ML19329B624
| ML19329B624 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 04/07/1977 |
| From: | Roe L TOLEDO EDISON CO. |
| To: | Stolz J Office of Nuclear Reactor Regulation |
| References | |
| 210, NUDOCS 8002050740 | |
| Download: ML19329B624 (53) | |
Text
__
O U.S. NUCLEAR REGULATORY CIMP2'S510N DOCK 7TNUMRPA MCsu,uia5 kg3 d (2 76)
NRC DISTRIBUTION roR PART 50 DOCKET MATERIAL FROM:
DATE OF DOCUMENT yg.
Toledo Edison Company 4/7/77 Mr. John F. Stolz Toledo, Ohio oATE RECEivEo Iowell E. Roe 4/8/77 de.sTTER O NOTORIZ E D PROP INPUT FORM NUMBER OF COPIES RECEIVED d.URIGIN AL NNC LAS$1FIE D OCoPY
[.7 d' 3 M OEECRIPTION ENCLOSU RE Ltr. trans the following:
Consists of documents describing the pressurizer heater interlocks that will be installed at Unit No. 1 prior to the start of the second fuel cycle.....
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(2-P)
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PLANT NAIE:
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4 LOWELL E. ROE April 7, 1977 v.c. en......
' ***a o=="5 Docket No. 50-346 Q
(4191 259-5242 Serial No. 260 Director of Nuclear Reactor Regulation Attn:
Mr. John F. Stolz, Chief Light Water Reactor Branch No. 1 Division of Project Management United States Nuclear Regulatory Commiss'.on Washington, D.C.
20555
Dear Mr. Stolz:
Attached are the following documents describing the pressurizer heater interlocks that will be installed at the Davis-Besse Nuclear Power Station Unit No. 1 prior to the start of the second fuel cycle:
1.
Revised FSAR pages 7-47, 7-47a, 7-47b, P.7.1.1-4, and P.7.1.1-5.
2.
Revised responses (all pages) to the questions on the Reactor Coolant System overpressurization protection and the locking out of power to valves DH-11 and DH-12.
These responses were originally submitted to the NRC on February 18, 1977 (Serial No. 220) as Enclosures 1 and 2.
3.
Revised Davis-Besse Unit 1 Technical Specification Page No.
3/4 5-4.
4.
Sket:hes No. E52B; Sheets 24A, 24B, 24C, 24D, 42A, 42B, 42C, 42D, 42E, 42F, 42H, 43A, 43B, 43C, 43D, 44.A, and 67 chowing the details of the pressurizer heater interlocks.
At the time the next FSAR revision is submitted to the NRC, all appro-priate sections in the FSAR will be changed to describe this new pres-surizer heater interlock. Also, the attached sketches will become part of the E&IC package when it is revised.
The attached revised FSAR pages and responses to your questions also describe temporary changes that will be made to the station setpoints and procedures until the pressurizer heater interlocks are installed.
i THE TOLEDO EDISON COMPANY EDISON PLAZA 300 MACISON AVENUE TOLEDO. CHIO 43652 t
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.The above submittals result indirectly from the meeting held with you and other members of NRC management on February 17, 1977, at which time we attempted to justify operation of the decay heat removal system with power removed from valves DH-11&l2 while in the DER mode. Although I have yet to receive a direct response as to your disposition of our meeting, on March 21 our Mr. E. C. Novak was informed orally by your Licensing Project Manager that our appeal to the NRC position was denied.
In an effort to bring the issue to resolution, my staff has continued to pursue alternative courses with NRC staff reviewers.
The concepts submitted with this letter have had preliminary review by NRC personnel, and reviewers have expressed favorable reaction. We strongly believe that this design modification will allow removal of power on DH-11&l2 and provide the assurance required, when increasing reactor coolant system pressure, that the valves are properly closed when necessary.
The operation of Davis-Besse Unit I will proceed as identified in the attachments to this letter.
Yours very truly, Attachments dh c/16-17 i
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.c D-3 T.6.1.1.2
System Description
The design of the decay heat removal system includes controls on each of the high-pressure motor-operated valves in the suction line from the RC system.
These independent and diverse controls are designed to automatically close l22 the valves or to prevent the opening of the valves when the RC pressure is above 280 psig sensed at the centerline of DH-11 and DH-12. A relief valve 123 is also included in the DH system piping.
In addition, an interlock is being provided which trips off the pressure heaters if the primary system pressure reaches 280 psig and either one or both valves are n'ot fully closed.
NOTE y
Until such time as this interlock for the pressuricer heaters is installed (prior to the second fuel cycle), the following temporary changes are being made to the system:
27
-1.
The.setpoint for the auto closure feature on valves DH-11 and DH-12 vill be changed from 280 psig to 381 psig which is 61 psig higher than the setpoint of decay heat removal system suction line relief valve PSV-10h9 2.
Power vill not be removed from DH-11 and DH-12 when the decay heat removal system is in operation.
3 Only one decay heat renoval punp will be used to take a suction through DH-11 and DH-12 at one time.
'This prevents overpressurizing the DH system in the event the valves are inadvertently left open during heatup or if an operator pre =aturely tries to
(, pen the valves during cooldown.
The automatic closing signal to one of the valves is derived from an RC pres-sure switch located in RC loop one(l). The automatic closing signal to the other valve is derived from a signal comparator located in the SFAS cabinet.
22 The signal comparator receives its RC pressure signal from the RC loop two(2) wide-range RC pressure transmitter that supplies the signal to the SFAS.
The automatic closure of the valves cannot be bypassed manually. Manual oper-ation is prevented as long as the RC pressure is above the setpoint pressure -
of the signal comparator and pressure svitch. At shutdown, the valves vill l22 2327 be opened and power removed as discussed in section 9 3 5 5_ (see NOTE above).
Revision 27 T-hT
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i D-B The pressurizer heater trip interlock signals are derived from the signal comparators located in the SFAS cabinets. The signal comparators receive their reactor coolant pressure signal from the RC loop 1 or 2 vide range pressure transmitter that supplies the signal for the corresponding SFAS cabinet.
The pressurizer heater trip interlocks are provided by means of relay logic in redundant essential relay cabinets. A separate output relay is provided for the essentially povered pressurizer heater control circuits and the non-essentially povered pressurizer heater control circuits, in each redun-dant " trip interlock logic." A contact from the same signal ecmparator in the SFAS that provides the RC pressure closing signal to one DH valve is used in one " trip interlock logic" to indicate RC pressure above 280 psig.
A similar signal comparator is provided in a redundant SFAS channel for the other " trip interlock logic." To provide limit switch contacts to indicate 27 that either valve is not fully closed into each redundant " trip interlock logic," a stem-mounted li=it switch is provided on both DH-11 and DH-12.
