 and 4 provide the top five sequences contributing to CDF for both Unit's Case 1 and Case 2, respectively. As can be seen in the tables, only the first sequence in both cases at each Unit would be considered dominant, according to the Regulation Guide 1.174 definition (i.e.,

sequences that contribute more than 5% to the risk).

For Case 1, the Unit 1 initiating event CDF contributions are presented in Table 5, while Table 6 presents the Unit 1 sequence type contributions. For Case 2, the Unit 1 initiating event CDF contributions are presented in Table 7, while Table 8 presents the Unit 1 sequence type contributions. At Unit 2, the Case 1 initiating event CDF contributions are presented in Table 9, while Table 10 presents the Case I sequence type contributions. For Case 2, the Unit 2 initiating event CDF contributions are presented in Table I 1, while Table 12 presents the Unit 2 sequence type contributions.

Attachment A to L-04-141 Page 18 Table 3 Case I CDF Sequences Unit 1 Rank Initiator Frequency Failed and Multi-State Split Fractions

%/a of CDF 1

CS1L1C 1.7945E-06 ZXF* BVA*CCF*TBF*PL1*AFF*MFF*OFF*OBF* HHF*SEF*RL1*LAF*LBF 7.7%

CDF*NRF*NMF*QAF*QBF*SMF*CIF*REF*SSF*CG1 2

SEIS3 5.0791E-07 ZC3*ZD3*ZB3*OGF*NAF*NDF*AOFPBPF*XTF*M5F*M1F*M3F*M6F*

2.2%

M2F*M4FPDOF*DPF*D3F*D4F*IRF*IBF*IWF*IYF*SAFPSBF*OSF*BK F*WAF*WBF*CTF*CCF*TBF*TTF*MSF*PL1*ASF*AFF*MFF*DFF*OFF*

OBF*HHF*SEF*RL1*LAF*LBF*CDF*NRF*NMF*QAF*QBF*SMF*CIF*R EF*SSF*CG1 3

SEIS2 4.4960E-07 ZC2*ZD2*ZB2*OGF*NAF*NDF*AOF*BPF*XTF*M5F*M1F*M3F*M6F*

1.9%

M2F*M4F*DOF*DPF*D3F*D4F*IRF*IBF*IWF*IYF*SAFPSBF*OSF*BK F*WAF*WBF*CTF*CCF*TBF*TTF*MSF* PL1*ASF*AFF*MFF*DFF*OFF*

OBF*HHFPSEPRL1*LAF*LBF*CDF*NRF*NMF*QAF*QBF*SMF*CIF*R EF*SSF*CG1 4

SEIS3 4.0336E-07 ZC3*ZB3*ZG3*OGF*NAF*NDF*BKF*WAF*WBF*CTF*CCFPTBF*PL1*

1.7%

MAF*MFF*DFF*OFF*OBF*HHF*SEF*RL1*LAF*LBF*ODF*NRF*NMF*Q AF*QBF*SMF*REF*SSF*CG1 5

SEIS3 3.9929E-07 ZP3*ZC3*ZB3*OGF*NAF*NDF*BKF*WAF*WBF*CTF*CCF*TBF*PL1*

1.7%

MAF*MFFPDFF*OFF*OBF*HHF*SEF*RL1*LAF*LBFPODF*NRF*NMF*Q AF*QBF*SMF*REF*SSF*CG1 Unit 2 Rank Initiator Frequency Failed and Multi-State Split Fractions

% of CDF 1

AOX 1.9298E-06 ZXF*AOF*BP1*XTD*M1F*M2F*M3F*M4F*WAF*WBF*CSF*CCF*TBF*

5.9%

PL1*HHF*HCF*SEF*RL1*LHF*LCF*RRF*NRF*NMF*QSF*SMF*REF*S

_SF*CG1 2

BPX 9.4435E-07 ZXF*AO1*BPF*XTG*MlF*M2F*M3F*M4F*WAF*WBF*CSF*CCF*TBF*

2.9%

PL1*HHF*HCF*SEF*RL1*LHF*LCF*RRF*NRF*NMFPQSF*SMF*REF*S SF*CG1 3

EXFW 6.2338E-07 ZXF*PL1*AF1*MFF*OB1*CDF*ODF*RRF*NRF*NMF*REF*SSF*CG1 1.9%

4 CB3L1P 6.0024E-07 ZXF*CSF*IAF*ICPFTBFPMSF*PL1*AFF*OFF*OB4*CDF*ODF*RRF*NR 1.8%

F*NMF*REF*SSF*CG1 5

BPX 5.4149E-07 ZXF*NA1*AO2*BPF*XTPF*M1F*M2F*M3F*M4F*WAF*WBF*CSF*CCF*

1.7%/

TBF*PL1*HHF*HCF*SEF*RL1*LHPFLCF*RRF*NRF*NMF*QSF*SMF*RE A*SSF*CG1

Attachment A to L-04-141 Page 19 Table 4 Case 2 CDF Sequences Unit 1 Rank Initiator Frequency Failed and Multi-State Split Fractions

%/a of CDF 1

CS1L1C 1.7945E-06 ZXF*BVA*CCF*TBF* PL1*AFF*MFF*OFF*OBF*HHF*SEF*RL1*LAF*LBF 7.6%

CDF*NRF*NMF*QAF*QBF*SMF*CIF* REF*SSF*CG1 2

SEIS3 5.0791E-07 ZC3*ZD3*ZB3*OGF*NAF*NDF*AOF*BPF*XTF*M5F*M1F*M3F*M6F*

2.2%

M2F*M4F*DOFPDPF*D3F*D4F*IRF*IBF*IWF*IYF*SAF*SBF*OSF*BK F*WAF*WBF*CTF*CCF*TBF*TTF*MSF*PL1*ASF*AFF*MFF*DFF*OFF*

OBF*HHF*SEF*RL1*LAF*LBF*CDF*NRFPNMFPQAF*QBF*SMF*CIF*R EF*SSF*CG1 3

SEIS2 4.4960E-07 ZC2*ZD2*ZB2*OGF*NAF*NDF*AOF*BPF*XTF*M5F*MlF*M3F*M6F*

1.9%

M2F*M4F*DOF*DPF*D3F*D4F*IRF*IBF*IWFPIYF*SAF*SBF*OSF*BK F*WAF*WBF*CTF*CCF*TBF*TTF*MSF*PL1*ASF*AFF*MFF*DFF*OFF*

OBF*HHF*SEF*RL1*LAF*LBF*CDF*NRF*NMF*QAF*QBF*SMF*CIF*R EF*SSF*CG1 4

IAX 3.9583E-07 ZXF*IAF*ICFPTBF*PL1*VL1*HCFPSEF*RL2*CDB*NRF*NMF*REF*SSF 1.7%

CG1 5

SEIS3 3.8607E-07 ZC3*ZB3*ZG3*OGF*NAF*NDF*BKF*WAF*WBF*CTF*CCF*TBF*PL1*

1.6%

MAF*MFFPDFF*OFF*OBF*HHF*SEF*RL1*LAF*LBF*ODF*NRF*NMF*Q I

AF*QBF*SMF*REF*SSF*CG1 Unit 2 Rank Initiator Frequency Failed and Multi-State Split Fractions l/o of CDF 1

AOX 1.9303E-06 ZXF*AOF* BP1*XTD*M1F*M2F*M3F*M4F*WAF*WBF*CSF*CCF*TBF*

5.6%

PL1*HHF*HCF*SEF*RL1*LHF*LCF*RRF*NRF*NMF*QSF*SMF*REF*S SF*CG1 2

BPX 9.4475E-07 ZXF*AO1*BPF*XTG*MlF*M2F*M3F*M4F*WAF*WBF*CSF*CCF*TBF*

2.8%

PL1* HHF*HCFPSEF*RL1*LHF*LCF*RRF*NRF*NMF*QSF*SMF*REF*S SF*CG1 3

BPX 7.4397E-07 ZXF*NA1*AO2*BPF*XTF*MIF*M2F*M3F*M4F*WAF*WBF*CSF*CCF*

2.2%

TBF*PL1*HHF*HCF*SEF*RL1*LHF*LCF*RRF*NRF*NMF*QSF*SMF*RE

_5A*SSF*CG1 4

AOX 6.3891E-07 ZXF*ND2*AOF*BP8*XTF*MlF*M2PM3PM4PWAF*WBF*CSF*CCF*

1.9%

TBF*PL1*HHF*HCF*SEF*RL1*LHF*LCF*RRF*NRF*NMF*-QSF*SMPKRE 5A*SSF*CG1 5

EXFW 6.2338E-07 ZXF*PL1*AF1*MFF*OB1*CDF*ODF*RRF*NRF*NMF*REF*SSF*CG1 1.8%

Unit 1 Dominant Sequence Comparison Based on the comparison of these sequences at Unit 1, it can be seen that there are no differences in the top three sequences. Sequence 1 remains essentially unaffected by the increased EDG AOT, since the PRA model assumes that all AC power is failed and non-recoverable due to the loss of emergency switchgear ventilation (split fraction BVA). For sequences 2 and 3, the emergency AC busses are set to guaranteed failures (split fractions AOF & BPF) and are non-recoverable due the seismic initiating events (SEIS3 and SEIS2).

For Table 3 Case 1, sequences 4 and 5 are also initiated by seismic events, with the seismically induced failure of the offsite grid (ZC3), ERF diesel generator substation (ZB3),

and river water system due to either the collapse of the intake structure (ZG3) or primary auxiliary building (ZP3). For these sequences, the EDGs successfully start and load to supply the emergency busses following the loss of offsite power. However, with all river

Attachment A to L-04-141 Page 20 water cooling failed the EDGs soon fail along with the emergency AC busses. These sequences show up as sequence 5 in Table 4, and what would be sixth ranked sequence for Case 2, with a frequency of 3.8217E-07. As can been seen Table 4 sequence 5, there was a slight reduction in frequency when compared to Table 3 sequence 4. This difference in frequency can be attributed to the success terms of the emergency AC power split fractions.

Since there were no failures of the EDGs observed in these sequences, the 14-day EDG AOT extension sequence frequency would be lower since the success term (one minus the failure term) would have a smaller value than for the base case, due to the higher failure probability associated with increased EDG unavailability. For example, the A02 split fraction value associated with the emergency AC orange train, given that the normal 4KV bus IA failed (e.g., loss of offsite power) is 1.1830E-01 for Case I and 1.3703E-0l for Case 2, with the increase in frequency due to the increased EDG unavailability. The associated success term values for sequences in which A02 is successful would be 1.0 minus 1.1830E-01 or 0.88170 for Case 1, and 1.0 minus 1.3703E-01 or 0.86297 for Case 2. Therefore, Case 2 sequences would be lower in frequency than the associated Case 1 sequences, whenever split fraction A02 is successful. This same reasoning would also be true for Table 3 sequence 5, which was reduced in frequency from 3.9929E-07 to 3.8217E-07.

The fourth ranked sequence in Table 4 is essentially the same as what would be the sixth ranked sequence for Case 1. Since offsite power is available in this sequence, the impact of the increased EDG unavailability associated with the 14-day AOT is minor and the reduction in the success terms is insignificant.

Unit I - Case 2 Sequence Progression Description Sequence 1: This sequence is initiated by one of the 3 clustered emergency switchgear ventilation fans (VS-F-16A, 16B, 55A) igniting with a fire radius greater than 6 feet that destroys one of the other nearby fans, with a subsequent failure of the operators to align portable ventilation. The loss of all emergency switchgear ventilation then leads to a total loss of all Emergency AC and DC Power, and also fails the vital buses. The operators go to ECA-0.0, but are unsuccessful in establishing a cross-tie to the Unit 2 Emergency Diesel Generators, primarily due to non-recoverable failures of the Emergency AC Power equipment from overheating. This results in an extended loss of all Emergency AC and DC Power at Unit 1, and a 21-gpm/RCP Seal LOCA develops. Additionally, no credit for electric power recovery to the Emergency AC buses is taken, since it is assumed that they cannot be repaired in the 24-hour mission time. Without any emergency AC power, RCS inventory makeup is not available. Auxiliary Feedwater is also assumed to be unavailable due to the loss of AC power to the motor driven AFW pumps and loss of instrumentation (vital bus failures) to support the turbine driven AFW pump. Without any instrumentation, the operators are also unsuccessful in aligning an MFW or Dedicated AFW pump, or establishing bleed and feed cooling. This leads to the Steam Generators drying out and increasing the RCS pressure above the RCS safety valve lift setpoint. As the safety valves open, RCS inventory is lost and pressure decreases, until the RCS pressure is below the safety valve reseat pressure. Once the safety valves close, the loss of RCS inventory is terminated; however, the RCS pressure increases again until the safety valves lift. This process keeps on cycling, and eventually the core uncovers at about 1.9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months following the loss of all power, with core damage occurring shortly after, at approximately 2.1 hours1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

Attachment A to L-04-141 Page 21 Sequence 2: This sequence is initiated by a seismic event with the earthquake ground acceleration in the 0.35-g to 0.50-g range. Since the plant was seismically designed to ground accelerations below 0.125-g, massive structural damage occurs. This leads to the seismic failure of the Emergency DC Battery block walls and all components located within.

Additionally, seismic failures of the Offsite Grid and the ERF Diesel Generator occur. These failures lead to a Station Blackout (loss of all Normal and Emergency AC Power) along with a loss of all DC power to the station, since the Emergency Diesel Generators would fail to start following a loss of Offsite Power, due to the failure of the Emergency DC Batteries. No credit for the cross-tie to the Unit 2 Emergency Diesel Generators or electric power recovery to the Emergency AC buses is taken since DC power is not available to restart any equipment. The remaining sequence of events is the same as Sequence 1, following the extended loss of all Emergency AC and DC Power.

Sequence 3: This sequence is also initiated by a seismic event, except this time the earthquake ground acceleration is in the 0.25-g to 0.35-g range. Since the plant was seismically designed to ground accelerations below 0.125-g, massive structural damage occurs that results in the same components failures as in Sequence 2. The remaining sequence of events is therefore the same as Sequence 2.

Sequence 4: This sequence is initiated by a loss of Station Instrument Air, which results in the failure of RCP thermal barrier cooling due to the isolation valves failing closed. The loss of air also results in letdown isolation, which cause a low Volume Control Tank (VCT) level and signal to swapover to the Refueling Water Storage Tank (RWST). However, swapover to the RWST does not occur due to either the RWST check valve (SI-27) not opening or the RWST/VCT MOVs fail to open/close. This results in the cavatation and failure of HHSI pumps, which leads to a loss of RCP seal injection. Without any RCP thermal barrier cooling or RCP seal injection a 21-gpm/RCP Seal LOCA develops. After about 30 minutes following the RCP Seal LOCA initiation, the RCP Second Stage Seals fail and the 21 -

gpm/RCP Seal LOCA develops into a 57-gpm!RCP Seal LOCA. Auxiliary Feedwater is available but the operators are unsuccessful in the cooldown and depressurization of the RCS. Without any HHSI, RCS conditions degrade to some point where entry into EOP FR-C. I occurs. However, without the ability to depressurize the RCS for LHSI injection or recovery of the HHSI, there is no makeup to the RCS and the core eventually uncovers at about 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months with subsequent core damage at 28 hours3.240741e-4 days 0.00778 hours 4.62963e-5 weeks 1.0654e-5 months .

Sequence 5: This sequence is also initiated by a seismic event with the earthquake ground acceleration in the 0.35-g to 0.50-g range. Since the plant was seismically designed to ground accelerations below 0.125-g, massive structural damage occurs that results in the seismic failure of the River Water and Auxiliary River Water Intake Structures, as well as the Offsite and ERF AC power supplies. Both of the Emergency Diesel Generators successfully start and supply power to the Emergency AC buses following the loss of Offsite Power.

However, due to the structural damage of the Intake Structures, the River Water pumps catastrophically fail, leading to the loss of all River Water/Auxiliary River Water. This consequently leads to the failure of the Emergency Diesel Generators due to loss of cooling, and a Station Blackout (loss of all Normal and Emergency AC Power) occurs. These failures lead to the loss of all RCP seal cooling and a 21-gpm/RCP Seal LOCA develops. Dedicated AFW is unavailable due to the seismic failure of the ERF power, but Auxiliary Feedwater is

Attachment A to L-04-141 Page 22 available via the turbine driven AFW pump and the operators successfully cooldown and depressurize the RCS, which reduces the RCP seal leakage and conditions stabilize. However due to the SBO, after about 3.8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months the batteries supplying power for the Steam Generator level indication depletes, and the operators are forced to leave the AEW flow control valves in their last known position. Due to the core decay heat reduction over time, the fixed AFW flow eventually overfills the Steam Generators after about 11 hours1.273148e-4 days 0.00306 hours 1.818783e-5 weeks 4.1855e-6 months , which leads to water ingestion and failure of the turbine driven AFW pump. Without any AFW, the Steam Generators eventually dryout and the RCS quickly repressurizes; thereby, increasing the RCS break flow through the RCP seals and eventually lifting RCS safety valves. Once the safety valves open, the increase in RCS leakage rapidly leads to core uncovery at about 19 hours2.199074e-4 days 0.00528 hours 3.141534e-5 weeks 7.2295e-6 months , with core damage occurring shortly after, at approximately 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months .

Unit 2 Dominant Sequence Comparison Based on the comparison of these top five sequences at Unit 2, it too can be seen that there are no differences in the top two sequences, other than the frequency at which they occur.

For these sequences, a loss of one train of emergency AC power is the initiating event, with the probabilistic failure of the opposite train of emergency AC. These differences in the sequence frequencies can be attributed to the slight increase in the emergency AC power probabilistic split fraction (BPI and AO I) values. For these split fractions, since offsite power remains available in the sequences, the impact of the increased EDG unavailability associated with the 14-day AOT is only minor.

Table 3 Case 1, sequence 3 and Table 4 Case 2, sequence 5 are also the same sequence with the same frequency. This sequence is initiated by an excessive main feedwater event. Since offsite power and both emergency AC busses are available in this sequence, the impact of the increased EDG unavailability associated with the 14-day AOT is minor and the reduction in the success terms is insignificant.

The fourth ranked sequence in Table 3 Case I is essentially the same as what would be the sixth ranked sequence for Case 2, with a frequency of 6.0023E-07. This sequence is initiated by a fire in the Control Room Benchboard Sections Cl and C2, and spreads to Section C3.

Once again, since offsite power is available in this sequence, the impact of the increased EDG unavailability associated with the 14-day AOT is minor and the reduction in the success terms is insignificant.

Sequences 3 and 4 in Table 4 Case 2 are essentially the same as sequence 5 in Table 3 Case I and what would be the sixth ranked sequence for Case 1, with a frequency of 4.6534E-07.

For these sequences, a loss of one train of emergency AC power is the initiating event, with the probabilistic failure of the opposite train of normal 4KV and emergency AC power.

Since the normal 4KV bus fails, there is a need for the associated EDG to start, load, and run for the 24-hour mission time modeled. Failure of emergency AC power split fractions (AO2 and BP8) in these sequences implies that there is a high likelihood that EDGs failures were observed. Therefore, the 14-day EDG AOT extension sequence frequencies in Table 4 Case 2 are higher than the associated Case I frequencies, due to the higher failure probability associated with increased EDG unavailability. However, the total increase in risk associated

Attachment A to L-04-141 Page 23 with these 14-day EDG AOT extension sequences is approximately 3.8E-07, and is not considered to significantly exacerbate the sequence risk.

Unit 2 - Case 2 Sequence Progression Description Sequence 1: This sequence is initiated by a loss of Emergency AC Orange Power (which is assumed to be non-recoverable), with a subsequent failure of Emergency AC Purple Power, mostly due to 480VUS-2-9 bus unavailability or equipment failures of the 4KVS-2DF bus.

The operators go to ECA-0.0, but are unsuccessful in establishing a cross-tie to the Unit I Emergency Diesel Generators, primarily due to non-recoverable failures of the Emergency AC Purple Train equipment. This results in an extended loss of all Emergency AC Power at Unit 2, and a 21-gpm/RCP seal LOCA develops. Additionally, no credit for electric power recovery to the 2DF Emergency AC bus is taken, since the bus failed even though offsite power and the Emergency Diesel Generator were available. Without any emergency AC power, RCS inventory makeup is not available. Auxiliary Feedwater is available via the turbine driven AFW pump and the operators successfully cooldown and depressurize the RCS, which reduces the RCP seal leakage and conditions stabilize. However, after about 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months the batteries supplying power for the Steam Generator level indication depletes, and the operators are forced to leave the AFW flow control valves in their last known position.

Due to the core decay heat reduction over time, the fixed AFW flow eventually overfills the Steam Generators after about 22 hours2.546296e-4 days 0.00611 hours 3.637566e-5 weeks 8.371e-6 months , which leads to water ingestion and failure of the turbine driven AFW pump. Without any AFW, the Steam Generators eventually dryout and the RCS quickly repressurizes; thereby, increasing the RCS break flow through the RCP seals and eventually lifting RCS safety valves. Once the safety valves open, the increase in RCS leakage rapidly leads to core uncovery at about 37 hours4.282407e-4 days 0.0103 hours 6.117725e-5 weeks 1.40785e-5 months , with core damage occurring shortly after, at approximately 38 hours4.398148e-4 days 0.0106 hours 6.283069e-5 weeks 1.4459e-5 months .

Sequence 2: This sequence is similar to the first sequence; however this time the initiator is a loss of Emergency AC Purple Power, with a subsequent failure of Emergency AC Orange Power. In this sequence the operators are also unsuccessful in establishing a cross-tie to the Unit 1 Emergency Diesel Generators, but this time it is primarily due to non-recoverable failures of the Emergency AC Orange Train equipment. Additionally, no credit for electric power recovery to the 2AE Emergency AC bus is taken, since the bus failed even though offsite power and the Emergency Diesel Generator were available. This also results in a 21-gpm/RCP seal LOCA due to the extended loss'of all Emergency AC Power. The remaining sequence of events is the same as Sequence 1, following the RCP seal LOCA initiation. This sequence has about half the frequency of occurring compared to the first, due to no historical maintenance unavailability of the 480VUS-2-8 bus during the update period; whereas, the 480VUS-2-9 bus had 2.75 hours8.680556e-4 days 0.0208 hours 1.240079e-4 weeks 2.85375e-5 months of unavailability.

