ML20202D940
ML20202D940 | |
Person / Time | |
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Site: | Zion File:ZionSolutions icon.png |
Issue date: | 11/28/1997 |
From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
To: | |
Shared Package | |
ML20202D918 | List: |
References | |
50-295-97-22, 50-304-97-22, NUDOCS 9712050192 | |
Download: ML20202D940 (23) | |
See also: IR 05000295/1997022
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I U. S. NUCLEAR REGULATORY COMMISSION
REGIONlil
Docket Nos: 50-295, 50-304
Report Nos: 50-295/97022(DRP); 50-304'07042(DRP)
Licensee: Commonwealth Edison Company
Facility: Zion Nuclear Plant, Units 1 and 2
Location: 101 Shiloh Boulevard
Zion,IL 60099
Dates: August 30 through October 10,1997
Inspectors: E. Cobey, Acting Senior Resident inspector
D. Calhoun, Resident inspector
J. Yesinowski, Illinois Department of
Nuclear Safety (IDNS) Inspector
Approved by: Anton Vegel, Acting Chief
Reactor Projects Branch 2
9712050192 971128
PDR ADOCK 05000295
0 PTR
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EXECUTIVE SUMMARY
Zion Nuclear Plant, Units 1 and 2
NRC inspection Report No. 50-295/97022(DRP); 50-304/97022(DRP)
This inspection included aspects of licensee operations, maintenance, engineering, and plant
support. The report covers a six week period of inspection activities by the resident staff.
During this inspection period, the inspectors noted some improvement in the operators'
implementation of the Zion Operations Department Standards. This was most evident in the
operators' response to the unexpected loss of instrument bus 213. However, the inspectors also
noted that the implementation of the out-of-service program remained problematic and that
operators continue to be challenged by inappropriate procedural guidance.
Operations
. A violation was identifieo involving three examples of deficiencies in the implementation
of the out-of-service program (Section 01.1).
. The inspectors identified that tha pre-job briefing for the autostart inhibit circuitry testing
was effective. However, the inspectors alto concluded that the evolution was not
consistently controlled by the Unit Supervisor from the control room and that the
operators were repeatedly challenged by the inconsistent use of three-way
communications by the supporting engineering and maintenance personnel. In addition,
a violation was identified for the failure to provide appropriate guidance to test the
autostart inhibit circuitry for the OC component cooling water pump (Section 01.2).
. The inspectors concluded that the operators' response to the loss of instrument bus 213
was appropriate and effective; however, the event recovery was delayed by tne
unavailability of the auxiliary power to the instrument bus due to a lack of priority on the
retum to service of equipment following maintenance activities. In addition, a violation
was identified for the failure to provide appropriate guidance for operator response to a
loss of instrument bus 213 event (Section 01.3).
Maintenance
. The inspectors determined that an inadvertent engineered safety feature actuation
resulted from inappropriate work practices during a maintenance activity (Section M1.1).
. A violation was identified pertaining to the establishment of the nuclear instrumentation
powe range rate trip setpoint greater than that allowed by the Technical Specification
Limiting Safety System Setting, in addition, a violation was identified involving the failure
to maintain the minimum number of operable power range rate trip channels or compiv
with the Technical Specification Action Statements. Of particular concem was the failure
of the licensee to identify these deficiencies without prompting by the inspectors
(Section M8.2).
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Plant Syp19d
. The inspectors concluded that the licensee inappropriately secured the compensatory
measures for a degraded vital area barrier (Section 81.1).
+ The inspectors concluded that on two occasions security officers were inattentive to their
duties while at an assigned security post (Section St.2).
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Resort Details .
Summary of Plard Status
During this inspection period, the licensee maintained Unit 1 in a defueled condition and Unit 2 in
a cold shutdown, depressurized cor dition pending completion of restart actions delmented in the
Zion Recovery Plan. .
1. Operations
01 Conduct of Operations
01.1 Out-of-Service (OOS) Pronram implementation Problems
a. lDspection Scope (71707 and 62707)
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The inspectors reviewed the circumstances surrounding four events involving
OOS program implementation problems. The inspectors interviewed operations and
engineering personnel and reviewed applicable documentation and procedures, including
Zion Adm;nistrative Procedure 300-06, "Out of Service Process," Revision 15.
b. Observations and Findinos
During this inspection period, the inspectors noted four examples of deficiencies in the
licensee's implementation of the OOS program. As previously documented in
NRC Inspection Report No. 50-295/96020; 50-304/96020, 50-295/96017; 50-304/96017,
and 50-295/96014; 50-304/96014, the im?iemontation of the OOS program continues to '
be an area of concom. Specifically;
OOS on the OA Fire Pumo Imoroperty Cleared
On September 10,1997, following the clearance of OOS No. 970009297 on the QA iire
pump, an operator identified that the expected indication for the OA fire pump was not
available in the control room. The licensee subsequently determined that while clearing
the OOS, a non-licensed operator incorrectly retumed the 0A fire pump breaker to
service, in that, the control power knife switch had not been closed as required. The
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non-licensed operator's failure to close the control power knife switch also resulted in the
shunt trip circuit being disabled, which would have prevented the pump from tripping on
an engineered safety feature load shed during an undervoltage condition. Consequently,
during an undervoltage condition, the OA fire pump would have immediately loaded onto -
the 1 A emergency diesel generator (EDG) At the end of this inspection period, the
. licensee's investigation was still in progress.
Zion Administrative Procedure 300-06,"Out of Service Process," Revision 15,
Appendix B. " Lifting OOS Techniques," spedfied, in part, that equipment be retumed to
service in accordance with the applicable system operating instruction (SOI). Step 5.2.9
- of sol-63N, "480V Breaker Racking Operations," Revision 4, specifiaf, in part,' that the
control power knife switch be closed. The failure to close the control power knife switch
during the retum to service of the OA fire pump breaker as required by SOI-63N,
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step 5.2.9, is considered an example of a violation of TS_6.2.1.a (No. 60-295/97022-01a;
50-304/97022-01a), as described in the attached Notice.
