ML042190085
| ML042190085 | |
| Person / Time | |
|---|---|
| Site: | Seabrook  |
| Issue date: | 08/18/2004 |
| From: | Scott Wall NRC/NRR/DLPM/LPD1 |
| To: | Peschel J, Warner M Florida Power & Light Energy Seabrook |
| Wall, S. NRR/DLPM 415-2855 | |
| References | |
| TAC MC2364 | |
| Download: ML042190085 (24) | |
Text
August 18, 2004 Mr. Mark E. Warner, Site Vice President c/o James M. Peschel Seabrook Station PO Box 300 Seabrook, NH 03874
SUBJECT:
SEABROOK STATION, UNIT NO. 1 - REQUEST FOR ADDITIONAL INFORMATION FOR PROPOSED AMENDMENT REQUEST REGARDING THE APPLICATION FOR STRETCH POWER UPRATE (TAC NO. MC2364)
Dear Mr. Warner:
By letter dated March 17, 2004, as supplemented by a second letter dated March 17, 2004, and letters dated April 1, and May 26, 2004, FPL Energy Seabrook, LLC, submitted its application to increase the licensed thermal power level at Seabrook Station, Unit No. 1. The proposed amendment would allow the maximum authorized power level to increase by approximately 5.2 percent, from 3411 megawatts thermal (MWt) to 3587 MWt.
The Nuclear Regulatory Commission staff is reviewing the information provided in these submittals and has determined that additional information, as delineated in the Enclosure, is needed to complete its review. The request for additional information was discussed with your staff on August 5, and August 17, 2004. A response date of October 1, 2004, was mutually agreeable.
If you have any questions, please call me at (301) 415-2855.
Sincerely,
/RA/
Scott P. Wall, Project Manager, Section 2 Project Directorate I Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-443
Enclosure:
Request for Additional Information cc w/encl: See next page
Seabrook Station, Unit No. 1 cc:
Mr. J. A. Stall Senior Vice President, Nuclear and Chief Nuclear Officer Florida Power & Light Company P.O. Box 14000 Juno Beach, FL 33408-0420 Mr. Peter Brann Assistant Attorney General State House, Station #6 Augusta, ME 04333 Resident Inspector U.S. Nuclear Regulatory Commission Seabrook Nuclear Power Station P.O. Box 1149 Seabrook, NH 03874 Town of Exeter 10 Front Street Exeter, NH 03823 Regional Administrator, Region I U.S. Nuclear Regulatory Commission 475 Allendale Road King of Prussia, PA 19406 Office of the Attorney General One Ashburton Place, 20th Floor Boston, MA 02108 Board of Selectmen Town of Amesbury Town Hall Amesbury, MA 01913 Ms. Deborah Bell Federal Emergency Management Agency Region I J.W. McCormack P.O. &
Courthouse Building, Room 401 Boston, MA 02109 Mr. Tom Crimmins Polestar Applied Technology One First Street, Suite 4 Los Altos, CA 94019 Mr. Stephen McGrail, Director ATTN: James Muckerheide Massachusetts Emergency Management Agency 400 Worcester Road Framingham, MA 01702-5399 Philip T. McLaughlin, Attorney General Steven M. Houran, Deputy Attorney General 33 Capitol Street Concord, NH 03301 Mr. Bruce Cheney, Director New Hampshire Office of Emergency Management State Office Park South 107 Pleasant Street Concord, NH 03301 Mr. Gene F. St. Pierre Station Director Seabrook Station FPL Energy Seabrook, LLC P.O. Box 300 Seabrook, NH 03874 Mr. M. S. Ross, Managing Attorney Florida Power & Light Company P.O. Box 14000 Juno Beach, FL 33408-0420 Mr. Rajiv S. Kundalkar Vice President - Nuclear Engineering Florida Power & Light Company P.O. Box 14000 Juno Beach, FL 33408-0420 James M. Peschel Regulatory Programs Manager Seabrook Station FPL Energy Seabrook, LLC PO Box 300 Seabrook, NH 03874
Seabrook Station, Unit No. 1 cc:
David Moore Vice President, Nuclear Operations Support Florida Power & Light Company P.O. Box 14000 Juno Beach, FL 33408-0420 Marjan Mashhadi Senior Attorney Florida Power & Light Company 801 Pennsylvania Ave., NW Suite 220 Washington, DC 20004
Mr. Mark E. Warner, Site Vice President c/o James M. Peschel Seabrook Station PO Box 300 Seabrook, NH 03874
SUBJECT:
SEABROOK STATION, UNIT NO. 1 - REQUEST FOR ADDITIONAL INFORMATION FOR PROPOSED AMENDMENT REQUEST REGARDING THE APPLICATION FOR STRETCH POWER UPRATE (TAC NO. MC2364)
Dear Mr. Warner:
By letter dated March 17, 2004, as supplemented by a second letter dated March 17, 2004, and letters dated April 1, and May 26, 2004, FPL Energy Seabrook, LLC, submitted its application to increase the licensed thermal power level at Seabrook Station, Unit No. 1. The proposed amendment would allow the maximum authorized power level to increase by approximately 5.2 percent, from 3411 megawatts thermal (MWt) to 3587 MWt.
The Nuclear Regulatory Commission staff is reviewing the information provided in these submittals and has determined that additional information, as delineated in the Enclosure, is needed to complete its review. The request for additional information was discussed with your staff on August 5, and August 17, 2004. A response date of October 1, 2004, was mutually agreeable.
If you have any questions, please call me at (301) 415-2855.
Sincerely,
/RA/
Scott P. Wall, Project Manager, Section 2 Project Directorate I Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-443
Enclosure:
Request for Additional Information cc w/encl: See next page DISTRIBUTION:
PUBLIC PDI-1 Reading CHolden JClifford EMarinos RJenkins MMitchell TChan LLund DTerao KManoly DSolorio SWeerakody MRubin RDennig JUhle TBoyce DTrimble PLoeser NTrehan NRay ZFu PKlein SBailey TTjader JCai SMiranda SImboden JTatum HWagage RHernandez NIqbal MStutzke RLobel SLaVie WLyon JBongarra KDensai FOrr SWall CRaynor BMcDermott, RGN-I CBixler, RGN-I OGC ACRS Accession Number: ML042190085 OFFICE PDI-2/PM PDI-1/SC NAME SWall DCollins for JClifford DATE 8/18/04 8/18/04 OFFICIAL RECORD COPY
Enclosure REQUEST FOR ADDITIONAL INFORMATION REGARDING PROPOSED STRETCH POWER UPRATE (SPU) AMENDMENT SEABROOK STATION, UNIT NO. 1 (SEABROOK)
DOCKET NO. 50-443 Instrumentation and Controls 1.
