L-PI-10-046, Response to Requests for Additional Lnformation License Amendment Request to Adopt the Alternative Source Term Methodology
| ML101460064 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 05/25/2010 |
| From: | Schimmel M Xcel Energy |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| L-PI-10-046, TAC ME2609, TAC ME2610 | |
| Download: ML101460064 (18) | |
Text
@ Xcel Energym MAY 2 5 20101 L-PI-10-046 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 RE: License Amendment Request to Adopt the Alternative Source Term Methodolonv (TAC NOS. ME2609 and ME2610)
References
- 1. Xcel Energy 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, "Prairie Island Nuclear Generating Plant, Units 1 and 2 - Requests for Additional lnformation RE: License Amendment Request to Adopt the Alternative Source Term Methodology (TAC Nos. ME2609 and ME261O)," dated March 26,2010 (ADAMS Accession No. ML100820298).
- 3. Xcel Energy Letter to US NRC, "Response to Requests for Additional lnformation RE: License Amendment Request to Adopt the Alternative Source Term Methodology (TAC Nos. ME2609 and ME2610)," dated April 29, 2010 (ADAMS Accession No. MLI 01200083).
In Reference I , the Northern States Power Company, a Minnesota corporation (NSPM),
doing business as Xcel Energy, hereby requested an amendment to the Technical Specifications (TS) for Prairie Island Nuclear Generating Plant (PINGP). The proposed amendment requested to adopt the Alternative Source Term (AST) methodology, in addition to TS changes supported by the AST design basis accident radiological consequence analyses.
In Reference 2, the Nuclear Regulatory Commission (NRC) Staff requested additional information to support their review of Reference 1. In Reference 3, NSPM agreed to provide responses to the Reactor Systems Branch requests for additional information (RAI) by May 28, 2010. Enclosure 1 to this letter provides these responses 1717 Wakonade Drive East Welch, Minnesota 55089-9642 Telephone: 651.388.1121
Document Control Desk Page 2 to the NRC 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.
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 Ms. Amy Hazelhoff, at 269-370-7445.
Summary of Commitments This letter contains no new commitments and no revisions to existing commitments.
I declare under penalty of perjury that the foregoing is true and correct.
Mark A. Schimmel Site Vice President, Prairie Island Nuclear Generating Plant Northern States Power Company - Minnesota Enclosure cc: Administrator, Region Ill, USNRC Project Manager, PINGP, USNRC Resident Inspector, PINGP, USNRC State of Minnesota
Enclosure 1 Nuclear Regulatory Commission (NRC) Request for Additional Information (RAI)
Reactor Systems Branch (S RXB)
The follow~ngrequests for additional information are associated with the NRC staff review of the steam generator tube rupture (SG TR) overfill analysis in support of the AST LAR application, as discussed in the Enclosure to Reference 7, Pages 106 and 107.
Please provide the following information for the NRC staff to continue its review:
SRXB RAI 7 Discuss the methods used for the SGTR overfill analysis. If the methods were previously approved by NRC, list the NRC safety evaluation reports approving the methods. If the methods were not reviewed and approved by NRC, address acceptability of the methods.
The information should include a description and justification of reactor coolant system (RCS) models with safety injection simulation, models for determination of the primary-to-secondary break and steam relief flow rates, and steam generator (SG) water level model accounting for the effects of bubble formation during depressurization on the SG water level for a SGTR event.
Northern States Power Company, a Minnesota corporation (NSPM) Response SRXB RAI 1 The approach used in this calculation has not been reviewed by the NRC for the Prairie Island Nuclear Generating Plant (PINGP). In lieu of computer models of (1) the RCS with safety injection simulation, (2) determination of primary-to-secondary break and steam relief flow rates, and (3) steam generator water level accounting for the effects of bubble formation during depressurization, the approach determines margin to overfill using standard engineering principles based on the volume available in the SG, the mass flow rates into the ruptured SG, and the times for operator action. Conservatisms are provided in the determination of flow rates into the ruptured SG, the RCS and SG pressures used in each step of the evaluation, and by not taking credit for steam release from the ruptured SG. Bubble formation is not expected as steam is not released from the ruptured SG. These conservatisms are described in more detail below. For the purposes of this evaluation, the approach is considered to be acceptable given that standard engineering principles are used coupled with conservative inputs and assumptions.
