ML18152A232
| ML18152A232 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 06/26/1990 |
| From: | Fredrickson P, Holland W, Tingen S, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A233 | List: |
| References | |
| 50-280-90-20, 50-281-90-20, NUDOCS 9007170339 | |
| Download: ML18152A232 (18) | |
See also: IR 05000280/1990020
Text
Report Nos.:
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
50-280/90-20 and 50-281/90-20
Licensee:
Virginia Electric and Power Company
5000 Dominion Boulevard
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50-281
Facility Name:
Surry 1 and 2
License Nos.:
, 1990
Inspector
r\\-;3-;z~:z
S. G. Tingen, Resident Inspector
f"1..
Approved by: () I ~£~J,,_*
P. E. Fredrickson, Section Chief
Division of Reactor Projects
SUMMARY
Scope:
This routine resident inspection was conducted on site in the areas of plant
operations, plant maintenance, and plant surveillance reviews.
Backshift or
weekend tours were conducted on May 6, 12, 20, 25, 26, 31, June 1, and 2.
Results:
During this inspection period, one violation was identified for failure to take
timely corrective action for oil leakage from the lower bearing oil reservoir
drain plug for the outside recirculation spray pump 2-RS-P-2A motor (paragraph
3.d).
In the area of plant operations, the operations crews performance during the
reactor trips on May 22 and 31 was good [paragraphs 3.f.(3) and 3.f.(4)J.
Also, restarts of Unit 2 on May 26 and June 2, and the restart of Unit 1 on
June 2 was improved over past startups. Procedure adherence was good *
Attention to detail and deliberate conservative actions were noted with no
operator errors being observed.
However, several operator distractions,
including rod control and indication problems, and a nuisance annunciator alarm
(SI VALVES OUT OF POSITION) indicated that additional attention was warranted
to correct these problems (paragraph 3.a).
9001.:.2~.
050002:::(1
F'DC
Report Nos.:
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
50-280/90-20 and 50-281/90-20
Licensee:
Virginia Electric and Power Company
5000 Dominion Boulevard
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50-281
Facility Name:
Surry 1 and 2
License Nos.:
Approved by:
Scope:
1990
nt nspector
1.-1,, ,.-
/ 2..--.
S. G. Tingen, Resident Inspector
("1..
l)(~{,~J_:__
P. E. Fredrickson, Section Chief
Division of Reactor Projects
SUMMARY
This routine resident inspection was conducted on site in the areas of plant
operations, plant maintenance, and plant surveillance reviews.
Backshift or
weekend tours were conducted on May 6, 12, 20, 25, 26~ 31, June 1, and 2.
Results:
During this inspection period, one violation was identified for failure to take
timely corrective action for oil leakage from the lower bearing oil reservoir
drain plug for the outside recirculation spray pump 2-RS-P-2A motor (paragraph
3.d).
In the area of plant operations, the operations crews performance during the
reactor trips on May 22 and 31 was good [paragraphs 3.f.(3) and 3.f.(4)J.
Also, restarts of Unit 2 on May 26 and June 2, and the restart of U~it 1 on
June 2 was improved over past startups.
Procedure adherence was good .
Attention to detail and deliberate conservative actions were noted with no
operator errors being observed.
However, several operator distractions,
including rod control and indication problems, and a nuisance annunciator alarm
(SI VALVES OUT OF POSITION) indicated that additional attention was warranted
to correct these problems (paragraph 3.a).
2
In the area of maintenance, weaknesses were identified that involved
maintenance department personnel not following the requirements of recently
implemented station administrative procedures.
Examples of this were craftsman
failing to sign completed procedural steps prior to performing subsequent
steps, and cognizant supervision not reviewing completed work packages prior to
declaring the affected equipment operable. This problem resulted in identifi-
cation of an NCV for failure to follow administrative procedure in the perform-
ance of maintenance activities. Maintenance management was responsive to this
concern and implemented corrective actions to address the problem (paragraph
4.a).
In the area of safety assessment/quality verification, management restart
assessments were conducted in addition to the required post trip reviews prior
to each unit restart. These reviews provided an indication of the continuation
of management involvement and control in the assurance of quality which had
been noted during past unit startups (paragraph 3.a) .
1.
