Text

Forwards Response to RAI on Resolution of USI A-46
	ML20138J120
Person / Time
Site:	Davis Besse
Issue date:	04/30/1997
From:	Jeffery Wood; CENTERIOR ENERGY
To:	; NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
Shared Package
ML20138J127	List: ML20138J120; ML20138J141; ML20138J152;
References
	REF-GTECI-A-46, REF-GTECI-SC, TASK-A-46, TASK-OR 2460, TAC-M69441, NUDOCS 9705080041
	Download: ML20138J120 (102)
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{{#Wiki_filter:- t CENTER 00R ENERGY t 4

 %01 N. State Route 2                                419-249 2300                  John K. Wood Oak Harbor, OH 43449                                FAX; 419 3218337              Vce Presdont . Nuclear Davis-Besse Docket Number 50-346 License Number NPF-3 Serial Number 2460 April 32, 1997 United States Nuclear Regulatory Commission Document Control Desk Washington, D. C. 20555-0001

Subject:

Response to Request for Additional Infonnation on The Resolution of Unresolved Safety Issue (USI) A-46, Davis-Besse Nuclear Power ; Station, Unit 1 (TAC NO. 69441) Ladies and Gentlemen: By letter dated December 17, 1996, (Log Number 4961) the Nuclear Regulatory Commission (NRC) issued a request for additional information (RAI) regarding Toledo Edison's (TE's) Seismic Evaluation Report submittal for the Davis-Besse Nuclear Power Station (DBNPS). Enclosure 1 contains TE's r ponse to the RAI. Should you have any questions or require additional information, please contact Mr. James L. Freels, Manager - Regulatory Affairs, at (419) 321-8466. Very truly yours, I v i D L/dle I l Laclosure ij j f cc: A. B. Beach, Regional Administrator, NRC Region III ) j A. G. Hansen, DB-1 NRC/NRR Project Manager ! S. Stasek, DB-1 NRC Senior Resident Inspector Utility Radiological Safety Board , j 070020 9705000041 970430 " ll. .ll lll ll llle llrll PDR ADOCK 05000346 6 - P PDR_,

1 License Number NPF-3 Serial Number 2460 Enclosure Page1of30 , l QUESTION 1 Section 4.3, " Operations Department Review of the SSEL," c'ontains a short description of procedural evolutions an operating crew would be required to take in order to mitigate the design ; basis earthquake. As stated in Section 4.3,"This review concluded that a trained licensed I operator, without a need for an operating procedure following a seismic event, can follow the existing Davis-Besse procedures and will be directed to use the Safe Shutdown Equipment and Instruments to cool the plant to llot Shutdown conditions. Although direction to use the Safe Shutdown Equipment and Instruments was not always provided as the primary procedure path,

 - no procedural flow paths were identified that would prevent a trained licensed operator fron, completing the cool down to the llot Shutdown condition." Based on these statements, what measures have been taken to ensure that the operating crews will in fact use the SSEL given that procedural directions do not always explicitly provide for their use? Do you expect the operating crew to rely solely on the equipment and instrumentation provided in the SSEL for mitigation of the postulated seismic event? If so how do you plan to ensure only the SSEL equipment is used.    '

If not, what additional equipment is to be used and how did you determine that it would be available and operational during the postulated event?"

RESPONSE

At Davis-Besse Nuclear Power Station,(DBNPS) the Safe Shutdown Equipment List (SSEL) was not intended to be the sole source of equipment used by the operators to mitigate a seismic event. Rather, it represents a minimum equipment set that is ensured to be available after the seismic event. The approach used regarding the interface between the control room operators and the SSEL was to verify that the procedures used by the control room operators when responding to a seismic event provide for the following as a minimum:

A successful mitigation strategy is readily available leading to equipment on the SSEL e Procedural direction is provided to operate equipment on the SSEL l The DBNPS does not have a seismic procedure similar to the event-based Abnormal Operating Procedures or the Serious Station Fire Procedure that describes how to operate station equipment ,

following a seismic event. A symptom-based approach to respond to the actual events encountered is the method utilized at the DBNPS. The approach used primarily involves the use of two procedures to stabilize the plant and determine the existing conditions of structures, systems, and components:

       . The symptom-based Emergency Operating Procedure, DB-OP-02000,"RPS, SFAS, SFRCS Trip or SG Tube Rupture," (DB-OP-02000)
       . The event-based Emergency Plan Off-Normal Procedure, RA EP-02310," Earthquake,"

(RA-EP-02810) Procedure DB-OP 02000 provides direction for plant operation following a Reactor Trip, Safety Features Actuation System (SFAS) actuation, Steam Feed Rupture Control System (SFRCS) actuation, or a Steam Generator Tube Rupture. This procedure provides direction to identify and

1 License Number NPF-3 Serial Number 2460 Enclosure

Page 2 of 30 ' mitigate the following symptoms: Loss of Subcooling Margin, Lack of Heat Transfer, Excessive Heat Transfer, Steam Generator Tube Rupture and triadequate Core Cooling. Once the plant is stabilized, the control room operators will use RA-EP-02810 to address specific concerns that arise as a result of an earthquake and to begin to determine the condition of plant systems, 1 structures, and components. Direction for operation beyond this point is provided by Plant 1 Operating Procedures, Abnormal Ope:2 ting Procedures, and System Operating Procedures. ' 1 As a result of the reviews conducted in responding to this request for additional information, it l was concluded that specific information regarding the operation of equipment on the SSEL will l be added as an enhancement to DB-OP-06903," Plant Shutdown and Cooldown." This new information will detail the specific activities that may be required by the control room operators I as they perform a plant cooldown in response to a seismic event. This approach will provide more structure compared to the previous method of responding to the event as failures are identified. The control room operators will be relied upon to accomplish the actions, but specific procedural direction will be provided. l The control room operators will not be restricted to using just equipment on the SSEL, however only equipment on the SSEL was credited in the reviews. For example, the control room I operators may attempt to place the Motor Driven Feedwater Pump (MDFP)in service. This l pump is not on the SSEL. If the pump is available,it will be utilized. If the pump is not I available, the control room operators will continue to seek a source of feedwater, eventually J resulting in use of equipment on the SSEL. The reviews assumed the MDFP was not available. Regarding the stabilization of the plant prior to cooldown, the Operations and the Training Sections have verified that no procedural dead end flow paths exist using DB-OP-02000 to operate the plant following a seismically induced trip where only equipment on the SSEL was available. Plant operation following the seismic event using only equipment on the SSEL for mitigation did not present any significant difficulty for the six operating crews or the three off-shift crews that were trained using the specifically written simulator scenario. QUESTION 2 Section 4.3 states in part that a scenario was developed that limited operator response to only that equipment of the SSEL. Ilow was this accomplished? Based on the method used to limit the operators to the SSEL, does this present a realistic scenario of the conditions an operating crew would encounter during an actual seismic event? RESPONSE l A sequence of plant events was selected that would likely occur as the result of a significant seismic occurrence. This sequence of events included the following:

    . Main Turbine Trip (due to vibration)                                                         i e   Reactor Trip (due to Main Turbine Trip)
    . Loss of offsite power (due to switchyard / transmission line failures)

License Numbcr NPF-3 Serial Number 2460 Enclosure Page 3 of 30 Steam Feed Rupture Control System actuates on the L.oss of Reactor Coolant Pumps (RCPs) (RCPs lost due to loss of offsite power) e Steam Feed Rupture Control System isolates the Main Steam and Feedwater Systems as a result of the loss of Main Feedwater Pumps (MFPs) (MFPs lost due to loss of offsite power) The scenario was then developed using the Safe Shutdown Equipment List (SSEL). All equipment not on the SSEL was faulted or otherwise rendered unavailable (e.g., loss of offsite power) in a manner that precluded the use of that equipment. For example, a malfunction on the Condensate Storage Tank was activated that ruptured the Tanks when the seismic event was initiated. The tank rupture is dynamically modeled on the DBNPS Simulator. This means that the effects one would expect to see caused by the failure and release of approximately 500,000 gallons of water were presented to the operators by the response of the simulator. Water levels in the Turbine Building rose rendering the equipment located there unavailable. In addition, a single failure of one train of essential onsite AC power was added to the . scenario preventing the use of one train of essentially powered equipment. The scenario developed was realistic with the exception that the ground motion was not duplicated in the DBNPS simulator. The control room operators were alerted to the seismic event by a plant annunciator for the Seismic Monitoring System and notification to the crew by the simulator instructor that ground motion was felt. QUESTION 3 Section 4.3 states in part that the scenario was not inclusive of a cool down to hot shutdown conditions. Based on the procedural outline provided in Section 4.3, what parts of this procedural outline were initiated / accomplished during the simulator scenarios? As part of the I scenario exercised, were any time critical operator actions identified? What were they and what were the time constraints determined?

RESPONSE

During the simulator scenarios, the following actions were initiated or accomplished during the simulator sessions:

    . DB-OP-02000, "RPS, SFAS, SFRCS, Trip or SG Tube Rupture," (DB-OP-02000),

Immediate Actions, steps 3.1 through 3.4, were completed.

    . DB-OP-02000 Supplemental Actions, steps 4.1 through 4.15, were completed. Step 4.15 established manual control of the Atmospheric Vent Valves (AVV) using Attachment 3.         i e   DB-OP-06910, " Trip Recovery," (DB-OP06910), was entered.

DB-OP-06910, Step 3.1 was completed. This is a routing step that directed the operators to Section 4.0, Recovery from Reactor Trip and SFRCS Actuation.

