ML18152A444
| ML18152A444 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 01/27/1993 |
| From: | Belisle G, Tingen S, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A445 | List: |
| References | |
| 50-280-92-25, 50-281-92-25, NUDOCS 9302020028 | |
| Download: ML18152A444 (12) | |
See also: IR 05000280/1992025
Text
Report Nos.:
UNITED STATES
NUCL~AR REGULATOFJY COMMiSSION
. REGION II
101 MARIETTA STREET,N.W.
ATLANT~. GEORGIA 30323
50-280/92-25.and 50-281/92-25
licensee:_ Virginia Electdc and Power Compan_y
5000 Dominion Boulevard *
~ljn All~n, VA
23060
Docket Nos.:
50-280 and 50-281
License Nos.: *DPR-32 and DPR-37
Facility-Name:* Surry-I and 2
,
Inspection Conducted:
November 2_9, 1992-January 2, 1993 .
Inspectors:
Approved by:
Scope:
G. A. Belisle,S'Chief
Division of Reactor Projects
SUMMARY
/- 27- 7" 3
Date Signed
/ - ). 7-t1)
Date Signed
/-J]-fs
. Date Sign~d
This routine resident inspection was conducted on site in the area of
operations, maintenance, internal plant evaluation corr~c~ive action, safety
assessment and quality verification, and licensee event review.
During the
performance of this i n.spect ion,. the resident inspectors condu.cted review of
the licensee's backsh i fts, holiday *or weekend operat i ans on. November 29,
December 6, 11, 12, 13,. 16, and 24.
.
Results: *
In the operations ar~a, the follriwing ite~ was noted:
Operatot~ responded properly to a leak in the letdown system and their
prompt action minimized the loss of reactor coolant (paragraph 3.b) .
9302020028 930127
ADOCK 05000280
G
2
-
In the maintenance/surveillance functional area, the following items were
noted:
The cause determihation evaluation backlog has been reduced but still
remains high.
Additional act~ons ~ere being imple~ented to further
reduce the backlog (p~ragraph 4.a).
The intermediate seal cooler was replaced, tested, and returned. to
service within the Technical Specification allotted time period,
however, a temporary*repair performed during a previous cooler
rep 1 acement was* not documented.
This d*e 1 ayed the coo 1 er rep 1 acement and
its ret~rn to service (paragraph 4.b).
The m~(:hanical maintenance outage group has taken a proa_ctive role in
scheduling maintenance* items for the upcoming refueling outage
(paragraph 4.c).
Performance of periodic maintenance associated with replacement of
backflow preventers was delayed because an upgraded procedure did not
- contain leak rate acceptance criteria (paragraph 5.a).
In the safety assessment/quality verification area, the fril1owing items were
noted:
-
,,
The inspectors concluded that the root cause evaluation associate*d with
the failure of the Unit 2 turbine building service water joint in July
1992 was thorough and the root ciuses of the event were identifi~d
(paragraph 5. a).*.
Throughout 1992, problems a*ssociated with Kaman radiation-monitor
spiking have occurred.
The cause determinati6n ev,luation performed as
corrective action in response to this problem was unabl_e to identify the
root cause of the problem.
Although the 1 i censee was unable to identify
the root ca~se, th~ problem-was aggressively pursued (paragraph 6.b). *
Recurring problems were identified in the areas of intermediate seal
cooler tube leakage, ground water intrusion, and roof leakage.
(paragraphs 3.c and 4.b).
-
REPORT DETAILS
1.
Persons Contacted
licensee Employees
R. Allen, Supervisor, Operations
- W. Benthall, Supervisor, Licensing
- R. Bilyeu, Licensing Engineer *
- H. Blake, Superintendent of Site Services -
M. Bowling, Manager, Corporate Nu~l~ar Licensing.
- R. Blourit, superintendent of Engineering
- D. Christian, Assistant Station Manager
J. Downs, Superintend~nt of Outage arid Planning
D. Ericksoni Superintendent of Radiation Protection
- R. Gwaltney, S~perintendent of Maintenance
- M. Kansler, Statiop Manager
. .
.
- A. Meekins; Supervisor, Administrative Service~
- J. McCarthy, Superintendent of Operations
J. O'Hanlon, Vice President, Nuclear Operations
A. Price; Assistant Station Manager *
.
