ML18152A227
| ML18152A227 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 11/01/1989 |
| From: | Fredrickson P, Holland W, Larry Nicholson, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A228 | List: |
| References | |
| 50-280-89-28, 50-281-89-28, NUDOCS 8911140119 | |
| Download: ML18152A227 (20) | |
See also: IR 05000280/1989028
Text
Report Nos.:
UNITED STATES
NUCLEAR REGULATORY COMMISSION
. REGION 11
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
50-280/89-28 and 50-281/89-28
Licensee:
Virginia Electric and Power Company
5000 Dominion Boulevard
Glen Allen, VA
23060
Oocket'Nos.:
50-280 and 50-281
Faci 1 ity Name:
Surry- 1 and 2
License Nos.:
Inspection Conducted:
September 3 - 30, 1989
Accompanying Inspector: M. S. Lewis, Project Engineer, DRP
, ... , s
I
-
Approved by:
- 1,
.
eA...A....,1/)
..*.
Scope:
P .. E. Fredrickson, Sect"bn Chief
Division of Reactor Protects
SUMMARY
/I /1 le?
Da& ITgned
This routine resident inspection was conducted on site in the areas of plant
operations,
plant maintenance,
plant surveillance,
plant
startup
from
refueling, evaluation of licensee self assessment capability, licensee event
report review, and followup on inspector identified items.
Certain tours were conducted on backshifts or weekends.
Backshift or weekend
tours were conducted on September 3, 4, 10, 15, 16, 17, 20, 23, 24, 28, and 30.
Results:
During this inspection period, one non-cited violation was identified for
failure to provide an adequate procedure for restoration of safety-rela_ted
valves following periodic testing (paragraph 3.a).
In addition, a licensee
8911140119 891101
ADOCK 05000280
Q
PNU
2
identified non-cited violation was noted for failure to provide adequate
procedures for filling *evolutions associated with the service water system
(paragraph 9).
A weakness in operator control of the electro-hydraulic control system at low
powers was noted. This weakness contributed to a Unit 2 reactor trip (paragraph
3.a). Strengths were noted with regards to the licensee 1 s management review of
Unit 2 restart readiness (paragraph 4) .
1.
Persons Contacted
Licensee Employees
REPORT DETAILS
- W. Bentha 11 , Supervisor, Licensing
- R. Bilyeu, Licensing Engineer
R. Blount, Superintendent of Technical Services
D. Christian, Assistant Station Manager
D. Erickson, Superintendent of Health Physics
- E. Grecheck, Assistant Station Manager
iM. Kansler, Station Manager
T. Kendzia, Supervisor, Safety Engineering
J. McCarthy, Superintendent of Operations
G. Miller, Licensing Coordinator, Surry
J. Ogren, Superintendent of Maintenance
T. Sowers, Superintendent of Engineering
- E. Smith, Site Quality Assurance Manager
- Attended exit interview
Other licensee employees contacted included control room operators, shift
technical advisors, shift supervisors and other plant personnel.
On September 19, 1989, one of the Commissioners of the Nuclear Regulatory
Commission, Dr. Kenneth C. Rogers, visited the Surry Power Station for a
familiarization tour, to meet with licensee management and staff, and to
review the current status of the station.
Commissioner Rogers was
accompanied by the following personnel:
J. Stohr, Director, DRSS, Region II
M. Lewis, Project Engineer, DRP, Region II
NRC Resident Inspectors
The
Commissioner
met
with
the resident inspectors, was
given a
presentation on the status of the station by licensee management, met with
selected station personnel, and was taken on a tour of the station
including the turbine building, control room, training simulator, and the
independent spent fuel storage installation.
Acronyms and initial isms used throughout this report are listed in the
last paragraph.
2.
Plant Status
Unit 1 began the reporting period at power.
The unit operated at power
for the duration of the inspection period .
2
Unit 2 began the reporting period in cold shutdown. After completion of
all work which was required prior to leaving cold shutdown, the unit
commenced heatup above 200 degrees Fon September 10.
The unit continued
with the startup sequence in accordance with procedures and was critical
on September 16, 1989.
During initial approach to criticality, the unit
was manually tripped due to improper control rod bank overlap.
This
problem is further discussed in paragraph 3.a.
Physics testing was
conducted on September 16 and 17, and the unit was connected to the
turbine generator on September 18.
However, during electrical checkouts
in preparation for connecting to the grid, the unit tripped from 14%
power.
This trip is further discussed in paragraph 3.a. After completion
of repairs to a generator relay, the unit was restarted late on
September 18 and connected to the grid on September 19.
However, during
initial turbine load1ng, the unit tripped from approximately 23% power on
low SG level in
11 8
11 SG.
This trip is further discussed in paragraph 3.a.
The unit was restarted on September 19 and was connected to the grid later
that evening.
The unit was operated at up to 40% power until September 22
when the turbine was taken off line for balancing due to vibration
problems.
The turbine was pl aced back on line on September 23; however,
the vibration problems continued and the unit was operated at 40% power
until September 28 when the turbine was again taken off line for
additional balancing.
