ML20209J247
| ML20209J247 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 09/08/1986 |
| From: | Allen C COMMONWEALTH EDISON CO. |
| To: | Harold Denton Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML20209J253 | List: |
| References | |
| 2053K, 4114I, NUDOCS 8609160241 | |
| Download: ML20209J247 (13) | |
Text
-
I i
.N4, h
'Ii n ) One Firm Nabonel Maza. Chcago, IEnois N
Address Reply to: Post Omco Box 767
(
Chca00,15nois 80000 - 0767 i
(,*
September 8, 1986 i
l' J
t i
kl
/
- I
- l, Mr. Harold R. Denton i
U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation Washington, DC.
20555
,f 1
i i,
Subject:
LaSalle County Station Unit 1 Information Regarding "SOR" Differential Pressure Switches NRC Docket No. 50-3~13 I
Reference (a): Letter dated August 29, 1986 from C.M. Allen to H.R. Denton regarding LaSalle Unit 1 SOR Switches.
<l!.
~
w r g
Dear Mr. Denton:
\\
In a telecon with your staff on September 5, 1986, Commonwealth Edison was asked to amplify information provided in Reference (a) concerning the SOR differential pressure switches installed in LaSalle County Station Unit 1 to allow the staff to complete a safety analysis review for Unit 1 startup. The information regt:ested in that telecon, itemized;below, 'is
/
provided in the enclosure to this letter. This document supercedes.
'/
Reference (a) in its entirety.
i[ <,'
Commitment to do an operating pressure level drop tese'during i
a planned S/D following 90 days of operation of Unit 6 (other conditions permitting).
s Commitment to follow same calibration program for-Unit (1' level 3 switches as was performed on Unit 2 level 3 sshches. : j
.i
<,.g Explain difference in setpoints for Main Stear,High Flow between f
Units 1 and 2.
[
Perform the equivalent of a 500# 1evel drop test and provide data to NRR. This data will be provided by separate cover.
f Discuss actions to be taken if a switch exceeds its reject / limit or fails in service.
8609160241 860908 8
DR ADOCK 00000373
'l}
1 PDR
\\
,4 Mr. H. R. Denton September 8, 1986 4
E l
provide brief overview of alternative options being considered by Commonwealth Edison to replace series 102 and 103 differential l
pressure switches.
s In addition, your staff requested a revised response to IEB 86-02 updating the information provided in our supplemental response dated August 29, 1986 (Peference (a)). This response will be provided under separate cover to Region III in addition to the enclosure provided with this lette:.
i please direct any additional questions you may have regarding this i
matter to this office.
'p Very truly yours, u
5 C. M. Allen
/
Nuclear Licensing Administrator 4
1m 3
Enclosure cc:.R. Bernero - NRR
'Dr.' A. Bournia - MRR G. Wright - RIII t
Resident Inspector - LSCS l
I o
2053K
MXECUTIVE SUfflARY A.
PURPOSE The purpose of this sununary is to provide information concerning the ".4R, Inc., differential pressure switches installed in LaSalle County Station Unit 1 and to describe the actions that have been taken to ensure these switches operate reliably and operate within technical specification limits.
B.
BACKGROUND SOR series 102 and 103 differential pressure switches were installed in LaSalle County Station Unit 1 during the first quarter of 1985 and the first two quarters of 1986 as part of environmental qualification modifications. A total of 58 switches are installed in Unit 1.
These switches are used to actuate various safety system functions including the reactor protection system, emergency core cooling system, and primary containment isolation system. The attached Table 1 lists the system
)
application and function for each SOR switch.
On June 1, 1986, LaSalle 2 experienced a feedwater transient that resulted in low water level in the reactor vessel (see Figure 1 for illustration of water levels). 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 raised concerns that the level apparently had gone below the scram setpoint and the reactor scram system did not actuate. This event is described in more detail in reference 1.