Independent Vertfication identified an improperty Huna OOS Card
On September 29,1997, during independent verification of OOS No. 970009648 on the
2B EDG train *A" starting air system, a non-licensed operator identified that the OOS card
for the 'A' starting air compressor local control switch was on the wrong switch. The
licensee subsequently determined that the local control switch for the "A" starting air
compressor had been repositioned to the "OFF" position, as required. However, the
non licensed operator mistakenly hung the card on the 2B east fuel oil transfer pump
local control switch. As a result, the licensee immediately corrected the error and initiated
problem identification form (PIF) Z1997-01972. Tha 28 EDG was operable throughout
this occurrence sincc the train *B' starting air system was operable.
Improperty Positioned OOS Valve identified While Clearina the OOS
On October 2,1997, while clearing OOS No. 970009345, a non-licensed operator
idantified that the 1 A EDG train 'A' main starting air check valve test tap isolation valve,
il>G0169, was capped and open. However, the OOS position for 1DG0169 was
uncapped and open. The licensee subsequently determined that the OOS had initially
been hung correctly since the starting air header had successfully been depressurized via
this vent path. As a result, the licensee completed clearing the OOS, retumed the
1 A EDG to service, and initiated PIF Z1997 02045. At the end of this inspection period,
the licensee'= investigation was still in progress. The failure to maintain 1DG0169, in the
position required by OOS No. 970009345 is considered an example of a violation of
TS 6.2.1.a (No.50-295/97022-01b; 50-304/97022-01b), as described in the attached
Notice.
Besidual Heat Removal (RHR) Valve Not in the Reauired OOS Position Resulted in a
Three Percent Decrease in Pressurizer t.evel
On October 10,1997, while attempting to depressurize the 2B RHR train during the
performance of periodic test (PT) 2C-CSD ST, "RHR System CIV [ Containment isolation
Valve) Stroke Timing in Mode 5," the operators noted that the 2B RHR train did not
depressurize as expected. The operators also identified that while attempting to
depressurize the 2B RHR train, pressurizer level dropped approximately 3 percent
(360 gallons); as a result, the operators stopped the test. The licensee subsequently
determined that the 28 RHR heat exchanger bypass valve,2RH87268, was 2/3 of a tum
open. However, OOS No. 970007778, which isolated the 2B RHR train from the
operating 2A RHR train, required 2RH8726B to be in the closed position. Subsequently,
the licensee closed 2RH8726B and successfully depressurized the 2B RHR train. The
failure to place and maintain 2RH8726B in the position required by OOS No. 970007778
is considered an example of a violation of TS 6.2.1.a (No 50-295/97022-01c:
50-304/97022-01c), as described in the attached Notice.
c. Conclusion
The inspectors concluded that although each OOS error had minimal safety
consequence, the entrs collectively indicated that the licensee's implementation of the
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OOS program remained problematic. Although the violation examples were licensee-
identified or self-disclosing, a violation is being cited since this is a repetitive issue.
01.2 Autostart Inhibit Circuitry Testina Failure due to en inadeauste Operatino Special
Procedure
a. Inspection Scope f71707 and 61726)
The inspectors observed the pre-job briefing and performance of Operating Special
Procedure (OSP)97-039, West of Autostart inhibit Circuitry for Bus 149 Pumps,"
Revision 0, interviewed operators and maintenance personnel, and reviewed applicable
documentation,
b. Observations and Findinas
On September 19,1997, C.e licensee conducted a pre-job briefing for the performance of
OSP 97-039. The inspectors noted that the Nuclear Station Operators (NSOs)
participating in the pre-job briefing exhibited a questioning attitude. For example, the
NSOs questioned the applicability of step 1.9.2, which required a jumper to have been
installed only if the steam generetor lo-lo level relays were deenergized, in response to
the question, the licensee suspended the briefing while an NSO determined the state of
the relays. The NSOs also qt.estioned the electrical maintenance technicians supporting
the evolution on the appropriateness of utilizing jumpers with alligator clips, which had
been identified as a contributing cause for the inadvertent engineered safety faature
(ESF) actuation on September 2,1997 (See Section M1.1). However, the technicians
convinced the NSOs that tne use of this type of jumper was appropriate for this evolution.
Following the completion of the pre-job briefing, the licensee initiated OSP 97-039.
During the performance of step 1,10, which installed a jumper to simulate a component
cooling water (CC) low header pressure autostart signal to the OC CC pump, the electrical
maintenance technician knocked off the jumper previously installed in step 1.9.2.
Fortuitously, the dislodged jumper did not contact any other component prior to being
restrained by the technician. The inspectors identified that the technician dislodged the
jumper due to the use of jumpers with alligator type clips and the technician having
reduced manual dexterity as a result of using low voltage rubber gloves with leather
protector outer gloves. The inspectors subsequently determined that the electrical
maintenance technicians had been made hware of the Ocumstances surrounding the
inadvertent ESF actuation on September 2,1997, during a maintenance shop meeting.
However, at the time of this event, the licensee's investigation lato the inadvertent
ESF actuation had not been completed; and as a result, the licensee's corrective actions
had not been developed and implemented.
During performance of OSP 97-039, Section 2," Component ActuationNerification," the
OC CC pump breaker did not close automatically as expected in step 2.6. As a result, the
operators stopped the testing and restored equipment to normal configuration. The
licensee determined that the procedure would not work as written, in that, the closure
signal for the OC CC pump breaker was being inhibited by the manual actuation of ralay
SX1 in accordance with step 2,1. On September 20,1997, the licensee revised
OSP 97-039 and successfully completed the evolution.
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The licensee also identified 15at the technical review of the procedure was conducted by
an individual who contributed to writing the procedure. Consequently, the reviewer did
not recognize the deficiency in the procedure. As a result of this occurrence, the licensee
initiated PlF Z1997-01896. The failure of OSP 97-039 to provide appropriate guidance to
test the autostart inhibit circuitry for the OC CC pump is considered an example of a
violat:on of 10 CFR cart 50, Appendix B, Criterion V (No.50 295/97022 02a;
50 304/97022-02a), as described in the attached Notice.
While observing the performance of OSP 97-039, the inspectors identified that the NSOs
conducting the testing in the bus 149 switchgear room satisf actorily controlled the
evolution. However, the NSos were repeatedly challenged by the inconsistent use of
three-way communication by the system engineer and maintenance technicians
supporting the evolution. Specifically, the system engineer and m%)ntenance technidens
did not consistently repeat back the direction that they had received to ensure that their
understanding was correct prior to implementing the direction without prompting by the
NGOs.
