ML18152A386
| ML18152A386 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 08/23/1990 |
| From: | Fredrickson P, Holland W, Tingen S, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A387 | List: |
| References | |
| 50-280-90-24, 50-281-90-24, NUDOCS 9009140223 | |
| Download: ML18152A386 (14) | |
See also: IR 05000280/1990024
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report Nos.:
50-280/90-24 and 50-281/90-24
Licensee:
Virginia Electric and Power Company
5000 Dominion Boulevard
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50-281
Faci 1 i ty Name:
Surry 1 and 2
License Nos.:
Inspector
DaieS gned
F6?/f/)
Di'tei gned
- Approved
SUMMARY
Scope:
This routine resident inspection was conducted on site in the areas of plant
operations, plant maintenance, plant surveillance, licensee event report
review, action on previous inspection findings, and licensee self assessment.
During the performance of this inspection, the resident inspector~ conducted
review of the licensee's backshift or weekend operations on July 1, 2, 8, 14,
15, and 28.
Results:
In the area of plant operations, the operators performance during the reactor
trip on July 1 was considered good; however, distractions that challenge
operator expertise should be minimized or eliminated.
These distractions
involve recurring problems in the instrument air system, individual rod
position indication, and the operation of main steam dump valves and indicated
that additional corrective actions were warranted in these areas (paragraph
3.f.(1)).
9009140223 9ggg5~80
~DR
ADOCK O
PNU
2
In the area of maintenance, a weakness was identified in the program for
planning and accomplishing of work. in a timely manner.
The issue involved
isolation of safety related equipment for a longer period of time than was
required to perform the maintenance activity (paragraph 4.a).
In the area of safety assessment/quality verification, the preparation and
conduct of safety committee meetings that were reviewed during this inspection
period has improved over past committee meetings that were monitored earlier
this year (paragraph 8).
1.
Persons Contacted
Licensee Employees
REPORT DETAILS
W. Benthall, Supervisor, Licensing
- R. Bilyeu, Licensing Engineer
- R. Campbell, Electrical Foreman
- D. Christian, Assistant Station Manager
J. Downs, Superintendent of Outage and Planning
- D. Erickson, Superintendent of Health Physics
W. Gross, Supervisor, Shift Operatio~s
- R. Gwaltney, Superintendent of Maintenance
- D. Hart, Supervisor, Quality Assurance
M. Kansler, Station Manager
T. Kendzia, Supervisor, Safety Engineering.
- J. McCarthy, Superintendent of Operations
- A. Price, Assistant Station Manager
- E. Smith, Site Quality Assurance Manager
- T. Sowers, Superintendent of Engineering
- J. Williams, Mechanical Foreman
NRC Personnel
- A. Ruff, Project Engineer, Region II
- Attended exit interview.
Other licensee employees contacted included control room operators, shift
technical advisors, shift supervisors and other pla~t_p~rsonnel.
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2.
Plant Status
Unit 1 began the reporting period at power.
On July 1 the unit
experienced a reactor trip from 90% power. The trip is further discussed
in paragraph 3.f.(l). The unit returned to power operation on July 3 and
operated at power for the remainder of the inspection period.
Unit 2 began the reporting period at power and maintained this condition
throughout the inspection period.
3.
Operational Safety Verification (71707 & 42700)
a .
Daily Inspections
The inspectors conducted daily inspections in the following areas:
control room staffing, access, and operator behavior; operalor
adherence to approved procedures, TS, and LCOs; examination of panels
b.
C.
2
containing instrumentation and other reactor protection system
elements to determine that required channels are operable; and review
of control room operator logs, operating orders, plant deviation
reports, tagout logs, temporary modification logs, and tags on
components to verify compliance with approved procedures.
The
inspectors also routinely accompanied station management on plant
tours and observed the effectiveness of their influence on activities
being performed by plant personnel.
