ML18152A250
| ML18152A250 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 11/30/1993 |
| From: | Belisle G, Branch M, Tingen S, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A251 | List: |
| References | |
| 50-280-93-24, 50-281-93-24, NUDOCS 9312140051 | |
| Download: ML18152A250 (19) | |
See also: IR 05000280/1993024
Text
4,
I
.
Report Nos. :
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
50-280/93-24 and 50-281/93-24
Licensee: Virginia Electric and Power Company
5000 Dominion Boulevard
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50-281
License Nos.:
Facility Name:
Surry 1 and 2
Inspection Conducted: October 3 through November 6, 1993
Inspectors:
Inspector
J~ ~ort!R7menf'I~or
Approved by:
SUMMARY
Scope:
1/*Jtr f'3
Date Signed
1/-..Jer-f~
Date Signe
/l-~-13
Date Signed
This routine resident inspection was conducted on site in the areas of plant
status, operational safety verification, maintenance inspections, surveillance
inspections, balance of plant inspection, action on previous inspection items,
emergency response training for off-site support groups and engineered safety
feature system walkdown.
While performing this inspection, the resident
inspectors conducted reviews of the licensee's backshifts, holiday or weekend
operations on October 12, 21, 26, 30, 31 and November 1, 2, and 3, 1993.
. . .
2
Results:
In the Operations area, the following items were noted:
Measures implemented to compensate for reactor coolant system leaking
into the Unit I B safety injection accumulator did not prevent the boron
concentration in the accumulator from decreasing below the Technical
Specification (TS) minimum requirements on two occasions (paragraph
3.e).
The initial Station Nuclear Safety and Operating Committee screening of
the deviation report documenting that boron concentration in the Unit I
B safety injection accumulator was below TS minimum requirements
categorized the event as not reportable. After additional engineering
review, the event was considered reportable. A licensee event report
will be written (paragraph 3.e).
Although the licensee had recently completed a component relabeling
program, seven components in the Unit I and 2 charging pump service
water support systems were not labeled with the new label plates
(paragraph 9).
In the Maintenance/Surveillance area, the following items were noted:
During the period, two Unit I rod control system problems occurred that
resulted in rod control system urgent failure alarms (paragraphs 3.a and
4.c).
During summer months, recurring operational problems with the 555-ton
mechanical chiller condensers continued to cause entry into TS action
statements for containment partial pressure. This challenged operators
unnecessarily (paragraph 3.f).
The licensee's temporary leak sealant program was identified as a
strength (paragraph 4.a).
During the previous Unit 2 refueling outage, a new type of packing was
installed in the auxiliary feed water pumps that required special
installation and run-in instructions. The packing was installed
correctly but the process could have been done more efficiently
(paragraph 4.e).
The use of the motor operated valve diagnostic equipment for
troubleshooting the reactor trip bypass breaker was innovative, provided
the licensee with additional diagnostic information, and was considered
a strength (paragraph 4.b).
During reactor protection system logic testing, the inspectors observed
good communication between all parties, as well as, good self checking
techniques by the personnel manipulating the test switches. This was
considered extremely important since the procedure directed
approximately 500 various switch operations (paragraph 5).
,.
',
3
In the Engineering/Technical Support area, the following item was identified:
The licensee's ability to utilize advanced metallurgical analysis
techniques for failure analysis cases, such as the cast aluminum-bronze
service water valves, was a continuing strength (paragraph 3.b).
In the Plant Support area, the following item was noted:
The licensee was proactive in working with the state and local
governments in resolving Federal Emergency Management Agency emergency
exercise items (paragraph 8).
- REPORT DETAILS
1.
Persons Contacted
Licensee Employees
W. Benthall, Supervisor, Licensing
- R. Bilyeu, Licensing Engineer
- H. Blake, Jr., Superintendent of Nuclear Site Services
- R. Blount, Superintendent of Maintenance
D. Christian, Assistant Station Manager
J. Costello, Station Coordinator, Emergency Preparedness
- J. Downs, Superintendent of Outage and Planning
- D. Erickson, Superintendent of Radiation Protection
A. Friedman, Superintendent of Nuclear Training
B. Hargrave, Nuclear Materials
- M. Kansler, Station Manager
- C. Luffman, Superintendent, Security
- J. McCarthy, Assistant Station Manager (Acting)
- A. Price, Assistant Station Manager
- K. Sloane, Superintendent of Operations (Acting)
- M. Small, Senior Reactor Operator
- E. Smith, Site Quality Assurance Manager
- D. Souza, Senior Reactor Operator
- T. Sowers, Superintendent of Engineering
J. Swientoniewski, Supervisor, Station Nuclear Safety
NRC Personnel
- M. Branch, Senior Resident Inspector
- S. Tingen, Resident Inspector
- J. York, Resident Inspector
- Attended Exit Interview
Other licensee employees contacted included control room operators,
shift technical advisors, shift supervisors and other plant personnel.