In addition, the inspectors noted that at times the evolutiou was not controlled by the
Unit Supervisor from the cmtrol rocm. Specificalty, when the temporary jumper was
dislodged, the NSos in tN. switchgear room directed the rnalntenance technicians to
remove the installed jumpers prior to receiving authorization from the control room.
Furthermore, following the fallute of the OC CC pump breaker to close automatically, the
system engineer, with concurrence from the NSOs, directed the maintenance technicians
to perform continuity checks on the installed jumpers without evaluating the possible
romifications of the troubleshooting or receiving authorization from the control room.
Upon the completion of the continuity checks, the NSos stopped the troubleshooting
activities and coordinated with the control room to restort. the plant equipment from the
failed test.
c. Qqo.clusions
The inspectors concluded that the pre-job briefing effectively prepared the operating shift
to perform OSP 97 039. The Inspectors also enneluded that the NSOs exhibited a
questioning attitude during the briefing; however with respect to the use of temporary
jumpers with alligator clips, the NSos missed an opportunity to ensure that actions were
implemented whicii could have prevented the jumper from being dislodged during the
evolution. In addition, the inspectors concluded that the evolution was not consistently
controlled by the Unit Suoervisor from the control room and that the NSos were
repeatediv challenged by the inconsistent use of three-way communications by the
system engineer and maintenance technicians supporting the evolution. The inspectors
also concluded that OSP 97-039 was inadequate, in that, the procedural steps were not
sequericed in a manner which allowed the successful testing of the au'ostart inhibit
circuitry for tha OC CC pump. As documented in NRC Inspection Report
No. 50 295/97013; 50 304/97013, 50 295/97012, and 50-295/97002; 50-304/97002, the
failure to provide operating procedures that contain guidance appropriate to the
circumstances remains problematic (See also Section 01.3). Although the violation
example was self-disclosing, it is being cited since this is a repetitive issue.
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01.3 Lgss of Electdcal Power to Instrument Bus 213
a. Inspection Scope f71707 and 37651)
The inspectors reviewed th6 eircumstances surroune.;ing the loss of instrument bus 213
on September 22,1997. The inspectors interviewed operators, reviewed Abnormal
Operating Procedure (AOP) 8.1, ' Loss of instrument Bus,' Revision 19(G), and the
electdcal circuitry associated with the bode acid transfer pumps and the RHR minimum
flow valve, and evaluated the licensee's root ca'tse investigation and subsequent
corrective actions,
b. Observations and Findinos
On September 22,1997, the control room received numerous unexpected annunciators
and equipment actuations due to the loss of electdcal power to instrument bus 213.
Based on the inspectors' review of the circumstances surrounding this event, the
inspectors determined that the operators' response to the event was app opdate and
eff9ctive. Specifically:
. The operators quickly and correctly diagnosed the failure and entered the
appropriate AOP.
. The operetors recognized the expected increase in charging flow when the
charging flow control valve,2FCV-VC121, failed to 20 percent open. The
operators also recognized the potential for a positive reactivity addition when the
bonc acid trcnsfer pump failed to start as expected on the volume control tank
(VCT) automatic make-up, which resulted in pure water being added to the VCT.
In response, the operators appropriately switched the charging pump suction to
the refueling water storage tank to provide a borated water supply to the charging
pumps.
. The operators recognized th4, expected increase in RHR flow when the
2A RHR heat exchanger outlet valve,2HCV RH606, and the 2A RHR heat
exchanger bypass valve,2HCV-RH618, both failed open. As a result, the
operatort mor,itored the decreasing reactor coolant system temperature
throughout the event.
- The operators identified that the 2A RHR pump minimum flow valve,
2MOV-RH610, unexpectedly cycled continuously throughout the event. As a
result, the operators monitored the RHR pump ampurage to ensure that the pump
was not operati g in a runout condition.
The inspectors also noted that the recovery from the loss of the instmment bus was
delayed appmximately 15 minutes due to the auxiliary power feed for the instrument t,us
being tagged OOS. The maintenance on this component had been completed
approximately 16 days earlier, however, the OOS had not been cleared due to a lack of
priority on retuming equipment to servicu in a timely manner followir.g the completion of
maintenance activities.
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The licensee subsequently revealed that the boric acid transfer pump and the
2A RHR pump minimum flow valve operated as designed for a loss of
instrument bus 213. The boric acid transfer pump did not start since the Unit 2 boric wd
tank level instrument, which was powered from instrument bus 213 and failed low on a
loss of power, provided a pump start inhibit signal to prevent pump damact due to low
tank level. The 2A RHR pump minimum flow valve cycled continuousY throughout the
event since both the open and closed flow contact circuits in the valve positioning
circuitry were powered from Instrument bus 213, coupled with the seat in arrangement of
the position circuitry. Consequently, the valve received a continuous open demand as
soon as the valve went full clos,ed, and a closed demand as soon as the valve went full
open. In both of these cases, AOP 8.1 did not identify the equipment response to a loss
of power to instrument bus 213 or direct appropriate follow-up actions. The failure of
AOP 8.1 to provide appropriate guidance for operator response to a loss of instrument
bus 213 event is considered an example of a violation of 10 CFR Part 50, Appendix B,
Criterion V (No. 50 295/97022-02b; 50-304/97022 02b), as described in the attached
Notice.
In response to this event, the licensee's planned or (ompleted long terrn corrective
actions included the following:
. The licensee identified that an intemal DC fuse was blown in inverter 213 (the
normal power feed to instrument bus 213); however, engineering pomernel were
unable to determine the ca ,se of the blo nn fuse. As a result, system engineering
personnelinitiated engineering request No. 9503202 to evaluate a hardware
upgrade to the control circuits of the instrument inverters.
. Operators evaluated the adequacy of AOP 8.1 utilizing various simulator
scenarios. As a result, the operations department personnel plan to revise
AOP 8.1 to recognize and provide appropriate follow-up actions for the loss of
boric acid transfer pumps and for the continuous cycling of the RHR pump
minimum flow valve during a loss of instrument bus 213 event. In addition, while
conducting these simulator scenarios, the licencee determined that the simulator
incorrectly modeled the aivallability of the boric acid transfer pumps during this
event; consequently, the licensee plans to correct the simulator modeling.
