ML20006C938
| ML20006C938 | |
| Person / Time | |
|---|---|
| Site: | Callaway  |
| Issue date: | 01/29/1990 |
| From: | Schnell D UNION ELECTRIC CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| ULNRC-2145, NUDOCS 9002090307 | |
| Download: ML20006C938 (14) | |
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1?I Gratiot Street Past Offce Box 149 St. Iouis, Mswn t3I66 314 $542650 DonaldT.Schnell Et c
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jgg January 29, 1990 U. S. Nuclear Regulatory Commission
-ATTN:
Document Control Desk Mail Station P1-137 ULNRC-2145 Washington, D.C.
20555 Gentlement DOCKET NUMBER 50-CALLAWAY PLANT STEAM GENERATOR TUBE RUPTURE - OPERATOR ACTION TIMES
References:
1)
NRC letter from T. W. Alexion to D. F. Schnell dated October 17, 1989 2)
ULNRC-1849 dated October 21, 1988 3)
SLNRC-86-01 dated January 8, 1986 4)
ULNRC-1518 dated May 27, 1987 Reference 1 requested additional information concerning operator action times to support the steam generator tubo rupture analysis.
The attachment to this letter provides information on operator action times from six simulated steam generator tube ruptures (SGTR) with a stuck-open atmospheric relief valve (ARV).
The STGR with a stuck-open ARV is the limiting accident scenario for callaway since it has the largest dose consequence to the general public.
As shown in Table 1, the times assumed'in the analysis are supported by these simulator runs.
Thesc times are also consistent with the times obtained from simulator exercises conducted in 1985 (Reference 2).
Additional accident scenarios were run to simulate the SGTR steam generator overfill casc.
These were not successful duc, in most part, to the inability of the callaway simulator to match tho' extremely unrcalistic conditions in the safety analysis which were input to force the overfill of a steam generator.
The simulator programming is based on best-estimate conditions whereas the accident analysis is based on worst-case conditions.
The accident analysis assumed higher initial steam
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generator levels, lower stcam generator pressure,-higher pressurizer pressure, higher auxiliary feedwater flow, and greater safety injection flow than modeled on the simulator.. These differing assumptions prevent a good-comparison of simulated operator action times to safety e
analysis assumed times, i.e.,
the operators don't observe and, therefore, don't react to the extreme conditions assumed in the accident analysis.
The operator action times for all overfill cases (Reference 3 and 4) are based-t on demonstrated times from simulated exercises (for less I:,
extremo conditions) conducted in 1986 (Reference 2).. The validity of the Reference 2_ data is supported by.results
'obtained during the most rocent Callaway ARV cxcrcises.
The operator action times obtained from the 1989 cxercises
'do-not significantly differ from those obtained in 1985.-
F L
Based on this fact and the'carlier exercisos, we-believe the operator actions times for the overfill cases are reasonabic.
It is our feeling that the enclosed information closos License Condition 2.C.(ll).-
We would be happy to moet with you to discuss this-submittal.
Very truly yours,
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Donald F. Schnell DS/sla Attachment f.
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I STATE OF MISSOURI )
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Donald F.
Schnell, of lawful age, being first duly sworn upon oath says that he is Ser.ior Vice President-Nuclear and an officer of Union Electric Company; that he has read the foregoing document and knows the content thereof; that he has executed the same for and on behalf of said company with full power and authority to do so; and that the facts therein stated are true and correct to the best of his knowledge, information and belief.
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By
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Donald F.
Schnell i
Senior Vice President Nuclear SUBSCRzBED and sworn to before me this MIN day of (XeW/w 1990.
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a-e er GARGA<A J. N aff N01 ARY PUBLIC, STATE Of MISSOURI MY COMMISSION EXPIRES Ari!IL 22, 1993 ST. LoVIS COUNTY L
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I cc Gerald Charnoff, Esq.
Shaw, Pittman, Potts & Trowbridge 2300 N. Street, N.W.
Washington, D.C. 20037 Dr. J. O. Cermak g
CFA,_Inc.