Page 1 of 16
NSPM As noted above, the approach utilized in the calculation determines the margin to overfill based on available volume in the ruptured SG, mass flow rate through the tube rupture, and operator time response. Key inputs to the approach are the total volume in the SG, the initial liquid volume in the ruptured SG, the differential pressure across the ruptured SG tube, and timing of operator actions. Mass flow rate through the SG tube rupture is determined based on the differential pressure across the tube rupture for two different time periods; (1) Initiation of the event until safety injection (SI) is initiated, and (2) From SI initiation until break flow is terminated. During each time period, the differential pressure is assumed to remain static; that is, no credit is taken for the differential pressure decreasing during each time period. This provides a break flow for each time period that bounds a more dynamic break flow determination where break flow is determined based on predicted pressure responses.
Timing of operator actions is determined based on simulator runs for each crew. The times are then used in the calculation to ensure that there is sufficient time margin to preclude overfill of the ruptured Steam Generator for each crew.
The outline of the calculation approach is as follows:
Using information from the simulator runs for each crew, operator response times are determined for the following actions directed in Emergency Operating Procedures (EOP) E-0, "Reactor Trip or Safety Injection," and E-3, "Steam Generator Tube Rupture":
Manual initiation of SI Isolation of Auxiliary Feedwater (AFW) flow to the ruptured SG Termination of flow through the ruptured tube - based on cooldown and depressurization of RCS Operator response times are a key input to determining the margin to overfill in the ruptured SG. Operator response times are determined based on EOPs and timed operator responses for key actions determined based on scenarios carried out on the plant simulator. EOP E-3 is specifically for the response to a SGTR. As described in the basis for EOP E-3, the principal goal of the procedure is to stop primary-to-secondary leakage and to establish and maintain sufficient indications of adequate coolant inventory. Primary-to-secondary leakage is terminated by cooling down and depressurizing the RCS; i.e., equalizing the pressure across the ruptured SG tube. Cooldown of the RCS is performed by dumping steam from the intact SG using the power operated relief valve (PORV) if steam dump to the condenser is not available.
Determine the initial inventory in the SG prior to the SGTR event. Appropriate uncertainties and operating margin are included to ensure that a conservative initial inventory is used.
Page 2 of 16
NSPM Determine break flow rate based on the differential pressure across the ruptured tube for two discrete time periods; (1) Initiation of the event until SI is initiated. During this first time period, the break flow is determined based on the RCS and SG pressures prior to the event occurring. Assuming this maximum differential pressure results in conservative break flow.
(2) From SI initiation until break flow is terminated. Following SI initiation, break flow is determined where the break flow vs. RCS pressure curve intersects the SI pump flow rate vs. RCS pressure curve. A maximum SI pump curve is used based on both SI pumps injecting at maximum capacity. In order to conservatively estimate the margin to overfill, the additional injection due to one charging pump operating at maximum flow rate is also included.
During each time period, the differential pressure is assumed to remain static; that is, no credit is taken for the differential pressure decreasing during each time period.
Determine a maximum AFW flow rate to the ruptured SG. In addition to the Safety Injection flow rate, the AFW system adds inventory to the ruptured SG.
The margin to overfill is then determined based on the initial SG inventory, injection flow rates and operator response times.
Mitigation of a SGTR overfill event requires operator actions in accordance with the associated EOPs. A list of the systems, components and instruments that are used to preclude overfill in a ruptured SG is provided in Table 1 below. This list is developed based on the PlNGP EOPs; specifically EOP E-3. As described in Updated Safety Analysis Report (USAR) Section 14.5.4.5, the actions prescribed in the EOP E-3 focus on the following key aspects:
Identify the ruptured SG - Initially, the presence of a SGTR is indicated by high secondary side activity, as indicated by the condenser air ejector, steam generator blowdown liquid radiation alarm, and/or main steam line high radiation indication. The high secondary side activity indicates that a SGTR exists, but (with the exception of the main steam line high radiation indication) would not identify the ruptured SG. EOP E-3 directs the operators to identify the ruptured SG by the following indications:
Unexpected increase in any SG narrow range level.
