ML023500398

Request for Additional Information Concerning Risk Informed Inservice Inspection

ML023500398
Person / Time
Site:	Turkey Point
Issue date:	12/16/2002
From:	Ellen Brown NRC/NRR/DLPM/LPD2
To:	Stall J Florida Power & Light Co
Brown E, NRR/DLPM, 415-2315
References
TAC MB5551
Download: ML023500398 (6)

Text

December 16, 2002 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:

TURKEY POINT PLANT, UNIT 4 - REQUEST FOR ADDITIONAL INFORMATION REGARDING RISK-INFORMED INSERVICE INSPECTION RELIEF REQUEST (TAC NO. MB5551)

Dear Mr. Stall:

By letter dated July 8, 2002, Florida Power and Light Company requested relief from the Inservice Inspection (ISI) requirements specified in the American Society of Mechanical Engineers Code. On October 23-24, 2002, the U.S. Nuclear Regulatory Commission (NRC) staff performed an audit of the probabilistic risk assessment analyses used to support the risk-informed ISI relief request. At the conclusion of the audit on October 24, 2002, the NRC staff discussed three questions that were identified during the audit that will require supplemental information to resolve.

Based on our review of your submittal and questions generated during the October 2002 audit, the NRC staff finds that a response to the enclosed request for additional information is needed before we can complete the review.

This request was discussed with your staff on December 16, 2002, and it was agreed that a response would be provided within 30 days of the issuance of this letter.

If you have any questions, please contact me at (301) 415-2315.

Sincerely,

/RA/

Eva A. Brown, Project Manager, Section 2 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-251

Enclosure:

Request for Additional Information cc w/encl: See next page

ML023500398 *See Previous concurrence OFFICE PDII-2\PM PDII-2\LA SPSB\SC EMCB\SC PDII-2\SC NAME EBrown BClayton MRubin TChan AHowe DATE 12/16/2002 12/16/2002 12/12/2002* 11/26 /02* 12/16/2002 Mr. J. A. Stall TURKEY POINT PLANT Florida Power and Light Company cc:

M. S. Ross, Attorney Attorney General Florida Power & Light Company Department of Legal Affairs P.O. Box 14000 The Capitol Juno Beach, FL 33408-0420 Tallahassee, Florida 32304 Mr. John P. McElwain, Site Vice President T. O. Jones, Plant General Manager Turkey Point Nuclear Plant Turkey Point Nuclear Plant Florida Power and Light Company Florida Power and Light Company 9760 SW. 344th Street 9760 SW. 344th Street Florida City, FL 33035 Florida City, FL 33035 County Manager Walter Parker Miami-Dade County Licensing Manager 111 NW 1 Street, 29th Floor Turkey Point Nuclear Plant Miami, Florida 33128 9760 SW 344th Street Florida City, FL 33035 Senior Resident Inspector Turkey Point Nuclear Plant Mr. Don Mothena U.S. Nuclear Regulatory Commission Manager, Nuclear Plant Support Services 9762 SW. 344th Street P.O. Box 14000 Florida City, Florida 33035 Juno Beach, FL 33408-0420 Mr. William A. Passetti, Chief Mr. Rajiv S. Kundalkar Department of Health Vice President - Nuclear Engineering Bureau of Radiation Control Florida Power & Light Company 2020 Capital Circle, SE, Bin #C21 P.O. Box 14000 Tallahassee, Florida 32399-1741 Juno Beach, FL 33408-0420 Mr. Craig Fugate, Director Division of Emergency Preparedness Department of Community Affairs 2740 Centerview Drive Tallahassee, Florida 32399-2100

REQUEST FOR ADDITIONAL INFORMATION RISK-INFORMED INSERVICE INSPECTION (RI-ISI) RELIEF REQUEST TURKEY POINT PLANT UNIT 4 DOCKET NO. 50-251

1. Table 3.1-1 includes a note which states that 22 segments are categorized as not used for Unit 4. Explain what is meant by not used and why the segments are categorized this way.

2. Table 3.7-1 indicates that none of the segments with a risk reduction worth less than 1.005 were defined as high safety significant (HSS). Please describe the characteristics of Unit 4 and the RI-ISI evaluation that caused the expert panel to be satisfied that all HSS segments were identified by the quantitative calculations.

3. Are there any piping segments that include piping of a different diameter? If so how were the failure frequencies estimated for these segments? For segments including piping of a different diameter where the number of inspection locations was determined using the Perdue method, how were the number of locations to be inspected determined? How does the methodology for determining the failure frequency comport with the methodology described on page 71 of the Topical Report Westinghouse Commercial Atomic Power (WCAP) Report, WCAP-14572, Revision 2-NP-A? How does the methodology for determining the number of inspections comport with the methodology described on pages 170, 171, and 174 of the WCAP?

4. Will the proposed RI-ISI program be implemented during the current third 10-year ISI interval? What interval and period will the program be implemented?

5. How will the RI-ISI program be implemented?

6. For the current interval, how much of the American Society of Mechanical Engineers (ASME) Code ISI program has been completed? How much will be covered by the RI-ISI program? How many RI-ISI examinations will be performed?

7. Will the RI-ISI program be updated every 10 years and submitted to the U.S. Nuclear Regulatory Commission (NRC) consistent with the current ASME Section XI requirements?

