L-PI-11-060, Response to Requests for Additional Lnformation (RAI) Associated with Adoption of the Alternative Source Term (AST) Methodology

Response to Requests for Additional Lnformation (RAI) Associated with Adoption of the Alternative Source Term (AST) Methodology

ML111740145
Person / Time
Site:	Prairie Island
Issue date:	06/22/2011
From:	Schimmel M Northern States Power Co, Xcel Energy
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
L-PI-11-060
Download: ML111740145 (69)

Text

L-PI-11-060 10 CFR 50.90 U S Nuclear Regulatory Commission ATTN: Document Control Desk, Washington, DC 20555-0001 Prairie Island Nuclear Generating Plant Units 1 and 2 Dockets 50-282 and 50-306 License Nos. DPR-42 and DPR-60 Response to Requests for Additional lnformation (RAI) Associated with Adoption of the Alternative Source Term (AST) Methodologv (TAC NOS. ME2609 and ME2610)

References:

1. NSPM Letter to US NRC, "License Amendment Request (LAR) to Adopt the Alternative Source Term Methodology," dated October 27,2009 (ADAMS Accession No. ML093160583).

2. US NRC Letter to NSPM, "Prairie Island Nuclear Generating Plant, Units 1 and 2 - Request for Additional lnformation (RAI)

Associated with Adoption of the Alternative Source Term (AST)

Methodology (TAC NOS. ME2609 and ME261O)," dated May 12, 201 1 (ADAMS Accession No. ML103540433).

In Reference I , the Northern States Power Company, a Minnesota corporation doing business as Xcel Energy (hereafter "NSPM") , requested an amendment to the Technical Specifications (TS) for Prairie Island Nuclear Generating Plant (PINGP). The proposed amendment requested adoption of the Alternative Source Term (AST) methodology, in addition to TS changes supported by AST design basis accident radiological consequence analyses.

During a January 26, 201 1 teleconference, NSPM discussed delayed implementation of the AST LAR. It was noted that the delayed implementation could be documented as a License Condition. Enclosure 1 provides a proposed License Condition to address delayed implementation of the AST LAR. NSPM will implement the License Condition within 30 days following issuance of the AST License Amendment (LA), and implement the balance of the LA, in accordance with the terms of the License Condition.

1717 Wakonade Drive East a Welch, Minnesota 55089-9642 Telephone: 651.388.1121

Document Control Desk Page 2 In Reference 2, the Nuclear Regulatory Commission (NRC) Staff requested additional information to support their review of Reference 1. Enclosure 2 to this letter provides the responses to the Staff RAls, specifically, responses to RAls from the Reactor Systems Branch.

NSPM submits this supplement in accordance with the provisions of 10 CFR 50.90.

The supplemental information provided in this letter does not impact the conclusions of the Determination of No Significant Hazards Consideration and Environmental Assessment presented in the October 27, 2009 submittal, as supplemented by letters dated April 29, 2010 (ADAMS Accession No. ML101200083), May 25,2010 (ADAMS Accession No. ML101460064), June 23, 2010 (ADAMS Accession No. ML101760017), August 12,2010 (ADAMS Accession No. ML102300295), and December 17,2010 (ADAMS Accession No.

M L I 03510322).

In accordance with 10 CFR 50.91, NSPM is notifying the State of Minnesota of this LAR supplement by transmitting a copy of this letter to the designated State Official.

If there are any questions or if additional information is needed, please contact Mr. Gregory Myers, P.E., at 651-267-7263.

Summaw of Commitments This letter contains no new commitments or revisions to existing commitments.

I declare under penalty of perjury that the forgoing is true and correct.

Mark A. Schimmel Site Vice President, Prairie Island Nuclear Generating Plant Northern States Power Company - Minnesota Enclosures (2) cc: Administrator, Region Ill, USNRC Project Manager, PINGP, USNRC Resident Inspector, PINGP, USNRC State of Minnesota

ENCLOSURE l License Additional Conditions (Retyped)

Unit 1 6-3 Unit 2 6-3 4 pages follow

APPENDIX B ADDITIONAL CONDlTlONS FACILITY OPERATING LICENSE NO. DPR-42 Aniendnient lniplenientation Number Additional Conditions 158 The schedule for performing Surveillance Requirements October 31, (SRs) that are new or revised in Amendment No. 158 shall 2002 be as follows:

For SRs that are new in this amendment, the first performance is due at the end of the first sirtveillance interval, which begins on the date of implementation of this amendment.

For SRs that existed prior to this aniendment, whose intervals of performance are being reduced, the first reduced siirveillance interval begins tipon completion of the first sutveillatice pelformed after implementation of this amendment.

For SRs that existed priot to this amendment thai have modified acceptance criteria, the first perforniance is dire at the end of the surveillance intetval that began on the date the surveillance was last petfornied prior to the implementation of this amendment, For SRs that existed prior to this amendment, whose intervals of performance are being extended, the first extended sirtveillance interval begins upon completion of the last sulveillance perfornled prior to the implementation of this aniendment:

The licensee is a~rthorizedto relocate certain Tecllnical October 31, Specification requirements previously included in 2002 Appendix A to licensee-controlled docunients, as described in Table LR, "Less Restrictive Changes - Relocated Details," and Table R, "Relocated Specifications," attached to the NRC staff's safety evaluation dated July 26, 2002, Those requirements shall be relocated to the approptiate documents no late[ than October 31, 2002.

The Alternative Source Term (AST) License Amendments Within 90 days

-/-will be irnpleniented after installation of the Unit 2 after completion Replacement Stearn Generators (RSGs). of the outage in which the Unit 2 RSGs are installed Aniendment No,

APPENDIX B ADDITIONAL CONDITIONS FACILITY OPERATING LICENSE NO. DPR-42 Amendment Ncrmber Additional Conditions NSPM will provide the NRC written notification when Unit 2 Within 30 days RSG installation is complete and AST License Amendment after completion implementation has commenced. of the outage in which the Unit 2 RSGs are installed Amendment No.

APPENDIX B ADDITIONAL CONDITIONS FACILITY OPERATING LICENSE NO. DPR-60 Amendment lniplementation Number Additional Conditions Oate 149 The schedule for performing Sirrveillance Requirements October 31, (SRs) that are new or revised in Amendment No. 149 shall 2002 be as follows:

For SRs that are new in this amendment, the first performance is due at the end of the first surveillance intewal, which begins on the date of implenientation of this amendment, For SRs that existed prior to this amendment, whose intervals of performance are being reduced, the first reduced surveillance interval begins upon completion of the first surveillance performed after irnplenientationof this amendment.

For SRs that existed prior to this amendment that have modified acceptance criteria, the first performance is due at the end of the surveiliance interval that began on the date the suweillance was last pelformed prior to the implementation of this amendment.

For SRs that existed prior to this amendment, whose intervals of performance are being extended, the first extended surveillance interval begins upon conipletion of the last su~veillancepe~formedprior to the iniplementation of this amendment.

149 The licensee is authorized to relocate cettain Technical October 31, Specification requirements previously included in 2002 Appendix A to licensee-controlleddocuments, as described in Table LR, "Less Restrictive Changes - Relocated Details," and Table R, "Relocated Specifications,"attached to the NRC staff's safety evaluation dated July 26, 2002, Those requirements shall be relocated to the appropriate documents no later than October 31, 2002.

The Alternative Source Term License Amendments Within 90 days

-I-will be implemented after installation of the Unit 2 after completion Replacement Steam Generators (RSGs). of the outage in wtiich the Unit 2 RSGs are installed Amendment No.

APPENDIX B ADDITIONAL CONDITIONS FACILITY OPERATING LICENSE NO, DPR-60 Amendment Implenientation Number Additional Conditions Date NSPM will provide the NRC written notification when Unit 2 Within 30 days RSG installation is complete and AST License Amendment after completion iniplernentation has commenced. of the oirtage in whicti the Unit 2 RSGs are installed Amendment No.

NSPM Response to Reactor Systems Branch RAls Enclosure 2 Nuclear Regulatory Commission (NRC) Request for Additional Information (RAI)

In order for the NRC staff to continue its review, the following additional information is needed:

A. RAI Related to the MTO Analysis A. 1 If the licensee chooses to continue to use its simulator for the MTO analysis, it should provide additional information related to the computer codes and RCS physical models in the simulator for the NRC staff to review and approve. The additional information provided should include: a discussion of the methodology; computation device manuals; user's manuals and guidelines; scaling reports; assessment reports and uncertainty assessment reports as described in the applicable sections of Regulatory Guide 1.203, "Transient and Accident Analysis Methods."

The information should show that: the constituent equations representing the RCS thermal-hydraulics are correct and complete; the correlations for the heat transfer and flow rate determination are adequately supported by the applicable test data; the nodal scheme appropriately models the RCS; the mathematical methods provide stable solutions; the time step used for the mathematical solution does not result in divergent conditions; the system responses of the RCS for both with and without a loss of AC power are validated by comparing with the applicable integrated and separated effects test data; and the MTO analyses show that the assumptions and the plant conditions used result in a maximum response time for the AS? application.

Response

As described in the response to question 2, below, the Northern States Power Company, a Minnesota corporation, doing business as Xcel Energy (hereafter, "NSPM"), has decided to perform a Steam Generator Tube Rupture (SGTR) margin-to-overfill (MTO) Analysis aligning as closely as possible to the NRC approved methodology described in Westinghouse topical report WCAP-10698-P-A. Thus, NSPM is not using the simulator for the MTO analysis, with the exception of substantiating operator action times in support of the analysis described below.

