ML18152A357
| ML18152A357 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 08/28/1995 |
| From: | Belisle G, Branch M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A358 | List: |
| References | |
| 50-280-95-14, 50-281-95-14, NUDOCS 9509070215 | |
| Download: ML18152A357 (16) | |
See also: IR 05000280/1995014
Text
- - - - - - - - - - - - - - - - - - - -
Report Nos.:
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
50-280/95-14 and 50-281/95-14
Licensee:
Virginia Electric and Power Company
Innsbrook Technical Center
5000 Dominion Boulevard
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50-281
License Nos.:
Facility Name:
Surry 1 and 2
Inspection Conducted:. July 2 through August 5, 1995
Lead Inspector: ;t;LJ ~
- ,__
M. W. Branch,_ Senior Resident Inspector
Other Inspectors:
Approved by:
Scope:
D. M. Kern, Resident Inspector
W. K. Poertner, Resident Inspector
S. G. Tingen, Resident Inspector
~~e*
G.~Beisction Chief
Reactor Projects Section 2A
- Division of Reactor Projects
SUMMARY
8-/2-r/?J-
Date Signed
This routine resident inspection was conducted on site in the areas of plant
status, operational safety verification, maintenance inspections, surveillance
inspections, and Licensee Event Report followup, and action on previous
inspection items.
Inspections of backshift and weekend activities were
conducted.
Re-sults:
Plant Operations
Sufficient self contained breathing apparatus (SCBA) equipment was available
and operations and control room personnel were properly trained to respond to
9509070215 950828
ADOCK 05000280
G
2
a toxic gas event.
The recent decision to SCBA certify all Shift Technical
Advisors (STA) was a positive initiative to improve STA availability to the
control room staff during certain events (paragraph 3.1).
With the Unit 1 control room annunciators degraded, operators implemented
appropriate compensatory actions.
Management involvement and compensatory
_measures taken during corrective maintenance were good (paragraph 3.2).
Maintenance
On July 20, Unit 1 annunciators became degraded when an electrician
inadvertently .shorted the annunciator power supply during troubleshooting
activities (paragraph 3.2).
Engineering
Fire brigade composition and responsibilities, methods used to alert the fire
brigade, and fire fighting methods established for electrical fires were
consistent with NRC fire protection program guidance (paragraph 5.1).
Engineering calculations for a cask drop within the fuel building, were
technically accurate and sufficiently bounded current dry fuel storage cask
handling practices.
The inspectors noted that fuel handling procedures did
not specify a maximum height* at which dry storage casks could be moved above
the fuel building operating floor or the spent fuel pool. Appropriate actions
were taken to strengthen procedures in this area (paragraph 5.2).
Plant Support
Highly radioactive Na-24 sources were used during moisture carryover tests
performed on July 12 and July 14.
Controls for the unusual radiological
conditions were good.
Information gained from other utilities was effectively
integrated into the radiological work plan. Radiological protection
technicians provided close oversight and incorporated lessons learned from the
Unit 1 test into the Unit 2 test. Minor radiological control and
communication discrepancies were properly addressed.
Liquid radioactive
releases were effectively managed (paragraph 6.2) .
e
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
2.
- W. Benthall, Supervisor, Licensing
- H. Blake, Jr., Superintendent of Nuclear Site Services
- R. Blount, Superintendent of Maintenance
D. Christian, Station Manager
J. Costello, Station Coordinator, Emergency Preparedness
- D. Erickson, Superintendent of Radiation-Protection
- B. Garber, Licensing
- R. Garner, Outage and Planning
B. Hayes, Supervisor, Quality Assurance
- D. Hayes, Supervisor of Administrative Services
C. Luffman, Superintendent, Security
J. McCarthy, Assistant Station Manager
- S. Sarver, Superintendent of Operations
R. Saunders, Vic~ President, Nuclear Operations
- B. Shriver, Assistant Station Manager
K. Sloane, Superintendent of Outage and Planning
- E. Smith, Site Quality Assurance Manager
- T. Sowers, Superintendent of Engineering
- B. Stanley, Supervisor, Procedures
- J. Swientoniewski, Supervisor, Station Nuclear Safety
- N. Urquhart, Supervisor, Training
Other licensee employees contacted included plant managers and
supervisors, operators, engineers, technicians, mechanics, security
force members, and office personnel.
