ML20205A139
| ML20205A139 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 03/23/1999 |
| From: | Clifford J NRC (Affiliation Not Assigned) |
| To: | Ray H SOUTHERN CALIFORNIA EDISON CO. |
| References | |
| NUDOCS 9903300303 | |
| Download: ML20205A139 (21) | |
Text
dkW g@ M.ouq g
k UNITED STATES s
j NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20666 4 001
\\.....[2 March 23, 1999 Mr. Harold B. Ray Executive Vice President Southern California Edison Company San Onofre Nuclear Generating Station P. O. Box 128 San Clemente, Califomia 92674-0128
SUBJECT:
REVIEW OF PRELIMINARY ACCIDENT SEQUENCE PRECURSOR ANALYSIS OF OPERATIONAL CONDITION AT SAN ONOFRE NUCLEAR GENERATING STATION, UNIT 2
Dear Mr. Ray:
Enclosed for your review and comment is a copy of the preliminary Accident Sequence Precursor (ASP) analysis of an operational condition which was discovered at San Onofre Nuclear Generating Station, Unit 2 (San Onofre 2) on February 5,1998 (Enclosure 1), and was reported in Licensee Event Report (LER) No. 361/98-003. This analysis was prepared by our contractor at the Oak Ridge National Laboratory (ORNL). The results of this preliminary analysis indicate that this condition may be a precursor for 1998. In assessing operational events, an effort was made to make the ASP models as realistic as possible regarding the specific features and response of a Civen plant to various accident sequence initiators. We realize that licensees may have additional systems and emergency procedures, or other i
features at their plants that might affect the analysis. Therefore, we are providing you an opportunity to review and comment on the technical adequacy of the preliminary ASP analysis, including the depiction of plant equipment and equipment capabilities. Upon receipt and evaluation of your comments, we will revise the conditional core damage probability calculations where necessary to consider the specific,information you have provided. The object of the review process is to provide as realistic an analysis of the significance of the event as possible.
In order for us to incorporate your comments, perform any required reanalysis, and prepare the.
final report of our analysis of this event in a timely manner, we request that you complete your review and provide any comments within 30 days of receipt of this letter. We have streamlined the ASP Program with the objective of significantly improving the time after an event in which the f;nal precursor analysis of the event is made publicly available. As soon as our final analysis of tne event has been completed, we will provide for your information the final precursor analysis of the event and the resolution of your comments.
pl 46 We have also enclosed several items to facilitate your review. Enclosure 2 contains specific guidance for performing the requested review, identifies the criteria that we will apply to determine if any credit should be given in the analysis for the use of licensee-identified additional equipment or specific actions in recovering from the event, and describes the specific information that you should provide to support such a claim. Enclosure 3 is a copy of LER No.
361/98-003, which documented the event.
9903300303 990323 m
e o r-r g 1 DR ADOCK 050003 1 g g grg ysgg e.em.
r-e*
+.%o e.-
v
-m..,-
-.. ~..
Mr. Harold B. Ray. March 23, 1999 i
- Please contact me at 301-415-1352 if you have any questions regarding this request. This request is covered by the existing OMB clearance number (3150-0104) for NRC staff followup review of events documented in LERs.- Your response to this request is voluntary and does not constitute a licensing requirement.
Sincerely, Original Signed By 2
James W.: Clifford, Senior Project Manager Project Directorate IV-2 Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-361
' DISTRIBUTION:
t Docket
Enclosures:
- 1. Preliminary Accident Sequence Precursor PUBLIC
- 2. Guidance PDIV-2 Reading
- 3. LER 361/98-003 '
JZwolinski/SBlack WBateman cc w/encis: See next page.
JClifford EPeyton OGC ACRS KBrockman, RIV LSmith, RIV PO'Reilly, RES SMays, RES Document Name: SOASPLET.WPD OFC PDIV-2 PDIV-2 NAME JCdfdrd EM DATE 3 /73 /99 3 A/99
~ OFFICIAL RECORD COPY
. - - _. ~. - -. -
.~..-.-.
-... ~ - -. - - -. - -
Mr. Harold B. Ray 3-March 23, 1999 cc w/encis:
Mr. R. W. Krieger, Vice President Resident inspector / San Onofre NPS Southem Califomia Edison Company clo U.S. Nuclear. Regulatory Commission San Onofre Nuclear Generating Station Post Office Box 4329 P. O. Box 128 San Clemente, Califomia 92674 San Clemente, Califomia 92674-0128 Mayor Chairman, Board of Supervisors City of San Clemente County of San Diego 100 Avenida Presidio 1600 Pacific Highway, Room 335 San Clemente, Califomia 92672 San Diego, Califomia 92101
' Mr. Dwight E. Nunn, Vice President Alan R. Watts, Esq.
Southem Califomia Edison Company Woodruff, Spradlin & Smart San Onofre Nuclear Generating Station 701 S. Parker St. No. 7000 P.O. Box 128 Orange, California 92668-4702 San Clemente, Califomia 92674-0128 Mr. Sherwin Harris
- Resource Project Manager Public Utilities Department City of Riverside 3900 Main Street Riverside, California 92522 Regional Administrator, Region IV U.S. Nuclear Regulatory Commission Harris Tower & Pavilion
. 611 Ryan Plaza Drive, Suite 400 Arlington, Texas 76011-8064 Mr. Michael Olson San Onofre Liaison San Diego Gas & Electric Company P.O. Box 1831 San Diego, California 92112-4150 Mr. Steve Hsu Radiologic Health Branch State Department of Health Services Post Office Box 942732 Sacramento, Califomia 94234 4
}
4 T
y-r
..e
n-
LER No. 361/98-003 LER No. 361/98-003 Event
Description:
Inoperable sump recirculation valve Date of Event: February 5,1998 Plant: San Onofre Nuclear Oenerating Station, Unit 2 Event Summary San Onofre Nuclear Generating Station, Unit 2 (San Onofre 2'), was in a mid-cycle outage when personnel discovered that the linestarter for the containment emergency sump outlet valve was jammed because of grit in the sliding cam. De grit would have prevented the valve from opening on a recirculation actuation signal (RAS). This would result in one inoperable train while in the recirculation mode of the Emergency Core Cooling System (ECCS) and the Containment Spray (CS) system. This condition existed for about 18 days until the unit shut down for a mid-cycle outage. He core damage probability (CDP) at San Onofre 2 increased during these 18 days because of the increased susceptibility to a postulated loss-of-coolant accident (LOCA) initiator that progressed to the recirculation phase. The estimated increase in the CDP (i.e., the importance) for this event is 7.2 x 104 Event Description On February 5,1998, utnity electricians were replacing Square D linestarters as part ofplanned maintenance.
The electricians discovered the mechanical interlock on the linestarter for the Train A containment emergency sump outlet valve (HV-9305) jammed. The sump outlet valve was in the closed position at the time the failure was discovered, fulfilling the containment isolation function of the valve (Fig.1). However, the as-found condition ofthe linestarter would have prevented valve HV-9305 from opening. Consequently, the recirculation function for Train A of High Pressure Safety Injection (HPSI) and CS could not be fulfilled without some recovery action. The Train A containment emergency sump outlet valve was last cycled open and closed on January 6,1998. San Onofre 2 was shut down for the mid-cycle outage on January 24,1998. Therefore, from the nature of the failure, the licensee considered the Train A continment emergency sump outlet valve inoperable for approximately 18 days before it was no longer required by Technical Specifications.
Consequently, ECCS Train A and CS Train A were inoperable for approximately 18 days.'
Additional Event-Related Information The licensee hadjust started programmatically replacing all of the Square D linestarters - 60 of 86 linestarters at Unit 2, and 61 of 86 Enestarters at Unit 3 had already been replaced. All remauung old linestarters (26 at Unit 2 and 25 at Unit 3) were replaced; no additional failures were discovered.
