ML16131A348

Forwards Request for Addl Info Re Individual Plant Exam. Responses Requested within 60 Days

ML16131A348
Person / Time
Site:	Oconee
Issue date:	06/26/1991
From:	Wiens L Office of Nuclear Reactor Regulation
To:	Tuckman M DUKE POWER CO.
References
GL-88-20, TAC-74440, TAC-74441, TAC-74442, NUDOCS 9107020296
Download: ML16131A348 (12)

Text

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June 26, 1991 Docket Nos. 50-269, 50-270 DISTRIBUTION and 50-287 Docket File L. Wiens NRC PDR E. Chow NLS324 Local PDR PDII-3 R/F Mr. M.S. Tuckman, Vice President S. Varga Oconee File Nuclear Productions G. Lainas E. Jordan MNBB3701 Duke Power Company D. Matthews OGC P.O. Box 1007 L. Reyes, RII ACRS (10)

Charlotte, North Carolina 28201-1007 R. Ingram

SUBJECT:

REQUEST FOR ADDITIONAL INFORMATION - OCONEE GENERIC LETTER 88-20 IPE SUBMITTAL (TAC NOS. 74440, 74441 AND 74442)

The NRC staff is reviewing the Duke Power Company (DPC) Generic Letter 88-20 IPE (Individual Plant Examination) submittal provided to the staff in December 1990. The staff finds that it needs additional information in order to complete its review. Accordingly, please provide responses to the questions identified in the enclosure within 60 days of the date of this letter. If you have any questions, please contact me.

This requirement affects fewer than 10 respondents and, therefore, is not subject to OMB clearance under P.L.96-511.

Sincerely, original signed by Leonard Wiens, Project Manager Project Directorate II-3 Division of Reactor Projects -

I/II Office of Nuclear Reactor Regulation

Enclosure:

As stated cc w/enclosure:

See next page OFC

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OCONEE SUBMITTAL 9107020296 910626 PDR ADOCK 05000296 P

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UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 2068 June 26, 1991 Docket Nos. 50-269, 50-270 and 50-287 Mr. M.S. Tuckman,.Vice President Nuclear Productions Duke Power Company P.O. Box 1007 Charlotte, North Carolina 28201-1007

SUBJECT:

REQUEST FOR ADDITIONAL INFORMATION - OCONEE GENERIC LETTER 88-20 IPE SUBMITTAL (TAC NOS. 74440, 74441 AND 74442)

The NRC staff is reviewing the Duke Power Company (DPC) Generic Letter 88-20 IPE (Individual Plant Examination) submittal provided to the staff in December 1990. The staff finds that it needs additional information in order to complete its review. Accordingly, please provide responses to the questions identified in the enclosure within 60 days of the date of this letter. If you have any questions, please contact me.

This requirement affects fewer than 10 respondents and, therefore, is not subject to OMB clearance under P.L.96-511.

Sincerely, Leonard Wiens, Project Manager Project Directorate 11-3 Division of Reactor Projects -

I/Il Office of Nuclear Reactor Regulation

Enclosure:

As stated cc w/enclosure:

See next page

Mr. M.S. Tuckman Oconee Nuclear Station Duke Power Company Units Nos. 1, 2 and 3 cc:

Mr. A.V. Carr, Esq.

Mr. Stephen Benesole Duke Power Company Duke Power Company 422 South Church Street Post Office Box 1007 Charlotte, North Carolina 28242-0001 Charlotte, North Carolina 28201-1007 J. Michael McGarry, III, Esq.

Winston and Strawn Mr. Alan R. Herdt, Chief 1400 L Street, N.W.

Project Branch #3 Washington, D.C. 20005 U.S. Nuclear Regulatory Commission 101 Marietta Street, NW, Suite 2900 Mr. Robert B. Borsum Atlanta, Georgia 30323 Babcock & Wilcox Nuclear Power Division Ms. Karen E. Long Suite 525 Assistant Attorney General 1700 Rockville Pike N. C. Department of Justice Rockville, Maryland 20852 P.O. Box 629 Raleigh, North Carolina 27602 Manager, LIS NUS Corporation Mr. R.L. Gill, Jr.