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2.
Plant Status
Unit 1 operated at full power for the majority of this inspection
period.
On November 4, the unit began a power coast down.
At the end
of the inspection period the unit was at 98% power.
Unit 2 operated at approximately 98% power throughout the period in
order to minimize level oscillation in the C SG .
j
3.
2
Operational Safety Verification (71707, 42700)
The inspectors conducted frequent tours of the control room to verify
proper staffing, operator attentiveness and adherence to approved
procedures.
The inspectors attended plant status meetings and reviewed
operator logs on a daily basis to verify operational safety and
compliance with TSs and to maintain overall facility operational
awareness.
Instrumentation and ECCS lineups were periodically reviewed
from control room indications to assess operability.
Frequent plant
tours were conducted to observe equipment status, fire protection
programs, radiological work practices, plant security programs and
housekeeping.
Deviation reports were reviewed to assure that potential
safety concerns were properly addressed and reported.
a.
Unit I Control Rod Drive System Urgent Failure Alarms
At 6:24 a.m., on October 13, a Unit 1 rod control system urgent
failure alarm was received.
By design, an urgent failure locks up
the rod control system and prevents normal rod motion.
It does
not prevent rods from tripping into the core if a protective
actuation was initiated. A two hour TS action statement to clear
the alarm was entered in accordance with TS 3.12.C.3. At 8:24
a.m., the two hour action statement was exited and a six hour
action statement to HSD was entered.
The rod control internal
alarm was reset and the urgent failure alarm cleared.
The cause
for the urgent failure alarm was not determined.
Procedure
l-PT-6, Control Rod Assembly Partial Movement, was satisfactorily
performed and the six hour action statement was exited.
On October 21, another rod control system urgent failure alarm
occurred in Unit I. This event is discussed in paragraph 3.d and
4.c.
b.
Through-Wall Leaks in SW Valve Bodies
On October 12, the licensee documented a deficient condition on DR
S-93-1350 which involved several valves in the SW system used for
charging pump lube oil and seal cooling.
The DR described a
condition where SW was seeping through what appeared to be
porosity in the cast valve bodies.
Eleven valves from each unit
exhibited some degree of corrosion attack, from weepage to visual
corrosion products present on the outside of the valves.
The portion of the SW system with the leaking valves provided
cooling water to the charging pump lubricating oil and seal cooler
heat exchanger.
These leaking Jamesbury ball valves provided
maintenance isolation capability. This low pressure system
(approximately 45 psi) normally flows approximately 50 gpm and
varies on a seasonal basis.
The flow velocity is sometimes as low
as two to three feet per second.
Flow below approximately five
feet per second lends the system to the potential to fouling which
can promote the formation of MIC nodules.
3
The SW valves in question are cast aluminum-bronze, alloy C 95400.
After discovering the problem, the licensee replaced several
valves that exhibited through-wall leakage. Originally, this
system was constructed of plastic components.
In 1986 because of
Appendix R considerations, the components were changed to
aluminum-bronze.
The valves that were removed were taken to the site metallurgical
laboratory for determining the failure mechanism. A chemical
analysis of one of the cast valves showed that the chemical
composition requirements in ASTM B 148, Standard Specification for
Aluminum-Bronze Sand Castings, were met.
Cross sections of leaking areas {under MIC nodules) revealed that
the aluminum rich phases had been leached out leaving a porous
structure through which the weeping/leaking occurred. Also, this
examination showed that the through-wall dealloying did not exceed
25 percent of the circumference for any given cross section.
Corrosion product analysis on the outside of the valves showed a
large percentage of aluminum thus confirming the dealloying
process.
Some sections from the first valve removed were used to perform
tensile tests. Samples were taken from the unaffected, as well
as, the dealloyed sections of the cast material. The visual and
metallographic evaluations, along with the tensile tests results,
were used as the basis for the licensee's evaluation that the
valves would maintain their structural integrity in the identified
degraded condition until they could be replaced.
Discussions between the licensee and the NRC concluded that the
licensee needed to request relief from the ASME Section XI Code in
order to continue to operate without immediate repair of the
defects. This determination was consistent with the guidance
contained in GL 91-18 and 90-05.
The licensee indicated that they
disagreed with the NRC's interpretation on addressing operational
leakage under the ASME Code.