Each stem-mounted switch is redundant to the li=it switch provided in the motor-operator. Thus, all the necessary viring into the " trip interlock logic" is co=pletely separate and independent.
Valves DH-11 and DH-12 are autonatically closed by RC pressure signals as described above and both are located inside the CV.
Therefore, the valves are not controlled by the SFAS.
- 7. 6.1.1. 3 Supporting Syste=s The no=al decay heat re= oval valve control system obtains control power frem the essential power supply (Chapter 8).
7 6.1.1.h Portion of Syste= Not Required for Safety The alar =s to the station annunciator and station computer are not required for safety.
7.6.1.1.5 Drawings Electrical schematic diegrams of the normal decay heat removal valve centrol system are shown in Figures 7-8A, 7-8B, 7-8C, and 7-8D.
l22 6
Revision 27 T-hTa 27
~~
T.6.1.2 Core Flooding Tank Isolation Valve Control System A control system is provided to open the core flooding tanks injection isola-a.
tion valve and prevent their closing when the RC pressure rises above a pre-A complete description of the control system is given in section set level.
i 6.3.2.15 I
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Revision 27 l27 T-kTb
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p D-B the isolation switch is in the " CONTROL POWER OFF" position and the valve is open. A diverse and redundant stem-mounted limit switch provides an input to the plant computer, which is alarmed in the control room, when the valve is not open or the isolation switch is not in the " CONTROL POWER OFF" position or the disconnect switch is in the local position and bypasses the isolation switch.
5.
The valves HV-DH14A and HV-DH14B are normally open. The type of failure is the spurious closure of the valve. To meet 22 the single failure criterion by administrative procedure, both the hand / auto control station (analog control) and the open/ auto control switch (digital control) are lapt in the OPEN position. An alarm relay is provided to monitor the golenoid coil and input to the plant computer, which is alarmed in the control room if the solenoid is energized. Essential position indication is provided on the main control board. A diverse and redundant limit switch has been added on the valve stem to provide an input to the plant computer, which is alarmed in the control room when the valve is not open.
i i
6.
The valves HV-DH11 and HV-DH12 are closed during power operation, but must be opened to initiate decay heat removal.
The type of failure is a spurious closure of the valve during decay heat removal. To meet the single failure criterion, after the valves 24 are fully open and before the decay heat removable pumps are 26 started, the breakers of the combination line starters of each valve vill be tripped open and padlocked (see Section 7.6.1.1.2 7
for further details). Essential indication is provided on the i
1 main control board to indicate the valve is open.
c.
1.
The valves HV599 and HV608 can have power restored by the
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operator from the main control room by properly aligning the 4
control switches of both starters to the same position. The plant condition which requires operation of the valve is a 22 steam line or feedwater line rupture. A signal from the SFRCS will assure proper alignment of the two starters to return power to the valves.
If the automatic signal to close the valve to the affected steam generator fails, no operator action is required since the appropriate auxiliary feedwater alignment valves will also remain closed.
2.
Tha valves ZV5037 and HV5038 do not have control power removed. For a discussion of conditions requiring operator action,see the discussion under item "o, above.
23 3.
The valves HV-CFlA and HV-CF1B have no system safety function that requires them to be closed except as described in subsection 6.3.2.15 and summarized here.
Power will be removed from the valves after depressurizing the reactor coolant system below 300 psig and prior to j
initiating decay heat removal if the core flood tanks are l
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Revision 27 l
P7.1.1-4 l
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D-B pressurized. With power rencved, the possibility of the valves opening and causing either the pressure-temperature limits of the RC system or the design pressure limits of the LHR system to be exceeded, is precluded.
23 4.
The valves HV-DHlA and HV-DHlB have no system safety function that requires automatic closing, although they are containment isolation valves which can be closed remote manually. However, the operator can restore power to the valve from the main control board by use of the isolation switch.
5.
The valves HV-DH14A and HV-DH14B may have control power restored from the main control board (for throttling in the post-LOCA long term cooling mode of operation) when the operator pushes the AUTO button on the valve control switch if the normal air supply is available. If it is not available, the valve can be throttled manually by use 23 of a seismically qualified air supply provided locally in a low-radiation area for utilization of a portable air bottle. A local essential flow indication is available to.the local operator.
6.
Valves HV-DHil and HV-DH12 are operable from the control room; removal and restoration of electric power is accom-plished from the breaker at the motor control center for each valve. Should the valve inadvertantly close after being opened but prior to the operator removing power from the breaker, decay heat can continue to be removed by the 24 auxiliary feedwater system via the steam generatorsn he decay T
heat pumps will be started af ter the_ valves are opened and power is removed to preclude damage to the pumps (see 27 Section 7.6.1.1.2 for further details). Should the valve be open when the operator intended for it to be closed
.upon unit startup, this could not lead to an unsafe lconditionsincetheonlyconsequencewouldbethatthe tunit could not be pressurized.
If, after power has been treturned to DH-ll and DH-12, only one valve closes, an interlock is provided to trip off the pressurizer 27 heaters as described in FSAR Section 7.6.1.1.2 which prevents the unit from being pressurized.
. Revision 27 P7.1.1-5
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INTERIM SOLUTION FOR ENCLOSURE 1 (First fue l. cyc le )
1.
Describe all design and operational features or procedures for Davis-Besse Unit No. I that will minimize the likelihood of violating 10 CFR Part 50, Appendix G limits. Your letter to NRC, dated December 7, 1976, did not adequately address such procedures.
RESPONSE
As discussed briefly below there are numerous design and operational features that assure the Appendix G limits are not exceeded for the first five (5) effective full power years.
Design features:
1.
The metallurgy of the reactor vessel is such that the girth weld on the vessel is not limit-ing with respect to overpressurization for the first five (5) effective full power years,
therefore, the Appendix G limits are highar than other 177 fuel assembly design plants for this period.
2.
The pressurizer is never, with the exception of the code hydro, permitted to be in a solid condition which assures a steam or nitrogen bubble to dampen any overpressurization event.
3.
The make up pumps are high head low capacity (160 gpm) pumps which permit only a slow increase in pressure in the event of an inad-vertent start.
4.
The steam generator secondary volume is small which limits a potential primar system pres-sure increase caused by heating of the secon-dary side of the generator and transferring that heat to the primary system.
5.
A computer alarm is provided which alerts the operator when the primary system pressure is within 200 lbs. of the Technical Specification limit for any primary temperature.
6.
