Text

Response to a Request for Additional Information (RAI Dtd August 2, 2005) in Support of License Amendment Request Nos. 302 and 173, Extended Power Uprate
	ML052550373
Person / Time
Site:	Beaver Valley
Issue date:	09/06/2005
From:	Lash J; FirstEnergy Nuclear Operating Co
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	L-05-140
	Download: ML052550373 (113)
	v • d • e

FENOC Beaver Valley Power Station P.O. Box 4 FirstEnergy Nuclear Operating Company Shippingport, PA 15077-0004 Jantes H. Lash 724-682-7773 Director, Site Operations September 6, 2005 L-05-140 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555-0001

Subject:

Beaver Valley Power Station, Unit Nos. I and 2 BV-1 Docket No. 50-334, License No. DPR-66 BV-2 Docket No. 50-412, License No. NPF-73 Response to a Request for Additional Information (RAI dated August 2, 2005) in Support of License Amendment Request Nos. 302 and 173, Extended Power Uprate By letter dated August 2, 2005, the U.S. Nuclear Regulatory Commission (NRC) issued a request for additional information (RAI) pertaining to FirstEnergy Nuclear Operating Company (FENOC) License Amendment Request (LAR) Nos.

302 and 173 (Reference 1). These LARs propose an Extended Power Uprate (EPU) for Beaver Valley Power Station (BVPS) Unit Nos. 1 and 2.

The EPU LAR proposes increasing the licensed power level approximately 8 percent above the current licensed power level. contains the non-proprietary FENOC responses to all of the August 2, 2005 RAI questions except question number 4. The response to question number 4 is not included in this enclosure because it contains proprietary information. contains the proprietary FENOC response to question number 4 of the August 2, 2005 RAI. The proprietary information in Enclosure 2 has been identified with brackets. contains the non-proprietary FENOC response to question number 4 of the August 2, 2005 RAI. The proprietary information in Enclosure 3 has been identified with brackets and deleted.

As the response to RAI question number 4 in Enclosure 2 contains information proprietary to Westinghouse Electric Company LLC, it is supported by an affidavit signed by Westinghouse, the owner of the information. The affidavit sets forth the basis on which the information may be withheld from public disclosure by the Commission

Beaver Valley Powver Station, Unit Nos. 1 and 2 Response to a Request for Additional Information in Support of License Amendment Request Nos. 302 and 173, Extended Power Uprate L-05-140 Page 2 and addresses with specificity the considerations listed in paragraph (b)(4) of Section 2.390 of the Commission's regulations.

Accordingly, it is respectfully requested that the information which is proprietary to Westinghouse be withheld from public disclosure in accordance with 10 CFR 2.390 of the Commission's regulations.

Correspondence with respect to the copyright or proprietary aspects of the items listed above or the supporting Westinghouse affidavit should reference Westinghouse letter CAW-05-2046 and should be addressed to B. F. Maurer, Acting Manager, Regulatory Compliance and Plant Licensing, Westinghouse Electric Company LLC, P. 0. Box 355, Pittsburgh, Pennsylvania 15230-0355.

No new regulatory commitments are contained in this submittal. If you have questions or require additional information, please contact Mr. Henry L. Hegrat, Supervisor -

Licensing, at 330-315-6944.

I declare under penalty of perjury that the foregoing is true and correct. Executed on September 6 2005.

Sincerely, mes H. Lash

Enclosures:

1. Non-Proprietary responses to all RAI questions except number 4

2. Proprietary response to RAI question number 4

3. Non-Proprietary response to RAI question number 4

4. Affidavit

References:

1. FENOC Letter L-04-125, License Amendment Request 302 and 173, dated October 4, 2004.

c:

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

E. Ryan (BRP/DEP)

L-05-140 Enclosure 1 REQUEST FOR ADDITIONAL INFORMATION RELATED TO FIRSTENERGY NUCLEAR OPERATING COMPANY (FENOC)

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

EXTENDED POWER UPRATE (EPU)

DOCKET NOS. 50-334 AND 50-412 By letter dated October 4, 2004, as supplemented February 28, May 26, June 14, and July 8, 2005, Agencywide Documents Access and Management System (ADAMS)

Accession Nos. ML042920300, ML051530376, ML051670270, and ML051940575, FENOC (the licensee) proposed changes to the BVPS-1 and 2 operating licenses to increase the maximum authorized power level from 2689 to 2900 megawatts thermal rated thermal power or approximately 8 percent. The Nuclear Regulatory Commission (NRC) staff has reviewed the licensee's application against the guidelines in the EPU review standard (RS-001) and determined that it will need the additional information identified below to complete its review.

Question

1.

Section 10.16.1.2 of the risk assessment (Reference 2), states: "A review of the engineering change packages associated with the EPU including containment conversion was performed to determine their effect on systems and associated equipment that are important to plant risk."

a.

Are the BVPS-1 auxiliary feedwater cavitating venturis and main feedwater (MFW) fast-acting isolation valves related to EPU?

Response

The BVPS-1 auxiliary feedwater cavitating venturis and main feedwater fast-acting isolation valves were installed to support the BVPS-1 containment conversion design modification License Amendment Requests (LAR 317 & 190), and these components are related to the extended power uprate (EPU).

As noted on page 1-4 of Enclosure 2 of LAR 302 & 173 (L-04-125), the containment conversion from a sub-atmospheric to an atmospheric containment design, including related modifications such as the addition of feedwater isolation valves and auxiliary feedwater flow limiting venturis for BVPS-1 are required to support the implementation of the EPU analyses.

L-05-140 Enclosure 1 Page 2 of 34 Question

b.

For EPU-related change packages, please provide the details of these reviews for BVPS-1 and 2, including the effect of each modification on the probability risk assessment (PRA) model.

Response

An evaluation was performed as a two-step screening process. The end result determined whether there is a significant impact on risk due to a plant modification. The two steps are outlined below and shown on Figure 1-1. In each step, if the criterion can be answered in the negative for a given component, that component can be eliminated from further consideration, as it is considered to have no impact or a negligible impact on risk.

Step 1: Is the modified system or component currently modeled in the PRA, or not modeled and considered potentially important to plant risk? - Modifications to components that are currently included in the PRA model will be evaluated for risk impact.

In the event a component is not included in the PRA model, yet the component is determined to be potentially important to plant risk, and therefore should be included in the PRA model, the component will be evaluated for risk impact. Potential risk impact for components not included in the PRA model are determined by engineering judgment.

Step 2: Modification meets guidelines in Standard Review Plan 19.0:

Does the change impact the system performance in a potentially negative or non-conservative manner?

Does the change impact the system design in such a way as to alter system reliability models?

Does the change impact the support function of the system in such a way as to alter the dependencies in the model?

If the answer to all of these criteria is no, then there is no expected impact on system function or component reliability due to the plant modification.

The process resulted in the majority of the plant modifications being screened as not modeled in the PRA, or not important to risk. Only seven plant modifications passed the first screen. Those modifications are:

BVPS-1 Installation of Main Feedwater (MFW) Fast Acting Feedwater Valves BVPS-1 Installation of Auxiliary Feedwater (AFW) Cavitating Venturis Extended Power Uprate Charging System Rethrottling (BVPS-1 and BVPS-2)

Charging Pump Rotating Assembly Replacement (BVPS-1 and BVPS-2)

Replacement Steam Generator Level Transmitters (BVPS-1)

Feedwater Valve Replacement (BVPS-2)

Replacement Steam Generators (BVPS-1)

L-05-140 Enclosure 1 Page 3 of 34 A review of the above seven modifications was performed. It was determined that these modifications were to be made in order to maintain or improve the performance of equipment under EPU conditions. This will ensure that the plant systems and equipment will continue to be operated within their design constraints. Therefore, it was concluded that the failure rates of the affected components would not change with the implementation of EPU. A brief description of the evaluations performed for each of the seven modifications is provided below.

The MFW fast-acting feedwater valves and AFW cavitating venturis were considered to be potentially important to risk, as they were new components that were not modeled in the current PRA and may impact the function of the MFW and AFW systems, respectively.

Thus, these components were added to the BVPS-1 PRA model. Since similar components were modeled in the BVPS-2 PRA model, their failure rates were assumed to be applicable to BVPS-1 also. Results from the re-evaluation, as addressed in response to RAI question 3, indicate that these components are not significant contributors to risk.

The fast-acting feedwater valves have a Fussell-Vesely of 1.05E-07 each, and the cavitating venturis have a Fussell-Vesely of 1.90E-09 each.

The charging system modifications (rethrottling and rotating assembly replacement) were included in the thermal-hydraulic Modular Accident Analysis Program (MAAP) to evaluate their impact on the PRA model success criteria at EPU conditions. It was concluded that these modifications have no impact on the success criteria due to the EPU, as all the pre-EPU modeling success criteria remained valid for the post-EPU conditions (one auxiliary feedwater pump delivering flow to one steam generator provided enough heat removal capability at BVPS-1, even with the AFW cavitating venturis installed, to prevent core damage).

The replacement steam generator (RSG) level transmitters at BVPS-1 are not explicitly modeled in the PRA, and will not impact any modeled component or success criteria. The feedwater valve replacements at BVPS-2 are considered to be a one-for-one replacement for PRA modeling purposes, and also will not impact any modeled component or success criteria. Therefore, these modifications were not considered further.

The RSG was addressed by a re-calculation of the steam generator tube rupture (SGTR) initiating event frequency to account for the improved Alloy 690 material used for the replacement steam generator U-tubes. The methodology for this re-calculation is provided in the response to RAI question 4. The RSG SGTR initiating event frequency was calculated to be 6.96E-04 /year per steam generator versus 1.48E-03 per steam generator in the original steam generator model. The contribution to core damage frequency (CDF) due to SGTRs is 1.71 E-07 /year per steam generator for the replacement steam generator EPU model. This contribution is based on the re-evaluation as addressed in RAI question 3. The contribution to CDF from SGTRs for the original steam generator EPU model is 3.93E-07 /year per steam generator. Thus, it can be seen that both the SGTR initiating frequency and the contribution to CDF decrease with the replacement steam generator.

L-05-140 Enclosure 1 Page 4 of 34 Figure 1-1 Is the modified system or component currently modeled in the PRA?

NO0l Is the modification considered potentially important to plant risk?

NO YES YES YES Further evaluation of plant modification for risk impact is required.

Does the change impact the system performance in a potentially negative or non-conservative manner?

NO Does the change impact the system design in such a way as to alter system reliability models?

YES NO I Does the change impact the support function of the system in such a way as to alter the dependencies in the model?

NOD IF YES Modification can be screened from post-EPU PRA model, since there is no expected Impact on system functions or component reliability.

L-05-140 Enclosure 1 Page 5 of 34 Question

2.

Section 10.16.1.4 of Reference 2, discusses the impact of EPU conversion on the human reliability analysis (HRA). The major impact is that the time available to perform some operator actions had decreased. In some cases, the base PRA model used a conservative estimate of the time available, which is taken in the analysis to bound the post-EPU time. The NRC staff notes that use of bounding times can mask the actual change in risk, although such practice should result in a bounding estimate of risk. The following clarifications and additional information are needed to facilitate determining the overall impact of EPU on the HRA.

Question

a.

For both units, please provide the detailed HRA for all human interactions

("operator actions") that (1) have a Fussell-Vesely importance measure greater than 0.005 or a risk-achievement worth greater than 2, or (2) were modified to represent the post-EPU plant. Include whether the time available is considered "bounding" or is best estimate for pre-and post-EPU conditions.

Response

The following tables provide the Fussell-Vesely importance measures, risk achievement worth, and basis for the time available to perform the operator action used in the HRA for all BVPS-1 and BVPS-2 human interactions that:

(1) have a Fussell-Vesely importance measure greater than 0.005 or a risk achievement worth greater than 2.0 for the pre-EPU and post-EPU conditions, or (2) were modified to represent the post-EPU plant.

It should be noted that the post-EPU importance measures are based on the realistic human error probability (HEP) values that were reassessed using MAAP results to determine a best estimate of the time available, and the requantified PRA model used to address RAI question 3.

Table 2-1 identifies the BVPS-1 pre-EPU operator actions that have either a Fussell-Vesely importance greater than 0.005, or a risk achievement worth of greater than 2.0. All of these pre-EPU human actions were evaluated using best estimate hand calculations to determine the time available to perform the action.

L-05-140 Enclosure 1 Page 6 of 34 Table 2-1. BVPS-1 Pre-EPU Risk Significant Operator Action Importance Measures Basic Fussell-Risk Time Event Description Vesely Achievement Available Importance Worth Basis Operators setup portable fans &

Best OPRBV3 open doors to cool Emergency 1.38E-01 2.62E+00 Estimate

__________Switchgqear.

Operator cools down &

OPRCD3 depressurizes the RCS using 7.88E-03 2.54E+00 Best OPC3 atmospheric steam dumps or 78E3Estimate RHR valve during a SGTR.

Operator depressurizes RCS to LHSI entry conditions by using Best OPRCD6 pressurizer PORVs; given a 5.02E-02 1.96E+00 Estimate Small Break LOCA and failure of HHSI.

Operator depressurizes RCS to LHSI entry conditions by using Best OPRCD7 pressurizer PORVs; given a 4.76E-02 1.31 E+00 Estimate Small Break LOCA and failure of HHSI and AC Orange power.

Operator initiates Bleed & Feed OPROB2 when AFW fails, given that 1.55E-02 2.13E+00 Best OPO2 DAFW and MFW restoration was 15E2 23+O Estimate not attempted.

OPROCI Operator trips the RCPs during a 8.16E-03 2.70E+00 Best

_____loss of all CCR.

Estimate Operator depressurizes RCS to OPOi RHR and LHSI entry conditions 24E3 23+OBest OPROD1 b~~~lngpr~sieizer~~~~~ns 2.44E-03 2.53E+00 OLtjmst by using pressurizer PORVs or Estimate sprays; cooldown is successful.

OPROS6 Operator manually initiates safety 2.44E-03 3.99E+00 Besti injection given failure of SSPS.

______Estimate OPRSL1 Operator identifies ruptured S/G 5.30E-03 2.54E+00 Best

______and initiates isolation.

Estimate ORI3 Operator locally gags a stuck 23E0 11E00Best OPRSL3 open S/G safety relief valve.

235E-02 11OE+00 Estimate Operator manually aligns OPRWAI Auxiliary River Water pump when 5.1 7E-03 1.6E00Best main RW pumps fail given that Estimate Offsite Power is available.

Operator aligns makeup to the Best OPRWM1 RWST, given a SGTR with 4.70E-02 6.75E+00 Estimate secondary leakage.

Estimate I

L-05-140 Enclosure 1 Page 7 of 34 Table 2-2 identifies the BVPS-2 pre-EPU operator actions that have either a Fussell-Vesely importance greater than 0.005, or a risk achievement worth of greater than 2.0. All of these pre-EPU human actions were evaluated using a hand calculation best estimate time available to perform the action.

Table 2-2. SVPS-2 Pre-EPU Risk Sianificant Onerator Action Imnortance Measures Basic Fussell-Risk Time Event Description Vesely Achievement Available Importance Worth Basis Operator depressurizes RCS Best OPRCD3 using atmospheric steam dumps -

1.50E-03 2.03E+00 Estimate SGTR Estimate Operator depressurizes RCS to OPRCD6 LHSI entry conditions by using 2.48E 02 1.31 E+00 Best pressurizer PORVs given a Small

.E-Estimate Break LOCA and failure of HHSI.

Operator initiates Bleed & Feed, Best OPROB1 after attempting to realign MFW 6.46E-02 1.66E+01 Estimate OPROB2 Operator initiates Bleed & Feed, 3.28E-02 1.89E+00 Best OPO2 MEW restoration not attempted' 32E0I.8E0 Estimate OPRODI Operator depressurizes 1.23E-03 2.03E+00 Best LHSIIRHS entry conditions 1_____________0 Estimate OPROF2 Operator realigns main feedwater 1.38E-03 5.06E+00 Best OP 2

-no Si 13E3 50E0 Estimate OPO6 Operator manually actuates AFW 4.24E-03 5.23E+00 Best OPROS6 following transient Estimate OPROT1 Operator manually trips reactor 2.36E-03 2.88E+00 Best OPOI within 1 minute Estimate OPRSL1 Operator identifies ruptured S/G 5.69E-03 2.03E+00 Best OPRand initiates isolation to Estimate OPW 1 Operator aligns makeup to RWST 2.19E-02 4.61 E+00 Best OPW 1

- SGTR with secondary leakage

______________Estimate Table 2-3 identifies the BVPS-1 post-EPU operator actions that have either a Fussell-Vesely importance greater than 0.005, or a risk achievement worth of greater than 2.0. These importance measures are based on the reassessment of the HEP values and requantification of the post-EPU PRA model used to address the issues raised in RAI question 3. All of these post-EPU human actions were reassessed using the MAAP results for the time available to perform the action, and are considered best estimates.