Sequence 3: This sequence is also initiated by a loss of Emergency AC Purple Power; however, this time a subsequent failure of the Normal 4KVS-2A bus occurs during the fast bus transfer to offsite power. This leads to a demand on the No.1 Emergency Diesel Generator (2EGS-EG2-1), which is unsuccessful, thereby causing a failure of Emergency AC Orange Power. The operators go to ECA-0.0 and try to restore Normal AC Power to the 2A bus, but are unsuccessful in their attempts to repair/replace the fast bus transfer breakers.

Without the Normal 4KVS-2A bus to supply power to the Emergency AC Orange bus, and a

Attachment A to L-04-141 Page 24 non-recoverable failure of the Emergency AC Purple bus, there is no way to establish a cross-tie to the Unit I Emergency Diesel Generators, so no credit is given. This results in an extended loss of all Emergency AC Power with a loss of the Normal 4KVS-2A bus at Unit 2, and a 21-gpm/RCP seal LOCA develops. The remaining sequence of events is the same as Sequence 1, following the RCP seal LOCA initiation.

Sequence 4: This sequence is initiated by a loss of Emergency AC Orange Power, with a subsequent failure of the Normal 4KVS-2D bus that occurs during the fast bus transfer to offsite power. This leads to a demand on the No.2 Emergency Diesel Generator (2EGS-EG2-2), which is unsuccessful, thereby causing a failure of Emergency AC Purple Power.

The operators go to ECA-0.0 and try to restore Normal AC Power to the 2D bus, but are unsuccessful in their attempts to repair/replace the fast bus transfer breakers. Without the Normal 4KVS-2D bus to supply power to the Emergency AC Purple bus, and a non-recoverable failure of the Emergency AC Purple bus, there is no way to establish a cross-tie to the Unit I Emergency Diesel Generators, so no credit is given. This results in an extended loss of all Emergency AC Power with a loss of the Normal 4KVS-2D bus at Unit 2, and a 21-gpm/RCP seal LOCA develops. The remaining sequence of events is the same as Sequence 1, following the RCP seal LOCA initiation.

Sequence 5: This sequence is initiated by an excessive feedwater event that results in Main Feedwater isolation. Eventually the loss of MFW leads to a steam generator low-low level and an Auxiliary Feedwater initiation signal, which subsequently fails. The conditions warrant entry into EOP FR-H.1, but the operators fail to implement RCS bleed and feed cooling. This leads to the Steam Generators drying out and increasing the RCS pressure above the PORV lift setpoint. As the PORVs open, RCS inventory is lost and pressure decreases, until the RCS pressure is below the PORV reseat pressure. Once the PORVs close, the loss of RCS inventory is terminated; however, the RCS pressure increases again until the PORVs lift. This process keeps on cycling, and eventually the core uncovers. At this point, the operators would normally enter into EOP FR-C.1 to initiate HHSI and depressurize the RCS to restore core cooling (essentially bleed and feed cooling). However, even if the operators were successful in manually actuating HHSI at this time, the flow rate would not be adequate to keep up with the inventory lost out the PORVs at these RCS pressures. Therefore, no credit is given for these actions since they were unsuccessful in EOP FR-H.1.

Attachment A to L-04-141 Page 25 Table 5 Unit 1 - Case I Initiating Event CDF Contribution Init. Event I.E.

Core Damage % of Total I.E. Description Frequency Frequency CDF AMSIVA 1.45E-02 2.74E-11 0.00% CLOSURE OF ALL MSIV'S -

ATWS AOXA 2.04E-02 1.85E-09 0.01% LOSS OF EMERGENCY 4160V AC ORANGE -

ATWS BPXA 2.04E-02 2.04E-09 0.01% LOSS OF EMERGENCY 4160V AC PURPLE -

ATWS CCXA 3.14E-03 4.OOE-12 0.00%

LOSS OF REACTOR COMPONENT COOLING WATER -

ATWS DOXA 3.38E-02 1.30E-08 0.06% LOSS OF EMERGENCY 125V DC ORANGE -

ATWS DPXA 3.38E-02 5.95E-09 0.03% LOSS OF EMERGENCY 125V DC PURPLE-ATWS EXFWA 1.90E-01 1.44E-08 0.06% EXCESSIVE FEEDWATER FLOW -

ATWS IAXA 7.89E-02 6.07E-09 0.03% LOSS OF STATION INSTRUMENT AIR -

ATWS IBXA 6.OOE-03 3.02E-09 0.01%

LOSS OF VITAL BUS III (BLUE) -

ATWS ICXA 1.25E-02 2.37E-11 0.00% CNMT INST AIR INITIATING EVENT -

ATWS IMSIVA 1.89E-01 1.41E-08 0.06% CLOSURE OF ONE MSIV -

ATWS IRXA 6.OOE-03 9.79E-11 0.00%

LOSS OF VITAL BUS I (RED) -

ATWS ISIA 9.56E-02 7.09E-09 0.03%

INADVERTANT SAFETY INJECTION INITIATION -

_ _ _ ATW S IWXA 6.OOE-03 1.03E-10 0.00%

LOSS OF VITAL BUS II (WHITE) -

ATWS IYXA 6.OOE-03 2.11E-09 0.01% LOSS OF VITAL BUS IV (YELLOW) -

ATWS LB1AA 3.85E-03 5.41E-11 0.00% LOSS OF NORMAL 4KV BUS 1A -

ATWS LB1DA 3.52E-03 4.61E-11 0.00%

LOSS OF NORMAL 4KV BUS 1D -

ATWS LCVA 1.34E-01 3.01E-10 0.00%

LOSS OF CONDENSER VACUUM -

ATWS LOSPA 3.16E-02 8.98E-09 0.04% LOSS OF OFFSITE POWER -

ATWS LOPFA 9.09E-02 1.99E-10 0.00%

LOSS OF PRIMARY FLOW -

ATWS MFWLBA 2.62E-03 1.84E-10 0.00% MAIN FEEDWATER LINE BREAK -

ATWS MSVA 9.76E-04 1.12E-10 0.00% MAIN STEAM RELIEF OR SAFETY VALVE OPENING ATWS PLMFWA 5.88E-01 4.47E-08 0.19%

PARTIAL LOSS OF MAIN FEEDWATER - ATWS SGTRAA 1.48E-03 5.66E-09 0.02% STEAM GENERATOR A TUBE RUPTURE -

ATWS SGTRBA 1.48E-03 5.66E-09 0.02% STEAM GENERATOR B TUBE RUPTURE -

ATWS SGTRCA 1.48E-03 5.66E-09 0.02% STEAM GENERATOR C TUBE RUPTURE -

ATWS SLBIA 8.49E-04 1.04E-10 0.00% STEAMLINE BREAK INSIDE CONTAINMENT -

ATWS SLBCA 1.54E-03 1.81E-10 0.00% STEAM LINE BREAK IN COMMON RHS LINE -

ATWS SLBDA 4.58E-03 5.54E-10 0.00% STEAM LINE BREAK OUTSIDE CONTAINMENT -

ATWS TLMFWA 4.85E-02 3.63E-09 0.02% TOTAL LOSS OF MAIN FEEDWATER -

ATWS TTRIPA 7.17E-01 1.74E-09 0.01% TURBINE TRIP -

ATWS WCXA 3.80E-06 1.25E-11 0.00%

LOSS OF RIVER WATER HEADERS A & B -

ATWS 1.48E-07 I 0.63% ATWSTOTAL AFILIC 1.31E-06 2.66E-11 0.00% DETAILED FIRE SCENARIO AFl-L-1C CRlLlA 3.10E-05 1.51E-11 0.00%

DETAILED FIRE SCENARIO CR1-L-1A CRlLlB 2.95E-05 1.43E-11 0.00% DETAILED FIRE SCENARIO CR1-L-1B

Attachment A to L-04-141 Page 26 Table 5 Unit 1 - Case I Initiating Event CDF Contribution Init. Event I.E.

Core Damage % of Total I.E. Description Frequency Frequency CDF CRlLlC 4.57E-05 2.22E-11 0.00%

DETAILED FIRE SCENARIO CR1-L-1C CRlLlD 4.27E-05 2.08E-11 0.00%

DETAILED FIRE SCENARIO CR1-L-1D CRILlF 2.95E-05 1.43E-11 0.00%

DETAILED FIRE SCENARIO CR1-L-1F CRlLlG 9.14E-05 5.81E-11 0.00% DETAILED FIRE SCENARIO CR1-L-lG CRlLlO 5.71E-06 8.18E-08 0.35% DETAILED FIRE SCENARIO CRI-L-1O CRlLlP 1.47E-05 2.11E-07 0.90% DETAILED FIRE SCENARIO CR1-L-1P CRlLlQ 3.54E-06 5.07E-08 0.22% DETAILED FIRE SCENARIO CR1-L-1Q CRlLlS 1.62E-06 5.02E-08 0.21% DETAILED FIRE SCENARIO CR1-L-1S CR3L1E 8.78E-07 6.17E-08 0.26% DETAILED FIRE SCENARIO CR3-L-1E CR3L1F 8.61E-06 1.97E-12 0.00% DETAILED FIRE SCENARIO CR3-L-1F CR3L1G 8.10E-07 5.69E-08 0.24% DETAILED FIRE SCENARIO CR3-L-1G CR3P1A 2.47E-07 1.73E-08 0.07%

DETAILED FIRE SCENARIO CR3-P-1A CR4L1A 2.22E-04 1.58E-10 0.00% DETAILED FIRE SCENARIO CR4-L-1A CR4L1C 1.90E-07 1.90E-07 0.81%

DETAILED FIRE SCENARIO CR4-L-1C CR4L1D 1.13E-07 1.13E-07 0.48% DETAILED FIRE SCENARIO CR4-L-1D CR4L1E 5.65E-07 3.96E-08 0.17%

DETAILED FIRE SCENARIO CR4-L-1E CR4L1O 2.74E-07 1.92E-08 0.08%

DETAILED FIRE SCENARIO CR4-L-1O CR4L1P 8.01E-08 8.00E-08 0.34% DETAILED FIRE SCENARIO CR4-L-1P CRLlAC 2.89E-05 1.42E-09 0.01% DETAILED FIRE SCENARIO CR1-L-1AC CRLlAP 2.89E-05 1.20E-09 0.01%

DETAILED FIRE SCENARIO CR1-L-lAP CRL1EB 4.93E-05 1.1OE-09 0.00% DETAILED FIRE SCENARIO CR1-L-lEB CRP1AE 5.34E-05 2.61E-08 0.11% DETAILED FIRE SCENARIO CR1-P-1AE CS1L1A 3.95E-05 1.92E-11 0.00% DETAILED FIRE SCENARIO CS1-L-1A CSlLlB 5.39E-06 4.26E-07 1.81%

DETAILED FIRE SCENARIO CS1-L-1B CSlLlC 3.23E-05 2.55E-06 10.85% DETAILED FIRE SCENARIO CS1-L-1C CSlLlD 1.07E-04 7.02E-11 0.00% DETAILED FIRE SCENARIO CS1-L-1D CSlLlE 1.80E-06 1.27E-07 0.54% DETAILED FIRE SCENARIO CS1-L-1E CS1L1F 2.05E-07 1.43E-08 0.06% DETAILED FIRE SCENARIO CS1-L-1F CV1L1A 1.20E-06 O.OOE+00 0.00% DETAILED FIRE SCENARIO CV1-L-1A CV1L1B 8.12E-06 1.62E-10 0.00% DETAILED FIRE SCENARIO CV1-L-1B CVlLD 7.46E-06 1.71E-12 0.00% DETAILED FIRE SCENARIO CV1-L-1D CV1L1G 1.14E-06 O.OOE+00 0.00% DETAILED FIRE SCENARIO CV1-L-1G VlLlH 7.26E-07 O.OOE+00 0.00% DETAILED FIRE SCENARIO CV1-L-1H CV2L1A 7.02E-06 1.60E-12 0.00%

DETAILED FIRE SCENARIO CV2-L-1A V2L1E 1.20E-06 O.OOE+00 0.00%

DETAILED FIRE SCENARIO CV2-L-1E CV2L1F 1.47E-05 5.97E-12 0.00%

DETAILED FIRE SCENARIO CV2-L-1F CV3L1A 3.11E-06 2.19E-07 0.93% DETAILED FIRE SCENARIO CV3-L-1A CV3L1B 1.16E-06 8.15E-08 0.35% DETAILED FIRE SCENARIO CV3-L-1B DGlLA 9.08E-03 4.52E-08 0.19% DETAILED FIRE SCENARIO DG1-L-1A DG2L1A 9.OOE-03 4.44E-08 0.19% DETAILED FIRE SCENARIO DG2-L-1A

Attachment A to L-04-141 Page 27 Table 5 Unit I - Case 1 Initiating Event CDF Contribution Init. Event I.E.

Core Damage % of Total I.E. Description Frequency Frequency CDF ES1AE1 1.40E-04 1.69E-08 0.07%

DETAILED FIRE SCENARIO ES1AE-L-1 ESlDF1 1.61E-04 1.21E-08 0.05% DETAILED FIRE SCENARIO ES1DF-L-1 NS1L1B 1.83E-07 1.28E-08 0.05%

DETAILED FIRE SCENARIO NS1-L-1B NS1LlG 4.57E-08 3.17E-09 0.01%

DETAILED FIRE SCENARIO NS1-L-1G NSlLII 4.57E-08 3.17E-09 0.01%

DETAILED FIRE SCENARIO NSl-L-lI NS1L1J 1.84E-07 1.29E-08 0.05% DETAILED FIRE SCENARIO NS1-L-1J NS1L1K 2.75E-07 1.93E-08 0.08%

DETAILED FIRE SCENARIO NSl-L-1K NS1L1L 2.75E-07 1.93E-08 0.08%

DETAILED FIRE SCENARIO NS1-L-lL NS1L1M 1.84E-07 1.29E-08 0.05%

DETAILED FIRE SCENARIO NSl-L-1M NS1L1Q 1.80E-07 1.26E-08 0.05% DETAILED FIRE SCENARIO NS1-L-1Q PA1ELC 6.43E-07 7.12E-09 0.03% DETAILED FIRE SCENARIO PA1E-L-1C PA1ELE 6.43E-07 7.12E-09 0.03% DETAILED FIRE SCENARIO PA1E-L-1E PA1ELF 4.29E-07 4.74E-09 0.02% DETAILED FIRE SCENARIO PAlE-L-1F PA1ELG 1.07E-07 1.17E-09 0.00%

DETAILED FIRE SCENARIO PAlE-L-1G PA1ELH 2.14E-07 2.36E-09 0.01%

DETAILED FIRE SCENARIO PA1E-L-1H PA1ELI 2.14E-07 2.36E-09 0.01%

DETAILED FIRE SCENARIO PA1E-L-1I PA1ELM 6.09E-08 6.63E-10 0.00% DETAILED FIRE SCENARIO PA1E-L-1M PA1GDB 2.54E-05 1.14E-11 0.00% DETAILED FIRE SCENARIO PA1GD-L-1B PA1GDH 9.03E-06 1.01E-09 0.00% DETAILED FIRE SCENARIO PA1GD-L-1H PNAP1A 1.14E-04 9.09E-11 0.00% DETAILED FIRE SCENARIO PNA-P-1A PT1ALA 1.44E-04 1.09E-10 0.00% DETAILED FIRE SCENARIO PT1A-L-A PT1APA 2.22E-05 9.07E-12 0.00% DETAILED FIRE SCENARIO PT1A-P-1A RC1L1 1.46E-02 2.31E-08 0.10% DETAILED FIRE SCENARIO RCi-L-1 TB1ALA 2.39E-04 3.89E-09 0.02% DETAILED FIRE SCENARIO TB1A-L-1A TG1P1A 1.47E-04 2.38E-09 0.01% DETAILED FIRE SCENARIO TG1-P-1A 4.69E-06 19.95% INTERNAL FIRES TOTAL CRFL 3.29E-06 1.95E-09 0.01% FLOOD IN CONTROL BLDG HVAC ROOM CVFL 1.50E-04 1.50E-11 0.00% WEST CABLE VAULT FLOOD ISFLA 9.01E-04 3.64E-09 0.02%

INTAKE STRUCTURE FLOOD IN CUBICLE A ISFLB 6.76E-04 2.74E-10 0.00%

INTAKE STRUCTURE FLOOD IN CUBICLE B ISFLC 6.76E-04 2.08E-10 0.00%

INTAKE STRUCTURE FLOOD IN CUBICLE C ISFLD 1.13E-03 1.56E-10 0.00%

INTAKE STRUCTURE FLOOD IN CUBICLE C PABF1A 3.85E-04 1.39E-08 0.06% PAB FLOOD AT EL 735 RW TRN A -

ISOLATED PABF1B 3.85E-04 8.48E-09 0.04% PAB FLOOD AT EL 735 RW TRN B -

ISOLATED PABF2A 2.53E-05 2.83E-07 1.20%

PAB FLOOD AT EL 735 TRN A -

NOT ISOLATED PABF2B 2.53E-05 2.83E-07 1.20%

PAB FLOOD AT EL 735 TRN B -

NOT ISOLATED PABF3A 3.90E-04 1.20E-08 0.05%

PAB FLOOD AT EL 722 TRN A -

EARLY ISOLATION PABF3B 3.90E-04 5.98E-09 0.03%

PAB FLOOD AT EL 722 TRN B -

EARLY I _ISOLATION

r Attachment A to L-04-141 Page 28 Table 5 Unit 1 - Case 1 Initiating Event CDF Contribution Init. Event I.E.

Core Damage % of Total I.E. Description Frequency Frequency CDF PABF4A 3.32E-05 1.12E-09 0.00% PAB FLOOD AT EL 722 TRN A -

LATE ISOLATION PABF4B 3.32E-05 6.66E-10 0.00%

PAB FLOOD AT EL 722 TRN B -

LATE ISOLATION PABF5A 1.68E-06 6.09E-11 0.00%

PAB FLOOD AT EL 722 TRN A -

NOT ISOLATED PABF5B 1.68E-06 4.35E-11 0.00%

PAB FLOOD AT EL 722 TRN B -

NOT ISOLATED TBFL 7.71E-03 7.45E-08 0.32%

TURBINE BUILDING FLOOD 6.89E-07 2.93% INTERNAL FLOODS TOTAL ELOCA 2.66E-07 2.66E-07 1.13% EXCESSIVE LOSS OF COOLANT ACCIDENT LLOCAA 2.40E-06 3.54E-09 0.02%

LARGE LOSS OF COOLANT ACCIDENT IN LOOP A LLOCAB 2.40E-06 3.54E-09 0.02% LARGE LOSS OF COOLANT ACCIDENT IN LOOP B LLOCAC 2.40E-06 3.54E-09 0.02% LARGE LOSS OF COOLANT ACCIDENT IN LOOP C MLOCAA 2.03E-05 4.20E-08 0.18% MEDIUM LOSS OF COOLANT ACCIDENT IN LOOP A MLOCAB 2.03E-05 4.20E-08 0.18% MEDIUM LOSS OF COOLANT ACCIDENT IN LOOP B MLOCAC 2.03E-05 4.20E-08 0.18% MEDIUM LOSS OF COOLANT ACCIDENT IN LOOP C SLOCI 7.26E-04 7.31E-10 0.00% SMALL LOCA, ISOLABLE SLOCN 2.68E-03 1.12E-07 0.48% SMALL LOCA, NONISOLABLE SGTRA 1.48E-03 4.07E-07 1.73%

STEAM GENERATOR A TUBE RUPTURE SGTRB 1.48E-03 4.07E-07 1.73% STEAM GENERATOR B TUBE RUPTURE SGTRC 1.48E-03 4.07E-07 1.73% STEAM GENERATOR C TUBE RUPTURE VSX 1.07E-05 8.OOE-08 0.34%

INTERFACING SYSTEMS LOCA (V-SEQUENCE) 1.82E-06 7.73% LOCAS TOTAL AOX 2.04E-02 6.61E-07 2.81%

LOSS OF EMERGENCY AC ORANGE POWER BPX 2.04E-02 4.16E-07 1.77% LOSS OF EMERGENCY 4160V AC PURPLE DOX 3.38E-02 5.17E-07 2.20% LOSS OF EMERGENCY 125V DC ORANGE DPX 3.38E-02 7.84E-07 3.34% LOSS OF EMERGENCY 125V DC PURPLE IBX 6.OOE-03 3.29E-09 0.01%

LOSS OF VITAL BUS III (BLUE)

IRX 6.OOE-03 2.41E-08 0.10% VITAL BUS 1 INITIATING EVENT IWX 6.OOE-03 1.50E-08 0.06% VITAL BUS 2 INITIATING EVENT IYX 6.OOE-03 3.28E-09 0.01% LOSS OF VITAL BUS IV (YELLOW)

LB1A 3.85E-03 3.46E-08 0.15%

LOSS OF NORMAL 4KV BUS 1A LB1D 3.52E-03 2.09E-08 0.09%

LOSS OF NORMAL 4KV BUS 1D LOSP 3.16E-02 2.87E-07 1.22%

LOSS OF OFFSITE POWER 2.77E-06 11.77% AC/DC POWER LOSSES TOTAL SEIS1 1.42E-04 4.50E-07 1.92%

SEISMIC PGA (0.10 -

0.25 G)

SEIS2 1.70E-05 3.OOE-06 12.75% SEISMIC PGA (0.25 -

0.35 G)

SEIS3 8.36E-06 5.25E-06 22.34% SEISMIC PGA (0.35 -

0.50 G)

SEIS4 2.93E-06 2.93E-06 12.44% SEISMIC PGA (0.50 -

1.00 G)

SEIS5 7.57E-08 7.50E-08 0.32% SEISMIC PGA (1.00 -

1.33 G) 1.17E-05 49.77% EARTHQUAKES TOTAL AMSIV 1.45E-02 3.63E-09 0.02%

CLOSURE OF ALL MSIV'S BVX 1.86E-07 5.27E-09 0.02% LOSS OF EMERGENCY SWITCHGEAR VENTILATION

Attachment A to L-04-141 Page 29 Table 5 Unit 1 - Case 1 Initiating Event CDF Contribution Init. Event I.E.

