ML040370428

01/21-22/2004 - Attachments 7 and 8, Questions & Answers

ML040370428
Person / Time
Site:	Salem
Issue date:	02/09/2004
From:	Office of Nuclear Reactor Regulation
To:
Thompson JW, NRR/DIPM/IIPB, 415-1011
Shared Package
ML040410121	List: ML040370428
References
Download: ML040370428 (16)

Text

On September 20, 2003, Salem 1 and 2 were manually shutdown due to switchyard arcing from salt buildup on insulators in the switchyard. The salt buildup was due to unusual and unpredictable meteorological conditions (hurricane force winds, with minimal rain). These conditions led to an abnormal buildup of salt from the Delaware Bay being deposited on the insulators. The shutdown was not in response to any existing or immediate equipment problems or electrical system protective actuations. These shutdowns were initiated to alleviate nuclear plant safety concerns arising from an external event outside the control of the plant. Though PSEG LLC has previously experienced hurricanes, the high wind condition with minimal rain present on September 20 has not occurred before at Salem and is not a repeat event. This shutdown is not being counted in the indicator and an FAQ has been submitted to address this shutdown.

PSEG is treating this Pi as though it is white, and will complete the same level of review and corrective actions that we would perform if it were a white PI. In addition, this review will be made available to the NRC for inspection, if requested.

The facts of the event have not changed since the October 20, 2003, PI submittal. After the shutdowns, an FAQ was prepared and submitted. The shutdowns were conservatively reported as unplanned power changes while awaiting the resolution of the FAQ. After further review and discussion of the shutdowns and the guidance in NEI 99-02, PSEG believes that both the Salem 1 and 2 shutdowns are not reportable as unplanned power changes and has retracted them from the Pi report. The FAQ remains active, and is in the process of being resolved through the joint NEI/NRC Reactor Oversight Process Working Group.

FAQ LOG DRAFTr TempNo. Pi Question/Response Status Plant/ Co.

27.3 IE02 Question: 1/25 Introduced LaSalle Should a reactor scram due to high reactor water level, where the feedwater pumps tripped due 2/28 NRC to discuss with resident to the high reactor water level, count as a scram with a loss of normal heat removal 4/25 Discussed Background Information: 5/22 On hold On April 6, 2001 LaSalle Unit 2 (BWR), during maintenance on a motor driven feedwater 6/12 Discussed. Related FAQ 30.8 pump regulating valve, experienced a reactor automatic reactor scram on high reactor water 9/26 Discussed level. During the recov'cry, both turbine driven reactor feedwater pumps (TDRFPs) tripped due 10/31 Discussed to high reactor water level. The motor driven reactor feedwater pump was not available due to the maintcnance being performed. The reactor operators choose to restore reactor water level through the use of the Reactor Core Isolation Cooling (RCIC) System, due to the fine flow control capability of this system, rather than restore the TDRFPs. Feedwater could have been restored by resetting a TDRFP as soon as the control board high reactor water level alarm cleared. Procedure LGA-001 "RPV Control" (Reactor Pressure Vessel control) requires the unit operator to "Control RPV water level between II in. and 59.5 in. using any of the systems listed below: Condensate/feedwater, RCIC, HPCS, LPCS, LPCI, RHR."

The following control room response actions, from standard operating procedure LOP-FW-04, "Startup of the TDRFP" are required to reset a TDRFP. No actions are required outside of the control room (and no diagnostic steps are required).

Verify the following:.:.i TDRFP M/A XFER (Manual/Automatic Controller) station is reset to Minimum No TDRFP trip signals are present Depress TDRFP Turbine RESET pushbutton and observe the following Turbine RESET light Illuminates TDRFP High Pressure and Low Pressure Stop Valves OPEN PUSH MWA increase pushbutton on the Manual/Automatic Controller station Should this be considered a scram with the loss of normal heat rem6val?

Proposed Answer:

The ROP working group is currently working to prepare a response.

28.3 IE02' Question: 3/21 Discussed Perry This event was initiated because a feedwater summer card failed low.' The failure caused the 4/25 Discussed feedwater circuitry to sense a lower level than actual. This invalid low level signal caused the 5/22 Modified to reflect discussion of 4/25, On Reactor Reeirculation pumps to shift to slow speed while also causing the feedwater system to Hold feed the Reactor Pressure Vessel (RPV) until 'a high level scram (Reactor Vessel Water Level - 6/12 Discussed. Related FAQ 30.8 High, Level 8) was initiated.'

Within the first three Tniinutes of the transient, the plant had gone from Level 8, which initiated the scram, to Level 2 (Reactor Vessel Water Level - Low Low, Level 2), initiatirig High Pressure Core Spray (HPCS) and Reactor Core Isolation Cooling (RCIC) injection, and again back to Level 8. The operators had observed the downshift of the Recirculation pumps' nearly

._____ coincident with the scram, and it was not immediately apparent what had caused the trip due to 1*

FAO LOG DRAFT TempNo. P Question/Response Status Plant/ Co.

the rapid sequence of events.

As designed, when the reactor water level reached Level 8, the operating turbine driven feed pumps tripped. The pump control logic prohibits restart of the feed pumps (both the turbine driven pumps and motor driven feed pump (MFP)) until the Level 8 signal is reset. (On a trip of one or both turbine feed pumps, the MFP would automatically start, except when the trip is due to Level 8.) All three feedwater pumps (both turbine driven pumps and the MFP) were physically available to be started from the control room, once the Level 8 trip was reset.

Procedures are in place for the operators to start the MFP or the turbine driven feedwater pumps in this situation.