Persons Contacted
Licensee Employees
REPORT DETAILS
- W. Benthall, Supervisor, Licensing
- R. Bilyeu, Licensing Engineer
D. Christian, Assistant Station Manager
J. Downs, Superintendent of Outage and Planning
D. Erickson, Superintendent of Health Physics
- E. Grecheck, Manager, Nuclear Engineering
- W. Gross, Supervisor, Shift Operations
- R. Gwaltney, Superintendent of Maintenance
- M. Kansler, Station Manager
T. Kendzia, Supervisor, Safety Engineering
J. McCarthy, Superintendent of Operations
- T. 0
1 Connor, Corporate Nuclear Safety
- A. Price, Assistant Station Manager
- E. Smith, Site Quality Assurance Manager
- T. Sowers, Superintendent of Engineering
- G. Thompson, Supervisor, Maintenance Engineering
- Attended exit interview.
Other licensee employees contacted included control room operators, shift
technical advisors, shift supervisors and other plant personnel.
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2.
Plant Status
Unit 1 began the reporting period at power.
The unit operated at power
until May 22, when the unit experienced an automatic reactor trip from
100% power.
The trip is further discussed in paragraph 3.f.(3). After
repairs were completed, the unit was returned to critical operation on
June 2, and was operating at 54% power when the inspection period ended.
Unit 2 began the reporting period at power.
The unit operated at power
until May 22, when the unit was manually tripped from 100% power.
The
trip is further discussed in paragraph 3.f.(3). After repairs were
completed, the unit was taken critical and resumed power operation on
May 26, 1990.
The unit operated at power until May 31, when the unit was
manually tripped from 100% power.
The trip is discussed in paragraph
3.f.(4). After repairs were completed, the unit was returned to critical
operation on June 2, and was operating at 2% power when the inspection
period ended.
2
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
elements to determine that required channels are operable; and review
of control room operator logs, operating orders, plant deviation
reports, tagout logs, jumper logs, a~d tags on components to verify
compliance with approved procedures.
The inspectors also routinely
accompany station management on plant tours and observe the
effectiveness of their influence on activities being performed by
plant personnel.
On May 25, 1990, the inspectors commenced 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> monitoring coverage
of Unit 2 startup. Unit 2 had experienced a reactor trip from full
power on May 22.
The Unit 2 reactor was taken critical at 1216 hours0.0141 days <br />0.338 hours <br />0.00201 weeks <br />4.62688e-4 months <br />
on May 26, and was operating in automatic feedwater control at
approximately 30% power at 1758 hours0.0203 days <br />0.488 hours <br />0.00291 weeks <br />6.68919e-4 months <br /> on the same day.
During the startup, the inspectors monitored the operators'
performance of selected portions of the following procedures:
2-0P-1.4, Unit Startup Operation - HSD To 2% Power,
dated
January 27, 1989
2-0P-58.2.1, Rod Control - Withdrawal Of The Shutdown Banks,
dated January 27, 1989
2-0P-lC, Estimated Rod Bank Position, dated June 22, 1989
2-0P-58.2.2, Rod Control System - Withdrawal Of The Control
Banks, dated October 19, 1989
2-0P-2.1.1,Increasing Power From 2%. To 100%, dated September 22,
1989
2-0P-2.2.1, Turbine Generator Startup To 20%, dated January 2,
1990
The following observations were noted by the inspectors during the
performance of the preceding procedures:
Several of the procedures reviewed had been revised since the
last Unit 2 startup in September, 1989, but they had not been
upgraded in accordance with the TPUP.
These procedures were
generally better organized and fewer were required to accomplish
the unit startup; however, some minor procedural changes were
required prior to procedure performance.
3
During the withdrawal of the control banks, operators frequently
stopped the withdrawal sequence to allow for instrument
technicians to adjust the !RPI.
This action was accomplished
whenever any !RP indicator varied or was anticipated to vary
from the group demand step counter by more than plus or minus 12
steps. Although this action did not affect operator performance
during procedural evolutions, it did result in the operations
crew being distracted from the startup evolution when IRPis were
being adjusted.
Adherence to procedures by operators was good.
On June 1, 1990, the inspectors commenced 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> monitoring coverage
of Unit 1 startup.
Unit 1 had experienced a reictor trip from full
power on May 22.
The Unit 1 reactor was taken critical at 0645 hours0.00747 days <br />0.179 hours <br />0.00107 weeks <br />2.454225e-4 months <br />
on June 2, and was operating in automatic feedwater control at
approximately 30% power at 1615 hours0.0187 days <br />0.449 hours <br />0.00267 weeks <br />6.145075e-4 months <br /> on the same day.
During the
startup, the inspectors noted startup procedures were revised to
correct problems identified during the previous Unit 2 startup on May
26, and that the startup was delayed on several occasions because of
rod control system urgent failure alarms.
The first rod control
system urgent failure alarm was caused by a blown fuse in the power
supply cabinet.
The fuse was replaced and the alarm cleared.
