ML20059C117
| ML20059C117 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 11/20/1992 |
| From: | Sharon Hudson BOSTON EDISON CO. |
| To: | Kraft E BOSTON EDISON CO. |
| Shared Package | |
| ML20059C116 | List: |
| References | |
| FOIA-93-92 ESED92-167, NUDOCS 9401040386 | |
| Download: ML20059C117 (32) | |
Text
{{#Wiki_filter:' i Office Memorandum Boston Edison Company To: E.S. Kraft, Jr. From: S.D. Hudson Record Type A4.08 , Date: November 20, 1992 Dept. Doc. ESED92-167 Non-Safety Related
Subject:
REACTOR WATER LEVEL SPIKING STATUS REPORT Distribution: l R.A. Anderson E.T. Boulette W.S. Clancy J. Bellefeuille W.C. Rothert R.V. Fairbank l H.V. 0heim T. Sullivan D. Tarantino J. Rogers-BT S. Dasgupta-BT R. Cannon T. Trepanier R. Kelley-BT K. Kampschneider E. Almeida P.D. Smith L. Francis Approval for Release Outside Plant Dept. E.S. Kraf t, Jr. BACKGROUND: During the shutdown and cooldown on 10/24/92, reactor water level was continuously monitored with the EPIC Computer. Close communication was maintained with the ! Control Room. Spiking was observed to begin at approximately 350# on the "B" ECCS l l instruments. The characteristic signature which had been observed in the past was ' present during depressurization. The overall performance of the water level instrumentation was similar to past performance. A Group 1 Isolation occurred at approximately 160*F due to a maximum recorded spike of 29 inches (limited by instrument range). Water level was +21 inches at the time of this spike. All valves responded as designed due to the false high level signal. Spiking began at 63# on the "A" Side instruments. The "A" Side also performed as , expected. The maximum spike observed on the "A" Side was 17 inches. OfPLRABiliTY DETERMINATION FOLLOWING OCTOBER 24. 1992 SHUTDOWN: Reactor water level instrumentation remained operable during the shutdown and I cooldown on 10/24/92. An Operability Evaluation was performed by Engineering and Plant personnel in September 1992 which assumed the existence of non-condensible gas in the reference legs. This evaluation recommended operability criteria for the reactor water level instrumentation if notching were to occur during a plant shutdown. The ORC reviewed and concurred with the evaluation and was accepted by 1 Plant Operations. The evaluation assumed bounding notching characteristics which were then evaluated for their impact on the ability of systems to perform their , specified functions. The notching characteristics assumed in the evaluation bound l l the notching observed during the October shutdown. Therefore, the reactor water l l level instrumentation remains operable, j l l
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3 9401040386 930521 PDR FOIA ; LAMPERT93-92 PDR l '
I i . l ACTIONS DURING MCO #9:
-Measurement of instrument Bypass Valve leakage The Reactor vessel reference legs were tested under TP92-47. _ This pressurized the ;
reference leg and all instrument bypass valves to 20 psi. The test was performed on i the 'A' and 'B' reference legs. The 'B' side was completed first, and after 1 stabilization, a leak rate of zero was determined after 8 hours of test. On the 'A' side', pressure was applied between the root valve and the instrument I bypass valves. The total leakage observed was approximately 22 ml/ day. However, - leakage continued after all level transmitters had been valved out. The amount of - leakage past the instrument bypass valves and how much was leaking past the ,normally i open root valve could not be determined. No instrument bypass valves were replaced.
-Repair of External Leakage l The external leaks on the 'A' reference leg and 'B' reference leg were quantified _ :
prior to shutdown as approxititely .14 ml/ day and 97 ml/ day, respectively. Additionally, seepage had been identified at mechanical joints but'its too small to ; quantify. The identified leaks and seepage were tightened under a Maintenance Request and will be examined as part of Post-Work Testing after startup.
-Condensing Chamber Steam Drain Line Insulation ,
During a short outage in the spring of 1992, the insulation on the drain line (from condensing chamber to vessel) was removed from the 'B' side. It was originally , postulated that this action could mitigate the water level anomolies noted during ' vessel depressurization. The insulation was removed to increase the surface area available for condensation in order to increase the rate of steam flow into the i condensing chamber. Although it was recognized that this would increase the reate :, of dilute gas flow into the drain line, it was expected the corresponding increase ! in condensate flow returning to the vessel would sweep / scrub a disproportionately larger amount of concentrated gas. This was expected to slow the rate of gas ; accumulation so as to delay the onset of or prevent gas binding of the chamber. Unfortunately, the chamber temperature trends during operation and shutdown as well i as the instrument performance during the shutdown indicate that little if any . ! benefit was gained and the condensing chamber gas binding was not significantly retarded. , h s I r
However, during the October 1992 shutdown, the pattern and volume of level errors on f
'B' side instruments did not show any distinct improvement. Moreover, the !
insulation removal adds surface area for vapor condensation, potentially ;
- accelerating the inflow of' dilute gas into the condensing chambers and shortening !
l the period for gas accumulation and concentration in the chamber. Chamber : temperature trends during the last operating period tend to support this possibility. Previous operation with the insulation on 'B' side did not result in t more adverse level anomolies than observed in the October 1992 shutdown. Thus, the ' reinstallation of this insulation during MC0 #9 was implemented.
