ML18153C967
| ML18153C967 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 03/26/1992 |
| From: | Branch M, Fredickson P, Tingen S, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18153C965 | List: |
| References | |
| 50-280-92-04, 50-280-92-4, 50-281-92-04, 50-281-92-4, NUDOCS 9204140048 | |
| Download: ML18153C967 (18) | |
See also: IR 05000280/1992004
Text
UNITED STATES.
NUCLEAR REGULATORY COMMISSION
REGION II *.
101 MARIETTA STREET,N.W.
ATLANTA, GEORGIA 30323
Report Nos.i * 50-280/92-04 and 50~281/92~04
License~: *. Virginia Electric and Power Company
5000 Dominion Boulevard
~len Allen, VA* 23060
Docket Nos.:
50~280 and 50-281
Facility Name:
Surry 1 and 2 *
License Nos.:
DP~-32 and DPR-37
Inspection Conducted:
February 2 through March 7, 1992.
Inspectors:
M. ~ikident Inspector
a~~**
-3. L-/ff2
. .0'a~i gned
3.&~d~
Dci'te S"i gned
s iclen tinspec tor
~~~~~.L-.--,--~---.:... 30,:/9 .
DfuSign~
Approved by:
SUMMARY
Scope:
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
reviews of the licensee's backshift or weekend pperations on February 2; 13, 16,
17, 19, 23, March 1, 3, 4, and 5, 1992.
Results:
In the operations area, the follow,ng items were noted:
A weakness was identifi~d in that~ procedures do not recognize the
manual mode of operation of the ventilation system (paragraph 3.a).
The .ability to trend hours spent in action statements will.
significantly enhance the licensee's ability to focus on problem areas
(paragraph 3.e).
Housekeeping throughout the plant is generally good (paragraph 3.c).
9204140048 920326
.PDR
ADOCK 05000280
G_
. ____!:PR __
2
In the maintenance/surveillance area, the follo.wi.ng items were noted:
Planning and implementation of the switchyard CT replacement (paragraph
- 3.b) demonstrated the following:.
Coordination of many parallel and series ictivities as well as the
regulatory awareness was observed as a strength *
- - The switchyard design does not allow for normal preventive and
corrective maintenance of some switchyard- equipment .
. Th~ failure to provide adequate procedures to calibrate the station
blackout motor driven AFW. pump start relays and to test the T average
port of the ESF*logic circuits a~e non-cited licensee identified
. violations -u,aragt:"aphs _10.a and b). *
. . .
The ESF logjc testing observed was well coordinated and ~eceived ~ high
level of management attention as evidenced by assignment of the Senior
Operations Mana~er to this infrequent task (paragraph 4.b).
In the SA/QV area, the following items were noted: .
. The TS and FSAR failure to describe the ventilation systems .manual mode
of operation was identified *as a weakness (paragraph 8) .
. The *corporate IR, IDER,. and CNS assessment. and event review programs
~ere found to be effective and met TS requirements (paragraph 6).
The failure to properly correct HHSI *pump lube oi"l temperature control
valve deficiencies is identified as a violation and weakness
(paragraph 3.g}.
REPORT.DETAILS
1.
Per~ons Contacted
Licensee Employees
- W. Benthall, Supervisor, Licensing
- R. Bilyeu, licensing Engfneer
H. H. Blake, Nuclear Safety
- D. Christian,:Assistant Station Manager
J. Downs, Superintendent_of Outage and Planning
- A. Fletcher, Assistant Superintendent of Engineering
- R. Gwaltney, Superintendent of Maintenance
- D. Hart, Supervisor,.Quality Assurance
M. Kansler, Station Manager
- J. McCarthy, Superintendent of Operations
- K~ Moore, Vice President-Nuclear Engineering Servites
- A. Pri~e~ Assistant Station Manager
- R. F. Saunders, Assistant Vice President.;.Nuclear
- S. Semmes, Senior Staff Engineer
- E. Smith, Site Quality Assurance Manager
T. Sowers, Superintende~t of Engineering
NRC Personnel
- M. Branch, Senior Resident Inspector*
- S. Tingen, Resident Inspector
- J. York~ Resident lnspect6r
- Attended exit interview.
Other licensee employees contacted included control room operators, shift
techni~al advisors, shift supervisors and other plant personnel.
Acronyms and initial isms used throughout this report .*are listed in the -
last paragraph.
2.
Pl ant Status
- ,
Unit 1 began the reporting period at 97 percent power.
On* January 30,
1992, coastdown began and on February 29, the unit was shutdown from 73
percent _power to, begin_ a* s~heduled 64-day refueling outage.
Unit 2 began the reporting period in power operation.
The unit was at
power at the end of th~ inspection period, day 80 of continuous operation.
2
3.
Operational Safety Verification (71707,42700~37828)
The inspectors conducted frequent tours of the* control * rooni to verify
proper *staffing,. operator attentiveness and aqherence to approved
procedures.
The inspectors ~ttended 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 control- room indication to assess operability.
