ML18152A240
| ML18152A240 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 02/28/1992 |
| From: | Branch M, Frederickson P, Tingen S, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A241 | List: |
| References | |
| 50-280-92-02, 50-280-92-2, 50-281-92-02, 50-281-92-2, GL-82-12, NUDOCS 9203100170 | |
| Download: ML18152A240 (16) | |
See also: IR 05000280/1992002
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
. 101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
50-280/92-02 and 50~281/92-02
Licensee:
Virginia Electric and Power Company
5000 Dominion Boulevard
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50-281
Facility Name:
Surry 1 and 2
License Nos.:
Accompany
Approved
Scope:
J.
February 1, 1992
Projects
SUMMARY
..?:-2?-,92
Date Signed
)- ~) 7,,. 92.__
Date Signed
- 2.-)/-7?
Date Signed
This routine resident inspection was conducted on site. in the areas of
operations, maintenance, surveillance~ quality verification and safety
assessment review,. independent plant evaluation, and licensee event review.
During the performance of this inspection, the resident inspectors conducted
review of the licensee's backshift or weekend operations on January 6, 9, 13,
14, 24, 26, and 29, 1992.
Results:
In the safety assessment/quality verification area, a weakness associated with
FSAR quality was identified (paragraph 3.a).
In the operations functional area, the program to relabel plant components
appears to be adequate, but this program cannot be fully eva 1 uated until full
implementation has been completed (paragraph 3.b).
In the operations functional area, overtime worked by licensed and non-licensed
operators was within Generic Letter 82-12 requirements, and the use of overtime
was closely monitored by management (paragraph 3.c).
9203100170 920228
ADOCK 05000280
G
-2
- In the operations functional area, staffing of the operations shift crews
exceeds the staff_ing requirements of *10 CFR. 50.54 and Technical Specifications
{paragraph-3.d).
- *
In the operations functional area, the licenses generally did a gobd job in
minimizing the number of lit control room indicators; however, one nuisance
annunciator was routinely lit (paragraph 3.e).
-In the maintenance functional are~, the roof and ground water leaks continue to
_ impact __ other equipment and_ may resu_lt fn operational transients if not-
corrected (paragraph 4.b).
-
- .
-
- -
. -__
In the safety assessment/quality verification function~ l area, the failure
to identify arid correct the installation of improperly sized air supply tubing*
for the feedwater regulating valves may have contributed to an operational *
transient (paragfaph 4.c).
In the maintenance functional area, the utilized procedure to accomplish
emergency ventilati-On system testing was adequate and adhered to.
The system
engineer who directed the test was very knowledgeable of the ventilation system
(paragraph 5.b).
'
-
-
-
-
In _the safety assessment/quality verification functional area, discussions
in Management Safety Review Committee (MSRC) meeting were frank and str~ight
forward, the MSRC consultants significantly contributed to providing alternate
view poiht~, and the licensee exceeded Technical Specification requireme~ts in
the areas of_MSRC minimum staffing and meeting intervals (para9raph 6.a)~
In the safety assessment/quality verification functional area, the quality
assessments being performed by QA/QC compliments plant operations and appears
, to have improved safety (paragraph 6).
-
In the engineering/technical support functional area, a strength was identified
-for the design and installation of a condenser inlet box secondary water
barrier as an alternative to removing trains of safety related equipment from
service.
This temporary modification s i gni fi cantly improved plant safety in
both units (paragraph 7).
- REPORT DETAILS *
1.
Persons Contacted
L kensee * Employees
2 .
R. Allen, Supervisor; Shift Operations
.*M. Bowling, Manager Nuclear Licensing and Programs
- W. Ben.thal l ,_ S_upervisor, Licensing
- R. Bilyeu, Lic~nsing Engineer
- H~ Blake, Nucleai Site Services
- D. Christian,_ Assistant Station Manager
- J. Downs, Superintendent of Outage and Planning
D. Erickson, Superintendent of Health Physics
- R. Gwaltney, Superintendent of Maintenance
- D. Hart, Supervisor, Quality Assurance
- H. Hay, Corporate Supervisor, Quality Assurance
- *M. Kansl er, Station Manager
- A. Keagy, Superintendent Materials
_
T. Kendzia, Supervisor, Safety Engineering
- J. McCarthy, Superintendent of Op~rations
- J. O'Han1on, Vice President, N~clear Operatioris
- A. Price, Assistant Station* Manager
- E. Smith, Site Quality Assurance Manager
- T. Sowers, Superintendent of Engineering
G. Thompson, Supervisor Maintenance Engineering
G. Woodzell, Senior lnstructor
Other Personnel
- R. Eytchison, visitor to Virginia Power
NRC Personnel
- M. Branch, Senior Resident Inspector
- S. Tingen, Resident Inspector
- J~ York, Resident Inspector
- Attended exit interview~
- Other licensee employees. contacted included control room operators, shift
technical advisors, shift supervisors and other plant personnel.