Because the cause of the scram was not immediately apparent to the operators, there was initially some misunderstanding regarding the status of the MFP. (Because the card failure resulted in a sensed low level, the combination of the recirculation pump downshift, the reactor scram, and the initiation of HPCS and RCIC at Level 2 provided several indications to suspect low water level caused the scram.) As a result of the initial indications of a plant problem (the downshift of the recirculation pumps), some operators believed the MFP should have started on the trip of the turbine driven pumps. This was documented in several personnel statements and a narrative log entry. Contributing to this initial misunderstanding was a MFP control power available light bulb that did not illuminate until it was touched. In fact, the MFP had functioned as it was supposed to, and aside from the indication on the control panel, there were no impediments to restarting any of the feedwater pumps from the control room. No attempt was made to manually start the MFP prior to resetting the Level 8 feedwater trip signal.

Regardless of the issue with the MFP, however, both turbine driven feed pumps were available once the high reactor water level cleared, and could have been started from the control room without diagnosis or repair. Procedures are in place to accomplish this restart, and operators are trained in the evolution. Since RCIC was already in operation, operators elected to use it as the source of inventory, as provided for in the plant emergency instructions, until plant conditions stabilized. Should this event be counted as a Scram with a Loss of Normal Heat Removal?

Response

The ROP working group is currently working to prepare a response.

30.8 IE02 Question: 5/22 Introduced Generic Many plant designs trip the main feedwater pumps on high reactor water level (BWRs), and 6/12 Discussed high steam generator water level or certain other automatic trips (PWRs). Under what 9/26 Discussed.

conditions would a trip of the main feedwater pumps be considered/not considered a scram with 10/31 Discussed loss of normal heat removal?

Response

The ROP working group is currently working to prepare a response.

32.3a IE02 Question: 1/23 Revised. Split into two FAQs DC Cook An unplanned scram occurred October 7, 2001, during startup following an extended forced 3/20 Discussed outage. The unit was in Mode I at approximately 8% reactor power with a main feed pump and 5/1 Discussed low-flow feedwater preheating in service. The operators were preparing to roll the main turbine 5/22 Tentative Approval when a reactor tripped occurred. The cause of the trip was a loss of voltage to the control rod 6/18 Discussion deferred to July drive mechanisms and was not related to the heat removal path. Main feedwater isolated on the 7/24 Discussed 2

FAO LOG DRAFr TempNo. I PI I Question/Response [ Status I Plan Co.

trip, as designed, with the steam generators being supplied by the auxiliary feedwater (AFW) pumps. At 5 minutes after the trip, the reactor coolant system (RCS) temperature was 540 degrees and trending down. The operators verified that the steam dumps, steam generator power operated relief valves, start-up steam supplies and blowdown were isolated. Additionally, AFW flow was isolated to all Steam Generators as allowed by the trip response procedure. At 9' minutes after the trip, with RCS temperature still trending down, the main steam isolation valves (MSIV) were closed in accordance with the reactor trip response procedure curtailing the cooldown.

The RCS cooldown was attributed to steam that was' still being supplied to low-flow feedwater preheating and #4 steam'generator AFW flow control valve not automatically moving to its flow retention position as expected with high AFW flow. The low-flow feedwater preheating is a known steam load during low power operations and the AFW flow control issue was identified by the control room balance of plant operator. The trip response procedure directs the operators to check for and take actions to control AFW flow and eliminate the feedwater heater steam supply.

When this trip occurred the unit was just starting up following a 40 day forced outage. The reactor was at approximately 8% power and there was very little decay heat present following the trip. With very little decay heat available, the primary contribution to RCS heating is from Reactor Coolant Pumps (RCPs). Evaluation of these heat loads, when compared 'to the' cooling provided by AFW, shows that there is approximately 3.5 times as much cooling fl6w'provided than is required to remove decay heat under these conditions plus'pump heat. This resulted in rapid cooling of the RCS and ultimately required closure'of the MSIVs; Other conditions such as low flow feedwater preheating and the additional AFW flow due to the AFW flow control valve failing to move to its' flow retention setting contributed to this cooldown, but were notthe primary cause. Even without these contributors to the cooldown, closure of MSIVs would have been required due to the low decay heat present following the trip.  :

It should also be noted that the conditions that are identified as contributing to the"cooldown are not conditions which prevent the secondary plant from being available for use as a cooldown path. The AFW flow control valve not going to the flow retention *settingincreases the AFW flow to the S/G, and in turn causes an increase in cooldown. This condition is corrected by the trip response procedure since the procedure directs the operator to control AFW flow as a method to stabilize the RCS temperature. With low-flow feedwater-preheating in'service, main steam is aligned to feedwater heaters 5 and 6 and is remotely regulated from the'control room.

Low-flow feedwater preheating is used until'turbine bleed steam is sufficient to provide the steam supply then the system is isolated. There are no automatic controls or responses associated with the regulating valves, so when a trip occurs, operators must close the regulating valves to secure the steam source. Until the steam regulating valves' are closed, this is a steam load contributing to a cooldown; The low-flow preheating'steam supplies are identified in the trip response procedure since they are a CNP specific design issue. '

The actions taken to control RCS cooldown were in accordance with the'plant procedure in response to the trip. The primary reason that the MSIVs were required to be closed was due to the low level of decay heat present following a 40 day forced outage. The closure of the MSIVs was to control the cooldown as directed by plant procedure and not to mitigate an off-normal condition or for the safety of personnel or equipment. With the low decay heat present following the 40 day forced outage, there would not have been a need to reopen the MSIVs

.3

FAO LOG DRAFT TempNo. PI - Question/Rcsponse Status Plant/ Co.

prior to recommencing the startup.

Should the reactor trip described above be counted in the Unplanned Scrams with Loss of Normal Heat Removal Performance Indicator?

Response

Yes. The licensee's reactor trip response procedure has an "action/expected response" that reactor coolant system temperature following a trip would be stable at or trending to the no-load Tavg value. If that expected response is not obtained, operators are directed to stop dumping steam and verify that steam generator blowdown is isolated. If cooldown continues, operators are directed to control total feedwater flow. If cooldown continues, operators are directed to close all steam generator stop valves (MSIVs) and other steam valves.

