05000354/LER-1995-033, :on 951114,TS Surveillance Requirements 4.8.3.1 & 4.8.3.2 Not Completed Fullfilled Due to Surveillance Test Inadequacies.Surveillance Procedures Revised & Surveillances Successfully Performed
| ML20135F314 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 12/09/1996 |
| From: | Bezilla M, Karrick J Public Service Enterprise Group |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| LER-95-033, LER-95-33, LR-N96409, NUDOCS 9612120493 | |
| Download: ML20135F314 (30) | |
| Event date: | |
|---|---|
| Report date: | |
| Reporting criterion: | 10 CFR 50.73(a)(2)(1) 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications |
| 3541995033R00 - NRC Website | |
text
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KO PSEG Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, New Jersey 08038-0236 Nuclear Business Unit DEC 06 E06 LR-N96409 U.S. Nuclear Regulatory Commission Document Control Desk Washington, DC 20555
Dear Sir:
HOPE CREEK GENERATING STATION DOCKET NO. 50-354 UNIT NO. 1 LICENSEE EVENT REPORT NO. 95-033-13 This Licensee Event Report supplement entitled " Technical Specification Surveillance Requirement Impl3 mentation Deficiencies" is being submitted pursuant to the requirements of 10CFR50. 73 (a) (2) (1) (B).
This supplement documents the discovery of a Technical Specification surveillance implementation deficiency identified by the Technical Specification Surveillance Improvement Program (TSSIP).
As stated in LER 354/95-033-01, additional Technical Specification surveillance implementation deficiencies discovered by TSSIP with minimal safety significance will be documented in supplements to thiu LER until completion of the TSSIP project.
Sincerely,
);f y
Mark Bezilla General Manager, Hope Creek Operations t
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4 DEC 06 B96.
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l Document Control Desk LR-N96409 Attachment A i
There are no new commitments included in this correspondence.
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i Technical Specification Surveillance Requirement implementation Deficiencies i
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John Karrick, Hope Creek LER Coordinator (609) 339-5298 i
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COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT (13) causs sysTEhe CotApoNENT hAANUFACTURM AoM CAUeE Sv8 TEM COMPONENT RfANUPACTURM AeLE D
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ABSTRACT (Umit to 1400 spaces, i.e., approximately 16 eingle-spaced typewritten lines) (14) 4 i
i LER 95-033-00 described two events that occurred due to identification of a i
Technical Specification (TS) surveillance test inadequacy.
On 11/14/95, J
the Technical Specification Surveillance Improvement Program (TSSIP) team datermined that the undervoltage auxiliary relays were not adequately tested in accordance with the LOGIC SYSTEM FUNCTIONAL TEST (LSFT) requirements.
As j
stated in LER 95-033-01, supplements would be transmitted to document j
additional findings of the TSSIP team.
2 i
)
On 11/8/96, the TSSIP team identified to Operations personnel that the j
Surveillance Requirements of TS 4.8.3.1 and 4.8.3.2 had not been completely j
fulfilled. These surveillance requirements direct that specific power j
j.
distribution system channels be determined to be energized at least once l
I par 7 days by verifying correct breaker / switch alignment and voltage on the busses /MCCs/ panels.
Although'the applicable surveillance procedure did varify the correct breaker / switch alignment, it did not verify voltage on j
all of the specified busses /MCCs/ panels. Corrective actions included i
revising the surveillance procedure and successfully performing the i
surveillance.
There was no safety significance associated with this l
dnficiency.-
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,1CFORJ3XA U.S. NUCLEAR REauLATCRY COMMIS813N wes LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION j
FACILITY NAME fil DOCKET NUMBER (2)
LER NUMBER I Si pAGE(3) l "m*"e".m" M
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H::pe Creek Generating Station 05000354 95 -- 33 13 2 OF 28 I
i TEXT #f mero opeos is required, use additional copies of NRC Form 368Al (17) l l
PLANT AMD SYSTEM IDENTIFICATION G2neral Electric - Boiling Water Reactor (BWR/4) i I
l Safety Auxiliaries Cooling System (SACS) - EIIS Identifier {CC}
l Reactor Water Cleanup System (RWCU)
EIIS Identifier {CE}
t l
4.16 KVAC - EIIS Identifier {EB) i Emergency Diesel Generator - EIIS Identifier {EK, l
High Pressure Coolant Injection System - EIIS Identifier {BJ}
)
Average Power Range Monitor System - EIIS Identifier {IG)
{
Traversing Incore Probe - EIIS Identifier {IG}
Annunciator System - EIIS Identifier {IB}
Plant Protection System - EIIS Identifier {JC}
Containment Vacuum Relief System - EIIS Identifier {BF)
Low Voltage Power System - Class 1E - EIIS Identifier {ED}
i Low Voltage Power System (600V and less) - EIIS Identifier {EC}
Medium Voltage Power System - Class 1E - EIIS Identifier {EB}
Medium Voltage Power System (601V through 35KV) - EIIS Identifier {EA}
IDENTIFIchTION OF OCCURRENCE Discovery dates:
11/14/95, 12/12/95, 1/4/96, 2/26/96, 3/25/96, 3/29/96, 5/8/95, 5/10/96, 6/24/96, 6/25/96, 6/27/96, 7/8/96, 7/18/96, 7/19/96, 7/25/96, 7/26/96, 10/24/96, and 11/8/96.
l ESF actuation date: 11/16/95 Problem Reports:
951114174, 951116123, 951212158, 960104265, 960226156, 960322230, 960326238, 960430230, 960509086, 960624084, 960625200, 960627098, 960708161, 960719224, 960718069, 960718139, 960725055, 960726084, 961015124, 961024254, and 961107263.
CONDITIONS PRIOP. TO OCCURRENCE For the events in this LER the plant was in various operational conditions.
DESCRIPTION OF OCCURRENCE LER 95-033-00 described two events that occurred due to identification of a l
Technical Specification (TS) Surveillance Test inadequacy.
This supplement rewrites the original LER to describe an additional occurrence of a TS curveillance implementation deficiency identified during the Technical Specification Surveillance Improvement Program (TSSIP) review.
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CC FORlJ SSSA U.S. NUCLEAR RE4ULATCRY CtMMISSICN 14 es)
LICENSEE EVENT REPORT (LER)
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TEXT CONTINUATION
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FACILITY NAME (1)
DOCKET NUMSER (2)
LER NUMSER 18)
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H:rpe Creek Generating Station 05000354 95 -- 33 13 3
OF 28 1
l TEXT let mere spese le,equired, use edetional copies of NRC Form 3SSA) (17) i DESCRIPTION OF OCCURRENCE (Continued) i i
Undervoltage Relay Testing and ESF Actuation i
I On November 14, 1995, during the TSSIP review of TS 3.3.3,
" Emergency Core Cooling System Actuation Instrumentation", it was determined that the undervoltage auxiliary relays were not adequately tested in accordance with the IAGIC SYSTEM FUNCTIONAL TEST (LSFT) requirements of TS 4.3.3.2.
As a i
rasult, the vital bus undervoltage relays were declared inoperable, and the l
TS Action Statement was entered for the failure to perform the appropriate surveillance testing.
The surveillance test was revised to address the concerns that TSSIP identified.
On November 16, 1995, during.the performance of the revised surveillance on the
'A' 4 kV vital bus, a bus transfer occurred at 0521.
The
'A' Loss of Offsite Power (LOP) Sequencer initiated 4
per plant design.
A four-hour report was made to the NRC at 0841 in accordance with 10CFR50.72 (b) (2) (ii).
j RTD and T/C Channel Calibrations i
l On December 12, 1995, the TSSIP team determined that channel calibrations for the Reactor Water Cleanup System (RWCU) instrumentation, required by TS Table 3.3.2-1, were not being performed appropriately.
Specifically, the RWCU ambient temperature instrumentation and differential temperature instrumentation channel calibrations have not included a sensor calibration as specified in TS Definition 1.4, CHANNEL CALIBRATION.
The RWCU instrumentation was not required to be operable at the time of discovery of the deficient surveillances and no TS Actions were required to be taken.
However, this condition has existed since plant startup and TS Actions were not previously implemented as required by Table 3.3.2-1.
Therefore, this condition is being reported under the provisions of 10CFR50.73 (a) (2) (1) (B).
SACS Meat Exchanger Inlet valve surveillances On January 4, 1996, the TSSIP team determined that the Safety Auxiliaries Cooling System (SACS) heat exchanger inlet valves EG-HV-2491 A&B and EG-HV-2494 A&B have not been tested in accordance with the requirements of TS curveillance requirement 4.7.1.1.b.1.
This surveillance requirement cpecifies that at least once per 18 months, during shutdown, these valves actuate to their correct position on the appropriate test signal (i.e., a SACS pump start signal).
At 1719 hours0.0199 days <br />0.478 hours <br />0.00284 weeks <br />6.540795e-4 months <br /> on January 4, 1996, the SACS heat exchanger inlet valves were declared inoperable and administratively controlled to ensure performance of the valves safety function until they ware satisfactorily tested prior to leaving Operational Condition 4 (Cold Shutdown).