The turbine balancing was completed and the unit
was preparing to return to power operations when the inspection period
- ended._
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;
operator
adherence to approved procedures, TS, and LCOs; examination of panels
containing instrumentation and other RPS elements to determine that
required channels are operable; and review of control room operator
logs, operating orders, plint deviation reports, tagout logs, jumper
logs, and tags on components to verify compliance with approved
. procedures.
On September 11, the inspectors were informed of a condition in which
the Unit 2 LHSI pump, 2-SI-P-lA, was operated for approximately 3
minutes witho~t*a suction flowpath.
Investigation by the operators
determined that-a manually operated pump suction valve (2-SI-57) was
shut.
Review of the configuration status logs and valve lineups for
restart of the un.it indicated that the valve was open.
Additional
reviews by the oper~ti6ns department determined that Type C leakage
testing in accordance with periodic test 2-PT-16.4 for containment
penetration 60 had been performed after the system valve lineups.
The test, which was performed on September 4, shut the valve for
3
testing, then required that the valve be reopened in the restoration
portion of the test.
However, the restoration step of the periodic
test required that valves which were positioned for testing be
returned to their required position without specifically listing each
affected valve.
The step did require independent verification;
however, it a 1 so necessitated that the operators review the entire
procedure to determine which valves needed to be repositioned.
After
completion of a review of the valves that were repositioned by
2-PT-16.4, it was discovered that one additional valve was not in its
correct position.
The inspectors and 1 i censee management discussed the use of the
PT-16.4
series
procedures
in
their
present
condition.
The
discussions focused on procedure use after unit valve lineups for
startup had been completed.
The inspectors were informed that use of
these procedures in their current condition would not be allowed
without requiring that additional
valve
by
valve
lineups be
accomplished and documented as a part of the valve restoration
process .. A 1 though the inspectors concluded that the valve 1 i neup
problem was caused in part by the operators 1 failure to follow
~rocedures, an
additional
contributor was
inadequate procedure
concerning the lack of specific valve restoration requirements.
Additional reviews concluded that the safety significance of this
problem was minimal due to the fact that the pump was not required to
be operable during the time frame that the valve was out of position
and additional critical valve lineups during the startup process
would have discovered the problem.
Failure to provide an adequate
procedure for restoration of safety-related valves following periodic
testing is a violation (NCV 281/89-28-01).
However, the violation is
not being cited because the criteria specified in Section V.G of the
Enforcement Policy were satisfied.
The inspectors specifically focused on Unit 2 restart activities
during the earlier part of the inspection period.
Inspection was
increased during the heatup and return to criticality of the unit.
The inspectors focused on the startup controlling procedures and
noted that greater operator attention was being placed on completion
of procedures prior to commencing the next sequential procedure than
had been displayed during the Unit 1 startup in July 1989.
Also
noted was proper verifications of initial condition steps prior to
commencing the performance section of the procedures.
However, the
inspectors believed that the operations procedures were still not
written in a manner which would provide for the best possible aid to
operators during the startup evolutions.
The inspectors consider
that these procedures should be upgraded in a priority manner
consistent with usage.
This concern was discussed with licensee
management and they agreed to review the priority assigned to these
upgrades.
The inspectors will review this area as part of the
procedure upgrade program review.
4
On
September 16,
the inspectors were conducting a backshift
inspection of the Unit 2 startup and witnessed a problem with the rod
control bank overlap system.
During rod withdrawal to criticality,
the
118
11 control bank was reading 15 st~s out when the
11A
11 control
rod bank was reading 103 steps out. This constitutes a bank overlap
of 88 steps versus the expected 128 steps.
The RO stopped rod motion
and contacted the SRO.
A decision was made to trip the rods in and
initiate troubleshooting by the instrument technicians. A four hour
notification was
made
to the
NRC at 1458 hours0.0169 days <br />0.405 hours <br />0.00241 weeks <br />5.54769e-4 months <br />.
Subsequent
troubleshooting failed to identify and/or repeat the problem and the
reactor was taken critical at 1950 hours0.0226 days <br />0.542 hours <br />0.00322 weeks <br />7.41975e-4 months <br />.
No abnormal conditions
were noted in the contra 1 rod bank overlap system during the
subsequeni pull to criticality.
The
inspectors witnessed the
operator actions in the control room during this time frame and
considered them to be appropriate.
On September 18, 1989 at 1042 hours0.0121 days <br />0.289 hours <br />0.00172 weeks <br />3.96481e-4 months <br />, Unit 2 tripped from 14% reactor
power.
The inspectors were in the control room at the time of the
trip and observed operator actions.
At the time of the trip, the RO
was
placing the generator voltage
regulator
in
service
in
preparations for connecting the main generator to the electrical
grid. While increasing generator voltage, the operator received a
generator backup relay trip alarm, indicating: that the Unit 2
generator had tri*pped.
The generator trip initiated a turbine trip
and
subsequent reactor trip.
Following the reactor trip, the
inspectors noted that Tavg decreased to less than 530 degrees F.
All
safety systems responded as required and the inspectors noted that
operator actions following the reactor trip were adequate.