The grit that caused the linestarter for the Train A containment emergency sump outlet valve to jam was identified as gunite similar to what was used to stabilize the hillsides outside the protected area. The grit was not iiscovered on or around other switchgear room components or in the ventilation ducts. However, some grit was found in other 480 V ac motor control center buckets, but had not affected the operation of the associated 1
l LER No. 361/98-003 1
linestarters. The grit was assumed to have been introduced before plant startup and was known rd to migrate aAer being deposited.'
'Ihe HPSI system has three centrifugal pumps divided between two trains (Fig.1). Pump P-017 is in Train A and pump P-019 is in Train B. The third pump, P-018, is a swing pump and can be aligned to either trais on the suction or discharge side. P-018 is normally aligned to Train A. Because the HPSI pumps do not automatically stop in response to an RAS signal, operators are directed to stop the pumps before the RWST level decreases below 5%2 While the recirculation phase of ECCS Train A was compromised between January 6,1998, and January 24, 1998, the opposite train - ECCS Train B - was inoperable six times during this same period. These six i
occasions were as follows:
1.
I h,43 min, to perform an in-service test of an HPSI pump (January 12,1998),
- 2. 27 h,5 min, to repair a Component Cooling Water (CCW) heat exchanger t-
, leak (January 13,1998)
-(CCW is required to support ECCS.),
- 3. 6 h,36 min, to perform heat treatment of the main condensei (Jan=ry 16,1998). (This treatment process increases the heat load on the salt water cooling (SWC) system, which is required to support ECCS.),
4.
19 min, to swap the in-service SWC pump to the opposite train (January 22,1998),
- 5. 5 h,45 min, to perform maintenance work on the Train B Refueling Water Storage Tank (RWST) outlet valve (January 23,1998), and 6.
5 h,31 min, to perform an additional heat treatment of the main condenser (January 24,1998).
Modeling Assumptions This event was modeled as an 18 day (432-h) condition assessment with the Train A cantainment emergency sump outlet valve failed (valve HV-9305). The CCW heat exchanger maintenance (27 h,5 min) was included in the modeling because the heat exchanger was out of service during this period and not readily recoverable.
Likewise, the maintenance period with the unavailable RWST outlet valve (5 h,45 min) was included in the event model because of the immediate impact on Train B during the injection phase of an accident. The two periods involving heat treatment of the main condenser (6 h, 36 min and 5 h,31 min) were no: included in the model of this event because any heat treatment would likely be terminated quickly by the operator. Even ifthis were not done, a turbine trip initiated by a LOCA would self-limit any added heat loads on the SWC system.
The in-service test of the Train B HPSI pump (1 h,43 min) was not modeled because of operator staffing for the test, the ability to restore the nonnal lineup quickly, and the limited time the pump was unavailable. The time required to swap pumps (19 min) was not modeled because of the limited time required to perform the task. Therefore, three distinct cases, totaling 432 h (18 days), were modeled as part of this event.
Case 1. 399 h,10 min, with only the Train A containment emergency sump outlet valve failed (valve HV-9305).
Case 2. 27 h,5 min, with the Train A containment emergency sump outlet valve failed (valve HV-9305) and CCW Train B unavailable.
2
~..... - -
LER No. 361/98-003 Case 3. 5 h,4;.3!n, with the Train A containment emergency sump outlet valve failed (valve HV-9305) and the RWST Train B outlet valve unavailable because of maintenance (valve HV-9301).
The CS pumps are not represented in the Integrated Reliability and Risk Analysis System (IRRAS) model for San Onofre. However, because Train B of the CS system and all of the containment emergency fan coolers were available throughout the 18-day event, no attempt was made to incorporate the unavailability of one train of CS into the IRRAS model for San Onofre. This is estimated to have an insignificant impact on the calculated importance of this event because CS impacts containment pressure and not core cooling.
The failed Train A contamment emergency sump outlet valve was modeled by setting basic event HPR-SMP-FC-SUMPA (Containment Sump A Failure) failure probability from 6.1 x 108 to TRUE (i.e.,
probability = 1.0 that the valve would fail on demand). The associated common-cause failure basic event 4
(HPR-MOV-CF-SUMP) was adjusted from 1.1 x 10 to the p factor of the Multiple Greek letter method used in the IRRAS models (8.8 x 104) based on the failnre ofthe Train A containment emergencysump outlet valve.
It was assumed that the operators would correctly follow procedures and secure the HPSI pumps before the RWST level decreased below 5%. Derefore, this was not modeled in the analysis.
~ An evaluation of this event,' prepared by the licensee, estimated that if a small-break LOCA (SLOCA)
(%-2 in. pipe diameter) occurred,250 min would be available to recover a recirculation flow path before the onset ofcore damage. Operators would initiate recirculation flow about 118 min after an SLOCA occurred.
Although other CE plants consider depressurization an option, simulator exercises at San Onofre 2 indicated
'. hat operating crews would not attempt to cool down and depressurize the plant for a leak in this size range.
Conversely, it was v ' expected that small-small-break LOCAs (SSLOCAs) (<% in. pipe diameter) would proceed to the recirculation phase because sufficient time was assumed to be available to cool down and depressurize the primary system. This differentiation required the IRRAS model to be adjusted to reflect the different operator responses expected following an SSLOCA and an SLOCA. Because the importance of medium-break and large-break LOCAs calculated by the licensee using a methodology widch parallels the 4
IRRAS development was less than 1,0 x 10, these larger LOCAs were not specifically modeled (i.e., the contribution to the overall importance of the event from these events is small).
Recovery from the CCW heat exchanger maintenance could begin at the time a LOCA event is recognized because the operating staffwas aware of the maintenance being performed from pre-shift briefmgs. Recovery
~ from the RWST Train B outlet valve maintenance was not considered likely because this flow path would be required immediately followmg the occurrence of a LOCA.
- De recovery from the train B CCW heat exchanger maintenance to repair a tube leak was expected to require 200 min.' This assumes 15 min for operators to rmwnim that a small-break LOCA occurred and to order the restoration of the CCW heat exchanger,120 min for maintenance personnel to reassemble the CCW heat exchanger,60 min for operators to realign the system valves correctly, and 5 min to restore power and start the appropriate CCW pump. These time estimates made by the licensee are conservative, yet still leave an additional 50 min before core damage would occur following an SLOCA. Performance shaping factors considered that the process would be governed by a maintenance procedure and performed under stress outside f
3
.-.m.
~
.... ~
~
LER No. 361/98-003 the control room by a skilled crew.) Based on this, the licensee estimated a 60% probability of success in restoring the CCW heat exchanger within 250 min. In addition, one HPSI pump and one residual heat removal (RHR) pump were affected by the maintenance on the CCW heat exchanger. Because the CCW system is not directly modeled by the San Onofre IRRAS model, a basic event was added to several fault trees to represent the CCW system failure probability during the ~27 h maintenance period. De new basic event (CCW-TRNB-FAIL) was added such that a failure to return the train B CCW heat exchanger to service would cause the affected pumps (HPI-MDP-FC-P019 and RHR-MDP-FC-P016) to be failed during the ~27 h CCW 1
maintenance period. The probability of basic event CCW TRNB FAIL was adjusted to 0.4 for Case 2; for Cases 1 and 3, the probability of this basic event occurring is zero.
Two viable options for recovering from the Train A containment emergency sump outlet valve failing closed exist.8 First, the failure of the valve could be traced to the breaker linestarter and replacement could be initiated. Secondly, it is possible to cross-connect the HPSI Train A suction to the Train B suction. In either j
case,132 min (250 - 118 min) would be available before the onset of core damage following an SLOCA.
