ML19339B561
| ML19339B561 | |
| Person / Time | |
|---|---|
| Site: | Yankee Rowe |
| Issue date: | 05/27/1977 |
| From: | Vandenburgh D YANKEE ATOMIC ELECTRIC CO. |
| To: | Schwencer A Office of Nuclear Reactor Regulation |
| References | |
| WYR-77-55, NUDOCS 8011070248 | |
| Download: ML19339B561 (29) | |
Text
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TcI: phone bi7 36u 90li twx Flo-3OO-0739 YANKEE ATOMIC ELECTRIC COMPANY uYR,,-55 y pl
( YA[ux,@us gp 20 Turnpske Road Westborough, Massachusetts 01581
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May 27, 1977 Regulatory Docket File a + ti
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United States I;uclear Regulatory Commission p(,
g Washing ton, D. C.
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- Attention: Office of Nuclear Reactor Regulation p.p3
-8 Mr. Albert Schwencer, Chief
% J o.vgj /* g 7 References (1) License No. DPR-3 (Docket No. 50-29) k J,/,$ \\
(2) USNRC letter to YAEC, dated 2/16/77 4 [ TT '
(3) YAEC letter to USNRC, dated 12/1/76 (4) YAEC letter to USNRC, dated 2/4/77 (5) YAEC letter to USNRC, dated 3/31/77
Subject:
Reactor Vessel Overpressurization
Dear Sir:
Your letter, Reference (2), requested additional informaticn af ter a preliminary review of our submittal, Reference (3).
Our letters, References (4) and (5) stated, respectively, that Yankee Rowe has never.
experienced an overpressurization transient; and that an additional eight weeks would be required to provide further information.
Enclosed herewith is the information requested in Reference (2).
We trust you will find this satisfactory; however, should you require additional detali, please contact Mr. R. P. Shone at (617) 366-9011, Extension 2830.
Very truly yours, YANKEE AMMIC ELECTRIC COMPANY D. E. Vandenburgh Senior Vice President Rl!G/kg 8011070 M y $
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~ RESPONSE TO nRC QUESTIONS RECARDING IHE YANKEE R0WE SUBMITTAL ON REACTOR VESSEL OVERPRESSURIZATION The following questions pertain to formal discussions with all operators 3
and Instrumentation and Control Technicians.
1.1.a.
QUESTION:
If you have not already completed the required formal discussion, when will you do so?
i AUSWER:
The formal discussion will be completed by June 4, i
1977.
I l
1 1.1.b.
QUESTION:
How will the discussions be held?
ANSWER:
For=al discussions will be held at scheduled training meetings. The training session will be repeated until all Operating and Instrumentation and Control personnel have received the required training.
I.l.c.
QUESTION:
Identify which of the past Appendix G violations that have occurred at PWR f acilities and which are described 1
in Licensee Event Reports, are not credible in your plant due to equipment differences. Provide a description of the distinctions.
ANSWER:
From the information available in the Licensee Event Report Summaries only a general response can be provided. The overpressurization incidents can be attributed to 4 or S general classifications. These incidents are:
- l. Inadvertent ECCS operation.
- 2. Charging without bleed flow.
):
- 3. Loss of shutdown cooling heat removal capacity.
- 4. Main coolant flow initiation transients.
- 5. Direct operator error or improper procedural controls.
4 It is not possible to determine which events that have occurred at other PWR f acilities are not credible at Yankee Rowe without more specific info rmation about each of these other facilities.
The information required would be system prints, instrumentation and control prints, any interlocks or permissive circuits available and operating procedure controls.
1
f-L 4
1.1.d.
QUESTION:
Describe, in datail, hew you are reducing the i
likelihood of che other remaining credible events.
{
Furnish sche.catics, diagrams or procedural summaries I
necessary to support the effectiveness and reliability j
of these measures.
1 j
ANSWER:
Summaries of postulated events, design features and procedural controls which minimize the possibility
}
of overpressurization events were provided as j
Appendices, A, B and C to Yankee Rowe's December 1, j
1976 submittal to the Commission.
l The ef fectiveness and reliability of these design i
features and administrative controls is documented 1
by the fact that Yankee-Rowe, in its sixtuen years i
of operation, has never experienced a reactor vessel overpressurization incident.
The following questions pertain to operations which are performed in the water-solid condition.
- 1. 2. a.
QUESTION:
Discuss the necessity for establishing a wa;.r-solid system during each of these procedures. Also provide l
your justification for not using a nitrogen, air or steam bubble.
ANSWER:
As described in detail in Appendix A to our original submittal, an air bubble is present in the pressurizer during the main coolant loop venting process. The water-solid condition is. established only briefly during plant heatup in preparation for steam bubble formation and during plant cooldown for cooldown'of the pressurizer. The water-solid condition is currently escablished only during heating or cooling of the pressurizer. This long-standing practice is based upon the assumption that the pressurizer should not be heated or cooled without being full of water i
in order to minimize thermal stress concentrations.
Further evaluation of this assumption would be required if elimination of water-solid operation were j
contemplated.
Due to administrative controls, the inadvertent initiation of either main coolant flow or ECCS flow 4
from a complete ECCS train is not a credible event while in the water solid condition. Moreover, the time spent in the water solid condition is small in j
compstison to the total time spent heating up or cooling down. Therefore, the additional protection af forded against reactor vessel overpressurization i.
by eliminating this small duration of water-solid operation seems negligible.
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2
_- - - ~ _. _ _
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I.2.b.
QUESTION:
Include any supplementary information such as system i
diagrams and descriptions of equipment operation to justify your need for operating the plant water-solid.
ANSWER:
As stated in the response to Question No.
I.2.a.,
)
it is currently assumed that the pressurizer should be full whenever it is being heat ed or cooled.
Th t ?
assumption is based upon information contained in the pressurizer technical manual which co...iders thermal stresses and stress concentration restrictions.
An evaluation of the necessity of this long-stending operating practice would be performed before the current, minimal amount of water-solid operation could j
be eliminated.
The following questions pertain to inadsertent operation of SIS j
components.
- 1. 3. a.
QUESTION:
Furnish a schematic diagram of the SIS showing the 7
I components and the flow paths into the RCS.
- Also, provide the head flow characteristics of each of the SIS pumps.
t ANSWER:
Attachment A is a schematic diagram of the SIS.
j Attachment B and C are pump characteristic curves for the low pressure and high pressure pumps respectively.
I.3.b.
QUESTION:
Pagas A-1 and 2 of your submittal indicate that two of the three ECCS trains are taken out of service at 1000 psig and the third at 200 F, 300 psig.
Describe how this is done, (e.g., switches or brea'kers repositioned). Indicate these trains on the requested schematic diagram.
ANSWER:
A safety injection pump is removed f rom service by racking out, locking and tagging its ACB.
A train consists of one high pressure and one low pressure pucp. As indicated on Attachment A a train would be HPSI-1 and LPSI-1.
I.3.c.
QUESTION:
You discuss the closing of selected S1 header isolation valves at 1000 and 300 psig.
Is the power from these valves also removed? Indicate how and from where j
the valves are controlled.
Identify them on the requested schematic diagram.
ANSWER:
Below 1000 psig the following valves are-closed but electrically operable:
SI-MOV-2 2, SI-MOV-2 3, SI-MOV-1 1
24 and SI-MOV-25.
At less than 300 psig the-following valves are closed but electrically operable:
SI-MOV-4 6, CS-MOV-533, CS-MOV-534, CS-MOV-535, CS-MOV-536, CS-MOV-5 3 7, CS-MOV-5 38 and CS-MOV-5 39.
These valves 3
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.2, are identified by their respective numbers on Attachment A, and are controlled remotely from the control room safety injection panel.
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1.3.d.
QUESTION:
Indicate on the schematic diagram any other pumps that are disabled and valves which are in an off-normal position during a cold, and shutdown condition.
ANSWER:
At less than 1000 psig the s,fety injection accumulator is removed f rom s' rvice by locking closed, tagging 4
e i
and making electrically inoperable, SI-MOV-1.
In l
addition nitrogen regulator isolation valves SI-V-52A and SI-V-53A are tagged and locked closed and NS-V-19 is opened to vent the accumulator.
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1.3.e.
QUESTION:
During cooldown or shutdown conditions other than
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fill and vent operation, for each SIS breaker opened (or " racked-out"), describe the following:
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- 1. The SI component.
- 2. The breaker location.
l
- 3. The place f rom which the breaker's position can he controlled.
- 4. The places from which the breaker's position can be determined.
i 5._The position indication and status signals which 4
j will be lost as a result of opening or removing j
(rack-out) the breaker.
ANSWER:
Each safety injection train is powered by its respective 480 volt emergency bus located in the safety injection building (i.e., HPSi-1 and LPSI-l ACB's are located.in No. 1 480 volt emergency bus.)
Breaker position for the pumps can be determined both locally i
at the emergency bus and remotely from the control l
room. The pump ACB's are controlled only from the control room.
By racking out these ACB's the position j
indication in the control room will be lost.
SI-MOV-1 ACB is located in Emergency MCC No. 2 in the safety injection building. The breaker position can be determined locally.
By opening the ACB an indirect indication of breaker position is given in the control room because valve position indication is lost.
Once the ACB is closed the motor contactor for the valve can be controlled only remotely from the control room.
1 In other words the valve cannot be operated from the motor contactor locally.
l 1.3.f.
QUESTION:
Describe the administrative controls that ensure the l
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proper equipment alignment shown on the diagram.
What supervisory personnel are responsible for maintaining control?
ANSWER:
All equipment previously mentioned is initially positioned by plant operating procedures. All equipment which was locked and tagged in position i
is under continuous administrative control of the plant tagging procedures. Responsibility for 4
maintaining the latter rests with the duty Shift Supe rviso r.
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1.3.g.
QUESTION:
Below 1800 psig, automatic safety injection is blocked.
Describe any " unblock" or " block-bypass" features
]
you have, and how this factors into your pressure j
protection procedures.