Weekly Inspections
The inspectors conducted weekly inspections in the following areas:
operability verification of selected ESF systems by valve alignment,
breaker positions,
condition bf equipment or component,
and
operability of instrumentation and support items essential to system
actuation or performance. Plant tours were ~onducted which included
observation of general plant/equipment conditions, fire protection
and preventative measures, control of activities in progress,
radiation protection controls,
plant
housekeeping
conditions/
cleanliness, and missile hazards.
The inspectors routinely noted the
temperature of the AFW pump discharge piping to ensure increases in
temperature were being properly monitored and evaluated by the
licensee .
Biweekly Inspections
The inspectors conducted biweekly inspections in the following areas:
verification review and walkdown of safety-related tagouts in effect;
review of sampling program (e.g., primary and secondary coolant
samples, boric acid tank samples, plant liquid and gaseous samples);
observation of control room shift turnover; review of implementation
of the plant problem identification system; verification of selected
portions of containment isolation lineups; and verification that
notices to workers are posted as required by 10 CFR 19.
d.
Other Inspection Activities
Inspections included areas in the Units 1 and 2 cable vaults, vital
battery rooms, steam safeguards areas, emergency switchgear rooms,
diesel generator rooms, control room, auxiliary building, cable
penetration areas, independent spent fuel storage facility, low level
intake structure, and the safeguards valve pit and pump pit areas.
RCS leak rates were reviewed to ensure that detected or suspected
leakage from the system was recorded, investigated, and evaluated;
and that appropriate actions were taken, if required. The inspectors
routinely independently calculated RCS leak rates using the NRC
Independent Measurements Leak Rate Program (RCSLK9).
On a regular
basis,
RWPs were
reviewed,
and specific work activities were
monitored to assure they were being cond~cted per the RWPs.
Selected
radiation protection instruments were periodically checked, and
equipment operability and calibration frequency were verified.
3
On July 1, following the Unit 1 reactor trip, which is discussed
paragraph 3.f.(l), 2 of 8 main steam dump valves stuck. partially
open. After unit restart, the inspectors examined the Units 1 and 2
main steam dump valves. Results of this examination revealed t~at the
licensee had utilized a rubberized compound in the pack.ing area of
several main steam dump valves to prevent air leakage into the
condenser. This condition was brought to the attention of licensee
management.
The
licensee stated this would not affect valve
operation; however, the inspectors did not consider this type of
repair to be normal. The licensee was investigating a better type of
packing repair to resolve this issue which would be implemented
during upcoming outages. The inspectors will monitor future licensee
actions in this area as part of their routine outage inspection
activities.
During this inspection period, the inspectors observed operator
requalification program training.
The training included a scenario
on the simulator performed by the C operations team in which two non-
licensed operators were
used as emergency communicators
for
performing certain steps in the emergency
plan
implementing
procedure. The scenario involved a steam generator tube rupture with
other complications, such as a failed air ejector radiation monitor,
and the inability to manually initiate safety injection.
The
inspectors noted that the team detected the problems and properly
handled the scenario satisfactorily and in a reasonable period of
time.
The inspectors noted that the team detected the problem and
properly handled the scenario satisfactorily and in a reasonable
period of time.
During the latter part of the inspection period, several events
occurred which were brought to the inspectors attention by station
management.
These events included operational errors associated with
alignment of systems (CVCS
and chilled water) and unexpected
detection of gaseous releases through the monitored release path.
Although no TS LCOs or limits were reached, these multiple events
occurring over the last week. warrant further review and evaluation
and will be discussed in next month 1 s inspection report.
e.
Physical Security Program Inspections
In the course of monthly activities, the inspectors included a review
of the licensee 1 s physical security program.
The performance of
various shifts of the security force was observed in the conduct of
daily activities to include: protected and vital areas access
controls; searching of personnel, pack.ages and vehicles; badge
issuance and retrieval; escorting of visitors; and patrols and
compensatory posts.
No discrepancies were noted.
f.
Licensee 10 CFR 50.72 Reports*
(1)
On July 1, 1990 the licensee made a report in accordance with 10
CFR 50.72 concerning a Unit 1 reactor trip. At approximately
1802 hours0.0209 days <br />0.501 hours <br />0.00298 weeks <br />6.85661e-4 months <br />, on July 1, the A RSST input and output breakers
opened on a sudden pressure lockout signal. The transformer was
4
supplying normal power to the Unit lJ emergency 4160 volt bus.
