ML080580476
| ML080580476 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 01/11/2008 |
| From: | Gerald Bichof Dominion, Dominion Nuclear Connecticut |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| 07-0834G | |
| Download: ML080580476 (34) | |
Text
D~ominion Nudear Connecticut, Inc.
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';())0 Dominion Boulevard, Glen Allen, Virginia 23060 Wei, Address: www.dom.com January 11, 2008 U. S. Nuclear Regulatory Commission Serial No.:
07-0834G Attention: Document Control Desk NLOS/MAE:
RO One White Flint North Docket No.:
50-423 11555 Rockville Pike License No.:
NPF-49 Rockville, MD 20852-2378 DOMINION NUCLEAR CONNECTICUT, INC.
MILLSTONE POWER STATION UNIT 3 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING STRETCH POWER UPRATE LICENSE AMENDMENT REQUEST RESPONSE TO QUESTIONS SRXB-07-0013 THROUGH SRXB-07-0047
-Dominion Nuclear Connecticut, Inc. (DNC) submitted a stretch power uprate license amendment request (LAR) for Millstone Power Station Unit 3 (MPS3) in letters dated July 13, 2007 '(Serial Nos. 07-0450 and 07-0450A), and supplemented the submittal by letters dated September 12, 2007 (Serial No. 07-04508) and December 13, 2007 (Serial No. 07-0450C).
The NRC staff forwarded requests for additional information (RAIs) in October 29, 2007 and November 27, 2007 letters. DNC responded tothe RAIs in letters dated November 19, 2007 (Serial No. 07-0751) and December 17, 2007 (Serial No. 07-0499). The NRC staff forwarded an additional RAI in a December 14, 2007 letter. The response to questions SRXB-07-0013 through SRXB-07-0047 of this RAI is provided in the attachment to this letter.
The information provided by this letter does not affect the conclusions of the significant hazards consideration discussion in the December 13, 2007 DNC letter (Serial No. 07-0450c).
Should you have any questions in regard to this submittal, please contact Ms. Margaret Earle at 804-273-2768.
Sincerely, erald T. Bischof Vice President - Nuclear Engineering COMMONWEALTH OF VIRGINIA, COUNTY OF HENRICO The foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, today by Gerald T. Bischof, who is Vice President - Nuclear Engineering of Dominion Nuclear Connecticut, Inc. He has affirmed before me that he is duly authorized to execute and file the foregoing document in behalf of that Company, and that the statements in the document are true to the best of his knowledge and belief.
7/
Acknowledged before me this day of 2008.
My Commission Expires:.
0 VICKI L. HWA, Notiry Public Conrmmiio bplms M"y31. 210
Serial No. 07-0834G Docket No. 50-423 SPU Ques. SRXB-07-0013 to SRXB-07-0047 Page 2 Commitments made in this letter: None Attachment cc:
U.S. Nuclear Regulatory Commission Region I Regional Administrator 475 Allendale Road King of Prussia, PA 19406-1415 Mr. J. G. Lamb U.S. Nuclear Regulatory Commission One White Flint North 11555 Rockville Pike Mail Stop O-8B1A Rockville, MD 20852-2738 Ms. C. J. Sanders Project Manager U.S. Nuclear Regulatory Commission One White Flint North 11555 Rockville Pike Mail Stop O-8B3 Rockville, MD 20852-2738 Mr. S. W. Shaffer NRC Senior Resident Inspector Millstone Power Station Director Bureau of Air Management Monitoring and Radiation Division Department of Environmental Protection 79 Elm Street Hartford, CT 06106-5127
Serial No. 07-0834G ATTACHMENT LICENSE AMENDMENT REQUEST STRETCH POWER UPRATE LICENSE AMENDMENT REQUEST RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION RESPONSE TO QUESTIONS SRXB-07-0013 THROUGH SRXB-07-0047 MILLSTONE POWER STATION UNIT 3 DOMINION NUCLEAR CONNECTICUT, INC.
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 1 of 31 Reactor Systems Branch SRXB-07-0013 (2.8.3-1)
Briefly describe the statistical combination process used to obtain the overall departure from nucleate boiling ratio (DNBR) uncertainty factor in accordance with the reactor technology development plan.
DNC Response The Revised Thermal Design Procedure (RTDP) is the methodology applied in the current licensing basis for statistically combining uncertainties for the DNBR evaluations. This is unchanged by SPU. RTDP is described in WCAP-1 1397-P-A, "Revised Thermal Design Procedure," approved by the NRC in NRC letter from Ashok C. Thadani to W. J. Johnson, dated January 17, 1989 "Acceptance for Referencing of Licensing Topical Report WCAP-11397, Revised Thermal Design Procedure." Using the RTDP methodology, the uncertainties associated with the DNBR correlation, plant operating parameters, fabrication parameters, nuclear parameters and thermal parameters are statistically combined to establish the DNBR thermal design criterion that assures the probability DNB will not occur on the most limiting rod is at least 95% (at a 95% confidence level).
Table 3-1 of WCAP-1 1397 provides a listing of the parameters used in the RTDP methodology.
SRXB-07-0014 (2.8.3-5)
For the steam line break (SLB) accident analyses, provide initial assumed DNBRs for hot full power (HFP), both core average and minimum assumed.
DNC Response As discussed below, the initial DNBR at Hot Full Power using the WRB-2M correlation is greater than 2 for the full range of initial conditions assumed in the steam line break accident analysis.
Since statepoint evaluations rather than transient calculations are performed for the steam line break DNBR analyses, a specific initial DNBR calculation for steam line break analysis has not been calculated.
However, for a number of the other transient analyses, transient DNBR calculations have been performed and plots provided that show the DNBR at the start of the transients. These are shown in the following license report figures:
Malfunction at Full Power DNBR vs. Time
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 2 of 31 2M8.5.2.1-3 Turbine Trip DNBR Case Vessel Average Temperature and DNBR vs. Time 2.8.5-3 Loss of Forced Reactor Coolant Flow-Frequency Decay Pressurizer Pressure and DNBR vs. Time 2.8.5.4.2-3 Rod Withdrawal at Power Minimum Reactivity Feedback -
100% Power - 100 pcm/sec Vessel Average Temperature and DNBR vs.
