ML20214P643
| ML20214P643 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 06/18/1986 |
| From: | SOR, INC. (STATIC O-RING) |
| To: | |
| Shared Package | |
| ML20214P629 | List: |
| References | |
| 8601-009, 8601-9, NUDOCS 8609230335 | |
| Download: ML20214P643 (9) | |
Text
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E' gO teoOEL 183 LONG TERM TEST Pt.AN i
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"_Purpeee:
To prove long term set point stability of Model 103 Delta-P switches as suppiled to the nuclear power Industry.
oblectiveI
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This test is designed to prove the stability of the Model 103 as used in the LaSelle Station reactor level safety system.
The met points and pressurus Nl wars selected based on their operational parameters.
The test is comprised of three sections.
Section One is a sfx week test in which the static U
pressure of approximately 1000 PSIG will be mainteined with a differential j [
g' pressure of appewximately 47.6" W.C. (HI side over low side).
The set point readings will be taken on a scheduled bases of g
D (X) Series taken delly and at 2, 4 and 6 week intervals
' N 2 wk. (X) Series taken each 2 week Interval 4 wk (X) Series taken at 4 weeks and 4 weeks i -
6 wk (X) Series taken at 6 wseks
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Section Two is a repeat of the Section One test.
These two sections will e.
reinflerce each other as well as allow a complete report to be writte7 at tieth
+
six weeks and twelve weeks.
Section Three is comprised of 6n ongoing tcst using twenty switches.
This ongoing testing program will yloid long term g
data to support those applications in the field.
The Third Section witi be a O,
six week cycle with twenty readings (one for each switch).
The twenty q'i readings will be taken at the same time and recorded in the d.ita 1o.,3 T.w Section Three test will be considered terminated after le months of i m consistent data. The A series switches will be: the control switche.t (refer to 4.ig test set-up schematic).
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i SECTION g gDR ADOCK 05000374 Procedure:
.. g 1,
Bulld 20 $103AS-8212-NX-JJTTX5 Delta-P switches.
Insta:1 polis %d g
cross shafts per $601-008 in 16 switches.
Install stenciard cios s shaftu in 4 switches. (The 4 switches are to be control switches.)
1.Jse only quellflod meterial and nboerve all approved nuclecr assem-)ly d eminD procedures.
2.
After final calibration ("Rearfy to Shipa condition) laste'l itie swit.ch tu in a
test circuit per attached schematic.
Calltrate Roy,or.sount transmitter, Model #1151DP4E12, S/N 794122, (dry), lo side open to vent, against a water manometer and record readings ori ot te ch:4*
cellbration sheet, b-@
3.
With EQ valve open, fill the system with de-lonized water anct bleo.1 au a
from system.
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-f a'"Llllllylllll"'" M i ] m -cam-4, Close valves 4H, 4L, 2H, 2L, DH & DL. (GH 6 SL valves open).
f*
pressurlaa system to 1000 pol.
Close equalize valve at:d cellbrate 6 (g
week switchee to approx.:
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4 WMA - 56.9= +
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4 WKB - 57.9" +
4 WK C - 59.9" +
s WKD - 59.9" +
.4 WKE - 60.9" +
I HOTE:
Hold different!al pressure 4 47.s" for a minimum of one minute befbre final reading.
Obtain increasing met point coming up I
from 47.6" W.C. di Terential pressure.
Obtain decreasing set point coming down from increasing set point.
Record base line deta.
,s 1-5..
Open EQ valve.
l 6.
Close 6H, GL 5 Open 4H s 4L Valves.
Close equalize valve and calibrate switches to approx.:
4 WK A - 54.98 +
4 WKB - 57.t" +
4 WKC - as.t" +
l 4 WKD - 59.9" +
4 WKE - 60.9" +
Obtain incrossirig and decreasing met points as in Step 4 above ami I
i record base line data.
7.
Open EQ valve.
Close 4H s 4L valves and open 2H & 2L valses.
~
s.
Close equall e valvd and cellbrate switches to approx.:
2 WK A - 56. 9". +
2 WKB - 57.9"'W 2 WKC - 58.9" +
2 WKD - 59.9" +
2 WKE - 60.9" +
Obtain incrusalng and decreasing met points as in Step a above and record bene line data.
9.
Open EQ volve.
10.
Close 2H & 2L valves, open DH & DL valves.
Close equ: dire velsic a:nf calibrate switches to approx.:
DA - 56.9" +
DB - 57.9" +
1 l
DC - 55.9" +
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DE - 59.9" +
DD - 60.9" +
,y i.
f Obtain increasing and decreasing set points as in Step 4 a'<.ve snd T-recorti base line data, j
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- 11. Open EQ volve.
Open all valves (6H, SL, 4H, 4L, 2H, 2L, DH. DL) and adjust pressure to approximately 1900 psi.
Close equellae valve and maintain 12.
differential pressure e approximately 47.0" W.C.
I,J. _
NOTE:
i This completes inittel calibration and establishes base lins data.
i
' 13. Dolly Calibrations C
To calibrata dally switchess f
13.a.
c Close SH, GL, 4H. 4L, 2H, 2L valves, Adjust and hold differential pressure at 47.t" W.C. for a l
13.a.1.
r f
13.a.2.
L mintanum of one minute, l
Incrosse differential pressure and record incromulng sat 13.a.3.
i se differential pressure and twoord decreasing set 13.a.4 pointsOpen all valves and adjust static pressure to 13.a.5.
approximately 1000 psi.Close EQ valve and adjust differe 13.a.6.
opproximetaty 47.6' W.C.
84sintain pressure in 13.a.5 and 13.a.f. above as close as practical until next cellbration period.
II.e.7.
2 Week calibration Check 14.
To calibra,te 2 week switches:
i i
14.a.
Cellbeste daily switches as in Step 13 above.
Assuhi that valves 6H. 6L, 411, 4L, DH, and DL are
- 14. a.1.
14.a.2.
cloemd.
Open EH, 2L and EQ valves.
Adjust static pressure to appinximately 1000 psi.
- 14. a. 3.
Adjust and hold differentla' pressure at 47.6" W.C. for a 14.s.4.
14.a.5.
minimum of one minute.
Incrossa differential pressure and record inc.reasing s,at 14.a.6.
se differential pressure and record d.creessng met 14.a.7.
- nta, pen all valves and adjust static preuvre to i
14.s.s.
approximately 1000 pai.Close EQ valve and adjust different i
14.a.9.
mpproximately 47.4" W.C. Maintain pressure in 14.a.s and I
l 14.s.10.
as practical until next calibration period.
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Modet 103 Long Term y
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- 15. 4 Week CalibratAon Check
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' 15.a.
To callbrate 4 week awltches:
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15.a.1.
Calibrata dally owltches as in Step 13.
15.a.2.
Cellbrate 2 week switches as in Step 14.
15.a.3 Assure that valves 6H, 41., 2H, IL, DH, and DL are g
closed.
15.a.4.
Open 4H, 4L and EQ volves.
15.a.5.
Adjust static pressure to approximately 1000 pol.
15.a.6.
Adjust and hold differential pressure at 47.6# W.C. for a 4
minimum of one minute.
15.a.7.
Increase differential pressure and record increasing set
#
points.
0 15.a 5.
Decrease differential pressure and record decreasing set
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Q points.
15.a.9.
Open all valves and adjust static pressure to g
approximately.1000 pol.
15.a.10.
Close EQ valve and adjust differential pressure to l
approximately 47.6" W.C.
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15.a.11.
Maintain pressure in 15.a.9. and 15.a.10. above as close me.
as practical until next calibration period.
g St.
16.
8 Week Calibretton Check g
16.a.
To collbrate s week switches:
16.a.1.
Collbrata dally switches as in Step 13.
5 16.a.2.
Calibrate 2 week switches as in Step 14.
16 a.3.
Calibrate 4 week switches as in Step 15.
(
16.a.4.
Assure that valves 4H, 4L, 2H. 2L, DH, and DL are f*
clossid.
16.a.5.
Open,6H, GL and EQ valves.
(
16.a.6.
Adjuiit' static pressure to approximately 1000 pol.
16.a.7.
Adjust and hold differential pressure at 47.t>* W.C. for a a*
minimum of one minute.
16.a.8.
Increase differential pressure and record incressing set h
points.
- 16. a. 9.
Decrease differential pressure and recon d decreasing set points.
16.a.10.
Open all valves and adjust static pressure to approximately 1000 pai.
16.a.11.
Close EQ valve and adjust differential pressure to approximately 47.6" w.C.
16.a.12.
Maintain pressure in 16.s.10. and 16.a.11. above as i
close as practical until next callt, ration parloo.
t
- 17. This completas SECTION 1 Testing.
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SECTION 2
-,e, Section 2 testing is identical to Section 1 Testing (beginning on Week 7).
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- SECTl_0N 3 Precedure T
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Sectkm 3 testing is to be dont at Week it.
W 2.
Additional testing le to be done at 6 week Intervals.
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During Section 3 testing, all twenty switches are to be checked Ci concurrently.
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ATTACHMENT 10 Documents Reviewed LIS-NB-201, " Unit 2 Reactor Vessel Low Water Level Scram and Primary Containment Isolation Calibration," Revision 1.
LIS-NB-401, " Unit 2 Reactor Vessel Low Level Scram and Primary Containment Isolation Functional Test," Revision 1.
LIS-RP-02, " Reactor Vessel Low Water Level S ram and RHR (Shutdown Cooling Mode) Isolati'on Response Time Test," Revision 8.
LIP-r -937, " Administration of Response Time Tests," Revision 2.
Special Test Procedure LST-86-096, " Unit 2 Level 3 Scram Test," Revision 0.
Special Test Procedure No.86-099, " Static-0-Ring Operability Evaluation For the Unit 2 Reactor Vessel Low Water Level Scram and Primary Containment Isolation," Revision 0.
Sargent and Lundy (S&L) Piping and Instrument Drawing (P&ID) Unit 2, M-139, Sheets 4 and 5.
S&L Schematic Diagram No.1E-2-4215 Sheets AC through AF.
S&L Specification No. T-3702, " Pressure and Differential Pressure Switches, LaSalle County Station - Units 1 and 2 Commonwealth Edison Company."
l EQ-LS075, " Environmental Qualification Report for Static-0-Ring Differential Pressure Switches."