Liccnse Number NPF-3 Serial Number 2460 l Enclosure ' Page 4 of 30 1 e DB-OP-06910, Step 4.2 was completed. This step restores normal Makeup and Reactor ! Coolant Pump (RCP) operation, if possible. Without off site electrical power, RCP 1 operation is not possible. This step also allows shifting Makeup Pump suction to the Makeup tank, however, once the Reactor Coolant System (RCS) cooldown is started, the suction will be returned to the Borated Water Storage Tank (BWST) to accommodate ; RCS contraction. j e DB-OP-06910, Step 4.3 was initiated. This step establishes Secondary Pressure control l via manual operation of the Atmospheric Vent Valves. Condenser vacuum cannot be established without the Circulating Water System Pumps. The Circulating Water System Pumps are not available without offsite power. DB-OP-06910, Step 4.4 was initiated. This step restores normal secondary inventory control from Main Feedwater, if possible. Based on the seismic event, secondary ; inventory control will remain on Auxiliary Feedwater. l i e DB-OP-06910, Step 4.5 was initiated. This step establishes a normal electrical alignment. A majority of these steps cannot be completed until offrite power is restored 1 e DB-OP-06910, Step 4.6 was initiated. This step provides miscellaneous actions to be completed as time permits. A majority of these actions were completed. A routing step l to Section 5 is provided.

     . DB-OP-06910, Section 5.0 was initiated. This section provides direction to cooldown to an average temperature of 532* F and stabilize at llot Standby.                          1 Once the cooldown had started and control of the components required to perform the cooldown was demonstrated, the simulator sessions were ended. A discussion of the SSEL followed the simulator scenarios.

l No time critical operator actions were identified as part of the simulator scenarios. QUESTION 4 I Based on the procedural outline provided in 4.3, were any activities identified which require local manual action by an auxiliary operator outside of the control room? If so, please describe these actions. How were these actions evaluated to determine if they could be accomplished in the time frame required under the assumed post-transient conditions present in the plant? Were any manual actions identified which would require performance of tasks under harsh environmental conditions (e.g., temperature, humidity, lighting, radiological, etc.)? How was this factored into the evaluation?

License Number NPF-3 Serial Number 2460 Enclosure Page 5 of 30

RESPONSE

The exact required local manual operator actions for any specific event will depend on the failures that occur as a result of that seismic event. Equipment potentially requiring manual action outside the control room was noted on the SSEL. It is unlikely that potential barriers such as damaged equipment or structures would inhibit the operator's ability to access plant equipment. Earthquake experience has shown that typical industrial grade equipment and structures are inherently rugged and are not susceptible to damage at the USI A-46 plant Safe Shutdown Earthquake (SSE) levels. None of the equipment on the SSEL is located in areas unfamiliar to the operators. The following potential local manual operator actions were identified: Local Operation of valve MU 366 (SSEL Note 2): This valve is a manually operated valve in the flow path for boric acid injection from the Boric Acid Addition Tanks to the Makeup system. This valve affects the long term reactivity control primary and backup paths. Direction for the operation of this valve is provided in DB-OP-06903, " Plant Shutdown and Cooldown," (steps 4.13,4.14, 4.22, and 4.41) which directs the boration of the Reactor Coolant System. Boration is accomplished by use of DB-OP-06001, " Boron Concentration and Control," (DB-OP-06001), Section 5.0, Emergency Operations. Subsection 5.1 of DB-OP-06001 provides the alternate lineup for boric acid supply from the Boric Acid Addition Tanks. In addition, DB-OP-02528," Loss ofInstrument Air," provides direction to use MU 366 if the normal control valve, MU 23, is not available as a result of a loss ofinstrument air, which in this case is seismically induced. Since the immediate reactivity concerns were addressed by the Control Rods, no specific time ame was identified for performing this action. Use of boric acid will be required to maintain the required Shutdown Margin as the Reactor Coolant System cools. Valve MU 366 is known as the emergency boration valve and is familiar to all licensed and equipment operators. The valve is located in an accessible area of the Boric Acid Addition Tank Room. No harsh environmental conditions are expected in this area, with the exception of a possible loss of area lighting. Flashlights and other emergency lighting are available as needed to mitigate the impact af the loss oflighting.

    . Local operation of valve MU 209 (SSEL Note 11): This valve would be used to isolate the primary path for Reactor Coolant System inventory control from the secondary path if the secondary path was placed in service. The use of this valve would only be necessary if a piping failure or other malfunction created a diversion flow path, in the Makeup System, downstream of MU 209. It is not likely this valve would need to be manually operated. The need to operate MU 209 would be recognized as a Reactor Coolant System leak. Procedure DB-OP-02522,"Small RCS Leaks," would provide direction for isolating leaks in the Makeup system. Although this direction does not specifically direct operation of MU 209, the direction does allow for isolation of the normal injection flow path. Since the immediate Reactor Coolant System inventory concerns were addressed by the primary flow path, and no Reactor Coolant System leaks are postulated, no specific time frame was identified for performing this action. Although the use of the

1 License Number NPF-3 Serial Number 2460 Enclosure Page 6 of 30 secondary flow path may be required, no immediate need is anticipated. No harsh environmental conditions are expected in this area, with the exception of a possible loss l of area lighting. Flashlights and other emergency lighting are available as needed to mitigate the impact of the loss oflighting. l e Local Operation of valve MU 216, (SSEL Note 20): This is a normally closed bypass valve around valve MU 19. Valve MU 19 controls the flow of seal injection from the I Makeup System to the Reactor Coolant Pump seal package. This valve provides a l backup method to supply seal injection flow to the Reactor Coolant Pumps should the l primary method using MU 19 not be available. Since MU 19 fails open on a loss of air, it ! is unlikely that repositioning of this valve would be required. A review of the Operating Schematics would lead the control room operator to identify the use of MU 216 to resolve a failure of MU 19. No specific time frame was identified for the operation of valve MU 216. No harsh environmental conditions are expected in this area, with the exception of a possible loss of area lighting. Flashlights and other emergency lighting are available as needed to mitigate the impact of the loss oflighting. Local operation of valve SW 8432,(SSEL Note 24): This is a normally open isolation valve that stops the Service Water flow to the Service Water Return Radiation Monitor. This flow path diverts a small amount of service water to a drain. Valve SW 8432 is common to both trains of the SSEL Support Systems. The proper alignment must be i established within three hours of the event to maintain proper inventory in the Ultimate I IIeat Sink if the Ultimate Heat Sink becomes isolated " rom Lake Erie. The changes to DB-OP-06903," Plant Shutdown and Cooldown,' u seu -d in the response to Question 1 will specifically include the requirement to reposition this <alve. It is not expected that a seismic event would result in isolation of the Ultimate Heat Sink from Lake Erie. With the Ultimate Heat Sink connected to Lake Erie, an almost infinite supply of water is available. No harsh environmental conditions are expected in this area, with the exception of a possible loss of area lighting. Flashlights and other emergency lighting are available as needed to mitigate the impact of the loss oflighting.

   . Local Operation of valves SW 2929, SW 2930, SW 2931 and SW 2932,(SSEL Notes 25 and 26): The.se four valves determine the return flow path for the Service Water system.

These four valves are electrically powered, however one of the valves is normally depowered and open to provide the 10CFR50 Appendix R Servict Water Return flow path. Following a seismic event, manual operator action may be required to verify or establish the Service Water Return flow path to the forebay by manually operating the normally depowered valve in conjunction with other valve operations in the control room. Specific procedural direction is provided in DB-OP-02511, " Loss of Service Water Pumps / Systems," Section 4.4, Supplemental Actions - Service Water Non-Seismic Line Break. The proper alignment must be established within three hours of the event to maintain proper inventory in the Ultimate Heat Sink if the Ultimate Heat Sink becomes isolated from Lake Erie. It is not expected that a seismic event would result in isolation of the Ultimate Heat Sink from Lake Erie. With the Ultimate Heat Sink connected to Lake Erie, an almost infinite supply of water is available. No harsh environmental conditions

l License Number NPF-3 Serial Number 2460 Enclosure Page 7 of 30 j l are expected in this area, with the exception of a possible loss of area lighting. Flashlights and other emergency lighting is available as needed to mitigate the impact of j the loss oflighting. 1

     . Local operation of valve SW l13 and SW 121 (SSEL Note 27): These valves are the bypasses around the normally open and depowered SW 5422 and SW 5421, Emergency Core Cooling System (ECCS) Room Cooler 4 and 5 Outlet Isolation Valves. When the SSEL was developed, SW 5422 and SW 5421 were aligned with power normally                       )

available to the valves. As a result, the valves could close as a result of the seismic event. Current alignment will prevent the valves from closing in response to a seismic event. SW l13 and SW 121 are also available as a flowpath for Service Water to the ECCS l Room Cooler 4 and 5. SW li and SW 121 are normally open manually-operated j valves. Since the primary and secondary methods to provide cooling to the ECCS Room ! Coolers are both always avaticble, no operator action is required for these components. Current operating philosophy has rendered the noted action in the SSEL unnecessary.

Local operation of valves SW 89 and SW 105 (SSEL Note 28): These normally closed valves provide a bypass around the normally open and depowered SW 5425 and SW 5424, ECCS Room Cooler 1 and 2 Outlet Isolation Valves. When the SSEL was developed, SW 5425 and SW 5424 were aligned with power normally available to the l valves. As a result, the valves could close as a result of the seismic event. Current alignment will prevent the valves from closing in response to a seismic event. Valves SW 89 and SW 105 are also available as a flowpath for Service Water to the ECCS Room Cooler 1 and 2. Valves SW 89 and SW 105 are normally open manually-operated valves.

Since the primary and secondary metheds to provide cooling to the ECCS Room Coolers are both always available, no operator action is required for these components. Current operating philosophy has rendered the noted action in the SSEL unnecessary.

