ML13330A170

Forwards Request for Addl Info Re Dedicated Shutdown Sys for Fire Protection.Info Requested within 45 Days of Ltr Receipt

ML13330A170
Person / Time
Site:	San Onofre
Issue date:	12/13/1984
From:	Zwolinski J Office of Nuclear Reactor Regulation
To:	Baskin K Southern California Edison Co
References
TAC-64883 LSO5-84-12-009, LSO5-84-12-9, NUDOCS 8412170253
Download: ML13330A170 (9)

Text

December 13, 1984 Docket No. 50-206 LS05-84-12-009 Mr. Kenneth P. Baskin, Vice President Nuclear Engineering Safety and Licensing Department Southern California Edison Company 2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770

SUBJECT:

DEDICATED SHUTDOWN SYSTEM FOR FIRE PROTECTION Re:

San Onofre Unit No. 1 The NRC staff has reviewed your April 24, 1984 submittal regarding a conceptual design for a dedicated safe shutdown system. The staff finds that the additional information identified in the enclosure is needed to continue our review. Please provide your response within45 days of the receipt of this letter.

Note that item 14a in the enclosure relates to information that should be included when your detailed submittal on the system design is provided.

The reporting and/or recordkeeping requirements contained in this letter affect fewer than ten respondents; therefore, OMB clearance is not required under P.L.96-511.

Sincerely, John A.

Zwolinski, Chief Operating Reactors Branch #5 Division of Licensing

Enclosure:

Request for Additional Information 8412170253 841213 cc w/enclosure:

PDR ADOCK 05000206 See next page F

PDR DISTRIBUTION Docket PM ORB Reading PFMcKee NRC PDR OELD NSIC ACRS (10)

Local PDR ELJordan JZwolinski SEPB CJamerson CMiles, OPA TChandra eka n DL:ORB#5 D &5 DL N15 B

DL:ORB#5 CJamerson-'b W u son EMcKenna Parr JZwolinski I/4/84

/84 84

/1/13/84 ftp13/84

Mr. Kenneth December 13, 1984 cc Charles R. Kocher, Assistant Joseph 0. Ward, Chief General Counsel Radiological Health Branch James Beoletto, Esquire State Department of Health Southern California Edison Company Services Post Office Box 800 714 P Street, Office Bldg. 8 Rosemead, California 91770 Sacramento, California 95814 David R. Pigott Orrick, Herrinqton & Sutcliffe 600 Montgomery Street San Francisco, California 94111 Dr. Lou Bernath San Diego nas & Electric Company P. 0. Box 1831 San Diego, California 92112 Resident Inspector/San Onofre NPS c/o U.S. NRC P. 0. Box 4329 San Clemente, California 92672 Mayor City of San Clemente San Clemente, California 92672 Chairman Board of Supervisors County of San Diego San Diego, California 92101 Director Energy Facilities Siting Division Energy Resources Conservation &

Development Commission 1516 - 9th Street Sacramento, California 95814 U.S. Environmental Protection Agency Region IX Off-ce ATTN:

Regional Radiation Representative 215 Freemont Street San Francisco, California 94105 John B. Martin, Regional Administrator Nuclear Regulatory Commission, Region V 1450 Maria Lane Walnut Creek, California 94596

REQUEST FOR ADDITIONAL INFORMATION DEDICATED SHUTDOWN SYSTEM FOR FIRE PROTECTION AT SONGS 1 (DOCKET NO. 50-206)

Reference:

"05000361/LER-1984-020, :on 840326,w/unit in Mode 2 at 2% Power,Reactor Trip Occurred on High Steam Generator Level.Caused by Overfeeding Steam Generators During Manual Operation of [[system" contains a listed "[" character as part of the property label and has therefore been classified as invalid. Control Sys|April 24, 1984 letter]], M. Medford to D. Crutchfield

1. Clarify how the following components and equipment needed for Dedicated Shutdown.(DS) System are cooled in the absence of Component Cooling Water (CCW) and Salt Water Systems:

a. North Centrifugal Charging Pump G-8A Is the local bearing oil cooling fan powered by DS power supply (Enclosure 1, p. 13) a totally self contained cooling unit?

b. RCP Thermal Barriers You state that in the event both the CVCS and the CCW are unavailable due to a fire event (either the CVCS or the CCW can provide cooling water to the RCP thermal barriers), tEie thermal barrier pump can supply the needed cooling water to the RCP thermal barriers for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> by which time the chargina pump will be restored to operable status (Enclosure 1, p. 13).