However, after determining
structural integrity of the valves in question, the licensee
indicated that they would comply with the NRC's interpretation for
this case and on November 2, a relief request was submitted for
NRC's review.
The licensee indicated that they plan to address
this issue further and have requested a meeting with the NRC to
present their position.
The inspectors are following the licensee's actions to evaluate
the root cause of the material failure, the reportability of the
issue, and replacement of the defected valves. At the end of the
inspection period, the licensee had replaced some of the SW valves
that were subject to through-wall leakage and were developing
plans for replacing the remaining valves.
The licensee's ability
to utilize advanced metallurgical analysis techniques for failure
4
analysis cases, such as the cast aluminum-bronze service water
valves, is a continuing strength.
c.
Unit 2 C SG Special Test
Since Unit 2 startup in May of 1993, the C SG has experienced
level oscillation whenever attempts were made to increase reactor
power to 100%.
Consequently, the unit operated at a reduced power
of approximately 98%.
The licensee's original investigation
centered around FW flow control. Gain adjustments were made to
the C FWRV in an attempt to dampen the SG level oscillations. The
adjustments to the FWRV controls did slow down the valve's
response to level oscillations; however, it was unsuccessful in
resolving the level oscillations to a point that power could be
increased back to 100%.
The licensee contracted a failure analysis expert in an attempt to
find other possible causes for the level oscillations.
Additionally, the licensee held discussions with their NSSS and SG
supplier to determine if other plants had experienced this type of
SG level phenomenon.
There were several possible causes discussed
which refocused the licensee's attentions to possible mechanical
or thermodynamic changes internal to the SG.
The possible
internal causes included damage to the feedwater "J-Tube", or
sludge buildup in the upper tube support region of the SGi
During a forced shutdown in August 1993, the licensee performed a
limited visual inspection of the internals of the C SG through
restrictive openings and no obvious defects were identified.
The inspectors reviewed the safety evaluation {93-196) that
supported the special test {2-ST-306) and attended the pre-shift
operating crew briefing. The scope and precautions contained in
the test procedure were discussed in detail and questions were
directed to the test director who resolved them in an acceptable
manner.
The test entailed raising the C SG program level from the normal
44% to 49% and monitoring the SG for level oscillations, both at
the existing 98% reactor power and at 100% power.
The test
directed holding at this new SG level for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> and then
raising the program level to 54% and monitoring the resultant
plant response for an additional 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
At the 98% reactor power, the level oscillations in the C SG
appeared to have stabilized after the program level was increased
to 49%.
However, when reactor power was increased to 100%, the
maximum level {on the narrow range instrumentation) oscillation of
+/- 20% magnitude was experienced.
The operators stabilized the
SG level in accordance with the precautions of the special test
procedure and the test was suspended at the direction of the SS
and test director. After reviewing the test results, plant
management directed that the.C SG level setpoint be returned to
d.
e.
5
the 44% value and that reactor power be controlled to minimize
level oscillations.
The C SG level setpoints were returned to the 44% value and
reactor power was lowered to 98%, and level oscillation was
reduced to the pre-test value.
The inspectors continued to
monitor the licensee's corrective actions in this area and will
review any C SG planned outage related activities.
Notice of Enforcement Discretion
On October 21, the NRC granted Enforcement Discretion to TS 3.12.C.3 for Unit 1 only.
On October 21, the Unit 1 Bank D
control rod assemblies became inoperable when a rod control system
urgent failure alarm occurred when operators were performing l-PT-
6, Control Rod Assembly Partial Movement.
TS 3.12.C.3 requires
that inoperable control rod assemblies be restored to operable
status within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or that the plant be put into a hot shutdown
condition within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
The discretion permitted
continued operation of Surry Unit 1 in Power Operation for a
period of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> versus the 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> specified in TS 3.12.C.3.
This additional time was projected to allow troubleshooting and
possible repairs to the Control Rod Drive System.
Although the
Bank D control rod assemblies were immovable on demand from the
Control Rod Drive System, the ability of the control rod
assemblies to perform their intended safety function (trip into
the core) when a safety system setting was reached was not
effected. A blown fuse was identified as the cause of the rod
control system urgent failure alarm which resulted in the
immovable Bank D control rod assemblies.
The fuse was replaced
and the control rods were satisfactorily tested in accordance with
l-PT-6.
The Control Rod Drive System was returned to operable
status approximately one hour after the Notice of Enforcement
Discretion as verbally approved by the NRC.
Since rod control system failures appear to be a continuing
problem, the NRC requested the licensee discuss their assessment
of previous failures with NRC management.