During the unit trip described, the #4 steam generator auxiliary feedwater flow control valve did not reposition to the flow retention setting as expected (an off normal condition). In addition, although control room operators manually closed the low-flow feedwater preheat control valves that were in service, leakage past these valves (a preexisting degraded condition identified in the Operator Workaround database) also contributed to the cooldown. Operator logs attributed the reactor system cooldown to the #4 AFW flow control valve failure as well as to steam being supplied to low-flow feedwater preheating. As stated above, the trip response procedure directs operators to control feedwater flow in order to control the cooldown. Operator inability to control the cooldown through control of feedwater flow as directed is considered an off normal condition. Since the cooldown continued due to an off normal condition, operators closed the MSIVs, and therefore this trip is considered a scram with loss of normal heat removal.

34.6 IE02 Question: 3/20 Introduced STP Should the following event be counted as a scram with loss of normal heat removal? 3/20 Discussed STP Unit Two was manually tripped on Dcc. 15, 2002 as required by the off normal procedure 6/18 Discussed; Question to be revised to for high vibration of the main turbine. Approximately 17 minutes after the Unit was manually reflect discussion tripped main condenser vacuum was broken at the discretion of the Shift Supervisor to assist in 7/24 Discussed slowing the turbine. Plant conditions were stabilized using Auxiliary Feedwater and Steam Generator Power Operated Relief Valves. Main Feedwater remained available via the electric motor driven Startup Feedwater pump. Main steam headers remained available to provide cooling via the steam dump valves. At any time vacuum could have been reestablished without diagnoses or repair using established operating procedures until after completion of the scram response procedures.

Scrams with a Loss of Normal Heat Removal performance indicator is defined as "The number of unplannedscramis while critical, both nianual and automatic, during the previous. 12 quarters that wvere eithercaused by or involved a loss of the nonralheat removal path priorto establishing reactorconditions that allow use of the plant's nonnallong term heat removal systems. " This indicator states that a loss of normal heat removal has occurred whenever any of the following conditions occur: loss of main feedwater, loss of main condenser vacuum, closure of the main steam isolation valves or loss of turbine bypass capability. The determining factor for this indicator is whether or not the normal heat removal path is available, not whether the operators choose to use that path or some other path.

The STP plant is designed to isolate main feedwater after a trip by closing the main feedwatcr control valves. The auxiliary feedwater pumps are then designed to start on low steam generator levels. This is expected following normal operation above low power levels and in turn provides the normal heat removal.

... . . . ... . . .~

FAO LOG DRAFT TempNo. I PI I Question/Response I Status PlantCo.

This design functioned as expected on December 15, 2002 when the reactor was manually tripped due to high turbine vibration. Normal plant operating procedures OPOP03-ZG-0006 (Plant Shutdown from 100% to Hot Standby) and OPOP03-ZG-OOOI (Plant Heatup)'state if Auxiliary Feedwater is being used to feed the steam generators than the preferred method of steaming is through the steam generator power operated relief valves. This can be found in steps 7.4 and 7.5 of OPOP03-ZG-0001 and steps 6.6.5 and 6.6.10 of OPOP03-ZG-0006. The note prior to 6.6.10 states "the preferred methodfor controlling SG steaming rates while feeding with AFIV is wiith the SG POR Vs".

The normal heat removal path as defined in NEI 99-02 Revision 2 was in service and functioning properly for seventeen minutes after the manual reactor trip and would have continued to function had not the shift supervisor voluntarily broke condenser vacuum and closed the MSIV's. Interviews with the shift supervisor showed that the decision to break vacuum was two part. 1) Based on experience and reports from the field it was known that vacuum would need to be broken to support the maintenance state required for the main turbine and at a minimum to support timely inspection. 2)This would assist in'slowing the turbine. The decision to break vacuum was not based solely on mitigating an off-normal condition or for the safety of personnel or equipment. Because Auxiliary Feedwater system'had actuated and was in service as expected, the decision was made to use Auxiliary Feedwater and steam through the SG PORVs. As stated earlier, this is the preferred method of heat removal if the decision to use Auxiliary Feedwater is employed as suplported by the normal operating procedures while the plant is in M6de 3. Main" feedwater'remained available via the electric motor driven Startup Feedwater pump and the main steamn headers remained available to provide cooling via the steam dump valves if required. Discussion with the shift supervisor showed he was confident that at any time vacuum could have been readily recovered from the control room without the need for diagnoses or repair using established operating procedures if the need arose. An-outside action would be required in drawing vacuum in that a Condenser Air Removal pump would require starting locally in the TGB. This is a simplistic, proceduralized and commonly performed evolution. Personnel are fully confident this would have been performed without incident if required.

Closing the MSIVs and breaking vacuum as quickly as possible is not uncommon at STP. For a normal planned shutdown MSIVs are closed and vacuum broken within four to six hours typically tosupport required maintenance in the secondary. If maintenance in the secondary is known to be critical path than vacuum has been broken as early as three hours and fifteen minutes following opening of the main generator breaker. The only reason ihat'vacuum is not broken sooner is because in most cases it is needed to support chemistry testing.

By limiting the flow path as described in NEI 99-02 for normal heat removal there is undue burden being placed on the utility. Only recognizing this one specific fl6w path reduces operational flexibility and penalizes utilities for imparting conservative decision making.

Conditions are established immediately following a reactor trip (100% to Mode 3) that can be sustained indefinitely using Auxiliary Feedwater and steaming through the steam generator PORVs. This fact is again supported in the stations Plant Shutdown from'100% to IHotstundbyHot standhv and Plant Heatup normal operating procedures. The cause of a trip the intended forced outage work scope, or outage duration varies and inevitably will factor into which method of normal long term heat removal is best for the station to employ shorftl 5

FAQ LOG DRAFT TcnpNo. PI ' Qucstion/Response ' ' ' Status Plant/ Co.

following a trip. - .

Response

The ROP working group is currently working to prepare a response:;'

Licensee Proposed Response:

NO. Since vacuum was secured at the discretion of the Shift Supervisor and could have' been restored using existing normally performed operating procedures, the function meets the

.________ intention of being available but not used.