+ Design engineering personnel initiated engineering request No. WO6286 to
determine whether a design change is needed to the RHR minimum flow valve
control circuitry.
. The Shift Operations Supervisor plans to establish an operations department
policy to require that auxiliary power be verified available prior to allowing tork on
or in the instrument inverter cabinets.
+ The operating procedures group personnel plan to provide an additional section to
the licensed operator tumover check sheets to list the irnportant equipment that is
unavailable in order to heighten the operators' awareness to this equipment.
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c. Conclusions
The inspectors concluded that the operators' response to the loss of lastrument bus 213
was g#: and efiscove. The inspectors also concluded that the event recovery
was delayed by the unavailability of the auxiliary power to the instrument bus due to a
lack of priority on the retum to service of equipmerd following maintenance activities, in j
addition, the inspectors concluded that AOP 8.1 was dancient, in that, the procedure did
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not recognize that a posieve reactivity addition would have ocouned due to the boric acid '
transfer pump autostari signal 1 eing inhibited or that the residual heat removal pump
minimum flow valves would have cycled continuously, due to the loss of . ,
instmmerd bus 213. As documented in NRC inspection Report No. 50 295/97013; ,
50-304/97013; 50-295/97012, and 50 295/fe7002; 50-304/97002, the failure to provioe
opwating procedures that contain guidance appropriate to the circumstances remains
F d'wi (See Also Section 01.2). Although tne violation example was self<hseiosing, t
it is be,ng cited since this la a repet'tive issue. _
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08 Miscellaneous Operations leaues ,
08.1 50.54m Performanoe Indicators
a. inspection Scope (71707)
The inspectors reviewed the development of selected 50.54(f) performance 'ndscators
- and interviewed operations, maintenance, and radiation protection personnel. ,
b. Observations and Findinns
The inspectors reviewed the following performance indicators:
C7 Percent Contaminated Floor Somoe
The licensee developed performance indicator C7, percent contaminated floor space, j
based on the percentage of the plant floor space that was contaminated ;
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> 1000 dpm/100 cm2, exclutting high radiation areas with infrequent access, inaccessible
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areas, vaults, pits, and area, routinely used for contaminated work. Throughout 1997,
the licensee lowered the percent of contaminated floor space consistent with the
established work down curve. At the end of September 1997, the goal for this
performmoe indicator was 3.18 percent, while the actual contaminated floor space was
3.20 percent. The inspectors noted that, while the percent contaminated floor space
- Indicator was approximately 3.20 percent, an additional 14.03 percent of floor space was ;
contaminated and excluded from the indicator in accordance with the definition. Some .
examples of areas that were contaminated and excluded from this indicator incduded the
volume control tack rooms, the horizontal and vertical pipe chases, the hold up tank
rooms, the maintenai.co caves, and the fuel pool areas. In addition, the inspedors noteo
that the containment buildings were contaminated and were not considered I.i the .
development of this indicator,
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C9 Per 91 Rework
The licensee developed performance indicator C9, percent rework, based on the
performance of any maintenance task which resulted in a loss of time or money within a
12-month period. However, the inspectors noted that the licensee only counted
corrective maintonat 4 items in assessing rework and that rework on preventive
maintenance, surveillance, repair /retum to stores, and modification activities were not
considered during the development of this indicator. Throughout 1997, the licensee had
lowered the percent rework from approximatet,r 10 percent to less than 3 percent, items
identified as rework were primarily captured by two processes, the integrated reporting
program and the rework focus report. The effativeness of the integrated reporting
program was dependent on the event screening committee to identify each item that as
rework. The inspectors also noted that the rework performance indicator manager
depended on the individual maintenance department's concurrence on each iter 1 that
was identified as rework.
C17 Overtime Hours
The performance indicator C17, overtime hours, was developed based on the number of
paid overtime hours for Zion Station employees through grade 11. The inspectors noted
that this indicator did not account for the overtime hours worked by senior management
or contractor personnel working at Zion Station. The action threshold for thir indicator
was met when the station's actual overtime hours worked plus the projected usage for
the year exceeded the goal by more than 10 percent. However, the action threshold was
for the entire station and did not apply for any single department, such as operations. For
example, operations' projected overtime for the period of January through June 1997 was
29,830 hours0.00961 days <br />0.231 hours <br />0.00137 weeks <br />3.15815e-4 months <br />. However, actual paid overtime was 43,367 hours0.00425 days <br />0.102 hours <br />6.068122e-4 weeks <br />1.396435e-4 months <br /> (45.38 percent above
projected); yet, this performance indicator did not provide any indication that there was a
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problem with the excessive use of overtime. In addition, the inspectors noted that this
indicator was financially oriented and was not an indication of safety performance.
c. Conclusions
l The insptetors concluded that the performance indicators C7, percent cortminated floor
space, and C9, percent rework, indicated that the licensee's performance in these areas
was improving; however, due to the limited scope of the definitions utilized to develop
these indicators, the inspectors questioned the absolute numbers represented in these
indicators, in addition, the inspectors concluded that the performance indicator C17,
j overtime hours, did not provide any meaningful indication of licensee safety performance.
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M1 Conduct of Maintenance !
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M1.1 Dislodned Temocrary Jumor Resulted in an inadvertent ESF Actuation j
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a. insooction Scope (62707) ;
The inspectors reviewed the circumstances surrounding the %edvertent E8F aduation on l
September 2,1997. The inspedors interviewed maintenance personnel, reviewed the r
applicable work instructions, and evaluated the licensee's root cause investigation and
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subsee9ent corrective actions. l
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b. Qhtervationsindfindinas
On September 2,1997, in support of the 2C accumulator level transmitter modification,
E22 2-97 264, instrument maintenance technicians installed temporary jumpers tc
maltdain power to the 2A s'.eam generator wide range level indication, in socordance with -
Work Package No. 970060620-01. During the installation of th6 second temporary l
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L jumper, the technician dislodged the first jumper which momentarily contaded an
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adjacent terminal en the terminal board and caused a short circuit. This short resulted in .