NRC FORM 3esA(4-96)
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TEXT CONTINUATION I
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DOCKET NUMSER (2) 1.ER NUMSER i S) pAGE13) k "E M Mi
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i H2pe Creek Generating Station 05000354 95 -- 33 13 4
OF 28 TEXT lif mere spoos is required, use additional copies of NRC Form 3SSA) (17)
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DESCRIPTIcti OF OCCURRENCE (Continued) j EPCI Valve Surveillances I
On February 26, 1996, the TSSIP team determined that several High Pressure
{
Coolant Injection (HPCI) system valves have not been periodically tested in accordance with TS surveillance requirement 4.5.1.c.2.b.
This surveillance i
requirement states that, "At least once per 18 months, verify that the cuction is automatically transferred from the condensate storage tank to j
the suppression chamber on a condensate storage' tank water level-low signal and on a suppression chamber-water level high signal."
Specifically, TSSIP dstermined that:
- 1) the HPCI system suppression pool suction valve (BJ-HV-l F042) has not been verified to open on a suppression chamber-water level j
high signal; 2) the HPCI system condensate storage tank (CST) suction valve (BJ-HV-F004) has not been verified to close on a suppression. chamber high
)
water level signal; and 3) the HPCI full flow test line valve (BJ-HV-F011) has not been verified to close on a suppression chamber high water level signal.
Since Hope Creek was in an Operational Condition where HPCI was j
not required to be operable, administrative controls were used until the 1
l valves were properly tested in accordance with the TS requirements prior to leaving Operational Condition 4 (Cold Shutdown).
4 Primary Containment Penetration Isolation Barrier Verification I
j On March 25, 1996, the TSSIP team determined that certain primary
{
containment penetration test and drain valves were not periodically i
verified to be closed in accordance with the requirements of TS 4.6.1.1.b.
l This surveillance requirement states that, "At least once per 31 days 1
(verify) that all primary containment penetrations not capable of being closed by OPERABLE containment automatic isolation valves and required to l
bs' closed during accident conditions are closed by valves...".
J i
Specifically, TSSIP determined that several test and drain valves were omitted 4
from the procedure that verifies primary containment integrity per TS 4.6.1.1.b.
l The valves were verified to be in their proper closed position and no additional j
TS actions were warranted.
The procedure that verifies primary containment integrity for TS 4.6.1.1.b was revised to incorporate the excluded valves.
4 4
l A review of all primary containment penetrations was completed on October 15, 1996 as a corrective action to the March 25, 1996_ event.
This review identified i
cpproximately 390 additional containment isolation valves, 14 hatches, and 4 blanked drain connections that had not been previously verified in accordance with TS 4.6.1.1.b.
At 1228 on October 15, 1996 the Primary Containment was drclared inoperable and the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> delayed action provision of TS 4.0.3 was l
cntered.
An immediate verification of these components was performed and none f
wsre found out of position or missing.
This verification was completed at 0229 i
on October 16, 1996 at which time the primary containment was declared operable and TS 4.0.3 was exited.
l NRC 2
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l NAC FORM 3SSA U.S. NUCLEAR REauLATCRY CEMMISSIEN I4-est i
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION FACILITY NAME fil DOCKET NUMBER (2)
LER NUMBER ' SI pAGE (3) as,ogmL g
vaan Hcpe Creek' Generating Station 05000354 95 -- 33 13 5
OF 28 TEXT lit more opeoe is required, use additional copies of NRC Form 3SSA) (17) pascRIPTION OF OCCURRENCE (Continued)
APRM Surveillances on March 29, 1996, the TSSIP team determined that the Average Power Range Monitoring (APRM) system has not been appropriately tested in accordance with the Reactor Protection System Instrumentation TS Table 4.3.1.1-1.2.a and the Control Rod Block Instrumentation TS Table 4.3.6-1.2.d.
l Surveillance requirement 4.3.1.1. states that, "Each reactor protection system instrumentation channel shall be demonstrated OPERABLE by the parformance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the Operational Conditions and at the frequencies show in Table 4.3.1.1-1."
TS Table 4.3.1.1-1.2.a requires that the APRM Upscale, Setdown function undergo a Channel Functional Test once par week and a Channel Calibration once every six months during operational l
CondMions 2 through 5 (STARTUP through REFUELING).
Surveillance i
requirement 4.3.6 states that, "Each of the... control rod block trip systems and instrumentation channels shall be demonstrated OPERABLE by the parformance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the Operational Conditions and at the frequencies shown in Table 4.3.6-1."
TS Table 4.3.6-1.2.d requires that the APRM Neutron Flux - Upscale, Startup function undergo a Channel Functional Test quarterly and a Channel Calibration once every six months during Operational Conditions 2 and 5.
l In the review of Hope Creek's implementation of these requirements, TSSIP l
dstermined that the Channel Calibrations (which are also credited to meet the Channel Functional Test requirements when they are performed) do not i
satisfy the requirements for a channel Calibration or a Channel Functional Test as defined in the TS.
Specifically, the surveillance test procedure for the APRM Channel Calibrations specifies the replacement of the K18 relays with test relays (required in order to perform the calibration during Operational Condition 1, POWER OPERATION).
The removed K18 relays are re-installed at the conclusion of these tests; however, the K18 relays remain untested upon completion of the APRM Channel Calibration.
Since the entire channel is not tested, the APRM Channel Functional Tests and Channel Calibrations have not been performed in accordance with the TS definitions 1.4 and 1.6.
Since Hope Creek discovered this deficiency in an Operational Condition (POWER OPERATION) where these APRM functions are not required to bn operable, administrative controls were implemented to ensure that this instrumentation is properly tested in accordance with the TS requirements when entering the operational Conditions where it is required.
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TEXT CONTINUATION FACILITY NAME lil DOCKET NUMBER (2)
LER NUMBER 16)
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H2pe Creek Generating Station 05000354 95 -- 33 13 6
OF 28 TEXT pf more opeos is required, use additional copies of NRC Form 3SSA) (17)
DESCRIPTICII OF OCCURRENCE (Continued)
RWCU Isolation Actuation Instrumentation Surveillances i
i On 5/8/96, the TSSIP team confirmed that the Reactor Water Cleanup (RWCU) system has not been appropriately tested in accordance with Isolation 4
Actuation Instrumentation TS Table 4.3.2.1-1.4.a.
TS Table 4.3.2.1-1.4.a j
requires that the RWCU differential flow isolation function undergo a j
quarterly Channel Functional Test during Operational Conditions 1 through 3 (POWER OPERATION through HOT SHUTDOWN).
Specifically, the TSSIP team datermined that the loss of power to the K6 relay for the Nuclear Maasurement Analysis and Control (NUMAC) leak detection instrumentation has i
not been tested as required by the TS during the quarterly Channel i
Functional Tests.
i The RWCU is designed such that a loss of power to the leak detection system l
will cause the respective containment isole. tion valve to close.
The NUMAC laak detection monitor loss of power circuit has been functionally tested as part of the 18 month RWCU Logic System Functional Test (LSFT), which I
would also satisfy the TS requirement fcr a Channel Functional Test. The LSFT for this RWCU isolation actuation instrumentation was last completed on 11/9/95 for one division and 4/25/96 for the other division.
Therefore, i
at the time the deficient RWCU Channel Functional Test procedures were identified, one RWCU instrumentation division had exceeded the specified 92 i.
day surveillance interval for the Channel Functional Test and was declared inoperable.
As a result, on 5/8/96, at 1158 hours0.0134 days <br />0.322 hours <br />0.00191 weeks <br />4.40619e-4 months <br />, TS Action Statement j
3.3.2.1.b.1.c was entered, which requires the inoperable channel to be placed in the tripped condition (closing the associated RWCU isolation valve) within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
By 2101 hours0.0243 days <br />0.584 hours <br />0.00347 weeks <br />7.994305e-4 months <br /> on 5/8/96, the inoperable RWCU i
isolation actuation instrumentation division had been appropriately tested and was returned to service.
The action statement to close the affected isolation valve was not invoked.
i 4
On 5/10/96, the TSSIP team confirmed that the RWCU system has not been appropriately tested at the frequency specified by Isolation Actuation Instrumentation TS Table 4.3.2.1-1.4.e.
TS Table 4.3.2.1-1.4.e requires l
that each channel of the Standby Liquid control (SLC) system initiation RWCU isolation function undergo a Channel Functional Test during Operational Conditions 1, 2 and 5# (POWER OPERATION, STARTUP and REFUELING when SLC is required to be operable) every other 92 days.
Specifically, i
the TSSIP team determined that the interval between these Channel
(
Functional Tests has exceeded the 92 day frequency required by the TS.
At 1
the time this deficiency was discovered, the required channel Functional 1
l Tests had been completed within the previous 92 days for both channels and j
]
the current operability of this isolation function was not affected.
l However, previous testing schedules did not support the required test j
frequency and therefore were not performed as necessary.
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i NRC FORM 388A(4 86) l
N.C FORM 366A U.S. NUCLEAR RE2ULATCRY COMMISSION I4-es)
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DOCKET NUMBER (2)
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H::pe Creek Generating Station 05000354 95 -- 33 13 7
OF 28 l
l' TEXT lit more space le required, use additional copies of NRC Form 366Al (17)
DESCRIPTICBI OF OCCURRENCE (Continued)
TIP Isolation Actuation Instrumentation Surveillances On June 24, 1996, the TSSIP team determined that the Primary Containment l
Isolation due to High Drywell Pressure signal has not been appropriately l
tested in accordance with Isolation Actuation Instrumentation Table 4.3.2.1-1.