Acronyms and initialisms used throughout this report are listed in the
1 ast paragraph.
Plant Status
Unit 1 began the reporting period in cold shutdown.
This unplanned outage
was required t6 replace the control rod drive cbil stacks for rod E-5~
2
The unit was* critical on January 8, and on line Janua-ry 9.
The Unit was
at 100 percent power on January 13.
The delay in achieving full power was
due to power restrictions associated with adverse secondary pl ant
chemistry *caused by condenser tube leaks identified during the startup.
On January 30,. the unit began a coastdown from 100% power. * At the end of v
the inspection period, the unit was at 97% power, day 24 of con_ti nuous
operation.
Uni~ 2 began the reporting period in ~ower operation.
The unit was at
power at the __ end. of the inspection period, day 44 of continuous operation.
3. * Operational Safety Verification* (71707,42700.)
Th~ , nspectors 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 operations safety and compliance
with TS and to maintain awareness of the overall operation of the
facility. _ Instrumentation and ECCS lineups were periodically reviewed
from c.ontrol room indication 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.
a.
AFW Pump Relays
On January 6, the licensee entered a six-hour-to-hot-shutdown LCO.
for Unit 2 due to the discovery that the undervoltage relays for the
transfer buses had i_mproper setpoints.
The relays are listed as the
.
11s.tation blackout start motor driven AFW pump relays" in Tables 3.7-2
and 3.7-4 of th~ TS;
Table 3.7-4 required these relays to be set to
a value that is greater than or equal to 46.7 percent of nominal
voltage.
The error was discovered by the licensee through a technical adequacy
review of surveillance tests.
The licensee determined that the
actual setpoints contained in the procedure were a voltage value that
did not equate to the 46.7 percent limit. * The licensee's control
operations group who verifies and adjusts the setpoi nts for
protective relays were using a setpoint ~oltage whic~ equated to a
.setting of approximately 45~8 percent of ~ominal voltage.
After discovery of the error, the licensee verified and or adjusted
the relay setting to the TS required value and exited the six hour
LCO.
There are six transfer bus undervoltage relays associated with
auto-starting of the AFW pump; two for each of the three transfer
buses.
Each unit is supplied power from two of the three transfer
buses.
Unit 1 was not at power at the .time of discovery and was not
affected by the improperly set relays.
3
The inspectors reviewed the licensee actions associated with the
relay problem discussed above and also witnessed the setpoint
verification of one of the six affected. relays.
The inspectors*
reviewed Chapter a.of the UFSAR fbr additional information on the
safety functions and design basi.s for these relays.
Section 8.5
briefly describes these relays and provides a setpoint of 45.8
percent of rated voltage.
The UFSAR va 1 ue is nonconservative
compared to the TS limits, and the inspectors questioned the licensee
as to the basis for both the TS and UFSAR values.
The licensee is
developing an. LER to describe the deta,ils of this item .. Final review
and. closure of this issue wi 11 *occur as part of the LER review *
_process;
The discrepancy between the FSAR and the TS may have led to
the problem of not testing th~ relays to the TS required value and
the FSAR needs to be corrected in this area.
This is the second *
- recent example of FSAR ~uality, the other issue was discussed in .IR
'50-280,281/91-37 and in¥ol~ed the time respdnse of the OT delta T
trip circuit.
There is currently an NCV which documents that the FSAR may be.
lagging plant modifications.
However, it is not clear that the
licensee's program to fix the outdated FSAR will correct problems of
the nature discussed above.
10CFR50.71 requires the FSAR to be
accurate and reflect the act~al plant configuration and the recent
exa~ples~ as discussed abbve, may represent a diff~rent problem than
that currently being corrected by the* licensee .. Additionally, the*
licensee's efforts in improving the desig~ basis of the plant should
also identify and correct problems of this nature.
b.
Review of Configuration Management Program
- During the previous two SALP cycles, plant component labeling was an
area identified as needing additional attention.
In February, 1990, *
the Configuration Management Program was implemented to install new
identification labels on safety and nonsafety related components.*
The scheduled completion date for this program is March, 1993 .. The
licensee is presently in the process of walking down systems and*
comparing
the as-found configuration_ with system drawings.