- * _ R. Saunders, Assistant Vice Presiderit, Nuclear Operations
- E. Smith, Site Quality Assurance Manager
B. Stanley, Supervisor, Station Procedures
-NRC Personnel *
- S. Tingen~ Resident Insp~ctor
- J. York, Acting Senior Resident Inspector.
Accompanying NRC Inspector
A. Ruff
- Attended Exit Interview
Othe.r licenseeemployees contacted included control room operators,*
.
shift technical advisors, shift supervisors and other plant personnel.
On December *a, the Region II Regional Administrator,*s.* Ebheter; visited
the Surry Power Station for a familiarjzation tour.
He also met with
licensee management and *staff and reviewed the current status of the
station.
The Regional Administratof was accompanied by M. Sinkule,
Brarich Chief, Region II. Later in the day,- the Regional Administrator
held a press conference in Richmond, Virginia.
Acronyms and initialisms used throughout this report are listed ~n the
last paragrap_h ..
2
2.
Plant Status
Unit 1 began the reporting period in power operation and was at power -at
the end of the -inspection period, day 118 of co_ntinuous op_eration.
Unit- 2 began the reporting period in power operation and was at power at
the end of the inspecti~n period, day 168 of_continuous operation.
3:
Operational Safety Verifitation (71701, 42700)
The *inspectors conducted _frequent tours of the control room to verify
-proper staffing, operator attentiveriess and adherence to approved
ptocedures .. The inspettors attended plant status meetings and reviewed
operator logs on a daily basis to veri,fy operations safety and
compliarice with TSs and to maintain awareness ~f the overall ~peration
of the facility.
Instrumentation and ECCS lineups* were periodically
reviewed from control room indication to assess operability.
Frequent
p1~h~ tours were conducted to bbserve equipment status; fire protection
programs, radiological ~ork practit~s, plant security programs and
housekeeping.
Deviation reports were reviewed tci assure that .potential
safety concerns were pfoperly addressed and reported.
a.
b.
Cold Weather Protectio~ Preparations (71714)
During this fnspection period, the*.inspectors reviewed the
licensee's program for-implementation of protective measures for
cold weather.
This program is implemented by monthly performance
(October through March) of STP-52, Cold Weather Protec_tion, dated
April 3~ 1992.
This proced~re contains a_detailed checklist of
areas and components that need to be routinely inspected to ensure
that there is adequate protection to preve~t freeiing;
STP-52 is
performed by both operations and maintenance personnel ..
Defici~ncies that are noted durihg the performance of STP-52 are
documented and discrepancy reports/work requests are written to
ichedule cortective action. A designated individual from the
operations department i-s assigned the- re_spons i bi l i ty for
_
prioritizing these w_ork requests for _action.
The inspectors
discussed the performance of STP-52 with this individual and
operations management, and no concerns were identified.
The
inspectors toured severa1 areas listed in.STP-52 and no
discrepancies were identified.
The inspectors reviewed the results of a QA assessment that was
perfojmed during the per~od October 12-15, 1992.
This assessment
evaluated the performance of STP-52 and concltided that the methods
used to protect station equipment from cold weather were adequate.
RCS Leak on Unit 2 Letd6wn System Flow Trans~itter
On December 12, a swag el ok/tubi_ng connection failed and
approximately twenty-to thirty gallons of reactoi coolant spilled.
- -**
3,
_,
into the lower level <_>f the auxiliary building.
Two lfcensee-
wotkers in the ar~a were contaminated.
The*swagelok connectioh
that failed_ .was on the high pressure side drain va*lve for letdown
flow transmitter.2-CH-FT-2150. -When the conne~tion failed,
-control room letdown flow indication decreased to_ zero and VCT and
pressurizer lev~ls itarted to decreas~.
The ~rintrol room.
operators immediately isolated letdown and charging**flow, and
stabilized VCT and pressurizer levels.
TS 3.1.C.5 was -entered
because the RCS leakrate had exceeded 10 GPM. _ The failed
connection was repaired and letdown-flow was reestablish~d later*
in the shift. The inspectors concluded that the operators * _
_
r~sponded*proper1y to*the event and their prompt action minimized
- the loss of reactor coolant.
- *
At the end of the inspection period, the licensee was performing
an RCE to determine the cause~for the failure of the connection.
c~.
Roof Leaks and Ground Water Intruiion
_ On December 12, the inspectors toured the_ itation and identified
the fo 11 owing locations and components that were wetted from
ground water intrusion and roof leakage:
In the auxiliary building, the Uriit 2 MSTV SOVs and Test Box_
and an emergency lighting panel _near the Unit 1 MSTV SOVs
were wet from ground water intr~sion.