~
l EVALUATION OF ROOT CAUSE ANALYSIS: The instrumentation response was consistent with the non-condensible gas theory developed by Saul Levy, Inc. Additionally, ultrasonic detectors installed on the reference leg piping on the back of the 'B' ECCS Rack detected gases traveling up the piping during the spiking. Detectors on the 'A' side did not detect the gas l because the upper detector was not functioning. Therefore, it is now believed that the cause of the spiking is due to non- I condensible gases coming out of solution during depressurization. As the gas forms , a bubble and travels up the vertical sections of piping, the weight of the water in ! the reference leg is reduced and the transmitter indicates a higher level than. actual. When the gJ bubble reaches a horizontal section of piping, it has , negligible effect on the level transmitter output and indicated level returns to :' actual level. The characteristic " square wave" shape is a function of the geometry of the reference leg piping. At low reactor pressure, gas is being' released from multiple collection points at slightly different times. Therefore, the response takes on a ragged mountain peak shape. Three factors are necessary for the spiking to occur. These are: (1) a buildup of l non-condensible gases in the condensing chamber; (2) horizontal sections in the - , reference leg piping; and (3) leakage near the transmitters which cause the gas ; saturated water to migrate down the reference leg. Elimination of any one of these -i three factors should prevent the spding during normal reactor depressurization. 1 IMPACT ON GENERIC LETTER 92-04 RESPONSE: 4 GL 92-04 requested licensees to determine the impact of level errors caused by non-r condensible gas on automatic safety system response, Operator short and iong term actions, and Operator actions described in Emergency Operating Procedures. Boston l Edison performed a Plant Specific Safety Assessment in addition to ths Generic l Safety Assessment performed by the BWR Owner's Group. This safety assessment was
" reviewed by the ORC and approved by the Plant Department Manager . This assessment concluded that potential errors would have no affect on limiting FSAR transient and accident analyses, and in the event Operators are unable to determine water level, :
E0Ps provide clear direction for Operator actions. The notching caused.by non- ( condensible gas does not affect operability as described previously, nor does it affect the conclusions of the safety assessment contained in Boston Edison's response to GL92-04. l
i The testing and analysis program being performed by the BWROG is predicated upon the i existence of non-condensible gas in reference legs. ' The notching observed during j this shutdown confirms non-condensible gas buildup. The observed notching was ! consistent with our past experience and does not invalidate our response to Generic j Letter 92-04. Therefore, the proper course of action is to pursue the BWROG testing i and analysis program so the causes and effects of gas buildup can be determined and l fixed, i f necessary, j OPERABILITY EVALUATION FOR 2/3 CORE COVERAGE PERMISSIVE: Since 2/3 core coverage interlock is the only level device that must function after l reactor pressure has dropped to the point where degassing occurs, the operability of ; this function has been revisited in light of data obtained during the recent l shutdown and industry information. Experience from the recent shutdown and previous ; shutdowns provides empirical evidence that notching of 29 inches or more can occur. l The' root cause of level notching is now believed to be primarily due to non-condensibles. Although previous level responses during slow depressurizations reasonably compare with theoretically predicted level system responses, no validated industry analyses, plant specific analyses have been completed that can predict responses during rapid depressurizations. Theoretical performance must be benchmarked against real test data. Such testing is actively being pursued by the industry. Therefore, the magnitude of any error can not accurately be determined by analysis. l It should be noted that over 20 linear feet of reference leg volume, including both-horizontal and vertical sections, must be lost during a rapid depressurization to _ create 14 inches of continuous level error. This level error is already considered in establishing the set point for the 2/3 core coverage level switch. - t The potential for level errors should be considered lessened because the presence of non-condensibles relies on transport into the reference legs due to leakage. j External leakage is believed to be reduced from the leakage conditions that existed l during past operating periods. This eliminates one of the conditions necessary for rapid depressurization level error as discussed in NRC Generic Letter 92-04. Less- ; gas in the reference legs should decrease magnitude of the error due to rapid , depressurization. l The 2/3 core coverage condition is only expected for large recirculation pipe breaks. These breaks lead to level recovery to at least 2/3 core height since this ' is the level of the refloodable vessel volume. The 2/3 core coverage permissive prevents operators from inadvertently diverting LPCI flow to containment cooling if reactor level is less than 2/3 core height. Also, if LPCI flow has been diverted to containment cooling and reactor level drops to 2/3 core height, the containment cooling valves automatically close to redirect all LPCI flow to the reactor. E0Ps direct operators to maintain level above top of active fuel (TAF). 2/3 core coverage is 4 feet below TAF. Level errors of up to approximately 4 feet would not ; prevent operators from maintaining 2/3 core coverage. This level is adequate for core cooling.
Tech Spec Table 3.2.B indicates that the 2/3 core coverage interlock prevents inadvertent actuation of containment spray during accident conditions. The trip < device is set at the trip setting specified in the table. Water level errors do not affect the sensed level at which the Tech Spec switches actuate and Table 3.2.B is therefore satisfied. .llowever, Tech Spec Bases 3.2 indicates that the objective of . the specification is to prescribe the trip setting required to assure adequate [ performance. As shown below, under rapid depressurizations, the system performance is adequate to assure the core cooling function. This condition, therefore, represents a potential nonconformance with the FSAR design criteria for the system and not : noncompliance with Tech Specs. Water level. inputs to the 2/3 core ; coverage interlock function are expected to the extent practical and feasible, to be ; true measures of operational conditions and to respond correctly to the sensed condition over the expected range of magnitudes and rates of change. Level errors represent a departure from fully conforming with these criteria. This departure does not prevent the 2/3 core coverage interlock from detecting abnormal conditions with sufficient timeliness, precision, and reliability to assure that its specified safety functions can be performed. t flow diverson to containment spray represents roughly 25% of a single RilR pump's fl