L 4 Professional Drive (Suite 110) 0-Gaithersburg, MD 20879
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R. C. Knop l
Chief, Reactor Project Branch 1
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U.S. Nuclear Regulatory Commission F
Region III L
799 Roosevelt Road Glen Ellyn, Illinois 60137 L
Bruce Little Callaway Resident Office U.S. Nuclear Regulatory Commission RR#1 Steedmam, Missouri 65077 S. V. Athavale (2)
Officc of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission 1 White Flint, North, Mail Stop 13E21 11555 Rockville Pike Rockville, MD 20852
. Manager, Electric Department Missouri Public Service Commission P.O.
Box 360 Jefferson City, MO 65102 L
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bec:
D. Shafer/A160.761
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/QA Record (CA-758) f Nuclear Date E210.01-DFS/ Chrono D.
F. Schnell i
J. E. Birk J. V. Laux M. A. Stiller G.
L. Randolph R. J.
Irwin H. Wuertenbaecher-W. R. Campbell A. C. Passwater R.
P. Wendling
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E. Shafer D.
J. Walker O. Maynard (WCNOC)
N. P. Goel (Bechtel)
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ULNRC - 2145 l
i-f RESPONSE TO NRC REQUEST FOR ADDITIONAL INFORMATION REGARDING STEAM GENERATOR L
RUPTURE ANALYSIS CALLAWAY PLANT During the conference call on August 2, 1989, the staff indicated that the licensee's response of October 21, 1988 to the staff's request for information dated August 18, 1988, was incomplete for several reasons.
First, operator action time to initiate depressurization was not provided.
Second, the exact number of operators that participated in each of nine demonstration runs depicted $n Table 2 of the licensee's L
submittal was unspecified.
Third, the response times for operators T
did not provide sufficient assurance that they represented operators currently at the plant.
For these reasons, the licensee is requested to provide additional information regarding operator response times during a steam generator tube rupture (SGTR) at the Callaway Plant, Unit 1.
The licensee should provide response times for the following actions:
Identify and isolate ruptured steam generator.
" Operator action time to initiate cooldown.
- Cooldown of reactor coolant system (RCS).
' Depressurization of RCS.
- Operator action time to initiate safety injection (SI).
' SI termination and pressure equalization.
Assuming a simulated as-close-to-design-basis-as-possible scenario, the licensee should provide operator response times (1) demonstrating i
that the SGTR event can be mitigated within a period of time compatible with overfill prevention and (2) assuring that response times are
. representative of most, if not all, the operators currently at the plant.
RESPONSE
1.0
-Introduction In response to the NRC request for additional information, steam generator tube ruptures (SGTR) were simulated on the Callaway Plant simulator during the period 10/30/89 to 12/14/89.
The scenarios simulated were six SGTRs with a stuck open Atmospheric Relief Valve (ARV) (also referred to as Atmospheric Steam Dump Valve (ASD)) on the ruptured steam generator (SG), three with-offsite power available and three with offsite power unavailable.
In addition, we attempted to model failure of the auxiliary feedwater (AFW) valve controller on the discharge at the motor-driven AFW pumps.
Two efforts were made.
Data from the first exercise was rejected due to the failure of the simulator NRCREQ.NCR
p o-Att chment ULNRC - 2145 1
to model the valves correctly (throttled versus full open).
The second group of exercises incorporated a trip time at the j
time of tube rupture and included another failure, a turbine-driven main feedwater pump.
j i
2.0 Description of Simulated SGTRs 2.1.
Maximum Dose Casas (ARV Cases)
The design basis SGTR with the maximum potential offsite dose i
is one with the failure of an APV in wide-open position.
This failure releases radioactive sten directly to the atmosphere; I
and if the ARV is left in the opet 1sition, has the potential of releasing the entire contents oi the faulted steam generator secondary side to the atmosphere.
In the ARV cases, isolation of the ruptured SG requires that the block valve ahead of the ARV be closed.
This is a manually actuated valve located in the steam tunnel.
i 2.1.1. The initial conditions assumed for the ARV case are summarized in Table 3-2 of Reference 1.