TS Table 4.3.2.1-1, item 1.b, requires that the High Drywell Pressure isolation function undergo a quarterly Channel Functional Test during Operational conditions 1 through 3 (POWER OPERATION through HOT SHUTDOWN).
Specifically, the TSSIP team determined that a relay contact, 1
which is part of the channel for the High Drywell Pressure withdrawal signal to the Traversing Incore Probes (TIP), was not being tested at the correct frequency.
This function was tested as part of a Channel Calibration on January 25, 1995.
However, at the time that the deficient Channel Functional Test procedure was identified, the 92' day surveillance interval had been exceeded.
As a result, on June 24, 1996, at 1445 hours0.0167 days <br />0.401 hours <br />0.00239 weeks <br />5.498225e-4 months <br />, i
l TS Action Statement 3.6.3 was entered.
These TS actions were complied with, and, after soccessfully performing the required surveillance test, the TS Action Statement was exited on June 25, 1996, at 0740 hours0.00856 days <br />0.206 hours <br />0.00122 weeks <br />2.8157e-4 months <br />.
On June 27, 1996, the TSSIP team determined that the TIP withdrawal function is tested via an LSFT procedure; however, the LSFT does not completely test the TIP response to a primary containment NSSSS isolation signal.
Therefore, the surveillance was not being appropriately conducted as required by TS 4.3.2.2.
TS 4.3.2.2 requires an LSFT to be performed on an 18 month basis.
Specifically, the LSFT did not include the withdrawal function of the TIP probe upon receipt of an isolation signal while the probe was being incerted into the core.
As a result, TS Action Statement 3.6.3 was entered, the penetration was isolated, and the TIP system was restricted from use.
On July 17, 1996, after completion of the surveillance on the previously untested function, the TS Action Statement for TIP was exited.
On July 19, 1996, Engineering documented a concern that the surveillance test that was conducted on July 17, 1996, which had tested the TIP withdrawal logic in the automatic mode, may not have been adequate to address all of the potential circuit paths on the logic card for the TIP withdrawal function.
As a result, the TIP system was again declared inoperable.
The surveillance test procedure was revised and the surveillance test was completed in the manual mode on July l
26, 1996.
A follow up investigation has concluded that the requirements of the'LSFT were not completely fulfilled during the July 17, 1996 test.
Specifically, not all potential circuit paths on the TIP withdrawal logic card were tested with the TIP mode of operation in automatic.
Therefore, i
b2 tween July 17 and July 19, 1996, the TIP withdrawal and isolation function was inappropriately considered operable.
As a result, the actions required by TS were not met and operation in a TS prohibited condition occurred.
NRC FOMM 308A (4-96)
i NRC FERM 3SSA U.S. NUCLEAR RESULATCRY CCMMISSIEN f
w es:
LICENSEE EVENT REPORT (LER) i TEXT CONTINUATION
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H2pe Creek Generating Station 05000354 95 -- 33 13 8
OF 28 j
TEXT IN more space is required, use additional copies of NRC Form 346Al (17) t i
DESCRIPTION OF OCCURRENCE (Continued) l i
l Turbine Stop Valve closure l
On June 25, 1996, the TSSIP team determined that the Main Turbine Stop Valve closure annunciation verification was not documented in the quarterly Channel Functional Test; however, it is documented as part of the 18 month
{
Channel Calibration procedure.
The Channel Calibration was last performed i
on March 6 and 7, 1996.
At the time that the deficient Channel Functional Tast procedure was identified, the 92 day surveillance interval, plus the 25% grace period, had not been exceeded.
The required portion of the j
zurveillance was completed prior to the expiration of the grace period.
)
However, this event is being reported due to the lack of documentation of j
the annunciation for past surveillances.
Turbine Control Valve Fast closure j
On July 8, 1996, the TSSIP team determined that t?' Main Turbine Control i
Valve Fast Closure Trip Channel was not being tet' si in accordance with the j
requirements of TS Table 4.3.1.1-1, Reactor Proteccion System j
Instrumentation Surveillance Requirements.
This TS Table requires the i
psrformance of a quarterly Channel Functional Test and an 18 month Channel l
Calibration of the Turbine Control Valve Fast Closure function.
TS require i
both of these surveillances to include alarm functions.
Contrary to this
{
requirement, the contacts that actuate the Control Room annunciator for the l
Turbine Control Valve Fast Closure were not verified during the performance of the quarterly channel Functional Test;-however, these contacts are j
varified as part of the 18 month Channel Calibration procedures.
The Channel Calibrations were last performed between December 4 and 8,
- 1995, j
which exceeds the 92 day surveillance interval plus the 25 % grace period allowed by TS 4.0.2.
The most recent quarterly Channel Functional Test was j
parformed on July 7, 1996.
Documentation of the alarm function during this 4
Channel Function Test was generated based on operator observation of the required alarm.
This event is being reported due to the lack of i
documentation of the annunciation for previous surveillances.
scram Discharge Volume Vent and Drain Valve Reactor Protection System Actuation 1
On July 18, 1996, the TSSIP team determined that the Reactor Protection
~
System Instrumentation was not being tested in accordance with the requirements of TS'4.3.1.2.
TS 4.3.1.2 requires the performance of an 18 month LSFT.
The TS definition of an LSFT states "A LOGIC SYSTEM FUNCTIONAL TEST shall be a test of all logic components, i.e.,
all relays and contacts, all trip units, solid state logic elements, etc., of a logic circuit, from sensor through and including the actuated device, to verify OPERABILITY."
Contrary to this requirement, the relays and associated NRC FORM 308A (4 96)
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O NRC FORM 36SA U.S. NUCLEAR RESULATCRY CCMMISSICN Ives) l LICENSEE EVENT REPORT (LER)
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vem Hcpe Creek Generating Station 05000354 95 -- 33 13 9
OF 28 TEXT lif more space le required, use additional copies of NRC Form 366A) (17) l DESCRIPTION OF OCCURRENCE (Continued) i contacts that actuate the Scram Discharge Volume (SDV) vent and drain valves following a scram signal from the Reactor Protection System Instrumentation were not individually verified during the performance of 1
the 18 month Reactor Protection System Simulated Operation procedure; i
however, post maintenance testing following replacement of the majority of these relays during the last refueling outage tested and verified operability of a portion of the affected relays and associated contacts.
As a result, at 1130 hours0.0131 days <br />0.314 hours <br />0.00187 weeks <br />4.29965e-4 months <br />, TS Action Statement 3.3.1.b was entered and the associated instrumentation for those relays and contacts which were not tested were declared inoperable.
In accordance with TS 4.0.3, "the ACTION requirements may be delayed for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to permit the completion of the surveillance when the allowable outage time limits of the ACTION raquirements are less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />."
A temporary procedure to test and varify operability of the untested portions of the SDV vent and drain valve logic was completed satisfactorily at 1910 hours0.0221 days <br />0.531 hours <br />0.00316 weeks <br />7.26755e-4 months <br /> on July 18, 1996.
The associated instrumentation was declared operable and the LCO exited.
Based upon this finding, it has been determined that the required testing was not parformed in accordance with TS.
This is reportable in accordance with 10CFR50. 73 (a) (2) (1) (B), as a condition prohibited by TS.
Scram Discharge Volume High Level Bypass Function Incomplete Logic System Functional Test On July 25, 1996, the TSSIP team identified to operators that the RPS Scram Discharge Volume (SDV) High Level Bypass function had not been completely tested in accordance with TS 4.3.1.2.
This surveillance requirement 4
epecifies that " LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months".
Par the HCGS TS definition: "A LOGIC SYSTEM FUNCTIONAL TEST shall be a test of all logic components, i.e.,
all relays and contacts, all trip units, colid state logic elements, etc, of a logic circuit, from sensor through and including the actuated device, to verify OPERABILITY.
The LOGIC SYSTEM FUNCTIONAL TEST may be performed by any series of sequential, overlapping or total system steps such that the entire logic system is tested."
The portion of the SDV logic that was not tested were those contacts in the bypass logic that could have inhibited the SDV high level scram function when a bypass signal was not desirable.
This deficiency represents an incomplete LSFT and therefore a non-compliance with TS 4.3.1.2, which constitutes a condition prohibited by TS and is being reported pursuant to 10CFR50.73 (a) (2) (1) (B).
Upon notification of this deficiency, the SDV High Level trip function was dsclared inoperable and the provisions of TS 4.0.3. were entered at 1230 on July 25, 1996.
Testing was satisfactorily completed at 2244 on July 25, 1996.
NRC FORM 180A M 96)
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N.T FCRM sSSA U.S. NUCLEAR RESULATORY CCMMISSIUN I4-05)
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DOCKET NUMBER (2)
LER NUMBER 16)
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DESCRIPTICBI OF OCCURRENCE (Continued) i Incomplete 18 Month Visual Inspection of the Reactor Building.to j
suppression Chamber vacuum Breaker Assemblies i
On July 26, 1996, the TSSIP team identified to operators that TS Surveillance Requirement 4.6.4.2.b.2.b had not been completely fulfilled.
