ML20033A727
| ML20033A727 | |
| Person / Time | |
|---|---|
| Site: | Clinton  |
| Issue date: | 11/20/1981 |
| From: | LICENSING REVIEW GROUP II |
| To: | |
| Shared Package | |
| ML20033A724 | List: |
| References | |
| TASK-***, TASK-TM NUDOCS 8111270169 | |
| Download: ML20033A727 (46) | |
Text
a, NOVEMBER 20,1981 LRG-Il PC>SITION PAPERS VOLUME I
TECHNICAL DISCUSSIONS AND RESOLUTION OF 22 LRG-il ISSUES.
THE POSITIONS TAKEN IN THESE PAPERS WILL BE REFERENCED IN LRG-Il PLANT OL APPLICATIONS.
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NOTE: ADDITIONAL ISSUES WILL BE ADDRESSED
'IN SUBSnOUENT POSITION PAPER VOLUMES.
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e TADLE OF CONTENTS LRG-II POSITION PAPERS --- VOLUME 1 Issue 1 - RSB Auto-Restart of HPCS 2 - RSB
'asign Adequacy of RCIC 6 - RSB Liquid Flow Through SRV 7 - RSB Preclude Vortex Formation 8 - RSB Long-Term Operability of ADS 10 - RSB Flow Control Valve Closure 11 - RSB Shaft Seizure Event 12 - RSB Proper Classification of Transients 4 - CPB High Burn-Up Fission Gas Release 5 - CPB Cladding Water-Side Corrosion 7 - CPB Rod Withdrawal Transient Analysis 8 - CPB Mislocated or Misoriented Fuel Bundles 9 - CPB Void Coefficient Calculation 10 - CPB Bounding Rod Worth Analysis 4 - ASB RCIC Pump Room Cooling System 1 - RAB Exposure From SRV Actuation 2 - RAB Routine Exposures Inside Containment j
3 - RAB Radioactivity During Dryer / Separator Transfers 4 - RAB Shielding of Transfer Tube & Canal During Refueling 1 - ICSB Vessel Level Sensing Line Failure 1 - HFS Special Low Power Testing Program 3 - HFS Vessel Level Reference Common i
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I i-LRG-II POSITION PAPER 11/20/81-a 1-RSB REQUIREMENT FOR AUTOMATIC RESTART OF HPCS AFTER MANUAL TERMINATION ISSUE:
TMl Action Plan Item II.K.3.21 required analysis to determine if automatic 1
restart of the LPCS and LPCI systems should be incorporated into the plant design.
The results of the analysis, as documented in the December 29, 1980 BWR Owners' Group submittal to the NRC was that the LPCI and LPCS systems should not be modified to provide automatic restart. The NRC Staff requires a commitment to install the HPCS restart modification and to provide design details.
RESPONSE
If the operator manually terminates HPCS flow, a manual action is required to restart HPCS.
If a persistent LOCA signal is present, it will not be possible for the operator to return the HPCS to a standby mode and continuous manual control will be required.
It is this NRC concern for reliance upon the operator to restart the HPCS that prompts the design modification, irrespective of time availability for operator response.
The RG-II position is to modify the HPCS logic to automatically restart the PCS pump on low reactor water level following manual termination by the operator.
The details of the modification consist of a bypass of the high drywell pressure signal (which inhibits reset) thus causing reset such that auto reinitiation of HPCS will occur when the low level signal recurs.
This will allow auto restart on low level after operator stop of the pump.
It does block auto restart on high drywell pressure unless drywell pressure decreases below the setpoint and again increases above the setpoint.
A decrease in drywell pressure below trip level will remove all reset features and return HPCS logic to the original status.
The HPCS pump is not stopped automatically by any reset.
Pump stop still requires operator action.
MJA:rm:csc/15083 u
LRG-II POSITION PAPER 11/20/81'-
1-RS8 (Page 2)
System isolation is not affected by this modification.
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NOTE:
The Grand Gulf SER established the BWROG modification as resolution of issue.
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MJA:rm:csc/15084
LRG-II POSITION PAPER 11/20/81 2-RSB(a)
DESIGN ADEQUACY OF THE RCIC SYSTEM PROVIDING AUTOMATIC RESTART CAPABILITY ISSUE:
TMI Action Plan Item II.K.3.13 identified a need to modify the RCIC system to allow for automatic restart of the system at RPV Level 2 after-it has been tripped by a RPV Level 8 signal.
The NRC Staff requires a commitment to install the automatic restart. capability.
The design details of this modification should also be provided.
RESPONSE
The LRG-II participating utilities sponsored, through the BWR Owners' Group, a program to evaluate this concern and develop an appropriate modification.
The results of this program were submitted to the NRC via a letter from D. B. Waters, Chairman of BWR Owners' Group' to D. G.
Eisenhut, Director of NRC, dated December 29, 1980.
An evaluation of modifications to the RCIC system to allow automatic restart following a trip of the system at high RPV water level was conducted.
The evaluation of the automatic restart indicates that it would contribute to improved system reliability and that it could be accomplished without adverse effects on system function and plant safety.
The LRG-II position is to implement an RCIC automatic restart modi-fication on their projects.
The planned modification will consist of the relocation of the existing high vessel level trip function from the RCIC turbine trip valve to the RCIC steam supply valve.
This signals the RCIC steam supply valve to close when the high reactor vessel water level is attained.
Closure of the RCIC steam supply valve also automatically resets many of the functions that allow RCIC to restart when low vessel water level is reached.
MJA:rm:csc/150BS
LRG-II POSITION PAPER 11/20/81 2-RSB(a) (Page 2)
One additional relay device is required to accomplish this new auto-restart function.
No adverse system effects were found to result from this design change.
This modification enables RCIC to restart on low vessel level (Level 2) Because the logic resets or aligns the RCIC valving for startup.
Formerly, this reset was accomplished manually.
This reset condition is indicated on an annunciator in the control room.
NOTE:
The Grand Gulf SER established the BWROG modification as resolution of this issue.