After recalibrating the reactor protection system low level (level 3) switches, switch performance was tested by lowering the water level in the reactor (level drop test) and reading levels indicated on Icvel l
transmitters when each of the four level 3 switches tripped. At 950 psig reactor pressure, the switches tripped at levels between 3.9 inches and 10.8 inches. At 0 psig reactor pressure, the switches tripped at levels between 10.7 inches and 13.5 inches. These measurements are relative to instrument zero, which is 161.5 inches above the top of active fuel. The Technical Specifications established the allowable trip point for level 3 at 11 inches above instrument zero.
Testing of other SOR Model 102 and 103 differential pressure switches on Unit 2 used to actuate the emergency core cooling system, primary I
containment isolation system, and other engineered safety feature systems revealed that these switches displayed the same type of behavior as the switches used for reactor protection system level 3.
DOCUMENT ID 41141/
C.
SPECIAL TESTS AND SETPOINT REVISIONS The initial investigation to determine the source of the variability in SOR differential pressure switches setpoint concluded that additional special testing was required to quantify the setpoint variability. These setpoint characterization tests measured the shift in setpoint due to the differences in static pressure between calibration and operation, the effects of cycling the switch during calibration, and the random repeatability of the switch setpoint. These tests were performed on a special test rig that allowed simultaneous testing at operating static pressure and the specified differential pressure setpoint. This Unit 2 testing program was described in detail in reference 2.
J During the Unit 2 testing program, enough was learned about the behavior of the switches to develop a more refined calibration methodology that minimizes the offset from the last calibration "as-left" setting to the next first-actuation trip. This methodology requires that each time the switch is cycled to obtain trip and reset values, the applied calibration differential pressure should first be reduced to zero (for switches with increasing trip points) or 100% of adjustable range (for switches with decreasing trip points). This form of cycling is more representative of actual process operation, and results in the highest expected trip values for the switch at any given setting. This method of calibration was used in the Unit 1 test program to put each switch into a known starting condition prior to the characterizatior, testing on the special test rig.
The Unit 1 test program consisted of performing a static pressure cycling test (to determine repeatability) on all installed switches, and a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> static pressure " soak" test performed on all switches, except for five of the eight ECCS minimum flow switches.
(The five switches were not " soak" tested because the setpoint chosen for the function served by those switches was very conservative with respect to the measured static shift found on the three identical switches that were tested for this function.) The results of the tests for setpoint shift with static pressure and setpoint repeatability measured in the Unit 1 test program ara presented in Table 2.
The effects of cycling were confirmed and have resulted in revised calibration procedures.
Information justifying the validity of 24-hour test results was submitted to the NRC by references 3 and 4.
DOCUMENT ID 41141/
C.
SPECIAL TESTS AND SETPOINT REVISIONS (Continued) on the basis of the setpoint characterization tests described in the preceeding paragraphs, setpoints of the LaSalle County Station Unit 1 SOR differential pressure switches have been revised to provide additional margin for static pressure shift and repeatability. The revised setpoints and margins are listed in attached Table 3.
These revisions will increase the margin between the existing Technical Specification allowable limit and the calibration setpoint; therefore Technical Specification changes are not necessary at this time. Note that for LaSalle Unit 1, 100% of the Reactor Level, Main Steam Line Break, and RHR/RCIC line break switches were tested and static offset and repeatability values were determined. This allows a less conservative setting of the switches than the Unit 2 bounding margins (which were used in Table 3) allowed. The availability of complete test data shows that in some cases that the worst-case measured static pressure offset was much smaller than the bounding value. The setpoint values shown in the table reflect the Unit 2 values with the exception of the setpoint for Main Steam Line Hi Flow. These setpoints may be changed in the future to take advantage of the more complete test data.
D.
CONCLUSIONS The setpoint variability of the SOR differential pressure switches installed in l'aSalle County Station Unit I has been fully characterized and will be incorporated into new setpoints. In addition to the margins and bases for switch actuation included in the revised setpoints shown in attached Table 3, corrective actions listed in attached Table 4 will be completed. These actions ensure the SOR differential pressure switches will perform within Technical Specification limits with high reliability.
E.
REFEPENCES Reference 1 - Letter to J.G. Keppler from C. Reed, dated July 1, 1986.