Please confirm that the following are the only safety-related instrumentation setpoint changes required for the SPU:
a.
Technical Specification (TS) Table 2.1-1, "Reactor Trip System Instrumentation Trip Setpoints," Functional Unit 13, "Steam Generator Water Level Low-Low," is revised as follows:
1)
The Trip Setpoint is changed from >14.0% to >20.0% of narrow range instrument span.
2)
The Allowable Value is changed from >12.6% to >19.5% of narrow range instrument span.
3)
The Total Allowance (TA), Z, and Sensor Error (S) are changed from values to N.A.
b.
TS Table 3.3-4, "Engineered Safety Features Actuation System Instrumentation Trip Setpoints," Functional Unit 5b, "Turbine Trip, Steam Generator Water Level High-High (P14)," is revised as follows:
1)
The Trip Setpoint is changed from >86.8% to >90.8% of narrow range instrument span.
2)
The Allowable Value is changed from >87.7% to >91.3% of narrow range instrument span.
3)
The Total Allowance (TA), Z, and Sensor Error (S) are changed from values to N.A.
c.
TS Table 3.3-4, Functional Unit 6a, "Feedwater Isolation, Steam Generator Water Level Hi-Hi (P14)," is revised as follows:
1)
The Trip Setpoint is changed from >86.8% to >90.8% of narrow range instrument span.
2)
The Allowable Value is changed from >87.7% to >91.3% of narrow range instrument span.
3)
The Total Allowance (TA), Z, and Sensor Error (S) are changed from values to N.A.
d.
TS Table 3.3-4, Functional Unit 7c, "Emergency Feedwater, Steam Generator Water Level Low-Low, Start Motor-Driven Pump and Start Turbine-Driven Pump," is revised as follows:
1)
The Trip Setpoint is changed from >14.0% to >20.0% of narrow range instrument span.
2)
The Allowable Value is changed from >12.6% to >19.5% of narrow range instrument span.
3)
The Total Allowance (TA), Z, and Sensor Error (S) are changed from values to N.A.
2.
In each case where a setpoint is shown as a percentage of instrument span, identify the instrument by manufacturer, model and range, its span, and the actual and allowable physical values of the setpoint.
3.
Provide calculations and supporting setpoint methodology for the setpoints indicated in of the March 17, 2004, submittal. Details should be sufficient to allow the Nuclear Regulatory Commission (NRC) staff to understand the values used, assumptions made, and formulae used. If the NRC staff has previously reviewed and approved the setpoint methodology, provide a reference to the acceptance document.
4.
Explain why, in each case, the Total Allowance (TA), Z, and Sensor Error (S) setpoints indicated in TS Table 2.1-1 and Table 3.3-4 were changed from values to N.A.
5.
Explain how channel operability is determined for the functional units indicated in Question 1 above.
6.
Due to the SPU, are there any other changes to the instrumentation and controls needed beyond the setpoint changes identified in Question 1 above (i.e., changes in control systems, span changes, or instrument replacement)?
7.
Discuss any changes to how Seabrook meets the acceptance criteria and guidelines outlined in NRUEG-0800, Standard Review Plan (SRP), Chapter 7, "Instrument and Controls," because of the SPU.
Electrical Engineering 8.
In support of Section 8.4.16.7, "Grid Stability," provide details about the grid stability analysis including assumptions and results and conclusions for the power uprated condition.
9.
Address and discuss the following points:
a.
Identify the nature and quantity of MVAR support necessary to maintain post-trip loads and minimum voltage levels.
b.
Identify what MVAR contributions Seabrook is credited for providing to the offsite power system or grid.
c.
After the power uprate, identify any changes in MVAR quantities associated with Items a. and b. above.
d.
Discuss any compensatory measures to adjust for any shortfalls in Item c.
above.
e.
Evaluate the impact of any MVAR shortfall listed in Item d. above on the ability of the offsite power system to maintain minimum post-trip voltage levels and to supply power to safety buses during peak electrical demand periods. The subject evaluation should document any information exchanges with the transmission system operator.
Vessels & Internal Integrity and Welding 10 In Section 5.1.3.5, "Pressurized Thermal Shock," of the March 17, 2004, submittal, FPL Energy Seabrook, LLC (FPLE or the licensee) states the following:
Based on this evaluation, the reference temperature-pressurized thermal shock values will remain below the Nuclear Regulatory Commission screening criteria values using the projected SPU fluence values through end of license [EOL] for 40 Effective Full Power Years [EFPYs] for Seabrook Station and thus meet the requirements of 10 CFR 50.61.
To substantiate the statement, provide the following:
a.
The projected neutron fluence (E > 1.0 Mev) for each vessel beltline material at EOL including the impact of the proposed SPU.
b.
Reactor vessel beltline material properties including initial RTNDT, Cu and Ni contents and the source of the information (generic or plant specific).
c.
RTPTS values for the all vessel beltline materials. Also provide the basis of RTPTS values.
11.
In Section 5.1.3.5, "Results," under "Upper Shelf Energy," FPLE states the following:
Based on this evaluation, the upper shelf energy [USE] values for Seabrook Station will maintain a level above 50 ft-lbs.
For each beltline material, provide the USE values at the end of the current licensed life, including the impact of the SPU. Also, provide the basis of the calculation including beltline material copper percentage, the unirradiated USE value, and the projected neutron fluence (E>1.0 MeV) at 1/4 thickness. If surveillance data was used, provide the surveillance data.
12.
In Section 5.1.3.5, under "Applicability of Heatup and Cooldown Pressure-Temperature Limit Curves," FPLE states the following:
This review indicates that the revised adjusted reference temperature [ART] the SPU will be less restrictive than that used in developing the current adjusted reference temperature values for Seabrook Station at 20 [EFPY].