In the Unit 2 safeguards building~ the A and B outside
recirculation spray pumps were wet. _ No electrical
components on these pumps were wet; however; the fasteners
on the base of the B pump were corroded indicating that this
problem has existed for some time ..
- In the Unit 2 safeguards buflding Valv~ pit, sections df the
Unit 2 LHSI and outside recirculation spray pumps piping
were wet and corroded.
Also, several cable triy~ in the
area were wet.
The fuel bu il d_i ng roof* was leaking, but rain water was not
observed to be ~ripping into the fuel ~ool.
The Unit 2 safeguards roof was leaking onto the floor behind
the containment spray pumps.
There was approximately one inch of water on the floor of -
the boron recovery room whith appeared to be caused from
- .*ground water intrusion.
- -
Roof leakage and grourid water intrusion were idintified as~ problem
- duting the previous SALP assessment period, and the licensee has
- implement~d the following cbrrective actions: repair roofs, improve
grading around the buildings in-order to direct water away
4
from the building, and improve the performance of sump pumps.
These
corrective actions -are still ongoing.
The majority of the components
- identified during this inspection were wetted by gro~nd water intrusion.
No roof leaks were fdenti.fied in the auxiliary building which recently
had a new roof installed .
. Within the areas inspected; no virilations were identified.
'
'
4.
Maintenance Inspectio~s (62703) (42700)
~
.
.
.
During the ~eporting period; the inspectors re~iewed the following
maintenance activities to assure compliance w.ith the appropriate
procedures.
a:
- Maintenance Engineering CDE Backlog
During the previous SALP assessment periods, the backlog of CDEs
increased.
The CDE backlog has been reduced but still remains
high.
The previous backlog. of approximately 400 CDEs has been
reduced to lesi that 200 CDEs.
In order to further re~uce the CDE
backlog, two engineers were assigned to-the maintenance
engineerihg department at the end bf the ihspection period to aid
in the performance of CDEs, -and the maintenance engineering
department has established a goal to complete CDEs within 45 days
of WO closure.
b.
Unit 1 Jntermediate_ Seal Coolef Replatement
The inspectors witnessed the repl~cement of the Unit 1 charging
- pump intermediate seal cooler 1-SW-~-lA.
The intermediate seal
cooler was replaced due to tube leakage. This maintenance was
accomplished in accordance with WO 3800135897, and procedures
O-MCM-1004-01, Flange Gasket Replacement, dated June 14, 1991, and
O-MCM'-1801-01, Piping/Components Repair/Replacement, dated
February 27,1992.
The inspectors observed ~ortions of the m~intenance, and* reviewed
the work package, post maintenahce test requirements, and work
histories for the Unit 1 and 2 intermediate seal coolers.
During
- the maintenance, a scratch on one cooler union connection's mating
surfaces was identified. ~he licensee repair~d the defect by seal
. welding the union.-
The resolution for the defect delayed
completi~n of.the seal ~ooler replacement.
This defect was a pre-
existing condition that had been temporarily repaired in September
1992.
Proper documentation ~of the temporary *repair would have -
resulte_d in maintenance planning for the permanent seal weld
repair thereby reducing the equipment out of service time.
The*
~ooler was replaced, tested,* and placed back into service within
- rs time constraints.
The post maintenance test requirements were
considered correct.
-
- -
5
Review of the maintenance histories for thefour intermediate seal
coolers -indicated that the c.oolers in both Units had to be
_
fr~quently replaced due to tube leikage. * Since 1986, intermediate
. seal coole~, 1-SW-E-lA, has been replaced seven times, 1-SW-E-lB
has been replaced six times, 2-SW-E-lA has been _replaced four
times, and 2~SW-E-la has been replaced three times.
The licensee
replaced the coolers due to excessive tube leakage, but has not
implemented corrective actions to prevent the problem from
recurring.
c.
_ Mechanical Maintenance .outage Planning
The mechanical mainte~ance de~art~~ht formed a special group to
~lan f6r the upcoming Untt 2 RFO.
The goals of this group ar~ to.
- min1mi~e the radiation dose and ma~imize the cost effectivehess
for mechanical maintenance j9bs scheduled,for,the upcoming RFO.
Some'of the functions of the group are to maximize pre-outage
work, and if the work is required to be done during the outage,
determine the best opportunities (windows} for *performance.
