ML18152A107
| ML18152A107 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 07/08/1991 |
| From: | Branch M, Frederickson P, Holland W, Tingen S, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A108 | List: |
| References | |
| 50-280-91-14, 50-281-91-14, NUDOCS 9107160227 | |
| Download: ML18152A107 (23) | |
See also: IR 05000280/1991014
Text
-
UNITED STATES
NU-AR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report Nos.:
50-280/91-14 and 50-281/91-14
Licensee:
Virginia Electric and Power Company
5000 Dominion Boulevard
Glen Allen, VA
23060
e
Docket Nos.:
50-280 and 50-281
Facility Name:
Surry 1 and 2
License Nos.:
Inspector
7
"-1
Dat Signed
7/rj,,
Date Signed
o:Zffis;~
1
- J
Accompanying Personnel:
B. Buckley, Senior Project Manager, NRR
Approved by:
SUMMARY
Scope:
7fa'ft1
DateSigned
This routine. resident inspection was conducted on site in the areas of plant
operations, plant maintenance, plant surveillance, licensee event report
closeout, and licensee self assessment capability.
During the performance of
this inspection, the resident inspectors conducted review of the licensee's
backshift or weekend operations on May 13, 15, 16, 19, 21, 22, 26, 28, 31,
June 1, 2, 5, and 7.
Results:
In the safety assessment/quality verification functional area, one example of a
violation was identified for failure to provide adequate instructions and/or
- procedures when implementing a revision to TS 3.11 regarding waste gas decay
- tank H2/0 2 limitations.
A similar North Anna problem occurred in March, 1991,
9107160227 910708
ADOCK 05000280
Q
e
2
and the resultant corrective actions could have prevented this violation.
(paragraph 3.a)
In the operations functional area a continuing strength was identified
regarding operator attention to detail and sensitivity to plant conditions and
reactivity management during the Unit 2 startup.
Good communi cati ans and
selfchecking techniques were frequently observed between operations personnel.
(paragraph 3.b)
In the engineering/technical support functional area, an additional example of
the violation for failure to provide adequate instructions and/or procedures
was identified.
This involved a failure to implement safety analysis
assumptions contributin~ to a Unit 1 reactor load increase above licensed power
limits. (paragraph 3.c)
In the maintenance/surveillance functional area, a weakness was identified
regarding previous corrective actions, associated with air lock deficiencies,
being ineffective in correcting material condition problems of the equipment.
(paragraph 3.d)
In the safety assessment/quality verification functional area a strength was
identified regarding the licensee making available a second means of level
indication for reduced inventory operations ahead of their commitment and prior
to entry into reduced inventory condition. This action demonstrated a positive
sensitivity to safety.
(paragraph 3.g)
In the safety assessment/quality verification functional area, a violation
associated with the seal head tank low level alarms was identified for failure
to promptly identify and correct conditions adverse to quality (paragraph 5.a).
...
,--------------------------~
- e
1.
Persons Contacted
Licensee Employees
REPORT DETAILS
R. Allen, Supervisor, Shift Operations
- W. Benthall, Supervisor, Licensing
- R. Bilyeu, Licensing Engineer
- R. Blount, Supervisor, Station Procedures
- D. Christian, Assistant Station Manager
J. Downs, Superinterident of Outage and Planning
D. Erickson, Superintendent of Health Physics
- R. Gwaltney, Superintendent of Maintenance
M. Kansler, Station Manager
T. Kendzia, Supervisor, Safety Engineering
- J. McCarthy, Superintendent of Operations
- A. Price, Assistant Station Manager
- H. Royal, Supervis*or, Nuclear Training
- E. Smith, Site Quality Assurance Manager
- T. Sowers, Superintendent of Engineering
NRG Personnel
- W. Holland; Senior Resident Inspector
- M. Branch, Senior Resident Inspector
S. Tingen, Resident Inspector
- J. York, Resident Inspector
- Attended exit interview.
e
Other licensee employees contacted included control room operators, s,h.ift
technical advisors, shift supervisors and other plant personnel.
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2.
Plant Status
Unit 1 began the reporting period in power operation.
The.unit operated
at or about 100% power for the duration of the in~pection period.
However, on June 6, 1991, reactor power was reduced to approximately 93%
when the unit experienced turbine iontrol problems.
This item is further
discussed in paragraph 3.c.
Unit 2 began the reporting period in refueling shutdown (day 45 of a
scheduled 67 day refueling/maintenance outage).
During this period the
.unit entered reduced inventory conditions for approximately four pays to
conduct maintenance activities on safety injection check valves.
This
item is further discussed in paragraph 3.g.
Also the unit completed
,**
,*
e
2
refueling/maintenance evolutions and Type.A containment testing. The* unit
exited cold shutdown conditions on May 31 and had reached hot shutdown
conditions when identified leakage greater than TS allowable limits were
identified. AUE was declared and the unit returned to cold shutdown to
correct the leakage problem. This issue is further discussed in paragraph
3.f. Corrective actions were completed and the unit commenced heatup from
cold shutdown on June 4.
The unit was taken critical on June 5 and
physics testing was conducted over the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The unit was
connected to the grid on June 7. However, approximately 25 minutes after
connection, an electrical problem in the switchyard occurred resulting in
opening of an electrical breaker in the yard.
This problem is further
discussed in paragraph 3.b. After the electrical problem was corrected,
the unit was reconnected to the grid on June 7 to continue startup testing
and was operating at approximately 30 percent power when the inspection
period ended.
3.
Operational Safety Verification {71707 & 42700)
a.
Daily Inspections
The inspectors conducted daily inspections in the following areas:
control room staffing, access, and operator behavior; operator
adherence to approved procedures, TS, and LCOs; examination of panels
containing instrumentation and other reactor protection system
ele~ents to determine that required channels are operable; and review
of control room operator logs, operating orders, plant deviation
reports, tagout logs, temporary modification logs, and tags on
components to verify compliance with approved procedures.
The
inspectors also routinely accompanied station management on plant
tours and observed the effectiveness of their influence on activities
being performed by plant personnel.
On May 24, during routine review of operator logs, the inspectors
noted that the following information was recorded with regards to
concentrations of oxygen and hydrogen in the waste gas holdup tanks.
On May 24, at 0025 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br />, routine sample results of the A WGDT
revealed that the oxygen and hydrogen concentrations exceeded the TS
limits.