Clarify whether in addition to the manual operation such as aligning the charging pump suction to the RWST and supplying dedicated power to the charging pump G-8A motor throuah a "dedicated manual transfer switch" (you have described these operations on p. 16 of the enclosure), any repair is required to restore the charging pump G-8A to operable status.

(Note that repair work is not acceptable to achieve hot shutdown.)

Where will the "dedicated manual switch" be located?

c. Motor Driven Auxiliary Feedwater Pump, Thermal Barrier Pump How are these pumps cooled?

d. Dedicated Diesel Generator Clarify whether the cooling for the DS diesel generator (referred to on page 22 of Enclosure 1) is provided by a self contained cooling unit. If so, describe it briefly.

e. The staff's November 1982 Safety Evaluation (SE) identified that RC pump oil coolers, seal water heat exchanger and letdown heat exchangers are also provided cooling water by CCW. Confirm whether this equipment is needed when the DS system is utilized to accomplish shutdown (presumably, these are not needed and consequently unavailability of CCW will not compromise the DS capability to achieve shutdown).

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2. On pages 12 and 13 of Enclosure 1, you state that charging pumps operation must be ensured within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

Clarify whether primary coolant inventory will be sufficient and therefore acceptable for approximately 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after the reactor trip even without any charging flow for 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />?

3. Emergency Diesel Generators

a. Clarify whether the station emergency diesel generator will be required to power any needed equipment for accomplishing safe shutdown when the DS system with its DS diesel generator is used.

b. On page 9 of Enclosure 1, you state that in the event of a fire in the area of the AFW pumps, the East Main Feedwater (MFW) pump powered by the station emergency diesel generator can provide the feedwater to the steam generators (SGs).

State how this station emergency generator is cooled.

4. East Main Feedwater Pump G-3A In case the East MFW pump G-3A has to be used to provide the needed feedwater to the SGs for achieving normal hot shutdown, where does the pump take its suction from? Does utilization of this pump require any manual operation? How is the cooling provided for this pump?

5. Charging Pumps G-8A and G-8B

a. Clarify whether the spray shield/radiant heat shield proposed to be installed between the charging pumps G-8A and G-8B (Refer to page 30 of Enclosure 1) constitutes the fire barrier between the pumps you mention on page 13 of Enclosure 1.

b. With regard to charging pump G-8B, provide information on the following:

i.

What provides cooling for this pump (Is it CCW?)

ii. How is this pump motor powered?

iii.

Should charqing pump G-SA be disabled by a fire in the G-8A area, will pump G-88 be used and reactor safe shutdown accomplished by the normal shutdown system? (i.e., the RHR is available and will be utilized to achieve the cold shutdown.)

6. The staff's November 1982 SE identified the addition of fire barriers between.pumps for the CVCS, CCW and RHR systems. In addition, the SE identified additions of enclosures and fire suppression for components of the CVCS and the AFW systems. Examine the plant modifications identified in the SE item by item to verify their applicability in the light of the proposed DS system.

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7. The staff's November 1982 SE identified the addition of a new motor driven AFW pump. Clarify how the proposed DS system eliminates the need for the additional motor driven AFW pump for Appendix R analysis.

(Please note that this is strictly in relation to Appendix R considerations.

For example, the need for the new motor driven AFW pump may arise due to other considerations such as a line break in the steam supply line to the turbine of the turbine driven AFW pump coincident with a single failure, i.e., failure of.the motor driven AFW pump.)

8. On pages 7 and 19 of Enclosure 1, you state that AFW will be supplied by the Auxiliary Feedwater Storage Tank (AFWST). On page 17, you further state that water stored in the AFW and condensate storage tanks will supply AFW to the SGs. Clarify whetTer the suction for the AFW pump includes the condensate storage tanks (CST) also.

9. How do you propose to support the static water loads in a small segment of the main steam line and the steam supply line to the turbine of the steam driven AFW pump, when these lines carry water to be letdown to the outfall point?

10. With regard to Figure 3-1 of Enclosure 1, provide the following:

a. Identify valve CV-113 and the existing manual isolation valve referred to on page 7 of Enclosure 1. Clarify whether the manual isolation valve referred to above is the 3"-600-129 manual turbine isolation valve referred to on page 17 of Enclosure 1.

b. From the outfall point, where does the water go and get collected?

c. On page 9 of Enclosure 1, the motor operated supply valves to the charging pump suction header are identified as LCV-1100 C and D.