35.7 EP03 Question: 8/21 Introduced Generic Can the licensee modify the ANS testing methodology when calculating the site 9/25 Tentative Approval. The response will be value for this indicator? modified to state that the methodology may be Response: changed once a 50.54 (q) has been completed Yes. Page 95 line 19-23 of NEI 99-02 will be modified as follows: ' and a letter sent to FEMA requesting the Tietestin of tile public alert and notificationsystem shall meet thle requirements of tchange.

Tilhetn fteulcaetadntfcto ytn hl etterqieet fthe 10/23 Modification proposed 9/25 deleted.

licensee's FEWM approved Alert and Notification System (ANS) design report and suportint e Tentative Approval FEMA approval letter. Changes to the activation anti/ortesting methodoloev shall receive 1214 Discussed revised wording. Awaiting FEMA approval priorto implementation and shall be noted in the licensee's quarterly PI Discussedw ith wdgA1 report in the comment section Siren systems may be designed with equipment redundancy, with FEMA.

multiple signals or feedback capability. It may be possible for sirens to be. activated from multiple control stations or sienals. If the use of redundant control stations or multiple signals is in approved procedures and is part of the actual system activation process, then activation.

from either control station or any sienal should be considered a success. .  :

Note: If prior to this FAQ response, a plant changed their testing methodology without prior FEMA approval, it is not necessary to recalculate their past PI data from ihe time.of thexchange, so long as they subsequently obtain FEMA approval. However, those plants still need to update the affected PI data report by noting the change in the comment section.

35.8 MS03 Question: ' 9/25 Introduced Beaver NEI 99-02 states that Planned Unavailabie Hours include testina. unless thie "function can be 10/23 Discussed Valley promptly restored ... by an operator in the control room". The guideline further states that 12/4 Discussed. Question being revised.

"restoration actions must be contained in a wTitten procedure. must hb uncomplicated (a single action or a low simple acctions). and must not require diagnosis or rWair". "The inient ;.. is to allow licensees to take credit for restorafion actions that are virtually cerfain to be su&cessful (i.e.. probability nearly equal to l) during accident conditions".

In the following scenario, a motor driven auxiliary feed pump with an auto start feature is placed in "oull-to-lock" for performance of a calibration procedure on the recirculation valve flow transinitter. Only the positioning of the pumn's control switch affected its availability.

A licensed reactor operator in flhc control room was briefed on tlie manuial pump restoration task. The prc-evolution briefin, to restore this pump to automatic status was completed by the Senior Reactor Operator. The "balance of plant" reactor operator was designated as the owner of this task. All crew mcinbers were briefed of tlie need to retiuri the pump tlo automatic conirol. This action is uncomplicated in that it is a single action (i.e. remove theI pump friom pull-to-lock) and does not require diagnosis.

Restoration acti(ins are contained within three different procedures. 'lie Precautions and Limitation's section of the calibration procedurc for the recirculation valve flow transmitter states that "the Control Room Operator'shall be briefed and assigned responsibiliLv for restoring

________ __-__.: the pump (ite. remivine fromn pull-to-lock to automlatic a t1 control if ipluet is needed o --

6

FAQ LOG DRAFTC TempNo. PI Question/Response - Status Plant/ Co.

perform il's safety function". directs the performer to inform the control room operator to align the control switch for the auxiliary feed pump in accordance with its "normal system arraneement" per ihe current plant conditions. The conduct of operations procedure;' which governs operator performance at all times. specifies "anytime valid plant conditions indicate a need for. .. Saretv System actuation. and the actuation fails to automatically occur. the operator is required to manually initiate the protective action". That is, if there is a need for the auxiliarv feedwater pump to start, the operator is to manually ensure a pump start is satisfied hbyaking the switch out of pull to lock. Simulator training is used to re-enforce this expectation. Finaliv.

this pump is only required to operate during an event requiringf use of the Emergency Operating Procedures and instructions are contained within this network to direct the operator to verify and/or initiate pump operation.

In this example. can the manual operator action he credited in place of the automatic pump start function for continued pump availibility2

Response

36.1 IE02 Question:: - - 9/25 Introduced and discussed Quad With the unit in RUN mode at 100% power, the control room received indication that aReactor Cities Pressure Vessel relief valve was open. After taking the steps directed by procedure to attempt to reseat the valve without success,'operators scrammed the reactor in response to increasing suppression pool temperature: Following the scram, and in response to procedural direction to.

limit the reactor cooldown rate to less than 100 degrees per hour, the operators closed the Main  : ..-..

Steam Isolation Valves (MSIVs)." The operators are trained that closure of the MSIV's to limit cool down rate is expected in order to minimize steam loss through normal downstream'.

balance-of-plant loads (steam jet air ejectors, offgas preheaters, gland seal steam).

At the time that the MSIVs were closed, the reactor was at approximately 500 Osig.' One half hour later, condenser vacuum was too low to open the turbine bypass valves and reactor pressure was approximately 325 psig. Approximately eight hours after the RPV relief valve opened, th'e RPV relief valve closed with reactor pressure at approximately 50 psig. This information is provided to illustrate the time frame during which the reactor was pressurized and condenser vacuum was low.

Although the MSIVs were not reopened during this event, they could have been opened at any time. Procedural guidance is provided for reopening the MSIVs. Had the MSIVs been' '

reopened within approximately 30 minutes'of their closure, condenser vacuum was sufficient to allow opening of the turbine bypass valves. If it had been desired to reopen the MSIVs later than that, the condenser would have been brought back on line by following the normal startup procedure for the condenser.

As part of the normal startup procedure for the condenser, the control room operator draws vacuum in the condenser by dispatching an operator to the mechanical'vacuum pump. The operator starts the mechanical vacuum pump by opening a couple of manual valves and operating a local switch. All other actions, including opening the MSIVs and the turbine bypass valves, are taken by the control room operator in the control room. It normally takes between 45 minutes and one hour to establish vacuum using the mechanical vacuum pump.