High radiation from any SG sample.
High radiation from any SG steam line.
Page 3 of 16
NSPM The limiting scenario with respect to overfill during a SGTR event is the complete severance of a tube (design basis SGTR). The complete severance of a SG tube results in a high flow rate from the primary to the secondary side of the SG.
The high primary to secondary side flow rate allow the ruptured SG to be promptly identified by the operators due to the unexpected increase in the associated SG narrow range level. Thus, the timely indication of the design basis SGTR is provided by the narrow range level. This is consistent with the description in USAR Section 14.5.4.5.
The chemistry sample is one of three means specified in EOP E-3 for the
~dentificationof the ruptured SG. The operator can use any one of the three methods. As described in the bases for this step in EOP E-3:
"The indications listed in this step identify the unique features of a ruptured SG. In the case of a large rupture, SG water level should provide obvious indication of the ruptured SG. For smaller tube ruptures, however, SG water level may respond slowly so that identification on high secondary radiation may be required. If SG samples had been obtained before initiation of safety injection, the ruptured SG may be identifiable from sample results."
In summary, 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. Therefore, 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.
Isolate the ruptured SG - Following identification of the ruptured SG, steam flow paths from, and feedwater flow paths to, the ruptured SG are isolated.
Cool down the RCS using the intact SG - Afler isolating the ruptured SG, the RCS is cooled down to less than the saturation temperature corresponding to the ruptured SG pressure by dumping steam from only the intact SG. If offsite power is available, the normal steam dump system to the condenser is used to perform this cooldown. If offsite power is not available, the RCS is cooled down using the intact SG power operated relief valve. This is also described in the Bases for Technical Specification 3.7.4 which states:
"In the steam generator tube rupture (SGTR) accident analysis presented in Reference 2 [USAR], the SG PORV in the unaffected steam generator is assumed to be used by the operator to cool down the unit for accidents accompanied by a loss of offsite power."
Depressurize the RCS - The RCS depressurization is performed using normal pressurizer spray if it is available. However, if normal pressurizer spray is not available, RCS depressurization is performed using the pressurizer power Page 4 of 16
NSPM operated relief valve or auxiliary pressurizer spray. This is also described in the Bases for Technical Specification 3.4.1 1 which states:
"Plant operators employ the PORVs to depressurize the RCS in response to certain plant transients if normal pressurizer spray is not available. For the Steam Generator Tube Rupture (SGTR) event, the safety analysis assumes that manual operator actions are required to mitigate the event.
A loss of offsite power is assumed to accompany the event, and thus, normal pressurizer spray is unavailable to reduce RCS pressure. The PORVs are assumed to be used for RCS depressurization, which is one of the steps performed to equalize the primary and secondary pressures in order to terminate the primary to secondary break flow and the radioactive releases from the affected steam generator."
Terminate Safety Injection - Safety injection is terminated when the RCS is cooled down and depressurized.
A potentially limiting SGTR scenario, with respect to SG overfill includes a coincident loss of offsite power (LOOP). The LOOP scenarios results in some of the equipment directed to be used in the EOPs to be unavailable. The EOP-prescribed equipment presented in Table 1 below is based on offsite power not being available.