NRC Personnel
- M. Branch, Senior Resident Inspector
D. Kern, Resident Inspector
- K. Poertner, Resident Inspector
S. Tingen, Resident Inspector
- Attended Exit Interview
Acronyms used throughout this report are listed in the last paragraph.
Plant Status
During this *report period Mr. Brice Shriver replaced Mr. Alan Price as
Assistant Station Manager, Safety and Licensing.
Mr. Price is currently
on temporary assignment to INPO for two years.
2
On July 8, Unit 1 reactor power was reduced to 85% to allow turbine
valve freedom testing.
Power was returned to 100% after the test and
the unit remained at full power until August 3 when refueling coast down
commenced.
The unit was at 97% power at the end of the report period.
Unit 2 operated at full power for most of the report period.
On July
14, power was reduced to 98% and returned back to 100% for SG moisture
carryover testing.
3.
Operational Safety Verification (71707)
The inspectors conducted frequent tours of the control room to verify
proper staffing, operator attentiveness and adherence to approved
procedures.
The inspectors attended plant status meetings and reviewed
operator logs on a daily basis to verify operational safety and
compliance with TSs and to maintain overall facility operational
awareness.
Instrumentation and ECCS lineups were periodically reviewed
from control room indications to assess operability.
Frequent plant
tours were conducted to observe equipment status, fire protection
programs, radiological work practices, plant security programs and
housekeeping.
Deviation reports were reviewed to assure that potential
safety concerns were properly addressed and reported.
3.1
Self Contained Breathing Apparatus
A toxic gas release near another nuclear power facility recently
necessitated control room personnel to don SCBAs to permit them to
continue performing their duties in the control room.
The
inspectors reviewed the Surry UFSAR, station procedures, and
interviewed personnel to determine the degree to which Surry
Station control room operators rely upon SCBAs to cope with a non-
radio~ctive toxic gas release.*
The inspectors reviewed UFSAR section 2.1, and confirmed that no
serious on-site or off-site hazardous material threats to Surry
Station were identified. The last potential on-site source of
poisonous gas which could effect control room habitability,
bottled chlorine gas, was removed in 1988.
The TS were
subsequently amended to eliminate. the requirement for control room
chlorine gas monitors.
In addition, the control and relay room
ventilation system is equipped with tight redundant seismic
category I isolation dampers and weatherstripped doors which
permit control room pressurization with bottled air following an
accident.
The inspectors concluded that the introduction of toxic
gas to the control room was highly improbable.
Abnormal operating procedures O-AP-20.00, Main Control Room
Inaccessibility, revision 3 and O-AP-20.01, Main Control Room
Oxygen Monitor - Alarm or Malfunction, revision 1, discuss use of
SCBA in the control room.
Procedure O-AP-20.00 conservatively
lists poisonous gas as a possible cause for degraded control room
air. Fire and fire extinguishing system (carbon dioxide or Halon)
3.2
3
actuation are listed as the most probable events for which control
room operators would don SCBA.
The inspectors noted that these
procedures provided clear instruction regarding when to don SCBAs
in the control joom.
Five SCBAs are maintained in the control room for use by control
room personnel.
The inspectors observed that this number was
sufficient for the TS 6.1 required compliment of on-shift ROs(3)
and SROs(2) and that all RO/SRO personnel were SCBA qualified.
The inspectors questioned whether a SCBA was needed in the control
room for the STA, a TS required member of the shift. The STA
performs most of his duties from the STA office, but may be
requested to augment the control room staff during event response.
The fire protection coordinator informed the inspectors that there
are numerous SCBAs readily available to the STA along the main
turbine hallway.
The inspectors visually verified that a
sufficient number of SCBAs were available for the STA in close
proximity to the control _room.
The inspectors observed that some
STAs are not currently SCBA qualified. This could limit their
availability to the shift during certain events.