2650 McCormick Drive, 3 Floor Nuclear Production Department Clearwater, Florida 34619-1035 Duke Power Company P.O. Box 1007 Senior Resident Inspector Charlotte, North Carolina 28201-1007 U.S. Nuclear Regulatory Commission Route 2, Box 610 Seneca, South Carolina 29678 Regional Administrator, Region II U.S. Nuclear Regulatory Commission 101 Marietta Street, N.W., Suite 2900 Atlanta, Georgia 30323 Mr. Heyward G. Shealy, Chief Bureau of Radiological Health South Carolina Department of Health and Environmental Control 2600 Bull Street Columbia, South Carolina 29201 Office of Intergovernmental Relations 116 West Jones Street Raleigh, North Carolina 27603 County Supervisor of Oconee County Walhalla, South Carolina 29621

ENCLOSURE QUESTIONS FOR DUKE POWER ON OCONEE IPE SUBMITTAL Please note: It is not the intent of the NRC staff to request information that already appears on the docket. Therefore, in response to the questions listed below, the licensee may reference docket information, provided that the specific page number in the referenced document is also included.

1.

In accordance with NUREG-1335 (p. 2-4), please provide "a description of the walkthrough activity of the IPE team, including the scope and team makeup."

Describe the walkdown activities that investigated systems interactions and spatial interactions.

2.

When was the human reliability analysis (HRA) conducted? Has it ever been updated? If it has been updated, was the HRA performed again in its entirety, or were selected parts of it performed again?

3.

Duke Power states that the resulting human error probabilities are lower than LERs warrint. Duke Power justifies this by saying that "most LER latents are easily rLcoverable and the PRA recovery analysis seldom credits their recovering..." (p. 5.6-2). Why not model recovery realistically and use realistic probabilities?

4.

Please discuss the performance shaping factors that were considered for the latent human error analysis.

For some dynamic human errors, Duke Power used the Human Cognitive Reliability Model. In quantifying the human error probabilities using this method, were the only factors considered (1) whether the action is rule-skill-or knowledge-based, and (2) the estimated amount of time the operator had to decide what action to take? Were other performance shaping factors considered?

If so, which performance shaping factors? Were they systematically considered for all actions?

6.

Page 1.3-2 of the Oconee PRA indicates that "realistic recovery actions that would be expected to be taken in response to the progression of a core-inelt sequence were then added to the cut sets." Discuss which, if any, of these recovery actions are not covered by existing procedures. Please provide the basis for taking credit for any actions not covered by procedures. Include any training provided to operators.

Concerning taking credit for non-proceduralized recovery actions, NUREG-1335 (p. C-19) states, "The analyst's judgment should be reflected at that point. The staff, however, expects that all assumed or modeled recovery actions will have written procedures. Most often the staff has received justifications for the assumptions of success for nonproceduralized actions based solely on time available for such actions. The staff does not believe this type of argument to be correct. There is much to be gained by pre-planning." NUREG-1335 also states (p. C-31), "It is the responsibility of each utility to ensure that procedures for which it takes credit in the IPE are in place and that operators have been trained on them." Contrary to this guidance, the Oconee PRA includes credit taken for recovery actions that are not proceduralized (pp. 5.3-5, 5.4-2, and 5.5-1). Does Duke Power plan to change its procedures or its PRA to follow the guidance in NUREG-1335? If not, please justify.

7.

The ultimate strength of the Oconee prestressed containment is relatively high.

To what extent have penetration and equipment hatch performances been included in the ultimate strength calculations to insure that their failure capability preclude a "weak link" in the failure analysis?

Given the ultimate strength evaluation of Oconee, what is the perceived failure location and size for early versus late containment failures? What is the failure mechanism?

What temperature/radiation environment has the containment elastomeric seal material been qualified to? Is this adequate to preclude leakage before the ultimate failure is predicted?

8.

The IPE indicates that all three units at Oconee will function in a similar fashion in a severe accident. In terms of the containment behavior, provide information on any structure, system, or component which is not identical in operation or characteristics across all three units, and which could impact containment performance.

9.

To what extent has in-vessel steam explosion been considered as a contributor to early containment failure probability?

10.

Discuss the assumptions that were considered in evaluating hydrogen combustion?