{-
This surveillance requirement states that both reactor building -
cuppression chamber vacuum breaker assemblies be demonstrated OPERABLE at 4
least once per 18 months by visual inspection.
TS 3.6.4.2 defines a vacuum i
breaker' assembly as consisting of a vacuum breaker valve and a butterfly
}
isolation valve.
Previous procedures to fulfill this surveillance raquirement included a visual inspection of the vacuum breaker valve; but l
not the inboard butterfly isolation valve.
Failure to fulfill this j
surveillance requirement in the past resulted in a condition prohibited by TS and is being reported pursuant to 10CFR50.73 (a) (2) (i) (B).
Upon notification of this deficiency, the Reactor Building to Suppression Chamber Vacuum Breaker Assemblies were declared inoperable and the provisions of TS 4.0.3 were entered at 1030 on July 26, 1996.
The inspections were completed satisfactorily at 1635 on July 26, 1996.
Class 1E Isolation Breaker Instantaneous Overcurrent Protective Device l
TCating i
l On October 24, 1996, the TSSIP team documented a deficiency in the performance of surveillance testing pursuant to TS 4.8.4.5.a.
This surveillance requirement directs that each of the Class 1E isolation breaker 4
overcurrent protective devices shown in Table 3.8.4.5-1 to be demonstrated OPERABLE at least once per 18 months and states "The instantaneous element chall be tested by injecting a current in excess of 120% of the pick-up value I
of the element and verifying that the circuit breaker trips instantaneously with no intentional time delay".
Contrary to this requirement, previous i
tests of the instantaneous overcurrent devices were performed at i
approximately 113% of the pick-up value.
As a result, at 1645 on October 24, j
1996, the affected isolation breakers were declared inoperable and a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> i
LCO was entered in accordance with TS 3.8.4.5.
1 The surveillance procedure, HC.MD-ST.ZZ-0006(Q), was revised, the affected j
isolation breakers were tested satisfactorily, and at 1712 on October 25, 1996, the LCO was exited.
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DOCKET NUMBER (2)
LER NUMBER iS)
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H pe Creek Generating Station 05000354 95 -- 33 13 11 OF 28 TEXT IIf more opeos is required, use additional copies of NRC Form 3SSA) (17)
DESCRIPTION OF OCCURRENCE (Continued)
Incomplete Onsite Power Disgribution System Voltage Verification On November 8, 1996, the TSS!P team identified to Operations personnel that the Surveillance Requirements of TS 4.8.3.1 and 4.8.3.2 had not been completely fulfilled. These surveillance requirements direct that the power distribution system channels listed in the LCO be determined to be energized at least once per 7 days by verifying correct. breaker / switch alignment and voltage on the busses /MCCs/ panels.
Although the applicable curveillance procedure did verify the correct breaker / switch alignment, it did not verify voltage on all of the specified busses /MCCs/ panels.
As a rssult, at 1100 on November 8, 1996, an LCO was entered for the Onsite l
Power Distribution Systems.
The surveillance procedure, OP-ST.ZZ-0001(Q), was revised, the affected busses /MCCs/ panels were vcrified to have voltage available to them, and the LCO was exited at 1009 on November 9, 1996.
AIDLLYSIS OF OCCURRENCE As a Corrective Action from LER 95-017, a Technical Specification Surveillance Improvement Program (TSSIP) had been initiated.
The charter of this project is to compare the TS surveillance requirements (with the cxception of the Technical Specification 4.0.5 requirements) to the I
established surveillance procedures to verify that all requirements are met.
Undervoltage Relay Testing and ESF Actuation j
i Daring TSSIP review of TS 3.3.3, " Emergency Core Cooling System Actuation Instrumentation", it was determined that individual contacts, and their i
i configuration, from the undervoltage auxiliary relays and the degraded j
voltage relays were not tested in accordance with the LSFT requirements of TS j
i 4.3.3.2.
These contacts are for the load shedding of major 4.16 kV loads of the vital bus, incoming feeder breaker trips and lock outs, diesel generator start permits, and input to the load sequencer.
The LSFT is required to be performed at least once per 18 months.
On November 15, 1995 both the degraded voltage and the bus undervoltage aurveillance procedures were revised to incorporate the contacts and wiring that ner %d to be tested to satisfy the TS surveillance testing.
?
While' testing the
'A' Vital Bus (10A401), a bus transfer occurred when the l
tr,chnician inadvertently touched an adjacent terminal.
The bus transfer i
performed as designed.
The ' A' Loss of Offsite Power (LOP) Sequencer initiated per_ plant design.
The affected systems performed as expected.
Testing was terminated and subsequently was successfully completed.
NRC FORM 300A M45) l
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CC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION l
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LICENSEE EVENT REPORT (LER) 1 TNT CONTINUATION j
FACILITY N AME (1)
DOCKET NUMBER (2)
LER NUMBER i8)
PAGE (3) vtAn l
H::pe Creek Generating Station 05000354 9 5 -- 33 13 12 OF 28 TEXT lit more space le required, use additional copies of NRC Form 366Al (17)
ANALYSIS OF OCCURRENCE (ContinueG)
RTD and T/C Channel Calibrations In December 1995, the TSSIP reviewed the implementing procedures for curveillance requirements associated with the RWCU system.
The suction line (reactor coolant pressure boundary portion) of the RWCU system contains two motor operated isolation valves that automatically close in i
rcsponse to, among other signals, RWCU equipment compartment high ambient t2mperature and high differential temperature across the RWCU equipment compartment ventilation ducts.
The event concerned the channel calibrations performed for these signals.
I In the past, channel calibrations for instrument channels having resistance l
tcmperature detector (RTD) or thermocouple (T/C) sensors have been completed by performing an in-place qualitative assessment of sensor l
behavior and normal calibration of the remaining adjustable devices in the channel.
This test methodology is consistent with standard industry practice and has been considered to satisfy the surveillance requirements.
However, the TSSIP team determined that these surveillance procedures were inconsistent with the literal requirements specified in TS 1.4, CHANNEL l
CALIBRATION, which requires calibration of the sensor regardless of whether the channel has an RTD or T/C sensor.
Unlike other nuclear plant TS, there l
io no qualifying TS Table notes in the Hope Creek TS to exempt RTDs and T/Cs from the sensor calibration requirements.
The qualifying note was added to other plant's TS since calibration of RTDs and T/Cs cannot usually be performed in place.
Removal and subsequent re-installation of the sensors introduces a potential for an undetectable fcilure and alarm considerations that outweighs the benefits of the sensor calibration.
In lieu of sensor calibration, an in-place qualitative cesessment of sensor behavior is performed.
This position was adopted in l
NUREG-1433, " Improved Standard Technical Specifications for General Electric BWR/4 Plants."
l Failure to appropriately perform the surveillances for the RWCU instrumentation requires entry into the TS Action Statement specified in Tcble 3.3.2-1.
Since this did not occur, this event is reportable under the provisions of 10CFR50.73 (a) (2) (1) (B).
4 li
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FolM 36fA U.S. NUCLEAR REGULATORY COMMISSION LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION FACluTV NAME (1)
DOCKET NUMBER (2)
LER NUMBER 1Si pAGE ISI mamm mmun Hnpe Creek Generating Station 05000354 95 -- 33 13 13 OF 28 TEXT pl more opeos is required, use additional copies of NRC Form 366Al (17)
AMhLYSIS OF OCCURRENCE (Continued)
Additional review performed by the TSSIP identified that this condition
{
cxists for all of the RTD and T/C sensors for instrumentation listed in TS Table 4.3.2.1-1, Isolation Actuation Instrumentation Surveillance Rsquirements, Table 4.3.7.4-1, Remote Shutdown Monitoring Instrumentation Surveillance Requirements and. Table 4.3.7.5-1, Accident Monitoring Instrumentation Surveillance Requirements.
The affected instrumentation l
was not required to be operable at the time of discovery of the deficient i
curveillances and no TS Actions were required to be taken.
However, this l
condition has also existed since plant startup and TS Actions were not l
previously implemented.
This condition is also being reported under the provisions of 10CFR50.73 (a) (2) (1) (B).
l EACS Beat Exchanger Inlet valve Surveillances In January 1996, the TSSIP team determined that TS surveillance requirement l
l 4.7.1.1.b.1 has not been performed for the SACS heat exchanger inlet valves.
The SACS is designed to provide cooling water to the engineered cafety feature equipment, including the residual heat removal heat exchangers, during normal operation, normal plant shutdown, loss of offsite power and loss of coolant accident conditions.
Failure to demonstrate that the SACS heat exchanger inlet valve actuates to the open position upon its associated pump start signal at the specified TS frequency and Operational Condition requires entry into the SACS Action Statement for LCO 3.7.1.1,
+
"with both SACS subsystems inoperable, immediately initiate measures to i
place the unit in at least Hot Shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />."
Since this did not occur, this event is reportable under the provisions of 10CFR50. 73 (a) (2) (1) (B).
l HPCI Valve Surveillances On February 26, 1996, TSSIP determined that TS surveillance requirement 4.5.1.c.2.b had not been performed for sevcral HPCI valves.