L-05-140 Enclosure 1 Page 8 of 34 Table 2-3. BVPS-1 Post-EPU Risk Significant Operator Action Importance Measures Basic Fussell-Risk Time Event Description Vesely Achievement Available Importance Worth Basis Operator depressurizes the RCS to 400 psig by dumping steam through the intact steam Best OPRCD3 generator atmospheric steam 1.05E-02 3.48E+00 Estimate dumps to depressurize and cool down the secondary side (SGTR).

Operator depressurizes the RCS to 400 psig by locally Best OPRCD5 manipulating the steam generator 5.90E-03 1.22E+00 esti atmospheric steam dumps to Estimate relieve steam during a SBO.

Operator depressurizes the RCS to 400 psig by dumping steam through the steam generator Best OPRCD6 atmospheric steam dumps to 1.43E-01 4.09E+00 Estimate depressurize and cool down the secondary side (SGTR with HHSI has failed).

Operator depressurizes the RCS to 400 psig by locally manipulating the steam generator Best OPRCD7 atmospheric steam dumps to 1.55E-01 2.14E+00 Estimate relief steam, given HHSI failure and loss of emergency AC oran ge.

Operators provide borated makeup water to the RWST OPRMU5 initially from the spent fuel pool, 1.02E-02 2.63E+00 Best and, in the long term, from Estimate blending operations following an ISLOCA.

Operator starts charginglHHSI OPROA1 pumps and aligns an appropriate 4.1 1 E-04 2.06E+00 Best OPOI flow path for boron injection after Estimate an ATWS event.

OPROC1 Operator trips RCP during loss of 2.12E-02 5.40E+00 Best OPOI CCR Estimate OPROC2 Operator trips RCP during loss of 5.30E-03 2.10E+00 est OPO2 all seal cooling.

53E3 20+0 Estimate Operator depressurizes RCS to Best OPRODI RHS entry conditions using 3.53E-03 3.48E+00 Estimate pressurizer spray/PORVs.

Estimate

L-05-140 Enclosure 1 Page 9 of 34 Table 2-3. BVPS-1 Post-EPU Risk Significant Operator Act on Importance Measures Basic Fussell-Risk Time Event Description Vesely Achievement Available Importance Worth Basis Operator starts diesel driven Best OPROF6 AFW pump and manually 9.66E-03 1.49E+00 Estimate controls MFW bypass valve.

Estimate Operators protect RSS pumps by OPROP1 stopping them (QS failure) 1.27E-02 1.22E+00 Best restrtig whn tere s sfficentEstimate water in the sump.

Operator manually actuates safety injection and verifies operation of certain safety equipment on loss of SSPS due OPROS1 to actuation relay failure given a 8.78E-03 2.14E+00 Best transient initiating event that Estimate leads to Si conditions. On failure of manual safety injection actuation, the operator manually aligns the safety equipment.

Operator starts AFW given failure OPROS6 of SSPS for sequences in which 1.21 E-02 1.18E+01 Best there is no safety injection; e.g.,

Estimate turbine trip sequences.

Operator identifies the ruptured steam generator, and isolates or Best OPRSL1 verifies closed all flow paths to 8.58E-03 3.49E+00 Estimate and from that steam generator, following an SGTR event.

Operators locally gag the stuck-Best -

OPRSL3 open steam relief valves during 3.80E-02 1.17E+00 Estimate the SGTR event.

Operator manually starts and OPRWAI aligns auxiliary river water pumps 3.03E-02 4.85E+00 Best to the required river water header Estimate given no LOSP.

Operator supplies borated makeup water to the RWST OPRWM1 initially from the spent fuel pool, 7.17E-02 1.03E+01 Best OPW1 and, in the long term, from Estimate blending operations during an SGTR event.

L-05-140 Enclosure 1 Page 10 of 34 Table 2-4 identifies the BVPS-2 post-EPU operator actions that have either a Fussell-Vesely importance greater than 0.005, or a risk achievement worth of greater than 2.0. These importance measures are based on the reassessment of the HEP values and requantification of the post-EPU PRA model used to address the issues raised in RAI question 3. All of these post-EPU human actions were reassessed using the MAAP results for the time available to perform the action, and are considered best estimates.

Table 2-4. BVPS-2 Post-EPU Risk Significant Operator Action Importance Measures Basic Fussell-Risk Time Event Description Vesely Achievement Available Importance Worth Basis Operator depressurizes the Reactor Coolant System (RCS) to 400 psig by dumping steam OPRCD3 through the intact steam generator 1.22E-03 2.01 E+00 Best atmospheric steam dumps to Estimate depressurize and cool down the secondary side (SGTR).

Operator depressurizes the Reactor Coolant System (RCS) to 400 psig by dumping steam through the steam generator Best OPRCD6 atmospheric steam dumps to 2.51 E-02 1.30E+00 Estimate depressurize and cool down the secondary side (small LOCA with HHSI failed).

Not impacted by EPU.

Operator cross-ties station instrument air to containment Best~

OPRICI instrument air. t

.04E-02 I.20E+OO Estimate Not impacted by EPU.

Operators initiate bleed-and-feed operation by initiating safety injection, opening the PORVs, Best OPROB1 reopening the PORV block valves, 6.94E-02 1.69E+01 Estimate and verifying HHSI pump operation.

Not impacted by EPU.

Operators initiate bleed-and-feed operation by initiating safety injection, opening the PORVs, reopening the PORV block valves, B

OPROB2 and verifying HHSI pump 3.49E-02 1.88E+00 Estimate operation. Actions take place after the operators fail to attempt to restore MFW.

Not impacted by EPU.

L-05-140 Enclosure 1 Page 11 of 34 Table 2-4. BVPS-2 Post-EPU Risk Significan Operator Acti n Importance Measures Basic Fussell-Risk Time Event Description Vesely Achievement Available Importance Worth Basis Operator depressurizes RCS to Residual Heat Removal System (RHS) entry conditions after dumping steam via the atmospheric steam dumps to cool Best OPRODi down the RCS, and to 1.OSE-03 2.OOE+0O Estimate depressurize the RCS by using pressurizer spray/PORVs following a steam generator tube rupture (SGTR) event.

Operator opens main feed bypass OPROF2 valves following a partial 191E03 529E+00 Best feedwater isolation event after a Estimate plant trip.

Operator starts AFW given failure of SSPS for sequences in which Best OPROS6 there is no safety injection; for 4.23E-03 5.23E+00 Estimate example, turbine trip sequences.

Not impacted by EPU.

Operator pushes the manual reactor trip buttons after the Solid State Protection System (SSPS)

Best OPROT1 fails to automatically actuate 2.53E-03 2.87E+00 Estimate reactor trip in response to a plant trip condition.

Not impacted by EPU.

Operator identifies the ruptured steam generator, and isolates or Best OPRSL1 verifies closed all flow paths to 3.73E-03 2.01 E+00 Estimate and from that steam generator, following an SGTR event.

Operators locally gag the stuck-Best OPRSL3 open steam relief valves during an 1.48E-02 1.OQE+00 Estimate SGTR event.

Operator supplies borated makeup water to the RWST initially from the spent fuel pool, Best OPRWM1 and in the long term, with makeup 1.91 E-02 4.19E+00 Estimate from service water during an SGTR event.

Not impacted by EPU.

L-05-140 Enclosure 1 Page 12 of 34 Table 2-5 identifies the remaining BVPS-1 post-EPU operator actions that were modified using realistic HEPs to represent the post-EPU plant, but did not have a Fussell-Vesely importance greater than 0.005, or a risk achievement worth of greater than 2.0. These importance measures are based on the reassessment of the HEP values and requantification of the post-EPU PRA model used to address the issues raised in RAI question 3. All of these post-EPU human actions were reassessed using the MAAP results for the time available to perform the action, and are considered best estimates.

Table 2-5. BVPS-1 Post-EPU Non-Risk Significant Operator Action Importance Measures Basic Fussell-Risk Time Event Description Vesely Achievement Available Importance Worth Basis Operator depressurizes the RCS to 400 psig by dumping steam through the steam generator atmospheric steam dumps to OPRCD4 depressurize and cool down the secondary side (SGTR given AC 1.36E-04 1.OOE+00 Best orange power has failed, and operators have to locally manipulate the steam generator atmospheric steam dumps to cooldown.)

Operator manually aligns power supply for the standby HHSI Best OPRHH1 pump, starts and aligns the pump 1.52E-03 1.48E+00 Estimate to provide the necessary flow after a small LOCA event.

OPRHH2 Operators fail to properly monitor Best plant parameters and prematurely NIA 1.OOE+00 Estimate secure the safety injection system.

Operators align main feedwater or OPROF1 the dedicated auxiliary feed pump Best given the auxiliary feedwater was 8.75E-05 1.66E+00 Estimate successful, but makeup to the PPDWST failed.

Operators manually initiate recirculation mode of operation by starting the RSS pumps, aligning OPROR1 power supplies to appropriate Best RSS equipment, resetting safety I.92E-06 1.OOE+00 Estimate injection system and verifying RW flow to RSS headers, following a small LOCA event.

Operators align outside OPROR2 recirculation spray trains A or B to Best the LHSI flow path for high 5.49E-05 1.02E+00 Estimate pressure recirculation, given that both LHSI supply trains fail.

L-05-140 Enclosure I Page 13 of 34 Table 2-5. BVPS-1 Post-EPU Non-Risk Signifi ant Operator Ac tion Importance Measures Basic Fussell-Risk Time Event Description Vesely Achievement Available Importance Worth Basis Operator manually actuates safety injection and verifies operation of OPROS2 certain safety equipment on small Best LOCA or steam line break. On 2.65E-03 1.34E+00 Estimate failure of manual safety injection actuation, the operator manually aligns the safety equipment.

Operator manually actuates safety injection and verifies operation of OPROS3 certain safety equipment on Best medium LOCA. On failure of 2.17E-04 1.01 E+00 Estimate manual safety injection actuation, the operator manually aligns the safety equipment.

Operators locally close the steam OPRSL2 generator steam valves given that Best these valves cannot be closed 1.55E-04 1.03E+00 Estimate remotely during an SGTR accident.

Table 2-6 identifies the remaining BVPS-2 post-EPU operator actions that were modified using realistic HEPs to represent the post-EPU plant, but did not have a Fussell-Vesely importance greater than 0.005, or a risk achievement worth of greater than 2.0. These importance measures are based on the reassessment of the HEP values and requantification of the post-EPU PRA model used to address the issues raised in RAI question 3. All of these post-EPU human actions were reassessed using the MAAP results for the time available to perform the action, and are considered best estimates.

Table 2-6. BVPS-2 Post-EPU Non-Risk Significant Operator Action Importance Measures Basic Fussell-Risk Time Event Description Vesely Achievement Available Importance Worth Basis Operator depressurizes the Reactor Coolant System (RCS) to 400 psig by dumping steam Best OPRCDI through the steam generator 2.77E-05 1.03E+00 Estimate atmospheric steam dumps to depressurize and cool down the secondary side (small LOCA).

This is the same as CD1 except that AC Orange power has failed OPRCD2 and operators have to locally B.esE+00 1.t0E+00 Best manipulate the steam generator 0OE0

.E+

Estimate atmospheric steam dumps to cool down.

L-05-140 Enclosure 1 Page 14 of 34 Table 2-6. BVPS-2 Post-EPU Non-Risk Significant Operator Action Importance Measurps Basic Fussell-Risk Time Event Description Vesely Achievement Available Importance Worth Basis Operator depressurizes the Reactor Coolant System (RCS) to 400 psig by dumping steam through the steam generator atmospheric steam dumps to OPC4 depressurize and cool down the 5.27E-06 1.00E+00 Best OPRCD4 secondary side (SGTR, AC Estimate Orange power has failed, and operators have to locally manipulate the steam generator atmospheric steam dumps to cool dow n)._

Operator manually aligns power supply for the standby HHSI Best OPRHH1 pump, and starts and aligns the 1.76E-04 1.07E+00 Estimate pump to provide the necessary flow after a small LOCA event.

Operators fail to properly monitor OPRHH2 plant parameters and prematurely 1.12E-04 1.25E+00 Best secure the safety injection system.

Estimate Operators provide borated makeup water to the RWST initially from the spent fuel pool, Best OPRMU1 and in the long term, with makeup 0.OOE+00 1.OOE+00 Est from service water following a stmate transient-initiated small LOCA or SGTR.

This is the same as MUl except Best OPRMU2 that the actions follow a small 1.14E-03 1.21 E+00 est LOCA event.

Estimate This is the same as MUI except OPRMU3 that the actions follow a medium 1.37E-05 1.OOE+00 Best LOCA event.

Estimate Operators manually initiate recirculation mode of operation by starting the Recirculation Spray System (RSS) pumps, aligning power supplies to appropriate Best OPRORi RSS equipment, resetting safety 1.39E-04 1.13E+00 Estimate injection system, and verifying service water flow to RSS headers, following a small LOCA event.

L-05-140 Enclosure 1 Page 15 of 34 Table 2-6. BVPS-2 Post-EPU Non-Risk Significant Operator Action Importance Measures Basic Fussell-Risk Time Event Description Vesely Achievement Available Importance Worth Basis Operator manually actuates safety injection and verifies operation of certain safety equipment on loss of both trains of SSPS due to actuation relay failure. On failure OPO1 of manual safety injection 3.0E0 12E 0

Best OPROSI actuation, the operator manually Estimate aligns the safety equipment.

Though there is no LOCA present, a valid safety injection condition has occurred; for example, steamline break.

Operator manually actuates safety injection and verifies operation of certain safety equipment on loss of both trains of SSPS due to Best OPROS2 actuation relay failure. On failure 9.46E-04 1.07E+00 Estimate of manual safety injection actuation, the operator manually aligns the safety equipment.

Following a small LOCA Operator manually actuates safety injection and verifies operation of certain safety equipment on loss of both trains of SSPS due to OPROS3 actuation relay failure. On failure 4.17E-05 1.OOE+00 est of manual safety injection Estimate actuation, the operator manually aligns the safety equipment.

Following a medium LOCA OPRPRI Operator secures safety injection 11Best before PORVs are challenged.

1.71 E03 Estimate Operators locally close the steam generator steam valves given that Best OPRSL2 these valves cannot be closed 1.97E-04 1.06E+00 Estimate remotely during an SGTR accident.

All of the operator actions identified in the Tables 2-1 through 2-6 meet the criteria of either having a Fussell-Vesely importance measure greater than 0.005 or a risk achievement worth greater than 2, or were modified to represent the post-EPU plant using best estimate times to develop realistic HEPs (see response to RAI question 3). The human reliability analysis for all of these operator actions used the success likelihood index methodology (SLIM). As such, the SLIM process evaluates groups of human actions. Therefore, all human actions contained in the SLIM grouping are included in with the details of the operator actions identified in Tables 2-1 through 2-6.

L-05-140 Enclosure 1 Page 16 of 34 The details of the HRA for the operator actions are provided in the attached SLIM worksheets (included as Attachments 1 - 4 to Enclosure 1), which provide the rankings, weightings, and HEP mean values for each human interaction within the group. For BVPS-1, all pre-EPU human action SLIM worksheets are provided in Attachment 1, while Attachment 2 provides the BVPS-1 post-EPU human action SLIM worksheets which were reassessed in response to RAI question 3. Attachments 3 and 4 provide the SLIM worksheets for the pre-EPU and post-EPU reassessed human actions for BVPS-2, respectively.

Question

b.