Core Damage % of Total I.E. Description Frequency Frequency CDF CCX 3.14E-03 1.12E-08 0.05%

LOSS OF REACTOR COMPONENT COOLING WATER CPEXC 1.18E-02 1.95E-09 0.01%

CORE POWER EXCURSION EXFW 1.90E-01 3.30E-08 0.14%

EXCESSIVE FEEDWATER FLOW IAX 7.89E-02 7.40E-07 3.15%

LOSS OF STATION INSTRUMENT AIR ICX 1.25E-02 4.46E-08 0.19% CNMT INSTRUMENT AIR INITIATING EVENT IMSIV,

1.89E-01 9.52E-08 0.40%

CLOSURE OF ONE MSIV ISI 9.56E-02 4.77E-08 0.20%

INADVERTANT SAFETY INJECTION INITIATION LCV 1.34E-01 2.31E-08 0.10%

LOSS OF CONDENSER VACUUM LOPF 9.09E-02 1.54E-08 0.07%

LOSS OF PRIMARY FLOW MFWLB 2.62E-03 9.52E-10 0.00%

MAIN FEEDWATER LINE BREAK MSV 9.76E-04 4.81E-10 0.00%

MAIN STEAM RELIEF OR SAFETY VALVE OPENING PLMFW 5.88E-01 1.03E-07 0.44%

PARTIAL LOSS OF MAIN FEEDWATER RTRIP 8.39E-01 1.48E-07 0.63% REACTOR TRIP SLBC 1.54E-03 8.69E-10 0.00% STEAM LINE BREAK IN COMMON RHS LINE SLBD 4.58E-03 3.11E-09 0.01%

STEAM LINE BREAK OUTSIDE CONTAINMENT SLBI 8.49E-04 4.43E-09 0.02%

STEAMLINE BREAK INSIDE CONTAINMENT TLMFW 4.85E-02 1.68E-08 0.07%

TOTAL LOSS OF MAIN FEEDWATER -

ATWS TTRIP 7.17E-01 1.30E-07 I 0.55% TURBINE TRIP WCX 3.80E-06 2.67E-07 1.14%

LOSS OF RIVER WATER HEADERS A & B 1.70E-06 7.22% TRANSIENTS TOTAL

f Attachment A to L-04-141 Page 30 Table 6 Unit 1 - Case I Sequence Type Contribution Sequence Type Frequency Percentage Seismic Events 1.17E-05 49.77%

Internal Fires 4.69E-06 19.95%

Loss of Emergency DC Power 1.30E-06 5.54%

Steam Generator Tube Rupture 1.22E-06 5.20%

Loss of Emergency AC Power 1.08E-06 4.58%

Loss of Station Air 7.40E-07 3.15%

Internal Floods 6.89E-07 2.93%

Loss of Offsite Power 2.87E-07 1.22%

Loss of River Water 2.67E-07 1.14%

Excessive LOCA 2.66E-07 1.13%

Other Sequence Types 1.88E-07 0.80%

Reactor Trip 1.48E-07 0.63%

ATWS 1.48E-07 0.63%

Turbine Trip 1.30E-07 0.55%

Medium LOCA 1.26E-07 0.54%

Non-Isolable Small LOCA 1.12E-07 0.48%

Partial Loss of MFW 1.03E-07 0.44%

Interfacing Systems LOCA 8.OOE-08 0.34%

Loss Of Normal AC Power 5.55E-08 0.24%

Inadvertent Safety Injection 4.77E-08 0.20%

Loss of Containment Air 4.46E-08 0.19%

Excessive MFW 3.30E-08 0.14%

Loss of Condenser Vacuum 2.31 E-08 0.10%

Total Loss of MFW 1.68E-08 0.07%

Large LOCA 1.06E-08 0.05%

Isolable Small LOCA 7.31E-10 0.00%

Attachment A to L-04-141 Page 31 Table 7 Unit 1 - Case 2 Initiating Event CDF Contribution Init. Event I.E.

Core Damage % of Total I.E. Description Frequency Frequency CDF AMSIVA 1.45E-02 2.74E-11 0.00% CLOSURE OF ALL MSIV'S -

ATWS AOXA 2.04E-02 1.85E-09 0.01%

LOSS OF EMERGENCY 4160V AC ORANGE -

ATWS BPXA 2.04E-02 2.04E-09 0.01%

LOSS OF EMERGENCY 4160V AC PURPLE -

ATWS ZCXA 3.14E-03 4.OOE-12 0.00%

LOSS OF REACTOR COMPONENT COOLING WATER -

DOXA 3.38E-02 1.3LSS ATWS DOXA 3.38E-02 1.30E-08 0.05%

LOSS OF EMERGENCY 125V DC ORANGE -

ATWS DPXA 3.38E-02 5.96E-09 0.03%

LOSS OF EMERGENCY 125V DC PURPLE-ATWS EXFWA 1.90E-01 1.44E-08 0.06% EXCESSIVE FEEDWATER FLOW -

ATWS IAXA 7.89E-02 6.07E-09 0.03%

LOSS OF STATION INSTRUMENT AIR -

ATWS IBXA 6.OOE-03 3.02E-09 0.01%

LOSS OF VITAL BUS III (BLUE) -

ATWS ICXA 1.25E-02 2.37E-11 0.00% CNMT INST AIR INITIATING EVENT -

ATWS IMSIVA 1.89E-01 1.41E-08 0.06% CLOSURE OF ONE MSIV -

ATWS IRXA 6.OOE-03 9.80E-11 0.00%

LOSS OF VITAL BUS I (RED) -

ATWS ISIA 9.56E-02 7.09E-09 0.03%

INADVERTANT SAFETY INJECTION INITIATION -

____ATWS IWXA 6.OOE-03 1.02E-10 0.00% LOSS OF VITAL BUS II (WHITE) -

ATWS IYXA 6.OOE-03 2.11E-09 0.01%

LOSS OF VITAL BUS IV (YELLOW) -

ATWS LB1AA 3.85E-03 5.90E-11 0.00%

LOSS OF NORMAL 4KV BUS 1A -

ATWS LB1DA 3.52E-03 5.13E-11 0.00%

LOSS OF NORMAL 4KV BUS 1D -

ATWS LCVA 1.34E-01 3.03E-10 0.00%

LOSS OF CONDENSER VACUUM -

ATWS LOSPA 3.16E-02 9.14E-09 0.04% LOSS OF OFFSITE POWER -

ATWS LOPFA 9.09E-02 1.99E-10 0.00%

LOSS OF PRIMARY FLOW -

ATWS MFWLBA 2.62E-03 1.84E-10 0.00% MAIN FEEDWATER LINE BREAK -

ATWS MSVA 9.76E-04 1.12E-10 0.00% MAIN STEAM RELIEF OR SAFETY VALVE OPENING ATWS PLMFWA 5.88E-01 4.47E-08 0.19%

PARTIAL LOSS OF MAIN FEEDWATER -

ATWS SGTRAA 1.48E-03 5.66E-09 0.02%

STEAM GENERATOR A TUBE RUPTURE -

ATWS SGTRBA 1.48E-03 5.66E-09 0.02%

STEAM GENERATOR B TUBE RUPTURE -

ATWS SGTRCA 1.48E-03 5.66E-09 0.02%- STEAM GENERATOR C TUBE RUPTURE -

ATWS SLBIA 8.49E-04 1.04E-10 0.00% STEAMLINE BREAK INSIDE CONTAINMENT -

ATWS SLBCA 1.54E-03 1.81E-10 0.00%

STEAM LINE BREAK IN COMMON RHS LINE -

ATWS SLBDA 4.58E-03 5.54E-10 0.00% STEAM LINE BREAK OUTSIDE CONTAINMENT -

ATWS TLMFWA 4.85E-02 3.63E-09 0.02%

TOTAL LOSS OF MAIN FEEDWATER -

ATWS TTRIPA 7.17E-01 1.75E-09 0.01%

TURBINE TRIP -

ATWS WCXA 3.80E-06 1.25E-11 0.00%

LOSS OF RIVER WATER HEADERS A & B -

ATWS 1.48E-07 0.62% ATWS TOTAL AFlLlC 1.31E-06 2.92E-11 0.00% DETAILED FIRE SCENARIO AFl-L-1C CRlLlA 3.10E-05 1.79E-11 0.00% DETAILED FIRE SCENARIO CR1-L-1A

Attachment A to L-04-141 Page 32 Table 7 Unit 1 - Case 2 Initiating Event CDF Contribution lnit. Event I.E.

Core Damage % of Total I.E. Description Frequency Frequency CDF CRlLlB 2.95E-05 1.70E-11 0.00% DETAILED FIRE SCENARIO CRl-L-1B CRlLlC 4.57E-05 3.21E-11 0.00% DETAILED FIRE SCENARIO CR1-L-1C CRlLlD 4.27E-05 2.90E-11 0.00% DETAILED FIRE SCENARIO CR1-L-1D CRlLlF 2.95E-05 1.70E-11 0.00% DETAILED FIRE SCENARIO CR1-L-1F CRILIG 9.14E-05 6.95E-11 0.00% DETAILED FIRE SCENARIO CR1-L-1G CRlLlO 5.71E-06 8.18E-08 0.34%

DETAILED FIRE SCENARIO CR1-L-1O CRlLlP 1.47E-05 2.11E-07 0.89% DETAILED FIRE SCENARIO CR1-L-1P CRlLlQ 3.54E-06 5.07E-08 0.21% DETAILED FIRE SCENARIO CR1-L-1Q CRlLlS 1.62E-06 5.02E-08 0.21% DETAILED FIRE SCENARIO CR1-L-1S CR3L1E 8.78E-07 6.17E-08 0.26% DETAILED FIRE SCENARIO CR3-L-1E CR3L1F 8.61E-06 3.54E-12 0.00%

DETAILED FIRE SCENARIO CR3-L-1F CR3L1G 8.10E-07 5.69E-08 0.24%

DETAILED FIRE SCENARIO CR3-L-1G CR3P1A 2.47E-07 1.73E-08 0.07%

DETAILED FIRE SCENARIO CR3-P-1A CR4L1A 2.22E-04 1.91E-10 0.00%

DETAILED FIRE SCENARIO CR4-L-1A CR4L1C 1.90E-07 1.90E-07 0.80% DETAILED FIRE SCENARIO CR4-L-1C CR4L1D 1.13E-07 1.13E-07 0.48% DETAILED FIRE SCENARIO CR4-L-1D CR4L1E 5.65E-07 3.96E-08 0.17% DETAILED FIRE SCENARIO CR4-L-1E CR4L1O 2.74E-07 1.92E-08 0.08% DETAILED FIRE SCENARIO CR4-L-1O CR4L1P 8.01E-08 8.OOE-08 0.34% DETAILED FIRE SCENARIO CR4-L-1P CRLlAC 2.89E-05 1.62E-09 0.01% DETAILED FIRE SCENARIO CR1-L-1AC CRL1AP 2.89E-05 1.36E-09 0.01% DETAILED FIRE SCENARIO CR1-L-1AP CRL1EB 4.93E-05 1.11E-09 0.00% DETAILED FIRE SCENARIO CR1-L-1EB CRP1AE 5.34E-05 2.93E-08 0.12% DETAILED FIRE SCENARIO CR1-P-1AE CSlLlA 3.95E-05 2.59E-11 0.00% DETAILED FIRE SCENARIO CS1-L-1A ZS1L1B 5.39E-06 4.26E-07 1.79%

DETAILED FIRE SCENARIO CS1-L-1B CS1L1C 3.23E-05 2.55E-06 10.76% DETAILED FIRE SCENARIO CS1-L-1C CS1L1D 1.07E-04 8.35E-11 0.00%

DETAILED FIRE SCENARIO CS1-L-1D CSlLlE 1.80E-06 1.27E-07 0.53% DETAILED FIRE SCENARIO CS1-L-1E CS1L1F 2.05E-07 1.43E-08 0.06% DETAILED FIRE SCENARIO CS1-L-1F CV1L1A 1.20E-06 O.OOE+00 0.00%

DETAILED FIRE SCENARIO CV1-L-1A CV1L1B 8.12E-06 1.71E-10 0.00% DETAILED FIRE SCENARIO CV1-L-1B CV1L1D 7.46E-06 2.08E-12 0.00%

DETAILED FIRE SCENARIO CV1-L-1D CV1L1G 1.14E-06 O.OOE+00 0.00% DETAILED FIRE SCENARIO CV1-L-1G CV1L1H 7.26E-07 O.OOE+00 0.00% DETAILED FIRE SCENARIO CV1-L-1H ZV2L1A 7.02E-06 1.96E-12 0.00%

DETAILED FIRE SCENARIO CV2-L-1A CV2L1E 1.20E-06 O.OOE+00 0.00%

DETAILED FIRE SCENARIO CV2-L-1E CV2L1F 1.47E-05 7.06E-12 0.00%

DETAILED FIRE SCENARIO CV2-L-1F CV3L1A 3.11E-06 2.19E-07 0.92% DETAILED FIRE SCENARIO CV3-L-1A CV3L1B 1.16E-06 8.15E-08 0.34%

DETAILED FIRE SCENARIO CV3-L-1B DGlLlA 9.08E-03 5.20E-08 0.22%

DETAILED FIRE SCENARIO DG1-L-1A

Attachment A to L-04-141 Page 33 Table 7 Unit I - Case 2 Initiating Event CDF Contribution Init. Event I.E.

Core Damage % of Total I.E. Description Frequency Frequency CDF DG2L1A 9.OOE-03 5.12E-08 0.22% DETAILED FIRE SCENARIO DG2-L-1A ES1AE1 1.40E-04 1.89E-08 0.08% DETAILED FIRE SCENARIO ES1AE-L-1 ES1DF1 1.61E-04 1.37E-08 0.06% DETAILED FIRE SCENARIO ESlDF-L-1 NS1L1B 1.83E-07 1.28E-08 0.05%

DETAILED FIRE SCENARIO NS1-L-1B NS1L1G 4.57E-08 3.17E-09 0.01% DETAILED FIRE SCENARIO NS1-L-1G NS1L1I 4.57E-08 3.17E-09 0.01% DETAILED FIRE SCENARIO NS1-L-1I NS1L1J 1.84E-07 1.29E-08 0.05%

DETAILED FIRE SCENARIO NS1-L-1J NS1L1K 2.75E-07 1.93E-08 0.08% DETAILED FIRE SCENARIO NS1-L-1K NS1L1L 2.75E-07 1.93E-08 0.08%

DETAILED FIRE SCENARIO NS1-L-1L NS1LlM 1.84E-07 1.29E-08 0.05% DETAILED FIRE SCENARIO NS1-L-lM NS1L1Q 1.80E-07 1.26E-08 0.05% DETAILED FIRE SCENARIO NS1-L-1Q PA1ELC 6.43E-07 7.12E-09 0.03%

DETAILED FIRE SCENARIO PA1E-L-1C PA1ELE 6.43E-07 7.12E-09 0.03% DETAILED FIRE SCENARIO PA1E-L-1E PA1ELF 4.29E-07 4.74E-09 0.02% DETAILED FIRE SCENARIO PA1E-L-1F PA1ELG 1.07E-07 1.17E-09 0.00%

DETAILED FIRE SCENARIO PA1E-L-1G PA1ELH 2.14E-07 2.36E-09 0.01% DETAILED FIRE SCENARIO PA1E-L-1H PA1ELI 2.14E-07 2.36E-09 0.01%

DETAILED FIRE SCENARIO PAIE-L-1I PA1ELM 6.09E-08 6.62E-10 0.00% DETAILED FIRE SCENARIO PA1E-L-1M PA1GDB 2.54E-05 1.47E-11 0.00% DETAILED FIRE SCENARIO PAlGD-L-lB PA1GDH 9.03E-06 1.12E-09 0.00% DETAILED FIRE SCENARIO PA1GD-L-1H PNAP1A 1.14E-04 1.07E-10 0.00%

DETAILED FIRE SCENARIO PNA-P-1A PTlALA 1.44E-04 1.30E-10 0.00% DETAILED FIRE SCENARIO PT1A-L-A PTlAPA 2.22E-05 1.19E-11 0.00% DETAILED FIRE SCENARIO PT1A-P-1A RC1L1 1.46E-02 2.50E-08 0.11%

DETAILED FIRE SCENARIO RC1-L-1 TB1ALA 2.39E-04 4.27E-09 0.02% DETAILED FIRE SCENARIO TBlA-L-1A TG1P1A 1.47E-04 2.61E-09 0.01%

DETAILED FIRE SCENARIO TG1-P-1A 4.71E-06 19.87% INTERNAL FIRES TOTAL CRFL 3.29E-06 1.95E-09 0.01% FLOOD IN CONTROL BLDG HVAC ROOM CVFL 1.50E-04 1.50E-11 0.00% WEST CABLE VAULT FLOOD ISFLA 9.01E-04 3.65E-09 0.02%

INTAKE STRUCTURE FLOOD IN CUBICLE A ISFLB 6.76E-04 2.83E-10 0.00% INTAKE STRUCTURE FLOOD IN CUBICLE B ISFLC 6.76E-04 2.10E-10 0.00% INTAKE STRUCTURE FLOOD IN CUBICLE C ISFLD 1.13E-03 1.57E-10 0.00%

INTAKE STRUCTURE FLOOD IN CUBICLE C PABF1A 3.85E-04 1.45E-08 0.06%

PAB FLOOD AT EL 735 RW TRN A -

ISOLATED PABF1B 3.85E-04 8.90E-09 0.04%

PAB FLOOD AT EL 735 RW TRN B -

ISOLATED PABF2A 2.53E-05 2.83E-07 1.19%

PAB FLOOD AT EL 735 TRN A -

NOT ISOLATED PABF2B 2.53E-05 2.83E-07 1.19%

PAB FLOOD AT EL 735 TRN B -

NOT ISOLATED PABF3A 3.90E-04 1.25E-08 0.05%

PAB FLOOD AT EL 722 TRN A -

EARLY ISOLATION PABF3B 3.90E-04 6.41E-09 0.03%

PAB FLOOD AT EL 722 TRN B -

EARLY

r Attachment A to L-04-141 Page 34 Table 7 Unit 1 - Case 2 Initiating Event CDF Contribution Init. Event I.E.

Core Damage % of Total I.E. Description Frequency Frequency CDF ISOLATION PABF4A 3.32E-05 1.16E-09 0.00% PAB FLOOD AT EL 722 TRN A -

LATE ISOLATION PABF4B 3.32E-05 7.OOE-10 0.00%

PAB FLOOD AT EL 722 TRN B -

LATE ISOLATION PABF5A 1.68E-06 6.44E-11 0.00%

PAB FLOOD AT EL 722 TRN A -

NOT ISOLATED PABF5B 1.68E-06 4.55E-11 0.00%

PAB FLOOD AT EL 722 TRN B -

NOT ISOLATED TBFL 7.71E-03 7.47E-08 0.32% TURBINE BUILDING FLOOD 6.91E-07 2.91% INTERNAL FLOODS TOTAL ELOCA 2.66E-07 2.66E-07 1.12%

EXCESSIVE LOSS OF COOLANT ACCIDENT LLOCAA 2.40E-06 3.55E-09 0.01%

LARGE LOSS OF COOLANT ACCIDENT IN LOOP A LLOCAB 2.40E-06 3.55E-09 0.01% LARGE LOSS OF COOLANT ACCIDENT IN LOOP B LLOCAC 2.40E-06 3.55E-09 0.01%

LARGE LOSS OF COOLANT ACCIDENT IN LOOP C MLOCAA 2.03E-05 4.21E-08 0.18%

MEDIUM LOSS OF COOLANT ACCIDENT IN LOOP A MLOCAB 2.03E-05 4.21E-08 0.18%

MEDIUM LOSS OF COOLANT ACCIDENT IN LOOP B MLOCAC 2.03E-05 4.21E-08 0.18%

MEDIUM LOSS OF COOLANT ACCIDENT IN LOOP C SLOCI 7.26E-04 7.73E-10 0.00% SMALL LOCA, ISOLABLE SLOCN 2.68E-03 1.12E-07 0.47%

SMALL LOCA, NONISOLABLE SGTRA 1.48E-03 4.07E-07 1.72%

STEAM GENERATOR A TUBE RUPTURE SGTRB 1.48E-03 4.07E-07 1.72%

STEAM GENERATOR B TUBE RUPTURE SGTRC 1.48E-03 4.07E-07 1.72%

STEAM GENERATOR C TUBE RUPTURE VSX 1.07E-05 8.07E-08 0.34%

INTERFACING SYSTEMS LOCA (V-SEQUENCE) 1.82E-06 7.67% LOCAS TOTAL AOX 2.04E-02 6.92E-07 2.92%

LOSS OF EMERGENCY AC ORANGE POWER BPX 2.04E-02 4.44E-07 1.87%

LOSS OF EMERGENCY 4160V AC PURPLE DOX 3.38E-02 5.50E-07 2.32%

LOSS OF EMERGENCY 125V DC ORANGE DPX 3.38E-02 8.29E-07 3.50%

LOSS OF EMERGENCY 125V DC PURPLE IBX 6.OOE-03 3.30E-09 0.01%

LOSS OF VITAL BUS III (BLUE)

IRX 6.OOE-03 2.49E-08 0.11% VITAL BUS 1 INITIATING EVENT IWX 6.OOE-03 1.59E-08 0.07% VITAL BUS 2 INITIATING EVENT IYX 6.OOE-03 3.29E-09 0.01%

LOSS OF VITAL BUS IV (YELLOW)

LB1A 3.85E-03 3.70E-08 0.16% LOSS OF NORMAL 4KV BUS 1A LB1D 3.52E-03 2.21E-08 0.09%

LOSS OF NORMAL 4KV BUS 1D LOSP 3.16E-02 3.14E-07 1.33% LOSS OF OFFSITE POWER 2.94E-06 12.38% AC/DC POWER LOSSES TOTAL SEIS1 1.42E-04 4.51E-07 1.90% SEISMIC PGA (0.10 -

0.25 G)

SEIS2 1.70E-05 3.OOE-06 12.65% SEISMIC PGA (0.25 -

0.35 G)

SEIS3 8.36E-06 5.25E-06 22.14% SEISMIC PGA (0.35 -

0.50 G)

SEIS4 2.93E-06 2.93E-06 12.33% SEISMIC PGA (0.50 -

1.00 G)

SEIS5 7.57E-08 7.50E-08 0.32% SEISMIC PGA (1.00 -

1.33 G) 1.17E-05 49.34% EARTHQUAKES TOTAL AMSIV 1.45E-02 3.80E-09 0.02% CLOSURE OF ALL MSIV'S

Attachment A to L-04-141 Page 35 Table 7 Unit 1 - Case 2 Initiating Event CDF Contribution Iit. Event I.E.