The
rod control urgent failure alarm annunciated again when bank C
reached 225 steps and also subsequently when repositioning the bank
selector switch from bank C to bank B.
After receipt of the alarm,
the alarm was acknowledged and would clear.
The alarm was attributed
to a faulty card in the rod control logic circuit. The licensee
determined that the rod control system was operable with this
condition and elected to repair the faulty card at a later date.
On June 2, 1990, the inspectors monitored the Unit 2 startup.
Unit 2
had experienced a reactor trip from full power on May 31.
The Unit 2
reactor was taken critical at 2154 hours0.0249 days <br />0.598 hours <br />0.00356 weeks <br />8.19597e-4 months <br />.
During the startup the
inspectors noted that numerous !RPI adjustments were required to
maintain IRPI plus or minus 12 steps within the group step counter.
Also during the startup, the SI valves out-of-position annuciator
alarmed and cleared several times.
Each time the SI valves
out-of-position annuciator would alarm, the operators would verify
that the SI valves were in their proper positions. It was concluded
by the 6perators that the problem was a fault in the alarm circuit
and not an SI valve out-of-position condition.
A deviation report
was submitted which documented the abnormal condition.
In summary, the performance of the operations crews during the
restarts of Unit 2 on May 26 and June 2 and the restart of Unit 1 on
June 2 was improved over past startups.
Procedure adherence was
good.
Attention to detail and deliberate conservative actions were
noted with no operator errors being observed.
However, several
operator distractions, including rod control and indication problems,
and a nuisance annunciator alarm (SI VALVES OUT OF POSITION)
4
indicated that additional attention was warranted to correct these
problems.
During this inspection period, the inspectors also noted that
management restart assessments were conducted in addition to the
required post-trip reviews prior to each unit restart. The
inspectors attended the restart assessment meetings which were held
prior to each unit
1s restart, and also reviewed the completed
assessment meeting minutes.
The meetings focused on corrective
actions for the unit trip causes as well as additional work that
could only be accomplished during a untt shutdown.
These reviews
provided an indication of the continuation of management involvement
and control in the assurance of quality which had been noted during
past unit startups.
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, plant
housekeeping conditions/cleanliness, and missile hazards.
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.
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.
d.
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, independent spent fuel storage facility, low level
intake structure, and the safeguards valve pit and pump pit areas.
RCS leak rates were reviewed to ensure that detected or suspected
leakage from the system was recorded, investigated, and evaluated;
and that appropriate actions were taken, if required.
The inspectors
' J
5
routinely and 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.
On May 16, while performing maintenance to correct oil leakage from
the lower bearing oil drain plug for the outside recirculation spray
pump 2-RS-P-2A motor,
the licensee discovered that the plug had
failed.
A modified oil drain assembly was installed in place of the
failed drain plug and the pump was returned to an operable condition.
Inspection Report 280,281/90-19 discussed the oil leakage from this
specific motor drain plug and identified it as an item that would be
monitored by the inspectors.
The sequence of events leading to the
discovery of the failed drain plug was as follows:
On April 21, during a tour of the Unit 2 safeguards building,
the inspectors discovered that oil for the motor lower bearing
oil sightglass on the outside recirculation spray pump 2-RS-P-2A
was not in the visible range.
This condition was brought to the
attention of the licensee. Eighteen ounces of oil had to be
added to the 64 ounce reservoir to bring level within specifica-
tion. After adding the oil, the licensee evaluated the
condition and determined that the pump was operable with no
visible oil level in the motor's lower bearing sightglass.
On April 23, the system engineer for the recirculation spray
system was contacted. A discussion on pump operability was
inconclusive with regards as to whether the pump could perform
as designed for an extended period of time following a design
base LOCA with the known oil leakage condition.
The system
engineer responded that this issue would be investigated.
On May 12, during a tour of the Unit 2 safeguards building, the
inspectors noted that a five gallon plastic container had been
installed to collect the oil leaking from the lower bearing oil
drain plug for pump 2-RS-P-2A motor.
There was oil on the pump
base plate and on the floor beneath the pump.
The inspectors
also noted that oil was also leaking from the upper bearing oil
drain plug for pump 2-RS-P-2A motor.
Oil levels in the upper
and lower bearing sightglasses for pump 2-RS-P-2A motor were in
the visible range.
On May 14, the inspectors reviewed pump 2-RS-P-2A work order
history in order to detennine how much oil was being added to
maintain oil levels in the upper and lower bearing sightglasses.