They
are also providing priorities for performance of these items,
doing walk downs on components* arid work items, and developing
pre-job briefings.
The inspectors met with this group and it appeared .that the.
group's activities should have a positive impact on the upcoming
.RFO.
For example, the original Unit 2 1993 outage schedule
required that 5 of he 15 MS safety valves be remov~d, overhauled
and tested with the remaining MS saf_ety valves tested in place.
However, the outage group review~d the 1994 RFO schedule and noted
- that all MS safety va]ves were to be removed and the MS lines
blanked to support a ten-year ISi hydrostatic test of the system.
The group concluded that it would be more cost effective to remove
and ov~rhaul all the valve~ during the 1994 RFO.
Additionally,*
one of the lessons learned _from the previous RFO was_that shift
turnovers were ~ot always adequate.
The group revised foreman
shift schedules for the upcoming RFO to enhance shift turnovers.
The inspectors concluded that the mechanical maintenante group was
taking.a proactivi role in scheduling for the upcoming RFO.
Within the ,reas jnspected, no Violations were identified.
5.
Review of IPE Flooding Corrective Actions *(71~00)
a.
Floor Drain Stop Valve Replacement
One of th~ protective measures implemented to mitigate the
consequences of turbine. building flooding was to enhance the
performance of.specific floor-drain backflow preventers by
implementing a periodic maintenance progr~m.
The inspectors
witnessed the testing and replacemen~ of the flopr drain backflow
preventers in MER 3, the Unit 1 and 2 cable vaults, MER 4, and the
Unit 1 and 2 ESGRs.
This quarterly PM wa~ accomplished per WO
6
. .
.
.
3800135842 and upgraded procedure O-MPM~1900-02, Quarterly Flood
Ptotection Floor Drain s,ck Water Stop Valve Replacement, dat~d
February 13, 1992.
-Each backf\\ow preventer was seat leak tested fn a test rig and
then installed in the ~lant.
One of the backflow preventers
leaked e~cessively and th~ seating surfaces had to be lapped in
order-for .it to pass the leakage testa Procedure O-MPM-1900-02
did not ~ontain a quantitative seat le~kage speci.fication which
delayed the PM completion.-
The mechanics consulted with _system
engineering to obtain a satisfactory acceptance crited a for
-leakage.
The licensee planned to revise the procedure to include_
the appropriate acceptance criteria.
No other discrepancies ~ere
identified..
-
Within the areas inspected, no violations were identified.
6.
Safety Assessment and Quality Verification {40500)
a.
Review of Root Cause Evaluation
Ad~inistrati~e *Procedure*VPAP-1601, Correcifve Action, Revfsion 1,
requires that RCEs be performed for events that are *safety
significant. The purpo~es of the RCE are to: 1) provid~ a method
for i dent i fyi ng root causes of human, equipment, and programmatic -
performance probl~ms; 2) identify adverse trends; and 3) identify.
corrective action.
- *
The inspector_s reviewed RCE Report 92-006, dated October 14, 1992.
This report addressed the event _associated \\'{ith the Unit 2 *turbine
building chiller SW line joint failure of July 13; 1992, which was
discussed i~ NRC Inspection -Report Nos. S0-2Bo; 281/92-17.
This
event-was caused by the failure of a chiller supply breaker to
open when the chiller was removed from service.
As .a result, the
chiller continued to operate with SW flow secured: This resulted
tn overheating of the SW in the system, overpressurizati_on of the*
SW supply to the chiller-and the subsequent failure- of a SW pi~ing
joint_.
The inspectors concluded that RCE 92-06 was thrirough in
identifying the root causes of the event.
Hunian performance
problem were identified in the areas of operator-performance and*
procedural adequacy.
Equipment performance prob 1 ems were *
identified in the areas of chiller configuration and SW-piping
epoxy joints. The inspectors also concluded that the* RCE's
proposed corrective actions were adequate~
Many of the proposed
corrective actions required review and evaluation of procedures or
operating practices for necessary revisions. Since these reviews
have not been completed, .the adequacy of the corrective actions
could not be evaluated.
7
b~ * -
Review of ~orrective Action for Repeated Kaman Spikes
Ka~an radiation monitor, RI-VG-131-1, operated er~atically at the
end o~the assessment period in that it repeat~dly spiked into the
alarfu range.