Time
- 2.8.5.4.2-6 Rod Withdrawal at Power Minimum Reactivity Feedback-100%
Power - 1 pcm/sec Vessel Average Temperature and DNBR vs. Time 2.8.5-4 RCS Depressurization DNBR vs. Time These are representative of the' DNBR at HFP for the steam line break analysis and all of the values in these plots are greater than 2.
SRXB-07-0O0 5 (2.8.3-6)
For the SLB accident analysis, the Licensing Report (LR) states, "Both HFP and HZP [hot zero power] steam line break are typically reanalyzed for each reload."
Please clarify what the language, "typically," means. Under what conditions would these events not be re-analyzed? What determines the need to re-analyze these events? Based on past experience at MPS3, how often are these events re-analyzed?
DNC Response The reload methodology applied in the current licensing basis will continue to apply for the SPU reloads. The Westinghouse reload methodology is described in WCAP-9272-P-A 'Westinghouse Reload Safety Evaluation Methodology" approved by the NRC in NRC letter from Cecil O. Thomas to E. P. Rahe dated May 28, 1985, "Acceptance for Referencing of Licensing Topical Report WCAP-9272(P)19273(NP), Westinghouse Reload Evaluation Methodology."
Table 3.4 of WCAP-9272 defines the key safety analysis parameters for each accident, including steam line break, that are verified for every reload.
This statement is confirmed in the NRC Safety Evaluation Report (SER) where it states 'When a reload safety parameter is not bounded, further analysis is considered necessary to ensure that the margin of safety is maintained for the accident in question."
Thus, for MP3 reloads, if the key safety analysis parameters are not all bounded by the current analysis of record, then the corresponding Steam Line Break statepoint will be re-analyzed. If the statepoint results are not bounded, the transient analysis will be revised.
Past history at MPS3 has shown that while statepoint evaluations are common, the revision of the transient analysis is rare.
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 3 of 31 SRXB-07-0016 (2.8.3-8)
N For the determination of F AH' describe the process used to determine the fraction of full power for analytical purposes. Does the thermal power include flow measurement uncertainty? Does the rated power include flow measurement uncertainty?
DNC Response N
As stated in footnote 3 of License Report Table 2.8.3-1 for the F,H equation, P is determined as the ratio of the thermal power to rated thermal power.
HFP corresponds to P=1.0 (i.e., without uncertainties). The RTDP process described in WCAP-1 1397-P-A addresses the application of uncertainties to the thermal-hydraulic analyses, including thermal power and flow (see the response to RAI N
SRXB-07-0013). As seen from License Report Table 2.8.3-1, the F AH limit for the SPU analysis is being reduced to provide additional DNBR margin. This will be reflected in the Core Operating Limits Report for the SPU cycles. Core design analyses assure that this limit will be met for the SPU cycles.
SRXB-07-0017 (2.8.3-10)
In Table 2.8.3-2, limiting parameter directions for departure from nucleate boiling (DNB) are presented. However, moving any of these parameters in a limiting direction could have an effect on other parameters used in the analysis. For instance, assuming a decreased value of the nominal vessel/core inlet temperature would have the effect of increasing the reactor core heat output and the average heat flux. Discuss the intent of providing the information in this table.
Provide additional information showing the effects that changing each parameter in a "conservative" direction would have on each other parameter listed in the table.
DNC Response License Report Table 2.8.3-2 is meant to provide general information about the DNBR correlation as implemented in VIPRE. The table provides the direction of DNBR assuming all of the other parameters remain unchanged. For example, for core inlet temperature, it is assumed that all other parameters, including fuel rod heat flux remains the same with only the inlet temperature being changed.
Raising inlet temperature will result in a lower calculated minimum DNBR.
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 4 of 31 SRXB-07-0018 (2.8.4.1-1)
Verify that the reactor cavity cooling systems-(RCCAs) will continue to meet the reactivity control requirements of the uprated core design.
DNC Response There are no hardware modifications required to the Rod Cluster Control Assemblies (RCCAs) for implementation of SPU. As shown in Licensing Report Table 2.8.2-1, the RCCAs will continue to provide at least 1'.3% shutdown margin at SPU conditions. This is unchanged from the current licensing basis. The RCCAs will continue to provide the required shutdown margin for all modes of operation.
Some of the control rod parameter limits such as rod worth and differential rod worth are being changed to provide additional operational and DNBR margin.
However, as described in License Report Section 2.8.5, the SPU DNBR analysis performed for each of the required accidents, demonstrates that the control rods will continue to assure that all thermal design limits are met.
As discussed in License Report Section 2.4.2, Nuclear Supply Steam System (NSSS) Instrument and Control (I&C) systems, including the rod control system, will continue to respond to plant operational transients without initiating a reactor trip or Emergency Core Cooling System (ECCS) actuation at SPU conditions.
Thus, the RCCAs will continue to meet all reactivity control requirements at SPU conditions.
SRXB-07-0019 (2.8.4.2-1)
Please provide transient plots and sequence of events tables for the analysis cases of Section 2.8.4.2.
Please identify the reactor scram signals that are credited in the analyses (i.e., the second safety-grade signals).
DNC Response For the analysis of the Turbine Trip event with a failure of the first safety-grade signal, it was assumed that the high pressurizer pressure reactor trip has failed and the reactor trips on Overtemperature AT. Table 1 provides the sequence of events and pertinent plots are provided in Figures 1, 2, and 3 for this analysis.