The inspectors continue
to monitor the licensee's rod control system reliability
improvement activities and are currently reviewing the RCM study
of that system and the status of implementing any recommended
corrective actions.
Unit 1 B Accumulator In-Leakage
On October 9 and 15, 1993, sample analyses from the Unit 1 B
accumulator revealed that the boron concentration was less than
the minimum required by TS.
It was suspected that back leakage
from the RCS through the accumulator check valves diluted the
boron concentration in the accumulator.
TS 3.3.B states that any
one of the following SI components may be inoperable at any one
time and that if the condition is not restored within the allowed
6
time period then the unit must be placed in hot shutdown within 6
hours.
TS 3.3.B.l states that one accumulator may be isolated for
a period not to exceed 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
On both occasions when the boron concentration was out of
tolerance, the licensee declared the B accumulator inoperable in
accordance with TSs 3.3.B and 3.3.B.l and entered a four hour
action statement to restore the accumulator to an operable status.
On both occasions, the boron concentration was restored within
four hours.
The accumulator was not isolated at any time during
these evolutions. The inspectors discussed the licensee's
interpretation of TS 3.3.B.l with the NRC staff and concluded that
the licensee correctly interpreted the TSs.
Although the boron
concentration was low, it was still significantly higher than RCS
boron concentration and could have discharged into the RCS if
needed.
This condition was more conservative than a condition
where the accumulator would have been isolated and not available.
SI accumulator levels are logged every shift. The inspectors
reviewed the logs for the B SI accumulator level from July 1
through November 1, 1993, and concluded that around September 1
levels began to increase due to leakage into the accumulator.
Prior to September 1, coolant was leaking out of the accumulator
and the accumulator had to be filled approximately every 10 days.
After September 1, small amounts of water were drained from the
accumulator to reduce level approximately every three to four
days.
The inspectors concluded that measures implemented to
compensate for leakage of reactor coolant into the Unit 1 B safety
injection accumulator did not prevent the boron concentration in
the accumulator from decreasing below the TS minimum requirements
on two occasions.
The inspectors also reviewed the licensee's reportability
determination for this event. VPAP-1501, Station Deviation
Reports, Revision 3, states that the SS makes the initial
reportability determination and this determination is reviewed by
the Superintendent of Operations, SNS supervisor, and SNSOC.
The
inspectors reviewed DR S-93-1372. This DR documented that on
October 15 the boron concentration in the Unit 1 B SI accumulator
was below the minimum TS requirements.
The inspectors noted that
this event was initially categorized as not reportable.
The
inspectors and other station personnel questioned if the boron
concentration was less than required by TSs for a period greater
than fours hours allowed by the licensee's TS interpretation
discussed above.
Engineering reviewed this event and concluded
that the boron concentration was less than required by TS for a
period greater than four hours.
The licensee subsequently
identified that this event was reportable by an LER .
At the end of the inspection period, the licensee was preparing an
LER and was evaluating corrective action to reduce leakage into
the Unit 1 B SI accumulator.
The licensee was also sampling the B
g.
7
accumulator every two. days to verify proper boron concentration.
The inspectors will review the licensee's LER on this issue to
determine if any additional actions are necessary.
f. Containment Partial Pressure Less Than 9.0 PSIA
TS Figure 3.8.1 requires that containment partial air pressure be
maintained greater than or equal to 9.0 psia.
TS 3.8.D.l.a
specifies that if containment partial air pressure is less than
9.0 psia then containment air partial pressure must be restored to
within acceptable limits within one hour or be in at least hot
shutdown within the next six hours.
The inspectors noted, and the licensee's trending programs
confirmed, that in the summer months a one-hour action statement
had been entered in accordance with TS 3.8.D.l.a on numerous
occasions in both units because indicated containment partial air
pressure fell below 9.0 psia.
In 1992 and 1993 there were at
least six and fourteen DRs, respectively, written to document that
a one hour action statement was entered because containment
partial air pressure was less that 9.0 psia.
Operational problems with the 555-ton mechanical chillers which
normally are used only during the summer months cause indicated
containment partial air pressure to decrease below 9.0 psia. The
licensee has appointed a task team and initiated a station Level I
action item to improve the operation of the 555-ton mechanical
chillers; however, operators have been routinely challenged to
restore containment partial *air pressure on a recurring basis
during the summer months.
The inspectors are continuing to follow
this issue.
Air Leak on EOG #1
During a backshift tour on November 2, the inspectors noted that
air was blowing by the seat of valve l-EG-18.