Page 5 of 16
NSPM Enclosure 1 Table 1, Equipment Used to Preclude Overfill in a Ruptured SG If Non-Safety Grade, Equipment1 Safety is Safety Grade Component Grade Function Remarks Name Backup Available I (Y or N)
Condenser Air Provide indication Ejector Radiation that a SGTR exists Provide indication Note (1) (2)
I
/ Blowdown Liquid that a SGTR Note (2)
/ Radiation Monitor exists Provide indication Main Steam Llne Radiation Mon~tor SG Water Level -
that a SGTR exists Identify ruptured Note (1) (2)
I Narrow Range Ruptured SG Closed to isolate PORV ruptured SG Steam Supply from Ruptured SG to Closed to isolate Turbine Drlven ruptured SG AFW Pump -- -
SG Blowdown Closed to isolate lsolat~onValve ruptured SG I Main Steam Closed to isolate lsolat~onValve Y NIA ruptured SG 1 (MSIV) --
+ -
Closed to stop AFW Isolation to Y NIA feedwater to Ruptured SG ruptured SG Used to cooldown lntact SG PORV I N I N I the RCS via the I Note (3) (5) 1 intact SG Core Ex~t Monitor RCS Y NIA Thermocouples cooldown Pressurizer Depressurize PORVs (alr N N Note (4) (5)
RCS 1 operated)
' ~ r e s s u r ~ zWater el SI Termination Y NIA Criteria SI Termination N N Criteria Provide make-up to RCS.
Safety lnject~on Secured as part Y
Pumps of terminating Page 6 of 16
NSPM Notes.
(1) As described in USAR Section 7.10, the Condenser Air Ejector Radiation Monitor and the Main Steam Line Radiation Monitors are classified as Category 2 instrumentation consistent with Regulatory Guide 1.97, Revision 2, dated December 1980.
(2) The Condenser Air Ejector Radiation Monitor and the Steam Generator Blowdown Liquid Radiation Monitor are maintained and tested in accordance with the Offsite Dose Calculation Manual requirements.
(3) The SG PORVs form part of the main steam system pressure boundary upstream of the MSIVs; which is a safety related function. Control air for the SG PORVs is from the lnstrument Air System; which is non-safety grade. Thus, the valve classification in Table 1 is shown as non-safety related. The lnstrument Air Compressors are automatically powered from emergency power sources in the event of a loss of offsite power, assuring that control air will be available for operation of the valves.
(4) The Pressurizer PORVs form part of the reactor coolant system pressure boundary; which is a safety related function. PORV controls are powered from vital buses that normally receive power from offsite power sources, but are also capable of being powered from emergency power sources in the event of a loss of offsite power. The control air supply to the Pressurizer PORVs is non-safety grade. Thus, the valve classification in Table 1 is shown as non-safety related. As described in USAR Section 4 4 2.3.1, the Pressurizer PORVs are provided with a back-up air supply inside of containment to support valve operation. Operability requirements for the Pressurizer PORVs are controlled by TS 3.4.11, and, as stated in the Bases for TS 3.4.1 1, are intended to ensure that the Pressurizer PORVs are available to mitigate a SGTR.
(5) As described above, the PlNGP licensing basis SGTR analysis, described in USAR, Section 14.5.4, credits non-safety grade equipment to mitigate the consequences of a SGTR event. Thus, the use of the non-safety grade equipment (e.g., SG PORVs) for accident mitigation following a SGTR in the calculation to determine the margin to SG overfill is consistent with the PlNGP licensing basis. Using licensing basis assumptions regarding crediting non-safety grade equipment to mitigate SGTR overfill is consistent with the NRC Safety Evaluation Report for the Donald C. Cook Nuclear Plant, dated October 24, 2001 (Accession Number ML012690136).