Results of this review were as follows:
6
DATE
OUNCES OF OIL ADDED TO
OUNCES OF OIL ADDED TO
LOWER BEARING RESERVOIR
UPPER BEARING RESERVOIR
3/25/90
16
16
4/21/90
18
0
4/28/90
8
0
5/5/90
6
32
Based on these leak rates, the inspectors were concerned that if
a design bases LOCA were to occur, pump 2-RS-P-2A could fail
during an extended time of operation due to loss of lubrication
to the motor lower bearing reservoir.
On May 15, the inspectors questioned the operations
superintendent and the superintendent of engineering with
regards to oil leakage from the lower bearing reservoir drain
plug for pump 2-RS-P-2A motor.
The discussion focused on a loss
of lubrication to the lower bearing during extended operation *
following a LOCA.
The operations superintendent stated that
during the extended period following a LOCA, pump 2-RS-P-2A
would be started and secured as required to maintain water
inventory temperature.
However, engineering stated that
radiation levels in the pump motor vicinity could prevent
refilling of the lower oil reservoir during post LOCA
conditions.
On May 16, engineering obtained records of pump 2-RS-P-2A
motor lower bearing reservoir oil addition.
However, the
records did not agree with the inspectors' evaluation of oil
addition. After further investigation, it was concluded that
pump 2-RS-P-2A motor lower bearing drain plug leakage to be
approximately one ounce a day.
The licensee contacted the pump
vendor and was informed that as long as the oil level was
visible in the sightglass there was an adequate amount of oil
available in the reservoir to lubricate the lower bearing.
The
vendor also stated that the motor lower bearing 64-ounce
reservoir required approximately 32 ounces of oil to establish a
minimum visible sightglass level.
The licensee concluded that
if the lower bearing sightglass was filled to the maximum fill
line, then approximately 32 ounces of oil could leak from the
lower drain plug before oil level would decrease below the
visible range on the sightglass. This condition would allow for
a one ounce per day leak rate with enough oil in the motor lower
bearing reservoir to run the pump for 32 days.
On May 16, the
licensee filled pump 2-RS-P-2A motor lower bearing reservoir to
the maximum sightglass fill line and planned to maintain the oil
level at the maximum fill line until the drain plug oil leak
could be repaired.
7
On May 18, the licensee performed EWR 85-668E, Predictive
Analysis Oil Schedule/Surry/Units 1 & 2, for the upper and lower
bearing drain plugs for outside recirculation spray pump
2-RS-P-2A motor.
EWR 85-668E removed the upper and lower
bearing drain plugs and installed alternate oil drain assemblies
composed of piping and valves.
This made it easier to obtain
upper and lower bearing oil samples and corrected the oil
leakage problem.
Prior to removing the lower bearing drain plug
per EWR 85-668E, the new drain rig was held next to the drain
plug to verify proper fitup.
During this fitup, the mechanic
bumped the lower drain plug and-dislodged it from the drain
plug housing.
The mechanic reinstalled the lower drain plug but
the plug was very loose and would not fully engage.
Subsequently, it was discovered that the threaded portion of the
plug had broken off and remained lodged in the drain plug
housing.
Only the oil plug rubber a-ring and a portion of one
thread had secured the plug in the drain plug housing. The
licensee concluded that the drain plug, which was made of a thin
pot metal, had been previously over-torqued during installation.
Over-torquing the drain plug caused a crack to develop between
the drain plug head and threads which eventually caused the
drain plug to sever.
It could not be concluded if the drain
plug severed when bumped during the fit of the new drain
assembly or at a previous time. After removal of the motor upper
bearing oil drain plug, the plug was also discovered to have a
crack around its circumference between the plug threads and
head.
The upper drain plug crack was in the same area that
the lower drain plug had severed and also appeared to be the
result of over torquing.
The licensee inspected the motor upper
and lower oil reservoirs for the remaining outside recirculation
spray pumps and determined that only pump l-RS-P-28 had drain
plugs similar to pump 2-RS-P-2A.
Pump 1-RS-P-28 motor upper and
lower bearing oil drain plugs were not leaking oil and therefore
not considered an immediate problem.
During a walkdown of the
outside recirculation spray pumps, the inspectors noted that
several varieties of motor upper and lower bearing oil reservoir
drain assemblies existed on pumps 1-RS-P-2A and 2-RS-P-28.
These oil reservoir drain assemblies ranged from bolts, pipe
plugs, or pipe and pipe cap in lieu of drain plugs.
The
inspectors questioned why and when these alternative drain plug
assemblies were installed, and if drain plug oil leakage on
outside recirculation spray pumps had ever occurred previously.
The licensee's response was that it was not known when, why, and
how the alternate drain plug assemblies got installed.
10 CFR 50, Appendix B, Criterion XVI states, in part, that measures
shall b~ established to insure that conditions adverse to quality are
promptly identified and corrected.