Frequent plant tours
were conducted to_ observe equipment status, ffre protection programs,
_ radiological work practices, plant security programs and housekeeping.
Deviation reports were reviewed_ to assure that potential safety concerns
-were properly addressed and re~orted.
a~
Operation Of Th~ Ventilation System
The inspectors reviewed the various operational modes for the
emergency ventilation system.
When both units are operating at
power, the ventilation system will automatically realign when an SI
signal occurs in either unit_.
When .the ventilation system realigns,
the areas that contain ECCS pumps are exhaust~d through filters to
remove fission products and _provide cooling for pump motors.
In
addition, ventilation to the non-~CCS areas is ~ecured, and
ventilation is p~ovided for the operating charging ~ump in the other
unit.
When one unit is operating and the other unit is moving fuel,
the ventilation system is aligned _such that the primary objective is
to ensure that the fuel building and containment exhaust is
discharged through filters.
In the ventilation system's*refueling mode alignment, if an SI stgoal
occurred in the operating unit, the ventilation system would not
automatically realign to the SI mode of operation. It would remain in
the refueling configuration. - Operators would be required to place
the fuel in a safe condition and then manually realign the
ventilation system for the SI mode of operation.
Step 18 of EP
1-E-O, Reactor Trip or Safety Injection, dated January 16, 1992,
provides instructions for realignment of the ventilation system when
in the refueling mode of operation.
Operators estimated that it
would take approximately five minutes to pl ace the fuel in a safe*
condition and realign the ventilation system if required.
The
ventilation system can be realigned.from the control room.
The inspectors reviewed DC 78-S34, Auxilary Ventilation System,
dated *April 27, 1979.
This DC was implemented in. 1980 and
significantly modified the ve*ntilation system.
One of the
ventilation system changes implemented by DC 78-S34, added the need
to manually realign the system as previously discussed.
Prior to
1980, the ventilation system would automatically realign on recei~t
of an SI signal during the movement of fuel in the ~ther unit.
The
safety analysis performed for DC 78-S34 recognized this change of
b.
3
operation and cohsidered it acceptable.
The safety evaluation, dated
January 17, 1984, performed by the NRC staff for amendments 91 and 92
to the operating l i cense, approved this . method of operation.
The
licensee stated that*the offsite dose during a refueling accident was
significantly higher if the ventilation system exhaust was not
filtered; however, not filtering the exhaust from ECCS areas during
the first twenty minutes following a LOCA had only a minor effect on
the off-site dose. *
.
.
The inspectors reviewed section- 3.22 of the TS and FSAR chapters 5~3
and 9.13 in order determine if the ventilation system was required to
realign automatically or manually upon receipt of an SI signal during
the movement of fuel.
The FSAR only discussed the automatic features
of the system and did not describe the need to manually realign the
ventilation system in the event of an SI signal in one unit when
- moving fuel in the other unit. The TS did not state that the system
was required to be a~tomatic, but the basis section did de~cribe the
system as automatic.
The TS and FSAR failure to describe . the
ventilation systems manual mode of operation was identified as a
weakness.
The inspectors noted another example where *the emergency ventil ati_on
system was aligned such that manual action was required if the system
was required to .respond to an SI. :During this inspection period,
operators placed the controllers-for the emergency ventilation fans
from automatic to manual. In this -alignment, operators would have to
make ventilation system flow rate adjustments during an SI wh_ere
normally the flow* rate is automatically adjusted~
Also, this
alignment increases the potential for a fan to tri~ due to excessive
fl ow rates.
Procedures do not recognize this a 1 ternate mode of .
opera ti on.
This is considered a weakness because procedures should
alert the operators that additional precautions are invoked when in
this configuration.
Opera.ti onal Activity Associated With The Replacement of Swi tchyard
Bus #5 Current Transfonner.
-
On February 28, the licensee replaced ~ current tran~former on one
of the three phases *of bus #5.
This activity involved several TS
action statements and was closely observed by the inspectors.
Switchyard bus #5 supplies power to 2 of .the 3 RSSTs, A and B.
The A
RSST provides off-site power to emergency bus 1-J and the B RSST
provides off-site power to the 2-H emergency bus.
The CT which provides protective and metering_ functions for the
34.5kva/120 vac was noted as having a low fluid level and was leaking
fluid.
The licensee postulated that failure was eminent.
Failure
would cause an unplanned loss of 2 of.the 3 RSSTs which has in the
past _resulted in turbine runbacks due to !RPI power spikes.
Also,
the failure would affect both units and challenge the fast start of 2
4
of_the 3 EDGs .. Several TS action statements impa~t taking the CT
and bus #5 out-of-service:
.
-
TS 3.*9
11Station Services Systems" requires that the 4160
emergency buses to beenergized as explained in TS 3.16
11Emergency Power System
11
requires two EDG to be
operable, two emergency buse.s energized-, and two independent
offsite circuits to energize the 4160v buses.