Table 10.1 6-5 provides post-EPU importance measures for selected operator actions. (1) Which unit PRA model was used to generate these importance measures? (2) Are the operator actions in this table, which are of the form "OPR*," the same as the corresponding actions in Table 10.16-2, which are designated "ZHE*" (where "*" represents an alphanumeric string).

Response

The first two sheets of Table 10.16-5 (L-05-104 Enclosure 1, pages 21 and 22 of 32) were generated using the BVPS-1 EPU PRA model. The second two sheets of Table 10.16-5 (L-05-104 Enclosure 1, pages 23 and 24 of 32) were generated using the BVPS-2 EPU PRA model.

The operator actions listed in Table 10.16-5 (UOPR*" designators) are the basic event identifiers used in the top event fault tree models. The operator actions listed in Table 10.16-2 ("ZHE*" designators) are the RISKMAN database HEP distribution identifiers used to quantify the basic events. Typically, these correspond directly to each other (OPRAF1 and ZHEAF1 are the same action). However, there are some cases where they do not correspond directly to each other. The following list includes the exceptions to the rule.

BVPS-1:

OPRCC3 is quantified using ZHECC1 OPRDF1 is quantified using ZHEOF1 OPRHH3 is quantified using ZHEHH1 OPRHH4 is quantified using 1.0 OPRNA1 is quantified using 1.OOE-02

L-05-140 Enclosure 1 Page 17 of 34 BVPS-2:

OPRCC3 is quantified using ZHECC1 OPRHH3 is quantified using ZHEHH1 OPRPR2 is quantified using ZHEPII OPRMU4 is quantified using 1.0 OPROS4 is quantified using 1.0 OPRPR1 is quantified using 1.0 OPRRI2 is quantified using 1.0 OPRSL3 is quantified using 1.0 OPRXT3 is quantified using 1.0 Question

c.

Table 10.1 6-1 gives pre-and post-EPU times to core damage for station blackout scenarios. Why does this time increase on BVPS-1 and decrease on BVPS-2 for the "182 gpm, successful cooldown/depressurization, primary plant demineralized water storage tank make-up available" case?

Response

The increase in time to core damage for the BVPS-1, 182 gpm reactor coolant pump (RCP) seal LOCA with successful cooldown/depressurization and primary plant demineralized water storage tank (PPDWST) make-up available case is primarily due to changes in the primary system water mass used in the MAAP parameter file for the pre-to post-EPU/ replacement steam generators (RSG) conditions.

This key difference in the BVPS-1 MAAP inputs is that the initial primary system water mass (excluding the pressurizer) for the EPU model is 388,127 lbs. vs. 382,073 lbs. for the pre-EPU model MAAP analysis. Thus, the EPU model has about 1.5% more water mass in the primary system. This initial mass difference is due to a slightly larger primary side volume for the RSG's as compared to the original steam generators (OSG). The total primary side volume of one steam generator is 1136 ft3 for the RSG and 1087 ft3 for the OSG.

The impact of this change is subtle and does not appear to have a significant impact on thermal-hydraulic (T/H) behavior. Both the pre-and post-EPU cases behave similarly for the first 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months except for a time shift due to differences in time of seal binding failure (30 minutes for the pre-EPU case and 13 minutes for the post-EPU case). Around 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months , the two cases have different pressurizer behavior and the T/H results begin to diverge. Thus, there appears to be some beneficial impact from the RSGs due to an increased primary side initial inventory.

L-05-140 Enclosure 1 Page 18 of 34 Moreover, the effects of the increased inventory are more pronounced for the 182 gpm with successful cooldown/depressurization and PPDWST make-up available case, where the RCS inventory loss out the RCP seal LOCA is the governing circumstance to core uncovery, as opposed to the 21 gpm break sizes and PPDWST depletion cases where decay heat removal capability governs the time to core uncovery.

As expected, since the BVPS-2 RCS volume remained essentially the same for the pre-to post-EPU MAAP analysis, all BVPS-2 EPU cases provided in Table 10.16-1 resulted in a decrease in the time to core damage, due to the increase in decay heat associated with the power uprate.

Question

d.

Under the discussion of "general transients," it states: "Thus, with the RSG [replacement steam generators] there is less margin for successful completion of the plant-specific feed and bleed procedure... initiated at 0.495 hours0.00573 days 0.138 hours 8.184524e-4 weeks 1.883475e-4 months ...." Does the time available for this action change under EPU conditions? What is the human error probability (HEP) for this action, both pre-and post-EPU? Why was this action not included in Table 10.16-2 or 10.16-5?

Response

The general transient success criteria discussion presented in LAR 302 & 173 (L-05-104) was based on a loss of all feedwater (both main and auxiliary), with credit for operators to initiate feed and bleed at 13% wide range SG level per the plant procedures. This stemmed from a Westinghouse Owner's Group issue regarding the required component success criteria for feed and bleed implementation (number of power operated relief valves (PORVs) and high head safety injection (HHSI) pumps). To address this concern for EPU conditions, a MAAP analysis was performed assuming that one HHSI pump injects and one PORV was opened once the replacement steam generator reached the 13% wide range level, which occurred at 0.495 hours0.00573 days 0.138 hours 8.184524e-4 weeks 1.883475e-4 months . The results of this analysis showed that even at EPU conditions the feed and bleed component success criteria did not change from the current plant model (one HHSI pump and one PORV).

The timing used for the operator action to initiate feed and bleed developed for the human reliability analysis (HRA) was based on the maximum time that operators have available in order to successfully implement feed and bleed. In the thermal-hydraulic hand calculations developed for the Individual Plant Examination (IPE) human action accident scenarios, the time for feed and bleed implementation was based on the time for the PORVs to lift prior to steam generator dryout. This was estimated to occur 5 minutes prior to dryout, or at about 58 minutes following a reactor trip.

Since this time was shorter than the corresponding time of 63 minutes in a similar EPU MAAP analysis (a station blackout scenario with a 21 gpm RCP seal LOCA and loss of all feedwater), the IPE time value was bounding. Therefore, the HEPs used in the current PRA models (BVPS-1: 1.22E-03 for OPROB1, and 1.39E-02 for OPROB2; BVPS-2:

4.34E-03 for OB1, and 3.79E-02 for OB2) were bounding so the values were not changed for the EPU. As such, Tables 10.16-2 and 10.16-5, which listed operators actions that have changed for the EPU analyses, did not include these actions.

L-05-140 Enclosure 1 Page 19 of 34 Question

e.

Note 2 of Table 10.16-2 explains that the reduction in time available for a number of the operator actions is due to adopting a new reactor coolant pump seal loss-of-coolant accident model. Is this considered an EPU change?

Response

The RCP seal LOCA expected time of occurrence, due to seal popping or binding failures, was assumed to occur at 13 minutes in the post-EPU PRA models. This assumption was not a result of the EPU, but was made in order to have the PRA models reflect the most recent RCP seal LOCA issues that were approved by the NRC in their acceptance of WCAP-15603-A, Revision 1.

Question

f.

Note 3 of Table 10.16-2 refers to changes in HRA because the pre-EPU model did not credit resetting containment isolation phase B. Is this considered an EPU change?

Response

As noted in Note 3 of Table 10.16-2, the current (pre-EPU) HEP analyses takes credit for the operators resetting the containment isolation phase 'B' (CIB) signal and stopping the quench spray pumps, whereas the post-EPU HEP analyses does not.

The assumption of not resetting the CIB signal is not considered part of the EPU change but was done in order to maximize the impact of the EPU on the HEP by minimizing the time to transfer to safety injection recirculation mode. This timing was of interest for operator actions ZHECD1 and ZHECD2, where the operators are trying to depressurize the RCS below 400 psig. If core damage occurs due to additional equipment failures during the recirculation phase, the RCS would be at low pressure at the time of vessel melt-through. It is also of interest for operator actions ZHEMU1 and ZHEMU2, where the time to deplete the refueling water storage tank (RWST) is of relevance.

The operators actions to reset the CIB signal and stop quench spray flow are in the current plant procedures and will continue to be in the respective post-EPU emergency operating procedures.

Question

g.

Note 4 of Table 10.16-2 says that ZHEIAI is considered a "guaranteed success since the diesel air compressor will auto-start." Is this change due to a change to the plant equipment? Is it related to the EPU?

Response

The change in the diesel air compressor starting signal from manual to automatic was due to a physical plant modification that was implemented by ECP-02-0541. This modification installed a backup train of instrument air, comprised of a 1500 scfm diesel powered, oil free, rotary screw air compressor, which auto-starts upon a low system air pressure signal.

L-05-140 Enclosure 1 Page 20 of 34 This backup train of instrument air was not related to the EPU modifications, but rather was performed to increase the reliability of the station air supply.

Question

h.

Table 10.16-5 shows the Fussell-Vesely importance of operator action OPRIA1, "Given LOSP [loss of offsite power], operators locally start the diesel air compressor," as 6.13E-04. Is this the same operator action as ZHEIAI in Table 10.16-2? (It has the same description.) If "yes", how was the Fussell-Vesely determined, given that the HEP for ZHEIA1 is given as 0.0?

Response

Operator action ZHEIA1 is the same operator action as OPRIA1. ZHEIA1 is the RISKMAN database variable for the HEP and OPRIA1 is the PRA basic event for the operator action. ZHEIA1 is the operator action to manually start the diesel air compressor, and was evaluated using the time of the first RCP seal damage, given a loss of all seal cooling. As discussed in the response to RAI question 2.e, and shown in Table 10.16-2, this timing was changed from 60 minutes to 13 minutes for the post-EPU HRA. As such, it resulted in an increase in the HEP from 5.87E-03 to 1.18E-02.

However, as noted in the response to RAI question 2.g, there was a currently installed non-EPU change to auto-start the diesel air compressor. To represent this change in the post-EPU PRA model, the database variable ZHEIA1 was to be set to "guaranteed success" to accurately reflect the current plant conditions that would also be present following the EPU. This was considered necessary, since the post-EPU condition would have resulted in an increase in the HEP for the operator action to manually start the diesel air compressor, had it not already been changed to an auto-start feature.

It was later discovered (post-submiftal) that the change to make ZHEIA1 a "guaranteed success" was not incorporated into the post-EPU PRA model, and that the post-EPU adjusted value without the auto-start feature was used (1.18E-02). As such, a Fussell-Vesely importance value was calculated in the RISKMAN quantification and reported in Section 10.16 of Reference 2. However, as noted in the response to RAI question 2.g this change to the diesel air compressor starting circuit is not EPU related, so the HEP was set back to its pre-EPU normal value of 5.87E-03 used in the re-quantification to respond to RAI question 3.b.

It was also noted during this subsequent review that some of the other numbers listed in Table 10.6-2 of L-05-104 Enclosure I were not correctly identified. These include the following:

For BVPS-1, the true value of operator action ZHEIC2 that was used to quantify the pre-EPU (current) PRA model is 2.99E-03, not 2.73E-03.

For BVPS-2, the correct time available to complete the operator action used in the evaluation of ZHECD1 was 5.95 hours0.0011 days 0.0264 hours 1.570767e-4 weeks 3.61475e-5 months , not 12.3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months .

For BVPS-2, the correct time available to complete the operator action used in the evaluation of ZHECD2 was 5.9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months , not 12.3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months .

L-05-140 Enclosure 1 Page 21 of 34 Question

i.

Section 10.15 of Reference I states: "A review of operating procedures!

emergency operating procedures/training potentially impacted by EPU will be completed...." How was the full impact of the EPU on the human reliability analysis determined if operating procedure changes have not yet been identified?

Response

The full impact of the EPU on the human reliability analysis will be addressed during the PRA model update process following the EPU implementation. However, in order to address the impact of the EPU on the operator actions analyzed in the LAR, it was assumed that only the timings and stress levels could be significantly impacted by the EPU, and that the indications, proceduralized steps and operator actions would essentially remain unaffected. The basis for this assumption is provided below.

Application of the success likelihood index methodology (SLIM) to quantify the event-level dynamic operator actions in the plant response model of a PRA has been adopted at BVPS. It is based on the assumption that the HEP in a particular situation depends on the combined effects of a relatively small set of performance-shaping factors (PSF) that influence the operators' ability to perform the action successfully. The PSFs were selected to describe the range of problems that the operators face. They were chosen to relate the impact of the following:

The scenario in which the action must be accomplished. These include plant/operator interface and indications from instrumentation; adequacy of time to accomplish the action; preceding and concurrent actions; and the complexity of the task.

The psychological and cognitive condition of the operators during the scenario. This includes stress; training and experience relative to the action; and procedures or other operational aids available to the operators, and their performance up to the current point in the scenario.

Based on these PSFs, it was assumed that the scenario based plant/operator interface and indications, preceding and concurrent actions, and task complexity would not be significantly impacted enough by the EPU to warrant a change in their ranking.

Additionally, for the psychological and cognitive condition of the operators during the scenario, it was assumed that only the stress rankings of the operator actions that had significantly less time to complete due to the EPU conditions would be impacted.

L-05-140 Enclosure I Page 22 of 34 Question

j.

Are there any additional operator actions that are considered in the model for estimating large early release frequency (LERF)? Please provide a listing of any operator actions unique to LERF and an assessment of the impact of the EPU on the corresponding HEPs.

Response

All of the operator actions developed for the BVPS PRA models are contained in the plant model (Level 1) event trees used to calculate the core damage frequency, including actions for containment isolation and other actions important for estimating release frequencies. This approach, used in the BVPS PRA models, was selected for the following reasons:

All active systems, including the containment engineered safeguards, are included in the plant model event tree because their dependencies on support systems, such as electrical power and service water, can be determined more easily in the plant model event trees. This avoids the dependency tracking problems associated with placing certain active containment systems into the Level 2 containment event trees (CETs).

The prescribed boundary separates the phenomenological CET from the plant model event trees that deal only with active systems and operator actions with a well-defined interface.

The prescribed boundary facilitates a clean separation between analyses of likelihood (as measured by frequency) and uncertainty (as measured by probability).

This clean separation between plant model and CETs allows an optimization of both the plant analysis and the containment analysis, while at the same time providing needed flexibility in the modeling process. However, in doing so, all of the plant model information on the operability status of active systems important to the timing and magnitude of the release of radioactive materials must be passed into the CET when linked to the Level 1 event trees. This required that, in addition to representing the systems and functions that are important to keeping the core cooled, the plant model event trees had to also address active systems and functions important to containment isolation, containment heat removal, and removal of radioactivity from the containment atmosphere.

As such, there are no additional operator actions considered in the PRA models for estimating large early release frequency (LERF), and the Level 2 analyses are strictly based on containment phenomenology or events that have occurred during the core damage process. However, the operator actions that are modeled would have different importance measures based on their contribution to either CDF or LERF.

L-05-140 Enclosure 1 Page 23 of 34 Question

3.

Please provide an assessment of the increase in risk if only the EPU is considered.

For example, the impact of containment conversion, BVPS-1 replacement steam generators, BVPS-1 AFW cavitating venturis and MFW fast-acting isolation valves should not be included unless they are required for the EPU. Note that this can be done either by having non-EPU changes in both the base model and the post-EPU model or in neither.

The NRC staff would prefer that this assessment use realistic HEPs for both the pre-EPU and post-EPU analysis (where these would change) to avoid masking of the actual change in risk; refer to question 2, above. However, if bounding HEP numbers are employed, justify that the final risk metric is bounding with respect to those HEPs.

The following risk metrics should be provided for both BVPS-1 and 2:

a.

Internal events core damage frequency (CDF) and LERF.

b.

CDF and LERF from internal fires.

Response

As noted in Section 1.1.2 of Enclosure 2 of LAR 302 & 173, L-04-125, the principal modifications planned to support implementation of the EPU LAR analyses include:

Containment conversion from a sub-atmospheric to an atmospheric design basis including related modifications such as the addition of (fast-acting) feedwater isolation valves and auxiliary feedwater flow limiting (cavitating) venturis for BVPS-1 Replacement charging/safety injection pump rotating assemblies Replacement steam generators for BVPS-1 Since the above modifications are required to support the EPU, they were considered necessary and either explicitly or implicitly included in the EPU risk analysis (as addressed in the response to RAI question 1.b) in order to accurately determine the risk impact associated with the EPU.

Consequently, the only changes that were made to the post-EPU PRA models that were not associated with the EPU, were changes to the HEPs resulting from:

The change in timing of the RCP seal binding failure (see response to RAI question 2.e.)