The inspectors consider that the
timeliness of corrective action _for outside recirculation spray pump
2-RS-P-2A motor lower bearing oil reservoir drain plug oil leakage
8
was inadequate.
After the oil leakage was identified, the licensee
did not monitor how much oil was being added to the reservoir and
therefore was unable to determine if the pump could perform its
emergency function for an extended period of time with the existing
oil leakage.
Adequate corrective action was not taken until the oil
leakage rate and pump operability were questioned by the inspectors.
Failure to take prompt adequate corrective action after the motor
lower bearing drain plug was found to be leaking oil is identified as
a violation (281/90-20-01).
e.
Physical Security Program Inspections
f.
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 discrepancies were noted.
Licensee 10 CFR 50.72 Reports
(1)
On May 11, 1990 the licensee made a report in accordance with 10
CFR 50.72 concerning the ambient temperature exceeding 78°F in
the area of the TSC that contains the ERFCS computer.
The high
ambient temperature occurred when one of the TSC's air
conditioning units was removed from service for maintenance.
Within approximately four hours after exceeding 78°F, the air
conditioning unit was returned to service and ambient
temperature was reduced to 71°F.
All ERFCS equipment functioned
properly during the temperature excursion.
(2)
On May 13, 1990 the licensee made a report in accordance with 10
CFR 50.72 concerning all Unit 1 IRPis indicating greater than 12
steps above their respective group step demand position
indication.
TS 3.12.C.1 requires that IRPI be within 12 steps
of its group step demand indication. This event occurred when
one of the two IRPI power supplies was put into service *
following replacement.
The gain on the new IRPI power supply
was set too high which caused all IRPis to indicate high.
Within approximately 20 minutes after exceeding the IRPI
limitations, the IRPI was adjusted to within the TS limitations
of group step demand indication.
(3)
On May 22, 1990 the licensee made a report in accordance with 10
CFR 50.72 concerning reactor trips for both Units 1 and 2.
At
approximately 1158 hours0.0134 days <br />0.322 hours <br />0.00191 weeks <br />4.40619e-4 months <br />, on May 22, with Unit 1 and Unit 2 at
100% power, a fault occurred on the Unit 1 A main transformer .
The fault condition resulted in a Unit 1 generator trip which
initiated a turbine trip which initiated a reactor trip. The
9
electrical fault also resulted in a fault condition for the A
RSS transformer which is the preferred power supply for the Unit
1 J 4160 volt emergency bus.
The loss of preferred power to the
Unit 1 J bus resulted in an auto-start of the #3 emergency
diesel generator and loading of the bus from the generator.
The loss of Unit 1 electrical output also resulted in a voltage
reduction on the Unit 2 J electrical bus for approximately 5
seconds.
The voltage reduction condition affected the IRPI
on Unit 2 such that the unit operator noticed erratic rod
position indication. Also, the unit received a turbine runback
signal which was attributed to at least one IRPI indicating
below the rod bottom limit. Based on these indications, the
Unit 2 operator initiated a manual reactor trip approximately 11
seconds after the Unit 1 trip.
After both units tripped, operators took required actions to
stabilize the units in in a hot shutdown condition.
Due to
normal load shedding of non-vital loads and the lockout of A RSS
transformer, both main feed pumps for Unit 1 were not available.
Auxiliary feedwater pumps auto-started as designed and supplied.
water for heat removal from Unit 1.
Unit 2 B main feedwater
pump continued to run after the events and supplied required
water for heat removal from Unit 2.
All safety systems
performed as designed.
Operator actions were performed in a
manner which eliminated challenge to other safety functions.
However, these actions were performed by more than the normal
shift crew compliment.
The inspectors noted that approximately
30 minutes after the trips, there were eight licensed reactor
operators performing recovery evolutions within the control
room.
This number of operators would normally not be available
on back shifts. The licensee is presently operating with a
minimum of 3 SROs and 4 ROs on each shift and intends to
increase this number to a minimum of 4 SROs and 5 ROs on each
shift by the end of 1990.
The inspectors consider that the
proposed licensee action to increase licensed operator manning
on each shift will provide for increased capability during
transient conditions on all shifts.
After both units were in a stable condition, the licensee
implemented a recovery plan to restore offsite power to the Unit
1 J bus.
The A RSS transformer was inspected and insulators
were repaired.
The transformer was returned to service by 2400
hours on May 22.
A post-trip review for Unit 2 was held on May
23, and licensee management reviewed the Unit 2 trip and
corrective actions, including items that required unit shutdown
to effect repair.
The pressurizer spray valve controller
(paragraph 4.c) and the rod control PS4 power supply (paragraph
4.d) were replaced during the shutdown.