Approximately 70% of the system walkdowns have been completed.
After
a system is walked down, the proper label plate wording i~ determined
. and the label plates ordered.
One person installs a label plate
while a second person verjfies correct installation and removes the
old label plate.
All configuration discrepancies are documented and
resolved by the responsible system engineer. Approximately 2% of the
station components scheduled for rel abe 1 i ng have been completed.
This program included the radiation waste facility components which
have been completed. * The Configuration Management program does not
include control room components or breakers inside electrical panels.
.
.
Because the majority of the station components have not been
relabled, * examples of inadequate or misleading labeling are
occasionally_ identified.
When identified, the configuration
4
management group is required to be notified to ensure that th.e.
components* are included in the program.
An example of a recent
labeling problem, wa~ the labeling for the motor driv~n fir~ *pump
start/stop -push buttons which was confusing. to the operators and.
resulted in an inadvertent trip of the pum~.
Th~ ih~pectors reviewed
the DR disposition for this particular labeling problem with the *
supervisor of configuration management, who stated that this type of
problem would have been corrected during the relabeling process.
The
inspectors concluded that the program to relabel plant ~omponents .
. appears to be adeq~~te, but the program cannot be fully evaluated
until full implementation has b~en completed.
c.
Review bf Operations Department Use Of Overtime
d.
GL 82-12,- Nuclear Power Piant Staff Working Hours, dated Jun~ 15,
1982, provides NRC policy for use of overtime.
VPAP".'0103, Working
Hours and Limitations, dated. March 29, 1991, is the station's
administrative procedure that implements GL 82-12.
The inspectors
reviewed VPAP-0103 and time sheets for selected personnel in the
operations department in *order to verify that the intent of GL 82-12
had been met.
The inspectors reviewed time sheets foi four non-licensed opet~tors, *
six ROs, and two SROs for select dates in the September through
December, 1991 time frame.
The inspectors concluded that overtime
- was frequently used; however,* operators did not exceed overtime
1 imits during the time period reviewed.
VPAP-0103 requires that the
station manager approve overtime that exceeds certai.n specified -
limits (i.e., when station pers~nnel work more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> iri a 7
day period).
The inspectors noted three examples where operators
worked exactly 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in 7 days.
Si nee this did -not exceed
overtime limits, station manager approval was not required.
The inspectors reviewed the 1991 overtime rates for ROs, non-licensed
operators, and SROs.
ROs and non-1 i censed operators RFO average
overtime rate was 10.88 hours0.00102 days <br />0.0244 hours <br />1.455026e-4 weeks <br />3.3484e-5 months <br /> per person per week and the non-RFO
average overtime rate was 4.87 hours0.00101 days <br />0.0242 hours <br />1.438492e-4 weeks <br />3.31035e-5 months <br /> per person per week.
The SROs
RFO average overtime rate was 6.06 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> per-person per week and
non-RFO rate was 2. 1 hours1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> per person per week.
The* i rispectors
concluded that the operations department overtime was within GL 82-12
req~irements and that the use of overtime was cl.osely monitored by
managemenL *
Operation~ Department Shift Change
In October, 1990, the Operations Department changed from an 8-hour
working .shift to a 12-hour working shift.
During this inspection
period, the Operations Department changed back to a 8-hour working
shift.
The reason for the change back to the 8-hour shift was
because the majority of operators preferred a 8-hour shift duration.
Operating shifts continue to be staffed with a minimum of four SROs
5
(except one shift has three SROs), five ROs, eight non-licensed
operators (except one shift has seven non-licensed operators), and
one STA.
With the exception of STA staffing, the shift crew
composition exceeds TS Table 6.1-1 and 10 eFR 50.54 staffing
requirements.
Each shift is staffed with one STA which meets minimum
staffing requirements.
e.
Units 1 and 2 Annunciator Panels
Station management has implemented a policy to minimize lit
annunciators on certain control room annunciator panels when a unit
is operating. It is preferred to maintain a black board condition on
certain control room annunciator panels; however, many.maintenance
evolutions and abnormal conditions result in lit annunciators.
Throughout this inspection period, annunciators were lit due to
-maintenance associated with condenser water box expansion joint -
replacement in both units. The Unit .2 rod control non-urgent failure
annunciator was lit due to a power supply failure.
The fire water
system trouble annunciator was frequently lit due to operation and
- maintenance related with the fire pumps.