Failure of the curveillance test procedures to require verification of the automatic alignment of the subject HPCI valves has existed since initial plant otartup.
HPCI is designed to provide make-up during a small break Loss of Coolant Accident (LOCA).
HPCI may be used for reactor vessel inventory or pressure control whenever the reactor vessel is pressurized and isolated from the feedwater and/or main steam system.
The HPCI pump normally draws water from the CST and discharges to the core spray and feedwater system piping. A full flow test line (back to the CST) is provided on the HPCI pump discharge line to allow testing of the system during normal plant operations without injecting water into the reactor vessel.
i NRC PORM 308A (445)
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i NRCPcC33SSA U.S. NUCLEAR RE2ULATORY CaMMISSICN M-05)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION FACILITY NAME til DOCKET NUMBER (2)
LER NUMBER 18)
PAGE (3)
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Hcpe Creek Generating Station 05000354 95 -- 33 13 14 OF 28 TEXT lit more spoos is required, use additional copies of NRC Form 3SSA) (17)
AMhLYSIS OF OOCURRENCE (Continued) l Surveillance test procedures have not required verification of the automatic actuation capability of the subject HPCI valves.
Failure to parform these surveillances in accordance with the frequency specified in the TS requires actions to be taken to enter at least Hot Shutdown within
- 12. hours after the allowed outage. time expires.
Since these actions were not taken, a condition prohibited by the TS occurred, which is reportable under the provisions of 50.73 (a) (2) (1) (B).
Primary Containment Penetration Isolation Barrier Verification l
l On March 25, 1996, TSSIP determined that TS surveillance requirement 4.6.1.1.b had not been performed for several primary containment psnetration test and drain valves.
Failure of the surveillance test procedure to verify all primary containment penetration valves has existed since initial plant start-up.
Since the surveillance test procedures.did not require verification of all the primary containment penetration valves, the missed TS surveillance is reportable under the provisions 10CFR50.73 (a) (2) (1) (B).
l As a corrective action from the March 25, 1996 discovery, a review was l
completed of all Primary Containment Isolation Barriers which resulted in j
the numerous additional components that were reported on October 15, 1996.
l l
Prior to implementation of this follow up review, there was no accurate list of which components needed to be verified to satisfy TS 4.6.1.1.b.
During this review, interpretations varied regarding which components within extended containment boundaries required verification per TS 4.6.1.1.b.
These differences resulted in several different revisions to this list and delayed completion of the project.
A revised position document provided by the TSSIP team clarified the differences in interpretations with conservative guidance to include a second isolation l
barrier within extended containment boundaries.
APRM Surveillances On March 29, 1996, TSSIP determined that Channel Functional Tests and Channel Calibrations for the APRM Reactor Protection System and Control Rod Block Instrumentation functions have not been performed in accordance with the TS definitions 1.4 and 1.6.
This condition has existed since initial l
plant startup whenever an APRM Channel Calibration was performed.
The l
APRMs monitor and record average core power between 0 and 125% of rated j
power and initiate protective actions should core power exceed specified l
satpoints.
The APRMs provide reference core power signals and rod motion i
paraissive signals to the Rod Block Monitor and the Reactor Manual Control NRC FORM 300A (4-96)
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8 NRC FORM 3SSA U.S. NUCLEAR REGULATORY COMMISSION i
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LICENSEE EVENT REPORT (LER) i TEXT CONTINUATION
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FACILITY NAME (1)
DOCKET NUMBER (2)
LER NUMBER 1Sl PAGE (3) es_oumma=
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j Hrpe Creek Genwating Station 05000354 95 -- 33 13 15 - OF 28 i
i TEXT III more opeos le required, use additional copies of NRC Form 3SSA) (17)
)
AMRLYSIS OF OCCURRENCE (Continued) 1 System.
They also generate a scram signal in response to average neutron flux increases from abnormal operating transients.
Since the APRMs have not been properly tested, the APRM channels could not be considered j
cperable in Operational Ccnditions 2 through 5.
When the Reactor Mode Switch has been in the STARTUP, SHUTDOWN or REFUELING positions, it was i
possible to have an undetected circuit failure where the K18 relay contacts remain closed regardless of Reactor Mode Switch position.
In this situation, the APRM setdown setpoints would not be placed in effect; i
however, the probability of this type of failure occurring is very low I
j since the Reactor Mode switch contacts and K18 relays have been tested j '
during performance of weekly surveillance testing and the K18 relay
)
j contacts open when the relay is de-energized (the fail safe position).
j
]
With the K18 relay contacts closed, the flow biased trip would be in effect.
I i
j During the TSSIP investigation of this issue, deficiencies in the operating l
procedures were identified relative to scheduling of the APRM Channel l
Functional Tests.
TSSIP determined that Hope Creek does not have sufficient procedural controls in-place to ensure that APRM Channel 3
Functional Tests are completed within seven days prior to entry into other Operational Conditions from Operational Condition 1.
This may have j
resulted in Operational Condition changes (plant scrams in particular) l bsing made without the provisions of TS 3.0.4 and/or 4.0.4 being satisfied for the APRMs.
This condition has also been determined to exist for the 4
Intermediate Range Monitors (IRMs) and Source Range Monitors (SRMs).
Since i
Hope Creek discovered this deficiency in an Operational Condition (POWER OPERATION) where the IRM and SRM functions are not required to be operable, j
guidance was provided to the operators to ensure that this instrumentation is properly tested in accordance with the TS requirements when entering the i
Operational Condition where it is required.
Failure to perform these j
required surveillances would have required (among other actions) that the i
Rsactor Mode Switch be locked in the Shutdown position within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after
{
leaving Operational Condition 1.
On April 10, 1996, guidance was provided i
to the operating shift crews to ensure that the appropriate TS actions are taken for this instrumentation until the required surveillances are
{
completed.
Subsequent Channel Functional Tests for this instrumentation have demonstrated its operability in Operational Conditions 2 through 5, 4
l but may not have been performed within the time specified in the TS i
relative to Operational Condition changes.
i I
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Nr.C FEM 34CA U.S. NUCLEAR REGULATOMY COMMISSION l
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l LICENSEE EVENT REPORT (LER)
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TEXT CONTINUATION f
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j Hope Creek Generating Station 05000354 95 -- 33 13 18 OF 28 j'
TEXT III mere opeos is required, use additional oopies of NRC Form 34SA) (17l 4
1, j
ROCU Isolation Actuation Instrumentation Surveillances
!j On 5/8/96, TSSIP determined that Channel Functional Tests for the RWCU isolation actuation instrumentation had not been performed in accordance with the TS Definition 1.6.-
In addition, on 5/10/96, TSSIP determined that the Standby Liquid Control (SLC) system initiation RWCU isolation function I
has not been tested at the frequency specified in the TS.
Failure to parform these surveillances in accordance with the TS requires actions to close the affected RWCU isolation valves and declare the RWCU inoperable after the allowed outage time expires.
Since these actions were not taken, a condition prohibited by the TS occurred, which is reportable under the l
provisions of 50.73 (a) (2) (1) (B).
3 TIP Isolation Actuation Instrumentation Surveillances i
On June 24, 1996, TSSIP determined that the Channel Functional Test for the Primary Containment Isolation due to High Drywell Pressure signal had not j
been appropriately tested.
Failure to properly perform this testing j.
rasulted in a condition prohibited by TS and is being reported pursuant to 10CFR50. 73 (a) (2) (1) (B).
1 On June 27, 1996, TSSIP determined that the TIP withdrawal function was not j
completely tested.
On July 17, 1996 the withdrawal and isolation function was tested with the TIP system in the automatic mode of operation and the j
2 LCO was exited.
The adequacy of this test was later questioned through j
follow up reviews by.the system manager and by an NRC inspector.
As a result, on July 19, 1996,-the TIP isolation function was again declared inoperable and TS LCO 3.3.2 entered.
The TIP isolation function was 4
subsequently satisfactorily re-tested in the manual mode on July 26, 1996.
)i Since that time, a follow up investigation has concluded that testing the TIP withdrawal logic in the manual mode in the forward direction is the optimum test method.
The testing performed in the automatic mode on July 17, 1996 did not assure operability of the TIP withdrawal and isolation i
function because not all portions of the logic up to and including the i
actuating device was tested.
Therefore, the restoration of the TIP withdrawal and isolation function to an operable status on July 17, 1996, was inappropriate.
As a result, the actions required by TS were not met j
and operation in a TS prohibited condition occurred.
Turbine Stop Valve Closure l
On June 25, 1996, TSSIP determined that the Main Turbine Stop Valve closure i
annunciation was not documented in the quarterly Channel Functional Test.
i The surveillance was not overdue at the time that this discrepancy was discovered.
However, this event is being reported due to the lack of l
documentation of the annunciation for past surveillances.
NRC PORM 306A (4-96)
.1,.C FIRM 366A U.S. NUCLEAR RECULATERY COMMISSl2N (4-M)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION FACILITY NAME (1)
DOCKET NUMBER (2)
LER NUMBER 16)
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H:pe Creek Generating Station 05000354 95 -- 33 13 17 OF 28 TEXT lif more space le required, use additional copies of NRC Form 366A) (17) l ANALYSIS OF OCCURRENCE (Continued)
Turbine control Valve Fast Closure On July 8, 1996, TSSIP determined that the Main Turbine Control Valve Fast Closure annunciation was not documented for the quarterly Channel Functional Test.