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a voltage per*urt>ation on instrument bus 212, which onused an ESF actuation. The
squipment that actuated included trips of all Eagle 21 bistables from rocks 8,9, and 10, ,
with the exception of those that were " energize to trip" or in a tripped condition before the j -
event, auto-start of the 08 and OC CC pumps, auto closure of the containment air sample
iniw isolation valve,2FCV-PR248, and a falso high alarm condition on the 2A residual ,
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heat removal cubicle radiation monitor,2Rl-PR03. The licensee subsequently stopped i
the work, restored the plard systems and equipmerd, and init;ated an investigation into
the event, in addition, the licensee made a four hour non-emergency report in !
accordance with 10 CFR Part 50.72.
The licensee's investigation determined that the cause of the event was the use of I
, jumpers with alligator type dips, which do not positively attach, and the technician having ;
reduced manual dexterity as a result of using low voltage rubber gloves with leather ;
protector outer gloves in a confined area. The licensee implemented interim corrective ,
actions prior to recommencing the work activity on September 4,1997. These actions
included protecting the terminal strip and adjacent areas to prevent the possibility of a
short, and the use of insulated jumpers and non-rated ' surgical" gloves instead of low
voltage gloves to improve the technicians manual dexterity. In addition, the licensee's
immediate corrective actions included briefing each of the maintenance departments on
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the event.
On Octobsr 9,1997, the maintenance department established a policy on the use of
temporaryjumpers. This policy included: (1) maintenance department head approval
'
prior to the installation of tempoJ.ry jumpers into an energized cabinet; (2) the use of
insulated jumpers when voltage is less than 480 volts instead of low voltage gloves ,
(" surgical * gbves optional); (3) protecting the terminal strip and agacent areas to prevent :
the possibility of a short; and (4) briefing operations prior to jumper installation to discuss ,
the ramifications of a dotadM Jumper or short circuit,
i
12
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c. Conclusiong
The inspectors concluded that the inadvertent ESF actuation was caused by the use of
temporary jumpers with alligator type clips and reduced manual dexterity due to the use
of low voltage gloves in a confined space.
M8 Miscellaneous Maintenance issues
M8.1 [Qoen) Licensee Event Report (LER 50-304/97001h Unit 2 Instrument Bus Perturbation
Caused by a Short Circuit Occuning During 2C Accumulator Level Transmitter
Modification installation Resulted in Engineered Safety Feature Actuation (See
Section M1.1)
While reviewing this LER, the inspectors identified that the CC phase B containment
isolation valve 2MOV-CC685 did not fait close as expeded; however, the LER state.t hat
all systems functioned as design and no anomalies were noted during the event. The
inspectors raised this apparent discrepany to the licensee's attention; and as a result,
the licensee initiated PIFZ1997-02259 to address this issue. This LER will remain open
pending the licensee's resolution of this apparent discrepancy.
MB.2 (Closed) Unresolved item 50-295/97016-09: 50-304/97016-09: Non-Conservative Power
Range Rate Trip Setpoint Tolerances
On July 15,1997, the licensee identified that the instrument maintenance procedure
acceptance criteria for the nuclear instrumentation power range rate trip setpotr' #as not
conservative. Specifically, instrument maintenance procedures N-41 throut' 44,
" Power Range Nuclear Instrumentation," required that the power range rat. , be
calibrated to trip at 5 percent of rated flux in 2 seconds with an allowable to,e ance of +1
percent. However, TS Limited Safety System Setting (LSSS), Section 2.1.1.C. required
that the trip be set at less than or equal to 5 percent of rated . lux in 2 seconds. As a
result, the licensee reported this issue to the NRC in accordance with 10 CFR Part 50.72.
During follow-up inspection, the i..spectors noted that on August 21,1997, the licensee
downgraded this issue from one that required a licensee event report in accordance with
10 CFR Part 50.73. The licensee's justification for this downgrade was that a search of
instrument calibrations back to 1995 did not identify any examples where the *as left"
setpoints exceeded the LSSS and that a review of this issue in 1995 did not identify any
previous examples where the LSSS had been exceeded.
On September 19,1997, in response to the inspectors' questions and requests for
documentation, the licensee identified that on May 16,1994, the nuclear instrumentation
power range rate trip setpoint for channel 2N-43 had been set 'as loft" at 5.1 percent In
addition, prior to the next calibration of channel 2N-43, the licensee removed channel
2N 41 from service for calibration on August 1,1994, which resulted in only 2 operable
channels being available for 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> and 28 minutes. However, TS Table 3.1-1 requires
a minimum of 3 operable channels, except that for channel testing, calibration, or
maintenance the minimum number of channels may be reduced by 1 for a maximum of
2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />; otherwise, the unit should be in hot shutdown withh 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
13
_ - ____- ___ ____ _ _ - _ - - _ _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ - _ -
_ _ _ _ _ _ . _ _ _ - -__ -
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While reviewing the cabbration documentation previoush reviewed by the licensee, the (
- inspectors identWlod a second example where the nuclear instrumentation power range l
rate trip setpoint was set 'as left* greater than the L888. SpeclRosly, on l
>
February 6,1993, channel 2N 42 was rst *as left" at 5.6 percent. In addition, prior to the
next onlibration of channel 2N-42, the licensee removed chantni 2N-41 from service for
j' calibration on April 26,1993, which resuhvi in ony 2 operable channels being available j
for 9 hows and 15 minutes. The inspectors also identined that the l6censee was missing ;
and had not reviswed the data from approximately 35 power range calibration j
procedures. The licensee subsequenth located each of the calibration procedures, l
except 2N-42 which was completed on May 13,1994. The subsequerd review of these
=
procedures did not identify any additional instances where the power range rate trip was i
t
'
set greater than the L888,
-!