The decay heat suction liae, while the decay heat removal system is in operation, is pro-tected by relief valve PSV-4849 (see FSAR fig-ure 6-17).
PSV-4849 has been sized to pass 1
February 18, 1977 1
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1800 gpm at a set pressure of 320 psig.
The relief valve is a seismic class I Nuclear Class
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2 Q-listed bellows type" safety-relief.valvt.
The valve has been sized to accommodate a flow that is twice that which would be experienetd assuming the worst credible overpressurization accident during decay heat removal system oper-ation Operation Features:
The following is a short outline of the chronological events that will take place on a cooldown and heatup.
Outlined are the operator actions and the alarms that alert the operator that a required action should be taken. Note that only those portions of the cooldown and heatup that are applicable to possible overpre-surization are outlined. The actual procedures are in far more detail Plant Cooldown from a Hot Standby Condition 1.
Cooldown is commenced at a rate equal to or less than 100 F per hour using both steam generators.
The use of both steam generators prevents the pec-sibility of the secondary system being hotter than the primary system.
(If only one steam generator can be utilized for cooldown the idle generator shell must be maintained within 100 F of the reactor coolant system (RCS) temperature).
2.
Pressurizer level is slowly being decreased from a level of 220" to 60" over the course of the cooldown.
3.
Flow is maintained in both RCS loops with at least one reactor coolant pump running when cooling dos,n with steam generators which assures that there is no temperature stratification within the RCS.
4.
The SFAS is blocked when depressurized below 1800 psig. The RCS low pressure trip is blocked to pre-vent actuation of the ECCS system.
The operator gets a permission to block signal at 1800 psig.
1Rie trip must be blocked prior to reaching 1600 psig.
5.
The rupture contral system must be blocked prior to the main steam prestire reaching 600 psig. A per-mission to block alarm is sounded at 650 psig.
If the operator did not ' lock the system and it tripped, o
the auxiliary feedwater system will be started and the two steam generators isolated which has no ad-verse affect.
2 February 18, 1977
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6.
When RCS pressure reaches 700 psig the operator receives an alarm that tells him to close
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re-move and lock out power to the core flood', tank outlet valves.
If this operation is not com-pleted by 675 psig another alarm is sounded.
If the valves are not closed there is no safety implication. The tanks will " float" on the pri-mary and as such, depressurize at the same rate as the primary system.
In this event the oper-ator will receive two additional alarms - CFT low pressure and low level.
7.
At 600 psig the operator gets a permission to block alarm for the RCS low low pressure trip.
The block must be initiated before system pressure reaches 400 psig.
8.
Pressurizer level is maintained at 60" when RCS pressure is 310 psig.
9.
When RCS is below 280 F one HPI train is removed from service by racking out power to the pump.
10.
When the RCS temperature is between 280 F and 340 F and the pressure is less than 260 psig, the DHR system is placed in operation by opening DH-11 and DH-12 and removing power from their motor operators. The Dacay Heat Remov:1 pumpe ::: then placed in operation.
11.
At 30 to 50 psig in the pressucizer, nitrogan is injected to maintain a bubble in the pressurizer.
12.
At 200 F in the RCS the second HPI train is re-moved from service.
13.
At 150 F the makeup system is removed from ser-vice. It is needed up to this time to provide seal injection flow to the RCP seals.
Plant Startup from Cold Shutdown 1.
A steam bubble is drawn and the nitrogen is vented from the pressurizer with level' main-tained at approximately 75".
2.
The make up system is placed in operation to supply seal injection flow to the reactor cool-ant pumps.
3.
The RCS system pressure is increased by the use of the pressuriizer heaters to between 200 and 250 psig (maximum pressurizer heatup rate is 100 F/hr.).
3 February 18, 1977
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4.
One reactor coolant pump is started and as ".
Loon as possible (within 10 minutes) a second pump is started in the same loop.
5.
Stop the DHR pumps.
I. Place one train of HPI in service at 200 F.
7.
Prior to reaching an RCS temperature of 280 F place the auxiliary feedwater system and the second train of HPI in service.
8.
Heat up to a temperature above 280 F at a rate not to exceed 50 F in any 1/2 hour period. The actual heatup rate obtainable is about 13 F per hour per pump plus the reactor core decay heat.
9.
When RCS temperature reaches 300 F, the system pressure is increased by use of the pressurizer heaters.
10.
Restore power to valves DH-11 and DH-12 and in-crease RCS pressure to above 260 psig (sensed at primary system pressure tap) and assure that they automaticaly close and the pressurizer heaters trip off then turn the pressurizer heaters back on.
Note:
a As indicated in FSAR Section 7.6.1.1.2 an interlock is being provided to trip off the pressurizer heaters at 260 psig (sensed at the primary system pressure tap) if both DH-11 and DH-12 are not fully closed. Until the additional interlock is installed the temporary changes described in FSAR Section 7.6.1.1.2 will preclude an actual test of DH-11 and DH-12. The operability test of DH-ll and DH-12 will be accomplishd with a test signal.
11.
Start a third reactor coolant pump when the RCS pressure is greater than 315 psig.
12.
Prior to exceeding an RCS pressure of 500 psi, reset the SFAS low low pressure trips.
13.
Prior to exceeding 700 psi RCS pressure, unlock and restore power to che core flood tank outlet valves.
4 April 7, 1977
14.
Verify that at a pressure of 800 psig RCS pres-sure, that the core flood tank outlet valves auto-matica11y open. An alarm will actuate at 720 psig indicating that the valves are not open.
15.
After the core flood tank outlet valves have opened, remove and lock out power to the valves.
16.
When RCS pressure is between 1650 and 1700, reset the SFAS low RCS pressure trip.
17.
Increase RCS pressure to 2000 psig.
13.
Increase RCS temperature to greater than 520 F and start the fourth reactor. coolant pump.
19.
When Tave is at 582 F the pressurizer is raised to 180 inches.
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4a April 7, 1977
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2.
Provide assurance that the startup of a reactor coolant pump will not cause an Appendix G violation by. virtue of circulating cold water into the secondary system (steam generator) a'nd increasing temperature with a resultant significant change in pressure. What a,dministrative procedures are employed to prevent inadvertent reactor coolant pump startup? What are the consequences of an inadvertent reactor coolant pump startup?
RESPONSE
Several postulated situations have been examined which may lead to primary fluid expansion due to energy absorption from hot OTSG secon-dary water af ter start of an RC pump. The two types of situations which lead to possible RCS pressurization have been identified as follows:
Type A.
Filling of OTSG secondary side with hot water with subsequent start of an RC pump, and Type B.
Restarr of an RC pump during heatup following a period of stagnant (no flow) conditions.