Generally, the licensee did
a good job in minimizing the number of lit control room indicators;
however there was one nuisance annunciator associated with the eves
Heater Tape Trouble that was routinely lit whenever there was flow
through the piping.
Because the annunciator was routinely lit, it
was not an aid to operators.
Within the areas inspected, no violations were identified.
4.
Maintenance Inspectio~s (62703, 42700, 71500)
During the reporting period, the inspectors' reviewed maintenance
activities to assure compliance with the appropriate procedures.
Th~ following maintenance activities were reviewed.
a.
Installation of Stop Logs
On J_anuary 6, the inspectors monitored the installation of stqp logs
into the Unit 28 main condenser CW inlet bay at the high level intake
structure.
The stop logs were installed to provide isolation for the
replacement of the B main condenser CW outlet expansion joint
2-CW-REJ-2018.
The work was accomp 1 i shed in accordance with WO 3800118930, procedures MMP-C-D-207, Corrective Maintenance Procedure
For Diving, dated February 13, 1990, and 2-MOP-48.3, Removal From
Service of 28 Waterbox, dated November 22, 1991.
After securing CW flow through the B CW inlet bay, a diver equipped
with a high pressure water hose removed debris from the trash gate
and stop log guides.
The first of four stop logs was installed and
the diver was then utilized to verify that the stop log was *
adequately seated in the bottom guide.
The stop log was lifted with
-.
6
a crane ~nd once in position, the weight of the stop log drove the
stop log into the inlet bay guides .. The remaining three stop logs
were then -installed in the B CW inlet bay one at a time.
It took
- approximately one hour and fifteen minutes to install the sfop *logs
after the diver completed-the cleaning process~
The inspectors noted,
that difficulties were encountered during the inst~llation of the.
stop logs.
Many times the stop logs became misaligned between the
guides and stuck.
The stop log had_ to be lifted and realigned and
dropped into the guides.
At one point, the stop log edges had to be
coated with grease in order .for the stop log to fully descend into
the inlet bay guides. It was not_ windy during the installation;-
however, the inspectors were infor~ed that wind further hampers the
installation of stop logs.
In response to recent -turbine building flooding issues, the
possibility of installing stop logs under flow conditions was*
- considered.
In resolving the IPE flood issues, no credit f_or stop
log installation.has been used to mitigate a flooding condftion~
Due
to the difficulties encountered under ideal conditions (i.e. with
flow secured, surfaces cleaned, and no wind), the inspectors
questioned the ability to install the stop logs under actual flow
conditions, should credit be.taken in the future for th.is activity .
b.
Roofing, Plug and Groundwater Leaks
On January 23, the inspectors accompanied licensee personnel. in
to_uring the station during a rainy period to look for roof and plug
leak~ as well as of ground watei leakage.
Eight areas of roof or
ground leaks were noted in the auxiliary bujldtng, additional leaks*.
were noted by the inspector and 1 icensee personnel in the Unit 1
safeguards and valve pit are-a.
The lice.nse.e identified additional.
leaks in the Unit 2 safeguards and valv~ pit-area.
These roof and
access plug leaks were documented in station devi.ation S-92-0127 and
the identified ground water problems in S-9~-0128. *
During the inspectors' walkdown, groundwater was observed dripping
onto the Unit 2 test p~sh button junction box for the MS trip valves
(JB-NR-MS 201, AE, BE, and CE).
The licensee evaluated the condition
of this junction box and stated there was not a problem and that this
junction box had been recent1y repaired becaus-e of a 1 eaking gasket. ,_
This condi_tion led to internal box corrosion and a ground.
The
inspectors reviewed deviation report no. S-91-0395, dated April 1,
1991, and noted that the B MS trip valve went closed when the ground
occurred .. Unit 2 ~as in an outage when this happened, otherwise a
unit trip would have occurred.
The inspectors were aware that the following station deviations (in
addition to DR's written durlng the January 23 walkdown) had been
issued:
DR S-91-1568, dated October 17, 1991, water leaking into Units 1
and 2 cable vaults and valve pits, turbine building, and.
decontamination building.
7
. DR s~91~1939, dated December 23, 1991, water leaking through
roof onto 4160 volt buses~
- DR S-91-0012, dated January 4., 1992', roof p'lug allowed leakage
onto Unit 1B LHSI Pump Motor. (Licensee had to megger the
electric motor*to prove it was operable.)