Page 1 of 62 NSPM Response to Reactor Systems Branch RAls A.2 Alternatively, the licensee may perform an SGTR MTO analysis for PlNGP at current licensed thermal power conditions. The analysis should align as closely as possible to an NRC-approved methodology described in a Westinghouse topical report, WCAP-10698-P-A. However, since the licensee has stated that a limiting single failure is not in the PlNGP licensing basis, this exception to the WCAP-10698-P-A methodology will be acceptable. The requested analytical results should include sequences of the event with specification of operator actions and the associated times credited in the analysis, and the response of key plant parameters versus time.

Response

NSPM has performed sensitivity analyses to determine the limiting margin-to-overfill (MTO) scenarios at 1683 MWt, which is the current licensed reactor core power level of 1677 MWt, plus calorimetric uncertainties. The analyses followed the methodology in WCAP-10698-P-A, with the exception of the assumption of a single failure.

The analyses were performed using the LOFTTR2 thermal hydraulic model consistent with the methodology in WCAP-10698-P-A.

The results indicate a margin-to-overfill of 186 ft3 in the ruptured steam generator for the limiting scenario. The limiting scenario models 0%

steam generator tube plugging (SGTP), low decay heat, maximum safety injection (SI) enthalpy and minimum auxiliary feedwater (AFW) enthalpy.

No water is transferred into the steam lines.

The analyses were performed utilizing the configuration of the replacement steam generators (Framatome ANP 56119). As discussed in a 1/26/11 teleconference between NRC and NSPM, AST implementation will be delayed until after implementation of the Unit 2 replacement steam generator (RSG) is complete. See the Enclosure 1 for the associated License Condition.

Page 2 of 62 NSPM Response to Reactor Systems Branch RAls The sequence of events for the limiting scenario analysis is presented in Table 1. Figures 1 through 8 provide the time-dependant values of the following parameters for the limiting MTO scenario:

Reactor Coolant System (RCS) and Secondary Pressures (Intact and Ruptured Steam Generators)

Primary-to-Secondary Break flow rate Steam Generator (SG) Water Volumes (Intact and Ruptured Steam Generators)

Pressurizer Level Intact Steam Generator lnlet and Outlet Temperatures Ruptured Steam Generator lnlet and Outlet Temperatures Steam Generator Steam releases Steam Generator Narrow Range Level (Ruptured Steam Generator)

Table 1: Sequence of Events Event Tube Rupture 0 Reactor Trip 49 Auxiliary Feedwater (AFW) 50 Initiation Safety Injection (SI) Actuation 119 Ruptured SG AFW Isolation 251 Close Main Steam Isolation Valve 1130 (MSIV) lnitiate Cooldown with Intact SGs Terminate Cooldown I Terminate Delsressurization 1 1962 1 Stop SI Flow 2082 Balance Charging and Letdown 2982 Flows I Break Flow < 0 3212 Page 3 of 62 NSPM Response to Reactor Systems Branch RAls Figure 1: RCS and Secondary Pressures Page 4 of 62 NSPM Response to Reactor Systems Branch RAls Figure 2: Primary-to-Secondary Break Flow Rate Page 5 of 62 NSPM Response to Reactor Systems Branch RAls Figure 3: Steam Generator Water Volumes Page 6 of 62 NSPM Response to Reactor Systems Branch RAls Figure 4: Pressurizer Level Page 7 of 62 NSPM Response to Reactor Systems Branch RAls Figure 5: Intact SG Inlet and Outlet Temperatures I r:toc; Sb; C o I i1 L e g I l r ~ I t e t T ~ n r p et a t i l t r_.

Intac; 56 Hot Lcg I n l e t Tempcraturc Page 8 of 62 NSPM Response to Reactor Systems Branch RAls Figure 6: Ruptured SG lnlet and Outlet Temperatures R u p t u r e d SG C o l d L e g O u t l e t T e m p e r a t u r e R u p t u r e SG Hot Leg l n l e t T e m p e r a t u r e Page 9 of 62 NSPM Response to Reactor Systems Branch RAls Figure 7: SG Steam Releases R u p t u r e d S G I n t o c t SG Page 10 of 62 NSPM Response to Reactor Systems Branch RAls Figure 8: Ruptured SG Narrow Range Level Page 11 of 62 NSPM Response to Reactor Systems Branch RAls In addition to providing the analytical results, please address the following:

A.2.a Address compliance with the conditions and restrictions specified in the NRC safety evaluation reports approving the WCA P-10698-P-A methodology.

Response

NRC safety evaluation report approving the WCAP-10698-P-A methodology, dated March 30. 1987, Enclosure 1, Section (D) identifies plant specific inputs that are required to support a margin to overfill analysis that references WCAP-10698-P-A (for clarification, the plant specific inputs identified in the NRC SER for WCAP-10698-P-A are identified in italics).

(1) Each utility in the SG TR subgroup must confirm that they have in place simulators and training programs which provide the required assurance that the necessary actions and times can be taken consistent with those assumed for the WCAP-10698 design basis analysis. Demonstration runs should be performed to show that the accident can be mitigated within a period of time compatible with overfill prevention, using design basis assumptions regarding available equipment, and to demonstrate that the operator action times assumed in the analysis are realistic.

Compliance A NSPM fleet administrative procedure establishes the process to capture analysis-credited operator actions, such as SGTR analysis operator actions, and documents and validates the actual timing of operator actions. The Prairie Island Nuclear Generating Plant (PINGP) Operations Manager has overall responsibility for the operator action time validation process.

NSPM procedures require consideration of all the time critical operator actions necessary to accomplish the nuclear safety functions for each design basis event. The safety analyses document the time critical operator actions and their associated instrumentation and controls required for design basis events. Any equipment required to perform time critical operator actions is identified and assured that it is available.

Each time critical operator action (TCOA) is validated on a periodic basis or as needed in response to plant procedure changes, crew Page 12 of 62 NSPM Response to Reactor Systems Branch RAls human performance methodology changes, and plant modifications that affect completion time.

Simulator validation of time critical operator actions is performed unless:

e Simulator validation is impractical due to modeling constraints; Time critical operator actions are performed outside the control room; e Simulator validation is combined with walkthrough validation since the event involves control room and local operator action; e For changes that do not warrant simulator validation due to nature or scope The specific time critical tasks are controlled in a station specific procedure maintained by station Operations. The procedure identifies the licensing and design basis requirements for each time critical operator action, the time requirement and the time validation and training requirements.

The response to RAI A.2.f provides confirmation that operator actions credited in the analysis are consistent with procedures and action times are conservative, resulting in a minimum margin to overfill.

(2) A site specific SGTR radiation offsite consequence analysis which assumes the most severe failure identified in WCAP-10698, Supplement 1. The analysis should be petformed using the methodology in SRP Section 15.6.3, as supplemented by the guidance in Reference (I).

Compliance As described below in the response to RAI A.2.g, a SGTR radiological consequence analysis was provided by Reference 1, and supplemented by Reference 3. As described below in the response to RAls B . l and B.2, a supplemental thermal hydraulic analysis demonstrates that the thermal hydraulic mass transfers resulting from realistic modeling of operator actions following a SGTR event are bounded by the mass transfers modeled in the previously submitted SGTR radiological consequence analysis. As described above, the MTO analysis predicts that the ruptured Page 13 of 62 NSPM Response to Reactor Systems Branch RAls steam generator will not be overfilled. Thus, liquid will not be released through the SG PORV or Safety Valves. Therefore, the previously submitted SGTR radiological consequence analysis is bounding.

( 3 ) An evaluation of the structural adequacy of the main steam lines and associated supports under water-filled conditions as a result of SG TR overfill.

Compliance As described below in the response to RAI A.2.c the analysis results determine that there will be no liquid release or water filled conditions in the main steam line. Therefore, an evaluation of the structural adequacy of the main steam lines and associated supports under water filled conditions is not necessary.

(4) A list of systems, components, and instrumentation which are credited for accident mitigation in the plant specific SG TR EOP(s).

Specify whether each system and component specified is safety grade. For primary and secondary PORVs and control valves specify the valve motive power and state whether the motive power and valve controls are safety grade. For non-safety grade systems and components state whether safety grade backups are available which can be expected to function or provide the desired information within a time period compatible with prevention of SGTR overfill orjustify that non-safety grade components can be utilized for the design basis event. Provide a list of all radiation monitors that could be utilized for identification of the accident and the ruptured steam generator and specify the quality and reliability of this instrumentation if possible. If the EOPs specify steam generator sampling as a means of ruptured SG identification, provide the expected time period for obtaining the sample results and discuss the effect on the duration of the accident.

Compliance The PlNGP SGTR Emergency Operating Procedure (EOP),

identifies the following systems, components, and instruments for accident mitigation. Note that the EOP identifies multiple means and equipment available to the operators to perform required mitigation functions. Therefore, not all of the equipment in Table 2 below is required for any postulated SGTR event.

Page 14 of 62

Enclosure 2 NSPM Response to Reactor Systems Branch RAls Table 2 Systems, Components, and Instruments Available for SGTR Mitigation 1 Safety I If Non-Safety Equipment 1 Equipment1 class Related, is ~ a i e t y Discussion Component ID# Component Name (SR, AQ, Grade Backup NSR) Available (Y or N)

Main Steam CV-31 Og8, 31Og9 Safety Isolation Valves CV-31116, 31 117 Related SR MSlvs MV-32045, 32047 MSIV Bypass MV-32048. 32050 Valves The motive power to open the SG PORV is supplied from the Instrument Air (IA) system; which is reliable but not safety related. Redundant IA compressors are SG Power powered from diesel-backed safeguards Operated Relief electrical buses. The air compressors are Valves (PORVs) automatically loaded on to the emergency diesel generators in response to a loss of offsite power (LOOP). This is further described below in the response to RAI A.2.d.

The power supply to the SG PORV control Non-Safety 1HC-468,478 SG PORV Control board controllers is safety related. The Related N 2HC-468,478 Board Controllers power supply to the controller will be NSR available during a LOOP.