ow. The remaining LPCI flow to the reactor would still be well in excess of jet pump leakage (800 gpm per FSAR 3.3.6.5.2) and 2/3 core coverage would be maintained during spray diversion. It is also important to note that for large recirculation line breaks, at least one I core spray loop will be available assuming a worst single failure. Accounting for 800 gpm jet pump leakage, one core spray pump can maintain 2/3 core coverage and the effects of water level errors on the core cooling function are further diminished. Appendix K LOCA Analyses for PNPS indicate that massive core uncovery (e.g., more ! than 10 feet below TAF) for approximately 60 seconds can occur without exceeding 2200*F peak clad temperatures. The LOCA analysis is done assuming the reactor has just been shutdown due to the accident when fuel sensible heat and decay heat are still high and coolant temperature is high. Worst peak clad temperatures are for ' the recirculation suction line break with LPCI injection valve failure. Conservative analysis indicates this peak clad temperature to be 1821*F which provides margin to 2200"F. Operator actions to divert LPCI flow would not occur until the core had been reflooded with comparatively cool water and fuel sensible and decay heats had substantially decreased. Loss of injection at this time would lead to level reduction due to boiloffs and not due to depressurizatinn blowdown. Core spray flow and some LPCI flow will maintain 2/3 core height. Multiple failures must occur to cause a condition where no core makeup flow exists. Level errors of i up to five feet under this unlikely scenario will not lead to PCTs exceeding those in current LOCA analyses. l l l l 5-i l
The FSAR acknowledges some level. errors occur during design basis events. In-selecting reactor water level as. an input parameter to initiating safety functions, ; it is understood that some inaccuracy is inherent in the design. Deviations between actual and sensed level- are expected due to pressure and thermal density effects, reference leg flashing, coolant voiding, and-flow across instrument nozzles (see - - FSAR 7.8.5.2). In selecting level trip settings, FSAR 7.2.4 states that the " trip point selected is not the only value of the trip point which results in acceptable - results relative to the fuel or nuclear system process barrier. Trip setting selection is based on operating-experience and is constrained by the safety design- Li basis". As has been shown, trip actuations at levels different than assumed in accident analysis due to level errors do not lead to unacceptable results. , The potential for level error following a rapid depressurization is an industry-wide issue. Although the exact nature of the effects rapid depressurizations have on the. . 2/3 core coverage interlock has not been quantified by the ' industry (BWROG) or. Boston Edison, the available design margins, empirical plant data and reductions in reference leg leaks provide reasonable assurance that the 2/3 core coverage interlock will remain operable. , Performed By: ~ W h// v
- 1. //[>o[O Reviewed By: NwWA}pA. FOR David Lene 7e>r itjeccm rw/wof, FAX Recommends Approval: 1 )/2/h Nuc}yar Efigi r'ng Manag3 Rt/ P i l
Recommends Approval: _
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Pilgnm Nuclear Power Station Rock y HS Road Plymouth Massachusetts 02360 SPECIAL ORC MEETING NO. 92-100 LOCATION: Technical Support Center DATE: November 20, 1992 ATTENDEES: J.A. Seery, Chairman (SRO) T.A. Sullivan, Member (SRO) (Partial) P.T. Cafarella, Member J.D. Purkis, Member (Partial) J. Bellefeuille, Member P.D. Smith, Alternate (SR0) R.W. Green, /,lternate , S.D. Hudson, Alternate (Partial) i D.A. Montt, Alternate E.T. Boulette E.S. Kraft, Jr. e
'~
R.L. Cannon H.V. 0heim T.F. White J. Mcdonald (NRC) M.T. McLoughlin i K.J. Kampschneider li C.M. Jungclas ; J.M. MacDougall ; l Ouorum reauirements satisfied PRINCIPLE TOPICS: 1
- 1. Operability Evaluation
- 2. Temporary Modification i
- 3. Procedures I
6 \
/
SPECIAL.0RC MEETING NO. 92-100
- l. OPERABILITY EVALUATION FOR 2/3 CORE COVERAGE PERMISSIVE:
Since 2/3 core coverage interlock is the only level device that must function after reactor pressure has dropped to the point where degassing , occurs, the operability of this function has been revisited in light of data obtained during the recent shutdown and industry information. - Experience from the recent shutdown and previous shutdowns provides empirical evidence that notching of 29 inches or more can occur. The root cause of level notching is now believed to be primarily due to noncondensibles. Although previous level responses during slow : depressurizations reasonably compare with theoretically predicted level i system responses, no validated industry analyses, plant specific ! analyses have been completed that can predict responses during rapid depressurizations. Theoretical performance must be benchmarked against real test data. Such testing is actively being pursued by the industry. Therefore, the magnitude of any error can not accurately be determined by analysis. It should be noted that over 20 linear feet of reference leg volume, - including both horizontal and vertical sections, must be lost during a ! rapid depressurization to create 14 inches of continuous level error. This level error is already considered in establishing the set point for the 2/3 core coverage level switch. The potential for level errors should be considered lessened because the presence of non-condensable relies on transport into the reference legs due to leakage. External leakage is believed to be reduced from the leakage conditions that existed during past operating periods. This eliminates one of the conditions necessary for rapid depressurization level error as discussed in NRC Generic Letter 92-04. Less gas in the reference legs should decrease magnitude of the error due to rapid depressurization. The 2/3 core coverage condition is only expected for large recirculation pipe breaks. These breaks lead to level recovery to at least 2/3 core height since this is the level of the refloodable vessel volume. The : 2/3 core coverage permissive prevents operators from inadvertently ; diverting LPCI flow to containment cooling if reactor level is less than - 2/3 core height. Also, if LPCI flow has been diverted to containment cooling and reactor level drops to 2/3 core height, the containment cooling valves automatically close to redirect all LPCI flow to the reactor. E0Ps direct operators to maintain level above top of active fuel (TAF). 2/3 core coverage is 4 feet below TAF. Level errors of,up to approximately 4 feet would not prevent operators from maintaining 2/3 core coverage. This level is adequate for core cooling. Tech Spec Table 3.2.B indicates that the 2/3 core coverage interlock prevents inadvertent actuation of containment spray during accident conditions. The trip device is set at the trip setting specified in the table. Water level errors do not affect the sensed level at which the Tech Spec switches actuate and Table 3.2.8 is therefore satisfied. Page 2 of 8 t