Documentation of the alarm function during the most recent Channel Function Test was generated based on operator observation.
Therefore, the alarm function is considered to be operable.
This issue is being reported under the provisions of 50.73 (a) (2) (1) (B) as a condition prohibited by the TS due to the lack of documentation for previous l
curveillances.
Ccram Discharge Volume Vent and Drain Valve Reactor Protection System Actuation On July 18, 1996, TSSIP determined that the LSFTs for the Reactor i
Protection System Instrumentation functions have not been performed in cccordance with the TS definition of an LSFT.
The logic for the SDV vent cnd drain valves contains twenty (20) contacts and four (4) relays.
There cre four (4) contacts in each of the four (4) Reactor Protection System cubsystems arranged in a one-out-of-two-taken-twice logic pattern.
Each of the four (4) subsystems actuates a relay, which changes the state of a contact in a one-out-of-two-taken-twice logic pattern that controls the position of the SDV vent and drain valves.
The Reactor Protection System i
Simulated Operation prc7edure, used to satisfy the requirements of the LSFT, verifies the functionality of the SDV vent and drain valves but did not test each individual relay and contact to verify operability of the l
radundant logic paths.
The redundant logic paths for the automatic closure of the SDV vent and drain valves in response to a Reactor Protection System Instrumentation l
ecram signal were not adequately tested.
This condition has existed since initial plant startup whenever a Reactor Protection System Instrumentation l
LSFT was performed.
Failure to perform these surveillances resulted in a l
condition prohibited by TS and is being reported pursuant to 10CFR50. 73 (a) (2) (1) (B).
Ocram Discharge Volume High Level Bypass Function Incomplete Logic System Functional Test l
The HCGS TS definition of an LSFT includes the requirement for testing of all relays and contacts of a logic circuit.
For bypass functions, Generic Lstter 96-01 and its related workshop summary documents state that contacts in the logic circuit whose failure could affect the safety function are required to be tested.
Previously performed SDV High Level Channel Calibration testing ensured that the bypass function was not inhibiting the ceram function, but due to the configuration of this logic, credit could I
not be taken for verifying each of the contacts in the bypass logic.
NRC FORM 306A (4-M)
lNRC F4RM 3SSA U.S. N UCLEAR RECULATt.RY CCMMISSir.",4 (4-956 LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION FACILITY NAME (1)
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LER NUMBER i6)
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13 18 OF 28 H:pe Creek Generating Station 05000354 9 5 -- 33 TEXT (if more space le,equired, use additional copies of NRC Form 366A) (17) l l
ANALYSIS OF OCCURRENCE (Continued)
Incomplete la Month visual Inspection of the Reactor Building to suppression Chamber vacuum Breaker Assemblies TS Surveillance Requirement 4.6.4.2.b.2 states that both reactor building-cuppression chamber vacuum breaker assemblies be demonstrated OPERABLE at least once per 18 months by visual inspection.
TS 3.6.4.2 defines a vacuum j
breaker assembly as consisting of a vacuum breaker valve and a butterfly icolation valve.
Previous procedures to fulfill this surveillance rsquirement included a visual inspection of the vacuum breaker valve; but not the inboard butterfly isolation valve.
Class 1E Isolation Breaker Instantaneous overcurrent Protective Device TOsting TS 4.8.4.5.a requires each of the Class 1E isolation breaker overcurrent protective devices shown in Table 3.8.4.5-1 to be demonstrated OPERABLE at least once per 18 months and states "The instantaneous element shall be tssted by injecting a current in excess of 120% of the pick-up value of the olement and verifying that the circuit breaker trips instantaneously with no intentional time delay".
Contrary to this requirement, previous tests of the e
instantaneous overcurrent devices was performed at approximately 113% of the pick-up value.
The value of 113% is consistent with vendor (General Electric) recommendations which had been incorporated into surveillance test procedure HC.MD-ST.ZZ-0006(Q).
The procedure history for this test indicates that this discrepancy between the TS value and the procedure has existed since initial plant startup.
3 Incomplete Onsite Power Distribution System Voltage Verification TS 4.8.3.1 and 4.8.3.2 require that the power distribution system channels, listed in the LCO, be determined to be energized at least once per 7 days by verifying correct breaker / switch alignment and voltage on the busses /MCCs/ panels.
These surveillances verify that the Onsite Power Distribution Systems are functioning properly, with the correct circuit breaker alignment.
The correct breaker alignment ensures the appropriate c:paration and independence of the electrical busses are maintained, and that voltage is available to each required bus.
The verification of voltage availability on the busses ensures that power is readily available for motive and control functions for critical system loads connected to these busses.
Although the applicable surveillance procedure did verify the correct breaker / switch alignment, it did not verify voltage on all of the specified busses /MCCs/ panels.
The surveillance procedure, OP-ST.ZZ-0001(Q), was rsvised and the affected busses /MCCs/ panels were verified to have voltage available to them.
The procedure history for this surveillance indicates that this discrepancy has existed since initial plant startup.
l NzC FORM 366A U.S. NUCLEAR RE;1ULATCMY CCMMISSitN (4-96)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION j
FACILITY NAME (1)
DOCKET NUMBER (2)
LER NUMBER 16)
PAGE13)
)
vaan H:pe Creek Generating Station 05000354 95 -- 33 13 19 OF 28 l
l TEXT lif more space is required, use additional copies of NRC Form 366Al (17)
APPARENT CAUSE OF OCCURRENCE The apparent cause of these TSSIP identified missed / deficient surveillance tests is ineffective procedures / inadequate review of the surveillance i
I activities intended to satisfy Hope Creek's TS during the near-term cperating license stage in the 1980s.
l l
The cause of the bus transfer was a test lead coming into contact with a terminal while the technician was attaching test equipment to a relay.
Contributing factors were the decision to perform the test while the bus was energized and inadequate job planning in that the effects of conducting the test in an energized cubicle that was not designed for test leads were not completely analyzed.
The apparent causcs for the inadequate revision to the TIP withdrawal and ieolation surveillance on July 17, 1996 were: (1) poor judgment to proceed with an On-the-Spot-Procedure-Change (OTSC) to conduct the test with the TIP cystem in the automatic mode without fully understanding why the TIP probe would not move forward in the manual mode and (2) the OTSC that was performed l
w s inappropriate in that it constituted a change of intent and should not l
h ve been allowed.
A contributing factor was incomplete vendor information cvailable regarding the operational details of the TIP drawer.
l
SAFETY SIGNIFICANCE
Undervoltage Relay Testing Although the undervoltage and degraded voltage relays were declared inoperable due to nonperformance of a surveillance requirement, reasonable acsurance existed that the Emergency Diesel Generators would start and energize the bus on a loss of power coincident with a Loss of Cooling Accident, and that all required ESF loads would sequence on the vital bus.
l This assurance is based on previous successful past performances of the integrated Emergency Diesel Generator test.
Additionally, performance of testing on the
'A' and
'C' vital busses demonstrated compliance with the LSFT requirements, and showed all required relays and contacts to be cycrational.
l E!F Actuation During Testing of Undervoltage Relays Due to the risks associated with the performance of this surveillance test (i.e., loss of the bus), Operations evaluated each load on the associated bus and provided recommendations regarding the use of redundant equipment to minimize the impact to plant operations.
Therefore, the safety significance ecsociated with this event was minimal.
j V:
i I
I
%RC FCAM 386A U.S. NUCLEAR REGULATORY COMMISSION f
44-88) l LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION FACILITY NAME (1)
DOCKET NUMBER (2)
LER NUMBER 16)
PAGE (3) i
"."uu".A" 2llE
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Hcpe Creek Generating Station 05000354 95 -- 33 13 20 OF 28 TEXT III more opeos is required, use additicaal copies of NRC Form 388Al (17)
RAFETY SIGNIFICANCE (Continued)
RTD and.T/C channel Calibrations POrformance of in-place qualitative assessments of RTD and T/C sensor behavior in lieu of sensor calibrations has been determined to be an acceptable method for demonstrating the operability of the isolation function.
This method has been accepted by the NRC and described in NUREG 1433 for this instrumentation.
Therefore, there is no safety significance of'the failure to perform sensor calibrations as specified in the existing TS Definition 1.4 for the RTD and T/C sensors.
SACS Beat Exchanger Inlet valve surveillances There was minimal safety significance for the inadequate SACS heat exchanger inlet valve surveillance test procedures.
The basis for this minimal impact is:
- 1) the normal position of the heat exchanger inlet valves is open; 2) the SACS operating procedure directs the operator to varify that the valve opens following a pump start; 3) the valves fail as-is, which ensures a suction flow path for pumps previously in service in the event of a design basis accident; and 4) indications available in the control room make the operator aware of a logic malfunction (causing the valve to'not open as required), such that compensatory actions can be initiated.
EPCI Valve Surveillances The normal positions for the subject HPCI valves enable HPCI to function upon an initiation signal without these valves changing position.