Page 15 of 62

Enclosure 2 NSPM Response to Reactor Systems Branch RAIs Table 2 Systems, Components, and Instruments Available for SGTR Mitigation Safety If Non-Safety Equipment I Equipmentl Class Related, is Safety Discussion Component ID# Component Name (SR, AQ, Grade Backup NSR) Available (Y or N)

The power supply to the SG PORV control SG PORV Control board valve position indicating lights is 44032,44033 NSR safety related. The power supply to the Board Indicating 44532,44533 valve position indicating lights will be Lights available during a LOOP.-

I Steam Supply from I Ruptured SG to MV-32016, 32017

~ ~~~i~~~~ b i ~ ~

MV-3201" 32020 Auxiliary Feedwater MV-32044, 32051 SG Blowdown MV-32043, 32049 Isolation Valve Page 16 of 62

Enclosure 2 NSPM Response to Reactor Systems Branch RAls Table 2 Systems, Components, and Instruments Available Safety Equipment I Equipment1 class Related, is Safety Discussion Component ID# Component Name (SR, AQ, Grade Backup NSR)

The motive power to open the Pressurizer PORVs is IA, which is reliable but not safety-related. Redundant IA compressors are powered from diesel-backed safeguards electrical buses. The air compressors are automatically loaded on to the emergency diesel generators in response to a loss of offsite power (LOOP). In addition, a Seismic Category I passive air accumulator is provided inside of containment as a back-up air supply for the Pressurizer PORVs.

The power supply to the Pressurizer CS-46259,46260 Pressurizer PORV PORV control switches is safety related.

NSR CS-49576, 49577 Control Switches The power supply to the control switches will be available durina a LOOP Pressurizer CV-31329 Auxiliary Spray SR NIA CV-3 1421 Valves MV-32195, 32196 Pressurizer Block SR NIA MV-32197,32198 Valves Page 17 of 62

Enclosure 2 NSPM Response to Reactor Systems Branch RAls Table 2 Systems, Components, and Instruments Available for SGTR Mitiaation Safety If Non-Safety Equipment 1 Equipment1 Class Related, is Safety Discussion Component ID# Component Name (SR, AQ, Grade Backup NSRI Available (Y or NI The power supply to the pressurizer CS-46241,46242 Pressurizer NSR heaters is from a safety related power CS-49555,49556 Heaters source.

I / pressurizer I I The power supply to the Pressurizer I CS-46295,49579 1 Auxiliary Spray Valve Control I NSR I Auxiliary Spray valve control switches is safety related. The power supply to the I 1 Switches 1 I control switches will be available during a LOOP Safety Injection (SI)

Pumps Chemical and Volume Control SR NIA System (CVCS)

Charging Pumps The analysis credits operation of the letdown or excess letdown system for balancing CVCS charging flow following CVCS Letdown Various NSR N securing of the SI Pumps (with appropriate System time delay). Note: excess letdown provides a backup method to normal letdown.

Safety Injection SR NIA 1 Reset Circuitrv Page 18 of 62 NSPM Response to Reactor Systems Branch RAls Table 2 Systems, Coml ~onents,and Instruments Available For SGTR Mitigation Safety If Non-Safety I' Equipment 1 Equipment/ Class Related, is safety Component ID# Discussion Component Name (SR, AQ, Grade Backup NSR) Available (Y O;N)

Containment Isolation Reset SR NIA Circuitry Redundant IA compressors are powered from diesel-backed safeguards electrical lnstrument Air buses. The air compressors are NSR N Compressors automatically loaded on to the emergency diesel generators in response to a loss of offsite power (LOOP).

Control Switches for providing SR NIA lnstrument Air to Containment lnstrument Loops from sensing line through transmieer are safety related. The indication is on the non safety related side SG Water Level of the current to pneumatic transmitter (111).

Indication - Narrow NSR The power supply is safety related and will Range be available during a LOOP. Three indication channels for each Steam Generator are available in the Control Page 19 of 62

Enclosure 2 NSPM Response to Reactor Systems Branch RAls Table 2 Systems, Components, and Instruments Available for SGTR Mitigation Safety 1 If Non-Safety Equipment 1 Equipment1 Class Related, is Safety Discussion Component ID# Component Name (SR, AQ, Grade Backup NSR) Available (Y or N)

TEA3234 to 13272 Core Exit TEI 3407 to 13445 Thermocou~les 1 SR 1 lnstrument Loops from sensing line through transmitter are safety related. The

- 1 1LI-426, 427, 428 Pressurizer LA Vla+-~ L G I Augmented Quality indicators are augmented quality. The power supply is safety related and will be 2L1-426, 427, 428 Level lndication AQ available during a LOOP. Three indication channels per unit are available in the Control Room.

The indicators and transmitters are augmented quality. The power supply is RCS Pressure NIA safety related and will be available during lndication a LOOP. Two indication channels per unit are available in the Control Room.

lnstrument Loops from sensing line through transmitter are safety related. The indicators are non safety related. The SG Pressure NSR N power supply is safety related and will be lndication available during a LOOP. Three indication channels per Steam Generator are available in the Control Room.

Page 20 of 62 NSPM Response to Reactor Systems Branch RAls Table 2 Systems, Components, and Instruments Available for SGTR Mitigation Safety If Non-Safety Equipment / Equipment/ Class Related, is Safety Discussion Component ID# Component Name (SR, AQ, Grade Backup NSR) Available (Y or N)

Radiation monitor is non safety related.

The radiation monitor is maintained and Condenser Air N tested in accordance with the Offsite Dose Ejector Radiation NSR See Note 1 Calculation Manual. The power supply to Monitor the radiation monitor is safety related and will be available during a LOOP.

The radiation monitor is maintained and Steam Generator tested in accordance with the Offsite Dose N

Blowdown Liquid NSR Calculation Manual. The power supply to See Note 1 Radiation Monitor the radiation monitor is safety related and will be available during a LOOP.

Radiation monitor is non safety related.

The radiation monitor is maintained and tested in accordance with the Offsite Dose Main Steam Line NIA Calculation Manual. The power supply to NSR Radiation Monitor See Note 1 the radiation monitor is non-safety related, backed up by a non-safety related diesel generator and expected to be available during a LOOP.

1. The installed radiation monitors and the SG level transmitters are used in the EOPs to identify the ruptured SG. As directed by the Emergency Operating Procedures, SG water sampling is performed to confirm the identification of the ruptured SG during a SGTR event that does not result in abnormal radiation monitor indication. The high primary to secondary flow rate due to a design basis tube rupture results in SG water level increase that provide relatively quick indication of a ruptured SG. SG chemistry sample analysis time is not a critical aspect of the accident mitigating actions for scenarios that could be challenging with respect to overfill. Therefore, the time duration for sampling and analysis of SG secondary water would not delay the response to this event.

Page 21 of 62 NSPM Response to Reactor Systems Branch RAls (5) A survey of plant primary and "balance-of-plant" systems design to determine the compatibility with the bounding plant analysis in WCAP-10698. Major design differences should be noted. The worst single failure should be identified if different from the WCA P-10698 analysis and effect of the difference on the margin to oven'ill should be provided.

Compliance Consistent with the reference plant from WCAP-10698-P-A, PINGP Units 1 and 2 are Westinghouse designed plants utilizing similar features such as reactor trip setpoints, safety injection system, auxiliary feedwater system, SG relief valves, and emergency operating procedures for the SGTR scenario. PINGP plant-specific inputs were used in the analysis and applied consistent with the WCAP-10698-P-A methodology. There are no major design differences between the WCAP-10698-P-A reference plant and the PINGP Units that would affect the methodology application. Also, the exclusion of a single failure from the analysis is acceptable and consistent with the PINGP current licensing basis for the SGTR scenario. In addition, the NRC recently approved application of this methodology for the Point Beach Nuclear Plant (ADAMS Accession Nos. MLI 10880039 and MLI 10450159), which is a very similar Westinghouse NSSS two-loop plant, as documented by Reference 4.

Page 22 of 62 NSPM Response to Reactor Systems Branch RAls A.2.b List in a table the nominal values with the associated uncertainties, and corresponding values used in the MTO analysis for the major input initial conditions described in WCA P-7 0698-P-A. Discuss the bases used to select the numerical values of the input parameters and show that the numerical values used are conservative, resulting in a minimum SG MTO during an SGTR event. In addition, provide a basis for the target cooldown temperature used in the analysis.

Response

NSPM has performed a series of analyses of the limiting margin-to-overfill (MTO) scenarios 1683 MWt, which is the current licensed reactor core power level of 1677 MWt, plus calorimetric uncertainties..

The analyses followed the methodology in WCAP-10698-P-A, with the exception of the assumption of a single failure. A comparison of the WCAP-10698-P-A modeling to that used in the PlNGP SGTR MTO analysis is provided in Table 4 below. The nominal values, associated uncertainties and corresponding values used in the MTO analyses for major input initial conditions are provided by Table 3 below.

Page 23 of 62

Enclosure 2 NSPM Response to Reactor Systems Branch RAls Table 3 Major Input Initial Conditions Parameter Nominal Value Uncertainty 1 Value Modeled in MTO Analysis Core Power 1677 MWt 0.36% or 1683 MWt 6 MWt Reactor Coolant System 2250 psia 2190 psia Pressure I I I Pressurizer level 33% span 5% span 38% span Steam Generator Level 44% 10% NRS 73% NRS' Narrow Range Span (NRS)

Low Pressurizer Pressure 1915 psia 65 psi 1980 psia Reactor Trip Setpoint Low Pressurizer Pressure Safety 1845 psia 103 psi 1948 psia2 Injection Actuation I.

Includes 10% increase in initial steam generator mass plus mass added due to turbine runback.