     . Local operation of valve MU 338 (SSEL Note 37): This valve is a normally closed cross connect isolation between Boric Acid Addition Tanks (BAATs) I and 2. This valve woF       ; opened if cross connecting the BAATs was desired. Procedural direction for tl       an is provided in the system operating procedure DB-OP-06031," Boric Acid Adamon Tanks Operating Procedure,"(DB-OP-06031). Sections 4.1 and 4.2 of DB-OP-06031 provide lineups to pump BAAT 1 with Pump 2 and pump BAAT 2 with Pump 1.

No harsh environmental conditions are expected in this area, with the exception of a possible loss of area lighting. Flashlights and other emergency lighting are available as needed to mitigate the impact of the loss oflighting. Since the immediate reactivity concerns were addressed by the Control Rods, no specific time frame was identified for performing this action. Use of boric acid will be required as the Reactor Coolant System cools to maintain the required Shutdown Margin.

     . Local operation of valves MU 348 and MU 349 (SSEL Note 38): These throttle valves 4

are used to obtain the desired flow rate when adding boric acid from the Boric Acid Addition Tanks to the Reactor Coolant System. The need to perform this manual throttling would be the result of an inability to remotely throttle valve MU 23. Direction

i License Number'NPF-3 Serial Number 2460 Enclosure Page 8 of 30 for throttling MU 348 and MU 349 is provided in the abnormal operating procedure DB- { OP-02528, " Loss ofInstrument Air," (DB-OP-02528). Ifinstrument air is lost as a result of a seismic event, the operators will be unable to use the normal flow control valve MU 23. Procedure DB-OP-02528, Attachment 4, Boric Acid Addition System A :tions, i provides the procedural direction to establish boric acid flow including the throttling of l MU 348 and MU 349. No harsh environmental conditions are expected in this area, with the exception of a possible loss of area lighting. Flashlights and other emergency lighting are available as needed to mitigate the impact of the loss oflighting. Since the immediate reactivity concerns were addressed by the Control Rods, no specific time frame was identified for performing this action. Use of boric acid will be required as the Reactor Coolant System cools to maintain the required Shutdown Margin. Local operation of valves MU 66A, MU 66B, MU 66C, and MU 66D (SSEL Note 51): These valves isolate seal injection flow path from the Makeup System to the Reactor Coolant Pump Seals. The valves are normally open, but may fail closed on a loss of instrument air if the air volume tank provided for each valve lost air pressure. The desired position for these valves is open. As the air volume tank pressure is depleted, the valves would close. The loss of seal injection flow would be recognized in the control room and an operator would be dispatched to use the manual hand wheel to re-open the valve that had closed. This action is provided in Abnormal Operating Procedure DB-OP-02528," Loss ofInstrument Air," Attachment 6, RCP SealInjection Restoration. 'No I harsh environmental conditions are expected in this area, with the exception of a possible loss of area lighting. Flashlights and other emergency lighting are available as needed to mitigate the impact of the loss oflighting. No specific time frame was identified for this action as the valves each have an air volume tank that should maintain the valves open during the loss ofinstrument air. Sufficient time is available to manually position these valves as required.

   . Local operation of valve MU 38 (SSEL Note 51): This valve isolates the seal return flow path from all of the Reactor Coolant Pump Seals to the Makeup System. This valve is normally open, but may fail closed on a loss ofinstrument air if the air volume tank provided for the valve lost air pressure. The desired position for this valve is open. If the air volume tank pressure was depleted, the valve would close. This loss of seal return flow would be recognized in the control room and an operator would be dispatched to use the manual hand wheel to re-open the valve. This action is provided in Abnormal Operating Procedure DB-OP-02528," Loss ofInstrument Air,"(DB-OP-02528)

Attachment 5, RCP Seal Return Restoration. No harsh environmental conditions are expected in this area, with the exception of a possible loss of area lighting. Flashlights and other emergency lighting are available as needed to mitigate the impact of the loss of lighting. A time frame for re-opening the valve of 30 minutes from valve closure was identified, if continued operation of the Reactor Coolant Pumps (RCPs) is desired, otherwise the RCPs would have to be secured. The time frame and the action if the 30-minutes is not met are provided in DB-OP-02528. The valve has an air volume tank that should maintain the valve open during the loss ofinstrument air. The 30-minute time frame is sufficient to manually position this valve as required.

License Number NPF-3 Scrial Numbcr 2460 Enclosure Page 9 of 30 l Local operation of AC 111 and AD 111 High Pressure Injection Pumps 1 and 2 Breakers (SSEL Note 68): These breakers are racked out once the plant is cooled to Mode 4, Hot Shutdown, (Reactor Coolant System temperature of 280 'F) to provide low temperature over pressure protection (LTOP). This is a normal action required on each cooldown to : Mode 4. This action is directed by procedure DB-OP-06903," Plant Shutdown and l Cooldown." No harsh environmental conditions are expected in this area, with the l exception of a possible loss of a ca lighting. Flashlights and other emergency lighting are available as needed to mitigate tlse impact of the loss oflighting. No specific time frame was identified for this action. This action is required once Mode 4 has been entered. 1 Local operation of valves DH 21 and DH 23 (SSEL Note 80): These valves provide a ! backup flow path for establishing long term decay heat removal in the event the normal flow path via DH I 1 and DH 12 is not available. The operation of these valves requires l entry into the normally closed Containment. The operation of these valves is directed in the normal syst m operating procedure DB-OP-06012," Decay Heat and Low Pressure Injection System Operating Procedure," Sections 3.5 and 3.6. No harsh environmental conditions are expected in this area, with the exception of a possible loss of area lighting. l Flashlights and other emergency lighting are available as needed to mitigate the impact of the loss oflighting. No specific time frame was identified for operation of these alves. The use of the valves would be required if the normal flow path via DH 11 and DH 12 was not available. The need to use DH 21 and DH 23 would delay the transition to the ; Decay Heat Removal System, however the Auxiliary Feedwater System would continue to remove the decay heat until the DH 21 and DH 23 flow path could be established.

Local Operation of valve DH 10 (SSEL Note 81): This is a normally open valve which provides a method far establishing long term boron dilution following a Loss of Coolant Accident. This valve is closed during each plant cooldown just prior to entering Mode 4, Hot Shutdown. This is a normal action required on each cooldown to Mode 4. This action is directed by procedure DB-OP-06903," Plant Shutdown and Cooldown." No harsh environmental conditions are expected in this area, with the exception of a possible loss of area lighting. Flashlights and other emergency lighting are available as needed to mitigate the impact of the loss oflighting. No specific time frame was identified for this action. This action is required just prior to Mode 4 entry.

     . Local Operation of valve DH 26 (SSEL Note 83): This is a nonnally open valve which provides a method for establishing long term boron dilution following a Loss of Coolant Accident. This valve is closed during each plant cooldownjust prior to entering Mode 4, Hot Shutdown. This is a normal action required on each cooldown to Mode 4. This action is directed by procedure DB-OP-06903," Plant Shutdown and Cooldown." No harsh environmental conditions are expected in this area, with the exception of a possible loss of area lighting. Flashlights and other emergency lighting are available as needed to mitigate the impact of the loss oflighting. No specific time frame was identified for this action. This action is required just prior to Mode 4 entry.

i License Number NPF-3 l Serial Number 2460 Enclosure Page 10 of 30 e Local Operation of Motor Control Center (MCC) El IB and F11 A cross connect (SSEL Note 86): Due to single failure concerns related to the operation of valve DH 11 and j DH 12, a method exists to cross connect these two essentially powered 480 volt MCCs. 1 This method is provided in the emergency operating procedure DB-OP-02000,"RPS, SFAS, SFRCS Trip or SG Tube Rupture," Section 10. This activity, if required, would be completed by Electrical Maintenance personnel. The need to provide this cross connect would be recognized by a loss of power to El1B or Fl1 A. No harsh environmental conditions are expected in this area, with the exception of a possible loss of area lighting. Flashlights and other emergency lighting are available as needed to mitigate the impact of the loss oflighting. No specific time frame was identified for operation of these valves. The use of this cross connect may restore the control room operators' ability to use the normal flow path for decay heat removal via valves DH I1 and DH 12. The inability to promptly open DH 11 and DH 12 would delay the transition to the Decay Heat Removal System, however the Auxiliary Feedwater System would continue to remove the decay heat until the DH 11 and DH 12 flow path could be established or the use of the backup flow via DH 21 and DH 23 was placed in service.