ANSWER:
Atfl800 psig both of the safety injection actuation i
channel switches are positioned to " Cutout" whi-h blocks any automatic initiation signal. There is no unblock or block bypass feature associated with the system.
In addition, the six safety injection pump control switches.are positioned at the remote panel to " Trip Pull Out".
This means that the pumps would not start even if they did receive an " Auto Start" signal.
In order for a pump to operate, two operating errors have to be made; the " Auto Start" signal must be reintroduced, and the pump control j
switch must be placed in an operable position.
- 1. 3. h.
QUESTION:
The third ECCS train is not tagged out of service until the RCS has been cooled to around 200 F.
W'at h
,L is the justification for not tagging out this ECCS train along with the others at 1000 psig, 360 F?
4 ANSWER:
Technical Specification 3. 5. 3.a. requires that at least one safety injection train be operable in the manual mode above 200 F and between 300 and 1000 psig.
This Technical Specification is an NRC requirement whose basis is not completely apparent.
I
1.3.1. QUESTION
During system fill and vent,-you state on page A-3 that all ECCS pumps are tagged inoperable. Does this include the removal of power from all high pressure SIS pumps and motor operated header Isolation valves?
Show the equipment status on a SIS schematic. Desc ribe the location of the breakers that will be opened, and the places from which they can be controlled.
Describe the position indication and status signals which will be lest as a result of de-energizing these components.
ANSWER:
At the time of main coolant system fill and venting, 5
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system temperature is less than '000F.
Therefore,
- all safety injection pumps are tagged inoperable as stated in Answer #I.3.c., SI-MOV-1 is closed and locked d
as stated.in Answer #1.3.d., and all other SI system j
motor operated valves are positioned as.stited in Answer #1. 3.c.
r l
The only motor operated _ valve breaker which is open and tagged at this point is that f or SI-MOV-1.
Inforcation on breaker location, control and indication.
j is presented in Answers #I.3.c. and 1.3.e.
I The following questions pertain to component or systen tests performed I
during cold shutdown conditions which could lead to Appendix C violations.
)
1.4.a.
QUESTION:
What components or system that could cause a pressure transient are routinely tested while in a cold shutdown j
condition?
I ANSWER:
The main coolant charging pumps are tested on the basis of one pump each week.
i 1.4.b.
QUESTION:
What extra measures are taken to prevent an
[
overpressure event during these tests?
f ANSWER:
The pumps are not tested while in a water solid condition.
In addition, pump capacity is 33 gpm maximum and any pressure transient, if it did occur, 4
would be limited by the two shutdown cooling system relie' valves.
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i L. 5 QL'E STION :
You oriefly describe a proposed alarm in Appendix B, on page B-3.
With regard to this proposed alarm, furnish the following information:
4 a.
Your =ethod to provide the alarm, and the implementation schedule.
ANSVER:
The bistable / relay unit formerly used to operate the SIS valves associated with the main coolant pressure channel of the reactor protection system will be utilized. This modification will be installed during the Core XIII ref ueling outage scheduled for June i
1977.
b.
A synopsis of the system modifications titat are necessary.
ANSWER:
A new pressure channel 1. to be installed that will
' sense the main coolant pressure. The sensing line is the same as that used by the main coolant pressure channel of the reactor-protection system.
The new L
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channel will consist of a power supply, 0-3000 psig pressure transmitter, dual setpoint trip device, i
auxiliary relay and a strip chart recorder. One setpoint of the t rip device will be conuert ed to a window on panalarm N-C.
This alarm wili netuate at 450 psig decreasing main coolant system pressure and will be used to signal the operator to activate the key operated interlock discussed below.
The other setpoint of the trip device will be adjusted to operate, through the auxiliary relay, the pressurizer solenoid operated relief valve.
A key' operated inter 1< :k switch will also be installed.
The contacts of this Interlock will be connected to the pressurizer solenoid relief valve and the main coolant overpressurization alarm circuitry.
c.
The alarm setpoint, mode of annunciation and sensor.
4 l
j ANSWER:
The bistable trip-on point that informs the operator
)
of a transient will be set at 400 psig increasing; and the trip device setpoint that operates the i
pressurizer solenoid relief valve will be set to operate at 500 psig. The relay associated with the bistable will operate a window on panalarm N-C on
.the Main Control Board. The sensing channel for this alarm consist of a Bailey Meter' Company KIX pressure transmitter, Westinghouse 927D 658 GR7 Linear Amplifier, Westinghouse 92 7D633 GR6 bistable and a Westinghouse 443D - 821 C6 Relay Panel.
d.
How you ensure that the alarm is available and operating properly during all water-solid operations and how you minimize its down-time for all other cold shutdown conditions.
ANSWER:
The key operated-switch will be utilized'to ensure that a circuit will exist for the operation of the alarm. This, together with the panalarm windaw being lit informing the operator that an overpressurization a
transient could occur will indicate the system is operating properly. Also calibration procedures will l
include precautions prohibiting isolation when an l
overpressurization condition could occur. These desinn features and calibration procedures together with administrative controls will ensure availability of the alarm during all water-solid conditions.
i
- 1. 6.
QUESTION:
The use of the SCS code safety valves as overpressure protection devices is discussed in your submittal.
To assist us in evaluating your proposal. supply the following information:
4 7
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a.
A diagram of your SCS showing the arrangement on the code safety valves.
ANSWER:
A diagram of the shutdown cooling systen showing the arrangement of the code safety valves.ind system isolation valves is included as At tarbr.ent D.
b.
SCS design pressure.
ANSWER:
The shutdown cooling system is designed for 2300 psig up to and including SC-MOV-551 and SC-MOV-552.
The remainder of the system is designed for 425 psig.
c.
A description of the system isolation valves and their arrangement (e.g., number and configuration of valves installed, and pneumatic or motor operated).
ANSWER:
The four system isolation valves (SC-MOV-551, SC-MOV-552, SC-MOV-553 and SC-MOV-554) are six inch, Limitorque motor operated, stainless steel gate valves.
d.
Interlocks, interlock setpoints, and alarms associated with each isolation valve.
ANSWER:
The system isolation valves mentioned in I.6.c. can only be operated by inserting a key into the respective control switch. Once the key is removed, the control switch cannot be operated and hence, the valve cannot be electrically operated.
The keys are kept under the administrative control of the duty Shift Supervisor. There are no alarms associated with the shutdown cooling system isolation valves.
1 e.
Nominal stroke time of isolation valves.
ANSWER:
The nominal stroke time for each shutdeen cooling system isolation valve is approximate 1;. 33 seconds in each direction.
f.
All pressure alarms, setpoints and associated annunciation for the system.
ANSWER:
There are no pressure alarms associated with the shutdown cooling system.
The following question pertains to operating the cooling charging pucps.
- 1. 7.
QUESTION:
Based on your December 1,1976 submit tal, we assume that the SIS high pressure pumps and the coolant charging pumps are not the same.
Desc ribe the methods you use to prevent inadvertent pressure transients from the latter.
8
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ANSWER:
The SIS high pressure pumps and coolant charging pumps.
are not the same. An inadvertent pressure transient l
would be limited by the fact that shutdown cooling L
safety valve capacity exceeds charging pump capacity.
j Operation of the charging pumps while in a water solid mode is only for the purpose of controlling pressure and by a man stationed solely to monitor and control pressure.
~
The fo11owing question pertains to increasing pressurizer level during plant startup.
I l
- 1. 8 QUESTION:
After admitting filtered air at 80 psig to the pressurizer, the water level is increased so that 4
j RCS pressure is sufficient for the main coolant pump (MCP) jog procedure (page A-4 of your submittal).
i 1
A pressure transient is considered possible while j
raising the pressurizer level. Describe the steps i
you take to ensure this does not occur.
l ANSWER:
The pressure transient, if it developed, would be d
limited by the shutdown cooling safety valves, which are still in service, and have a greater capacity than the charging pumps. Additionally, during the j
next refueling, the plant is planning to modify the i
pressurizer solenoid relief valve so that during cold j
shutdown conditions it can be set for 500 psig.
J 11.1.a.
QUESTION:
On page B-1 you state that each SGS safety valve hab the capacity to relieve 101 gpm of 400 F water at ~
about 467 psig. - Please address the following questions:
i Provide an analysis which estimates the combined relief
- rate assuming the fluid is at 100 F. 200 F and 300 F for a range of - pressure above the setpoint.
1 ANSWER:
The results of the requested analysis are presented in the table below. Description of the analysis 4
procedure is contained in the answer to question II.1.b. below.
Table II.1.a i
Pressure Combined Capacity of both~SCS safety valves (GPM) i psig T=100 F T-2000F T=3000F 468 (10%)
172 174 178
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532 (25%)
256 259 264 i
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I II.l.b.
QUESTION:
The ef fects of flashing and backpressure on safety valve discharge rate should be determined by your analysis. We request that the results of your analyses be provided, even if a significant reduction in discharge capacity is not found. Furnish your time schedule for completing and submitting this analysis.
ANSWER:
The procedure for calculating the rellet rates of Table ll.2.a. are based upon available data on safety valve capacity. consideration of backpressure buildup in the safety v lve discharge piping, and in the discharge recatt ing tank.
At present, the extent to which flashing within the valve occurs or is accounted for by the manuf acturer in determination of safety valve capacity, is unknown.
A detailed inquiry, aimed at clarifying this point, has been sent to the valve manufacturer; and we are awaiting his response.
In the meantime, we are t'tilizing the following relation, taken f rom the manufacturers catalogue, to comput e sa fe ty valve capacity:
Capacity (gpm) = 2 7. 2 (C ) (KSG ) (KBL)(A) V P-Pb A
where:
C accumulation factor
=
3 1.0 for 25% accumulation
=
0.6 for 10% accumulation
=
Kgg = specific gravity correction. f actor (1.0)
Kgt = backpressure flow f actor (1.0) orifice area (in2)
A
=
= set pressure (425 psig)
P backpressure (psig)
Pb
=
Backpressure imposed at the discharge of the safety valve depends upon pressure in the receiving tank and flow losses in tM discharge piping from the valve to the receiver tai.>,
iae receiver tank is the low pressure surge tank (LPST).