Calibration Data Sheets dated:
l April 6, 1985 April 22, 1985 l
May 3, 1985 May 16, 1985 August 5, 1985 i
January 3, 1996 March 31, 1986 May 10, 1986 June 1, 1986 June 2, 1986 Discrepancy Records86-007, Switches N024A, C, and D 86-167, Switches N024B and D 86-231, Switch N024B l
l
L(I cc.
ATTACHMENT 10 Documents Reviewed LIS-NB-201, " Unit 2 Reactor Vessel Low Water Level Scram and Primary Containment Isolation Calibration," Revision 1.
LIS-NB-401, " Unit 2 Reactor Vessel Low Level Scram and Primary Containment Isolation Functional Test," Revision 1.
LIS-kP-02, " Reactor Vessel Low Water Level Scram and RHR (Shutdown Cooling Mode) Isolati^on Response Time Test," Revision 8.
LIP-A'-937, " Administration of Response Time Tests," Revision 2.
Special Test Procedure LST-86-096, " Unit 2 Level 3 Scram Test," Revision 0.
Special Test Procedure No.86-099, " Static-0-Ring Operability Evaluation For the Unit 2 Reactor Vessel Low Water Level Scram and Primary Containment Isolation," Revision 0.
Sargent and Lundy (S&L) Piping and Instrument Drawing (P&ID) Unit 2, M-139, Sheets 4 and 5.
S&L Schematic Diagram No.1E-2-4215 Sheets AC through AF.
S&L Specification No. T-3702, " Pressure and Differential Pressure Switches, LaSalle County Station - Units 1 and 2 Commonwealth Edison Company."
EQ-LS075, " Environmental Qualification Report for Static-0-Ring Differential Pressure Switches."
Calibration Data Sheets dated:
April 6, 1985 April 22, 1985 May 3, 1985 May 16, 1985 August 5, 1985 January 3, 1986 March 31, 1986 May 10, 1986 June 1, 1986 June 2, 1986 Discrepancy Records86-007, Switches N024A, C, and D 86-167, Switches N0248 and D 86-231, Switch N0248
__._..-m
~. 0 Deviation Report No. 1-2-85-90, Switch N024A SOR, Incorporated Products Manual, " Pressure Switches for Process Control."
LaSalle License System Description Chapter 3, " Reactor Vessel Instrumentation," December 2, 1983.
LaSalle License System Description Chapter 29, " Reactor Feedwater System (FW),"
December 5, 1983.
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l On May 9,1986 at 0910 hours0.0105 days <br />0.253 hours <br />0.0015 weeks <br />3.46255e-4 months <br />,. with LaSalle Unit 2 at 86% power, a reactor scram occurred when a stationman accidentally bumped open a breaker while
~
sweeping the floor. The breaker was a primary transformer disconnect feeding the 120/208V distribution panel at Motor Control Center (MCC) 235x-3 The distribution panel f eeds the f eedvater level control pinel 2H13-P612.
With a loss of AC power to this panel, the 2B Turbine Driven Reactor Feed Pump locked out at bl% demnd and the 2A Turbine Driven Ree. tor Feed Pump coasted down to zero output. With bl% flov from only one Feed Pump, the reactor water level dropped rapidly and a full auto scram occurred. The Motor Driven Reactor Feed Pump was manually started during the event, but due to the loss of control power the Feedvater Regulating valve was locked out.
The cause of the scram was a loss of feedvater due to loss of power to the feedvater level control panel. An investigation meeting and training tailgate meeting were held on May 9,1986 with the stationman involved and with all other stationmen. The sessions stressed the importance of caution when working around any plant equipment, especially distribution centers and instrument racks.
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EVENT DESCRIPTION:
On May 9,1986, at 0910 hours0.0105 days <br />0.253 hours <br />0.0015 weeks <br />3.46255e-4 months <br /> with laSalle Unit 2 at 86% power a reactor scram (JC) occurred when a Stationman accidentally bumped open a breaker with his elbov vhile sweeping the floor. The breaker was a primary transformer disconnect feeding the 120/208 V distribution panel (ED) at Motor Control Center (MCC) 235X-3. The distribution panel feeds the feedvater (SJ, FW) level control panel, 2H13-P612, which sends reactor vessel level, pressure, feed flow and steam flow information to the feedvater level controllers (JK) that control feedvater turbine speed. Also fed of f the distribution Innel are various valve position indications, Emergency Core Cooling system motor heaters, Diesel Generator "0" fuel oil (DC) valve ODO-00h, 2h VDC battery charger (EI), and panel 2H13-P632 for leak detection (IJ, LD) logic control power. The Reactor Operator observed a lockout trip on the feedvater regulating valve, level alarcs, feedvater control signal failure alarms, no flow indication on feedvater or feedvate headers, and a narrow range level indication vent downscale.
Both reactor recirculation pumps (AD, i
RR) tripped to slov speed causing level to swell to kl.5 inches. The 2B Turbine Driven Reactor Feed Pu=p locked out at kl% demand, meaning it continued to supply feedvater at kl% capacity. The 2A Turbine Driven Reactor Feed Pump coasted all the way down to zero output.
The Motor Driven Reactor Feed Pump was manually started and level I
control was attempted, but the feedvater regulating valve was locked I
out due to the loss of control power caused by the breaker trip.
Reactor Water Clean Up (CE, RT) outboard isolation valve, 2G33-F004, isolated (JM) due to loss of leak detection logic power due to the breaker trip. This was an ESF actuation. Subsequently, the 2G33-F001 inboard isolation valve isolated due to high differential flov from the 2G33-F00h valve closing.
The reactor operator (licensed RO) noticed the 2h/h8 VDC battery trouble alarm up and sent an Equipment Operator to investigate. The Equi; rent Operator identified and closed the breaker that had been accidentally tripped by the Statiora:nn. The feedvater regulating valve lockout was reset. Vessel level dropped to a minimum of -30 inches during the event.
I The transient was about 2 minutes in duration. The Shift Engineer (SE) was directing operator actions using the Wide Range (WR) level i
recorder to formulate a basis for those actions. The WR recorder normally reads 6-10" lower than the Narrow Range (NR) recorder depending on the power level.
He was compensating for that difference as level decreased to verify in his mind that Reactor Water Level (RWL) was within Technical Specifications (TS) limits.
The Nuclear Station Operator (NS0) was stationed at the Reactor Water Level Control Station (RWLC) announcing level from the NR recorder.
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0 [h IaSalle County Station Unit 2 o plololel3l7lh 8l6 0 l0 [8 0 l0 0l 3 or nren -.
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w=aca mumm The initial half scram occurred from RPS Channel B-2 and both operators noted RWL was >+12.5".
As level decreased the NSO indicated 8.5",
armed the manual scram pushbuttons and asked the SE if he should insert a manual scram. The SE had determined that if RWL dropped to 6" on the WR recorder without a full scram he vould insert a manual scram.
This was based on his knowledge the WR recorder normally reads 6-10" lover than the NR recorder. The full auto scram was received when the WR 'evel recorder indicated +8".
The SE was confident RWC was not below TS limits when the full scram was received.
II.
CAUSE:
The cause of the scram was a loss of feedvater due to a loss of power to the feedvater level control panel. The loss of power was caused by a Station =an inadvertently bumping and causing a trip of the feedbreaker to the 120/208 V distribution panel on MCC 235X-3 while sweepin6 the area. The loss of feedvater led to a scram on low reactor water level.
III. PROBABLE CONSEQUENCES OF THE OCCURRENCE:
The plar.t performed as expected during a partial loss of feedvater event; no Emergency Core Cooling systems initiated or were required.
The reactor recirculation (AD, RR) pumps down shifted to slow speed and r.o Saf ety Relief (SB, ADS ) Valves (SRV's ) opened.
Safe operation of the plant was maintained.
IV.
CORRECTIVE ACTIONS:
1.
A tailgate training session was held with all Stationmen on site on May 9, 1986, to stress the importance of caution when working around any plant equipment, especially electrical distribution cer.ters and instrument racks.
2.
An investigative meeting was held on May 9, 1986, with the Stationman involved. The conclusion was reached that the person accidentally bumped the breaker and tripped it.
His subsequent actions were correct.
He immediately notified his supervisor of what happened.
3.
An investigative meeting was held at 1500 hours0.0174 days <br />0.417 hours <br />0.00248 weeks <br />5.7075e-4 months <br /> on May 9, 1986, with the shift Operating personnel. The conclusion reached was that everything happened as it should have. There was a question about the failure of the 2A Turbine Driven Reactor Feed Fump to lockout on loss of signal.
Investigation by the Instrument Maintenance Department found that 2A Turbine Driven Reacter Feed Pump performed as designed on a loss of power to its level controller.
The 2B Turbine Driven Reactor Feed Pump locked up because lover was not lost to its controller.
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The scram review addressed a statement by the Unit Operator that when the full scram was received he was watching the Narrow Range indicator and he thought it was reading about +8.0 inches.
The reading on the Narrow Range recorder could not be correlated to the scram. The review decided that the Narrow Range level indicators and the scram switches should be checked by calibration prior to start-up. The B Narrow Range Level indicator read 1.2 inches lov and the 'C' Narrow Range level indicator read 2 inches lov. The 'A' level indicator was failed due to the power loss at the beginning of the event. The control room indicators were recalibrated.
The recalibration on the scram switches were as follows:
2B21-N02hD (RPS Ch B-2)
+13.88 inches 2B21-N02hB (RPS Ch B-1)'
+13.h inches 2B21-N02hC (RPS Ch A-2)
+11.6 inches 2B21-N02kA (RPS Ch A-1)
+11.6 inches The recalibration shows the initial 1/2 scram on RPS Ch B-2 did come in early and the full scram signal on RPS Ch A-2 was at a lover set point but within tolerance.
Confirmation that the scram switches tripped within tolerance supported the Shift Engineer's initial determination that Reactor Water Level was within the Technical Specification scra= setpoint value of greater that 11.0 inches.
V.
PREVIOUS OCCURRENCES:
NonC.
XI.
N/#2 AND TELEPHONE NUMBER OF PREPARER:
Paul Sampson, Technical Staf f Engineer, 815/357-6761, extension 70h.
e
i 1 CommonweeIth Edison
- ~
LaSalle County Nuclear Station 1
[
Rural Route #1. Box 220 i
i Marseilles. lihnois 61341 Telephone 815/357 6761 t
1 June 2, 1986 U.S. Nuclear Regulatory Commissien Document Control Desk Washington, D.C. 20555
Dear Sir:
Reportable Occurrence Report #86-008-00, Docket #050-37h is being submitted to your office in accordance with 10CFR 50.73.