The reactor feed pumps and feedwater system remained in operation'or available for operation throughout the event. The condenser remained intact and available and the MSIVs were available to be opened from the' control room throughout the event. The normal heat removal 7

FAO LOG DRAFT --

Tem No. PI Question/Response Status Plant/ Co.

path was always and readily available (i.e., use of the normal heat removal path required only a decision to use it and the following of normal station procedures) during this event.

Does this scram constitute a scram with a loss of normal heat removal?

Response

No. The normal heat removal path was not lost even though the MSIVs were.maniually closed to control cooldown rate. There was no leak downstream of the MSIVs, and reopening the MSIVs would not have introduced further complications to the event. The normal heat removal path was purposefully and temporarily isolated to address the cooldown rate, only. Reopening the normal heat removal path was always available at the discretion of the control room operator and would not have involved any diagnosis or repair.

Further supporting information:

The clarifying notes for this indicator state: "Loss ofnormal heat removal path means the loss of the normal heat removal path as defined above. The determining factor for this indicator is whether or not the normal heat removal path is available, not whether the operators choose to use that path or some other path." In this case, the operator did not choose to use the path through the MSIVs, even though the normal heat removal path was available.

The clarifying notes for this indicator also state: "Operator actions or designfeatures to control the reactorcooldown rate or water level, such as closing the main feedwater valves or closing all MSIVs, are not reported in this indicator as long as the normal heat removal path can be readily recovered from the control room without the need for diagnosis or repair." In this case, the closing of the MSIVs was performed solely to control reactor cooldown rate. It was not performed to isolate a steam leak;. There was no diagnosis or repair involved in this event. The MSIVs could have bccn reopened following normal plant procedures 36.2 IE02 Question: 9/25 Introduced and discussed Peach Should an "Unplanned Scram with a Loss of Normal Heat Removal" be reported for the' Peach Bottom Bottom Unit 2 (July 22, 2003) reactor scram followed by a high area temperature Group'l isolation?

Description of Event:

At approximately 1345 on 07/22/03, a Main Generator 386B and 386F relay trip resulted in a load reject signal to the main turbine and the main turbine control valves went closed. The Unit 2 reactor received an automatic Reactor Protection System (RPS) scram signal as a result of the main turbine control valves closing. Following the scram signal, all control rods fully inserted and, as expected, Primary Containment Isolation System (PCIS) Group II and III isolations occurred due to low Reactor Pressure Vessel (RPV) level. The Group III isolation includes automatic shutdown of Reactor Building Ventilation. RPV level control was re-established with the Reactor Feed System and the scram signal was reset at approximately 1355 hours0.0157 days <br />0.376 hours <br />0.00224 weeks <br />5.155775e-4 months <br />.

At approximately 1356 hours0.0157 days <br />0.377 hours <br />0.00224 weeks <br />5.15958e-4 months <br />, the crew received a High Area Temperature alarm for the Main Steam Line area. The elevated temperature was a result of the previously described trip of the Reactor Building ventilation system. At approximately 1358, a PCIS Group I isolation signal occurred due to Steam Tunnel High Temperature resulting in the automatic closure of all Main Steam Isolation Valves (MSIV).Following the MSIV closure, the crew transitioned RPV pressure and level control to the High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) systems. Following the reset of the PCIS Group II and I1isolations at approximately 1408, Reactor Building ventilation was restored.

At approximately 1525, the PCIS Group I isolation was reset and the MSIVs were o cned.

FAQ LOG DRAir TemnpNo. Pi I Question/Response - Status 0Pla Co.

Normal cooldown of the reactor was commenced and both reactor recirculation pumps were restarted. Even though the Group I isolation could have been reset following the Group IIIIII reset at 1408, 'the crew decided to pursue other priorities before reopening the MSIVs including:

stabilizing RPV level and pressure using HPCI and RCIC; maximizing torus cooling; evaluating RCIC controller oscillations; evaluating a failure of MO-2-02A-53A "A" Recirculation Pump Discharge Valve; and, minimizing CRD flow to facilitate restarting the Reactor Recirculation pumps.

Problem Assessment:

It is recognized that loss of Reactor Building ventilation results in rising temperatures in the Outboard MSIV Room. The rate of this temperature rise and the maximum temperature attained ate&'ec6erbated by summertime temperature conditions. When the high temperature isolation occurred, the crew immediately recognized and understood the cause to be the loss of Reactor Building ventilation.' The crew then prioritized their activities and utilized existing General Plant (GP) and System Operating (SO) procedures to re-open the MSIVs.

Reopening of the MSIVs was:

. easily facilitated by restarting Reactor Building ventilation,

• completed from the'control room using normal operating procedures

' without the need of diagnosis or repair, -

Therefore, the MSIV closure does not meet the definition of "Loss of normal heat removal path" provided in NEI 99-02, Rev. 2, page 15, line 37, and it is appropriate not to include this event in the associated performance indicator- Unplanned Scrams with Loss of Normal Heat Removal. -l Discussion of specific aspects of the event:

Was the recognition of the condition from the Control Room?

• Yes. Rising temperature in the Outboard MSIV Room is indicated by annunciator in the main control room. Local radiation levels are also available in the control room.'During the

- July 22, 2003 scram, control room operators also recognized that the increase in temperature was not due to a steam leak in the Outboard MSIV Room because the'local radiation monitor did not indicate an increase in radiation levels. Initiation of the Group I

'isolation on a Steam Tunnel High Temperature is indicated by two annunciators in the control room.: ' '

Does it require diagnosis or-was it an alarm?

• The event is annunciated in the control room as described previously.:

Is it a design issue?

• Yes. The current Unit 2 design has the Group I isolation temperature elements closer to the Outboard MSIV Room ventilation exhaust as compared to Unit 3. As a result, thie baseline temperatures, which input into the Group I isolation signal, are higher on Unit 2 than Unit 3.