Using conservative times to SI recirculation phase or RWST depletion by not crediting the resetting the CIB signal and stopping quench spray flow (see response to RAI question 2.f.)

Crediting the auto-start of the diesel air compressor by setting the HEP to zero (see response to RAI question 2.g.)

L-05-140 Enclosure 1 Page 24 of 34 Since the first two bulleted items above are not associated with the EPU, the impacted HEPs were reanalyzed excluding these changes, and instead used the pre-EPU PRA model assumptions. That is, the start of the increased RCP seal LOCA was assumed to occur at 60 minutes (based on NUREG-1 150) instead of the 13 minutes suggested in WCAP-15603-A, Revision 1, and credit was given for resetting the CIB signal and stopping quench spray flow, As noted in the response to RAI question 2.h, the third bulleted item was not included in the post-EPU PRA model, so the operator action to manually start the diesel air compressor was evaluated in the LAR 302 and 173 submittal using the post-EPU HEP, which reflected the change in timing of the RCP seal binding failure. In response to this RAI, the HEP for this operator action was set back to the pre-EPU value, since it removed the effects of non-EPU changes, as addressed below.

All of the operator actions impacted by excluding these non-EPU changes and using realistic HEPs developed from the MAAP result best estimate timings, when considering only the EPU related modifications, are presented in Table 3-1. This table complements Table 10.16-2 of Reference 2 to complete the full post-EPU HRA. This re-evaluation resulted in several changes, as outlined below:

In response to RAI question 2.e, since the new RCP seal LOCA model is not related to the EPU, all operator action times available were changed back to the pre-EPU model times available.

In response to RAI question 2.f, the HRA for the post-EPU model will use the operator action times available while taking credit for resetting the CIB signal and securing the quench spray system, as was done in the pre-EPU model.

In response to RAI question 2.g, the operator action OPRIA1 is no longer set to "guaranteed success," since the change to the diesel air compressor is not related to the EPU.

The HRA no longer uses the "bounding" operator action time available. Realistic timings are used, which resulted in decreasing many of the human error rates.

Table 3-1: Operator Action Human Error Probabilities Human Action Description Time PSF -

HEP -

1 Time PSF -

HEP - post-Available pre-EPU pre-EPU Available post-EPU EPU I pre-EPU post-EPU BVPS-11 OPROS2 - Operator manually actuates 0.67 hours7.75463e-4 days 0.0186 hours 1.107804e-4 weeks 2.54935e-5 months Time - 5 9.19E-03 0.94 hours0.00109 days 0.0261 hours 1.554233e-4 weeks 3.5767e-5 months Time - 3 7.68E-03 safety injection and verifies operation of certain safety equipment on small LOCA or steam line break. On failure of manual safety injection actuation, the operator manually aligns the safety equipment.

OPROS3 - Operator manually actuates 0.15 hours1.736111e-4 days 0.00417 hours 2.480159e-5 weeks 5.7075e-6 months Time -6 2.77E-02 0.35 hours4.050926e-4 days 0.00972 hours 5.787037e-5 weeks 1.33175e-5 months Time - 4 1.90E-02 safety injection and verifies operation of certain safety equipment on medium LOCA.

On failure of manual safety injection actuation, the operator manually aligns the safety equipment.

L-05-140 Enclosure 1 Page 25 of 34 Table 3-1: Operator Action Human Error Probabilities Human Action Description Time PSF -

HEP -

Time PSF -

HEP - post-Available pre-EPU pre-EPU Available post-EPU EPU pre-EPUpost-EPU OPRHH1 - Operator manually aligns power 0.67 hours7.75463e-4 days 0.0186 hours 1.107804e-4 weeks 2.54935e-5 months Time - 4 3.87E-03 0.94 hours0.00109 days 0.0261 hours 1.554233e-4 weeks 3.5767e-5 months Time - 2 3.13E-03 supply for the standby HHSI pump, starts and aligns the pump to provide the necessary Dow after a small LOCA event.

OPRHH2 - Operators fail to properly monitor 2.21 hours2.430556e-4 days 0.00583 hours 3.472222e-5 weeks 7.9905e-6 months Time - 3 7.15E-04 13.91 Time - 1 5.77E-04 plant parameters and prematurely secure the hours safety injection system.

OPROF1 - Operators align main feedwater 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Time - I 1.58E-04 10.34 Time -0 1.32E-04 or the dedicated auxiliary feed pump given hours the auxiliary feedwater was successful, but makeup to the PPDWST failed.

OPROR1 - Operators manually initiate 1.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months Time - 2 2.01E-03 2.82 hours9.490741e-4 days 0.0228 hours 1.35582e-4 weeks 3.1201e-5 months Time - 1 1.88E-03 recirculation mode of operation by starting the RSS pumps, aligning power supplies to appropriate RSS equipment, resetting safety injection system and verifying RW flow to RSS headers, following a small LOCA event.

OPROR2 - Operators align outside 1.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months Time - 2 2.85E-03 2.82 hours9.490741e-4 days 0.0228 hours 1.35582e-4 weeks 3.1201e-5 months Time - 1 2.60E-03 recirculation spray trains A or B to the LHSI flow path for high pressure recirculation.

given that both LHSI supply trains fail.

OPRODI - Operator depressurizes RCS to 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months lime - 1 1.58E-03

>24 hours Time - 0 1.42E-03 RHS entry conditions using pressurizer spray/PORVs.

OPRSL2 - Operators locally close the steam 9.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months Time - 2 5.52E-03 17.99 Time - I 4.96E-03 generator steam valves given that these hours valves cannot be closed remotely during an SGTR accident.

OPRCD3 - Operator depressurizes the RCS 11 hours1.273148e-4 days 0.00306 hours 1.818783e-5 weeks 4.1855e-6 months Time - 5 5.12E-03

> 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Time - 2 4.19E-03 to 400 psig by dumping steam through the intact steam generator atmospheric steam dumps to depressurize and cool down the secondary side (SGTR)

OPRCD4 - Operator depressurizes the RCS 11 hours1.273148e-4 days 0.00306 hours 1.818783e-5 weeks 4.1855e-6 months Time - 5 8.29E-02

> 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Time - 1 5.10E-02 to 400 psig by dumping steam through the steam generator atmospheric steam dumps to depressurize and cool down the secondary side (SGTR given AC orange power has failed, and operators have to locally manipulate the steam generator atmospheric steam dumps to cooldown.)

L-05-140 Enclosure 1 Page 26 of 34 Table 3-1: Onerator Action Human Error Probabilities Human Action Description Time PSF -

HEP -

Time PSF -

HEP - post-Available pre-EPU pre-EPU Available post-EPU EPU pre-EPU post-EPU OPRCD6 - Operator depressurizes the RCS 0.83 hours9.606481e-4 days 0.0231 hours 1.372354e-4 weeks 3.15815e-5 months Time - 3 4.99E-02 1.02 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Time - 2 4.40E-02 to 400 psig by dumping steam through the steam generator atmospheric steam dumps to depressurize and cool down the secondary side (SGTR with HHSI has failed).

OPRCD7 - Operator depressurizes the RCS 0.83 hours9.606481e-4 days 0.0231 hours 1.372354e-4 weeks 3.15815e-5 months Time - 5 1.35E-01 1.02 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Time - 4 1.20E-01 to 400 psig by locally manipulating the steam generator atmospheric steam dumps to relief steam, given HHSI failure and loss of emergency AC orange.

OPRWM1 - Operator supplies borated 21 hours2.430556e-4 days 0.00583 hours 3.472222e-5 weeks 7.9905e-6 months Time - 1 8.40E-03 30.46 Time - 0 7.68E-03 makeup water to the RWST initially from the hours spent fuel pool, and, in the long term, from blending operations during an SGTR event.

OPRWA1 - Operator manually starts and 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Time - 5 7.80E-03 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Time - 5 7.80E-03 aligns auxiliary river water pumps to the (was 13 required river water header given no LOSP.

minutes due to RCP seal leakage)

OPRIAI - Given LOSP, operators locally start 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Time - 1 5.84E-03 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Time - 1 5.84E-03 the diesel air compressor OPRIC2 - Operators cross-tie station 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Time - 5 2.99E-03 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Time - 5 2.99E-03 instrument air to containment Instrument air (was 13 by locally opening manual valve IA-90.

minutes due to RCP seal leakage)

OPRCD1 - Operator depressurizes the RCS 5.95 hours0.0011 days 0.0264 hours 1.570767e-4 weeks 3.61475e-5 months Time - 2 1.71E-03 6.63 hours7.291667e-4 days 0.0175 hours 1.041667e-4 weeks 2.39715e-5 months Time - 2 1.71E-03 to 400 psig by dumping steam through the (was 1.23 (time steam generator atmospheric steam dumps hours due difference to depressurize and cool down the secondary to CIB did not side (small LOCA).

setpoint) justify a change in PSF)

OPRCD2 - Same as OPRCD1 except that AC 5.9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months Time - 2 2.58E-03 11.6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Time -2 2.58E-03 orange power has failed and operators have (was 2.02 (time to locally manipulate the steam generator hours due difference atmospheric steam dumps to cooldown.

to CIB did not setpoint) justify a change in PSF)

OPRMU1 - Operators provide borated 4.03 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months Time - 1 8.40E-03 4.03 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months Time - 1 8.40E-03 makeup water to the RWST initially from the (was 0.46 spent fuel pool, and, in the long term, from hours due blending operations following a steam to CIB generator tube rupture event.

setpoint)

L-05-140 Enclosure 1 Page 27 of 34 Table 3-1: Operator Action Human Error Probabilities

{

Human Action Description Time PSF -

HEP -

Time PSF -

HEP - post-Available pre-EPU pre-EPU Available post-EPU EPU pre-EPU post-EPU OPRMU2 - Same as OPRMU1 except that 1.9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months Time - 3 1.01E-02 1.9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months Time - 3 1.01 E-02 the actions follow a small LOCA event.

(was 0.46 hours5.324074e-4 days 0.0128 hours 7.60582e-5 weeks 1.7503e-5 months due to CIB setpoint)

BVPS-2 OPROS2 - Operator manually actuates 0.67 hours7.75463e-4 days 0.0186 hours 1.107804e-4 weeks 2.54935e-5 months Time - 4 1.71 E-02 0.94 hours0.00109 days 0.0261 hours 1.554233e-4 weeks 3.5767e-5 months Time - 2 1.33E-02 safety Injection and verifies operation of certain safety equipment on loss of both trains of SSPS due to actuation relay failure.

On failure of manual safety injection actuation, the operator manually aligns the safety equipment. Following a small LOCA OPROS3 - Operator manually actuates 0.15 hours1.736111e-4 days 0.00417 hours 2.480159e-5 weeks 5.7075e-6 months Time -5 2.20E-02 0.28 hours3.240741e-4 days 0.00778 hours 4.62963e-5 weeks 1.0654e-5 months lime - 3 1.71E-02 safety injection and verifies operation of certain safety equipment on loss of both trains of SSPS due to actuation relay failure.

On failure of manual safety injection actuation, the operator manually aligns the safety equipment. Following a medium LOCA OPRHH1 - Operator manually aligns power 0.67 hours7.75463e-4 days 0.0186 hours 1.107804e-4 weeks 2.54935e-5 months Time - 4 3.29E-03 0.94 hours0.00109 days 0.0261 hours 1.554233e-4 weeks 3.5767e-5 months Time - 2 2.49E-03 supply for the standby HHSI pump, and starts and aligns the pump to provide the necessary flow after a small LOCA event.

OPRHH2 - Operators fail to properly monitor 5.56 hours6.481481e-4 days 0.0156 hours 9.259259e-5 weeks 2.1308e-5 months Time - 3 5.87E-04 19.62 Time - I 4.44E-04 plant parameters and prematurely secure the hours safety injection system.

OPROR1 - Operators manually initiate 0.95 hours0.0011 days 0.0264 hours 1.570767e-4 weeks 3.61475e-5 months Time - 2 1.38E-03 9.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months Time - 0 1.05E-03 recirculation mode of operation by starting the Recirculation Spray System (RSS) pumps, aligning power supplies to appropriate RSS equipment, resetting safety injection system, and verifying service water flow to RSS headers, following a small LOCA event.

OPROD1 - Operator depressurizes RCS to 14 hours1.62037e-4 days 0.00389 hours 2.314815e-5 weeks 5.327e-6 months Time - 1 1.20E-03

> 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Time -0 1.04E-03 Residual Heat Removal System (RHS) entry conditions after dumping steam via the atmospheric steam dumps to cool down the RCS, and to depressurize the RCS by using pressurizer spraylPORVs following a steam generator tube rupture (SGTR) event.

OPRSL1 - Operator identifies the ruptured 0.93 hours0.00108 days 0.0258 hours 1.537698e-4 weeks 3.53865e-5 months lime - 7 5.25E-03 1.6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Time - 5 3.63E-03 steam generator, and isolates or verifies closed all flow paths to and from that steam generator, following an SGTR event.

L-05-140 Enclosure 1 Page 28 of 34 Table 3-1: Operator Action Human Error Probabilities l

Human Action Description Time PSF -

HEP -

Time PSF -

HEP - post-Available pre-EPU pre-EPU Available post-EPU EPU pre-EPU post-EPU OPRSL2-Operators locally close the steam 11.2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Time - 2 4.33E-03

> 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Time - 0 3.28E-03 generator steam valves given that these valves cannot be closed remotely during an SGTR accident.

OPRSL3 - Operators locally gag the stuck-11.2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Time - 1 1.35E-01

> 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Time -0 1.18E-01 open steam relief valves during an SGTR (Assigned (Assigned event.

1.0) 1.0)

OPRSL4-Operator isolates ruptured steam 0.83 hours9.606481e-4 days 0.0231 hours 1.372354e-4 weeks 3.15815e-5 months Time - 7 3.41E-02 1.22 hours2.546296e-4 days 0.00611 hours 3.637566e-5 weeks 8.371e-6 months Time - 5 2.66E-02 generator given HHSI failed.

(Not used in PRA models)

OPRSL5 - Operator isolates ruptured steam 0.83 hours9.606481e-4 days 0.0231 hours 1.372354e-4 weeks 3.15815e-5 months Time - 8 1.09E-02 1.22 hours2.546296e-4 days 0.00611 hours 3.637566e-5 weeks 8.371e-6 months Time - 6 7.53E-03 generator given one train of emergency AC power and HHSI failed.

(Not used in PRA models)

OPRCD3-Operator depressurizes the 14 hours1.62037e-4 days 0.00389 hours 2.314815e-5 weeks 5.327e-6 months Time - 1 1.46E-03

> 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Time - 0 1.21 E-03 Reactor Coolant System (RCS) to 400 psig by dumping steam through the intact steam generator atmospheric steam dumps to depressurize and cool down the secondary side (SGTR).

OPRCD4 - Operator depressurizes the 14 hours1.62037e-4 days 0.00389 hours 2.314815e-5 weeks 5.327e-6 months Time - 4 1.04E-02

> 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Time - 0 4.99E-03 Reactor Coolant System (RCS) to 400 psig by dumping steam through the steam generator atmospheric steam dumps to depressurize and cool down the secondary side (SGTR, AC Orange power has failed, and operators have to locally manipulate the steam generator atmospheric steam dumps to cool down).

OPRMU1 - Operators provide borated 1.14 hours1.62037e-4 days 0.00389 hours 2.314815e-5 weeks 5.327e-6 months Time -3 5.97E-03 2.58 hours6.712963e-4 days 0.0161 hours 9.589947e-5 weeks 2.2069e-5 months Time - 2 5.45E-03 makeup water to the RWST initially from the spent fuel pool, and in the long term, with makeup from service water following a transient-initiated small LOCA or SGTR.

OPRMU2 - This is the same as OPRMU1 1.01 hours1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Time - 3 5.97E-03 2.58 hours6.712963e-4 days 0.0161 hours 9.589947e-5 weeks 2.2069e-5 months Time - 2 5.45E-03 except that the actions follow a small LOCA event.

OPRMU3 - This is the same as OPRMU1 1.3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months Time - 7 8.60E-03 2.67 hours7.75463e-4 days 0.0186 hours 1.107804e-4 weeks 2.54935e-5 months Time - 5 7.17E-03 except that the actions follow a medium LOCA event.