2.

The nominal trip setpoint is 1802.1 psia. The modeled value is conservatively based on the actual plant setting instead of the lower nominal setpoint.

Page 24 of 62

Enclosure 2 NSPM Response to Reactor Systems Branch RAls Table 4: Comparison of WCAP-10698-P-A Modeling to the Analysis Assumptions WCAP-10698-P-A Modeling Direction of Conservatism Initial Conditions nominal + uncertaint nominal + uncertaint RCS Pressure Pressurizer Water Level Steam Generator (I)

Secondary Mass Break Location 1 2:;: 1 2:;:

Maximum Maximum Offsite Power Availability Offsite Power 1 LOOP # LOOP Protection Setpoints and Errors Minimum Turbine Trip Delay Minimum SG Relief or Safety Valve Minimum Minimum setpoint Pressurizer pressure trip Maximum Maximum setpoint Pressurizer pressure SI Maximum Maximum setpoint Safeguards Capacity SI Flow Rate Maximum Maximum AFW Flow Rate (isolation Minimum ~aximum(~)

on SG level)

Minimum Minimum AFW Temperature Maximum ~inimurn(*)

Control Systems CVCS Operation Not operating Pressurizer Heater Control Not operating Not operating Turbine runback mass Included Included penalty Reactor Coolant Pump Not Operating Not Operating Running Decay Heat 1 1 Maximum I Minimum (ANS 1979-2d2))

Single Failure Single Failure Included I Not Included, consistent with current licensina basis Page 25 of 62

Enclosure 2 NSPM Response to Reactor Systems Branch RAls Table 4: Comparison of WCAP-10698-P-A Modeling to the Analysis Assumptions I WCAP-I 0698-P-A Modeling Direction of Conservatism Operator Actions 0 1 1 Maximum 1 Maximum (1) Consistent with the discussion of power in WCAP-10698-P-A, the initial steam generator mass is more conservatively calculated without inclusion of the initial power uncertainty since it results in a higher mass.

(2) Plant-specific sensitivities for PlNGP concluded that it is more conservative to model minimum AFW temperature and decay heat rather than maximized as prescribed by WCAP-10698-P-A for the margin-to-overfill analysis. Also, plant-specific sensitivities concluded it is more conservative to model maximum AFW flow rate rather than minimum as prescribed by WCAP-10698-P-A for the margin-to-overfill analysis.

(3) It is conservative to model charging flow in this analysis since its initiation is modeled by operator actions well after reactor trip. When charging flow is initiated automatically, its impact in delaying reactor trip is the basis for no charging flow being modeled per WCAP-10698-P-A.

The emergency operating procedures provide a table of reactor coolant system cooldown target temperatures corresponding to a range of secondary pressures. The target cooldown temperature was taken from the EOP table and was based on the conservatively modeled steam generator PORV setpoint modeled in the analyses.

The steam generator PORV setpoint modeled is 1020 psia, which corresponds to the no-load reactor coolant system average temperature. A target temperature of 5 0 5 ' ~was chosen in accordance with the emergency operating procedures.

Page 26 of 62 NSPM Response to Reactor Systems Branch RAls A.2.c Ensure that the limiting liquid release pathway and scenario are identified. Include consideration of the steam line equipment water-release failures discussed in WCAP-11002-P (Note that the NRC staff discussed WCAP-I 1002-P in its evaluation of WCAP-10698-P-A, but did not find that it provided an acceptable method for performing a licensing basis safety analysis). If a liquid release is predicted, provide analyses of the static and dynamic structural effects in the main steam system and of the consequences of passing water through the steam pressure relief valves.

Response

Based on the analyses described above there is no predicted liquid release or water filled conditions in the main steam lines. Therefore, an analysis of the static and dynamic structural effects of the main steam system and the consequences of passing water through the steam pressure relief valves is not necessary.

Page 27 of 62 NSPM Response to Reactor Systems Branch RAls A. 2.d Under the assumed LOOP conditions, address the functionality of each power operated relief valve (PORV). Discuss what, if any, mitigating function the PORV provides, and its capability to perform that function under the assumed LOOP conditions. If the valve's actuation must be manual, provide information to demonstrate that the operator is capable of actuating the valve within the analytically assumed time.

Response

Each SG has one PORV located on the main steam line between the SG and the MSIV. As part of the LOFTTR2 modeling for the SGTR MTO analysis, the PORV on each SG petforms the following functions:

The PORV for the ruptured SG is closed. The position of the PORV during normal power operation is de-energized in the closed position and the fail safe position for the PORV is closed.

The PORV for the intact SG is used by the operator in the Control Room to cooldown the Reactor Coolant System (RCS).

The PORV controllers are powered from 120 VAC instrumentation buses; which are safety related (battery backed). The PORV position indication lights are powered from 125 VDC buses, which are powered from safety-related batteries. The PORVs require air to operate remotely from the control room. The PORVs receive air from the instrument air (IA) system headers, which supply air to both Unit 1 and 2 PORVs. There are three instrument air compressors. During normal power operation, two compressors are operating to provide compressed air for both units. One compressor is fully loaded and the other compressor is loaded part of the time. The IA compressors are powered from the safety-related 480 VAC buses, which, during a LOOP, are powered from emergency diesel generators (EDGs).

During a LOOP the EDGs will automatically restore power to the safeguards buses. The IA compressors are automatically loaded on to the associated EDG at step 5 (30 seconds following the occurrence of the LOOP assuming 10 seconds for the EDG to be up to speed and voltage) with no action required from the control room operators.

During the 30 seconds that the IA compressors are not operating prior to being loaded on the EDGs, the IA system air receivers maintain IA system pressure. In addition, the SG PORVs or Pressurizer PORVs are not credited in the analysis during the brief time period following the initiation of the accident that the IA compressors are not operating.

Page 28 of 62 NSPM Response to Reactor Systems Branch RAls A.2.e One of the key parameters that will affect the results of the SG MTO analysis during an SG tube rupture event is the initial SG water level, which is a function of the initial power level. The MTO analysis to be submitted should consider the effects of initial SG water levels corresponding to power levels that capture 95 percent of the operating time during a fuel cycle. Also, for the range of power levels that envelop 95 percent of operating time, provide trending data for the corresponding SG water levels to show that conservative initial SG water levels (with the inclusion of measurement uncertainties, thus resulting in a smaller margin to SG overfill) have been selected,

Response

PlNGP operates at power levels of approximately 100% for more than 95% of the operating time during a fuel cycle. The data shown on the attached Figure 9 for Unit 1 and Figure 10 for Unit 2 represents the time period of July 2008 through May 201 1. On Figure 9, the entire time period of early September to late November 2009, the reactor was shutdown.

The 100% power nominal setpoint for steam generator level control is 44% narrow range. Steam Generator narrow range water level data for both Unit 1 and Unit 2 was reviewed for the same time period used in Figures 9 and 10 for displaying power. The data is shown on the attached Figures. For each Unit a Figure is provided for each Steam Generator indicated narrow range water level for the same periods of time that are shown in Figures 9 and 10 for the power levels. As shown in the Steam Generator water level plots, during full power operation, the water level varies from the program level by a small amount. The data shows that this variance is less than +I- 1%

indicated level. As shown on Table 3, included as part of the response to RAI A.2.b, above, an assumed initial SG narrow range water level of 73% is used in the MTO analysis. It is noted that the 73% initial SG water level includes accounting for the turbine runback.

Thus, actual steam generator indicated level for 100% steady state power operation is bounded by the initial SG water level assumed in the analysis.

Page 29 of 62 NSPM Response to Reactor Systems Branch RAls Figure 9, Page 1 Unit 1 Power Level and Steam Generator Narrow Range Water Level Unit 1 Power r(

Date Page 30 of 62 NSPM Response to Reactor Systems Branch RAls Figure 9, Page 2 Unit 1 Power Level and Steam Generator Narrow Range Water Level Date I Date Page 31 of 62 NSPM Response to Reactor Systems Branch RAls Figure 10, Page 1 Unit 2 Power Level and Steam Generator Narrow Range (NR) Water Level Power Date I Date Page 32 of 62 NSPM Response to Reactor Systems Branch RAls Figure 10, Page 2 Unit 2 Power Level and Steam Generator Narrow Range (NR) Water Level Date

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A Page 33 of 62 NSPM Response to Reactor Systems Branch RAls A.2.f Identify operator actions and associated action times credited in the analysis. Where an operator action is credited, confirm that such action is consistent with station procedures and action times are conservative, resulting in a minimum SG MTO.

Response

The operator actions and associated time frames credited in the MTO analysis are shown in the following table.

Table 5 Operator Actions Credited in Margin to Overfill Analysis Operator Action I Time for Operator Action I

Isolated based on SG water Isolation of AFW to the ruptured level SG (see below discussion) lnitiation of RCS cooldown time 19 minutes following reactor trip lnitiation of RCS depressurization following termination of RCS 4 minutes cooldown Secure Safety Injection pumps following termination of RCS 2 minutes depressurization Balance letdown and charging following securing Safety Injection 15 minutes Pumps.

Isolation of AFW is based on Steam Generator water level.

Emergency Operating Procedures direct control room operators to isolate AFW to the ruptured SG when the indicated water level is greater than 5%. To be conservative, the analysis assumes that this action is not performed until the indicated water level reaches 35%. A SG water level of 35% is conservative relative to values observed in the simulator and result in a minimum margin to overfill.

The operator actions credited in the analysis are consistent with the Emergency Operating Procedures (EOPs) for mitigating a SGTR.

These same EOPs are used for training and simulator time validation.

The operator action times credited in the analysis are conservative and result in a minimum margin to overfill.