Start of an RC Pump Under Type A Condition Figure number 1 presents results of RCS pressure versus time for the worst case Type A (see above) condition.
Initial conditions for this transient are a result of filling of the steam generators with feeduster at 420 ". At Davis-Besse, the maximum feedwater temperature from the deaerator is 300 F, and the high pressure feedwater heaters are not available until the reactor is at power. The temperature of the feedwater in the OTSG secondary side following the filling with the assumed 420 F water reaches a temperature of 240 F as does the primary water contained in the RCS at elevations greater than the lower OTSG tubesheet.
This is a result of the heating of OTSG tubes and primary water during OTSG filling where heated primary water circulates to a limited extent through the RCS.
At the end of the filling opera-tion, the RCS water located below the OTSG lower tubesheet remains at the initial value of 140 F.
The primary system pressure versus time as shown in Figure 1 is based on an initial pressurizer level et the maximum value of the high-high level alarm for a 177 FA plant.
The initial pressurizer level is normally kept much lower to minimize the heating requirements for raising the pressurizer temperature and pressure in preparation for starting an RC pump.
The initial pressure is 300 psig, the normal pressure required prior to starting an RC pump. No credit has been taken for pressurizer level control.
The pressurizer level increased during the transient by 30 inches; the level would have to rise an additional 70 inches before entering the upper head.
Other conditions of primary and secondary temperatures which may exist prior to starting of an RC pump have been evaluated and are bounded by the results of Figure 1.
These conditions include the situation where the feedwater temperature entering the OTSC's during filling operations 5
February 18, 1977 s _
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is at the normal maximum value of 225 F but the operator fills the steam generators beyond the maximum allowable level and completely fills the steam generators.
In addit-ion, the results presented here bound the case where the initial RCS temperature is'50 F before filling the steam generators.
In all of the above cases, the pressure-temperature limits of the RCS were not exceeded for the Type A event.
Start of an RC Pump Under Type B Conditon Figure number 2 presents results of RCS pressure versus time for the Type B conditions (see above).
Initial conditions for this transient are a result of the accumulation of pump seal injection and makeup injection water in the RC cold leg piping during stagnant (no flow) conditions. Although the operator is required to initiate a cooldown of the RCS if RC pumps are inoperable and RC temperature
> 250 F (Plant Limit and Precautions), the assumption is made that the operator fails to do so while allowing makeup and seal injection water temperature to drop to 50 F, which is below the minimum value of RC temperature less 120 F.
The cold water is assumed to accumu-late in the RC cold leg piping without mixing with hot RC water.
The RC pump is started following a period of one hour of stagnant (no flow) conditions in the RC System.
The primary system pressure versus time as shown in Figure 2 is based on an initial pressurizer level at the maximum value of the h* gh-h'gh level alarm tor a 177 FA plant. The initial pressure is 450 psig which is approximately midway between the Tech. Spec. and RC pump NPSH pressure limits at 275 F.
No credit has been taken for pressurizer level control. The decrease in pressure at approximately 2 minutes is a result of hot RC primary fluid entering a steam generator which has been cooled by the passage of the slug of low temperature RC fluid (the mixing of RC fluid and heat transfer through the OTSG tubing brings the RC fluid to a constant temperature and produces a net contraction of the fluid and a decrease in system pre-sure at final equilibrium conditions). The pressurizer level increases during the transient by 13 inches; the level would have to rise an additional 87 inches before entering the uppper head.
In the above case, the pressure temperature limits of the RCS was not exceeded for the Type B event.
In conclusion, the preceding evaluation and analysis demonstrates that the RCS is protected from overpressurization during RCP startup events.
Further, at any time it makes no difference if it is an inadvertent or normal RCP startup.
6 February 18, 1977
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'3.
Discuss how the safety features actuation system (SFAS) pre-cludes single spurious signals or oper'ator error from initiat-ing high pressure injection (HPI) pumps.
s
RESPONSE
The SFAS system is designed as a 2 out of 4 logic system. A single spurious signal failure will reduce the system coin-cidence logic from a 2 out of 4 logic to either a 2 out of 3 or a 1 out of 3 coincidence logic.
Neither of the reduced logie modes can cause an inadvertent actuation of the HPI system.
The only possible methods by which the HPI pumps could be actuated by SFAS are 4 psig containment pressure or by an operator inadvertently manually tripping the SFAS. If the manual trip button is depressed one train of the ECCS system will actuate causing one HPI pump to attempt to inject water into the primary system. Relief valve PSV-4849 has been sized for twice this condition.
4.
Provide the basis for the initial temperature of 280 F and the initial pressure of 735 paig assu=ptione uced in the inadvertent HPI startup transient.
RESPONSE
By administrative control the unit will stay on the DHR system until 280 F is reached. At the RCS pressure tap the pressure
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will be between 200 and 260 psig. A pressure of 235 psig was used for the transient.
The.only significance of the initial pressure is that the lower the initial pressure the longer the time it takes to reach the set. point of 320 psig for PSV-4849. FSAR figure 9-29 shows the sequence of events for the transient of two HPI pump initiation starting at 235 psig.
5.
How sensitive is the pressure excursion event to the assumption that the DHR pumps are operating?
RESPONSE
The pressure excursion was considered both with the decay heat removal system in operation (3000 gpm per train) and with the system secured. - The pressure drop in the decay heat system 7
February 18, 1977
- s
- s suction line in operation is 15.9 psi (6000 gpm) and 26.4 psi with 7800 gpm which would be the flow if both pumps were running and there was 1800 gpm flow from PSV4849.
It can be seen that with the DHR system in operation at full capacity the primary system would be subjected to a 26.4 psi greater pressure than if the DH pumps were stopped in the event of a relief valve lif t.
The 26.4 psi increase in pressure will not exceed the Appendix C limits.
6.
The staff considers it essential that all plant operators be made aware of the details of the overpressure events which have taken place at all facilities.
Formal discussions should be held to review the causes of past overpressure transients, the plant con-ditions at the time, the mitigating action that could have been or was taken, and the preventive measures that could have been taken to avoid the event and the steps taken to prevent similar further occurrences.
Identifying plant similarities and dis-tinctions, and discussing how these relate to plant startup, shutdown, and testing opers.tions are also necessary. Provide a schedule for conducting the above discussions.
RESP 0 HSE Applicant has reviewed the industry incidents of overpressuriza-tion, and has found that the B&W NSSS's have incurred only one (1) such incident, which resulted frLu an erroneously planned plant evolution conducted during system zero power physics testing. Applicant's operating staff, including plant operators, have been apprised of the concern with the overpressurization occurrences in the industry. Operating personnel are cognizant of system design and written operating procedures reflecting protection against such occurrences at the Davis-Besse facility.