The valve is a
manual strainer blowdown valve on one of the two banks of EOG
starting air. The air accumulator pressure was normal and no low
pressure alarms were lit. The inspectors notified the SS and an
operator was dispatched to investigate.
The operator checked the
valve closed and then attempted to blow any trash from the seat by
cracking open the valve.
The low pressure alarm was actuated
during the blowdown and the operator reclosed the valve and
allowed the compressor to recover pressure above the alarm
setpoint. The blowdown reduced the leakage somewhat; however, the
valve continued to leak and WR 027327 was initiated to repair the
valve.
Within the areas inspected, no violations were identified .
j
4.
8
Maintenance Inspections (62703) (42700)
During the reporting period, the inspectors reviewed the following
maintenance activities to assure compliance with the appropriate
procedures.
a.
Inspection of Leak Sealant Practices
The site utilized contractors to repair leaks with temporary leak
sealant. Temporary leak sealant has been used to repair a variety
of leaks. The process involves drilling and tapping a valve
bonnet, flange, manway cover or packing gland, and installing
injection adapters.
An injection gun is utilized to inject leak
sealant into the adapter and the desired area.
In other
instances, a box is built around a leak and the box is injected
with leak sealant or sealant can be utilized to plug a valve that
has excessive seat leakage.
Temporary leak sealant can be
utilized on safety and non-safety systems; however, the use of
temporary sealant on safety systems is minimized.
Generally a
rubber based sealant is utilized on systems less than 460 degrees
F and a synthetic fiber based sealant utilized on systems up to
1000 degrees F.
Whenever a temporary leak sealant is utilized to
repair a leak, a WR is processed to restore the component back to
original specifications during the next scheduled outage of
sufficient duration.
Generic procedure O-MCM-1918-01, On-Line Leak Repairs, provides
guidelines for the temporary leak sealant of components in safety
and non-safety related systems.
This procedure was approved by
SNSOC and required that engineering approve using a temporary leak
sealant for repair. Engineering is extensively involved when a
temporary leak sealant is used.
Design Engineering is required to
evaluate stress, seismic calculations, the need for additional
supports, and design pressure when utilizing a temporary leak
sealant. System Engineering evaluates the impact of repair on
system operation, potential for blockage, and the affect of
intrusion of sealant into the system being injected.
Engineering
is also required to perform a safety evaluation screening for the
temporary repair in order to determine if the evolution is a
modification.
Engineering is required to specify any post
maintenance testing that may be required and evaluate if repair
meets ASME specifications. Generally the temporary leak sealant
contractor calculates the injection pressure and the amount of
sealant to inject. This calculation is reviewed by engineering.
Personnel cannot inject more sealant than specified for the job.
Normally injecting temporary sealant to repair a leak is
considered maintenance and not a modification.
Procedure O-MCM-
1918-01, Step 6.1.11, required that the SNSOC review and approve
each work package for the repair of a leak with a temporary leak
sealant when the leak is located inside containment with the unit
operating.
Work packages for injecting sealant into components
located outside of the containment did not require SNSOC review
9
and approval.
The QA department reviewed the work package prior
to performance and specified hold point requirements.
There have been no recent issues or problems due to the
inappropriate use of sealant for temporary leak repairs. The
inspectors were informed that in the 1970s and early 1980s there
was a issue associated with contaminates in the sealant which
contributed to bolting failures on the main steam trip valves and
main feedwater regulating valves which were resolved.
The
licensee's temporary sealant program was identified as a strength.
b.
Unit 1 B Reactor Trip Bypass Breaker Troubleshooting
C.
On October 15, while the licensee was performing l-PT-8.1, Reactor
Protection System Logic, for the B RPS train, the closed indicator
light for the B RTBB went out after the breaker was closed for
testing purposes.
The licensee's investigation identified that a
10 amp fuse in the circuit had blown.
The fuse was subsequently
replaced and it blew again after the breaker was closed.
The RTBB
was opened after the main RTB was verified closed and the licensee
initiated troubleshooting to determine the cause of the blown
fuse.
The RTBB is normally open and is used solely for testing
purposes and when closed its safety function is to open if a RPS
signal is received.
The inspectors witnessed some troubleshooting and subsequent
testing of the breaker after repairs. The troubleshooting had
indicated that the closing solenoid coil was drawing excessive
current because it was kept energized longer than designed.
The
licensee used test equipment normally used for MOV testing to
monitor and record the current being drawn by the closing coil.
Using this equipment allowed the licensee to determine that the
control (X) relay that deenergizes the closing coil solenoid was
not actuating as required.
The mechanical linkage (relay release
arm) between the closing coil solenoid push rod and the relay was
not properly adjusted.