SPECIAL ORC MEETING NO. 92-100 However, Tech Spec Bases 3.2 indicates that the objective of the specification is to prescribe the trip setting required to assure adequate performance. As shown below, under rapid depressurizations, the system performance is adequate to assure the core cooling function. This condition, therefore, represents a potential nonconformance with the FSAR design criteria for the system and not a noncompliance with Tech Specs. Water level inputs to the 2/3 core coverage interlock function are expected to the extent practical and feasible, to be true measures of operational conditions and to respond correctly to the sensed condition over the expected range of magnitudes and rates of change. Level errors represent a departure from fully conforming with these criteria. This departure does not prevent the 2/3 core coverage interlock from detecting abnormal conditions with sufficient timeliness, precision, and reliability to assure that its specified safety functions can be performed. Flow diversion to containment spray represents roughly 25% of a single RHR pump's flow. The remaining LPCI flow to the reactor would still be well in excess of jet pump leakage (800 gpm per FSAR 3.3.6.5.2) and 2/3 core coverage would be maintained during spray diversion. It is also important to note that for large recirculation line breaks, at least one core spray loop will be available assuming a worst single failure. Accounting for 800 gpm jet pump leakage, one core spray pump can maintain 2/3 core coverage and the effects of water on the core cooling function are further diminished. Appendix K LOCA Analyses for PNPS indicates that massive core uncovery (e.g., more than 10 feet below TAF) for approximately 60 seconds can occur without exceeding 2200 F peak clad temperatures. The LOCA analysis is done assuming the reactor has just been shutdown due to the accident when fuel sensible heat and decay heat are still high and coolant temperature is high. Worst peak clad temperatures are for the recirculation suction line break with LPCI injection valve failure. Conservative analysis indicates this peak clad temperature to be 1821 F which provides margin to 2200 F. Operator actions to divert LPCI flow would not occur until the core had been reflooded with compartively cool water and fuel sensible and decay heats had substantially decreased. ; Loss of injection at this time would lead to level reduction due to boiloffs and not due to depressurization blowdown. Core spray flow and some LPCI flow will maintain 2/3 core height. Multiple failures must occur to cause a condition where no core makeup flow exists. Level errors of up to five feet under this unlikely scenario will not lead to PCTs exceeding those in current LOCA analyses. ) Page 3 of 8
SPECIAL ORC MEETING NO. 92-100 The FSAR acknowledges some level errors occur during design basis events. In selecting reactor water level as an input parameter to initiating safety f' unctions, it is understood that some inaccuracy is inherent in the design. Deviations between actual and sensed level are expected due to pressure and thermal density effects, reference leg flashing, coolant voiding, and flow across instrument nozzles (see FSAR 7.8.5.2). In selecting level trip settings, FSAR 7.2.4 states that the
" trip point selected is not the only value of the trip point which results in acceptable results relative to the fuel or nuclear system process barrier. Trip setting selection is based on operating l experience and is constrained by the safety design basis". As has been [
shown, trip actuations at levels different than assumed in accident analysis due to level errors do not lead to unacceptable results. The potential for level error following a rapid depressurization is an industry-wide issue. Although the exact nature of the effects rapid depressurizations have on the 2/3 core coverage interlock has not been quantified by the industry (BWROG) or Boston Edison, the available design margins, empirical plant data and reductions in reference leg leaks provide reasonable assurance that the 2/3 core coverage interlock will remain operable. ORC Comment Mr. S.D. Hudson, Electrical Systems Engineering Division Manager, presented a history of the problems PNPS has experienced with the reactor water level instrumentation. Mr. T.F. White, S&SA Division Manager (Acting), then discussed the bases for determining that the 2/3 r core coverage interlock will remain operable. The ORC reviewed the Operability Evaluation and concurred with the conclusion that the system was operable and recommended approval. (See Attachment 1)
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oston Edison Company To: E.S. Kraft, Jr. From: S.D. Hudson Record Type A4.08 Date: November 3, 1992 Dept. Doc. ESED92-158 Non-Safety Related
Subject:
REACTOR WATER LEVEL SPIKING ON OCTOBER 24, 1992 Distribution: R.A. Anderson E.T. Boulette W.S. Clancy J. Bellefeuille W.C. Rothert R.V. Fairbank H.V. 0heim T. Sullivan D. Tarantino J. Rogers-BT S. Dasgupta-BT R. Cannon T. Trepanier R. Kelley-BT K. Kampschneider E. Almeida P.D. Smith L. Francis 8d. M , , Approval For Release Outside Plant Dept..E.S.Kraftgr.g BACKGROUND: During the shutdown and cooldown on October 24, 1992, reactor water level was continuously monitored with the EPIC Computer. Close communication was maintained with the Control Room. Spiking was o.bserved to begin at approximately 350# on the "B" ECCS instruments. The characteristic signature was present during depressurization. A Group 1 Isolation occurred at approximately 160"F due to a maximum recorded spike t of 29 inches (limited by instrument range). Water level was +21 inches at the time of this spike. All valves responded as designed due to the false high level signal. Spiking began at 63# on the "A" Side instruments. The "A" Side also performed as expected. The maximum spike observed on the "A" Side was 17 inches. CONCLUSION: The spiking was similar to that which has been seen in the past and the reactor water level instrumentation is operable. The instrumentation response was consistent with the non-condensible gas theory. Additionally, the ultrasonic detectors installed on the reference leg piping detected the non-condensible gas traveling up the piping during the spiking. Therefore, the primary cause of the- ' spiking is now believed to;be due to non-condensible gases coming out of solution as the reactor is depressurized. h; i
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REACTOR WATER LEVEL SPIKING ON OCTOBER 24, 1992 - ESED92-IS8 PAGE 2 ; ACTIONS: Based on the above, and consistent in our previous strategy, the Reactor Water Level Team recommends the following actions: .
- 1. Determine the relative volume of gas that was released when compared with the March 1992 shutdown. This will be used to make a recommendation on the amount of insulation on the "B" condensing chamber steam line.
** 2. Confirm the accuracy of all RTDs used for temperature monitoring.
- 3. Fix the external leaks on the "B" rack.
l
- 4. Measure "as-left" external-leakage on the "B" rack after startup.
- 5. Measure instrument bypass valve leakage on the "A" and "B" racks -
)
TP92-47. 1
-Do not perform repairs on the "A" side leakage. ;
i l Calculate plant run time with the "as-left" leakage before spiking will recur. Remove the ultrasonic temporary modification from the "A" and "B" racks.