The licensee concluded
that the fault in the Unit 1 A main transformer was caused by an
inadvertent actuation of the transformer's fire mitigation
10
deluge system.
The deluge system manual initiation switch was
bumped by a station carpenter which resulted in the reposition-
ing of the switch and spraying a large quantity of water on the
transformer.
The A main transformer was repaired and all six
manual deluge system initiation switches were replaced.
Restart
evolutions for each unit are discussed in paragraph 3.a.
(4)
On May 31, 1990 the licensee made a report in accordance with 10
CFR 50.72 concerning a manual reactor trip of Unit 2 from 100%
power.
The manual trip was initiated due to a failure of the A
feedwater regulation valve controller that caused the FRV to
close.
The unit was stabilized in hot shutdown after the trip.
All safety systems performed as designed.
However, immediately
after the manual trip occurred six !RPI rod bottom lights were
not lit. Several minutes later when the review was conducted on
the emergency sequence procedure, all but one rod bottom light
was lit. Operators replaced the bulb and restored rod bottom
indication for that rod.
The licensee's post-trip review of rod
position and reactor flux distribution computer printouts showed
that all rods reached the bottom immediately following the trip.
When loads were transferred from the unit station service
transformers to the RSS transformers, voltage fluctuation in the
IRPI power supply occurred and caused erroneous IRPI indication.
Following the trip, the licensee performed rod drop testing on
selected rods.
All rod drop times were within the TS
requirements.
The cause of the
1A
1 feedwater regulation valve
controller failure was determined to be clogging of a small air
passage in the controller that resulted in .loss of the
controller output signal which caused the valve to close.
The
part that contained the small air passage was replaced on Units
1 and 2 FRV controllers. Restart evolutions for this unit is
discussed in paragraph 3.a.
Within the areas inspected, one violation was identified.
4.
Maintenance Inspections (62703 & 42700)
During the reporting period, the inspectors reviewed maintenance
activities to assure compliance with the appropriate procedures.
Inspection areas included the following:
a.
EOG No. 2 Speed Sensing Relay Adjustment
On May 17;1990, the inspectors witnessed the adjustment of EOG No. 2
speed sensing relay.
As discussed in paragraph 5.a, during a PT on
No. 2 EOG, one of the two redundant speed sensing relays did not
energize when the EOG speed reached 890 RPM.
The purpose of the
speed sensing relays are to energize when the EOG is at full rated
speed and automatically shut the EOG output breaker.
Only one of the
speed sensing relays are required to energize in order for the output
breaker to shut.
The rheostat for the speed sensing relay that did
11
not energize at 890 RPM was adjusted, and EOG No. 2 was
satisfactorily tested per procedure 2-PT-22.3B, Diesel Generator No.
2 Return To Service Following Maintenance Test.
Procedures EMP-C-EE-31, The Emergency Diesel Generator, dated August
4, 1988, and EMP-C-EE-215, EOG Start And Shutdown Circuit Relay
Setpoint Checks, dated December 12, 1989, were used to troubleshoot
and adjust the EOG No. 2 speed sensing relay.
The inspectors
reviewed procedures EMP-C-EE-31 and EMP-C-EE-215 at the job site
while maintenance was in process and after completion of maintenance.
As a result of these reviews, the inspectors noted several areas
where maintenance personnel were not following the requirements of
recently implemented station administration procedures.
While
maintenance was in process, the inspectors reviewed the working.copy
of the procedure and noted that the electricians were on step 5.4 of
procedure EMP-C-EE-31.
During the inspectors* review of the
procedure, it was noted that the prerequisites, initial conditions,
and steps before 5.4 were not initialed by the electricians to
indicate completion of work or requirements.
Procedure EMP-C-EE-215
which had been previously utilized on May 16, 1990, to troubleshoot
the speed sensing relay also contained steps that had been
accomplished but not initialed by the electrician performing the
work.
Step 6.7.2 of VPAP-0501, Procedure Administration Control
Program, dated December 1, 1989, requires the procedure signoff
be completed as the procedure step is completed.
The inspectors
reviewed the EOG No. 2 speed sensing work package after the
maintenance and retest were completed and the EOG was declared
On May 18, during the review of EMP-C-EE-215 which was
performed again on May 17 after a one-time change, it was noted that
step 5.47 signature and verification blocks for the reconnection of
electrical leads contained initials obtained by a telephone call made
on May 18, between the maintenance supervisor and the electricians
that accomplished the work.