Reference 2 - Letter to H.R. Denton from C.M. Allen, dated August 8, 1986.
Reference 3 - Letter to H.R. Denton from M.S. Turbak, dated July 21, 1986.
Reference 4 - Letter to H.R. Denton from M.S. Turbak, dated July 23, 1986.
Reference 5 (Attached) - Letter to J. G. Keppler from I. M. Johnson containing revised response to I.E.Bulletin 86-02, dated September 5, 1986.
l 5
DOCUMENT ID 41141/
TABLE 1 LASALLE COUNTY UNIT 1 LIST OF INSTALLED SOR DP SWITCHE_S Tag Number Service Range Setpoint Model Number B21-N024A,B,C,D Rx. Level 3 7"-100" W.C.
63.78" W.C. 103-B212 B21-N031A,B,C,D Rx. Level 2 20-200" W.C.
143.3" W.C. 103-B203 B21-NO37AB,BB Rx. Level 2 20-200" W.C.
145.5" W.C. 103-B203 CB,DB Rx. Level 2 20-200" W.C.
145.5" W.C.
103-B203 B21-N037AA,BA Rx. Level 1 40-300" W.C.
200" W.C.
103-BB205 CA,DA Rx. Level 1 40-300" W.C.
200" W.C.
103-BB205 E22-N006 HPCS Min. Flow 5-35" W.C.
18.1" W.C.
103-BB202 E21-N004 LPCS Min. Flow 5-35" W.C.
11.01" W.C.
103-B202 E12-N010AA RHR LPCI "A" Flow 5-35" W.C.
6.2" W.C.
103-B202 AB Alarm 5-35" W.C.
13.3" W.C.
103-B202 BA RHR LPCI "B" Flow 5-35" W.C.
6.2" W.C.
103-B202 BB Alarm 5-35" W.C.
13.3" W.C.
103-B202 CA RHR LPCI "C" Flow 5-35" W.C.
6.2" W.C.
103-B202 CB Alarm 5-35" W.C.
13.3" W.C.
103-B202 B21-NO38A,B Rx. Level 3 7-100" W.C.
63.14" W.C. 103-B212 B21-N026AB,BB Rx. Level 2 20-200 W.C.
143.3" W.C. 103-BB203 CB,DB Rx. Level 2 20-200 W.C.
143.3" W.C. 103-BB203 E31-N008A,B,C,D Main Steam Line Break 100-500 psid 111 psid 102-B305 E31-N009A,B,C,D Main Steam Line Break 100-500 psid 111 psid 102-B305 E31-N010A,B,C,D Main Steam Line Break 100-500 psid 111 psid 102-B305 E31-N011A,B,C,D Main Steam Line Break 100-500 psid 111 psid 102-B305 E31-N012AA,BA RHR Shutdown Cooling 20-200" W.C.
170" W.C.
103-B203 l
E31-N012AB,BB RHR Shutdown Cooling 20-200" W.C.
170" W.C.
103-B203 I
E31-N007AA,AB RCIC Steam Hi Flow 20-200" W.C.
117" W.C.
103-B203 E31-N007BA,BB RCIC Steam Hi l
Flow 20-200" W.C.
87" W.C.
103-B203 I
E31-N013AA,BA RCIC Steam Hi Flow 20-200" W.C.
170" W.C.
103-B203 E31-N013AB,BB RCIC Steam Hi Flow 20-200" W.C.
170" W.C.
103-B203 i
l l
(
DOCUMENT ID 41141/
l l
TABLE 2 SUpptARY OF SETPOINT CHARACTERIZATION TESTS RESULTS FOR UNIT 1 l 24-Hour Static l 24-Hour Static l Repeatability l l
i l Pressure Test l Pressure Shift l Test Sample l
l Switch Application I Saniple Size l
Results l
Size l Repeatability Results 1 l
l l
l l
l l
l l
l l
l
-l l
l l
-Reactor vessel Level 3 l
100%
l0.9"-5.4" W.C.(1)l 100%
l Less Than 2%
l l
(6 switches) l l (6 switches) l l
t
-Reactor Vessel Level 2 l
100%
l-0.9"-+5.0" W.C.