The licensee replaced the closing coil
solenoid, the X relay, and adjusted the linkage prior to breaker
reinstallation and successful retesting.
The use of the MOV diagnostic equipment for troubleshooting the
RTBB was innovative and provided the licensee with additional
diagnostic information and was considered a strength.
Troubleshooting the Rod Control Syitem Urgent Failure Alarm
On October 21, the licensee, while performing a periodic test,
received a rod control system urgent failure alarm when moving
control D bank.
The failure was determined to be in the
01-RD-CAB-lBD power cabinet. The inspectors observed technicians
performing troubleshooting which included electrical measurements
in the affected cabinet.
From the readings taken, it was
suspected that the B phase fuse on the supply power lines to the
10
movable coil circuit was blown.
The licensee requested
enforcement discretion, which was discussed in paragraph 3.d, in
order to proceed with the fuse replacement and testing in an
orderly manner.
At the conclusion of the troubleshooting the
licensee processed a WO and the blown fuse was replaced.
Procedure IMP-C-EPCR-46, Maintenance of Rod Control System, dated
December 22, 1992 was used to control the work.
Periodic test
l-PT-6 was performed on the D control bank and the rod control
system was returned to service.
Good coordination between the two
maintenance groups was noted and no problems were identified by
the inspectors.
d.
Fuse Schedule Inspection
The inspectors reviewed l-DRP-002, Instrument Fuse Schedule,
Revision 5 and 2-DRP-015, Power Fuse Schedule, Revision 0.
The
purpose of these procedures is to provide a fuse control program
for the most critical fuses in the units.
When replacing a fuse
or when obtaining fuse reference data, these procedures are to be
used in lieu of electrical drawings.
If a fuse schedule does not
contain a specific fuse, then the information is obtained from an
electrical drawing or engineering.
Fuse schedules are generally not utilized when isolating
electrical components.
The locations of fuses required to be
removed for isolation are generally obtained from drawings and the
same fuses are reinstalled when returning the component/system
back to service. Through discussions with operators and
electricians the inspectors were informed that as a good working
practice, personnel routinely inspect fuses that are removed to
verify that the fuse specifications are the same as the
specifications on the drawing.
Any discrepancies are resolved.
During the EDSFA conducted by the licensee, the following concerns
were identified with the fuse schedules:
Not all fuses in the fuse schedules were analytically
verified against design basis.
The fuse schedules were not complete in that they did not
contain all critical plant fuses and in some instances did
not specify all fuse data for a specific fuse.
Electrical department personnel were not aware that the
power fuse schedule was an approved document.
There were inconsistencies between fuse schedules and ESK
drawings.
Training was provided to ensure personnel were knowledgeable of
the fuse schedules.
The remaining concerns have not been fully
J
11
resolved but are scheduled to be resolved during future EDSFA
followup inspections performed by the licensee.
e.
Unit 2 A Auxiliary Feed Pump Repack
On October 29, the inspectors witnessed the licensee repacking AFW
pump 2-FW-P-3A.
WO 274804 and procedure O-MCM-0131-01, General
Pump Packing, Revision 0, were utilized to accomplish this
maintenance.
The inspectors reviewed the work package at the job
site while the mechanics were repacking the pump.
The mechanics
received guidance from maintenance engineering personnel. After
maintenance was completed and the pump was returned to service,
the inspectors reviewed the work package a second time. During
the second review, the inspectors noted that the work package
contained additional instructions for repacking the pump and
running the new packing that were added after the pump was
repacked. The additional instructions were provided in an
Information Transmittal Record from maintenance engineering.
The inspectors questioned why these instructions were not on the
job site when the work was accomplished.
The inspectors were
informed that during the previous Unit 2 RFO a different type
packing was installed in the AFW pumps.
The new packing required
different installation and run in methods than the previous
packing.
The inspectors were informed that prior to repacking the
pump on October 29, maintenance personnel were briefed on the
installation and run in methods for the new packing and
maintenance engineering subsequently documented what was done in
the Information Transmittal Record.
The inspectors concluded that the packing was properly installed
in the A AFW pump; however, this maintenance would have been
accomplished more efficiently if mechanics or procedures
recognized the special instructions associated with the new type
of packing.
The need for an Information Transmittal Record
indicated that the work package/training provided for the
mechanics was lacking all the necessary information to accomplish
the maintenance and maintenance engineering support was required
to augment the work package.
Within the areas inspected, no violations were identified.
5.
Surveillance Inspections (61726, 42700}
During the reporting period, the inspectors reviewed surveillance
activities to assure compliance with the appropriate procedure and TS
requirements.