The A WGDT oxygen concentration was 8.6%, and the hydrogen
concentration was 4.6%.
TS 3.11.A.1 states that the concentration of
oxygen in the waste gas holdup system shall be limited to 2% by
volume when the hydrogen concentration exceeds 4% by volume.
TS 3.11.A.1.a states that with the concentration of oxygen in the waste
gas holdup system greater that 2% by volume but less than or equal to
4% by volume, and the hydrogen concentration greater than 4% by
volume reduce the oxygen concentration to the required limits within
48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
TS 3.11.A.l.b states that with the concentration of oxygen
greater than 4% by volume immediately suspend all additions of waste
gases to the affected tank and reduce the concentration of oxygen to
less than or equal to 4% by volume.
3
A backup sample of a WGDT A on May 24, 1991, confirmed that the
oxygen and hydrogen concentration level exceeded the TS limits.
Operators suspended all additions of waste gases to A WGDT, made
preparations to release the tank in accordance with procedure
OP-23.2.3, Placing 1-GW-TK-lA On Bleed, dated February 8, 1990. Prior
to releasing the A WGDT, operators determined that OP-23.2.3 needed
to be revised and decided to wait until day shift to revise the
procedure.
The procedure was revised on day shift and at 0946 hours0.0109 days <br />0.263 hours <br />0.00156 weeks <br />3.59953e-4 months <br />,
operators initiated the release of the A WGDT.
The following day,
May 25, at 1448 hours0.0168 days <br />0.402 hours <br />0.00239 weeks <br />5.50964e-4 months <br /> the A WGDT oxygen and hydrogen concentration
levels were within the TS limitations.
The release of the tank was
then secured and the TS LCO exited.
The inspectors reviewed the licensee's actions and considered that
the actions did not meet the requirements of TS 3.11.A.1.b because
action was not taken irrnnediately to reduce the concentration of
oxygen in the A WGDT to less than 4% by volume.
It took
approximately 38 hours4.398148e-4 days <br />0.0106 hours <br />6.283069e-5 weeks <br />1.4459e-5 months <br /> to reduce the oxygen concentration to less
than 4% by conducting a long tank drain prior to actually reducing
the oxygen concentration with nitrogen.
Only several hours are
necessary to reduce the concentration, if the nitrogen addition is
conducted at the beginning of the evolution.
A primary contributor to this problem was a TS amendment effecting
this activity.
TS 3.11.A, Explosive Gas Mixture, was amended on
April 17, 1991.
This new amendment required ilTD'Tiediate action be
taken when WGDT oxygen and hydrogen concentrations exceeded 4% by .
volume.
The old TS 3 .11. A a 11 owed 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> to reduce the oxygen
concentration to less than 4% by volume.
The inspectors concluded
that the licensee did not develop an adequate plan to correctly
implement the requirements of TS 3.11.A.1.a and 3.11.A.l.b when the
TS 3 .11 amendment was approved.
As a result, procedures and
instructions were not in place to immediately reduce the A WGDT
hydrogen/oxygen concentrations on May 24.
10 CFR 50, Appendix B, Criterion V, requires that activities
affecting quality be prescribed by* documented instructions or
procedures of a type appropriate to the circumstances and shall be
accomplished in accordance with instructions, or procedures.
The
failure to provide adequate instructions and/or procedures when
implementing the revised TS 3.11 is identified as one example of a
Violation, 50-280,281/90-10-0l, Inadequate Implementatinn of a Waste
Gas Decay Tank TS.
North Anna had a similar problem in March 1991
where releasing the tank contents, instead of purging with nitrogen,
was used in an attempt to reduce the concentration.
During review of the waste gas problems.described above, the
inspectors noted that tank sampling was necessary as a compensatory
measure because the H2/02 monitors were not operable.
TS 3. 7-2.E
for the explosive gas monitoring instrument requires that the
equipment have an alarm/trip setpoint set to ensure that the limits
..
,
4
of TS 3.11.A.1 are not exceeded.
The actions for inoperable
monitoring instrumentation requires that a grab sample be taken at
least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and analyzed within the following 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
The inspectors observed that grab samples were being taken at
approximately 12-hour intervals. Even with this increased sample
frequency, though, on four occasions during the inspection period,
the samples were in the range that required entry into TS 3.11.A.1
LCOs.
Since the purpose of the grab samples was to compensate for .
inoperable instrumentation and to ensure that the TS 3.11 limits were
not exceeded, the inspectors questioned as to whether the licensee
had considered further increasing the sample frequency.
Discussions
with station management on this issue resulted in implementation of a
policy to review sampling frequency and increase the frequency based
on sample results.
b.
Weekly Inspections
The inspectors conducted weekly inspections in the following areas:
operability verification of selected ESF systems by valve alignment,
breaker positions, condition of equipment or component, and
operability of instrumentation and support items essential to system
actuation or performance.
Plant tours were conducted which included
observation of general plant/equipment conditions, fire protection
and preventative measures, control of activities in progress,
radiation protection controls, physical security controls, missile
hazards, and plant housekeeping conditions/cleanliness.
The
inspectors routinely noted the temperature of the AFW pump discharge
piping to ensure increases in temperature were being properly
monitored and evaluated by the licensee.
During this period, the licensee returned Unit 2 to power operation
after a refueling/maintenance outage that lasted over two months.
The inspectors monitored the performance of the operations department
during the restart and made the following observations:
New startup controlling procedures were used by the operators
during the unit startup.
These procedures appeared to provide
for good control of startup evolutions.
However, the procedure
for unit startup, 2-GOP-1.1, Unit Startup, RCS Heatup From
AMBIENT TO 195 F, revision 0, should have been clearer in
recognizing the pl ant entry conditions for restart after
correction of the valve leakage problem discussed in paragraph
3.f.
Similar to previous startups, operator attention to detail and
sensitivity to plant conditions and reactivity management
continued to be very good.
Good co111T1unications and self
checking techniques were frequently observed between operations
personnel and was considered to be a continuing strength.
5
On June 6, approximately 25 minutes after Unit 2 was connected to the
grid, a loss of electrical load was experienced.
The unit was
supplying approximately 80 megawatts of power at the time.
The loss
of load occurred when a crew working in the switchyard noticed that
one of the electrical disconnects in the electrical flowpath from
Unit 2 to the grid was arcing and appeared to be on fire.