2.G.
G. J. Diederich Station Manager laSalle County Station GJD/DRR/kg Enclosure xc: NRC, Regional Director INPO-Records Center File /NiiC 1
l JUN 11 1986
SSINS No.:
6835
.c IN 86-47 m 2 UNITED STATES NUCLEAR REGULATORY COPMISSION OFFICE OF INSPECTION AND ENE0RCEMENT WASHINGTON, DC 20555 June 10, 1986 IE INFORMATION NOTICE NO. 86-47:
ERRATIC BEHAVIOR OF STATIC "0" RING OIFFERENTIAL PRES 5URE SWITCHES Addressees:
All boiling water reactor (BWR) and pressurized water reactor (PWR) facilities holding an operating license (OL) or a construction permit (CP).
Purpose:
This information notice is intended to advise licensees of erratic behavior of certain dif ferential pressure switches supplied by. 50R, Incorporated (formerly Static "0" Ring Pressure Switch Company) which apparently caused failure of the tasalle 2 reactor to scram automatically when it was operating with water level below the low level setpoint.
Similar switches are also installed in the high pressure core spray system and the residual heat removal system.
i It is expected that recipients will review this ir. formation for applicability to their reactor facilities and consider actions, if appropriate, to preclude J
the occurrence of a similar problem at their facility.
Suggestions contained In this notice do not constitute NRC requirements.
Therefore, no specific action or written response is required.
The NRC evaluation of this incident is continuing.
If specific action is determined to be necessary, a separate notification will he issued.
Summary of Circumstances On June 1,1986, LaSalle 2 experienced a feedwater transient that resulted in a low reactor water level.
One of the four low level trip channels actuated, resulting in a half scram.
The operator recovered level and operation was continued.
Subsequent reviews by licensee personnel raised concerns that the level had apparently gone below the scram setpoint and thus a malfunction of the reactor scram system may have occurred.
Based on this concern, the licensee declared an " Alert" and shut the plant down. The NRC dispatched an augmented inspection team to the site.
Subsequently, the licensee found that the " blind" switches which operate on differential pressure perform erratically.
The licensee also found erratic operation for similar switches in the high pressure core spray system and the residual heat removal system which operate valves in the minimum flow recirculation lines.
Based on these results, the licensee declared all emergency core cooling systems in LaSalle 1 and 2 to be Inoperable.
Both units are in cold shutdown pending further evaluation of the problem.
TewM81'
& i
m ue,,
June 10, 1986 Page 2 of 4 1
Description of Circumstances:
The following description was constructed from a preliminary sequence of events prepared by the augmented inspection team and from other input by the team.
At 4:20 A.M. on Sunday, June 1,1986, LaSalle 2 was operating at 93 percent of full power.
Both turbine-driven feedwater pumps were operating, with the "A" The motor-driven pump in manual control and the "B" pump in automatic control.
While a surveillance test was being conducted feedwater pump was in standby.
pump "A", the turbine governor valve opened further and caused pump on femdwatm At about the same time, the speed and reactor water level to t, tert increasing.
The reactor automatic control systems for both turbine-driven pumps locked out.
operator regained control of feedwater pump "A" and ranback feedwater pump speed in an attempt to restore water level to the nominal value (36 inches on the narrow range recorder).
A few seconds later when the control system was reset, the "B" feedwater pump controller automatically ranback the pump speed to zero for no apparent reason.
Resctor water level started falling at about 2 inches /second.
Subsequently, the reactor protection system responded via separate level switches to the falling reactor water level by reducing recirculation flow to reduce power, and the operator started the motor-driven feedwater pump to increase level.
The The level continued to fall for a few more seconds before turning around.
minimum reactor scram setpoint required in the technical specification is 11 inches.
The level channels are normally set to trip at 1$.5 inches, and the operators are trained to expect reactor scram by the time that the water level reaches 12.5 inches.
As the level was falling, one of the four reactor scram
)
level switches (the "D" switch) tripped at approximately 10 inches, causing a None of
" half scram." As designed, this did not initiate control rod motion.
the other three level switches tripped during this transient.
No reactor scram occurred during this transient, either automatically or manually, in the BWR scram system logic, which is one out-of-two-taken-twice, at least one instrument channel in each scram system must trip to generate a scram demand s1 nal and thereby initiate control rod motion.
Preliminary res lts 0
of the investigation indicate that the reactor water level fell to a minimum value of about 4.5 inches on the narrow range instrumentation, which is several inches' below the specified scram setpoint but still 13 to 14 feet above the top of reactor fuel.
The period that the water level was below the specified After feedwater flow turned scram setpoint value was approximately 2 seconds.
the transimt around, the plant stabilized at a power level of about 45 percent.
The The "B" scram system half scram was manually reset about 30 seconds later.
power level was increased to 60 percent about 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> later.
Shortly af ter the subsequent shif t change, the oncoming shif t engineer's review was effective in indicating that the reactor water level appeared to have fallen below the scram setpoint and the level switches may not have performed properly.
lie then requested that an instrumentation technician check the calibration of the switches.
Ihe results were that the "A" and "C" switches, which are in the "A" scram system, tripped at 10 and 13.5 inches respectively during the calibration check; the "B" and "D" switches, which are in the "0" scram system, tripped at 11 and 13.5 inches respectively.
The switches were readjusted to
- - -. ~.. _
1H 86-41 June 10, 1986 Pcge 3 of 4 trip at 13.5 inches.
Based on these results, the, operating staff believed that a malfunction of the scram system may have occurred.
An orderly shutdown of the plant was initiated at 2:00 P.M. (CDT).
At 2:30 P.M., the resident inspector was notified, and at 5:30 P.M.,
the NRC Operations Center was called via the emergency notification system and informed of this event by the licensee.
At 6:20 P.M., the licensee decided that the "A" scram system had failed to perform during the transient.
The "A" scram system was manually tripped providing a half scram on the side that had apparently malfunctioned.
The orderly shutdown was continued, and an " Alert" was declared. When all the control rods had been fully inserted at 9:22 the next morning, the Alert was terminated.
On Monday, June 2, the NRC determined that the incident warranted a thorough investigation.
The NRC Regional Administrator dispatched an augmented inspection team to the plant site.
i On Monday evening, June 2, the licensee checked the calibration of the reactor scram water level switches by varying the actual level in the vessel.
The results were that the "A" and "C" switches tripped at indicated levels of 9.0 and 6.9 inches respectively and the "B" and "0" switches tripped at 3.9 and 10.2 inches respectively.
These data were obtained about 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> after the switches had been calibrated according to plant procedures and suggest a non-trivial difference.
Additional data obtained over the next two days tiy varying reactor water level demonstrated continued erratic behavior of switch setpoints.
)
On Saturday, June 7, af ter calibrating the Static "0" Ring flow switch which actuates the minimum flow recirculation valve in the high pressure core spray f
system, the licensee performed a different test using actual system flow.
The switch actuated when flow was at 530 gpm instead of 1000 gpm where it had been set to actuate.
The licensee found similar performance of flow switches in the residuni heat removal cyctem.
The liconcee now suspects all Stat.ir "0" Ring differential pressure switches and has declared all emergency core cooling systems in both units to be inoperable.
Both units remain in cold shutdown.
Discussion:
It appears at present that the water level decreased below the scram setpoint for about two seconds and reached a minimum level of about 4.5 inches.
This is based on a recording from the narrow range water level instrument and records from the startup testing data acquisition system which recorded levels from the same transmitter.
Itad the reactor operatur been awar e of this fact before the water level had increased to a level above the setpoint, the reactor operator would have been expected to scram the reactor manually.
The dif ferential pressure switches which provide the water level trip input to the reactor scram system were provided by 50R, Incorporated, these level switches are not original equipment; but were installed during replacement of equipment in secondary containment.
Affccted licensees had determined that the original 5
switches were not qualified to operate in the environment created by an accident.
Operation of the SOR switches has been demonstrated to be erratic with little correlation between the setpoints established during atmospheric pressure h
IN 86-4/
June 10, 1986 Vage 4 UI 4 calibrations and switch actuations under system pressure conditions.
Exercising the switches by applying successive differential pressure cycles appears to mask erratic setpoint behavior.
Similar problems with SOR differential pressure switches have been reported at Oyster Creek.
Per plant procedure, the switches for reactor water level had been exercised prior to calibration following failure of the reactor to scram automatically.
For this reason, performance of the level switches may have been different during calibration than during the event.
Further, none of the level switches in the i
taSalle 2 reactor scram system operate in conjunction with individual level transmitters.
therefore, the calibration and performance of the individual low level trip channels cannot easily be compared to each other.
In effect, the operator is blind to switch performance.
The vendor has indicated that those plants identified in Attachment I have similar dif ferential pressure switches.
This list of plants includes pressurized water reactors as well as boiling water reactors.
NRC intends to meet with 1
representatives of General Electric Company, SOR Incorporated, and interested licensees at 10 A.M. on Thursday, June 12, 1986, in Bethesda, Maryland to discuss experience with the switches.
It is suggested that licensees consider advising their reactor operators of the taSalle incident and providing guidance to them as to how to promptly detect the occurrence of a similar problem at their plants and the proper remedial action to be taken.
No specific action or written response is required by this notice.
If you have any questions regarding this matter, please contact the Regional Administrator of the appropriate regional of fice or this office.
dw rr
, Director Divis' of Emergency Preparedness and ngineering Response i
Office of Inspection and Enforcement Technical Contacts:
J. T. Beard, NRR (301) 492-4415 4
Roger W. Woodruff, IE (301)492-7207 Attachments:
1.
Plants with Similar Dif ferential Pressure Switches 2.