MJA: rm:csc/15086
LRG-II POSITION PAPER 11/20/81 2-RSS(bl DESIGN ADEQUACY OF THE RCIC SYSTEM PREVENTING INADVERTENT RCIC SYSTEM ISOLATION ISSUE:
TMI Action Plan Item II.K.3.15 identified a need to modify the break detection logic on the RCIC system steam supply line in order to prevent spurious isolation of the system.
The NRC Staff requires a commitment-to install a modification to correct the problem.
The design details of this modification should also be provided.
RESPONSE
The LRG-II participating utilities sponsored, through the BWR Owners' Group, a generic program to evaluate the inadvertant trip concern and develop an appropriate modification.
As a result of this generic program, the LRG-II position is that plant design will include a provision for the prevention of spurious isolation of the RCIC system as a result of pressure spikes which may occur during start-up of that system.
The design details consist of installation of a 3 to 13 second time delay on the isolation logic which will avoid the RCIC isolation due to any short duration pressure spikes during system startup.
This time delay is short enough such that for postulated system pipe breaks, the system will isolate in time to prevent unaccept-able radiological releases to the environment.
Releases due to a 3 to 13 second time delay will still be less than the design basis conditions and within existing safety analyses.
Figure 2-RSB-1 shows a typical example of that part of the RCIC elementary diagram which will be changed when the time delay relay replaces the existing isolation relay.
Figure 2-RSB-2 summarizes in schematic form the sequence of events that will occur during the starting of the RCIC system after a time delay has been added.
The timer will te started j
when the flow rate sensed by elbow flow meters exceeds the trip setpoint.
MJA:rm:csc/15087
LRG-II POSITION PAPER 11/20/81 2-RSB(b)
(Page 2)
At the end of the timer period, syste.1 isolation will occur only if the flow meters are still reading at or above the trip setpoint.
As demon-strated in Figure 2-RSB-2, this will ensure that isolation of a pipe break will occur.
It is noted that the RCIC system has two break detection circuits each of which controls one of the two isolation valves.
Both circuits will be modified in order to successfully implement this change.
NOTE:
The Grand Gulf SER establishes this BWROG modification as resolution of this issue.
MJA:rm:csc/15088
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FIGURE 2-RSB-1 A TYPICAL RCIC STEAMLINE BREAK DETECTION LOGIC DIAGRAM PROPOSED TO REPLACE EXISTING RELAY (AS SHOWN AB0VE)
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LRG-II POSITION PAPER 11/20/81 2-RS8(d)
DESIGN ADEQUACY OF RCIC SYSTEM PROVIDING WATER HAMMER PROTECTION ISSUE:
Provide water hammer protection for the RCIC system which is comparable to that provided for ECCS systems.
RESPONSE
In order to protect the RCIC system against the effects of water hammer when system flow starts, the LRG-II participants have incorporated into their plant designs a water leg pump in the RCIC system to keep the system full. This water leg pump runs continuously and is powered from the standby AC power source.
The pump takes suction from the RCIC pump suction line in the suppression pool.
Pressure instrumentation is provided on each water leg pump discharge line to initiate an alarm in the main control room when pressure in the discharge line is less than the hydrostatic head required to maintain the line full of water up to the injection valves.
The RCIC system is equipped with high point vents for removing trapped air.
Standard BWR/6 Technical specifications require that the RCIC system be checked at least every 31 days to assure that the lines are filled.
NOTE:
LaSalle SER establishes the use of RCIC water leg pumps as resolution of this issue.
MJA:rm:csc/150B9
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LRG-II POSITION PAPER 11/20/81 6-RS8 APPLICABILITY OF THE LIQUID-FLOW-THROUGH-SRV TESTS PERFORMED IN RESPONSE TO TMI ACTION PLAN ITEM II.D.2 ISSUE:
An alternate shutdown cooling condition, which is considered in the design evaluation of many BWR plants, requires the flow of water through the SRV and into the supnression pool.
In order to take credit for this alternate mode of shutdown cooling, it is necessary to demonstrate the ability of the SRVs and their discharge piping to withstand the resulting flow conditions.
RESPONSE
The LRG-II participating utilities sponsored, through the BWR Owners' Group, a generic test program to satisfy the requirements contained in TMI Action Plan Item II.D.1 as specified in NUREG-0737, " Clarification of TMI Action Plan Requirements".
The testing requirement to qualify SRV's for the " expected operating conditions" associated with design-basis accidents and operational transients were determined by the BWR Owners' Group through systematic analysis of these events as defined in Regulatory Guide 1.70, Revision 2.
The conclusion from that evaluation was submitted to the NRC in September 1980 in response to Item 2.1.2 of NUREG-0578; the conclusion was that "there is no design-basis accident or transient which requires safety, relief, or dual function SRVs to pass two phase or liquid flow at high pressure." This submittal, however, acknowledged the alternate shutdown cooling moda which is considered in the design analysis of plants and committed to testing SRVs with liquid and with two phase flow under low pressure conditions associatesi with this event.
Additional justification was provided by the BWR Owners' Group to the NRC Staff on February 10, 1981 and March 10, 1981.
A test plan which addresses the alternate shutdown made of cooling was included in this September 1980 submittal to the NRC.
The purpose of the test plan was two-fold:
MJA: rm:csc/150B10 1
LRG-II POSITION PAPER 11/20/81 6-RSB (Page 2) a.
To demonstrate the capability of each type of SRV to operate satisfactorily under the bounding case of expccted water discharge release of low pressure water with resultant typical BWR pipe loads on the SRV.
b.
To measure the SRV piping discharge loads during water discharge through these valves.
The Dikkers 8x10,SRV used at the Clinton Power Station and Perry Power Station was indl,uded in this test.
The Crosby 8x10 SRV used at the River Bend Poweh Station was also included in the test.
The genaric test program;has been completed.
The final test report for the operability te.;t progiam was submitted in a letter from T. J. Dente (BWR Qwners' Group) to D.'G. Eisenhut (NRC), dated September 25, 1981.
This report, which includes final test data and analyses, demonstrates the operational adequacy of the SRVs and the SRV discharge piping and supports.