* = already included in MCO 9 Scope
** = to be added to MCA 9 Scope SDH/lef l
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PNPS-FSAR are the valves which, if not closed, would permit the pumps to take suction from the reactor recirculation system, a lineup that is used during normal shutdown cooling system operation. All valve motors are : protected by overload alarms. l The LPCI is designed for automatic operation following a break in one ! of the reactor recirculation loops. The IPCI logic is required to open the injection valve to the unbroken recirculation loop and close the recirculation pump suction and discharge valves in the unbroken recirculation loop. The control scheme for the LPCI-to-recirculation loop injection valves is shown on Figure 7.4-11. The purpose of the injection valve control circuitry is to identify and direct LPCI flow to the undamaged recirculation loop. This is done by comparing the absolute pressure of the two recirculation : loops. The broken loop is indicated by a lower pressure than the unbroken loop. The loop with the higher pressure is then used for LPCI injection. Four indicating type differential pressure switches are used in the control circuitry for the injection valves. The differential pressure switches detect the pressure difference between corresponding risers supplying the jet pumps from each recirculation loop. The switches are connected in stch a way that a one-out-of-two-taken-twice logic is used to positively identify a broken recirculation loop. The differential pressure switch setting
- is selected to give the earliest valid indication of a break in a recirculation loop.
Upon receipt of either a reactor low-low level or a high drywell i pressure signal the LPCI logic senses the recirculation pump operation , by means of differential pressure between the cuttion and discharge of each pump. Four differential pressure switches are provided across each recirculation pump. The four sensors in each loop are arranged in a one-out-of-two taken twice logic. A time delay relay provides 1/2 second for the logic to detect if one recirculation pump is . running. If the logic senses that one pump is not running, the operating pump is tripped off. Stopping this pump is necessary to eliminate the possibility of breaks being masked by the operating recirculation pump pressure. If pump stoppage is initiated, there is next a requirement that reactor vessel pressure drop to a specified value before the logic will continue. This adjusts the selection time to optimize sensitivity and still ensure that the LPCI action is not unnecessarily delayed. There are four separate reactor pressure sensors arranged in a one-out-of-two taken twice logic. After satisfaction of this pressure requirement, or if both recirculation pumps were initially running, a time delay of about 2 sec is provided to remove initial perturbations and allow momentum effects to stabilize. Loop selection is then initiated by means of the differential pressure switches between the corresponding recirculation loop risers. See Figure 7.4-15. If, after approximately a half second delay, the pressure in Loop A is not indicating greater than Loop B, the circuit provides a signal to shut the Loop B recirculation pump discharge valve and opens the LPCI injection valve to Loop B. If recirculation Loop A pressure indicates higher than Loop B, the f recirculation valves in Loop A are ordered shut and the LPCI
- 7. 4-2 Revision 12 - Jan 1991 I
f PNPS-FSAR ! injection valve to Loop A is signaled open. The injection valves do not open however, until reactor vessel pressure decreases to a value which approximates the discharge head of the LPCI system. LPCI flow then enters the vessel when the check valve opens due to LPCI pressure i being higher than reactor pressure. The sensing circuit for break detection and valve selection is arranged so that failure of a single - device will not prevent correct selection of the loop for injection.
- A timer cancels the LPCI signals to the injection valves after a delay time long enoagh to permit satisfactory operation of the LPCI system.
The cancella'. ion of the signals allows the operator to divert the water for otuer post-accident purposes. Cancellation of the signals does not cause the injection valves to move. The manual controls in the main control room allow the operator to open an LPCI injection valve only if either nuclear system pressure is low or the other injection valve in the same pipeline is closed. These i restrictions prevent overpressurization of the RHR piping. The same pressure transmitter / trip unit combination used for the automatic opening of the valves is used in the manual circuit. Limit switches l on both injection valves in each side provide valve position signals. To protect the pumps from overheating at low flow rates, a minimum , flow bypass pipeline, which routes water from the pump discharge to the suppression pool, is provided for each pair of pumps. A single motor-operated valve controls the condition of each bypass pipeline. The minimum flow bypass valve automatically opens upon sensing low ! flow in both injection lines. Figure 7.4-10 shows the location of the two flow indicating differential pressure switches on the LPCI l injection flow elements. t figures 7.9-2,3,4 shows the control arrangement for the recirculation i loop valves. If a recirculation loop has been damaged, the recirculation pump discharge valve in the undamaged retirculation loop automatically closes upon the receipt of an LPCI injection signal. The valves in the damaged recirculation loop are left open to allow t continued depressurization of the nuclear system so that the LPCI and core spray systems can inject water into the reactor vessel as soon as possible. r The same arrangement of differential pressure switches that is used in the LPCI injection valve circuitry to identify a damaged recirculation l loop is used in the recirculation loop valve control circuitry. The ] manual control circuitry for the recirculation loop valves is l interlocked to prevent valve opening whenever an LPCI initiation signal is present. 1 The valves that allow the diversion of water for containment spray cooling are automatically closed upon receipt of an LPCI initiation signal. The manual controls for these valves are interlocked so that opening the valves by manual action is not possible unless both I i 7.4-22 Revision 12 - Jan 1991 I 1 I