List of Recently Issued IE Information Notices j
i 4
'r
,,,.,n,
_4
-,._, -, ~ - - - -..,, -
,------e---,
-.,-.----n,,----
Attcchment 1 IN 86-47 June 10, 1986 PLANTS WITH SIMILAR DIFFERENTIAL PRESSURE SWITCHES PLANT SOR MODEL NUMBER Penn. Pwr. & Light /Susquehanna 103/8202 So. Cal. Edison / San Onofre 103/8903 TVA/ Brown's Ferry 103/8212 IVA/Sequoyah 103/88212 103/88203 103/88803 WPPS 103/88203 GPU/0yster Creek 103/B905 103/88212 103/8212 103/8202 H.E. Nuc./ Millstone 103/B903 South Texas Projects 103/BB212 103/88803 Commonwealth Edison /LaSalle 103/8202 103/B212 103/8203 103/88203 103/B8212 103/88205 103/88202 e
A e l
MLt!CRmef1L 2 IN 86-47
~
June 10, 1986 LIST OF RECENTLY ISSUED IE INFORMATION NOTICES Information Date of Motice No.
Subject Issue Issued to 86-46 Improper Cleaning And Decon-6/12/86 All power reactor tamination Of Respiratory facilities holding Protection Equipment an OL or CP and fuel fabrication facilities 86-45 Potential Falsification Of 6/10/86 All power reactor Test Reports On Flanges facilities holding Manufactured By Golden Gate an OL or CP and Forge And Flange, Inc.
research and test facilities 86-44 Failure To follow Procedures 6/10/86 All power reactor When Working In liigh Radiation facilities holding Areas an OL or CP and research and test reactors 86-43 Problems With Silver Zeolite 6/10/86 Ellpowerreactor Sampling Of Airborne Radio-facilities holding iodine an OL or CP 86-42 Improper Naintenance Of 6/9/86 All power rector Radiation Monitoring Systems facilities holding an OL or CP 86-41 Evaluation Of Questionable 6/9/86 All byproduct Exposure Readings Of Licensee material licensees Personnel Dosimeters 86-32 Request For Collection Of 6/6/86 All power reactor Sup, l' Licensee Radioactivity facilities holding Measurements Attributed To an OL or CP The Chernobyl Nuclear Plant Accident 86-40 Degraded Ability To Isolate 6/5/86 All power reactor The Reactor Coolant System facilities holding From Low-Pressure Coolant an OL or CP Systems in BWRS OL : Operating L icense CP = Construction Permit i
)
. Attachment 13 9 4 f
LEVEL SETPOINT SWITCH FUNCTION B2l-NIOI A,8 TRIPS RCIC TURBINE CLOSES HPCS INJECTION VALVE B21-NIOO A,B 8
C.
TRIPS M AIN TURBINE C34 -K624 A, TRIPS FEED PUMPS B,C
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^
4 31.5" RECIRC. RUNB ACK PERMISSIVE C34-K626A,8 B21-NO24 A-b RE A9 TOR SCR AM @
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..m PRINCIPLE OF OPERATION
.03 0 103 Delta-P Differential Pressure Switches The predetermined differential pressure is set by Variable Set Point Force "V".
High Pressure Force "H"
is applied to one side of the Piston and Low Pressure Force "L"
is applied to the oDposite side of the Piston as shown in the diagram.
Thus, when the unit is at " Set Poin t", the dif ferential pressure across the Piston is represented by H-L=V, since they are applied at equa. radii.. and is shown in the diagram as Differential Force "D".
WI en the Differential Force "D" is less than Set Point Force "V", Set Point Force "V" holds the Cross Shaf t and Levers Assembly in its most counter-clockwise position and the Snap Switch in the " plunger in" position defined as normally open (NO) by wire markings.
j When the Differential Force "D" is greater than Set Point Force "V". it overcomes Set Point Force "V" as show.
by Arrow 2 and a!!ows the Piston, which is connected to the Piston Lever by an Operating Rod, to rnove the Piston Lever in a cleckwise (CW) manner as shown by Arrow 1.
This causes the Switch Lever to move as shown by Arrow 3. rotating away from the Snap Switch and the Snap Switch Operating Rod.
The_ Snap Switch is constructed with an internal Force "S" which moves the Operating Rod away allowing the Snap Switch to return to its " plunger out" position defined as normally closed (NC) by wire markings.
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Description 1-4 SOR Model 103 Differential Pressure Switches 2821-N024A-D as installed 5-6 Calibration Water Bottles connected to Differential Pressure Switch 7
Normal Test Rig 8
Narrow Range Level Recorder 9
Narrow Range Level Indicators 10-15 High Pressure Test Rig 16-25 SOR Model 103 Differential Pressure Switch 26 SOR Model 102 Differential Pressure Switch 1
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26
- ~
'*- 6 August 7, 1986 Docket No. 50-373 Docket No. 50-374 Comonwealth Edison Company ATTN: Mr. Cordell Reed Vice President Post Office Box 767 Chicago, IL 60690 Gentlemen:
On June 1, 1986 LaSalle Unit 2 experienced a reactor feedwater transient which caused water level to decrease below the low water level scram set point without the unit automatically shutting down. On June 2,1986 I issued a Confirmatory Action Letter (CAL) which identified a number of actions you planned to accomplish and stated that unit 2 (and unit 1 if the problem were generic) could not be restarted without my concurrence.
As a result of your investigation into the June 1 event you embarked on a testing program to determine the scope of the problem with the Static-0-Ring switches, and determine which switches are acceptable for continued use to support plant operation. The testing program and its results were closely monitored by the NRC. The results of these tests have served as the bases of a Safety Evaluation Report (SER) issued on August 7,1986. A copy of this SER is enclosed. This report concludes that the licensee's proposed actions supplemented by the actions listed in the SER, and the test results l
of the switches provide an adequate basis for the restart and short term operation of LaSalle County Station Unit 2.
We met with you on July 9,1986 to discuss actions taken by Commonwealth Edison Company in response to the June 2, 1986 CAL. We now consider all items listed in the CAL to be satisfactorily completed with regard to LaSalle Unit 2.
Based on the conclusions of the SER, your actions in response to the CAL and recommendations of the Staff, I concur that LaSalle Unit 2 may restart and operate in accordance with the provisions of the SER.
M
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Mr. Cordell Reed August 7, 1986 This will also acknowledge receipt of your letter dated August 4,1986, in which you describe actions planned to minimize personnel errors during the startup and operation of IJnit 2.
My staff will be monitoring your actions closely during the restart and initial operation of the unit.
We will gladly discuss any questions you may have in this regard.
Sincerel[e,1gned by Ortstna
-.. %r James G. Keppler Regional Administrator
Enclosure:
Safety Evaluation Report (SER) cc w/ enclosure:
D. L. Farrar, Director of Nuclear Licensing G. J. Diederich, Plant Manager DCS/RSB (RIDS)
Licensing Fee Management Branch Resident Inspector, RIII Phyllis Dunton, Attorney General's Office, Environmental Control Division
UNITED STATES ase NUCLEAR REGULATORY COMMisslON e
REGION lit
[
o h.
f 799 moostvtLT moAo o m. E u.v,..n.u oi... m SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION SUPPORTING THE RESTART _0F LASALLE COUNTY STATION UNIT 2 COMMONWEALTH EDISON COMPANY DOCKET NO. 50-374
1.0 INTRODUCTION
On June 1,1986, La Salle County Station Unit 2 was operating at 95 percent power when a feedwater transient occurred which caused reactor vessel level to drop to the level 3 trip setpoint. One of four level 3 trip channels actuated resulting in a half scram. The operators were able to restore level to the nor;=1 operating range and continue plant operation. Subsequent investigation determined that the reactor vessel level had dropped below the The licensee level 3 trip setpoint and a reactor scram had not occurred.
declared an " Alert, shut the plant down, and notified the NRC.
Further investigation determined that the event was due to a failure of the reactor vessel level 3 switches to trip at their set level. A special level drop test was performed to check the actual setpoints of each level 3 switch while at operating temperature and pressure. With the reactor at 950 psig, the reactor water was slowly lowered out of the nonnal operating range down to the trip point of each level 3 switch. The results were erratic with the switches tripping at levels between 3.9 and 10.2 inches versus their calibr-ated setpoint of 13.5 inches.
The investigation also revealed similar anomalous behavior of the same type of switch used to actuate the emergency core cooling system, primary contain-ment isolation system, and other engineered safety feature systems as illustrated below:
It was determined that the minimum flow valves for the emergency core 1.
For cooling system pumps would not open at the proper setpoints.
example, the switch for the high pressure core spray system pump was calibrated to actuate at 1300 gpm but did not actuate until flow decreased to 530 gpm.
As a result of observations of the level drop test, it was discovered l
2.
that one of two switches, used to initiate the automatic depressuri-J zation system due to low reactor water level, failed to function.
Calibration of the switch showed that the setpoint had shifted nonconservatively by 25 inches. With this shift of setpoint and the relative location of the instrument taps, sufficient differential The pressure could not have been produced to actuate the switch.
switch was disassembled and inspected. Rust was found inside the switch bearing assembly.
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-H-The investigation, conducted by the licensee, identified two collateral primary causes for the nonconservative behavior of the Static-0-Ring (SOR) switches:
1.
Rusted cross shaft bearing and 2.
Defomation of 0-ring seals The first cause, " Rusted cross shaft bearing," resulted in the functional failure of one of two SOR switches used to initiate the automatic depres-Initial calibration of the switch showed that the surization system.
A second calibration a few hours later setpoint had shifted 25 inches. Based on these calibration findings, the also showed setpoint shift.
licensee concluded that the " Rusted cross shaft bearing" cause for degraded switch perfomance can be detected through a nonconservative shifting of the calibration setpoint.
In order to detect this shift, the licensee has proposed an augmented surveillance program. This augmented surveillance program is discussed in Reference 2.
The second cause, "Defomation of 0-Ring Seals," was identified by the SOR When the 0-ring seals are subjected to operational switch manufacturer.
pressures over a period of time, they change shape such that a greater frictional force is exerted in opposition to the rotation of the cross shaft.
Thus, the switch trip setpoint shifts with the change of pressure from the "0" psig calibration level to the operational pressure level (1000 psig for The licensee has detemined through testing by the most applications).
switch manfacturer that maximum shift of the calibrated setpoint occurs during the first 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period of operation and that negligible shifts occur beyond this time.
The switches used in safety system applications at the La Salle County (Statio are a differential pressure type switch manufactured by Static-0-Ring 50R)
These switches are shown pictorially in Attachments 1 and 2 Incorporated.
of this report; and a discussion on the operation of the switch is made in Section III of the licensee's submittal of July 18, 1986 (Reference 2).
The differential pressure switches are calibrated at atmospheric pressure without removing them from the system by use of a test rig consisting of two bottles, each containing water and air or nitrogen connected to the differential pressure switch with one bottle on either side of the diaphragm.