The
supervisor of the crew notified the load dispatcher of the condition.
In accordance with normal policy, the dispatcher opened a breaker in
the switchyard to remove the load from the arcing disconnect. After
the load was disconnected, the arcing stopped.
The operators on Unit
2 responded to the loss of load and were able to stabilize the unit
and reduce reactor power from approximately 25 percent to less than 5
percent over the next hour.
Based on the excellent performance by
the operators, no reactor or turbine trip occurred. Several problems
were encountered during the transient including improper operation of
the A feed regulation bypass valve, and setpoint drifting of the A
All problems were corrected over the next 18
hours and the unit was again connected to the grid early on June 8,
1991.
c.
Biweekly Inspections
The inspectors conducted biweekly inspections in the following areas:
verification review and walkdown of safety-related tagouts in effect;
review of sampling program (e.g., primary and secondary coolant
samples, boric acid tank samples, plant liquid and gaseous samples};
observation of control room shift turnover; review of implementation
of the plant problem identification system; verification of selected
portions of containment isolation lineups; and verification that
notices to workers are posted as required by 10 CFR 19.
On June 6, 1991, Unit 1, while operating at 100 percent power,
turbine control problems occurred that resulted in an 80 MWE power
increase.
The operator noticed and logged the following and
immediately took manual control of the turbine:
All turbine governor valve went to 100% open
- Rods stepping out in auto
- Turbine load going to 880 MWE
Reactor high power alarm at 103%
- High steam line flow on two out of three channels
The turbine control problem was caused by a failure of the main speed
pickup card for the turbine governor control circuit.
The licensee
wrote station deviation S-91-0887 to document and evaluate the event.
The inspector witnessed portions of the licensee's response to the
transient and reviewed several of the control room recorder and alarm
printouts.
The inspector noted that the licensee was operating the
turbine with the governor valve position limiter set at 100 percent
turbine load which did not restrict governor valve movement.
The
turbine is oversized when compared to the 100 percent reactor power
d.
6
limit and two of the governor valves are not full open at 100 percent
reactor power.
Therefore, when all of the governor valves came full
open, reactor power exceeded the licensed limit for a brief period of
time.
The inspectors reviewed the safety analysis chapter of the UFSAR
(Chapter 14) to determine if there was any restriction on turbine
load limits.
Section 14.2.8, .Excessive Load Increase Incident,
stated that excessive loading by the operator or by system demand
would be prevented by the turbine load limiter.
The UFSAR further
indicated that reactor protection is provided by the high reactor
power and delta-T trip setpoints. * The inspectors reviewed the
turbine operating procedure 1-0P~2.2.1, dated January 2, 1990 and the
turbine inlet valve stroke test procedure 1-PT-29.1, dated January 6,
1990, for information on use of the turbine load limiter.
Both
station procedures instructed the operator to set the limiter at 100
percent.
With the turbine oversized with respect to full reactor
power, setting the limiter for 100 percent valve open does not
prevent exceeding the 100 percent licensed reactor power limits.
Thus, the load limiter requirements from Section 14.2.8 of the UFSAR
have not been incorporated into station procedures .
10 CFR 50, Appendix B, Criterion V, requires that activities
affecting quality be prescribed by documented instructions or
procedures of a type appropriate to the circumstances and shall be
accomplished in accordance with instructions, or procedures.
The
failure to provide adequate instructions and/or procedures to
implement the UFSAR operating requirements is identified as a second
example of Violation, 50-280, 281/90-10-01, Inadequate Turbine
Operating and Testing Procedures.
Other Inspection Activities
Inspections included areas in the Units 1 and 2 cable vaults, vital
battery rooms, steam safeguards areas, emergency switchgear rooms,
diesel generator rooms, control room, auxiliary building, cable
penetration areas, Unit 2 containment, low level intake structure,
and the safeguards valve pit and pump pit areas.
RCS leak rates were
reviewed to ensure that detected or suspected leakage from the system
was recorded, investigated, and evaluated; and that appropriate
actions were taken, if required.
The inspectors routinely
independently calculated RCS leak rates using the NRC Independent
Measurements Leak Rate Program (RCSLK9).
On a regular basis, RWPs
were reviewed, and specific work activities were monitored to assure
they were being conducted per the RWPs.
Selected radiation
protection instruments were periodically checked, and equipment
operability and calibration frequency were verified.
During a control room observation on May 13, 1991, the inspectors
noted that the Unit 1 CRO and SRO became involved with a problem
associated with the inside personnel airlock door.
Specifically, a
e
7
team of electricians who were exiting containment, reported that the
inside airlock door was jammed and would not close.
This*condition
resulted in the electricians being stuck in the airlock and not being
able to open the outside door because of containment integrity
interlocks and differential pressure.
The inspectors observed
operations response to this condition and noted that there was some
question as to what actions should be taken.
The Operations*
Superintendent's response to the situation which included calming the
team of electricians was considered good.
Discussions with the.
control room operators, though, revealed that many riperators had a
personal experience associated with being stuck in the airlock.
The inspectors reviewed a printout of DRs associated with the airloc.k
over the past 2 years and noted that there has been a continuing
problem with this equipment.
The airlock doors are required by TS 3.8 to be operable and closed for containment integrity.
Addition-
ally, the inspectors inspected the material condition of the Unit 2
inside airlock door which is identical to the Unit 1 door.
A combin-
ation of original design (i.e. single point of attachment and closure
mechanism) with the age and condition of the doors appears to have*.
contributed to the door failures and jamming.
Additiona.lly, it was
not clear .that the electricians operating the door had the training
. or experience to ensure proper operations.
The inspectors discussed the above observations and findings ~ith
plant management.
The station manager indicated that airlock door
operation was a continuing problem for both units and that actions
were planned.
The licensee sated that upgrading of the doors had
been evaluated and was at one time on the proposed plarit improvements
list.
However, priority of this ~pgrade has decreased to make way
- for more ~ressing items.
The station manager indicated that airlock
improvements will be reviewed in light of recent problems and that
short term actions, which may include using a tra:ined door operator
to operate the. door, will *be implemented.
Previous corrective
actions, associated with air lock deficiencies, have been ineffective
- . in correcting the material condition of the equipment and is identi-
fied as a weakness.
It should be noted, that establishing contain-
ment integrity for the heatup of Unit 2 from the current refueling
outage had to be delayed, due in part.to air lock door problems.
e.