Local operation of the Atmospheric Vent Valves (AVVs)(SSEL Note 93): Local operation of the AVVs is performed to shift Steam Generator Heat Transfer from the Main Steam Safety Valves (MSSVs) to the AVVs. The normal pc: trip response of the Steam Generators (SG) will cause a rise in Steam Generator pressure. This pressure rise will cause one or more MSSVs on each SG side to actuate. The MSSVs will lift as i necessary to maintain SG pressure at approximately 1050 psig. Establishing manual control of the AVVs will allow operator control of SG pressure. Operator control of SG pressure reduces the possibility of a stuck open MSSV and the resultant Reactor Coolant 1 System (RCS) cooldown. Atmospheric Vent Valve control will allow a controlled reduction of RCS temperature by venting SG steam to atmosphere. The room where the l AVV hand wheels are located can be reached from the Control Room via one normally closed door. No difficulty is anticipated in reaching the hand wheels. Local AVV control is established using procedure DB-OP-02000, "RPS, SFAS, SFRCS Trip or SG Tube Rupture," Attachment 3, Operation of Atmospheric Vent Valves. This Attachment establishes manual control by isolating and bleeding offInstrument Air to the actuators for the AVVs. The local hand wheels (on reach rods) are tumed as directed by the j Control Room to establish the desired AVV position. No harsh environmental conditions

are expected in this area, with the exception of a possible loss of area lighting. Flashlights and other emergency lighting are available as needed to mitigate the impact of the loss oflighting. No required time frame was identified to complete this action. j j QUESTION 5 Appendix E," Seismic Review Safe Shutdown Equipment List," contains several pieces of i equipment requiring manual or a combination of electrical / manual support systems. Did the I operations review of the SSEL ensure that these items requiring manual actions were embodied in the procedures to be usea for mitigation of the seismic event? As with (4) above, how were )

License Number NPF-3 Serial Number 2460 Enclosure Page11of30 potentially harsh environmental conditions evaluated to ensure these manual actions could be accomplished in the time frame required ts successfully mitigate the postulated transient? 1

RESPONSE

The question indicates the source as Appendix E. Toledo Edison believ.5 this should have referenced Appendix B. In addition to the local manual operator actions noted in response to i Question 4, the following control room manual operations were identified by reviewing Seismic ! Evaluation Report, Attachment B, Composite SSEL: ( e Operation of valve MU 19,(SSEL Note 10): This valve controls the flow of seal l injection flow from the Makeup System to the Reactor Coolant Pump seal package. This l valve affects the Reactor Coolant System Inventory Control primary and backup paths. l No local manual operation of MU 19 is required. Valve MU 19 may be throttled from the l Control Room ifInstrument Air is available, or more likely, will fail open ifInstrument Air is lost. In either case, no local r.1anual operator action is required.

   . Operation of valve MU 6422, (SSEL Note 12): This is a normally open isolation valve in the Makeup System of the Primary Reactor Coolant System inventory control. This valve is normally in service to provide makeup to the Reactor Coolant System. Failure of the valve would result in a loss of the makeup flow path and is an entry condition for procedure DB-OP-02512," Loss of RCS Makeup." This condition would be readily recognized by the control room operator. The control room operator would be directed to place in service the alternate injection flow path (SSEL Backup train) using step 4.2.8.

This valve is operated from the Control Room. No harsh environmental conditions are expected in this area, with the exception of a possible loss of area lighting. Flashlights and other emergency lighting are available as needed to mitigate the impact of the loss of lighting. No specific time frame was identified for this action.

Operation of valves SW 2929, SW 2930, SW 2931 and SW 2932, (SSEL Notes 25 and 26): These four valves determine the return flow path for the service water system.

These four valves are electrically powered, however one of the valves is normally depowered and open to provide the 10CFR50 Appendix R Service Water Return flow path. Following a seismic event, manual operator action may be required to verify or establish the Service Water Return flow path to the forebay. This may require operation cf two of the four valves from the control room. Specific procedural direction is provided in DB-OP-02511, " Loss of Service Water Pumps / Systems," Section 4.4, Supplemental Actions - Service Water Non-Seismic Line Break. The proper alignment must be established within three hours of the event to maintain proper inventory in the Ultimate IIeat Sink if the Ultimate IIcat Sink becomes isolated from the lake. It is not expected that a seismic event would result in isolation of the Ultimate Heat Sink from Lake Erie. With the Ultimate Ileat Sink connected to Lake Erie, an almost infinite supply of water is available. No harsh environmental conditions are expected in this area, with the exception of a possible loss of area lighting. Flashlights and other emergency lighting is available as needed to mitigate the impact of the loss oflighting. i

License Number NPF-3 Scrial Number 2460 Enclosure Page 12 of 30

Operation of valve DH 1518 (SSEL Note 84): This is a normally closed valve in the flow path that provides a method for using Decay Heat Removal Train 2 to remove decay heat.

This valve (or the opposite train's valve DH 1517) is opened during each plant cooldown once Mode 4, Hot Shutdown, is entered. This is a normal action required on each cooldown to Mode 4. This action is directed by procedure DB-OP-06903," Plant Shutdown and Cooldown,"in conjunction with the system operating procedure DB-OP-06012," Decay Heat and Low Pressure injection System Operating Procedure." This action is performed from the Control Room. No harsh environmental conditions are expected in this area, with the exception of a possible loss of area lighting. Flashlights and other emergency lighting are available as needed to mitigate the impact of the loss of lighting. No specific time frame was identified for this action. The Auxiliary Feedwater System would continue to remove the decay heat until the operation of DH 1518 could be completed.

Operation of valve DH 1517 (SSEL Note 88): This is a normally closed valve in the flow path that provides a method for using DH Train 1 to remove decay heat. This valve (or the opposite train's valve DH 1518) is opened during each plant cooldown once Mode 4, Hot Shutdown, is entered. This is a normal action required on each cooldown to Mode 4.

This action is directed oy procedure DB-OP-06903," Plant Shutdown and Cooldown,"in conjunction with the system operating procedure DB-OP-06012," Decay Heat and Low Pressure Injection System Operating Procedure." This action is performed from the , Control Room. No harsh environmental conditions are expected in this area, with the l exception of a possible loss of area lighting. Flashlights and other emergency lighting are available as needed to mitigate the impact of the loss oflighting. No specific time frame was identified for this action. The Auxiliary Feedwater System would continue to 1 remove the decay heat until the operation of DH 1517 could be completed. i e Operation of valve DH 1 A (SSEL Note 82): This is a normally open isolation valve between the Decay Heat Removal System and the Reactor Coolant System. This valve is normally operated from the Control Room. If this valve were to inadvertently close l during the seismic event and this position was not initially noted by the control room operator, the operator would not receive the expected Decay Heat Removal System flow when the Decay Heat Removal train was placed in service by DB-OP-06012," Decay Heat Removal and Low Pressure Injection System Operating Procedure." This situation is an entry condition for the abnormal operating procedure DB-OP-02527, " Loss of Decay Heat Removal,"(DB-OP-02527). Section 4.2, Loss of Flow Path, of DB-OP-02527 would direct the restoration of the flow path via DH 1 A, Use of the opposite train of Decay Heat Removal would be directed if the flow path could not be restored. This action is performed from the Control Room. No harsh environmental conditions are expected in this area, with the exception of a possible loss of area lighting. Flashlights and other emergency lighting are available as needed to mitigate the impact of the loss of lighting. No specific time frame was identified for this action. A recirculation flow path for the Decay Heat Removal Pump is provided. This flow path is included in the SSEL.

License Number NPF-3 Scrial Number 2460 Enclosure Page 13 of 30 The Decay Heat Pump would operate on the recirculation flow path until the closed DH 1 A was noted and resolved.

Operation of valve DH 1B (SSEL Note 87): This valve is a normally open isolation valve between the Decay Heat Removal System and the Reactor Coolant System. This valve is normally operated from the Control Room. If this valve were to inadvertently close during the seismic event and this position was not initially noted by the control room operator, the operator would not receive the expected Decay Heat Removal System flow when the Decay Heat Removal train was placed in service by DB-OP-06012,

        " Decay Heat Removal and Low Pressure Injection System Operating Procedure." This situation is an entry condition for the abnormal operating procedure DB-OP-02527, " Loss of Decay Heat Remc, val,"(DB-OP-02527). Section 4.2, Loss of Flow Path, of DB-OP-02527 would direct the restoration of the flow path via Dli 1B. Use of the opposite train of Decay Heat Removal would be directed if the flow path could not be restored. This action is performed from the Control Room. No harsh environmental conditions are expected in this area, with the exception of a possible loss of area lighting. Flashlights and other emergency lighting are available as needed to mitigate the impact of the loss of lighting. No specific time frame was identified for this action. A recirculation flow path for the Decay Heat Removal Pump is provided. This flow path is included in the SSEL.

The Decay Heat Pump would operate on the recirculation flow path until the closed DH 1B was noted and resolved. It should be noted that DB-OP-06910, " Trip Recovery Procedure," provides direction for other activities requiring manual operator actions, such as restoring secondary plant systems to a normal alignment. Since these systems were isolated from the Steam Generator as the result of a Steam Feed Rupture Control System actuation they would be inspected as directed by procedure RA-EP-02820," Earthquake," prior to retuming these systems to service. However, these actions are not required for completion of safe shutdown functions and have no specific timing requirements. Other manual actions may be specified in procedure DB-OP-02000, "RPS, SFAS, SFRCS Trip or SG Tube Rupture," such as shifting Auxiliary Feedwater (AFW) Pump Recirculation to the Condensate Storage Tank. These actions, whether accomplished or not, will not affect the stabilization of the plant. For example, AFW Pump recirculation is normally aligned to a floor drain. If the AFW Pumps are started, this recirculation flow path is shifted to the Condensate Storage Tank (CST). For a seismic event, the CST is assumed to be ruptured and the water drains to the floor drains. The position of the recirculation flow path does not affect plant stabilization. QUESTION 6 Appendix E," Third-Party Audit Report," states in part,"The control room ceiling was inspected with the understanding that some re-work is in order." Please describe the extent of this re-work and what, if any, implications it may have on crew activities.