The No. 3 EOG automatically started and the Unit lJ bus loaded
on the EOG as designed.
During the period of time that the
Unit lJ bus was deenergized, !RPI failed low and resulted in a
turbine runback from 100% power.
After !RPI was reenergized and
rod indication returned to normal, the runback signal cleared at
approximately 95% power.
At this time, operators noticed that
Unit 1 instrument air pressure was decreasing and dispatched an
operator to the air dryer location to investigate.
The
operator, upon arriving at the dryer location, noticed that the
Unit 1 air dryer was continually blowing down in an abnormal
manner.
The operator began to manually isolate the dryer from
the instrument air flowpath.
However, before the evolution
could be completed, Unit 1 was manually tripped when the control
room operator observed the C MSTV beginning to close. The MSTV
closure was due to the instrument air pressure reaching a point
where the valve began to drift shut.
After the reactor trip,
all three MSTVs went shut and the unit was stabilized in hot
shutdown with feedwater being supplied from the B MFP and C SG
PORV being used for decay heat removal.
lost power due to the A RSST not being available after the trip ..
All safety systems operated as designed. The B SG PORV did not
respond to demand and 3 of the 8 steam dump valves indicated
intermediate position after the unit was stabilized. Two of the
steam dump valves that indicated intermediate position were
later found to be stuck partially open.
Prior to the Unit 1 restart, corrective action was implemented
for each of the problems identified above.
The A RSST problem
was corrected. The packing was loosened on the two steam dump
valves that had stuck partially open. The position indication
limit switch was adjusted on the third steam dump valve and the
valves were then satisfactorily stroke tested.
controller was adjusted and the valve was satisfactorily
stroked. The licensee was not able to immediately identify the
cause of the instrument air dryer problem.
However, prior to
restart, interim corrective action was to have an operator
stationed at the IA area to bypass the dryers if they began to
blowdown and depressurize the instrument air system.
The inspectors monitored licensee immediate and corrective
actions prior to unit restart, reviewed the licensees post trip
review report, and observed selected restart evolutions.
The
operator's trip response was considered good; however, several
recurring equipment problems including instrument air dryer
problems, erratic individual rod position indication due to
momentary loss of power, and the operation of main steam dump
valves
indicated that additional corrective actions were
warranted to minimize or eliminate these problems.
Licensee
management al so recognized these recurring problems and was
planning corrective actions for each area.
On July 3, the unit
returned to power operation.
5
(2)
On May 12, 1990 the licensee made a report in accordance with 10
CFR 50.72 concerning a diesel oil spill of less than 10 gallons.
The spill occurred when a contractor's truck ran over a board in
the construction area causing a 3/8 inch fitting on the t~uck's
fuel tank to break. Approximately eight gallons of diesel oil,
which was not able to be recovered, leaked onto the dirt road in
the construction area
in
the
form
of a small
trail.
Approximately two gallons of diesel oil leaked from the truck at
the ISFSI pad.
The dirt where the two gallons of oil leaked was
removed and disposed of.
Diesel oil did not enter the waterway.
Within the areas inspected, no violations were identified.
4.
Maintenance Inspections (62703 & 42700)
During the reporting period, the inspectors reviewed maintenance
activities to assure compliance with the appropriate procedures.
Inspection areas included the following:
a.
Replacement of the Unit 1 TDAFW Pump Steam Supply SOVs
On July 10, the licensee replaced the ASCO SOVs to the Unit 1 TDAFW
pump main steam supply trip valves. These SOVs were replaced because
their EQ life had expired. Work orders 3800096886 and 3800096887 and
upgraded procedure O-EPM-2102-02,
ASCO Solenoid Valve Replacement,
dated May 24; 1990, were utilized to accomplish this maintenance.
After replacement, the SOVs were tested in accordance with procedure
1-PT:-I°5.1C, Turbine Driven Auxiliary Feedwater Pump, dated May 10,
1990.