The SNS
Supervisor noted that while not required to perform duties from
the control room, SCBA qualification could improve STA ability to
respond to certain events.
He further stated that a schedule
would be developed by which all STAs would be SCBA certified
within the next.couple of months.
The inspectors noted that this
was a positive initiative to improve STA availability to the
control room staff. The inspectors concluded that personnel were
adequately trained and SCBA equipment was available for control
room personnel to respond to a toxic gas event.
Degraded Unit 1 Control Room Annunciators
On July 20, ~lectricians were checking voltage readings to verify
the condition of a suspected failed Unit 1 control room alarm
annunciator power supply.
The electricians inadvertently shorted
across a fuse holder and propagated a fault to the remaining eight
parallel power supplies. All annunciators on the A through E*
annunciator panels actuated. All, with the exception of two,
cleared when acknowledged.
Operators promptly adjusted selected
monitored parameters (i.e. containment partial pressure) and
verified that the A-E alarm circuits would still light to indicate
when an alarm condition was present.
However, the audible
annunciator horn and the alarm lock in feature were not working
properly.
The _licensee determined that the A-E annunciator panels
were degraded, but remained operable.* The shift implemented
abnormal operating procedure O-AP-10.13, Loss of Main Control* Room
Annunciators, revision 0, and directed the third RO to
continuously monitor the A-E annunciator panels.
The inspectors
concluded that operator response was appropriate .
The inspectors observed control room operators between July 20 and
23 and determined that augmented monitoring was effective. The
. *
4
inspectors discussed emergency plan entry conditions with the
shift supervisor.
The A-E annunciator panels represented 50
percent of the Unit 1 control room alarm annunciators.
The
emergency plan specified Unusual Event entry upon loss of >75
percent of control room alarms.
The operations shift properly
reviewed the emergency plan for implementation in the event the
annunciators further degraded.
Initial troubleshooting failed to identify the specific components
which caused the annunciator degradation.
Vendor assistance was
requested and troubleshooting activities were halted pending
arrival of the vendor.
SNSOC reviewed and approved further
annunciator corrective maintenance activities prior to
implementation. Certain maintenance activities required the A-E
annunciator panels to be fully inoperable.
Further compensatory
measures were established during this period. Critical parameters
were continuoµsly monitored on the ERF computer and the sequence
of events recorder was frequently reviewed.
Additionally, a
fourth RO was assigned to the shift to directly monitor related
plant parameters.
Electricians determined that three of the nine
parallel power supplies had failed. *Two power supplies .were
replaced and the A-E annunciator panels were returned to service
on July 23.
DR S-95-1694, including a human performance
evaluation, was initiated to determine the root cause of the ~vent
and verify follow-up corrective actions.
The inspectors
determined that management involvement and compensatory measures
taken were good.
Within the areas inspected, no violations or deviations were identified.
4.
Maintenance and Surveillance Inspections (62703, 61726)
During the reporting period, the inspectors reviewed the following
maintenance and surveillance activities to assure compliance with the
appropriate procedures and TS requirements.
4.1
Component Cooling Water Heat Exchanger Cleaning
4.2
On August 3, the inspectors witnessed work activities associated
with cleaning the A CC heat exchanger.
The work activity was
accomplished in accordance with WO 32139901 and procedure
O-MCM-0812-01, BC and CC Heat Exchanger Cleaning, revision 1.
The
inspectors reviewed the work package and verified that procedures
were followed.
The inspectors also verified that the isolation
boundary was adequate.
Control Room Chiller Flow Data
On August 3, the inspectors witnessed the performance of temporary
operating procedure O-TOP-4062, Obtaining Flow Data for 1-VS-P-18,
revision 1. This temporary procedure obtained service water flow.
data associated with control room chiller l-VS-E-48.
The
5
inspectors noted that service water flow dropped when control room
chiller 1-VS-E-4C came on.
This observation was discussed with
the system engineer who indicated that 1-VS-E-4C would not
normally be operated in parallel with 1-VS-E-4B.
Thus, the flow
data without 1-VS-E-4C in operation was the desired flow data.
The evolution was performed in accordance with approved
procedures.