OPRMU4 -This is the same as OPRMU1 0.54 hours6.25e-4 days 0.015 hours 8.928571e-5 weeks 2.0547e-5 months Time - 9 1.03E-02 1.11 hours1.273148e-4 days 0.00306 hours 1.818783e-5 weeks 4.1855e-6 months Time -7 8.60E-03 except that the actions follow a large LOCA (Assigned (Assigned event.

1.0) -

1.0)

L-05-140 Enclosure 1 Page 29 of 34 Table 3-1: Operator Action Human Error Probabilities Human Action Description Time PSF -

HEP -

Time PSF -

HEP - post-Available pre-EPU pre-EPU Available post-EPU EPU pre-EPU post-EPU OPRPR1 - Operator secures safety injection 15 Time - 9 3.44 E-02 33 minutes Time - 8 2.65E-02 before PORVs are challenged.

minutes (Assigned (Assigned I

1.0) 1.0)

OPRCD1 - Operator depressurizes the 5.95 hours0.0011 days 0.0264 hours 1.570767e-4 weeks 3.61475e-5 months Time - 3 9.1OE-04 6.63 hours7.291667e-4 days 0.0175 hours 1.041667e-4 weeks 2.39715e-5 months Time - 1 6.88E-04 Reactor Coolant System (RCS) to 400 psig (was 1.04 by dumping steam through the steam hours due generator atmospheric steam dumps to to CIB depressurize and cool down the secondary setpoint) side (small LOCA).

OPRCD2 - This is the same as OPRCD1 5.9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months Time - 3 4.93E-03 11.6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Time - 1 3.73E-03 except that AC Orange power has failed and (was 3.62 operators have to locally manipulate the due to CIB steam generator atmospheric steam dumps setpoint) to cool down.

OPRWA1 - Operator manually stops the EDG 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Time - 6 7.93E-02 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Time - 6 7.93E-02 and racks the spare service water (SWS)

(was 13 pump onto the bus prior to restarting the EDG minutes during a loss of offsite power.

due to RCP seal leakage)

OPRCC1 - Operator starts the manual 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Time - 2 3.31E-03 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Time - 2 3.31E-03 standby component cooling pump (CCP) on (was 13 loss of the operating and the automatic minutes standby CCPs, to restore component cooling due to water (CCW) flow to the RCP thermal RCP seal barriers.

leakage)

OPRTB1 - Operator cross-ties station 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Time - 1 7.92E-04 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Time - 1 7.92E-04 instrument air to containment instrument air.

(was 13 minutes due to RCP seal leakage)

OPRTB2 - Operator resets containment 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Time - 1 1.12E-02 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Time - 1 1.12E-02 isolation Phase A (CIA) and restores (was 13 containment instrument air.

minutes due to RCP seal leakage)

The BVPS-1 and BVPS-2 post-EPU models were requantified using the above realistic operator action HEPs and removing the non-EPU associated modifications. The results from the requantification of the BVPS-1 and BVPS-2 post-EPU PRA models are presented in Tables 3-2 and 3-3, respectively.

L-05-140 Enclosure 1 Page 30 of 34 Table 3-2. BVPS-1 Pre-EPU and Post-EPU Core Damage Frequency Pre-EPU CDF Post-EPU CDF Delta CDF

(/year)

Internal 7.45E-06 6.53E-06

-9.15E-07 Events Fire 4.60E-06 4.59E-06

-1.44E-08 External 1.63E-05 1.63E-05

-1.50E-08 Events Total 2.37E-05 2.28E-05

-9.31 E-07 Table 3-3. BVPS-2 Pre-EPU and Post-EPU Core Damage Frequency Pre-EPU CDF Post-EPU CDF Delta CDF

(/year)

Internal 2.01 E-05 2.01 E-05

-6.OOE-09 Events Fire 5.29E-06 5.29E-06

-1.20E-09 External 1.48E-05 1.48E-05

-2.00E-09 Events Total 3.49E-05 3.49E-05

-8.OOE-09 In many instances, the best-estimate HEPs improved (the HEP decreased) as a result of the new analyses using MAAP results versus hand calculations. As a result, the BVPS-1 and BVPS-2 post-EPU PRA models indicate a decrease or no change in CDF, as shown above in Tables 3-2 and 3-3. The HEPs did not impact the BVPS-1 and BVPS-2 LERF values. Therefore, LERF remains as reported in Section 10.16 of Reference 2.

In addition to the change in timing of the RCP seal binding failure affecting some of the above reanalyzed HEPs, the post-EPU station blackout (SBO) MAAP analyses also assumed that the start of the increased RCP seal leakage started at 13 minutes, as opposed to the 30 minutes used in the pre-EPU MAAP analyses (based on WCAP-15603, Revision 0). The time to core damage from these pre-and post-EPU SBO MAAP analyses were used in the electric power recovery models.

For the pre-EPU SBO MAAP analyses, the impact of the change in the onset of the increased seal LOCA from 30 minutes to 13 minutes on the time to core damage was evaluated to assess the NRC concerns in approving WCAP-15603, Revision 1A. The results of this sensitivity assessment did not lead to any significant changes in the time to core damage. Thus, it was concluded that the time to core damage provided in the current, pre-EPU seal LOCA sequences, using the 30-minute timing, was sufficient to access the electric power recovery models.

L-05-140 Enclosure 1 Page 31 of 34 The impact of this change on the post-EPU PRA model was also assessed by performing sensitivity analyses. For the post-EPU SBO MAAP sensitivity analyses, the onset of the increased seal LOCA changed from 13 minutes back to 30 minutes. The results of this sensitivity assessment did not lead to any significant changes in the time to core damage.

Thus, it was concluded, over the spectrum of seal binding failure sizes, that the core damage timing difference between the pre-EPU and EPU models is due largely to the EPU design changes and not the start of the increased RCP seal leakage.

Moreover, there is an insignificant impact on CDF from the non-electric power recovery split fractions developed using the electric power recovery model whose time to core damage decreased by more than one minute from the change in timing of the RCP seal binding failure. All of these split fractions had Fussell-Vesely importance values less than 2E-04 and risk achievement worths less than 1.01. This shows that the impact of the time change in the RCP seal binding failure from 13 minutes to 30 minutes, or vice versa, on CDF is insignificant. Additionally, since over 99% of the LERF contribution is attributed to interfacing system LOCAs and SGTRs, the impact of this timing change on LERF is also expected to be insignificant.

Question

5.

What is the expected impact of EPU on the probability of consequential loss of offsite power (LOOP)? For each unit, provide the contribution to the total CDF from consequential LOOP events in the current model. Provide the same information for operation at EPU conditions, or provide a sensitivity analysis showing how CDF would change assuming the probability of consequential LOOP increases after EPU.

Response

The probability of a consequential LOOP is 2.66E-04 at both BVPS-1 and BVPS-2, and is not expected to be impacted by the EPU.

Studies were performed to evaluate the impact of BVPS EPU operation on the transmission system grid stability. The results of these studies yield generally comparable results to that obtained from the previous pre-EPU study. In addition, the 345 kV and 138 kV switchyards were also evaluated. This evaluation concluded equipment and components associated with the 345 kV and 138 kV overhead lines between the station and the switchyards are adequate under EPU conditions. The equipment and components in the 345 kV and 138 kV switchyards are also adequate under EPU conditions. As such, the plant response following a unit trip will be essentially the same following the EPU as it currently is modeled.

The contribution to the total CDF from consequential LOOP events for the current PRA models and EPU PRA models for both BVPS-1 and BVPS-2 are provided below:

BVPS-1:

Current PRA model = 2.62E-03 (0.26%)

EPU PRA model = 1.95E-03 (0.20%)

L-05-140 Enclosure I Page 32 of 34 BVPS-2:

Current PRA model = 1.22E-02 (1.22%)

EPU PRA model = 1.25E-02 (1.25%)

The slight decrease in the consequential LOOP contribution to the total CDF at BVPS-1 is attributed to the reduction in CDF due to the steam generator replacement, since there were several SGTR sequences involving consequential LOOPs. The consequential LOOP contributions to the total CDF at BVPS-2 remains essentially the same for both the current pre-EPU and post-EPU conditions.

Question

6.

The PRA results in the EPU risk assessment (Reference 2) were compared with those provided in a response to the NRC staff's questions on a recent license amendment request for extending the emergency diesel generator (EDG) allowed outage time (AOT) (Reference 3). The table below compares the Information.

EDG AOT (Ref. 3)

EPU (Ref. 2)

Beaver Valley Unit I PRA Model Designator BVI REV3 BVI REV3 Date Updated 912003 9/2003 CDF (per year) 2.34E-5 7.45E-6 LERF (per year) 1.03E-6 1.03E-6 Beaver Valley Unit 2 PRA Model Designator BV2 REV3B BV2 REV3D Date Updated 512003 5/2003 CDF (per year) 3.27E-5 2.01 E-5 LERF (per year) 1.12E-6 1.12E-6 Question

a.

What has changed in the BVPS-1 and BVPS-2 PRA models since the Reference 3 letter?

Response

The BVPS-1 and BVPS-2 baseline PRA models used in the EDG AOT analyses are the same as the BVPS-1 and BVPS-2 baseline PRA models used in the EPU analyses.

There were some changes associated with the EDG AOT PRA models for Case 1, which were noted in LAR 306 and 176, L-04-072 (dated May 26, 2004), Section 4.3.2, Page 15.

These consisted of the following:

L-05-140 Enclosure 1 Page 33 of 34 "Case 1 modeled the current EDG unavailability. This sensitivity case was run by changing the EDG unavailability from 2.5%, which is the current value used in the BVPS-1 and BVPS-2 baseline PRA models, to the present mean unavailability of the EDG under the current AOT or 0.77% (Unit 1) and 0.348% (Unit 2)."

The EPU baseline PRA models used the 2.5% EDG unavailability value. Additionally, the EPU PRA model include all of the modifications identified in Section 10.16.1.6 of L-05-104 (page 17 of 32). It should also be noted that BV2REV3B is the current model revision of record at BVPS-2; however, BV2REV3D was used in both the EDG AOT and EPU analyses, which removed common cause failures from the 4KV transformers.

Question

b.

Explain why BVPS-1 CDF has dropped significantly and BVPS-2 CDF has dropped somewhat compared to the Reference 3 values.

Response

The EPU CDF values in the comparison table provided with this RAI question are incorrect.

As stated in Section 10.16.1.6 of L-05-104 Enclosure 1 (page 18 of 32), "...the effect of the BVPS-1 EPU was to decrease the internal events CDF from 7.45E-06 per year to 6.85E-06 per year. This section also states that "...the effect of the BVPS-2 EPU was to increase the internal events CDF from 2.01 E-05 per year to 2.02E-05 per year..."

Moreover, the EPU CDF values provided in the comparison table are based on point estimate values and only include the core damage frequency associated with internal initiating events. The EDG AOT CDF values provided in the comparison table represents the total core damage frequency, including both internal and external initiating events.

Using the PRA baseline models and the information provided in Reference 3 for Case 1 (Tables 5 and 9 for BVPS-1 and BVPS-2, respectively), a better breakdown comparison between the Baseline PRA CDF, EDG AOT CDF, and EPU CDF are provided in Tables 6-1 and 6-2:

Table 6-1. BVPS-1 l

BASELINE PRA EDG AOT EPU (Ref. 2)

MODELS (Ref. 3)

________._)

Internal Events 7.45E-06 7.13E-06 6.85E-06 CDF Fire CDF 4.60E-06 4.69E-06 4.61 E-06 Seismic CDF 1.17E-05 1.17E-05 1.17E-05 Total CDF 2.37E-05 2.35E-05 2.31 E-05

L-0-14 Enlsr L-05-140 Enclosure 1 Page 34 of 34

[

Table 6-2. BVPS-2 BASELINE PRA EDG AOT EPU (Ref. 2)

MODELS (Ref. 3) l

___(ef_2 Internal Events 2.01 E-05 1.86E-05 2.02E-05 CDF Fire CDF 5.29E-06 4.71 E-06 5.30E-06 Seismic CDF 9.54E-06 9.58E-06 9.54E-06 Total CDF 3.49E-05 3.29E-05 3.51 E-05 Based on the above tables, the reduction in BVPS-1 total EPU CDF is insignificant when compared to the total AOT CDF, and is mostly attributed to the reduction in the SGTR initiating event frequency.

It should also be mentioned that Reference 3, Case 1 modeled the current EDG unavailability, as opposed to the baseline PRA model unavailability of 2.5%. This sensitivity case was run by changing the EDG unavailability from 2.5%, to the present mean unavailability of the EDG under the current AOT or 0.77% (BVPS-1) and 0.348%

(BVPS-2). These changes in EDG unavailability account for the differences in the internal events CDF as stated in Section 10.16.1.6 of L-05-104 Enclosure 1 (7.13E-06 vs. 7.45E-06 for BVPS-1, and 1.86E-05 vs. 2.01 E-05 for BVPS-2).

REFERENCES:

1.

Letter from L. William Pearce, FirstEnergy Nuclear Operating Company, to U.S.

Nuclear Regulatory Commission, "Beaver Valley Power Station, Unit No. I and No. 2 BV-1 Docket No. 50-334, License No. DPR-66 BV-2 Docket No. 50-412.

License No. NPF-73 License Amendment Request Nos. 302 and 173," L-04-125, October 4, 2004. (ADAMS Accession No. ML042920300)

2.

Letter from L. William Pearce, FirstEnergy Nuclear Operating Company, to U.S.

Nuclear Regulatory Commission, "Beaver Valley Power Station, Unit Nos. I and 2 BV-1 Docket No. 50-334, License No. DPR-66 BV-2 Docket No. 50-412, License No.

NPF-73 Probabilistic Safety Review for License Amendment Request Nos. 302 and 173," L-05-104, June 14, 2005. (ADAMS Accession No. ML051670270)

3.

Letter from L. William Pearce, FirstEnergy Nuclear Operating Company, to U.S.

Nuclear Regulatory Commission, "Beaver Valley Power Station, Unit No. I 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," L-04-141, October 29, 2004. (ADAMS Accession No. ML043070444)

L-05-140 Enclosure 1, Attachmen6t 1 Page 1 of 16 to RAI 2.a.

BVPS-1 Pre-EPU SLIM Worksheets

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0.0003404 Figure 1: BVPS-1 Pre-EPU SLIM Worksheet Group I

L-05-140 Enclosure 1, Attachment 1 Page 3 of 16 BEAVER VALLEY UNIT I - GROUP 2 HUMAN ACTIONS EVALUATION PERFCRUANCESHAPINGFACTCRS PERFCRAMANC0ESHAPINOFACTCRS C

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L-05-140 Enclosure 1, Attachment I Page 4 of 16 BEAVER VALLEY UNIT 1 - GROUP 3 HUMAN ACTIONS EVALUATION PERFCRMANCESHAPINGFACTCRS C

P N

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2 Figure 3: BVPS-1 Pre-EPU SLIM Worksheet Group 3

L-05-140 Enclosure 1, Attachment 1 Page 5 of 16 BEAVER VALLEY UNIT I - GROUP 4 HUMAN ACTIONS EVALUATION PFRFCRMANCEtSAPINMFACTCRS C

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2 Figure 4: BVPS-1 Pre-EPU SLIM Worksheet Group 4

L-05-140 Enclosure 1, Attachment I Page 6 of 16 BEAVER VALLEY UNIT I - GROUP 5 HUMAN ACTIONS EVALUATION PEWFORMANCESWWPINOVACTCRS C

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Figure 5: BVPS-1 Pre-EPU SLIM Worksheet Group 5

L-05-140 Enclosure 1, Attachment 1 Page 7 of 16 BEAVER VA PE9FORMANCESHAPINGFACTCRS C

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2 Figure 6: BVPS-1 Pre-EPU SLIM Worksheet Group 6

L-05-140 Enclosure 1, Attachment 1 Page 8 of 16 BI PERFORMANCESRAPiNGFACTCRS C

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Figure 7: BVPS-1 Pre-EPU SLIM Worksheet Group 7

L-05-140 Enclosure 1, Attachment 1 Page 9 of 16 BEAVER VALLEY UNIT I - GROUP 8 HUMAN ACTIONS EVALUATION PERFOCRMANCESHAPINGFACTC61S C

P I

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Figure 8: BVPS-1 Pre-EPU SLIM Worksheet Group 8

L-05-140 Enclosure 1, Attachment 1 Page 10 of 16 BEAVER VW PERFCRMANCE SHAPINGFACTORS C

P I

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2 Figure 9: BVPS-1 Pre-EPU SLIM Worksheet Group 9

L-05-140 Enclosure 1, Attachment 1 Page 11 of 16 PERFCOMANCESHAPiNGFACTCRI C

P I

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Figure 10: BVPS-1 Pre-EPU SLIM Worksheet Group 10

L-05-140 Enclosure 1, Attachment 1 Page 12 of 16 BEAVER VALLEY UNIT I. GROUP 11 HUMAN ACTIONS EVALUATION PERFcRMANCESHAPNGFACTORS C

P I

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sn Figure 11: BVPS-1 Pre-EPU SLIM Worksheet Group 11

L-05-140 Enclosure 1, Attachment 1 Page 13 of 16 BE PERFO00OANCESHAPMNQFACTORS C

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L-05-140 Enclosure 1, Attachment 1 Page 14 of 16 BE PERFERMANCESHAPINOFACTCRS C

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L-05-140 Enclosure 1, Attachment 1 Page 15 of 16 BEAVE PERFORMANCES0APINGFACTCRS C

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Figure 14: BVPS-1 Pre-EPU SLIM Worksheet Group 14

L-05-140 Enclosure 1, Attachment I Page 16Of 16 BEAVER VA PERFORMANCE5HAPINOFACTCRS C

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2 Figure 15: BVPS-1 Pre-EPU SLIM Worksheet Group 15

L-05-140 Enclosure 1, Attachment 2 Page 1 of 17 to RAI 2.a.