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 5 of 31 Table 1 (RAI SRXB-07-0019)
Time Sequence of Events Turbine Trip without First Safety Grade Reactor Trip Event Time into Transient (sec)
Turbine Trip 0.0 High Pressurizer Pressure 6.2 Reactor Trip Setpoint Reached (Trip Not Credited)
Pressurizer Safety Valves 8.2 Open Peak RCS Pressure Occurs 11.8 (2747 psia)
Overtemperature AT Reactor 12.8 Trip Setpoint Reached Rods Begin to Drop 14.3
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 6 of 31 Figure 1 (RAI SRXB-07-0019)
Turbine Trip without First Safety Grade Reactor Trip RCS Pressure and Pressurizer Water Volume vs. Time Pressur izer Pressure RCP Out le t Pressure 2800" 2700" 2600 2500" CO C-)
&- 2400" -
0-
¢ 2300-2200" -,*
2100 05 10 15 20 25 30 Time (seconds) 1800 1600" E
S1200-CD loo 15 Time (seconds)
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 7 of 31 Figure 2 (RAI SRXB-07-0019)
Turbine Trip without First Safety Grade Reactor Trip Nuclear Power and Steam Generator Pressure vs. Time 1 0-6 0
-T 0 I I
I I
I I
I I~ I~ I I
I I
I I
I I
I U
0 5
10 15 Time (seconds) 20 25 30 a--
U)
CD E)
U)
(.n 15 Time (seconds)
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 8 of 31 Figure 3 (RAI SRXB-07-0019)
Turbine Trip without First Safety Grade Reactor Trip Vessel Average Temperature vs. Time 630' 620-
-ý 610-_
CE 600-I--
590-
-*580 Time (seconds)
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 9 of 31 SRXB-07-0020 (2.8.4.3-1)
Note the typo in Section 2.8.4.3.2.3. The inadvertent startup of a reactor coolant pump (RCP) is the limiting heat addition transient, not the limiting mass addition transient.
DNC Response There is a typographical error in the first sentence of License Report Section.
2.8.4.3.2.3. It should read:
"The limiting heat addition transient is the inadvertent startup of a RC pump with the SG 50 degrees F hotter than the reactor coolant system (RCS)."
SRXB-07-0021 (2.8.4.3-2)
Which is the more limiting transient, the mass addition or the heat addition?
DNC Response The limiting transient is the heat addition transient and the current analysis remains bounding for SPU.
SRXB-07-0022 (2.8.4.4-1)
The cooldown analysis for safety grade cold shutdown shows significant improvements in analyzed performance from pre-to post-SPU.
Explain what differences in the analysis performed cause this effect.
DNC Response Table 2.8.4.4-1, Table 2.8.4.4-5, and Table 2.8.4.4-6 provide the safety grade cold shutdown (SGCS) analysis results.
Table 1 below summarizes the SGCS cooldown results:
Table 1 Safety Grade Cold Shutdown Analysis Results SGCS Scenario Cooldown Time to 200 OF (hours)
Pre-SPU Post-SPU One Train Available 48 49.25 Two Trains Available 55.25 64
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 10 of 31 The SGCS analysis results show that the proposed cooldown related design changes identified in Table 2.8.4.4-2 are effective in offsetting the increased decay heat due to SPU for the SGCS one train available case. The SGCS two train available case results shows a longer cooldown time and this result is related to a licensing bases change identified in Attachment 1 of the MPS3 SPU Licensing Amendment Request.
The normal cooldown cases have a significant improvement in cooldown time.
This significant improvement is due to an increase in the maximum residual heat removal heat exchanger reactor plant component cooling water return piping operating temperature and decay heat modeling changes (see Tables 2.8.4.4-2 through 2.8.4.4-4).
SRXB-07-0023 (2.8.4.4-2)
Explain why the initial power level for normal cooldown analysis does not include power measurement uncertainty.
DNC Response The selected normal cooldown analysis calculational methodology produces a representative or accurate assessment of actual normal cooldown performance.
There are many parameters that go into the normal cooldown analysis and each has some uncertainty. If all parameters are biased in the conservative direction simultaneously, the analysis result becomes inaccurate/non-representative.
Therefore, a few analysis parameters were selected for biasing in the conservative direction so that the analysis is somewhat conservative, but not overly conservative.
The alternate would be a complicated statistical based uncertainty analysis; which is unwarranted for a normal cooldown analysis.
Table 1 lists some normal cooldown analysis parameters and provides a characterization.
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 11 of 31 Table 1 Selected Normal Cooldown Analysis Parameters and Characterization Parameter Characterization Initial Power Level Best Estimate Value Decay Heat Model Better Estimate Value RCS Initial Temperature Extreme of Operating Range RHS HX UA Upper End of Fouling Range CCP HX UA Upper End of Fouling Range CCP Tube Plugging Upper End of Plugging Range Service Water Flow Best Estimate Value Service Water Temperature Upper End of Operating Range (75 OF) -
average ultimate heat sink temperature over cooldown evolution would be less given the normal daily temperature cycle.
SFP Heat Load Extreme Value - SFP heat load just after a refueling outage. This is conservative because refueling outages are not scheduled during peak UHS temperature conditions.
This is standard engineering practice for an analysis that does not have specific regulatory requirements, such as 10 CFR 50.46 or 10 CFR 50 Appendix K.
A comparison was performed between the decay heat curve promulgated in BTP ASB 9-2 (attached to SRP 9.2.5) and the MPS3 normal cooldown analysis decay heat curve and they are consistent (in the time frame of interest for the normal cooldown analysis).
The MPS3 normal cooldown analysis decay heat model and initial power level assumptions represent standard industry practice for normal cooldown analysis on Westinghouse plants. For example, normal cooldown calculations associated with the Kewaunee License Amendment Request 193 (up-rate) utilize the ANSI 5.1-1979 decay heat standard with zero uncertainty and an initial power level with zero uncertainty.
Additional Information The current MPS3 normal cooldown and SGCS calculation of record was completed in 1997.
In 1997, to simplify the cooldown analysis (i.e., as an engineering convenience), the same conservative methods/inputs were applied to the normal cooldown analysis as were applied to the SGCS analysis (e.g.,
ANS 5.1.1979, with 2a uncertainty and 2 % uncertainty in initial power level).
The prior normal cooldown analysis of record was S&W Calculation P(R)-1164 (circa 1985) and the analysis used nominal licensed power level and a decay heat curve equivalent to the SPU normal cooldown analysis decay heat model.
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 12 6f 31 Therefore, the normal cooldown analysis decay heat changes should be viewed as re-establishing the normal cooldown analysis decay heat model.