TS 3.1.1 states that the setpoints for the reactor protection system are presented in
Table 3.1 1. Table 3.1 1 spoolnes, in part, that the power range rate trip setpoint be
5 percent of rato6 neutron flux /2 seconds. In addition, the setpoints are to be *
estat:lished tolerances for instrument channel and setpoint errors as speciAed in -
" Zion N888 [ Nuclear Steam Suppy System] 8etpoint Evaluation, Protection System ,
. Channels, Eagle 21 Version," but, the instruments shall not os set to exceed a L888. ;
- The failure to establish the nucluar instrumentation power rence rate trip setpoint for 1
channels 2N-42 on February 6,1993, and 2N-43 on May 16,1994, as required by
Teble 3.1 1 is considered 3 violation of TS 3.1.1 (50-304/97022 03), as described in the ;
,
attached Notice.
.
TS 3.1.2 states, in pa,1, that for all on line testing or instrumentation failure, plant
! operation shall be permitted in accordance with Table 3.1 1. Table 3.1 1 requires for the
power range rate trip, a minimum of three operable channels, except that for channel
testing, calibration, or maintenance the minimum number of channels may be reduced by
one for a maximum of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />; otherwise, the unit should be in hot shutdown within 4
hours. The failure to maintain the minimum number of operable power range rate trip ,
channels or place the plant in hot shutdown within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> on April 26,1993, and
August 1,1994, as required by Table 3.1 1 is considered a violation of TS 3.1.2
(No. 50 304/97022-04), as described in the attached Notice.
TS 6.5.1.D requires, in part, that calibrations performed to verify surveillance ;
'
requirements (Section 4 of the TSs) be retained for at laast five years. TS 4.1.2
specifies, in part, that inst!ument dannel calibration requirements for the various reactor
4
protection instrumentation and logic channals are established in Table 4.1 1. Table 4.1-1
requires, in part, that the power range rate trip channels be calibrated quarterty. The
failure to retain the calibration record for the calibration of channel 2N-42 on May 13,
1994, is considered a violation of TS 6.5.1.0 (No. 50-304/9702LO5), This failure :
constitutes a violation of minur significance and is being treated as a Non Cited Violation,
consistent with Section IV of the NRC Enforcement Manual.
This unresolved item is closed.
1
14
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_ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
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lil. Enoineerina
E1 Engineering Support of Facilities and Equipment
E2.1 Containment Thermal Stress Anatvsis May Not B,qund the Main Steam Line Break
(MSLB) Analysis
On September 15,1997, while performing a safety evaluation for a recently re-performed
containment analysis, engineering personnel identified that the MSLB accident resulted in
a higher containment temperature than the lost of coolant accident event. This elevated
temperature could adversely affect the conf einment thermal stress analysis. The
licensee subsequently completed an evaluation of this condition which concluded that the
elevated temperature from the MSLB was bounded by the containment design
parameters. Consequently, the licensee determined that there was minimal safety
significance for this issue. This issue is considered an Unresolved item
(No. 50 295/97022-06; 50-304/97022-06) pe,iding NRC review of the licensee's
e.aluation of the containmerit thermal stress during a MSLB accident.
E2.2 Star'dbv Instrument Air Comoressor_Qaoacity Testina Not Performed
On September 30,1997, while performing modification testing on the north cribhouse
heating ventilation and air conditioning standby instrument air compressor, engineering
personnelidentified that the air compressor, as well as the station's other standby
- nstrument air compressors, had not been s.dequately tested. Specifically, the
compressors had not been tested to verify that they could maintain system pressure on a
loss of pressure in the instrument air system. As a result, the Shift Manager declared ali
of the station's standby instrument air compressors inoperable, initiated
PlF Z1997-01997, and initiated the development of a procedure to test the capacity of
each compressor. This isste is considered an Unresolved item (No. 50-295/97022-07;
50-304/97022-07) pending NRC review of the completeJ capacity test results and the
licensee's corrective actions.
E8 Miscellaneous Engineering lasues
E8.1 (Open) Unresolved item 50-295/97019-06: 50-304/970t9-0J6 Review the licensee's
investigation and corrective acuons for the zebra mussel fouling of the service water
(SW) system.
On August 7,1997, the iicensee declared the 1A SW pump inoperable due to not havlag
adequate service water cooling flow to the motor cooler. Following flushing of the cooling
water supply lines, the 1 A SW pump was declared operable on August 21,1997.
On August 23,1997, the licensee identified that the 1 A SW pump again had no cooling
water flow to the motor cooler. As a result, Unit i did not have any operable SW pumps.
With no operable Unit i SW pumps, the SW system was inuperable since the system
was unable to meet the single passive failure criteria. Consequently, the common unit
CC system was also declared inoperable since SW was a necessary support system.
Therefore, the Unit 2 RHR system was also inoperable since the CC system was a
necessary support system. b a result, the licensee entered Technical Specification
15
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Action Statement 3.3.1.A.5.a for having one operable RHR loop (one reactor coolant !
L system loop capable of natural circulation), which required immediate corrective action to l
retum the inoperable RHR loop to en operable status as soon as possible. In addition, >
the licensee notined the NRC of this condition in socordance with 10 CFR Part 50.72. l
,
Subsequently, on August 23,1997, the licensee restored the 18 SW pump to an operable t
condition; arW as a result, the SW, CC, and RHR system were declared operable. ;
On August 24,1997, the licensee's investigation identined live zebra mussels, too large :
!
to pass through the SW strainers, in the 1 A 8W pump pre 4ube piping. As a result, the
- licensee conducted radiography of the SW pre 4ube piping on both units, which identified ,
zebra mussel blockage in the pre 4ube piping for both the 1 A and 2A SW pumps. (
Cer.x ;1+,0y, the licensee initiated flushing of the pre 4ube pipirs for both the 1 A and !
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2A SW pumps. On August 25,1997, the pre 4ube piping for the 2A SW pump was
suooenfuny cleared of zebra mumis. Hower, the fiushing of the 1 A SW pump
pre 4ube piping was not suoosssful in clearing the zebra mussels from the piping. ;
4
in addition, the licensee identified that no chlorine (utilized to control zebra mussel !