The inspectors monitored the licensee's activities associated with
the replacement of the SOVs, including review of the maintenance area
isolation, work package, test results, and TS LCOs that were created
as a result of this maintenance. The inspectors visited the job site
and observed the craft plan the job using the upgraded O-EPM-2/02-02
procedure.
However, prior to performing the procedure, the craft
made several changes to it that involved torque values and
replacement of electrical connectors.
Since this procedure was
recently up-graded, the inspector specifically reviewed and examined
it in detail and after further investigation with regard to the
changes, the inspectors concluded that they were not necessary.
The
up-graded procedure could have been performed as it was written. The
inspectors considered that the changes, which were made at the
craft's request, were the results of poor and inadequate preplanning
for the job.
The job preplanning involved procedure review, changes and processing
of changes, staging of tools and parts that resulted in safety
related equipment being inoperable for approximately one shift longer
than necessary, however no LCD time constraints were exceeded.
The
isolation to accomplish this maintenance was established at 0539,
however, replacement of the SOVs did not commence until approximately
1545 hours0.0179 days <br />0.429 hours <br />0.00255 weeks <br />5.878725e-4 months <br /> on the same day.
The inspectors consider that activities
6
accomplished between 0539 and 1545 involving the above discrepancies
should have been identified during the prejob review.
The inspectors
ot,,
reviewed administrative procedure VPAP-2002, Work Requests and Work
Orders, dated July 1, 1990, and concluded that specific guidance on
minimizing out of service time on safety related components was not
addressed.
The inspectors discussed the delay in the start of work
on the subject components with station management.
Management agreed
that the subject maintenance activity experienced excessive delay in
the commencement of work after tagout of the safety related component
and were reviewing corrective actions when the inspection period
ended.
The inspectors consider that the excessive time involved in
commencing maintenance on safety related components after establish-
ment of isolation for the work is a weakness in the licensee's
program for planning and accomplishment of work.
b.
Repair of No. 2 Emergency Diesel Generator
On July 11, 1990, the licensee performed the quarterly exercise test
(2-PT-22.3M) on No. 2 EOG.
During this test a high temperature alarm
was received on the 1 ubri cat i ng oil system for the diesel.
The
cooling water alarm is set at 200 degrees Fahrenheit maximuM and the
actual water temperature reached 202 degrees.
Failure of the
periodic test placed the unit in a seven day LCO .
The licensee processed a work order to correct the high temperature
condition.
The corrective actions included replacement of the oil
cooler, cleaning of the radiator, repair of a small leak in the
cooling water to radiator piping, and replacement of the two cooling
water pumps.
The work was performed on work order no. 3800097762.
The inspectors reviewed applicable parts of the following procedures
which were used to perform the repairs:
- Procedure No. EE-EDG-M/Al, Emergency Diesel Generator Engine
One Year Service and Inspection, dated October 31, 1989
- Procedure No. EE-EDG-M/N3, Emergency Diesel Generator Engine
Six Year Service and Inspection, dated October 30, 1989
- Procedure No. MCM-1801-01, Piping/Components
Repair/Replacement, dated February 27,1990
The inspectors observed work in progress over a three day period of
time and observed the performing of the appropriate periodic test
used for returning the diesel to service.
No discrepancies were
noted.
Within the areas inspected, no violations were identified.
5.
Surveillance Inspections (61726 &'42700)
During the reporting period, the inspectors reviewed various surveillance
activities to assure compliance with the appropriate procedures as
follows:
~~~-~---
7
Test prerequisites were met.
Tests were performed in accordance with approved procedures.
Test procedures appeared to perform their intended function.
Adequate coordination existed among personnel involved in the test.
Test data was properly collected and recorded.
Inspection areas included the following:
- a.
Testing No. 2 Emergency Diesel Generator
b.
On July 14, 1990, the inspectors witnessed the performance of
periodic test 2-PT-22.3M, Diesel Generator No. 2 Quarterly Exercise
Test, dated December 12, 1990.