In the analysis of the design basis SGTR, initial values of plant parameters (e.g.,
RCS pressure, reactor power, SG level, SG pressure, etc.)
are determined by adding or subtracting parameter uncertainties to the nominal values of the plant parameters as appropriate to maximize the resulting offsite doses.
For example, the initial RCS pressure is equal to the nominal pressure plus uncertainty to maximize primary to secondary break flow result $ng in high break flow flashed fraction and offsite doses.
However, since the goal of the simulator runs was only to validate the operator response times assumed in the ARV case and was not to conservatively calcr. late offsite dose, the initial simulated plant conditions as seen by the operators t-corresponded to nominal plant conditions.
2.1.2. Availability of Offsite Power For the ARV case, offsite powar is assumed lost coincident with reactor trip.
The loss of offsite power (LOOP) results in more radioactivity being released to the atmosphere and higher offsite doses than if offsite power is available.
If offsite power is lost, radioactivity is released to the atmosphere through the ARV and/or steam line safety valve without being filtered through the condenser air removal system.
In addition, loss of offsite power makes it more difficult to diagnose a tube rupture.
Simulated ARV cases were run with and without offsite power available.
Operator response times for both of these situations are provided herein.
Like the analysis, the simulated ARV cases have LOOP occur coincident with reactor trip.
This occurred whether the reactor was tripped manually NRCREQ.NCR l
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Atttchm:nt ULNRC - 2145 or automatically.
In fact, in all simulated SGTRs with a stuck open ARV, the operating crew manually tripped the reactor before plant protection systems caused an automatic trip and LOOP was coincident with the manual reactor trip.
2.1.3. Operator Response to Stuck-Open ARV Steam release through a stuck-open ARV is terminated by manual closure of the block valve.
The longer it takes the operators to close the block valve, the higher the offsite dose will be.
A conservatively long estimate of the time to manually close J
the block valve is 20 minutes after the ARV fails open (Reference 1).
This isolation time was extensively discussed in Reference 2, and is based on an expected action time of 4 to 8 minutes plus additional margin added for conservatism to maximize offsite dose in the analysis.
During an emergency situation, control room personnel dispatched to operate the SG ARV block valves would walk from the Control Room through the Secondary Alarm Station and into the Control Room Filtration Room in the Auxiliary Cuilding.
Once in the Auxiliary Building, the operator would have a direct route into the Steam Tunnel.
The total distance is approximately 180 ft.
The expected travel time is 1 to 3 minutes.
Callaway equipment operators indicated that, once in the Steam Tunnel, it would require personnel 3 to 5 minutes to identify and operate the SG ARV block valves.
As a result, the total isolation time is estimated to be between 4 and 8 minutes.
For the simulated ARV cases, once the operators have identified the stuck-open ARV, they contact a secondary equipment operator (EO) over the plant intercom system and direct him to manually close the ARV block valve.
From within the simulator instructor's booth, the simulator is programmed to close the ARV block valve 8 minutes after the control operator ends his call to the secondary equipment operator.
Thus, the Control Room must complete his call to the secondary EO within 12 minutes after the ARV opens in order that the ARV be isolated within the required 20 minutes.
3.0 Operator Responses _to_ Mitigate a SGTR As implied in the NRC Request for Additional Information, there are nine operator responses which must be performed in a timely manner to mitigate the consequences of a SGTR.
These are:
1)
Identify the ruptured SG.
2)
Isolate the ruptured SG.
3)
Initiate RCS cooldown.
4)
Complete RCS cooldown. '
NRCREQ.NCR
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ULNRC - 2145 l
5)
Initiate RCS depressurization.
6)
Complete RCS depressurization.
7)
Initiate SI.
8)
Terminate SI.
9)
Equalize primary and secondary pressures.
These individual operator responses have previously been i:
extensively described in References 1 through 5.
The important l
portions of these descriptions relevant to the present discussion are reiterated below.
3.1.
Identification of the Ruptured Steam Generator In Reference 4, the indications available to the operators to identify the occurrence of an SGTR and to identify the SG(s)
L.
which have ruptured are extensively discussed.
Portions of that discussion are repeated below.
For the simulated SGTR(s), the operators are considered to have identified the ruptured SG at any time at which they state unequivocally that a particular SG is ruptured without regard to what procedure they are currently operating under.