_
- allows the primary source of offsite power to be unav_ailable for
up to seven* days as long as back-feed capability exists.
TS 3.16.B requires that the EDGs be 6p~rable when offsite power
i-s degra_ded (i.e. 3.16.B only allows 3.16.B.1 or 3.16.B.2).
-.
11Limiting Conditions For Operation
11 specifies that_if
the emergency power supply for equipment on one train is
inoperable that the normal and backup power supplies for the
other equipment must be operable.
The licensee decided to replace the defective CT prior to Unit 1
shutdown with both uni ts at power with the lJ and 2H * emergency
buses being powered by the #3 and #2 EDGs.
Leaving Unit 1 on .
line allows for emergency backup power by backfeeding the
emergency buses if necessary from the station* service trans-
formers.
During the 6-8 hour time that bus #5 would be unavai 1-
abl e, primary offsite *power and
EDG alignment would be as
follows:
RSST A would be deenergized.-
RSST B would be deenergized.
RSST C would be energized.
EDG#3 wi 11 be in standby for the lH bus.
EDG#2 will be running and s~pplying power to the 2H bus.
EDG#3 will be running and ~upplying power to the lJ bus.
EDG#3 is the swing EDG and would not be 100 p_ercent operable to
supply the Unit 2J bus in an emergency.
It would swap to the 2J
bus on an ESF signal, but would not on degraded or under voltage
conditions.
The above offsite pow~r alignment and EOG availabilitj for the 2J bus
would result in violation of TS 3.16.& and, therefore, TS 3.0.1 rir
3.0.2 wo~ld apply.
To replace the CT with both units ai power would
require entry into TS 3.0.1 if it could be accomplished within the
- time allowed by TS 3.0.1. .However, the licensee determined that
based on their estimates the repair would take longer then allowed by
IS 3.0.1 and would require a waiver of compliance .
- -*
5
On February 28, at 1236, TS 3.0.1 LCO was entered and the repairs to
switchyard bus #5 b~~an.
The inspectors monitored the establishment
of the required electrical alignment, bri~fing of the shifts, and
starting of and operational parameters for the #2 and #3 EDG's. The
licensee used te_mporary maintenance operating procedure No. TMOP-312,
Removal From Service of 34.5 KV Bus #5, dated March 2, 1992.
The-
.. inspectors made several trips to the switchyard and verified that
swi tchyard access was under control of the security department and
that bus #6 had access restricted by barriers.
The inspectors
observed the removal and replacement of the defective CT and the
inspection of the other two CTs which were found to be acceptable.
The inspectors also monitored* the* restoration of the plants
electrical systems after replacement of the CT.
The actual time
spent in the action of TS 3.0.1 was such that the waiver of*
compliance was not needed.
However, the provisions in the licensee's
written request for TS waiver, dated February 28, were verified by
the inspectors.
The NRC acknowledged the waiver request in a March 2
letter from the Region II Regional Administrator to the Senior
Vice-President, Nuclear. The NRC recognized the licensee's extensive
planning and* regulatory awareness as contributors iii reducing the
time for repairs* such that the requested waiver ~as not actually
needed.
c.
Housekeeping
d.
Housekeeping throug~out the plant is generally good.
The licensee
. has significantly.improved housekeeping in the condensate polishing
building, boric acid flats, Unit 1 charging pumps -cubicles, cable
fa*ults, emergency switchgear room, turbine building, and auxiliary
builping by refinishing the floors and/or repainting wall and
component surfaces.
The licensee is in the process of repainting the
No. 1 EDG room and Unit 2 charging pump cubicles..
Prior _to
repainting, the original surfaces were sanded or chipped away which
sometimes resulted in poor housekeeping in the adjacent areas.
Station management * has reemphasized the need to maintain good
housekeeping to station personnel while painting or other maintenance
is in process.
Operations TPUP Review
The. TPUP program has completed approximately 1162 of the 3700
_
procedures requiring upgrade in the operatfons area.
The number of
completed procedures exceeded _the program goals.
This program is
closely monitored by management and reports are routinely issued in
order to inform management of program completion status.
The
inspectors routinely monitor the performance of upgraded procedures*
and consider them to be of good quality.
The licensee utilized QA
assessments and quarterly procedure ~pgrade surveys to e~aluate the
- - effectiveness of this program.
Approximately 100 randomly picked
procedure users are surveyed quarterly in order to track the stations
6
perception of new procedures.
The results of these surveys are
utilized to further enhance the quality of procedures.
Vendor manuals are being updated in accordance with the Configuration
Management Program.
The inspectors were irifonned that procedures are
being upgraded* prior to updating vendor manuals and that any vendor
manual update that effected procedure*s would have to be incorporated
into procedures at a later date.
- *
.e~
Computer Programs
The Operations department has implemented a new computer program,
VPASS, which aid operators: in performing their duties and* also_
records and trends hours* ~pent in TS action statements.
Whenever a
TS acti o*n statement is entered, operators are required to enter the
appropriate data into VPASS.