To substantiate the statement, provide the following:
a.
Basis for current Pressure-Temperature (P-T) limits (applicability in EFPY and ART values at the 1/4 thickness (T) and 3/4T locations).
b.
Projected ART values for the proposed period of applicability using the SPU fluence.
- 13.
Table Matrix-1 of NRC Review Standard RS-001, Revision 0, provides the NRC staffs basis for evaluating the potential impacts for stretch power uprates and the subsequent aging effects. In Table Matrix-1, the staff states that, in addition to the SRP, guidance on the neutron irradiation-related threshold levels inducing irradiation-assisted stress corrosion cracking (IASCC) in reactor vessel (RV) internal components are given in Westinghouse document, License Renewal Evaluation, Aging Management for Reactor Internals, WCAP-14577, Revision 1-A. WCAP-14577, Revision 1-A establishes, a threshold of 1 x 1021 n/cm2 (E 0.1 MeV) for the initiation of IASCC, loss of fracture toughness, and/or void swelling in pressurized water reactor (PWR) RV internal components made from stainless steel (including cast austenitic stainless steels) or Alloy 600/82/182 materials. In Table Matrix-1 of NRC Report RS-001, the staff established guidance that plants exceeding this threshold of neutron irradiation would either have to establish plant-specific degradation management programs for managing the aging effects associated with their RV internals or else indicate that the licensees would participate in industry programs designed for investigating and managing age-related degradation in the RV internal components. Provide the threshold fluence values for the internals (E > 0.1 MeV) due to the SPU. Also, discuss the inspection program that will be implemented by Seabrook if the threshold values exceed 1 x 1021 n/cm2 (E 0.1 MeV).
Piping Integrity and Nondestructive Examination 14.
Discuss service adequacy of materials in nuclear steam supply system (NSSS) and balance-of-plant piping under the power uprate operating conditions.
15.
Discuss service adequacy of materials in control rod drive mechanism (CRDM) nozzles under the uprated conditions relative to primary water stress corrosion cracking susceptibility.
Steam Generator (SG) Integrity & Chemical Engineering 16.
In Section 5.7.4.4.3 of the March 17, 2004, submittal, when discussing tube undercut, the licensee states that the Seabrook tube end evaluation utilized the results from a previous evaluation of Model F SGs, adjusted, as appropriate, for Seabrook conditions.
Clarify the conservatism associated with the adjustment value being based on the increase in differential pressure across the tubesheet for the analyzed SPU conditions.
In addition, confirm that all design criteria of Section III of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code) are met for the tube and weld in the undercut condition.
17.
In Section 5.7.4.4.5, the licensee indicates tube remnants in SG "D" from a 2002 tube removal were analyzed under the most limiting SPU conditions and determined to be stable with respect to fluid elastic excitation. The licensee states turbulence induced stresses are sufficiently low that crack propagation will not occur. The licensee concludes, as a result, that these tubes will not require stabilizers prior to operation at SPU conditions since the tubes have been shown to remain intact and will not contact any adjacent active tubes.
Clarify if the analysis indicates the tube remnants are acceptable for the remainder of the operating license without the need for stabilization or if stabilization will be performed at a later date but is not necessary prior to initial operation at SPU conditions.
18.
In Section 5.7.4.4.6, when discussing the loose part wear evaluation in SG "B" and SG "C," the licensee states that the loose part will be evaluated on a cycle-by-cycle basis for future operation if tube wear is present.
Confirm that all loose parts will be evaluated on a cycle-by-cycle basis even if tube wear is not present. The NRC staff notes that a loose parts location can change during operation and that a part that has not caused wear in a certain location may potentially cause wear in a different location within the SG.
19.
Table 5.7.6-1 provides a summary of tube structural limits as determined by analysis for both high Tavg and low Tavg operating conditions. This analysis was performed assuming a uniform thinning mode of degradation in both the axial and circumferential directions.
For the locations and axial wear scar lengths shown in Table 5.7.6.1, confirm the following:
a.
Uniform circumferential thinning, for analysis purpose, was assumed to be affecting 360 degrees of the tube; b.
The analytical approach for all locations shown in the table was identical but different axial lengths were assumed for the 360 degree thinning; and c.
For all cases involving normal and transient operating conditions (including postulated accidents with the appropriate safety factor on membrane and membrane plus bending loads) the most limiting structural limit resulted from maintaining a factor of safety of three against burst under normal steady state full power operation at the SPU conditions.
If any of items (a) through (c) above require clarification, confirm that the 40-percent plugging limit continues to provide adequate margin to the structural limit at the SPU conditions. That is, confirm the 40-percent plugging limit provides for a 360-degree, infinitely long flaw at the most limiting location (e.g., straight span, U-bend) under the most limiting condition (normal operating pressure, accident) with the appropriate regulatory margin on load (e.g. 3, 1.4, 1.2).
20.
In Section 5.7.7.4.1, material considerations related to SG tube integrity are discussed.
The licensee states that if the plant is operated at or near the analyzed maximum reactor vessel outlet temperature, the slight increase of maximum temperatures in the SG suggests a slight increase in the propensity for development of stress corrosion cracking (SCC) in comparison to the current parameters.
Did the evaluation of tube integrity at slightly higher temperatures consider tubes that may be more susceptible to SSC as a result of higher residual stress (see NRC Information Notice 2002-21, Supplement 1). The NRC staff understands all tubes exhibiting an eddy current offset have been removed from service. Assuming some tubes with higher residual stress may not exhibit an eddy current offset but be more susceptible to SCC, confirm that the existing SG tube inspection program accounts for changes in operating conditions and operating experience when determining the appropriate inspection intervals necessary to maintain tube integrity. Given the conclusion in Section 5.7.7.5 that the performance criteria of Nuclear Energy Institute (NEI) 97-06, "Steam Generator Program Guidelines," Revision 1, will continue to be met, discuss your plans for revising the Seabrook TSs to be consistent with the SG program and NEI 97-06.
21.
The licensee concludes SG blowdown is acceptable for SPU conditions since the blowdown flow does not change and steam pressure and temperature are bounded by the Steam Generator System Design. Has the blowdown system experienced any degradation due to flow accelerated corrosion (FAC)? Did the blowdown system evaluation consider a potential increase in FAC due to a potential increase in particles (e.g., oxides) carried into the SG resulting from higher secondary system flow rates under SPU conditions?