These final test results are contained in the General Electric Co. document NEDE-24988-P, " Analysis of Generic BWR Safety / Relief Valve Qperability Test Results" which was included in the September 25, 1981 letter.
A review of the test report shows the operational adequacy of the SRVs, discharge piping and supports has been demonstrated for the conditions defined in this TMI Action Plan item.
The participation of the LRG-II members in this program is indicated in Appendix B of the report.
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LRG-II POSITION PAPER 11/20/81 7-RSB PROVISIONS TO PRECLUDE VORTEX FORMATION (UNRESOLVED SAFETY ISSUE A-431 ISSUE:
To preclude vortex formation, air entrainment, and subsequent damage to ECCS pumps due to cavitation, it must be shown that adequate margin exists between the minimum suppression pool level and the depth of submergence of the ECCS Pump suction strainers.
This can be shown by analysis or by observations during pre-op testing that no vortex is formed.
RESPONSE
LRG plants have determined the ECCS suction strainer submergence at minimum suppression pool level.
The submergence provides sufficient margin to preclude formation of vortices.
Strainer Minimum Suppression Centerline Minimum Plant Pool Level (elevation)
Elevation Submergence CLINTON1 727.3' 720.0' 7.3' PERRY 1 589.0' 578.5' 10.5' RIVER BEND 2 83.4' 75.5' 7.9' Notes:
1.
All ECCS (HPCS, LPCS, RHR) strainers are at the same elevation.
2.
HPCS and LPCS strainer elevation is shown.
RHR strainers are slightly lower (73.4).
MJA:rm:csc/15081
LRG-II POSITION PAPER 11/20/81 8-RSB ASSURANCEFORLONG-TERMbPERABILITY 0F-THE AUTOMATIC DEPRESSURIZATION SYSTEM ISSUE:
TMI Action Plan Item II.K.3.28 identified the need tc assure that air or nitrogen accumulators for tha ADS valves are hrovided with sufficient capacity to cycle the valves open five times at design pressures.
It should also be assured that the long-term air supply-is designed to withstand a hostile environment and still perform its function 100 days after an accident.
Finally, it should be verified that no single active failure can disable the long-term air supply.
RESPONSE
The Automatic Depressurization System (ADS) utilizes selected safety / relief valves for depressurization of the reactor.
Each of tae safety / relief valves utilized for automatic depressurization'is equipped with an air accumulator and check valve arrangement.
The ADS pneumatic supply is split into two divisions.
One supplies - he ADS valves on steamlines "A" and "C", the other supplies to the ADS valves on steamlines "B" and "D".
1 The accumulators are designed to provide two ADS actuations at 70% of drywell design pressure, which is equivalent to 4 to 5 actuations at atmospheric pressure.
The ADS valves are designed to operate at 70% of drywell design pressure because that is the maximum pressure for which rapid reactor depressurization through the ADS valves is required.
The greater drywell design pressures are associated only with the short duration primary system blowdown in the drywell immediately following a-large pipe rupture for which ADS operation is not required. For large breaks which result in higher drywell pressure, sufficient reactor depressurization occurs due to the break to preclude the need for ADS.
One ADS actuation at 70% of drywell design pressure is sufficient to depressurize the reactor and allow inventory makeup by the low pressure MJA:rm:csc/150812
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LRG-II POSITION PAPER
.s 11/20/81
,- 6 8-RSB (Page 2) e ECC systems.
However, for conservatism, the accumulators are sized to allow 2 actuations at 70% of drywell design pressure.
Perry and Clinton v
The 100-day post-accident functional operability requirement is satisfied on the Clinton and Perry projects through the use of two banks of air bottles located outside containment.
Each bank ha,s a
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seven day supply of air and serves only one division of the ADS pneumatic supply.
Both banks have remote makeup capability provided to accomodate the remainder of the postulated accident to assure system functional operability.
The air bottle supports and restraints, air accumulators, intercon-nected piping, and associated valves are designed to the requirements of ASME Section III, Class 3, and are seismic Category 1.
River Bend The River Bend Station design utilizes 60 gallon accumulators and a safety grade air charging system (Penetration Valve Leakage Control System).
The air supply system includes two ASME III Division I, Class 2 air compressors which feed two separate charging systems f
for the accumulators.
Both compressors are powered from the preferred AC/So;wer supply systems and can be powered by on-site power.
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s Each charging system consists of an air dryer, associated piping and valves, necessary to provide air to each of the two divisional sets of accumulators.
Each charging system has physical separation in order to protect them from postulated pipe breaks.
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LRG-II POSITION PAPER 11/20/81 8-RSB (Page 3)
For all BWR/6's, only two of the ADS valves need to function to meet short-term demands and the functional operability of only one ADS valve will fulfill longer term needs.
Each accumulator is instrumented to provide the reactor operator with indication of an air supply problem.
The air supply to the ADS valves has been designed such that the failure of any one component will not result in the loss of air supply to more.
than one nuclear safety related division of ADS valves. The lo'ss of air supply to one division of ADS valves will not orevent the safe shutdown of the unit.
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NOTE:
The Grand Gulf SER established single failure proof bottled air as resolution of this issue.
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LRG-II POSITION PAPER 11/20/81 10-RSB LOCA ANALYSIS WITH RECIRCULATION FLOW CONTROL VALVE CLOSURE ISSUE:
The ECCS analysis presented-in FSAR Chapter 6.3 assumes the nonsafety grade flow control valve (FCV) locks at its present position during the LOCA.
Discuss the effects on the analysis of assuming the flow control valve closes at a realistic rate.
Indicate the probability of the controller failing in such a fashion.
LRG-TI RESPONSE:
Generic BWR/5, BWR/6 ECCS analyses were performed to show the sensitivity of peak clad temperature'to FCV' closure.
The analyses used the standard approved licensing models and assumed the FCV closed at a' rate of 11%/sec.
Peak clad temperature was calculated to increase 45*F.
Given the remote probability of FCV closure during the LOCA, this effect-on peak clad temperature is small and the event should not be considered a design basis event.