Page 34 of 62 NSPM Response to Reactor Systems Branch RAls A.2.g Update the licensing basis radiological consequence analyses for the AST conditions to reflect radiological consequences of the above-identified limiting release, should they be more severe than the current, proposed, radiological analysis. Since the NRC staff is a110 wing the single failure exception to the WCAP- 10698-P-A methodology, the above requested analysis represents an event that has a significantly higher likelihood of occurrence.

Response

As described above, the MTO analysis predicts that the ruptured steam generator will not be overfilled. Thus, liquid will not be released through the SG PORV or Safety Valves, and the SGTR radiological consequence analysis provided in the Reference 1 LAR, as supplemented by Reference 2 remains bounding. Therefore, there is no need to update the radiological consequence analysis previously provided.

Page 35 of 62 NSPM Response to Reactor Systems Branch RAls A. 2.h Identify how procedures address the steam generator overfill condition. What parameters do operators monitor to help ensure that overfill does not occur?

Response

The PINGP procedural guidance for a SGTR event is consistent with Westinghouse Owners' Group (WOG) Emergency Response Guidelines (ERGS). For a SGTR event with loss of offsite power, as the event progresses, water level in the ruptured steam generator could potentially go off scale high on control room indications. Once this condition is reached, however, there is significant volume (approximately 1300 ft3) available to accommodate break flow into the ruptured steam generator. In order to minimize the potential for overfill, the procedural guidance directs the operator to continue with rapid cooldown and depressurization of the RCS, secure safety injection, and maintain RCS and ruptured steam generator pressures equal until transition to a recovery procedure.

Page 36 of 62 NSPM Response to Reactor Systems Branch RAls A.2.i For any revised radiological consequence analyses, provide the basis for the assumed flashing fraction, if it is less than 100 percent.

Response

This response is not required as, described above in the response to question 2.g, it was not necessary to update the radiological consequence analyses.

Page 37 of 62 NSPM Response to Reactor Systems Branch RAls B. RAI Related to the SGTR Mass Release Analvsis 6.I Information on page 116 of the October 27, 2009 LAR indicates that the results of a recent Westinghouse SGTR analysis were used to determine:

(1) primary coolant releases to the ruptured SG; (2) steam mass releases from ruptured SG to the environment; and (3) steam mass releases from intact SG to the environment.

Provide a discussion of the Westinghouse SGTR analysis for mass releases determination and verify thaf the methods used in the analysis are NRC- approved methods, and address compliance with restrictions and conditions specified in the NRC safety evaluation report approving the methods and computer codes. The requested information should also include the plant parameters considered in the analysis, identify the major input initial conditions and the worst single failure used in the analysis, discuss the bases used to select the numerical parameters and demonstrate thaf the numerical values with consideration of the uncertainties and fluctuations around the nominal values are conservative, resulting in maximum mass releases during an SGTR event. The results to be provided should include sequences of the event with specification of operator actions, associated times credited in the analysis and their bases for acceptance, and the response of key parameters versus time.

Also, address the acceptability of the analysis performed at the extended power uprate (EPU) power level to the AST application, which is based on the current power level.

Response

As indicated in Section 3.7.5.2 (page 114) of Reference I, the current licensing basis analysis for the SGTR is described in the Updated Safety Analysis Report (USAR) (Section 14.5.4.3) and is consistent with that contained in the original Final Safety Analysis Report (FSAR). This analysis method is the original and current licensing basis for PlNGP Units 1 and 2. It also was used as the basis for the SGTR dose analyses in AST applications for a number of other plants. NRC approval of these applications is documented in References 4 through 9. As discussed further below, computer codes are not used for the analysis, specific operator actions are not modeled and a detailed sequence of events is not generated. The PlNGP licensing basis does not include consideration of a single failure. The calculation includes conservative consideration of a higher power level corresponding to a planned extended power uprate (EPU) power level which bounds current operation since it results in Page 38 of 62 NSPM Response to Reactor Systems Branch RAls increased steam releases from the ruptured and intact steam generators (SGs). The calculations will be repeated in detail for the EPU and confirmed to remain bounding.

The SGTR calculations performed for the earlier Westinghouse plants, including PINGP, did not include a computer analysis to determine the plant transient behavior following a SGTR. Rather, a simplified thermal-hydraulic approach was utilized. This simplified thermal-hydraulic analysis assumes that primary-to-secondary break flow continues until 30 minutes from the start of the event and includes conservative assumptions that maximize the primary to secondary break flow and the steam release to the atmosphere for use in calculating the radiological dose consequences of the event. The current licensing basis for PINGP Units 1 and 2 is consistent with plants which received their operating license prior to the R.

E. Ginna Nuclear Power Plant SGTR event which prompted development of the WCAP-10698-P-A steam generator tube rupture methodology.

The accident considered is the double-ended rupture of a single steam generator tube. The primary to secondary break flow rate is calculated using the orifice equation and neglecting the frictional losses in the tube.

It is assumed that the primary-to-secondary break flow following an SGTR results in depressurization of the reactor coolant system (RCS), and that reactor trip and safety injection (SI) are automatically initiated on low pressurizer pressure. The analysis assumes that reactor trip and SI actuation occur simultaneously when the pressurizer pressure decreases to the SI actuation setpoint. Loss of offsite power (LOOP) is assumed to occur at reactor trip resulting in the release of steam to the atmosphere via the steam generator safety valves. Immediately following reactor trip and SI actuation it is assumed that the RCS pressure stabilizes at the equilibrium point where the incoming SI flowrate equals the outgoing break flowrate. The equilibrium primary-to-secondary break flow is assumed to persist until 30 minutes after the initiation of the SGTR.

A portion of the break flow will flash directly to steam upon entering the secondary side of the ruptured SG. Although not included in previous PINGP SGTR calculations, the calculations performed to provide input to the radiological consequences analysis for the LAR incorporates a break flow flashing fraction. Since a transient break flow calculation is not performed, a detailed time dependent flashing fraction that incorporates the expected changes in primary side temperatures cannot be calculated.

Instead, a conservative calculation of the flashing fraction is performed using the limiting conditions from the break flow calculation. Two time intervals are considered, as in the break flow calculations: pre- and post-reactor trip (SI initiation occurs concurrently with reactor trip). Since the RCS and SG conditions are different before and after the trip, different Page 39 of 62 NSPM Response to Reactor Systems Branch RAls flashing fractions would be expected. For the flashing fraction calculations it is conservatively assumed that all of the break flow is at the hot leg temperature and that there is no reduction in hot leg temperature despite the reactor trip and subsequent plant cooldown. This is an especially limiting assumption since it maintains a constant flashing fraction from the time of trip until 30 minutes when break flow is terminated, while in an actual SGTR the operators must perform the plant cooldown using the intact SG to assure subcooling at the ruptured SG pressure and this cooldown must be performed at a point in the transient well before break flow termination.

The steam released from the steam generators to the environment after reactor trip until 30 minutes is determined from a mass and energy balance for the primary and secondary systems. The energy which must be dissipated during this period includes the energy generated in the core and the change in the plant sensible heat between the initial and final conditions. The steam released from the ruptured SG is determined by dividing the total steam release by the number of steam generators in the plant. This is a conservative simplification since it assumes that the ruptured SG participates equally in removing the decay heat in the period from reactor trip until break flow termination while the plant emergency operating procedures instruct that only the intact SG should be used to perform the cooldown. The steam release calculation also conservatively neglects energy absorption by the injection of relatively cold safety injection flow directly into the RCS.

After 30 minutes, it is assumed that steam is released only from the intact SG in order to dissipate the core decay heat and to cool the plant down to the residual heat removal (RHR) system operating conditions. (During post-SGTR cooldown, the pressure in the ruptured steam generator is assumed to be decreased by the backfill method in which core decay heat and RCS fluid energy is dissipated by releasing steam from the intact steam generator. This is the preferred approach in the plant emergency operating procedures since it minimizes the radioactivity released to the atmosphere.) A primary and secondary side mass and energy balance is used to calculate the steam release from the intact SG from 0 to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, from 2 to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, and from 8 to 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> when the RHR is assumed to be in service removing all decay heat.

A summary of the key inputs used in the calculation follows:

0 Core power level of 1811 MWt Nominal RCS pressure of 2250 psia 0 RCS average temperature range of 560.9"F to 574°F 0% to 10% steam generator tube plugging (SGTP)

Page 40 of 62 NSPM Response to Reactor Systems Branch RAls e AREVA Model 56/19 SGs for Unit 1 and Westinghouse Model 51 SGs for Unit 2 Low pressurizer pressure SI actuation setpoint = 1845 psia

• Lowest steam generator safety valve reseat pressure = 1016 psia (includes 4% main steam safety valve (MSSV) blowdown and 3%

tolerance) e Maximum high head safety injection (HHSI) flow rates are assumed. The injection flow is used to determine the equilibrium RCS pressure, where injection flow equals break flow and the corresponding break flow is modeled from reactor trip until 30 minutes. Transient changes in pressure would reduce the injection flow and result in break flow rates lower than this equilibrium value. These are not considered.

Decay heat based on the 1971 American Nuclear Society (ANS) decay heat model +20%

Eight distinct cases were considered. The first four cases modeled the Unit 1 SGs at the varying conditions of 0% and 10 % SGTP (and the associated secondary side conditions), and high and low values for the RCS average temperature. The second four cases modeled the Unit 2 SGs at the same varying combinations of tube plugging, and RCS average temperature. These 8 cases were considered individually to determine the primary-to-secondary break flow and steam releases to the atmosphere for the dose analysis between 0 and 30 minutes. The limiting break flow from all of the different calculations along with the limiting steam released to the atmosphere are used in the dose calculation. A single calculation was performed to calculate the long-term steam releases from the intact steam generator for the time intervals 0 to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, 2 to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, and 8 to 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br />. The Unit 2 SG configuration provided the bounding break flow and steam releases.