The maintenance supervisor reviewed the
work package on May 18, after EOG No 2 was tested and returned to
service and explained that the leads had been reconnected, but a hand
written one time only change to the procedure made on May 17, was
confusing in that step 5.47 appeared to be not applicable, and
therefore not initialed as complete by the electricians performing
the work.
The inspectors noted that many of the steps in procedure
EMP-C-EE~215 had been deleted by the change, but considered that if
the procedure was worked in a step-by-step manner and signed off each
step as required when complete, it would have been apparent that step
5.47 was not deleted by the change.
The inspectors had another
concern regarding step 5.47 not being signed off as complete because
maintenance had been performed on EOG No. 2, and the EOG was tested
and returned to service without a complete review of the work package
to ensure all work was completed as required.
Discussion with the
maintenance supervisor indicated that the foreman did a partial
review of EMP-C-EE-215 but not a complete review and therefore missed
that step 5.47 was not signed off. Step 6.14.2.a of VPAP-0801,
12
Maintenance Program, implemented February 2, 1990, requires that
following maintenance and post-maintenance testing, the functional
acceptability of the affected equipment shall be documented before
the equipment is declared operable. This step also states that the
completed work instruction package including failure analysis, if
required, shall be reviewed and signed off by appropriate personnel.
The inspectors questioned the maintenance superintendent on the
requirements to satisfy step 6.14.2.a. The maintenance superintend-
ent replied that a foreman should review the work package before the
equipment is declared operable and that a memorandum was going to be
issued to clarify this requirement.
These examples where maintenance personnel were not following the
requirements of recently implemented station administrative proce-
. dures is identified as an NCV (281/90-20-02).
However, because the
violation meets the criterion of 10 CFR, Part 2, Appendix C, Section
V.A, it is not being cited. The inspectors also noted that NRC
Inspection Report 280,281/90-07 had a similar ob~ervation where
station administrative procedures were not being strictly adhered to
by maintenance personnel.
The licensee stated that this type of maintenance was not typical
because it was performed while an LCO was in effect, and therefore
time to accomplish the maintenance was limited, and that there was no
indication that not signing steps off as performed was a common main-
tenance practice.
The licensee also stated that it has recognized
that the area of maintenance supervisory review of work packages
after completion of work was a problem area and corrective action was
being implemented.
Maintenance management was responsive to this
concern and implemented additional corrective actions to address the
problem.
b.
Preventive Maintenance on Component Cooling Water Pump 1-CC-P-2A
On May 21, 1990, the inspectors witnessed preventive maintenance
being performed on this pump which supplies cooling water to the
charging pump seal coolers. Maintenance Operating Procedure
1-MOP-8.41, Removal of Charging Pump Cooling Water Pump 1-CC-P-2A
From Service, dated February 20, 1990 and Preventive Maintenance
Procedure CC-P-M/SA 1, Charging Pump Cooling Water Pump Checks and
Lubrication, dated February 15, 1990, were reviewed.
The work was
performed on Work Order No. 3800095284.
The inspectors observed the
prejob briefing, the tagging operation, manipulation of a discharge
valve, and the post-maintenance evaluation of the pump.
No
discrepancies were noted.
c.
Repair of Unit 2 Pressurizer Pressure Controller
During recent operation, the licensee noticed erratic operation of
one of two pressurizer spray valves.
The problem was traced to the
valve controller and the unit continued operation with the controller
13
being maintained in the manual mode.
Evaluation of repair at power
was proceeding slowly due to the location of the component on the
control panel and the potential to cause other problems during the
repair evolutions. After the unit trip on May 22, the licensee
commenced repair of the controller with the unit shutdown.
The
inspectors reviewed Instrument Maintenance Procedure 2-IMP-C-RC-048,
P-444 Pressurizer Pressure Control, dated March 6, 1990, which was
used to replace the controller. The work was performed on Work Order
No. 3800094298.
The manual/automatic station and PC-2-444D were
replaced.
The inspectors reviewed the procedure, prejob briefing
information, and some of the other documentation.
No discrepancies
were noted.
d.
Repair of Unit 2 Rod Control Logic Cabinet Unit 2
This maintenance was initiated because of a non-urgent failure alarm
in the rod control logic cabinet on Unit 2.
The inspectors reviewed
Instrument Maintenance Procedure IMP-C-EPCR-46 dated June 26,1989.
Several operations were performed on Work Order No. 3800092105 prior
to the unit shutdown.
Specifically, on February 15 the auxiliary
power supply and fuses were checked (annunciator alarm indications *
were cleared, but returned later), and on February 22 the
.
overvoltage protection device was replaced (power supply still failed
low).
However, replacement of the PS 4 power supply had been
deferred until a unit outage due to the potential of tripping the
unit if repairs were done with the plant at power.