On September 18, the licensee held a post trip review meeting with
those operators involved.
The inspectors attended the meeting, and
questioned the licensee with regards to the lower than expected Tavg
after the trip. The licensee concluded that the cooldown was nor~al
for the reactor conditions at hand, i.e. cool feedwater due to no
extraction steam, 210 gpm blowdown from the SGs, and no fuel decay
heat.
Licensee investigations on that same day revealed that the
generator trip was caused by an electrical problem in the generator
backup relay.
The relay was replaced and the unit was returned to
criticality. A four hour notification was made to the NRC at 1351
hours on September 18.
On September 19, 1989 at 0051 hours5.902778e-4 days <br />0.0142 hours <br />8.43254e-5 weeks <br />1.94055e-5 months <br />, Unit 2 tripped from 23% reactor
power on low low level in the
118
11
SG.
After the trip, required
safety systems performed as designed.
Both motor driven AFW pumps
auto started and SG levels were recovered into the normal bands.
A
four hour notification of the trip ~as made to the NRC at 0120 on
September 19.
b.
5
During discussions with the inspectors, the licensee attributed the
ca~se of the reactor trip to operator error in the operation of the
EHC turbine control system combined with a sensitive manual feedwater
control system.
Prior to the trip, feedwater to the SGs was being
controlled manually.
Just prior to the trip one operator was
attempting to establish AFW regulating valve control while another
operator was raising turbine load.
The operator controlling the
turbine increased load faster than normal, causing a temperature
decrease in the RCS ~nd subsequent closing of the SG steam dumps at a
low Tavg of 540 degrees F.
SG levels began to oscillate as a result
of increased load and subsequent steam dump closures.
Because of the
sensitive feedwater control
system, the operator was unable to
control the SG levels in the required band. Subsequently, a low low
level in the
11 8
11 SG initiated the reactor trip.
The Operations Superintendent described to the inspectors the proper
operator actions in increasing load for the reactor conditions at
hand, and stated that the turbine 1 oad 1 imi ter should have been
increased in a more controlled manner.
Discussions with the training
department personnel indicated that only specific steps in the
startup procedure are emphasized during training.
The specific
requirement associated with deliberate bumping up of turbine load
limiter at low powers appeared to be addressed in start~p procedure
2-0P-2. 2 .1,
Turbine -
Generator Startup to
20~6.
This event
demonstrated a weakness in operator control of the EHC system at low
powers.
Weekly Inspections
The inspectors conducted weekly inspections in the following areas:
verification of operability of selected ESF systems by valve
alignment, breaker positions, condition of equipment or component,
and operabi 1 i ty of instrumentation and support items es sent i a 1 to
system actuation or performance.
Plant tours were
conducted which
included observation of general
plant/equipment conditions, fire
protection and preventative measures, control of activities in
progress, radiation protection controls, physical security controls,
plant housekeeping conditions/cleanliness, and missile hazards.
The
inspectors routinely monitored the temperature of the AFW pump
discharge piping to ensure increases in temperature were being
properly monitored and evaluated by the licensee.
c.
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);
6
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 a re posted as re qui red by 10 CFR 19.
d.
Other Inspection Activities
Inspections included areas in the Unit 1 and 2 cable vaults, vital
battery rooms, steam safeguards areas, emergency switchgear rooms,
diesel generator rooms, control room, auxiliary building, Unit 2
containment, 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 fro~ 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 conducted per the
RWPs.
Selected radiation protection instruments were periodically
checked, and equipment operability and calibration frequency were
verified.
~-
Physical Security Program Inspections
In the course of monthly activities, the inspectors included a review
of the 1 icensee' 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, packages and -v_ehicles;
badge
issuance and retrieval; escorting of visitors; and patrols and
compensatory posts.
f.
Licensee 10 CFR 50.72 Reports
(1)
On September 3, 1989, the licensee made a report in accordance
with 10 CFR 50.72 concerning an inadvertent ESF actuation.
The
event, which was an auto start of the No.3 EOG, occurred during
the securing of the EOG in accordance with normal procedures.
The diesel had previously been running as a part of special test
ST-241, ESF Actuation with Instantaneous Undervoltage on the
Unit 2
11J
11 Bus.
The inadvertent restart was traced to a loose
connection on the terminal block of the Hi
Hi
CLS signal
circuitry.
Because of this loose terminal, the Hi Hi CLS signal
remai~ed locked in after the test and could not be reset.
This
condition resulted in the EOG auto start after returning the
diesel to the standby condition by placing the EOG selector
switch in auto. After identification of the problem, the loose
terminal was tightened, the Hi Hi CLS signal was reset and the
EOG was properly secured and placed in standby.
7
- (2)
On September 8, 1989, the licensee made a report in accordance
with 10 CFR 50.72 concerning an inadvertent a_ctuation of ESF
components on Unit 2 during performance of surveillance testing
on flood control circuitry. The testing was not associated with
ESF circuitry and the closure signal was not an ESF signal ..
However, the two valves that inadvertently closed were. ESF
components.
The problem was traced to a fault in a relay for
the flood control circuitry.
The
relay problem will be
corrected after completion of the investigation and procurement
of required parts.