The break flow flashing fraction is based on the difference between the primary side fluid enthalpy and the saturation enthalpy on the secondary side. Therefore, the highest flashing will be predicted for the case with the highest primary side temperatures. Similarly, a lower secondary side pressure maximizes the difference in the primary and secondary enthalpies, although a lower pressure would have a higher heat of vaporization that would result in less flashing. The highest possible pre-trip flashing fraction based on the range of operating conditions covered by this analysis is for a case with a hot leg temperature of 606.8"F, RCS pressure of the SI setpoint of 1845 psia and initial secondary pressure of 740 psia. All cases consider the same post-trip RCS equilibrium pressure of 2062 psia and post-trip SG pressure of 1016 psia. The corresponding calculated flashing fractions are 0.18 before trip and 0.12 after trip.

Page 41 of 62 NSPM Response to Reactor Systems Branch RAls The results of the analysis are reflected in the input listed in Table 3.7-7 (page 116) of Reference 1.

Following approval of the WCAP-10698-P-A methodology, the NRC did not require plants that received their operating licenses prior to the R.E. Ginna Nuclear Power Plant SGTR event to update their analyses to the new methodology. In order to confirm the conservative nature of the licensing basis input to dose mass releases, a supplemental input to dose analysis was performed for PlNGP Units 1 and 2 at planned EPU conditions. The supplemental analysis modeled operator responses leading to break flow termination consistent with the PlNGP SGTR Emergency Operating Procedure. The supplemental thermal hydraulic evaluation was performed to verify that the radiological consequences analysis input determined by the licensing basis hand calculation input to dose analysis discussed previously are bounding and conservative despite continuation of break flow beyond 30 minutes.

The thermal hydraulic input to dose analysis was performed using the LOFTTR2 computer code and modeling from WCAP-10698-P-A and its supplement. The evaluation includes explicit simulation of operator actions leading to break flow termination based on the PlNGP EOPs and simulator studies specific to PlNGP Units 1 and 2. The analysis considers the allowable vessel average temperature and SGTP ranges consistent with the hand calculation input to dose analysis, as well as a consistent power level. The analysis models reactor trip on over-temperature delta-temperature and SI actuated on low pressurizer pressure. The analysis does not include consideration of a single failure, assumes nominal plant conditions without consideration of uncertainties, and assumes nominal initial secondary mass consistent with the approach approved in the Point Beach Nuclear Plant safety evaluation report (SER) (Reference 4).

Consideration of uncertainties on nominal conditions would have a small impact on the flashed break flow. Following reactor trip and the assumed loss of offsite power, the reactor coolant system temperatures trend towards the no-load temperature, independent of the initial conditions assumed.

The initial secondary mass mainly impacts the steam releases. The licensing basis analysis assumes the ruptured SG participates equally in removing the decay heat in the period from reactor trip until break flow termination while the supplemental analysis utilizes the intact SG for the cooldown, consistent with the plant EOPs. Adding conservatism to the initial SG mass would not change the conclusion that the licensing basis analysis is bounding. Conservatisms contained in the supplemental evaluation include consideration of maximum SI flow rate, minimum auxiliary feedwater (AFW) flow rate, maximum AFW initiation delay, and maximum decay heat. Note that the decay heat model includes uncertainty to maximize the releases and time required to cool the RCS.

Page 42 of 62 NSPM Response to Reactor Systems Branch RAls Another conservatism included in the supplemental analysis is the break flow flashing fraction, which is determined using the hot leg temperature.

Since the tube rupture flow calculated using the LOFTTR2 code consists of flow from the hot leg and cold leg sides of the SG, the actual break flow temperature and the flashing fraction is much lower. This approach of maximizing flashing fraction by assuming all flow is at the hot leg temperature is similar to the licensing basis analysis approach; however, the LOFTTR2 code is able to calculate a flashing fraction based on the transient changes in primary and secondary side conditions. This results in reduced flashing fractions than those calculated using the licensing basis approach.

In the event of an SGTR, the operator is required to take actions to stabilize the plant and terminate the primary-to-secondary break flow. The operator actions for SGTR recovery are provided in the PlNGP Units 1 and 2 EOPs, and major actions were explicitly modeled in this analysis. The main operator actions modeled leading to break flow termination are identification and isolation of the ruptured steam generator, cooldown and depressurization of the RCS to reduce break flow and restore inventory, and termination of SI flow to stop primary-to-secondary break flow. The operator actions modeled in the analysis are discussed in more detail as follows.

Following the tube rupture, the RCS pressure decreases as shown in Figure 11 due to the primary-to-secondary break flow. In response to this depressurization, the reactor trips on overtemperature-AT at approximately 89 seconds. The main feedwater flow was assumed to be terminated and AFW flow was assumed to be automatically initiated with a maximum delay following reactor trip and the coincident LOOP. After reactor trip, core power rapidly decreases to decay heat levels and the RCS depressurization becomes more rapid. The steam dump to condenser system is inoperable due to the assumed LOOP, which results in the secondary pressure rising to the steam generator PORV setpoint as shown in Figure 11. The decreasing pressurizer pressure leads to an automatic SI signal on low pressurizer pressure at approximately 192 seconds. Following SI initiation, the high head safety injection (HHSI) flow begins to restore the reactor coolant inventory and the RCS pressure trends toward the equilibrium value where the SI flow rate equals the break flow rate. After the SGTR and reactor trip, the following operator actions are modeled to mitigate the SGTR event.

Isolate auxiliary feedwater flow to the ruptured steam generator Following reactor trip, auxiliary feed flow to the ruptured steam generator is stopped based on a steam generator level of greater than 35% narrow range. For an SGTR that results in a reactor trip at high power as assumed in this analysis, the steam generator water level as indicated on the narrow Page 43 of 62 NSPM Response to Reactor Systems Branch RAls range will decrease significantly for both steam generators. The AFW flow will begin to refill the steam generators. Since primary-to-secondary leakage adds additional inventory to the ruptured steam generator, the water level will increase more rapidly in that steam generator. This response, as displayed by the steam generator water level instrumentation, will result in operator isolation of AFW flow to the affected steam generator.

2. Identify the ruptured steam generator The SGTR EOP instructs the operators to identify the ruptured steam generator based on a number of criteria, including an unexpected increase in any steam generator narrow range level and high radiation indications.

The first actions to isolate AFW to the affected steam generator have already provided indication that it is a ruptured steam generator. Primary-to-secondary leakage will continue to add additional inventory to the ruptured steam generator so the water level will continue to increase even after AFW isolation. This response, as displayed by the steam generator water level instrumentation, provides confirmation of an SGTR event and also identifies the ruptured steam generator.

3. Isolate steam flow from the ruptured steam generator Once the ruptured steam generator has been identified, operators continue recovery actions by isolating steam flow from the ruptured steam generator.

This enables the operators to establish a pressure differential between the ruptured and intact steam generators as a necessary step toward terminating primary-to-secondary break flow. Isolation of steam flow from the ruptured steam generator was assumed to be completed immediately following AFW termination to provide conservative ruptured steam generator releases.

4. Cooldown the RCS using the intact steam generator After isolation of the ruptured steam generator steamline, actions are taken to cool the RCS as rapidly as possible by dumping steam from the intact steam generator. Since offsite power is lost, the RCS is cooled by dumping steam to the atmosphere using the atmospheric dump valves on the intact steam generator. An operator action is assumed to initiate cooldown 19 minutes from reactor trip, at 1230 seconds. The cooldown is continued until the core exit temperature is less than the target temperature, which provides the necessary RCS subcooling at the ruptured steam generator pressure. The reduction in the intact steam generator pressure required to accomplish the cooldown is shown in Figure 11. When the target temperature is reached at 1936 seconds as determined by the LOFTTR2 code, it is assumed that the operator terminates the cooldown and maintains the RCS temperature using the intact steam generator atmospheric dump valves. This cooldown ensures that there will be Page 44 of 62 NSPM Response to Reactor Systems Branch RAls adequate subcooling in the RCS after the subsequent depressurization of the RCS to the ruptured steam generator pressure.

5. '~stablishcharging flow Following initiation of the RCS cooldown, the PlNGP procedures instruct the operators to establish charging flow to help maintain RCS inventory lost through the primary-to-secondarybreak flow. Modeling initiation of charging flow is conservative for a SGTR analysis and is consistent with the PlNGP specific EOPs and operator training. Actions to initiate charging flow are performed at 1232 seconds.

6. Depressurize the RCS to reduce break flow and restore reactor coolant inventory The RCS is depressurized to reduce the break flow rate. SI flow will tend to increase RCS pressure until break flow matches injection flow.

Consequently, HHSl flow must be terminated to stop primary-to-secondary leakage. However, adequate reactor coolant inventory must first be assured. This includes both sufficient reactor coolant subcooling and pressurizer inventory to maintain a reliable pressurizer level indication after HHSl flow is stopped. If sufficient subcooling is not available, or a high level in the pressurizer is approached, the depressurization is terminated.

The RCS depressurization is performed using normal pressurizer spray if the reactor coolant pumps are running. Since offsite power is assumed to be lost at the time of reactor trip, the reactor coolant pumps are not running and, thus, normal pressurizer spray is not available. Therefore, the depressurization is modeled using a single pressurizer power operated relief valve.

After the RCS cooldown is completed, a conservatively bounding 7-minute operator action time is included prior to the RCS depressurization. The RCS depressurization is initiated at 2356 seconds and continued until any of the following conditions are satisfied: RCS pressure is less than the ruptured steam generator pressure and pressurizer level is greater than the allowance of 7% for pressurizer level uncertainty, or pressurizer level is greater than 75%, or RCS subcooling is less than the 20°F allowance for subcooling uncertainty. The LOFTTR2 code determined conditions are met for RCS depressurization termination at 2446 seconds. The RCS depressurization reduces the break flow rate as shown in Figure 12 and increases SI flow to refill the pressurizer.