l 100%
l
_l l
l (12 switches) l l (12 switches)l Less Than 2%
l l
-Reactor Vessel Level 1 l
100%
l 2.9"-6.0" W.C.
l 100%
l l
1 l
(4 switches) l l (4 switches) l Less Than 2%
l
-RHR/RCIC Steamline Break ) l l
l l
l
) l l
l l
l l
-RHR Shutdown Cooling Line) l 100%
l-6.9"-+6.3"W.C.
l 100%
l 0.3% to 3.3% (2) l j
) l (12 switches) l l (12 switches)l l
-RCIC Steeni Line Break
) l l
l l
l i
l l
l l
l l
l l
l l
-RHR LPCI-A,B,C Min. Flow ) l l
l l
l
) l l
l l
l 4
l
-LPCS Min. Flow
) l 37.5%
l-2.08-+3.61"W.C. l 100%
l 0.5% to 11%
l l
) l (3. switches) l l (8 switches) l l
j
-HPCS Min. Flow
) l l
l l
l l
l l
l l
-Main Steant Line HI Flow l
100%
l-1.3-7.7 PSID l
100%
l 0.1% to 0.7%
l l
(16 switches) l l_(16 switches)l l
Notes:
(1) Switches exceeding 3.0" W.C. were replaced with switches 3.0" W.C. or less.
(2) Safety action switches with repeatability exceeding 2% of adjustable range will be replaced with switches with 2% or less.
1 i
DOCUMENT ID 41141/
4
_ ~ _ _ _ _ - _ -. _
~
TABLE 3 LASALLE COUNTY UNIT 1 SETpOINT CHARACTERIZATION TESTING CONCLUSIONS Switch Application l
Margin from LCO l
l proposed l
l (4)l Existing Tech l
l Existing l New (6) 1 Static Shift 1 Repeatability I
Spec. Drift l
Total l
L.C.O.
l Setpoint l
l l
l l
l
-Reactor vessel Level 3 l
4.2" RWL I
2.6" RWL l
1.5" RWL l
8.4" RWL l 11.0"RWL l19.4" RWL s
l l
l l
l 1
-Reactor Vessel Level 2 l
11.2" RWL 1
5.0" RWL 1
7.0" RWL l 23.2" RWL l-57.0" RWL l -33.8" RWL l
l l
l l
l j
-Reactor Vessel Level 1 l
11.2" RWL l
7.3" RWL I
7.0" RWL l 25.5" RWL l-136.0" RWLl-l10.5" RWL l
l l
l l
l l
-RHR/RCIC Steamline Break l
8.0" W.C.
l 3.6" W.C.
l 5.0" W.C.
l 16.6" W.C.
I 128" W.C. l111.4" W.C.
i i
l l
l l
l l
-RHR Shutdown Cooling Line l
8.0" W.C.
l 3.6" W.C.
I 6.0" W.C.
l 17.6" W.C.
I 186" W.C. l168.4" w.C.
i l
l l
l l
l
-RCIC Steam Line Break l 7.2% rated flow l 3.0% rated flow I 5.0% rated flow l 15.2% rated l295% rated l 280% rated l
l I
1 flow iflow l flow j
l
'l l
l l
l
-RHR LpCI-A,B,C Min. Flov l
268 gpm l
216 gpm I
450 gpm i
1423 gpm l 550 gpm l 1973 gpm 2
l l
l l
l l
l
-LPCS Min. Flow l
265 gpm 1
203 gpm l
110 gpm l
1079 gpm l 640 gpm l 1719 gpm 2
l l
l l
l l
l
-HpCS Min. Flow l
171 gpm l
146 gpm i
100 gpm l 640 gpm l 900 gpm i 1540 gpm 8
l l
l l
l l
-Main Steam Line HI Flow l
8.0 psid (5) l 5.4 psid (5) l 5.0 psid l 18.4 psid (5)l 116 psid I 97.6 psid (5) l l
l l
l l
l NOTES:
Includes Additional Margin of 1) 489 gpm for LpCI
- 2) 501 gpm for LPCS and 3) 223 gpm for HpCS
.l 4)
For applications other than main steam line high flow and ECCS minimum flow, repeatability for each switch l
tested was less than 2% of range-therefore 2% was used for repeatability.