Because the significant shifts of the 50R differential pressure switch calibration trip setpoints occur at operating pressures of approximately 1000 psig over a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period, the use of existing procedures to perform all switch calibrations and checks which are performed at atmospheric pressure (i.e., initial calibration, pre-operational testing, periodic I
functional testing, and periodic calibrations) could not detect the setpoint shift cf these switches.
e
f.
l In its submittals of July 18, 21, 23, and 24, 1986, the licensee has proposed a plan for testing and monitoring operation of the switches to support restart and short term cperation of La Salle Unit 2.
Staff evaluation of this plan is discussed in Section 2.1 of this SER.
j In order to address the generic implications of these setpoint shifts, the staff issued IE Bulletin No. 86-02, " Static-0-Ring Differential Pressure 18, 1986, to all power reactor facilities holding Switches,"datedJuly(OL)oraconstructionpermit(CP).
La Salle County an operating license Station Unit 2 submitted its responses to the bulletin by letter dated July 25,1986. Staff evaluation of the licensee response to the bulletin is discussed in Section 2.2 of this SER.
2.0 EVALUATION Licensee's Plan for Testing and Monitoring of SOR Switches to Support 2.1 Restart and Short Term Operation of La Salle Unit 2 The purpose of this SER is to evaluate the licensee's proposed short tenn actions to change switch calibration set points for operational parameters associated with SOR switches in the more conservative direction to compensate for anomalous switch behavior. Hardware changes and/or continued use of SOR type switches with their associated operational constraints for the longer tern (beyond the next scheduled refueling outage) will be the subject of a future safety evaluation report.
At a July 18, 1986 meeting in Bethesda, the La Salle County Station licensee (with representatives from SOR Inc.) presented the results of their investiga-Subsequent to tion into the June 1,1986, setpoint shift of SOR switches.
this meeting, the licensee provided submittals, in which it discussed the investigative efforts expended to identify the root cause of the anomalous l
switch behavior, and described its short term plan and actions it will implement to compensate for switch behavior and to monitor and test the switches to assure safe operation of the plant to support restart and short term operation of La Salle Unit 2.
The licensee's investigative process to determine the root cause of the anomalous SOR switch behavior as described in Reference 2 appears to be The discussion provided on 0-ring deformation sufficiently comprehensive.
is clear and reasonable; however, the theory on causes of switch failure j
due to rusting may not fully explain the phenomena for observed switch i
Therefore, additional investigation and testing is being j
failure.
When the results of i
conducted by the switch manufacturer in this area.
this additional investigation and testing become available, they will be evaluated by the staff and the results of the staff evaluation will be included in a future report.
. The licensee's investigative program to detemine measures that could be implemented to compensate for anomalous switch behavior included seven (7) tests and test procedures which are described on pages V-4 through V-12 in
~
Representative switch samples were subjected to each test to Reference 2.
establish the impact on switch perfomance. Results nf these tests indicated that test No.1. " Static Pressure Cycling" test, and test No. 2. " Time Related Effects" test results showed the most adverse impact on switch per-The static pressure cycling test, which was perfomed for all SOR formance.
differential pressure switches, involved the calibration of each switch per station calibration procedures. Each switch was then cycled at zero static pressure, and at elevated static pressure to determine the repeatability of The time related effects test involved perfomance of first actuations.
subjecting several switches to elevated static pressure for periods of 4, 24, 48, and 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> periods and then cycling each to detemine the first actua-tion point. Successive first actuation cycling following each time / pressure period was compared to determine whether the setpoint drift increased with time. Results of this test indicated that the significant setpoint shifts occurred between 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and that shifts beyor,d 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> were The information derived from the testing program was used to negligible.
characterize SOR switch operation, to establish bounds for static pressure shifts and switch actuation repeatability, and to develop an operational monitoring and test program (Reference 5).
To confirm the data derived from the La Salle test program, 50R Inc. is per-In the 50R Inc. test forming tests in parallel over a longer period of time.
program, several different models of SOR switches are being exercised at intervals of everyday, every two weeks, every four weeks, and every six weeks, to determine the magnitude and direction of setpoint shift over time.
4 The licensee's program for identifying the problems associated with the SOR switch and the testing program to develop measures to compensate for anomalous switch behavior are acceptable to the staff.
The licensee's proposed corrective actions for the short term for monitoring and testing of SOR differential pressure switches is discussed in Reference 5 and is also included as Attachment 3 to the SER. Attachment 3 also includes a list of S0R switches installed at La Salle, and a table which provides pro-posed new calibration setpoints for each SOR switch application.
The licensee's corrective actions plan consists of eight (8) elements with The actions include: flow testing to completion dates for each element.
verify ECCS minimum flow switch setpoints (completed); reactor water level drop tests for level 3 switches at startup and shutdown for the next refueling outage (scheduled for December 1986); completion of calibration procedures (completed); completion of recalibration of switches with new setpoints, (prior to startup); implementation of increased surveillance (after startup);
establishment of acceptance limits for switches (completed); submittal of La Salle Unit 2, Final SOR Report (completed); and completion of evalua-tion of alternative level sensing instruments to possibly replace SOR i
switches (by 1/1/87).
- 'I '
.The staff concludes that the licensee's corrective action plan and schedule supplemented by the actions described below, provide an adequate basis for restart and short tenn operation of La Salle Unit 2 until the next refueling outage (scheduled for December,1986). The staff discussed the supplemental actions with the licensee; and the licensee agreed to them via a telecon on July 31, 1986. The licensee confinned this in a letter dated August 1,1986.
The supplemental actions are as follows:
The licensee's plan to conduct reactor water level drop tests to verify A.
level 3 switch setpoints during startup after the current outage and The results during shutdown for the next refueling outage is acceptable.
from the water level drop tests which are conducted at operating pressure for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> should demonstrate stability of the trip setpoints and should confinn that the switches operate within the La Salle Technical Specification limits.
The licensee's plan for defining an action limit and a reject limit for B.
each switch application is acceptable except that when any 50R differ-ential pressure switch calibration check indicates a change which equals or exceeds the reject limit, the licensee shall declare the component and the associated channel inoperable and take the appropriate actions required by the La Salle County Station Unit 2 Technical Specifications, and the licensee shall report the incident in accordance with the require-ment of 10 CFR 50.72 and 10 CFR 50.73.
The licensee's increased surveillance program (Reference 5) provides h
C.
for calibration of the SOR Differential Pressures Switches at atmospheric pressure to the new trip setpoints (Attachment 3) which compensate, in a conservative direction, for shifts due to pressure and time, and perfonns periodic checks of the new trip setpoint for each switch at The increased surveillance program, conducted at atmospheric pressure.
atmospheric pressure, should demonstrate stability of the trip setpoint, and confirm that the switches operate within the technical specification The increased surveillance program, supplemented 'oy the actions limit.
'q described below, is acceptable to the staff.
The licensee shall continue performing its monthly channel func-
'l 1.
I f
tional test in accordance with the LaSalle Technical Specification.
If one channel of a system of redundant channels (or similar equip-l 2.
ment in redundant safety systems) is found to have an actual trip point that is outside the Technical Specifications or otherwise unacceptable for reliable system operation, then the redundant channels (or similar equipment) shall be tested as soon thereafter as practical.
In addition, if the licensee is contemplating long term use of the SOR dif-1 ferential pressure switches, or other mechanical devices, it should consider providing the means for making local channel checks by use of a differential t
l pressure gauge or other equivalent instrument display.
i
. Licensee Response to IE Bulletin 86-02 " Static-0-Ring Differential 2.2 Pressure Switches" In response to IE Bulletin 86-02, the licensee has taken certain actions to assure that systems using SOR 102 and 103 differential pressure switches operate reliably and has submitted the information for the staff to review by letter dated July 25, 1986. This information is the same as that dis-cussed in paragraph 2.1 of the SER. Our evaluation of the licensee's sub-mittal in response to IE Bulletin 86-02 follows.
The licensee installed 59 SOR series 102 and 103 switches at La Salle Unit On June 1, 1986, 2, as part of an environmental. qualification modification.
certain 50R differential pressure switches failed to actuate at the calibrated trip setpoints. Subsequent test results showed that a number of the switches would not have actuated at their existing setpoints under normal operating The licensee has taken short term corrective actions and has conditions.
developed a program (see paragraph 2.1) to improve the perfonnance of these The setpoints of the differential pressure switches have been switches.
revised to provide additional margin for static pressure shift and These revisions will ensure that the 50R Differential repeatability.
Switches Pressure Switches will actuate at the required trip setpoints.
that do not meet the static shift and repeatability acceptance limits To provide assurance that the switches will function pro-will be replaced.
perly, the ECCS minimum flow switches have been tested at their new setpoints during system operation and the reactor level drop tests will be performed at 950, 500 and 0 psig to verify the level 3 switch setpoints during pressures of The calibration startup and during shutdown for the next refueling outage.
procedure is being revised to record the first actuation of the switch as l
The the "as found" setpoint and to eliminate the effects of cycling.
surveillance frequency will be increased if a switch setpoint exceeds 1
its action limit.
If its setpoint exceeds the rejection limit or the action limit on two consecutive surveillance tests, the switch will be replaced.
The staff has evaluated the licensee's submittal in response to IE Bulletin 86-02 " Static-0-Ring Differential Pressure Systems" and has concluded that the licensee has taken short term corrective actions to assure that systems There-using 50R 102 and 103 differential pressure switches operate reliably.
fore, the staff finds the short tenn actions taken by the licensee are at least equivalent to the actions required by IE Bulletin 86-02 and are, there-fore, acceptable for La Salle Unit 2.
3.0 CONCLUSION
Licensee Actions to Support Restart and Short Tenn Operation of 3.1 La Salle Unit 2 Until Shutdown for the Next Refueling Outage Based on our review of submittals dated July 18, 21, 23, and 24, 1986, and the licensee's commitment to implement actions to assure reliable 50R pressure switch actuation at the required trip setpoints as described
I
. in Table 5.." Corrective Action" (Reference 5), the test results of SOR switches reviewed to date and the calibration of all SOR switches to new calibration trip setpoints which should assure reliable safe operation of the SOR switches, we conclude that the licensee's action plan supplemented by the actions described below provides an adequate basis for the restart.and short term safe operation of the La Salle County Station Unit 2 until the next refueling outage (scheduled for December, 1986). The supplemental actions have been discussed with, and agreed, to by the licensee during a telecon on July 31, 1986. The licensee The confim to perform these actions in a letter dated August 1,1986.
supplemental actions are:
When any SOR differential pressure switch calibration setpoint check 7
1.
indicates a change which equals or exceeds the reject limit, the licensee shall declare the component and the associated channel inoperable and take the appropriate actions required by the La Salle County Station Unit 2 Technical Specifications, and the licensee shall report the incident in accordance with the requirements of 10 CFR 50.72 l
and 10 CFR 50.73.