This power supply
was replaced on May 22, 1990, when the unit was shutdown, I&C
personnel noted that the PS 4 power supply replacement unit appeared
to be different although the part numbers were the same.
The
licensee initiated a call to the vendor (Westinghouse) and verified
that the replacement was acceptable.
During this inquiry it was
learned that the new power supply for the logic cabinet should be
adjusted to 15.5 plus or minus 0.5 volt DC instead of 16.5 plus or
minus 0.5 volt specified in the maintenance procedure.
Engineering
Work Request (EWR)90-230, Rod Control Power Supply-Evaluation For
Lambda Power Supply/Surry/Unit 2, discusses the evaluation of the
newer model power supply and the voltage and amperage settings. The
inspector reviewed the work package documentation.
No discrepancies
were noted.
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.
14
Tests were performed in accordance with approved procedures.
Test procedures appeared to perform their intended function.
Adequate coordination existed among personnel involved in the test.
Test data was properly collected and recorded.
Inspection areas included the following:
a.
On May 16, 1990, the inspectors witnessed the performance of periodic
test 2-PT-22.3J, Diesel Generator No. 2 Monthly Exercise Test, dated
December 12, 1989.
The purpose of the test was to verify that EOG
No. 2 and associated fuel transfer pumps and lines operated as
required by TS 4.6 and 4.6.A.l.c and to verify that the air start
system check valves were operable as required by inservice test
requirements.
The inspectors witnessed this testing from both the
EOG No. 2 room and the control room.
During the test, EOG No. 2 was
declared inoperable because one of the two parallel EOG speed sensing
relays did not operate correctly.
Repair of the speed sensing relay
is discussed in paragraph 4.a. After repair of the speed sensing
relay, EOG No. 2 tested satisfactorily. The inspectors reviewed the.
completed copy of procedure 2-PT-22.3J.
No discrepancies were noted.
b.
On May 25, 1990, the inspectors witnessed the performance of periodic
test 2-PT-14.2, Main Steam Trip Valves and Main Steam Non-Return
Valves, dated December 12, 1989.
The purpose of the test was to
verify that the valves operated as required by TS 4.7.
The
inspectors witnessed the stroke timing of one of the valves in the
control room, witnessed the measurement of valve stroke in the steam
safeguards room, and reviewed the completed test procedure.
No
discrepancies were identified.
c.
On May 25, 1990, the inspectors witnessed the performance of periodic
test 2-PT-8.2, Reactor Protection Logic, dated September 8, 1989.
The purpose of the test was to verify that the logic for the reactor
trip system interlocks listed in TS Table 4.1.A were operable prior
to reactor startup. The inspectors witnessed portions of the logic
testing from the control room and reviewed the completed test
procedure.
No discrepancies were noted.
Within the areas inspected, no violations were identified.
6.
Exit Interview
The inspection scope and results were summarized on June 6, 1990 with
those individuals identified by an asterisk in paragraph 1.
The following
summary of inspection activity was discussed by the inspectors during this
exit.
15
A violation (281/90-20-01) was identified for failure to take timely
corrective action for oil leakage from the lower bearing oil reser-
voir drain plug for outside recirculation spray pump 2-RS-P-2A motor
(paragraph 3.d).
Strengths and weaknesses identified in this inspection report were
discussed (paragraphs 3.a and 4.a).
An NCV (281/90-20-02) was identified for failure to follow
maintenance program implementing procedures (paragraph 4.a).
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.
7.
Index of Acronyms amd Initialisms
CFR
EOG
EMP
ERFCS
HSD
IRPI
LCD
NRC
OP
TPUP
TS
CODE OF FEDERAL REGULATIONS
ELECTRICAL MAINTENANCE PROCEDURE
EMERGENCY RESPONSE FACILITY COMPUTER SYSTEM
ENGINEERED SAFETY FEATURE
ENGINEERING WORK REQUEST
FEED REGULATING VALVE
HOT SHUTDOWN
INSTRUMENT MAINTENANCE PROCEDURE
INDIVIDUAL ROD POSITION INDICATOR
LIMITING CONDITION FOR OPERATION
LOSS OF COOLANT ACCIDENT
NON-CITED VIOLATION
NUCLEAR REGULATORY COMMISSlON
OPERATING PROCEDURE
PERIODIC TEST
REVOLUTION PER MINUTE
REACTOR OPERATOR
RESERVE SERVICE STATION
RADIATION WORK PERMIT
SAFETY INJECTION
SENIOR REACTOR OPERATOR
TECHNICAL PROCEDURES UPGRADE PROGRAM
TECHNICAL SPECIFICATIONS