During the previous performance of
this test, the diesel failed to satisfy the test requirements because
of a high temperature in the lube oil system.
This condition
resulted in the repair to the cooling system which is discussed in
paragraph 4.b.
This test was being conducted after corrective
maintenance in order to return the diesel to service. The inspectors
observed testing in the diesel room including preparation for
starting, checking air starting system check valves and solenoids*
(IS! requirements), locally starting the diesel, performing diesel
oscilloscope test analysis, and recording of some of the test data.
The PT recorded a normal temperature for the lube oil cooling system
indicating that the maintenance activity had corrected the problem.
No discrepancies were identified.
Testing of Unit 2 Inside Recirculation Spray Pumps
On July 20, the inspectors witnessed the performance of periodic test
2-PT-17.2, Inside Recirculation Spray Pumps Test, dated October 25,
1989.
The purpose of this test was to verify operability of the
pumps as required by TS 4.5.B.l. The inspectors witnessed this test
from the Unit 2 swithgear room and reviewed the completed test
procedure.
2-PT-17.2 requires that the inside recirculation pump
vibration alarm be monitored during the test and if the alarm
persists, the pump is required to be immediately stopped.
The
inspectors asked what the alarm setpoint value was and if the pump's
vibration sensors were routinely calibrated. The licensee responded
that there were no procedures that routinely calibrated the vibration
instrumentation and that the alarm setpoint value was not immediately
available.
The
inspectors
reviewed the vibration detectors'
technical manual which specifies that the alarm setpoint value could
be adjusted to a. range of values and also contains instructions to
calibrate the detector.
The inspectors noted that the 1 i censee I s
inservice test program states that the inside recirculation - spray
pumps are equipped with a vibration detector and a high vibration
alarm in the control room and that this alarm would be observed
during each pump test. The inspectors consider that since the inside
recirculation pumps are safety related equipment and the inservice
c.
8
test program takes credit for this alarm during pump testing, the
vibration detector should be calibrcted and the alarm setpoint be set
at a conservative value. The licensee was evaluating the inspectors*
concerns in this area.
This wi 11 be foll owed up during subsequent
inspections
Testing of Unit 1, A Inside Recirculation Spray Pump
The inspectors noticed that on July 25, 1990, a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> hot shutdown
LCD was entered pending amperage reading evaluations on Unit 1 inside
recirculation spray pump A.
The pump was run for a period of 30
seconds maximum and the amperage on each of the three phases was
measured.
The three readings are required to have a minimum average
value of 109 amps.
When the abeve test was performed the average
amperage value was approximately 0.3 amp below 109 amps.
The
licensee recalibrated the meters used in the test and found one of*
the meters was reading ten percent 1 ower than the actua 1 value and
another meter was reading approximately three percent lower.
These
meters were reca 1 i brated and were used to re-perform the periodic
test. The inspectors witnessed the re-performance of this test, which
also was performed on July 25th, and observed that the amperages were
in the proper range.
Procedure l-PT-17.2, Inside Recirculation Spray
Pump Test, dated October 25, 1989 was used for these tests.
No
discrepancies were noted.
Within the areas inspected, no violations were identified.
6.
Licensee Event Report Review
(92700)
The inspector reviewed the LER 1 s listed below to ascertain whether NRC
reporting requirements were being met and to evaluate initial adequacy of
the corrective actions. The inspector 1s review also included followup on
implementation of corrective action and review of licensee documentation
that all required corrective actions were complete.
(Closed) LER 281/89-05, Unplanned ESF Component Actuation, Closure of 1A1
and
1C1 Condenser Waterbox Circulating Water Inlet Valves.
The issue
involved unexpected closure of valves during testing of the turbine
building flood control circuitry.
Immediate response included operator
actions to maintain intake canal level within the normal operating band.
, The event was caused by the actuation of a relay that was recently
replaced.
The *licensee 1 s review of the event determined that the new
relay, which was different from the old relay, required on electrical
circuit modification
for
proper system operation.
A subsequent
modification was made to the electrical circuit for the new relay and
verified proper operation by testing.