Its cperating pressure is maintained below 25 psig by means of an automatic vent valve, and its maximun pressure is limited to 10
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75 psig by six safety valves which relieve back to the vapor container. This analysis conservatively assumes a constant LPST pressure of 75 psig.
In treating flow losses in the safety valves' discharge line, the actual pipe configuration is simplified using standard methods outlined in Crane Co. Technical Paper #410 and the Hydraulic Institute Pipe Friction Manual. Head losses in the equivalent length of discharge pipe are computed based upon previously calculated flow through the safety valve. The computed head losses in the discharge line are added to low pressure surge tank pressure (75 psig) to arrive at total backpressure at the safety valve discharge.
To arrive at the actual safety valve capacity, an iterative approach based on trial and error was used.
Safety valve relief rate (capacity) is initially computed from the above formula using LPST pressure (75 psig) as the sole component of backpressure on the valve. This results in a maximum (although incorrect) value for valve capacity.
Using this first calculated value of relief valve flow rate, head loss in the discharge line is calculated. This pressure drop, combined with LPST constant pressure is then used as the corrected backpressure value in the next trial calculation of relief valve capacity. This iterative process produces a series of trial results which rapidly converge on the value of relief valve capacity which is compa tible or " balanced" with the actual piping losses. These final or " converged" values are the values reported in Table II.1.a.
The artificial imposition of a constant 75 psig pressure in the LPST is discussed further in the answer to Question II. 2.b.
Since 75 psig is in excess of the saturation pressure for 300 F water, the calculation of relief valve capacity need not consider directly the complicated effects of two phased flow in the discharge piping. Our assumption of a constant 75 psig pressure in the LPSI artificially reduces the calculated relief valve capacity because it is a f unction of the pressure dif ference across the valve.
We are confident that this approach yields results which are conservative with respect to the actual situation in which two phase flow might occur.
II.2.a.
QUESTION:
On page B-1, you state that the discharge of the shutdown cooling system safety valves is directed to a terminal tank.
Regarding this arrangement, address the following:
- a. Does the pressurizer relief valve relieve to the 11
I.:
same place?
ANSWER:
Fluid discharged from the shutdown cooling system safety valves can be routed by means of a three way, diverting valve to either the low pressure surge tank (LPST) or the primary drain collecting tank. When the shutdown cooling system is in service, the three way valve is aligned to direct any discharge to the LPST. The pressurizer relief valve also discharges to the LPST.
II.2.b.
QUESTION:
Since the SCS safety valves and the pressurizer relief valve may be open during a pressure transient, simultaneous discharge is possible.
If the terminal tank is common to both relief valves, what is the possibility of backpressure from one discharge effecting the flow rate from the other?
ANSWER:
In the circumstance established by the question, the LPST would be the common relief tank f or both the pressurizer relief valve and the SCS safety valves.
The only ef fect of one discharge upon the other would be an increase in internal pressure of the LPST during the duration of the discharge. Such a pressure increase would be the combined result of a level increase and accumulation of uncondensed steam in the LPST during the period of the discharge. All discharges from the SCS safety and pressurizer relief valves enter the LPST below normal water level and mix with its contents through an eductor and sparger arrangement. LPST initial temperature and pressure are typically below 150 F and 25 psig during the latter stages of p; ant cooldown or early stages of plant heatup. Therefore the LPST in ready to quench any steam entering the LPST during a discharge.
If LPST pressure were to reach 75 psig during the discharge, six high capacity safety valves will f unction to limit LPST pressure to essentially 75 psig. The calculation described in the answer to Question II.1.b.
conservatively assumes LPSI pressure constant
't 75 psig.
11.3.
OUESTION*
Provide printe of the existing and proposed circuitry used to operate the solenoid on the pressurizer relief valve. These diagrams should enable us to trace signals f rom the detector to the solenoid.
ANSWER:
The following attached sketches describe the existinh and proposed circuitry.
- 1. Yankee Rowe Low Temperature Overpressurization Transient Protection System 12
, ~.. -
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Sketches 1, 2 and 3 11.4 Q'JESTION:
.it is the staff's position that the probability of a LOCA not. be allowed to increase significantly because of design modifications made to protect against overpressurization at ' low temperatures. You propose to replace your' existing pressurizer relief valve with one of higher capacity.
Further, the proposed dual pressure setpoint potentially introduces additional f ailure modes that could cause the valve to open while the RCS is at normal operating pressure.
j Describe the features of your proposed design (such i
as single failure proof circuitry and interlocks) that would minimize the probability of inadvertent opening of the relief valve.
i 3
r l
ANSWER:
The primary change to be implemented at Yankee Rowe l
l consists of adding a Icw pressure setpoint feature l
to the actuation circuitry for the existing pressurizer i
i solenoid relief valve. This low setpoint (approximately 500 psi) for low temperature operation will, via standard operating procedures, be activated j
during required stages of RCS low temperature
[
i operation. The monitoring circuitry.will consist 1
of a main coolant pressure transmitter, an adjustable i
dual contact output bistable, a strip chart recorder j
and the required circuitry power supplies..The p essure transmitter will be located in the vapor container. The pressure taps for the t ransmit ter will be on the cold leg of main coolant loop 81 such that it cannot be isolated f rom the reactor vessel' by closure of the cold leg loop isolation valve.
This tap location will ensure monitoring of actual reactor vessel pressure during all stages of plant operation. Required inlation, drain and -test l
connect f ons will be pro. ided on pre %ne e se n s i ny. I n nm..
l The power supply and trip histable will be located inside the main control board. The rec order will be mounted on the nuclear section of the main control board and will prcvide a continuous record and indication of-reactor vessel pressure. One of the dual trip device contacts will be set to actuate at 500 psig increasing and will be wired to the relief valve actuattin circult'via the pernt.ssive keylock swi tch.
The keylock switch will be located on the front part of the-nuclear section of the MCB.
The second dual trip device contact will be set to actuate at approxicately 450 psig decreasing and will provide alarm notification to the operator to activate the low temperature overpressurization system during low tecperature plant operation. An existing bistable located in the MCB will be set to' actuate at 400 psi 13 3'y me-o b
Aa e
b.
i 1
increasing and will be wired via the permissive keylock l
Hwitch to a MCH annunciator window to provide an alarm output to notif y operators of an impending low f
temperature overpressure condition. This alarm i
bistable is set below the relief valve trip bistable setpoint to allow the operator to initiate corrective action to avert a possible low temperature overpressure t
j condition. The addition of the low setpoint circuitry does not ef fect the existing circuitry for the 2500
]
psig setpoint and will not introduce additional failure modes to the existing system. The 500 psis circuitry incorporating the key-locked switch, will be under the administrative control of the control room
)
operator.
Plant operating procedures will incorporate 3
the use of the key-locked switch and will address proper system operation to minimize the probability i
of inadvertent opening of the relief valve.
l 11.5.
QUESTION:
Discuss the feasibility of including an alarm that would warn the operator to actuate the low pressure j
setpoint on the pressurizer relief valve, to assure its availability during RCS low temperature operations.
l ANSWER:
As discussed in the answer to Question 11-4, an alarm will be made available which will warn the operator to actuate the low pressure setpoint system on the pressurizer relief valve.
l
]
11.6 QUESTION:
The use of an extra dedicated operator for RCS pressure monitoring during water-solid operations is discussed on pages A-2 and B-3.
Describe the indications, alarms and warning devices available to this operator thht guarantee his awareness of a pressure transient in progress, and indicate those analyses in which you take credit for his action.
4 ANSWER:
Indication of main coolant pressure available to the operator during water-solid conditions consists of the main coolant pressure indicators on the main control board. The response to questions I. S.b. and 11.4 describe the -additional indications to be installed during the forthcoming refueling outage.
The dedicated operator currently required by plant operating procedures during water-solid conditions is expected to open the pressurizer solenoid operated relief valve if necessary to prevent exceeding the Appendix C pressure limits. This is a temporary 1
measure instituted to provide immed ia t e. availability' of the pressurizer relief valve as a pressure transient mitigating device during solid conditions. Once the j
-design change providing a inw pressure setpoint feature for this relief valve is implemented, the temporary i
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14 i
1 i
m
,..m
_-- ~-. -. -
b
(;
b.;.
I requirement for this dedicated operator can be removed.
The pressurizer relief valve is the primary means i
of mitigating an overpressurization event, should one occur. However, as described in the response
{-
to Question No. II. 7.b., the shutdown cooling system j
safety valves, a pressurizer steam volume and operator j
action af ter ten minutes all serve variously as backup measures depending upon the specific event.
l Therefore, it can be stated that reliance on this special, dedicated operator is not required to mitigate I
I the consequences of any overpressurization event.
I
)
However, until the low pressure setpoint feature is i
implemented, reliance on this operator responding l
within ten minutes of an event is raquired to meet j
the suggested " single failure" criteria.
i i
II. 7.a.
QUESTION:'
It is not clear from your discussion of design j
criteria, (page B-3 to B-5) whether the criteria are being applied to your present or future pressure I
protection system. To clarify this, address the following:
i In discussing the operator action criteria, using an operator to take corrective action within ten i
(10) minutes is described. Will this be needed when your dual setpoint feature is installed?
l What operator action design criteria will be applied for your final design modification?
i ANSWER:
Our intention is to meet the suggested design crit'eria
{
to the extent practicable with both the presently installed and planned replacement pressurizer relief j
valves. The answer to the previous question (11.6) j indicates that our reliance on the proper - response of the special, dedicated operator is a temporary requirement which immediately makes available the existing pressurizer relief valve as a pressure transient mitigating device. The installation of a low pressure automatic satpoint feature to the solenoid for this valve will preclude the requirement for the special, dedicated operator. The only operator action criterion planned for. the final design configuration is the suggested ten minute response j
time delay criterion. However, we believe that the j
' principle of a special, dedicated operator with very limited responsibilities being able to properly respond within the ten minute period is a sound and reasonable concept. -In the event that future developments regarding reactor vessel overpressuriza tion protect ion 1
indicate the need for f urther protection featutes, we will consider this principle as a viable alternative 15
(
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4 1
to some expensive design change.