On .January 23, the inspectors met with station management personnel
to discuss the leakage and ground water problems.* Several projects
are currently underway to:fiX.**roof areas; improve drainage (repaving
to achiev~: proper slope)~~~nd d~~tease amount of ground water *. The
inspector r~vi~wed an*engineering report issued on August 9; 1991,
which ,concluded that rainwater .. and ground water prob 1 ems existed *in
the past an*d are still a problem.
The continuation of the
rainwater/groundwater leakage into the facilities may contribute to
operational transients jf not *corrected.
c.
Troubleshooting the Feedwater Regulating Valves
During the previous inspection pe~iod on December 17, 1991, Unit 2
was increasing, power after an outage to repair an .RTD bypass Hne
instrument leak, when .the B feedwater regulating valve (2-FW-FCV-
2488) *started oscillating open and closed at appioximately 23 percent
. power a~ it was placed in automatic .. This resulted in a _rise in the.
level in the B steam generator, a turbine trip, and a reactor trip.
The trip report stated that the oscillations were c.aused by the
failure of the valve to*hold a demand position.
The B FWRV was inspected and the positioner arm was.found to *be worn.
The positioner arm may have *contributed to the valve oscillations and
was replaced prior to unit restart.
The licensee believed that this
would resolve the oscillation problem.
In addition, the licensee
- performed diagnostic AirCet testing of the air control. syst.em of the
three Unit 2 FWRV's.
The unit was returned to power on December 18,
- and a much less severe and lower frequency oscillation was observed
during the switch from manual to automatic.
The-post trip review
recommended that the AirCet test results and the tendency of this
valve to *oscillate at low power (approximately 23 percent) be further
evaluated under the root cause evaluation program.
.
.
During this inspection period, the inspectors reviewed the 1icensee
evaluation of the FWRV oscillation as well as the AirCet * test
results.
The vendor's evaluation of the AirCet test curves was that
the air supply lines to the valves.were too small.
A search of the
modification/maintenance history for these. valves showed that a
modification had been made on the valves because of a vibration
problem that was causing fatigue failures in the air supply lines.
This modification was made during the March-to-June time frame in
1984 using EWR 84-105.
The EWR did not specify the tubing size* for
the air supply lines, but the vendor's drawing (Copes-Vulcan)
8
specified three-eights inch diameter.
A smaller one-quarter inch
diameter tubing was installed on all three of the FWRVs.
.
.
The ~nit-1 valv~s could not be tested using the AirCet diagnostic
system since the unit was at power, butt dimensional check showed
the air supply lines ~ere too small (one-quarter inch diameter) when
compared to the vendor requi reinents.
The fa i1 ure to i den ti fy and
. correct the installation of improperly sized air supply tubing for
the FWRVs may h~ve contributed to the unit trip on December 17, 1991,
and is identified as a weakneis.
A related issue with operation of the FWRVs, involved an EWR (No.89-735 dated May 13, 1989) which states that there is a pot~ntial for
excessive ccioldown of the RCS following a normal r~actor trfp from
100 percent power.
This EWR was cancelled on November 28, 1990,
without beirig implemented even though it stated that the tubing size
should be increased .. This EWR states that a larger size of tubing
would allow the FWRVs to close faster and lessen the loss of heat in
the RCS.
Tests show that these val~es close in ten seconds and the
design time is five seconds.
The licensee is currently evaluating the safety significance of the
longer closing _time for these valves. and the*need to.replace the
undersized tubing, and wi 11 correct the discrepancy between the
actual installation and that specified_ on the drawing.
This item is
being tracked_ by the licensee under DR S-92-0121 and wi 11 be fo 11 owed
by the inspectors.
Within the areas inspected, no violations were identified.
5.
Surveilla~ce Inspections* (61726, 42700)
. During the reporting* period, the inspectors reviewed surveillance
activities to assure compliance with the appropriate procedure and .Ts*
requirements.
a.
Testing Unit 2 Turbine Building Sump Pumps
On January 24, the inspectors witnessed the performance of perodic
test 2-NSP-PL-001,- Performance Test of Turbine Building Sump Pumps
2-PL-P-2A,_B, and C (Turbine Building Sump No. 3), dated December 31,
1991.
The purpo*ses of the* test is to verify the auto-start
capability of the pumps, the maximum flow capacity in gpm, and to
determine the deve 1 oped head in feet.
When the leve 1 in Sump No. 3
was filled to. the high alarm level all three of the pumps were
supposed to pump th~ level down, but when the switch was turned on
only two of the pumps started. Station deviation rio; S1~92-0126 wa~
written and a work request was* submitted.