(3)
On September 11 , 1989, the licensee made a report in accordance
with 10 CFR 50.72 concerning an ESF component actuation.
The
actuation was the closing of the containment instrument air
isolation valves due to a containment radiation monitor alarm.
The cause of the radiation monitor alarm was attributed to a
natural isotope buildup inside containment after pressure was
reduced in preparation for startup.
Sampling and no increase in
RCS leakage confirmed this conclusion. A setpoint change to the
radiation monitor was accomplished to allow for natural isotope
buildup.
(4)
On September 16, 1989, the licensee made a report in accordance
with 10 CFR 50.72 concerning an ESF component actuation.
The
actuation was the closing of one of the containment isolation
valves for the suction of the containment instrument air
compressor due to an* apparent loss of power to the valve
solenoid.
No valid ESF signal was present.
The licensee was
conducting an investigation into the cause of this problem when
the report period ended.
An
LER wi 11 be prep a red for this
event.
(5)
On September 16, 1989, the licensee made a report in accordance
with 10 CFR 50.72 concerning a manual trip of the Unit 2 reactor
during startup.
The licensee stated that during withdrawal of
the control banks for approach to criticality, _the operators
noticed an improper bank overlap between the A and B control
banks.
The startup was stopped and a manual reactor trip was
accomplished at the direction of the Operations Superintendent.
This event is further discussed in paragraph 3.a.
(6)
On September 18, 1989, the licensee made a report in accordance
with 10 CFR 50.72 concerning an automatic reactor trip of Unit 2
from
14% power.
The cause was a generator trip causing a
turbine trip which resulted in the reactor trip.
All safety
systems operated as designed.
This event is further discussed
in paragraph 3.a.
8
(7)
On September 19, 1989, the* licensee made a report in accordance
with 10 CFR 50.72 concerning an automatic reactor trip from 23%
power due to a low low level in the
11 8
11 SG.
All safety systems
operated as designed.
This event is further discussed in
paragraph 3.a.
(8)
On September 19. 1989, the licensee made a report in accordance
with 10 CFR 50.72 concerning a pipe which penetrates the Unit 2
containment being classified in *an unanalyzed condition from a
containment integrity standpoint.
The pipe was determined to be
suspect during a review of an existing pipe design.
The review
concluded that the support for the pipe was connected to both
the auxiliary building and the reactor building, which did not
allow for proper movement in a seismic event.
Corrective action
was. taken to disconnect the pipe support from one of the
buildings.
In addition, a licensee inspection determined that
the same condition did not exist on the other unit.
The cause
of the event was due to inadequate design review during
installation in the early 1980s.
This issue is discussed in
greater detail in paragraph 5.c.
Within the areas inspected, one non-cited violation was identified.
4.
Operaticinal Readiness Assurance Program Review - Unit 2 (7171P)
On September 4, 1989. the inspectors monitored the continuation of the
licensee
1 s management review of the functional areas associated with the
return to opera't ion of
Un it 2.
These funct i ona 1 areas inc 1 uded
operations, maintenance, surveillance, engineering, radiological controls,
safety assessment and QA.
The management team involved in these reviews
included the Station Manager, the two Assistant Station Managers, and the
Quality Assurince Manager.
The reviews were similar to those accomplished
for Unit 1 restart, and consisted of the appropriate supervisors of each
functional area discussing the restart readiness of their responsible
areas.
The inspectors _noted that one problem was .identified in the
l{censing area with regards to verification of the Unit 2 containment sump
cleanliness in accordance with a recent revision to TS.
Accordingly, a
decision was made to open up and reinspect the containment sump, resulting
in the unit restart schedule being
delayed.
This activity is further
discussed in paragraph 5.b.
After the completion of each review area, a list of action items was
generated.
The 1 icensee management al so discussed the status of unit
readiness prior to changing plant conditions and authorized each plant
condition change.
The inspectors monitored the licensee
1 s actions in this
area and believes that all restart issues* were adequately addressed. This
is considered an area of strength in the licensee
1 s performance.
- -
9
On August 31, 1989, the licensee sent a letter to the NRC which formally
documented the resolution of the CAL items that were identified in a
letter from the NRC dated March 9, 1989.
In their letter, the licensee
reviewed the status of each item and listed each outstanding action to be
completed prior to Unit 2 criticality.
The NRC sent a. letter to the
licensee on September 8, 1989 concurring with the completion status of
each CAL item for Surry Unit 2 restart.
The residents reviewed the
licensee 1 s letter and verified completion of the items prior to Unit 2
restart.
Within the areas inspected, no violations or deviations were identified.
5.
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.
Low Head Safety Injection Pump 2-SI-P-18 Repairs
During this inspection period, the inspector monitored the progress
and reviewed the documentation associated with the repair of the Unit
2 LHSI pump 18.
The pump repairs were required as a result of a high
vibration condition that occurred during performance of a routine
periodic test.
The licensee decided to disassemble, inspect, and
repair the pump in order to correct the condition which was
contributing to the high vibration.