However, this 45*F increase does not push the peak clad temperature of any of the LRG-II plants over the 10CFR50.46 limit of 2200'F.
FLOW CCNTROL VALVE CLOSURE RATE Failure modes.and. effects analyses show thst, given a LOCA, no single failure in the electrohydraulic controls can cause the FCV to close.
Two failures are required tu signal the FCV to close during a LOCA:
failure of high pressure signals, such that FCV lockup does not occur, and a failure of the recirculation control system.
It is therefore unlikely that the FCV would be signalled or permitted to close during a LOCA.
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LRG-II POSITION PAPER 11/20/81 10-RSB (Page 2)
If however, the valve was signalled to close and was not locked up, the FCV actuator velocity would be limited to 1011%/sec by electronic velocity limiters. Additional multiple failures must occur for the full closure velocity to exceed this value.
The probability of failure of these
-7 specific components during LOCA is less than 10 per year because they don't experience a hostile environment.
The FCV analog flow control cabinet and hydraulic control unit are both located outside the drywell and are not subject to the loss of coolant accident environment.
Accor-dingly, actuator stroke rate of 11%/sec. was chosen as the maximum rate the valve would move, if it were to move at all.
PEAK CLAD TEMPERATURE CALCULATION Figure 10-RSB-1 is a generic plot of the peak cladding temperature vs.
time with and without FCV closure for the case which resulted in the largest peak clad temperature increase due to flow control valve closure.
The initial increase in PCT is caused by the earlier loss of nucleate boiling with FCV closure.
After boiling transition, the convective heat transfer coefficients for both cases are nearly identical for the remainder of the transient.
This earlier loss of nucleate boiling results in a higher heat removal rate for the FCV closure case and a decrease in the PCT difference to a value of 45 F at the time of reflooding.
NOTE:
The Grand Gulf SER establishes this generic analysis as a resolution of this issue.
MJA:rm:csc/150B18
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LRG-II POSITION PAPER 11/20/81 11-RSB USE OF NONSAFETY GRADE EQUIPMENT IN SHAFT SEIZURE EVENT ISSUE:
The recirculation pump seizure accident described in FSAR Chapter 15.3 takes credit for nonsafety grade equipment.
Section 15.3.3 of the Standard Review Plan, Revision 1, allows the use of safety grade equipment only and requires safety functions be accomplished assuming the worst single failure of an active component.
Reevaluate this accident using the SRP criteria and provide the resulting ACPR and percentage of fuel rods in boiling transition.
RESPONSE
Failure of nonsafety grade equipment during a Recirculation Pump Seizure event will not cause the MCPR to drop below 1.06.
Therefore, the consequences of the event are bounded not only by those of the design basis accident, but also by those of the most limiting anticipated transient presented in the FSAR.
Two nonsafety grade pieces of equipment are assumed to work in the FSAR analysis.
They are the turbine bypass valves and the Level 8 trip of turbine and feedwater pump.
It is appropriate to assume the Level 8 trip works because it makes the event more severe by turning it into a pressurization event (turbine trip).
If the turbine were not to trip, the event would be a mild decrease in core power with insignificant effect on fuel.
The most limiting combination of failures is a proper functioning of the Level 8 trip with failure of the bypass valves to open.
The sequence of events would be:
the pump seizes, causing the core power to decrease MJA: rm:csc/150819 11 /4n /01
I LRG-II POSITION PAPER 11/20/81 11-RSB (Page 2) due to decreased core flow. Water level would swell until the Level 8 trip tripped the turbine and feedwater pumps.
The event would then resemble a turbine trip without bypass but would be less severe than the one presented in the FSAR because of the reduced core power at the time of the trip.
The MCPR for the turbine trip without bypass presented in the FSAR is above 1.06.
The discussion above shows the FSAR analysis bour.ds the Recirculation Pump Seizure event so the MCPR for this svent will also be above 1.06.
i NOTE:
The Grand Gulf SER established this analysis as resolution of this issue.
MJA;rm:csc/150820
LRG-II POSITION PAPER 11/20/81 12-RSB PROPER CLASSIFICATION OF TRANSIENTS ISSUE:
Turbine trip without bypass and generator load rejection without bypass should not be classified as infrequent events in Chapter 15 accident analysis.
They should be classified as moderate frequency events.
RESPONSE
The LRG-II position is to change the classifications of generator load rejection without bypass and turbine trip witnout bypass to moderate frequency events. The consequences of these events are to be compared to the MCPR safety limit (1.06) for anticipated transients.
These events will not be bounding with this change of classification.
The Loss of Feedwater Heater event is still the bounding moderate frequency transient.
No changes to the analyses are required.
NOTE:
The Grand Gulf SER establishes this reclassification as resolution of this issue.
MJA: rm: csc/150821'
LRG-II POSITION PAPER 11/20/81
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4-CPB HIGH BURN-UP FISSION GAS RELEASE ISSUE:
General Electric's model for predicting fission gas release from the fuel pellets to the gap (GEGAP III) may underpredict the amount of fission gas released for fuel with burn-up greater than 20,000 mwd /T.
If the release of low thermal conductivity fission gas is underestimated, the calculated gap conductance wi11 be overestimated and the peak clad
' temperature calculation will be nonconservative A fission gas release enhancement factor will be required for fuel with burn-ups greater than 20,000 mwd /T.
RESPONSE
Application of the correction factor does not result in the 2200 F limit en peak clad temperature being exceeded.
The correction factor becomes significant for bundles with large exposure; these bundles are old and no longer are high power bundles.
During a LOCA the decrease in peak clad temperature due to the low energy level is more significant than the increase due to the NRC correction factor.
Table 4-CPB-1 taken from a letter from R. M. Pifferetti (GE) to R. L. Tedesco (NRC) dated August 21, 1981, illustrates this effect.
1 NOTE:
Grand Gulf SER establishes this approach as resolution to this issue.