Within the areas inspected, no violations or deviations were identified.
5.
On-Site Engineering Review (37551, 64704)
5.1
Fire Protection
The inspectors reviewed station fire brigade response activities.
The fire protection program is described in procedure VPAP-2401,
Fire Protection Program, revision 2.
The fire brigade is composed of three personnel from the
operations department (one of which is the scene leader), and two
security officers.
None of the fire brigade members share TS
licensed duties.
VPAP-2401 requires that the fire brigade be
activated upon notification in the control room of a fire, *
suspected conditions that could result in a fire, or at the
discretion of the SS.
The licensee's policy is not restricted to
fire or smoke.
VPAP-2401 states that if a fire is suspected,
notify the control room.
Neither VPAP-2401 or AP-48, Fire
Protection, Operations Response, revision 3, describe any delays
associated with activating the fire brigade.
Discussion with SS
and security personnel indicate that fire brigade responsibility
takes precedence over other duties.
However, security personnel
on the fire brigade would be relieved prior to abandoning their
security post.
The inspectors also reviewed the fire alarms available in the
control room and other areas of the station. The station fire
alarm which alerts fire brigade personnel is audible in the plant
during other alarms. Additionally, in high noise areas a red
alarm light is installed to alert.personnel of off-normal
conditions.
The station alarm system and Gai-Tronics used to
announce the fire emergency are powered from the semi-Yital bus.
The control room alarm which sounds when plant detectors sense
smoke or heat is faint but audible in the control room and it has
a distinct sound.
Based on conversation with operators, they
believe that they could hear the alarms during other events.
Additionally, there is a control room vertical panel annunciator
that also lights and sounds when a fire system alarm is received.
The inspectors questioned whether the licensee would combat an
electrical switchgear fire with water fog and under what*
conditions.
The stated licensee's policy leaves this decision up
to the scene leader .. The fire strategy plans indicate that
5.2
6
electrical systems should be deenergized if possible or practical.
Backup fire suppression is a water hose and procedures contain a
caution note about electrical shock hazard if water is used on
electrical fires.
Fire brigade-training addressed water usage on
electrical fires in the event that the power source can not be
deenergized.
The inspectors determined that fire brigade manning is the same
for all shifts. At least once per year each operating crew has a
back* shift drill. The criteria used to request off site
assistance is left to at the discretion of the scene leader and
the control room SS.*
Additionally, the inspectors reviewed the licensee EPIPs in the
area of fire related events.
Per EPIP-1.01 Tab I, Emergency
Managers Controlling Procedures, revision 34, a fire in the PA or
switchyard which is not under control within 10 minutes after the
fire brigade is dispatched is designated as an NOUE.
An Alert is
declared when a fire has the potential for causing a safety system
to become jnoperable when the plant is above cold shutdown
conditions. A Site Area Emergency exist when a fire causes major
degradation of a safety system function required for protection of
the public and affected systems are rendered inoperable .
Based on the inspectors review, fire brigade composition and
responsibilities, *methods used to alert the fire brigade, and fire
fighting methods established for electrical fires were consistent
with NRC fire protection program guidance.
Dry Fuel Storage Cask Drop Analysfs
The inspectors reviewed various engineering calculations to
determine whether current spent fuel storage cask loading
practices were bounded-by existing cask drop accident analysis.'
Engineering calculation 194, Fuel Cask Drop Crash Pad Design and
Analysis, dated September 23, 1982, postulated a cask drop into
the SFP from 1 foot above the refueling building operating floor~
The calculation was later updated to analyze a cask drop from
5 feet 8 inches above the operating floor.
In each case, the
postulated cask drop caused a tear in the SFP stainless steel
liner, but no significant structural damage to the surrounding six
foot concrete SFP wall or floor.
The resulting SFP leakage was
minor and well within the capacity of makeup sources. A
postulated radioactive material release due to damaged fuel
assemblies within the SFP was within regulatory limits. The
inspectors concluded that the calculations were technically
accurate and sufficiently bounded current dr~ fuel storage cask
handling practices .
