ML050730385
| ML050730385 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 03/14/2005 |
| From: | Moroney B NRC/NRR/DLPM/LPD2 |
| To: | Stall J Florida Power & Light Co |
| Moroney B, NRR/DLPM, 415-3974 | |
| References | |
| TAC MC1566, WCAP-9272 | |
| Download: ML050730385 (6) | |
Text
March 14, 2005 Mr. J. A. Stall Senior Vice President, Nuclear and Chief Nuclear Officer Florida Power and Light Company P.O. Box 14000 Juno Beach, Florida 33408-0420
SUBJECT:
ST. LUCIE UNIT 2 - CORRECTION TO NRC SAFETY EVALUATION FOR ISSUANCE OF AMENDMENT NO. 138 REGARDING CHANGE IN METHODOLOGY AND INCREASE IN STEAM GENERATOR TUBE PLUGGING LIMIT (TAC NO. MC1566)
Dear Mr. Stall:
By letter dated January 31, 2005, the U.S. Nuclear Regulatory Commission (NRC) issued Amendment No. 138 to Renewed Operating License No. NPF-16. This amendment consists of changes to the Technical Specifications to permit operation with a reduced reactor coolant system flow corresponding to a steam generator tube plugging level of 30 percent per steam generator. The analysis performed to support this change utilized the Westinghouse Reload Safety Evaluation Methodology (WCAP-9272). This amendment also includes the transition to WCAP-9272 as the reload analysis methodology for St. Lucie Unit 2.
The Florida Power & Light Company staff informed the NRC staff of inaccuracies regarding the discussion of the control room ventilation system operation in the isolation mode and the need for editorial corrections in Tables 1 and 2 to the safety evaluation (SE) supporting the amendment. We have resolved this by revising the appropriate wording in the SE and correcting the tables. The corrected SE page and Tables 1 and 2 are included as an enclosure to this letter. Revisions are identified by lines in the margin. This letter, with its enclosure, should be attached to the subject SE to document the resolution of the issue.
If you or your staff have any questions concerning the resolution of this matter, please contact me at 301-415-3974.
Sincerely,
/RA/
Brendan T. Moroney, Project Manager, Section 2 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-389
Enclosure:
As stated cc w/enclosure: See next page
Mr. J. A. Stall ST. LUCIE PLANT Florida Power and Light Company cc:
Senior Resident Inspector St. Lucie Plant U.S. Nuclear Regulatory Commission P.O. Box 6090 Jensen Beach, Florida 34957 Craig Fugate, Director Division of Emergency Preparedness Department of Community Affairs 2740 Centerview Drive Tallahassee, Florida 32399-2100 M. S. Ross, Managing Attorney Florida Power & Light Company P.O. Box 14000 Juno Beach, FL 33408-0420 Marjan Mashhadi, Senior Attorney Florida Power & Light Company 801 Pennsylvania Avenue, NW.
Suite 220 Washington, DC 20004 Mr. Douglas Anderson County Administrator St. Lucie County 2300 Virginia Avenue Fort Pierce, Florida 34982 Mr. William A. Passetti, Chief Department of Health Bureau of Radiation Control 2020 Capital Circle, SE, Bin #C21 Tallahassee, Florida 32399-1741 Mr. William Jefferson, Jr.
Site Vice President St. Lucie Nuclear Plant 6351 South Ocean Drive Jensen Beach, Florida 34957-2000 Mr. G. L. Johnston Plant General Manager St. Lucie Nuclear Plant 6351 South Ocean Drive Jensen Beach, Florida 34957 Mr. Terry Patterson Licensing Manager St. Lucie Nuclear Plant 6351 South Ocean Drive Jensen Beach, Florida 34957 David Moore, Vice President Nuclear Operations Support Florida Power and 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 Mr. J. Kammel Radiological Emergency Planning Administrator Department of Public Safety 6000 Southeast Tower Drive Stuart, Florida 34997
March 14, 2005 Mr. J. A. Stall Senior Vice President, Nuclear and Chief Nuclear Officer Florida Power and Light Company P.O. Box 14000 Juno Beach, Florida 33408-0420
SUBJECT:
ST. LUCIE UNIT 2 - CORRECTION TO NRC SAFETY EVALUATION FOR ISSUANCE OF AMENDMENT NO. 138 REGARDING CHANGE IN METHODOLOGY AND INCREASE IN STEAM GENERATOR TUBE PLUGGING LIMIT (TAC NO. MC1566)
Dear Mr. Stall:
By letter dated January 31, 2005, the U.S. Nuclear Regulatory Commission (NRC) issued Amendment No. 138 to Renewed Operating License No. NPF-16. This amendment consists of changes to the Technical Specifications to permit operation with a reduced reactor coolant system flow corresponding to a steam generator tube plugging level of 30 percent per steam generator. The analysis performed to support this change utilized the Westinghouse Reload Safety Evaluation Methodology (WCAP-9272). This amendment also includes the transition to WCAP-9272 as the reload analysis methodology for St. Lucie Unit 2.
The Florida Power & Light Company staff informed the NRC staff of inaccuracies regarding the discussion of the control room ventilation system operation in the isolation mode and the need for editorial corrections in Tables 1 and 2 to the safety evaluation (SE) supporting the amendment. We have resolved this by revising the appropriate wording in the SE and correcting the tables. The corrected SE page and Tables 1 and 2 are included as an enclosure to this letter. Revisions are identified by lines in the margin. This letter, with its enclosure, should be attached to the subject SE to document the resolution of the issue.
If you or your staff have any questions concerning the resolution of this matter, please contact me at 301-415-3974.