SRXB-07-0024 (2.8.4.4-3)
Explain why a zero uncertainty decay heat model is acceptable for safety grade cold shutdown analysis.
DNC Response Table 2.8.4.4-5, and Table 2.8.4.4-6 provide the safety grade cold shutdown (SGCS) analysis details.
Table 1 below summarizes the SGCS analysis parameter related to decay heat:
Table 1 Safety Grade Cold Shutdown Analysis Parameter Related to Decay Heat Pre-SPU Post-SPU Decay Heat Model ANS 5.1-1979. with 2y ANS 5.1-1979. with 2a uncertainty uncertainty Initial Power Level 102 %
102 %
Therefore, the zero uncertainty decay heat model is not used in the SGCS analysis.
Additional Information The SPU normal cooldown analysis uses an ANS 5.1-1979 with zero uncertainty heat model. The preceding RAI response was expanded to address the normal c'ooldown analysis uncertainty in both initial power level and the decay heat model.
SRXB-07-0025 (2.8.4.4-4)
Discuss the design details of the residual heat removal system heat exchanger to show that a 15°F increase in heat exchanger outlet temperature is acceptable.
DNC Response LR Table 2.8.4.4-2, "Proposed Cooldown Related Design Changes" reports a 15'F (130 => 145 0F) RHR heat exchanger reactor plant component cooling water return piping maximum operating temperature increase for the normal cooldown scenario. There is a 5°F (140 = 1450F) increase for the SGCS scenario.
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 13 of 31 Table 1 provides selected residual heat removal heat exchanger (3RHS*E1A/B) design details.
Table 1 RHR Heat Exchanger Design Details Parameter TEMA Type BEU___________
Shell Side Tube Side Fluid Component Cooling Water RCS Fluid Design Temperature 200 400 (OF)
Design Pressure (psig) 175 600 The proposed 145°F shell-side residual heat removal heat exchanger outlet maximum operating temperature is acceptable because the maximum operating temperature is well below the 200'F residual heat removal heat exchanger shell-side (component cooling water side) design temperature.
SRXB-07-0026 (2.8.4.4-5)
Confirm the capability of the plant to remove the increased heat load from the component cooling water.
DNC Response General With respect to safety grade cold shutdown (SGCS) cooldown analysis, the reactor plant component cooling water (CCP) heat exchanger's capability to reject heat to the ultimate heat sink (UHS, Long Island Sound) is confirmed through engineering analysis.
The two main considerations relative to uncertainty in the CCP heat exchanger's heat transfer capability are: 1) component cooling water heat exchanger overall heat transfer coefficient (U) and 2) service water flow rate.
NRC GL 89-13 and CCP Water Heat Exchanger Overall Heat Transfer Coefficient NRC Generic Letter 89-13, Item II addresses a program to verify heat transfer capability to all safety related heat exchangers cooled by service water. The MPS3 NRC Generic Letter 89-13, Item II response with respect to the CCP heat exchangers is based on a program of periodic cleaning and inspection.
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 14 of 31 Review of Available CCP Heat Exchanger Overall Heat Transfer Coefficient Benchmarking Information 3CCP*E1A and 3CCP*E1B were subject to thermal performance testing in 1999 with high CCP heat exchanger heat load due to residual heat removal heat exchanger operation.
CCP System temperature control system automatically bypasses CCP flow around the CCP heat exchanger to regulate CCP supply header temperature.
Technical Evaluation M3-EV-99-0080 shows the 1999 3CCP*E1 B thermal performance test was conducted with a maximum 2328-gpm shell-side flow and this shell-side flow was too far from actual SGCS shell-side process conditions for meaningful comparison.
Technical Evaluation M3-EV-99-0079 assesses the 1999 3CCP*E1 A thermal performance test results. For the tested condition with the highest shell-side flow (i.e., Test 3 with a 5919-gpm shell-side flow) test results reduced to a nominal 321 Btu/(hr-sqft-F) overall thermal performance coefficient, with a possible range of 293 to 354 Btu/(hr-sqft-F) due to test measurement uncertainty. This test was conducted in the "as-found" condition (end of the heat exchanger's operating cycle).
The SGCS analysis is based upon a 349 Btu/(hr-sqft-F) overall thermal performance coefficient (8000-gpm shell-side flow and 7388-gpm tube-side flow).
A more rigorous thermal performance analysis is required for 1999-result comparison to the analysis value. Specifically the impact of thermal property differences (due to operating temperatures) and shell-side & tube-side mass flow rate differences need to be quantified. A calculation was performed to support this RAI response and it shows the following:
Table 1 Comparison of SGCS Analysis Overall Heat Transfer Coefficient To 1999 3CCP*E1 A Thermal Performance Results Limited Benchmarking Information SGCS Design Analysis 1999 Thermal Performance Results1
[Btu/(hr-sqft-F)]
[Btu/(hr-sqft-F)]
Overall Heat Transfer 349 357 Coefficient I
II Nominal 1999 thermal performance results scaled to SGCS design process conditions.
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 15 of 31 Therefore, the 1999 3CCP*E1A thermal performance results do provide limited thermal performance benchmarking data which substantiates that a representative overall heat transfer coefficient has been used in the SGCS analysis.
Service Water Flow The SGCS analysis is based upon a 7388-gpm SW flow, which is 82 percent of the best estimate flow [7388/9000 = 82%].
The 7388-gpm SW flow is based upon an analysis that postulated many coincident unlikely conditions.
This provides confidence that the actual CCP heat exchanger SW flow during the SGCS cooldown phase with the residual heat removal heat exchanger in-service (which starts at 11-hours after reactor shutdown) would be
> 7388 gpm.
SRXB-07-0027 (2.8.4.4-6)
Explain why the auxiliary heat load is reduced.