The inspectors observed that procedure OP-4.22, Castor V/21 Cask
Loading and Handling, revision 6, did not specify a maximum height
at which dry storage casks could be moved above the fuel building
7
operating floor or the SFP.
The original license submittal stated*
that casks should not be carried at a height >6 inches above the
operating floor to minimize the chance of a cask roll accident.
Although operators typically minimized cask h~ight above the SFP,
the inspectors questioned whether procedure OP-4.22 provided
sufficient instructions to ensure cask handling was conducted
within the height limitations which had been analyzed.
The
inspectors discussed this observation with. nuclear fuel
performance analysis engineers and the fuel handling supervisor.*
The fuel handling supervisor revised procedure OP-4.22 to
incorporate the height restrictions prior to the next dry cask
load.
The inspectors reviewed the procedure revision and
determined that the handling height considerations were properly
addressed.
Within the areas inspected, no violations or deviations were identified.
6.
Plant Support (71707, 71750}
6.1
Plant Tour Observations
6.2
The inspectors observed radiological control practices and
radiological conditions throughout the plant. Radiological
posting and control of contaminated areas was good.
Workers.
complied with radiation work permits and appropriately used
required personnel monitoring devices.
The protected area
security perimeter was well maintained with no equipment or debris
obstructing the isolation zones.
Installation of new diesel fuel
oil supply lines for the station EDGs involved substantial civil
engineering .activities within the RCA.
Actions to maintain the
integrity of RCA boundaries and the security perimeter during
construction activities were effective.
Moisture Carryover Test
The licensee intends to implement a four percent core power uprate
during the second half of 1995.
MCO tests were performed on July
12 (Unit l} and July 14 (Unit 2} to measure the quality of the
steam currently produced by the SGs at rated power.
Station
engineers plan to use the test results to project the effect of
the core uprate on water impingement to the main turbine.
The MCO
tests involved injection of a highly radioactive Na-24 source into
the feedwater header-and monitoring the amount of sodium entrained
in moistur~ leaving the SGs.
The source vial contained over 1
curie of Na-24 and had a dose rate of over 1600 Rem.per hour on
contact.
The fifteen hour Na-24 decay half-life resulted in
elevated radiation levels at several locations within the turbine
building for several days following the MCO tests. The inspectors
closely observed the MCO tests to determine whether appropriate RP
practices were implemented to minimize personnel radiation
exposure and liquid effluent release.
8
Preparations for the MCO test were good .. Secondary leaks were
identified and repaired to the maximum extent practical. The
surveillance schedule was reviewed to ensure surveillances, such
as periodic TDAFW pump run which could release steam to the
environment, were completed prior to Na-24 injection.
SNSOC test
plan approval and pretest crew briefings were generally good.
The
inspectors toured the turbine building and verified that
appropriate radiological postings were inplace prior to the start
of the test.
The inspectors reviewed RWP-1090, MCO Project - Perform Unit 1 and
2 MCO Test Utilizing Na-24 Source, with the RP supervisor prior to
the test. The licensee had discussed RP precautions with other
utilities who recently performed similar MCO tests. Activities
which had a potential for high personnel exposure, e.g., Na-24
vial handling and injection valve manipulation, were rehearsed
prior to actual Na-24 injection.
The inspectors concluded that
the information gained from the other utilities was effectively
integrated into RWP-1090.
During performance of the Unit 1 MCO test, the inspectors noted
that the prerequisites for plant restoration following test
completion were DOt commonly understood by operations and RP
personnel.
Minor miscommunications resulted in slightly elevated
dose rate levels in the condensate polishing b~ilding before RP
personnel were positioned to survey the area.
The test
coordinator revised procedure 2-ST-0314, Steam Generator Moisture
Carryover Measurement, revision 0, to clarify prerequisites for
plant restoration and clearly communicated these prerequisites
during the prebrief for the Unit 2 MCO.
The inspectors discussed
other observations, including concerns for personnel heat stress
with the test coordinator. Radiological controls and protective
clothing requirements were appropriately modified for the Unit 2
MCO test.
.
.
Continuous RP coverage was provided during transport of the Na-24
sources from a local airport to the site. Security expedited on-
site acceptance of the Na-24 source which further minimized the
personnel radiation exposure received by the transportation crew.