Infestation) was evident in the 18 and 2A SW strainers and the 1 A,18 and 1C SW pump
motor host exchanger discharge lines. The pre 4ube piping tapped off the downstream :
- side of the B SW strainer on both units; honos, the Unit 1 pre 4ube piping was not being '
i
chlorinated. The licensee subsequently determined that the failure of the chlorination
system to deliver chlorine to the 18 SW strainer was due to a stuck check valve or an ;
obstruction in the line; and, the failure to deliver chlorine to the 2A SW strainer was a
mispositioned chemical injection valve, 2CA0416. 7
On August 25,1997, the licensee performed PT-11 DG28, *2B Diesel Generator Loading -
Test." During the performance of this test, the operators noted that the diesel lube oil ;
'
temperature was abnormally high (approximately 178 'F), but romshed less than the test
soooptance criteria of 180 'F. The diesel lube oil temperature was normally maintained
approximately 172 'F by a temperature control valve. The operators discussed the
elevated temperature with system engineering; however, no actions were taken since the
temperature remained less than the test acceptance criteria. On August 26,1997, the '
inspectors expressed concem to operations and engineering management, that the
identification of the zebra mussel infestation in the SW pre 4ube piping and the elevated
!
lobe oil temperatures on the 28 EDG could have been related.
. On August 27,1997, in response to the inspectors questions, the licensee initiated
PlF Z1997-01430 to document the elevated lube oil temperatures identified during testing
-
on August 25,1997. During the review of this Pif, the Shift Manager concluded that the
2B EDG was operable, and that no operability assessment was required. The
Shift Manager's basis for this determination was that the lube oil temperature did not
'
exceed the acceptance criteria; even though, the EDG loading was greater than that
required during accident conditions.
On August 28,1997, the licensee removed the 2B RHR train from service for testing. l
The inspectors were concemed that in the event of a loss of offslie power with the
2B RHR train OOS for testing; and with the operabi'ity of the 2B EDG ( the emergency ,
power supply for the 2A RHR train) in question due to expected heat exchanger fouling,
'
t L the licensee may not have had an operable RHR train capable of removing decay heat.
The inspectors again questioned operations and engineering management on the basis
.
16
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..~-,a n==~+--- -----vv, --,e. - . , ., ---w,.--n - , ~,an,-,-
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of the 28 EDG being considered operable given: (1) the elevated lube oil temperatures ;
observed on August 25,1997; (2) the identificatiors of zebra mussel infestation in the r
SW pro-lube piping; and (3) the historical fouling of the 25 EDG heat exchangers. l
W j
acceptance criteria of 100 'F. The 28 EDG was declared inoperable and the heat l
exchangers were inspected. Approximately 28.6 percent of the jacket water heat '
exchanger tubes and approximately 48.8 percent of the lobe oil heat exchanger
4 tubes were blocked.
!
!
temperature was approxionately 179 'F. The subsequerd inspections of the heat
exchangers revealed that gfsJ.Tf; 29.6 percent of the jacket water heat l
exchanger tubes and approximately 53.5 percord of the lube oil heat exchanger i
tubewere blocked.
!
- The design ce'oulation 228-B 009M 165, *EDG Jacket Water Heat Exchanger
Tube Plugging Margin," Revision 0, specified a maximum tube plugging margin of
11.18 percent; and,228-8 009M 186, * EDG Lube oil Cooler Tube Plugging ,
Margin," Revision 0, specified a maximum tube plugging margin of 19.19 percent. !
'
Engineering management responded that the 28 EDG was operable and not degrLded
since: (1) the EDG had met all of the acceptance critoria during testing on August 25, ,
1997; (2) the previous heat exchanger inspedion on March 28,1997, did not identify
significent fooling; and (3) the design calculation 228 8-009M 166, *EDG Lube Oil Cooler
Tube Plugging Margin," Revision 0, was conservative. On August 29,1997, the j
28 RHR train was retumed to service.
On September 3,1997, the licensee removed the 2B EDG from service and inspected I
the heat exchangers. The inspection revealed that approximately 59 petent of both the
Jacket water and the lube oil heat exchanger tubes were blocked. At the end of this _
!
inspection period, the licensee's investigation was in progress and corrective actions had
not yet been developed and implemented. Th's Untosolved item will roms:in open
pending further NRC review of the licensee's investigation and corrective actions for the
zebra mussel fouling of the SW system, including the licensee's basis for concluding that ,
the 2B EDG was fully operable with significant heat exchanger fouling,
i
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IV. Plant Support !
1
.
Si Conduct of Security and Safeguards Activities ;
S1.1 Compensatory Measures Not Established For A Dearaded Vital barrier
a. Inspection Scope (71750)
f
! The inspectors reviewed the circumstar,ces surrounding the licensee's failure to establish ,
i
compensatory measures for a degraded vital area barrier. The inspectors interviewed
operations and security personnel and reviewed applicable proce(ures and
17
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documentation including Zion Administrative Procedure 110006, " Security Banies and
Compensatory Measures By Secunty Personnel," Revision 0. ,
,
. b. Observations and Findines l
On Septemtm 22,1997, a security wporvisor identified that a vital area border for the
Unit 2 unN auxiliary transformer was degraded without compensatory measures in place, i
The licensee immediately implemented compensatory measures for the degraded banier
>
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and reported the event to the NRC in accordance with 10 CFR Pad 73.71.
.
The licensee determined that elodrical maintenance personnel removed the security l
access sleeve en Septer%er 8,1997, in support of the isolated phase bus duct shorting ;
!
strap modification,522 2 96 213. On September 9,1997, maintenance personnel
reinstalled the border. However, the banier was not installed in the original configuration, ,
in that, only one of two bolts was fastened on one of two collars. This as left l
configuration was determined to have been soceptable by a security supervisor and the :
responsible maintenance supervisor; and, the associated compensatory measures were . !
terminated. At some point between September 9 and 22,1997, tne security collar
became unattached.- As a result, on September 22,1997, a pathway from the protected
area to the vital area was created when electrical maintenance personnel removed a
panel inside the vital area that was associated with the bus duct.
While reviewing the everd, the inspectors identifled that the security compensatory I
checklist did not provide guidance or instrudions for ensuring that barriers were i.
adequately secured prior to secuting the compensatory measures. This issue is '
considered an Inspection Follow up item (No. 50 295/97022 06) pending NRC review of
the licensee's completed investigation and conective actions.
c. Conclusion
The inspectors concluded that the security personnel inappropriately terminated the
compensatory measures for the degraded vital area banier.
81.2 inattentive Secunty Officers .
a. Insoection Scope (71750)
.