Sincerely,
/RA/
Brendan T. Moroney, Project Manager, Section 2 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-389
Enclosure:
As stated cc w/enclosure: See next page DISTRIBUTION:
PUBLIC EHackett LLund PClifford AAttard PDII-2 R/F MMarshall RJenkins JLazevnick JMunday, RII OGC BMoroney RDennig MBlumberg UShoop, EDO ACRS JArroyo TBoyce EMurphy BClayton (paper copy)
DLPM DRP DCoe SSun BHarvey GHill (2 paper copies)
ADAMS Accession No.: ML050730385 NRR-028 OFFICE PDII-2/PE PDII-2/PM PDII-2/LA PDII-2/SC NAME JArroyo BMoroney BClayton MMarshall DATE 03 / 14 /2005 03 / 14 /2005 03 / 14 /2005 03 / 14 /2005
OFFICIAL RECORD COPY
The licensee assumed the control room is isolated 30 seconds after the LOOP. The licensee also assumed the operators act to un-isolate the control room and initiate filtered air makeup 90 minutes after the start of the event in order to maintain positive pressure and air quality within the control room. By observing the radiation monitors located in the outside air intake ducts, the licensee stated that operators are assumed to be able to identify and open the outside air intake with the lesser amount of radiation. The licensee assessed the dose from the filtered makeup contribution using the dispersion factors for the more favorable air intake location throughout the rest of the 30-day duration of the dose calculation.
In Question 19 of the RAI letter dated July 9, 2004, the staff asked how the operators would be able to continuously observe radiation monitor levels at each intake throughout the 30-day event period to ensure that the less contaminated intake is always being used to pressure the control room during wind shifts and changing release rates from multiple release pathways. In its RAI response to the staff dated September 21, 2004, the licensee committed to revising plant procedures to identify the need for operators to be aware of changing meteorological conditions and how such changes may affect which outside air intake path provides the lower radiation levels.
During the entire course of the event, the licensee assumed unfiltered inleakage enters the control room. At the beginning of the event, prior to control room isolation, the licensee modeled unfiltered inleakage using the dispersion factors associated with the less favorable control room intake location. Following control room isolation, when both control room intakes are closed, the licensee used a dispersion factor corresponding to the midpoint between both control room intake locations (for closest MSSV/ADV releases). At the time when the operators are assumed to un-isolate the control room by opening the more favorable air intake, the licensee used the dispersion factor for the more favorable control room intake location.
In Question 23 of the RAI letter dated July 9, 2004, the staff inquired why the licensee did not model the unfiltered inleakage pathway using the most limiting dispersion factors associated with the bounding potential unfiltered inleakage pathway for the duration of the event. In its RAI response to the staff dated September 21, 2004, the licensee stated that Unit 2 unfiltered inleakage testing demonstrated that a large portion of the control room unfiltered inleakage comes from the B switchgear room which is fed from fans that take suction in the vicinity of the south control room intake. Since the atmospheric dispersion factors for the south control room intake are lower than the other possible receptor points, assigning the unfiltered inleakage to other possible receptor points is conservative.
Staff qualitatively reviewed the inputs to the ARCON96 computer runs and found them generally consistent with site configuration drawings and staff practice. The two potential release pathways (i.e., the condenser and the closest MSSV/ADV) were modeled as ground-level point sources with the difference in heights between the release point and receptor taken into consideration. The building area used to model building wake effects was conservatively set equal to zero. The staff made an independent evaluation of the resulting atmospheric dispersion estimates by running the ARCON96 computer model and obtained similar results.
TABLE 1 SGTR DBA ANALYSIS ASSUMPTIONS (CONTINUED)
Pre-incident iodine spike activity (60 µCi/gm dose equivalent I-131) Reference 7, Table 2.4-3 Coincident spike appearance rate, based on Reference 7, Table 2.4-5 RCS letdown flow rate (120F, 2250 psia), gpm 150.0 RCS letdown demineralizer efficiency 4
RCS mass, lbm 452,000 RCS leakage, gpm 11 Coincident spike multiplier 335 Release duration, hrs Ruptured SG 8
Unaffected SG 8
Liquid Masses, lbm RCS 475,385 (pre-incident spike)
RCS 452,000 (Coincident spike)
SG 105,000 (minimum)
SGTR integrated mass releases Reference 7, Table 2.4-2 Break Flow Flash Fraction, %
Pre-trip (up to 379.2 sec) 17.19 Post-trip 6.6 Primary-to-secondary leakage Ruptured SG, gpm
.15 To unaffected SG, gpd
.15 Duration, hours 12 Chemical form release fractions Elemental 0.97 Organic 0.03 Steam partition coefficient in SGs Ruptured SG (flashed flow) 1.0 Ruptured (non-flashed flow) 100 Intact SG 100
a The receptor is assumed to be the north CR intake b
The receptor is assumed to be the midpoint between the CR intakes c
The receptor is assumed to be the south CR intake Table 2 St. Lucie Unit 2 Control Room Relative Concentration (X/Q) Values Steam Generator Tube Rupture Accident TIME FRAME RELEASE POINT
/Q VALUES (sec/m3) 0 TO 2 HOURS 2 TO 8 HOURS 8 TO 24 HOURS 1 TO 4 DAYS 4 TO 30 DAYS Prior to CR Isolation Condensera 2.47x10!3 Closest MSSV/ADVa 6.69x10!3 During CR Isolation Closest MSSV/ADVb 3.11x10!3 After Initiation of Filtered Make-up Closest MSSV/ADVc 1.88x10!3 1.46x10!3 5.98x10!4 4.23x10!4 3.19x10!4