The j
position of these valves is verified twice daily.
The capability for the HPCI system to automatically take suction from the suppression chamber on a cuppression chamber-water level high signal has also been demonstrated within the past 18 months.
LERs 95-014-00 and 95-020-01 were written to document two ESF actuations where the HPCI suction realigned to the suppression chamber from the CST on a suppression chamber-water level high i
signal.
In addition, surveillance testing satisfying the requirements of TS 4.5.1.c.2.b has been completed and demonstrated the capability of the subject valves to automatically actuate on a suppression chamber-water level high signal.
Since the operability of the HPCI system was not affected with the subject valves in an off-normal position, there were no j
adverse safety consequences associated with this event.
1 NRC Poled 30BA (4-86)
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I
.n NRC FCRM 3SSA U.S. NUCLEAR REGULATCRY COMMISSl#N 84 95)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION FACILITY NAME til DOCKET NUMSER (2)
LER NUMSER 16)
PAGE13)
I se,ogu
,s m om vsAn Hspo Creek Generating Station 05000354 95 -- 33 13 21 OF 28 j
TEXT III more opeos le resguired, use addtional copies of NRC Fo,m 368Al (17)
SAFETY SIGNIFIchMCB (Continued) i Primary containment Penetration Isolation Barrier Verification l
The normal position for the subject primary containment penetration test and drain valves is the closed position with the downstream piping isolated closed with a secured pipe cap.
Positioning of plant components, including l
valves, is controlled by various administrative means.
It is unlikely that l
these valves or components could be mispositioned without noticing the L
related indications.
All the valves have been field verified to be in the correct closed position.
Since the valves were verified to be in the correct positions and administrative means were in place to control valve positioning, a past valve mispositioning error is unlikely.
Therefore, the cafety significance of this event is minimal.
The additional components identified in the october 15, 1996 list were found to be correctly positioned.
APRM Surveillances As stated previously, the APRM channels were not previously demonstrated as operable in Operational Conditions 2 through 5.
When the plant was in these conditions, it was possible to have an undetected failure where the K18 relay contacts remain closed regardless of Reactor Mode Switch position.
In this situation, the APRM setdown setpoints would not.be placed in effect; however, the Reactor Mode Switch contacts and K18 relays have been tested during performance of weekly surveillance testing'and-the K18 relay contacts open when the relay is de-energized (the fail safe l
position).
In addition, the IRMs would have been able to provide. signals j
to the Reactor Manual Control System to block rod motion and to the Reactor Protection System to initiate a scram during postulated conditions.
Therefore, the safety significance of this event is minimal.
RCCU Isolation Actuation Instrumentation Surveillances The subject RWCU isolation functions have been tested in accordance with the TS requirements and were found to be operable.
Although previous curveillance tests did not appropriately demonstrate operability of the RWCU isolation functions for loss of power to the leakage detection monitor or SLC initiation, the RWCU was capable of being isolated from redundant diverse isolation signals (i.e., reactor vessel low water level and manual initiation).
In addition, the successful completion of surveillance tests l
for these functions has demonstrated the continued capability for the RWCU system to isolate as designed.
Therefore, the safety significance of this f
avant is minimal.
NRC Polet 308A(406)
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N i
NAC FoR2 SiSA U.S. NUCLEAR REAULATORY COMMISSitN 14-9 5)
UCENSEE EVENT REPORT (LER)
TEXT CONTINUATION j
FACILITY NAME (1)
DOCKET NUMBER (2)
LER NUMBER IS)
PAGE13)
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H pe Creek Generating Station 05000354 95 -- 33 13 22 OF 28 l
8AFETY SIGNIFICMICE (Continued)
TIP Isolation Actuation Instrumentation Surveillances The Primary Containment Isolation and the withdrawal function of the TIP probe due to High Drywell Pressure signals have been tested in accordance with the TS requirements and were found to be operable.
Previous l
surveillance tests did not appropriately demonstrate operability of all TIP i
icolation functions.
The successful completion of the surveillance tests i
have demonstrated the continued capability for the TIP system to operate as d2 signed.
Therefore, there is no safety significance associated with this event.
)
i l
During the July 17 to July 19, 1996 period when the TIP withdrawal and leolation function was inappropriately considered operable, the TIP ball
.J l
valves remained closed (normal position) and the redundant isolation shear valves remained operable.
Therefore, the containment isolation function j
was maintained and there was no safety significance associated with this l
condition.
h' Turbine Stop valve Closure Annunciation I
The Turbine Stop Valve Closure Annunciation function has been tested in i
accordance with the TS requirements and was found to be operable. The i
successful completion of the surveillance tests for this function has damonstrated,the continued capability of the Turbine Stop Valve Closure signal to annunciate as designed.
There is no safety significance casociated with this event.
i Turbine control Valve Fast Closure Annunciation The Turbine Control Valve Fast Closure Channel Functional Test has been completed in accordance with the TS requirements and was found to be i
The successful completion of the surveillance tests for this function has demonstrated the continued capability of the Turbine control j
Valve Fast Closure signal to annunciate as designed.
There is no safety eignificance associated with this event.
l Baram Discharge volume vent and Drain Valve Reactor Protection System Actuation t
j The Reactor Protection System Instrumentation LSFT procedure was inadequate in that it did not test each relay and contact associated with the actuation j
of the SDV vent and drain valves.
However, actual performance of the i
curveillance testing on the untested relays and contacts demonstrated i
compliance with the LSFT requirements, and proved the required relays and contacts to be operable.
Therefore, there was no safety significance to the svent.
j NRC FOled 300A (4-06)
l N%C FCRM 3SSA U.S. NUCLEAR REGULATORY CCMMISSinN ites.
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION i'
FACILITV NAME (1)
DOCKET NUMBER (2)
LER NUMBER ' St PAGE (3)
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I H pe Creek Generating Station 05000354 95 -- 33 13 23 OF 28 j
SAFETY SIGNIFIchWCE (Continued) l Scram Discharge Volume High Level Bypass Function Incomplete Logic System i
Functional Tests l
l The purpose of the SDV Bypass logic is to allow for draining and venting the SDV after a rsactor scram.
With the reactor mode switch in SHUTDOWN or
'i l-REFUEL and the bypass switch in BYPASS, the SDV vent and drain valves open I
providing the draining necessary to reset the scram signal.
l When the subject contacts were tested in response to this event, the results were satisfactory.
Prior to this event, verification that the SDV i
l high level trip function was not bypassed has been performed by the l
successful completion of the SDV channel calibration tests, most recently parformed between May 1 and May 31, 1996.
The channel calibration tests did not include all of the contacts required by the LSFT, but did provide reasonable assurance that the trip function was not bypassed.
There were no potential safety consequences associated with this event.
Incomplete 18 Month' Visual Inspection of the Reactor Building to i
suppression Chamber vacuum Breaker Assemblies The butterfly isolation valves function to provide primary containment isolation and operate in conjunction with the vacuum breaker (check) valves i
to limit containment external to internal differential pressure to within 3.0 psi during post-LOCA containment depressurization.
Subsequent implementation of the Surveillance Requirement for the butterfly icolation valves performed on July 26, 1996, was satisfactory.
Additionally, previous successful performance of the remaining surveillance rcquirements of TS 4.6.4.2.b provided assurance of the ability of the icolation valves to have performed their intended safety functions during previous periods of operation.
I There were no potential safety consequences associated with this event.
l NRC Folhe 308A(&e6) l 1
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l
%%C FORM 3SSA U.S. NUCLEAR RE2ULATCRY CCMMISSIEN s4-es)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION FACILITY NAME (1)
DOCKET NUMBER (2)
LER NUMBER l6)
PAGE (3) muussi muussi Hspe Creek Generating Station 05000354 95 -- 33 13 24 OF 28 TEXT lif more space is resguired, use additionel copies of NRC Form 366Al (171 l
SAFETY SIGNIFICANCE (Continued)
Class 1E Isolation Breaker Instantaneous Overcurrent Protective Device TOsting The isolation breakers applicable to TS 3.8.4.5 are those that are tripped (load shed) by a LOCA signal.
The 113% value at which these breakers were i
previously tested indicates that the protective devices would bava tripped j
i prior to reaching the TS required value of greater than 120%.
This j
i condition was conservative considering the overcurrent protective device and load shed functions of the affected breakers.
Therefore, this event l
had minimal safety significance.
Incomplete Onsite Power Distribution System Voltage Verification The surveillance test has been completed in accordance with the TS l
rsquirements and all busses /MCCs/ panels were found to be operable.
The l
euccessful completion of the surveillance test has demonstrated the l
continued capability of.the Onsite Power Distribution System to operate as dtsigned.
Prior to this discovery, had there been a loss of or degraded voltagc condition on the unverified busses /MCCs/ panels, other indications exist that could have alerted operators to that condition.
Therefore, this event had minimal safety significance.
PREVIOUS OCCURRENCES
Failure to follow TS surveillance requirements has been documented in LERs l
95-003-00 and supplements, 95-017-00, 95-034-00 and 95-035-00.