Are actions virtually certain to be successful?

• The actions to reset a Group I isolation are straight forward and the procedural guidance is provided to operate the associated equipment. No diagnosis or troubleshooting is required.

Are operator actions proceduralized?

• The actions to reset the Group I isolation are delineated in General Plant procedure GP-8.A "PCIS Isolation-Group I." The actions to reopen the MSIVs are contained in System 9

FAQ LOG DRAFT TempNo. PI Questionl/Response Status Plant/ Co.

Operating procedures SO 1A.7.A-2 "Main Steam System Recovery Following a Group I Isolation" and Check Off List SO IA.7.A-2 "Main Steam Lineup After a Group I Isolation." These procedures arc performed from the control room.

How does Training address operator actions?

• The actions necessary for responding to a Group I isolation and subsequent recovery of the Main Steam system are covered in licensed operator training.

Are stressful or chaotic conditions during or following an accident expected to be present?

• As was demonstrated in the event of July 22, 2003, sufficient time existed to stabilize RPV level and pressure control and methodically progress through the associated procedures to reopen the MSIVs without stressful or chaotic conditions

Response

The Peach Bottom Unit 2 July 22, 2003 reactor scram followed by a high area temperature Group I isolation should not be included in the Performance Indicator - "Unplanned Scram with a Loss of Normal Heat Removal." This specific MSIV closure does not meet the definition of "Loss of normal heat removal path" provided in NEI 99-02, Rev. 2, page 15, line 37, in that the main steam system was "easily recovered from the control room without the need for diagnosis or repair. Therefore, it would not be appropriate to include this event in the associated performance indicator- Unplanned Scrams with Loss of Normal Heat Removal.

36.3 EP01 Question: 12/4 Introduced and Te ive Appr al Sequoyah In April 2003, Sequoyah Operations decided to change from marking "Drill" to marking "Actual" on the notification forms used in LOR simulator sessions to enhance realism.

Emergency Preparedness was unaware of the policy change at the time since only Annual License Exam simulator sessions contribute to DEP at Sequoyah.

A LOR trainee questioned the use of "actual" in mid May 2003 and this question was forwarded to Emergency Preparedness for resolution. EP reevaluated the policy of using "Actual" based on the recent Palisades OE and FAQ 338. Sequoyah decided to change its practice back to marking the notification forms as "Drill" during LOR Training as of June 2003. The expectation of how to mark notification forms during LOR simulator training was reviewed with the personnel but notification opportunities in the September NRC Exams were subsequently inconsistently marked as either "drill" or "actual" consistent with the trainee understanding of the accuracy expectation of no blank forms. There were 13 notification opportunities with 7 marked "Actual" and 6 marked "Drill". The inconsistent form completion was discovered during EP's review of PI data from the LOR classes for the last three weeks of September in preparing the 3 rd Quarter 2003 PI results.

Reasonable assurance exists that the same error would not have occurred for an actual emergency since it is implicitly clear that "Actual" is to be marked during an actual event. The inconsistent form completion is addressed in the Corrective Action Program.

FAQ 338 provide Palisades with the one time site specific allowance to count the forms as accurate with either drill or actual as long as one or the other was checked. The bases for this decision was that the lack of providing clear expectations to the LOR simulator crews on marking drill or actual event on the notification form is indicative of a programmatic weakness 10.

- . . I PAO LOG. DRAFT TempNo. PI Question/Response Status Plant/ Co.

and not a performance weakness.

Due to the short duration from the resolution of FAQ and 338 and the September NRC. exam and the infrequency of the performance of simulator training EP drills, is it acceptable to apply the similar resolution to SQN also on a one time basis? This would allow the notifications to be considered as accurate as long as either actual or drill was selected (completing all the appropriate blocks on the notification form).

Proposed Response:.

Yes. For this occurrence only (and only on a one-time basis), the plant may treat the notifications as accurate as long as either "actual" or "drill" was selected (compieting all the appropriate blocks on the notification form).

For all PI submittals for all plants for the second quarter of 2004 and beyond, all notification forms must be marked consistently, either "drill" or "actual" in accordance with the*

requirements of the licensee's emergency preparedness program.

36.5 OR] Oucstion: 1/22 Introduced Voetle Two in(lividuals enter an area of containment. previously surveyed and posted as a radiation area. They comply with all applicable RWPs anti procedures. Additionally. they are continuously. remotely monitored by teledosimetrEy (Electronic Personnel Dosimeter. EPD).

Durine the cntn. their EPDs alarm on dose rate, which had been prcset to alarm at 150 mremnhr. The individuals detect the alarm and immediatcly exit the arca to notify HP.

Concurrently. HP technicians maning the Central Alarm Station delect the alarm condition ahd dispatch a nearby rovine HP technician to the area to confinn the alarm and vcrify wvorker protcction. The area is inmiicdiaiclv suivevcd bv HP and found to contain dose rates or approximately 2 rem/hr at 12 in6hcs'the e arca is rcposted as a Locked Vigih Radiation Area (1,HRA). Investigation of tfie event reveals that the area entered contains a length of-pipine and a valve through which 1l1e reactor cavitv is filled and drained. ShortTi before thisecntry. the reactor cavitv had been filled via this piPe. Thc specific area's dose rate hid becn'confirmed bv past experience to he unaffected hy cavity filling and therefore was not flagecd for resurvey followine the fill evolution. It is hypothesized that a hot particle dislodged from an upstream location during filling and mierated into the vicinity of the work location 12rior to the worker's entry. The samc area had been occubied numerous times after the last survey, before filling.

with no problems. Should this be counted as a performance indicator event?

Furthermore. should any event he counted aiainst this PT in which an entry into an area occurs whlere the'dose rate increased (to greater than I rem/hr) in a reasonably unanticipated manner?