MJA:rm:csc/150822
l LRG-II POSITION PAPER 11/20/81 4-CPB'(Page 2)
TABLE 4-CPB-1 GENERAL ELECTRIC ASSESSMENT OF NRC FISSION GAS CORRECTION FACTOR-PCT INCREASE LIMITING WITH PLANT MARGIN OVERALL PLANT FUEL EXPOSURE
'NRC CORRECTION TO 2200*F MARGIN TYPE TYPE (GWd/MT)
FACTOR (*F)
(*F)
(*F)
BWR/6 8x8R 22 10 70 60 28 40 140 100 33 85 270 185 39.
160 390 230 l
44 250 460 210 50 300
>460
>160 P8x8R 22 10 110 100 28 30 180 150 33 70 310 240 39 130 430 300 44 200 500 300 50 240
>500
>260 MJA:rm:csc/150823
LRG-II POSITION PAPER 11/20/81
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5-CPB CLADDING WATER-SIDE CORROSION (COPP,ER CONCENTRATION IN FEEDWATER)
ISSUE:
If copper bearing tubes are used in, for example, the main condenser tubes, a high corrosion rate related to the copper ion concentration in the feedwater may result.
Corrosion can be satisfactorily controlled thru the use of deep bed demineralizers capable of copper ion output in the PPB range with supplemental surveillance to determine that cladding corrosion is not occurring.
RESPONSE
Cladding water side corrosion due to copper is not expected to be a proalem in Clintoc or Perry condensate or feedwater systems because these plants use stainless steel tubes in this service.
River Bend, as described in FSAR Section 10.4.6.2, incorporates a deep bed condensate demineralizer system designed to maintain the condensate at the required purity
< the removal of contaminates.
At the design condensate flow and wi afluent quality for copper of 50 PPB (soluable and insoluable), the der....
lizers typically produce effluent containing metallic impurities of Fe Cu (as the metal) of 15 PPB max, of
'which total copper (soluaose a noluable) does not exceed 2 PPB max.
As a supplement to deep bed dem aralization, visual inspection will be used to detect corrosion.
Note:
Supplement 1 to the Zimmer SER established a 2 PPB Cu concen-tration limit with supplemental surveillance as resolution of-this issue.
MJA: rm:csc/150B2
LRG-II POSITION PAPER 11/20/G1 7-CPB ROD WITH0RAWAL TRANSIENT ANALYSIS ISSUE:
Is the analysis presented in the Perry FSAR, Appendix 158, applicable to all LRG-II plants?
The current design utilizes readings from the first stage of turbine to determine total reactor power.
This measurement is used as input to the rod withdrawal limiter (RWL).
However, if the turbine bypass valve is open, the core power may be underestimated by as much as the bypass capacity.
This in turn may violate the restrictions in the use of the rod withdrawal limiter.
RESPONSE
The Perry Appendix 15B "BWR/6 Generic Rod Withdrawl Error Analysis" is applicable to LRG-II plants.
Technical specifications will be written to prohibit rod movement at indicated power levels below the low power setpoint of the Rod Control and Information System if the bypass valves are open.
This will prevent inadvertent rod motion greater than allowed by the RWL.
If the bypass valves are open, power estimates based on measurements at the turbine first stage will be underestimated by 'the amount of bypass steam flow.
The RWL limits rod motion to 2.0 feet for indicated power levels between 70% and 20% power.
The rod pattern control system provides protection at power levels below 20% where the RWL is not operational.
If power is underestimated, it is possible for the reactor power to be greater than 20% but the RWL indicated power to be less than 20%.
Therefore, at reactor power levels above 20% the RWL may not be engaged where rod motion should be limited.
MJA:rm:csc/150824
LRG-II POSITION PAPER 11/20/81 8-CPB FUEL ANALYSIS FOR MISLOCATED OR MISORIENTED BUNDLES ISSUE:
Will the mislocated analyses be generic or reactor dependent? The presentations in Clinton and Perry FSARs are different.
Provide the impact of misorienting a bundle for the first cycle.
Why is this not covered in the FSAR?
RESPONSE
Mislocated Bundle Accident The Clinton and River Bend mislocated bundle accident analyses are generically applicable.
Perry has an older, more conservative analysis than Clinton and River Bend.
The early analysis of the mislocated bundle accident is based on 1 and 1 group diffusion theory and evaluates the change in core power distri-bution due to the misloading of fuel bundles.
This calculation shows the natural uranium bundle loaded next to an LPRM in the center of the core to be the limiting mislocated bundle accident.
A more detailed analysis shows this early analysis to be unrealistically conservative.
The early analysis does not account for the additional spectral effects of misloading fuel bundles as detected by the thermal neutron systems (LPRM and APRM).
The spectral effects of misloading a natural uranium bundle near a LPRM have been separately analyzed and compensate for the power depression effects (based on multigroup fine meshed diffusion calculations which account for the spectral effects).
Thermal margins i
actually increased for this event so it cannot be considered as a candidate for the limiting mislocated bundle accident.
MJA: rm:csc/150B25 l
L
LRG-II POSITION PAPER 11/20/81 8-CPB (Page 2)
Perry still reports the older analysis with a change in MCPR of
.114.
Clinton and River Bend do not consider this event for the reason given above so report the next most limiting event which has a change in MCPR of
.10.
Both analyses are valid and conservative.
Misoriented Bundle Loading Error The misoriented bundle loading error, i.e., rotated 180*, is of no consequence for C-lattice BWR plants.
The C-lattice configuration has equal size gaps on all four sides of the bundle, thus rotation would have no effect on the maximum R-factor.
Similar to the 0-lattice, the bundle in a C-lattice configuration would tilt axially due to the channel buttons at the top of the level assembly.
Contrary to the 0-lattice where the tilting tends to mitigate the effect of a rotation, the R-factor increases slightly for the C-lattice.
The net effect for the C-lattice is a ACPR of less than.05.
MJA: rm:csc/150B26 J
LRG-II POSITION PAPER 11/20/81 9-CPB DISCREPANCY IN VOID COEFFICIENT CALCULATION ISSUE:
Clarify why one calculates a different void worth (by a factor of 2) if the calculation is done by two different approaches.