For mainsteam line high flow switches and ECCS minimum flow, repeatability of the most variable switch in service was used. Repeatability l Wds CdlCuldted for each switch to bound 95% of the population with a 95% confidence level.
5)
It is planned to improve these values in the future by replacement of the worst performing switches with switches that have better repeatability and static offset performance.
)
6)
Since 100% of the switches were tested on Unit 1, the static offset and repeatabilities are known for every switch. This allows a knowledgeable setting of the switch which is not dependent on a bounding margin established for Unit 2 switches. The values shown in this column represent initial Unit I setpoints based on Unit 2 setpoints, with the exception of the setpoint for Main Steam Line Hi Flow switches. These setpoints l
4 may be changed in the future to take advantage of.the more complete test data.
DOCUMENT ID 41141/
i TABLE 4 LaSalle County Unit 1 CORRECTIVE ACTIONS 1.
Final LaSalle County Station Unit 1 This Executive SOR Investigation Report Summary dated 9/5/86 2.
Unit 1 Flow testing to verify ECCS Prior to startup minimum flow switch setpoints 3.
A reactor vessel level drop test will be 0.0 PSIG test prior performed at 0.0 psig in order to verify to startup following system operability. The results of the current outage, 950 950 psig level drop testing on Unit 2 psig test greater was successful in proving that operability than 3 months after of the scram function may be relied upon by startup, and at adjusting the switch setpoints to take into shutdown for the account the results found in the SOR set-second refueling point characterization program. Additional outage.
thermal cycles, pressure tests and other challenges to the Unit 1 safety system equipment are not technically justified.
When plant conditions permit, a level drop test will be performed at approximately 950 psig.
during the first planned shutdown greater than 3 months after startup.
4.
Complete calibration procedure revisions Week of 8-25-86
- a. New setpoints including: static pressure shift, repeatability margin and drift margin.
- b. New calibration methods including: The "as-found" setpoint will be the first actuation and during calibration the switch will be cycled from the appropriate 0% or 100% of differential pressure i
span to the setpoint.
- c. "As-found" setpoint acceptance limits will be lacluded into the procedures, and actions will be defined for each I
limit. The limits and actions will be the following:
(1) Action Limit (a)
Except Main Steam Line High Flow and ECCS minimum flow, 1 3% of adjustable range from new calibration setpoint.
,I (b)
For main steam line high flow g
and ECCS minimum flow, this limit was 1.5X repeatability of i
the most variable switch in service.
Repeatability was calculated for each switch to bound 95% of the
(
population with a 95% confidence level.
DOCUMENT ID 41141/
l TABLE 4 (cont.)
LaSalle County Unit 1 4.
Complete calibration procedure revisions (cont.)
- c. "As-found" setpoint acceptance limits (cont.)
i (1) Action Limit (continued)
(c)
If this limit is exceeded, the next surveillance will be performed at the same interval as the last successful surveillance within this limit.
(d)
If this limit is exceeded during the second consecutive surveillance, the switch will be scheduled for replacement within 14 days.
(2) Rejection Limit (a) i (2% of adjustable range + tech.
spec. margin for drift)
(b)
For main steam line high flow and ECCS minimum flow switches l
this limit is (repeatability + tech.
spec. drift) for the most variable switch in service. Repeatability was calculated for each switch to 95% of the population with a 95%
confidence level.
(c)
If this limit is exceeded the switch will be rejected, and appropriate actions will be taken in accordance with the LaSalle County Technical Specification.
5.
Complete recalibration of switches with revised setpoints and revised procedures.
prior to startup from current outage.
l 6.
Implement increased Surveillance After startup I
from current outage.
