ML20212A940
| ML20212A940 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 12/19/1986 |
| From: | Leeds E NRC OFFICE FOR ANALYSIS & EVALUATION OF OPERATIONAL DATA (AEOD) |
| To: | |
| Shared Package | |
| ML20212A911 | List: |
| References | |
| TASK-AE, TASK-T610 AEOD-T610, NUDOCS 8612290089 | |
| Download: ML20212A940 (5) | |
Text
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o AE00 TECHNICAL REVIEW REPORT Unit: River Bend-1 TR Report No.:
AE0D/T610 Docket No.:
50-458 Date: December 19, 1986 Licensee: Gulf States Utilities Evaluator /
Contact:
E. Leeds
)
NSSS/AE: General Electric / Stone and Webster
SUBJECT:
ADS /RCIC SYSTEM INTERACTION EVENTS AT RIVER BEND-1 Sunnary On November 11, 1985, while River Bend-1 was in startup at 3% power, a reactor core isolation cooling (RCIC) Division I system isolation occurred during a surveillance test of the automatic depressurization system (ADS). The RCIC turbine steam line taps off the "A" main steam line between the reactor vessel and two ADS safety relief valves (SRVs). The licensee, (Gulf States Utilities) believes that lifting either of the two SRVs on the "A" main steam line produces pressure / flow fluctuations in the RCIC steam line. The pressure / flow fluctuations caused a RCIC Division I steam flow containment isolation signal which resulted in the RCIC system isolation. After resetting the isolation and adjusting the Division I differential pressure (D/P) transmitter damping potentiometer, the two SRVs on the "A" main steam line were retested on December 6, 1985. A RCIC Division I containment isolation did not occur during the retest. However, a RCIC Division II containment isolation occurred after l
each test of the SRVs on the "A" main steam line.
Each Division II containment I
isolation was reset and the Division II D/P transmitter damping potentiometer was adjusted. Subsequent testing of both the "A" main steam line SRVs did not cause a RCIC Division I or II containment isolation.
This study was performed to assess the generic implications and potential safety significance of the November 11 and December 6,1985 events at River Bend-1.
In particular, the events at River Bend-1 raiseo the concern that a similar systems interaction involving the ADS ard high pressure coolant injection (HPCI) system (as well as the RCIC system) could occur at a boiling water reactor (PWR) 3 or 4.
This postulated scenerio would result in the temporary loss of all sources of high pressure coolant makeup.
This concern is not applicable to the BWR 5 and 6 class of plants (River Bend-1 is a BWR 6) which are equipped with a high pressure core spray (HPCS) system rather than a HPCI system. The HPCS system relies on a motor-driven pump rather than the steam-driven pump used in the HPCI system.
The study found that the events at River Bend-1 involving the ADS /PCIC system interaction appear to have limited safety significance.
Each event resulted in the RCIC system being unavailable for less than an hour until the system was returned to the standby condition. The resultant unavailability of the i
This document supports ongoing AE0D and NRC activities and does not represent the position or requirements of the responsible NRC program office.
8612290089 861219 PDR ADOCK 05000458 S
2-RCIC system was estimated to be nearly insignificant compared to the system's expected yearly total unavailability. Additionally, it appears that the licensee's corrective actions are adequate to prevent recurrence of an ADS /RCIC system interaction. Finally, the study found that there was no operational data to support the postulated scenerio involving a similar ADS /HPCI system irteraction at a BWR 3 or 4 It appears that the ADS /RCIC system interaction events at River Bend-1 were plant-specific events and are not a generic concern. Based on these findings and conclusions, no further AE0D action concerning the ADS /RCIC system interaction events at River Bend-1 appears necessary at this time.
DISCUSSION 1.
Event Description On November 11, 1985, while River Bend-1 was in startup at 3% power, a RCIC Division I steam line containment isolation signal occurred during a surveillance test of the ADS system (Ref.1). The RCIC outboard steam supply valve and the RCIC turbine trip throttle valve both closed on the Division I containment inlation signal at designed. The RCIC turbine steam line taps off the "A" main steam line between the reactor vessel and two ADS SRVs. The ADS surveillance test involved lifting each of the seven main steam safety relief valves (SRVs) utilized in the ADS system. The licensee believes that lifting either of the two SRVs on the "A" main steam line produces pressure / flow fluctuations in the PCIC/ residual heat removal (RHR) steam line. The pressure / flow fluctuations caused the RCIC/RHP. steam flow differential pressure (D/P) transmitter to generate the containment isolation signal. The licensee reset the containment isolation signal and returned the RCIC system to the standby condition. To prevent a recurrence of the event, the damping potentiometer on the D/P transr'itter was adjusted to increase the transmitter's time constant.
The two SRVs en the "A" main steam line were retested on Decenber 6,1985, wFile River BEND-1 was in startup at 8% pcwer. A RCIC Division I containment isolation signal did not occur during the retest.