II. 7.b.
QUE ST'l'N:
The single failure criterion discussed on page B-4 states that below 3000F, three relief valves are availab le.
For RCS temperatures between 3000F and l
3600F, operator action af ter a response delay of ten minutes provides pressure protection. The RCS can i
be fully pressurized above 3600F. Will operator action still be required in the 300 F to 3600F range when.
1 the dual setpoint, higher capacity pressurizer relief is installed? What single failure criteria will you use then?
l ANSWER:
Preliminary note: See Answer # III.2.
The above quoted 360 F velue has been revised to 3240F.
Below 3000F, the shutdown cooling system safety valves are available. Therefore, these valves and the pressurizer relief valve are available as pressure transient limiting devices. As described in the answer
]
to Question No.11.9, the SCS safety valves have i
]
suf ficient capacity to be considered as 100 percent backup for both the present and planned pressurizer 4
relief valves. Therefore, the suggested single failure criterion is met at temperatures below 3000F without l
operator action. (1) l l
Above 3000F, the SCS safety valves are isolated from j
the main coolant system and therefore unavailable to limit a pressure transient. However, the main i
coolant system is not solid at these temperatures, and a pressurizer steam volume of _> 198 cubic feet is available.
For all postulated events that could lead to overpressurization at these tempe ra tur es,
the pressurizer steam volume limits pressure buildup over the first ten minutes to a value less than dm Appendix G limits. Therefore, in this temperature range, operator action beyond ten minutes is an ef fective backup to the pressurizer relief valve low setpoint in limiting main coolant pressure. Therefore, j
the suggested single failure criterlun can be met
]
for' all conditions requiring reactor vessel i
overpressure protection. Tabla II. 7.b. summarizes the above discussion.
5 j
(1) Except that special dedicated operator action is required until the low pressure setpoint feature is implemented.
4 i
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4 Table II. 7. b.
Protection Means O
MCS Temperature F Primary Backup 1300 Pressurizer Relief SCS Safety Valve Valves 300 " T 1324 Pressurizer Relief Operator Action a Valve (t+10) minutes II. 7. c.
QUESTION:
Do the Testab.'lity, Seismic Considerations and IEEE 279 sections of Appendix B pertain to the system as it now exists or as it will exist once the proposed features are installed (e.g., dual setpoint, high capacity relief)?
ANSWER:
The testability, seismic, and IEEE-279 sections of Appendix B pertain to the system which will exist once the proposed features are installed.
11.8.
QUEST'ON :
We do not understand your statements at the bottom of page B-3 and the top of page B-4.
In these statements you are describing how you take credit for operator action within ten (10) minutes, and that this action is fully redundant to the SCS reliefs or operator action at ten (10) cinutes. To clarify our understanding of these state ents, address the following:
- a. If action at ten (10) minutes prevents overpressurizations, then why is action required before this, (i.e., why is it necessary to deviate from the stafi's operator action criterion)?
- b. With regard to Appendix C in which you evaluate potential overpressure causing events, several of these require operator action to prevent RCS ov e rp r es s ur i za '..o ns.
Hewever, in each of these cases, the operator action took place ten (10) minutes after the event despite your stated need for action in less time (page 3-3).
Clarily this ap pa ren t disc repa ncy.
ANSWER:
Shortly af ter NRC's letter of August 11, 1976 expressed concern about reac t or vessel ove rpressur iza tion the Superintendent of the Yankee Rowe plant established the temporary requirement for the special, dedicated 17
L operator to be stationed at the main control board during water-solid conditions.
At that time, as now, the pressurizer relief valve was not equipped with a low pressure se tpoint feature. The primary purpose of the special, dedicated operator, therefore, was to immediately make available the relief capability of the pressurizer relief valve in the unlikely event of an overpressuriza tion transient.
Instead of waiting for the implementation of an undefined, automatic design feature, this prudent action provided immediate, assured protection during subsequent plant conditions requiring such protection. This action was taken swiftly despite the fact that plant operating procedures were already extremely conservative and cautious regarding water-solid conditions and in light of the fact that not a single overpressurization event is known to have occurred at the Yankee Rowe plant in its entire, long operating history.
This temporary requirement for a dedicated operator was established before all analyses were completed of the various postulated pressure transient. Whether or not operator action within the ten minute period was required to either protect the plant or meet the to-be-suggested single f ailure criterion was not known at that time.
By having the operator available, the plant had the protection available until such time as it was shown to be unnecessary.
Since then, review and analyses of various pressure transient events have been conducted and reported in our original submittal and in the answers to these questions.
Reliance on operator action within ten minutes has been shovn to be unnecessary except to operate the pressurizer relief valve manually until the automatic, low pressure setpoint feature is installed in the n ex t few months.
We hope this clarifies any conf usion that may have existed regarding why the dedicated operator requirement was established. We think our action was prudent, conservative, and timely and stands as testimony to Yankee's positive responsiveness to valid NRC concerns.
11.9.
QUESTION:
On page B-4, in Section B you state that two of the three relief valves that are available below 300 F are sufficient to keep transient RCS pressures in the worst-case event to less than vessel limits.
You further state that the new high capacity pressurizer relief valve will be fully redundant to both of the SCS safety valves.
You also stated, previously, that each SCS safety valve can relieve 101 gpm at 4o7 psig ( Appendix B, page B-1). From 18
t Figure A-1 on page C-23, the replacement pressurizer relief valve capacity does not reach 202 gpm 'intil system pressure is about 500 psig.
Explain this inconsistency. Consider future operation with more restrictisc Appendix G limits as vessel irradiation increases.
ANSWER:
A comparison of the relief rates of the pressurizer relief valve (both existing and new) and the two shutdown cooling safety valves (taken together) should help clarify the apparent inconsistency.
The following table includes values from Table II.l.a. (response to a previous question) and data extracted from Figure A-1 of Appendix C to the original submittcl (page C-23).
Table II.9 Capacity gpm Existing System Pressurizer New Pres.
SCS Valves Pressure Valve (I)
Valve (I)
(4000F 467 psig 136 178 178 532 psig 160 238 264 The above table shows that the shutdovn cooling safety valves have a calculated capacity at least equal'to that of the new and existing pressurizer relief valves.
The transient analyses of the postulated reactor coolant pump full flow initiation event contained in Appendix C to the original subnittal shews that the single pressurizer relief valve is sufficient in capacity to limit the transient pressure to within acceptable limits.
Since the pressurizer relief valve alone was the basis for the analysis, our statement on page B-4 should have been:
"The shutdown cooling safety valves possess sufficient relief capability to be fully redundant to either the existing or the new pressurizer relief valve."
11.10 QUES 110N:
The single f ailure criteria we specified at our November 3 meeting, and as sunmarized in the meeting summary (copy a ttached) require that following the initiating event ( f a ilure) the pressure protection (1) at 440 F, 500 psig.
19
...~.
5-2 system be designed to protect the RCS with a single (additional) failure (either equipment or operator) once the pressure transient is in progress.
It is not evident from your submittal whether your system is designed in accordance with this criteria. Provide j
additional discussion on your system's single f ailure criteria, 'and what modifications in your final design wuld be needed to meet the acceptance criteria desc ribed above.
ANSt!ER:
First, we would like to emphasize our understanding that the single failure criteria and all other design and operator action criteria discussed at the November 3,1976 meeting were and remain " suggested" criteria.
4 We feel that your apparent trend toward treating all equipment which could either cause or mitigate an overpressuriza tion event as full safety-grade equipment may be unwarranted considering the potential cost of design changes necessary to meet these various suggested criteria. Since low temperature overpressurization can never occur at power, equipment designed or modified to prevent or mitigate its consequences should not necessarily have to be designed to meet all criteria imposed on ECCS systems.
In view of the above, and because we are committed to implementing all reasonable steps to protect against ever having an overpressurization event at Yankee Rowe, we have attempted to meet all suggested criteria t
to the extent feasible. There is only one pressurizer solenoid-operated relief valve installed at Yankee c
Rowe.
Theref ore a simple mechanical failure of the valve itself could be postulated. As explained in the original submittal and the response to Question No. II. 7.b., the single f ailure criteria relative to mitigation of an event, can be cet at Yankee Rowe primarily by the principle of diverse methods.
11.11.
OUESTION:
Paragraph C, page B-4 discusses the testability of your pressure protection components.
Provide further i
explanation-as to why the " total operability" of the i
dual setpoint pressurizer relief valve cannot be determined.
ANSWER:
The pressurizer relief valve is a solenoid-operated, pilot-actuated valve. Electrical impulse to the i
solenoid positions a pilot which opens a vent path I
which, in turn, permits upstream fluid pressure to open the valve. An indicating light on the main a
control board shows whether or not the solenoid is i
energized but does not positively indicate whether the valve physically opens or not.
During the pre-cooldown test, the upstream isolation valve is closed i
i 20 t
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and the solenoid energized. Since the relief valve 4
is isolated, no-changes in pressurizer. pressure or downstream temperature will occur. Therefo re, " total
' operability" of the valve cannot be verified by an in-place test.
11.12.
QUESTION:
As we stated in our-November 3 meeting, the electrical components of the pressure relief system should be designed to meet the requirements of IEEE 279, or you should ' provide the basis ' fo r any deviations.
Paragraph E page B-5 discusses. IEEE 279 requirements but lacks suf ficient justification for the deviations.
Provide your basis for not meeting the requirement specified in IEEE 279.
Include any prints or diagrams necessary to your explanation. Will the additional instrumentation and electrical equipment you have proposed meet IEEE 279 requirements as well as Class IE criteria?