At shift turnovers, operators are able
to print out all TS action statements for review.
Also, the VPASS
record of action statements is provided to station management. for
review. *The program is able to sort and- trend action statements in
many different ways, and provide valuable historical information
relative to action statements.
F6r ~xample, the licensee is able to
accurately specify how*many hours were spent in TS action statements -
_ in 1991 due to inoperable charging pumps *or.any other component or
system covered by the TS.
The ability to trend hours spent in _a~tion
statements will significantly enhance the licensee's ability to focus
ori problem areas:
f:
HHSI Pump Lube Oil Cooler TCVs
Each of the six HHSI pumps hai a lube oil cooler. Service ~ater is
aligned to each cooler tQ remove heat .from the lube oil.
As the lube
oil ;temperature increases, a TCV .automatically opens and regulate SW
flow through the cooler. Review of 1990 and 1991 statfon deviations
revealed that failure- of TCVs to automatically control lube oil
temperature in the required band was a reoccurring problem.
The
primary f~ilure mechanisms were the .TCV being stuck in the shut or
intermediate position due to debris from the SW system that accumu-
lated in the valve internals or the temperature controller not
maintaining the proper setpoi nt.
In order to correct these TCV
. deficiencies, the licensee has .replaced TCV disks ~ith disks that are
different in material and design on five of the six HHSI pumps and
initiated routine flushes to remove silt and other debris from the SW
system.
The new TCV disks were installed in June, 1990 on all three
Unit 1 HHS! pumps and the Unit 2A HHSI pump and in July 1991, on the
Unit 2C HHSI pump.
This modification has not been performed on the.
Unit 28 HHSI pump.
On August 26, 1991, the licensee began to rou-
tinely flush the valves oh a two-week interval.
The licensee's corrective actions have reduced TCV failure rates, but
the problem continues to exist. OnSeptember 10, 1991, the TCV on
the Unit 18 HHSI pump failed to properly oper~te.
on* November 10 and
7
December 3, 1991 and on March 2, 1992, the TCV on the Unit 28 HHSI
failed to properly-operate.
On March 6, 1992, the TCV on the Uhit 2A
HHSI pump failed to properly operate. Whe~*these failures- occurred,_
operator manual action or maintenance was required to correct. the
problem.
The licensee* is aware that the corrective actions
_- _
implemented have not eliminated this problem and was in the process
of procuring redesigned TCVs and contra 11 ers.. . The materials and
procedures requir~d t6 accomplish this modification are scheduled to
be available* May 1, 1992.
Installation of these new components has
not been scheduled.
The modification does not require an outage and
therefore could be started when materials and procedures are
available._
The inspectors concluded- that until the *proposed modifi-
cation is installed, the .li.censee needs to implement additional
- temporary corrective measures to preclude repetitive TCV failures .
HHSI pumps are required to automati~ally start and operate on receipt
of an SI signal.
By design, operator manual actions are not required
for pump operation during the inittal phases of a LOCA~ In addition~
during the LOCA RMT phase, high radiation levels. in the area of the .
HHSI pumps would prohibit operators from manipulating the TCV
controllers.
The inspectors are concerned _that if a TCV failed to -
_ properly control lube oil -temperature during a LOCA, significant HHSI
pump degradation or failure would occur.*
The fai 1 ure to implement adequate corrective actions to prevent _
t~petitive TCV failures was identified as Violation 280,281/92-04-01.
Within the areas inspected, one violation was identified.
4.
Mainte~ance Inspections (62703, 42700, 71500)
During the reporting period, the inspectors reviewed maintenance
activiti~s to assure compliance with the appropriate procedures.
The following maintenance activities were reviewed.
a. * * Roofing Leaks
One of the areas examined during the last inspection period involved
the number of roofing leaks present at the Surry plant.
During this
inspection period,* a meeting was held with. the *manager of
Civil/Mechanical Engineering to discuss the roof program~ There wete
several parts to this program; and one part,_ the a_uxiliary building
roof replacement, has had the ~pecifications established and the roof
designed.
The total roofing program wi 11 be prioritized with the
auxiliary building roof being first.
The presentation-of the roof
m_anagement program recommendations to upper management is scheduled
for March 31, 1992.
These recommendations will include- repair,
replacement, and retrofit for a five-year period.
The inspectors
will continue to follow this program and its effect -On decreasing the
number of leaks.
b.
8
Maintenance Program Innovations
The inspectors observed several maintenance innovations that are
being implemented to improve the overall perfor~ance of the
maintenance department.
These innovations are as follows:
During a maintenance self assessment, it was determined that
there was a lack of corrununi cation between the maintenance
manager ind the maintenance craftsmen.
The maintenance manager
decided to alleviate this situation by holding quarterly
meetings starting February 1992.
The inspectors attended one of
these meetings and noted that there was a good exchange of
information.
The maintenance department has started issuing a maintenance
department report on a monthly basis.
It's purposes are to
explain various department tasks and processes, to make
individuals more cognizant of their own and other depart~ents
1
work.