Core Damage % of Total I.E. Description Frequency Frequency CDF BVX 1.86E-07 5.27E-09 0.02% LOSS OF EMERGENCY SWITCHGEAR VENTILATION CCX 3.14E-03 1.12E-08 0.05%

LOSS OF REACTOR COMPONENT COOLING WATER CPEXC 1.18E-02 1.97E-09 0.01%

CORE POWER EXCURSION EXFW 1.90E-01 3.35E-08 0.14% EXCESSIVE FEEDWATER FLOW IAX 7.89E-02 7.41E-07 3.12% LOSS OF STATION INSTRUMENT AIR ICX 1.25E-02 4.46E-08 0.19% CNMT INSTRUMENT AIR INITIATING EVENT IMSIV 1.89E-01 9.78E-08 0.41% CLOSURE OF ONE MSIV ISI 9.56E-02 4.90E-08 0.21%

INADVERTANT SAFETY INJECTION INITIATION LCV 1.34E-01 2.34E-08 0.10%

LOSS OF CONDENSER VACUUM LOPF 9.09E-02 1.56E-08 0.07%

LOSS OF PRIMARY FLOW MFWLB 2.62E-03 9.55E-10 0.00% MAIN FEEDWATER LINE BREAK MSV 9.76E-04 4.89E-10 0.00% MAIN STEAM RELIEF OR SAFETY VALVE OPENING PLMFW 5.88E-01 1.05E-07 0.44%

PARTIAL LOSS OF MAIN FEEDWATER RTRIP 8.39E-01 1.50E-07 0.63% REACTOR TRIP SLBC 1.54E-03 8.83E-10 0.00% STEAM LINE BREAK IN COMMON RHS LINE SLBD 4.58E-03 3.23E-09 0.01% STEAM LINE BREAK OUTSIDE CONTAINMENT SLBI 8.49E-04 4.44E-09 0.02%

STEAMLINE BREAK INSIDE CONTAINMENT TLMFW 4.85E-02 1.79E-08 0.08% TOTAL LOSS OF MAIN FEEDWATER -

ATWS TTRIP 7.17E-01 1.32E-07 0.56% TURBINE TRIP WCX 3.80E-06 2.67E-07 1.13%

LOSS OF RIVER WATER HEADERS A & B 1.71E-06 7.20% TRANSIENTS TOTAL

Attachment A to L-04-141 Page 36 Table 8 Unit 1 - Case 2 Sequence Type Contribution Sequence Type Frequency Percentage Seismic Events 1.17E-05 49.34%

Internal Fires 4.71 E-06 19.87%

Loss of Emergency DC Power 1.38E-06 5.82%

Steam Generator Tube Rupture 1.22E-06 5.15%

Loss of Emergency AC Power 1.14E-06 4.79%

Loss of Station Air 7.41 E-07 3.12%

Internal Floods 6.91 E-07 2.91%

Loss of Offsite Power 3.14E-07 1.33%

Loss of River Water 2.67E-07 1.13%

Excessive LOCA 2.66E-07 1.12%

Other Sequence Types 1.93E-07 0.8 1%

Reactor Trip 1.50E-07 0.63%

ATWS 1.48E-07 0.62%

Turbine Trip 1.32E-07 0.56%

Medium LOCA 1.26E-07 0.53%

Non-Isolable Small LOCA 1.12E-07 0.47%

Partial Loss of MFW I.05E-07 0.44%

Interfacing Systems LOCA 8.07E-08 0.34%

Loss Of Normal AC Power 5.91E-08 0.25%

Inadvertent Safety Injection 4.90E-08 0.21%

Loss of Containment Air 4.46E-08 0.19%

Excessive MFW 3.35E-08 0.14%

Loss of Condenser Vacuum 2.34E-08 0.10%

Total Loss of MFW 1.79E-08 0.08%

Large LOCA 1.07E-08 0.04%

Isolable Small LOCA 7.73E-10 0.00%

Attachment A to L-04-141 Page 37 Table 9 Unit 2 - Case 1 Initiating Event CDF Contribution Init. Event I.E.

Core Damage % of Total I.E. Description Frequency Frequency CDF AMSIVA 5.15E-03 7.71E-11 0.00% CLOSURE OF ALL MSIV'S -

ATWS AOXA 1.69E-02 2.08E-09 0.01%

LOSS OF EMERGENCY 4160V AC ORANGE -

ATWS BPXA 1.70E-02 1.20E-09 0.00% LOSS OF EMERGENCY 4160V AC PURPLE -

ATWS CCXA 7.34E-03 1.14E-10 0.00%

LOSS OF PRIMARY COMPONENT COOLING WATER -

ATWS CPEXCA 1.28E-02 2.13E-10 0.00%

CORE POWER EXCURSION -

ATWS DOXA 6.34E-03 6.12E-10 0.00%

LOSS OF EMERGENCY 125V DC ORANGE -

ATWS DPXA 6.31E-03 7.18E-09 0.02%

LOSS OF EMERGENCY 125V DC PURPLE EXFWA 1.04E-01 4.21E-08 0.13% EXCESSIVE FEEDWATER FLOW -

ATWS IAXA 7.76E-02 3.13E-08 0.10%

LOSS OF STATION INSTRUMENT AIR SUPPLY -

ATWS IBXA 6.23E-03 8.14E-09 0.02%

LOSS OF VITAL BUS III (BLUE) -

ATWS ICXA 8.70E-02 1.58E-09 0.00%

LOSS OF CONTAINMENT INSTRUMENT AIR SUPPLY ATWS IMSIVA 4.94E-02 1.93E-08 0.06% CLOSURE OF ONE MSIV -

ATWS IRXA 6.23E-03 7.25E-10 0.00%

LOSS OF VITAL BUS I (RED) -

ATWS ISIA 4.30E-02 1.67E-08 0.05% INADVERTANT SAFETY INJECTION INIT -

ATWS IWXA 6.23E-03 7.07E-10 0.00%

LOSS OF VITAL BUS II (WHITE) -

ATWS IYXA 6.23E-03 6.92E-09 0.02%

LOSS OF VITAL BUS IV (YELLOW) -

ATWS LB2AA 7.70E-03 1.65E-10 0.00%

LOSS OF 4160V BUS 2A -

ATWS LB2DA 6.94E-03 1.65E-10 0.00%

LOSS OF 4160V BUS 2D -

ATWS LCVA 1.58E-02 6.32E-09 0.02%

LOSS OF CONDENSER VACUUM.- ATWS LOSPA 2.31E-02 6.07E-09 0.02%

LOSS OF OFFSITE POWER -

ATWS LPRFA 4.51E-02 8.07E-10 0.00%

LOSS OF PRIMARY FLOW -

ATWS MFWLBA 2.79E-03 1.06E-09 0.00% MAIN FEEDWATER LINE BREAK -

ATWS MSVA 1.03E-03 4.93E-10 0.00% MAIN STEAM RELIEF/SAFETY VALVE OPENS -

ATWS PLMFWA 2.50E-01 1.01E-07 0.31%

PARTIAL LOSS OF MAIN FEEDWATER -

ATWS SGTRAA 1.61E-03 7.66E-10 0.00% A STEAM GENERATOR TUBE RUPTURE -

ATWS SGTRBA 1.61E-03 7.66E-10 0.00% B STEAM GENERATOR TUBE RUPTURE -

ATWS SGTRCA 1.61E-03 7.66E-10 0.00% C STEAM GENERATOR TUBE RUPTURE -

ATWS SLB1A 8.69E-04 4.29E-10 0.00% STEAM LINE BREAK INSIDE CONTAINMENT - ATWS SLBCA 1.62E-03 7.81E-10 0.00%

STEAM LINE BREAK IN COMMON RHS LINE -

ATWS SLBDA 4.90E-03 2.37E-09 0.01%

STEAM LINE BREAK OUTSIDE CONTAINMENT -

ATWS TLMFWA 6.26E-02 2.53E 0.08% TOTAL LOSS OF MAIN FEEDWATER -

ATWS TTRIPA 5.56E-01 1.03E-08 0.03% TURBINE/GENERATOR TRIP -

ATWS 4AX.A 3.21E-03 8.17E-11 0.00%

LOSS OF SERVICE WATER TRAIN A -

ATWS WBXA 2.46E-03 5.93E-11 0.00% LOSS OF SERVICE WATER TRAIN B -

ATWS

Attachment A to L-04-141 Page 38 Table 9 Unit 2 - Case 1 Initiating Event CDF Contribution Init. Event I.E.

Core Damage % of Total I.E. Description Frequency Frequency CDF WCXA 5.31E-08 0.OOE+00 0.00%

LOSS OF BOTH TRAINS A & B SERVICE SWTER -

ATWS 2.97E-07 0.90% ATWS TOTAL ZB1L1G 4.63E-05 2.18E-08 0.07%

FIRE SUB SCENARIO CB1L1G CB1L1H 2.15E-06 3.37E-09 0.01%

FIRE SUB SCENARIO CB1L1H ZB1P1A 2.51E-07 2.51E-07 0.76% FIRE SUB SCENARIO CB1P1A CB2L1A 4.28E-05 3.99E-10 0.00% FIRE SUB SCENARIO CB2L1A CB3L1E 5.99E-05 2.70E-09 0.01% FIRE SUB SCENARIO CB3L1EB ZB3L1F 3.59E-05 1.59E-09 0.00% FIRE SUB SCENARIO CB3L1F CB3L10 6.86E-06 2.64E-07 0.80% FIRE SUB SCENARIO CB3L10 CB3L1P 1.76E-05 6.78E-07 2.06% FIRE SUB SCENARIO CB3L1P CB3L1Q 4.31E-06 1.66E-07 0.50% FIRE SUB SCENARIO CB3L1Q CB3L1S 1.98E-06 1.45E-07 0.44%

FIRE SUB SCENARIO CB3L1S CB3P1A 6.50E-05 9.77E-09 0.03% FIRE SUB SCENARIO CB3P1AE CT1L1A 5.08E-07 5.08E-07 1.54% FIRE SUB SCENARIO CT1L1A CT1L1B 3.05E-07 3.05E-07 0.93% FIRE SUB SCENARIO CT1L1B CT1L1C 9.18E-05 9.99E-08 0.30% FIRE SUB SCENARIO CT1L1C CT1L1D 7.14E-05 4.10E-08 0.12% FIRE SUB SCENARIO CT1L1D CT1P1A 1.54E-07 1.54E-07 0.47% FIRE SUB SCENARIO CT1P1AA CT1P2A 1.54E-07 1.54E-07 0.47% FIRE SUB SCENARIO CT1P2A CV1L1A 1.74E-04 1.07E-09 0.00% FIRE SUB SCENARIO CV1L1A ZVILIB 1.74E-04 1.07E-09

0. 0%

FIRE SUB SCENARIO CV1L1B CV1L1F 5.58E-05 3.03E-10 0.00%

FIRE SUB SCENARIO CV1L1F CV2L1A 1.74E-04 4.80E-10 0.00%

FIRE SUB SCENARIO CV2L1A CV3L1A 1.25E-04 9.32E-0B 0.28% FIRE SUB SCENARIO CV3L1A CV3L1E 1.81E-04 1.35E-07 0.41%

FIRE SUB SCENARIO CV3L1E CV3L1F 1.81E-04 2.23E-07 0.68%

FIRE SUB SCENARIO CV3L1F DG1L1A 1.04E-02 3.68E-07 1.12%

FIRE SUB SCENARIO DG1L1A DG2L1A 1.03E-02 3.64E-07 1.11%

FIRE SUB SCENARIO DG2L1A PA4L1K 1.45E-04 5.28E-09 0.02%

FIRE SUB SCENARIO PA4L1K PA4L1Q 3.63E-05 1.27E-09 0.00%

FIRE SUB SCENARIO PA4L1Q PA6L1A 1.74E-04 1.38E-09 0.00%

FIRE SUB SCENARIO PA6L1A PA6L1C 2.04E-04 1.64E-09 0.00% FIRE SUB SCENARIO PA6L1C SBOP4A 2.49E-07 2.49E-07 0.76% FIRE SUB SCENARIO SB10P4A SB1L1B 2.47E-05 2.40E-08 0.07% FIRE SUB SCENARIO SB1L1B SB1L1D 1.64E-05 1.77E-08 0.05% FIRE SUB SCENARIO SB1L1D SB1L1E 4.66E-05 2.19E-08 0.07% FIRE SUB SCENARIO SB1L1E SB1L1G 2.37E-04 1.13E-07 0.34%

FIRE SUB SCENARIO SB1L1G SB2L1A 7.81E-05 1.04E-08 0.03% FIRE SUB SCENARIO SB2L1A SB2L1B 2.47E-05 1.41E-08 0.04%

FIRE SUB SCENARIO SB2L1B

Attachment A to L-04-141 Page 39 Table 9 Unit 2 - Case I Initiating Event CDF Contribution Init. Event I.E.

Core Damage % of Total I.E. Description Frequency Frequency CDF SB2L1G 2.37E-04 1.21E-07 0.37% FIRE SUB SCENARIO SB2L1G SB4L1A 2.44E-04 6.89E-09 0.02%

FIRE SUB SCENARIO SB4L1A SB4L1B 5.58E-04 1.60E-08 0.05%

FIRE SUB SCENARIO SB4L1B SB4L1C 2.09E-05 5.31E-10 0.00%

FIRE SUB SCENARIO SB4L1C SB4L1D 4.74E-04 1.20E-08 0.04%

FIRE SUB SCENARIO SB4L1D SB4L1E 4.74E-04 1.28E-08 0.04%

FIRE SUB SCENARIO SB4L1E SB4L1F 6.97E-06 1.78E-08 0.05% FIRE SUB SCENARIO SB4L1F SB4L1G 6.97E-06 1.78E-08 0.05%

FIRE SUB SCENARIO SB4L1G SB4L1H 5.17E-06 1.32E-08 0.04%

FIRE SUB SCENARIO SB4L1H SB4L1I 5.17E-06 1.32E-08 0.04%

FIRE SUB SCENARIO SB4L1I SB4L1J 2.44E-04 1.10E-08 0.03%

FIRE SUB SCENARIO SB4L1J SB4L1K 5.18E-06 1.98E-10 0.00%

FIRE SUB SCENARIO SB4L1K SB4L1L 6.04E-06 2.33E-10 0.00% FIRE SUB SCENARIO SB4L1L SB4L1N 6.97E-06 2.71E-10 0.00%

FIRE SUB SCENARIO SB4L1N SGNL1A 2.33E-04 2.14E-09 0.01%

FIRE SUB SCENARIO SGNL1A SGNL1M 3.22E-05 1.05E-09 0.00%

FIRE SUB SCENARIO SGNL1M SGSL1A 2.07E-04 1.13E-08 0.03%

FIRE SUB SCENARIO SGSL1A SGSL1L 3.22E-05 1.09E-09 0.00%

FIRE SUB SCENARIO SGSL1L 4.71E-06 14.30% INTERNAL FIRES TOTAL ABFL1A 6.76E-04 1.20E-08 0.04% AUXILIARY BUILDING FLOOD, SW HDR A ISOLATED ABFL1B 6.76E-04 1.63E-08 0.05% AUXILIARY BUILDING FLOOD, SW HDR B I_

_ISOLATED ABFL2A 2.19E-06 3.62E-11 0.00% AUXILIARY BUILDING FLOOD FROM SW HDR A, NONISOLATED ABFL2B 2.19E-06 4.35E-11 0.00% AUXILIARY BUILDING FLOOD FROM SW HDR B, NONISOLATED CBFL 2.96E-04 4.06E-08 0.12% CONTROL BUILDING FLOOD CVFLA 6.00E-06 2.20E-09 0.01% CABLE VAULT FLOOD FROM SW HDR A CVFLB 6.OOE-06 2.23E-09 0.01%

CABLE VAULT FLOOD FROM SW HDR B CVFLF 1.46E-04 5.30E-08 0.16% CABLE VAULT FLOOD FROM FIRE WATER ISFLB 6.76E-04 5.64E-09 0.02% INTAKE STRUCTURE FLOOD CUBE B ISFLC 6.76E-04 5.95E-09 0.02% INTAKE STRUCTURE FLOOD CUBE C ISFLD 1.13E-03 1.01E-08 0.03% INTAKE STRUCTURE FLOOD CUBE D SGFL1A 3.64E-04 2.51E-07 0.76%

S. SAFEGUARDS TRAIN A AREA FLOOD, ISOLATED SGFL1B 3.64E-04 2.02E-08 0.06% N. SAFEGUARDS TRAIN B AREA FLOOD, ISOLATED SGFL2 4.88E-05 2.30E-07 0.70% BOTH SAFEGUARDS AREA FLOOD, NONISOLATED TBFL 7.58E-03 6.20E-08 0.19% TURBINE BUILDING FLOOD VPFLA 6.76E-04 1.20E-08 0.04% SERVICE WATER VALVE PIT FLOOD, HEADER A VPFLB 6.76E-04 1.63E-08 0.05% SERVICE WATER VALVE PIT FLOOD, HEADER B 7.40E-07 2.25% INTERNAL FLOODS TOTAL

Attachment A to L-04-141 Page 40 Table 9 Unit 2 - Case I Initiating Event CDF Contribution Init. Event I.E.

Corc Damage % of Total I.E. Description Frequency Frequency CDF ELOCA 2.66E-07 2.66E-07 0.81% EXCESSIVE LOSS OF COOLANT ACCIDENT LLOCAA 2.40E-06 1.08E-08 0.03% LARGE LOSS OF COOLANT ACCIDENT IN LOOP A LLOCAB 2.40E-06 1.08E-08 0.03% LARGE LOSS OF COOLANT ACCIDENT IN LOOP B LLOCAC 2.40E-06 1.08E-08 0.03% LARGE LOSS OF COOLANT ACCIDENT IN LOOP C MLOCAA 2.03E-05 4.OOE-08 0.12% MEDIUM LOSS OF COOLANT ACCIDENT IN LOOP A MLOCAB 2.03E-05 4.OOE-08 0.12% MEDIUM LOSS OF COOLANT ACCIDENT IN LOOP B MLOCAC 2.03E-05 4.OOE-08 0.12% MEDIUM LOSS OF COOLANT ACCIDENT IN LOOP C SGTRA 1.61E-03 3.30E-07 1.00% A STEAM GENERATOR TUBE RUPTURE SGTRB 1.61E-03 3.31E-07 1.00% B STEAM GENERATOR TUBE RUPTURE SGTRC 1.61E-03 3.30E-07 1.00% C STEAM GENERATOR TUBE RUPTURE SLOCI 7.87E-04 5.35E-09 0.02%

SMALL LOCA, ISOLABLE SLOCN 2.71E-03 3.36E-07 1.02% SMALL LOCA, NONISOLABLE VSX 2.80E-07 2.80E-07 0.85%

INTERFACING SYSTEMS LOCA (V-SEQUENCE) 2.03E-06 6.17% LOCAS TOTAL AOX 1.69E-02 5.01E-06 15.23% LOSS OF EMERGENCY 4160V AC ORANGE BPX 1.70E-02 4.46E-06 13.54% LOSS OF EMERGENCY 4160V AC PURPLE DOX 6.34E-03 5.28E-07 1.60%

LOSS OF EMERGENCY 125V DC ORANGE DPX 6.31E-03 5.11E-07 1.55%

LOSS OF EMERGENCY 125V DC PURPLE IBX 6.23E-03 5.39E-08 0.16% LOSS OF VITAL BUS III (BLUE)

IRX 6.23E-03 2.95E-08 0.09% LOSS OF VITAL BUS I (RED)

IWX 6.23E-03 2.08E-08 0.06% LOSS OF VITAL BUS II (WHITE)

IYX 6.23E-03 5.40E-08 0.16% LOSS OF VITAL BUS IV (YELLOW)

LB2A 7.70E-03 1.03E-07 0.31%

LOSS OF 4160V BUS 2A LB2D 6.94E-03 7.44E-08 0.23%

LOSS OF 4160V BUS 2D LOSP 2.31E-02 4.02E-07 1.22%

LOSS OF OFFSITE POWER 1.12E-05 34.16% AC/DC POWER LOSSES TOTAL SEIS1 1.42E-04 1.76E-07 0.53% EARTHQUAKES (0.01 -

0.25 G'S)

SEIS2 1.70E-05 1.97E-06 5.98% EARTHQUAKES (0.25 -

0.35 G'S)

SEIS3 8.36E-06 4.43E-06 13.47% EARTHQUAKES (0.35 -

0.50 G'S)

SEIS4 2.93E-06 2.92E-06 8.88% EARTHQUAKES (0.50 -

1.00 G'S)

SEISS 7.57E-08 7.55E-08 0.23% EARTHQUAKES (1.00 -

1.33 G'S) 9.58E-06 29.10% EARTHQUAKES TOTAL AMSIV 5.15E-03 3.47E-09 0.01% CLOSURE OF ALL MSIV'S CCX 7.34E-03 6.39E-08 0.19%

LOSS OF PRIMARY COMPONENT COOLING WATER CPEXC 1.28E-02 9.56E-09 0.03% CORE POWER EXCURSION EXFW 1.04E-01 8.54E-07 2.59% EXCESSIVE FEEDWATER FLOW IAX 7.76E-02 6.38E-07 1.94% LOSS OF STATION INSTRUMENT AIR SUPPLY ICX 8.70E-02 7.50E-07 2.28% LOSS OF CONTAINMENT INSTRUMENT AIR SUPPLY IMSIV 4.94E-02 1.15E-07 0.35% CLOSURE OF ONE MSIV ISI 4.30E-02 7.98E-08 ; 0.24%

INADVERTANT SAFETY INJECTION INITIATION

Attachment A to L-04-141 Page 41 Table 9 Unit 2 - Case 1 Initiating Event CDF Contribution Init. Event I.E.