PNPS-FSAR priraary containment (drywell) pressure is high, which indicates the need for containment spray cooling, and reactor vessel water level , inside the core shroud is above the level equivalent to 2/3 the core height. Four transmitters are used to monitor drywell pressure for [ the set of valves in each subsystem. The trip setting is selected to be as low as possible yet provide indication of abnormally high drywell pressure. The drywell pressure trip units associated with ' these transmitters are arranged in a one-out-of-two taker, twice logic [ arrangement. A single level transmitter / trip unit combination is used ' to monitor water level inside the core shroud -for the set of valves in each subsystem. A keylock switch in the main control room allows a manual override of the 2/3 core height permissive contact for the : containment cooling valves. Sufficient temperature, flow, pressure, and valve position indications are available in the main control room for the operator to accurately assess the LPCI operation. Valves have indications of full open and full closed positions. Pumps have indications for pump running and pump stopped. Alarm and indication devices are shown on Figures i 7.4-10 and 7.4-13. 7.4.3.5.5 LPCI Environmental Considerations The only control components pertinent to LPCI operation that are located inside the primary containment and that must remain functional in the environment resulting from . a LOCA are the cables and valve closing mechanisms for the recirculation loop valves. The cables and , valve operators are selected with environmental capabilities that assure valve closure under the environmental conditions resulting from a design basis LOCA. Gamma and neutron radiation is also considered in the selection of this equipment. Other equipment, located outside the drywell, is selected in consideration of the normal and accident environments in which it must operate. 7.4.4 Safety Evaluation In Section 14 Station Safety Analysis, and Section 6, Core Standby Cooling Systems, the individual and combined capabilities of the standby cooling systems are evaluated. The control equipment characteristics and trip settings described in these sections were considered in the analysis of CSCS performance. For the entire range of nuclear process system break sizes the cooling systems are effective both in preventing fuel clad melting and in preventing more than a small fraction of the reactor core from reaching the temperature at which a gross release of fission products can occur. This conclusion is valid even with significant failures in individual ' cooling systems because of the overlapping capabilities of the CSCS. The controls and instrumentation for the CSCS satisfy the precision , and timeliness requirements of safety design bases 1 and 2. , Safety design basis 3 requires that instrumentation for the CSCS responds to the potential inadequacy of core cooling regardless of the location of a breach in the nuclear system process barrier. The 7.4-23 Revision 12 - Jan 1991
t ( PNPS-FSAR reactor vessel low water level initiating function, which alone can i actuate HPCI, LPCI, and core spray, meets this safety design basis ~ because a breach in the nuclear system process barrier inside or - > outside the primary containment is sensed by the low water level ' detectors. ; Because of the isolation responses of the Primary Containment and Reactor Vessel Isolation Control system to a breach of the nuclear j system outside the primary containment, the use of the reactor vessel low water level signal as the only Standby Cooling System initiating function that is completely independent of breach location is satisfactory. The other major initiating function, primary containment high pressure, is provided because the Primary Containment and Reactor Vessel Isolation Control system may not be able to isolate all nuclear system breaches inside the primary containment. The primary containment high pressure initiating signal for the CSCS provides a second reliable method for sensing losi,es of coolant that cannot necessarily be stopped by isolation vP c action. This second initiating function is independent of the Gy41 cal location of the : breach within the drywell. The method ur.ed ta initiate the ADS, which employs reactor vessel low water fevel and primary containment high pressure in coincidence, requires that the nuclear system breach be : inside the drywell because of the required primary containment high ! pressure signal: This control arrangement is satisfactory in view of the automatic isolation of the reactor vessel by the Primary Containment and Reactor Vessel Isolation Control System for breaches oeiside the primary containment and because the ADS is required only if the HPCI fails. Thus, safety design basis 3 is satisfied. i An evaluation of CSCS controls shows that no operator action beyond the reasonable capability of the operator is required to initiate the correct responses of the CSCS. The alarms and indications provided to the operator in the main control room allow interpretation of any situation requiring CSCS operations and verify the response of. each system. Manual controls are illustrated on functional control diagrams. The main control room operator can manually initiate every The degree to which safety is essential operation of the CSCS. dependent on operator judgement and response has been appropriately ' limited by the design of CSCS control equipmsnt and safety design ' bases 4a, 4b, and 4c are therefore satisfied. The redundancy provided in the design of the control equipment for the ! CSCS is consistent with the redundancy of the cooling systems themselves. The arrangement of the initiating signals for the CSCS is similar to that provided by the dual trip system arrangement of the No failure of a single initiating sensor can prevent the start RPS. ' of the cooling systems. The numbers of control components provided in the design for individual cooling system components is consistent with , the need for the controlled equipment. An evaluation of the control schemes for each CSCS component shows that no single control failure can prevent the combined cooling systems from providing the core with adequate cooling. In performing this evaluation the i 7.4-24 Revision 12 - Jan 1991
p m PNPS TABLE 3.2.A ' INSTRUMENTATION THAT INITIATES PRIMARY CONTAINMENT ISOLATION Minimum # of Operable Instrument Channels Per Trip System (1) Instrument Trio Level Setting *
' Action (2) 2(7)
Reactor low Hater Level 19" indicated level (3) A and 0 1 Reactor High Pressure 1110 psig D 2 Reactor low-Low Hater level at or above -49 In. A Indicated level (4) 2 Reactor High Hater Level 148" indicated level (S) B
, 2(7) High Drywell Pressure 12.5 psig A 2
High Radiation Main Steam Line Tunnel (9) 17 times normal rated B full power background 2 Low Pressure Main Steam Line 1880 psig (B) B 2(6) High Flow Main Steam Line 1140% of rated steam flow B 2 Main Steam Line Tunnel Exhaust Duct High Temperature 1170*F B 2 Turbine Basement Exhaust Duct High Temperature-il50*F B 1 Reactor Cleanup System High Flow . 1300% of rated flow , C 2 Reactor Cleanup System High Temperature 1150*F C I :. Amendment No. 86 b 45
EQTES FOR TABLE 3.2.A
- 1. Whenever Primary Containment integrity is required by Section 3.7, there
- *- shall be two operable or tripped trip systems for each function. An instrument channel may be placed in an inoperable status for up to 6 hours for required surveillance without placing the trip system in the tripped condition provided at least one OPERABLE channel in the same trip system is monitoring that parameter; or, where only one channel exists per trip system, the other trip system shall be operable.
- 2. Action If the first column cannat be met for one of the trip systems. .at trip system shall be tripped. If the first column cannot be met foi both trip systems, the appropriate action listed below shall be taken.
A. Initiate an orderly shutdown and have the reactor in Cold Shutdown Condition in 24 hours. B. Initiate an orderly load reduction and have Hain Steam Lines isolated within eight hours. C. Isolate Reactor Water Cleanup System. D. Isolate Shutdown Cooling.
- 3. Instrument set point corresponds to 128.26 inches above top of active fuel.
- 4. Instrument set point corresponds to 77.26 inches above top of active fuel.