8. Under what conditions will the RI-ISI program be resubmitted to the NRC before the end of any 10-year ISI interval?

9. Version 0 of the Probability Risk Assessment was used to support the Unit 4 RI-ISI submittal, and credited the use of the Unit 3 reactor water storage tank (RWST) as a back-up water supply to the Unit 4 RWST. This mode of operation was credited for small-small loss of coolant accidents (LOCAs) (3/8 to 2 inches) and for small LOCAs Enclosure

(2 to 6 inches). A probability of about 2E-4/demand was used as the probability that the operators would fail to properly align the Unit 3 RWST.

The refill of the RWST using water sources and paths other than the Unit 3 RWST is included in the emergency operating procedures. Version 0 did not, however, credit these other sources of water. Use of the Unit 3 RWST to refill the Unit 4 RWST is implied but not defined in the sites severe accident management guidelines (SAGs).

The SAGs are to be initiated when the core exit temperature is high enough to indicate that core damage has begun. The SAGs only include identification of all potential water sources (of which the Unit 3 RWST is one) and then directs the operator to provide sufficient cooling water to the reactor vessel. The individual steps of the process are left to the operator.

The "Standard for Probabilistic Risk Assessment for Nuclear Power Plant Application,"

ASME RA-S-2002, April 5, 2002, allows crediting, "those actions performed by the control room staff either in response to procedural direction or as skill-of-the craft to recover a failed function, system or component that is used in the performance of a response action in dominant sequences (e.g., manual start of a standby pump following failure of auto-start)." As a result, the failure probability of 2E-4/demand for the non-proceduralized use of the Unit 3 RWST to refill the Unit 4 RWST in order to prevent core damage following a small-small and a small LOCA is in question.

Please re-evaluate the modeling of the RWST refill, and determine the impact of the re-evaluation on the proposed RI-ISI program. Provide the specific changes made to the model to credit the refilling of the RWST and submit sufficient information to allow the staff to review the changes. The submitted information should include a description of each RWST refill source and associated path (including all human actions) credited in the evaluation. For each RWST refill source and for each human action provide, as appropriate, the success criteria, the logic models, the input values, and the quantitative results. Identify and discuss the impact of these changes on the conditional core damage probabilities (CCDP) used to support the RI-ISI relief request, and on the selection of inspection locations in the proposed RI-ISI program.

10. LOCA size definitions are defined based on the functional requirements that would prevent core damage for the given rate of primary coolant loss. Florida Power & Light (FPL) defines four LOCA sizes whereas other licensees normally only define three. The Unit 4 small-small LOCA corresponds to the size that other licensees label as a small LOCA. For Unit 4, the small LOCA corresponds to the size that other licensees label medium LOCA. Other licensees label all LOCAs with a 6 inch or greater (equivalent) diameter as a large LOCA.

For Unit 4, FPL divides LOCAs with a 6 inch or greater, diameter into a medium LOCA between 6 and 13 1/2 inches, and a large LOCA greater than 13 1/2 inches. FPL stated that the introduction of a medium LOCA between 6 and 13 1/2 inches is necessary because thermal-hydraulic evaluations indicate that at least one train of high-pressure injection is required for LOCAs in this size range; other licensees success criteria require only low-pressure injection for all LOCAs greater than 6 inches. It was noted by FPL that this was more conservative than requiring only low-head injection for LOCA sizes between 6 and 13 1/2 inches.

During the audit, the staff observed in the RI-ISI submittal documentation that the CCDP for the medium LOCA (about 0.03/demand) was about five times smaller than the CCDP for the large LOCA (about 0.15/demand). The staff further noted that the peer review final report stated that the peer reviewers could not locate the thermal-hydraulic analyses supporting introduction of a fourth LOCA size for Unit 4. Is the CCDP for the medium LOCA smaller than for the large LOCA? If so, explain why the medium LOCA (that apparently requires more equipment to operate) has a smaller CCDP than the large LOCA. Also provide the criteria used to identify core damage initiation. Include a discussion of the thermal-hydraulic analyses and the results justifying the introduction of an additional LOCA size between 6 and 13 1/2 inches. The justification should include results from the bounding size compared with the criteria used to identify core damage initiation.

11. During the audit, a description of the individual changes to the probabilistic risk assessment was provided in the documentation. Some contradictory statements were found regarding whether one or two high pressure injection trains were modeled as success criteria for a small-small LOCA.

Identify the appropriate success criteria for high-pressure injection following a small-small LOCA and confirm that this success criteria is accurately reflected in the final proposed RI-ISI program.

12. Section 3.8 of the licensees submittal addresses additional examinations. It states, The evaluation will include whether other elements on the segment or segments are subject to the same root cause and degradation mechanism. Additional examinations will be performed on these elements up to a number equivalent to the number of elements initially required to be inspected on the segment or segments. If unacceptable flaws or relevant conditions are again found similar to the initial problem, the remaining elements identified as susceptible will be examined. No additional examinations will be performed if there are no additional elements identified as being susceptible to the same service related root cause conditions or degradation mechanism.

ASME Code directs licensees to perform these sample expansions in the current outage that the flaws or relevant conditions were identified. Verify in what time frame the sample expansions will be completed.