In addition, an evaluation was
conducted to determine how the new relay was initially installed without
the required circuit modifications.
This evaluation determined that a
substitute part had been provided by the vendor which did not have the
exact electrical characteristics of the old part. Therefore, use of the
new replacement part on this non-safety related maintenance activity was
not challenged.
Since this occurrence, the procurement process has been
changed to assure that adequate reviews are accomplished for all parts.
9
The inspector reviewed the licensee 1 s actions associated with this event
and held several discussions with station supervision and engineering
personnel in reviewing this area.
7.
Action on Previous Inspection findings
(92701, 92702)
a.
(Closed) Violation 280, 281/87-06-01, Failure to Follow Procedure.
b.
C.
This issue involved maintenance activities that were not properly
completed or documented.
The licensee responded to this violation in
a letter dated July 17, 1987.
In that letter, the licensee stated
that corrective action involved correction of the deficiencies
identified, meetings between mintenance personnel
and
station
management where the importance of procedural adherence and proper
documentation were discussed, .p.nd the formation of teams that
reviewed completed work packages for completion.
The inspectors
verified that the corrective actions were implemented.
(Closed)
Violation 280/89-21-01,
Failure to Provide Adequate
Procedure and/or Instructions for the Calibration of Instrumentation.
The violation was identified in Inspection Report 280, 281/89-21.
In
that report, the cause of the Unit 1 reactor trip that occurred on
July 9, 1989 was attributed to the I&C technicians* improper use of
an
ungrounded volt meter during recalibration of the NI flux
setpoints.
The licensee responded to this violation in a letter
dated October 2, 1989.
In that letter, the licensee stated that
in-house and operations experience review reports involving the
misuse of test equipment were reviewed and incorporated into lesson
plans taught to the technicians and that the instrument technician
development training program was revised to include instruction on
the used of grounded/ungrounded test equipment.
The inspectors
reviewed these revised training plans and consider that the
licensee 1 s corrective action was adequate.
(Closed) URI 280, 281/89-21-05, Review of Licensee* s Program for
Implementing TS Requirements.
The issue was discussed in inspection
report 280, 281/89-21.
In that report a potential problem was
identified with regards to the normal implementation and review/audit
functions for implementation of TS requirements due to changes.
Since identification of this issue, the licensee has completed a
review of the TS and did not discover any additional discrepancies
with regards to TS requirements.
However, in order to assure that
the process of changing the TS would be adequately controlled, the
licensee implemented administrative requirements to provide guidance
so that changes to TS are processed in an orderly and expedient
manner
and
that adequate documentation is maintained.
These
requirements are addressed in SUADM-LR-05, Technical Speci fi cation
Changes.
The
inspector
reviewed
administrative
procedure
SUADM-LR-05,
Revision 2 dated June 7, 1990 and considers that
adequate administrative controls are in place to assure that TS
requirements are implemented at the station.
-1
10
8.
Review of Licensee Self Assessment Capability (40500)
During this inspection period, the inspectors attended several onsite
safety committee (SNSOC) meeting~ and evaluated the licensee's onsite
program for continuing review of the operational and safety aspects of the
nuclear facility as required by TS 6.1.C. The inspectors attended SNSOC
meetings on July 17, 19, and 24 and made the following observations:
The inspectors reviewed the TS requirements and verified that the
meeting was in compliance with respect to composition, quorum,
meeting frequency, and review responsibilities.
On
July
17,
the committee
reviewed proposed administrative
procedures, procedure revisions 1 deviation report closeouts, and one
root cause evaluation associated with ESW pump 1-SW-P-18 failure to
start.
On July 19, the committee reviewed several engineering work requests
and design change packages which are* scheduled to be implemented
during the upcoming Un it 1 outage, two security training pl an
changes, several deviation report packages for closeout, one root
cause evaluation associated with reactor trips of both units on
May 22, 1990, and several operations and maintenance completed
procedures or procedure changes.
On July 24, the committee reviewed a design change package for
control room modifications.
In addition, the station QA supervisor
for audits presented the results of a corporate QA audit in the area
of fitness for duty.