7. Terminate SI flow The previous actions establish adequate RCS subcooling, a secondary side heat sink, and sufficient reactor coolant inventory to ensure that HHSl flow is no longer needed. When these actions have been completed, the HHSl flow must be stopped to prevent re-pressurization of the RCS and to terminate primary-to-secondary leakage. The HHSl flow is terminated at Page 45 of 62 NSPM Response to Reactor Systems Branch RAls this time if RCS subcooling is greater than the 20°F allowance for subcooling uncertainty, maximum AFW flow is available or the intact steam generator level is within the required range, the RCS pressure is stable or increasing, and the pressurizer level is greater than the 7% allowance for uncertainty. After depressurization is completed, an operator action time of 2 minutes was assumed prior to HHSl flow termination. Since the LOFTTR2 code determined that the above requirements are satisfied, SI flow termination actions were performed at 2566 seconds. After HHSl flow termination, the RCS pressure begins to decrease as shown in Figure 1I .

8. Balance charging flow to minimize primary-to-secondary leakage Once HHSI has been stopped, charging flow, letdown flow, and pressurizer heaters will then be controlled to prevent re-pressurization of the RCS and re-initiation of leakage into the ruptured steam generator. In the LOFTTR2 modeling, charging flow is terminated in place of modeling the balance of charging and letdown flow. An operator action time of 15 minutes was assumed prior to effective termination of charging flow. Charging flow was effectively terminated at 3466 seconds. No actions are modeled to reduce RCS pressure after termination of SI or charging flow. The break flow gradually reduces the RCS pressure until it equals the secondary pressure and break flow is terminated. Break flow termination occurs at 3830 seconds. The primary-to-secondary break flow rate throughout the recovery operations is presented in Figure 12. It is noted that the total time required to complete the recovery operations consists of both operator action time and system, or plant, response time. For instance, the time for each of the major recovery operations (i.e., RCS cooldown) is primarily due to the time required for the system response, whereas the operator action time is reflected by the time required for the operator to perform the intermediate action steps.

The operator actions and corresponding operator action times used for the analysis are summarized in Table 6. These operator response time inputs were obtained from a simulated SGTR event at PINGP.

Table 8 contains a comparison of the thermal hydraulic mass transfer results for the 30-minute licensing basis hand calculation input to dose analysis to the supplemental thermal hydraulic input to dose analysis. The calculated sequence of events is presented in Table 7. Figures I 1 through 16 contain plant transient responses to the tube rupture event including primary and secondary pressure, primary-to-secondarybreak flow, primary-to-secondary flashing fraction, and secondary steam releases.

Conservatism was added to the reported results to cover plant changes that may impact the SGTR analysis, such that a recalculation does not need to be performed for minor changes to the plant. Note that Figures 11 through 16 do not reflect the added conservatism.

Page 46 of 62 NSPM Response to Reactor Systems Branch RAls The supplemental thermal hydraulic analysis demonstrates that, despite the continuation of break flow beyond the 30-minute assumption used in the licensing basis SGTR analysis, the thermal hydraulic mass transfers resulting from a transient analysis modeling operator actions are bounded by those calculated for the licensing basis analysis. Table 8 shows that the supplemental thermal hydraulic analysis results in an approximate increase of 18% in total tube rupture break flow (pre- and post-trip) and 13% in intact steam generator steam releases (trip to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />), while showing a decrease of approximately 77% in total flashed break flow (pre- and post-trip) and 52% in ruptured steam generator steam releases. The difference in intact steam generator steam releases would not have a significant impact on a dose analysis due to the minimal activity contained in the intact steam generator. Flashed break flow, which shows the largest reduction compared to the licensing basis analysis, would be expected to have the greatest impact on the SGTR radiological dose consequences analysis since it is generally modeled as a direct release from the RCS to the environment with no mitigation in the secondary side of the ruptured steam generator. The increase in total break flow is more than offset by the reduction in actual releases (i.e., flashed break flow and ruptured steam generator steam release). Note from Table 7 that the break flow flashing stops at 1442 seconds, during cooldown using the intact steam generator.

As seen in Figure 14, the flashing fraction is reduced over time and this reduction is taken into account for the resulting mass transfers. In contrast, the licensing basis analysis maintains a constant flashing fraction for the entire 30-minute break flow duration.

As such, the 30-minute mass transfer data from the licensing basis hand calculation used in the dose analysis provides conservative results when compared to a transient analysis modeling operator actions, with break flow duration lasting longer than 30 minutes. The evaluation was performed without inclusion of a single failure, assumes nominal conditions without uncertainties, and does not minimize initial secondary mass. The approach is judged to be acceptable, since a comparison of the releases with the licensing basis hand calculation, to those determined by the transient analysis modeling operator actions, provides a credible demonstration that the licensing basis hand calculation is quite conservative. The comparison and results are similar to those shown for the Point Beach Nuclear Plant SER (Reference 4).

Page 47 of 62

Enclosure 2 NSPM Response to Reactor Systems Branch RAls Table 6 Operator Action Times for PlNGP Supplemental Thermal-Hydraulic Analysis Action Time Operator action time to isolate auxiliary feedwater AFW isolated on SG flow to the ruptured steam generator following level, LOFTTR2-reactor trip calculated Operator action time to close main steam isolation Immediately following valve to isolate steam flow from the ruptured steam AFW isolation generator1 Operator action time to initiate cooldown following 19 minutes reactor trip Operator action time to establish maximum charging Immediately following flow cooldown initiation Plant response to complete cooldown LOFTTR2-calculated Operator action time to initiate depressurization 7 minutes following completion of cooldown Plant response to complete depressurization LOFTTR2-calculated Operator action time to terminate emergency core 2 minutes cooling system (ECCS) flow following completion of depressurization Operator action time to balance letdown and 15 minutes charging flow following safety injection termination Plant response until break flow termination resulting LOFTTR2-calculated from primary and secondary pressure equalization No operator action time was given. A minimum time after AFW isolation is used to provide conservative ruptured steam generator releases to atmosphere.

Page 48 of 62

Enclosure 2 NSPM Response to Reactor Systems Branch RAls Table 7 Sequence of Events for PlNGP SGTR Supplemental Thermal Hydraulic Analysis Event Time (sec)

SGTR Occurs 0 Reactor Trip and Loss of Offsite Power 89 Initiation of Auxiliary Feedwater 149 Initiation of Safety Injection 192 Isolation of Auxiliary Feedwater Flow to Ruptured 738 Steam Generator Isolation of Main Steam Isolation Valve to Ruptured 740 Steam ene era to?

Initiation of Cooldown with Intact Steam Generators 1230 Initiation of Maximum Charging Flow 1232 Break Flow Flashing Stops 1442 Termination of Cooldown 1936 Initiation of Depressurization 2356 Termination of Depressurization 2446 Termination of Safety Injection 2566 Balance of Charging and Letdown Flow 3466 Termination of Break Flow 3830 2

A minimum time following AFW isolation is assumed for MSlV isolation to provide conservative ruptured steam generator releases to atmosphere.

Page 49 of 62

Enclosure 2 NSPM Response to Reactor Systems Branch RAls Table 8 Comparison of Thermal Hydraulic Results for PlNGP SGTR lnput to Dose Analysis Releases Presented Supplemental in AST Submittal Thermal Hydraulic EPU lnput to Dose Analysis Pre-Trip Break low^ 14,600 Ibm 5,500 Ibm Post-Trip Break low^ 125,400 Ibm 159,300 Ibm Pre-Trip Flashed Break 2,630 Ibm 900 Ibm Flow Post-Trip Flashed 15,050 Ibm 3,100 Ibm Break Flow Post-Trip Ruptured 80,500 Ibm 38,700 Ibm Steam Generator Steam Release Intact Steam 237,100 Ibm 266,900 lbm4 Generator Releases from Trip to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Intact Steam 569,000 Ibm Generator Releases from 2 to 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />s5 Intact Steam 416,100 Ibm Generator Releases from 8 to 14 hour1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br />s5 3

Includes flashed break flow.

The supplemental analysis only calculates intact SG steam releases from trip until break flow termination.

Therefore, the 30 minute to 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> intact SG release of 156,600 Ibrn calculated in the licensing basis analysis for the AST submittal was included in the presented value to provide comparable time period results.

5 Values calculated in licensing basis are assumed to apply to both analyses.

Page 50 of 62 NSPM Response to Reactor Systems Branch RAls Figure 11: SGTR Supplemental Input to Dose Evaluation RCS and Secondary Pressures RCS Pressure I n t a c t SG P r e s s u r e

--- ------ R u p t u r e d S G P r e s s u r e Page 51 of 62 NSPM Response to Reactor Systems Branch RAls Figure 12: SGTR Supplemental Input to Dose Evaluation Primary-to-Secondary Break Flow Rate Page 52 of 62 NSPM Response to Reactor Systems Branch RAls Figure 13: SGTR Supplemental Input to Dose Evaluation Integrated Primary-to-Secondary Break Flow 160000 1 40000-120000-" ' " '

A -

22 100000-V 3

- 0 -

LL x

U . . . . . . . . . . .

a L

80000- ' ' " '

m -

73 -

a!