On October 15, the inspectors witnessed the licensee performing l-PT-8.1
for the B RPS train. This testing was being performed as additional
testing for the repairs of the B RTBB discussed in paragraph 4.b to
verify that the protective logic was not affected by the breaker
I
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12
repairs. The inspectors monitored activities at the test panel in the
protection racks.
Communications between the I&C technicians at the
RTBB, in the control room, and at the test panel were also monitored.
The inspectors observed good communication between all parties, as well
as, good self checking techniques by the personnel manipulating the test
switches.
The inspectors considered this to be extremely important
since the procedure directed approximately 500 various switch
operations.
Within the areas inspected, no violations were identified.
6.
Balance Of Plant Inspection (71500)
The inspectors conducted tours of portions of the TB and other plant
areas susceptible to flooding.
During these tours, the inspectors
verified the availability of the non-safety related TB sump pumps.
The
licensee relies on these pumps to mitigate certain flooding scenarios.
Additionally, the inspectors were sensitive to any work activities that
would increase -the possibility of TB flooding such as openings in the
condenser waterboxes or piping systems.
a.
Hole In Unit 2 D CW Discharge Piping
During the plant tour on October 13, the inspectors became aw~re
of a one-inch diameter hole in the 96-inch CW discharge piping
from the Unit 2 D waterbox.
This non-safety related piping was
designed to AWWA specification and it is isolable from the gravity
flow intake canal by closing the 96-inch safety-related waterbox
inlet MOV.
The condition of the waterbox discharge piping for all
four Unit 2 waterboxes was observed by the inspectors. There was
evidence of previous welded overlay plate repairs to several of
the pipes.
The area where the hole was discovered was rusted
through and crumbled further when probed by the inspectors.
Although no leakage was noted, the C waterbox discharge piping
appeared to be corroded in the area near the floor level where
standing water had previously accumulated.
The inspectors discussed the observed conditions with the system
engineer and reviewed the Surry IPE for sensitivity of a possible
failure of the 96-inch waterbox discharge piping.
The pipe in
question is not routinely inspected.
Five of the eight CW supply
pipes are currently being inspected as part of the licensee's SW
system inspection developed as part of GL 89-13, SW System
Problems Affecting Safety-Related Equipment.
The three CW supply
pipes currently not routinely inspected do not supply the SW
system and were not included in the program.
The inspectors' IPE finding review concluded that a catastrophic
failure of the outlet piping was not considered since the inlet
MOV should close and isolate the leak. The licensee's IPE
considered the condenser waterbox as the weak-link for an isolable
failure.
The IPE described the probability of the inlet MOV not
13
closing and when multiplied by the probability of a waterbox
failure, the results were within acceptable IPE values.
The
licensee's IPE personnel indicated that even with the observed
conditions of the discharge piping, the probability of a
catastrophic failure would still be bounded by the weak-link
analysis. They further stated that it would not be valid to
multiply the probability of a MOV failing to close times a
probability of 1 for the discharge piping failure.
The inspectors discussed the IPE issue with regional personnel and
concluded that the licensee's PRA evaluation of the impact of the
observed condition of the discharge piping was reasonable.
b.
Water Bubbling From Floor Near Unit 2 D CW Pipe
On October 26, DR S-93-1394 documented a condition where the
operators identified that water was bubbling up through a crack in
the floor near the Unit 2 D CW supply line to the condenser.
DR
S-93-1394 indicated that the water was sampled and determined to
be greater than 5000 ppm sodium {similar to raw river water). The
inspectors walked down the area. Water was bubbling from two
locations in a concrete expansion joint approximately two feet
from where the D CW supply line penetrated the floor.
The leakage
rate was difficult to estimate. It was estimated to be one gpm.
The inspectors were initially concerned because the sodium
concentration in the sample indicated that the water may have been
CW which also contains approximately 5000 ppm sodium.
Subsequent
samples indicated that the water was substantially less than 5000
ppm sodium.
The inspectors witnessed personnel collecting water
bubbling from the expansion joint and also observed chemistry
department personnel analyze the sample for sodium.
A Flame
Emission Spectrometer was used to analyze the sample.
The sample
results indicated that it contained 1020 ppm sodium.
The
inspectors also observed personnel analyze a sample of CW for
sodium concentration.
The results of the CW sample indicated that
it contained 5400 ppm sodium.
It was undetermined why the sodium
concentration in the first water obtained from the expansion joint
was higher than the samples obtained later.
Per the licensee, ground water samples obtained just outside of
the turbine building contained approximately 500 ppm sodium.