1 Because operator training and emergency operating procedures focus attention on the correct entry into the recirculation mode, it is assumed that the operators would quickly notice the failure of the train A sump valve to open. Recognition and correction of the breaker failure are assumed to require 40 min.' His would allow an additional 92 min (132 - 40 min) to complete repairs before the onset ofcore damage. Performance shaping factors considered that the breaker repair process would not be governed by a maintenance procedure and performed under stress outside the control room by a skilled crew.8 Based on this, the licensee estimated a 50%
probability of success in restoring the linestarter and opening the train A sump valve within 132 min of RAS.
A new basic event (HPR-SMPA-XHE-NRE) was added to the High Pressure Recirculation (HPR) fault tree to represent the probability (0.5) that electricians would fail to repair the breaker linestarter. Recognition of the failure and cross-connecting the HPSI pump suctions is assumed to require 20 min. This action allows an additional 112 min (132 - 20 min) to complete realignment before the onset of core damage. Performance shaping factors considered that the breaker repair process would be governed by an operating procedure and performed under stress outside the control room by a skilled crew.' Based on this, the licensee estimated an 80% probability ofsuccess in cross-connecting the HPSI pump suction if there were an SLOCA. A new basic event (HPR-XCONN-XHE-NR) was added to the HPR fault tree to represent the probability (0.2) that operators fail to cross-connect the HPSI pump suctions within 132 min ofRAS. Because these two new events involve separate groups of plant personnel (electricians and operators), the basic events are considered to be independent. Independence is also assumed when these two new basic events are compared with the erTort to restore the CCW heat exchanger, which would involve mechanics.
Analysis Results Determining the overall increase in the CDP required determining the increase in the CDP for the three different cases and then summmg the cases. The three cases are as follows:
4 Case 1. 399 h,10 min, with only the Train A containment emergency sump outlet valve failed (valve HV-9305).
Case 2. 27 h,5 min, with the Train A containment emergency sump outlet valve failed (valve HV-9305) and CCW ~1 rain B unavailable.
t 1
4
7 LER No. 361/98-003
' Case 3. 5 h,45 min, with the Train A containment emergency sump outlet valve failed (valve HV-9305) and the RWST Train B outlet valve unavailable because of maintenance (valve HV-9301).
The combined increase in the CDP from this 432-h event (i.e., the importance) is 7.2 x 104. This increase is above a base probability for the 432-h period (the CDP) of 3.9 x 10 5. Most of the increase (89%) is driven by Case 1. As expected, the common-cause failure of the containment sump valve shows up most oAen in the cut sets of the most significant sequences because it is driven by the initial sump valve failure. Potential recovery actions and the CCW train B failure are more conspicuous in Case 2. Failure ofinjection flow is pronunent in Case 3 because of the maintenance on the Train B RWST outlet valve. However, the dommant core damage sequence in each case of this event (sequence 2 on Fig. 2) involves I
1 an SLOCA, a successful reactor trip, a successful initiation of emergency feedwater, a
a successful initiation of high pressure injection, and a failure of high pressure recirculation.
The SLOCA sequences account for 88% of the calculated increase in the CDP for this event. The next most dominant sequence among all three ::ases invdves an SSLOCA with a failure to cool down the plant before requiring HPR. This sequence contributes 5% to the calculated importance of this event.
The nominal CDP over a 432-h period estimated using the IRRAS model for San Onofre is 3.9 x 10-5. This model was modified to include possible recovery actions as discussed in Reference 3. The failed Train A containment emergency sump outlet valve linestarter increased the CDP by 18% to 4.6 x 10 5. This latter value j
(4.6 x 10-5) is the conditional core damage probability (CCDP) for the 432-h period in which the linestarter was failed.
Defmitions and probabilities for selected basic events are shown in Table 1. The conditional probabilities associated with the highest probability sequences are shown in Table 2. Table 3 lists the sequence logic associated with the sequences listed in Table 2. Table 4 describes the system names associated with the 1
dommant sequences. Minimal cut sets associated with the dominant sequences are shown in Table 5.
Acronyms CCDP conditional core damage probability CCW component cooling water CDP core damage probability CS containment spray ECCS emergency core cmling system HPR high-pressure recirculation HPSI high-pressure safety injection IRRAS Integrated Reliability and Risk Analysis System LOCA loss-of-coolant accident 5
= ww w.mne w "'-
aa e = e ew e eve =rewe e e' winee e'e -o w a>.*asw +1F ' *- 5*
4
..r %ews erw" s e e wow **., + ew thew e se eem o + ev M2 f. -
j LER No. 361/98-003 LOOP loss ofoffsite power MOV motor operated valve RAS recirculation actuation signal RHR residual heat removal RWST refueling water storage tank SGTR steam generator tube rupture SLOCA small-break LOCA SSLOCA small-small-break LOCA SRV safety /reliefvalve SWC salt water cooling TRANS
' transient event i
References
{
- l. LER 361/98-003, Rev.1, " Inoperable Valve Due to Grit in Linestarter Mechanism," March 17,1998.
- 2. San Onofre, Final Safety Analysis Report (Updated Version).
- 3. Letter from Dwight E. Nunn, Vice President, San Onofre Nuclear Generating Station, to U. S. Nuclear Regulatory Commission, "Linestarter and AFW Supplemental Information," April 7,1998.
6
o LER No. 361/98-003 j@
5 e
A a
I I
I I
gE 9
O 5
5 g
Zs e
e a
s IXtl 7,
H l *ill*1ll i Id j C l
- ]:l W ld j l Xe l
Zs1 I
I l
[
l Ze d I d I
(. =
i'
{g-a hg x
8 8
XB
.E-A;9 M
)i l
Ou<
j i
I-i i
gl gl
-l fB i
4 E
ej eii Z i,r x
x e
i N
~
j ge-J
}s I~~~
6 ZI 5
l
'h l
- IIl d l ml
- i y
,_ _ _U l '3
[
I gI l
lIlI 92l el l
I 1
4
?
j i
i l
Fig. I San Onofre High Pressure Inj<xtion System (source: San Onofre Nuclear Generating Station, Units 2 and 3, IndividualPlant Examination). [CCW is component cooling water system, CS is containment spray, LPSI is low-prersure safety injection, RCS is reactor coolant system, and RWST is refueling water storage tank.)
7 j
i 4
I 1
LER No. 361/98-003 i
Eh 6
8 8
6 8
8 6
8 8
8 8
a
=
a a
~
2 1
I 5
11; 8 e
il r
3e s
i Ga ln i
ll i g
l l
I ll1 3
1 I
IE i
l Fig. 2 Dominant core damage r.equence for LER No. 361/98-003.
8 l
l e.