3.1.1.
Identification of SGTR Transient Operator actions in response to a SGTR are assumed to follow plant specific emergency procedures.
Depending whether or not a reactor trip had occurred, Off-Normal or Emergency Operating Procedures would direct the operator to identification of a SGTR.
Plant-specific Off-Normal procedures address some actions to take if an SG tube rupture is in progress with no reactor trip or safety injection.
With condenser air removal radiation monitors or steam generator blowdown radiation monitors indicating above normal or alarming, the plant chemistry departments would start sampling generators to determine the faulted SG.
Associated instruments alarms, and setpoints are tabulated in Attachment 1 of Reference 4.
e The operator would enter E-O on a reactor trip or safety injection whether the signal was automatic or a requit of manual actuation.
Through symptom-based diagnosi, the operator is directed to the proper Optimal Recovery Guidelines to facilitate optimal recovery.
As directed in E-0, the operator would review radiation levels in the SG blowdown and/or the condenser air removal systems.
Abnormal primary-to-secondary leakage and directs the operator to E-3.
i NRCREQ.NCR 9
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Attcchm:nt
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ULNRC - 2145 Once in EOP E-3, the operator would be directed to identify the ruptured SG(s).
For the ARV case, reactor trip and LOOP did not occur for some minutes after the rupture.
During that time, the operator l
would have observed abnormal radiation levels in the SG blowdown and condenser air removal and would be preparing for the. reactor trip and SG identification via Off-Normal Procedures.
3.1.2. Identification of the Ruptured SG s
a once the operator has proceeded to EOP E-3, procedural guidance quickly requires identification of the ruptured SG.
This accomplished by observing one of the following:
- 1) Unexpected increase in any SG narrow range level, or
- 2) High radiation from any SG sample, or i
- 3) High radiation from any SG steam line, or
- 4) High radiation from any SG blowdown line.
Since Reference 1, Union Electric has revised procedure E-3 to i
include manual sampling of steam generator steam lines.
This was done to assure that the steam generator could be identified after LOOP without having to rely on the SG sampling system.
After LOOP SG sampling is complicated by the need to implemes' temporary measures to open sample valves and cool the sample.
The steam line sampling procedure is not burdened by these difficulties and assures that the operators can identify the ruptured steam generator within the time allotted in the analysis.
These indications are obtained by consulting instrumentation within the control room (except for SG manual steam line or SG manual sampling where the information is communicated to the control room).
High radiation indicetions are given by both alarms and displays.
With the exception of the Secondary Side Release Point Monitors (SSRM), the monitors above would be unavailable after LOOP.
As discussed in Reference 7, the SSRM are supplied with a reliable power supply and are available after LOOP.
The readings of these monitors are available in the control room and after LOOP locally near the auxiliary shutdown panel.
These monitors are therefore ideal for detecting a situation similar to the stuck-open ARV scenario.
With this exception updated information is not available after LOOP, though radiation alarms would occur prior to trip for the ARV case.
-S-NRCREQ.NCR
a-o Attcchm:nt ULNRC - 2145 3.2.
Isolation of the Ruptured SG For isolation of the ruptured SG, the E-3 procedure calls for:
- 1) Closure of the MSIV and bypass valves,
For the ARV case, as stated in Section 2.1.3, the ARV is assumed to close within 20 minutes of the tube rupture.
This includes 8 minutes for manual isolation of the valve.
3.3.
Initiation of RCS Cooldown For the ARV case, the RCS cooldown is initiated within 41 minutes of the rupture by opening at least one ARV on an intact SG, or by dumping steam to the condenser if offsite i
power is available.
3.4.
Completion of RCS Cooldown The cooldown is completed by closing the ARVs on the intact j
SGs.
For the ARV case, the cooldown is completed in 14
- minutes, 3.5.
Initiation of RCS Depressurization
{
Depressurization of the RCS is accomplished after the RCS cooldown has been completed.
The E-3 procedure specifies use of a pressurizer PORV, if normal spray is not available, as is t
the case if offsite power is lost.
For the ARV case, the depressurization is initiated 3 minutes after completion of cooldown.