License Number NPF-3 Serial Number 2460 Enclosure Page 14 of 30

RESPONSE

The area that was inspected by the Third-Patty Auditor was room 502, (the control room cabinet area), which is adjacent to the control room. This area was walked down and found to contain several housekeeping concerns such as cracked ceiling tiles, disconnected T-bar wire hangers, secondary T-bars not connected to the primary T-bar, and a light panel attached to adjacent secondary T-bars and not supported. A maintenance work order was generated for room 502 to replace the ceiling tiles, properly position suspended items and replace tie wires, bolts and other restraint system items as necessary. The work activities associated with room 502 han been completed with no complications to the crew's activities. l QUESTION 7

Section 5.2 and Table 5-1 of your submittal provide a summary ofinstances where the intent rather then the letter of certain caveats, as described in Appendix B of the Generic Implementation Procedure, Revision 2 (GIP-2) was met. Based on the information you provided, it is unclear as to how some equipment was determined to meet the intent of the stated caveat. Listed below are specific areas that fall in this category for which we are requesting i

additional information:

a. As indicated in Table 5-1 of your submittal, the cutouts on end panels of the

, switchgear for El and F1,480V Essential Unit Substation, exceed the allowable limit 4 described in GIP-2. The concern regarding these cutout caveats, as described in Appendix B of GIP-2, is that the shear load from the earthquake will not be able to be transferred through the shear walls to the anchorage. GIP-2 states that reinforcement

,            around the cutouts with additional plate or steel members may alleviate the concern of

. shear transfer. Based on the information you provided, it is unclear as to how these end panels werejudged to meet the intent of the caveat. Please provide additional information concerning the size of the cutouts, and a description of how the transformers that are bolted to the switchgear may stiffen the end panels and alleviate the concern of shear transfer.

RESPONSE

4 Transformers are attached to each end of the low voltage switchgears E-1 and F-1 to form a unit substation. Since the opening between the transformer and the low voltage switchgear was not accessible, the Seismic Capability Engineers (SCEs) conservatively assumed that the opening could exceed the limitations identified in Caveat #8 of Equipment Cltss 2. This condition wasjudged to be acceptable based on the added stiffness of the attached transformer. The transformer flange is constructed out of 1/4-inch bent plate material and is securely fasten to the switchgear side panel using eight 3/8-inch diameter bolts. Based on the above, it was concluded that the transformer flange and transformer housing is at least as stiff as the existing switchgear sheet metal and that an adequate load path to the anchorage exist.

License Number NPF-3 Serial Number 2460 Enclosure Page 15 of 30

h. In Table 5-1 of your submittal, you stated that Pumps / Motors K3-1, K3-2, P14-1, and P14-2 are installed with I %-inch expansion anchors. Since GIP-2 only provides anchor allowables up to 1 inch diameter, the 1 inch anchor allowables were used in your analyses. Please confirm that the analyses were found to be acceptable.

RESPPNSE The anchor bolts used to anchor the K3-1/P14-1 and the K3-2/P14-2 skids to the floor are 1 % - inch diameter anchors. The calculated shear load on these anchors is 313 pounds per anchor. There is no tension on these anchors as a result of a seismic event since the dead weight of the skid and equipment counteracts the overturning moment due to a seismic event. The vendor catalog information for 1 %-inch diameter anchors indicate an allowable shear value of 14500 pounds (Safety Factor = 4) and the 1 diameter anchor made by the same manufacturer has an allowable shear value of 8271 pounds (SF = 4). The GIP-2 provides its own allowable values based on generic grouping of anchor bolt types with a knockdown factor as appropriate. Since the GIP-2 recognizes a 1 inch anchor has a shear capacity of 9530 pounds and the 1 %-inch anchor has a higher capacity than the 1 inch anchor, engineering judgment was used to meet the intent of the GIP-2, i.e. ensure the equipment is adequately anchored.

c. For the reactor coolant pump seal return isolation valve MU-38, you stated that the valve actuator and yoke are supported independently of the connecting pipe. The j caveat described in Appendix B of GIP-2 is that the valve actuator and y< ke should not !

be independently braced to the structure or supported by the structure unless the pipe is also braced / supported to the same structure immediately adjacent to the valve. The concern is that if the actuator is independently supported from the valve and attached piping, then the operator may act as a pipe support during seismic motion and attract considerable load through the yoke and possibly fail the yoke or bind the shaft In addition, if both the operator and the valve / pipe are restrained, and if they are both not tied back to the same structure, then differential motion of support points may lead to high seismic loads and possible binding of the shaft If either of these concerns are noted, then a special evaluation should be conducted to demonstrate low stress and small deflections. Please provide additional information to address these concerns.

RESPONSE

Valve MU 38 is a 1 inch bonnetless globe valve with a cylinder operator. The pipe associated with this valve is supported from the Auxiliary Building floor with an anchor located 10 inches from the valve on one side and a two directional support (vertical and lateral) located 7 inches on the other side of the valve. The operator is laterally supported from a short W4x13 section which is attached to the 14WF193 structural steel column. The W4x13 is located approximately 4 ft above the Auxiliary Building floor. This support wasjudged to meet the intent of the caveat based on the following. An anchor and support is located immediately adjacent to the valve. This will isolate any seismic forces from the pipe and preclude the operator acting as a pipe support during strong seismic motion. The

License Number NPF-3 Serial Number 2460 Enclosure Page 16 of 30 14WF193 structural steel column with the structural steel floor framing is an integral part of the floor slab, and it was judged to be rigid with no differential displacement between the structural steel and the concrete floor. The operator support has a gap of approximately 1/8-inch which could also accommodate displacement. In addition, this valve is located toward the bottom of the plant where the accelerations due to a seismic event are low. Therefore, it was concluded that 4 the valve met the intent of being braced / supported to the same structure immediately adjacent to 4 the valve and that differential motion does not exist and that binding of the shaft will not occur.

d. In Table 5-1 of your submittal, you stated that temperature indicating controllers, TIC 5443 and 5444, are anchored to block walls and that those anchors were judged to be acceptable due to low loads. However, GlP-2 does not provide anchor capacity installed in block walls. It is unclear as to how you determined these anchorage capacities. Please describe how the anchorage capacities were determined and provide a comparison of the anchorage capacity with the seismic demand.

RESPONSE 1 Temperature Indicating Controllers, TIC 5443 and TIC 5444, are each attached to the block wall i using four 1/2-inch diameter anchors. The panels weigh approximately 125 pounds each and were judged to be rigid based on the small panel size, type of construction, and weight. The ' block wall is a 12 inch thick grouted concrete block wall and per DBNPS design criteria,1/2-inch anchors have an allowable tension capacity of 450 pounds and an allowable shear capacity of 450 pounds when installed in this type of block wa!!. Engineeringjudgment was originally used to evaluate the adequacy of the anchorage due to low loads and low seismic acceleration (zero period acceleration) values. A recent evaluation, performed by the Seismic Capability Engineers (SCEs), indicated the loads during a seismic event on the anchor bolts are 30 pounds / bolt tension and 36 pounds / bolt shear. This confirmed the original engineering judgment that the anchorage is acceptable. In addition, the anchorages for TIC 5443 and TIC 5444 were successfully " tug tested." QUESTION 8 In your submittal, you proposed to resolve all the identified outliers by the end of the 12th Refueling Outage (currently scheduled to begin March 2,2000). Please provide ajustification to ensure that the proposed schedule for resolving all the identified outliers does not lead to a potential safety-significant scenario. For all outliers that require analysis or modification, please provide the current / planned status of the modification and a briefjustification on why the as-found configuration does not affect system / component operability.

RESPONSE

All SQUG outliers were reviewed for deficiencies against the plant's licensing or design basis. Those SQUG outliers that were determined to L.; 3eficiencies against our design basis were identified and resolved prior to the end of the 10th Refueling Outage (June 2,1996). The remaining outliers are outliers against the SQUG Program. i l l

License Number NPF-3 Serial Number 2460 Enclosure Page 17 of 30 The SQUG modi 6 cations are scheduled as part of the current work load. However, to support { plant emergent activities, some rescheduling of activities may be necessary. Maintaining the ! individual schedule without regard to other work activities would place an unnecessary burden on the DBNPS staff. The SQUG outliers are being actively pursued. l The following is a status of the 30 outliers that were identined as requiring modi 6 cations: I . Modi 6 cations that are Held complete 4 Modi 6 cations in which additional information was obtained to resolve the outlier without Geld modi 6 cation 7

Modi 6 cation packages ready for Geld implementation 7 e Modi 6 cation packages being developed by engineering 7

. Modi 6 cation packages scheduled for engineering to start 5 1 The proposed schedule to resolve all of the SQUG outliers within two outage cycles (i.e., by 12 RFO) is a reasonable time frame especially when considering the availability of equipment during alternating refueling outages. Since the remaining outliers are outliers against only the SQUG program, the two-outage cycle implementation schedule is justined. QUESTION 9 Table 4-1 of Section 4, Attachment 2 of your submittal provides a relay review safe shutdown equipment list. On pages I through 5 of the same section, you provide a list of explanations for the notes used in the review of the safe shutdown equipment list to Table 4-1. However, the staff noted that Table 4-1 does not contain all the notes listed on pages I through 5. Please examine the completeness of Table 4-1 and provide clari6 cation.

RESPONSE

in order to resolve the seismic issue, a list of equipment relied upon for safe shutdown of the plant following a seismic event was developed. This equipment list, the Composite Safe Shutdown Equipment List (SSEL), was used as the basis for several other lists, including the Relay Review List (i.e., Table 4-1 of Section 4, Attachment 2). In order to provide detaib about the equipment, notes were generated with each application of the SSEL. The notes from each application of the SSEL were collected into a single universal set of notes. In any particular application of the SSEL., only the notes pertaining to that application are referenced, although the entire set of notes was included. In performing the Relay Review, it was not necessary to refer to all the notes listed on pages 1 through 5. If the Composite SSEL and the associated SQUG drawings are checked, it would be found that all notes are used, except for notes which state "This note intentionally left blank" and Notes 19, 21, and 22 as discussed below. Some notes, pertaining to system boundaries, are only referred to on the SQUG drawings submitted as a part of the A-46 resolution package (Toledo Edison Serial

 . License Number NPF-3 Serial Number 2460 Enclosure Page 18 of 30 2316). This was done because the boundary function cannot always be assigned to a piece of equipment.