NSPM NRC RAI - SRXB R A l 2 Provide a list of the nominal values with measurement uncertainties and the corresponding values used in the SGTR overfill analysis for the following applicable plant parameters:
Initial RCS pressure lnitial SG water inventory Safety injection actuation pressure setpoint Safety injection flow versus RCS pressure Safety injection system pump delay time SG relief valve pressure setpoint Auxiliary feedwater actuation setpoint and delay time Auxiliary feedwater flow rate per SG Auxiliary feedwater temperature Time of loss of offsite power Delay times for reactor trip and turbine trip Decay heat model and initial value in percentage of the rated power level Discuss the effects of an increase or decrease in the value for each of the above plant parameters on the SG water level calculations during a SGTR and address the adequacy of the values used in the SGTR overfill analysis in minimizing the margin to SG overfill NSPM Response - SRXB RAI 2 Table 2 below describes the key inputs and assumptions used in the methodology. The values for the parameters included in SRXB RAI 2 are included in Table 2, along with other parameter values that are important to the methodology (for example, SG pressure) In Table 2, the justification for the selected parameters is discussed. In general, parameter values are selected to maximize break flow and minimize the margin to overfill. Thus, a bounding approach was taken in lieu of including sensitivities where parameter values are increased or decreased. Instrument uncertainties have been included for determination of a conservative initial SG water level. As discussed in Table 2. several parameter values are assumed based on data recorded during an event that occurred at PlNGP on October 2, 1979, where a SG tube failed. The extent of the tube failure is described in the response to SRXB RAI 4.
NSPM Enclosure 1 Table 2, Parameters Used in the Analysis Value Used in Parameter Justification I
Calculation Determined based on RCS and SG pressures during normal full power operation. Prior to SI initiation, the flow rate through the ruptured tube is determined based on the initial RCS pressure and SG pressure (conservatively
/ Initial RCS and SG 2235 psig (RCS) low relative to normal operation). RCS and Pressures 700 psig SG pressures are assumed to remain at these initial pressures until SI is initiated.
This differential pressure results in a conservatively high estimate of initial break flow.
RCS pressure is determined based on Safety Injection pump curve (both pumps operating)
RCS Pressure at and the break flow curve. RCS pressure is Equilibrium Conditions 965 psig assumed to remain at equilibrium conditions (after SI ~nltlation) until break flow is terminated. This provides a conservatively high estimate of break flow.
Determined based on the initial liquid
( inventory at the SG full power program level. I Initial SG L ~ q u ~Inventory d 1 19'500 Ibm Nominal SG liquid inventory is 107,000 Ibm.
Uncertainties are added for SG internal dimensions, level instruments and allowed operational margin.
To be conservative, the initial steam inventory l n ~ t ~SG a l Steam Inventory 5700 Ibm is assumed to condense and is added to the I - - -
initial liquid volume in the SG.
Determined based on data from the 1979 SG I SG Pressure at tube failure event. SG pressure is assumed Equilibrium Conditions 900 psig to remain at 900 psig after SI initiation until (ruptured SG, after SI break flow is terminated. This provides a ln~t~atlon~
conservatively high estimate of break flow.
I Both SI pumps are assumed to be running
! until break flow is terminated. The SI pumps Safety Injection (SI) Pump are assumed to be operating at their Curve (used to determine maximum allowable pump curves. These Maximum SI pump flow rate versus assumptions maximize the SI flow rate to the RCS pressure) RCS, which in turn, maximizes the break flow.
I---
I I I SI is manually initiated. Both SI pumps are SI Pump Actuation assumed to start when SI is initiated. Times None Pressure and Delay Time for manual initiation of SI are discussed in the response to SRXB RAI 3.
As described above, based on data from the SG Relief Valve Pressure 1979 SG tube failure event, the equilibrium Not Included Setpolnt Dressure in the ru~turedSG remains below Page 9 of 16
NSPM Enclosure 1 Parameter I Value Used in Calculation Justification the SG relief valve pressure setpoint. Thus, the relief valve setpoint is not included in the calculation.
The AFW pumps are assumed to start at the Auxiliary Feedwater initiation of SI. No credit is taken for any 1I (AFW) Actuation Setpoint SI initiation AFW system time delays. AFW flow to the i and Delav Time I
ruptured SG is assumed to continue until isolated by the Operators.
AFW flow rate to the ruptured SG is determined based on both pumps injecting to both SGs at their maximum rate with SG Auxiliary Feedwater 317 gpm pressure at 900 psig. For conservatism, the (AFW) Flow Rate per SG maximum calculated flow rate was increased bv 10%. AFW flow rate to the intact SG is not an input to the calculation.