- -.. ~...... - -
- -., -.~
1 LER No. 361/98-003 Table 1. Dennitions and Probabilities fo-Wiected Basic Events for LER No. 361/98-003 Modified Event Base Current for this name Description probability probability Type event IE-LOOP Initiating Evem-loss ofoffsite 1.1 E-005 1.1 E-005 No j
power (LOOP)(Includes the Probability ofRecovering Ofbc Power in the Short Term)
IE SOTR Initiating Event-Steam Generator 2.1 E-006 2.1 E 006 No Tube Rupture (SOTR)
IE-SLOCA Initiating Event-SLOCA 1.6 E-007 -
1.6 E-007 Yes IE-SSLOCA Initiating Event-SSLOCA 2.1 E 006 2.1 E406 NEW Yes.
IE-TRANS Initiating Event-Transient 6.2 E-004 6.2 E-004 No (TRANS)
CCW TRNB-FAIL Train B CCW Heat Exchanger is 0.0 E+000 4.0 E-001 NEW Yes not Retumed to Service (Case 2)
HPI-MOV-OC-SUCB RWST Train B Outlet Valve 1.4 E-004 10E+000 L' TIE Yes Fails Closed (Case 3)
HPR-MOV-CF-SUMP Common Cause failure ofSump 1.1 E 003 8.8 E-002 Yes isolation motor-operated valves (MOVs) i HPR-SMP-FC-SUMPA Containment Sump Train A 6.1 E-003 1.0 E+0C0 TRUE Yes Failure (Valve HV-9305 Stuck Closed)
HPR-XCONN-XHE-NR Operator Fails to Cross-Connect 2.0 E-001 2.0 E-001 NEW No HPSISuction from Train B to Train A HPR-XHE-SOREC Operator Fails to Recover the 1.0 E+000 1.0 E+000 No HPR System HPR-XHE XM-HLEG Operator Fails to Initiate Hot-Leg 1.0 E-003 1.0 E-002 No Recirculation PCS VCF-HW Failure ofEquipment Required 1.0 E-003 1.0 E 003 No for Plant Cooldown PCS-XHE-XM-CDOWN Operator Fails toInitiate 1.0 E 003 1.0 E-003 No Cooldown PPR SRV CO-TRAN Safety / Relief Valves (SRVs) 2.0 E 002 2.0 E-002 No Open During a Transient PPR-SRV OO l SRV I Fails to Rescat 1.6 E 002 1.6 E-002 No 9
~
.,n,
LER No. 361/98-003 Table 1. Definitions and Probabilities for Selected Basic Events for LER No. 361/98-003 (Continued)
Modified Event Base Current for this Description probability probability Type event name 1
PIM r_V-OO-2 SRV 2 Fails to Rescat 1.6 E-002 1.6 E-002 No RHR MDP-CF-AB Common-Cause Failure of RIIR 5.6 E-004 5.6 E-0(A No Mofor Driven Pumps RHR-MOV-CF-HX Common-Cause Failure of RHR 1.1 E 003 1.1 E-003 No Heat Exchanger Isolation MOVs RHR-MOV-CF-SUC Common-Cause Failure of RHR 1.3 E-003 1.3 E-003 No Suction MOVs RHR-PSF VF-BYP Flow Diverted From Heat 9.0 E-003 9.0 E-003 No Exchangers or Reactor Vessel j
RHR-XIE-NOREC Operator Fails to Recover the 3 A E-001 3A E-001 No RHR System RHR XIE-XM Operator Fails to Actuate the 1.0 E-003 1.0 E-003 No RHR System P
10
l L.
LER No. 361/98-003 Table 2. Sequence Conditional Probabilities for LER No. 361/98-003 i
Conditional Event tree Sequence core damage Core damage Importance Percent name number probability probability (CCDP-CDP) contribution' (CCDP)d (CDP)
SLOCA 02 5.9 E-006 1.8 E-007 5.7 E-006 89.2
)
SSLOCA 03 4.0 E-007 1.3 E-008 3.8 E-007 5.9 SSLOCA 05 1.5 E-007 4.7 E-009 1.5 E-007 2.3 TRANS 05 7.5 E-008 2.4 E-009 7.2 E-008 1.1 Subtotal Case 1 (shown)'
4.2 E-005 3.6 E-005 6.4 E-006 O W pf"+p%
w
. w 4
Subtotal Case 2 3.2 E-006 2.4 E-006 7.0 E-007 Ef@M6Mp.
6 Subtotal Case 3' 6.4 E-007 5.2 E-007 1.2 E-007
. M / "*
Total (all sequences) 4.6 E-005 3.9 E-005 7.2 E-006 E ' %+ >
W')h$2
' Case I represents the increase in the CDP because of the long-term unavailability of the Train A containment emergency sump outlet valve IW.9305 (399.1 h).
i 6Case 2 represents the increase in the CDP because of maintenance being performed on the Train B CCW heat exchanger while the Train A containment emergency sump outlet valve IW-9305 w1ui unavailable (27.1 h).
' Case 3 represents the incrase in the CDP because of maintenance being performed on the Train B RWST outlet valve while the Train A containment emergency sump outlet valve IW-9305 was unavailable (5.8 h).
- Because case I presents the largest contibution to the total importance, the reported percent contribution to the total importance is for case 1 only.
8Because case I presents the largest contibution to the total importance, the reported dominant sequences are ordered according to the importance of case 1.
I1
-a we,,iy.,,,,.,we, y.pg
,.e N
a-~.v f
C"
(
\\
l LER No. 361/98-003 Table 3. Sequence Logic for Dominant Sequences for LER No. 361/98-003 (Case 1 Only)
Event tree name Sequence Logic number SLOCA 02
/RT, /AFW,/HPI,HPR SSLOCA 03
/RT,/AFW, /HPI, /COOLDOWN, RHR, HPR SSLOCA 05
/RT,/AFW,/HPI, COOLDOWN, HPR TRANS 05
/RT, /AFW, SRV, SRV-RES, /HP1,
/COOLDOWN, RHR, HPR Table 4. System Names for LER No. 361/98-003 (Case 1 Only)
System name Logic AFW No or Insumcient Auxiliary Feedwater System Flow COOLDOWN Reactor Coolant System Cooldown to RHR Decay Heat Removal Mode of Operation i
HPI No orlasumcient HPSI Flow HPR No orInsumcient HPR Flow RHR No or Insumcient RHR System Flow RT Reactor Fails to Trip SRV SRVs Open During a Transient SRV-RES SRVs Fail to Rescat 12
=. - _ _
i LER No. 361/98-003 Table 5. Conditional Cut Sets for liigher Probability Sequences for LER No. 361/98-003 l
Cut set Percent number contribution CCDI" Cut sets' SLOCA Sequence 02 5.9 E-006 k}h$MihMD!k'N MN3M@@d P.
1 96.6 5.6 E-006 IIPR MOV-CF SUMP.lFR-XIE-NOREC 2
1.1 6.4 E-008 IIPR SMP-FC-SUMPA,lFR XIEXM-liLEO SSLOCA Sequ nce 03 4.0 E-07
$$7k(($$$$$ $[$$$$$$$$?[
l 57.2 2.3 E-007 RHR-PSF-VF BYP, RIEXIENOREC, IIPR-MOV-CF-SUMP, HPR XIE-NOREC 2
18.7 7.4 E-008 RHR-XIE-XM,HPR MOV{F-SUMP,IFR-XHE-NOREC RHR-MO' CF-SUC,RIEXIE NOREC,HPR MOV CF-SUMP.
V 3
8.4 3.3 E-008 IIPR XIE-NOREC 4
6.7 2.8 E-00g RHR MOV-CF IIX, RHR-XIIE-NOREC, HPR-MOV-CF-SUMP, HPR-XIE-NOREC 5
3.6 1.4 E-008 RIEEP CF-AB. RI %XIE-NOREC, lFR-MOV-CF-SUMP, IFR-XIE-NOREC
%$$dENd5dfMQEdikNhdhjh is!
SSLOCA Sequence 05 1.5 E-007 f
l 48.1 7.4 E-008 PCS XIEXMCDOWN,HPR-MOV CF-SUMP,i!PR XHE NOREC 2
48.1 7.4 E-008 PCS-VCF-HW,HPR-MOV CF SUMP,HPR XIE-NOREC
' M b m dim [I@NMSd$sjh((NM sN@
TRANS Sequence 05 7.5 E-008 l
28.6 2.1 E-008 PPR-SRV-CO TRAN, PPR-SRV OO 1,RHR-PSF-VF-BYP, l
RHR-X)E-NOREC,IIPR-MOV CF-SUMP,HPR XIE-NOREC 1
2 28.6 2.1 E-008 PPR-SRV-CO-TRAN, PPR-SRV-OO-2, RHR-ISF VF-BYP, l
RHR-XIENOREC,IIPR-MOV CF-SUMP, HPR-XHE-NOREC 3
9.3 7.0 E-009 PPR-SRV-CO-TP.AN, PPR-SRV-OO 1, RlWXIE-XM, isPR-MOV-CF-SUMP,IFR-XFENORFI 4
9.3 7.0 E-009 PPR SRV CO TRAN, PPR-SRV OO-2, RHR-XHE-XM, HPR MOV CF-SUMP.HPR XIE-NOREC 13 l
l t
LER No. 361/98-003 1
Cut set Percent nusnber contribution CCDP' Cut sets' 5
4.2.