22.
In Section 9.1.3, the licensee indicates, based on an evaluation of high energy piping systems, that no new piping will require inclusion into the FAC program due to the SPU.
The licensee states that carbon steel moisture separator drain lines were specifically evaluated using the Seabrook FAC Checworks Model.
Clarify the extent of the piping evaluated using the Checworks program. For those systems evaluated by methods other than Checworks, identify the extent of piping evaluated and the evaluation method. Discuss the basis for the conclusion that no new piping will need to be included in the FAC program.
Civil & Engineering Mechanics 23.
In several places, the application states that the allowable stresses after the SPU will exceed the ASME Code allowable stresses.
a.
For the reactor vessel outlet nozzle safe end, the maximum stress exceeds 3Sm.
The footnote states that the stress intensities are qualified using simplified elastic-plastic analysis per Subsection NB of the ASME Code. Elaborate on the simplified elastic-plastic analysis.
b.
For the RV bottom head instrument tubes, the maximum stress exceeds 3Sm.
There is no indication of how this exceedance was resolved (i.e., no footnotes).
Elaborate on how this issue was resolved.
c.
For the SG divider plate, the footnote to Table 5.7.2-1 states that plastic analysis performed in the design basis analysis for fatigue evaluation to show ASME Code criteria are satisfied. (Note that this is the condition both before and after SPU). Elaborate on the plastic analysis. What computer code was used for the analysis? Has this code previously been approved by the NRC?
d.
For the SG tubesheet and shell junction, main feedwater nozzle, steam nozzle insert fillet weld, and support ring the stress exceeds 3Sm. The footnotes state that simplified elastic plastic analysis was performed for the design basis evaluation, and Ke factors were used in the fatigue calculation to demonstrate that ASME Code criteria (NB-3228) are met. Elaborate on the elastic plastic analysis.
e.
For the SG tube to tubesheet weld the stress exceeds 3Sm. The footnote states that inelastic analysis performed in the original analysis demonstrated that ASME Code criteria are satisfied. Elaborate on the inelastic analysis.
24.
In Section 5.2.7, Structural Evaluation of Reactor Internal Components," FPLE states the following:
... the reactor pressure vessel internals were designed to meet the intent of Section III, Subsection NG of the ASME Boiler and Pressure Vessel Code. Plant-specific stress report on the reactor pressure vessel internals was not required. The structural integrity of the Seabrook Station reactor pressure vessel internals design has been ensured by analyses performed on both generic and plant-specific bases.
Provide a comparison of the calculated stresses to the allowed stresses of Subsection NG of the ASME Code.
25.
In Section 5.4.3, "Description of Analyses and Evalutions, FPLE discusses the evaluation of the CRDMs and states the following:
The only evaluations that were not bounded were those associated with the changes in NSSS design transients that were not enveloped by the current analyses. Ratios of the new transients to the old transients were used (very small change, less than 5%) to multiply the existing stress evaluation results. After this was performed, it was shown that the component stresses were within the allowable limits of the ASME Boiler and Pressure Vessel Code.
However, the application does not provide the new stresses or the margin to allowable of the current stresses. Provide the above information to support the assertion that the new stresses are acceptable.
26.
In Section 5.6.2, "Results," FPLE describes the results for the pressurizer surge line and states the following:
The design basis analysis for the Seabrook Station pressurizer surge nozzle did however, originally show the cumulative fatigue usage factor to be close to 1.0 prior to consideration of the SPU conditions. For the surge nozzle, a comparative evaluation was performed utilizing stress and fatigue results from another unit having essentially the same pressurizer design. The comparison identified significant conservatisms in the method used for design transient combinations for Seabrook Station. By adopting the evaluation from the comparison unit, it was demonstrated that the more accurate analytical effort resulted in acceptable fatigue usage for operating conditions which envelop the Seabrook Station SPU conditions.
The application does not provide a clear or complete description of what was changed in the analyses or why the analysis from the comparison unit is appropriate for Seabrook.
Provide the above information in order to justify adopting the analysis of the comparison unit.
27.
In Section 5.8.1.3.2, "Transient Evaluation," FPLE states the following:
The original qualification of the pump was based on using a fatigue waiver, as defined in Section NB-3222.4(d) of the ASME Boiler and Pressure Vessel Code, to address fatigue for the Code pressure boundary parts of the pump. The revised calculations show that the pump casing, the thermal barrier, bolting ring and main flange bolts, and the seal housing still qualify for the fatigue waiver.
Provide stresses and cumulative usage factors for the indicated reactor coolant pump (RCP) components for the SPU condition. Discuss how these components qualify for the fatigue waiver.
28.
In Section 9.2.2.1, "Inside Containment," FPLE states the following:
... the protective coatings (i.e., organic material) will continue to meet the requirements of Regulatory Guide 1.54
[Reference 9.2-3] and will be acceptable following implementation of the SPU.
This statement is unclear. Provided an explanation of what is meant by this statement.
Fire Protection Engineering 29.
NRC RS-001, Rev. 0, "Review Standard for Extended Power Uprates," Attachment 2 to Matrix 5, "Supplemental Fire Protection Review Criteria, Plant Systems," states that
"... power uprates typically result in increases in decay heat generation following plant trips. These increases in decay heat usually do not affect the elements of a fire protection program related to (1) administrative controls, (2) fire suppression and detection systems, (3) fire barriers, (4) fire protection responsibilities of plant personnel, and (5) procedures and resources necessary for the repair of systems required to achieve and maintain cold shutdown. In addition, an increase in decay heat will usually not result in an increase in the potential for a radiological release resulting from a fire.
However, the licensees application should confirm that these elements are not impacted by the extended power uprate..."
Section 9.1.1, "Fire Protection Program," of the March 17, 2004, submittal does not address items (1) through (5) above. Provide statements to address these items.
30.