Core Damage %of Total I.E. Description Frequency Frequency CDF LCV 1.58E-02 1.30E-07 0.40% LOSS OF CONDENSER VACUUM LPRF 4.51E-02 3.44E-08 0.10%

LOSS OF PRIMARY FLOW MFWLB 2.79E-03 2.65E-08 0.08% MAIN FEEDWATER LINE BREAK MSV 1.03E-03 2.60E-09 0.01% MAIN STEAM RELIEF OR SAFETY VALVE OPENING PLMFW 2.50E-01 1.99E-07 0.61%

PARTIAL LOSS OF MAIN FEEDWATER RTRIP 3.64E-01 2.55E-07 0.77% REACTOR TRIP SLB1 8.69E-04 1.90E-08 0.06%

STEAM LINE BREAK INSIDE CONTAINMENT SLBC 1.62E-03 2.28E-08 0.07% STEAM LINE BREAK IN COMMON RHS LINE SLBD 4.90E-03 4.90E-08 0.15% STEAM LINE BREAK OUTSIDE CONTAINMENT TLMFW 6.26E-02 5.18E-07 1.57% TOTAL LOSS OF MAIN FEEDWATER TTRIP 5.56E-01 4.32E-07 1.31% TURBINE/GENERATOR TRIP WAX 3.21E-03 5.64E-08 0.17% LOSS OF SERVICE WATER TRAIN A WBXX 2.46E-03 5.77E-08 0.18% LOSS OF SERVICE WATER TRAIN B WCX 5.31E-08 4.OOE-09 0.01% LOSS OF SERVICE WATER TRAINS A & B 4.32E-06 13.12% TRANSIENTS TOTAL

r Attachment A to L-04-141 Page 42 Table 10 Unit 2 - Case 1 Sequence Type Contribution Sequence Type Frequency Percentage Seismic Events 9.58E-06 29.10%

Loss of Emergency AC Power 9.47E-06 28.76%

Internal Fires 4.71E-06 14.30%

Loss of Emergency DC Power 1.04E-06 3.16%

Steam Generator Tube Rupture 9.90E-07 3.0 1%

Excessive MFW 8.54E-07 2.59%

Loss of Containment Air 7.50E-07 2.28%

Internal Floods 7.40E-07 2.25%

Loss of Station Air 6.38E-07 1.94%

Total Loss of MFW 5.18E-07 1.57%

Other Sequence Types 5.04E-07 1.53%

Turbine Trip 4.32E-07 1.31%

Loss of Offsite Power 4.02E-07 1.22%

Non-Isolable Small LOCA 3.36E-07 1.02%

ATWS 2.97E-07 0.90%

Interfacing Systems LOCA 2.80E-07 0.85%

Excessive LOCA 2.66E-07 0.81%

Reactor Trip 2.55E-07 0.77%

Partial Loss of MFWV 1.99E-07 0.61%

Loss Of Normal AC Power 1.77E-07 0.54%

Loss of Condenser Vacuum 1.30E-07 0.40%

Medium LOCA 1.20E-07 0.36%

Loss of Service Water 1.18E-07 0.36%

Inadvertent Safety Injection 7.98E-08 0.24%

Large LOCA 3.24E-08 0.10%

Isolable Small LOCA 5.35E-09 0.02%

Attachment A to L-04-141 Page 43 Table 11 Unit 2 - Case 2 Initiating Event CDF Contribution Init. Event I.E.

Core Damage % of Total I.E. Description Frequency Frequency CDF AMSIVA 5.15E-03 7.71E-11 0.00% CLOSURE OF ALL MSIV'S -

ATWS AOXA 1.69E-02 2.08E-09 0.01% LOSS OF EMERGENCY 4160V AC ORANGE -

ATWS BPXA 1.70E-02 1.21E-09 0.00% LOSS OF EMERGENCY 4160V AC PURPLE -

ATWS CCXA 7.34E-03 1.14E-10 0.00% LOSS OF PRIMARY COMPONENT COOLING WATER -

ATWS CPEXCA 1.28E-02 2.13E-10 0.00% CORE POWER EXCURSION -

ATWS DOXA 6.34E-03 6.11E-10 0.00% LOSS OF EMERGENCY 125V DC ORANGE -

ATWS DPXA 6.31E-03 7.18E-09 0.02% LOSS OF EMERGENCY 125V DC PURPLE EXFWA 1.04E-01 4.21E-08 0.12% EXCESSIVE FEEDWATER FLOW -

ATWS IAXA 7.76E-02 3.14E-08 0.09% LOSS OF STATION INSTRUMENT AIR SUPPLY -

ATWS IBXA 6.23E-03 8.14E-09 0.02% LOSS OF VITAL BUS III (BLUE) -

ATWS ICXA 8.70E-02 1.58E-09 0.00% LOSS OF CONTAINMENT INSTRUMENT AIR SUPPLY ATWS IMSIVA 4.94E-02 1.93E-08 0.06% CLOSURE OF ONE MSIV -

ATWS IRXA 6.23E-03 7.26E-10 0.00% LOSS OF VITAL BUS I (RED) -

ATWS ISIA 4.30E-02 1.67E-08 0.05%

INADVERTANT SAFETY INJECTION INIT -

ATWS IWXA 6.23E-03 7.08E-10 0.00% LOSS OF VITAL BUS II (WHITE) -

ATWS IYXA 6.23E-03 6.92E-09 0.02% LOSS OF VITAL BUS IV (YELLOW) -

ATWS LB2AA 7.70E-03 1.74E-10 0.00% LOSS OF 4160V BUS 2A -

ATWS LB2DA 6.94E-03 1.68E-10 0.00%

LOSS OF 4160V BUS 2D -

ATWS LCVA 1.58E-02 6.32E-09 0.02% LOSS OF CONDENSER VACUUM -

ATWS LOSPA 2.31E-02 6.17E-09 0.02%

LOSS OF OFFSITE POWER -

ATWS LPRFA 4.51E-02 8.06E-10 0.00% LOSS OF PRIMARY FLOW -

ATWS MFWLBA 2.79E-03 1.06E-09 0.00% MAIN FEEDWATER LINE BREAK -

ATWS MSVA 1.03E-03 4.92E-10 0.00% MAIN STEAM RELIEF/SAFETY VALVE OPENS -

ATWS PLMFWA 2.50E-01 1.01E-07 0.29%

PARTIAL LOSS OF MAIN FEEDWATER -

ATWS SGTRAA 1.61E-03 7.65E-10 0.00% A STEAM GENERATOR TUBE RUPTURE -

ATWS SGTRBA 1.61E-03 7.65E-10 0.00% B STEAM GENERATOR TUBE RUPTURE -

ATWS SGTRCA 1.61E-03 7.65E-10 0.00% C STEAM GENERATOR TUBE RUPTURE -

ATWS SLB1A 8.69E-04 4.28E-10 0.00%

STEAM LINE BREAK INSIDE CONTAINMENT -

ATWS SLBCA 1.62E-03 7.81E-10 0.00%

STEAM LINE BREAK IN COMMON RHS LINE -

ATWS SLBDA 4.90E-03 2.37E-09 0.01%

STEAM LINE BREAK OUTSIDE CONTAINMENT -

_ _ _ A T W S TLMFWA 6.26E-02 2.53E-08 0.07% TOTAL LOSS OF MAIN FEEDWATER -

ATWS TTRIPA 5.56E-01 1.03E-08 0.03% TURBINE/GENERATOR TRIP -

ATWS WAXA 3.21E-03 8.17E-11 0.00%

LOSS OF SERVICE WATER TRAIN A -

ATWS WBXA 2.46E-03 5.93E-11 0.00%

LOSS OF SERVICE WATER TRAIN B -

ATWS

Attachment A to L-04-141 Page 44 Table 11 Unit 2 - Case 2 Initiating Event CDF Contribution Init. Event I.E.

Core Damage % of Total I.E. Description Frequency Frequency CDF WCXA 5.31E-08 0.OOE+00 0.00%

LOSS OF BOTH TRAINS A & B SERVICE SWTER -

ATWS 2.97E-07 0.86% ATWS TOTAL CBlLlG 4.63E-05 2.58E-08 0.07% FIRE SUB SCENARIO CBlLlG CBlLlH 2.15E-06 3.54E-09 0.01% FIRE SUB SCENARIO CBlLlH CBlPlA 2.51E-07 2.51E-07 0.73% FIRE SUB SCENARIO CBlPlA CB2L1A 4.28E-05 4.46E-10 0.00% FIRE SUB SCENARIO CB2L1A CB3L1E 5.99E-05 2.75E-09 0.01%

FIRE SUB SCENARIO CB3L1EB CB3L1F 3.59E-05 1.62E-09 0.00%

FIRE SUB SCENARIO CB3L1F CB3L1O 6.86E-06 2.64E-07 0.77% FIRE SUB SCENARIO CB3L1O CB3L1P 1.76E-05 6.78E-07 1.97% FIRE SUB SCENARIO CB3L1P CB3LlQ 4.31E-06 1.66E-07 0.48% FIRE SUB SCENARIO CB3L1Q CB3L1S 1.98E-06 1.45E-07 0.42% FIRE SUB SCENARIO CB3LlS CB3P1A 6.50E-05 1.13E-08 0.03% FIRE SUB SCENARIO CB3P1AE CTlLlA 5.08E-07 5.08E-07 1.48%

FIRE SUB SCENARIO CT1L1A CTlLlB 3.05E-07 3.05E-07 0.89%

FIRE SUB SCENARIO CTlLlB ZTlLlC 9.18E-05 1.08E-07 0.31% FIRE SUB SCENARIO CT1L1C CTlLlD 7.14E-05 4.79E-08 0.14% FIRE SUB SCENARIO CT1L1D CTlPlA 1.54E-07 1.54E-07 0.45%

FIRE SUB SCENARIO CT1P1AA CT1P2A 1.54E-07 1.54E-07 0.45% FIRE SUB SCENARIO CT1P2A CVlLlA 1.74E-04 1.31E-09 0.00% FIRE SUB SCENARIO CVlLlA CV1L1B 1.74E-04 1.31E-09 0.00% FIRE SUB SCENARIO CV1L1B CV1L1F 5.58E-05 3.76E-10 0.00%

FIRE SUB SCENARIO CVlLlF CV2L1A 1.74E-04 6.44E-10 0.00%

FIRE SUB SCENARIO CV2L1A CV3L1A 1.25E-04 1.05E-07 0.31% FIRE SUB SCENARIO CV3L1A CV3L1E 1.81E-04 1.52E-07 0.44% FIRE SUB SCENARIO CV3L1E CV3L1F 1.81E-04 2.40E-07 0.70%

FIRE SUB SCENARIO CV3L1F DGlLlA 1.04E-02 4.91E-07 1.43% FIRE SUB SCENARIO DGlLlA DG2L1A 1.03E-02 4.87E-07 1.42% FIRE SUB SCENARIO DG2L1A PA4L1K 1.45E-04 7.03E-09 0.02%

FIRE SUB SCENARIO PA4L1K PA4L1Q 3.63E-05 1.69E-09 0.00%

FIRE SUB SCENARIO PA4L1Q PA6L1A 1.74E-04 1.62E-09 0.00% FIRE SUB SCENARIO PA6L1A PA6L1C 2.04E-04 1.93E-09 0.01% FIRE SUB SCENARIO PA6L1C SBOP4A 2.49E-07 2.49E-07 0.72%

FIRE SUB SCENARIO SB10P4A SB1L1B 2.47E-05 2.61E-08 0.08% FIRE SUB SCENARIO SB1L1B SB1L1D 1.64E-05 1.91E-08 0.06%

FIRE SUB SCENARIO SB1L1D SBlLlE 4.66E-05 2.59E-08 0.08% FIRE SUB SCENARIO SBlLlE SB1L1G 2.37E-04 1.33E-07 0.39%

FIRE SUB SCENARIO SB1L1G SB2L1A 7.81E-05 1.21E-08 0.04%

FIRE SUB SCENARIO SB2L1A SB2L1B 2.47E-05 1.65E-08 0.05%

FIRE SUB SCENARIO SB2L1B

Attachment A to L-04-141 Page 45 Table 11 Unit 2 - Case 2 Initiating Event CDF Contribution

[nit. Event I.E.

Core Damage % of Total I.E. Dcscription Frequency Frequency CDF SB2L1G 2.37E-04 1.44E-07 0.42% FIRE SUB SCENARIO SB2L1G SB4L1A 2.44E-04 9.06E-09 0.03% FIRE SUB SCENARIO SB4L1A SB4L1B 5.58E-04 2.10E-08 0.06% FIRE SUB SCENARIO SB4L1B SB4L1C 2.09E-05 7.09E-10 0.00% FIRE SUB SCENARIO SB4L1C SB4L1D 4.74E-04 1.56E-08 0.05% FIRE SUB SCENARIO SB4L1D SB4L1E 4.74E-04 1.75E-08 0.05% FIRE SUB SCENARIO SB4L1E SB4L1F 6.97E-06 2.43E-08 0.07% FIRE SUB SCENARIO SB4L1F SB4L1G 6.97E-06 2.43E-08 0.07% FIRE SUB SCENARIO SB4L1G SB4L1H 5.17E-06 1.80E-08 0.05% FIRE SUB SCENARIO SB4L1H SB4L1I 5.17E-06 1.80E-08 0.05% FIRE SUB SCENARIO SB4L1I SB4L1J 2.44E-04 1.51E-08 0.04% FIRE SUB SCENARIO SB4L1J SB4L1K 5.18E-06 2.76E-10 0.00% FIRE SUB SCENARIO SB4L1K SB4L1L 6.04E-06 3.25E-10 0.00% FIRE SUB SCENARIO SB4L1L SB4L1N 6.97E-06 3.78E-10 0.00% FIRE SUB SCENARIO SB4L1N SGNL1A 2.33E-04 2.76E-09 0.01% FIRE SUB SCENARIO SGNL1A SGNL1M 3.22E-05 1.43E-09 0.00% FIRE SUB SCENARIO SGNL1M SGSL1A 2.07E-04 1.36E-08 0.04% FIRE SUB SCENARIO SGSL1A SGSL1L 3.22E-05 1.47E-09 0.00% FIRE SUB SCENARIO SGSL1L 5.13E-06 14.91% INTERNAL FIRES TOTAL ABFL1A 6.76E-04 1.39E-08 0.04% AUXILIARY BUILDING FLOOD, SW HDR A ISOLATED ABFL1B 6.76E-04 1.93E-08 0.06% AUXILIARY BUILDING FLOOD, SW HDR B ISOLATED ABFL2A 2.19E-06 4.01E-11 0.00% AUXILIARY BUILDING FLOOD FROM SW HDR A, NONISOLATED ABFL2B 2.19E-06 5.01E-11 0.00% AUXILIARY BUILDING FLOOD FROM SW HDR B, NONISOLATED CBFL 2.96E-04 4.06E-08 0.12% CONTROL BUILDING FLOOD CVFLA 6.OOE-06 2.21E-09 0.01% CABLE VAULT FLOOD FROM SW HDR A CVFLB 6.OOE-06 2.25E-09 0.01% CABLE VAULT FLOOD FROM SW HDR B CVFLF 1.46E-04 5.29E-08 0.15% CABLE VAULT FLOOD FROM FIRE WATER ISFLB 6.76E-04 5.71E-09 0.02% INTAKE STRUCTURE FLOOD CUBE B ISFLC 6.76E-04 6.07E-09 0.02% INTAKE STRUCTURE FLOOD CUBE C ISFLD 1.13E-03 1.03E-08 0.03% INTAKE STRUCTURE FLOOD CUBE D SGFL1A 3.64E-04 2.56E-07 0.75% S. SAFEGUARDS TRAIN A AREA FLOOD, ISOLATED SGFL1B 3.64E-04 2.03E-08 0.06% N.

SAFEGUARDS TRAIN B AREA FLOOD, ISOLATED SGFL2 4.88E-05 2.30E-07 0.67% BOTH SAFEGUARDS AREA FLOOD, NONISOLATED TBFL 7.58E-03 6.22E-08 0.18% TURBINE BUILDING FLOOD VPFLA 6.76E-04 1.39E-08 0.04% SERVICE WATER VALVE PIT FLOOD, HEADER A VPFLB 6.76E-04 1.93E-08 0.06% SERVICE WATER VALVE PIT FLOOD, HEADER B 7.55E-07 2.20% INTERNAL FLOODS TOTAL

Attachment A to L-04-141 Page 46 Table 11 Unit 2 - Case 2 Initiating Event CDF Contribution Init. Event I.E.

Core Damagc % of Total I.E. Description Frequency Frequency CDF ELOCA 2.66E-07 2.66E-07 0.77%

EXCESSIVE LOSS OF COOLANT ACCIDENT LLOCAA 2.40E-06 1.08E-08 0.03% LARGE LOSS OF COOLANT ACCIDENT IN LOOP A LLOCAB 2.40E-06 1.08E-08 0.03% LARGE LOSS OF COOLANT ACCIDENT IN LOOP B LLOCAC 2.40E-06 1.08E-08 0.03% LARGE LOSS OF COOLANT ACCIDENT IN LOOP C MLOCAA 2.03E-05 4.02E-08 0.12% MEDIUM LOSS OF COOLANT ACCIDENT IN LOOP A MLOCAB 2.03E-05 4.02E-08 0.12% MEDIUM LOSS OF COOLANT ACCIDENT IN LOOP B MLOCAC 2.03E-05 4.02E-08 0.12% MEDIUM LOSS OF COOLANT ACCIDENT IN LOOP C SGTRA 1.61E-03 3.30E-07 0.96% A STEAM GENERATOR TUBE RUPTURE SGTRB 1.61E-03 3.31E-07 0.96%

B STEAM GENERATOR TUBE RUPTURE SGTRC 1.61E-03 3.30E-07 0.96% C STEAM GENERATOR TUBE RUPTURE SLOCI 7.87E-04 5.46E-09 0.02%

SMALL LOCA, ISOLABLE SLOCN 2.71E-03 3.36E-07 0.98% SMALL LOCA, NONISOLABLE VSX 2.80E-07 2.80E-07 0.81% INTERFACING SYSTEMS LOCA (V-SEQUENCE) 2.03E-06 5.91% LOCAS TOTAL AOX 1.69E-02 5.38E-06 15.65% LOSS OF EMERGENCY 4160V AC ORANGE BPX 1.70E-02 4.87E-06 14.17% LOSS OF EMERGENCY 4160V AC PURPLE DOX 6.34E-03 5.59E-07 1.63%

LOSS OF EMERGENCY 125V DC ORANGE DPX 6.31E-03 5.44E-07 1.58%

LOSS OF EMERGENCY 125V DC PURPLE IBX 6.23E-03 5.41E-08 0.16% LOSS OF VITAL BUS III (BLUE)

IRX 6.23E-03 2.97E-08 0.09% LOSS OF VITAL BUS I (RED)

IWX 6.23E-03 2.09E-08 0.06% LOSS OF VITAL BUS II (WHITE)

IYX 6.23E-03 5.41E-08 0.16% LOSS OF VITAL BUS IV (YELLOW)

LB2A 7.70E-03 1.27E-07 0.37%

LOSS OF 4160V BUS 2A LB2D 6.94E-03 1.OOE-07 0.29%

LOSS OF 4160V BUS 2D LOSP 2.31E-02 4.47E-07 1.30% LOSS OF OFFSITE POWER 1.22E-05 35.46% AC/DC POWER LOSSES TOTAL SEISI 1.42E-04 1.87E-07 0.54% EARTHQUAKES (0.01 -

0.25 G'S)

SEIS2 1.70E-05 1.98E-06 5.75% EARTHQUAKES (0.25 -

0.35 G'S)

SEIS3 8.36E-06 4.44E-06 12.90% EARTHQUAKES (0.35 -

0.50 G'S)

SEIS4 2.93E-06 2.92E-06 8.50% EARTHQUAKES (0.50 -

1.00 G'S)

SEIS5 7.57E-08 7.54E-08 0.22% EARTHQUAKES (1.00 -

1.33 G'S) 9.60E-06 27.92% EARTHQUAKES TOTAL AMSIV 5.15E-03 3.57E-09 0.01%

CLOSURE OF ALL MSIV'S CCX 7.34E-03 6.41E-08 0.19% LOSS OF PRIMARY COMPONENT COOLING WATER CPEXC 1.28E-02 9.82E-09 0.03% CORE POWER EXCURSION EXFW 1.04E-01 8.56E-07 2.49% EXCESSIVE FEEDWATER FLOW IAX 7.76E-02 6.40E-07 1.86% LOSS OF STATION INSTRUMENT AIR SUPPLY ICX 8.70E-02 7.53E-07 2.19% LOSS OF CONTAINMENT INSTRUMENT AIR SUPPLY IMSIV 4.94E-02 1.17E-07 0.34%

CLOSURE OF ONE MSIV ISI 4.30E-02 8.15E-08 0.24%

INADVERTANT SAFETY INJECTION INITIATION

I Attachment A to L-04-141 Page 47 Table 11 Unit 2 - Case 2 Initiating Event CDF Contribution Init. Event I.E.