3.6.
Completion of RCS Depressurization Depressurization of the RCS is completed in approximately 1.5 minutes for the ARV case..
In many cases in the simulated ARV cases, the operators will depressurize the primary system below the ruptured steam generator pressure making the following steps unnecessary.
}
3.7.
Termination of Safety Injection Following completion of RCS depressurization to a pressure NRCREQ.NCR
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approximately equal to that of the ruptured SG, the E procedure requires several conditions to be met prior to terminating safety injection (SI).
These ares.
a minimum RCS pressure, _a minimum RCS subcooling based on core outlet thermocouples, and a minimum pressurizer level.
It is assumed that the operators can stop SI flow within three minutes after completion of RCS depressurization.
This time ~ corresponds to 1 minute for each of the three manipulations which the operators mustiaccomplish stopping two SI pumps and one CCP.
3.8.
Equalization of Primary and Secondary Pressures The immediate situation after termination SI is that RCS pressure is a few hundred psi higher than the pressure in the ruptured SG and the break flow, though reduced, still continues.
The first requirement is to equalize pressures in the RCF and the ruptured SG.
Continued steam release from the intact SGTs is necessary to remove decay heat; and a slight reduction of intact SG pressure will reduce RCS temperature, g
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shrink RCS volume, and reduce RCS pressure.
It is assumed that pressure equalization is achieved within 5 minutes after termination of SI.
4.0 Results from Simulated SGTRs The results of the simulated STGRs involving a stuck open ARV are presented in Table 1.
The six crews involved were comprised of senior reactor operators, reactor operators and training personnel.
5,0-References
'l
?. SLNRC_86-01, January 8, 1986, " Steam Generator Tube Rupture
.j l
Analysis - SNUPPS" 2
..NRC 86-05, April 1, 1986, " Steam Generator Tube Rupture Analysis'- SNUPPS" q
i 3.
SLNRC 86-08, September 4, 1986, " Steam Generator Tube Rupture. Analysis - SNUPPS"
- 4. ULNRC-1442, February 3, 1987, " Docket Number 50-483/Callaway Plant / Steam Generator Tube Rupture Analysis"
- 5. ULRNC-1849, October 21, 1988, " Docket Number 50-483/Callaway Plant / Steam Generator Tube Rupture - Operator Action Times" 1
- 6. ULNRC-1518, May 27, 1987, " Docket Number 50-483/Callaway l
Plant / Steam Generator Tube Rupture Analysis"
- 7. ULWRC-1825, September 2, 1988, " Docket Number 50-483/Callaway Plant / Request for information.Regarding i
Noble Gas / Radiation Monitors Location and Technical Specifications"
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- (4b) - Tube leak identified in "A".SG~on'highEcondenser air discharge radiation alarm, and-
-increasing SG level in "A" SG.
Plant announcement at 02:50.
(4c)'
. Tube-leak' identified in"A" SG on high condenser air discharge radiation' alarm, and-increasing SG level in "A" SG.
Plant announcement at 02:10.
(4d)1-Tube leak ~ identified in "A" SG on steam-feed mismatch, increasing-level in "A" SG,.
l
. (4e)
Tube leak identified in "A" SG on decreasing pressurizer level, high radiation alarm-and low feedjflow to "A"
SG.
Plant ~ announcement at'00:50.
in secondary side, and increasing level in "A" SG.-
Tube leak in "A" SG declared'ati 02:07.
(4f) - Tube _ leak identified in "A" SG on'high condenser air discharge radiation alarm, decreasing pressurizer level, increasing level-in "A" SG, and decreasing feed.? flow to "A".SG.
(5)
- Not achieved within'50:29.. Simulation terminated 10 minutes after end of~
depressurization due to: entry into Emergency Operating Procedure ECA ".1, "SGTR'with Subcooled Recovery Desired," due to loss of RCS subcooling.
(6)
- LOOP not simulated.
Offsite power : remained available.
(7)
- Depressurization terminated on 80% pressurizer level.
~
(8)
- Simulation ended at 42:35.
(9)
- Simulation ended when pressurizer went solid.
,.NRCREQ.NCR u.
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