NRR RS-001, Rev. 0, Attachment 2 to Matrix 5, states that "... where licensees rely on less than full capability systems for fire events..., the licensee should provide specific analyses for fire events that demonstrate that (1) fuel integrity is maintained by demonstrating that the fuel design limits are not exceeded and (2) there are no adverse consequences on the reactor pressure vessel integrity or the attached piping. Plants that rely on alternative/dedicated or backup shutdown capability for post-fire safe shutdown should analyze the impact of the power uprate on the alternative/dedicated or backup shutdown capability..."
Licensees should identify the impact of the SPU on a plants post-fire safe-shutdown procedures. Sections 4.1.4.3.3, "Appendix R and Safe Shutdown Cooldown," and 9.1.1, of the March 17, 2004, submittal do not address items (1) and (2) above. Provide statements to address these items.
PWR Systems 31.
Table 1.2-1 of the March 17, 2004, submittal, lists the computer codes used to perform non-LOCA [loss of coolant accident] transient and accident reanalyses for the SPU at Seabrook. RETRAN-02 has been generically approved by the NRC staff for non-LOCA transient analyses; however, this is the first time RETRAN-02 will be used at Seabrook.
Explain the quality assurance process used to verify that RETRAN-02 was adequately used at Seabrook and show that the Seabrook nodalization modeling is consistent with the Westinghouse 4-loop plant nodalization model of WCAP-14882-P-A. If the modeling of Seabrook deviated from the plant model in the WCAP-14882-P-A, justify the technical validity. Identify and explain which accident analyses the use of RETRAN code is not suitable.
32.
Table 2.3-1 lists the design operating parameters. Provide a tabulation of the thermal design parameters compared to values assumed in the safety analyses to demonstrate that adequate conservatism is available for the safety analyses assumptions.
Table 6.3.1-2 lists non-LOCA plant initial conditions assumptions for the SPU. Explain why these parameters values are same as Table 2.3-1 which shows design operating parameters. In this table, explain why the initial power condition uncertainty is +/- 0%
rated thermal power.
Discuss the basis for the average temperature operating range (571.0 F - 589.1 F) listed in Table 2.3-1.
33.
Table 2.3-1, Note 4, discusses core bypass flow which includes 2% for thimble plug removal and 0.5% for intermediate flow mixers. Explain why 0.5% for intermediate flow mixers is not reflected in the table. Should the core bypass flow be 2.5%?
34.
Table 3.1-1 lists the summary of reactor coolant system (RCS) design transients.
Expand this table to include the numbers of cycles for each design transient at the current and SPU conditions. Describe the basis for each of the changes.
35.
The March 17, 2004, submittal provides a summary of LOCA analysis parameters. This submittal also refers to information specific to the LOCA analyses performed to define the licensing basis for Seabrook LOCA. The NRC staff requests further information to address the programmatic requirements of 10 CFR 50.46 (c).
To show that the referenced generically-approved Seabrook small break LOCA (SBLOCA) analysis methodology continues to apply specifically to the Seabrook plant, provide a statement that FPLE and its vendors have ongoing processes that assure the ranges and values of the input parameters for the Seabrook SBLOCA analysis bound the ranges and values of the as-operated plant parameters. Furthermore, if the Seabrook plant-specific analyses are based on the model and/or analyses of any other plant, then justify that the model or analyses apply to Seabrook (e.g. if the other design has a different vessel internals design the model would not apply to Seabrook).
36.
The LOCA submittals did not address slot breaks at the top and side of the pipe.
Justify why these breaks are not considered for the Seabrook large break LOCA (LBSOCA) and SBLOCA responses.
37.
Provide the LBLOCA analysis results via tables and graphs to the time that stable and sustained quench is established.
38.
It is not clear from LBLOCA and SBLOCA figures what specific upper core plate is used for Seabrook. Identify the specific upper core plate design used in Seabrook. Also identify whether Seabrook features a baffle/barrel upflow or baffle/barrel downflow design. Confirm that these features have been modeled in the input decks appropriately.
39.
Tables 6.1.1-2 and 6.1.2.5-3 provide LBLOCA and SBLOCA analyses results for the Seabrook SPU.
Provide all results (peak clad temperature, maximum local oxidation, and total hydrogen generation) for both LBLOCA and SBLOCA. For maximum local oxidation, include consideration of both pre-existing and post-LOCA oxidation, and cladding outside and post-rupture inside oxidation. Also include the results for fuel resident from previous cycles.
40.
Does the uprated power level or increased decay heat load affect the Emergency Core Cooling System (ECCS) switchover from injection mode to sump recirculation mode (timing in Emergency Operating Procedures (EOPs)) for Seabrook? Does this affect the Seabrook Updated Final Safety Analysis Report (UFSAR) Figure 6.3-10? Are ECCS pump net positive suction head analyses affected?
41.
Provide the minimum time for switchover to hot leg injection and the basis for this time.
Include: (a) the times specified in the EOPs that address switchover to hot leg injection, (b) a description of the applicable EOP (or a copy of the EOP), and (c) information that reasonably ensures the EOP actions will occur consistent with the stated times.
42.
Provide a copy of Reference 6.1-13, "Hot Leg Switchover Time Clarification,"
NSAL-04-01, January 2004.
43.
Table 6.3.1-4 summarizes the initial conditions and computer codes used which are approved by the NRC staff for non-LOCA transients analysis. For each computer code, the NRC staff provides a safety evaluation report which lists the staffs positions and limitations for its application. List the NRC staff approval status, the staffs positions or limitations for each computer code and address how Seabrook satisfies these requirements for SPU conditions.
44.
Provide the safety injection flowrate, as a function of pressure, that is assumed for the steam line break and other non-LOCA analyses. For the steam line break analysis, identify the most restrictive active single failure postulated for the safety injection system.
45.
Provide the results of thermal hydraulic analysis of a SG tube rupture for radiological consequences including sequence of events, major assumptions, and transient curves.
46.
Confirm that the thermal hydraulic analysis of a SG tube rupture for radiological consequences, is performed with the most limiting single failure of a stuck open atmospheric steam dump valve associated with the failed SG and a concurrent loss of off-site power. Explain why the failure of an intact SG atmospheric steam dump valve to open during cooldown is assumed to be limiting with respect to margin to SG overfill.
47.