The disassembly, inspection, and repair of the pump were accomplished
Actua 1 pump work was accomp 1 i shed in
accordance
with
maintenance
procedure
MMP-C-SI-090,
Removal,
Disassembly, Inspection, Repair, Reassembly, and Reinstallation of
Low Head Safety Injection Pump.
The inspector reviewed the completed
work package and specifically focused on foreign material exclusion
controls during reinstallation of the pump.
The inspector noted that
prior to reinstallation of the pump in its container, a visual
cleanliness inspection was made of this location by a QC inspector.
The inspector verified that pump container cleanliness was documented
by the QC inspector in the comp 1 eted procedure.
In *addition, the
inspector noted that the procedure required appropriate cleanliness
to be
maintained during all work evolutions.
The
inspector
specifically reviewed several material control accountability sheets
for different shifts accomplishing work.
The inspector believes that
the procedure documented adequate repair and
foreign material
exclusion control for the repair of ~-SI-P-18.
b.
Review of the Unit 2 Containment Sump Closeout Activities
During this inspection period, the licensee conducted a closeout
inspection of the Unit 2 containment sump.
This inspection was
accomplished in order to satisfy a TS amendment that was issued on
10
August 28, 1989.
The _amendment required that a visual inspection of
the containment sump be accomp 1 i shed at 1 east once each refue 1 i ng
period and/or after major
maintenance activities.
The
inspection was accomplished in accordance with Design Change 88-02-2,
Revisions 54, 55, 56, and 57, which were reviewed by the inspectors.
An inspection was conducted in this area during a containment tour.
The inspector specifically focused on the foreign material exclusion
requirements of the procedure. It was noted that the procedure
required a confined entry and tool control be implemented prior to
removing blanks over pump suctions and/or any time a screen assembly
was not in place.
The inspector verified that the foreign material
controls were documented in accordance with requirements whenever
action steps removing screens and/or blanks were accomplished.
The
inspection of the containment sump identified foreign objects from
the suction piping of one outside recirculation spray pump (one piece
of wire) and one LHSI pump (2 rags).
Deviation reports weie written
for the foreign objects and evaluation of each object concluded that
pump operability would not have been affected.
The
inspector
reviewed the deviation reports and discussed them with engineering
personnel. It was concluded
that this maintenance activity was
accomplished in accordance with required procedures.
c.
Seismic Support Repair
On September 19, 1989, the licensee made a report in accordance with
10
CFR
50.72 describing a pipe which penetrates the Unit 2
containment being classified in an unanalyzed condition from a
containment integrity standpoint.
One of the supports for the pipe
had hanger members connected on both the auxiliary building and the
reactor building surfaces.
The potential exists that both of these
buildings could move at different rates or distances during a seismic
event, and since it is uncertain how the hanger will respond, an
unanalyzed condition was identified.
The inspectors reviewed field
change AW to EWR 88-309, Repair to Miscellaneous Hangers.
This field
change required removal of the hanger member which was attached to
the reactor building wall (member RC-19.lA).
The inspectors also
discussed the removal .of this member with maintenance personnel
. performing the task.
Field change AY to EWR 88-309 documents that calculation SE0-1486 was
performed to demonstrate the acceptability of the modified support
with a new brace and base plate attached to the auxiliary building
floor.
Results of the calculation are that the interim condition of
the support, with the member to the reactor building wa 11 removed,
was acceptable, i.e. meets interim seismic requirements.
Although
the inspectors did not review the calculations, the inspector's
review of the EWR which documents that the calculations, along with
the witnessing of part of the hanger modification, allowed the
11
inspectors to arrive at the conclusion that the problem had been
properly addressed.
An engineering walkdown was performed to ensure
that the corresponding piping in Unit 1 did not have a similar
condition.
No discrepancies were found.
d.
Feedwater Isolation Valve Repair
On
September 15,
1989,
the inspectors observed a maintenance
electrician changing the wiring of a motor on Unit 2 feedwater
isolation valve MOV-FW-254C.
The work was being performed in
accordance with EWR 89-466, Eva 1 uate MI
Va 1 ves, and work order 3800085719.
A quality maintenance organization inspector was also
observing the work.
The inspectors reviewed the EWR, the work order,
and the work in progress, and found no problems.
Within the areas inspected, no violations or deviations were identified.
6.
Surveillance Inspections (61726 & 42700)
During the reporting period, the inspectors reviewed various surveillance
activities to assure compliance with the appropriate procedures as
fo 11 ows:
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.
Special Test 2-ST-245
On September 3, 1989, the inspector witnessed selected portions of
the performance of special test 2-ST-245, ESF Actuation with Delayed
Under Voltage (UV) (5 Min) - J Bus.
The purpose of the test was to
functionally check the sequencing of loads onto emergency bus 2J
following the injection of an ESF signal.
An undervoltage signal was
injected greater than 5 minutes after the initial ESF signal to
verify that the required loads tripped off the emergency bus and were
re-sequenced back onto the emergency bus in the required manner.
The inspector reviewed the test procedure to ensure that initial
conditions and testing prerequisite steps were performed.