The inspectors reviewed the circumstances surrounding two security officers who were
inattentive while standing watch. The inspectors interviewed operations and security
personnel and reviewed app lcable procedures and documentation including Zion Station
Approved Security Program (ASP) OP-003, " Attention To Duty,' Revision 5.
b. Observations and Findinog
On September 23,1997, a security officer identified that another security officer was .
.
.
asleep while standing watch at the Unh 2 auxiliary electric equipment room. The security
officer had been stationed to control access to the room while the licensee was
conducting an investigation into the loss of instrument bus 213 (See Section 01.3).
On October 7,1997, a security supervisor identified that a security officer was inattentive
18
a
Jn.~.-- , . . ., l- w - - ~- . , , , , , - . ~ . - - - - - - - , - , , , , , - , - . - - , . . - - - , - , - - - - - - - , - ~ - ~--,-v.
_ _ _ - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _
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while performing duties as a compensatory measure. The security post had been
established as a corrective action to the degraded vital area barrier event on
September 22,1997 f,See Section 81.1). Although the licensee had established the
security post, during the time that the security officer was inattentive, the compensatory
measure was not required since the vital Srea barrier was intact.
In each case, after finding the inattentive security officer, the licensee searched the area,
relieved the security officer from duties, and commenced an investigation. This issue is
corisidered an Inspection Follow-up item (50-304/97022-09), pending NRC review of the
licensee's completed investigation and corrective actions.
c. Conclusion
The inspectors concluded that the security personnel were inattentive to their assigned
( duties.
V. Manaaement Meeti_nnt
X1 Exit Meeting Summary
The Inspectors presented the inspection results to members of licensee management at
the conclusion of the inspection on October 10,1997. The licensee acknowledged the
findings pressented. The inspectors asked the licensee whether any materialc examined
during the inspection should be considered proprietary. No proprietary information was
identified.
19
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PARTIAL LIST OF PERSONS CONTACTED j
Licensee
R. Starkey, Station Manager ;
D. Bump, Restart Manager
R. Godly, Regulatory Assurance Manager
F. Higgins, Work control Manager
E. Katzman, Radiation Protection Manager
T. Luke, Site Engineering Manager i
T. O'Connor, Operations hlanager
L Sdwneling, Training Manager
R. Zyduck, Quality and Safety Assessment Manager
K. Dickerson, Executive Assistant to Site VKm President
T. Saksefski, Executive Assistant to Site Vice President
R. Davey, Assistant Site Engineering Manager
R. Landrum, Shift Operating Supervisor
T. Marini, Quality and Safety Assessment AudN Supervisor
G. Ponce, Site Construction Superintendent
M. Bittman, Operations
R. Budowie, Operations
B. Knopper, Operations
M. Mason, Operations
D. Noldin, Operations
C. Stiles, Operations
8. Mehler, Engineering
B. Mammoser, Engineering
D. Beutel, Regulatory Assurance
F. Jones, Regulatory Assurance
L. Holde Nuclear Ucensing
N89
E. Cobey, Acting Senior Resident inspector
D. Calnoun, Resident inspector
IQUE
J. Yesinowski, Resident inspector
.
20
_ _ _ _. _
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LIST OF INSPECTION PROCEDURES USED
IP 37551 Engineering
IP 61726 Surveillance Observations
IP 62707 Maintenance Observation
IP 71707 P ani Operations
IP 71750 Plant Support Activities
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-295/304-97022-01a VIO Failure of non-licensed operator to retum the OA fire pump
to service in accordance with the OOS program
50 295/304 97022-01b VIO Failure to maintain an EDG starting air valve in the required
OOS position
50 295/304-97022-01c VIO Failure to place and maintain a RHR valve in the required
OOS position
50 295/304-97022-02a VIO Failure to provide appropriate guidance for testing the
autostart inhibit circuitry for the DC CC pump
50-295/304 97022-02b VIO Failure to provide appropriate guidance for operator
resporm to a loss of instrument bus 213 event
50-304/97022-03 VIO Failu to stablish nuclearinstrumentation power range
trip setpoint in accordance with tha LSSS
50-304/97022-04 VIO Failure to maintain the minimum number of operable power
range trip channels or place too unit in hot shutdown in
accordance with TS
50-304/97022-05 NCV Failure to retain calibration records in accordance with TS
50-295/304-97022-06 URI Review of the licensee's evaluation of the containment
thermal stress during a MSLB accident
50 295/304-97022-07 URI Review of the standby instrument air compressor capacity
test results and the licensee's corrective actions
50-304/97022-08 IFl Review the licensee's investigation and corrective actions
for the degraded vital arest banier
50-304/97022-09 IFl Review the licensee's investigation and corrective actions
for the inattentive security officers
Closed
50-295/304-97016-09 URI Review of licensee actions to resolve the power range rate
trip tolerance discrepancy
50-304/97022-05 NCV Failure to retain calibration records in accordance with TS
21
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Qiscussed
50-304/97001 LER Unit 2 instrument bus perturbation caused by a short circuit
occurring during 2C accumulator level transmitter
modification instaliation resulted in ESF actuation
50-235/304-97019 % URI Review of the licensee's investigation and corrective
actions for the zebra n.ussel fouling of the SW system,
including the licensee's basis for concluding that the 2B
EDG was fully operable with significant heat exchangar
fouling
22 .
.
UST OF ACRONYMS USED
AOP Abnormal Operating Procedure
CC Component Cooling Water
CIV Ch isolation Valve
DRP- Division of Reactor Pro}ects
EDG Emerge:wy Diesel Generator
ESF- Engineered Safety Feature
IDNS lilinola Department of Nuclear Safety
IFl inspector Follow-up item
IP inspection P.ooedure
LER Ucensee Event Report
LSSS Umiting safety System Setting
MSLB- Main Steam Une Break
NCV Noncited Violation
NRC- Nuclear Regulatory Commission
NGO Nuclear Station Operator
OOS Out-of-Service
OSP Operating Special Procedure
POR Public Document Room
PlF Problem identification Form
PT Periodic Test
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8 01_ System Operating instruction
TS Technical Specification
URI Unresolved item
VCT Volume Control Tank
VIO Violation
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