It appears that increasing the D/P transmitter time constant prevented a recurrence of the November 11 event. However, wbtn the first of the two SRVs on the "A" main steam lir.e was tested, a RCIC Division Il containment isolation signal occurred (Ref. 2).
In the SRV testing procedure, each SRV is lifted and then immediately closed.
Immediately after the SRV was closed, the RCIC Division II containment isolation signal occurred causing the RCIC inboard isolation valve and the RCIC turbine trip throttle valve to close as designed. The isolation was reset, the RCIC system was returned to the standby condition ar.d SRV testing was resumed.
The second SRV on the "A" main steam line was opened and then closed.
Irr:ediately after the valve closed, the RCIC Division II containment isolation signal occurred again. The isolation was again reset and the RCIC system was returned to the standby condition.
As in the case of the November 11, 1985 event, the licensee believes that lifting either of the two SRVs in the "A" main steam line produces pressure / flow fluctuations in the RCIC/RHR steam line which then caused the RCIC Division I and II containment isolation signals. Because adjusting the
,, damping potentiometer on the Division I D/P transmitter appears to have prevented spurious Division I containment isolation signals, the same corrective action was applied to the Division II D/P transmitter.
Subsequent testing of both the "A" main steam line SRVs did not cause a RCIC Division I or II containment isolation signal.
2.
Analysis and Evaluation The D/P transmitters which generated the RCIC Division I and II containment isolation signals on November 11 and December 6,1985, at River Bend-1 are part of the RCIC leak detection system (LDS). The RCIC LDS's puroose is to detect and isolate breaks in the RCIC steam supply line. A leak or break in the RCIC steam supply line outside of the drywell could challenge the environmental qualifications of the safety-related equipment in the area of the break. Also, excessive loss of reactor coolant could cause the release of a significant arrount of radioactive material from the nuclear system process barrier. The LDS mitigates these challenges by quickly detecting and isolating a leak or break in the RCIC steam supply line. Thus, the RCIC LDS preserves the environmental qualification of essential equipment and limits the release of radioactive material to the environment.
At River Bend-1, the LDS will automatically isolate the PCIC system on any of the followino signals:
(1) RCIC pipe route / equipment area high ambient or differential temperature.
(2) High RCIC steam line flow rate.
(3) RCIC turbine exhaust diaphram high pressure.
(4) Low RCIC steam line pressure.
There are two D/P transmitters which monitor the flow rate in the RCIC steam line: The Division I D/P transmitter which controls the outboard RCIC steam supply valve and the Division II D/P transmitter which controls the inboard RCIC steam supply valve. Diversity is provided by area ambient temperature, area differential temperature and RCIC steam line pressure monitoring.
These diverse methods of leak detection are designed to provide early detection of both large breaks and small leaks. Large breaks are detected almost instantaneously by the differential pressure sensors as well as the area temperature sensors.
Less challenging (smaller) breaks and leaks are detected by temperature sensors which monitor the environmental response of the area around the RCIC steam supply piping and in the RCIC equipment room.
The licensee's corrective actions of adjusting the damping potentiometer for both D/P transmitters at River Bend-1 appears to have corrected the spurious RCIC system isolations caused by lifting and reseating the "A" main steam line SRVs. The adjustment of the damping potentiometers increased each D/P transmitter time constant such that momentary system perturbations will not produce a spurious high steam flow signal.
By increasino the transmitter time constant, a sustained high steam flow condition will be required to generate an isolation signal. However, the increase in the transmitter time constant does not significantly affect the RCIC LDS response time or the RCIC isolation valve closure time.
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3.
Safety Significance m
The spurious RCIC system isolations that occurred at River Bend-1 on s
November 11 and December 6,1985, appear to have limited safety significance i i' for two reasons.
First, the RCIC system was inoperable ~for less than an hour during each event.. In each event, the containment is'olation signals were F
s" quickly reset andithe RCIC system returned to the standby ~conditio; The contribution of these events to RCIC system unavailability is estimated as (2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> /24 hours / day) / 365 days 0.75 = 1.8 x 10E-4, which is nearly insignificant compared to the estimated. total system unavailability of 5.2 x 10E-2 determined for the RCIC system at Grand Gulf-1, a BWR with a similar RCIC system design (Kef. 3).'
Second, this conclusion is supported by the fact that redundant and diverse means of coolant infection are available in addition to the RCIC system, i.e., the HPCS system and the low pressure coolant injection or the low pressure core spray systems in conjunction with the ADS. During both periods that the River Bend-1 RCIC system was 45clated, the plant was at
~.
low power levels (less than 10% power) and the HPCS system was available.