Inputs to the December~ 1991 report are from electrical
maintenance, mechanical maintenance, maintenance engineering,
preventive maintenance, MOV, predictive analysis, and welding
groups.
These articles included such topics as ALARA update on
- exposure reduction, challenges identified by the maintenance
self assessment, EOG task team report, and malfunction of a
control rod that caused a manual trip.
Another innovation involved the meeting of individual
maintenance teams with the QMT/ALARA coordinator and some of the
managers to establish goals that will improve quality of work
and reduce the radiation exposure.
The inspectors will monitor the effect of these innovations with
respect to the effects on the quality of maintenance.
c.
Feedwater Regulation Valve Repair
During the last two inspection periods, the inspectors have followed
the repair of FRVs.
In the December period, these valves may have
contributed to a turbine/reactor trip caused by a high f eedwater
level iri the B steam generator. A review was made of the 'licensee's
evaluation of the FRV oscillation, including testing and modification
documentation.
Modification documents and current evaluation showed
that a smaller size tubing had been installed for the supply.air
lines. This smaller tubing size could cause a longer stroka time for
the valves.
A station deviation (No. S-92--0121) was written.
The licensee
reviewed the time for the closing of the valves by reviewing a
previous trip/ESF actuation and noted that it took seven seconds to
close the valves. Analysis assumptions were for no more than a 10 to
9
15 second closing time.
Th~ licensee is replacing the Unit 1 tubing
with the proper size during this outage and the valves wil.l be placed
in an ISI .program *that will provide per*iodic timing testing of the
_valves.
Within the areas inspected, no violations were identified.
5.
Surveillance Inspections (61726, 42700)
- During th~ reporting period, the inspectors reviewed surveillance
activities to assure compliahce with the appropriate procedure and TS
requirements.
The following surveillance activity was reviewed:
a.
Testing of Unit 1 and 2 Relays
During a review of TS change no. 235, the licensee discovered.that a
relay in the SI system logic sequence was not-adequately tested as an
active component.
The subject relay actuates on low Tave* and makes
up the matrix needed for high steam flow in coincidence with low Tave
- or low steam line pressure.
The monthly periodic. test checks
continuity but does not test for relay actuation at the SI contacts~
The licensee entered a six hour clock to hot sh~tdown (TS 3.7 t~ble
3.7-2). at 1413 on February 14.
The appropriate perodic tests,
1-PT-8.3A (dated June 27, 1989) and 2-PT-8.3A (dated October 2,-
1990), Safety Injection and Feedwater Control Isolation Lo.gic, were
- revised to include the testing for these relays. * The inspectors
observed this testing in the ESGR room for both units and reviewed
the documentation.
Both units were successfully tested and the six
hour clock was exited at 1434 hours0.0166 days <br />0.398 hours <br />0.00237 weeks <br />5.45637e-4 months <br />.
_An LER {no. Sl-92-003) was .
written to cover this event and i*s discussed further in paragraph
10.b.
.
b.
lJ Bus ESF Actuation with Undervoltage and Degraded Voltage
The inspectors * witnessed the tes.ting of ESF actuation with
undervoltage on the lJ bus.
The test was accomplished in accordance
with procedure 1-0PT-ZZ-002, ESF Actuation With Undervol tage and
Degraded Voltage - lJ Bus, dated February 27, 1992.
The inspectors
-reviewed the test instructions. and attended the pre-evolution
briefing.
The. licensee had assigned a Senior Operation Manager on*
duty during performance of this infrequently performed task.
This
provided the shift crews with the needed support as well as allowing
the managers to participate iri the briefing *and monitor the
- performance~
Within the areas inspected, no violations were identified .
6.
10
Quality Verification and Safety Assessment Review (40500)
The inspectors conducted a review of the licensee's corporate independent
review functions and 'industry operating experience program.
TS 6.1.C.2
- requires that the MSRC be responsible* for the review of safety
eva*luations, unreviewed safety_ questions, -TS changes, violations,
.. significaDt abnor~alities, LERs, deficiencies that could affect nuclear
safety, and SN SOC meeting minutes.
the licensee implemented the
requirements by submitting all LERs, violations and TS changes to MSRC
members for review.
-
Additionally, al_l safety evaluations are independently reviewed *by CNS
while performing as a subcommittee to the MSRC.
CNS also reports to the
Manager of Nuclear Licensing and Programs when conducting independent
assessments of station activities and when implementing the industry
operating experience program.
The inspectors* reviewed the following
program implementing procedures:
LICP-4000 Corporate Nuclear Safety,
LICP-2001 Independent Review Program~ NLP ADM 4.1 Review and Processing of
Industry Operating Experience Documents and VPAP 3002 Operating Experience
Program.
.a *
Independent Review Process
- Throu~h t~e Independent Review program, CNS independently reviews all
safety evaluations performed in accordance with lOCFRS0.59 and
reviews a 11 SNSOC meeting minutes.