Physical Security Program Inspections
In the course of monthly activities, the inspectors included a review
of the licensee's physical security program.
The performance of
various shifts of the security force was observed in the conduct of
daily activities to include: protected and vital areas access
controls; searching of personnel, packages, and vehicles; badge
issuance and retrieval; escorting of visitors; and patrols and
compensatory posts.
No discrepan'Cies were noted.
.*
f.
e
Licensee 10 CFR 50.72 Reports
On June 3, 1991, the licensee made a report in accordance with 10 CFR
50.72 regarding entrance into the station emergency plan.
At 1431
hours, Unit 2 declared a UE due to uncontrolled RCS leakage exceeding
TS 3.1.C.5 limits of 10 GPM.
The unit was in hot shutdown with RCS
temperature and pressure in the normal operating range (i.e. 547
degrees F and 2235 psig) at the time of the event. The leakage rate
was calculated to be approximately 16 GPM and was from the packing
area of the "C" RCS RTD manifold isolation valve 2-RC-95 and was
observed blowing into the containment.
The leakage was unisolable
from the
loop and the licensee commenced a plant
cooldown/depressurization at approximately 1432 as required by the
TS.
The UE was terminated at 0506 on June 3, after the unit reached
cold shutdown at 0454.
The RCS leakage first appeared as a 6 GPM
leak into the POTT through the packing leakoff line and the licensee
attempted to backseat the valve to stop the leakage.
The packing
blew out after several attempts to backseat the valve. Operati.ons
personnel, who had just climbed down from trying to backseat the
valve, were not hurt when the packing failed.
The resident
inspector was on-site monitoring startup evolutions when the event
- occurred and observed the licensee actions and followup.
The
reporting requirements of 10 CFR 50. 72 were met and the 1 icetisee
actions associated with taking the plant to a cold shutdown condition
were in accordance with the TS.
The Operations Manager's decision to
take the plant to cold shutdown was not delayed and action was
started within the first ten minutes after determining that the
leakage rate exceeded TS limits.
The valve repairs and failure determination is further discussed in
paragraph 4.d.
g.
Reduced Inventory Conditions - Unit 2
Unit 2 entered a reduced inventory condition on May 17, 1991 in order
to conduct maintenance activities on safety injection check valves.
This condition was exited .on May 21, 1991.
Prior to entry into this
condition, the inspectors conducted a review of the 1 icensee' s
responses and implemented actions with regards to the requirements of
Generic Letter 88-17, Loss of Decay Heat Removal.
No discrepancies
were noted during the review.
The specific items reviewed were:.
Generic Letter 88-17 - The inspectors reviewed the subject
letter including the licensee's response to the letter dated
January 6, with supplemental responses dated February 3,
September 29, October 31, 1989, October 5, and November 16,
1990 .
Administrative Controls - The inspectors discussed controls and
procedures in affect to control reduced inventory operation with
the Operations Superintendent as well as several senior reactor
operators and licensed operators.
Additionally, the inspectors
attended a reduced inventory planning.meeting on May 14, 1991,
.
. .
e
9
where controls, precautions and required equipment status were
reviewed.
Containment Closure Activity - The licensee's procedures require
that the status of the containment configuration be established
and verified prior to entering a reduced inventory condition.
In addition, the procedure for loss of RHR capability directs
containment closure action to be initiated and continued until
the RHR system is returned to service and core conditions are
verified normal. The inspectors verified that the licensee has
prepared procedures to reasonably assure that containment
closure wi 11 be achieved prior to the time at which core
uncovery could occur.
This was done by reviewing 2-0P-3.4,
Draining the Reactor Coolant System, dated March 28, 1991,
2-0P-lG, Refueling Containment Integrity and RCS Mid-Loop
Containment Closure Checklist, dated April 28, 1989, and
2-AP-27, Loss of Decay Heat Removal Capability, dated March 28,
1991.
Other than the containment personnel entry hatch and the
equipment hatch, no containment openings will exist.
During a
containment tour on May 15, 1991, the inspector verified that
there was little obstruction in the way of the equipment hatch
and that the containment closure crew should have little
difficulty in closing the hatch.
RCS Temperature - The inspectors verified that the controlling
procedure for draining the RCS, 2-0P-3.4 required at least two
operable incore temperature indicators prior to draining the RCS
to a reduced inventory condition.
The inspectors also verified
that the control room operators record the temperatures every
six hours in their log as required by periodic test 2-PT-36,
Instrument Surveillance.
In addition a supplemental check list,
Control Room Operator Reduced RCS Inventory Relief Checklist,
requires at least two operable core exit thermocouples (i.e. one
from each train).
RCS Level Indication - The licensee has installed one means of
level indication which provides continuous readout in the
control room.
This system is calibrated and provides a low
level alarm for both low level and loss of level.
In a letter
dated October 31, 1989, the licensee committed to install a
second means of RCS level indication prior to the end of the
current Unit 2 refueling outage.
The licensee had completed the
construction portion of this modification, and this instrumenta-
tion was available to operators during this reduced inventory
period and provided additional assurance to operators of the RCS
water level.
The licensee plans to validate this equipment
during this reduced inventory evolution and operators
interviewed by the inspector were aware of the current status.
During the May 14, 1991, planning meeting, the 1 icensee
indicated that during the initial drain-down to mi d-1 oop an
operator will be stationed inside the containment to visually
. *-; .
e
10
monitor the standpipe level.
Additionally, operations was
instructed to monitor the UT system and if differences between
the two level monitoring systems were noted, the draining
operation was to be stopped. The licensee's actions to make
available this second means of level indication ahead of their
commitment and prior to entry into reduced inventory condition
demonstrated a positive sensitivity to safety and was identified
as a strength.
RCS Perturbations - The inspectors verified that the licensee
has a procedure, OC-28, Assessment of Maintenance Activities for
Potential Loss of Reactor Coolant Inventory dated January 22,
1991, that allows for operations' assessment of work on systems
for potential loss of reactor coolant inventory during reduced
RCS inventory conditions.
RCS Inventory Addition - The inspectors verified that procedure
2-0P-3.4 required at least two available and operable means of
adding inventory to the RCS.
These are in addition to the RHR
system.
The procedure requires that in a reduced inventory
condition, one charging/safety injection pump and one LHSI pump
must be available with appropriate flowpaths to the core .