ANSVER:
The design of the Pressurizer Relief Valve System l
does not meet the requirements of the IEEE 279 j
standard. The mechanical equipment will be purchased for Safety Class I application. The Quality Assurance 4
l-requirements which would be imposed on the purchase of electrical equipment and instrumentation designed to the requirements of the IEEE 279 standard will be imposed on the purchase of electrical equipment l
and instrumentation which will be used in the Pressurizer Relief Valve Control System.
III.L.a.
QUESTION:
Appendix C discusses your evaluation uf postulated events which could cause reactor vessel ove rp r es sur iza t io n.
Respond to the following:
In all postulated events, except the Main coolant j
pump (MCP) start, you assume that the presently installed equipment is available for pressure protection (e.g., SCS safety valves and operator control of pressurizer relief valve).
In the analysis of the MCP start transient, you assume-i the availability of only the-existing pressurizer i
relief valve with the dual setpoint feature, taking no credit for the two (2) SCS safety valves (425 psig. 101 gpm each) which are assumed operable j
'for all other transients. We do not understand
]
why an analysis was not performed assuming the higher capacity SCS safety valves were available for pressure protection.
Plaase explain this assumption.
ANSWER:
In all postulated events we assume the availability l
of protective features consistent with Table II.7.b included with the response to Question No. I I. 7. b.
i 1
21 1
1
,v:
The main coolant system full flow initiation transient (not necessarily a pump start)Lis no exception. The analysis considered only tho calculated relief capacity of the pressurizer relief valve in order to ascertain whether or not this valve alone could limit transient pressure to vithin acceptable limits.- Figures B-1 and B-2 of the original' submittal demonstrate that J
the single pressurizer relief valve has sufficient capacity to maintain transient pressure to within acceptable limits. Therefore, since the SCS safety j
valves' capacity is equal to or greater than that of the pressurizer relief valve (new or existing),
we have established that the SCS safety valves are fully redundant to the pressurizer relief valve.
111.1.b.
QUESTION:
You have not considered the inadvertent ECOS operation or the loss of shutdown cooling heat capacity t
transients as plausible events due to your procedural res tric tio ns.
However, the reactor coolant flow j
initiation transient is analyzed in detail, even though procedural restrictions do not. allow MCP starts unless an air or steam bubble exists in the pressurizer (page C-ll) and at all other times, the MCP breakers are withdrawn (page A-2).
Explain in detail why you have selected the MCP start transient as the event requiring 4
the most detailed study, and not the inadvertent ECCS operation or the loss of SCS.
Explain the difference in your procedural restrictions that allow the M;P start to be more likely than the other two transients.
ANSWER:
. We have analyzed the following postulated events regardless of their potential or probability for '
occurrence:
- a. MCP f ull flow initiation.
- b. Inadvertent ECCS initiation.
- c. Charging / bleed (letdown) flow mismatch.
I
- d. Pressurizer heater-induced expansion.
- e. Loss of residual heat removal capacity.
The fact that the main coolant f ull flow initiation i
transient was selected for a time-dependent transient analysis should not be construed to indicate that it is.either the most potentially suvere or the most likely to occur of the events considered.
It may actually be either, but we did not attempt to ascertain this.
Instead, we investigated the inpact of each 7
potential overpressurization event that could be initiated by a single equipment failure or operator 22 e
- (.
m error. This investigation ' led to definition of the above listed events. At this point we did two things:
- 1. Took measures to prevent the occurrence of each of these events.
- 2. Undertook an analysis of each of-these events.
The analysis of each event. attempted to determine whether or not - plant equipment and/or. operr r action could adequately protect against that event cegardless of whether or not it could occur. Most of the transients were slow and all transients except' the main coolant flow initiation transient could be adequately analyzed by means of hand calculations.
The primary reason for conducting a time dependent transient analysis on the main coolant flow initiation transient is that it is a short duration transient dependent on wany variables. 11and calculations could
- not have produced a sufficiently realistic yet conservative prediction of peak transient pressure.
III.l.c.
07ESTION:
On page C-13 you state that further reviews of your pressure protection system will be performed s vessel irradiation alters the Appendix G pressure-temperature limita tio ns. Furnish an estimated schedule for your future reviews and associated submittals to the staff.
Indicate if your high capacity pressurizer relief valve has been sized on the basis of anticipated vessel irradiatien ef fects on Appendix G limits and the applicable irradiation levels assumed.
ANSWER:
A revised Appendix G pressure-temperature curve is prepared-and applied to.each new eara. Therefore, a review of the adequacy of the pressure protection system will be conducted prior to each refueling CJtage.
The increased capacity of the planned replacement pressurizer relief valve was determined prior to development of the overpressurization issue. The
{
overpressurization question did not determine nor l
has it altered the sizing of this planned replacement J.
valve.
111.2 OUEST10N:
'On page C-4 you' state that the maximum allowable-l pressure at 3000F is about'1300 psig, and on page.
j
.C-2 you indicate.that the RCS may be. fully pressurized when above 360 F.
Furnish'a plot of your allowable pressure-temperature e-ves showing the Appendix G limits, as a f unction ut irradiation.
I
- ANSWER:
Figure 111.2 is representative of t he ap pl icab l e i
l' 1
-23 l
4 4
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-,-m.
, ~,
_,n.
Appendix C limits for heatup and cooldown. This figure is based upon Figures 3.4-4 and 3.4-5 of the current Technical Specifications. These pressure-temperature limits are revised each refueling outage to account for vessel cumulative irradiation.
The 1300 psig and 3600F limit quoted above, should be 1800 psig and 324 F respectively in accordance with the Figure provided. The 1300 psir, and J60"F limits were based upon the assumption that Technical Specifications Figures 3.4-2 and 3.4-3 applied to reactor vessel overpressurization protection.
In light of the Technical Specifications bases, we now feel that Figures 3.4-4 and 3.4-5 are the more appropriate limits for such low probability events.
III.3 QUESTION:
On page C-2, you conclude that further protection against an inadvertent ECCS actua tion is not required due to your procedural controls. We have reviewed your procedural measures described in Appendix A and on page C-2.
Since you close SI header isolation valves and disable S1 pumps, inadvertent injection is definitely less likely.
However, we will require that you denonstrate adequate overpressure protection considering all potential initiating events. Accordingly, address the following:
- a. Perfo rm a RCS t ransient pressure analysis assuming a non water-solid pressurizer and an inadvertent injection from a single ECCS train.
State your' initial conditions.
- b. Since the RCS is made water solid at around 180 F on a system cooldown (Appendix A), and the third ECCS train is tagged out when the RCS temperature is $_200 F, pe rf o rm the same analysis as above assuming a water-solid system.
(Assume a RCS temperature of about 180 F).
- c..Hcne sensitive is the predicted RCS pressure response in the above analyses to the initial RCS temperature and pressure (assuming accumulation ef fects on relief value pe rfo rmanc e) ?
ANSWER:
Consistent with the requirements of Technical Specifications, the following action has been taken on a plant cooldown when temperature and pressure are less than 3400F and 1000 psig, respectively:
- a. Automatic saf ety injection has been blocked.
24
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- b. The control. switches for all ECCS pumps have been placed in the Trip-Pullout position.
- c. Motors for two trains of ECCS pumps have been made electrically inoperable by racking out, locking and tagging their - circuit breakers.
1
- d. The accumulator isolation valve is closed made and tagged electrically inoperable.
(. One motor operated valve in the injection flow path to each main coolant loop is closed (but
. re=ains electrically operable).
Based upon. the above steps, it is concluded that at least three consecutive, single-equipment, spurious, active failures and/or single operator errors would
+
have - to occur in order to activate a single ECCS train under these conditions. Two possible activation sequences are listed below.
Sequence 1:
j
- 1. LPSI pump starts.
- 2. HPSI pucp starts.
j
- 3. A closed MOV leading to a main coolant loop opens.
t Sequence 2:
- 1. Place CS ~ f or llPSI pump in Auto.
l 1
l
- 3. Manually initiate safety injection or remove block j
on automatic safety injection.
Furthermore, a t least two single equipment failures 1
l and/or operator errors would be required in order to initiate flow to the reactor vessel from one pump l
of a single ECCS train.
1 It is therefore, concluded that procedural controls adequa tely 'pr event inadvertent initiation of flow to the reactor vessel by either a single pump or a complete train of ECCS.
Based upon the above conclusions, a transient analysis of this event seems unwarranted and has not been i
pe r f o rmed. However, a qualitative evalua tion of this 1
i 1
25 l
~-
i i
I l
event has been ' conducted and is presented below.
1
)
The maximum attainable pressure in this postulated j
event is dependent on the available relief valve capacity and the particular design features of the a
Yankee Rowe ECCS components and piping. The head-flow characteristics of each ECCS pump have been provided in the response to Question #1.3.a.
From these curves the following data is taken:
Table III.3 Pump Shutoff Head (psi)
Maximum Flow (gpm) i LPSI 700 1100 I
HPSI 850 220 Figure 111.3 is a simplified ' flow diagram of a single ECCS train. This drawing illustrates the series-parallel flow paths provided for the LPSI and HPSI pumps.. This arrangement provides series flow (through the LPSI then HPSI pump) when main coolant pressure is high; and parallel flow which effectively bypasses the HPSI pump when system pressure is low.
This inherent characteristic of each ECCS pump train comes into play in the_ postulated event under consideration.
The following-sequence would occur in the event of an inadvertent initiation of a single ECCS train while in the water-solid condition:
at least one main coolant loop beccmes available.
- b. The HPSI pump rapidly increases system. pressure to the set pressure of the pressurizer relief valve i
and the SCS safety valves. Maximum system pressure developed by the HPSI pump is approximately 850 Psig.
As the LPS1 pump accelerates to full RPM, system pressure w'll increase beyond 850 psig as the discharge of the LPSI pump feeds the suction of the HPSI pump.