The inspectors discussed the
program with responsible -personnel, reviewed selected independent
verification packages for effectiveness and reviewed qualifications
of individuals.
P_ersonnel assigned to perform the reviews a*ppeared
to collectively possess experience* and competenc~ in the diverse
disciplines necessary to be effective.
However, the training folders
for the persons assigned the IR function were not always complete and
were difficult to audit.
The inspectors questioned the licensee on the use of the 1R process
to meet the MSRC oversight requirements of TS 6.1.C.2 since the.TS
did not specifically discuss the use of subcommittees.
Tlie
licensee's TS amendment that invoked the current MSRC oversight does
discuss the use of subcommittees in the support information and the
use of subcorrmittees is described in the NRC's guidance on oversight*
o.f offs i te committees.
The inspector found the licensee process
acceptable and .in complian_ce with TSs.
The IR program was clearly
defined by the controlling proc~dure and appeared to be effective in
i dent ifyi ng and resolving concerns as we 11 as tracking and reporting
the status of items.
The inspectors noted that while safety _
evaluations-were reviewed, the licensee's program had no requirements
to independently review a sample of activity screening checklists. * *
Improper use of screening checklists could.res~lt in not performing
the necessary written safety evaluation.
Additionally, the person
assigned the primary review function for the SNSOC meeting minute*s
does not attend the meetings.
The licensee agreed to consider the
J
b.
c.
11
need to have the reviewer periodically attend SNSOC meetings and to
continue with their assessment of the quality of the safety evalua-
tion screening process.
Industry Operating Experience Review
CNS is responsible fcir maintaining the licensee's IOER Program with
the purpose of reviewing IOER documents to assess . ap*pl i cabi 1 i ty and
develop action plans necessary to. prevent or minimize the _ *
consequences of previously* experienced industry events.
IOER.
documents include NRC Inf_ormation Notices, Generic Letters, Virginia
Power LERs, *10 CFR 21 Notifications, INPO event reports and
Westinghouse Technical Bul_l~tins.
IDER documents are initially
sc_reened within 10 days and assigned a- priority to prepare an
analysis report and develop all acti.on plan within 30, 60, or.90 days
to address the concern. The inspectors selected a sampling of
documents and determined that appropriate priority had been assigned
and that action plans were of high quality, clearly identifying the
concerns and needs for further action.
IOERs selected for review
ihcluded IN 91-46, GL 91-05, IN 88-60, and GL 90-05.
The insp~ctors
identified weaknesses with the licensee's tracking system for
documents. In many cases, due dates were not assigned, due dates had
been exceeded or proposed acti ans had been rejected with no
.indication that followup was* being pursued.
The inspectors
determined that in general the actions were being adequately pursued
and the problems were confined to maintenance of the tracking system
data base.
CNS Assessments and Event Reviews
The CNS assessment and event review process is controlled by
procedure LICP-4000, Procedure for Performing Assessments and Event
Reviews.
At the time of the inspection, this procedure was in the
concurrence cycle for approval.
The new procedure replaced procedure
NL&P~ADM-2.2
and
incorporated changes in the. program and
organization. The assessment and event review process is not required
by the TS. The stated purpose of the CNS event review and assessment
process is to independently evaluate technical issues, performance
problems or other areas as requested by the MSRC, senior management,
or statfon management and make recommendations for improvements.
The inspectors discussed the ass~ssment and review process with the
supervisor of nuclear safety review and several members of his staff.
The planned CNS assessments are integrated. with other review
activities scheduled at the station. In some cases, personnel from
other organizations are included as part of the team.
The list of
1991 assessments and reviews were discussed and management's
involvement in the process was evident by the number of senior
management requested assessments that were performed ..
Within the areas inspected, no violations were identified.
12 _
7.
IPE Internal Flooding Corrective Action Review (71500)
Surry Power Stati.on's IPE determined that it had a higher than expected.
degree of vulnerability for turbine building flooding.
A team inspection
was made in November, 1991, to as~ess the licensee's correcti~e action
plans *and interim protective measures.
The Chairman held.a public meeting
ori this subject at the Surry Nuclear Information Center on November 29,
1991.
Certain actions were taken to reduce this vulnerability, among* them
was* inspection of one of the main condenser outlet expa*nsion joints by the
licensee.
This was done in order to estimate the service life of the
-
eight affected expansicin joints.
The inspection showed degradation of
this expansion joint and the licensee decided to inspect the remaining
expansion joints.
There were varying degrees -of degradation found in
these remaining joints *. * Consequently, the licensee decided to replace all
of these 96 inch diameter expansion joints and committed to accomplish
this by February 28.
_Cln .. February 22, this task was completed.
Each
expansion joint replacement took about ten days and initially the licensee
believed that TS waivers would be required for four of these replacements
(2 for each unit) because emergency service water lines would have to be
isolated by stop log installation.
However, the licensee developed and
designed a system that did ncit compromise safety, gave two barriers for
worker safety, and eliminated the need to isolate a safety system train
thereby neQating the need for an TS waivers.