In its letter of January 17, 1989, "Acceptance for Referencing Topical Report WCAP-11397, Revised Thermal Design Procedure," the NRC staff stated that, "Sensitivity factors used for a particular plant and their ranges of applicability should be included in the Safety Analysis Report or reload submittal." Supply the sensitivity factors, and their ranges of applicability for Seabrook.
48.
Discuss the implications of a failure to select the correct reference TAVG in the overtemperature T and overpower T setpoint equations (i.e., to select a reference TAVG that corresponds to the desired operating TAVG in the TAVG window), upon the accident analyses for events that rely upon the overtemperature T and overpower T reactor trips for protection.
49.
Please itemize the delays making up the 77-second delay to start the emergency feedwater pump.
50.
Has the RCP coastdown flow predicted by RETRAN for the accident analyses presented in the March 17, 2004, submittal been validated against plant data? If not, justify its validity.
51.
Table 1 of WCAP-8567-P-A, "Improved Thermal Design Procedure," upon which the Revised Thermal Design Procedure (RTDP) is based, is limited to F H factors of 1.61 or less. Tables 6.1.2-1 and 7.2-1 simply indicate that the F H is 1.65, whereas Tables 6.3.1-2 and Table 7.1-1 indicate that a "statistical" F H of 1.587 is used. Is the latter value of F H used only with the RTDP? If not, then justify the use of an F H of 1.587 with standard thermal design procedures.
52.
Table 6.1.2-1 indicates that the vessel average temperature uncertainty is +3/-6 F (represents a +/- 3 F uncertainty plus a -3 F bias); but temperature uncertainty is defined elsewhere (Sections 6.1.7.2 and 6.4.1.1.1) as +/- 6 F. A +/- 3 F uncertainty plus a -3 F bias would yield 0/-6 F, and a +/-6 F uncertainty would yield +3/-9 F. Which is correct? What is the source of the bias?
53.
Notes (1) and (2) of Table 6.3.1-4 state that the initial average temperatures, assumed for certain accident analyses, were 577 F and 584.1 F, and that these temperatures were determined from sensitivity studies. Describe the sensitivity studies and explain the phenomena that led to these conclusions.
55, In Section 6.3.1.2, "Overtemperature T and Overpower T Reactor Trip Setpoints,"
FPLE states the following:
The revised safety analysis setpoints are based upon the assumption that the reference average temperature (T) used in the overtemperature T and overpower T setpoint equations correspond to the selected operating temperature within the TAVG window.
How can one be sure that the correct T is being used in the overtemperature T and overpower T setpoint equations, at any given time during operations? How will the T be changed whenever the operating temperature is changed (within the TAVG window)?
56.
In Section 6.3.2.1.3, "Results," FPLE states the following:
The reduction in feedwater temperature due to a 10-percent step load increase is greater than 35°F. The increased thermal load, due to the opening of the low-pressure heater bypass valve, thus results in a transient very similar, but of reduced magnitude, to the steam system piping failure initiated from full power conditions described in [License Amendment Request] LAR Section 6.3.2.4.
No transient results are presented, as no explicit analysis is performed.
Similarly, in Section 6.3.2.1.4, "Conclusions," FPLE states:
With respect to the feedwater temperature reduction transient (accidental opening of the feedwater bypass valve), it was determined to be less severe than the steam system piping failure initiated at full power conditions (see Seabrook Station UFSAR Section 15.1.5); no explicit analysis is performed.
Section 6.3.2.4, "Steam System Piping Failure," and Seabrook UFSAR Section 15.1.5 describe the analysis of the steam system piping failure initiated from zero power conditions, only. How is the reduction in feedwater temperature, a Condition II event analyzed at hot full power (HFP), comparable to the steam system piping failure, a Condition IV event analyzed at hot full power (HZP)? Typically, the reduction in feedwater temperature event is compared to the excessive load increase event.
57.
In Section 6.3.2.3.1, "Accident Desciption," FPLE states that:
.... a safety injection signal will rapidly close all feedwater control valves and backup feedwater isolation valves and trip the main feedwater pumps.
Tables 6.3.2.1-1 and 6.3.2.1-2 do not show the generation of a safety injection signal.
Instead, they list the time the hi-hi SG water level trip setpoint is reached, and the time the turbine is tripped (two seconds later). Both tables indicate that the feedwater isolation valves are fully closed ten seconds after the turbine is tripped and 12 seconds after the hi-hi SG water level trip setpoint is reached. Shouldnt the feedwater isolation valves be fully closed 12 seconds after the turbine is tripped (i.e., the turbine trip/feedwater isolation signal is generated)?
58.
In Section 6.3.3.3.2, why are the RCPs assumed to lose power and begin coasting down two seconds after the reactor trip on low-low SG water level, and not at the same time as the reactor trip signal is received?
59.
Explain the drop in pressurizer pressure, occurring at about 10 minutes in Figure 6.3.3.3-3.
60.
According to Figures 6.3.3.3-3 and 6.3.3.3-4, the pressurizer relief valves open, after about 250 seconds, and relieve steam. Identify the single applicable acceptance criterion, indicated in Section 6.3.3.4, that is satisfied, and confirm that no RCS water is relieved from the pressurizer.
61.
In Section 6.3.2.4.1, "Accident Description," FPLE states that:
Following a steam line break, the core is ultimately shut down by the boric acid injected into the Reactor Coolant System by the Safety Injection System.
Although Figure 6.3.2.4-11 indicates that the core boron concentration continues to increase as safety injection fluid is added by the safety injection pumps and supplemented by the accumulators, the core reactivity, in Figure 6.3.2.4-1, does not become subcritical. The safety injection pumps reach full speed at about 28 seconds (Table 6.3.2.4-1); but the heat flux doesnt peak, and the minimum departure from nucleate boiling ratio is not reached until about two minutes later. Please explain this.
62.
Explain why steam flow in the faulted loop (Figure 6.3.2.4-7), goes to zero at less than ten seconds into the transient. Did the analysis assume that the main steam isolation valve (MSIV) in the faulted loop would fail to close?
63.
In Table 6.3.1-4, the initial average temperatures assumed for the loss of normal feedwater accident analysis is a value of 566 F. What is the basis for this temperature?
64.