7.
(a) Provide a pressure-temperature diagram for the primary system indicating:
Cut-in point of DHR system (operator action)
Isolation point of DHR system (operator action)
Cut-in point of RC pumps Shut-of f point of RC pumps Setpoint of RHR relief valve Automatic isolation setpoint of DHR Isolation of core flooding tanks 8
February 18, 1977
n.
Isolation of ECCS Initiation of nitrogen bubble in the pre'ssurizer Initiation of steam bubble in the pressurizer i
RESPONSE
A pressure-temperature diagram for the primary system, indicating the above information, is provided as figure 3.
The figure also shows the RCS pressure-temperature limits for heatup and cooldown for the first five EFPY, applicable for heatup and cooldown rates of $ 100 F/hr.
(b) Provide operator instructions relative to actuating and deactivating the RHR system and reactor coolant pumps.
RESPONSE
The Applicant will provide the Licensing Project Manager with copies of the requested procedures on or before Fehri'ary 25, 1977.
8.
(a) Provide the operator instructions for performing the isolation of the ECCS equipment.
RESPONSE
The Applicant will provide the Licensing Project Manager with copies of the requested procedures on or before February 25, 1977.
(b) Provide the operator instructions for activating the ECCS equipment.
RESPONSE
The Applicant will provide the Licensing Project Manager with copies of the requested procedures on or before February 25, 1977.
9 February 18, 1977
8.
(c) Discuss the safety significance of having ECUS equipment locked-out of service during startup, cooldown, and refueling. Describe what alarms are available to alert the operator to an accident situation during this period. Discuss the tims available to activate the ECCS if required.
RESPONSE
The safety consequences of a LOCA occurring during heatup and cool-down operations is discussed in the response e.o Question 12 cubmitted in Revision 13 of the Davis-Besse Unit 1 FSAR dated June, 1975. This response can be found under tab titled " Regulatory Position", Volume 9.
The probability of a LOCA requiring automatic ECCS actuation occurring in this period is considered extremely small, in part, due to the very small fraction of the plant life that the plant is in a heatup or cooldown mode.
In addition to the above, the operator would be alerted to the occurance of a LOCA, as noted below:
If a LOCA occurred between the pressure of 1500 and 400 psi the following indication and alarms will be available to the operator:
1.
High makeup system flow alarm 2.
Low makeup tank level alarm 3.
Low pressurizer level alarm 4.
Low reactor coolant pressure alarm and SFAS actuation of containment isolation and low pressure injection system 5.
Containment high radiation alarm - SFAS actuation of containment isolation 6.
Normal sump high level alarm 7.
Increasing containment pressure and temperature indication 8.
Core flood tank low level and pressure alarms (if LOCA is above 675 psi) 9.
High containment humidity 10.
Containment cooler condensate flow high If a LOCA occurred between the pressure of 400 and 280 psi the following indication and alarms are available to the operator:
1.
High makeup system flow alarm 2.
Low makeup tank level alarm 3.
Low pressurizer level alarm 4.
Containment high radiation alarm - SFAS actuation of containment isolation 5.
Normal sump high level alarm 6.
Increasing containment pressure and temperature indication 7.
High containment humidity 8.
Containment cooler condensate flow high Refer to FSAR Table 7-8 for more information on the above instru-mentation.
' 10 February 18, 1977
- 8. (d) Discuss the position indication and status signals which could be lost as a result of deenergizing of components.
Discuss the safety impact as a result of losing this infor-
- mation, s
RESPONSE
In all cases where power has been removed from components to prevent their inadvertent operation redundant position indica-tion powered from a separate source has been provided to assure that the operator has position indication at all times.
In addition the operator is provided with a " blue" light which is illuminated when power is removed from the valve.
If a component is deengergized due to a loss of power it will fail in its safe position or has a redundant component that serves an identical function that will operate if required.
For the above mentioned reasons, there is no safety impact as a result of the loss of position and status signals.
9.
Several Appendix G violations have occurred during component or systems tests while in cold or shutdown conditions.
(a) What components or systems that could cause overpressure transients are routinely tested while in cold shutdown conditions?
(b) What extra measures are taken to prevent an overpressure event during these tests?
RESPONSE
a.
The two systems which could be tested while in a cold shutdown condition are the HPI and makeup systems.
In a cold shutdown condition valves DH-11 and 12 are open and relief valve PSV-4849 protects both the decay heat removal and reactor coolant systems from overpressurization.
While in a hot shutdown condition RCS temperature greater than 280 F, the Appendix G Limit is above the shut off pressure of the HPI pumps. The makeup system was analyzed and it was determined that the makeup pump would trip on low suction pressure prior to overpressurizing the reactor coolant system (Ref. analysis described in the answer Item 3 of the long-term solution).
b.
By procedure the only time the HPI system will be tested 11 February 18, 1977
- 7 with the flow path to the reactor coolant system is when the reactor vessel head is off or the* primary system temper-ature is greater than 280 F which assures that the Appendix C limit will not be violated.
- 10. The staff requires that a high pressure alarm be used dur" g
low reactor coolant system temperature operations to attract the operator's attention to a transient in progress. Although this would not be a mitigating device, the staf f requires that it be installed.
Provide the following information:
(a) Your method to provide the alare, and associated time schedule.
(b) A synopsis of system modifications that are necessary.
(c) The alarm setpoint, mode of annunication, and sensor.
(d) Your means to assure the alarms availability during cold shutdown conditions.
RESPONSE
Prior to fuel load the computer will be programmed a.
to provide an alarm to the operator if primary pressure is within 200 psig of the Technical Specification limit at the temperature which the reactor coolant system is operating.
b.
No hardware changes are required.
c.
As indicated in 'a' the setpoint for the computer alarm is 200 psig below the Technical Specification limit at the temperature which the reactor coolant system is operating. The sensors used to provide the alarm are the reactor coolant cold leg pressure censor and the RCS wide range temperature sensor, d.
The alarm will be available at all times except when the computer is down for maintainence.
If the computer is down, the operator has been instructed to monitor his control console RCS pressure and temperature indication closely to assure that no limits are exceeded. In addition there is a normal sump alarm, and low pressurizer level alarm that would alert the operator of an over pressuri-zation event that is lifting relief valve PSV-4849.
12 February 18, 1977
F.
- 11. Reactor coolant systems (RCS) heatups, resulting from improper operation of the reactor coolant pumps while in cold shutdown and water-solid conditions have been responsible for a ' number of RCS overpressure events. Since Davis-Besse Unit No. I does not intend to operate in the water-solid condition, provide an analysis to show what margin in time is gained by using the nitrogen blanket and steam bubble in the pressurizer during cold conditions. The staff will require that adequate procedures be used to prevent RCS pump starts during shutdown conditions unless necessary.