However, during the review of the licensee's procedure 2-0P-3.4
the inspector noted that the procedure did not specify a
preferred injection path to the RC hot leg as specified in the
licensee's respqnse to GL 88-17, dated January 6, 1989.
In that
response the licensee stated that,
11The flow path checklist
specifies that the hot leg injection flow path is preferred,
with cold leg injection available as an alternative."
The
inspector discussed with the 1 icensee a concern that the
controlling procedure (2-0P-3.4) did not specify the preferred
flow path.
The licensee indicated that the checklist referenced
in their response is 2-0C-6 which does specify the hot leg as
the preferred path.
This checklist is performed every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
by the control room operators. However, use of the checklist to
establish the preferred flow path in-lieu of the operating
procedure may not ensure that the pref erred fl ow path is
available as a prerequisite for the intended inventory
reduction.
The inspector was satisfied that the preferred flow.
path wi 11 be a 1 i gned for the majority of the reduced inventory
operations scheduled for May 17, 1991.
The licensee is
evaluating the need to reference the checklist or to specify the
preferred flow path in the operating procedure as well as in the
turnover checklist.
Loop Stop Valves - -The licensee utilizes RCS loop isolation
valves for loop isolation.
Nozzle dams are not used.
The
licensee uses an operational checklist (OC-28) to ensure that
the reactor vessel upper plenum is adequately vented when
maintenance activities require opening of a RCS cold leg
pressure boundary.
The licensee ensured that the reactor vessel
11
was adequately vented by maintaining A and Bloops unisolated
with the loop bypass valves open.
Contingency Plans to Repower Vital Busses - The vital and
emergency electrical distribution system receives offsite power
from the A and C reserve station service transformers during
normal plant operations.
The RHR pumps and the CCW pumps, the
latter providing cooling water to the RHR heat exchangers,
operate off stub busses attached to the 2J and 2H emergency
buss es.
The stub buss es are shed during degraded or under-
voltage situations, but can be reconnected to the emergency
buss es by closing a breaker.
The equipment for the two
additional*means for adding inventory to the RCS, charging pumps
and LHSI pumps are powered off the 2H and 2J emergency busses.
During normal operations, the number 2 EOG supplies power to the
2H emergency bus in case of a degraded or undervoltage
situation, and the number 3 EOG supplies power to the 2J bus.
During this period, the licensee had the A and C reserve station
service transformers powering the emergency busses, and 2 and 3
EOGs available as emergency power sources.
The inspector noted
during a review of planned testing that the licensee had
scheduled performance of the number 2 EOG survei 11 ance test
while in reduced inventory. This test which is a 6-hour test,
aligns the EOG to the el ectri cal grid for loading and grid
perturbations could affect the EOG availability.
- These
conditions have occurred in the past and are recognized in
industry and regulatory information.
The licensee subsequently
informed the inspector that they reevaluated testing of the EOG
during reduced inventory operation and elected to either test
the EOG prior to or after reduced inventory operations as long
as their required surveillance grace period was not exceeded.
During the above review the inspector noted that a number of
procedures were required to perform reduced inventory operations.
This is similar to other procedure problems that have been noted at
Surry and the licensee indicated that consolidating the reduced
inventory evolution will be considered during the procedure upgrade
program.
Within the areas inspected, no violations were identified.
4.
Maintenance Inspections {62703 & 42700)
During the reporting period, the inspectors reviewed maintenance
activities to assure compliance with the appropriate procedures.
The following maintenance activities were reviewed:
a.
Non-Regenerative Heat Exchanger 2-CH-E-2
12
The inspectors reviewed the licensee's repair efforts on plugging two
tubes and repairing one leaking plug.
The work was performed using
WO. 3800097306.
Corrective maintenance procedure MMP-C-CG-119,
Disassembly, Leak Detection, Repair, Reassembly of Non-Regenerative
Letdown Heat Exchanger-Safety Related, dated October 30, 1989, was
used for the repair.
The licensee used a mechanical plug rather than
the welded plug for the repair.
The use of the mechanical plug
decreased the radiation exposure. A problem was encountered when the
warehouse stock flexitalic gasket did not have the same dimensions as
those on the tubesheet.
Part of the old gasket had to be reused.
The inspectors will followup on this problem during the next
inspection period.
b.
Modification of 2-SW-MOV-205D
The inspectors monitored the licensee's activities associated with
the modification of 2-SW-MOV-205D HBC adapter and valve. * The
maintenance was accomplished in accordance with WO 380011483.
The WO
had an engineering transmittal attached that provided instructions
and specifications for performing this modification.
The inspectors
periodically visited the job site, and while at the job site reviewed
the WO, the post-maintenance test fa 11 ower, and the engineering
transmittal.
The purpose of this minor modification was to replace the screws that
secured the HBC adapter to the valve body with larger diameter cap
screws.
This was required because movement between the HBC adapter
and valve body was noted during operation of the valve.
More torque
could be applied to the larger cap screws to ensure that the HBC
adapter would remain secure to the valve body.
The modification
required removal of the Limitorque operator and HBC adapter, drilling
and tapping the valve body, enlarging the HBC adapter bolt holes,
reinstallation of the Limitorque operator and HBC adapter to the
valve body, and setting of the L imi torque operator switches and
stops. This same modification was performed on the 2-SW-MOV-205A, B,
and C valves and also on the 2-SW-MOV-204 A, B, C, and D valves.
The licensee considered the modification to be an equipment enhance-
ment and that the MOVs were operable in the as-found condition. This
was based on the MOVs satisfactorily passing their surveillance
tests, and that the previous condition, before the modification, did
not affect the valves ability to reposition to the open accident
position.
Unit 1 and 2 SW-MOV-204, and 205 valves and operators are
scheduled for replacement during the next refueling outages.
While monitoring the modification, the inspectors noted that the
contractors performing the work were not provided a SNSOC approved
procedure to accomplish the work, and that the WO was annotated that
a procedure was not required.
The inspectors reviewed VPAP-801,
Maintenance Program, Revision 1, Maintenance Program.
VPAP-801
provides guidelines that specify when procedures are required.
- -
13
Although a SNSOC approved procedure was not available the craft were
working per the instructions of an engineering transmittal.
The
inspectors questioned the purpose of the engineering transmittal.