BVPS-1 Post-EPU SLIM Worksheets

L-05-140 Enclosure 1, Attachment 2 Page 2 of 17 BEAVERVALLEY UNT 1 -GROLP I HUVIAN ACLnCNS EVALLIA11CN PUC"ESMRN3 F -CF(

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L-05-140 Enclosure 1, Attachment 2 Page 3 of 17 BEAVER VALLEY UNT 1 -GROUP 2 HM4N ACnTMS EVALIJATIN P37IMNE StW"NG FACTMF P31 iE S4-PNG FACTORS C

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L-05-140 Enclosure 1, Attachment 2 Page 4 of 17 BEAVER VALLEY UNT 1-GROUP 3 HUMAN ACTIONS EVALUATION P

aFM

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L-05-140 Enclosure 1, Attachment 2 Page 5 of 17 BEAVER VALLEY UNIT 1 - GROUP 4 HUMAN ACTIONS EVALUATION PtERFt E StAt8G FACTVRS PERFOc SKAPIG FACrORS C

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Figure 19: BVPS-1 Post-EPU SLIM Worksheet Group 4

L-05-140 Enclosure 1, Attachment 2 Page 6 of 17 BEAVER VALLEY UTT I -GROUP 5 HUMAN ACnONS EVALUAImON PEIFaRFACE SHAF1NG FACTM P8U0MAM SR4AWG FARS C

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EM&A=PSF Qt15 015 Q15 Q15 Q15 011 Q14 MtGHTS Figure 20: BVPS-1 Post-EPU SLIM Worksheet Group 5

L-05-140 Enclosure 1, Affachment 2 Page 7 of 17 SrPH31XL3 srpMm MNHR-10 10 10 10 10 10 10 6

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Q013 Figure 20: BVPS-1 Post-EPU SLIM Worksheet Group 5 (continued)

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L-05-140 Enclosure 1, Attachment 2 Page 8 of 17 BEAVERVALLEY UNT 1 -GROP 6 HUMNACnCNS EVAL.TOCN fFtE9MGFPCF\\

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L-05-140 Enclosure 1, Affachment 2 Page 9 of 17 EAVEVALLEY tNT 1 -GMJP 7 HUMVN ATINPS EVA WllTCN PF~tPRNGMWnFXS P

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L-05-140 Enclosure 1, Attachment 2 Page 10 of 17 BEAVER VALLEY UNIT 1 -GROUP 8 HUMAN ACTIONS EVALUATION PERFaRMANE SWANG FACTORS PERFORMANCE SHAPING FACTORS C

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0.0w1103 Figure 23: BVPS-1 Post-EPU SLIM Worksheet Group 8

L-05-140 Enclosure 1, Attachment 2 Page 11 of 17 EAVEVAlUEY(lW 1-G1P 9 HlVlNpacsE B/ALINAM11 ESSRCfM94MFXCMS C

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L-05-140 Enclosure 1, Attachment 2 Page 12 of 17 SFAVERVALE YLUN1 -GAP 10 HMINACl S EVAWUA11CN FNE

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L-05-140 Enclosure 1, Attachment 2 Page 13 of 17 EEAVERVAUEY UNT 1 -GRLP 11 MnAN ACT1CNS EVALUA1IcN PE}ERV~

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L-05-140 Enclosure 1, Attachment 2 Page 14 of 17 BEAVER VALLE( UT1 -GROUP 12 HUMAN ACTIONS EVALUATION FP J

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Figure 27: BVPS-1 Post-EPU SLIM Worksheet Group 12

L-05-140 Enclosure 1, Attachment 2 Page 15 of 17 AVMERVALLEY UNT 1 -GROUP 13 VAMN ACnCNS EVALULIAON PFOCRaE S

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L-05-140 Enclosure 1, Attachment 2 Page 16 of 17 WEAVERVALlEY UT 1 - GROP 14 HUIAN ACTICNS EVALWATICN C

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L-05-140 Enclosure 1, Attachment 2 Page 17 of 17 EEVIRVAllEILNr 1 -GUP 15 HIUVNPClICNS EVALIATICN FRXRvVMWYSffNGFAMS PFU}UMCE qjHft'GFiCrCF c

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L-05-140 Enclosure 1, Attachment 3 Page 1 of 11 to RAI 2.a.

BVPS-2 Pre-EPU SLIM Worksheets

L-05-140 Enclosure 1, Attachment 3 Page 2 of 11 Beaver Valley Unit 2 - Group 1 Human Actions Evaluation PERFCRMANX SHING FACTCRS C

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L-05-140 Enclosure 1, Attachment 3 Page 3 of 11 Beaver Valley Unit 2 - Group 2 Human Actions Evaluation PERFORJ1MAC SHAPING FACTORS PUF AEMSHARNG FACTORS C

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L-05-140 Enclosure 1, Attachment 3 Page 4 of 11 Beaver Valley Unit 2 - Group 3 Human Actions Evaluation PERFCMAWE SHAPING FACTCRS PEV W

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L-05-140 Enclosure 1, Attachment 3 Page 5 of 11 Beaver Valley Unit 2 - Group 4 Human Actions Evaluation PERFMVNOE SjNt*3 FACRS PERFOIRANCE SWP NO FACTORS C

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L-05-140 Enclosure 1, Attachment 3 Page 6 of 11 Bcavcr Valley Unit 2 -Action Group 5 Human Actions Evaluation PUF M

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L-05-140 Enclosure 1, Attachment 3 Page 7 of 11 BeaverValley Unit 2 -Action Group 6 Human Actions Evaluation PECFAMCE SHAWtN FSCTM IPEWORF E SHWAPNG FACTR PSFV\\eid" PfRATfCRACTOS MAX HM DEOA1 MN IER CA1JMATIONTASK MAX HER DCZHEOE1 (1)

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L-05-140 Enclosure 1, Attachment 3 Page 8 of 11 BeaverValley Unit 2 -Action Group 7 Human Actions Evaluation PERFMNAEiAIRNG FACTrDS P9EtE SFIAFIfNGFACTO C

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I I

E C

N T

E N

M S

E G

Y S

G E

S C

P IP 0

R N

R M

0 T

E P

C E

C L

E R

E E

D F

D X

U A

I I

R C

N T

E E

G Y

S T

R A

N N

IN G

S T

T R

I E

M S

E S

S U

M S

U M

Nmn PSFV 1ts G12 G24 G14 0.12 012 G12 G14 1

OPEPATORACnCNS PSF PANNGS RF IER LOG"R)

AHER 10 10 10 10 10 10 10 10 529Et1

-27E01 D1E=

I 5

8 5

8 2

8 5.0Q 1.84E-02

-1.74E+00 ZfMt 1

5 7

3 2

5 2

377 7.52E3

.212E+00 ZHE-A2 3

7 2

2 2

5 6

424 1.04E42 Ag.BE#00 D{IA3 3

8 7

9 9

9 8

7.35 8.67E2 1.Q0E+0O 2HEC2 5

9 5

3 3

7 8

614 378E42

.1.42E0.0 ZH-SE3 2

9 1

2 5

1 6

4.35 1.12E42

1.95E.C0 Z-ESE4 2

9 2

2 7

1 6

4.73 1.45E42

-1.84E0.0 21-Et21v-6) 2 9

1 2

5 1

e 4.35 1.12E4C2

-1.95E.0 21-Er3 2

9 2

2 7

1 8

4.73 1.45E402

.1.84E0.0 UN FER 0

0 0

0 573E404 424E.00 CAUBRATIONTASKS PSF RANS FU FER LO(3GFR MAXIER 10 10 10 10 10 10 10 10 1.QOOE

>ODE.0 STP -EX 6

4 2

3 4

7 8

476 8880E43

205E+0 aR" 8(1) 5 9

5 3

3 7

6 5.s 1.QCE2

200+00 DCZ-EE03 7

5 4

7 6

6 8

e.oo 5.49E-42

-1.2500 MN HER0 0

0 0

.OCE43

-alOExl0 PEATORACTOCNS SNFVAGS 21DS ZMCI ZHEQA2 D ELA3 21E2 DfESE3 ZFESE4 21-Em MI ZTB3 5

10 5

5 5

10 10 5

5 10 5

5 5

10 5

5 5

10 5

5 5

10 5

5 5

10 5

5 5

10 5

5 5

10 5

5 5

5 10 5

5 5

S 5

5 5

5 45 45 40 40 40 40 40 40 40 N

DM WPSF Q122 0243 0135 0122 Q122 Q122 0135 Meaxrs NOMl (1) RqNNGSARE8ThSEFMRSMILAR AMCTON4IN BV (Z-EOP2)

Ressl Ojt ca~ta1

-324218457e St ErrdY Est 0.398545 R SqAn-e Q51099O Nta d Cbsim 5

DV" d Frned=

3 XCwidas)

M2U57372 SWdEsrdc W.

0Q55441061 Figure 37: BVPS-2 Pre-EPU SLIM Worksheet Group 7

L-05-140 Enclosure 1, Attachment 3 Page 9 of 11 Beaver Valley Unit 2 -Action Group 8 Human Actions Evaluation PE3RRAAt SH4AItN FKCTORS PERCRNAJ SWJ1NG FACRS C

P I

P 0

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R M

0 T

T E

P C

R E

C L

E A

S R

E E

D I

T F

D X

U N

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A I

I R

I I

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N T

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E G

Y S

G E

S C

P I

P 0

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0 T

T E

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C E

E A

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E D

I F

D X

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T S

A I

I R

I I

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N T

E N

M M

E G

Y S

G E

S T

R E

S S

S U

N Norm PSF at" Q128 0128 0128 0116 0.116 0.25z Q128 I

CPERATOR AClONS PSFRAN8NGS FU HER LOM MAXHER 10 10 10 10 10 10 10 10 353E-O1

-453E-O1 ZFECD3 2

3 3

2 2

1 5

238 1.46E-03

-2.84E.00 Z-ECC4 2

5 8

5 6

4 7

512 1.04E-02

.196+.00 ZFEIAt 1

3 2

5 2

7 3

376 31E503

-241E503 ZFEOT1 1

0 1

0 0

5 6

23D 1.37E-03

-280E403 ZE-REE 1

2 2

6 2

4 5

323 266E-03 Z-57400

{1 0

1 0

0 5

7 243 1.51E-03

-2.&04 D ESE1 (M-ECCt, DEC) 2 4

2 1

4 7

5 4.03 4.75E-03

-Z32E400 ZHESLI 2

1 5

2 3

7 6

4.16 525E-03

-2280403 ZFESL5 2

4 5

2 4

8 8

S17 1.09E0-2

1.56E+C0 21EWA2 2

3 7

4 2

5 5

4.15 5.20E-03

-228E000 Z-EWA4 2

6 7

7 10 5

6 594 1.80E-02

.1.72E+50 MINH-ER 0

0 0

0 2.61E-04 4.3580.E CAIJRATIONTASKS PSFRAWNGS FU HER L1-"

M4XHER 10 10 10 10 10 10 10 10 1.Q6E4W 0.03E*00 STPHECSL1 5

3 4

3 3

3 6

377 213E-03

-2.67+00 FE£M HERS1 2

7 2

3 2

4 6

378 1.75E-03

-276E400 STPHEOSOt 6

4 6

3 10 10 3

6850 1.80-t2

1.74E403 C

3HOX1 (1) 2 1

5 2

3 7

6 4.16 3.20E-03

-Z45E+.0 MNHER 0

0 0

0 1.0SE-03 43.03E4C OPERATOR AcnONS PSF Vf TS 3-1E=

Z4ECD4 2HEIA1 2-ER£E ZtESEI tD ECC1, 2HE1 2HELi ZHESLS D-EWA2 ZHEWA4 NOR9UZED PSF WVlG11TS 5

5 5

10 5

5 10 5

5 10 0

5 10 5

0 10 5

5 10 5

S 5

5 5

5 S

40 40 40 35 40 40 40 40 40 35 40 0128 0126 0.128 0.116 0116 0258 0.128 (1) RA*KNGS AREITIOSE FOR SMLAR ACCON IN EW2 (ZHELI)

FR*5iOs OAxt Cw 1t

-3 583050682 SW Err d Y Est 0455189834 R Swared 0Q8675190t3 Na d Cbsmcvlu 6

DCq d FR edon 4

X elid.s) 0.31302434 StdDT dCod.

006t141234 Figure 38: BVPS-2 Pre-EPU SLIM Worksheet Group 8

L-05-140 Enclosure 1, Attachment 3 Page 10 of 11 Beaver Valley Unit 2 -Action Group 9 Human Actions Evaluation PRFOFAIE SAFING FACTO PERFOMWE S9ARNG FCTORS C

P I

P 0

R N

R M

0 T

T E

P C

R E

C L

E A

S R

E E

D I

T F

D X

U N

T R

A I

I R

I I

E C

N T

E N

M S

E G

Y S

G E

S C

P I

P 0

R N

R M

0 T

T E

P C

R E

C L

E A

R E

E D

I F

D X

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A I

I R

I C

N T

E N

E G

Y S

G S

T T

R I

E M

S E

S S

U M

S U

M NormPSF Wat 0 0.176 0.176 Q176 Q176 0118 0175 1

OPERATaRACRCAS PS RAN SS FU FIER LOG"3EI MAXFIER 10 10 10 10 10 10 10 10 (28O1

-22E-01 Z1ED 2

9 3

3 7

3 9

5.82 7.65E42 1.12Edw) 2}EC07 2

9 8

5 8

4 9

7.35 1.65Et

-7.82E401 zIEW8O 2

4 5

2 1

359 248E42 41GIE.W MN KER 0

0 0

OO0 4.05E03

239C00 CAUERATIONTASiG PSFRANON5 FU FER LOG(E MAXIER 10 1010 10 10 10 10 10 1IE+00 OO0C0 STPWEOO 6

6 6

5 6

8 9

ft.582 4.3SE-2

1.3$E+00 EPRI SM1(1) 2 9

3 3

7 3

9 58235 1 OD Ot

-. 00E+C MNFER 0

0 0

0 5C4E-03 230E+00 OPERkTcPCRAXE8 ZFECUD5P PSF VA3GHrS 0

5 5

0 5

5 5

5 0

5 5

0 5

0 Q176 0178 0176 Q175 0118 0178 30 30 25 NO1TE~

(1) RAN0I-3NS ARE TIV FOR SIMLAR ACflION IN SW2 (ZI-E RegessciaOutput Omftt1

-a387M1371 td Err Y Est 0.3MM95 RSqtnmd 09151131 Na& ofCtbswafcs 4

D~mdAEixi, 2

X Cefdert(s) 0.219,17541 td ErrdCoe(.