Core Damage % of Total I.E. Description Frequency Frequency CDF LCV 1.58E-02 1.31E-07 0.38% LOSS OF CONDENSER VACUUM LPRF 4.51E-02 3.54E-08 0.10%

LOSS OF PRIMARY FLOW MFWLB 2.79E-03 2.66E-08 0.08% MAIN FEEDWATER LINE BREAK MSV 1.03E-03 2.63E-09 0.01% MAIN STEAM RELIEF OR SAFETY VALVE OPENING PLMFW 2.50E-01 2.05E-07 0.60% PARTIAL LOSS OF MAIN FEEDWATER RTRIP 3.64E-01 2.62E-07 0.76% REACTOR TRIP SLB1 8.69E-04 1.90E-08 0.06% STEAM LINE BREAK INSIDE CONTAINMENT SLBC 1.62E-03 2.29E-08 0.07%

STEAM LINE BREAK IN COMMON RHS LINE SLBD 4.90E-03 4.92E-08 0.14%

STEAM LINE BREAK OUTSIDE CONTAINMENT TLMFW 6.26E-02 5.19E-07 1.51% TOTAL LOSS OF MAIN FEEDWATER TTRIP 5.56E-01 4.44E-07 1.29% TURBINE/GENERATOR TRIP WAX 3.21E-03 6.55E-08 0.19% LOSS OF SERVICE WATER TRAIN A WBXX 2.46E-03 6.86E-08 0.20%

LOSS OF SERVICE WATER TRAIN B WCX 5.31E-08 4.OOE-09 0.01%

LOSS OF SERVICE WATER TRAINS A & B 4.38E-06 12.74% TRANSIENTS TOTAL

Attachment A to L-04-141 Page 48 Table 12 Unit 2 - Case 2 Sequence Type Contribution Sequence Type Frequency Percentage Loss of Emergency AC Power 1.03E-05 29.82%

Seismic Events 9.60E-06 27.92%

Internal Fires 5.13E-06 14.91%

Loss of Emergency DC Power 1.IOE-06 3.21%

Steam Generator Tube Rupture 9.90E-07 2.88%

Excessive MFW 8.56E-07 2.49%

Internal Floods 7.55E-07 2.20%

Loss of Containment Air 7.53E-07 2.19%

Loss of Station Air 6.40E-07 1.86%

Total Loss of MFW 5.19E-07 1.51%

Other Sequence Types 5.09E-07 1.48%

Loss of Offsite Power 4.47E-07 1.30%

Turbine Trip 4.44E-07 1.29%

Non-Isolable Small LOCA 3.36E-07 0.98%

ATWVS 2.97E-07 0.86%

Interfacing Systems LOCA 2.80E-07 0.81%

Excessive LOCA 2.66E-07 0.77%

Reactor Trip 2.62E-07 0.76%

Loss Of Normal AC Power 2.27E-07 0.66%

Partial Loss of MFW 2.05E-07 0.60%

Loss of Service Water 1.38E-07 0.40%

Loss of Condenser Vacuum 1.31 E-07 0.38%

Medium LOCA 1.21E-07 0.35%

Inadvertent Safety Injection 8.15E-08 0.24%

Large LOCA 3.25E-08 0.09%

Isolable Small LOCA 5.46E-09 0.02%

Attachment A to L-04-141 Page 49

9. Commitment # 3 in Attachment C to the May 26, 2004 application states: "If an EDG is unavailable, an EDG on the opposite unit will be removed from service only for corrective maintenance.... " Under the proposed 14-day AOT, it would appear that one EDG from one unit could be out-of-service for PM and one EDG from the other unit could be out-of-service for CM for almost the full 14 days. The risk assessment for this scenario was not included in the submittal. Please provide a risk assessment for the case where one EDG from one unit is in PM and one from the other unit is in CM at the same time or provide justification to prevent such an occurrence. (RG 1.174, Section 2.2.2; RG 1.177 Section 2.3)

Response

The current On-Line Work Management and Risk Assessment procedure (1/2-ADM-0804) states that:

Only one of the four emergency diesel generators at both Unit I and Unit 2 will be intentionally removed from service at the same time. This is not applicable when BOTH Unit 1 and Unit 2 are in shutdown modes. The performance of Diesel Surveillance Testing is exempted from this requirement.

Therefore, it is not expected that a condition would arise where one EDG from one unit is in preventative maintenance and one from the other unit is in corrective maintenance at the same time, especially for the full 14-days. However, if this condition did exist the conscientious site practice would be to work the EDG that is in corrective maintenance around the clock until it is repaired. If the repair time was estimated to take longer than the time to restore the EDG that is in preventative maintenance, then the focus would be to work around the clock to restore the EDG in PM.

Although, this alignment would not be intentionally scheduled, the on-line risk configuration program (Safety Monitor) evaluated the risk associated with taking one EDG out-of-service at each unit concurrently, and assuming that all other equipment was available. The risk increase associated with this alignment remained within the GREEN threshold values (i.e.,

less than two times the no maintenance CDF) at both units.

10. The LAR says that Table 5 was developed using Cases 3, 4, 5 and 6. If Case 5 is compared to Case 1, the incremental conditional core damage probability (ICCDP) over 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months would appear to be 4.3E-7 (BVPS-1) and 2.7E-6 (BVPS-2) compared to 4.75E-8 and 4.93E-7, respectively, shown in Table 5. Please explain how Table 5 was developed. (RG 1.174, Section 2.2.2; RG 1.177 Section 2.3)

Response

LAR Table 5 provided the evaluation of the ICCDP and ICLERP results, while an EDG is unavailable for corrective maintenance during the extended AOT. The evaluation was developed based on various corrective maintenance configurations, while crediting the restrictions in Technical Specification 3.8.1.1 action statements b and c for maximum

Attachment A to L-04-141 Page 50 allowable time for demonstrating absence of common cause failures and allowable time limit of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for a condition in which both the offsite power source and an EDG are inoperable. These configurations model Technical Specification 3.8.1.1 actions b and c, and account for the fraction of time that each condition is expected. Strictly calculating the ICCDP using Case 5 and comparing it to Case I does not account for the fraction of the year that the offsite power circuit fails. That is to say, that it will assume that every time the EDG is unavailable, an offsite power circuit is also unavailable. Because the LAR submittal is strictly for an EDG AOT extension, the increase in conditional probabilities should be solely based on the guaranteed failure of a single EDG, and not the guaranteed failure of both an EDG and one offsite power circuit.

Tech Spec 3.8.1.1 Action b (one EDG inoperable with offsite power circuits operable)

T = 0 One EDG becomes inoperable (Case 4)

T = 1 hr Other sources are verified operable by SR 4.8.1.11.La verifying breakers (No impact)

T = 24 hr Common Cause failure potential is eliminated from other EDG based on SR 4.8.1.1.2.a.5 (Same risk impact as Case 3, since one EDG is inoperable and common cause failures on the other EDG eliminated)

T = AOT duration EDG is restored operable

Tech Spec 3.8.1.1 Action c (one EDG and one offsite circuit inoperable)

T = 0 One EDG becomes inoperable and I offsite power circuit becomes inoperable (Case 5)

T = 1 hr Other sources are verified operable by SR 4.8.1.1.l.a verifying breakers (No impact)

T = 8 hr Common Cause failure potential is eliminated from other EDG based on SR 4.8.1.1.2.a.5 (Case 6)

T = 12 hr Restore offsite power circuit (Same risk impact as Case 3)

T = AOT duration EDG is restored operable.

The total conditional core damage probability then is the CCDP while in action b times the probability that the offsite power circuits are available (i.e., 1-split faction NAI) plus the CCDP while in action c times the probability that an offsite power circuit is unavailable (i.e.,

split faction NAI). For Unit I the split faction value for NAI= 3.51E-03 and Unit 2'sNAI=

4.72E-03.

CCDPAOT = ((Case 4

24 hr) + (Case 3 * (AOT duration - 24 hr)))/8760 * (I-NAl)

+ ((Case 5* 8 hr) + (Case 6

4 hr) + (Case 3 * (AOT duration - 12 hr)))/8760

NAI

Attachment A to L-04-141 Page 51 ForUnit 1:

CCDPAOT = ((2.63E-05

24) + (2.45E-05

312)) / 8760 * (1-3.51E-03) + ((3.37E-04

8) + (3.24E-04

4) + (2.45E-05

324)) / 8760

3.51E-03 CCDPAOT = 9.45E-07 The base core damage probability is the base case CDF times the AOT duration.

CDPbase = (Case 1

AOT duration)/8760 CDPbase = (2.34E-05

336) / 8760 CDPbase = 8.98E-07 ICCDP = CCDPAOT - CDPbase ICCDP = 4.75E-08 For Unit 2:

CCDPAOT= ((7.60E-05

24) + (4.29E-05

312) / 8760 * (1-4.72E-03) + ((2.01E-03

8) + (1.67E-03

4) + (4.29E-05

324)) / 8760

4.72E-03 CCDPAOT = 1.75E-06 The base core damage probability is the base case CDF times the AOT duration.

CDPbase= (Case 1

AOT duration)/8760 CDPbase = (3.27E-05

336) / 8760 CDPbase = 1.26E-06 ICCDP = CCDPAOT - CDPbase ICCDP = 4.93E-07 Similarly the conditional large early release probability (CLERP) is derived using the same approach. It should be noted that at Unit 2, since there is a reduction in LERF associated with one EDG being unavailable (LAR Table I Case 3 compared to Case 1) the incremental CLERP is risk neutral.

Attachment A to L-04-141 Page 52

11. Please explain the following with respect to the risk assessment: (RG 1.174, Section 2.2.2; RG 1.177 Section 2.3)

a. Why is BVPS-2 core damage frequency (CDF) so much more sensitive to EDG dependability than BVPS-1? Example 1: Table 2 shows delta CDF for BVPS-2 is 1.24 E-6 greater than BVPS-l delta CDF, even though the increase in EDG unavailability is smaller for BVPS-2. Example 2: Table I indicates a greater percent increase in BVPS-2 CDF than BVPS-1 for Cases 2 through 6.

Response

At Unit 1, almost half of the core damage frequency is associated with seismic events, which are largely unaffected by EDG unavailability. This is either due to direct seismic failures of the emergency AC busses, or indirect seismic failures of the EDG support systems. Examples of support system failures include the seismic failure of offsite power coincident with the seismic failure of 125V DC power or the river/service water system, either directly or through the collapse of the Auxiliary Building housing river/service piping. These seismic failures result in the guaranteed failure of the emergency AC busses and are assumed to be non-recoverable. Therefore, the unavailability of an EDG does not contribute to approximately 50% of the Unit I CDF.

Additionally, another 11% of the CDF is attributed to the failure of the emergency switchgear ventilation following a fire in the cable spreading room, CS-1 (see description for Unit 1, Case 2, Sequence 1 in response to RAI question 8). These sequences also remain essentially unaffected by the increased EDG AOT, since the PRA model assumes that all AC power is failed and non-recoverable due to the loss of emergency switchgear ventilation. Therefore, only about 39% of the CDF at Unit I can be impacted by EDG unavailability.

At Unit 2, only about 30% of the core damage frequency is associated with seismic events, so there are not as many guaranteed failures of the emergency AC busses.

Therefore, the probabilistic failure of an EDG, which increases with AOT unavailability, can impact more core damage sequences. Consequently, almost 70% of the Unit 2 CDF can be impacted by EDG unavailability. As a result of these differences, the CDF at Unit 2 is much more sensitive to EDG unavailability than Unit 1.

b. Why is BVPS-2 large early release frequency (LERF) less sensitive to EDG dependability than BVPS-1? Example: The percent increase in LERF for Cases 5 and 6 is much smaller for BVPS-2 than for BVPS-1?

Response

At Unit 1, the PRA model assumes that interfacing systems LOCA events can be mitigated, given that a HHSI pump can provide continued RCS inventory makeup via the RWST. These interfacing systems LOCAs dominate the LERF at Unit I for Cases 5 and

Attachment A to L-04-141 Page 53 6 (greater than 98% contribution to LERF) due to the probability of failing to makeup to the RWST, given that one offsite circuit and emergency AC orange power has failed.

Without continued RCS makeup, the interfacing systems LOCA can not be mitigated and the conditional LERP increases from about 7E-03 to essentially 1.0, resulting in an increase in the LERF by about.OE-05.

At Unit 2, the PRA models did not credit any mitigating actions to reduce the interfacing systems LOCA since the initiating event frequency was almost 2 orders of magnitude lower than Unit I's (1.07E-05 at Unit I vs. 2.80E-07 at Unit 2), due to system arrangements. As a result, the interfacing systems LOCA conditional LERP remains constant at 1.0, and the LERF contribution remains essentially the same as the initiating event frequency for all Cases analyzed.

Therefore, the impact to LERF at Unit I is much more sensitive to the EDG dependency than Unit 2, due to the interfacing systems LOCA conditional LERP.

c. Why is BVPS-2 LERF for Cases 3 and 4 less than Case 1, even though the respective CDF values are greater than Case I?

Response

A large portion of the LERF at Unit 2 is attributed to Steam Generator Tube Rupture (SGTR) events with failure of the steam lines to isolate (top event SL) and failure to makeup to the RWST (top event WM). The supporting AC power systems for top event WM are the normal 4KV busses. In the Case 3 and 4 analyses, it is known that only the EDG is unavailable and the offsite circuit supplies to the EDGs are available (unavailability of an offsite circuit supply to an EDG is analyzed in Cases 5 and 6).

Given this knowledge, the failure probability of the normal 4KV busses is lower in Cases 3 and 4, than was analyzed in Case 1, where there was some maintenance unavailability associated with the busses. The impact of the reduction in the normal 4KV bus failure probability can be seen in Table 13, with the following LERF sequences for Case 1 and 3 (with Case 4 similar to Case 3).

Attachment A to L-04-141 Page 54 Table 13 Unit 2 SGTR LERF Sequences Case 1 Initiator Frequency Failed and Multi-State Split Fractions SGTRA 1.5903E-08 ZXF*NA1*ND3*SLlA*WMF*NRF*NMF*REF*SSF*CG1 SGTRB 1.5903E-08 ZXF*NA1*ND3*SLIB*WMF*NRF*NMF*REF*SSF*CG1 SGTRC 1.5903E-08 ZXF*NA1*ND3*SL1C*WMF*NRF*NMF* REF*SSF*CG1 4.7709E-08 Case 3 Initiator Frequency Failed and Multi-State Split Fractions SGTRA 4.7214E-10 ZXF*NA1*ND3*AO2*Ml1FM3F*WAF*SL2A*WMF*NRF*NMF*RlF*RCF*RE5A*SSF*CG1 SGTRB 3.9683E-10 ZXF*NA1*ND3*AO2*MlF*M3F*WAF*SL2B*WMF*NRF*NMF*RlF*RCF*RE5A*SSFPCG1 SGTRC 3.9698E-10 ZXF*NA1*ND3*AO2*MIF*M3F*WAF*SL2C*WMF*NRF*NMF*RlF*RCF*RE5A*SSF*CG1 L 1.2660E-09 As can be seen in Case 1, the failure of both of the normal 4KV busses 2A (split fraction NAI) and 2D (split fraction ND3) lead to the guaranteed failure of RWST makeup (Split fraction WMF). Since the EDGs are successful in powering the emergency AC busses, as shown by the lack of any AO or BP split fractions, electric power recovery by replacing fast bus transfer breakers is not credited (split fraction REF). With the emergency AC busses available, 125V DC power to the turbine driven auxiliary feedwater (TDAFW) pump steam supply valves remains available to keep the valves closed (valves fail open on loss of DC power), and operator actions to close the valves can be performed in the control room. However, these actions fail as shown by the presence of split fractions SLIA, SLIB, or SLI C, which indicates steam line isolation failure. The cumulative LERF for just these three sequences is 4.7709E-08.

The exact SGTR sequences described in Case I are not present in Case 3, due the guaranteed failure of the train A emergency AC bus as a result of the EDG being out-of-service and failure of the supporting normal 4KV bus. Therefore, these, sequences are eliminated from the CDF/LERF contribution in Case 3, and would instead progress to the three sequences identified in the above Table 13 Case 3.

For Case 3, the failure of both of the normal 4KV busses 2A and 2D also lead to the guaranteed failure of RWST makeup. But as discussed above, these have lower failure

Attachment A to L-04-141 Page 55 probabilities than the NAI and ND3 split fractions for Case 1. Also, since the train A EDG is assumed to be unavailable, the train A emergency AC bus is now a guaranteed failure (split fraction A02 = 1.0), and credit for electric power recovery by replacing the fast bus transfer breakers is credited to re-power the train A emergency AC bus.

However, this action fails as shown by the presence of split fraction RE5A. With the train A emergency AC bus unavailable, it is assumed that 125V DC power to the A steam generator's TDAFW pump steam supply valves is eventually lost and the valves fail open. This requires operator actions to locally close the manual isolation valves and terminate any RCS leakage out the steam lines. However, as shown by the presence of split fractions SL2A, SL2B, or SL2C, these operator actions also fail. It should be noted that only the A steam generator's TDAFW pump steam supply valves are impacted by the failure of the train A emergency AC bus. Therefore, the local operator actions to isolate these valves are only required during a SGTR on the A steam generator (initiator SGTRA), and hence this sequence has a higher frequency than the SGTRB or SGTRC initiators. The cumulative LERF for just these three Case 3 sequences is 1.2660E-09.

These same three sequences would also be present in Case 1, but of a lower frequency since the train A emergency AC bus would be a probabilistic failure and not a guaranteed failure. The cumulative LERF for these same three sequences that would be present in Case 1 is 4.5901E-1 0.

When taking the difference in just these three LERF sequences in Table 13, it can be seen that there is a reduction of almost 5E-08 in the Case 3 LERF. Since CDF sequences have a lot more initiating events contributing to the frequency than just SGTRs, there is an overall increase in CDF for Cases 3 and 4 when compared to Case 1.

d. Why is Unit 1 Case 6 LERF higher than Case 5 LERF, when the corresponding CDF is lower?

Response

The slight difference in the LERF values between Unit 1 Case 5 and Case 6 can be attributed to the truncation frequency of the sequences quantified (1.OE-12) and the contribution of train B emergency AC power success terms. Since Case 5 includes common cause failures of the available EDG, the train B emergency AC power conditional failure probability, whenever the associated normal 4KV bus is failed, is higher in Case 5 than it is Case 6. Therefore, the retained LERF sequences with success terms for the train B emergency AC power (I - failure probability) are lower in Case 5 than they are in Case 6.

Round off of these retained LERF sequences to two decimal places in LAR Table I accounts for the increase of 1.OE-07 in Case 6 over Case 5. However, the actual increase in the retained LERF sequences for Case 6 is only 3.4E-09, when compared to Case 5.

Since the CDF is based on a larger set of initiators, this success term impact is not as influential in the Unit I Case 6 CDF.

Attachment A to L-04-141 Page 56

e. In Tier I of the LAR, the BVPS-2 EDG unavailability is estimated to increase to 156.8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months per year per EDG. Table 3 shows a total of 389.7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months per year EDG unavailability, which corresponds to 194.85 hours9.837963e-4 days 0.0236 hours 1.405423e-4 weeks 3.23425e-5 months per year per EDG. Please explain this difference in estimated unavailability.

Response

In the Unit 2 Tier I analysis, the extended EDG AOT unavailability was estimated based upon the expected mean time for tests (10.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months ) and for maintenance (146.21 hours2.430556e-4 days 0.00583 hours 3.472222e-5 weeks 7.9905e-6 months ),

for a total unavailability time of about 156.8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months per EDG. The 146.21 hours2.430556e-4 days 0.00583 hours 3.472222e-5 weeks 7.9905e-6 months of expected mean time for maintenance was based on 43.17 hours1.967593e-4 days 0.00472 hours 2.810847e-5 weeks 6.4685e-6 months of corrective maintenance, and 103.02 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months of preventative maintenance. See Tables I and 2 in the response to RAI question 6 for more details on this unavailability. This Unit 2 EDG unavailability time (or 1.79%) was then used to calculate the CDF values shown in LAR Table I Case 2. The change in CDF given in Table 2 was derived by using this CDF and subtracting off the Case I baseline value CDF. However, when using this approach, it does not discount for maintenance alignments that would not be allowed, either by Technical Specifications or by the On-Line Maintenance procedure (e.g., one EDG unavailable with one offsite power circuit out-of-service). Nor does this approach eliminate the effects of common cause failures, when corrective maintenance would put the plant into these restricted alignments.

In order to account for these restricted maintenance alignments, LAR Table 3 was generated. The 389.7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months of Unit 2 EDG unavailability presented in Table 3 also assumes that there are 10.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months associated with tests (surveillances) and about 43.2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months associated with corrective maintenance. However, the EDG unavailability time associated with preventative maintenance was increased to the full 14-day AOT (336 hours0.00389 days 0.0933 hours 5.555556e-4 weeks 1.27848e-4 months ) for conservatism. Therefore, the total EDG unavailability assumed in the Table 3 CCDP analysis was 389.7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months per EDG. This value was then used to derive the Delta CDF presented on page 19 of the LAR submittal.

Upon further review of the LAR Table 3 CCDP value during the response to this RAI question, it was noted that the Delta CDF calculation only accounts for one EDG being unavailable throughout the year. Therefore, the following replacement Table 3 and Delta CDF calculation are presented to account for two EDGs being unavailable during the year. This revised table also assumes that the expected preventative maintenance unavailability for Case 3 is 103.02 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months per EDG. This corresponds to the Unit 2 Tier 1 analysis assumed EDG hours, instead of the conservative full 14-day AOT (336 hours0.00389 days 0.0933 hours 5.555556e-4 weeks 1.27848e-4 months ) used in LAR Table 3.

Attachment A to L-04-141 Page 57 Revised Table 3 BVPS-2 Conditional CDP Using Expected Time in Maintenance Alignments Case Alignment Description Conditional CDF Hrs CCDP (per yr)

Corrective Maint.

One EDG in Corrective 7.60E-05 86.4 7.50E-07 (Case 4)

Maintenance Preventive Maint.

One EDG in Preventive 4.29E-05 206.0 L.OIE-06 (Case 3)

Maintenance Surveillances One EDG in routine 7.60E-05 21.0 1.82E-07 (Case 4) surveillance testing Baseline (Case 1) Base case assumptions 3.27E-05 8446.6 3.15E-05 for remainder of year CCDP Summation 3.35E-05 The revised increase in the BVPS Unit 2 CDF based on the expected time in the preventive and corrective alignments is therefore:

Revised Delta CDF

= (CDF expected time in maint. alignments) - (CDF for Baseline)

= (3.35E-05) - (3.27E-05)

= 7.7 1E-07 per reactor year As can be seen in the revised Delta CDF results, the calculated increase in CDF for BVPS Unit 2 using the expected time in the preventive and corrective maintenance alignments is still less than the Regulatory Guide 1.174 acceptance guideline of 1 E-6 per reactor year for demonstrating a very small increase in plant risk.

f. In Table 4 of the LAR, please explain why BVPS-2 incremental conditional large early release probability (ICLERP) is "risk neutral" with an EDG out of service, but BVPS-I demonstrates an increase under the same conditions?

Response

ICLERP was derived by subtracting the Case 1 LERF from the Case 3 LERF, then multiplying the result by expected duration or full 14-day AOT duration divided by the number of hours in a year. Since the LERF value at Unit 2 for Case 3 (see response to RAI question I.c) is less than it is for Case 1, there is a reduction in the ICLERP value, or "risk neutral" result. This is not the case for Unit 1, where the Case 3 LERF is slightly higher than the Case I LERF.