The inspectors specifically noted that control of the committee review
process was well coordinated by the chairman. Only one issue or item was
focused on by all committee members at one time, and members appeared to
be familiar with most of the items dis~ussed due to advance routing of the
review packages.
The inspectors discussed review of agenda items that
were distributed prior to the meeting with several committee members. The
members considered that the agenda packages were distributed in a timely
manner and that there was adequate time available to review the
information prior to the meetings.
The inspectors consider that the
preparation and conduct of SNSOC committee meetings, which were reviewed
during this inspection period, are an improvement over past committee
meetings which were monitored.earlier this calendar year.
On July 17, 1990 the inspectors attended a meeting of the licensee's MSRC
which was being held at the Surry Power Station.
The MSRC has been
identified in a pending TS change as the offsite review committee which
will replace the current IOER group currently required by TS 6.2.
The
MSRC is comprised of senior corporate and station management as well as
several industry consultants.
Areas of discussion included 10 CFR 50.59
training, proposed TS changes, summaries on nuclear safety, IDER reports,
and QA audits, and other special reports associated with requested action
i terns.
The inspector noted that the committee appeared to be fully
functional and capable of accomplishing the required independent reviews.
11
9.
Exit Interview
~
The inspection scope and results were summarized on August 1, 1990 with
those individuals identified by an asterisk in paragraph 1.
The folJowing
summary of inspection activity was discussed by the inspectors during this
exit.
In the area of plant operations, the operators performance during the
reactor trip on July 1 was considered good; however, recurring operator
distractions including instrument air problems, individual rod position
indication~ and the operation of main steam dump valves indicated that
additional corrective actions were warranted in these areas.
In the area of maintenance, a weakness was identified in the program for
planning and accomplishing of work in"a.timely manner.
The issue involved
isolation of safety related equipment for a period of time longer than was
required to perform the maintenance activity.
In the area of safety assessment/quality verification, the preparation and
conduct of SNSOC committee meetings reviewed during this inspection period
were improved over past committee meetings that were monitored earlier
this year.
Licensee management was informed of the items closed in paragraphs 6
and 7.
The licensee acknowledged the inspection conclusions with no dissenting
comments.
The licensee did not. identify as proprietary any of the
materials provided to or reviewed by the *inspectors during this
inspection.
10.
Index of Acronyms amd lnitialisms
ASCO
CFR
eves
IOER
!RPI
LCO
LER
AUTOMATIC SWITCH COMPANY
TURBINE DRIVEN AUXILIARY FEEDWATER
CODE OF FEDERAL REGULATIONS
CHEMICAL VOLUME AND CONTROL SYSTEM
ELECTRICAL PREVENTATIVE MAINTENANCE
ENVIRONMENTALLY QUALIFIED
ENGINEERED SAFETY FEATURE
EMERGENCY SERVICE WATER
INSTRUMENT AIR
INSTRUMENTATION AND CONTROL
INDEPENDENT OFFSITE EVALUATION AND REVIEW
INDIVIDUAL ROD POSITION INDICATOR
INDEPENDENT SPENT FUEL STORAGE INSTALLATION
INSERVICE INSPECTION
LIMITING CONDITIONS OF OPERATION
UCENSEE EVENT REPORT
MAIN FEED PUMP
MSRC
MSTV
NI
NRC
SNSOC
sov
TS
VPAP
12
MANAGEMENT SAFETY REVIEW COMMITTEE
MAIN STEAM TRIP VALVE
NON-CITED VIOLATION
NUCLEAR INSTRUMENTATION
NUCLEAR REGULATORY COMMISSION
PRESSURE OPERATED RELIEF VALVE
PERIODIC TEST
QUALITY ASSURANCE
REACTOR COOLANT PUMP
REACTOR PROTECTION
RADIATION WORK PERMIT
STATION NUCLEAR SAFET~ AND OPERATING COMMITTEE
SOLENOID OPERATED VALVE
TECHNICAL SPECIFICATIONS
UNRESOLVED ITEM
VIRGINIA POWER ADMINISTRATIVE PROCEDURES