Rcsponse: -

This is not a PI occurrence for either instance questioned above. particularly for a case where the area has been specifically considered for a possible dose rate increase. Howvever, instances where the potential dose rate change is not considered and should have been. would be a PT

.__________ ________ event. Additionally, the unanticipated dose criteria would still ajpjyL .

.S 11,

FAQ LOG DRAFT __

TcmpNo. PI Question/Response AP Status Plant/ Co.

36.6 IE(3 Ouestion: 1l/22 Introduccd Salcm NEI 99-02 states that anticipatory power reducitions inende(d to reduce Me impact of external events such as hurricanes or ranme fires threatening offlsite power lin/-arc excluded.

On Sepnemehr 20. 2003. Salem I and 2 wcre manually shilutdo due to switchyard arcing from salt buildup on insulators in the switchyard. The salt builditwas due to unusuaVl mccorologzical conditions (hurricane force winds, will n lrain). These conditiojis led go an abnormal huildup of salt from the Delaware River to beleposited on the insulators. The shutdowns were not conducted in response to any existing or immendiate equiimeilt problems.

The shutdowns were initiated to address the impact of an external event, that manifestcd itsclf in an unexpected maliner and to alleviale nuclear plant safety concerns arising froin an external event outside the control of the plant.

Shoukl these shutdowns he counled as inpplanned powcr reductions?

Response: t No. These power reductions are c nsidereO t an aus y were taken prior l any equipmcilt failures or electrical system proceclivT actuations at Salem I or 2. were caused by an unusual meteorological condition, and were taken to alleviate iiuclear plant safety concerns _risine from an cxternal event outside the control or the plant.

36.7 MS(I--Qtestion (Appendix D): 1/22 Introduced Catawba 04W Promosed Overhaul Exemption for IUnavailahility Hours Incurre d On Unit 2 Safetv Systems Due To Planned Ovcrhaul of Unit I Nuclear Service Witer System (NSWSV Calawba Nuclear Stalion (CNS) rcfurbished the B Nuclear Service Water Svstem (NSWS) punip during a recent refucline oultae. Unit I was defueled and Unit 2 at power operation during this activity. Technical Specifications provided for an allowable outagc timn6 sufficicnt to accommodate the overhatil hours associated with the pump replacement. Catawba has a shared NSWS betweeni both units such that the B train pumnps for both tinits (I B and 2B NSWS Vmnips) share a common intake pit andi disclhargc header. Reinovinge and reinstalling I B NSWS pump for refurbishiment rendered 2B NSWS puii unavailable.

Removal of the I B NSWS Loump required making the 2B NSWS pump inoperable fii r 2.6 hotirs in order to disconnect a submlereed sulpport and inspect the nuclear service water pond intake.

Oncc the [B NSWS punmp was removed from the pit. the 2B NSWS pump was restored to operable status and Unit 2 safety systems were restored to fully operable status. After the IB NSWS puoinV refurbishment was compiete. the 2B NSWS pump was again rcndered inoperable For reinstallation of tihe I B NSWS pump. The reinstallation was originally scheduled for 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> buit tuikhmiLondue to comoliott*os. Catawvbi is seekinLe to exclude the unavailahilty that was incurred from the aclu 2.6 ldur: r~ uired to remove the unip and the 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> oricinally sche(diuled for reinstalaitrr .6lhoLirs total).

Alth6ugh the NSWS is not a monitoied system tinder NEI 99-02 guidance. its unavailabilitv does affect various systems and coimponents. many of whichl are considered minjor components by the definition contained in FAQ 219 (diesel enuines, heal exchangers. and pitnps). The specific performance indicators affected by unavailability of tile NSWS are Emereency AC.

Hi!ch

'1 ~' Pressure

' Safetv Iniection.

-- ' ' Residual

• ' Beat.-' Remova1.'and

.'- !- Auxiliarv Feedwater. If ihe

'-_'._.. -J I ..

I_

12

FAQ LOG DRAFT :_--

TempNo. Pi Question/Response Status Plant/ Co.

rquesed hours for this overhamul orthe lB NSWS pump cannot be excluded it would result in 22.6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> unavailability on *B' train orccih of the four monitored systcms. .

NET 99-02 states that "overhatil exemption does not normally apply 6 support systems except under uniquc plani-specific sittimions on a case-by-case basis. Thccircumstances of each situation arc dirferent and should bc identified to the NRC so that addetermiinationi can be made.

Factors to be takeli into consideration for an excmiption for support systems includc (a) thc results of a quantitative risk assessmenlt (b) thC expected improvcment in plant performance as a result orthe overhaul activity. and (c) the net change in risk as a result of the overhaul activity." The followinlg information is provided iw tlie NE zuidance..

QUANTITATIVE RISK ASSESSMENT Duke Power has used a risk-informed approaci to determine therisksignificaice of taiine the 'B' loop of NSWS out of service for up to 22.6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> within its current technical specification limit of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The acceptance guidelines civen in the EPRI PSA Applications Guide vere used to determine the significance of ihe short-term risk increase from the outagc.

The NSWS outace didl not create any new core damage sequences not currently evaluated hy the existing PRA model. The resultin Incremental Conditional Core Damage Probability (ICCDP) was 1.2E-06. a low-to-moderate increase in the CDF. and was acceptable based on consideration of teie non-quantifiable factors involved in the contingencyv niehsures ihat were implemented during the overhaul. Bared on the expected increase in overall systein reliahilitv of the NSWS. an overall increase in the safetv of both Catawba units is expected.

Contingcncy measures during the oiverhaul included Component Cooling WVater'System cross train alignment which allowed the "A" train to supply cooling to the High Pressure Iniection..

and Auxiliary Feedwater pump motor coolers during the "B" train work. The RN pine inspection evolution also included the following protective measilres:

• "A" train EDGs were protected throughout the evolution.

. The Unit 2 transformer yard was protected throuchout the evolution.

. The "A" train equipment supported by RN was protected.

• No maintcnance or testine on operable offsitc power sources.

• All tcsting and maintenance on the operablc train rescheduled to other time periods.