4
(
The ADS /RCIC system interactions that occurred at River Bend-1 on November 11, and December 6,1985, raised the concern that a similar systems interaction involving the ADS and high pressure coolant injection (HPCI) system could occur at a BWR 3 or 4 plant. This concern is not applicable to the BWR 5 and 6 plants (River Bend-1 is a BWR 6) which are equipped with a HPCS system. The HPCS system relies on a motor-driven pump rather than the steam-driven pump used in the HPCI system. At many BWFt, the,HPCI system d aquipped with a LDS very siinilar to the RCIC LDS at River Bend-1 (Ref.t 4).
In a x rst case scenerio, a plant transient which results in the actuation of certain SRVs (i.e., a severe load rejection) could cause steam line pressure / flow fluctuations 'similar to those experienced at River Bend-1. The r'esultant pressure / flow fluctuations coupled with inadequate D/P transmitter instrument settings could result in high steam flow containment isolation signals in both the HFCI and RCIC LDS,.
This would cause both the HPCI ar.d RCIC systems to isolate. Thus, a worst case scenerio involvine a transient which causes SRV actuation could result in the temporary loss of all soufces of high pressure coolant makeup. This hypothetical scenerio would require the operator to actuate the ADS and depressurize the plant in order to use low pressure systems for coolant makeup.
If the operator fails to depressurfre in a timely manner, there is a high likelihood that some form of core damage would cccur before adequate coolant makeup could be provided.
In order to determine if operational data exists to support this worst case scenerio, a search of the Se(uence Coding and Search System (SCSS) Licensing Event Report (LER) data base was conducted. The LER ddta fase was searched for events that involved both\\the ADS and either the HPCI or the RCIC systea. The only events identified in the search which resulted in a HPCI/RCIC system isolation were the two events at River Bend-1 which originally prompted'this study. Other than the events at River Pend-1, there appears \\tn be no (
operational data to support the possibility of an SRV actuation resulting in a HPCI and/or RCIC system isolation.
In view of the lack of operational data concerning ADS and HPCI/RCIC system interactions, it appears that the ADS /RCIC systen interaction events at River Bend-1 were plant-specific events and are not a generic concern.
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FINDINGS AND CONCLUSIONS The events at River Bend-1 involving ADS /RCIC system interactions appear to have limited safety significance. Each event resulted in the RCIC system being unavailable for less than an hour until the containment isolation signal could be reset and the system returned to the standby condition. The contribution of these events to RCIC system unavailability is estimated as 1.8 x 10E-4 which is nearly insignificant compared to the estimated total system unavailability of 5.2 x 10E-2 determined for the RCIC system at Grand Gulf-1, a BWR with a similar RCIC system design.
In addition, during both brief periods that the RCIC system was unavailable, the plant was at low power levels (less than 10%
power) and the HPCS system was available.
At River Bend-1, the licensee's corrective actions of adjusting the damping potentiometer for each D/P transmitter appears to prevent spurious RCIC steam line isolations caused by lifting the "A" main steam line SRVs. The adjustment of the damping potentiometer increased the D/P transmitter time constant such that momentary system perturbations will not produce a spurious high steam flow signal. Since the increase in the D/P transmitter time constant does not adversely affect the RCIC LDS response time or the RCIC isolation valve closure time, the licensee's corrective actions appear to be adequate.
Although the ADS /RCIC system interactions at River Bend-1 appear to have linited safety significance, the events raised the concern that a similar systems interaction involving the ADS and HPCI system at a PWR 3 or 4 could have a potentially significant impact on plant safety.
In a worst case scenerio, a transient causing an SRV actuation (f.e., a severe load rejection) ceu!d cause the same type of pressure / flow fluctuations experienced at River Bend-1 and generate high steam flow containment isolation signals in both the HPCI and RIC LDSs. This would cause both the HPCI and RCIC systems to isciate.
In this scenerio, any transient causing an SRV actuation could cause the temporary loss of all sources of high pressure coolant makeup. However, a sE2rch of the SCSS systen revealed that there is no crerational data to support the possibility of this worst case scenerio occurring at an operating 8WR, Therefore, it appears that the ADS /RCIC system interaction events at River Ber.d-1 were plant-specific events and are not a generic concern.
Based on these findings and conclusions, no further AE0D action concerning the November 11 and December 6,1985, ADS /RCIC system interaction events at River Bend-1 appears necessary at this time.
REFERENCES 1.
Gulf States Utility Company, Docket No. 50-458, Licensee Event Report 85-042.
2.
Gulf States Utility Company, Docket No. 50-458, Licensee Event Report 85-049.
3.
" Reactor Safety Study Methodology Applications Program: Grand Gulf #1 BWR Power Plant," NUREG/CR-1659, October 1981.
4.
S. Salah, J. Pellet, " Engineering Evaluation Report:
Comon Mode Failure of HPCI liigh Steam Flow Isolation Capability," AE00/E405, March 22,1984.