Within the areas inspected, _no violations were _identified.
8.
ESF Verification -(7171b)
The inspectors walked down the safety related portions of the ventilation
system.
The ventilation system is shared between the units. Sheets 1, 2,
and 3 of drawing 11448-FB-6D were utilized for this walkdown.
The
fo 11 owing discrepancies were i dentifi_ed during tlie wa lkdown:
.
-
.
Overall labelin~ of ventilation system compone~ts was poor.
Manual
dampers were not labeled, many had the identification numbers and
open/closed positions annotated in handwriting with a felt marker on
the component.
The handwheel on the motor operated dampers to the
chargin~ pump motors were not labeled. Other components were labeled
with red tape, duct tape, pencil, or felt marker.
The inspectors
walked this system down with the Configuration Management labeling
personnel, and were informed that the relabeling program which is
scheduled for completion in March, 1993 would resolve these
deficiencies.
bil was dripping from 1-MOD-VS-lOdB hydraulic actuator:
There was
oil on the piping and wall below the MOD.* The inspectors hated that
a work order to repair the oil leak was initiated in February 1990,
but was classified as low priority and had not been scheduled to be
.worked.
1-MOD-VS-lOOB is required to automatically operate on an SI
signal.
The inspectors were informed'that monthly periodic testing
13
on the ventilation system verifies that* the MOD repositions.
The
inspectors were al~o informed that if the oil level in the damper's
reservoir got too low, the MOD would not open as required .. The MOD
oil leak hai been scheduled to be repaired during the second week of
March, 1992. *
The insp~ctors noted that the physical condition of the ventilation system
was in the process of being improved.
Some of the duct work ~as recently
painted or primed, but the majority of the duct work still needed
painting. Housekeepi~g in the ventilation system areas was adequate.*
Within the areas inspected, no violations were- identified.*
9.
Technical Procedures Upgrade Program. (42700).
The inspectors discussed the technical procedure upgrade program with the*
licensee on*March 3 and 5.
This program was started December 31,-1989, *
and is sc_heduled to be completed by December 1996.
The following table
shows the disciplines and the number of technical procedure that are to be*
written over the life of the program.
Discipline
Electrical
Mechanical
- Ops (Dual)
- Ops (Single)
- Other
- Annunciator Procedures and EOPs
- Nonnal OPS Procedures
- Special Tests, etc.
.
.
- Number of Procedures
- 1072
585
1538
1915
1784
588
A review of the status of the TPUP revealed that most cf the procedure
disciplines are above or just slightly below .the goal with the exception
of the I&C procedures.
The procedures. group exceeded the 1991 yearly goal
for writing I&C pro~edures, but still continues t6 be below the overall
goal, i.e. 210 procedures complet~d and the goal was approximately 410
completions.
.
The inspectors also ~eviewed the backlog of PAR's that are used to change
or modify the procedures.
The PAR program was started in February 1990.
Actual procedur~ revisions would be made when SNSOC directed the proce-
dures group to make the change.
In July 1990, this committee directed the*
procedure~ group.to incorpor~te changes to procedures when the number of*
I s reached five or more and on February 10, 1992, the process .of
incorporatiori of all PAR's into procedures was included in VPAP 0502.
As
of D~cember 1991, the number of outstanding PARS was 1323 and this appears
excessive to the inspectors.
Al so as of this date there were 23 proce-
dures outstanding that had five or more PARS's and 339 PARS's outstanding
14
.procedures). Approxi~ately 15 percent of*thi upgraded procedures have one
or more (open or closed) PAR
I s and approximately 31 percent of the.
.
rion-upgraded procedures have on~ or more. This indicates that the upgraded
procedures are of better quality and require fewer changes within the
areas inspected*.
No violations were identified.
16.
Licensee Event-Rev~e~ (92700)
The inspectors reviewed _the LER's listed below and evaluated the adequacy.
of corrective ~ction.
The inspector's review also included followup on
the licensee's implementation of corrective action.
.
.
.
.
.
a.
(Closed) LER 280,281/92-002, 4160 Volt Transfer Bus D, E, and F
Undervoltage Relay Trip Setpoints Set Below TS Limit Due to Procedure
Error.
This issue involved not setting the station blackout motor
driven AFW pump start relays in accordance with the values specifiep*
fn TSs. * This issue and corrective actions were discussed in
Inspection R~port 280,281/92-02.
This event was caused by an error
.in calibration procedures in that an incorrect" UV relay trip setpoint
was Specified.
TS 6.4.A.2 requires detailed written procedures for
ca 11-brati on of components i nvol vi ng nuclear safety of the* station.
The failure to provide an adequate procedure to calibrate the station
blackout motor driven AFW pump start relay~ is identified as NCV
280,281/92-04-02 .. This violation will not be subject to enforcement
action because the 1 i censee' s efforts in identifying and correcting
the violati~n meet the criteria specified in Section V.G. of the
b.