In those cases where RCP starts cannot be avoided, appropriate steps should be taken to determine and minimize temperature difference between primary and secondary system.
Provide the following information:
(a) What are the temperature limits before the first RCP can be started in a cold RCS?
(b) Specify the instruments used to determine the RCS temperature profile.
(c) Provide the necessary schematics and procedural description that show your actions to bring the RCS to an isothermal condition.
(d) Specify any other measures you take to reduce RCS pressure spikes during RCP starts (i.e., open all letdown orifice isolation valves, stop makeup flow, etc).
RESPONSE
(a) The limitations on RCP operation are provided in response to Questions 1 and 7.
(b) The instrumentation along with its range, type of readout, number of sensor channels, accuracy and location are in-dicated in FSAR Table 7-8.
This has also been discussed in our letter dated December 7,1976.
(c) A summary of actions is provided in response to Question 1.
(d) A discussion of the pressure transients due to RCP starts is provided in response to Question 2.
I 12.
To prevent an overpressurization incident due to CFT actuation, the applicant has noted that procedures will instruct the operator to close and remove power from the moter-operated isolation valve in each CFT.
The staff notes -that a further reduction in the likeli-hood of a CFT overpressure event would exist if the operator de-pressurized the CFT's to a pressure below the maximum allowed by 13 February 18, 1977
the P-T limits. He would then close and remove power from the iso-lation valves. Discuss die feasibility,of adopting such a procedure.
RESPONSE
As described in the response to Item 2 of the long term solution portion of enclosure 1, the inadvertent opening of the core flood tank valves is not considered a credible event.
The venting of the tanks during shutdown is not feasible ac it would impose severe operating limitations on the unit. The waste gas system design would require that thee venting operation be done very slowly and, therefore, cause delays on shutdown.
- Further, the nitrogen required to repressurize the tanks on startup would deplete the large majority of nitrogen maintained on site.
13.
If any administrative control for overpressurization during a startup or shutdown presented above would comptomise plant safety, discuss why and consider whether the procedure could be improved.
RESPONSE
In no case does administrative control compromise plant safety.
14 Febttary 18, 1977
LONG-TERM SOLUTION
- 1.
- Submit an alternate proposal for modifications which.will provide protection for overpressure transients during startup or shutdown.
The long-term solution should satisfy the following requirements.
(a) Credit of Operator Action - No credit can be taken for oper-ator action until 10 minutes after the operator is aware that a pressure transient is in progress.
(b) Single Failure Criteria - The pressure protection system should be designed to protect the vessel from the worst case pressure transient.
In this area, redundant or diverse pressure pro-tection systems would be considered as meeting the single fail-ure criteria.
(c) Testability - The equipment design should include some pro-vision for. testing on a schedule consistent with the frequency that the system is used for pressure protection.
(d) Seismic Design and IEEE 279 Criteria - Ideally, the pressure protection system should meet both seismic Category I and IEEE 279 criteria. The basic objective, however, is that the system should not be vulnerable to an event which both causes a pres-sure transient and causes a failure of equipment needed to term-inate the transient.
RESPONSE
The protection against exceeding Appendix G limit which has been described in the responses to the Interim Solution portion of en-closure 1 is applicable for the first five (5) effective full power years. Those f tures are consistent with the above requirements and are discussed below.
4 a.
No credit is taken for operator action to prevent the RCS from exceeding the Appendix G limit, b.
No single active failure can compromise the over pressure protection of the RCS. PSV-4849 has been sized to mitigate the consequences of the worst credible overpressurization transient while the DHR system suction valves (DH-ll and DH-12) are open. Relief valve PSV-4849 is a passive device and as such is not subject to a failure to open.
When DH-ll and DH-12 are closed, the RCS tempera-s ture is greater than 280 F and the Appendix G pressure limit (Reference Figure 3) is higher than the shut off head of the HPI pump.
An interlock is provided which trips off the 15 April 7. 1977
pressurizer heaters if both DH-11 and DH-12 are not fully closed which prevents the RCS from. being pres-surized unless both DH-11 and DH-12 are closed.
In addition, as described in the response to Item 3 below, the make-up pump will trip on make-up cank lov level prior to exceeding the Appendix G limit.
c.
Relief valve PSV-4849 will be tested to assure operability and proper set pressure every refuel-ing outage, d.
The present Davis-Besse Unit i design meets the specified requirements.
A modification to provide Appendix G protection after the first five (5) effective full power years will be submitted for staff review at a later date.
i N
15a April 7, 1977
.s 2.
The rationale for analyzing ECCS actuation, but excluding an analysis of CFR actuation, does not appear consistent.
It would appear that bounding calculations for both events are warranted.
Please clarify.
RESPONSE
The possibility of an inadvertent opening of the core flood tank outlet valves was analyzed and due to the design and operating procedures of the station is considered not credible. The perti-nent design features are referenced below and in the response to Item 1 of the interim solution portion of enclosure 1.
In order to ensure that the core flood tanks will not dump into the reactor coolant system, one option available to the operator is the removal of power from the core flood tank isolation valves once they are closed. To this end, the unit includes the following features, as discussed in FSAR subsection 6.3.2.15:
Position switches on each core flood tank valve actuate open and close valve position indication for each valve. The indicators are located in the control room.
Two separate alarms, one for each valve, are actuated if a valve is open and reactor coolant pressure is reduced to a value that could cause emptying of the core flooding tanks; these alarms alert the operator to an impending situation where he could inadvertently discharge the core flooding tanks during station shutdown.
The isolation valves will be closed, power removed and locked out, prior to depressurizing the reactor coolant system below 675 psig.
With power removed, the possibility of the valves opening and causing either the pressure-temperature limits of the RC system or the design pressure limits of the DHR system to be exceeded, is precluded.
Assuming that the unit is undergoing cooldown from the hot shutdown condition, the following events will take place:
As RC pressure decreases below 675 psig, the alarms are actuated in the control room if the operator has not closed the valves prior to this pressure. The operator would then close the valves to deac-tivate the alarms. Failure to close the valves would require a 16-April 7, 1977
double operator error.
First, the operator must fail to follow the procedure which specifically instrue,ts him to close the valve.
Second, the alarms resulting from the open valve at a pressure below 675 psig would have to be ignored by the operator.
In the event that no action was taken and the valves are not closed, there is no adverse effect on the safety of the plant since the tanks will " float" on the RCS and as such, depressurize at the same rate as the primary system.