Assumes AFW flow is at 70°F and 900 .psig. -
The fluid is then heated to the saturation temperature corresponding to 900 psig. Due AFW Temperature to small changes in liquid parameters at system operating temperatures, changes in assumed AFW temperature will have minor I impacts to results.
I No steam release is credited from the Steam Release from Ruptured SG
/ Not credited 1 ruptured SG for the determination of the margin to overfill. This conservatively minimizes the margin to overfill.
The loss of off-site power is assumed to I I occur coincident with the turbine trip. The I
, Time Power of Loss of Offsite Response during Simulator Runs turbine trip occurs at the time of the reactor trip. Time of reactor trip is determined from simulator scenarios. However, this time has I I no direct bearing on the inputs to the I t----
calculation.
Time of reactor trip is determined from 1 Delay T~mefor Reactor Response during 1I----
Trip and Turbine Trip Runs simulator scenarios. Refer to response to SRXB RAI 3 for additional details.
Decav heat is not specifically modeled in the Decay Heat Model and calcuiation. ~ e c a ~ ' h eis a tincluded in the Initial Value in Percentage Not Included plant simulator that is used to determine of Rated Thermal Power operator response times (specifically time to
- cooldown) used as input to the calculation.
Based on the above parameter values, the following break flow rates are used in the determination of the margin to overfill. As discussed in Table 2, the parameter values selected result in conservative break flows, which produce minimum margin to overfill.
Break flow from initiation of event until SI Initiation 82 Ibmlsec Break flow from initiation of SI to terminating break flow 67 Ibmlsec Page 10 of 16
NSPM NRC RAI - SRXB RAI 3 List operator action times for the following applicable operator actions as determined by the plant simulator in accordance with the Emergency Operating Procedure E-3 for a SGTR Identify and isolate the rupture SG
- lnitiate RCS cooldown lnitiate RCS depressurization Terminate safety injection flow Establish charging flow Establish RCS letdown Reopen pressurizer PORV Discuss the operator actions credited in the SGTR overfill analysis and provide a sequence of events for the SGTR including the above operator action times, and calculated times for the RCS cooldown, RCS depressurization and equalization of RCS and ruptured SG pressure. The information should show that the operator actions and their associated times assumed in the analysis were identical with that determined by the plant simulator.
NSPM Response - SRXB RAI 3 The following specific operator actions are used in the calculation.
Manual initiation of SI Isolation of AFW flow to ruptured SG Termination of flow through the ruptured tube - based on cooldown and depressurization of RCS Operator response times used in the calculation are based on runs for each crew on the plant simulator for the tube rupture events. Apart from the simulator runs, calculations have not been performed to determine times for RCS cooldown, RCS depressurization, and equalization of RCS and ruptured SG pressure. Based on the simulator times coupled with the conservative parameter values discussed in the response to SRXB RAI 2, the results of the calculations showed that all of the crews were able to complete the necessary actions to terminate the break flow prior to overfilling the ruptured SG.
As previously discussed, actual values for each crew are used in the margin to overfill calculation; i.e., thirteen different timing scenarios are used in the calculation to ensure that margin to overfill exists for each crew. Table 3 below provides the response times measured for each of the crews; i.e., the values that are applicable to the calculation.
Table 3 does not include times for all of the operator actions identified in SRXB RAI 3 (for example, establishing charging and letdown) as some of these times are not used in the calculation.
Page 11 of 16
NSPM Enclosure !