- d. If this event occurred at a tecperature above 300 degrees, when the SCS safety valves are unavailable, 4
and the pressurizer relief valve f ailed to operate, i
26 4
1-
system pressure, without operator action, could -
not exceed approximately 1550 psig. At 3000F,
-the applicable Appendix G pressure limit (based upon cooldown Technical Specifications Figure 3.4-
- 5) is approximately 1800 psig. Therefore, in this event, the Appendix G limits would not be exceeded.
- e. If this event occurred at a system temperature between 200 F and 300 F, when the SCS safety valves are available, and the pressurizer relief valve failed to operate, system pressure, without operator action, could not exceed approximately 700 psig, l
the shutoff head of the LPSI pu=p.
This is because the relief capacity available exceeds the design flow rate of the HPSI pump.
Consequently, the j
HPSI pump develops no appreciable head. At 200 F, the applicable Appendix G pressure limit (based
.upon Technical-Specifications Figure 3.4-5) is approximately 1000 psig. Therefore, in this event, the Appendix G limit is not exceeded,
- f. If this event occurred with a steam bubble in the pressurizer, the end result would be the same.
Initially, LPSI pump flow rate would be very high -
approximately 1100 gpm - the design flow rate --
4 until the steam volume was pucped solid in approximately 1.5 minutes. Once solid, the final
-system conditions would be the same as described ab ove.
i The inadvertent initiation of ECCS flow to the vessel from a single pump in a single ECCS train could udt pressurize. the system in excess of 850 psig. As stated above, this does not exceed the Appendix G limit.
From.the above discussion, it is concluded
- that, despite the unrealistic assumption that an inadvertent initiation of one train of ECCS pumps could occur, such an event cannot. increase pressure beyond the j
Appendix G limits assuming a f ailure of the pressurizer J
relief valve to open on signal.
I
. 111.4.
QUESTION:
Describe the procedural or equipment limitations that i
l ensure a minimum pressurizer steam volute of 1200 l
cubic feet, as you describe on page C-3.
- ANSk'ER:
At all main. coolant temperatures above 3000F (when j
the shutdown cooling system is isolated), a pressurizer steam volume of >l98 cubic feet is ma intained. Normal pressurizer water level of 120 inches narrow range is specified by plant operating procedures and-
[
maintained automatically by the variable speed, positive displacement charging pumps. This normal I
t i
i 27 j
=
s pressurizer water level provides a steam volume of
-205 cubic feet.
If level were to increase to 129 I
Linches, the charging' pumps would be tripped. At this
_high level point, pressurizer steam volume is 198 l
cubic feet.
111.5 QUESTION:
Two cases are discussed in the charging without bleed j
flow transient.
In Case B, you indicate that an i
analysis of this event was performed.
Provide :he
_ details of this analysis. As a minimum, furnish the following info rmation:
a._ Description of system.model i
- b. Initial conditions and assumptions l
- c. Plot of RCS pressure vs. time
- d. Sensitivity of predicted response to initial conditions.
ANSWER:
A transient analyais of this case was not pe rf o rmed.
The analysis consisted of a hand calculation (with conservative simplifying. assumptions) which determined the pressure increase in the pressurizer over a ten minute period resulting from the continuous charging of 100 gpm.
Pressurizer level increases steadily during the ten minute period, but a steam volume is always present. The thermodynamic behavior of the steam volume as it is being compressed limits the pressure rise to the order of 100 to 200 psi.
I 111.6.
QUESTION:
On - page C-4, you b riefly desc ribe an " ope rational-pressure limit" (OPL) that precludes vessel overpressurization in Case B of the charging without i
bleed flow transient.
Please furnish additional-information on this OPL, _ indicating when it is used, and how it precludes vessel overpressurization for this event..
f ANSUER:
Normal plant heatup and cooldown procedures define an upper limit on main coolant pressure as a function of temperature that is core limiting than the Appendix-G pressure-temperature curves. This operational limit curve is based upon operating restrictions inherent to the canned-rotor type coolant pumps installed at-1 the Yankee Rowe plant._ As an example, a t 3000F, the Appendix C curve ' limits pressure to about _1800 'psig.
The " operational limit" at 300 F is about 500 psig.
The " margin of safety" at :3000F, then, is 1300 psig.
Therefore, since an incident of continuous charging at the unrealistically high rate of 100 gpm will increase pressure only 100-200 psig in ten minutes, i
28 i
..t o
l the 1300 psig safety margin is more than enough to prevent exceeding the Appendix G pressure limit.
The operational limit is illustrated in Figure III.2.
111.7 QUESTION:
In your discussion of.the pressurizer heater operation without bleed flow, on page C-5, you state:
9 "It is assumed throughout the discussion t hat the single equipment f ailure or operator error is that which causes~ isolation of the bleed path. No f urther failures or errors occur."
This assumption is not consistent with single failure i[
criteria specified in our November 3,1977 meeting and as repeated in the meeting summary:
" Single Failure Criteria - The pressure protection system should be designed to protect the vessel given a single failure in addition to a failure that initiates the pressure transient."
If this criteria cannot be met, provide sufficient justification for not doing so.
f ANSWER:
What we mean by the statement on page C-5 quoted above, l
is that we are not considering multiple failures in the'cause of the postulated event.
In o t he r wo rds,
i we are not considering inadvertent isolation of the bleed path together with some other equipment failure or operation. error which could cocpound the' severity of the incident. Ilowever, as indicated in the answer to question II. 7.b., the additional single failure.
in the mitigating system proposed by the suggested single failure criterion has been accounted for.
Therefore, we feel that our analysis of this incident meets the suggested criterion.
III.6 QUESTION:
In your discussion of Cases A, B, C, and D of pressurizer heater operation without bleed ficw, you have omitted the details of the analysis.
- Provide, as a minimum, the information we requested in item 5 above.
ANSWER:
All four cases of this postulated event involve energy
+
input from pressurizer heaters as the driving force to increase pressure.' Each of the four cases describes dif ferent plant conditions during the postulated event.
In all cases the pressure transient is a slow increase, with the rate dependent on pressure. Consequently, 4
the analysis. consisted of hand calculations utilizing, where necessary, simplifying but c onse rva tive assumptions to estimate the rate of pressure increase for each case.
1 4
29
_, ~..
.=..
4 a
111.9 QUESTION:
You have also omitted the details of your analysis of the loss of shutdown cooling heat removal capacity transient.
Provide, as a minimum, the inf o rmation we requested in item 5 above.
ANSWER:
In this postulated event, an assumed loss of heat removal ability results in energy addition to the main coolant, thus tending to increase pressure.
As in the previous event (Question No. 111.8), a variety of applicable plant conditions were reviewed as initial conditions, and the resulting pressure transient is a slow increase; therefore the analysis again consisted of hand calculations which conservatively estimated the rate of pressure increase for each set of initial conditions.
i 111.10 OUESTION:
'In the discussion of the loss of shutdown cooling heat removal capacity transient, you state that the expected contribution to system expansion rate is i-below 33 gpm, and the total expansion rate would not exceed 202 gpm.
1
- a. Explain the differences between these rates.
Is it due to an assumed letdown flow?
- b. Provide a discussion of the model and assumptions used in this transient analysis which explain how the 33 and 202 gpm expansion rates were calculated.
- c. At the end of the description of the transient you state that inadvertent closure of the SCS ihlet isolation valves was not analyzed because of the administrative controls you use..We consider this 1
insuf ficient justification, and require an analysis i
of this event.
i 4
ANSWER:
- a. The answer to this question is clearly stated in the following paragraph reproduced directly from the submittal with underlines added for emphasis:
"Tbe maximum expected contribut ion to the system 3
expansion rate from core decav beat plus main coolant pump thermal energy is below 33 gpm, 4
the flow rate of one charging pump.
This g
expansion rate could be coupled with that
-produced by the pressurizer heaters under 4
previously discussed conditions. The total expansion rate in any case would not exceed 4
202 gpm."
There is no dif ference in an assumed bleed (letdown) flow. The difference between the 33 gpm and the k
30
s'
(
w.
i-i 202 gpm is due to the expected expansion rate from l
pressurizer heaters.
- b. As stated in the answer-to questian No. 111.9, a time dependent transient analysis of this postulated event was not 'perfo rmed due to the
-slowness of the pressure increase. The actual expansion rates due to main coolant pump heat, core decay heat and pre 6surizer heaters were i
calculated by hand, utilizing simplifying but conservative estimates.
The principal factors determining expansion rate are energy input, initial temperature, pressure and volume of the main coolant system.
Variables j
depending on plant operating conditions are:
1
- 1. Amount of core decay heat present.
- 2. Number of main coolant pumps running.
- 3. Number of pressurizer heat groups operating.
- 4. Number of main coolant loops isolated (if any).
- 5. Bleed flow rate.
- 6. Pressurizer condition - solid or steam volume.
From the above, it can be seen that the number l
of variables af fecting the system expansion rate for this postulated event are considerable. Ac'tual conditions chosen to determine that the maximum expansion rate was below the capacity of the SCS safety valves were based upon conditions specified in normal plant operating procedures.
- c. The controls and interlocks associated with the SCS isolation valves are' described in answers j.
- 1.6.a.,
c.,
and d.
Because of these controls j
and interlocks and the associated administrative i
controls, inadvertent closure of any SCS isolation j-valve is an extremely improbable event. Therefore,
)
an analysis of a postulated overpressurization event under these conditions is considered unnecessary.
111.11 QUESTION:
On page C-ll in the discussion of the MCP startup i'
t r an s i e r.t. you state that assuming a 1000F AT is conservative and is "significantly greater" than the normal temperature dif ferential. - Give 'f urther justification for this assumption.- 'Since the RCS is cooled to 220 F by using the steam generators, f
I I
31 t
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-e
,-,r,,
- - -,y ve w-
,---,-y a
,-m,-.w.n-
~--
--w,-n w.
L 1
and the RCS can.be f urther cooled to < 1000F, why could not a larger AT be experienced?