RP personnel closely monitored all handling of the Na-24 source
including injection and sampling activities which had the
potential to spread contamination.
Background radiation levels
were too high, at the established turbine building exit point, for
the RM-14 portable friskers to be accura.te.
The inspectors
observed that some test personnel were using the frisker to exit
the RCA without noting the excessive background radiation level.
The inspectors informed the RP supervisor, who took appropriate
action to reestablish the RCA exit in a lower background radiation
area.
All test personnel properly used whole body monitor~ prior
to exiting the protected area. The inspectors reviewed postings,
surveys, and personnel exposure monitoring and determined that
radiological controls were appropriate and well planned.
9
The inspectors observed that the injection connections to the
Unit 1 feedwater header were not visually checked for signs of
leakage during the first 15 minutes of injection.
The inspectors
expressed concern that the vibration present at these test
connections could cause the connections to become loose and leak
highly radioactive Na-24 solution. Test engineers subsequently
began visual inspections of the connections at periodic intervals.
Chemists had difficulty obtaining representative SG samples during
the Unit 1 MCO test, due to the small sample line purge rate.
The
Unit 2 MCO test procedure was revised to incorporate five to
fifteen minute SG blowdowns directly to the station discharge
canal prior to each of four samples.
The inspectors questioned
whether the resultant liquid releases of .radioactive Na-24 were
within regulatory requirements.
Chemistry personnel informed the
inspectors that effluent release calculations based on the SG
activity measured during the Unit 1 MCO would be below the
regulatory requirements.
The licensee's calculations were
conservative, in that, they assumed no credit for radioactivity
removal in the SG blowdown ion exchanger.
The inspectors
independently performed an effluent release calculation and
confirmed that the release would be below that allowed by TS 6.8,.
10 CFR 20.1302, 10 CFR 20 Appendix B, and 10 CFR 50 Appendix I.
Discharge samples were taken and discharge records were
appropriately completed which confirmed that the.liquid
radioactive effluent releases were within specifications.
Within the areas inspected, no violations or deviations were identified.
7.
Licensee Event Report Followup (92700, 92901)
The inspectors reviewed the LERs listed below and evaluated the adequacy
of the corrective action.
The inspectors' review also included followup
of the licensee's corrective *action implementation.
7.1
(Closed) LER 50-281/93-005, Reactor Trip Due to Parti~l Actuation
of Safety Injection Master Relay During Logic Testing.
On August 21, 1993, technicians were in the final stages of*
completing SI Train B logic testing when Unit 2 tripped.
Subsequent troubleshooting indicated that the Train B SI master
relay was defective and caused the trip. The reactor trip .and
Train B SI master relay replacement were discussed in IR 50-280,
281/93-22.
Following the trip, RCS temperature decreased to 530,°F, i.e.,
less than 547 °F, no load TAvG*
As a result of this overcooling
and other overcooling events the licensee investigated probable
causes.
The inspectors reviewed engineering report NP-3005, Surry
Power Station Post-Trip Over Cooling, dated April 17, 1995.
The
report concluded that long term overcooling could be eliminated by
-~-~-------------------------------
7.2
10
more carefully controlling AFW flow rates to the SGs, minim1z1ng
any secondary steam leakage and prompt removal of auxiliary steam
and TDAFW driven AFW pump steam loads.
The inspectors revie~ed
emergency response procedures and verified that they were revised
to control AFW flow rates. The inspectors also noted that
excessive RCS cooldowns have not occurred following recent Unit
trips.
(Closed) LER 50-281/93-006, Unit 2 Automatic Reactor Trip Due to
Low SG Level in Coincidence With Feed Flow Mismatch Following
Closure of All Three MFRV.
On November 15, 1993, a single circuit breaker failed which caused
all three MFRVs to shut.
When the circuit breaker failed, the SOV
to each MFRV deenergized and the respective MFRV shut as designed.
Unit 2 subsequently tripped due to the loss of flow to SGs.
The
trip and immediate corrective actions were discussed in IR 50-280,
281/93-26'.