I
- a. The level 3 switches will be calibrated 2 weeks after startup, 4 weeks after startup, 2 months after startup and 4 months after startup. After the fourth month, the level 3 switches will remain on a quarterly frequency. Note that this schedule assumes no problems occur with the limits as described above, i
i l
l DOCUMENT ID 41141/
\\
TABLE 4 (cont.)
LaSalle County Unit 1
- b. Main Steam Line Break Switches (16 switches)
- At least four of the main steam line (MSL) switches will be calibrated 4 weeks after startup. Of the remaining 12 switches, at least four of the MSL switches will be calibrated 8 weeks after startup. Of the remaining eight switches, at least four of the MSL switches will be calibrated 12 weeks after startup. The maximum interval for each individual switch will be limited to a quarterly frequency.
- c. Remaining switches (36 switches) - A sample (grouped by model numbers) representative of the remaining switches (approximately 1/3) will be calibrated 4 weeks after startup. Of the remaining switches, approximately 1/3 will be calibrated 2 months after startup.
The remaining switches will be calibrated 3 months after startup. The maximum interval for each individual switch will be limited to a quarterly frequency. The representative samples will be chosen, where possible, to include a sampling of various switch model numbers.
- d. Switches placed in service that exceed the reject limit of this surveillance program will be sent to SOR for disassembly and inspection for cause of failure if the switch can be decontaminated and the cause of the failure if not obvious.
7.
Complete evaluation of alternative level sensing instruments to replace SOR l-1-87
- a. Review requirements
- b. Review vendor environmental qualification data.
- c. Review vendor performance test data,
- d. Recommend technically acceptable alternatives.
- e. Complete preliminary conceptual design and obtain reviews and approval. General description of key features affecting design installaticn, operation and maintenance, and project plan,
- f. Initiate detailed conceptual design.
I f
TABL8_4 (cont.)
LaSalle County Unit 1 The alternative options being considered at this time include:
- a. Installation of improved design SOR differential pressure switches.
- b. Replacement of switches with analog transmitter /
trip units
- 1) Partial replacement -- only some applications-
- 2) Complete replacement -- all applications If other viable alternatives become available, they will be considered also.
8.
Establish acceptance limits for new SOR Completed switches. The Purchase Order with SOR will i
be revised to require tests similar to setpoint characterization tests including a 24-hour test and to require switches 4
perform within the static shift and repeatability limits.
i
)
l I
l DOCUMENT ID 41141/
Reactor Water Levels Figure 1-1 1
800 750 745 - Vesset tlange Level 8 55.5 inches above instrument zero RCIC turbine tnp HPCS injection valve Close 700 Reactor feed pump f rip Main turbine trip g
40.5 inches above instrument zero 7648-Mam steam hne Hig& level alann 36.0 inches above instrument zero Normal reactor level 600 31 f
.5 inches above instrument zero
- 587.
583(8) 4 Low /evet a: arm C
568(7)
Recirculation flow runbacn permisse.e
= 5 59(4)
Bottom of steam 550
- 540(3)
- Level 3 12.5 inches above instrument zero dryer skirt Reactor scram
$27.5 am-se instrument zero 9 PCIS groups 6 and 7 g
500 ADS low-level confirmation Feedwater 493.25 Recirculation pumps transfer to slow speed
-479.25-Core spray 477.5(2)
- Level 2 50 0 inches below instrument zero PCIS groups 1 2. 3 4 and 5 450 HPCS initiation HPCS diesel generator sta'ts I ini iation
- 416.
400 Recirculation pumps trip 397.5(1)
- Level 1 129.0 inches below instrument zero 377.5 Division 1 and 2 d esel generators start
= 366 LPCS initiation 350 LPCI initiat.cn ADS initiation
- -Level C 211.5 inches below instrum-nt zero 300 Two-thirds core neight Active fuel 250 u
- 216 200 g
=181 - Recire, discharge %
A nozzle Recire. suction 172.5 nozzle 150 100 50 Vessel zero 0-6959. t ?
Scale in inches above vessel zero-0 -ef-F 1-10
--w yv-,-m
.m
t m
v
m
-