01047187948 Figure 39: BVPS-2 Pre-EPU SLIM Worksheet Group 9

L-05-140 Enclosure 1, Attachment 3 Page 11 of 11 Beaver Valley Unit 2 - Group 10 Human Actions Evaluation PERF0RfNE SF-N3 FACTCRS.

PERFORNME SHP NG FACTORS C

P I

P 0

R N

R M

0 T

T E

P C

R E

C L

E A

S R

E E

D I

T F

D X

U N

T R

A I

I R

I I

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N T

E N

M S

E G

Y S

G E

S C

P I

P 0

R N

R M

0 T

T E

P C

R E

C L

E A

S R

E E

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T F

D X

U N

T R

A I

I R

I I

E C

N T

E N

M S

E G

Y S

G E

S S

U M

S U

M Norm PSFWigits 014 014 0.29 0.0m 0.14 014 0.14 1

CPERATORACTONS PSF RA*N2 S FU HER LO(R)

MkXHER 10 10 10 10 10 10 10 10 9.96E-01

-1.78E43 ZHEXTI a

9 10 1

4 5

8 7.71 3.56E-

1.45E.00 UN HER 0

0 0

0.00 4.67E-07 433E+50 CAUSRAT1C4CN TASKS PW RANNGS FLU HER LO3ER MAXFER 10 10 10 10 10 10 10 10 1.00E+00 0.0o SEABROCKON 0

0 1

o 2

0 0

0.5714 1ao0-s 4.exo MN IER 0

0 0

0 5s5E-07 4.3010 OfERATORACTONS PSFWBGHTS ZHEXTI 5

5 10 0

5 5

5 N-E1JEDPSF 014 014 0.29 0.00 014 0.14

.14 35 Reqwson oL(4x CSart Std Errf Y RS.m es NaL d Csvba DOman ofFmadom X COffides) 0 O Std Err f Coc.

01 433E+00 4.29E-02 J9927115 3

1 09685998 79403158 Figure 40: BVPS-2 Pre-EPU SLIM Worksheet Group 10

L-05-140 Enclosure 1, Attachment 4 Page 1 of 12 to RAI 2.a.

BVPS-2 Post-EPU SLIM Worksheets

L-05-140 Enclosure 1, Attachment 4 Page 2 of 12 BEAVERVAUEY UNT 2 - GROP 1 HUVIAN ACTlONS EVALUATION PETRRE SPINGFACMRS PERFOWE~ 9'A'1NG WrMXS C

P I

P 0

R N

R MO T

T E

P C

R E

C L

E A

S R

E E

D I

T F

D X

U N

T R

A I

R I

I E

C N

T E

N M

S E

G Y

S G

E S

C P

I P

0 R

N R

MO T

T E

P C

R E

C L

E A

S R

E E

D I

T F

D X

U N

T R

S A

I I

R I

I E

U C

NT E

N M

S M

E G

Y S

G E

S S

U M

INPlJT7O ISnfNFOR KRD0tSTREJBllCN Nr mPSFl WIUs Q116 0233 11 0116 0116 0233 007 1

CPERATCRAMCAN PSFRANGNSS FU HER L

OQH9G MSXKR 8

8 8

8 4.80601

-alg-01 ZFR1 2

8 4

2 3

8 6

5,42 26SE-2

.1SE.c ZEf" 5

8 4

5 5

7 5

6.05 53E402

-127E.00 HDEAI 7

8 7

5 5

6 5

640 7.gX,2

-1.10E4O)

D-EV3 7

8 7

5 5

6 5

6.40 7.90C2

.1.1CE+00 Z)E5 7

8 7

7 10 6

6 728 214601 47a0l MN KR 2

2 2

2 572-04

-324E.OD CAtlATICNTARG PSFFR*NSOS FU HER LOC-EF~

M&XKR 8

8 8

8 1.0X0L 00f0E FEWI CEI 4

6 4

4 5

4 4

4.5814 4.31603

-2.37E40)

STPKCER5 7

7 8

5 8

8 6

7.1628 1.2401

-9.07E-01 MN FER 2

2 2

2 1.0063

-34aE.0 WERATCRnCICNS ZHDM ZU5 NCRlq PSF DEGWS PSMMAIGM5 RAN FACTOR ELAN 5

10 5

5 5

10 5

5 10 5

5 5

10 5

5 10 5

5 5

10 0

5 10 5

5 5

10 0

5 10 5

5 5

10 5

Q116 0233 0.118 a118 Q118 0.233 0.07 45 45 40 40 45 5

1.64602 5

3 5

4.91E42 5

4.91E402 3

1.71E-01 1

F r

sdCt1O1t cm~ta-4.2167171 Sbd0rdYEst Q411087816 RSqaed Q9348YG3 ND.

d 4

DegvesodFrayfrn 2

Xlidst(s)

Q487245M4 W BT d W.

0037443M Figure 41: BVPS-2 Post-EPU SLIM Worksheet Group I

L-05-140 Enclosure 1, Attachment 4 Page 3 of 12 BEAVERVALLEY UNIT 2 - GROUP 2 HUMAN ACTIONS EVALUATION PERFORMAN6E SHAP1NG FACTORS PERFORMMICE SHAPINGIFACTORS C

P I

P 0

R N

R M

0 T

T E

P C

R E

C L

E A

S R

E E

0 I

T F

D X

U N

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A I

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I I

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N T

E N

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E G

Y S

G E

S C

P I

P 0

R N

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0 T

E P

C E

C L

E R

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0 F

D X

U A

I I

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N T

E E

G Y

S T

R A

N T

I I

N M

G E

S T

R S

S S

S U

M S

U M

Norm PSF\\1iet$gs 0.111 0.111 02 olli 0.111 om 0.111 1

OPERATOR ACTIONS PSF RANIQNGS FLI FER LOG(QER)

MAX HER 10 10 10 10 10 10 10 10 1.54E-01 413641 ZHEOS5 1

7 7

6 9

5 4

5.6567 1.33E-02

-1.885E40 ZFEOS21 8

8 8

9 2

5 5.6'67 1.33E-02

-1.885E40 ZHEOS3 1

8 8

8 9

3 7

6.1111 1.71E-02

-1.77E400 ZHEOS4 1

8 8

8 9

8 8

7.3333 341E5-2

-1.47E+00 ZHESL4 2

8 8

9 9

5 8

6.8889 26SE-02

-1.58E+00 2-IEXT2 8

9 10 1

4 9

9 7.6567 4.12E-02

-1.39E+00 ZFIEXT4 8

9 10 5

4 9

9 8.1111 5.29E2

.128E500 MN IER 0

0 0

0 5.44E44

-. 26E40 CAUBRATION TASKS PSF RANKINGS FU HER LOG(FIER)

MAX HER 10 10 10 10 10 10 10 10 5.OE-01 4.01E-01 DCZHEO51 2

2 1

5 5

3 4

28889 1.50E-03

-82E+00 EPRILI(1) 1 8

8 8

9 4

5 6.1111 ZOOE-03

-Z70E400 STP HEOR07 7

5 5

4 5

6 6

5.4444 Z08M-09

-1.685E00 MN HER 0

0 0

0 1.50E-03

-2.82E00 14INPTOMRISCAAN PC HER DISTRILJTON RANG)E FACTOR MEDItAN CPERATOR ACflONS ZHEOS3 ZI-50S4 NCRMAUZE PS:

VOGHT PSF WEIGHTS 5

5 10 5

5 5

45 45 45 45 45 45 45 5

8 26E-03 5

8 28E-03 5

1.05E-02 5

Z11E-02 5

1.65E02 5

255E-02 5

3.28E02 0.111 Q111 0222 0.111 0.111 Q2m Q111

NOTE, (1) RANINGSARETHOSE FOR SMLAR ACTION IN B92 (Z0 RPessge Ouw Ca1

-3.264095629 Std En dY Est 0.69738723 R Sqaed 0 69i79788 No, d OfvAan 5

DeMrees d F&rn 3

X Coeffide(s) 0.245075073 SId En f Cef.

0093338437 Figure 42: BVPS-2 Post-EPU SLIM Worksheet Group 2

L-05-140 Enclosure 1, Attachment 4 Page 4 of 12 A\\IRVAIlEYI'r2 - GtLP3 3HLNVPCN1N;EVLLUI~CN PEaWSHSRMFXGS PERM C

P I

P 0

R N

R MO T

T E

PC R

E CL E

A S

R E

E D

I T

F D

X U

N T

R A

I I

RI I

E C

N T

E N

M S

E G

Y S

G E

S C

P I

P 0

R N

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T E

P C

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CL E

A S

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F D

X U

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A I

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I I

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C N

TEN M

S M

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YS GE S

S M

FbmrPSFVW s

C111 Qa 01t11 111 Q167 Q22Z 0m2 1

CPEA\\TOvPCNS PSTR4N3S RI R

L0MBF MXSR tO 10 10 tO 10 10 10 10 216M

-des MR2 4

1 8

5 10 8

8 7.167 6706M

-1.17E+CO ZH31 1

2 8

9 9

8 7

69444 812

-121E'00 MN-R 0

0 0

0 a47E6

-243TD 0U1E1A0CNTAS9 PRFRiNS R

L W9HR 10 10 10 10 10 10 10 10 1.0 00-4 STPH;Ot 6

4 6

3 10 10 3

64444 1.8Z

-1.74E400 FEAIRE7 6

7 6

8 6

5 8

86 1.32

-1.88M MNFHR 0

0 0

0 8M3

-21iE INIORNRR HR-DCSTROLCN CPETCRM PSFV'SG-S 2

5 0

5 5

10 10 10 2H 5

5 5

10 10 N

0il)PF 111 003 0 Q1 Q1tt Q167 Q2m a MlGM 45 45 5

41!4 5

a7MM 1

WerdYEs Nd dCmas DqjdR+/-inm

-24S9 Q745E5100 COMMt 4

2 XtlfidO4(

atM5154 u4 B dP.

S1G Figure 43: BVPS-2 Post-EPU SLIM Worksheet Group 3

L-05-140 Enclosure 1, Attachment 4 Page 5 of 12 BEAWERVAUIBE UNT 2 -AC1ON GROUP 4 HUVIAN ACn1ONS EVALUAllON FBSCFTINWPMFACTORS RWNZES14INGFACTa;S CiP I

P HR N

R MO T

T E

P C

R E

CL E

A S

R E

E D

I T

F D

X U

N T

R A

I I

R I

I E

C N

T E

N M

S E

G Y

S G

E S

C P

I P

0 R

N R

M O

T T

E P

C R

E C

L E

A R

E E

D I

F D

X U

N S

A I

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E G

Y S

G S

T T

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S E

S S

U M

1W7TTOR19HNFCR KReMsTRaMCN NormPSF VMl Q125 0.125 Q125 Q125 Q125 Q125 Q25 I

CEATCRA CNS PSFRANGS RI FER L

CWFER MkXHER 10 10 10 10 10 10 10 10 1.76-

-7.55C-Z-EUJI 2

4 8

4 6

2 8

525 S45'43

-22SE4 ZEM22 2

4 8

4 6

2 8

525 5SA 3

-22E40 ZH 2

4 8

4 6

5 8

5.63 7.17EC3

-214E#CO aHBU 2

4 8

4 6

7 8

588 a6a;{

-207E400 YEVM1 2

5 8

6 6

0 8

538 597E603

-22M4M MNHER 0

0 0

0 1.17E04 4 EIM CAJERA=NTASS PSFR*HNGS RI HER LOcX6 MWXEIR 10 10 10 10 10 10 10 10 1.a01

-1.OE40o STP HFrC4 3

2 1

8 5

6 6

4.625 9.82EO4

-3.01E400 TMHTIB(1) 2 4

8 4

6 4

8 550 6202

-1E40 FERA HBM 4

6 3

3 3

3.50 1.1503

-294E+OD MNIHE 0

0 0

0 1.(0ED4 4.OOE+M CPEATCRACnONS PSFM8G-S WM FACTOR MtAN ZH3AJ2 ZFEMJ3 2YEM 5

5 5

5 10 5

10 5

10 40 40 40 40 40 75 Z57E43 7.5 Z57SE3 7.5

3IE 7.5 406E 7.5 282E03 Q125 Q125 Q125 Q125 Q125 0.125 025 1

NOlM (1) RA NFSAREASEFR SMLAR ACTICN INMBV2 tM Rweaf OJPLL Oft 4 9305 SWBrdYEs 022 RS~mied Q7970 NhdCb5v&

5 Deg d A rrb, 3

XOltxdal(s)

Q31748772 SdFud44 V.

aPosEPSMih Figure 44: BVPS-2 Post-EPU SLIM Worksheet Group 4

L-05-140 Enclosure 1, Attachment 4 Page 6 of 12 BEAVER VALLEY UNIT 2 - ACTION GROUP 5 HUMAN ACTIONS EVALUATION FERFORMAFE SHAPING FACTORS PERFORMANCE SHAPING FACTORS C

P I

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T E

P C

R E

C L

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S R

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D I

T F

D X

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A I

I R

I I

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N T

E N

M S

E G

Y S

G E

S 0.145 0145 0.14 0.145 014 0.14 0145 C

I P

0 N

R M

T E

P E

C L

R E

E F

D X

A I

I C

N T

E 0

Y P

R 0

C E

D U

R E

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I S

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S E

S S

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S U

NI Norm PSFSdqIts SI INPUT TO RISKNI4 FOR HER 3STIfAlON RANGE FACTOR MECtAN OPERATOR ACTIONS MAXHER DHEAF2 D EAF3 (ZHEMAI)

ZHECC1 ZHE=

ZHEMA2 afCB1 ZHEC02 Di~EOR1 DFIEOR2 ZHEOSS D-1ERE5 DFIERED ZHERR1 ZHEHH2 ZHESE2 ZHESES ZKS12 ZHEOD1 D,391 gFEC1)

IFER PSF RAN0NGS 10 10 10 10 2

3 3

2 2

3 3

2 2

6 6

7 2

6 7

7 2

4 3

3 2

5 8

5 1

2 4

1 3

7 7

7 2

7 6

4 1

7 5

5 2

2 3

1 2

6 5

3 5

3 2

3 5

2 2

4 5

2 2

1 1

2 2

3 5

3 2

3 5

3 1

4 2

2 0

0 1

5 1

2 8

9 1

2 2

8 2

2 5

5 2

2 5

5 2

7 1

2 5

4 5

2 3

2 8

5 7

10 9

9 2

7 1

2 0

0 0

0 10 10 10 2

0 2

2 0

2 2

2 5

2 4

6 2

1 4

6 1

4 3

3 3

7 7

e 7

1 3

2 2

6 3

1 4

8 5

6 3

7 6

5 0

5 3

4 5

2 3

5 4

0 5

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L-05-140 Enclosure 1, Attachment 4 Page 7 of 12 USWTNPS 1MMO SIP13P SPFEM MNHER FTRM 10 10 10 10 10

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L-05-140 Enclosure 1, Attachment 4 Page 8 of 12 R39CPRNNSFACIFP=

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L-05-140 Enclosure 1, Attachment 4 Page 9 of 12 BEAVER VALLEY UNIT 2 -ACTION GROUP 7 HUMAN ACTIONS EVALUAllON PERFORMANCE SH-APING FACTORS PERFORMAhCE SiAPING FACTORS C

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L-05-140 Enclosure 1, Attachment 4 Page 10 of 12 BEAVER V PERFORMANCE SHAPING FACTORS C

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L-05-140 Enclosure 1, Attachment 4 Page 11 of 12 EA\\EVAllEY UNT2 -

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L-05-140 Enclosure 1, Attachment 4 Page 12 of 12

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L-05-140 Enclosure 2 Proprietary Response to RAI Question Number 4

L-05-140 Enclosure 3 Non-Proprietary Response to RAI Question Number 4

Westinghouse Proprietary Class 3 "Probability Risk Assessment for the RSG/EPU (PRA) RAI Response #4 Program" BVPS EPU Submittal August 29, 2005 Westinghouse Electric Company LLC P.O. Box 355 Pittsburgh, PA 15230-0355 C) 2005 Westinghouse Electric Company LLC All Rights Reserved

Question

4.