Selected
pretest briefings by the test directors were monitored to evaluate
personnel
kn owl edge and understand;'ng of the re qui red tasks. The
inspector monitored test conduct from ESF signal initiation through
12
UV signal initiation and finally through test restoration. It was
noted that the test was controlled in an adequate manner and that
test discrepancies were identified to the test directors for proper
resolution.
No discrepancies were noted.
b.
Steam Dump Control System Valves
On September 10, 1989, the inspector reviewed test documentation
for calibration 63. Steam Dump Control System, and observed the
testing of three of the steam dump valves.
The inspector observed
the position of valves TCV-MS-2058, TCV-MS-2068, and TCV-MS-2088 as
the
information
was
bei~g
relayed to
other
instrumentation
technicians for a valve position verification.
Documentation was
complete and the test results indicated a proper position and
functioning of the three valves.
No discrepancies were noted.
c.
On September 15, 1989, the in specters witnessed hot rod testing of
the Unit 2 rods in accordance with periodic test 2-PT-7.2, Hot Rod
Drops.
This test measured the drop time for each of the 48 control
rods from fully wi thdra.wn to dashpot entry.
The in specter reviewed
the test procedure, witnessed control of testing from the control
room, and reviewed selected timing traces to independently verify
that the drop time was within the 2.4 seconds allowed by TS.
d.
Containment Spray System
On September 17, 1989, the inspector reviewed test documentation for
periodic test 2-PT-17.1, Containment Spray System, for spray pumps
2-CS-P-lA, wh-ich was tested on September 1, 1989, and spray pump
2-CS-P-18, which was tested on August 1, 1989.
Documentation was
complete and both pumps were considered operable.
e.
Inside Recirculation Spray Pumps
f.
On September 17, 1989, the inspector reviewed test documentation for
periodic test 2-PT-17.2, Containment Inside Recirculation Spray Pumps
Test, for inside recirculation spray pumps 2-RS-P-lA*and 18, which
were tested on August 28, 1989.
Documentation was complete and both
pumps were considered operable.
Condenser
On September 18, 1989, the inspectors witnessed licensee personnel
performing leakage tests on
the 8ntt 2 condenser.
Procedure
2-MOP-36.5, Secondary Plant Air Inleakage Inspection Procedure, was
being used.
The inspectors observed the planned release of helium
gas at five joints on the condenser during the testing.
Since the
condenser was under a partial vacuum, a leak at any of these joints
13
would enter into the condenser and later exit through the air ejector
line (elapsed time approximately one to two minutes). A helium leak
detector was placed in the air ejector line. The inspectors reviewed
part of the procedure, observed the release of the helium gas, and
observed the monitoring at the leak detector.
No discrepancies were
noted.
Within the areas inspected, no violations or deviations were identified.
7.
Plant Startup from Refueling
(71711)
During this inspection period, the inspectors witnessed testing and
monitored activities associated with periodic test 2-PT-28.11, Startup
Physics Testing. This procedure was the controlling procedure for several
of the tests that were required to be performed at low power levels
following refueling. The inspectors witnessed pretest briefings, verified
that specified conditions were met, and witnessed selected portions of the
following tests:
Reactivity Computer Accuracy Determination
This test determines the reliability range of the reactivity computer that
is used in subsequent testing by inserting and withdrawing control rods to
subtract or add reactivity.
The computer was determined to be accurate
within the range of plus 45 pcm and minus 43 pcm.
No discrepancies were
noted.
Isothermal Temperature Coefficient
This test involves measuring the MTC by determining the effects of plant
temperature changes on reactivity while maintaining constant rod position
and boron concentration.
The MTC was determined to be -3. 47 pcm/F.
No
discrepancies were noted.
Rod Swap Reference Bank Measurement
This test allows for measurement of the rod worth (pcm) of the reference
bank (control bank B) when fully inserted from 225 steps tb O steps.
No
discrepancies were noted.
Integral Rod Worth Measurements Using the Rod Swap Technique
This test allows for determination of the differential rod worth of the
reference bank (control bank B) when each of the remaining rod banks is
fully inserted from 225 to O steps.
The inspector witnessed selected
portions of this test when control bank
11 C
11 was the test bank.
No.
discrepancies were noted .
Within the areas inspected, no violations or deviations were noted.
14
8.
Evaluation of Licensee Self-Assessment Capability
On September 21, 1989, resident inspectors from Surry and North Anna, and
the NRC project engineer for Virginia Power plants visited the corporate
offices at Innsbrook Technical Center in Richmond, Virginia.
The visit
included discussions associated with the scheduling of current projects,
discussions
with
nuclear operations management,
discussions with
engineering management, and overviews of ongoing activities in the
emergency planning, nuclear operations support, quality assurance and
licensing areas.
Although the schedule did not provide for detailed
review of any area, it was apparent that the licensee had many new
programs in progress.
These new programs were in various stages of
preparation and/or development.
The inspectors concluded that additional
inspection time in the corporate offices to focus on specific programmatic
enhancements was warranted and additional inspection activities will be
scheduled as implementation of the new programs progress.
9.