Assumption 5 of Section 6.3.2.4.2 indicates that the MSIVs are assumed to be closed six seconds after receipt of a safety injection signal due to low steam line pressure (435 psia). Table 6.3.2.4-1 indicates that the low steam line pressure setpoint is reached at 0.54 seconds, in the faulted loop, and the safety injection signal isnt generated until two seconds later. Based on the above, shouldnt the MSIVs close at 8.54 seconds, rather than the 6.54 seconds indicated in the table?
65.
Explain the small oscillations in the steam pressure of the faulted SG (Figure 6.3.2.4-8),
beginning at about 500 seconds. Is the SG dry, or nearly dry at this time?
66.
Assumption 9 of Section 6.3.2.4.2 indicates that the feedwater isolation valves are assumed to be closed 12 seconds after receipt of a safety injection signal due to low steam line pressure (435 psia). Table 6.3.2.4-1 indicates that the low steam line pressure setpoint is reached at 0.54 seconds in the faulted loop, and the safety injection signal isnt generated until two seconds later. Based on the above, shouldnt the feedwater isolation valves close at 14.54 seconds, rather than the 12.54 seconds indicated in the table?
67.
In support of Section 6.3.2.4, provide transient plots of inventory in the faulted and intact SGs.
68.
Assumption 11 of Section 6.3.3.4.2 indicates the following:
Choked flow is assumed at the break with a high blowdown quality prior to reactor trip, resulting in an increase in the time required to obtain reactor trip. The blowdown quality after reactor trip corresponds to saturated water until the point at which all liquid inventory in the faulted steam generator is lost, resulting in a decrease in the heat removal capability of the faulted steam generator. After the liquid mass is depleted, the blowdown becomes saturated steam.
In Section 6.3.3.4.3, "Results," FPLE states the following:
The Reactor Coolant System heatup prior to reactor trip is due to loss of the secondary system heat sink as a result of main feedwater spillage through the break and the increased secondary system temperature and pressure following the turbine trip.
Reactor power increases slightly prior to the trip due to the Reactor Coolant System heatup. The primary and secondary systems were calculated to remain below 110 percent of their respective design pressures.
Following the reactor trip, steam flow out the break cools the Reactor Coolant System and eventually causes Reactor Coolant System pressure to decrease and the pressurizer to empty resulting in Safety Injection initiation on a low pressurizer pressure signal. The core remains covered with water as demonstrated by the fact that the coolant loops do not reach a saturated condition.
Low main steam line pressure causes closure of the main steam isolation valves and ends the cooldown period. Addition of safety injection flow aids in cooling down the primary and ensures that sufficient fluid exists to keep the core covered with water."
Prior to reactor trip, the high quality break flow, which is assumed in order to delay the time of reactor trip, would tend to cool the RCS, like a steam line break. However, the results refer to a heatup prior to reactor trip. Following reactor trip, the results discuss the cooling effect of steam flow; but there would be no steam flow out the break until the SG dries out. Please resolve these discrepancies.
69.
Section 6.3.3.4, "Feedwater System Line Break," indicates that the reactor trip signal is obtained from low SG level in the broken SG. How is the water level indication modeled?
70.
In support of Section 6.3.3.4, discuss the effects of assuming more entrainment in the break flow, prior to reactor trip, such that the reactor trip might be generated earlier when the RCS is hotter.
71.
In support of Section 6.3.3.4, provide the assumptions and models pertaining to feedwater line break flow quality.
72.
In support of Section 6.3.3.4, discuss the expected results of analyses of a spectrum of feedwater line break sizes, over a range of assumed levels of water entrainment in the break flows.
73.
In support of Section 6.3.3.4, provide a transient plot of break flow quality for the feedwater line break.
74.
In Section 6.3.5.3.2, "Method of Analysis," FPLE states the following:
A generic statepoint analysis for this event [Reference 6.3-25],
which was performed in 1986 to bound a number of four-loop pressurized water reactors, was evaluated and determined to remain applicable for the SPU. With the generic statepoints being applicable, the effects of the SPU are accounted for when performing the nuclear and departure from nucleate boiling analyses, which are performed on a cycle-specific basis.
Explain how it was determined that the statepoints were to remain applicable for Seabrook.
75.
Table 6.3.3.4-1 indicates that the MSIVs close only four seconds after the low steamline pressure isolation setpoint is reached; whereas, Assumption 5 of Section 6.3.2.4.2 indicates that the MSIVs are assumed to be closed six seconds after receipt of a safety injection signal. Please explain the difference.
76.
Tables 6.3.4.1-1 and 6.3.4.1-2 indicate that two trip time delays are assumed to be 1.5 seconds for the RCP undervoltage reactor trip, and 1.0 second for the under frequency reactor trip. Table 6.3.5.1-2 indicates that a 0.5 second trip delay time is assumed for the high neutron flux reactor trip. A 2.0 second delay time is assumed for other events. Provide a list of the trip time delays that are assumed for the events reported in the LAR, and their bases.
77.
For the feedwater line break (Section 6.3.3.4.2), describe the RETRAN model that decreases SG heat transfer area as the shell side liquid inventory decreases. How does this model behave in the rapidly changing shell side environment caused by the feedwater line break?
78.
In Section 6.3.3.4.3, FPLE states the following:
Following the reactor trip, steam flow out the break cools the Reactor Coolant System and eventually causes Reactor Coolant System pressure to decrease and the pressurizer to empty resulting in Safety Injection initiation on a low pressurizer pressure signal.
Justify the modeling of steam flow (and not water) through the break, which would tend to mitigate the consequences of the feedwater line break.
79.
In Section 6.3.5.3, it is stated that the single rod control cluster assembly (RCCA) withdrawal event is bounded by the rod ejection accident. Explain how a Condition IV event might bound a Condition III event.
80.
Section 6.3.5.7.3 provides results for the RCCA ejection analyses and indicates that the peak hot-spot fuel centerline temperatures reaches the fuel melting temperatures for several seconds during the full power cases. Describe how the extent of fuel melting is determined.
81.
In Section 6.3.6.1.4, "Conclusions," FPLE states the following:
Analytical results show there will be no water flow through the pressurizer safety relief valves as a consequence of inadvertent operation of Emergency Core Cooling Systems during power operation provided that a minimum of 10 minutes is available for operator action to terminate Emergency Core Cooling Systems.