ANSWER:
Normal plant cooldown procedures specify that steam generator level be permitted to decrease to a low point in the narrow range band during cooldown. When
_p l
main coolant temperature is about 2120F, all steam generator vent valves are opened.
Subsequently, water t
level in the steam generators is increased to a high layup level by means of the condensate system which provides water from the main condenser at a temperature below 100 F.
We have calculated the expected final water tempe
.ure after the filling operation. The initial water inventory of the S/G was taken to be at 220 F while the fill water was assumed to be a: 1000F. The resulting average fluid temperatrie is less than 200 F.
The lowest practically attainable water temperature in the core area during prolonged outages j
is > 80 F.
From this, it is concluded that a 1000 F AT is a reasonable maximum value for an initial condition to this analysis. However, since the worst-case AT could reach a value of approximately 120 F, an analysis of this transient was perf armed using a AT of 1500F. The peak pressure did not exceed the l
Appendix G limit. Ref er to Answer #111.18 for f urther
}
info rma tion.
i l
111.12 QUESTION:
On page C-16, in Section A. I.1 in the fo rmula 4
CL(1)l t+at =
h HCL (i) t + St *
(t + '. t / 2 )
- I (HCL (1-1) - HCL (i))lt b
l Is the argument of the m tern:
(E /2) or (t + A t)/2?
t+
c l
ANSWER:
The argument of the m term is:
(
t+
(At/2) 111.13
' QUESTION:
On page C-18, in Section A.ll you discuss the basic-assumptions of the primary system mass. One of the assumptions is:
K PRES l t PRESlt=0 - E 6- (k)
M l-t
=M k=1 v This states that the mass in the prissuri.ter can only remain constant or decrease, (e.g., no pressurizer insurge is allowed).
Please discuss further the I
i 32
4w:
i.
validity of this assumption after the relief valves lift. Even though the total quantity of the liquid released may be small, isn't the system peak pressure dependent on the mass and pressure in the pressurizer as well as the relief valve' discharge rate?
ANSWER:
The topical report describing the methodology used in analyzing the transient resulting from startup of a reactor coolant pump has been issued as YAEC-4 i
1124, " PRESS, An Analytical Model Used in PWR i
Overpressurization Analysis", February 1977. A detailed discussion of the manner in which the pressurizer is modeled is provided in Section 2.1-of this report. This discussion is repeated below fo r your review.
i To facilitate the modeling of the reactor coolant i
pump start transient, techniques dif fering from those normally used in system formulations developed for
~
two phase pressurizer situations were utilized for the RCS fluid. The primary technique utilized in PRESS which differs from conventional models is the use of constant mass nodes. Typical RCS transient models determine time dependent system performance i
via application of the conservative laws to fixed-control volumes with varying fluid conditions and masses. In PRESS, fixed control masses with varying fluid conditions and volumes are used in applying the conservation of mass and energy principles.
j Although constant mass nodes with varying volumes i
are employed, it remains necessary, of course, to retain the total system volume constant in order that system pressure calculations be valid.
Since the solid pressurizer serves only as a mass to absorb the expansion of the loop fluid being heated, surge rates will necessarily be small since there is no steam bubble to compress.
Even with the i
pressurizer relief valve (s) open, the small volumetric capacity of the valves and small loop expansion rates yields small surges. Thus, to facilitate modeling, the mass of each loop node was retained constant in i
time while the mass of the pressurizer was based on the integrated flow out the relief valve (s).
To illustrate the ef fect of this assumption, a comparison of an actual physical situation to the representation that would result in PRESS as a result of assuming constant loop mass nodes is provided in the following discussion.
During time At, the energy of the primary fluid external to the pressurizer is increased by some value A E.
The system will therefore expand into 33 i
~l
. -~
g a.m.+
1 the pressurizer until a new steady-state system j
pressure is attained. The fluid which expanded into the pressurizer volume will be removed from the loop - flow path 'and thus the mass in the loops will be decreased.
In PRESS, the fluid which would actually expand into the pressurizer remains available for flow. Conceptually, this is accomplished by increasing the loop volume by the j
amount that the initial pressurizer fluid would actually be compressed. Conceptually, of course, i
the pressurizer volume is decreased to yield a constant total system volume.- Thus, each fluid node has varying boundaries in time which depend on 1) the mass of the node, 2) the enthalpy of the node, and 3) the system pressure.
This procedure allows the system pressure to be simply calculated by the iterative solution in time of the following expression which was discussed in WYR 76-125.
L g (p,h ) + M (t)
- v (p.hpres)
V
=E M
- v g
pres pres tot 1
g,y Since the system is entirely solid and therefore highly incompressible, the only significant surges occur when the pressurizer relief valve (s) open. Even for this situation, the surge rates are small, and at i
the time of peak RCS pressure, less than 0.1 percent of the pressurizer volume has been released through the valve. Even if significant amounts of fluid were i
released through the valve and consequently remov'ed from the loop flow paths, the PRESS model would be censervative since allowing the total loop mass to be constant in time provides a larger sink for transfer of energy f rom the steam gener.itor tubes to the primary, thus yielding higher RCS_ pressures in time.
111.14 QUESTION:
On page C-18, Section A.111, in the formula describing steam generator tube temperatures in the nodes j=2 to j=J-1, is.the parameter k in the second term the node's thermal conductivity, or the time index, (used in Section A.11)?
ANSWER:
The parameter k is the node's thermal conductivity.
111.15 QUESTION:
Section A.IV describes how the time dependent steam
' l 4
generator secondary water temperature is calculated.
Address the following:
- a. Discuss why your only source of energy to the primary fluid is the steam generator tubes and secondary fluid. Why isn't the stored energy of 4
I 34 i
e
-e
, - - ~ - - -
w.-e---.
1
... ~
.~. -
i, '
'r ~
b the steam generator: internals (e.g. sepa rato rs, shrouds) considered as energy sources?-
- b. What mass do you use for the parameter M3g3(i)?
i Is it the liquid in the riser, in the downcomer, or a mixture of both?
- c. In the nodal representation of the % tubes, describe the method used for sstablishing the mass of each node and the value-used.
i.
ANSWER:
- a. The parameters of primary importance in the secondary system with respect to determining the
=aximum system pressure excursion are the total l
secondary energy and its temperature. At the time.
of peak system pressure for the YR analysis the
[
{
secondary nodal temperatures vary from 171 F to
[
190 F.
Thus the main concern (i.e. maximum system pressure) occurs at a time when the secondary conditions are reduced only slightly from initial-l conditions with respect to heat transfer to the l
primary.
- b. A conservative total steam generator liquid
. inventory consistent with cold shutdown conditions
[
was used. As indicated in Q.III.15.a. the value chosen was sufficiently large such that the decrease in secondary fluid temperature was maximized at 27 F below its. initial value at the time of peak i
RCS pressure. To assure that the secondary temperature decrease of 27 F.does not significantly j
reduce-the consequences of the transient an additional case was analyzed in which.the secondary i
temperature was held constant. The result indicates a change in the peak RCS pressure of less than 5 psia.
4
- c. The mass of each node is based on the total tube.
mass per steam generator and the axial and radial t
cross sectional nodalization of the tubes.
.athematically, this can be simply stated as follows :
"
- g,f g
n Vp where:
i l
M = cass of a steam generator tube node n
Vn - volume of a steam generntor tube node l
i VT = total tube volume per stear generator I-l
\\
i t
[
35 i
4 i
,.... _, _ _ ~
_ _,.. -. ~.,.
.,.,,m.,.
.. =. _ -
~. -
-~
.L 4-MT " total tube mass per steam generator
- 38500-lbm.
YAEC-1124 provides a detailed discussion of the above info rmation.
3 111.16 QUESTION:
The pressurizer relief. valve disch.irge rate calculatton is desc ribed in Section A.V.
The quantity FRAC sets 4
the f ractional flow rate, given the theoretical f ull open flow at pressure P..
Three f rac t ions are shown.
one being time dependent.
Explain the use of the time dependent term for determining your relief valve discharge rate.
How do you determine the quantity a
DT ? Is the time it takes to reach. full open dependent i
on the system pressure?
I l
ANSWER:
The time dependent term was used only as a sensitivity i
study parameter. For the analysis perfo rmed in which the valve opening was a function of tire the pressure argument remained valid. Thus the f raction of valve -
opening was determined as follows:
f i
FRAC = Minimum of (1.0, (P-500)/50, (t-ts)/10) where: FRAC is the f raction of full valve opening ~
l P is the system pressure t is time i
i t is time at which the valve opening pressure s
]
of 500 psia is attained.
l 111.17
_ QUESTION:
The determination of the pressurizer relief valve discharge rate is discussed in Section A.VIII.
We j
will require f urther information as listed below.
j l
- a. What KD are you using?
)
- b. Appendix XI to ASME Section VIII gives capacity i
conversions for safety valves. Do your relief 3
valves qualify for using Figure UA-231 to determine liquid flow rate? How-does the value from this figure compare with your ccuputed values? Discuss -
any differences.
- c. You state that assuming a. saturated condition in the pressurizer yields a conservative relief valve flow rate. Please justify this statement by providing a table of flow rates with corresponding critical pressures, for a number of subcooled and saturated inlet conditions.
36
~..
i
. ~,
i i
- d. Describe' how you go from the critical flow rate calculated in the formula, to the flow rate vs.
system pressure shown in Figure A-1.
What backpressure is assumed?
I
- e. Please note tFat the units for terms g and J are c
incorrect.
t ANSWER:
a) A discharge coefficient of.271 was used in the analysis. This value was conservatively determined
.by reducing the KD for steam discharge of 0.301 by 10%.
l b) The values provided in Appendix XI to ASME Section
~
l VIII are based on the same methodology used in our analysis (i.e., Isentropic Homogeneous Expansion Model). Thus the.results will be the same for identical conditions. The presently installed relief valve at Yankee Rowe is an old design as 1
evidenced above by its discharge coefficient of 0.301 (0.271 used). Thus the capacity at 400 psia saturated fluid conditions is considerably less than that provided in Figure UA-2 31 which is l
applicable for relief valves with a discharge i
coefficient in excess of 0.90.