--C, u -

40000-I I I I 1 1 1 1 I l l 1 I l l 1 0 1000 2000 3000 4000 Time (s)

Page 53 of 62 NSPM Response to Reactor Systems Branch RAls Figure 14: SGTR Supplemental Input to Dose Evaluation Primary-to-Secondary Break Flow Flashing Fraction Page 54 of 62 NSPM Response to Reactor Systems Branch RAls Figure 15: SGTR Supplemen,tal Input to Dose Evaluation Integrated Primary-to-Secondary Flashed Break Flow 2000 Time (s)

Page 55 of 62 NSPM Response to Reactor Systems Branch RAls Figure 16: SGTR Supplemental Input to Dose Evaluation Steam Generator Atmospheric Steam Releases Ruptured SG S t e a m F l o w I n t a c t SG Steam F l o w Page 56 of 62 NSPM Response to Reactor Systems Branch RAls B.2 Page 116 of the LAR indicates that, based on the current PlNGP licensing basis, the "termination of release from ruptured SG" was completed within 30 minutes from initiation of the SGTR event.

Discuss the 'kurrent licensing basis" for the event termination time of 30 minutes, its effect on and acceptability of the radiological release analysis, and its relationship with the break flow termination time of 30 minutes assumed in the MTO analysis.

Response

As noted above in the response to Part B . l of this question, the licensing basis SGTR analysis is based on the use of simplified calculations to determine the integrated break flow and the steam release from the SGs to the atmosphere for the assumed 30 minute duration of the accident.

This methodology is also used to perform the licensing basis SGTR analyses for many other plants and the results are included in the plant FSARs which are approved by the NRC. The overall calculation provides conservative estimates of the break flow and steam release to the atmosphere for the SGTR radiological consequences analysis, as shown by a comparison to the transient thermal hydraulic analysis in the Part B.1 response.

Following the R.E. Ginna Nuclear Power Plant SGTR event, which occurred in January 1982 the NRC raised several SGTR licensing issues with plants with license applications pending at that time. These included justification of the 30 minute operator action time assumed, qualification of the equipment assumed to be used for SGTR recovery, single failure considerations for the SGTR analysis, and the potential for steam generator overfill. A subgroup of the affected utilities in the Westinghouse Owners Group (WOG) was formed to resolve the SGTR issues. The resolution included the development of a new SGTR analysis methodology which is based on modeling the operator actions for SGTR recovery using design basis operator action times derived from plant specific simulator studies. The revised analysis was to be performed using the LOFTTR2 computer code. The LOFTTR2 program is based on the Westinghouse LOFTRAN code and includes the capability to model operator actions, an improved steam generator secondary side model, and a more realistic tube rupture break flow model. The NRC approved the revised SGTR analysis methodology in 1987 and the methodology has been applied for the SGTR analyses for plants licensed after the R.E.

Ginna Nuclear Power Plant SGTR event.

Page 57 of 62 NSPM Response to Reactor Systems Branch RAls The improved break flow model which incorporates frictional losses in the tube and pressure losses at the break site, results in a lower break flow rate at a given RCS pressure. The transient calculation results in delay from the time of safety injection actuation, until the equilibrium between injection flow and break flow is reached, and in many cases this equilibrium is never reached. Modeling of the operator actions to cool the RCS results in reduced primary pressures and associated break flow rates, as does the operator action to depressurize the RCS. After the RCS depressurization, SI is terminated and break flow gradually decreases to zero. The transient analysis calculation of the RCS temperatures, which includes the post-trip cooldown, cooling due to safety injection flow and manual cooling using the intact SG, results in lower flashing fractions, in comparison to the licensing basis hand calculation.

Ruptured SG steam releases are reduced due to the consideration of energy absorption by the cold safety injection flow and the cooldown performed using only the intact SG.

The plant analyses which have been performed using the LOFTTR2 SGTR analysis methodology have utilized operator action times based on simulator studies which have typically resulted in delaying break flow termination beyond the 30 minutes assumed in earlier analyses. The benefits provided by the improved break flow model and the modeling of the operator actions and transient affects, have tended to offset the penalties associated with using longer operator action times leading to later break flow termination.

Although the NRC initially indicated that the SGTR issues raised by the R.

E. Ginna Nuclear Power Plant SGTR event were considered to be generic and would likely become backfit issues, the NRC has not required the older plants that used the earlier methodology with the 30 minute break flow termination time to update their SGTR analyses. The NRC has also approved alternative source term submittals and power uprates for plants that continue to use this methodology.

Details of the calculation of the input to the dose analysis are provided in response to Part B . l of this question. A number of simplifying assumptions are in the calculation that support the conclusion that it provides acceptable input for the radiological analysis despite the assumed 30 minute duration. The most significant are (1) the use of a constant break flow at the equilibrium RCS pressure, (2) the use of a constant hot leg temperature in the calculation of the flashing fraction, (3) the application of this flashing fraction to all of the break flow, (4) neglecting cooling due to safety injection and (5) equal participation in decay heat and stored energy removal by the ruptured SG for the 30 minute duration. As discussed in response to Part B.l of this question, Page 58 of 62 NSPM Response to Reactor Systems Branch RAls a detailed analysis has been performed to confirm that radiological consequences analyses performed using the input developed with the simplified modeling and 30 minute break flow termination time are significantly more limiting than those performed using more accurate transient modeling with computer code such as LOFTTR2 incorporating expected operator actions time leading to break flow termination after 30 minutes.

As previously stated, the radiological licensing basis SGTR analysis is based on the use of simplified calculations to determine the integrated break flow and the steam release from the SGs to the atmosphere for the assumed 30 minute duration of the accident in order to determine the onsite and offsite consequence of the accident. The licensing basis SGTR analysis did not consider steam generator overfill. There is no direct connection between the input to dose calculations with the assumed break flow termination time of 30 minutes and the PlNGP margin to overfill assessments.

The supplemental margin-to-overfill analysis discussed in the response to A.2, models operator actions leading to break flow termination beyond 30 minutes and demonstrates that overfill does not occur, in consideration of extended operator action times. This demonstrates that break flow is terminated prior to the potential for a liquid release via the PORV and/or Safeties. In addition, the supplemental input to dose analysis discussed in Part B . l of this question, demonstrates that the event consequence is bounded by the original hand calculation method that utilizes the 30 minute break flow termination assumption, since a larger amount of mass is released to the environment when more accurate transient modeling incorporating extended operator action times beyond 30 minutes are utilized.

Page 59 of 62 NSPM Response to Reactor Systems Branch RAls C. RAI Related to Update of Updated Safety Analysis Report Discuss PINGP's plans to reflect the information provided in response to above items A and B in an update of the Updated Safety Analysis Report (USAR), pursuant to the requirements of 10 CFR 50.71, "Maintenance of records, making of reports."

Response

The PlNGP Updated Safety Analysis Repori (USAR) will be updated to reflect information provided in response to Items A and B above consistent with the requirements of 10 CFR 50.71(e), and NRC Exemption letter dated May 22.2006 (ADAMS Accession No. ML061110032), (Reference 10).

Page 60 of 62 NSPM Response to Reactor Systems Branch RAls References

1. NSPM Letter to US NRC, "License Amendment Request (LAR) to Adopt the Alternative Source Term Methodology," dated October 27, 2009 (ADAMS Accession No. ML093160583).

2. US NRC Letter to Xcel Energy Energy, "Prairie Island Nuclear Generating Plant, Units Iand 2 - Request for Additional Information (RAI) Associated with Adoption of the Alternative Source Term (AST) Methodology (TAC Nos. ME2609 and ME2610)," dated May 12,2011 (ADAMS Accession No. MLI 03540433).

3. NSPM Letter to US NRC, "Response to Requests for Additional Request RE: License Amendment to Adopt the Alternative Source Term Methodology (TAC Nos. ME2609 and ME2610)," dated August 12,2010 (ADAMS Accession No. ML102300295).

4. US NRC letter to NextEra Energy Point Beach, LLC, "Point Beach Nuclear Plant (PNBP), Units 1 and 2 - lssuance of License Amendments Regarding Extended Power Uprate (TAC Nos. ME1044 and ME1045),11 May 3,201 1 (ADAMS Accession Nos. MLI 10880039 and MLI 10450159).

5. US NRC letter to Consolidated Edison Company of New York, Inc., "Indian Point Nuclear Generating Unit No. 2 - RE: lssuance of Amendment Affecting Containment Air Filtration, Control Room Air Filtration, and Containment Integrity During Fuel Handling Operations (TAC No.

MA6955),11July 27, 2000 (ADAMS Accession No. ML003727500).

6. US NRC letter to Indiana Michigan Power Company, "Donald C. Cook Nuclear Plant, Units 1 and 2 - lssuance of Amendments (TAC Nos.

MB0739 and MB0740),11October 24,2001 (ADAMS Accession No. ML012690136).

7. US NRC letter to Nuclear Management Company, LLC, "Kewaunee Nuclear Power Plant - lssuance of Amendment Regarding Implementation of Alternate Source Term (TAC No. MB4596),11March 17, 2003 (ADAMS Accession No. ML030210062).

8. US NRC letter to Entergy Nuclear Operations, Inc., "Indian Point Nuclear Generating Unit No. 3 - lssuance of Amendments RE: Full Scope Adoption of Alternative Source Term (TAC No. MC3351),11March 22, 2005 (ADAMS Accession No. ML050750431).

Page 61 of 62 NSPM Response to Reactor Systems Branch RAls

9. US NRC letter to PSEG Nuclear LLC - X04, "Salem Nuclear Generating Station, Unit Nos. 1 and 2, Issuance of Amendments RE: Alternate Source Term (TAC Nos. MC3094 and MC3095)," February 17, 2006 (ADAMS Accession No. ML060040322).

10.NRC Exemption Letter, "Point Beach Nuclear Plant, Units 1 and 2, and Prairie Island Nuclear Generating Plant, Units 1 and 2 - Exemptions to 10 CFR 50.71(e)(4) (TAC Nos. MC8654, MC8655, MC8656, and MC8657),

dated May 22,2006 (ADAMS Accession No. ML061110032).

Page 62 of 62