For example, what hydrogen ignition limits were used in the analyses? Were sensitivity studies performed to evaluate the impact on the results due to the uncertainties of the ignition limits used? Please provide a discussion of the ignition sources and limits used in the analyses.

Were sensitivity studies performed in order to learn the influence of autoignition temperature and steam mole fraction on hydrogen combustion?

Discuss how hydrogen pocketing or stratification potentially leading to local detonations was treated in the Oconee IPE. Discuss the plant-specific effects on containment integrity and equipment survivability due to local detonations. The discussion should cover likelihoods of local detonation and potentials of missile generation as a result of local detonation.

Page 6.2-15 states that some credit is taken for scrubbing due to the sprays and the reactor building cooling unit (RBCU). In some circumstances the sprays can create turbulences that increase the hydrogen concentration in some zones. Are the spray timings considered ?

11.

For release catagories 2.04, Containment Bypass; 4.08, Containment Isolation Failure; 5.02, Early Containment Failure; and 6.08, Late Catastrophic Failure, discuss the extent to which decontamination factors, if any, were applied to the radionuclide release from containment? From what retention mechanisms, e.g.,

plateout, sprays, or deposition on structures did they originate?

12.

Please provide a cross-reference of the topics in Table 2-1 of NUREG-1335 with the respective sections of your submittal, as requested in Generic Letter 88-20 Supplement 1.

13.

In Table 2.2-3, the Te release fraction is considered to be the same as that of Sb.

Please provide the basis, noting that the Te behavior is different from the Sb behavior when the reaction Te-Zr is considered during a period of Zr oxidation.

14.

Page 1.3-2 states that MAAP (reference 8) was used. This MAAP version is from 1983, and p. 8.3-8 states that MAAP 3.0B was used in order to study some phenomena. Page 4.1-5 states that the MAAP version used was from February 1987. Please clarify the calculations made with each of these versions of the MAAP code and provide the reasons for using different MAAP versions.

15.

What is the basis for the assumptions on the water available in the cavity and the need of 1/2 of the BWST as stated on Page 6.2-4?

16.

Page 6.2-4 states that both small and large containment isolation failures preclude late overpressurization. Please indicate the sizes of these failures.

17.

Page 6.1-5 and Table 6.1.3 state that the grouping of the core-melt sequence categories into core-melt bins is based on MAAP calculations. Please describe the process of grouping sequences into bins and provide more references of these calculations. The assumptions taken into account are supposed tor be in the input (not provided).

18.

In the MAAP code the eutectic melt temperature is specified by the user. This temperature can affect the time of vessel failure and also influence the material temperature, composition and mass ejected. In the next phase of the accident

progression concerning the core-concrete attack, the temperature of the corium is very important because it drives the energy production through chemical reaction.

Were sensitivity studies performed in order to determine the effect of this model parameter (eutectic melt temperature) on the accident progression? If so, briefly describe the results of the studies.

Please discuss the containment analyses for investigating basemat meltthrough.

How did the analyses treat debris dispersal/spreading and debris coolability. The discussion should include the effects of the amount of steam accompanying debris dispersal, the compostion of basemat concrete, the geometry of reactor cavity, the availability of water in the reactor cavity, and the use of containment spray.

19.

Please explain in more detail the assumptions considered concerning the lower head failure criteria. Were sensitivity studies performed on the selected model parameters, for example, the delay time to vessel failure? Were uncertainties considered in the lower head failure model?

20.

Did the IPE evaluate the primary system natural circulation under various flow conditions? Were sensitivity studies performed on the available model parameters in the MAAP code?

21.

Discuss how cladding failure temperature influenced the source term in the containment bypass sequences. What temperature for cladding failure was used in the calculations?

22.

Please discuss your assumptions concerning the core blockage model. Were sensitivity studies performed in order to understand the influence of the blockage model to the hydrogen source term ?

23.

Section 10.3 of your IPE submittal addresses Generic Issue - 23 (GI-23) Reactor Coolant Pump Seal Failures, but only provides summary results. Section 2.1.6.7 of NUREG-1335 lists the information to be submitted for each generic issue, as follows:

a.

The ability of the methodology to identify vulnerabilities associated with the USI or GSI being addressed.

b.