The increased frequency of surveillance calibration testing program, 2.
which is conducted at atmospheric pressure, and the level drop tests, which are conducted at operating pressure for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and which are to be performed during restart and during shutdown for the next refueling outage, shall demonstrate stability of the trip setpoint, and shall i
confirm that the switches operate within the La Salle Technical Specifi-cation limits.
The licensee shall continue performing its monthly Channel Functional 3.
Test, performed in accordance with the La Salle Technical Specification.
If one channel of a system of redundant channels (or similar equipment 4.
in redundant safety systems) is found to have an actual trip point that is outside the Technical Specifications or otherwise unacceptable for (or similar equipment)ystem operation, then the redundant channels reliable s The licensee shall submit, for staff review, test results acquired 5.
through its periodic and increased surveillance calibration testing program and from the SOR Inc. long term testing of the SOR Differential Pressure Switch, as the data become available, or when the La Salle Unit 2 shuts down for the next refueling outage.
Licensee Response to IE Bulletin 86-02 " Static-0-Ring Differential 3.2 Pressure Switches" The staff has avaluated the licensee's submittal which responded to IE Bulletin 86-02 and has concluded that the licensee has taken appropriate measures for the short term to assure that the systems using SOR 102 and 103 switches operate reliably. Therefore, the staff finds the short term actions taken by the licensee are at least equivalent to the actions recuired by IE Bulletin 86-02 and are, therefore, acceptable for La Salle D ': :.
TABLE OF REFERENCES Letter from Region III to Comonwealth Edison dated June 19, 1986 regarding 1.
confimatory action to resolve problem prior to startup.
letter from M.S. Turbak to H. R. Denton transmitting this July 18, 1986, 2.
Draft " Report of Investigation of SOR Differential Pressure Switches."
3.
Letter to Denton from Turbak, dated July 21, 1986, regarding the validity of 24 hou'r static pressure tests.
4.
Letter to Denton from Turbak, dated July 23, 1986, Transmitting Daily and Two Week Test Data.
5.
Letter to Denton from Turbak, dated July 24, 1986, iransmitting the Executive Sumary.
Letter to Denton from Turbak, Response to I&E Bulletin 86-02, dated July 6.
25, 1986.
Letter to Denton fron Allen, dated August 1,1986, Transmitting Comitment 7.
to Supplemental Actions.
1
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4) the most variable muttch in service uns amo4.
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l N 48431
. AUG.07 '86 12:56 HRC. MESSAGE CENTER BETHE50R MD sevist P.006 T/asist tasas..a couw! s m ault 2
. SCE SWT Qt INVB3;IshT:CW N
"0" ComasCT:vs ac:Inus 1
1.
Final Lata 11e C ur.ty Station Unit 2 8 1-86 3CR Zavest*gatten Report 2.
Flow Testing to verify BC S completed M*nisman Flow switch setpoints 3.
Reactor water level drop tests to verify Dc".ng starv.rp Level 3 switch setpoints.
Tests will be fo1*c#.r.g r...
e::
performed at a;;rox1=mtely 9fC PS:0. 5cc ps:o o c ase ar4 tur*.=s ami 0 PS;G. The reac,cr v12; be held at shuttevn fer the 95C 75:G fcr a: lamat 2k hcurs prior to the 1s re^.:el =g outage 950 PSIG 1evel Drs; Tee.
c=17 c=e level (a,,. tr.1:st ey L t; tes- */.'.1 he perfor=ed at each pressre.
De===her 1966,.
'7-28-A6 4.
c:splete calibration procedure revisicas.
- a. New set;oints inclut.*ng: stat *c pressure shif t, j
repeatability margin and drif t aartin.
l
- b. New calibration methods including: The 'he-feund" J
setpoint will be the first actuation and during calthrat".on the switch will be sycled Esta the appropriate 0% or 100% of differential pressure l
s,an to the setpoint.
. "Ar-Feund* setpo*nt ac:aptar.ca
- 1. ' ts wi'.1 be intimied 1.nt; the p*:catures, and actions will be deO.ned for each 1* ** t.
C.e limits and actions will be the following:
(1; Action Limit (a)
Except Main Steam Line Nigh Ficw.
,t. 3% of addustable rar.ge frcus new calibrat"en set;oint.
(b)
For mais steam lir.e hi$P. 21cw this limit was 1.!X repeatatility of the most variatie swit=r. i= saritca.
l Repeatability was calculated for l
each switch to heur4 in of the data with a 99% conf
- danca level.
je)
If this lim *: is ezeseded increase surteillance freguancias for the switch. T.e nazt surve*11anca i
l will be perfcraed at sta same interial as the last survatilanes withi this 11:11.
-a eo,
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.R.U.G.k7'8612:57HRCME55RGECENTERBETHE5DRMD gdj. 07i aote calibration procedure revisions (continued)
(c)
'As-Found" setpoint acceptance limits (continued)
(2) tejoction Limit (a) 1 (2% of Adjustable Range + Tech. Spec.
Margin for drift)
(b)
For mainsteam line high flow this limit is (Repeatability + tech. Spec, drif t) for the 5
most variable Switch in service.
Repeatability. teas calculated for each switch to 95% of the data with a 95%
confidence level.
(c)
If this limit is exceeded the switch will be rejected.
S.
complete recalibration of switches with revised Prior to startu; actpcints a,nd reviseti procedures.
from currect outage.
6.
Implement Increased Surveillance After Startup from current outage, s.
Categories 1.
Level 3 switches (6 switches) - The Level 3 switches will be callbrated 2 weeks after startsp 4 weeks after startup. I aonths after sta and 4 months after startup. After the 4th month, the tavel 3 switches will reonin en a que ly fr-1q. meta that this schedule assumes no problems accer with the lleits as described _aheve.
2.
Rain 5 team Line Break Switches (16 switches) - At least 4 of the Main Steam Line (MEL) switches will be calibrated 4 weeks arter startup. Of the remaining 12 sultches at least 4 of the HEL switches will be calibrated 8 weeks after startsp.
Of the remainint 4 sultches.
t least a of the HEL switches will by callhetted 12 weeks after startup. The analamm faterval for each ladividual switch in11 be llelted to a gearterly frequency.
3.
Ameatning switches (37 sullches) - A sample (
by model maters) representative of the resiaing switches (apprestaatel 1/3) en11 en Ibrated 4 tests after starte. Of the I
runelning switches, laste 1/3 will be estibrated I seeths after starte. The rensining sul}ches be call ted 3 months efter startu The maalsass interval for each ladividual switch wi11 be ilmited to a quarterly frequency.p.The representative samples will be chosen where possible, to include a smeling of various switch model museers.
7.
Co..plete evaluation of alternative level sensing Ins tru=e.,ts to replace SCR 1-1-8*1
- a. Review Requirements
- b. Review vendor environmental qualification data.
- c. Review vendor performance test data.
- d. Roccassend Technically acceptable alternatives.
- e. Conplete preliminary conceptual design and obtain reviews and approval.
General description of key features effecting desig.
\\
installation, operation and maintenance and project plan.
i
- f. Initiate detailed cenceptual design.
l w
I RUG.87 '86 12:57 HRC MESSAGE CENTER BETHESDA MD hvisioP.008 T/95/86 completed l1 s
satablish acceptance limits for new 80R The Purchase Order erith SCE trill switches.
to revised to require tests stailar to
'hetpoint characterization tests including a 24 hout test and to requite switches perform within the static shift and repeatability limits.
~
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i Attachment.15 SSINS No.: 6820 OMB No.:
3150-0012 IEB 86-02 dNITED STATES NUCLEAR REGULATORY COMISSION OFFICE OF INSPECTION AND ENFORCEMENT WASHINGTON, DC 20555 July 18, 1986
.i IE BULLETIN NO. 86-02:
STATIC "0" RING DIFFERENTIAL PRESSURE SWITCHES Addresses:
All power reactor facilities holding an operating license (0L) or a construction permit (CP).
Purpose:
The purpose of this bulletin is to request that boiling water reactor (BWR) and pressurized water reactor (PWR) licensees determine whether or not they_have Series 102 or 103 differential pressure switches supplied by SOR, Incorporated (formerly Static "0" Ring Pressure Switch Company), installed as electrical l
equipment important to safety.
Those licensees that have SOR Series 102 or 103 l
differential pressure switches installed in systems subject to Technical Specifications are requested to take certain actions to assure that system f
operation is reliable.
Description of Circumstances:
SOR Series 103 differential pressure switches were installed in LaSalle 2 in mid 1985 as part of an environmental qualification modification which was performed after initial operation of the unit.
Identical switches were also l
installed in LaSalle 1.
LaSalle 1 and 2 each have about 60 of these switches in various systems, including the reactor protection system and the emergency core cooling system.
On June 1, 1986, LaSalle 2 experienced a feedwater transient that resulted in low water level in the reactor vessel.
One of four low level trip channels actuated, resulting in a half scram.
The operator recovered level and power operation was continued.
However, subsequent reviews by the Licensee's person-l nel raised concerns that the level apparently had gone below the scras setpoint and that a malfunction of the reactor scram system may have occurred. Based on this concern, the Licensee declared an " Alert," shut the plant down, notified the NRC, and subsequently informed 50R of possible switch malfunctions.
(This incident is described in greater detail in IE Information Notice 86-47).
NRC dispatched an augmented inspection team to the site on June 2 to investigate the root cause and significance of the feedwater transient, the performance of the differential pressure switches in the low level trip channels, the response
- of the reactor protection system, and related matters.
i J ' i n m 2 c if n ll G O Gr+ 4tu p y -
d IEB 86-02 July 18, 1986 Page 2 of 9 After recalibrating the level switches on June 1, the Licensee tested the performance of the level switches by lowering water level (drop test) in the reactor and reading the levels indicated on level transmitters when each of the four level switches tripped.