Licensee Event Report Review
(92700)
The inspectors reviewed the LER 1 s listed below to ascertain whether NRC
reporting requirements were being met and to determine appropriateness of
the corrective actions. The inspector's review also 1ncluded followup on
implementation of corrective action and review of licensee documentation
that all required corrective actions were co~plete.
LERs that identify violations of regulations and that meet the criteria of
10 CFR, Part 2, Appendix C,Section V shall be identified as NCV in the
following closeout paragraphs.
NCVs are considered first-time occurrence
violations which meet the NRC
Enforcement Policy for exemption from
issuance of a Notice of Violation.
These items are identified to allow
for proper evaluations of corrective actions in the event that similar
events occur in the future.
(Closed) LER 280/88-20, Control/Relay Room Chillers and Unit 2 Charging
Pump SW Pumps Air Bound Due to Inadequate Procedure. The issue involved
the tripping of the subject pumps due to an inadequate procedure which was
being used to fill a drained SW line.
The improper filling evolution
resulted in air entry into the SW flowpath to the subject components, and
the resultant binding of the pumps.
Corrective actions included
venting of the SW line and affected pumps and returning them to service.
The inspector reviewed the LER and has monitored additional licensee
corrective actions in this area.
Failure to provide adequate procedure
for filling evolutions associated with the SW system is identified as
(280/89-28-02).
This LER is closed.
(Closed) LER 280/88-38, Recirculation Spray Heat Exchanger Valve Leakage.
The
is sue involved wetting of the internals of the subject heat
exchangers.
This condition could be detri men ta 1 to the re qui red heat
transfer capability of the heat exchangers.
Corrective actions included
15
draining the heat exchangers and conducting an appropriate inspection and
engineering evaluation of the condition of the drained heat exchangers.
The inspector verified that the inspection and engineering evaluation were
accomplished and necessary corrective actions were completed.
This LER is
closed.
(Closed) LER 280/88-41, Lifting Frames over RHR Pumps not Seismically
Qualified.
The issue involved the licensee's identification of the
subject concern.
Immediate corrective actions included interim bracing of
the frames for potential seismic loading:
Additional corrective actions
included removal of the frames during the outage.
The licensee also
reviewed other potential lifting device problems associated with the
generic concern and corrected these conditions prior to either units 1
restart.
The inspector monitored the licensee's corrective actions in
this area during the outage.
This LER is closed.
(Closed) LER 280/88-45, Failure to Sample Waste Gas Decay Tank Within 24
Hours Due to Failed Pneumatic Control Valve (PCV).
The issue involved
inability to obtain the required sample due to a failure of the sampling
PCV and a misinterpretation by the chemistry technicians that a 25% grace
period in sampling could be applied to this LCO requirement.
Corrective
action included valve repair to obtain the required sample and reinstruc-
tion of station personnel on the TS requirements.
The inspector reviewed
the LER.
A weakness had been 'previously identified by the NRC with
regards to the licensee's failure to correct radiation monitoring
equipment problems in a timely manner. This has resulted in dependence on
grab samples that are required by TS LCOs.
The licensee is currently
reviewing their options for correcting the inoperable monitoring equipment
problems in several areas.
This LER is closed.
10.
Action on Previous Inspection Findings
(92701, 92702)
(Closed) IFI 281/88-51-03, Evaluation of Whip Restraints on Pressurizer
Surge Line.
This item involved the inspection of the Unit 2 pressurizer
surge line as a response for acquiring some of the data required for NRC
Bulletin 88-11, Pressurizer Surge Line Thermal Stratification.
During
this inspection, it was noted that there were several bent rods on whip
restraints, that three of the whip restraint spring hangers were not
installed directly over the surge line, and that several *of the spring
cans were in the bottomed position.
None
of these conditions were
attributed to thermal stratification in the pressurizer surge line, the
topic of to the bulletin. The ceiling attachments were installed out of
position during construction, the bottomed out spring cans were caused by
improper setting, and the slightly bent rods were determined to have been
caused by improper spring can settings:
Engineering determined that the
improper setting restricted the support from freely pivoting (during the
normal expansion of the piping and not due to thermal stratification) and
caused a slight bending of several rods.
Engineering evaluated the
slightly bent rods an_d determined that they would have performed their
16
intended function in this condition.
The inspectors reviewed completed
documentation for re 1 ocat i ng the spring hanger cei 1 i ng attachments
11 2
11
radially outward, replacing the bent hanger rod.s, and properly resetting
the spring hangers.
This area was
also reviewed by a specialist from
Region II during this inspection period, which is documented in Inspection
Report 280, 281/89-29.
This item is closed.
(Closed)
89-34,
Reactor Operator
License Verification.
This
inspection effort was conducted to determine the 1 i censee methods for
ensuring that a non-qualified operator does not perform a licensed duty.
The inspector selected five licensed operators that have been disqualified
for various reasons and verified that they did not perform licensed duties
during the time they were disqualified.
No problems were noted.
In addition, the inspector interviewed backshift shift supervisors to
ascertain their ability to verify an individual's qualification prior to
assignment to a licensed duty.
The
licensee does not have
an
administrative procedure that requires a check of qualifications prior to
assignment on shift. The integrity of the operator is the defense agaihst
a problem in this area.