On January 26, the
el ectri ci ans cleaned some of the contacts for this pump and the
inspectors observed the successful running of all three of the pumps
- simultaneously.
b.
9
The inspectors reviewed .the testing results for the other six pumps.
The ~ump pumps shared by both of the units 1-PL-P-2D, E, and F were
successfully tested using perodic test 1-NSP-PL-002.
The Unit 1 sump
pumps 1-PL-P-2A~ B, and C were. tested using perodic test
1-NSP-PL-001 .. No deficiencies were noted by the inspectors.
After
the initial verification and baseline testing is completed periodic
testing will also be performed based on the licensee's corrnnitments.
Auxiliary Ventilation Filter Flow Test
On January 29, the inspectors witnessed the performance of periodic
test PT-32.7, Auxilary Ventilation Filter Flow Test, dated April 9,
1991.
The purpose of this procedure is to ensure system air flow is
36,000 cfm +/- 10% in the SI mode of operation in accordance with TSs 4.12.A.3 and 4.12.B.3. This testing is normally accomplished during
refueling outages; however, troubleshooting of fan 1-VS-F-58A
revealed that flow through the emergency ventilation system may have
be-en excessive.
The test was accomplished by aligning the emergency
ventilation system in the SI configuration mode and then measuring
air flow rates in the ventilation ducts with an anemometer probe.
The 58A fan.flow test results indicated that .flow was approximately
40,010 cfm which exceeded the procedure's acceptance criteria. Also,
testing identified that the ventilation system installed flow
instrument, 1-VS-Ff-117A, was out of calibration.
The licensee
adjusted- the ventilation system flow rate to approximately 35,000 cfm
which was within the procedure's acceptable fange.
At the end of the
inspection period, the licens~e was in the process of determi~ing the
cause of inaccurate system flow instrumentation.
The inspectors
monitored the test from *the control room; Unit 1 safeguards building,
and auxiliary building.
The procedure utilized to accomplish this
testing was adequate and adhered to.
The system engineer whci
directed the test was very knowledgeable of the. ventilation system.
No discrepancies were noted.
Within the areas inspected, no violations were identified.
6.
Quality Verification and Safety Assessment Review (40500)
a.
On January 16, the inspectors attended a meeting of the licensee's
MSRC at the Surry Power Sta ti on.
The MSRC is a requirement of TS 6.1.C.2.
The MSRC is composed of fourteen members; ten are from the
licensee and four are consultants.
All fourteen members were present
at the January 16, meeting.
The purpose of the MSRC is to provide an
independent review and audit of designated station activities.
Some
of the items discussed at the meeting were the results of the annual
QA Fire Protection* and Loss Prevention audit, mid-SALP self
assessment presentation recently given to NRC Region II st~ff, FRV
oscillation problems, diesel generator CFA summary, and Surry !PE
issues .
10
The insp~ctors considered that the discussions betwee-n MSRC me~bets
to be f:rank and straight forward and that the consultants contributed
sign_Hicantly t.9 providing alternate view points.
TS 6.1.C.2
specifi~s minimum MSRC staffing requirements of a chairman and foui
members and requires _that the MSRC meets at 1 east once per ca 1 enda_r
quarter.
The licensee exceeds these requirements in that the MSRC is*
staffed with fourteen members and is scheduled to meet eight times in
1992.
b.
ColTlllitment Tracking Review
C * -
During the previous SALP.period, .the NRC questioned the effectiveness_ -
of the licensee I s * commitment tracking pro*gram.
Outages were
essentially complete when the 1 icensee .discovered that cormrii tments
had not been satisfied and need_ed to be changed. . During this
inspection period, the inspectors reviewed the effectiveness of the
licensee's system by requesting and verifying colTITiitment tracking
accuracy for four IPE internal flooding improvements.
The. licensee's system accurately captured these commitments.
However, there is some redundancy in the items being tracked, and it
appears that the user is to provide the necessary cross reference
information when items are consolidated. _ The inspector was able to
-follow the commitments reviewed to a final item and the commitments
were not lost.
QA Assessments
During this.inspection period, the inspectors continued to hold a
monthly QA status meeting with the licensee's QA manager and his
staff.
The purpose of this meeting is to communicate recent QA/QC
findings in selected areas as well as providing followup to the NRC
1s
inspectors concerns as well.
This-moriths meeting covered the recent
assessment of JCO colTITiitment followup as well as discussing the
findings from the_ recent fire protection program audit.
The inspectors also discussed with the licensee the process for
prioritizing the oreas for assessment.