Table 3 Response Times from Plant Simulator i ~ i r n e sshown are in seconds) -
Sequence of Events I Week 1 Group 1 Week 1 Group 2 7--
Week 1 ' W e e k Group 3 Group 1 2 Week 2 Group 2 Week 2 Group 3 Week 3 Group I Week 3 Group 2 1
Week4 Group I Week4 Group 2 i
Week 5 Group 1 1 Week 6 Group 1 Week 6 Group 2 SGTR occurs 0 0 0 0 0 0 0 0 0 0 0 0 0 Reactor Trrp 36 110 95 33 85 115 111 109 100 96 110 138 110 lnrtratron of Safety 90 110 145 145 138 130 118 120 138 110 78 130 120 Injectron lsolatron of AFW 443 420 599 480 600 490 460 480 685 480 371 574 450 to Ruptured SG lnrtratron of cooldown wrth 980 1175 1265 1160 1325 1500 1225 1115 1448 1317 1090 1185 1195 rntact steam generator Terrnrnatron of 1413 1492 1620 1462 1626 1850 1480 1500 1722 1630 1485 1485 1580 cooldown lnrtratron of 1300 1612 1485 1363 1560 1785 1425 1453 1583 1558 1598 1260 1600 depressurrzatron Termrnatron of 1718 1496 1660 1880 1527 1513 1683 1665 1710 1380 1710 1413 1585 depressurrzatron Termrnatron of 1778 1620 1787 1980 1641 1631 1783 1765 1765 1585 1780 1519 1670 safety rnjectron Times shown for each step are from the initiation of the event.
Page 12 of 16
NSPM Enclosure "
NRC RAI - SRXB RAI 4 List the s~nglefailure events considered in the SGTR overfill analysis and identifL the worst single failure used in the analysis that resulted in a minimum margin to the SG overfill.
NSPM Response - SRXB RAI 4 Regarding the design criteria applicable to PINGP, the USAR, Section 1.5, states:
"The Prairie Island Nuclear Generating Plant was designed and constructed to comply with NSP1sunderstanding of the intent of the AEC General Design Criteria for Nuclear Power Plant Construction Permits, as proposed on July 10, 1967.
Since the construction of the plant was significantly completed prior to the issuance of the February 20, 1971, 10 CFR50, Appendix A General Design Criteria, the plant was not reanalyzed and the FSAR was not revised to reflect these later criteria. However, the AEC Safety Evaluation Report acknowledged that the AEC staff assessed the plant, as described in the FSAR, against the Appendix A design criteria and "... are satisfied that the plant design generally conforms to the intent of these criteria."
As described in USAR Section 14.1. I , condition classification for various event analyses for PINGP is consistent with ANS 51.I-1973. USAR Section 14.1.Idefines the design basis SGTR as a condition IV event. As described in USAR Section 14.5.4.1, the design basis SGTR is a complete severance of a single SG tube. The tube failure event that occurred in 1979 was characterized as a break approximately 1.5" in the longitudinal direction with an opening width of approximately 0.5"; i.e., not a design basis SGTR.
Thus, the condition IV classification for the SGTR for PINGP is correct.
Consistent with the description in USAR Section 14.5.4, the design basis SGTR for PINGP does not include consideration of a single failure. Thus, there is no need for PINGP to include consideration of single failures in the SGTR margin to overfill calculation. This is also consistent with the description in the Bases for Technical Specification 3.7.4 which states that during a SGTR, the SG PORV in the unaffected steam generator is assumed to be used to cool down the unit. Per Technical Specification 3.7.4, two SG PORVs (one per SG) are required to be OPERABLE.
Consistent with the Bases for Technical Specification 3.7.4, this is to ensure that the PORV in the unaffected SG is available and not to account for a postulated single failure.
Using licensing basis assumptions regarding single failure considerations in the SGTR margin to overfill calculation is consistent with the NRC Safety Evaluation Report for the Page 13 of 16
NSPM Donald C. Cook Nuclear Plant, dated October 24, 2001 (Accession Number ML012690136).
It should be noted, as described previously, the SGTR margin to overfill calculation is based on conservative inputs and assumptions that maximize the mass transfer from the primary to the secondary side of the ruptured SG. These inputs and assumptions are based on both trains of equipment functioning as designed (for example, Safety Injection) to maximize the mass input.
Page 14 of 16
NSPM NRC RAI - SRXB RAI 5 Provide the results of the SGTR overfill analysis for the following applicable plant parameters..