3.1 E-009 PPR SRV CO-TRAN,PPR-SRV-OO 1,RHR-MOV CF-SUC, RHR XHE-NOREC,HPR-MOV CF-SUMP,HPR-XHE-NOREC 6
4.2 3.1 E-009 PPR-SRV-CO TRAN,PPR-SRV OO-2,RHR-MOV-CF SUC, RHR-XHE-NOREC, HPR MOV-CF-SUMP, HPR-XHE-NOREC 7
3.4 2.6 E-009 PPR-SRV CO TRAN, PPR SRV OO 1. RHR MOV-CF-HX, RHR XHE-NOREC,HPR-MOV CF-SUMP,HPR XHE-NOREC 8
3.4 2.6 E-009 PPR-SRV-CO TRAN, PPR-SRV OO 2, RHR-MOV-CF-HX, RHR XHE-NOREC,HPR-MOV-CF-SUMP,HPR-XHE-NOREC 9
1.8 1.3 E-009 PPR SRV CO.TRAN,PPR-SRV.OO-1,RHR-MDP-CF-AB, RHR-XHE-NOREC, HPR MOV CF-SUMP, HPR-XHE-NOREC 10 1.8 1.3 E-009 PPR SRV-CO-TRAN, PPR SRV OO-2, RHR-MDP-CF-AB, RHR-XHE-NOREC, HPR-MOV-CF-SUMP, HPR XHE-NOREC ne w Qgw ggyswgggd3t&ggggg%@gg$$ :
%g%ggQp Subtotal Case 16 4,2 E-005 g
gA
't Ms
- .L.
MMg/@@fW (shown above)
Subtotal Case 2' 3,2 E-006 $$dMM$NNNh$NMbNM$NME Subtotal Case 3 6,4 E-007 N M D M N$ M M @ @IMkM$h @
d Total (all sequences) 4.6 E-005 Mid$$NI[$MMNhddMMiNMh
'The change in conditional probability (importance)is determined by calculating the conditional probability for the period in which the condition existed, and subtracting the conditional probability for the same period but with plant equipment assumed to be operating nominal'y. The conditional probability for each cut set within a sequence is determined by multiplying the probability that the portion of the sequence that ms.kes the precursor visible (e.g., the system with a failure is demanded) will occur during the duration of the event by the probabilities of the remaining basic events in the minimal cut set. This can be approximated by 1 e*, where p is determined by multiplying the expected number ofinitiators that occur during the duration of the event by the probabilities of the basic events in that rainimal cut set. The expected number ofinitiators is given by it, where lis the frequency of the initiating event (given on a per hour basis), and t is the duration time of the event. This approximation is conservative for precursors made visible by the initiating event. The frequencies ofinterest for this event are: Anu.= 6.2 x 10%,1ux,- 1.1 x 10 8/h,1moe4 - 1.6 x 10 /h,18KOCA
= 2.1 x 10 %, and 1:ava - 2.1 x 10 d/h.
6Case 1 represents the increase in the CDP because of the long-term unavailability of the Train A containment emergency sump outlet valve (399.1 h).
' Case 2 represents the increase in the CDP bocease of Train B CCW heat exchanger maintenm, while the Train A containment emergency sump outlet valse was unavailable (27.1 h).
dCase 3 represents the increase in the CDP because ofTrain B RWST outlet valve maintenance while the Train A containment emergency sump outlet valve was unavailable (5.8 h).
14 a
f-L.'......---..-..
- -. ~,. - _.,... -. -....
m.--.m
_ _. _.. -.. ~,. - -.,.. -. _. -...
l 4
i LER No. 361/98-003 l
!~
' Basic event HPR-SMP-FC-SUMPA is a TRUE type event which is not normally in iuded in the output offault tree reduction programs but has been added to aid in understanding the sequences to potential core damage associated with the event.
l 1
I i
i 15
3 GUIDANCE FOR LICENSEE REVIEW OF PRELIMINARY ASP ANALYSIS
Background
The preliminary precursor analysis of an operational event that occurred at your plant has been provided for your review. This analysis was performed as a part of the NRC's Accident Sequence Precursor (ASP) Program. The ASP Program uses probabilistic risk assessment techniques to provide estimates of operating event significance in terms of the potential for core damage. The types of events evaluated include actualinitiating events, such as a loss of off-site power (LOOP) or loss-of-coolant accident (LOCA), degradation of plant conditions, and
- safety equipment failures or unavailabilities that could increase the probability of core damage from postulated accident sequences. This preliminary analysis was conducted using the information contained in the plant-specific final safety analysis report (FSAR), individual plant examination (IPE), and the licensee event report (LER) for this event.
Modeling Techniques The models used for the analysis of 1998 events were developed by the Idaho National Enginsering Laboratory (INEL). The models were developed using the Systems Analysis Programs for Hands-on Integrated Reliability Evaluations (SAPHIRE) software. The models
- are based on linked fault trees. Four types of initiating events are considered: (1) transients,
. (2) loss-of-coolant accidents (LOCAs), (3) losses of offsite power (LOOPS), and (4) steam generator tube ruptures (PWR only). Fault trees were developsd for each top event on the event trees to a supercomponent level of detail. The only suppcrt system currently modeled is the electric power system.
The models may be modified to include additional detail for the systems / components of interest for a particular event. This may include additional equipment or mitigation strategies as outlined in the FSAR or IPE. Probabilities are modified to reflect the particular circumstances of the event being analyzed.
Guidance for Peer Review Comments regarding the analysis should address:
Does the " Event Description" section accurately describe the event as it occurred?
.e Does the " Additional Event-Related Information" section provide accurate additiondl information conceming the configuration of the plant and the operation of and procedures associated with relevant systems?
e Does the "Modeling Assumptions" section accurately describe the modeling done for the event? Is the modeling of the event appropriate for the events that occurred or that had the potential to occur under the event conditions? This also includes assumptions regarding the likelihood of equipment recovery.
.o Appendix G of Reference 1 provides examples of comments and responses for previous ASP analyses.
Criteria for Evaluating Comments Modifications to the event analysis may be made based on the comments that you provide.
Specific documentation will be required to consider modifications to the event analysis.
References should be made to portions of the LER, AIT, or other event documentation concoming the sequence of events. System and component capabilities should be supported l
by references to the FSAR, IPE, plant procedures, or analyses. Comments related to operator response tims.. mnd capabilities should reference plant procedures, the FSAR, the IPE, or applicable operator respotise models. Assumptions used in determining failure probabilities should be clearly stated.
l Criteria for Evaluating Additional Recovery Measures Additional systems, equipment, or specific recovery actions may be considered for incorporation into the analysis. However, to assess the viability and effectiveness of the equipment and methods, the appropriate documentation must be included in your response.
This includes:
1 normal or emergency operating procedures '
piping and instrumentation diagrams (P&lDs),'
electrical one-line diagrams,'
results of thermal-hydraulic analyses, and operator training (both procedures and simulator),* etc.
Systems, equipment, or specific recovery actions that were not in place at the time of the event yvill not be considered. Also, the documentation should address the impact (both positive and n'agative) of the use of the specific recovery measure on:
the sequence of events, the timing of events, the probability of operator error in using the system or equipment, and other systems / processes already modeled in the analysis (including operator actions).