It was determined, while developing this response, that three notes are not used anywhere in the SSEL applications or the SQUG drawings. Specifically, the components that referred to Notes 19,21, and 22 were eliminated from the SSEL, but the notes were inadvertently not changed. While the presence of these notes does not affect the accuracy of the seismic evaluation of the plant, for accuracy, these three notes should have read "This note intentionally left blank". Other than this minor editorial change, Table 4-1 is complete and accurate. QUESTION 10 As indicated in the notes for safe shutdown equipment list in Section 4, Attachment 2 and the relay evaluation report in Section 5.2 of your submittal, the screenings and evaluations for some equipment were noted as relying upon operator actions. Please confirm that a controlled procedure that prioritizes the operator actions exists and that it will preclude any conflicting or competing events which could lead the operator to not perform timing actions.

RESPONSE

The relay screening and evaluation for portions of the Control Room Emergency Ventilation l System (CREVS) are documented on G.4 form numbers 90,91,92, and 93. This system is ! normally maintained in the standby mode, and it is not required to function during the period of strong shaking. The CREVS is manually started after the Control Room Normal Ventilation System dampers close. 1 Several contacts listed on the above G.4 Forms were screened as CA (Chatter Acceptable). The justification for screening as CA is: the system will perform its safe shutdown function and contact chatter will not result in other unacceptable consequences; and when needed, the system is manually placed into service and will be reset while being placed into service. Sections 10,11,12 and 13 in Emergency Procedure DB-OP-02000,"RPS, SFAS, SFRCS Trip or SG Tube Rupture" specify starting the CREVS by referring to procedure DB-OP-06505,

    " Control Room Emergency Ventilation Procedure,"(DB-OP-06505).

Section 5," Emergency Operation"in DB-OP-06505 directs switching the CREVS to ;he water cooled mode if an automatic switchover to the air cooled mode has occurred. Contact chatter could cause the automatic switchover to the air cooled mode requiring reset to the water cooled l mode. There are no other relays that were screened using operator action.

License Number NPF-3 Serial Number 2450 Enclosure Page 19 of 30 l - QUESTION 11 Please provide definitions for the acronyms BA, cal, CA4, CA6, CA7, CA8, and NG contained in G-4 Forms for relay evaluation report.

RESPONSE

The CA acronyms were defined in Section 2.1.3 of the Relay Evaluation Report. Those definitions are repeated here along with the definition of BA and NG. BA " Bad Actor", identifies relays requiring corrective action because ofinclusion on the Low Ruggedness Relays list, as identified in Appendix E to EPRI NP-7148-SL. CA-1 Chatter Acceptable because the contacts provide alarm / indication only. CA-4 Chatter Acceptable because contact will not conduct current as voltage is blocked by upstream or downstream seismically rugged contacts. CA-6 Chatter Acceptable because equipment will return to desired state after period of strong shaking and the equipment load is accounted for in Step 1 of the emergency diesel generator loading. CA-7 Chatter Acceptable as chatter may or may not cause the equipment go to the desired state. Note: this screening code is used when the CA-7 contact pair is paralleled with an essential contact which is cr.dited with causing the equipment to go to the desired state. CA-8 Chatter Acceptable because the contacts are not connected (open circuit) and cannot l cause equipment to change state. NG This acronym appears on G.4 Form #354 page 2 of 12 in reference to a General Electric type SB-1 voltmeter switch. The 'G' in NG was written in error. The correct . i reason for the contact being satisfactory is NV (i.e., mechanically actuated contact not vulnerable to chatter). i QUESTION 12 Referring to the in-structure response spectra provided in your 120-day response to the NRC's request in Supplement No. I to Generic Letter (GL) 87-02, dated May 22,1992, the following information is requested:

a. Identify structure (s) which have in-structure response spectra (5% critical damping) for elevations within 40-feet above the effective grade, which are higher in amplitude than 1.5 times the SQUG Bounding Spectrum.

License Number NPF-3 ' Scrial Number 2460 Enclosure Page 20 of 30

RESPONSE

The following structures, elevations and directions have in-structure response spectra (licensing i basis) higher than the 1.5 times the SQUG Bounding Spectrum: 1 Structure Elev. Direction Aux. Building Area 6 585 N-S Aux. Building Area 6 585 E-W Aux. Building Area 6 603 N-S Aux. Building Area 6 603 E-W Aux. Building Area 7 565 N-S Aux. Building Area 7 585 N-S Aux. Building Area 7 585 E-W Aux. Building Area 7 603 N-S Aux Building Area 7 603 E-W Aux. Building Area 8 584 N-S Aux. Building Area 8 584 E-W Aux. Building Area 8 603 N-S Aux. Building Area 8 603 E-W Containment Internal 603 N-S Containment Intemal 603 E-W Intake Structure 561 N-S l Intake Structure 561 E-W Intake Structure 576 N-S Intake Structure 576 E-W Intake Structure 585 N-S Intake Structure 585 E-W Attachment I contains the plots of the 1.5 x Bounding Spectra vs. the applicable floor response spectra for the licensing basis response spectra.

b. With respect to the comparison of equipment seismic capacity and seismic demand, indicate which method in Table 4-1 of GIP-2 was used to evaluate the seismic adequacy for equipment installed on the corresponding floors in the structure (s) identified in Item (a) above. If you have elected to use method A in Table 4-1 of the GIP-2, provide a technical justification for not using the in-structure response spectra provided in your 120-day response. it appears that some A-46 licensees are making an incorrect comparison between their plant's safe shutdown earthquake (SSE) ground motion response spectrum and the SQUG Bounding Spectrum. The SSE ground motion response spectrum for most nuclear power plants is defined at the plant

License Number NPF-3 Serial Numbcr 2460 Enclosure Page 21 of 30 foundation level. The SQUG Bounding Spectrum is defined at the free field ground surface. For plants located at deep soil or rock sites, there may not be a significant difference between the ground motion amplitudes at the foundation level and those at the ground surface. However, for sites where a structure is founded on shallow soil, the amplification of the ground motion from the foundation level to the ground surface may be significant.

RESPONSE

The following table indicates which method that was chosen by the Seismic Capability Engineers to evaluate the seismic adequacy of the equipment: Pieces of equipment Structure Elev. Method A Method B Aux Building Area 6 585 40 6 Aux. Building Area 6 603 74 2 Aux. Building Area 7 565 53 6 Aux. Building Area 7 585 37 0 Aux. Building Area 7 603 12 0 Aux. Building Area 8 584 7 0 Aux. Building Area 8 603 9 0 Containment Internal 603 5 0 Intake Structure 561 5 0 Intake Structure 576 18 0 Intake Structure 585 4 0 The justification for not using the in-structure response spectra provided in our 120 day response can be found in the Generic Implementation Procedure (GlP-2). Page 4-16 of the GIP-2 under Advantace and Limitations states:

       "The restrictions and limitations on use of the cround response spectrum for comparison to the Bounding Spectrum and the GERS is based on the conditions that the amplification factor between the free-ficid response spectra and the in-structure response spectra will not be more than about 1.5, and that the natural frequency of the equipment is not in the high energy range as follows:

License Number NPF-3 Serial Numbcr 2460 Enclosure : Page 22 of 30 I e The equipment should be mounted in the nuclear plant at an elevation below about 40 feet above the effective grade, and I i e The equipment, including its supports, should have a fundamental natural frequency greater that about 8 Ilertz. Seismic Capability Engineers should be alert for unusual, plant-specific situations which could cause the amplification factor to be greater than that of typical nuclear plant structures. The 1.5 amplification factor is only applicable to reinforced concrete frame and shear wall structures and to heavily-braced steel I frame structures." The structures that house the equipment that are included on the SSEL are typical thick , reinforced concrete frame and shear wall construction which is typical of nuclear plant structures. l There are no unusual plant specific situations which could cause the amplification factor to be j different. Therefore, the use of Method A of Table 4-1 is applicable. ! l The NRC Staffs concern that some licensees are making an incorrect comparison between their l plant's safe shutdown earthquake (SSE) ground motion and the SQUG Bounding Spectrum is not I applicable to DBNPS since DBNPS's SSEL structures are founded on bedrock.

l l

c. For the structure (s) identified in Item (a) above, provide the in-structure response j spectra designated according to the height above the effective grade. If the in-structure l response spectra identified in the 120-day-response to Supplement No. I to GL 87-02 was not used, provide the response spectra that were actually used to verify the seismic adequacy of equipment within the structures identified in Item (a) above. Also, provide a comparison of these spectra to 1.5 times the Bounding Spectrum. ,

RESPONSE i Attachment 1.0 contains the plots of the 1.5 x Bounding Spectra vs. the applicable licensing basis in-structure response spectra, llowever, as indicated in Section 2.2 of the Summary Report, the licensing basis response spectra was one of three different response spectra available to the Seismic Capability Engineers to use in determining the seismic demand of a component. The other two response spectra are the realistic, median-centered response spectra and the conservative design response spectra. A complete set of the realistic, median-centered response spectra was developed for all of the buildings that contain Safe Shutdown Equipment. The conservative design response spectra was developed for only the Auxiliary Building Area 7 and

8. Attachment 2 contains the plots of the 1.5 x Bounding Spectra vs. the realistic, median-centered spectra and Attachment 3 contains the plots of the 1.5 x Bounding Spectra vs. the conservative design response spectra.

The response to Question 15 provides a more in-depth discussion on the use of these response spectra.

License Number NPF-3 Serial Number 2460 Enclosme Page 23 of 30 The response to Question 16 provides a more in-depth discussion on the development of these response spectra. QUESTION 13 The Summary Results Report (SRR) states that Toledo Edison committed to implement GIP-2. The SRR also states that no significant or programmatic deviations from the GIP guidance were made. Please list all the deviations that are considered to be insignificant for Davis-Besse and provide the bases for categorizing them as such.