The inspectors were informed that the engineering transmittal
provided written guidance from maintenance engineering to . craft
personne 1 for performing the modi fi ca ti on, and that normally
engineering transmittals are *not utilized as procedures.
The
inspectors discussed the use of engineering transmittals as
procedures with the Maintenance Superintendent. The Maintenance
Superintendent considered engineering transmittals to be documented
instructions and therefore an acceptable procedure.
The inspectors
did not consider engineering transmittals as documented instructions
because station administrative procedures did not address the use of
engineering transmittals as an alternative to a SNSOC approved
procedure.
With minor modification in process for 2-SW-MOV-205D, the inspectors
ques1;:ioned why the craft was not utilizing an EWR to perform the the
work, and why an EWR was not approved prior to the performance .of the
modification.
The inspectors were informed that in order to
expedite maintenance, an EWR is prepared in parallel with or after
the.maintenance is completed.
The system that contains the modified
components is not declared operable until SNSOC approves the EWR that
documents the modification.
The inspectors concluded that station administrative instructions
SUADM-ENG-01, Engineering Work Request, Revision 1, and SUADM-ENG~13,
DCP/EWR Implementation and Closeout, Revision O, 'did not clearly
address the process of issuing an EWR in parallel with or after
completion of the work and that SNSOC approval of the EWR was
required prior to declaring the .system operable. This was discussed
with the Superjntendent of Engineering who stated that administrative*
procedures that govern modifications are currently being revised, and
that these issues would be clarified by the revisions.
The
inspectors reviewed EWR 90-272, revision K, MOV Modifications Surry.
1/2, and verified that SNSOC approval was obtained prior to the time
the recirculation spray system was required to be operable.
c.
Repairs to Check Valve 2-SI-85
The inspectors reviewed the work package for the open/inspect/repair
of check valve 2-SI-85. This maintenance was performed in accordance
. with WO 3800088856 and procedure 2-MPT-0417-04, Inspectipn of SI
.Check Valves 2-SI-79, 2-SI-82, and 2-SI-85, dated March 5, 1991.
- Inspection of the valve internals revealed that valve seat and disc.
were worn.
The valve disc was replaced and the valve was
reassembled.
Replacement of the valve seat would have required
installation of a new check valve which was a significant increase in
the job scope and therefore not performed.
Other diffjculties
encountered during the maintenance was high, radiation dose rates and
water in the maintenance area.
Water in the maintenance area
e
14
prevented the mechanics from obtaining a satisfactory blue check.
The inspectors also reviewed the post-maintenance test requirements.
No discrepancies were noted.
On May 28, check valve 2-SI-85 was
satisfactorily seat leak checked.
The testing is discussed in
paragraph 5.b.
d.
Repairs to Valve 2-RC-95
As discussed in section 3.f of this report, attempts were made to
back seat 2-RC-95 to stop a valve packing leak. Subsequently, the
packing blew out resulting in entry into the emergency plan and the
declaration of a UE.
The µnit had to be taken to cold shutdown to
depressurize the leak for fepairs.
Even after reducing the pressure
to 15 psig the leakage was still approximately 15 gpm.
The licensee
was considering the use of a freeze seal to isolate the valve for
repairs.
The other alternative was to go into reduced inventory
since the valve was not isolable from the RCS loop.
In order for the
successful application of a freeze seal the licensee's procedure
required the flow rate in the area to be decreased *to less than 5
gpm.
To accomplish this,* the valve stem was turned in the shut
posit ion to reduced 1 eakage and system pressure was reduced to 15
psig.
After safety evaluation 91-146 was reviewed and approved by
the SNSOC, the freeze seal was accomplished by procedure
MMP-C-FS-260, dated April 24, 1991.
The inspectors reviewed the
freeze seal procedure and the safety evaluation.
Conments on the
freeze seal procedure in thi area of operations involvement with the
authorization to melt the seal and conments associated with the
1 i censee' s oversight of the freeze seal contractor were given to
plant management.
The freeze seal was installed and no leakage was noted when valve
2-RC-95 was disassembled.
Inspection of valve 2-RC-95 revealed that
the valve stem had separated from the disc. The licensee determined
that the valve is no longer needed for plant operations and a plant
modification was made that removed the internals from the valve and
blanked the bonnet.
The licensee determined that the valve stem and
disc were separated (unscrewed) when initial back seating operations
were performed to stop the valve packing leak.
The valve yoke
bushing prevented the stem from being ejected from the .valve.
The
licensee plans to have a failure analysis performed on the valve disc
and stem.
The Operations Department issued a shift order to establish the
following guidelines associated with valve operation:
The guidelines
were:
Do not use a valve wrench on any safety related valve.
If RCS leakage is identified, do not backseat the valve without
concurrence frol)1 both the Operation Manager on ca 11 and
engineering.
- . *
15
Review of the failure analysis will be performed after the results
are received by the licensee.
Within the areas inspected, no violations were identified.
5.
Surveillance Inspections (61726 & 42700)
During the reporting period, the inspectors reviewed various surveillance
activities to assure compliance with the appropriate procedures as
follows:
Test prerequisites were met.
Tests were performed in accordance with approved procedures.
Test' procedures appeared to perform their intended function.
Adequate coordination existed among personnel involved in the test~
Test data was properly collected and recorded.
The following surveillances were either reviewed or observed:
a.
LHSI and Outside RS Testing
During surveillance testing on the Unit 2 LHSI pumps, 2-SI-P-lA and
2-SI-P-lB, and Unit 1 outside RS pump 1-RS-P-2A, the inspectors
noted, during review of the operator logs, that seal head tank low
level annunciators actuated.
The inspectors monitored the licensee's
corrective actions in response to the seal head tank low level
alarms.
The inspectors reviewed the seal designs and noted that each of the
LHSI and outside RS pumps contain an inboard and outboard seal.
The
purpose of the seals are to provide a pressure boundary so
radioactive fluid is not released into the safeguards building when
the pumps take a suction from the containment sump during accident
conditions.
The inboard seal cooling water is supplied from the
discharge of the pump and the outboard seal is cooled by the action
of a pumping ring and cooler unit.
The cooler unit (one for each
pump) is a closed loop filled with water.
The cooler unit contains a
seal head tank with high and low level switches and a cooling coil.
During pump operation, the pumping ring circulates water from the
area between the inboard and outboard seals through the cooling coil
and back to the area between the seals.