No credit for operation of the pressurizer power operated relief valves was assumed.
a.
Provide a justification that the operator will recognize the situation and act to terminate the safety injection flow in ten minutes or less.
b.
Explain how the pressurizer power-operated relief valve (PORV) opening setpoint can be set to just 25 psi below the reactor trip setpoint. Normally, the PORV is set to open at 50 psi below the reactor trip setpoint, which is consistent with an uncertainty of +/- 50 psi, as shown in Table 6.3.1-2.
c.
The PORVs, if they open, would tend to limit the backpressure seen by the ECCS, and allow a greater ECCS flow into the RCS, and thereby decrease the pressurizer fill time. Explain how the opening of the PORVs can be considered to be credit in this transient. What are the results of this event when analyzed assuming the PORVs are available?
d.
The PORV opening setpoint, 2400 psia, is not reached in this transient; but the maximum pressurizer pressure, 2378 psia, is within the pressure uncertainty,
+/- 50 psi, of the instrumentation. Justify the conclusion that the PORVs will not open.
e.
Are the PORVs and their associated downstream discharge piping qualified for water relief?
f.
Verify that the following initial conditions are the same as those assumed for the Seabrook UFSAR analyses: initial reactor power at the maximum value, and the initial pressurizer water level at its maximum value - consistent with steady-state full-power operation including allowances for calibration and instrument errors.
g.
Provide information to show that RETRAN-02 pressurizer model can properly calculate pressure when the pressurizer is water-solid.
h.
Describe the initial pressurizer water level assumed in the analysis of the inadvertent actuation of safety injection at power. Confirm that this assumption is consistent with the TS restrictions at Seabrook.
82.
For the Anticipated Transients Without Scram (ATWS) analyses, described in Section 6.3.8:
a.
What value for the moderator temperature coefficient was assumed?
- b.
Compare the results of the Seabrook loss of load and loss of feedwater ATWS analyses, with 1760 gpm auxiliary feedwater flow, to the corresponding results of Reference 6.3-20, as adjusted for the higher power level of the Seabrook SPU.
83.
In Section 6.3.3.2.3, FPLE states the following:
Following the reactor and turbine trip from full load, the water level in each steam generator falls due to the reduction of the steam generator void fraction, and because steam flow through the main steam safety valves continues to dissipate the stored and generated heat.
Level and void fraction were not explicitly calculated using LOFTRANs one-node steam generator secondary side model. Describe how this is done in RETRANs SG secondary side model.
84.
In Section 6.36.2-1, what operator actions, if any, are assumed to be implemented, and when, for the chemical and volume control system malfunction event?
85.
In Figure 6.3.6.1-2, ECCS flow is terminated manually at ten minutes, which causes pressurizer pressure to fall by almost 200 psi. However, the pressurizer remains full for more than six minutes following operator intervention. Explain why the pressurizer water level does not fall.
86.
In Section 6.3.6.2-2, what causes the pressurizer pressure and vessel average temperature to peak soon after the pressurizer fills? Explain why the pressure and temperature then begin to increase, at a lower rate, through the end of the reported transient.
87.
In Section 6.3.7.1-1, verify that the Overtemperature T trip provides adequate protection during this event in cases (i.e., for gradual depressurization) where the low pressurizer pressure setpoint may not be reached for a long time. If applicable, consider a single failure consisting of operating with the wrong reference temperature in the Overtemperature T trip setpoint calculation.
88.
Please note that Reference 15.1.6.5 of the Seabrook UFSAR indicates that WCAP-11397-P-A was issued in April, 1984. This should be corrected to show an issue date of April 1989, as indicated in Reference 7.1-1 of the LAR.
89.
In support of the TS 4.2.2.2.g change, justify the increase in the range of applicability of the limits specified in TSs 4.2.2.2.c, 4.2.2.2.e, and 4.2.2.2.f.
90.
In support of TS Table 2.2-1 changes, explain why total allowance is not applicable to SG low-low level setpoint.
91.
In support of TS Table 3.3-4 changes, explain why total allowance is not applicable to SG low-low and high-high level setpoints.
92.
With regard to TS 6.8.6.1.b changes, explain why the older report, YAEC-1854P, "Core Thermal Limit Protection Function Setpoint Methodology For Seabrook Station,"
October, 1992, is substituted for WCAP-14551-P, (Proprietary), "Westinghouse Setpoint Methodology for Protection Systems, Seabrook Nuclear Power Station Unit 1, 24 Month Fuel Cycle Evaluation," June 1998.
Human Performance 93.
Table Matrix-11 of NRC Review Standard RS-001, Revision 0, provides the NRC staffs guidance for evaluating the potential impacts for SPUs on human performance issues and outlines specific review questions. Section 11.0, "Impact on Operations," of the LAR does not sufficiently address the standard set of questions of Matrix-11.
a.
Describe how the proposed SPU will change the plant emergency and abnormal operating procedures.
b.
Provide a list of systems that require new operating and maintenance procedures as a result of the SPU. Provide a description of each of the new procedures's intended purpose.
c.
Describe any new operator actions required as a result of the SPU. Describe changes to current operator actions related to emergency or abnormal operating procedures that will occur as a result of the SPU.
d.
Describe any changes the SPU will have on the safety parameter display system. How will the operators be aware of such changes?
e.
Describe any changes the SPU will have on the operator training program and the plant referenced control room simulator. State the controlling standard for the control room simulator. Provide an implementation schedule for modifications to the simulator that are needed as a result of the SPU.
Environmental Impact 94.
In Section 13.0, "Environmental Evaluation," FPLE states the following:
The recirculation mode increases this discharge water temperature and therefore, the temperature rise between the intake and discharge transition structure is also increased.
a.
Does the National Pollutant Discharge Elimination System (NPDES) permit for Seabrook require a mixing zone? Is there adequate mixing of the thermal plume to accommodate the increase in circulating water outlet temperature?
b.
Will the SPU require any changes to the current NPDES permit or other plant administrative limits?
c.
Discuss the noise effects due to operation of Seabrook at uprated power conditions. Will there be an increase in noise resulting from the SPU?
95.
Verify that for post-accident conditions, the existing post-accident dose rate maps are adequate for power uprate conditions.