RESPONSE

The SQUG program allows for the use of sound engineering judgment from qualified, degreed, trained engineers. Engineering judgment was used to varying degrees on every piece of equipment evaluated. Some of this judgment may include estimating of weight, frequency, reactions, load path, equipment behavior, similarity with equipment in the data base, etc. Where agreement was casily obtained among the Seismic Capability Engineers (SCEs), little, if any, documentation was produced. When the SCEs felt that deviations to the GlP were taken, it was identified on the Screening Evaluation Worksheets (SEWS) and justification was provided as to why the intent of the program was met. Those items meeting the intent have been previously identified in Table 5-1 of the Summary Report. QUESTION 14 Section 2.1 states that Davis-Besse's ground response spectra are completely envelcped by the SQUG Bounding Spectrum at all frequencies (Table 2-1). Ilowever, no mention was made which spectrum were used for the Davis-Besse A-46 evaluation. The implication was that SQUG Spectrum was used and that it was conservative because it is higher than the plant ground response spectra. Please provide a clarification.

RESPONSE

The intent of the statement in Section 2.1 was to simply state that the DBNPS ground response spectrum is completely enveloped by the SQUG Bounding Spectrum and therefore, the use of seismic experience data may be used to establish seismic capacity of equipment. This is a requirement of Section 4.2.3 of the GIP. If DBNPS ground response spectrum was not enveloped by the SQUG Bounding Spectrum, then the use of hiethod A as identified in Table 4-1 of the GlP would not be appropriate. Table 2-1 of the Summary Report also illustrates the additional margin above the DBNPS ground spectrum that is available when detennining seismic capacity using hiethod A.

License Number NPF-3 1 Serial Number 2460 I Enclosure Page 24 of 30 QUESTION 15 Three different in-structure response spectra were provided in the report. Discuss how these different spectra are used. For instance, it is indicated that conservative design USI A-46 spectra were used for the Auxiliary Building. Ilowever, no indication was provided as to hew the other two spectra were used. Discuss in detail how the USI A-46 spectra were developed and how the spectra used were in conformance with GIP and staff criteria.

RESPONSE

Three different in-structure response spectra were used in the resolution to USI A-46. The l Seismic Capability Engineers (SCEs) could select any of the applicable spectra when evaluating seismic demand. Appropriate safety factors were used depending on the spectra selected. The three different in-structure response spectra used in the resolution to USI A-46 are detailed ; below: The orieinal (licensine basis) seismic analysis: This in-structure response spectra addresses all ! of the structures within the scope of USI A-46 at DBNPS. This analysis has been classified as being a " Conservative in-structure response spectra" as identified in the NRC's SSER-1, l Suppiement No. I to Generic Letter (GL) 87-02,"That Transmits Supplemental Safety Evaluation Report No. 2 (SSER No 2) on SQUG Generic Irr.plementation Procedure," Revision 2, Corrected on February 14,1992 (GIP-2) dated May 22, i992. Realistic. median-centered in-structure resnonse spectra: This in-structure response spectra was developed from the DBNPS Individual Plant Examination of External Events (IPEEE) in-structure response spectra and scaled in accordance with the criteria identified in Section 4.2.4 of the GIP-2. Realistic, median-centered spectra were developed for all structures within the scope of the USI A-46 program at DBNPS. Conservative desien resnonse spectra: A conservative design response spectra was dewloped specifically for the USl A-46 program at the DBNPS and is applicable only for Areas 7 and 8 of the Auxiliary Building. This spectra meets the criteria established in Section 4.2.4. of the GIP-2 for a conservative response spectra. As identified in Section 3 of the "Use Of Seismic Experience And Test Data To Show Ruggedness Of Equipment In Nuclear Power Plants" prepared by the Senior Seismic Review And Advisory Panel (SSRAP), dated February 28,1991,"SSRAP envisions that realistic (essentially median centered) in-structure spectra will be used for this comparison. Very conservative design spectra may be used, but their use is likely to introduce substantial conservatism." The realistic, median-centered in-structure response spectra developed for USl A-46 is a scaled DBNPS IPEEE in-structure response spectra. The scaling process was performed in accordance with Section 4.2.4 of the GIP-2. liowever, this introduced additional conservatism by the manner in which the scaling factor was determined. This additional conservatism, when

License Number NPF-3 Serial Numbcr 2460 Enclosure Page 25 of 30 multiplied by the required GIP-2 safety factor for the realistic, median-centered in-structure spectra, produced an overly conservative response spectrum. It was decided that a new, conservative, in-structure response spectra should be developed using the criteria specified in NUREG-0800," Standard Review Plan," Section 3.7.1 Seismic Design Parameters, Rev. 2,1989 and Section 3.7.2, Seismic System Analysis, Rev. 2,1989 (NUREG-0800). This response spectra would be considered a conservative spectra in accordance with Section 4.2.4 of the GIP. Only Areas 7 and 8 of the Auxiliary Building were reanalyzed for this spectra. The response to Question 16 provides a more in-depth discussion on the development of the realistic, median-centered and the conservative design response spectra. QUESTION 16 The staff did not review the floor response spectra (FRS) during its 120-day review (see NRC letter to Toledo Edison, dated December 6,1992). Provide detailed information for the spectra including the input ground motion, the structural model, the methodology used to construct the FRS, basis for the methodology, as well as the final results that are used for Davis-Besse.

RESPONSE

Toledo Edison has developed two additional floor response spectra for the resolution of USI A-46 at the DBNPS. These response spectra are the scaled DBNPS IPEEE floor response spectra (realistic, medium-centered spectra) and a conservative design response spectra for Auxiliary Building Areas 7 and 8. The structural models used for this analysis were based on the mathematical models documented in the original (licensing basis) analysis. These original models represent the structures as sets of two planar (two dimensional) models, and neglect the effects of coupling between the two horizontal directions and eccentricities in the structures. In order to better represent the dynamic behavior of the structures, three dimensional mathematical models of the rtructures were developed. These 3-D models were based on the 2-D models in the original analysis, supporting calculations for those models, and as-built drawings of the structures. To create a three dimensional model from the 2-D model, the following properties were calculated: the torsional stiffness of the wall system, the 3 rotational mass terms about the floor centers of gravity, the center of gravity of each floor, and the ceriter of rigidity for each wall system. These properties were calculated based on information found in the original supporting calculation for the 2-D models and plant structural drcwings. The result of these calculations was structural stick models that represcat the 3-dimensional i nature and eccentricities of the buildings studied. Dynamic eigenvalue extraction analyses were then performed on the stick models using EQE Intemational's program MODSAP. The resulting eigensystems were compared to the modal frequencies and participation ft ctors calculated in the

License Number NPF-3 Serial Number 2460 Enclosure Page 26 of 30 original analyses for the 2-D models. Where differences were found, they were determined to be attributable to the inclusion of the rotational mass moments ofinertia and the inclusion of eccentricities. For all of the structures studied in this project, a modal damping ratio of 7% was assumed for all modes. This damping is considered appropriate for the reinforced concrete , structures studied for the earthquake level considered, and is consistent with the recommendation given in Regulatory Guide 1.61 " Damping Values for Seismic Design of Nuclear Power Plants." dated October 1973,(RG 1.61). l The realistic, median-centered spectra were based on the free field motion defined in EPRI NP-

6042-SL, August 1991,"A Methodology for Assessment of Nuclear Power Plant Seismic Margin," and is a median shaped NUREG/CR-0098 " Development of Criteria for Seismic Review of Selected Nuclear Power Plants" May,1978, (NUREG/CR-0098) motion anchored to 0.30g peak ground acceleration (PGA). The local site conditions are characterized by a relatively stiff, shallow soil deposit overlying a massive bedrock formation. It was therefore decided that a NUREG/CR-0098 rock spectral shape was most appropriate to best represent the geologic conditions of the site and the intent of NUREG/CR-0098.

The seismic analyses performed for the realistic, median-centered analyses can be divided into three groups: Auxiliary Building Areas 7, and 8 and Containment Internal Structure; the Auxiliary Building Area 6; and the Intake Structure. The Auxiliary Building Areas 7 and 8 and the Containment Internal structure analyses were fixed based analyses using the deconvolved bedrock motions. The Auxiliary Building Area 6 was analyzed including the soil structure interaction (SEI) effects ofits rigid, surface foundation. The computer analysis used to calculate the foundation impedances and performed the SSI analyses. The intake structure was analyzed using a fixed based assumption, with special considerations made for embedment effects. The raw spectra were then broadened +/- 15%. The broadened spectra for each mass point degree of freedom (DOF) were then enveloped for all three soil conditions. The resulting DBNPS IPEEE spectra were then scaled down for use in USI A-46. The ground motion used to ; calculate the scale factor was a NUREG/CR-0098 84% non-exceedance probability (NEP) shape anchored to the site safe shutdown earthquake (SSE) peak ground acceleration. The value used for the scale factor was 0.697. The same scale factor was applied to all DBNPS IPEEE spectra in order to develop the USi A-46 set of spectra. He conservative design response spectrum analysis (CDRSA) used a Regulatory Guide 1.60

   " Design Response Spectra for Seismic Design of Nuclear Power Plants", Rev.1, dated 1

December,1973,(RG 1.60) shaped free field ground response spectrum anchored to the site SSE peak ground acceleration (0.15g). The definition of the control point for the target free field input motion was taken to be at the ground surface. This definition is considered to be appropriate and consistent with the intent of NUREG-0800, as the till soil layer is of high stiffness. The treatment of the calculation of the high strain soil properties and the deconvolved motions for the CDRSA is also different from a median centered analysis. For a CDRSA, the low strain shear moduli are scaled by 1/2 for the lower bound and 2.0 for the upper bound soil conditions.