The contribution of each USI or GSI to core damage frequency or unusually poor containment performance, including sources of uncertainty.

c.

The technical basis for resolving the issue.

To evaluate your IPE submittal relative to the resolution of GI-23 for the Oconee plants, we need further information. Please provide the details of your calculation of the transient-induced reactor coolant pump seal LOCA's that lead to core melt, including the particulars of the seal model used and the frequency of the initiating events (e.g., Station Blackout). You may reference appropriate sections of your supporting PRA submittal if those sections provide the requested information.

Is the quoted value of 6.2E-06/yr for transient-induced RCP seal LOCAs for one unit or for the Oconee Station (3 units)?

24.

Please identify the plant documentation used in performing the IPE (e.g., FSAR, LERs).

25.

Please provide the minimum success criteria for front-line systems following a transient or accident and the bases for the criteria.

26.

Please provide a concise discussion of any event tree spatial dependencies.

Please provide dependency matrices of support system to support system, and front-line systems to support systems.

27.

Please provide a concise description of interdependencies of shared systems or equipment among the units. Describe systems/equipment, for example, shared between Units 1 and 2, but not Unit 3.

Please identify those safety-related systems capable of performing a safety function at another unit (e.g., emergency feedwater), for which credit was taken in the IPE.

Describe how the IPE considered the potential for misalignments of shared systems.

Discuss how the IPE treated cross-connecting emergency feedwater systems between units. For example, how long does it take to cross-connect the emergency feedwater systems of one Oconee unit to another? Is this controlled by procedures? Can any unit feed any unit? Are there proceduralized limitations for sharing emergency feedwater among units if there is a loss of offsite power?

28.

Please provide a list of the component groups evaluated for common cause failure (CCF) in the Oconee IPE. List the source of the CCF rates and describe the methodology used to estimate and quantify CCFs.

29.

Please provide a list of essential equipment subject to a severe environment (i.e.,

beyond the plant design basis) following a severe accident.

30.

Identify any sequences that, except for low human error rates in recovery actions, would have been above the IPE screening criteria.

31.

Please provide a concise discussion of the criteria used by Duke Power to define a vulnerability.

32.

The Oconee PRA acknowledges that some of the methodologies used in NSAC-60 are no longer in use, having been superseded by improved methods. Concisely

describe where the Oconee IPE has used improved methods over those used in the NSAC-60 analysis.

33.

Please provide a concise discussion of the in-house review of the Oconee IPE.

34.

Please provide a discussion of any specific safety features (e.g., the SSF) believed to be unique and important to the facility.

35.

Duke Power has indicated that certain equipment or other potential failure points are important contributors to core damage frequency or risk. However in some of these instances, Duke Power has indicated that it cannot determine any appropriate fixes. Please provide a concise description of the fixes that were considered but were discarded.

36.

The Oconee IPE indicates that historical data has been used to apply non recovery values to direct losses of main feedwater. What period did this historical data cover? How many loss of feedwater events were there during this period?

Please provide the bases for assuming that the plant-specific data used in the Oconee PRA are appropriate today, since only data from January 1975 to June 1980 were considered. Specifically address test, maintenance, and equipment failures during non-scheduled challenges.

Please provide a concise discussion of why plant-specific data was not used for the high pressure service water pumps.

37.

Please provide a concise discussion of the SSF, for example, its design, its single failure points, the entry controls, and the time it takes to go from the control room to the SSF. Describe the operator training required in qualifying on the SSF.

Please provide a concise discussion of the steps that must be taken to start up the SSF and the minimum number of operators required to do this. Discuss how the access keys to the SSF are stored and who carries them around while on shift.

Provide a concise discussion of the time it would take to start up the SSF with the minimum complement of operators necessary. Discuss how inclement weather could hamper the start up (especially within the ten minute criterion) and operation of the SSF.

38.

Please provide a more detailed discussion of the flow path for the gravity feed, Emergency CCW System. Describe how the adequacy of this flow path as a cooling system has been determined, including any tests performed.

Please include a discussion of the CCW System dewatering process and its safety implication.

On page 3-3 of the Oconee IPE when discussing backflow from the CCW System

during a flood, there is a statement that indicates that "there is no service water or SSF suction requirements on Unit 1." Provide an expanded explanation of this statement.