Attachment A to L-04-141 Page 58

12. Discuss and provide information on the reliability and availability of offsite power sources relating to the proposed change. Provide the basis the loss of offsite power (LOOP) frequencies and non-recovery probabilities used in the PRA models. Were they adjusted as a result of the New York area blackout of August, 2003? If not, why not? How is the potential for loss of offsite power given a non-LOOP initiating event (e.g., "consequential LOOP")

modeled in the BVPS-I and 2 PRA models? (RG 1.174, Section 2.2.2; RG 1.177 Section 2.3)

Response

The offsite power sources for both BVPS Unit I and Unit 2 consist of two physically independent circuits between the offsite transmission network and the onsite power systems.

Each offsite circuit consists of a 138 KV switchyard bus connected to a system station service transformer (SSST) which can provide power to two of the four normal 4 KV station buses. One of these two normal 4KV buses supplies power to one of the redundant 4KV emergency buses through two series tie breakers to complete the offsite power circuit.

During normal power operation, the normal 4 KV station buses are supplied from the station output through the unit station service transformers (USST). Following a unit trip, the normal 4KV buses are transferred to the offsite power sources by a fast bus transfer scheme which transfers the normal 4 KV buses power source to the SSSTs.

In the event that one of the required offsite power circuits becomes inoperable, the BVPS Unit I and Unit 2 Technical Specifications (TS 3.8.1.1) requires the inoperable offsite power circuit be returned to operable status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , or a plant shutdown be initiated.

If both one of the required offsite power circuits and an EDG are inoperable, the BVPS Unit I and Unit 2 TS 3.8.1.1 requires one of the inoperable power sources be returned to operable status within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , or a plant shutdown initiated.

The following Tier 2 restrictions will be required when removing an EDG from service for scheduled maintenance, as provided in the LAR IA-306 & 2A-176, to ensure availability of the offsite power circuits.

If either offsite power circuit is unavailable, an EDG will be removed from service only for corrective maintenance, i.e., maintenance required to restore operability.

If an EDG is unavailable, the offsite power circuits will be removed from service only for corrective maintenance required to restore operability.

An EDG will not be removed from service for scheduled maintenance if weather forecasts are predicting severe weather conditions for the BVPS area with the potential to degrade or limit offsite power availability.

When an EDG is removed from service for scheduled maintenance, no discretionary switchyard maintenance will be allowed. In addition, switchyard access will be strictly controlled by the control room operating crew to minimize the potential for offsite power transients.

Prior to removing the EDG from service, the stability of the offsite power system in the vicinity of BVPS will be verified by contacting the FirstEnergy and Duquesne Light

Attachment A to L-04-141 Page 59 Company System Control Centers to determine the projected load demand and status of the grid during the period the EDG will be unavailable.

The following discussion provides information related to station loss of offsite power events.

The BVPS operating history was reviewed for station events related to loss of offsite power sources. This review covered the period of 1985 to present (20 years) for Unit I and from initial operation (1987) to present for Unit 2.

During this period the station experienced two total loss of offsite power events as discussed below:

10/12/93 BVPS Unit I and Unit 2 experienced a loss of all offsite power sources when various offsite feeder breakers in the switchyard opened unexpectedly. Prior to the event Unit I was operating a full power and Unit 2 was in a refueling outage. The operation of the switchyard breakers caused a loss of the majority of the Unit I electrical load and subsequent turbine/reactor trip. The event was caused by personnel error while performing maintenance on the Unit 2 main output breaker. Offsite power was restored in approximately 10 minutes at Unit 1 and 15 minutes at Unit 2. (LER 334/93-13) 11/17/87 BVPS Unit 2 experienced a loss of all offsite power sources following a Turbine/Reactor Trip from full power. The Unit 2 138 KV offsite power supply breakers opened during the transfer to offsite power following the unit trip. The event was caused by a problem with the normal supply breaker control scheme which allowed these breakers to reclose momentarily during the transfer to offsite power. One of the offsite power sources was lost only momentarily during the event. The other offsite power source was restored in approximately 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . (LER412/87-36)

Twelve events were identified during the review period that involved a partial loss (loss of one offsite power source to the station emergency buses). Seven of these events occurred at Unit 2 during the first few years of operation (1987 - 1990). Since then five events have occurred and are discussed below:

2/27/03 (Unit 1) One of the two 4KV emergency buses was isolated from its offsite power source when the offsite supply breaker to the normal 4KV bus supplying the emergency bus tripped open. The cause of the event was improper installation of an electrical protection relay which actuated when starting a main feedwater pump. (LER 334/03-03) 10/12/99 (Unit 2) The station automatic bus transfer capability to one of the offsite power sources was unavailable for approximately 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months due to personnel error. Manual transfer capability was available. (LER 412/99-09)

Attachment A to L-04-141 Page 60 7/16/99 (Unit 2) One of the two 4KV emergency buses was isolated from its offsite power source when the emergency bus supply breaker from the normal 4KV bus supplying the emergency bus tripped open. The cause of the event was an erratic EDG voltage regulator which actuated a protective relay operation.

(LER 412/99-06) 3/29/99 (Unit 2) One of the two 4KV emergency buses was isolated from its offsite power source when the normal 4KV bus supply to the emergency bus was de-energized due to an inadvertent protective relay actuation which locked-out the offsite supply to the normal 4KV bus. The protective relay actuation was caused by relay control power fluctuations. (LER 412/99-05) 6/1/94 (Unit 2) The 2A Station System Service Transformer offsite power source was de-energized due to an inadvertent protective relay actuation associated with the 138 KV buses. The event was caused by a system electrical disturbance following a Unit 1 plant trip. (LER 334/94-05)

The basis for the PRA model loss of offsite power (LOSP) frequencies comes from reviewing industry data presented in the following sources:

NUREG/CR-5496, "Evaluation of Loss of Offsite Power Events at Nuclear Power Plants: 1980-1996," November 1998 NUREG/CR-5750, "Rates of Initiating Events at U.S. Nuclear Power Plants: 1987-1995," February 1999, and EPRI Technical Report 1000158, "Losses of Off-Site Power at U.S. Nuclear Power Plants - Through 1999," July 2000.

Because the EPRI study thoroughly reviewed LOSP events, it was considered to be a better source of data for LOSP events than NUREG/CR-5750 and had more recent data than NUREG/CR-5496. Therefore, the EPRI report was used to develop the first stage (prior/generic) LOSP distribution using a two-stage Bayesian methodology with the following attributes:

Mean = 2.74E-02 5th Percentile = 4.93E-03 Median = 2.20E-02 95th Percentile = 6.34E-02 The BVPS plant specific LOSP event count and critical years of operation were then used to update the prior distribution in the second-stage of the Bayesian update to derive a LOSP distribution for the BVPS plant specific initiating event.

In order for an event to be classified as an LOSP, the PRA model assumes that both the outgoing 345KV and incoming 138KV lines must be lost. If only the 138KV lines are lost,

Attachment A to L-04-141 Page 61 the unit does not trip since the unit station service transformers (USST) are supplying normal 4KV power. Consequently, loss of only the 138KV lines is not modeled as an initiating event in the PRA models. If the 345KV line is lost it results in a generator trip, but equipment is re-powered when the fast bus transfer to the 138KV line is completed. This loss of load event is captured in the turbine trip (TTRIP) PRA model initiating event frequency. Additionally, if only one normal 4KV bus is lost, it is captured in the loss of a 4160V bus (LBIA, LBID, LB2A, or LB2D) PRA model initiating event frequency. It should also be mentioned that in response to PRA Peer Review F&O IE-04, derivations of initiating event frequencies did not use data from the initial year of commercial operation, since the use of this data, though conservative, could shift the importance of components, which could affect future use of the PRA for risk-informed applications.

For Unit 1:

The LOSP initiating event frequency developed for the baseline Unit 1 PRA model captured initiating events starting on January 1, 1980 and ending on December 31, 200 1.

Using the initiating event definitions defined above, only I event was retained in the LOSP category during the 15.8 years of critical power operation. Using a two-stage Bayesian update approach with this information and the LOSP prior distribution, a posterior value of 3.166E-02 is obtained.

For Unit 2:

The LOSP initiating event frequency developed for the baseline Unit 2 PRA model captured initiating events starting on January 1, 1989 and ending on May 31, 2001.

Using the initiating event definitions defined above, no events were retained in the LOSP category during the 9.93 years of critical power operation, when excluding the use data from the initial year of commercial operation and plant shutdown conditions. Using a two-stage Bayesian update approach with this information and the LOSP prior distribution, a posterior value of 2.31E-02 is obtained.

In the BVPS PRA models, two offsite power non-recovery probability distributions were developed; one for times to core uncovery prior to 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months used in the electric power recovery STADIC code, and one for times to core uncovery greater than 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months . This methodology was chosen over strictly using the STADIC electric power recovery model for all times, since the offsite power recovery curves used in STADIC model are constant between 12 and 100 hours0.00116 days 0.0278 hours 1.653439e-4 weeks 3.805e-5 months , and would not provide for any additional credit for offsite power recovery after 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

The mean probability of non-recovery of offsite power used in the STADIC code for the BVPS IPE electric power recovery models were developed from data presented in NSAC-144, "Losses of Offsite Power at U.S. Nuclear Power Plants All Years Through 1988," April 1989. In addition, specific line item data from the Seabrook site and South Texas Project site were used with data from NUREG/CR-5032 to develop the distributions from the mean for the I Oth and 90"h percentile cases. Together, these distributions form the basis for the offsite power non-recovery probability, used in the BVPS PRA electric power recovery models for times to core uncovery prior to 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months , and are shown at the end of this response.

Attachment A to L-04-141 Page 62 As part of the PRA model update process, a review of more recent work on LOSP events at nuclear power plants, as documented in NUREG/CR-5496, indicates that the recovery curves for offsite power recovery time in the NUREG report (for example, Figure 3-4 of NUREG/CR-5496) matches quite closely to the I 0th percentile recovery curve used in the BVPS IPE analyses. The recovery curves used in the BVPS IPE electric power recovery analyses are, therefore, slightly more conservative compared to the one documented in the NUREG/CR-5496 report. Consequently, the offsite power recovery curves developed for the BVPS IPEs were still utilized in the updated PRA electric power recovery models.

For times to core uncovery greater than 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months , the probability of not recovering offsite power before core uncovery occurs was developed using the Plant-Centered LOOP Recovery lognormal distribution (median = 29.6 min, error factor = 10.6) reported in NUREG/CR-5496. The plant-centered LOOP recovery values were chosen over the weather related LOOP values, since electric power recovery is not credited for external initiating events in the BVPS PRA models. The complementary cumulative distribution of the plant-centered LOOP recovery represents the probability that offsite power is not recovered, and is shown in Figure 34 of NUREG/CR-5496. This figure formed the basis for the electric power non-recovery factors for core uncovery times greater than 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months .

If core damage does not occur within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months following the loss of seal cooling, the BVPS SBO sensitivity cases using MAAP show that RCS conditions (temperature, pressure, and level) are controlled and safety injection recirculation is not required. Therefore, electric power recovery of some type is assumed to be a guaranteed success for these sequences, and they are not binned to a core damage end state in the PRA models. The underlying assumption in this approach is that there would be sufficient time to implement recovery strategies from the Beaver Valley Severe Accident Management Guidelines (SAMGs) prior to the onset of core damage.

The New York Area blackout of August 2003 did not adversely impact either of the BVPS Units enough to result in a plant trip or loss of offsite power. Therefore, data obtained from this event was not used to update the LOSP initiating event frequency when performing the EDG AOT extension evaluations.

However in response to this RAI question, a sensitivity was performed on the LOSP IE frequency assuming that each of the Units observed one additional LOSP event through the end of 2003 by using the two-stage Bayesian update approach. As previously mentioned, the current PRA models used December 2001 and May 2001 as the initiating event data cutoff dates for the Unit I and Unit 2 PRA model updates, respectively. Therefore, at Unit 1 the t wo-stage Bayesian update of the LOSP frequency used 2 events during 17.8 years of critical power operation, while Unit 2 used I event in 12.5 years of critical power operation. The results of this LOSP sensitivity and the impact on the CDF (by using Tables 5, 7, 9, and 11 to calculate conditional core damage probabilities) are given in the table below.

Attachment A to L-04-141 Page 63 New York Area Blackout of August 2003 CDF Impact Sensitivity LAR LOSP LAR LOSP CCDP RAI LOSP RAI LOSP Delta CDF IE CDF*

IE CDF Frequency Frequency Unit I Case I 3.16E-02 2.87E-07 9.09E-06 4.45E-02 4.05E-07 1.17E-07 Case 2 3.16E-02 3.14E-07 9.95E-06 4.45E-02 4.43E-07 I.28E-07 Unit 2 Case l 2.31 E-02 4.02E-07 1.74E-05 3.35E-02 5.83E-07 1.81E-07 Case 2 2.31 E-02 4.47E-07 1.94E-05 3.35E-02 6.48E-07 2.01 E-07

These values are obtained from Tables 5, 7, 9, and 11 of this RAI.

Consequential LOOP events are evaluated in top event OG in the PRA models. This top event models the supply of AC power from the 138KV switchyard to the SSSTs following a plant trip and is based on data from PLG-0500 Revision 1, 1989. For the loss of offsite power initiating event, this top event is assumed to be guaranteed failed. Loss of power at the 138KV grid will result in failure of the normal power supply to all of the emergency and non-emergency AC buses.

Following a plant initiating event, the turbine generator is assumed to trip, thereby requiring a fast bus transfer of the non-emergency normal 4KV buses from the USSTs to the SSSTs.

Power for these fast bus transfer breakers are modeled in the normal DC power top events, while the breakers, normal 4KV busses, and SSSTs are modeled in the normal 4KV power top events. If top event OG fails, the normal 4KV power top events are assumed to be guaranteed failed, thereby requiring the EDGs to start and load.

Attachment A to L-04-141 Page 64 OFFSITE POWER NON-RECOVERY DISTRIBUTIONS NOTES:

1. 50th PERCENTILE FROM NSAC-144 DATA.

2. 10th AND 90th PERCENTILE FROM ONE OR THREE LINE DATA FROM SOUTH TEXAS, SEABROOK.

AND NUREGtCR-5032.

'-10 0

.8 z0z ILo.6 90th PERCENTILE LU

.40th PERCENTILE

.2

<10th PERCENTILE 0 0 2

4 6

8 10 12 DURATION (HOURS)

13. The LAR proposes to change footnote (1) of Technical Specification (TS) 3.8.1.1 as follows:

"Required actions may be delayed for up to 7 days if the diesel generator(s) is inoperable solely due to the fuel oil contained in the storage tanks not meeting the properties in accordance with [TSs] 4.8.1.1.2.d.2 or 4.8.1.1.2.e." This proposed change appears to have two impacts: (1) Extends from 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to 7 days the actions to verify operability of the other diesel or determine that no common mode failure is present; and (2) The time to return the fuel oil to within specifications is not longer explicitly stated and could be interpreted as up to 21 days (i.e., 7 + 14).

Please clarify the intent of the proposed change to this footnote. What experience has the site had with fuel oil not meeting the surveillance requirements in TS 4.8.1.1.2.d.2 or TS 4.8.1.1.2.e? Is there an increasing trend in failure to meet these specifications? (RG 1.174, Section 2.2.2; RG 1.177 Section 2.3)

Attachment A to L-04-141 Page 65

Response

The changes to footnote (1) were proposed to provide clarification to the existing wording of the footnote which does not clearly define application of the associated action statements when an EDG is inoperable due to failure to meet the fuel oil property limits of surveillance requirements 4.8.1.1.2.d.2 or 4.8.1.1.2.e. With the current wording of this footnote and the proposed change to the EDG AOT, it could be interpreted that a more restrictive 7 days is allowed to restore EDG fuel oil to within limits than the proposed 14 days for restoring an inoperable EDG to operability. The Standard Technical Specifications for Westinghouse Plants, NUREG 1431, Specification 3.8.3 for Diesel Fuel Oil, Lube Oil and Starting Air, allows 7 days for restoring EDG fuel oil particulate to within limits (and up to 30 days for restoring new fuel oil properties to within limits) prior to declaring the EDGs inoperable and entering the required actions of Specification 3.8.1. Since the BVPS Technical Specifications provide EDG fuel oil surveillance requirements within the same LCO for the EDG, failure to meet these surveillance requirements requires the affect EDG to be declared inoperable. The proposed changes to footnote (1) would allow the action requirements for an EDG declared inoperable due to failure to meet the above fuel oil surveillance requirements to be delayed similar to the provisions in NUREG 1431. With the proposed change to the footnote, 7 days would be allowed to restore the fuel oil to within limits prior to entering the applicable action statement after which the 14 day AOT would apply to the affected EDG and the associated action requirements, including operability of the other diesel or determining that no common cause is present.

The past five years of EDG fuel oil sampling data required by surveillance requirements 4.8.1.1.2.d.2 and 4.8.1.1.2.e for BVPS Units I and 2 were reviewed by the BVPS Chemistry Department. None of the samples for these surveillance requirements showed any increasing trends either in failure to meet the surveillance requirement specifications or towards failure to meet the surveillance requirement specifications. In the five year period reviewed, there was only one result that failed to meet the specifications of the two surveillance requirements: the Unit 2 carbon residue on 10% bottoms on a new fuel oil delivery to EDG fuel oil storage tank 2EGF-TK21B of 3/19/04. The carbon residue result was 0.37%, which failed to meet the carbon residue specification of less than or equal to 0.35%. This was documented in CR 04-03416. Follow-up samples of the 2EGF-TK21B storage tank showed that the tank's carbon residue value had remained within specification at 0.15%. A review of all carbon residue on 10% bottoms new fuel oil results showed the 3/19/04 results to be an isolated case.

ATTACHMENT B Letter L-04-141 KEY DIFFERENCES IN THE BVPS PRA MODELS AND THEIR IMPACT ON THE EDG AOT EXTENSION Safety Iniection Recirculation Mode Unit 1: Low Head Safety Injection (LHSI) pumps take suction from the containment sump and discharge to the Reactor Coolant System (RCS) LHSI piping or to the High Head Safety Injection (HHSI) pumps suction.

Unit 2: Recirculation Spray pumps C & D take suction from the containment sump and discharge to the RCS LHSI piping or to the HHSI pumps suction.

EDG AOT Impact: These differences are only expected to have an insignificant impact on the risk assessment of the 14-day EDG AOT extension, since all associated pumps receive power from the EDGs.

Service Water / River Water Operating Pumps Unit 1: Normally one River Water (RW) pump is running with the A & B headers cross-connected. There is also one standby RW pump and one spare RW pump, along with two Auxiliary RW pumps available.

Unit 2: Normally two Service Water (SW) pumps are running, since they support the secondary component cooling water system. There is also one spare SW pump, along with two Standby SW pumps available.

EDG AOT Impact: These differences are only expected to have a slight impact on the risk assessment of the 14-day EDG AOT extension, since the Unit 1 standby RW pump must start to support its EDG, while the Unit 2 pump is already running.

Auxiliary River / Standby Service Pump Starting Unit 1: The Auxiliary River Water pumps need to be manually started from the control room under all conditions.

Unit 2: The Standby Service Water pumps auto start on low Service Water System pressure, given that offsite power is available. These pumps only need to be manually started from the control room during a loss of offsite power.

EDG AOT Impact: These differences are only expected to have an insignificant impact on the risk assessment of the 14-day EDG AOT extension, since all associated pumps must be manually loaded on to the EDG to start, following a loss of offsite power.

Main Feedwater Coolina Water Sunnort Svstems Unit 1: The Raw Water System supplies the secondary cooling water (CCT) loads.

Attachment B to L-04-141 Page 2 Unit 2: The Service Water System supplies secondary cooling water (CCS) loads.

EDG AOT Impact: These differences are only expected to have a slight impact on the risk assessment of the 14-day EDG AOT extension. The Unit 2 PRA model requires the CCS isolation MOVs to close for a Standby Service Water pump to successfully supply the cooling loads, including the EDGs following a loss of offsite power. This function is not required for the Unit I Auxiliary RW pump to cool the EDG, since the Raw Water System supplies the CCT loads.

Emergency Battery Capacity Unit 1: Battery 1 has 2.4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months of capacity (used to start EDG #1); Battery 2 has 2.6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months of capacity (used to start EDG #2); Battery 3 has 3.8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months of capacity (used for Steam Generator level indication); Battery 4 has 5.6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months of capacity.

Unit 2: Batteries 1 & 2 have 3.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months of capacity (used to start EDGs); Batteries 3 & 4 have 8.0 hours0 days 0 hours 0 weeks 0 months of capacity (used for SG level indication).

EDG AOT Impact: These differences are only expected to have a slight impact on the risk assessment of the 14-day EDG AOT extension. The battery capacities are primarily used in the electric power recovery model (Top Event RE). Batteries I and 2 are used to support starting the EDGs. During SBO events, credit is only given for EDG repair/recovery if it can be completed before core uncovery or its support battery depletes, since without the necessary battery capacity the repaired EDG cannot start. The impact between the Unit I and Unit 2 batteries 1 & 2 capacities is only slight (less than a 10 percent chance of not recovering a single EDG in 2.4 hrs vs. 3.5 hrs). The difference in the batteries 3 and 4 capacities between the Units is slightly higher. These batteries are used in the electric power recovery model to provide steam generator level indication. Once these batteries deplete, it is assumed in the model that the steam generators will overfill and consequently fail the turbine-driven auxiliary feedwater pump.

Without any feedwater, the overfilled steam generator eventually dries-out and core uncovery ensues due to the loss of secondary heat removal. Based on 3.8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months of capacity at Unit 1, this sequence of events is expected to take about 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months to overfill the steam generator and between 14 and 19 hours2.199074e-4 days 0.00528 hours 3.141534e-5 weeks 7.2295e-6 months to uncover the core, depending on Reactor Coolant Pump (RCP) seal leakage.

At Unit 2 based on 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months of capacity, this same sequence of events is expected to take about 23 hours2.662037e-4 days 0.00639 hours 3.80291e-5 weeks 8.7515e-6 months to overfill the steam generator and between 27 and 37 hours4.282407e-4 days 0.0103 hours 6.117725e-5 weeks 1.40785e-5 months to uncover the core, depending on RCP seal leakage. It should be noted, however, that Unit 1 also credits the dedicated auxiliary feedwater pump to provide water-to-water steam generator cooling in the event of an overfill. Whereas, this alternative is not available at Unit 2.