License Number NPF-3 1 Serial Number 2460 Enclosure ) Page 27 of 30 , Furthennore, the envelope of the spectra of the deconvolved motions from the three soil cases must envelop 60% of the free field ground surface target spectrum at the foundation level. The building models developed for the median centered analyses were considered appropriate for used in the CDRSA. Modal damping values used for the CDRSA were acceptable per RG 1.61 (7% damping for reinforced concrete structures). Slightly different frequency points were chosen for the calculation of the response spectra to ensure compliance with Regulatory Guide 1.122,

 " Development of Floor Design Response Spectra for Seismic Design of Floor-Supported Equipment or Components," Rev 1, dated February,1978.

Using EQE International's program, SSIN, fixed base analyses were performed for both Areas 7 1 and 8 of the Auxiliary Building. Input to the analyses were the deconvolved RG 1.60 0.15g motions for the three soil cases. The 3% and 5% damped response spectra of the output l acceleration time histories were then calculated. The responses for each degree of freedom were then enveloped for the three soil conditions, with the resulting spectra broadened by +/- 15%. 1 Attachment 4 provides the details of the development of these two response spectra. QUESTION 17 l Equipment items C5792 and C75-2 have been identified as outliers; the gap between the cabinet base and the concrete is greater than 1/4-inches (pages 36 and 37). Provide the analysis ! performed for the outlier resolution together with drawings that illustrate the gap as well as the equipment and the concrete bcm. Is this equipment expected to be subjected to a significant i increase in temperature as result of a design basis accident? If so, please discuss the temperature differential between the equipment and ihe concrete base and how the expansion of the equipment relative to the anchors imbedded in concrete is accommodated. Discuss how the dynamic ef1 ;ct of the earthquake load (SSE) due to the gap is accommodated (impact) when the design is such that a sliding or movement within the gap is allowed between the equipment and the concrete base.

RESPONSE

Both Cabinet C5792 (Control Room Cabinet Area) and exhaust fan C75-2 (Component Cooling Water lleat Exchanger and Pump Room) are located in areas that are considered to be a mild environment and will not see significant increases in temperature as a result of a design basis accident. Therefore, temperature differential between the equipment and the concrete base is not a consideration. Cabinet C5792 is bolted to the top of an adjacent cabinet RU5, which is not on the SSEL. It is this cabinet, RUS, that has the gap underneath its base. Cabinet C5792 was identified as an outlier for the effect RUS could have on cabinet C5792. Cabinet RU5 spans a small depression in the floor, with the anchors of RUS located in this depression. The walkdown concern was that the 1 inch gap between the bottom of the cabinet and the top of the concrete could add additional load on the anchor.

4 i License Numbcr NPF-3 Serial Number 2460 Enclosure Page 28 of 30 i The frequency and seismic forces on cabinets C5792 and RUS were calculmed based on the ; relative stiffness of the cabinets. Since cabinet RUS is lighter and stiffer than C5792, it attracted additional load from C5792. Tiiese loads were then applied to the 6 anchors for RUS. The anchors were checked for shear, tension, and bending loads and were found to be acceptable. There will be no impact within the gap based on its physical layout. Therefore, the outlier l identified for C5792 was resolved. l Attachment 5 provides a copy of the analysis for C5792 that was used to resolve this outlier, i Exhaust fan C75-2 is supported on a steel frame structure from the ceiling with two braces back to the wall. It is the base plate to one of these braces on the wall that has a gap of up to 5/16" on l one side of the base plate. A Structural Analysis And Design (STAAD) analysis was performed for the fan support structure with the affected base plate being modeled as fixed, with the i excep' ion that it cannot take direct tension or moments. This analysis showed that the member stresses for the structure are still relatively low. The shear on the affected base plate is also low I (35 pounds per bolt), and, based on engineering judgment, can be easily taken by the 3/8-inch diameter bolt when considering the 5/16-inch gap. The base plate to the wall was also analyzed and found to be acceptable. There v.ill be no impact within the gap based on its physical layout. Therefore, the outlier identified for C75-2 was resolved. Attachment 6 provides a copy of the analysis for C75-2 that was used to resolve this outlier. QUESTION 18 Tables 6-1 and 6-2 of the report provided a brief description and resolutions for the tank and heat exchanger outliers. Provide the analyses perfonned for equipment T12-1 and T18 together with references and justifications for the analyses methods.

RESPONSE

The Component Cooling Surge Tank (T12-1) is anchored to the floor using eight 1 inch diameter cast-in-place J-bolts. The overall embedment of the J-bolts is 19 inches into the concrete. However, the embedment length of the 10 inch long sleeve was not considered in the effective embedment length, which resulted in an anchorage outlier since the actual length is less than the minimum length of 16 diameters. The actual effective embedment length was calculated and the capacity reduction factor was calculated based on straight line interpolation. This calculated allowable is greater than the applied load. Therefore, this outlier was satisfactorily resolved. Attachment 7 provie, a copy of the analysis that was used to resolve this outlier. Upon further evaluation of the SSEL, it was concluded that Tank T-18 is not required to be part 3 of the SSEL. Tank T-18 will be removed from the SSEL and therefore Is outside the scope of USI A-46. The SSEL will be updated to reflect this when the Completion Letter is issued.

License Number NPF-3 Scrial Number 2460 Enclosure Page 29 of 30 QUESTION 19 Table 7-1 provides descriptions for the selected cable and conduit raceways for limited analytical reviews. Provide a typical sample calculation for the raceway that is not selected as an outlier (for example, case 422A-4, Aux. Bldg. Area 7). Also provide a discussion why the analysis method used is conservative.

RESPONSE

Cable tray support,422A-4, is a floor to ceiling support. It was chosen because it enveloped similar type supports. This support was analyzed using a STAAD computer analysis and normal engineering practices. The results of this analysis indicate the stresses on the members and connections are acceptable. Based on this evaluation, support 422A-4 and all similar supports were found to be acceptable. provides a copy of the analysis. QUESTION 20 Table 7-2 provides a description for the cable and conduit raceway outliers. Most of the resolutions were based on the assumption that the calculated weight on the structures is less than that allowed by GIP. Since the weight criterion of GIP is met for outlier incidents, discuss how they were determined to be outliers. Also, it should be noted that, for a dynamic response, weight alone would not determine the worst condition. Weight criterion may be sufficient for screening the taceways for outliers, but for the resolution of such outliers, one may need additional considerations such as stiffness of the raceways and their supports as well as forcing function (dynamic loading). Discuss how they were considered in the resolution. l

RESPONSE

l The cable tray installations were identified as outliers because they did not meet the Inclusion Rules criteria for span length as identified in Section 8.2.2 of the GIP-2 (i.e., spans were greater than 10 feet). j Section 8.4. of the GIP-2 provides guidance on methods that can be used to resolve this type of , outlier along with an example. Using this method, the Seismic Capability Engineers determined { that the overspan condition was acceptable based on the following:

    . The weight of the cable in the trays was accurately determined. This decrease in cable 2

weight from the GIP standard weight of 25 pounds /ft was used to compensate for the slight increase in span length. )

The cable trays are NEMA standard 6 inches in depth compared to the 4 inch tray in the GIP.' The extra depth provides a higher capacity for the tray to span greater lengths.

l

i License Number NPF-3 Scrial Number 2460 Enclosure Page 30 of 30 The adjacent spans were also checked to ensure that the total tributary spans on the supports were equal to or less than the standard tributary span of the GIP. QUESTION 21 Discuss the issue described in Information Notice 95-49 regarding Thermo-Lag panels, in particular the issue regarding seismic resistance capability of the cable tray and its support when appropriate weight and modulus of the Thermo-Lag are included in the analysis.

RESPONSE

1 Toledo Edison submitted the USI A-46 Summary Report on August 29,1995,(reference Serial , Number 2316). Information Notice 95-49 was issued on October 27,1995. However, Toledo ! Edison has reviewed Information Notice 95-49 and the installation of fire protection material used at the DBNPS and has concluded that Thermo-Lag 330-1 panels are not installed on cable j trays or their cupports at the DBNPS. Therefore, the concern identified in the above question is not applicable to the DBNPS. l l l l l l l i w

l Docket Number 50-346 License Number NPF-3 Serial Number 2460 Enclosure Attachment i I ATTACHMENT 1 - l Response to Question 12a Licensing Basis In-Structure Response Spectra Within 40-Feet of Grade That are Higher ) in Amplitude Than 1.5 Times The SQUG Bounding Spectrum 21 Pages Follow i l 1 e : l I l i i

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_ . . . _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ __________________________A
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____________j
Docket Number 50-346 License Number NPF-3 Serial Number 2460 Enclosure Attachment ATTACHMENT 3 Response to Question 12c Conservative Design In-Structure Response Spectra Within 40-Feet of Grade That are Higher in Amplitude Than 1.5 Times The SQUG bounding Spectrum 12 Pages Follow
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a: , i j, Dockct Number 50-346
License Number NPF-3 l
Serial Number 2460 .1 I
- Enclosure 1 i Attachment i
i J 7 r
t I 1 ! e i = 1 ATTACHMENT 4 f i Response to Question 16 ' 1
, Realistic Median-Centered and Conservative Design R.esponse Spectra ;
222 Pages Follow ! t !6
-)
t i i I : $ L l .. l i .- 4 1-4 ) i n 8 1 1 h A j' l i } i a i v . . , . , , , .#, ._ m ,, , , , . .._ , ,_ .._.. . , - , , , - ~ , .- ,}}

v t e Letter Sequence Response to RAI
TAC:M69441, (Open)
Initiation Acceptance... Administration Questions 17 December 1996 Answers 30 April 1997 Results Approval... Other:
MONTHYEAR1996-12-17 [Table View]

ML20138J120

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RESPONSE

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