- 5. Not required in Run Mode (bypassed by Mode Switch).
- 6. Two required for each steam line.
- 7. These signals also start SBGTS and initiate secondary containment ,
isolation.
- 8. Only required in Run Kode (interlocked with Mode Switch).
I
- 9. Hithin 24 hours prior to the planned start of hydrogen injection with the reactor power at greater than 201 rated power the normal full power radiation background level and associated trip setpoints may be changed based on a calculated value of the radiation level expected during the injection of hydrogen. The background radiation level and associated trip setpoints may be adjusted based on either calculations or measurements of actual radiation levels resulting from hydrogen injection. The background radiation level shall be determined and associated trip setpoints shall be set within 24 hours of re-establishing normal radiation levels after completion of hydrogen injection and prior to withdrawing control rods at reactor power levels below 20% rated power.
4 Revision 122 Amendment No. 86, 105, JJ8, 119 46 l
/ ig UNITED STATES [
) (
/
t n NUCLEAR REGULATORY COMMISSION - W ASHINGTON, D. C. 20555 [
>..Y../ e SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION SUPPORTING AMENDMENT NO. 90 TO FACILITY OPERATING LICENSE NO. DPR-35 BOSTON EDISON COMPANY PILGRIM NUCLEAR POWER STATION ,
DOCKET NO. 50-293
1.0 INTRODUCTION
By' letter dated June 18, 1985 the Boston Edison Company (licensee) proposed a change in Table 3.2.B relative to the trip level setting for Reactor low Water Level (inside shroud). The change consists of replacing the setting specification of " b 302 inches above vessel zero (2/3 core height)" with
" @ 307 inches above vessel zero (approximately 2/3 core height)."
2.0 EVALUATION . The proposed change would raise the minimum trip level setting for Reactor low Water Level by 5 inches to 307 inches above vessel zero. This is a correction to make the setting more nearly equivalent to the general term "2/3 core height". The 307-inch level above vessel zero will serve the purpose of the minimum setpoint, which is to prevent inadvertent operation of_the containment spray during an accident condition. The 5-inch higher minimum level will also provide a somewnat greater degree of core coverage during an accident condition. On this basis, we find that safety considerations would not be adversely affected by the proposed change. It is, therefore, acceptable.
3.0 ENVIRONMENTAL CONSIDERATION
S es. This amendment involves a change in the installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. I The staff has determined that the amendment involves no significant increase l in the amounts, and no significant change in the types,. of any effluents ! that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Comission ' has previously issued a proposed finding that this amendment involves no significant hazards consideration and there has been no public coment on such finding. Accordingly, this amendment meets the eligibility criteria i for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b) no environmental impact statement or environmental assessment need be prepared in connection with the issuance of this amendment. {
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l - m. PNPS TABLE 3.2.B INSTRUMENTATION THAT INITIATES OR__ CONTROLS THE CORE AND CONTAINMENT COOLING S Minimum # of Operable Instrument Channels Per Trip J s_ tem (1) Trip Function Trip level Setting Remarks 2 Reactor low-Low Hater e -49 in. 1. In conjunction with low Level Indicated evel (4) Reactor Pressure,
. . 77 initiates Core Spray and LPCI.
- 2. In conjunction with High Drywell Pressure, 120 second time delay and LPCI or Core Spray pump Interlock initiates Auto f Blowdown (ADS).
- 3. Initiates HPCI. RCIC.
i l
- 4. Initiates starting of Diesel Generators.
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. l ~~~ Teactor low Level -
1307" above ves,selhh Prevents inadvertent operation (Inside shroud) zero (approximately l of containment spray during 2A3 core height) accident condition. l 2 . Containment High Pressure 1 ( M ify Prevents inadverIeift operation of containment spray during accident conditlon. D' d .
- n. .
/
Ameinlment No. '80 47
BASES:
- i 3.5.A Core-Spray and LPCI System
- . 2. This specification assures that adequate emergency. cooling capability is 9
- available whefever-irradiated fuel-is in the reactor vessel.
Based on the loss of coolant analysis performed by General Electric in accordance with Section 50.46 and Appendix K of 10CFR50, the Pilgrim I
- Emergency Core Cooling Systems are adequate to provide sufficient cooling to the core to dissipate the energy associated with the loss of coolant accident, to limit calculated fuel clad temperature to less than 2200*F, to limit calculated local metal water reaction to less than or equal to 17%, and to limit calculated core wide metal water ' reaction to less than or equal to 1%.
i The detailed bases is descrabed in NEDC-31852P and summarized in Section I 6 of the PNPS FSAR. The analyses discussed in NEDC-31852P calculated a peak clad fuel temperature of less than 2200 F with a core syray pump flow of 3200 gallons per minute (gpm). A flow rate of 3300 gpm ensures adequate flow for events involving . degraded voltage. Core spray distribution has been shown, in full-scale tests of systems similar in design to that of Pilgrim, to exceed the minimum requirements by at least 25%. In addition, cooling effectiveness has been demonstrated at less than half the rated flow in simulated fuel assemblies with heater rods to duplicate the decay heat characteristics of irradiated fuel. The accident analysis , takes credit for core spray flow into the core at vessel pressure below 205 psig. However, the analysis is conservative in that no credit is taken for i spray cooling heat transfer in the hottest fuel bundle until the pressure at rated flow for the core spray (104 psig vessel pressure) is reached. The LPCI system is designed to provide emergency cooling to the core by ' flooding in the event of a loss-of-coolant accident. This system functions in ' combination with the core spray system to prevent excessive fuel clad . temperature. The LPCI system and the core spray system provide adequate l
- cooling for break areas of approximately 0.2 square feet up to and including ~
.2 ~ ~~ the double-ended recirculation line break without assistance from the high ,
' pressure emergency core cooling systems. The analyses in NEDC-31852P '
O^- calculated a peak clad fuel temperature of less than 2200 F with LPCI pump _;
~~
' flows of 4550 gpm, 4033 gpm, and 3450 gpm for two, three, and four pump l combinations feeding into a single loop. A single pump flow rate of 4800 gpm ensures sufficient flow to meet or exceed the analyses' assumptions. l The analyses of LOCA for PNPS demonstrated the combination of LPCS/LPCI systems are sufficient to provide core cooling even with a single failure of either an active or passive safety-related component. The analyses determined ,
l there were four significant single failures that challenge the Emergency Core Coolant Systems' capability to prevent fuel damage during the postulated LOCA. l They are: I 1) Battery Failure - Loss of a single battery train could leave only-This one LPCS pump, two LPCI pumps, and ADS to mitigate the LOCA. l is the most limiting single failure for all but the largest postulated recirculation line breaks and for all postulated non-recirculation line breaks. 113 Amendment No. 75, 109, 131 135
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"4 ) GL 92-04 BOSTON EDISON Pilgrim Nuclear Power Station Rocky Hill Road Plymouth, Massachusetts o2360 Roy A. Anderson September 28, 1992 Serwor vice President - Nuclear BECo 92-113.