However, in Figure 3-1, these are identified as LCV-1100B and D.

Which is correct?

d. On page 16, the AFW system flow control valves are identified as FCV-2300, 2301, 3300 and 3301. However, in Figure 3-1, these are identified as FCV-3200, 3201, 3300 and 3301.

Which is correct?

11.

Instrumentation and Controls

a.

CST, RWST, AFWST Level Indications Page 25 of Enclosure 1 states that level indication is not required for CST, RWST or AFWST. However, your Reference 6 explicitly states that level indication should be provided for all the tanks that are needed for achieving safe shutdown. For example, Reference 6 mentions specifically CST and RWST. Table 3-1 of Enclosure 1 also does not list these tanks. Since these tanks will be utilized when the DS system is used, explain how you propose to provide level indications for these tanks.

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b. AFW Supply and Letdown Flow Indications On page 21 of Enclosure 1, you state that the desired AFW flow rate is established through the coordinated action of the operators at the supply and letdown valve stations and subsequently, the flow is controlled at the letdown line alone. Also, Reference 6 requires that diagnostic monitoring should be provided. On page 25 of Enclosure 1 you state that AFW flow indication is desirable but not absolutely necessary for the operation of the DS system.

Table 3-1, however, includes AFW pump flow at the location of the AFW "throttle valves" (are these FCV 3200, 3201, 3300 and 3301 shown on Figure 3-1?) as a new modification. Clarify whether the indication of the AFW flow rate to the SGs will therefore be provided as a modification. Table 3-1 also shows that a radioactive effluent monitor will be provided at some location in the AFW "letdown" line.

Clarify whether the indication of the "letdown" flow rate, i.e., the flow rate of feedwater from the SG (via the steam supply line to the turbine of the steam driven AFW pump) to the outfall point will also be provided as a new modification. It looks as though "Radioactive Effluent Monitor" listed in Table 3-1 should have been Auxiliary Feedwater "letdown" flow. Check this entry.

c. On page 3 of Enclosure 1, you state that the DS system approach offers the advantage of using a single system and a single procedure for any fire which would cause the normal systems to be unavailable.

Obviously one category of fire events will involve utilizing the DS system when the RHR is available for achieving cold shutdown. This means that RHR pressure and flow indication should be available in the remote shutdown panel which you indicate is an integral part of your DS system. In this context, note that the November 1982 SE identified that instrumentation will be available at the remote shutdown panel for RHR flow. Explain how you propose to provide RHR pressure and flow indications which may be needed during DS system utilization.

d. On page 21 of Enclosure 1, you state that at the remote shutdown panel Th signal is available, but its indication is unavailable.

Since Re rence 6 requires the indication of Thotexplain how you propose to make this available.

12.

Primary Coolant Pressure Control

a. On page 14 of Enclosure 1, you state that a "bubble" can be maintained in the pressurizer without heaters for the postulated cooldown period. Explain what "bubble" referred to above means and also what is the "postulated cooldown period"? Clarify whether the normal pressure control (i.e., not injecting the "hard bubble" (nitrogen bubble) or not activating the pressurizer heater group D) is maintaining the "bubble" referred to above.

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b. Clarify whether injecting a nitrogen bubble or activating pressurizer heater group D may be needed only after the RCS temperature (Th ) reaches 200aF (please see the bottom paragraph of page 14 and hp lines of page 15).

c. On page 15 of Enclosure 1, you state that only if normal pressure control is not recovered, the options mentioned above may be needed. State how th.e "normal pressure control" can be recovered.

Also, explain how you will maintain the bubble when no heaters are used, especially when the pressurizer PORVs may be utilized for steam venting.

13.

Calculation Section - Pages 1 through 84

a. On page 3 (calculation section), you state that one of the options for removal of the heat from the RCS to achieve cold shutdown is utilization of the main feedwater system as a source of cooling water. Does this mean that RHR can be disabled concurrent with motor driven AFW pump being disabled?

b. On page 6 (calculation section), you state that the feedwater supply line and the blowdown line are both available for admitting cooling water into the active steam generator(s). What is the blowdown line referred to above? Is this the steam generator blowdown line?

c. On page 5 of 84, you state that pressurizer heaters are tripped and are no longer available. When will the pressurizer heater group D be restored? How will it be restored? (Will it be by manually operating the to be installed transfer switch to supply power from the DS system?)

d. On page 74 (calculation section), you state that if there is a need to accelerate the depressurization after the 35th hour, it can be done by the use of the relief valves and/or the pressurizer spray.