When power is removed from the valves, in the cases described above, the breaker of the combination starter of each isolation valve will be manually tripped open and padlocked. The tripped position of the breakers will be monitored by essential indication of the main con-trol board by one blue indication light for each breaker.
3.
Include a discussion of makeup pump potential for causing overpressure events and the rationale for the contention that these high head pumps would not be worst case, j
RESPONSE
The potential capability of the MU pumps to cause a reactor coolant system overpressure event has been considered.
It has been shown that these high-head pumpe uculd act causa RC pressure tu exseed its allowable limit following a failure of the MU valve in the full open position at reactor coolant system temperatures above 280 F.
Initial conditions considered the pressurizer level to be at the high alarm level and the MU tank level to be at its high alarm level. The tran-sient would be terminated without operator action by the MU tank low level interlock stopping the MU pump (s). Maximum RC pressure reached would be 700 psig. Should the low level interlock fail to operate, the RC pressure would not exceed 1140 psig. These calculated pres-sures assume no steam condensation within the pressurizer during the level and pressure increase.
Performance of the same calculation starting from an initially normal pressurizer level yields pressures of 555 and 750 psig respectively.
Were this transient to occur, the high makeup flow alarm would annun-ciate immediately. As MU tank level decreased, the low MU tank alarm would sound as would the high-high pressurizer level alarm.
17 February 18, 1977
ENCLOSURE 2
~
s STAFF POSITION ON LOCKING OUT POWER TO DHR ISOLATION VALVES The staff requested that the applicant provide information to show that the inadvertent closure of either DHR isolation valve during DHR operation would not compromise the heat removal capability.
In response, the applicant proposes to remove power from both valves during DHR operation. This proposal is not acceptable since, by removing power to these valves, an automatic feature is removed which provides additional assurance that both isolation valves would be closed during power operation. Branch Technical Position EICSB-3 and Section 5.4.7 in the USNRC Standard Review Plan require that these valves receive a signal to close automatically whenever the primary system pressure rea:hes a high value.
It is the staff's position that an alternate proposal to locking out power to DHR 11 and 12 be submitted with regard to the concern relating to inadvertent DHR isolation during shutdown.
Such a proposal must assure that an inadvertent isolation would allow time for operator action to maintain the heat removal capability.
4 18 February 18, 1977
,. s Resp:nsa to Enclosura 2 STAFF POSITION ON LOCKING OUT POWER TO DHR ISOLATION VALVES The removal of powar from the Decay Heat Removal (DHR) system suction line valves DH,11 and DH-12 assures the overpressure protection of the reactor coolant and DHR systems and meets all requirements of Branch Technical Posi-tion EICSB-3 and Section 5.4.7 of the U.S. NRC Standard Review Plan.
As discussed in FSAR Section 9.3.5.5.1, there is a relief valve on the DHR suction line, PSV-4849, (see FSAR figure 6-17) which has been sized to pass 1800 gpm at a set pressure of 320 psig.
The flow rate is based on the maxi-mum developed runout flow with both high pressure injection pumps running simultaneously.
The deoign flow is twice the maximum flow that can be ex-pected from a single active failure. This was done to afford the system with added conservatism in protecting against overpressurization.
Upon system startup if one or both valves (DH-ll and DH-12) are not closed, an interlock is being provided that trips the pressurizer heaters off if primary pressure reaches 280 psig (sensed at the centerline of valves DH-11 and DH-12) and both valves are not fully closed. The interlock provides added assurance that no single active failure will permit the primary system to be pressurized to greater than the decay heat removal sysrem design without both DH-ll and DH-12 fully closed.
NOTE: Until the time the pressurizer interlock described above is installed, the temporary changes as described in FSAR Section 7.6.1.1.2 will be initiated.
The temporary system changes described in FSAR Section 7.6.1.1.2 assure that Appendix C protection is afforded to the primary system at all times that it is required and no single active failure can cause the loss of both decay heat removal pumps thus assuring decay heat removal capabilities at all times.
At the time the pressurizer heater interlock is installed, the setpoints and operating procedures will be changed back to their original setpoints and procedures.
With power removed from DH-ll and DH-12 while the DHR system is in operation, all the requirements of Branch Technical Position EICSB-3 are satisfied, as discussed below:
POSITION 1.
At least two valves in series should be provided to isolate any subsystem whenever the primary system pressure is above the pressure rating of the sub-system.
The system as designed meets this position. Valves DH-11 and DH-12 are closed with power restored at all times when the Reactor Coolant System (RCS) is above the pressure rating of the DHR system. The valves at this time are pro-vided with an interlock, with redundant and diverse pressure sensors, which prevents them from being opened if primary 19 April 7, 1977
,rs system pressure is greater than 260 psig.
This feature prevents overpressurization of the' DHR system while the primary system is at a pressure greater than the design pressure of the DHR system. When the DHR system' is in operation, valve PSV-4849 prevents the DHR and RCS systems from reaching pressure limits for all credible overpres-
'suriz. tion events.
In addition, bypass valves DH-21 and DH-23 will be normally closed and locked.
POSITION 2.
For system interfaces where both valves are motor-operated, the valves should have independent and diverse interlocks to prevent them from both being opened unless the primary system pressure is below the subsystem design pressure. Also, the valve operators should receive a signal to close auto-matically whenever the primary system pressure exceeds the subsystem design pressure.
As discussed above the valves (DH-ll, DH-12) have indepen-dent and diverse interlocks to prevent them from opening unless primary system pressure is below the DHR system de-sign pressure. At all times when DH-il and DH-12 are open and power removed, valve PSV-4849 prevents overpressuriza-tion of the DHR system for any credible single active fail-ure including failure to close valves DH-11 and DH-12 on plant startup. There fore, since the primary system will never exceed the subsystem design pressure, the necessity for automatic closure, of the valves is negated.
POSITION 3.
For those system interfaces where one check valve and one motor-operated valve are provided, the motor-operated valve should be interlocked to prevent the valve from opening whenever the primary pressare is above the subsystem design pressure, and to close automatically whenever the primary system pressure exceeds the subsystem design pressure.
The primary isolation for the system is provided by valves DH-il and DH-12, however, there is a 1" bypass line with a check valve around valve DH-12 to prevent overpressuriza-tion of the piping between DH-11 and DR-12.
This piping has been sized to assure that will full design primary system pressure on one side and no pressure on the other the flow will not exceed 1800 gpm with a failure of the check valves and an inadvertent opening of valve DH-11.
Val,e DH-11 as discussed above is provided with an inter-lock to prevent its being opened if primary system pres-sure is above DHR system design pressure and PSV-4849 prevents overpressurization while on the the DHR system.