For example, Plant A (a PWR) experiences a reactor trip, and during the subsequent recovery, it is discovered that one train of the auxiliary feedwater (AFW) system is unavailable. Absent any furtherinformation regrading this event, the ASP Program would analyze it as a reactor trip with one train of AFW unavailable. The AFW modeling would be pattemed after information gathered either from the plant FSAR or the IPE. However, if information is received about the use of an additional system (such as a standby steam generator feedwater system) in recovering from this event, the transient would be modeled as a reactor trip with one train of AFW unavailable, but this unavailability would be mitigated by the use of the standby feedwater system. The Revision or practices at the time the event occurred.
..._.__.__.__.____.._____.-.m mitigation effect for the standby feedwater system would be credited in the analysis provided that the following material was available:
standby feedwater system characteristics are documented in the FSAR or accounted for in the IPE, procedures for using the system during recovery existed at the time of the
- event, the plant operators had been trained in the use of the system prior to the event, a clear diagram of the system is available (either in the FSAR, IPE, or supplied by the licensee),
previous analyses have indicated that there would be sufficient time available to implement the procedure successfully under the circumstances of the event under analysis, the effects of using the standby feedwater system on the operation and recovery of systems or procedures that are already included in the event modeling. In this case, use of the standby feedwater system may reduce the likelihood of recovering failed AFW equipment or initiating feed-and-bleed due to time and personnel constraints.
Materials Provided for Review The following materials have been provided in the package to facilitate your review of the preliminary analysis of the operational event.
The specific LER, augmented inspection team (AIT) report, or other pertinent reports.
A summary of the calculation results. An event tree with the dominant sequence (s) highlighted. Four tables in the analysis indicate: (1) a summary of the relevant basic events, including modifications to the probabilities to reflect the circumstences of the event, (2) the dominant core damage sequences, (3) the system names for the systems cited in the dominant core damage sequences, and (4) cut sets for the dominant core damage sequences.
Schedule i
Please refer to the transmittal letter for schedules and procedures for submitting your comments.
Refsrences 1.
R. J. Belles et al., " Precursors to Potential Severe Core Damage Accidents: 1997, A Status Report," USNRC Report NUREG/CR-4674 (ORNidNOAC-232) Volume 26, Lockheed Martin Eaergy Research Corp., Oak Ridge National Laboratory, and Science Applications international Corp., Oak Ridge, Tennessee, November 1998.
t
.. -. -. -. -......... ~........ -..... -...,.-.-.
e' LC FORM 366 U.S. NUCLEAR REGULATl;Y C09ilSSION APPROVED sv Ons NO. 3160-0104 EXP!sts set /DD/YYYY
$7U.7.2.7lJ$dNUiYO ",n"S.L",,Y,
( M -YYYY)
" $lll".'iLZ E,.i"n, T,%"f",",'O.,".'O, ~
LICENSEE EVENT REP 0RT (LER)
. m. i. e
,o.
em..-1, 1-
.n.n,...
(see reverse for regelred eseber of sis,1er a mm.tiv.4He se e. ire e.nw. im oc.ar. man.cs.r i
- w. w e 8m*" 'S "t 'wwd a maw w. tafonett.n onente.
digits / characters for occh block)
FACILITY NAME (1)
Decket Neober (2)
Page (3)
San Onofre Nuclear Generating Statien (SONGS) Unit 2 05000-361 1 of 7 TITLE (4): Inop2rable Valve Due to Grit in Linestarter Mechantsm EVENT DATE (5)
LER NUMltt (4)
REP 0tT DATE (7)
OTNEt FACILITIES INVOLVED (8)
MONTH DAY YEAR YEAR SEQUENTIAL REV!s!0N MONTH DAY TEAR FACILITY NAME DOCKET NUMBER NUMBER NUMBER SONGS Unit 3 01QaQ-16L _
01 04 17 1998 FACILITY NAME 00CKET NUMBER 02 05 1998 1998 -- 003 J
OPERATIRG TN!s REP 0tf 1s s5BMITTES PUtsuANT TO THE REQUIREMENTS 0F 10 CFR is (Check Dee er More) (11)
N0DE (t) 20.2201(b) 20.2203(a)(2)(v)
X 50.73(a)(2)(1) 50.73(a)(2)(v111)
POWEt 000 20.2203falf1) 20.2203(air 3)ti) 50.7)(a)(21tii) 50.73(air 21ri)
LEVEL (10) 20.2203(a)(fift) 20.2203(alf3)(iii 50.73(a)(2)(111) 71.71 20.2203falf2)ffi) 20.2203(e)(4) 50.73falff)fiv)
OTHER 20.2203(a)(2)(fIf) 46 H frif11 Ao fira)(?ifv) specify la Abstract
- 1'" " i' HI'"' 3"A 20.2203fa)(2)(iv) 50.36(e)(2) 50.73(a)(2)(vii)
LICENSEE CONTACT FOR TNis LER (12)'
NAME TELEPHONE NUMBER (Incinde Area Code)
R.W. Krieger, Vice President, Nuclear Generation f714-368-6255 COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT (13)
CAusE SYSTEM COMP 0NENT MANUFACTURER REPORTABLE CAUsE sYsiEM COMPONENT MANUFACTURER REPORTABLE TO EPIX TO EPIX E
- 80. BP. BE RLY 5345 Y
SUPPLEMENTAL REPORT EXPECTED (14)
EXPECTfD MONTH DAY YEAR b
l Na DT 5
Yes (If yes. completc 'XPECTED sVBM!ss10N DATE)
X ABSTRACT (Limit to 1400 spaces, i.e., approximately fifteen single-spaced typewritten lines.) (16)
On2/5/1998, while replacing a linestarter for the containment emergency sump outlet valve during the raid-cycle outage, Southern California Edison (SCE) discovered the linestarter's mechanical interlock was jammed. The cause was grit in the sliding cam. This condition would have prevented the valve from opening on a Recirculation Actuation Signal (RAS), making one train of the Emergency Core Cooling System (ECCS) and Containment Spray (CS) inoperable in the recirculation mode. SCE believes the interlock jammed on 1/6/1998. The ECCS and CS trains were inoperable for about 18 days, when Unit 2 was shutdown for its scheduled mid-cycle outage.
Technical Specification (TS) 3.5.2 requires two trains of ECCS to be operable in Modes 1 and 2, and in Mode 3 at and above 400 psia pressurizer pressure. TS 3.6.6.1 requires two trains of CS to be operable in Modes 1, 2, and 3.
Consequently, this event is reportable under 10 CTR 50.73(a)(2)(i).
Corrective actions included accelerating the linestarter replacement program in both units, and increased surveillance for Unit 3.
The safety significance was small for Unit 2 and minimal for Unit 3.
PDR ADOCK 05000361 ff S
LICENSEE EVENT RFPORT (LER) u.s. nueuan accutaron comission nac roan assa (4 9s)
TEXT CONTINUATION FACILITY NAME (1) 00LKET LER NUMBER (6)
PAGE (3) vtan sEQutNTIAL RtV!sloN f
m ata e ra San Cnofre Nuclear Generating Station (SONGS) Unit 2 05000-361 2 0F 7 01 003 1998 Plant:
San Onofre Nuclear Generating Station Units 2 & 3 R2 actor Vendor:
Combustion Engineering Eeent Date:
February 5, 1998 Event Time:
1100 PST Unit 2 Unit 3 Mode:
- 5. Cold shutdown 1, Power operation j
Power:
O percent 99.8 percent (approx.)
Temperature:
91 degrees F (approx.)
548 degrees F (approx.)
Pressure:
Atmospheric 2250 psia (approx.)