For example, in the Perry FSAR comparison of data from Table 4.3-3, Reactivity and Control Fraction for Various Reactor States, gives a value of 0.074 (after subtracting 0.012 for the Doppler effects) while the result of integrating the curve (Figure 4.3-24) is aoproximately 0.03.
RESPONSE
The void worths differ significantly because they are calculated on two different bases:
Table 4.3-3 The void worth calculated by using Table 4.3-3 represents the total reactivity difference as the core goes from hot rated power, no xenon, to hot zero power, no xenon.
The power and void distributions simulated for each condition on the 3-0 reactor model are completely different (e.g., bottom peak for rated power, top peak for zero power).
Therefore, the equivalent spatial rating of local infinite lattice worth and the leakage effects are different between conditions.
Figure 4.3-24 Figure 4.3-24 is based on peint model calculations.
Nuclear parameters are volume weighted and power shape is not assumed to change with void fraction and ' leakage effects.
This curve is adequate for the purpose MJA:rm csc/150827
_a.
4 i
4 LRG-II POSITION PAPER i
11/20/81 i
9-CPB (Page 2) intended by the point model code:
transient analysis of events where relatively small changes in void fraction (a few percent or less) occur.
before the net reactivity becomes sufficiently negative to scram.
Integrating this curve over large void fraction changes is not repre-sentative of the true change in reactivity because the basic assumption of the point model basis is violated (e.g., power shape changes).
MJA: rm:csc/150828
LRG-II POSITION PAPER 11/20/81 10-CPB BOUNDING ROD WORTH ANALYSIS ISSUE:
FSAR Section 15.4.9 " Control Rod Drop Accident" states that no bounding analysis needs to be performed for a rod worth of less than 1% A-K.
Provide the basis for this statement.
RESPONSE
Sensitivity studies presented in References 1 through 4 show large margins in peak enthalpy for rod worths below 1% A-K.
This margin is sufficiently large that changes in Doppler coefficients, scram curves, reactivity insertion shape, etc. for rod worths below 1% A-K will not significantly reduce this margin.
Therefore, if the compliance check shows the rod worth is below 1% A-K the peak enthalpy for the Control Rod Drop Accident will be well below the 280 cal /gm limit.
No unique bounding analysis is needed.
References:
1.
R. C. Stirn, et al, " Rod Drop Accident Analysis for Large BWRs,"
March 1972 (NEDO-10S27).
2.
C. J. Paone, " Bank Position Withdrawal Sequence," September 1976 (NED0-21231).
3.
R. C. Stirn, et al, " Rod Drop Accident Analysis for Large BWRs,"
July 1972 Supplement 1 (NE00-10527).
4.
R. C. Stirn, et al, " Rod Drop Accident Analysis for Large BWRs,"
January 1973 Supplement 2 (NEDO-10527).
MJA: rm:csc/150829 i
LRG-II POSITION PAPER 11/20/81 a
4-ASB DESIGN ADEQUACY OF THE RCIC SYSTEM DESCRIPTION OF PUMP ROOM COOLING SYSTEM ISSUF:
TMI Action Plan Item II.K.3.2.4 identified the need to confirm the adequacy of the RCIC system pump room cooling system to maintain allowable room temperature for at least two hours during a loss of offsite power event.
RESPONSE
In order to protect the RCIC system pump and equipment in the pump room, the LRG-II participants have incorporated in their plant design a room cooling system.
The RCIC equipment area cooling system is designated as-an engineered safety feature.
The cooling system is sized for abnormal and accident conditions to maintain the RCIC system equipment within the allowable temperature limit (148*F) following a LOCA.
The heat sink for this cooling system is a safety grade cooling water system.
If offsite power is lost, area cooling for the RCIC_ system equipment would not be lost because the cooling system power supply and control circuits are powered from the same essential bus.
NOTE:
Grand Gulf SER establishes RCIC room coolers powered from essential busses on resolution to this issue.
MJA.:.rm: csc/150815
LRG-II POSITION PAPER 11/20/81 i
1-RAB 4
EXPOSURE RESULTING FROM ACTUATION OF SRV'S ISSUE:
4 f
The occupational dose assessment should include projected doses during normal operation and anticipated. operational occurrences. The doses to plant personnel in the reactor building following a Type 2 safety / relief valve isolation scram should estimate maximum doses to workers rather than the average values.
Provide the assumptions used in the 3
calculations and estimate the whole body, skin, and thyroid doses to plant personnel following a safety relief valve discharge.
^
3 i
RESPONSE
The LRG-II position is to estimate of personnel exposure resulting from the actuation of SRV's based on the GE document 22A5718 " Mark III Containment Dose Reduction Study". The dose analysis for the standard 4
plant design in the report is applicable to the LRG-II plants because of the similarity of designs.
The safety relief valve discharge event considered in the analysis is i
the Type 2 isolation event, in which the reactor pressure is initially controlled by the cyclic lifting of the SRV's. All SRV's are assumed to i
open with the low set relief valves remaining open following the closure I
of the other valves.
Design basis radiation sources for normal operation are used in the analysis.
Normal ventilation in containment is assumed and airborne concentrations are not corrected for plateout on the walls. The dose assessment methodology including the pool retention factors are provided in the GE reference document.
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Assuming a conservative egress time of four minutes for an opera'.or located in the TIP drive area, the estimated doses for the LRG-II plant personnel exiting containment.following a Type.2 blowdown event are provided below.
DOSE, MREM / EVENT LRG-II PLANT WHOLE BODY & EYE (y)
SKIN (s)
THYROID Clinton 140 390
.81 Perry 150 440
.87 River Bend (Later)
(Later)
(Later)
MJA:hmc/10Q 11/13/81 f
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LRG-II POSITION PAPER 11/20/81 2-RAB ROUTINE EXPOSURES INSIDE CONTAINMENT ISSUE:
High radiation levels may be expected in routinely visited areas of containment in the vicinity of major drywell shield penetrations.
Specific areas of concern are the reactor water cleanup rooms, standby liquid control areas, TIP station, CRD hydraulic control unit, and containmeat personnel lock.