DNC Response Table 1 provides selected cooldown analysis auxiliary heat loads:
Table 1 Cooldown Analysis, Auxiliary Heat Loads, Selected Scenarios Case/Train Auxiliary Heat Load (MBtu/HR)
Pre-SPU Post-SPU SGCS, One Train Available 27 23.8 SGCS, Two Trains Available 2.6/27 2.6/23.8 (Lead Train/Follow Train)
Normal Cooldown; Second RHS Train Aligned 2.6/27 2.6/23.8 at 260 'F; One RCP Running (Lead Train/Follow Train)
The category "auxiliary heat loads" includes the spent fuel pool cooling system (SFC) heat exchanger design heat load (i.e., the spent fuel pool design heat load associated with full power operation, less evaporative cooling).
The pre-SPU cooldown analysis included a 5-MBtu/HR allowance for uncertainty in the future spent fuel pool heat load (e.g., an allowance for a future SFP design/licensing changes to accommodate the transfer of spent fuel from MPS1 and MPS2).
Given the Millstone dry spent fuel storage facility addition, this
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 16 of 31 cooldown analysis contingency is no longer required. Contingency elimination, plus accommodation for increased heat load due to future post-SPU SFP discharges, and less evaporative cooling, results in the reported SFC values.
Table 2.8.4.4-3 through Table 2.8.4.4-6 list the spent fuel pool heat loads assumed in the analysis and are summarized below:
Table 2 Cooldown Analysis Pre-SPU Post-SPU Spent Fuel Pool Heat Load Associated with 23.6 20.4 SFC System (MBtu/HR)
The 3.2 MBtu/HR "auxiliary heat loads" reduction (27 - 23.8 = 3.2 MBtu/HR) mirrors the 3.2 MBtu/HR spent fuel pool cooling (SFC) heat exchanger heat load reduction (23.6 - 20.4 = 3.2 MBtu/HR) in the cooldown analysis.
In summary, the cooldown analysis auxiliary heat load reduction is associated with spentfuel pool heat load inputs/assumptions.
Specifically, a contingency cooldown analysis to accommodate future SFP changes has been eliminated from the cooldown analysis.
SRXB-07-0028 (2.8.5.0-2)
Regarding the steady-state initial condition uncertainties listed on Page 2.8-74 of the LR, specifically explain how these uncertainties are applied to the analyses.
Despite the information provided in the preceding paragraph, the list items employ +/- uncertainties, suggesting that sensitivity studies were performed.
Confirm whether this was the case.
DNC Response The information in License Report Section 2.8.5.0.3.2 provides generic information about the range of each of the initial condition parameters. For each transient, the direction of conservatism for the significant initial parameters for that transient are determined (see LR table 2.8.3-2 and the response to RAI SRXB-07-0017) and the analysis is performed at the conservative limit of the range of that parameter as given in License Report Section 2.8.5.0.3.2.
The direction of conservatism for the significant parameters is provided in the section "Input Parameters, Assumptions and Acceptance Criteria" for each of the analyzed accidents discussed in Sections 2.8.5.1 through 2.8.5.7.
For some transient descriptions where initial condition assumptions are significant, a detailed discussion is provided. For others, where initial condition assumptions have a minor impact, a brief discussion is provided.
The non-significant
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 17 of 31 parameters are not discussed. The level of detail matches the discussion in the current MP3 FSAR.
SRXB-07-0029 (2.8.5.1-1)
For the major steam line rupture analysis, why is only the two-out-of-four pressurizer low-pressure signal credited for safety injection actuation? It seems that the safety injection actuation signal (SIAS) would be generated first by the two-out-of-three low-pressure signals in any steam line.
DNC Response For additional conservatism, the safety injection on low steam line pressure was not credited. This was done to provide future flexibility, since acceptable results could be shown without crediting this ECCS initiation function.
SRXB-07-0030 (2.8.5.3.1-1)
Loss of Forced Reactor Coolant Flow - For the loss of power to one RCP, the times assumed in the current licensing basis (CLB) analysis sequence are less than those in the SPU Licensing Report (SPULR).
This could be intuitive, considering that the pumps are delivering more mass to the reactor core at SPU power levels. However, the timing assumptions for the loss of power to all RCPs do not change from current licensed power (CLP) to SPULR.
Explain this inconsistency.
DNC Response As stated in License Report Section 2.8.5.3.1.2.3, the coastdown models between RETRAN and LOFTRAN were shown to compare favorably such that RETRAN is considered equivalent to LOFTRAN.
This is further shown by a comparison of the coastdown curves given in License Report Figure 2.8.5-1 and the current FSAR Figure 15.3-1 for the four pump coast down case.
The sequence of events for the four pump coast down case are the same.
For the single pump coastdown case, there are some very small changes in the sequence of events (0.2 seconds).
For the single pump coastdown case, the flow coastdown in the affected loop is affected by the flow being provided by the unaffected loops. The small differences in the sequence of events is attributed to the more detailed modeling of the RCS loops used in the RETRAN model when compared to LOFTRAN.
The MPS3 RCS implemented in the RETRAN model is bounded by the NRC approved Westinghouse Topical WCAP-14882-P-A "RETRAN-02 Modeling and Quantification for Pressurized Water Reactor Non-LOCA Safety Analysis," as
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 18 of 31 discussed in License Report 2.8.5.0.10. The MPS3 analyses represent a conservative evaluation for the single and four pump RCS coastdown analyses.
I SRXB-07-0031 (2.8.5.3.1-2)
Loss of Forced Reactor Coolant Flow - Discuss any conservatism with respect to the 2.8-230 selection of feedwater temperature assumptions used in the loss of forced coolant flow analysis.
DNC Response The maximum feedwater temperature is selected in order to minimize the heat transfer to the steam generator and consequently maximize the RCS temperature during the transient. With the four pump coastdown and subsequent reactor trip, natural circulation will be established. The cold leg temperature will be close to the steam generator temperature and the hot leg temperature will increase commensurate with the natural circulation flow.
By maximizing the initial feedwater temperature, the initial steam generator temperature will be maximized. This will maximize the cold leg temperature during natural circulation and will maximize the core inlet temperature.
Maximizing the core inlet temperature is conservative for DNBR analyses.
It should be noted that for the 10 second time frame of the transient shown in Figure 2.8.5-3, changes in steam generator heat removal will not be significant and thus, feedwater temperature is not a significant parameter for the loss of forced reactor coolant flow analysis.