Approximately 39 station devi~tions hav~ been
written in 1992 documenting spikes or erratic operation of the
Kaman monitor.
The Kaman radiation monitor is required by TSs to
be operational and ITJOnitors par~iculate* activity in the
- ventilation system vent stack.
Each time.a spike occurred the.*
ventilation system was sampled .. The sample results indicated that.
a radiation release did not occur.
On *numerous b~casions the
Kamari was decl~red inoperable and the appropriate TS LCO entered._
An engineering stlid_y and a CDE were performed to identify the
cause of the Kaman radiation monitor spiking. These reports.
concluded that the exact cause of the spikes.could not be
determined;. NUmerou~ corrective actions such as disassembling and
troubleshooting the components in the system, resoldering wires,
replacing*compone*nts, and the installing insulati_on on wiring were
- performed.
From the second ha 1 f of_ October_ through the first ha 1 f
of December, ilo spikes occurred and the 1 i censee. speculated that
the problem might have been corrected.
At the end of December,
lhe .Kam~n monitor spikin[ began to r~cur. A comparator board was
replaced and a flow switch was adjusted.
The Kaman monitor was*
- tested and. return~d to service. The Kaman has not spiked since
being return~d to service. *
The inspectors concluded that the licensee has aggressively
pursued corrective action for thi's problem; however, the: _inability
_ to i den ti fy the root ca*use of the spi ~es has resulted in recurring
of *the. problems over the past year.
c.
_Monthly QA Meetin~
The inspectors continued to meet with QA personnel *on a monthly.*
basis to discuss recent QA assessments and audits. The following
items were discuss~d: QA monitoring of the independent
verification process, Triennial and Annual_ Fire Protection Audit,
Inservice Inspection Audit, and the QMT Assessment.
The
inspectors concluded that QA oversight of station acti_vities
remains active.
Within the areas inspected, no violations were identified.
7. *
Lice~~ee Event Review (92700)
The inspectriri reviewed the LERs lfsted helow and evaluat~d the adequacy
of corrective action.
The inspector's review also included followup of
I.
the license*e's .corrective acti_on- implementation.
.8
a.
(Closed) LER 281/91-003, Pressurize'r Safety *Valve Setpoints *
Outside of Technical Specification Allowable Limits.
On April 24,
1991, with Unit 1 at pow~r and Unit 2 shutdown for refueling, two
Unit 2 pressurizer safety valve lift ~et points were found to have
c:lrifted lower than the min_imum allowed by TSs.
Actuation at these
. lower pressures could have an adverse affect on the DNBR. *An
evaluation by the licensee demonstrated that the.setpoinfs assumed
- by the DNBR analysis were less than .the actual set~oints 6f the
~two relief valves and that the safety valves _were capable.of
performing their overpressure mftigatibn function.
There were no
actual o_r potential consequences to the public health_and safety.
The i~tpoint drift of the~e type safety valves has been a ~eneric
issu~ and resulti from a number of causes, such as, loop seal
pufge ti~e, and the fluid medium (steam or water) used to test the
valve.
As a consequence, Westinghouse and the WOG have held*
meetings to expedite a satisfactory.resolution o.f this issue.
- sased on these. meeting and studies, Westihgho4se submitted a
position papei (WCAP 12910, Pfessurizer Saf~ty Valve Set Pressure
Shift) to the NRC for a safety evaluation. Surry has issued new
or revised procedures (l/2-MPT-0424-01, 02~ and 03) to test and
set the pressurizer safety valves in a manner that is supported by
Westingh~use and the WOG position (WCAP 12910).
These protedures
have been approved by the station SNSOC.
T~sting is performed
with steam~
Settings are adjusted to a+/- 1 percent tolerance.
Since th~ loop se~l purge times affected the maximum RCS pressure
during transients and is the major contributor to the apparent
_ pressure shift, plant modifications have been formulated to
provide additional operating.margin for these valves:. The loop
seal purge time will be eliminated by installing loop seal drain
lines.
Plant ~odifications in this area (i.e., steam trim package
- for the valves, loop seal drain lines, and the appropriate piping
supports) are scheduled for the Unit 1 RFO in the spring of .1994
and the Unit 2 RFO in the fall of 1994.
b.
(Closed) LER 281/91-004, Inadvertent Overfilling of Refueling
. Water Storage Tank.
This issue involved the results of a
techt:iical review that was performed for an evaluation of an.
inadvertent overfilling of the Unit 2 RWST.