The list of assessments is
somewhat controlled by resources.
However, it was obvious- that the
station manager has input into the areas to be assessed.
This was
evident by the station manager requesting eight out of the twenty _
assessments planned -for 1992.
This process demonstrates the fact
that both the plant-and the QA *organization are striving to improve
performance and overa 11 qua 1 i ty. Although not comp 1 ete ly documented,
it appears that the plant corrections of assessm~nt findings places
the appropriate priorities to _the items that will provide the most
impact on plant and personnel safety. *Recent examples of this was
the control of operator aids, operator overtime, and followup of JCO
requirements .
Within the areas inspected, no *violations *were identified.
----
-
11
7.
IPE. Internal Flooding Corrective Action Review (71500)
.
.
During the NRC's review of the* administrative controls to reduce the
vulnerability of internal flood_ing, the licensee described several new and**
niodified procedu*res that were being implemented.
The inspectors discussed
- with the licensee the methods being used to ensuie that personnel were
aware of the changes being implemented. -
The licensee provided operator training through*several avenues .. Training
on the new and improved procedures was accomplished through required
reading and pre-evolution briefings.
The licensee also used standing
orders to heighten the operators awarene-ss of the potential flooding
issue.
The inspectors found the licensee's training to be effective i-n
this*area.
The licensee continues the replacement of the expansion joints on the
outlet of the condenser.
The joints on the Band D water boxes for both
units have been replaced.
The emergency service water lines tap off the A
and C w~ter box supply lines on each unit and would have been isolated
using the stop log method to replace the expansion joints on the Band D
water boxes.
This action would have required a TS relief for the ten day*
period to replace a joint.
The li.c:ensee decided to use the butterfly
valve and designed a secondary .barrier to be p 1 aced on the* tube sheet of .
the condenser.
This method would not isolate the service water supply~
This action prevented the isolation of a train of a safety system for a
ten day period and is identified as a strength.
On January 21, the inspectors observed the testing of a mockup for this
second barrier.
The barrier corisists of a fiber reinforced plastic sheet
(rip stop) against the tube sheet an~ a softer and thicker plastic layer
(bituthene) with an adhesive backing placed against the plastic sheet.
The barrier was tested in a pipe with a plate on the end with drilled
holes to simulate the tube sheet.
The water in the pipe was- pressurized
- to various ~ressures to test the barrier.
The actual barrier would see
approximately eight psig and the maximum pressure _achieved during the test
was e1ghty psig without rupturing the barrier.
On January 3.0, the
inspectors observed the installation of the first of these barriers in the
-Unit 2A waterbox.
This barrier was attached to the tube sheet with
plywood strips held 1n place by expandable plugs inserted into various
tubes.
W~thin the areas inspected, no violations were 1dentified.
8 *. Licensee Event Review (92700) *
The inspectors reviewed the LER's listed below and evaluated the adequacy
of corrective acti6ns.
The inspector's review also included followup on
th~ licensee's implementation of corrective action .
(Closed) LER 280/91-022, Containment Spray Pump Exceeded Surveillance
Testing ~S Requirements Due to Personnel Error.
This issue involved the
discovery of a missed surveillance, 1-PT-17.1, on the containment spray
12
.
. .
.
.
.
.
.
'
.
-
system.
The cause of these events was reported as an administrative
pefsonnel error that occurred when the test was changed from a monthly to
a quarterly* frequency.. The resident inspectors* identified a similar
concern* durin~ an inspection in-
1991 involving several missed
surveillances, violation 280/91-06-01, and corrective*actions were taken
to prevent recurrence.
Since the corrective. actions were implemented*
after this last event, no violation was issued.* The licensee's correttive
actions appear to be adequate.
.
.
('Closed) LER 280/90-016, Type C Testing Resu.lt Exceeded 10 CFR 50 Appendix
J Acceptance Criteria.
This issue involved the fa_ilure of containment -
purge valve, l-VS-MOV-101, to meet the ~equired acceptance ctiteria during
Type C leakrate testing.
The cause. of the failure was attributed to not
testing the valve in its as-fo~nd ~hut condition.
Dufing unit operation,
this valve is shut and de~nergized .. The Type C method of testing required
that the valve be cycled to drain water from the system just prior to
testing.
The licensee concluded that the valve's elastomer seat was
damaged when the_ valve was cycled prior to testing.