- Pressurizer pressure versus time Secondary pressures and SG water volumes versus time for both intact and rupture SGs Total primary to secondary break flow and total integrated primary to secondary break flow versus time SG relief flow and integrated SG relief flow versus time for both intact and rupture SGs The results indicate the following: the calculated RCS break and SG relief flowrates are consistent with the primary and secondary pressures; there is no unexplainable therrnal-hydraulic phenomenon; the RCS pressure and the rupture SG secondary pressure are equal; and, the SG does not overfill with water.
NSPM Response - SRXB RAI 5 As discussed in the responses to SRXB RAI 1 and RAI 2, the objective of the methodology used is to demonstrate that (using conservative inputs for initial SG inventory, flow rates into the ruptured SG and not crediting flow from the ruptured SG) the operator actions can be performed in a manner to preclude overfill. For this methodology, the results are summarized below. The methodology used in the calculation provides the final ruptured SG water volume and does not provide results as a function of time.
Pressurizer pressure - A s discussed in the response to SRXB 2, RCS pressure is assumed to remain at 2235 psig until SI initiation. After SI mitiation, RCS pressure is assumed remain at 1965 psig until break flow is terminated. This is conservative as it maximizes break flow.
Secondary pressures - Only the ruptured SG is considered in the evaluation.
As discussed in the response to SRXB RAI 2, SG pressure is assumed at 700 psig prior to SI initiation. After SI initiation, SG pressure is assumed at 900 psig until SI termination. Secondary water volume can be shown to be steadily increasing based on rupture, AFW flow and time, although this value is not specifically calculated. Instead, the available volume prior to the event is compared to total calculated injection flow (Break Flow and AFW Flow) to determine the margin to overfill.
SG water volume - In the margin to overfill calculation the total calculated
~njectionflow (Break Flow and AFW Flow) is compared to the initial available Page 15of 16
NSPM volume in the SG to determine the margin to overfill to demonstrate that margin to overfill exists. The total volume of a Steam Generator is 5730 cubic feet. The initial liquid mass (volume) (including the assumption that the steam condenses) is taken at 125,200 Ibm (2666 ft3 based on saturation conditions at 900 psig).
SG relief flow - A s discussed in the response to SRXB RAI 2, no flow is considered from the relief valve(s) for the ruptured SG. That is, no credit is taken for steam release from the ruptured SG. This is conservative as it minimizes the available margin to overfill. Steam release from the intact SG is not included as part of the calculation. Instead, times for cooldown used in the calculation are based on operator response times in the simulator.
Total primary to secondary break flow - As described in the response to SRXB RAI 2, the following break flow rates are used in the calculation:
Break flow from initiation of event until SI Initiation 82 Ibmlsec Break flow from initiation of SI to terminating break flow 67 Ibmlsec Using the simulator times for each crew run of the scenario (refer to Table 3),
different values for total break flow are calculated. The total calculated break flow for each crew is shown in Table 4 below.
Table 4, Total Calculated Break Flow and Margin to Overfill Maximum Water Margin to Total Break Total Break Crew Volume in Ruptured Overfill Flow (Ibm) Flow (ft3)
SG (ft3)'" (fty Week IGroup I 115,740 2,464 5,405 325 Week 1 Group 2 94,410 2,010 5,093 637 Week 1 Group 3 116,370 2,478 5,453 277 Week 2 Group 1 96,021 2,044 5,041 689 Week 2 Group 2 116,756 2,486 5,442 288 Week 2 Group 3 108,370 2,307 5,399 33 1 Week 3 Group 1 102,407 2,180 5,160 570 Week 3 Group 2 113,290 2,412 5,511 219 Week 4 Group 1 127,910 2,723 5,727 3 Week 4 Group 2 104,079 2,216 5,203 527 Week 5 Group 1 103,171 2,197 5,200 530 Week 6 Group 1 114,831 2,445 5,624 106 Week 6 Group 2 113,205 2,410 5,423 307 (1)
\ ,
Maximum water volume ~nthe ru~turedSG includes the ~ n ~ t ivolume, al break flow, and the contribution from Auxiliary Feedwater.
(2) Margin to Overfill = Total SG Volume - Maximum Water Volume Page 16 of 16