This reevaluation of
the as-built configuration of the location of the Unit 2 overflow
line showed that the tank could be filled-to a volume of
approximately 399,000 gallons prior to a tank overflow.
Th~ TSs *
allowed 398,000 gallons (TS 3.4.A.3).
The Unit l_RWST's maX"imum
capacity calculated by the position of the overflow piping was
found to be within the TS limits.
The licensee cons6lted with the
Architect/Engineer and discoverea that an analysis had-been made*
during a previous evaluati.o~ for increasing the volume in the RWST
to their current levels. Using this analysis, it was concluded
that the tank design was adequate.
Since no structural concerns
eiisted, a TS change request was .submitted to delete the reference
to maximum capacity for RWSTs.
9
t.
(Closed) LER 281/91-009, *Failure t6 Full Flow Jest 2~RH-47 Due to
Procedure Deficiency. This issue* involved full flow te~ting of
check valve 2-RH-47 during the Unit 2 outage.
The station' ISL *
group's ind~pendent review of the ASME Section Xl program*
,
implementation identified the failure to accomplish full flow
testing of 2-RH~47.
The test procedure co~tained an improp~r
valve lineup.
The RHR sysfem has*a common discharge header which
sp_lits into separate discharge headers. The flow in one loop
passes .through_ a loop_ discharge check valve*, 2-RH-47, before _
discharging into the B reactor coolant loop;
The other loop
discharges directly into the C loop with no check.valve but the
loop does have an isolation valve. *To get full .flow through check
valve, 2-RH-47, the isolatfon ~alve to the C loop would have to be
closed.
The affected procedure was ~hanged and full flo~ testi~g
was performed duririg ~ forced outage.
The RHR syst~m had been
verified capable of delivering design basi~ flow during _the
previous Unit 2 normal outage and the subsequent testing of the
valve d~termined that it was operable. Therefore, no safety
implications were posed during the event.
Within the areas inspected, no viol~tions were identified.*
8.
Exit Interview
.The results were summarized on January 5, 1993, with those individuals
i dent_i fi ed by an asterisk in Paragraph 1.
The following summary of
inspection activity was discussed by the inspectors during this exit:
. * Item Number
Status
. LER .281(91-003
Closed
Closed
Cl os.ed
Description
Pressurizer Safety Valve
Setpoints Outside of Technical
Specification Allowable Limits
(paragraph 7.a).
Inadvertent Overfilling of
Refueling Water Storage Tank
(paragraph 7.b).
Failure t6 Full Flow Test
2-RH-47 Due to Procedure
- Deficiency (paragraph 7 .c).
Proprietary information is not contained in this report. -Dissenting
comments were not received from the licensee.
9.
Index of Acronyms and Initialisms
AMERICAN SOCIETY OF MECHANICAL ENGINEERS
CAUSE DETERMINATION EVALUATION
DEPARTURE FROM NUCLEATE BOILING RATIO
-~
I
I.
ESGR -
GPM
. I&C
- IPE
IR
LCO
LER
LHSI
-
MER
..,
MS
MSTV
NRC
QMT
-RHR
SNSOC -
sov
SW , . -
- TS .
VPAP
WO . --
. 10
EMtRGENCY SWITCHGEAR ROOM
GALLON_S P'ER MINUTE *
INSTRUMENTATION AND CONTROL_
INDIVIDUAL PLANT EVALUATION
INSPECTION REPORT
INSERVICE INSPECTIOij
LIMITED CONDITION-OF OPERATION
LICENSEE EVENT REPORT.
LOW HEAD SAFETY INJECTION
MECHANICAL EQUIPMENT ROOM
MAIN STEAM TRIP VALVE
N.UCLEAR REGULATORY COMMISSION
PERIODIC MAINTENANCE
QUALITY ASSURANCE
QUALITY MAINTENANCE TEAM
ROOT CAUSE EVALUATION
REFUELING OUTAGE
RESIDUAL HEAT-REMOVAL
_
REFUELING WATER STORAGE TANK
SYSTEMATIC ASSfSSMENT OF LICENSEE PERFORMANCE
STATION NUCLEAR SAFETY AND OPERATING COMMITTEE ..
. SOLENOID OPERATED VALVE
TECHNICAL.SPECIFICATION
VOLUME CONTROL TANK*
VIRGINIA POWER ADMINISTRATIVE PROCEDURE.
WORK ORDER .
WESTINGHOUSE OWNERS GROUP