SRXB-07-0032 (2.8.5.3.2-2)
RCP Rotor Seizure/Shaft Break - The updated final safety analysis report presents an analysis that assumes remaining pumps lose power 2 seconds after reactor trip and the SPU analysis assumes loss of power to pumps and coastdown simultaneous with reactor trip initiation at 1.1 seconds. Given that peak RCS pressure and peak cladding temperature occur on fairly short timescale, these apparent differences could be significant.
Explain these differences and account for the acceptability of the new method/SPU analysis.
DNC Response Tripping the remaining RC pumps will maximize the heatup of the core. It was decided to add additional conservatism, by reducing the time delay between reactor trip and loss of power to the remaining RC pumps.
This added conservatism provides added assurance that the SPU analyses are bounding.
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 19 of 31 SRXB-07-0033 (2.8.5.3.2-4)
RCP Rotor Seizure/Shaft Break - Figure 2.8.5-1 illustrates a slight decrease in lower plenum pressure prior to 2 seconds, and prior to the ultimate increase to the observed peak vessel pressure. The cause of this increase is not readily discernible from the listed initial conditions. Please explain.
DNC Response Based upon discussions with NRC staff, an explanation of the slight pressure drop noted prior to two seconds is being requested. The slight pressure drop is due to the drop in core power caused by reactor trip.
SRXB-07-0034 (2.8.5.4.1-1)
RCCA Withdrawal from Subcritical - Explain why the progression of this transient is delayed 4 seconds from that in the final safety analysis report (FSAR).
DNC Response The current analysis uses an overly conservative differential rod worth assumption of 145 pcm/in. The cycle specific analysis shows excess margin to this limit. Thus, the differential rod worth assumption has been changed to 100 pcrr/in to obtain additional DNBR margin.
The smaller differential rod worth decreases the rate of reactivity insertion and slows down the power rise such that the reactor trip will occur later. With the change in differential worth, the SPU analysis documented in License Report Section 2.8.5.4.1 demonstrates that all DNBR limits are met and the analysis remains conservative. The core design analyses assure that the new differential rod worth limit will be met for the SPU core design.
SRXB-07-0035 (2.8.5.4.2-1)
Uncontrolled RCCA Bank Withdrawal at Power - Explain why a change from 75 pcrn/sec to 100 pcrrVsec occurred from CLB to SPULR. Discuss this change with respect to current RCCA nuclear design and mechanical withdrawal capability.
Confirm that a 100 pcrm/sec withdrawal remains conservative and bounding based on expected operating parameters at the plant.
DNC Response To provide additional margin for rod worths at full power, the range of possible reactivity insertion rates was expanded from (3 pcm/sec-75 pcm/sec) to (1 pcrTlsec-1 00 pcrnsec). Demonstration of acceptable results at the wider band provides additional assurance that the limiting reactivity insertion rate for the
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 20 of 31 uncontrolled RCCA bank wiithdrawal is analyzed for the SPU conditions.
As seen in License Report Figures 2.8.5.4.2-7, 2.8.5.4.2-8 and 2.8.5.4.2-9 the limiting reactivity insertion rate is encompassed in the new range of 1 pcm/sec to 100 pcrrVsec.
Thus, the range assumed in the SPU analysis assures that a limiting DNBR for a uncontrolled RCCA band withdrawal at power has been determined for SPU conditions. The reload process will continue to ensure that the range of insertion rates considered in the rod withdrawal analysis is bounding for the cycle design.
As discussed in response to RAI SRXB-07-0018, there are no physical changes to the RCCAs and consequently no change in the mechanical withdrawal capability. The proposed change only applies to the range of some analytical parameters.
SRXB-07-0036 (2.8.5.4.2-2)
Uncontrolled RCCA Bank Withdrawal at Power - Provide the same information requested above justifying a transition from 3 pcm/sec slow withdrawal to 1 pcm/sec.
DNC Response See the response to RAI SRXB-07-0035.
SRXB-07-0037 (2.8.5.4.2-3)
Uncontrolled RCCA Bank Withdrawal at Power - Why does the rapid withdrawal analysis assume a lower volume in the pressurizer than that assumed in the CLB analysis?
DNC Response The current licensing basis, analysis models a pressurizer water level of 67.5%
span which is overly conservative with respect to the current program level of 61.5% span. The SPU analysis models a pressurizer water level of 64% span which is consistent with the SPU pressurizer level program. The DNBR analysis is not sensitive to the initial pressurizer level and, therefore, it is not necessary to include additional conservatism for this parameter. The SPU analysis properly reflects the pressurizer level for SPU and is a conservative evaluation of the DNBR for the uncontrolled rod withdrawal at power event.
It is also noted that there are some differences between the pressure level parameter implemented in the current LOFTRAN analysis and the pressurizer level parameter in the SPU RETRAN analysis.
For example, the pressurizer
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 21 of 31 water volume shown in FSAR Figure 15.4-5 "Uncontrolled Rod Withdrawal at Power Pressurizer Pressure and Pressurizer Water Volume vs Time Maximum Reactivity Feedback 75 pcm/sec Withdrawal Rate" and FSAR Figure 15.4-8 "Uncontrolled Rod Withdrawal at Power Pressurizer Pressure and Pressurizer Water Volume vs Time Maximum Reactivity Feedback 0.6 pcm/sec Withdrawal Rate" plots a LOFTRAN output variable which includes the volume of the pressurizer surge line (approximately 55 cu.ft.). The RETRAN output variable which is plotted in Figures 2.8.5.4.2-2 "Rod Withdrawal at Power Minimum Reactivity Feedback -
100% Power -100 pccm/sec Pressurizer Pressure and Water Volume vs Time" and 2.8.8.4.2-5 "Rod Withdrawal at Power Minimum Reactivity Feedback - 100% Power -1 pcm/sec Pressurizer Pressure and Water Volume vs Time" does not include the pressurizer surge line.