(-Closed) LER 280, 281/92-003, Incomplete Engineered Safety Features
Testing Due to Procedure Defici~ncy. This issue in~olved the failure
to fully test certain ESF system logic actuati6n relays in accordance
with TS Table 4.1-1, Item 26.
Specifically, actuation of the relays
which energize on low reactor coolant average temp~rature were ~ot
being verified (see paragraph 5.a for more d~tails).
The-licensee
discovered this during a procedure upgrade. TS 6.-4.A.2 requires
detailed written procedures for calibration of components involving
nuclear safety of the station.
The procedures were revised and the
relays were tested. This failure to provide an* adequate procedure to
fully test the ESF system logic actuation relays is i~entified as NCV
280,28l/92-04-03.
This violation will not be subject to enforcement
- action because the 1 i censee I s efforts* in i den ti fyi ng and correct fog
the violation meet the criteria specified in Section V.G. of the
c.
(Closed) LER 280/91-13, MCC Room Fire Suppression System Inoperable
Due to Personnel Eiror in Administratively Controlling the MCC Room
Exit Door,
This issue involved personnel blocking open the Unit 1
cable vault upper level MCC room exit door without es_tablishing
!
15
provisions to shut the door if a fire in the area would have
occurred.
.This issue was discussed in Inspection Report
280,281/91-29 and was 1 eft open because the 1 icensee had not
completed corrective actions:_ The licensee has install~d si9ns on
fire doors that explain the special precautions that must be followed -
when the door 1s open.
Within the areas inspected, no violations were identified.
11~
Exit Interview
The inspection scope and results were summarized on March 9, 1992~ 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
VIO S0-280,281/92-04-0l
Open
NCV 50-280;281/92-04-02
Closed
NCV 50-280,281/92-04-03
Closed
LER-50-280,281/92-002
Closed -
LER 507280,281/92-003
Closed
LER 50-280/91-13
Closed
12.
Index of Acronyms and Initialisms_
Description and Reference
Ineffective Corrective.Action
Associated With HHSI Pump
Lube-Oil Cool er TCVs ( paragraph
3.g}.
Fai 1 ure to Properly Test the
.
Blackout Relays for Starting Motor*
Driven AFW {paragraph 10.a).
Failure to P~operly Teit the
Average Temperature Portion of ESF
Logic Circuits (paragraph 10.b).
4160 Volt Transformer Bus D, E,
and _F Undervoltage Relay Trip
Setpoints Set Below TS Limit Due
to Procedural Error- (paragragh
10.a).
Incomplete Engineered Safety
Features Testing Due to Procedural
Deficiency (paragraph 10.b)..
-
MCC Room Fire Suppression System
Inoperable (paragraph 10.c).
- ALARA
AS LOW AS REASONABLY ATTAINABLE
16
CFR
CODE.OF FEDERAL REGULATIONS
CORPORATE NUCLEAR SAFETY.
. CURRENT TRANSFORMER
Design Change
EO.P
EMERGENCY OPERATING PROCEDURE
EMERGENCY PROCEDURE
ENGINEERED SAFETY FEATURE
~
EMERGENCY SWITCHGEAR ROOM
FEED REGULATING VALVE
FINAL SAFETY ANALYSIS REPORT
GL
GENERIC LETTER
HHS!
-
HIGH HEAD SAFETY INJECTION
INSTRUMENTATION AND CALIBRATION
IN
INFORMATION NOTICE
INSTITUTE OF NUCLEA~ POWER OPERATION
IOER *
INDEPENDENT OPERATIONAL EVENT REVItW
INDEPENDENT PLANT EVALUATION
IR
INDEPENDENT REVIEW
!RPI
. INDIVIDUAL ROD POSITION INDICATION
lNSERVICE INSPECTION
LCO
-
LIMITING CONDITIONS OF OPERATION
- LOSS OF COOLANT ACCI~ENT
LER
-
LICENSEE EVENT REPORT
-
MOTOR CONTROL CENTER
MOTOR OPERATED DAMPER
MOTOR OPERATED VALVE
MSRC
MANAGEMENT SAFETY REVIEW COMMITTEE
NON-CITED VIOLATION
NRC
.-
. NUCLEAR REGULATORY COMMISSION
OPERATIONS
PROCEDURE ACTION REQUEST
QUALITY ASSURANCE*
QMT
QUALITY MAINTENANCE TEAM
.
I
REVOLUTIONS PER MINUTE
RESERVE STATION SERVICE TRANSFORMER ..
SA/QV
SAFETY ANAL YSIS/QUAL!lY VERIFICATION
SAFETY INJECTION
SNSOC
STATION NUCLEAR AND SAFETY .OPERATING COMMITTEE .
TEMPERATURE ~ONTROL VALVE
TPUP *
TECHNICAL PROCEDURE UPDATE PROGRAM
TS
-
TECHNICAL SPECIFICATIONS
UV .
VPAP
VIRGINIA POWER ADMINISTRATIVE PROCEDURES
VPASS
VIRGINIA POWER ACTION STATEMENT SYSTEM