Provide maximum neutron and gamma exposure levels in these routinely visited areas.
RESPONSE
All plant areas are categorized into radiation zones according to expected radiation levels and anticipated personel occupancy with consideration given toward maintaining personnel exposure as low as is reasonably achievable and within the standards of 10CFR20.
LRG-II plant penetrations are located and designed to preclude the possibility of streaming from high to low radiation areas or otherwise will be adequately shielded.
LRG-II participants provide expected maximum total radiation levels during operations and refueling and provide plant unique radiation zone These zone maps include all the routinely visited areas in the maps.
containment. Zone radiation levels include contributions from any potential streaming through the drywell shield wall penetration.
This information is provided in Section 12.3 of the respective FSARs.
MJA:hmc: pes /10R 11/13/81
o l
LRG-II POSITION PAPER November 13, 1981 3-RAB CONTROLLING RADI0 ACTIVITY DURING STEAM DRYER AND STEAM SEPARATOR REFUELING TRANSFER ISSUE:
Potentially high airborne radioactivity concentrations during refueling are expected since the steam dryer and steam separator must be transferred partially out of water.
In addition to maintaining the equipment wet, other methods should be outlined to reduce the airborne radioactivity during transfers.
RESPONSE
LRG-II participants erpect airborne particulate radioactivity concentrations during refueling similar to that observed at operating plants.
Data from other operating plant experience estimate radioactive particulate ranges on the order of 5x10-11 ci/cc. Total airborne radio-activity concentration, when the dryer was transferred in air, was about
-8 1x10 ci/cc.
The primary method of minimizing exposure to airbo ne radioactivity material is maintaining the equipment wet during the short time the steam dryer and part of the steam separator are out of water.
Additionally, LRG-II participants will implement administrative control to minimize personnel exposure, including direct health physics surveillance, use of respiratory protection equipment and containment access control during the transfer operation.
MJA:hmc:oes/10S 11/13/81
\\
LRG-II P.0SITION PAPER November 13, 1981 4-RAB SHIELDING OF SPENT FUEL TRANSFER TUBE AND CANAL DURING REFUELING
- ISSUE:
All accessible portians of the spent fuel transfer tube and canal will be shielded during fuel transfer such that contact radiation levels are less than 100 rads per hour. All accessible portions must be clearly posted to identify potentially lethal ' radiation fields during fuel transfer.
RESPONSE
LRG-II plants provide shielding designs for the fuel transfer tube and canal comensurate with the guidance of Regulatory Guide 8.8 that results 4
in radiation doses within the limits of 10CFR20.
Access to areas where contact with the fuel transfer tube may occur is administrative 1y controlled.
Radiation monitors with audible and i
visible alarms are provided for these areas.
Further protection against inadvertent personnel exposures is assured through system interlocks l
that prevent fuel transfer tube operation when these accessible areas are unsecured. Signs are posted stating that potentially lethal radiation fields are possible during fuel transfer.
i.
MJA:hmc/10T 11/I3/81 i
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LRG-II POSITION PAPER 11/20/81 1-ICSB FAILURES IN VESSEL-LEVEL SENSING LINES COMMON TO CONTROL AND PROTECTIVE SYSTEMS ISSUE:
Operating reactor experience indicates that a number of failures have occurred in BWR reactu. vessel level reference sensing lines and that, in most cases, the failures have resulted in erroneously high reactor vessel level indication.
For BWRs, common reference sensing lines are used for feedwater control and as the basis for establishing vessel level channel trips for one or sore of the protective functions (reactor scram, MSIV closure, RCIC, LPCI, ADS, or HPCS initiation).
Failures in such sensing lines may cause reduction in feedwater flow and consequen-tial delay in trip within the related protective channel.
If an additional failure, perhaps of electrical nature, is assumed in a protective channel not dependent on the failed sensing line, protective action may not occur or may be delayed long enough to result in unacceptable consequences.
This depends on the logic for combining channel trips to achieve protective actions.
It is our position that those reference lines common to the feedwater control function and to any of the protective functions for loss of feedwater events be identified and that the consequences of failures in such reference lines concurrent with the worst additional single failure in the protective systems (reactor scram, MSIV closure, ADS, RCIC, HPCS/HPCI, LPCI, etc.) or their initiation circuits by analyzed.
MJA:rm:csc/150830
. o LRG-II POSITION PAPER 11/20/81 o
1-ICSB (Page 2)
LRG II RESPONSE:
Relay Plants (Perry, River Bend)
The following assessment of a break in a vessel level sensing line, common to control and protective systems, in combination with the worst single failure in a protective channel shows the resulting accident is less severe than, and bounded by, the accidents described in Chapter 15 of the Perry and River Bend FSARs.
This conclusion is based on a detailed analysis of a 251 size BWR/6.
A comparison of the characteristic of the 218 and 238 size plants shows the analysis for the 251 size plant to be conservative.
All combinations of vessel level instrument line breaks and active single failures in the remaining three electrical divisions were examined to determine which combination had the most severe consequences.
The postulated failure path with the most severe consequences is:
failure of the Division 1 instrument line, from which feedwater is controlled, combined with an electrical failure in Division 3 Reactor Protection System (RPS) scram circuits.
Tnis combination will prevent the plant l
from scramming on Level 3.
t I
l The sequence of events is shown in Table 1-1C58-1. The high Division 1 level indication input into the feedwater controller causes feedwater to coast down to zero flow.
Level drops because the reactor is steaming at nearly full power but has no makeup water. When water level reaches Level 3 a scram would normally occur but, because of the assumed failures, it does not.
Scram does not occur because complimentary failures in the "one out of two, twice" logic, (Division 1 or Division 3) and (Division 2 or Division 4), are assumed.
The line in Division 1 is assumed to break in such a way that neither Level 3 nor Level 8 scram circuitry is initiated.
Division 3 RPS circuitry is also assumed to fail.