When the Unit 2 reactor tripped, the AFW pumps started on low-low
SG level. The packing smoked excessively on the AFW pump 2-FW-P-
3A and the pump was secured and declared inoperable.
The cause
and corrective action associated with the pump packing were also
discussed in IR 50-280, 281/93-26.
Following the trip, RCS temperature decreased to 525 °F, an
overcooled condition.
RCS overcooling corrective actions are
discussed in paragraph 7.1.
The inspectors verified that the
failed breaker was replaced and a PM program was implemented to
periodically replace the breaker and similar type breakers.
7.3
(Closed) LER 50-280, 281/93-004, Condition Prohibited by TS during
Reactor Protection System Logic Testing.
During a procedure review on March 16, 1993, the licensee noted
that monthly procedure l/2~PT-8.l, Reactor Protection System
Logic, revision 1, blocked both trains of SGBD trip valves .from
automatic closure associated with an AFW start signal.
Prior to
February 21, 1993, TS 3.8 listed SGBD trip valves as phase I
containment isolation valves. These valve were required to be
-operable to satisfy containment integrity requirements when RCS
temperature* exceeded 200 °F.
The licensee determined that
performance of 1/2-PT-8.l violated TS 3.8 as written prior to
February 21, 1°993.
The cause was personnel error involving
failure to adequately assess 1/2-PT-8.*1 for TS compliance.
Engineers reevaluated the containment isolation function and
determined that.the SGBD trip valves were not required for
containment integrity.
TS Amendments 172 and 171 removed the SGBD
valves from TS on Units 1 and 2 respectively, effective February
21, 1993.
Engineers further determined that automatic closure of
these valves was not required to assure adequate AFW flow.
The
11
inspectors reviewed the bases for the license amendments and found
them to be technically adequate. Additional corrective actions
included UFSAR updates and a TS surveillance program review to
ensure full TS compliance.
The inspectors verified that
corrective actions were complete.
The LER described the event,
causal factors, *and corrective actions in detail and met the
reporting requirements of 10 CFR 50.72.
7.4
(Closed) LER 50-280/94-010, Missed Emergency Diesel Generator
Battery Surveillance Due to Personnel Error.
On September 29, 1994, engineers identified that procedure
O-EPT-0109-03, Weekly Emergency Diesel Generator Battery Pilot
Cell and Bus Voltage Checks, revision 1, due by September 27, had
not been performed.
The licensee immediately entered a 24-hour
LCO action condition in accordance with TS 4.0.3. Technicians
successfully completed O-EPT-0109-03, which confirmed that the EDG
batteries were operable, and the LCO was exited.
Based on
satisfactory battery surveillance results and the brief missed
surveillance interval, the inspectors concluded that this event
had marginal safety impact.
The licensee determined that the cause of this event was
inadequate post maintenance document review at the supervisor
level.
The electrical supervisors involved with this review were
personally counselled regarding their performance and management
expectations. Additional corrective actions included event
discussion during electrical department crew meetings to reinforce
the importance of self checking and personal accountability for
surveillance scheduling.
The inspectors determined that these
corrective actions were adequate and completed.
The LER
accurately ~escribed-the event and addressed all reporting
requirements.
Within the areas inspected, no violations or deviations were identified.
8.
Previous Apparent Violation Item Identification Number Revisions
To facilitate data trending and retrieval, items identified after 1992
that were considered as either apparent violations or potential
escalated enforcement items were assigned new Inspection Followup System
identification numbers.
For traceability, .these changes and the
associated status of each of the items are provided below.
Apparent Violation (EEI) 50-280, 281/94-24-01 is being
administratively closed in this report. The violation will now be
tracked as VIO 94-173 01014 and is considered open.
Apparent Violation (EEI) 50-281/95-06-0l was closed when tHe
Notice Of Violation, dated May 18, 1995, was issued with two
severity level IV *violations.* The violation, identified in the
NOV as violation A, was previously tr_acked as 50-281/95-06-03, and
9 ..
12
is now being tracked as VIO 95-053 01014.