Description of Event:
On February 5, 1998 (discovery date), while performing the planned replacement of Square D (5345) linestarters (RLY) (see Additional Information, below) for Train A ccntainment emergency sump outlet valve 2HV9305 (ISV), maintenance personnel (utility, non-licensed) discovered the linestarter's mechanical interlock was jamed. Photograph I shows a typical linestarter with its interlock. While 2HV9305 was closed fulfilling its containment isolation function, it would not have opened to fulfill its recirculation function for High Pressure Safety injection (HPSI) (80), and Containment Spray (CS) (BE). See Figure 1.
Thevalvehadbeencycledopen/closedonJanuary6,1998. Duetothenatureofthefailure(seetheCause of the Event section, below), Southern California Edison (SCE) believes that the interlock Jamed during that last close cycle. Consequently, 2HV9305, Emergency Core Cooling System (ECCS) Train A, and Containment Spray Train A were inoperable from January 6,1998, until the unit was shutdown for its planned mid-cycle outage on January 24, 1998.
Technical Specification (TS) 3.5.2 requires two trains of ECCS to be operable in Modes 1 and 2, and in Mode
.3 at and above 400 psia pressurizer pressure. (A train of ECCS is defined as a train of HPSI, Low Pressure Safety injection (LPSI)(BP), and Charging (CB). However, Charging does not take suction from the emergency sump. LPSI automatically trips on Recirculation actuation Signal (RAS).) With one train of ECCS inoperable, but with at least 100 percent of the ECCS flow equivalent to a single operable ECCS train available, TS 3.5.2 Action A requires the inoperable train be restored to operable within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, if Action A is not completed, Action B requires being in Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and below 400 psia pressurizer pressure within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Consequently, this condition is being reported under 10 CFR 50.73(a)(2)(1).
TS 3.6.6.1 requires two trains of CS to be operable in Modes 1, 2, and 3.
As discussed above, CS Train A cas inoperable between January 6, 1998, and January 24, 1998. TS 3.6.6.1 Action A requires the train be returned to operable within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. If that action is not met, Action B requires being in Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 4 within 84 hotrs.
Operations records showed that Train B ECCS (the opposite Train) was inoperable on six occasions between January 6, 1998, and January 24, 1998. These six occasions were:
1.
January 12, 1998, for an inservice test of a HPSI pump for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 43 minutes.
2.
January 13, 1998, for 27 hours3.125e-4 days <br />0.0075 hours <br />4.464286e-5 weeks <br />1.02735e-5 months <br /> and 5 minutes when a Component Cooling Water (CCW) heat exchanger tube leak was repaired. CCW is a required support system for ECCS.
3.
January 16, 1998, for 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and 36 minutes for main condenser heat treatment. The heat treat process increases the temperature of the Salt Water Cooling System (SWC), reducing the system's ability to remove heat. SWC is a required support system for ECCS. The affected train of ECCS is conservatively declared incperable.
~
LICENSEE EVENT REPORT (LER) u.s. nunui accutuen comission I
[
nac ro m m A (4 95)
TEXT CONTINUATION
_ l FACILITY NAME (1)
D0CKET LER NUMBER (6)
PAGE (3)
YtAR st0VtNTIAL REV!s!04
- 8E8
"*8 E "
San Onofre Nuclear Generating Station (SONGS) Unit 2 05000-361 3 0F 7 1998
-- 003 --
01 4
January 22,1998, for 19 minutes while Operations swapped the inservice SWC pump to the opposite train.
5.
January 23, 1998, for 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> and 45 minutes for Recirculation Actuation Signal (RAS) Train B valve 2HV9301 breaker work. 2HV9301 is the Refueling Water Stofage Tank (RWST) outlet valve.
6.
January 24, 1998, for 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> and 31 minutes another main condenser heat treatment.
For both trains of ECCS inoperable, TS 3.5.2 requires imediate entry into TS 3.0.3 (initiate action to enter Mode 3 within I hour, be in Mode 3 within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />, and, for inoperable ECCS, be less than 400 psia aithin 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />). Because SCE was unaware that Train A was inoperable, TS 3.0.3 was unknowingly applicable.
Cause of the Event:
Visual observation of the affected interlock found an accumulation of what appeared to be fine sar.d or grit on the back side of the linestarter assembly. The grit was tan colored, and had adhered to almost all parts of the interlock assembly. Concentrations of grit were located around the four openings at the bottom of the mounting plate and on the top sides of most components. The heaviest accumulations were around the four openings, indicating the majority of the grit entered through those openings, as opposed to entering though the open sides of the backing plate, and that the grit was introduced af ter the linestarter cas installed.
When the interlock was dismantled, both guide posts and plastic sliding cami showed the presence of grit.
The sliding cams were difficult to move on their guide post. Previous experience with both new and worn interlocks of this type has never shown binding from grit.
The interlock parts and grit were analyzed in the laboratory. The debris was identified using Energy Dispersive X-ray Spectroscopy (EDS) as primarily silicon, aluminum, and calcium, with traces of other metallic elements. To allow examination with a Scar.ning Electron Microscope (SEM), one sliding cam was cut l
into pieces to reveal the surface of the bore. Debris, consisting of fine particles with sharp edges, had galled the sliding plastic parts of the interlock, closing the clearance.
The cause investigation concluded that:
1.
Based on the color, visual appearance, and elemental makeup, the grit is most likely gunite particles. Gunite was used to stabilize hillsides outside the protected area during original plant construction.
2.
There was no conclusive evidence of any significant quantities of grit on or around other switchgear room components, nor was any evidence of it found in the ventilation ducts.
3.
Based on the evidence gained from the locations and ages of clean components, it is concluded that the grit was introduced prior to 1993, and most likely prior to plant startup. Onct. deposited, the grit does not migrate, so that deposition is not an on-going problem.
J 4.
The presence of grit, by itself, is not a sufficient reason to conclude that a given linestarter is inoperable. This conclusion is based on field evidence, laboratory testing, and the fact that only the one linestarter was found to be Jamed by grit contamination.
w
--er e
,,,.-m----w
~
LICFASEE EVENT REPORT (LER) u.s. nucuan nEcutatoav comission nac rom ma (4 95)
TEXT CONTINVATION FACILITY NAME (1)
DOCKET LER NUMBER (6)
PAGE (3)
YEAR sE0u[NTIAL REV!sION
"*8'"
"*'I" SanOnofreNuclearGeneratingStation(SONGS) Unit 2 05000-361 4 0F 7 01 003 1998 Corrective Actions:
As stated in the Additional Information section, SCE has been programmatically replacing Square D linestarters. As of February 5, 1998 (the discovery date), 60 of 86 linestarters in Unit 2, and 61 of 86 linestarters in Unit 3 had already been replaced. AdditionalMotorControlCenter(MCC)inspectionswere made, and the same contamination was found in other buckets of MCC 2BE as well as MCC cubicles 2BJ47 and 3BE13. See the Safety Significance of the Event section, below. Therefore:
1.
All remaining old interlocks in Unit 2 (26) were removed, inspected, and replaced with new interlocks during the Cycle 9 mid-cycle outage. No additional failures were discovered.
l 2.
All remaining old interlocks in Unit 3 (25) were visually inspected, and verified to be in the neutral position, and re-verified after each completed operation of the valve, assuring the associated valves were capable of performing at least one more operation. (See the Safety Significance,belce.) The interlocks which could be replaced with the unit on-line (16 total) were replaced prior to the mid-cycle outage. The remainder (9) were replaced during the Unit 3 Cycle 9 mid-cycle outage.
Safety Significance of the Event:
Based on equipment inspections and maintenance records, only linestarters installed prior to January 27, l
1993, are subject to contamination. As discussed above, the majority of the safety related linestarters in Units 2 and 3 were replaced with new linestarters in 1995 (or later). The following discussion addresses the potential effects the grit may have on components whicn are still installed in Units 2 and 3.