POSITION 4.
Suitable valve position indication should be provided in the control room for the interface valves.
20 February 18, 1977
m
~
Valve position indication for DH-11 and DH-12 is p'rovided in the control room with or without power removed from the motor operators. This indication is provided by essential indicating lights as well as alarms on the computer.
POSITION 5.
For those interfaces where the subsystem is required for ECCS operation, the above recommendations need not be implemented.
System interfaces of this type should be evaluated on an individual case basis.
Valves DH-11 and DH-12 are required to operate within seven (7) days of a postulated LOCA at which time primary pressure is well below the design pressure of the DHR system.
A review of Section 5.4.7 in the U.S. NRC Standard Review Plan indicates that Branch Techn16at Position EICSB-3 covers all germane areas of the Standard Review Plan. Therefore, since the system design meets, in total, Branch Technical Position EICSB-3 it also meets Section 5.4.7 of the U.S. NRC Stan-dard Review Plan.
It should also be noted that the removal of power from valves DH-11 and DH-12 does not violate BTP EICSB-18, Application of the Single Failure Criterion to Manually-Controlled Electrically-Operated Valves, as explained in response to FSAR position question P7.1.1.
21 February 18, 1977
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b.
At least once per 31 days by verifying that the ECCS piping is
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)
full of water by venting the ECCS pump casings and discharge 9
g iping high points.
/
By a visual inspection which verifies that no 1cose debris D
b (rags, trash, clothing, etc.) is present in the containment gg which could be transported to tne contain:er.t tmergency sc p and cause restriction of the pump suction during LCCA con-ditions. This visual inspection shall be performed:
1.
For all accessible areas of the containment prior to establishing CC:: TAI::7.ENT IiTEGRITY, and 2.
Of the areas affected within centainment at the comoletien of each containment entry when CCNTAI?iMENT INTEGRITY is established.
d.
At least once per 1S r.onths by:
O i
V 1.
Veritying cuto:ctic isciation and intericck action of the DHR syst:m frcm tne Rcactor Ccolant Systcm when tne Reactor Ccolant System pressure is > 929 psig[. c MW #
_m 2.
A visual inspecticn of the containment emergency sump which verifies that the subsystem suc:icn inlets are not restricted by debris and tnat the sump ccc::enents (trash racks, screens, etc.) shcw na evidence of structural distress cr corrosien.
3.
Verifying a total leak rate < 20 gallons per hour for the LPI system at:
a) flormal operating pressure er hydrectati: test pressure of > 150 psig for those parts cf the system cc.:nstream i
of tne pump suction isolation valve, anc g
b)
> 45 psig for the piping frem the containment exerco'cy sump isolatien valve to the pump suction isolatica valve.
4.
Verifying that a minimu.n of 72 cubic fact of solid granular trisodium phoschate dodecahydrate (TSP) is coin.ui.ned within the TSP storage baskets.
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SITE BOUNDARY B-SKIN p os **8 #
SITE BOUNDRY
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%d CONTAINMENT TOTAL
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4 6
8 10 g.
TIME (HOURS)
DAVIS-BESSE fiUCLEAR P0Y!ER STATION
' LOSES VS. It'4E FIGURE P7.6.1-1 REVISIGN 10 DECE?JBER 1974
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7.6.1 (10/4/74)
From our review of the Decay Heat..emoval (DHR) System (Sections 7.6.1.1, 6.3.2.16, and Figure 6.17), we have concluded that this sreene is ranuf-_a_d fe-o ferv,_< g,
r._f --. t.
he present cesign to acMaye < n'd
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does not meet the single f ailure criterion with respect to failare (to open) of either of two serially connected isolation valves (DHil & DH12) in the suctf_on line of the (DHR) pu=ps.
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k,'_e v111] remtire th_a__t, the (DF_O _nye.ta'_ d.a_d.t, _n -aat._th;
-. ale !.C.~i"re cr :-::en tren the stancpe:nc ct assuring sin
- - - ) and trom the stand-
,c,o :.d rIt--"n occay neat renova; (1.2.,
point of precluding o';.g.7-22A;;n of the system, and that the associatea :nstruncatation, ccatrol and elec-trical systers confor with IEEE Std 279-1971 and IEEE Std 308-1971. Therefore, mcdify your design to meet these requirements, or justify the present design en ccce other defined basis.
RESPONSE
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m.,- - aw, Tha -. m.1 br m has been chcne,ed as foliccs:
),5_r : t e, - e n > c ;
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.3 1.
The recovabic sectlon of piping has been inserted permanentl'/ into the bypass.
2.
Both valves on the bypass will be slesigned for pri=ary systen pressure 10 and 3.
The two " bypass" valves will be locked closed, with the necessary adninistrator centrols.
hing:.e t.u;ure of rne or enc rocor-cpara 2d icciation valves cculd be
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accer.=odated by a te=ber of the operationa staff enterin:; the containecntj af ter su f f ici nt _ r,,u,,r..n. ine i f d a_ mad. _ x_.ce__s.c :rv_.
..."~.,.#_- n - _#,_' - ~ i
-e-L_ valve =.,;i.m re_ul: cut cou to cc.a taa entcru.:; ::.e contain:.ent is J..S rc=.
The site boundary deses are shcun in figure P7.6.1-1.
The doses are based on the folleving assurptions:
1.
A primary syste leak of 140 gpa is assuced to cccur continuously.
(This is a b. 3.renk which the cal.euo purps can keep up with.)
2.
Purging does not occur until 6.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after the I this tire the coerator veuld disecver t S t_the =ain direc h n I can not be uscd.
l tie veuic enan initiate che currej 3.
The onerator enters the containment with a Scott air pack and takes Lten_ minutes]to open the bypass valves and exit centain:cnt.
4 Entry into the containment could b -ad e a f t e r two hou r_<;. The benefit
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of vaiting core than two hours is =inimal~and results in an increase Revision 10 Dc :c=ber 1974 P7.6.1-1 D
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E in the site boundary dose. The site boundary dose resulting from a
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two hour purge would be 15.5 rem thyroid, 0.42 rem whole body.
5.
To reduce beta skin doses, protectivc cloth g was assumed to be worn.
6 One percent failed fue1 was assu=ed.
10 Thyroid dose to the operator is reduced significantly by the use of the Scott air pack and in all cases 19 neclicible cercared to the e %,a,. -dose.
If the atr v---
ran were to enter tile centainment witncut purging, tne resuAcant ga:=a dose would be only 0.91 re=s.
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l Revision 10 Decenber 1974 P7.6.1-2 j
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