Emergency Diesel Generator Support Systems Unit 1: 125V DC Batteries I & 2 are required to start the EDG, and Vital Bus I (Red) & II (White) are required to sequence the loads.

Unit 2: Only the 125V DC Batteries 1 & 2 are required to start and load the EDGs.

EDG AOT Impact: These differences are only expected to have an insignificant impact on the risk assessment of the 14-day EDG AOT extension. The failure probability of the Unit 1 vital busses is approximately 2.0E-05, which is insignificant when compared to the diesel generator failure probability during a 24-hr mission time (about 4.0E-2).

Attachment B to L-04-141 Page 3 Dedicated Auxiliary Feedwater Pump Unit 1: A dedicated auxiliary feedwater (DAFW) pump serves as a backup to the turbine-driven AFW pump during SBO events. The DAFW pump electrical power is backed up by the non-safety related ERF diesel generator and is capable of supplying water to the steam generators for 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . It can also operate in water-to-water heat removal mode if the steam generators are overfilled.

Unit 2: Only the turbine-driven AFW pump can be used during SBO events. This pump is assumed to fail if the steam generators are overfilled, and consequently will lead to core uncovery and damage before a 48-hour mission time.

EDG AOT Impact: These differences have a significant impact on the risk assessment of the 14-day EDG AOT extension. At Unit I if DAFW is available and the RCS is cooled down and depressurized, the SBO can be successfully mitigated given that the RCP seal leakage would be less than 182 gpm/RCP at full RCS pressure and temperature conditions. The underlying assumption in this approach is that, since core damage does not occur within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months following the loss of all seal cooling, there would be sufficient time to implement recovery strategies from the Beaver Valley Severe Accident Management Guidelines (SAMGs). Therefore, these sequences are assumed not to result in core damage, since it is expected that some type of electric power recovery can be reestablished with guaranteed success, given 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months for implementation. At Unit 2 without a similar pump, all sequences resulted in core damage prior to 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months , so all RCP seal LOCAs were binned to a core damage end state.

PPDWST Makeup Unit 1: Makeup to the Unit I Primary Plant Demineralized Water Storage Tank (PPDWST) from the water treatment pumps requires power from normal AC power supplies. There are no makeup capabilities without normal AC power.

Unit 2: Makeup to the Unit 2 PPDWST from water treatment pumps requires power from normal AC power and are backed up by the ERF diesel. There is also a gravity feed flow path available from the Demineralized Water Storage Tank during station blackout conditions to provide additional water to supply the turbine-driven AFW pump.

EDG AOT Impact: These differences are only expected to have an insignificant impact, since the DAFW pump can also be used at Unit I during SBO events once the PPDWST depletes. In addition, the diesel-driven fire pump can be aligned to either Unit's TDAFW pump to provide a water supply during SBO events.

RWST Volume Unit 1: The Refueling Water Storage Tank (RWST) has a water volume of - 440,000 gal, makeup is from the spent fuel pool with fire protection system water.

Unit 2: The RWST has a water volume of-860,000 gal, makeup is from the spent fuel pool with Service Water or fire water.

EDG AOT Impact: These differences are only expected to have an insignificant impact on the risk assessment of the 14-day EDG AOT extension. The dominant core damage sequences

I.

I Attachment B to L-04-141 Page 4 contributing to the increase in risk due to the 14-day EDG AOT extension are some form of an SBO event or failure of one train of AC power and the opposite train of DC power. As such, there are no pumps available to draw suction from the RWST.

Instrument Air Unit 1: There are two motor-driven station air compressors powered from offsite power and a diesel-driven air compressor. Any one of these compressors can supply all the Unit's compressed air loads including containment instrument air via a normally opened cross-tie to the station instrument air header.

Unit 2: There are two motor-driven station air compressors and two motor-driven containment air compressors located outside containment. The power supplies to all four of these compressors are backed up by the ERF diesel generator. Additionally, a backup air compressor (Condensate Polishing) powered from offsite power is also available. The containment instrument air header can be cross-tied to the station instrument air header, though a normally closed manual valve.

EDG AOT Impact: These differences are only expected to have an insignificant impact on the risk assessment of the 14-day EDG AOT extension. Instrument air systems do not contribute significantly to the increase in risk due to the 14-day EDG AOT extension.

Pressurizer PORVs Unit 1: The Power Operated Relief Valves (PORVs) are air operated relief valves with DC powered solenoid.

Unit 2: The PORVs are DC powered solenoid relief valves.

EDG AOT Impact: These differences are only expected to have an insignificant impact on the risk assessment of the 14-day EDG AOT extension. The failure rates for the PORVs to open and close are similar between the Units (L.1096E-02 and 3.3919E-03 for failure to close and open, respectively at Unit 1; and 1.4185E-02 and 3.6662E-03 for failure to close and open, respectively at Unit 2). Furthermore, the core damage frequency contribution for PORV LOCAs are similar between the Units (5.14E-06/ yr. at Unit 1, and 4.29E-06/ yr. at Unit 2).

Interfacing System's LOCA Initiating Event Frequencv Unit 1: The VSX initiating event frequency at Unit 1 is 1.07E-05 per year. At Unit I there is CL-153 piping and associated flanges and seals that would be susceptible to rupturing from exposure to RCS pressure. Such an occurrence would require at least two normally closed valves, which isolate the RCS from low pressure piping, to fail in the open position.

Unit 2: The VSX initiating event frequency at Unit 2 is 2.80E-07 per year. At Unit 2 there is CL-153 piping and associated flanges and seals that would also be susceptible to rupturing from exposure to RCS pressure. However, at Unit 2 such an occurrence would require at least three normally closed valves, which isolate the RCS from low pressure piping, to fail in the open position.

Attachment B to L-04-141 Page 5 EDG AOT Impact: These differences are only expected to have a significant impact on Unit I LERF when an EDG and offsite power circuit is unavailable (see response to RAI question 1 L.b).

A ATTACHMENT C Letter L-04-141 EMERGENCY DIESEL GENERATOR RECOVERY METHODOLOGY Diesel Generator Hardware Recoverv Model The most important causes for diesel generator unavailability are diesel generator hardware-related failures during either the startup sequence or the subsequent operation, and diesel generator unavailability due to maintenance at the time of the initiating event. The diesel generator failures include all malfunctions that prevent the unit from delivering stable power to its output bus. These include failures of the engine, generator, mechanical controls, electrical controls, starting systems, and trip systems. The time to return a diesel generator to operation after a hardware failure depends on many factors, such as the cause of failure, repair personnel availability, alternate power supply status, and reactor operating conditions.

The causes of diesel generator hardware failures can range from the spurious operation of a trip solenoid to major physical damage of mechanical or electrical components. Recovery from these failures may involve the simple resetting of a local trip interlock and restarting of the diesel generator, or it may require disassembly and repair of the engine, generator, or its control system. If the time available for electric power recovery is relatively short (for example, less than approximately 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months ), review of generic diesel generator failure and maintenance data indicates that only the diesel generator startup failures present a significant potential for rapid recovery. Diesel generator failure during operation generally involves more severe problems that require detailed troubleshooting, repairs, or replacement of parts. These are difficult to complete in less than 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

Finally, because most maintenance events require at least partial reassembly of the diesel generator before it can be started, it is assumed for this analysis that the maintenance contribution to unavailability is also unrecoverable within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months after the initiating event.

The following table indicates some of the key actions that can be accomplished within given recovery time periods. This table was developed based on the experience and judgement of the analyst, who was a senior reactor operator. It was not based on plant-specific information, but instead represents assumptions on the time required to perform the actions indicated. These assumptions are believed to be representative of times applicable to Beaver Valley Power Station (and most other plants).

Attachment C to L-04-141 Page 2 Time Following Operator Response Action o to 5 minutes Reset trip relay and attempt local manual restart 5 to 15 minutes Troubleshoot simple problems; check electrical and mechanical indications 15 to 30 minutes Perform step-by-step problem diagnosis; notify cognizant engineering and maintenance personnel 30 to 60 minutes Refer to technical manuals and drawings for diagnosis of more complex failures; response time for first offsite personnel I to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Offsite personnel troubleshoot problems that do not require component repair; make complex adjustments to control systems 2 to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Replace simple failed components (includes maintenance crew response time) 4 to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Repair failed components requiring minor disassembly 8 to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Perform more complex repairs 24 to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Make repairs requiring disassembly

< 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Overhaul diesel engine It is emphasized that these key actions apply to the recovery for a given failed diesel generator following operator response to that unit and only to the recovery from hardware-related failures. They do not include the time for operators or maintenance personnel to reach the diesel room after the diesel generator fails. It is not the length of time required to recover any one of the failed units. These key actions are used as one piece of information in developing a distribution for the length of time required to recover a failed diesel generator.

The recovery time distribution summarized in the following table applies to situations involving a high urgency for diesel generator repairs. It is not derived directly from actual maintenance event duration data because most diesel generator repairs are not completed under the extremely urgent conditions that prevail after loss of all offsite and onsite AC power. It is based on a review of diesel generator failure and maintenance records collected from several plants, with an assessment of the severity of the observed failures, and the experience of operations and maintenance experts.

A Attachment C to L-04-141 Page 3 Time to Recover a Failed Diesel Generator Time Following Operator Response (hours)

Probability 0.0 to 0.5 0.20 0.5 to 1.0 0.10 I to 2 0.15 2to4 0.15 4 to 8 0.20 8 to 24 0.10

> 24 0.10 This assumed distribution is used to model the time needed to restore a single diesel generator to operation after the diesel has experienced a hardware failure. It is assumed that repair efforts are continuous from initial troubleshooting until the diesel generator is returned to service. This accounts for factors such as the need to call out additional maintenance personnel for major repairs. Recovery cannot begin until someone goes to the diesel generator room to investigate the failure, and this distribution does not include scenario-specific delays for operating or maintenance personnel reaching the room. These personnel response times are evaluated in the next section and integrated with the hardware repair time distribution to fully model diesel generator recovery for specific failure scenarios.

Diesel Generator Recovery Personnel Response Time Model Station auxiliary operators are responsible for operating the diesel generators and for initial problem troubleshooting. During the normal work day, additional personnel are also available. An auxiliary operator's normal responsibilities include monitoring plant equipment, changing valve positions and system configurations under direction of the control room operators, and performing walk-through inspections of plant areas. During normal shift working conditions, the operators will usually be moving about various locations or will be at a designated watch area. Other possible, but less likely, locations include the main control room or the administration building.

When offsite power is lost, all diesels will receive signals to start. If diesel generator failures occur after a LOSP, trouble alarms for the diesel generators and other safety systems will be annunciated in the main control room. These alarms, electrical equipment inoperability, and initial verification steps in the plant procedures will provide almost immediate notification to the control room operators, who may attempt to manually restart the affected engine from its control room switch. However, experience has shown that many failures require local troubleshooting to correct the problem and to reset engine trip relays. The control room operators may also be reluctant to quickly restart a diesel

A Attachment C to L-04-141 Page 4 generator that tripped during operation before they determine a cause for the failure. For this analysis, it is assumed that an auxiliary operator must locally investigate all failures before any engine restarts are attempted.

Therefore, local plant operators must be dispatched to the diesel generator building for all diesel generator recovery actions. The control room operators or the control room foreman will contact an auxiliary operator by telephone or page soon after the diesel generator fails.

After the auxiliary operator has been notified of the failure, the auxiliary operator will proceed to the diesel generator rooms to investigate the cause, reset engine trip relays, and begin local recovery efforts including manual restart attempts. It is estimated that the operator's response time for going to the diesel generator building from any of the normal duty locations is approximately 5 to 10 minutes after notification. This is expected to bound the time required, based on informal experience in walking from various plant areas to the diesel generator building. The auxiliary operators will be able to unlock controlled access doors since the key card is the identification badge, which is needed to enter the controlled areas.

The following distribution has been derived based on review of diesel generator failure and maintenance records, and on consultation with experts in maintenance and operation. It is used to model the response time for an auxiliary operator. It applies to the elapsed time from failure of the diesel generator until the operator begins local troubleshooting activities in the diesel generator room. This time includes initial failure detection time, delays for the control room to contact the operator and describe the problem, operator transit time to the diesel generator building, and possible additional delays due to communications problems or other considerations that could impede the operator's response.

Time for First Operator Response to Failed Diesel Generator (Includes Detection Time, Notification Time, and Transit Time)

Response Time (minutes)

Probability Oto5 0.01 5 to 10 0.25 10 to 15 0.50 15 to 20 0.20 20 to 30 0.03 30 to 60 0.01 It is also expected that the in-plant foreman and the onsite maintenance technicians will respond to diesel generator failures that are not quickly corrected by the auxiliary operator.

Depending on the status of equipment in other parts of the plant, additional qualified auxiliary operators may also be available to help with the recovery efforts. The

Attachment C to L-04-141 Page 5 participation of this normal complement of shift personnel has been considered in this recovery time distribution.

If both diesel generators for a Beaver Valley Unit fail, the operating and maintenance personnel would concentrate their initial recovery efforts on one of the diesels. A preliminary evaluation would be made to determine whether one of the diesels could be repaired more quickly than the others, and then that diesel would receive the most concentrated attention. For example, efforts would be made to restart a diesel generator that tripped spuriously before repairs were started on a diesel engine that sustained extensive mechanical damage. In this recovery model, it is assumed that the initial response team will concentrate its efforts almost exclusively on one diesel generator for approximately 20 minutes after the auxiliary operator reaches the building.

If the first diesel is not restored to operation after 20 minutes, it is expected that the response team will begin parallel efforts to recover the other failed unit. For example, the maintenance technicians could remain with the first diesel to begin component repairs or replacement while the operators turned their attention to troubleshooting and restart attempts on the other unit. As more support personnel respond to the site, the repairs of diesel generators can proceed in parallel and the recovery models can be substantially decoupled.

For the electric power recovery analysis, if both diesel generators have failed at a Beaver Valley Unit, recovery of only one is allowed during the first 30 minutes after initial operator response. Power can be restored from the diesel generators to one emergency AC bus in this interval. For periods longer than 30 minutes, the model permits recovery to be started on the second diesel generator and work is assumed to proceed on two diesel generators in parallel until power is restored. Thus, the minimum amount of time required to begin power recovery to all emergency AC buses by repairing failed diesel generators is more than 30 minutes after the diesel generators fail.

Integrated Diesel Generator Power Recovery Model The integrated diesel generator power recovery model is as follows:

Single Diesel Generator Recovery After a loss of offsite power, the emergency AC buses will be deenergized if both diesel generators at a Beaver Valley Unit fail due to a failure of their respective DC power or experience failure during the starting sequence or the subsequent operation. It is assumed for the analysis that DC power from the respective battery (I or 2) is required for diesel generator recovery. Thus, recovery of only one diesel generator is assumed to be possible if DC power is available to only one diesel generator. The model for a single diesel generator recovery is:

(I(t+ T) =1 [(oR(t)1[4 DH1(t)]dt (Eq. 1)

Attachment C to L-04-141 Page 6 where:

(t+ ar) = cumulative frequency of power recovery from a single diesel generator when only one diesel is available for recovery.

poR(t)dt = frequency of auxiliary operator response to diesel generator room between t + dt after the failure of diesel generator power.

)DII(T)

= cumulative frequency of diesel generator hardware recovery within time (T) after operator response.

This analysis is performed for conditions when only one diesel is available for recovery; that is, the other diesel has failed at t = 0 and cannot be recovered within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . For this analysis, approximately 20 percent of the single diesel unavailability is assumed to be attributed to preexisting maintenance scenarios. The 5th percentile model for the single diesel recovery reduces the cumulative frequency of recovery for one diesel by 20 percent.

For the 95th percentile, however, a more optimistic view is taken and it is assumed that this fraction of unavailability is recoverable. This will include, for example, restoring the diesel to service after minor maintenance or testing. For the 50th percentile, it is assumed that the fraction of unavailability due to maintenance is recoverable after 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

The 5th percentile of the single recovery model represents a pessimistic model for operator response and delays the auxiliary operator's arrival time by 30 minutes. The 50th percentile of the model represents a delay of the operator's arrival by 10 minutes.

The 95th percentile bound represents a more optimistic model for operator response, and no delay in the auxiliary operator's arrival is included.

Figure 1 presents the complementary cumulative distribution for the diesel generator non-recovery that is derived for these bounding models. (That is, the 95th percentile represents the 5th percentile recovery model, and the 5th percentile represents the 95th percentile recovery, as discussed previously.)

One Out of Two Diesel Generator Recovery If power can be recovered only from both diesel generators, successful recovery has been defined for this analysis as the restoration of power from at least one of the two diesel generators. This recovery model is characterized by the expression:

(D1/2(t +T)

=l0(t +T) +[I - 0(t +T)][(I(t +T -0.5)]

(Eq. 2)

I Attachment C to L-04-141 Page 7 This model allows recovery of the first of the two diesel generators to begin when an auxiliary operator arrives at the diesel generator room. Recovery of the second diesel begins 30 minutes after the auxiliary operator arrives, and the repairs of both diesels are modeled as continuing in parallel thereafter.

Two bounding scenarios are applied as the 5th and 95th percentiles for the diesel generator recovery model.

For the 5th percentile bound, the single diesel generator recovery model (Eq. 1) is used.

This model represents a pessimistic model for operator response, and it allows recovery of power from only one diesel generator. Parallel repairs of the second diesel generator are not considered. This bound accounts for possible unidentified dependencies in the recovery efforts for both diesel generators, which could couple the repair time distributions; for example, limited spare parts availability and limited support personnel availability.

For the 95th percentile bound, the dual diesel generator recovery model (Eq. 2) is used. The recovery of the second diesel begins 30 minutes after the operator arrives, and the repairs of both diesels are modeled as continuing in parallel thereafter. The 95th percentile bound, thus, represents a more optimistic assessment of operator response, and it includes a more realistic model for single and parallel diesel generator repairs. The 50th percentile is estimated from the 5th and 95th percentile curves.

Figure 2 presents the complementary cumulative distribution for the diesel generator non-recovery derived from these bounding models.

EDG Recoverv Time Window Based on Availabilitv of 125V DC Power Although each diesel has two independent air-starting systems, each diesel generator requires a supply of 125V DC from its respective DC bus for generator field flashing and generator start and control. The effect of the unavailability of DC power on diesel generator recovery is accounted for in the integrated recovery model.

The available time for recovery is a function of both support system availability and Reactor Coolant System (RCS) thermal-hydraulics. Each diesel generator requires a supply of 125V DC power to start and operate. If, for example, a battery can last 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after the loss of all onsite power (diesel generators), the auxiliary operators would have a time window of only 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to recover the diesels. This is as long as the thermal-hydraulic window is longer than or equal to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The thermal-hydraulic time window is a function of the availability of AFW and the leak rate from the reactor coolant pump (RCP) seals. For example, assuming AFW (the turbine-driven AFW pump) is available when and after onsite power is lost, then the time window for onsite power recovery and for the operator's response time to locally manually operate onsite breakers after DC power is lost is dependent on the leak rate from the RCP seals, which defines the time to core uncovery from this leak.

Attachment C to L-04-141 Page 8 During the variable time window established by thermal-hydraulic considerations for diesel generator failure scenarios, the operators will be restoring power to emergency AC buses by either recovering one diesel generator or recovering power from the offsite grid previously described. The diesel generators are assumed in this analysis to be unrecoverable after depletion of the DC batteries (that is, after a duty cycle of 2.6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months at Unit 1 and 3.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months at Unit 2), since DC power must be available to start the diesel. The restoration of offsite power, however, is assumed to continue after this duty cycle, but to add an additional 0.5-hour delay to the recovery. The addition of the 0.5-hour delay is to account for the contribution of manual operation of the breakers to offsite power recovery after the battery duty cycle.

Electric Power Recovery Model Assemblv The time-dependent calculations for the integrated electric power failure and recovery model are performed using the STADIC computer simulation program. The STADIC computer code, uses Monte Carlo simulation techniques to select a single random number for each variable based on the probability distributions provided as input.

The model computes the following:

Conditional probability of onsite power system (diesel generator) failure in a mission time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months with failure to recover diesel generators or offsite electric power before core damage (designated by the variable QLP in the STADIC subroutine QDG)

Conditional probability of onsite power system failure in a 24-hour period without including recovery (designated by the variable QTM in the STADIC subroutine QDG)

The ratio of QLP/QTM gives the electric power non-recovery factor. This model considers diesel generator failures after an LOSP initiating event.

The recovery of offsite power without onsite power available was assumed to be delayed for 0.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months , once the batteries have failed to allow time for making a decision about which breakers to close; for the control room supervisor to brief auxiliary operators; and for the auxiliary operators to manually close the breakers and to correct breaker malfunctions (or to choose alternate paths or a set of breakers). Since DC power is also required to recover the diesel generators, the cumulative non-recovery probability for the diesel generators was assumed to remain constant at the value calculated at the time the plant batteries fail when no offsite electric power is available. In conclusion, the recovery time available for the restoration of AC power from the diesel generators is limited either by the plant thermal-hydraulic time window or by the availability of the batteries.

4 0

1.0 0.9 0.8

>. 0.7 03 a

0.6 w

, 0.5 1 0.4 8 0.3 0.2 0.1 0

0 2

4 6

8 10 12 14 15 18 20 22 24 OUnATION (HOURS)

Figure 1. Non-Recovery of Single Diesel Generator

Attachment C to L-04-141 Page 10

.09 0.8 5 0.7 C,7 0.8 U_0.5 j

0.4

.U 0.3 0th PERCENTILE 12 DURATION (HOURS)

Figure 2. Non-Recovery of One Out of Tlvo Diesel Generator

L-04-141, Response to Request for Additional Information in Support of LAR Nos. 306 and 176 Emergency Diesel Generator Allowed Outage Time Extension

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ML043070444
Site:	Beaver Valley (DPR-066, NPF-073)
Issue date:	10/29/2004
From:	Pearce L FirstEnergy Nuclear Operating Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
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L-04-141
Download: ML043070444 (82)
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L-04-141, Response to Request for Additional Information in Support of LAR Nos. 306 and 176 Emergency Diesel Generator Allowed Outage Time Extension

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