The calculated j
capacity of the presently installed' valve for 4 lbm/hr-saturated liquid at 400 psia is 1.87 x 10 2
in. This is less than 32% of the value provided in Figure UA-2 31.
The-proposed replacement valve fo r Yankee Row'e has a discharge coefficient of 0.95 which yields 4
a capacity of 5.94 x 10 lb=/hr-in2 for saturated liquid at 400 psia. This is consistent with Figure UA-231.
]
c) Figures 111.17.1 and 111.17.2 provide the critical l
pressure ratios and discharge capa ities for a numbe'. of situa t ions.
Also included is a specification of the values used in our analyses which shows the conservative approach taken.
i d) To obtain the flow rates provided in Figure A-1 fro = the Isentropic Homogeneous Expansion formulation provided on page C-20 (i.e. b = 0.9
- p !" e).
The-following procedure is used:
K m
Q _(GPM) = 6 (1bm/sec)
- f1 8 #
- v(P.h )* (7.481 gal /f t )'
4 where Q = volumetric flow rate h = mass flow rate e
i 37
.i 1
i l
l 1
.a
- Tii, f
t v
= specific volume i
Po = stagnation pressure h = stagnation enthalpy o
Inherent in the model is that the system backpressure be less than the critical pressure.
Thus, to assure that the model is applicable for
.the pressurizer relief valve it is necessary to determine the critical pressure and compare this to the backpressure that could exist. Figure 111.17.1 provides the critical pressure ratio versus stagnation temperature for a number of stagnation pressures. Since the pressurizer relief valves open at 500 psia in the analysis, the 500 psia j_
trace is of interest.
Since the discharge fluid i
stagnation temperature was. conservatively assumed i
to be 4450F, it is evident that a very high critical pressure ratio exists (.797). -This critical j
pressure ratio yields a critical pressure of 398-psia. This value is significantly greater than any backpressure that could exist and thus validates the astamption of critical flow conditions in the valve.
1 i
e) Noted, but does not affect results.
III.18 QUESTION:
The results of your analysis of the RCP flow initiation transient are discussed in Section B, on page C-24.
We have reviewed these results and request the j
following additional information:
a) Please discuss the sensitivity of your analyses j
to the following:
1
- 1. Nutber of nodes in the model, i
- 2. Initial RCS pressure and temperature, l
- 3. Initial pressurizer temperature, 1
4.
Initial steam generator temperature.
l b) Perform an analysis of the RCS pressure response I
assuming:
- 1. Both SCS code safety valves and no pressurizer relief valves open.
\\
- 2. No relief s or safety valves open (for sensitivity study pu. oses).
l l
i 38 1
.~,.
--,~~.,s
_m
- 4.
ANSWER:
a)
- 1. YAEC-1124 provides a parametric study of the sensitivity of the transient to the number of nodes in the analysis. The study shows that the number of nodes in the YR submittal is adequate.
- 2. The prime concern with the initial temperatures is the secondary to primary dif ferential. To illustrate the minor ef fect of varying the initial RCS pressure and temperature while retaining the 100 F secondary to pri=ary temperature differential the following cases were analyzed.
- 1) TRCS = 1500F, PRCS = 400 psia
- 2) TRCS = 50 F. PRCS = 400 psia
- 3) TRCS = 200 F. PRCS = 400 psia
- 4) TRCS = 1500F, PRCS - 100 psia
- 5) TRCs - 50 F.
PRCS = 100 psia
- 6) TECS = 2000F, PRCS = 100 psia
- 7) TRCS = 100 F, PRCS = 100 psia 0
where TRCS = initial RCS temperature PRCS = Initial RCS pressure Results are tsbula ted in Table 111.18.
In addition, an analysis was perforced with a secondary to primary temperature dif ferential of 1500F (T
= 2500F, T
= 10 0 F, P 400 initialI"$. Although tkis event RC RCS "
cannot occur, results show that the consequences remain acceptable as shown in Table III.18,
- 3. The results of the transient are dependent on the initial pressurizer tecperature only with the pressurizer relief valve discharge respect to capacities.
Thus, the conservative values used in our analysis bound less conservative (yet more realistic) initial pressurizer conditions.
- 4. The initial stea= generator temperature is only impo rt ant with respect tu the dif ferential te=perature that it irposes with respect to the RCS.
This has been discussed in part 2) 39
ab ove.
b)
- 1. Figure III.18.1 provides the results of this analysis for the following case.
Initial RCS temperature = 1000F Initial secondary tecperature=200 F Initial RCS pressure = 300 psia 50 second linear flow acceleration for primary fluid The peak RCS pressures are less than those calculated with the pressurizer relief valves available due to the increased SCS valve capacity, and thus the results are acceptable.
- 2. Figure 111.18.2 provides this analysis for the following initial conditions:
- 1) TRCS = 100 F
- 2) T
= 2000F sec
- 3) PRCS = 400 psia III.19 QUESTION:
Note 2 on page C-2 7 says that the time dependent f ractinn used in Section A.V is intended to adjust the throat area available for flow.
Is this fraction allowed to exceed 1.0?
ANSWER:
The response to question III.19 was provided in the previous responsc to Question 111.16.
The program was written to allow either pressure or time to control the opening characteristics of the valve. The expression provided in the response to Question III.16 is included in this exact fo rm in the program.
40
Table 111.18 Reactor Coolant System Pressure Versus Initial Temperature and Pressure TRCS(F)
TSEC(F)
PRCS (Psia)
Peak System Pressure (psia) 100 200 400 520 (base case) 100 200 100 520 50 150 400 513 50 150 100 513 150 250 400 531 150 250 100 531 200 300 400 538 200 300 100 538 100 250 400 536 a.
100* IHE ilow 50 sec...near flow acceleration 107. valve accumulation (Popen - 500 psia, Pfull = 550 psia)
Note:
For the analyses perfor=ed f rom an initial condition of 100 psia, the relief valve capacity was based on relieving 4450F water as was assuced in the cases initiated f r om 400 psia. This is clearly conservative since the saturation temperature of 100 psia is 328 F and the capacity of the valves increased with decreasing teeperature.
i l
41
I V.1
. QUESTION:
Your submittal includes analyses of dif ferent RCS i
pressure transient causing events with a variety of 1
mitigating measures. As indicated above, we will require an analysis of each event, based on the mitigating equipment you intend to install.
Your i
response should clearly define the mitigating equipment assumed to be installed, the method of analysis, the single failures considered, and the operator action criterion assumed for:
- a. Inadvertent ECCS operation,
- b. Charging without bleed flow, i
- c. Pressurizer heater operation without bleed flow, i
I
- d. Loss of shutdown cooling heat removal capacity.
s ANSWER:
.The answer to this question has been provided in the response to several of the previous questions which have dealt individually with each of the above mentioned events.
IV.2 QUESTION:
You have indicated that a higher capacity solenoid operated pressurizer relief valve will be installed by June 30, 1978. We require the following information with respect to this new pressure mitigating system.
- a. Your anticipated pressure-temperature limit curves (and Appendix G limits) as they will exist in June 1978.
1
- b. Your present pressure-temperature curves expire j
at the end of core cycle XII, (about mid-summer 4
1977).
If analyses'show a core rastrictive Appendix j
G limit as a result of vessel irradiation, what overpressure protective measures will you icplement until the high-capacity valve is installed in June 19787
- c. Provide justification that the proposed dual i
setpoint, high capacity pressurizer relief valve will provide suf ficient-relief capacity with adequate response time during those transients analyzed in your December 1976 submittal.
ANSWER:
Technical, Specifications Figures 3.4-4 and 3.4-5 define the pressure-temperature limits applicable to reactor vessel overpressurization. The presently applicable s
limit curves have served as the basis for the initial submittal on overpressurization. The bases for these 1
4 42 s
am m,-
^
.i j
curves state that they will be revised each ref ueling outage.without a change submittal to the Technical Specifications. The revised limit curves have not i
been generated yet and cannot be provided. However, for the-purposes of ascertaining the impact of the impending limit curve changes on overpressurization.
the future curves have been estimated following the l
procedure outlined in the bases to the Technical t
Specifications (i.e. utilizing Figures B3/4.4-1 and i
1 B3/4.4-2).
The expected shift in RTNDT at the 1/4t and 3/4t -locations is on the order of a few degrees F.
This will have a minimal impact on the protection af forded for reactor vessel overpressurization.
It is expected that no protection or degree of redundancy discussed in either the original submittal or the respanse to these questions will be invalidated by
.this shift. As stated in the answer to question III.l.c, a review of the adequacy of protection against I
overpressurization incidents is to be performed each.
ref ueling outage in light of the shift in the Appendix G limit curves.
If the review indicates the need for further changes in either procedures or equipment, such action will be taken.
The June 30, 1978 date dated in our original submittal and quoted above was the anticipated date for the i
Core XIV ref ueling outage. We wish to note that the replacement' pressurizer relief valve is scheduled to be installed during the Core XIV ref ueling outage as opposed to June 30, 1978.
We do not understand Question IV.2.c.
Is the conservatively calculated capacity of the pressurizer relief valve shown in Figure A-1 of Appendix C to the original submittal inadequate? We request a further explanation of this question bef ore proceeding with an answer.
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( 1200 1100 1000 j 900 1 800 I 8' 700 E 5 4 f. t i e 4 }600 3 u u 3 3 500 q i 400 i-o 20 40 (30 80 100 Time, seconds J DR AWN BY TITLE. -sh YANKEE ATOMIC ELECTRIC COMPANY \\%Akrt ' RCS l'ressure versus Tire 20 TURNPIKE ROAD.WESTBORO.M ASS. CHECKED BY I.'i t h. a t Safety or Relie f Valvet NUCLEAR SERVICES DIVISION CwG NO. g g ;,;,,; APPROVED BY t e
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