The seal head tank level
switch annunciator alarms in the control room.
Maintenance performed on the LHSI pumps' seal cooler units during the
refueling outage required that the systems be drained.
On April 20,
-
16
maintenance on the Unit 2 A LHSI pump seal cooler unit was completed.
The seal cooler unit was filled with water and the pump was
satisfactorily tested in accordance with 2-PT-18.1, LHSI Test and
Flushing of Sensitized Stainless Steel Piping, dated October 25,
1991.
On May 8, the Unit 2 A LHSI pump was again tested in
accordance with 2-PT-18.1.
When the pump was initially started, the
seal head tank annunciator alarmed and the pump was secured.
The
seal head tank was filled in accordance with the procedure and
operators restarted the pump.
The seal head tank annunciator again
alarmed and pump was secured.
WO 3800111182 was initiated to
troubleshoot the seal head tank low level switch.
The switch was
inspected but no problems were identified.
On the following day, the
seal head tank was refilled.
The Unit 2 A LHSI pump was started and
operated without the seal head tank low level annuciator alarming.
On May 21, the Unit 2 A LHSI pump was operated several times to
support reactor fill evolutions.
On one occasion the seal head tank
low level annuciator alarmed for several seconds and cleared.
On May
22, during the first two start attempts of A LHSI pump, the seal head
tank low level annunciator alarmed and the pump was secured. The seal
head tank was refilled in accordance with procedure and the pump was
restarted and operated without the seal head tank level annunciator
alarming.
The inspector noted that no DRs were initiated for the
above annunciated conditions.
On May 23, the Unit 2 B LHSI pump was started and secured because its
seal head tank annunciator alarmed.
In this case, however, a DR
{S-91-0779) was initiated.
Troubleshooting identified that air was
present in the pump's seal cooling system.
When the the LHSI pumps
were started the air in the cooling system would compress and level
in the seal head tank would decrease.
The system was designed to be
operated full of water.
The air was introduced when the system was
opened for maintenance during the refueling outage.
The system's
configuration is such that it is extremely difficult to vent the air
out while filling the system.
The Unit 2 LHSI pumps seal cooling
systems were vented and the pumps operated without the low level seal
head tank annunciator alarming.
The licensee considers that most if
not all of the air is out of the system and that the Unit 2 LHSI
pumps were operational.
On June 4, during the performance of Unit 1 surveillance test
1-PT-17.3, Containment Outside Recirculation Spray Pump, dated
February 1990, the seal head tank low level annunciator alarmed when
the containment outside RS pump 1-RS-P-2A was started.
The pump was
secured and the seal head tank filled in accordance with procedure.
The pump was restarted and operated without the seal head tank low
level annunciator alarming.
The pump was considered fully operable.
A DR was not initiated for this abnormal condition.
The inspectors
questioned why a DR was not initiated and if there was air in the
seal cooling system.
17
As a result of the inspectors concern with regard to seal head tank
operation, discussions were held on June 6 with the licensee.
The
inspectors were informed that the seal cooling systems for the Unit 2
LHSI and Unit 1 containment outside RS pumps were similar in
configuration and that air in the. system was the probable cause of
the June 4 seal head tank low level alarm that occurred on pump
1-RS-P-2A .. The inspectors were a 1 so informed that in February and
August of 1990 the seal head tank low level alarm annunciated on the
same pump.
In August 1990, DR Sl-90-1104 was initiated as a result
of the seal head tank low level annunciator alarming after the pump
was started.
The inspectors reviewed the corrective action assigned
to the DR.
The corrective action involved refilling the seal tank
when the alarm occurred and did not require any actions to
investigate the cause of the alarm.
A DR was not initiated for the
February 1990 alarm.
T~e licensee stated that pump 1-RS-P-2A was considered operable with
air in the seal cooling system because there was an adequate volume
of water in the seal cooling system to provide cooling to the pump
outboard seals.
The inspectors questioned what operators would do
during an accident when the outside containment RS pumps were started
and the seal head tank low level annuciator alarmed.
The inspectors
were informed that there was no specific guidance in this area and
the shift supervisor would have to make a judgement call on securing
the pump or continuing to operate it in the alarm condition.
The
inspectors consider that annunciation of the seal head tank low level
alarms during an accident would add unnecessary work and confusion
for the operators during a critical time.
The inspectors consider that the seal head tank low level annunciator
alarms on the Unit 2 LHSI pumps and the Unit 1 containment outside
recirculation pump 1-RS-P-2A were conditions adverse to quality that
were not promptly identified nor was adequate corrective action
initiated.
During the Unit 2 refueling outage the A LHSI seal head
tank annuciator alarmed numerous times.
DRs were not initiated to
document these conditions.
Also, seal head tank low level alarms
have occurred on pump 1-RS-P-2A and DRs were not always initiated to
document thes~.conditions.
When a DR was issued to document a low
level alarm on pump 1-RS-P-2A, the corrective action was inadequate
to prevent reoccurrence.
Failure to promptly identify or correct the conditions adverse to
quality associated with the seal head tank low level alarms is
identified as a violation of 10 CFR 50, Appendix B, Criterion XVI
50-280, 281/91-14-02, Fai 1 ure to Identify and Correct Conditions
Adverse to Quality.
b.
Event V Pressure Isolation Valve Seat Leak Testing
TS 3.1.c.7a and TS Table 4.1-2A, item 18 specifies test frequency and
seat leak rate limits for Event V pressure isolation valves SI-79,
18
SI-241, SI-82, SI-242, SI-85, and SI-243.
On May 28, the inspectors
monitored portions of the seat leak testing accom~lished on Unit 2
check valves 2-SI-79, 2-SI-82, and 2-SI-85.
The inspectors also
reviewed the completed copy of 2-PT-18.11, SI Cold Leg Check Valve
Leakage-Primary Coolant System Pressure Isolation Valves, dated June
5, 1990. Results of this review indicated that individual leak rates
in lieu of combined leakage rates were obtained, leakage rates
obtained at lower than normal operating pressure were normalized,
and all procedure calculations were correct.
No discrepancies were
noted.
c.
Control Rod Drop Testing
On June 5, 1991, the inspectors witnessed portions of 2-PT-7.1, Cold
Rod Drops, dated May 28, 1991.