The results were erratic with the switches tripping at levels between 2.4 inches and 12.2 (plus or minus about 1.5 inches, depending on the transmitter read). These measurements are relative to instru-ment zero which is at 161.5 inches above the top of active fuel. The technical specifications require that level channels be declared inoperable if the actual trippoint is below 11.0 inches.
As of June 9,1986, the Licensee had tested differential pressure switches in the residual heat removal systems and the high pressure core spray system.
These switches open valves in minimum flow recirculation lines so that adequate cooling to pump seals and bearings is provided when system flow is low.
One of the switches actuated within the range permitted by technical specifications; the others did not. The switch for the high pressure core spray system was calibrated to actuate at 1300 gpm but did not actuate until flow decreased to 530 gpm. The switches for the two residual heat removal systems should have actuated at 1000 gpm but did not actuate until flow decreased to the 480 to 800 gpm range. On the basis of these results, the Licensee declared all emergency core cooling systems for Units 1 and 2 to be inoperable.
Both units remain in cold shutdown.
Information Notice 86-47 was issued by the Office of Inspection and Enforcement g
on June 10, 1986 to inform licensees of the erratic behavior of SOR differential pressure switches during the incident at LaSalle 2 on June 1 and during subse-quent testing.
An attachment to the information notice listed licensees to which SOR had supplied Series 103 differential pressure switches.
That list has been revised (Attachment 1) to include Series 102 differential pressure switches which have important similarities to Series 103 switches.
It should be noted that the list of affected licensees is not believed to be fully accurate. The information notice also announced a public meeting of represen-tatives from NRC, General Electric Company, SOR, and interested licensees to discuss the application and performance of Series 102 and 103 switches in safety related systems, which was held on June 12, 1986.
Testing at LaSalle of other Model 103 SOR differential pressure switches used to actuate emergency core cooling system, primary containment isolation system, and other engineered safety feature systems revealed that these switches displayed the same types of behavior as the switches used for reactor scram.
During the vessel water level drop tests at LaSalle 1 on June 2, one of two Series 103 switches used to provide a confirmatory water level input signal to the automatic depressurization system failed to function.
On June 17, 1986, testing showed that the trippoint had shifted nonconservatively by 25 inches.
In this application, the relative locations of the instrument taps are such that the system could not produce sufficient differential pressure to actuate the switch.
Therefore, this amount of shift constitutes a functional failure of the switch.
On June 25, the switch was disassembled and inspected.
Rust
-IEB 86-02 July 18,1986 Page 3 of 9 (severe corrosion) was found inside the switch assembly and probably caused a cross shaft bearing, which is outboard of the 0-rings, to seize.
A similar event (Licensee Event Report 86-001-00) occurred at Oyster Creek 1 on January 17, 1986, during monthly surveillance of four SOR differential 4
pressure switches which detect low water level in the reactor vessel. The "as-found" setpoints for three of the switches had drifted downward as much as 6 inches..During the subsequent 11 weeks, the level switches continued to perform erratically, each switch was replaced one or more times, and modified switches were installed.
On April 7, after a modified switch had nonconserva-tive setpoint drift, the Licensee performed daily surveillance until about April 12 when the reactor was shutdown for a six month outage.
Increased surveillance frequency did not resolve the problem.
Earlier concern for mechanical level indication equipment was expressed in NRC Generic Letter No. 84-23 which addressed water level instrumentation for BWR reactor vessels.
The generic letter was based on NRC's evaluation of a report by S. Levy, Incorporated, which had been commissioned by a BWR Owner's Group.
The generic letter addressed the need for BWR licensees to review plant experi-ence related to mechanical level indication equipment, indicated that analog trip units have better reliability and greater accuracy than mechanical level indication equipment, and stated that BWR licensees should replace such equip-ment with analog transmitters unless operating experience indicates otherwise.
Responses to Generic Letter No. 84-23 show that 80% of BWR licensees have replaced or plan to replace their mechanical level instrumentation with analog t
level transmitters.
Recipients of this bulletin should recognize that while this bulletin focuses on more immediate problems with two similar models of l
mechanical differential pressure switches manufactured by SOR, Incorporated, the reliability of other mechanical instrumentation is also in question because it may be vulnerable to similar problems.
Because the same urgency has not been demonstrated for other mechanical differential pressure switches, the NRC plans to address that matter separately.
Discussion:
DESCRIPTION OF SERIES 102 AND 103 DIFFERENTIAL PRESSURE SWITCHES 1
The Series 102 and 103 differential pressure switches consist of a piston (Series 102) or a diaphragm (Series 103) which moves a lever that rotates a cross shaft.
These components are contained in a steel case designed to withstand system pressure. Both ends of the cross shaft extend out of the wetted volume and 0-ring seals are provided to form the pressure boundary and t
prevent leakage along the cross shaft.
The condition of these surfaces and the 0-rings will determine the extent to which frictional forces cause a_
torque which opposes rotation of the cross shaft. A lever is attached to each end of the cross shaft.
When the cross shaft rotates, one lever moves to actuate a microswitch.
The other lever bears on a helical spring.
An adjust-ing screw is used to change the compression of the spring and thus change the set;,oint of the dif ferential pressure switch.
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IEB 86-02 July 18, 1986 Page 4 of 9 4
The case contains two ports on either side of the piston or diaphragm. The lower port on one side is connected to the system reference leg, and the lower port on the o^her side is connected to the lower instrument tap (i.e. variable leg). The upper ports on both sides are used as vents and are plugged when the switch is in service.
The design of the cavity containing the diaphragm (or piston) is such that motion of the diaphragm is limited to 0.015 inch. Most of the time, the diaphragm is against one or the other of the mechanical stops which limit motion of the diaphragm. Thus the sum of the unbalanced hydraulic forces across the diaphragm is supported by one stop or the other except when the microswitch is forced to change position. This occurs when the absolute value of the torque caused by the unbalanced hydraulic. forces changes from a value less than to a value greater than the torque caused by the helical spring.
This movement causes the cross shaft and the levers to rotate 1.8 degrees.
PROBLEM AREAS Differential pressure switches are often calibrated in situ after isolating them from the reactor system.
A test rig consisting essentially of two bottles each l
containing water and air or nitrogen are connected to the differential pressure switch with one bottle on either side of the diaphragm. The differential pressure for calibration is established by adjusting the gas pressures in the bottles.
Often,- the lower pressure is at or near atmospheric pressure.
When the'50R Model 103 differential pressure switch is calibrated to a setpoint at atmospheric pressure and then connected to a system operating at a static pressure of about 1000 psig, the actual setpoint shifts in most cases in the conservative direction toward less differential pressure required to trip.
In other cases, the offset of setpoint due to calibration at atmospheric pressure i,
has been found to be in the opposite direction. The manufacturer has stated that each switch has unique characteristics and that switches with the same model number do not all behave in the same way.
It has been postulated that this may be caused by deformation or movement of the 0-rings on the cross shaft when system pressure is applied.
For water level applications and depending on the location of the lower instrument tap relative to the required setpoint, offset may be so large that the switch will not actuate before the level drops below the tap.
In this case, the switch would not actuate no matter how low the level dropped.
The vendor has indicated to the staff that factory tests showed an offset between behavior at atmospheric pressure and behavior at system pressure and that this information is provided to all customers.
It has been the practice at LaSalle to calibrate at atmospheric pressure without compensating for errors due to static pressure effects.
For minimum flow applications where it is necessary to open a valve in a recirculation line to protect a pump in an emergency core cooling system, assurance is needed that offset will not delay that action and result in pump damage.
Testing of Series 103 differential pressure switches at LaSalle showed that application of a static pressure to the switch for a period of time also i
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IEB 86-02 July 18, 1986 Page 5 of 9 resulted in a significant shift in the setpoint of the switch, and that the shift due to prolonged pressure was generally in the opposite direction from the shift due to the initial application of static pressure. After being cali-brated at atmospheric pressure, a static pressure of 1000 psig was maintained.
A recheck of the setpoint of one switch at the end of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> showed that the setpoint had shifted by a net amount that was nonconservative by about 10 inches.
Subsequent rechecks continued to show shifting but in lesser amounts. To be 4
valid, it appears that calibration and tests would need to be rechecked after static pressure has been maintained for at least 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
Recent testing at LaSalle has also shown that the' point at which trip occurs depends on whether the switch setpoint is being approached from low differen-
- tial pressure or high differential pressure.
This is particularly important for automated blocking valves in the recirculation lines which protect emer-gency core cooling pumps from damage when system flow is low. When flow decreases to a value below the setpoint, the switches should actuate to open the valves.
Conversely, when flow increases, the switches should deactuate to provide maximum flow to the core.
4 In addition to showing offset problems, some of the Series 103 switches evidence sticky behavior, i.e. a larger change in differential pressure is required to actuate the switch on the first demand than on subsequent operations and on subsequent tests actuation may be erratic.
It is believed that starting fric-tion and the condition of the cross shaft surfaces may ca0se these problems.
If the 0-rings stick, then the torque that they apply is added to the' torque applied by the calibration spring.
SOR is conducting a long range test with switches that have more highly polished finishes on those parts of the cross shafts that are in contact with 0-rings.
It has been common practice at LaSalle to actuate the switches,several times and then to record the differential pressures required for the third or fourth actuation.
It appears that the Licensee has not emphasized that the "as-found" condition of the switch is the value of differential pressure required to actuate the switch during the first demand.
It is this value that must be used to determine whether the switch and its system would have performed their intended functions if called upon to do so.
The life of Series 103 switches has been said to be 20 to 40 years.
- However, the shelf life of the elastomeric material used in the 0-rings is considerably less than 40 years. The 0-rings may need to be changed several times during the life of the plant.
Further, there is some concern for the effect of reactor water on the 0-rings, cross shaft surfaces bearing on the 0-rings, and on the diaphragm material, and possible corrosion of the cross shaft bearings.
OBJECTIVES OF REQUIRED ACTIONS l
General Design Criterion 21 " Protection System Reliability and Testability" requires that the protection system be highly reliable.
It is clear that the l
SOR differential pressure switches that have been tested carefully to date have not performed reliably.
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IEB 86-02 July 18, 1986 Page 6 of 9 A significant uncertainty exists as to where SOR differential pressure switches are currently installed or planned to be installed.