Section 10.16.1.5 states that the RSGs will result in a lower frequency for steam generator tube rupture (SGTR) because of the use of Alloy 690. Please provide the basis for the new SGTR frequency including the supporting reference(s) (or excerpts).

Response

Beaver Valley Power Station Unit No. 1 will be installing Westinghouse Model 54F steam generators, designed and constructed with Alloy 690 tubes. It was recognized that current, industry generic steam generator tube rupture (SGTR) initiating event frequencies are based on years of operating experience of Alloy 600 steam generator tubes and that operating experience may not be applicable to new steam generator tube designs, such as designs utilizing Alloy 690. A methodology was prepared, by Westinghouse, for calculation of a generic SGTR initiating event frequency for steam generators constructed with Alloy 690 tube material. This methodology does not ignore the many years of data currently available for Alloy 600 steam generator design, but incorporates that information with current understanding of the SGTR failure modes and improvements to steam generator tube designs and improvements to plant operating practices.

STEAM GENERATOR TUBE RUPTURES EVENTS Most of the PWR steam generator tubes which have failed over the years have been mill-annealed Alloy 600 tubes. However, some failures of thermally treated Alloy 600 tubing have been reported, primarily due to fretting (degradation mechanisms due to the design of the support plates and anti-vibration bars (AVBs), and the presence of loose parts, rather than the tubing material). But there have also been a few failures of thermally treated Alloy 600 tubing due to primary and secondary-side stress corrosion cracking (SCC).

Degradation mechanisms include primary water stress corrosion cracking (PWSCC),

outside diameter stress corrosion cracking (ODSCC), transgranular stress corrosion cracking, intergranular stress corrosion cracking (IGSCC) (fretting, wear and thinning),

pitting, denting, high-cycle fatigue, and wastage (erosion-corrosion and corrosion-fatigue).

A search of the INPO database for SGTR License Event Reports was performed. The search confirmed the following SGTR events, which are provided in Table 4-1.

[Table 4-1: SGTR Industry Events 1

Plant Year Failure Mechanism Point Beach 1 1975 Wastage/SCC Surry 2 1976 PWSCC Doel 2 1979 PWSCC Prairie Island 1 1979 Loose Parts Wear Ginna 1 1982 Loose Parts Wear North Anna 1 1987 High-Cycle Fatigue McGuire 1 1989 IGSCC

Table 4-1: SGTR Industry Events Plant Year Failure Mechanism Mihama 2 1991 High-Cycle Fatigue Indian Point 2 2000 PWSCC STEAM GENERATOR TUBE RUPTURE FREQUENCY METHODOLOGY A methodology was created by Westinghouse for a generic SGTR initiating event frequency for use with Westinghouse Alloy 690 steam generator designs.

The methodology considers the history of steam generator operating experience (total tube years and plant availability) and calculates a steam generator tube non-plugging factor to determine a "tube years adjusted" value. The Alloy 690 SGTR initiating event frequency is the postulated number of SGTR events (based on expert elicitation) divided by the "tube years adjusted" value.

I Ia~c

[

]ac Expert Elicitation A Westinghouse expert opinion discussion was held to discuss the likelihood of SGTR due to various failure mechanisms.

The expert opinion discussion focused on the known, potential failure mechanisms for current steam generator tubes. Based on current knowledge of Alloy 690 steam generator tubes, the likelihood of a SGTR event due to a given failure mechanism was debated and the results were documented.

The results of the expert opinion discussion can be used to calculate a postulated number of steam generator tube rupture events.

I I

01) 0)

0D I

I

Page 6 ac Steam Generator Tube Rupture Frequency Calculations For mill annealed steam generators, a frequency per tube-year has been calculated to be 1.25 E-06 (see Table 4-3); and, for thermally treated or Alloy 690 steam generators, the frequency per tube-year has been calculated to be 1.94 E-07 (see Table 4-4).

An extensive search of data was performed for all domestic, foreign and foreign licensee Westinghouse type steam generators.

The data points for the overall database consist of the following:

Plant name Steam generator model Number of plant loops Number of tubes per steam generator Total number of tubes in all steam generators at that plant Date plant was commissioned or date the plant replaced the original steam generator Effective date of analysis or the date the plant ceased operation Total number of years between commission or replacement date and the date of analysis or ceased operation Tube-years (a multiplication between total number of years and the total number of tubes) 3 year availability 3 year capability Shutdown date if the plant ceased operation Steam generator replacement date if the steam generator was replaced Replacement model

Date the plant is considering future steam generator replacement Total number of tubes plugged at each plant I

Iaxc

Page 8 acI

ac

Page 10 BVPS-1 Steam Generator Tube Rupture Frequency Calculation BVPS-1 has three SGTR initiating events (one for each steam generator); thus, the calculation here will be on a per steam generator basis. Based on the frequency (tube-year) value of 1.94E-07 for Model 54F (Alloy 690) steam generators, the calculation for BVPS-1 results in the following:

Frequency = 6.96E-04 SGTR per year per steam generator

L-05-140 Enclosure 4 Affidavit

e Westinghouse Westinghouse Electric Company Nuclear Services P.O. Box 355 Pittsburgh, Pennsylvania 15230-0355 USA U.S. Nuclear Regulatory Commission Document Control Desk Washington, DC 20555-0001 Directtel: (412) 3744419 Directfax: (412) 374-4011 e-mail: maurerbf@westinghouse.com Our ref: CAW-05-2046 August 26, 2005 APPLICATION FOR WITHHOLDING PROPRIETARY INFORMATION FROM PUBLIC DISCLOSURE

Subject:

"Probability Risk Assessment (PRA) RAI Response #4 for the RSG/EPU Program" (Proprietary)

The proprietary information for which withholding is being requested in the above-referenced report is further identified in Affidavit CAW-05-2046 signed by the owner of the proprietary information, Westinghouse Electric Company LLC. The affidavit, which accompanies this letter, sets forth the basis on which the information may be withheld from public disclosure by the Commission and addresses with specificity the considerations listed in paragraph (b)(4) of 10 CFR Section 2.390 of the Commission's regulations.

Accordingly, this letter authorizes the utilization of the accompanying affidavit by FirstEnergy Nuclear Operating Company.

Correspondence with respect to the proprietary aspects of the application for withholding or the Westinghouse affidavit should reference this letter, CAW-05-2046, and should be addressed to B. F. Maurer, Acting Manager, Regulatory Compliance and Plant Licensing, Westinghouse Electric Company LLC, P.O. Box 355, Pittsburgh, Pennsylvania 15230-0355.

Very truly yours, B. F. Maurer, Acting Manager Regulatory Compliance and Plant Licensing Enclosures cc: B. Benney L. Feizollahi A BNFL Group company

CAW-05-2046 bcc: B. F. Maurer (ECE 4-7A) I L R. Bastien, IL (Nivelles, Belgium)

C. Brinkman, IL (Westinghouse Electric Co., 12300 Twinbrook Parkway, Suite 330, Rockville, MD 20852)

RCPL Administrative Aide (ECE 4-7A) I L, I A (letter and affidavit only)

A BNFL Group company

CAW-05-2046 AFFIDAVIT COMMONWEALTH OF PENNSYLVANIA:

ss COUNTY OF ALLEGHENY:

Before me, the undersigned authority, personally appeared J. A. Gresham, who, being by me duly sworn according to law, deposes and says that he is authorized to execute this Affidavit on behalf of Westinghouse Electric Company LLC (Westinghouse), and that the averments of fact set forth in this Affidavit are true and correct to the best of his knowledge, information, and belief:

A. resham, Manager Regulatory Compliance and Plant Licensing Sworn to and subscribed before me thisc i(

day of A,

2005 Notary Public I

Notaf SealI Shawn L Foi, Notary Pubic W=f Boro, Allehwy Cout MY Ad rExDires January 29,2007 Mamber. Pennsytvania Assndition of Noari"

2 CAW-05-2046 (1) 1 am Manager, Regulatory Compliance and Plant Licensing, in Nuclear Services, Westinghouse Electric Company LLC (Westinghouse), and as such, I have been specifically delegated the function of reviewing the proprietary information sought to be withheld from public disclosure in connection with nuclear power plant licensing and rule making proceedings, and am authorized to apply for its withholding on behalf of Westinghouse.

(2) 1 am making this Affidavit in conformance with the provisions of 10 CFR Section 2.390 of the Commission's regulations and in conjunction with the Westinghouse "Application for Withholding" accompanying this Affidavit.

(3)

I have personal knowledge of the criteria and procedures utilized by Westinghouse in designating information as a trade secret, privileged or as confidential commercial or financial information.

(4)

Pursuant to the provisions of paragraph (b)(4) of Section 2.390 of the Commission's regulations, the following is furnished for consideration by the Commission in determining whether the information sought to be withheld from public disclosure should be withheld.

(i)

The information sought to be withheld from public disclosure is owned and has been held in confidence by Westinghouse.

(ii)

The information is of a type customarily held in confidence by Westinghouse and not customarily disclosed to the public. Westinghouse has a rational basis for determining the types of information customarily held in confidence by it and, in that connection, utilizes a system to determine when and whether to hold certain types of information in confidence.

The application of that system and the substance of that system constitutes Westinghouse policy and provides the rational basis required.

Under that system, information is held in confidence if it falls in one or more of several types, the release of which might result in the loss of an existing or potential competitive advantage, as follows:

(a)

The information reveals the distinguishing aspects of a process (or component, structure, tool, method, etc.) where prevention of its use by any of Westinghouse's competitors without license from Westinghouse constitutes a competitive economic advantage over other companies.

3 CAW-05-2046 (b)

It consists of supporting data, including test data, relative to a process (or component, structure, tool, method, etc.), the application of which data secures a competitive economic advantage, e.g., by optimization or improved marketability.

(c)

Its use by a competitor would reduce his expenditure of resources or improve his competitive position in the design, manufacture, shipment, installation, assurance of quality, or licensing a similar product.

(d)

It reveals cost or price information, production capacities, budget levels, or commercial strategies of Westinghouse, its customers or suppliers.

(e)

It reveals aspects of past, present, or future Westinghouse or customer funded development plans and programs of potential commercial value to Westinghouse.

(f)

It contains patentable ideas, for which patent protection may be desirable.

There are sound policy reasons behind the Westinghouse system which include the following:

(a)

The use of such information by Westinghouse gives Westinghouse a competitive advantage over its competitors. It is, therefore, withheld from disclosure to protect the Westinghouse competitive position.

(b)

It is information that is marketable in many ways. The extent to which such information is available to competitors diminishes the Westinghouse ability to sell products and services involving the use of the information.

(c)

Use by our competitor would put Westinghouse at a competitive disadvantage by reducing his expenditure of resources at our expense.

(d)

Each component of proprietary information pertinent to a particular competitive advantage is potentially as valuable as the total competitive advantage. If competitors acquire components of proprietary information, any one component may be the key to the entire puzzle, thereby depriving Westinghouse of a competitive advantage.

4 CAW-05-2046 (e)

Unrestricted disclosure would jeopardize the position of prominence of Westinghouse in the world market, and thereby give a market-advantage to the competition of those countries.

(f)

The Westinghouse capacity to invest corporate assets in research and development depends upon the success in obtaining and maintaining a competitive advantage.

(iii)

The information is being transmitted to the Commission in confidence and, under the provisions of 10 CFR Section 2.390, it is to be received in confidence by the Commission.

(iv)

The information sought to be protected is not available in public sources or available information has not been previously employed in the same original manner or method to the best of our knowledge and belief.

(v)

The proprietary information sought to be withheld in this submittal is that which is appropriately marked in "Probability Risk Assessment (PRA) RAI Response #4 for the RSG/EPU Program," (Proprietary) dated August 26, 2005, for support of the RSG/EPU project, being transmitted by the FirstEnergy Nuclear Operating Company letter and Application for Withholding Proprietary Information from Public Disclosure, to the Document Control Desk. The proprietary information as submitted by Westinghouse for Beaver Valley Units I & 2 is expected to be applicable for other licensee submittals in response to certain NRC requirements for justification of Alloy 600 SG Tube Rupture Frequency methodology.

This information is part of that which will enable Westinghouse to have a:

(a) competitive position for RSG.

(b) competitive position for PRA Data Analysis.

Further this information has substantial commercial value as follows:

(a)

Westinghouse plans to sell the use of similar information to its customers for purposes of future PRA and RSG analysis contracts.

5 CAW-05-2046 (b)

Westinghouse can sell support and defense of SGTR Initiating Event Frequency Methodology.

(c)

The information requested to be withheld reveals the distinguishing aspects of a methodology which was developed by Westinghouse.

Public disclosure of this proprietary information is likely to cause substantial harm to the competitive position of Westinghouse because it would enhance the ability of competitors to provide similar calculations for SGTR Initiating Event Frequency and licensing defense services for commercial power reactors without commensurate expenses. Also, public disclosure of the information would enable others to use the information to meet NRC requirements for licensing documentation without purchasing the right to use the information.

The development of the technology described in part by the information is the result of applying the results of many years of experience in an intensive Westinghouse effort and the expenditure of a considerable sum of money.

In order for competitors of Westinghouse to duplicate this information, similar technical programs would have to be performed and a significant manpower effort, having the requisite talent and experience, would have to be expended.

Further the deponent sayeth not.

PROPRIETARY INFORMATION NOTICE Transmitted herewith are proprietary and/or non-proprietary versions of documents furnished to the NRC in connection with requests for generic and/or plant-specific review and approval.

In order to conform to the requirements of 10 CFR 2.390 of the Commission's regulations concerning the protection of proprietary information so submitted to the NRC, the information which is proprietary in the proprietary versions is contained within brackets, and where the proprietary information has been deleted in the non-proprietary versions, only the brackets remain (the information that was contained within the brackets in the proprietary versions having been deleted). Thejustification for claiming the information so designated as proprietary is indicated in both versions by means of lower case letters (a) through (f) located as a superscript immediately following the brackets enclosing each item of information being identified as proprietary or in the margin opposite such information. These lower case letters refer to the types of information Westinghouse customarily holds in confidence identified in Sections (4)(ii)(a) through (4)(ii)(f) of the affidavit accompanying this transmittal pursuant to 10 CFR 2.390(b)(1).

COPYRIGIT NOTICE The reports transmitted herewith each bear a Westinghouse copyright notice. The NRC is permitted to make the number of copies of the information contained in these reports which are necessary for its internal use in connection with generic and plant-specific reviews and approvals as well as the issuance, denial, amendment, transfer, renewal, modification, suspension, revocation, or violation of a license, permit, order, or regulation subject to the requirements of 10 CFR 2.390 regarding restrictions on public disclosure to the extent such information has been identified as proprietary by Westinghouse, copyright protection notwithstanding. With respect to the non-proprietary versions of these reports, the NRC is permitted to make the number of copies beyond those necessary for its internal use which are necessary in order to have one copy available for public viewing in the appropriate docket files in the public document room in Washington, DC and in local public document rooms as may be required by NRC regulations if the number of copies submitted is insufficient for this purpose. Copies made by the NRC must include the copyright notice in all instances and the proprietary notice if the original was identified as proprietary.

v t e Letter Sequence Response to RAI
TAC:MC4665, (Open)
Initiation Request, Request, Request, Request, Request, Request, Request, Request, Request, Request, Request Acceptance... Supplement, Supplement, Supplement, Supplement, Supplement Administration Meeting Questions 3 June 2005 9 February 2006 26 March 2008 18 February 2010 31 March 2010 18 May 2010 Answers 22 July 2005 6 September 2005 22 July 2005 Results Approval... Other: L-09-056, Downstream Effects for Recirculation Spray System Pumps and Low Head Safety Injection System Pumps, L-13-176, Generic Safety Issue 191 Resolution Plan, ML061380273, ML080220343, ML081230116, ML082740241, ML090750619, ML090900193, ML091050100, ML091240030
MONTHYEAR2008-03-21 [Table View]

L-05-140, Response to a Request for Additional Information (RAI Dtd August 2, 2005) in Support of License Amendment Request Nos. 302 and 173, Extended Power Uprate

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L-05-140, Response to a Request for Additional Information (RAI Dtd August 2, 2005) in Support of License Amendment Request Nos. 302 and 173, Extended Power Uprate

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