Therefore, it is not l
possible to activate the "one out of two" logic on the Divisions 1 and 3 side.
l MJA:rm:csc/150831 m
LRG-II POSITION PAPER 11/20/81 1-ICSB (page 3)
Water level will decrease through Level 2 where RCIC and HPCS will initiate and the recirculation pumps will trip to the low frequency M/G sets.
If the reactor does not scram from high drywell pressure or operator action, the water level will continue to drop to a minimum level somewhere above Level 1, still well above the top of the active fuel.
The reactor will settle out at an equilibrium power level of about 15% rated power.
The turbine will continue running and HPCS and RCIC will provide reactor makeup water.
The core will remain covered at all times and the MCPR will remain above 1.06.
No fuel will fail.
Automatic scram functions are still available; if the level were to drop below Level 1, the vessel would isolate causing
~
Low pressure ECCS is always available but is not needed.
The preceding analysis although done for a 251 size BWR/6 is applicable to the 218 and 238 size plants.
The minimum level that the water inventory would reach depends on the following factors:
(1) initial power level and power decay characteristics, (2) combined HPCS and RCIC flow capacities, and (3) the bulk water volume above Level 1.
The power decay characteristics are similar for the three plant sizes.
The combined HPCS and RCIC flow capacities, as a proportion of rated feedwater flow, are similar for the three plant sizes.
However, the bulk water to power ratios for 238 and 218 plants are approximately 3%
larger than that for a 251 plant, i.e., relatively more water inventory is available for 238 and 218 plants.
This assures that the minimum water level for 218 and 238 plants would not be icwer than that for a 251 plant.
MJA:rm:csc/150832
LRG-II POSITION PAPER 11/20/81 1-ICSB (Page 4)
Solid State Plants (Clinton, GESSAR)
The RPS logic in BWR/6 solid state plants requires an 2-out-of-4 channels to scram.
Therefore, if one RPS channel reads erroneously high due to the instrument line failure and any additional RPS channel is assuaed to fail, there are still 2 remaining channels left to accomplish norma!
Therefore, there will always be a normal Level 3 scram prior to auto-matic initiation of either (or both) high pressure coolant injection systems.
It is possible to fail RCIC or HPCS by postulating the addi-tional failure in ECCS busses 2 or 3 respectively.
However, both systems cannot fail due to a single electrical failure.
The postulated worst case scenerio is a break in the reference line on the division that is controlling feedwater in conjunction with a failure of the HPCS.
- Normally, the operator would switch feedwater control from tha failed instrument line to the operable one as soon as the level mismatch is detected by the annunciator alarm.
This would immediately restore normal water level.
Should the operator neglect to do this, the water level would continue to drop slowly until it reached Level 2.
A trip at this level would normally initiate both HPCS and RCIC and trip the recirc pumps.
Since a successful scram occurred at Level 3, RCIC is sufficient to cause water level to turn around between Level 2 and Level 1 and rise, slowly filling the vessel as power decays.
If still unattended, the vessel level will gradually increase until it reaches Level 8.
At Level 8, the RCIC turbine will trip and the main turbine stop valves will close.
The water level will drop back toward Level 2 and the cycle will repeat itself driven by the ever-decreasing l
l MJA:rm:csc/150833
LRG-II POSITION PAPER 11/20/81 1-ICSB (Page 5) residual heat decay in the vessel.
This will limit vessel water level between Level 2 and Level 8 until the operator takes the remaining shutdown action.
The postulated scenario therefore has no adverse safety consequences for BWR/6 solid-state plants.
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i MJA: rm:csc/150834.
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TABLE 1-ICSB-1 SEQUENCE OF EVENTS Time Events (sec) 0 One of the water level reference legs break (assume feedwater control relies on this instrument line).
Feedwater starts to decrease due to a f;1se high water level reading in the failed instrument line.
5:0 Feedwater flow decrease to zero.
6.9 Actual level drops to L-3.
No low level scram and high power source pump trip due to the failure of the reference leg and an RPS channel.
11.9
'4ater level drops to L-2, trips the recirculation pumps and also initiates RCIC and HPCS.
33.
HPCS and RCIC flow starts to enter vessel.
71.
Water level reaches minimum and begins to rise.
The minimum level is above the L-1 setpoint.
s200 A new equilibrium state is established at
$15% NBR power.
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MJA:csc/4-L1
LRG-II POSITION PAPER 11/20/81 1-HFS SPECIAL LOW POWER TESTING PROGRAM ISSUE:
TMI Action Plan Item I.G.1 indicated the need to supplement operator training by completing a special low power test program.
Further clarification to this item includes the need to perform a simulated loss of offsite and onsite A/C power.
RESPONSE
The LRG-II position is to develop a special low power test program using the guidelines provided in the report "BWR Owners' Group Program for Compliance with NUREG-0737, item I.G.1, Training During Low-Power Testing,"
which was transmitted to the NRC via a letter from D. B. Waters (Chairman -
BWR Owners' Group) to 0. E. Eisenhut (Director Licensing - NRC) dated February 9, 1981.
Licensed personnel and license candidates will parti-cipate in this training prior to full power operation.
The LRG-II position is to use the results from the first several simulated loss of A/C power tests at other BWRs to determine the need for such testing on their plants.
MJA:rm:csc/150816 L
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LRG-II POSITION PAPER
.11/20/81 3-HFS COMMON REFERENCE FOR REACTOR VESSEL LEVEL MEASUREMENT a
ISSUE:
Provide a common reference level for all reactor water level instruments.
RESPONSE
LRG-II plants use the bottom of the dryer skirt as the reference point for all RPV level instruments.
Only one instrument require a scale modification to meet this requirement:
the fuel zone level indicators.
The LRG-II position is to provide a fuel zone level instrument with two scales.
One scale will be referenced to the bottom of the dryer skirt 4
and the second scale referenced to the top of the fuel.
NOTE:
This issue is the subject of additional consideration by the HFS staff and LRG-II as a consequence of the staff's human factors review of the control room at the Clinton Power Station.
During that review it was agreed that Illinois Power Company will prepare full size sketches of proposea dual-scale.
i i
MJA.:.rm: csc/150835
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