. No work or testing that could affect the SSF or SSF Diesel Generator.

. No work-or testing that could affect the Turbine-Driven AFW Pump on Unit 2.

EXPECTED IMPROVEMENT IN PLANT PERFORMANCE The NSWS pumps are refurbished on a specified interval to assure continued. reliable operation. The NSWS pump refurbishment is cxpected to increase overall system reliability.

NET CHANGE IN RISK AS A RESULT OF THE OVERHAUL ACTIVITY Increased NSWS train unavailability as a result of this overhaul did involve an increase in the probability or consequences of an accident previously evaluated during the time frame the NSWS header wvas out of service for pump refuirbishment. Considering the small time frame of the 'B' NSWS train outage with the expected increase in reliability. expecled decrease in future NSWS unavailability as a result of the overhaul, and the contineency meastres that vere

____1_7______ +/-r~mvt33 ... mprai nmA nn^. rti

. .3 n *-3.~t tiC Url, -ti*,-h-l3t LUCS.IVE~ . EUU.-t I --- I . I.- - I 11- ..l.VuuY"!-- I 13

FAQ LOG. DRAFT TempNo. P1 Question/Response Status Plant/ Co.

Rcsponse:

For this phant specific situation. Vlanned overhaul hoLirs for the nuclear service water support system may be cxcluded from the coimputation of monitored system unavailability. Such cxexnptiins may be aranted O(ia casc-bv-casc hasis. Factors considered for this approval include (I) thc results of a muantmiative riskl assessment of the overhauil activity. (2) tiec xpected improvenicni in plant performance as a result of thc overhaul, and (3) the net chance in risk as a rcsult of the overhaul.

36.8 I F02 Qustion: . 1122 Introduced Ginna On Auizust 14. 2003 Ginna Stalion scrammed due to the wide spread mrid disturbance in the Norlheast United Staics. SubseQuent to the scram. Main Feedwater Isolation occurred as desiened on low Tave coincident with a reactor trip. However. due to voltage swings from ihc erid disturbance. instruimnent variations caused thc Advanced Dieital Feedwater Control System (ADFCS) to transfer to manual control. This transfer overrode tihe isolation signal causinLg the Main Fcedwater Reculation Valves (MFRVs) to fo to, and remain at. the normal or nominal automatic demand position at the time of the transfer. resulting in an unnecessary feedwater addition. The Feedwater addition was terminated when the MFRVs closed on the hidi-hiah stcamin encrator level (85%) signal. Operators conservatively closed the MSIVs in accordance with the procedure to initiate a hihsi water level condition in the Steam Generators. Decay heat was subsequently removed usine thc Atmospheric Relief Valves (ARVs). Shdulild thc scram be countcd under time Pt "Unplanned Scramrs with Loss of NonnalHeat Removal?'

Response

No. Under clarifying notes. pace 16. lines 1 -22. NET 99-02 states: "Actions ordesign features to control tile reactor cool down rate or water level. such as closin tihe main fecdwater valves or closini, all MSIVs. arc not reported in this indicalor as lone as the nomial heat removal palh can be readily recovered fromi the control roon without the need for diagnosis or repair. However, operator actions to mitiate an off-norinal condition or kor the safety of personnel or equipment (xc.. closing MSIVs to isolate a stcain leak) are reported." In this case.

a ikedwater isolation signal hadl automatically closed the main feed reculating valves.

effectively mitifatine the high level condition. Manually closing the MSIVs was a cdnservative proceduire driven action. which in this case was not by itself necessary to protect personnel or equipmeni. Thc main feed regtulating valves wcre capable of being easily opcned from thc control room. and thc NISIVs were capable of heing opened from the control room (aftcr local action to bypass and equalize pressurc. see FAQ 303).

In addition. the causc of the high steam cncraltor level was due to *oltace fluctuations on tile offsite power *rid which resulted in the operators closing the MSIVs. Clarifying notes for this perfonrance indicator exempt scramns resultine in loss of all main feedwater flow. condeiiser vacuum, or turbine bypass capability caused by loss of offsite lvower. In this ease. offshe power was not lost. However. the disturbances in nrid voltagc affccted thc ADFCS system which started a chain of events which ulifimately resultel in tihe closure of the MSIVs.

36.9 IE02 Question: 1/22 Introduced Millstone Durinig stariul activitics Fldlowing a refueling outane on Millstone Unit 2 new moinoblock 2 turbine rotors were installed in thc l.P turbines, rcactor power was approximately I0~of rated

• thernma.l p rcedwater was beingt hsla c ncncrators hv the lurhine driven main 14.

FAQ LOG DRAFI _

TempNo. PI Question/Response Status Plant/ Co.

rccdwatcr pumps. tile main condenscrS %'cicin service. and the main turbine was being started up in preparation for plant startup. During main turbine startup. the turbine becan to cxperience high bearing vibrations before reaching its normal operating sneed of I 800 rpm. and was manually tripped. The bearing vibrations hegan to increase as the turbine slowed dlown following the trip. To protect the main turbine. the alarm respomSe procedure for hiih-jligh turbine vibration required the operators to manually SCRAM the reactor. isolate steam to the main condcnsers by closing the main steam isolation valves and to open the condenser vacuum breaker thereby isolating tie normal heat removal path to the main condensers. This caused the turbine driven main feedwater pumps to (rip. Following the reactor SCRAM.: the operators manually started the auxiliary feedwater pumnS to supply feedwater to the steal generators.

The atmospheric dump valves operated automatically to control reactor coolant system temperiture. by removing core decav heat and reactor coolant pump heat. The core decay heat load was very low during this event due to the length of the refueling outage and the fact that apnroximatelv one-third of t(ie fuel assemblies in the core had been replaced.

Ouestion: Does a SCRAM in which the normal heat removal path is manuallv isolated in accordance with plant procedures for protection ol non-safet' plant equipment count against this indicator?

Response

_ _ .I___________ _____ _

15