The purpose of this test was to
ensure rod freedom after the cooldown of Unit 2 for repairs to valve
2-RC-95.
The licensee elected to perform this test during hot
shutdown conditions and a PAR was issued on May 30, 1991, to allow
this.
Additionally, the safety evaluation to allow continued
operations during cycle 10 with rod M-12 stuck was modified to
recognize that rod freedom testing could be performed either hot or
cold but prior to criticality.
Equipment performed as expected and
no discrepancies were noted.
Within the areas inspected, one violation was identified.
6.
Licensee Event Report Review
(92700}
The inspector reviewed the LER's listed below to ascertain whether NRC
reporting requirements were being met and to evaluate initial adequacy of
the corrective actions.
The inspector's review also included followup on
implementation of corrective action and review of licensee documentation
that all required corrective actions were complete.
(Closed}
LER 280/91-04, Two of Three Emergency Diesel Generators
Inoperable.* The issue involved a tagout of one of the two redundant fuel
oil transfer pumps for an EDG which was required to be fully operable
based on plant conditions at the time.
This event was addressed in
Inspection Report 280,281/91-10 and an NCV was identified in that report.
The inspector reviewed licensee actions at that time and also reviewed
additional corrective actions addressed in this report. Licensee correc-
tive actions appear to be adequate.
(Closed} LER 280/91-06, Unit 1 Auxiliary Feedwater System Cross-Connect
Capability From Unit 2 Inoperable In Excess of Technical Specifications
Allowed Time Due to a Drawing Error.
The issue involved an incorrect
configuration condition for underground suction line for a safety-related
- AFW pump.
This event was addressed in Inspection Report 280,281/91-10 and
an NCV was identified in that report.
The inspectors reviewed the
licensee actions at the time of the event and also reviewed the corrective
,,
19
actions addressed in this report.
Licensee corrective actions appear to
- ..
be adequate.
Within the areas inspected, no violations were identified.
7.
Evaluation of Licensee Self-Assessment Capability (40500)
During this inspection period, the NRR project manager for Surry conducted
a review of the licensee's program for the screening of plant ~hanges, and
proposed tests and experiments* to determine if a safety evaluation is
required and the process for preparing, reviewing, and approving safety
evaluations.
This review focused on the testing of main steam safety
valves accomplished during the past 12 months.
In October, 1990, testing of the Unit 1 main steam safety valves lift
setpoints was performed using the Furmanite Trevitest method.
Similar
testing of the Unit 2 main steam safety valves at approximately 70 percent
of rated power was conducted in March, 1991.
The licensee has previously
performed a 10 CFR 50.59 safety evaluation dated October 2, 1990, which
concluded 'that testing of the above cited safety valves at power did not
present an unreviewed safety question. A review of the safety e'valuation
showed that it was prepared using the then current. Surry Power Station
Procedure SUADM-LR-12 which has subsequently been superseded by*Station
Administrative Procedure No. VPAP-3001 dated April 1, :*1991.
The safety
evaluation referenced the steamline break analysis in Section 14.3.2 of
'the Station UFSAR.
Section 14.3.2 of the UFSAR indicated that if a safety
valve were to inadvertently stick open, the most severe transient would
occur at zero load without unacceptable consequences.
The analysis.
assumed, among other things, a steam release rate of 247 pounds per hour
which is equal to or greater than the relief capacity of any single dump
or main steam safety valve and the results indicated compliance with the
design basis as defined in the UFSAR.
The inspection concluded that the
analysis was procedurally correct and supported the lic.ensee's findings
that testing of the main steam line safety valves at power would not
constitute an unreviewed safety question.
Also, the inspector concluded
that the licensee's analysis methodology is in compliance with the
licensing basis as described in the UFSAR.
Within the areas inspecte~, no violations were identified.
8. *Exit'Interview
The inspection scope and results were sununarized on June 11, 1991 with
those individuals identified by an asterisk in paragraph 1.
The following
sununary of inspecti_on activity was discussed by the inspectors during .this
exit.
Item Number
VIO 50-280,281/91-14-01
Description and Reference
Failure .to provide adeq~ate procedures
and/or instructions with two examples.
.,
.
'
20
a. Inadequate implementation of a
waste gas decay tank TS.
(paragraph 3.a)
b. Inadequate turbine operating and
testing procedures.
(paragraph 3.c)
VIO 50-280,281/91-14-02
Failure to identify and correct
conditions adverse to quality. (paragraph
5.a)
Licensee management was informed of the strengths and weaknesses
identified in paragraph 3 and of the items closed in paragraph 6.
The licensee acknowledged the inspection conclusions with no dissenting
comments.
The licensee did not identify as proprietary any of the
materials provided to or reviewed by the inspectors during this
inspection.
9.
Index of Acronyms and Initialisms
CFR
CRO
DR
EOG
F
GL
GPM
LER
LCO
LHSI
MWE
NRC
POTT .
RC
RS
COMPONENT COOLING WATER
CODE OF FEDERAL REGULATIONS
CONTROL ROOM OPERATOR
DEVIATION REPORT
ENGINEERED SAFETY FEATURE
ENGINEERING WORK REQUEST
FAHRENHEIT
GENERIC LETTER
GALLONS PER MINUTE
LICENSEE EVENT REPORT
LIMITING CONDITIONS OF OPERATION
LOW HEAD SAFETY INJECTION
MOTOR OPERATED VALVE
MEGAWATT ELECTRICAL
NON-CITED VIOLATION
NOTICE OF UNUSUAL EVENT
NUCLEAR REGULATORY COMMISSION
NUCLEAR REACTOR REGULATION
PROCEDURE ACTION REQUEST
PRIMARY DRAIN TRANSFER TANK
POUNDS PER SQUARE INCH
POWER OPERATED RELIEF VALVE
RECIRCULATION SPRAY
,I
21
RESISTANCE TEMPERATURE DETECTOR
RADIATION WORK PERMIT
SENIOR REACTOR OPERATOR
SAFETY INJECTION
SNSOC
STATION NUCLEAR AND SAFETY OPERATING COMMITTEE
TS
TECHNICAL SPECIFICATIONS
UPDATED FINAL SAFETY ANALYSIS REPORT
UNUSUAL EVENT
ULTRASONIC TEST
VPAP
VIRGINIA POWER ADMINISTRATIVE PROCEDURES
WGDT
WASTE GAS DECAY TANK
WORK ORDER