SRXB-07-0038 (2.8.5.4.2-5)
Uncontrolled RCCA Bank Withdrawal at Power - Figure 2.8.5.4.2-5 illustrates the assumption that pressurizer sprays and relief valves are assumed to be operational. Provide a table that describes the pressurizer performance during the progression of this transient. Include the operation of the sprays and relief valves.
DNC Response The pressurizer performance is shown in Figure 2.8.5.4.2-2. Pressurizer spray flow was modeled in the RETRAN analysis because the spray can slow the pressure rise up to the Power Operated Relief Valve (PORV) setpoint of 2350 psia. The PORV maintains RCS pressure at or below 2350 psia. With no credit for sprays or PORVs, the RCS pressure will quickly rise to the pressurizer safety valve setpoint of 2500 psia. Thus, modeling the expected performance of the pressurizer sprays and PORVs is conservative since these systems will tend to lower RCS pressure and consequently result in a lower predicted DNBR.
SRXB-07-0039 (2.8.5.4.3-1)
RCCA Misalignment - Regarding the statement on Page 2.8-287 of the SPULR, "Steady-state power distributions are analyzed using the appropriate nuclear physics computer codes," these codes are typically named in other sections of the SPULR. What codes are used in this case?
DNC Response RCCA Misalignment evaluations, including those done for SPU and those done as part of the reload evaluations are performed with Advanced Nodal Code (ANC). ANC is discussed in License Report Section 2.8.5.0.10.
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 22 of 31 SRXB-07-0040 (2.8.5.4.5-2)
Chemical and Volume Control System (CVCS) Malfunction that results in a decrease in boron concentration in the reactor coolant - Throughout this section, the staff noted that assumed volumes of the RCS inventory are different than those listed in the FSAR. Explain why these values changed.
DNC Response Unrelated to the SPU analysis, Westinghouse identified a generic discrepancy associated with the RCS volume contained in the Loop Stop Valves. The current analysis has been updated to reflect resolution of this discrepancy. The SPU analyses have been performed with conservative assumptions for the RCS volume that bound the identified discrepancy.
SRXB-07-0041 (2.8.5.4.5-3)
CVCS Malfunction that Results in a Decrease in Boron Concentration in the Reactor Coolant - During Mode 3, it is noted that rod withdrawal and boron dilution may not occur simultaneously. How is this prevented?
DNC Response The text on License Report 2.8.5.4.2.3 titled "Dilution During Mode" on page 2.8-299 is a copy of the text in FSAR Section 15.4.6.2 titled "Dilution During Hot Standby (Mode 3)" on page 15.4-22. This text is unaffected by SPU.
The current procedural controls provide assurance that the operators will not simultaneously withdraw the control rods and initiate a boron dilution in the approach to Mode 2. These procedural controls will be unchanged for SPU and will continue to assure that there will not be a simultaneous rod withdrawal and boron dilution in the approach to Mode 2 as discussing in License Report Section 2.8.5.4.2.3 and FSAR Section 15.4.6.2.
SRXB-07-0042 (2.8.5.4.5-4)
CVCS Malfunction that Results in a Decrease in Boron Concentration in the Reactor Coolant - The staff noted that, in Modes 1 and 2, initial boron concentrations are assumed to be less than those assumed in the CLB analysis.
Therefore, the resulting change from initial condition is less. Explain why this change occurred.
DNC Response The current assumption is overly conservative. The SPU Boron dilution analysis
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 23 of 31 for Modes 1 and 2 demonstrate that with the new maximum limit for initial boron concentration, there is at least 15 minutes for operator action following reactor trip to ensure that the reactor will remain subcritical.
Core design analyses'ensure that the new limit on maximum boron concentration' in Modes 1 and 2 will be met for SPU conditions.
SRXB-07-0043 (2.8.5.4.6-1)
Spectrum of Rod Cluster Control Assembly Ejection Accidents - On page 2.8-307, the "typical" effective delayed neutron fraction values are discussed in comparison to the conservative values assumed in the safety analysis. What are limiting values, and how do they compare to the safety analysis assumptions?
DNC Response The text in License Report Section 2.8.5.4.6.2.2 titled "Delayed Neutron Fraction, Peff" on page 2.8-307 is essentially a copy of the text in FSAR section 15.4.8.2 titled "Delayed Neutron Fraction" on page 15.4-34. From FSAR section 15.4.8.2 it is seen that the "typical" values refer to historical information from the first cycle of operation and are not relevant for current cycles.
The delayed neutron fractions used in the SPU analysis are given in Table 2.8.5.4.6-1.
SRXB-07-0044 (2.8.5.4.6-3)
Spectrum of Rod Cluster Control Assembly Ejection Accidents - Confirm that the analyzed initial power level for the full power accidents included a 2 percent measurement uncertainty increase to the assumed 3650 MWt power level.
DNC Response The 2% calorimetric uncertainty is incorporated into FACTRAN analysis for the RCCA Ejection Accident.
SRXB-07-0045 (2.8.5.4.6-4)
Spectrum of Rod Cluster Control Assembly Ejection Accidents - Regarding the changes in conservative assumptions from current licensed thermal power (CLTP) to the uprated power level analyses, address the statement that "SPU analyses remain conservative and are revalidate as conservative for each subsequent reload." How is this revalidation performed?
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 24 of 31 DNC Response The revalidation process is described in NRC approved Westinghouse Topical Report WCAP-9272-P-A 'Westinghouse Reload Safety Evaluation Methodology" (Refer to the response to RAI SRXB-07-0015).
The key safety analysis parameters re-validated every reload for the RCCA ejection event are provided in Table 3.4 of WCAP-9272.
SRXB-07-0046 (2.8.5.5-2)
MPS3 proposes to add a permissive (P-19) that requires the coincidence of a SIAS and a low pressurizer pressure reactor trip signal to allow the automatic opening of the cold leg injection valves. An SIAS, alone, will result only in the delivery of RCP seal cooling water from the charging pumps.
- a.
Please provide a logic diagram, typical of the diagrams found in Chapter 7 of the FSAR, that depicts the P-19 permissive: its inputs, outputs, and connecting logic.
- b.