39.

Please provide a concise description of how the third LPI pump (spare) can be or is used to prevent or mitigate severe accidents.

40.

What are the indications used to determine when the manual switchover to recirculation is to be accomplished? How long does this procedure take?

41.

Please discuss the availability of Keowee Hydro, Lake Keowee, and the ability of the hydro units to supply emergency power to Oconee in the event of a loss of offsite power.

To what level of detail were the two Keowee hydro units and their failure modes modeled in the Oconee IPE? What are the dominant failure modes of the hydro units (failures of a single unit or both units)? Include a discussion of the support systems of the hydro units.

If a loss of offsite power occurs, do emergency loads have to be sequentially loaded onto the Keowee hydro units? If yes, have the hydro units ever sequentially picked up loads as would be required in an actual loss of office power event?

Describe hdw the Technical Specifications at the Oconee units address the Keowee hydro units. Please address how the Oconee operators have contro' of thZ hydro units or, if they do not, under whose control the units are. If controlled by some other entity, concisely describe how Oconee operators can contact them in an emergency such as loss of offsite power, a tornado, or a seismic event. What entity controls modifications to the Keowee hydro units?

In the event that the Keowee units are being used for peak loading by the grid or to help reduce grid undervoltage, are they considered to be inoperable by Oconee Technical Specifications? Would their connection to the grid put Oconee in a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement? If the Keowee units were being used to feed the grid, could they still supply sufficient power to handle the safety loads from all three Oconee units in the event that offsite power was lost in the switchyard?

To what extent do the Keowee hydro units meet the requirements of class 1E equipment/facility? In particular address items such as the proximity of power and control cables, open doorways between battery rooms, and seismic qualification of relays and switches. Describe how appropriate maintenance of safety related equipment at the hydro units is assured by Oconee maintenance procedures or other controls.

In the event of an upstream dam failure, what is the effect on the Keowee hydro units and their ability to provide emergency power to Oconee?

What is the effect on the Keowee hydro units if they were synchronized to the grid out of phase? If the potential damage is serious, has the hardware been evaluated (such as the synch check relay) to assure the units cannot be synchronized to the grid out of phase?

42.

How was the initiator, "loss of dc power" considered in the Oconee IPE? What is the effect of the most limiting failure of the isolating diode arrangement that links the three Oconee units?

43.

From Table 2.1-2 in the Oconee PRA it appears that the initiating event "loss of component cooling water" has been subsumed into the loss of service water initiating event. Was the frequency of loss of CCW events not associated with loss of SW added to the loss of service water frequency? If not so, please explain.

44.

Table 2.1-2 states that the ICS only affects main feedwater. Please discuss the effect of ICS at Oconee on control rod drives (diamond station), atmospheric dumps, condenser dumps, and turbine bypass.

45.

Please discuss the surveillance method and frequency for the suction and discharge valves in the DHR system. Describe the ability of the Oconee units to isolate a break in the DHR/LPI systems if the system should inadvertently be exposed to full primary system pressure.

46.

Since the idnstrument air system is shared among the three Oconee units, discuss how the IPE treated the simultaneous loss of instrument air on all three units.

What safety related equipment would have its function degraded by such a loss of instrument air?

47.

Describe how the Oconee flooding analysis considered the possibility that flooding barriers (e.g., seals, doors) might not be in place or might fail during a flooding event. If the analysis did not consider the effect of barrier loss, discuss the reasons for not including such a consideration.

48.

On page 3.3-11 Rev. 1, the Oconee PRA states that the flooding of the HPI and LPI rooms is not independent. Please discuss the common flooding paths and highlight where this dependence was accounted for in the flooding analysis.

49.

Discuss the impact on safety equipment that would result from flooding/spraying of the Equipment Room.

50.

Discuss the function and safety significance of the HPSW jockey pumps.

51.

A flood of the Oconee Turbine Building basement would flood equipment important to safety in all three units. Please discuss how the three units would cope with the effects of a flood in the Turbine Building.

52.

Please provide a blown-up or more readable Figure 3.3.-3 from the Oconee PRA.

53.

Did the flooding analysis consider hose ruptures and pump seal leaks? If these sources of flooding are bounded by other analyses, so state.