Safety Significance Of Grit On Other Components:
480 VAC MCCs contain components in addition to reversing motor linestarters. Only components with exposed moving parts, tight tolerances, and relatively low operating forces are subject to binding.
The only components other than reversing linestarters with moving parts are:
1.
Non-reversing starters. Non-reversing starters do not have e mechanical interlock and the moving parts are primarily shielded by an outer case. Both reversing and non-reversing starters have relay cotts which are unaffected by grit contaminants and their contacts are self cleaning. The moving parts of these starters have relatively loose tolerances and strong operating forces so they are not expected to bind from the additional friction of a thin layer of contamination.
2.
Auxiliary contactors. The moving parts of auxiliary contactors are typically not exposed, and the self cleaning wiping action of the contacts normally prevents the accumulation of foreign material.
3.
Agastat relays. Agastat relays are sealed to prevent entry of dust, and the motion of the internal mechanism does not lend itself to binding.
4.
Circuit breakers. The circuit breakers used have a molded case which tightly seals the unit. In the unlikely event that contamination should penetrate the breaker housing, the mechanism itself has loose tolerances and large operating forces, making it unlikely to bind.
l S.
Switches. Switches are normally sealed, and are manually operated, making them unlikely to bind from a thin layer of contamination.
= - - - - - - ~
nec ronn nu LICENSEE EVENT REPORT (LER) u.s. nuettu accutcom comission (e.es)
TEXT CONTINUATION
/
FACILITY NAME (1)
D0CKET LER NUMBER (6)
PAGE (3)
)
TEAR st0VENTIAL RtV!s10N San Onofre Nuclear Generating Station (SONGS) Unit 2 05000-361 5 0F 7 01 1998 003 l
(
Therefore, this event had no safety significance for components other than the Square D linestarters in the affected 480 VAC MCCs.
i Safety Significance for Unit 2:
)
SCE estimated the reported condition constituted an incremental increase in core damage probability of approximately 6E-6 for the period January 6, 1998, the date the valve became inoperable, through l
January 24, 1998, the date the unit exited TS 3.5.2 for the mid-cycle outage, when unproceduralized re'.overy actions a/e credited. This increase in risk is characterized as small. Details of the risk evaluation were provided in Reference 1 (see Additional Information, below).
l 1
l Safety Significance For Unit 3:
1 1
j As discussed in the Corrective Actions section, linestarters which could be replaced with the unit i
operating were replaced. Prior to the March 8, 1998, unit shutdown, 16 linestarters had already been replaced and none were jarsned. SCE expected these linestarters would have operated es required to mitigate j
the consequences of an accident because:
l J
1.
All old interlocks were visually inspected, and verified to be in the neutral position. The presence of the grit has no adverse effect on valve operation if the interlock is in the neutral j
position. The linestarter's solenoid is strong enough to overcome any grit induced resistance. The valve will still operate in either direction. It is only the interlock's return spring (which returns the interlock to its neutral position) which cannot overcome the friction caused by the 3
grit. Therefore, the associated valves were expected to be capable of performing at least one more operation upon demand.
2.
The linestarters have shown reliable operation since the pre-1993 introduction of the contaminant.
j 3.
Redundant components and trains were available to fulf t11 the required safety function for a valve l
which might fail to operate because of a jammed interlock.
Therefore, this event has minimal safety significance for Unit 3.
I j
Additional information:
Reference ': Letter, Dwight E. Nunn, SCE, to Document Control Desk (bSNRC), Linestarter and AFW Supplemental Information, April 1, 1998.
1 i
l-In LER 2-97-010 SCE reported that both trains of ECCS were made inoperable because of the failure of a check valve to open completely. The cause of that failure was a valve design defect, a cause not present for the event reported herein.-
i In early 1995, during the Unit 2 Cycle 7 refueling outage, Square 0 mechanical interlocks jauned during i
preventative maintenance. SCE concluded the mechanical inter 10cks jammed due to excessive wear of the j
sliding cams caused by the manual cycling performed as part of the preventative maintenance program.
Corrective actions included, among other things, the planned change out of the linestarters prior to i
returning to service from the Cycle 10 refueling outsges for both Units 2 and 3.
It was during this planned change out that the conditOn being reported herein was discovered. Because of the fine dust i
appearance of the grit to the nn es eye, it is not reasonable to expect that this problem could have been
~
identified by a prudent individual examining the cubicles using industry accepted QA inspection terhr.iques.
The grit cannot be differentiated from normal dust accumulation without optical microsecpy, or SEM and EDS.
Grit was not a contributor to the failure mechanism of the interlock in 1995.
. - - -.. -. -. ~.. - -. - - -.. - -
nic ro m m A LICENSEE EYENT REFORT (LER) u.s. nucue RtcutAroRv co+1ssica (4 95)
TEXT CONTINVATION FACILITY NAME (1)
DOCKET LER NUMBER (6)
PAGE (3)
YEAR
$(QutNTIAL REVISION San Ono'fre Nuclear Generating Station (SONGS) Unit 2 05000 361 NW8E8
"*8 E "
6 0F 7 01 1998 003 g:
j l
g 11
! i a4 i
Q.:
xu
'I ld 8 4 j!jri L.
?
s
'i Iw:wi:
i ta jd_i_pu$'.
la e hpd!
j!,
y.t r-
~
!S) - ! I s
.k..
i I
!]
S e
...!.....,.z o..........,.y.......o.....z z z 2 z
z zzzz 4
g
...o..o...u... p.o..p..o................... +--3 s
s a
3 oo. g oo a
mo 3
b,k[
I kIl
}N I l NF-GOl i hk I
i a
y _W."In!
2 m i
,ii jk!,!
@?i I
i g
a i ii r-A!i 7%i 22 m
o ii k,, >
i e
m i !.E a
Fg m
e e
e.
o
,=
a3
%s
.=
.e i,
=n n a.i %g, 8
i.
- c.'. oozy
- ij~r-i,l
.m
'I 1
je
%si 1
11 f?:!E
$'.id i
,G;!
8
! 1:Wib, id if iii,
i.
s 6
s-M lslh
.I 8f'8}i
'l I ~T,c.-
+ -oo a
i
,I, l
',tZ 5" !P
- l g
i-A., d
- l b
x
._..I g.
[E *'
i j m;I.
3 -Q. O,
! yJbig.!
i,
,2 1 1
!?
n z
2 1
m e
3.3 3..i
., ~, g:.....[t J
i W
i e
O!
l 7.3 I
. o: Gj j
._c c'
o-E l
Ej( 6
- t T.
f Ci j
l L-0:0.N
- i# 38 3
l N
sl(El se i
i xd-<: E i
j-17-
.il I: A tal!
a v
y LICENSEE EVENT REPORT (LER) u.s. nuctsAa accutaroar commissica nat rena m A 4
s (4 951 TEXT CONTINUATION FACILITY NAME (1)
DOCKET LER NUMBER (6)
PAGE (3)
TEAR SE0VENilAL lnEV!510N San Onofre Nuclear Generating Station (SONGS) Unit 2 05000-361 numsta
- numsta 7 0F 7 1998
-- 003 01 Figure 1 - Typical Square D Linestarter with Mechanical Interlock
, #* ' ~+r...._
~
.. 31 Return S 2 ring, G01Epost, drilPlastic Cam ji
&.,x 3
y 3.
kl.
f.
i L
.Ji h' W & g g fi g :, ; A I+.
asy
. ?
J f..
- . 9' 9. c
- -
sg_ y.
m.
y,
, - _q:a.,'.,.y:h,
,w
~.
~-
a
^ m'
' a '
... s h 4...
- %w u.
.w w.
I'j
- s. g..@
.t:?yQ.,
11b. l...
i i
- l
-t
- ~.. -
- -.