LER 95-03-00 documented an event where operators performed a surveillance in an l
operational condition other than that specified by the TS, LER 95-017-00 documented an event where the emergency bus undervoltage logic circuitry was improperly tested, LER 95-034-00 documented a failure to perform Rod l
Scquence Control System surveillances when required and LER 95-035-00
)
documented the failure to perform Reactor Mode Switch, Source Range Monitor I
and Suppression Chamber Level surveil]ances properly.
In response to LER 95-017-00, the General Manager - Hope Creek Operations chartered the TSSIP to investigate, define, and resolve weaknesses in the TS Surveillance Program.
The events described in this LER were identified as a result of implementation of this corrective action.
I l
PWtC FOled 306A(4 46)
NRC FORM 3SSA U.S. NUCLEAR RESULATORY COMMISSIEN 84-8 5)
LICENSEE EVENT REPORT (LER) l TEXT CONTINUATION FACILITY N AME (1)
DOCKET NUMBER (2)
LER NUMBER 161 PAGE(3) 22:2 H3pe Creek Generating Station 05000354 95 -- 33 13 25 OF 28 j
TEXT (if more spoos le required, use additional copies of NRC Form 366Al (17)
CORRBCTIVE ACTIONS i
1 The TSSIP review will continue and will be completed by December 31, 1996.
Undervoltage Relay Testing and ESF Actuation The implementing procedures for testing the bus undervoltage auxiliary contacts have been revised to defeat the undervoltage trip functfon during the performance of the test.
The TSSIP group independently reviewed the procedures to ensure satisfactory compliance.
This was completed prior to performance of the test procedures.
i Logic System Functional Testing was performed on the
'B' and
'D' vital busses l
to demonstrate operability of the undervoltage and degraded voltage relays to satisfy requirements of Surveillance Requirement 4.3.3.1.
The Technical Specification Matrix will be updated to reflect new procedures to comply with the LSPT requirement.
This will be performed as the TSSIP identifies issues and will be completed by December 31, 1996.
Position papers were prepared to outline the proper test methodology and acceptance criteria for performance of technical specification surveillances, Euch as LSFT and Channel Functional Test requirements.
Training based on the site approved position papers will be prepared and incorporated into initial and continuing training programs for personnel responsible for the preparation, review, and approval of logic system eurveillance procedures.
The initial training will be conducted for licensed operators, system managers, procedure writers, and Station Qualified Reviewers, and will be completed by December 31, 1996.
Guidance was provided to the relay and controls technicians regarding the colection and use of M&TE (specifically M&TE with alligator clips).
]
The Controls Pre-Job Brief Checklist has been revised to ensure the proper une of M&TE.
The procedures used to conduct the LSFT surveillance have been revised to specify the specific alligator clip to be used.
A design change to install test points outside these cubicles will be implemented by the end of the next refueling outage (RFO7).
RTD and T/C Channel Calibrations The TS definition of CHANNEL CALIBRATION was revised, prior to entry into l
Operational Condition 3 following the sixth refueling outage, to permit in-place qualitative assessments of RTD and T/C sensors.
NRc roRu sesA(4-es)
s n.
NRC FcRM 3SSA U.S. NUCLEAR RESULATCRY COMMISSIGN Wes)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION FACILITY NAME (1)
DOCKET NUMBER (2)
LER NUMBER 8)
PAGE13) mYan Hepe Creek Generating Station 05000354 9 5 -- 33 13 26 OF 28 l
TEXT lif more opeos le required, use additional copies of NRC Form 366Al (17) 90RRECTIVE ACTIONS (Continued)
CACS Beat Exchanger Inlet Valve Surveillances The SACS heat exchanger inlet valves have been administratively controlled to ensure performance of the valves' safety function.
These valves were cppropriately tested to satisfy the requirements of TS 4.7.1.1.b.1.
Parmanent procedure revisions to appropriately test the SACS valves in accordance with the requirements of TS 4.7.1.1.b.1 have been completed.
EPCI Valve Surveillances The HPCI surveillance test procedure has been revised to appropriately test the subject HPCI valves and ensure operability of HPCI.
The subject HPCI valves have been properly tested and the requirements of TS 4.5.1.c.2.b have been satisfied.
)
Primary Containment Penetration Isolation Barrier Verification 4
The primary containment penetration test and drain valves were added to the 1
surveillance procedure that verifies TS 4.6.1.1.b.
A review of all primary containment penetrations was completed to ensure all appropriate TS 4.6.1.1.b components are identified.
This review was completed on October 15, 1996 and the surveillance procedure was revised to include the required components.
APRM Surveillances 3
Administrative controls were placed in effect for the APRMs on March 29, 1996, to ensure that the instrumentation is appropriately tested prior to 4
cntering an Operational condition where it is required, j
On April 10, 1996, guidance was provided to operating shift crews to ensure
^
that the appropriate TS actions are taken for the APRM, IRM and SRM instrumentation until the required surveillances are completed, j
Surveillance test procedures for the quarterly and semi-annual APRM Channel Calibrations have been revised to ensure that they are performed in accordance with the TS definitions.
Operations procedures have been revised to incorporate the April 10, 1996, guidance on the performance of APRM, SRM and IRM surveillances.
N
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ei 4 NAC FEM 366A U.S. NUCLEAR RESULATCRY CCMMISSisN I4-95)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION FACILITY NAME th DOCKET NUMBER (2)
LER NUM8ER 16)
PAGE (3)
=
mn H:pe Creek Generating Station 05000354 9 5 -- 33 13 27 OF 28 TEXT (if more space le required, use additional copies of NRC Form 366Al (17)
CORRECTIVE ACTIONS (Continued)
[
RUCU Isolation Actuation Instrumentation Surveillances i
RWCU isolation actuation instrumentation Channel Function Test procedure rsvisions, which appropriately test RWCU isolation functions, have been completed.
Recurring tasks have been revised to ensure that the RWCU isolation l
actuation instrumentation is tested at the frequency specified in the TS.
J TIP Isolation Actuation Instrumentation Surveillances i
The portions of the Channel Functional Tests for the Primary Containment Isolation due to High Drywell Pressure that had not been performed at the correct frequency were completed satisfactorily.
The Functional Test procedure for the Primary Containment Isolation due to High Drywell Pressure signal has been revised.
I The surveillance procedure for the TIP probe withdrawal was revised.
The LSFT for the TIP probe withdrawal and isolation function was tested actisfactorily in the manual mode on July 26, 1996.
A review was completed of the implementation of the OTSC process.
This review determined that the process was adequate and that knowledge errors rsgarding the complexity of this particular circuitry resulted in the unawareness that the OTSC was a change of intent.
The needed vendor information that contributed to the event was captured in the revision to the surveillance procedure and a Design Change Package has been issued to update the vendor manuals.
Turbine Stop Valve closure The surveillance tests for the contacts were completed satisfactorily.
The Channel Functional Test procedure has been revised.
Turbine control Valve Fast closure The Channel Functional Test was completed satisfactorily on July 7, 1996.
The Channel Functional Test procedure was revised on July 31, 1996.
t NRC FORM 306A(4 95)
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f
(
my r s
- NIC FAM 3SSA U.S. NUCLEAR RESULATCRY C MMISSICN 84-85)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION FACILITY NAME lil DOCKET NUMSER (2)
LER NUMSER iSI PAGE (3) muuast H:pe Creek Genersting Station 05000354 95 -- 33 13 28 OF 28 TEXT lif more spoos le required, use additional copies of NRC Form 3SSA) (17) l CORRECTIVE ACTIONS (Continued) l Scram Discharge Volume vent and Drain valve Reactor Protection System Astuation Satisfactory testing of the untested SDV vent and drain valve relays and associated contacts was completed on July 18, 1996.
l The Reactor Protection System Instrumentation Simulated Operation procedure l
will be revised by June 1, 1997 to meet the requirement of surveillance raquirement 4.3.1.2.
Scram Discharge volume High Level Bypass Function Incomplete Logic System Functional Test The untested portions of the SDV Bypass logic were tested satisfactorily on July 25, 1996.
l Surveillance test procedure HC.OP-ST.SF-0001(Q) will be revised to include tasting of the previously omitted portions of the SDV Bypass logic.
procedure revision will be implemented by June 19, 1997.
. This Incomplete is Month Visual Inspection of the Reactor Building to Suppression Chamber vacuum Breaker Assemblies The required visual inspections were satisfactorily completed on July 26, 1996.
i Hope Creek procedure HC.MD-ST.GS-0002(Q) has been revised to include the visual inspection requirements for butterfly isolation valves 1GSHV-5029 and 1GSHV-5031 per TS Surveillance Requirement 4.6.4.2.b.2.b.
Class 1B Isolation Breaker Instantaneous Overcurrent Protective Device Tcsting Hope Creek procedure HC.MD-ST.ZZ-0006(Q) was revised to incorporate the rcquirements of TS 4.8.4.5.a and the affected breakers were satisfactorily tssted on October 25, 1996.
Incomplete Onsite Power Distribution System Voltage Verification l
Hope Creek procedure OP-ST.ZZ-0001(Q) was revised to incorporate the requirements of TS 4.8.3.1 and 4.8.3.2.
The revised surveillance test was performed satisfactorily on November 9, 1996.
This test included voltage msasurements of those busses /MCCs/ panels whose voltages could not be i
varified by other means.
NRC FORM 308A (4-96)