U. S. Nuclear Regulatory Commission Document Control Desk Washington,-DC 20555 License DPR-35 Docket 50-293 [ Generic Letter 92-04: Resolution of the Issues Related to Reactor Vessel Water level Instrumentation in BWRs Pursuant to 10CFR50.54(f) The attachment to this letter provides the Boston Edison Company response to Generic letter 92-04 (GL 92-04) dated August 19, 1992. GL 92-04 addresses various issues related to and corrective actions for Boiling Water Reactor water level instrumentation under transient conditions of reactor pressure reduction. This response reflects Pilgrim-specific analysis and actions as well as information developed by our participation in the BWR Owner's Group effort to address this topic. Ottb. i 1 R. A. Anderson fu - l PMK/cic/gl9204 , Attachment cc: See Page 2 ; i l 1
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. . 2 Less than 600 PSIG i
For breaks that occur with the plant initially below 600 psig, reactor power will be negligible, vessel blowdown rates will be reduced and the breaks are , bounded by the above evaluations. CSCS initiation on high drywell pressure , provides substantial coolant makeup for these conditions. Since this is a
- zero power event, CSCS will reflood the reactor and core uncovery does not occur. IF MSIVs do not close on high steam flow or low-low level operators can close the MSIVs manually.
Based on the above discussions and considering the Pilgrim LOCA analyses assume an initial power of 102%, initial pressure of 1050 psig, and reduced Low Pressure Coolant Injection (LPCI) and core spray flow rates (5% and 10%, , respectively), considerable margin exists for PBICs to conclude that water i level errors will not affect required safety functions. 2/3 Core Coverage 4 A 2/3 core coverage condition is only expected for a recirculation pipe break. i These are large break events with rapid level decreases and core level recovery to 2/3 core height using core spray and/or LPCI pumps. Diversion of ; LPCI flow to the containment cooling mode requires operator action. LPCI flow , will not be diverted for containment cooling unless operators are directed to by E0Ps. Operators are trained to recognize potential water level errors by level indicator comparisons and other indicatioas. With indeterminate level indications, E0Ps direct operators to flood the .eactor vessel, thereby assuring adequate core cooling. E0Ps also direct 9perators to maintain reactor level above +9". This level is more than 11 feet above the active fuel and more than 15 feet above 2/3 core coverage (required to assure adequate core cooling). The likelihood that all level indicators will consistently be in error in excess of these parameters is very remote. , Reculatory Guide 1.97. Post Accident Indication J Reactor water level indication is an important parameter for post-accident operator responses. Operator training regularly emphasizes that multiple j water level indications be checked to confirm accurate water level conditions. Discrepancies between water level channel readings would indicate to operators .l that water level is indeterminate. With different reference leg geometries ; and gas concentrations, it is extremely unlikely that all level indicators will provide consistent yet inaccurate data in an accident situation. Sufficient core cooling would be assured via the appropriate E0Ps. Pioe Breaks Outside Containment (PB0C) Analysis of PBOCs indicates reactor pressure remains high because PBOCs are-reactor isolation events. These events have peak clad temperatures - substantially below PBICs because inventory loss is limited. If pressure is , reduced later in the event (i.e., due to ADS actuation), it would be'the result of a low-low level condition that existed at high pressure (i.e., above 600 psig). PB0C isolation capability is unaffected by level errors because , most PBOCs isolate on high flow or high area temperature. The only PBOC that l isolates due to a level signal only is the shutdown cooling line break. This event occurs at initial low pressures and does not represent a rapid Page 4 l
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Duxbury Nuclear Advisory Committee Duxbury, Massachusetts 02332 FRE,EDOM 0F INFDRMATION February 5, 1993 ACT REQUEST e
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Secretary Samuel Chilk dcc g,) _f(,_ gj - Nuclear regulatory Commission , 16 G 15 Washington, D.C. 20555
Dear Secretary Chilk:
Last Wednesday evening, February 3, 1993, Mr. Hehl and ' other. representatives of the U.S. Nuclear Regulatory Commission met with concerned citizens on a current safety issue the faulty reactor vessel water level instrumentation. They were asked a question and reconnended a formal written FOIA request would be the appropriate vehicle to obtain the information. I, Mary Elizabeth lanpert, as chairnan of the Duxbury Nuc1 car Advisory Conr ittee, under the Freedom of Information Act 5 USC sec. 552 request all the materials (including all calculations and quantifications)" used by and presented to the NRC staff upon which they, ...also independently reviewed the bases for BECO's operab:lity deternination,-and
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agreed with its conclusion." (NEC Report, Docket No. 92-23, J December 1992, page 17). I also request notification of any inf ormation which may be exenpted f rom the above request. I am not waving my right to appeal any and all exemptions. I also deen this inf ormation is in the public interest and is to the benefit of public health and safety. Therefore, I request the NRC waive any and all fees. 1 I Tnanking you f or your prompt response, I am sincerely,
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tj Mary Elizabeth Lampert 148 Washington Street Duxbury, Massachusetts 02332 foianrc2.93 l
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