To prevent this
failure or similar failures, the licensee has changed its methodology for
Type C leak rate testing* valves in air systems to not cycle the valves
- prior to testing. The inspectors reviewed procedures 1- and 2-0PT-CT-201,
Containment Isolatioh Valve Local Leak Rate Testing~ dated March 12J and
May 8, 1991 respectively and verifi~d that the new test methodology was
i~corporated intb the procedures.
.
- .
.
.
(Closed) LER 280/91-002, Two Charging Pumps and One Charging Pump Service
Water Pump Inoperable Simult~neously Due to Instrument Air Line Failure
Caused by Personnel Error.
On March 26, 1991, with the charging pump
system aligned for normal operation, a contract-employed painting foreman
inadvertently stepped on the air supply line to the B pump's lube oil
temperature control valve resulting in failure of. the valve controller.
This failure required that the B pump be declared inoperable since part of
its support system was inoperable.
With the B pump declared. inoperable
and with the A and C charging ~umps powered from the same bus, only one
charging pump could be considered operable by TS requirements.
In
addition to the above, one of the two charging pump service water pumps
(pumps that cool the charging pump lube oil cooler and intermediate seal
coolers) was out of service foi maintenanc~. With two chargihg pumps and-
one charging pump service water pump inoperable, _a condition not allowed
by TS existed that placed the unit into section 3.0.1 of the TS, which is
the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> LCO to hot shutdown ~ction statement.
The unit ~ntered the 6
hour LCO at 1415.
At 1443, one of the charging pumps on the lH bus was
transferred to the lJ bus and the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> LCO was exited.
The charging
pump service water pump was returned to service at 1635 and the fbllowing.
day the instrument air line for B charging pump's oil temperature control*
valve ~as repaired and the pump was declared operable.
Due to the nature and location of the work in the arei of this particular
instrument air line, the personnel error was considered an isolated
occurrence.
The event and the cause was discussed in safety meetings with
craft personnel to emphasize the importance of unnecessary contact with
13
instrument lines. Station personnel were also informed of the incident by
an HPES
11 Problem Alert" memorandum.
The licensee's corrective actions are
considered satisfactory.
Within the areas inspected, no ~iolations were identified.
9.
Exit Interview
The inspection scope and results were* summarized on February 5, with those *
individuals identified by an asterisk in paragraph. 1.
The following
summary of inspection activity was discussed by the inspectors during this
exit.
Item Number
Status
Closed
Closed
Closed
Description and Reference
Containment Spray Pump Exceeded
Surveillance Testing TS Requirements
Due to Personnel Error.
Type C Testing Result Exceeded 10 CFR
50 Appendix J Acceptance Criteria.
Two Charging Pumps and One Charging*
Pum*p Service Water Pump Inoperable
Simultaneously Due to Instrument Air
Line Failure Caused by Personne-1
Error.
10.
Index of Acronyms and Initialisms
CFA
CFR
eves
DR
GL
GPM
HPES
JCO
IR
LCO
LER
COMPONENT FAILURE ANALYSIS
CUBIC FEET PER MINUTE
CODE OF FEDERAL REGULATIONS
CHEMICAL AND VOLUME CONTROL SYSTEM
CIRCULATING WATER
DEVIATION REPORT
ENGINEERING WORK REQUEST
FEED REGULATING VALVE
FINAL SAFETY ANALYSIS REPORT.
GENERIC LETTER
GALLONS PER MINUTE
HUMAN PERFORMANCE ENHANCEMENT SYSTEM
INDIVIDUAL PLANT EVALUATION
JUSTIFICATION FOR CONTINUED OPERATION
INSPECTION REPORT
LIMITING CONDITIONS FOR OPERATION
LICENSEE EVENT REPORT
14
LHSI
LOW HEAD SAFETY INJECTION
MS
MSRC
MANAGEMENT SAFETY REVIEW COMMITTEE
NON-CITED VIOLATION
NRC
NUCLEAR REGULATORY COMMISSION
OP
OPERATING PROCEDURE
POUNDS PER SQUARE INCH GAUGE
QUALITY ASSURANCE
QUALITY CONTROL
REFUELING OUTAGE
REACTOR OPERATOR
RESISTANCE TEMPERATURE DETECTOR
SYSTEMATIC ASSESSMENT OF LICENSEE PERFORMANCE
SAFETY INJECTION
SENIOR REACTOR-OPERATOR
TS
TECHNlCAL SPECIFICATIONS
UPDATED FINAL SAFETY ANALYSIS REPORT
VPAP
VIRGINIA POWER ADMINISTRATIVE PROCEDURES
WORK ORDER