A list provided by SOR, Inc. included one utility that had ordered the switches but later decided not to install the switches. The NRC later learned that another utility that was not on the 50R list had installed SOR switches.
It is impor-tant to assessing the safety impact to know with certainty which plants have SOR switches installed and in what plant systems.
Since these switches were installed predominately as environmentally qualified electrical equipment important to safety, as described in 10 CFR 50.49(b), this Bulletin requests all licensees to identify each such installation. The NRC intends to evaluate this information, in combination with the results of other actions required by this Bulletin, to determine if further actions should be required.
Licensees, who have SOR switches installed, are requested to determine which of those switches are installed in systems which are subject to Limiting Conditions for Operations of the plant Technical Specifications.
For SOR differential switches that are not in systems subject to Technical Specifica-tions, licensees are expected to review the information in this Bulletin and consider actions, if appropriate, to preclude problems similar to those discussed in this Bulletin from occurring.
For SOR differential pressure switches that are installed in systems subject to Technical Specifications, the Bulletin requests licensees to take certain actions to assure that these switches and systems will be capable of performing acceptably, if called upon during an actual plant transient or accident.
1 First, each licensed reactor operator (and senior reactor operator) on duty should be trade aware of the potential problem that may occur at his/her plant.
This information should include a knowledge of the incident at LaSalle, where SOR differential pressure switches are installed in his/her plant, how to detect a malfunction or failure of any of these switches, and the remedial actions that he/she should be prepared to take if a malfunction were to occur.
Second, the Bulletin requests licensees to conduct special operability tests of each system that is subject to Technical Specifications that involve 50R differential pressure switches.
Special tests are necessary to determine the actual trippoint of the switches and the operability of the systems since tests of the type typically conducted may not be adequate to reveal the type of problems that have been revealed at the LaSalle station.
l It is important that the tests simulate the conditions of the operation of the system.
Further, the test results from LaSalle suggest that the system i
operating conditions should be maintained for at least 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> before attemp-ting to measure the performance of the 50R switches.
For those systems that are not testable during plant power operations, it is anticipated that licensees will use test rigs in order to to simulate operating conditions and not impact plant operations.
It is also expected that licensees may take credit for the 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> that the switch was at system operating conditions prior to connecting the test rig, in order to minimize the time the switch / system is bypassed or tripped.
If the test rig can be connected to the switch so as to make a virtually "bumpless" transfer from the system to the test rig without
IEB 86-02 July 18, 1986 Page 7 of 9 tripping the switch, such credit may be appropriate.
A primary objective of the special tests is to determine how the switch will respond to its first demand after being at system op2 rating conditions for a period of time.
Special care may be necessary to assure that the first actuation is measured.
If one channel of a system of redundant channels (or similar equipment in redundant safety systems) is found to have an actual trippoint that is outside the Technical Specifications or otherwise unacceptable for adequately reliable system operation, then the redundant channels (or similar equipment) should be tested as soon thereafter as practical.
The short term corrective actions to be taken to return the set of channels to operable status should be based on an analysis that conservatively considers the performance of the set of redundant channels (or similar equipment).
In view of the generic safety concerns and the possibility of common mode failures, unacceptable performance of an SOR differential pressure switch should be reported to the NRC in accordance with 10 CFR 50.72 and 10 CFR 50.73.
Since the conduct of any special test could have potential adverse affects, the requirements for followup tests to verify continuing proper functioning of the switches and systems have been minimized to the extent possible consistent with the safety objective. The Bulletin requests that licensees propose an interim performance monitoring program that would cover the time between the special tests and full implementation of long term corrective actions. The objectives of the program are to detect any instance of unacceptable perfor-mance, to provide for timely initiation of additional corrective action, and to gather additional switch performance data.
The Bulletin requests licensees to determine what long term corrective actions may be appropriate and will be taken.
Part of this determination would include considering the potential effects of common mode failures.
This determination should be based upon an analysis using the worst observed shift of the actual trippoint from the calibration setpoint for SOR switches in each general type of application, e.g., water level measurement or main steam flow measurement.
The purpose of the analysis is to determine if improvements in calibration and j
testing methods, imprw oments in setpoint methodology, additional safety analysis to establish a revised licensing basis for the plant, change in the Technical Specifications, repair, modifications, or replacement, or other improvements are needed in order to meet existing regulatory requirements (e.g., General Design Criterion 21 or plant technical specifications).
The analysis should demonstrate that the long term corrective action will provide an adequate margin for safety so as to assure high functional reliability.
Actions Required of All Licensees:
1.
Within 7 days, submit a report on the extent to which SOR Model 102 or 103 differential pressure switches are installed (or planned) as electrical equipment important to safety, as defined in 10 CFR 50.49(b).
Include in the report:
the model number of the switch, the system in which it is ic talled (e.g., low pressure safety injection), the application of the J
switch (e.g., water level measurement, system flow measurement), and the I
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IEB 86-02 July 18, 1986 Page 8 of 9 function of the switch (e.g., control of minimum flow recirculation valve).
A negative report, if appropriate, is required.
Actions Required of Licensees That Have SOR Model 102 or 103 Differential Pressure Switches Installed in Systems That Are Subject to Limiting Conditions for Operation in Technical Specifications:
2.
Within 7 days, take positive action to assure that licensed reactor operators on duty are prepared for potential malfunctions of SOR switches.
3.
Within 30 days, conduct a special test of each SOR swit:h ta determine if the switch and system function properly or if short term corrective actions are necessary. The tests are to determine if the switches / systems will respond acceptably on the first demand after being at system operating conditions for a period of time.
The tests should be planned and conducted so as to miriimize any potential adverse affects of the testing.
If any corrective action includes the replacement of SOR switches with mechanical differential pressure switches by another manufacturer, the licensee should submit a technical justification, including a reliability demonstration.
Repeat the special tests on a monthly basis until two consecutive successful tests are attained.
4.
Report failures in accordance with 10 CFR 50.72 and 10 CFR 50.73.
5.
Within 60 days, develop, implement and submit a written report describing your interim performance monitoring program to provide continuing assurance that the performance of the switches and plant systems remains acceptably reliable until long term corrective actions are fully implemented.
6.
Within 60 days, submit a written report which describes the margin and basis for switch actuation. The report should also describe the long term corrective actions to be taken, including the implementation schedule, the impacts of potential common mode failures, and an analysis to demonstrate that the system involved will meet regulatory requirements and function reliably.
The report should include specific information.on the installed SOR switches:
the manufacturer's specified range for the switch, the nominal and allowable values for the calibration setpoint in the Technical Specifications in the same terms as the manufacturer's specified range for the switch, the relative locations of the instrument taps for water level monitoring applications, sources of systematic errors such as the differences in elevations of the installation of condensing pots, and "as found" and any subsequent test data for any switch that does not conform to the Technical Specifications or is otherwise unacceptable.
Recipients of this Bulletin who hold construction permits and licensees of plants that are shutdown for an extended period (e.g., Browns Ferry) are not required to complete the actions of this Bulletin on the schedule shown.
In each case, compliance with this Bulletin should be addressed prior to the next critical operation of the plant or within 1 year, whichever occurs first.
IEB 86-02 July 18, 1986 Page 9 of 9 If, because of plant unique conditions, a licensee should determine that any action requested by this Bulletin jeopardizes plant safety, the action should not be initiated and the NRC should be notified as soon as practical.
This notification should include the basis for the determination.
Further, if a licensee determines that,.even with "best efforts," an action requested by this Bulletin can not reasonably be completed within the prescribed schedule, the NRC should be notified within 7 days of receipt of the Bulletin.
The written reports shall be submitted to the appropriate Regional Administrator under oath or affirmation under the provisions of Section 182a of the Atomic Energy Act of 1954, as amended. Also, the original copy of the cover letters and a copy of the reports shall be transmitted to the U.S. Nuclear Regulatory Commission, Document Control Desk, Washington, DC, 20555 for reproduction and distribution.
The request for information.was approved by the Office of Management and Budget under blanket clearance number 3150-0012.
Comments on burden and duplication may be directed to the Office of Management and Budget, Reports Management, Room 3208, New Executive Office Building, Washington, DC, 20503.
If you have any questions regarding this matter, please contact the Regional Administrator of the appropriate NRC Regional Office or one of the technical contacts listed below.
r es M. Tay1
, Director fice of In ection and Enforcement Attachments:
1.
Plants with Similar S0R Switches 2.
List of Recently IE Bulletins Technical Contacts:
J. T. Beard, NRR (301) 492-4415 Roger W. Woodruff, IE (301) 492-7205
e_
Atttchment 1 IEB 86-02 July 18, 1986 PLANTS WITH SERIES 102 OR 103 DIFFERENTIAL PRESSURE SWITCHES.
Series 102:
Florida Power and Light Series 103:
Commonwealth Edison General.Public Utilities - Nuclear Corporation Houston Lighting & Power Company Northeast Utilities Pennsylvania Power & Light Southern California Edison Tennessee Valley Autho.rity Washington Public Power Supply System I
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Attichment 2 IEB 86-02 July 18, 1986 LIST 0F RECENTLY ISSUED IE BULLETINS Bulletin Date of No.
Subject Issue Issued to 86-01 Minimum Flow Logic Problems 5/23/86 All GE BWR facilities That Could Disable RHR Pumps holding an OL or CP 85-03 Motor-Operated Valve Common 11/15/85 All power reactor Mode Failures During Plant facilities holding Transients Due To Improper an OL or CP for Switch Settings action 85-02 Undervoltage Trip 11/5/85 All power reactor Attachments Of Westinghouse licensees and 08-50 Type Reactor Trip applicants Breakers 85-01 Steam Binding Of Auxiliary 10/29/85 Nuclear power facil-Feedwater Pumps ities and cps listed in attachment 1 for action; all other nuclear power facil-ities for information 84-03 Refueling Cavity Water Seal 9/24/84 All power reactor facilities holding g
an OL or CP except Ft. St. Vrain 84-02 Failures Of General Electirc 3/12/84 All power reactor i
Type HFA Relays In Use In facilities holding Class 1E Safety Systems an OL or CP 84-01
' Cracks In Boiling Water 2/3/84 All BWR facilities Reactor Mark I Containment with Mark I contain-Vent Headers ment and currently in cold shutdown with an OL for action and all other BWRs with an OL or CP for information OL = Operating License CP = Construction Permit