The violationi
identified in the NOV as violation B, was previously tracked as
50-281/95-06-04, and is now being tracked as VIO 95-053 02014.
Both 50-281/95-06-03 and 50-281/95-06-04 are considered
administratively closed per this report.
and 95-053 02014 are considered open.
Exit Interview
The inspection scope and findings were summarized*on August 8, with
those persons indicated in paragraph 1.
The inspectors described the
areas inspected and discussed in 'detail the inspection results addressed
in the Summary section and those listed below.
Item Number
LER 50-281/93-005
LER 50-281/93-00~
LER 50-280, 281/93-004 LER 50-280/94-010
EEi 50-280, 281/94-24-01
VIO 94-173 01014
VIO 50-281/95-06-03
Status
Closed
Closed
Closed
Closed
Closed
Open
Closed
Description/(Paraqraph No.}
Reactor Trip Due to Partial
Actuation of Safety Injection
Master Relay During Logic
Testing (paragraph 7.1)
Unit 2 Automatic Reactor Trip
Due to Low SG Level in
Coincidence With Feed Flow
Mismatch Following Closure of
All Three MFRV (paragraph 7.2)
Condition Prohibited by TS
during Reactor Protection
System Logic Testing
{paragraph 7.3)
Missed Emergency Diesel
Generator Battery Surveillance
Due to Personnel Error
{paragraph 7.4)
Failure to Identify and
Promptly Correct Conditions
Adverse to Quality
{paragraph 8)
Failure to Identify and
Promptly Cdrrect Conditions
Adverse to Quality
{paragraph 8)
Minimum Number of PZR Pressure
Instruments Not Operable
During Power Operation *
(paragraph 8)
.
,.
Item Number
VIO 95-053 01014
VIO 50-281/95-06-04
VIO 95-053 02014
13
Status
- Open
Closed
Open
Description/(Paragraph No.}
Minimum Number of PZR Pressure
Instruments Not Operable
During Power Operation
(paragraph 8)
Failure to Adequately
Establish Measures to Identify
And Correct PZR Transmitter
Calibration Problem
(paragraph 8)
Failure to Adequately
Establish Measures to Identify
And Correct PZR Transmitter
Calibration Problem
(paragraph 8)
Proprietary information is not contained in this report. Dissenting
comments were not received from the licensee.
10.
Index of Acronyms
BEARING COOLING
COMPONENT COOLING WATER
CFR
CODE OF FEDERAL REGULATIONS
CARBON DIOXIDE
DR
DEVIATION REPORT
EOG
EMERGENCY PLAN IMPLEMENTING PROCEDURE
EMERGENCY RESPONSE FACILITY
INSTITUTE OF NUCLEAR POWER OPERATIONS
IR
INSPECTION REPORT
LER
LICENSEE EVENT REPORT
LCO
LIMITING CONDITIONS OF OPERATION
MOISTURE CARRYOVER
MAIN FEEDWATER REGULATING VALVE
NOTIFICATION OF UNUSUAL EVENT
Na
NRC
NUCLEAR REGULATORY COMMISSION
PROTECTED AREA
PREVENTIVE MAINTENANCE
RADIOLOGICAL EQUIVALENT MAN
RADIOLOGICAL CONTROL AREA
REACTOR OPERATOR
RADIATION WORK PERMIT
RADIATION PROTECTION
14
SELF CONTAINED BREATHING APPARATUS
SPENT FUEL POOL
STEAM GENERATOR SLOWDOWN
SAFETY INJECTION
SNSOC
STATION NUCLEAR SAFETY AND OPERATIN~ COMMITTEE
SNS
STATION NUCLEAR SAFETY
SOLENOID OPERATED VALVE
SENIOR REACTOR*OPERATOR
SHIFT SUPERVISOR
TAvG
TEMPERATURE - AVERAGE
TURBINE DRIVEN AUXILIARY FEEDWATER
TS
TECHNICAL SPECIFICATION
UPDATED FINAL SAFETY ANALYSIS REPORT
VPAP
VIRGINIA POWER ADMINISTRATIVE PROCEDURE
WORK ORDER
~F
DEGREES FAHRENHEIT