However, on page 5, you state that pressurizer spray is tripped at time zero of the fire event and is no longer available. Also, on page 8 of Enclosure 1, you refer only to pressure relief by PORV/

block valve combination. Clarify whether the pressurizer spray will ever be used for pressure-relief following a fire event.

e. On page R of Enclosure 1, you state that during the initial hours of the RCS cooldown, pressurizer heaters are not necessary and pressure may have to be relieved from the system by utilizing PORV/

block valve combination. On page 74 (calculation section), however, you state that under certain circumstances (for example, mixing at the surge line or if the initial water level is less than the normal water level) there may be a need for external pressurization.

Explain this apparent discrepancy. Also statehow you will pressurize if it is needed during the initial hours of RCS cooldown.

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f. On page 73 (calculation section), you state that the required degree of subcooling to prevent the void formation in the upper head is marginally maintained during the early part of the cool down (up to the 8th hour). Examine whether the safety margin available up to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after a fire occurs provides reasonable assurance against void formation in the upper head up to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

g. On page 73 (calculation section), you state that beyond the 35th hour the primary system pressure exceeds the null ductility pressure limit and stays above that limit for the rest of the cooldown. On page 74, you state that there is an obvious need to accelerate the depressurization after the 35th hour in view of the above consider ation. You further state that this can be done by use of relief valves and/or the pressurizer spray. On page 8 of Enclosure 1, however, you state that later during the cooldown (as the RCS approaches cold shutdown) a nitrogen bubble will be established to preserve the system overpressure or one group of pressurizer heaters (Group D) will be restored to maintain the system overpressure.

Explain this apparent discrepancy.

14.

Miscellaneous

a. With regard to your commitment to provide additional information (see page 2 of your "05000361/LER-1984-020, :on 840326,w/unit in Mode 2 at 2% Power,Reactor Trip Occurred on High Steam Generator Level.Caused by Overfeeding Steam Generators During Manual Operation of [[system" contains a listed "[" character as part of the property label and has therefore been classified as invalid. Control Sys|letter dated April 24, 1984]]), please provide, in addition to what you have committed, the following:

i. Detailed description of how safe shutdown will be accomplished for a fire in each one of the fire areas.

Provide this information area by area.

ii. Detailed associated circuits analysis to reflect the utilization of the DS system. This analysis should encompass all the problems that may arise due to a fire in any fire area.

Your analyses should address the problem that may arise due to

1) common bus including high impedance faults, 2) common enclosure, 3) spurious signals particularly those that involve high/low pressure interface, and d) electrical isolation deficiency.

High Impedance Faults Provide assurance that the total of hot shorts associated with the non-safe shutdown loads supplied by a common bus power supply (also supplying safe shutdown loads) does not result in the opening of a circuit breaker associated with the common power supply thus causing loss of power supply to the safe shutdown equipment and/or components prior to the individual breakers of the associated non-safe shutdown loads opening due to the fire damage.

-7 Electrical Isolation Deficiency Fire in certain areas (for example, the control room) may necessitate operating transfer switches (to transfer power and control from the control room to alternate shutdown systems) prior to the fire in the area damaging the control circuits and resulting in blown fuses.

The staff does not give credit for operating the transfer switches prior to fire damage resulting.in blown fuses. Also, the staff does not give credit for replacement of the blown fuses to achieve and maintain alternate hot shutdown (this is regarded as a repair and the staff's guidelines do not permit repair to achieve and maintain hot shutdown).

To handle the potential for the electrical isolation deficiency in the design described above, review your electrical design and provide a drawing of all transfer switch designs in your plant. You should provide assurance that a blown fuse as a result of fire damage will not require replacement to achieve and maintain alternate hot shutdown (this can be done by modifying existing transfer switches if there is need for it and/or installing new isolation switches where necessary to provide redundant fusing).

b. Will the positive displacement charging test pump referred to in your FSAR ever be used for achieving safe shutdown following a fire event?

c. Figure 3-1 shows the valve CV-531 in series with the pressurizer PORV CV-546; also the valve CV-545 is in series with the block valve CV-530. What are the functions of these valves CV-531 and CV-545? Will they also be used in the shutdown procedures?