An SIAS can be generated by any of the following:
- Two-out-of-four pressurizer low-pressure signals;
- Two-out-of-three low-pressure signals in any steam line;
- Two-out-of-three high-containment pressure signals.
Please explain how the P-19 permissive would prevent the cold leg injection valves from opening, while the RCS is at nominal pressure, if the spurious SIAS were to originate in the pressurizer low-pressure logic.
DNC Response
- a. Updates to the following logic diagrams provide the P-19 inputs, outputs and connecting logic:
25212-39001 SH 4007 25212-28022 SH 22 25212-28434 SH 01
- b. The cold leg injection permissive will be placed in series with the SIAS signal in the Charging Pumps to Reactor Cold Legs Isolation Valves' control circuits.
Both the P-19 permissive and the SIAS are required to be actuated before the Charging Pumps to Reactor Cold Legs Isolation Valves will automatically open to allow Charging Pump flow to the Reactor cold legs. (25212-28434 SH 01)
The cold leg injection permissive will be generated in the MPS3 solid state protection system (SSPS) utilizing 'the two-out-of-four pressurizer pressure
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 25 of 31 low bistables that also generate the pressurizer low pressure reactor trip (25212-39001 SH 4007). These bistables are physically independent from the two-out-of-four pressurizer low pressure bistables that generate the SIAS.
No common mode failure within the pressurizer pressure bistables or the SSPS could result in a spurious SIAS coincident with a cold leg injection permissive.
Both sets of bistables receive their input from a common set of four pressurizer pressure transmitters. To have a spurious SIAS generated from a pressurizer low pressure coincident with a cold leg injection permissive would require two active failures of the safety related pressurizer pressure transmitters.
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 26 of 31
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Serial No. 07-0834G Docket No. 50-423 Attachment, Page 29 of 31 SRXB-07-0047 (2.8.5.5-3)
- a. The results of the CVCS malfunction analysis cases indicate that the pressurizer would become water-solid in 761 seconds (one charging pump in operation), and 503 seconds (two charging pumps in operation). The pressurizer safety valve (PSV) opening setpoint is reached in 1156.2 seconds, and 601.4 seconds, respectively.
Describe the process that is used to verify that the operators can terminate the CVCS malfunction (or make at least one power operated relief valve (PORV) available), after they are alerted by the pressurizer level deviation signal, and before the PSV opening setpoint is reached.
- b. Are any of the pressurizer level alarms that are assumed to alert the operators to a CVCS malfunction (e.g., the pressurizer level deviation signal) qualified safety-related signals?
If not, then how much time is available from receipt of the pressurizer high water level reactor trip signal?
Are the operators capable of terminating the CVCS malfunction (or making at least one PORV available) after they are alerted by the pressurizer high water level reactor trip signal, and before the PSV opening setpoint is reached?
DNC Response
- a. With a failure of the pressurizer level channel used to control RCS inventory, the charging control valve will go wide open and the CVCS letdown pathway will be isolated. This will generate a number of alarms immediately at the initiation of the failure. These include the following:
Pressurizer Level Deviation Pressurizer Level Low Heater Off and Letdown Secure Pressurizer Heater Control Group Auto Trip While the alarm circuitry itself is not safety related, they are driven by the pressurizer level instrumentation which is safety related.
This failure scenario is included in the simulator training exercises for initial operator qualification and is included in the requalification training program. The operators are expected to place the charging pump flow control in manual and terminate the pressurizer overfill. The training expectation is that the operators will terminate this transient before reactor trip. Failure to terminate the overfill prior to reactor trip would be a failure to meet expectations. Experience from the simulator exercises shows that the operators will routinely meet this expectation.
The excess charging flow rate for the CVCS malfunction is less than the inadvertent ECCS event, because the normal CVCS flow path is more restrictive
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 30 of 31 than the ECCS flow path.
This is the current basis for concluding that the Inadvertent ECCS Actuation is bounding for the CVCS malfunction.
Since the available response time is primarily a function of the charging capacity and is independent of the reactor power level, the operator response for the CVCS malfunction at SPU conditions will continue to remain bounded by the current.
inadvertent ECCS Actuation analysis.
- b. As stated above, the annunciator alarms are not safety grade. However, the alarm circuitry is driven off of safety related instrumentation through the appropriate isolation devices. It should be noted that, as the event progresses, there are a number of additional alarms that would occur as the reactor trip setpoint is reached. These include the following:
" Charging pump high flow alarm
" Initiation of automatic makeup to the Volume Control Tank (VCT)
- VCT low pressure alarm Pressurizer level deviation alarm Pressurizer heater backup group auto trip alarm and
- VCT low level alarm.
Considering the number of alarms that will be received from this event and that a number of the alarms are derived from safety related instrumentation, these alarms can be credited as is the case for the current licensing basis.
From the RETRAN results for this event, the 96.6% high pressurizer level trip (includes 7.6% uncertainty) would occur as follows:
Single pump case: trip time approximately 576 seconds Two pump case: trip time approximately 378 seconds The minimum time between reactor trip and pressurizer safety valve opening are as follows:
Single pump case: 1156-576 = 580 seconds, approximately 9.7 minutes Two pump case: 601-378 = 223 seconds, approximately 3.7 minutes Since the operators are expected to terminate this event prior to reactor trip, no operator response data is available to support a conclusion about the capability of the operators to terminate the transient in the time frame available between reactor trip and challenging the safety valve.
It should be noted that the timeframe for the single pump case is comparable to the 10 minute time limit applied to the current inadvertent ECCS actuation event.
Serial No. 07-0834G Docket No. 50-423 Attachment, Page 31 of 31 Operation with both charging pumps in service represents a very small fraction of system operation. Two pumps will be in service briefly when transferring the operating train charging pump. When this transfer occurs, charging flow control is normally placed in manual and as such would not be subject to the assumed failure.
Further, with charging flow control in manual, the operators are continuously monitoring pressurizer level and would quickly terminate any overfill event. Two pump operation is also used to reduce radiation doses in the plant.
This is typically done at the end of the operating cycle in preparation for shutdown. Operation in this configuration is usually less than two weeks of the total cycle time.