The on"'"shift operations management is not
provided with an updated ,tatus of the licensed operators.
The training
department provides a written statement to the Operations Superintendent
subsequent to an operator failing a requalification examination.
At this
point, the Operations Superintendent generally informs both the individual
and his shift supervisor that he is not to assume a licens~d duty.
This
process is done verbally and may not happen if the individual is a
licensed staff employee that does not work directly for operations.
The Operations Superintendent stated that he is developing a mechanism,
possibly by issuing drivers-license type cards, of ensuring that an
operator is prohibited from assuming a licensed watch station while he is
unqualified.
The inspectors will continue to monitor the implementation
of the enhanced program that is projected to be developed during the next
several months as a part of their regular inspection program.
11.
Exit Interview
The inspection scope and findings were summarized on October 3, 1989, with
those individuals identified by an asterisk in paragraph 1.
The following
new items were identified by the inspectors during this exit:
One non-cited violation was identified for failure to provide an adequate
procedure for restoration of safety-related valves following periodic
testing (paragraph 3.a) 281/89-28-01.
One licensee identified non-cited violation was identified for failure to
provide adequate procedures for filling evolutions associated with the SW
system (paragraph 9) 280/89-28-02.
17
A weakness in operator control of the EHC system at low powers was noted
which ultimately resulted in a Unit 2 reactor trip (paragraph 3.a).
Strengths were noted with regards to the licensee's management review of
Unit 2 restart readiness (paragraph 4).
The licensee acknowledged the inspection findings with no dissenting
comments.
The
1 icensee did not identify as proprietary any of the
materials provided to or reviewed by the inspectors during this
inspection.
12.
INDEX OF ACRONYMS ANO INITIALISMS
ANSI
cc
ccw
CFR
CLS
cw
DPI
DR
DRSS
EOG
EMP
F
GOC
GPM
I FI
IOER
IRPI
LER
LCO
LHSI
AMERICAN NATIONAL STANDARDS INSTITUTE
ABNORMAL OPERATING PROCEDURE
COMPUTER AIDED DESIGN
CONFIRMATION OF ACTION LETTER
COMPONENT COOLING
COMPONENT COOLING WATER
CODE OF FEDERAL REGULATIONS
CONSEQUENCE LIMITING SAFEGUARD
CIRCULATING WATER
DELTA PRESSURE INDICATORS
DEVIATION REPORT
DIVISION OF REACTOR PROJECTS
DIVISION OF RADIATION SAFETY AND SAFEGUARDS
ELECTRICAL MAINTENANCE PROCEDURE
ENGINEERED SAFETY FEATURE
EMERGENCY SERVICE WATER
ENGINEERING WORK REQUEST
FARENHEIT
GENERAL DESIGN CRITERIA
GALLONS PER MINUTE
HEALTH PHYSICS
HEAT EXCHANGER
HIGH PRESSURE SAFETY INJECTION
INSTRUMENT AIR
INSPECTION AND ENFORCEMENT
INSPECTOR FOLLOWUP ITEM
INDEPENDENT OFFSITE EVALUATION AND REVIEW
INDIVIDUAL ROD POSITION INDICATION
INSERVICE INSPECTION
LICENSEE EVENT REPORT
LIMITING CONDITIONS OF OPERATION
LOW HEAD SAFETY INJECTION
LOSS OF COOLANT ACCIDENT
MER3
MDV
MTC
NRC
OP
ORS
SNSOC
sov
TAVG
TI
TS
vs
18
MECHANICAL EQUIPMENT ROOM 3
MOTOR OPERATED VALVE
MAIN CONTROL ROOM
MODERATOR TEMPERATURE COEFFICIENT
NON-CITED VIOLATION
NUCLEAR REGULATORY COMMISSION
NUCLEAR REACTOR REGULATION
OPERATING PROCEDURE
OUTSIDE RECIRCULATION SPRAY
PERCENT MILLI RHO
PNEUMATIC CONTROL VALVE
PRESSURE INDICATOR
PREVENTATIVE MAINTENANCE
POUNDS PER SQUARE INCH
POUNDS PER SQUARE INCH GAUGE
PERIODIC TEST
QUALITY ASSURANCE
QUALITY CONTROL
RESIDENT ACTION ITEM
REGULATORY GUIDES
REACTOR OPERATOR
RECIRCULATION SPRAY SYSTEM
RADIATION WORK PERMIT
REFUELING WATER STORAGE TANK
STANDARD CUBIC FEET PER MINUTE
SAFETY EVALUATION REPORT
SAFETY INJECTION
. STATION NUCLEAR SAFETY AND OPERATING COMMITTEE
SOLENOID OPERATED VALVE
SAFETY PARAMETER DISPLAY SYSTEM
SENIOR REACTOR OPERATOR
AVERAGE TEMPERATURE OF RCS
TEMPORARY INSTRUCTION
TECHNICAL SPECIFICATIONS
UPDATED FINAL SAFETY ANALYSIS REPORT
UNRESOLVED ITEM
UNDER VOLTAGE
VENTILATION SYSTEM