The
inspectors concluded the water bubbling through the turbine
building floor appeared to be a mixture of ground water and CW due
to the elevated concentration of sodium.
The source of the CW is
unknown.
The inspectors considered the possibility that the leakage was
from the underground D CW supply line which is ASME code class Ill
piping.
The inspectors reviewed CW piping drawing 11548-FC-2C and
verified that the 96-inch carbon steel CW piping beneath the
turbine building floor was enclosed in 18 inches of concrete.
The
14
drawing also depicted mechanical transition joints between the
concrete intake structure piping and the 96-inch steel inlet
piping which the licensee indicated could also be the source of
the leakage.
The inspectors were informed that previous
inspections of the interior of this piping have not revealed
through wall defects. At the end of the inspection period the
licensee was evaluating methods to determine the source of the
leakage.
Within the areas inspected, no violations were identified.
7.
Action on Previous Inspection Items (92701,92702)
(Closed) VIO 50-281/91-20-01, Interval Between Surveillance of Unit 2
Hot Channel Factors Exceeded TS Requirements.
TS 3.12.B.2 requires that
hot channel factors be determined every EFPM and TS 4.0.2 allows a 25%
tolerance. The Unit 2 hot channel factors were determined on July 18
and September 4, 1990. This violation was identified because the
interval between these hot channel factors was 1.44 EFPM which exceeded
the allowable 1.25 EFPM.
In a letter dated October 16, 1991, the
licensee responded to this violation. The licensee determined that the
cause of the violation was improper interpretation of TS grace period
tolerances and that administrative limits to clearly define allowed
grace period limitations were implemented as corrective action. The
inspectors reviewed VPAP-1102, Periodic Testing, Revision 0, and
verified that administrative limits for specifying TS grace period
limitations were clearly defined.
The inspectors also reviewed
procedures that performed hot channel factors for Units 1 and 2 during
1993 and verified that the hot channel factors were performed within the
specified TS intervals.
Within the areas inspected, no violations were identified.
8.
Emergency Preparedness Training For Off-Site Support Groups
Throughout 1993 Virginia Power has provided emergency preparedness
training for state and local government personnel.
On October 26, the
inspectors witnessed several traintng sessions where Virginia Power
personnel instructed personnel from Surry, Newport News, Isle of Wight,
Richmond, Hampton, Smithfield and Petersburg in the areas of
radiological contamination, personal dosimetry and exposure control.
Areas emphasized during these training sessions included training in
corrective actions for previously identified FEMA items.
The inspectors
concluded that the licensee was proactive in working with state and
local governments in resolving FEMA emergency exercise items.
Within the areas inspected, no violations were identified.
9.
ESF Walkdown (71710)
The inspectors walked down the Unit I and 2 charging pump/HHSI SW
support systems. These systems provide cooling water to each
15
charging/HHS! pump lube oil cooler and to the intermediate seal coolers.
Drawings 11448-FM-071B, Revision 30 and 11548, Revision 31, were
utilized for the system walkdown.
During the walkdown the inspectors noted that the following components
were missing the new style label plates:
Duplex strainers 2-SW-S-2A, l-SW-S-2A and l-SW-S-2B.
Valves 2-SW-438, 2-SW-170 and l-SW-271.
Check valve 2-SW-130.
The inspectors concluded that although the licensee had recently
completed a component relabeling program, seven components in the Unit 1
and 2 charging pump SW support systems were not labeled with the new
label plates. This issue was discussed with the licensee.
The remaining deficiencies noted during the walkdown were previously
identified by the licensee and were annotated with WR tags. The
inspectors also noted that there was through-wall weepage on some of the
valves in the system. This issue was discussed in paragraph 3.b.
Within the areas inspected, no violations were identified.
10.
Exit Interview
The inspection results were summarized on November 9, 1993, with those
individuals identified by an asterisk in Paragraph 1.
The inspectors
described the areas inspected and discussed in detail the inspection
results listed below and in the Results section. Dissenting comments
were not received from the licensee. Proprietary information is not
contained in this report.
Item Number
Description
(Paragraph No.)
VIO 50-281/91-20-01
Status
Closed
Interval Between Surveillance
of Unit 2 Hot Channel Factors
Exceeded TS Requirements
(paragraph 7).
- 11.
Index of Acronyms and Initialisms
-
-
AWWA -
cw
DR
ECCS -
EOG
AMERICAN SOCIETY FOR TESTING AND MATERIALS
AMPERE
AMERICAN SOCIETY OF MECHANICAL ENGINEERS
AMERICAN WATER WORKS ASSOCIATION
BALANCE OF PLANT
CIRCULATING WATER
DEVIATION REPORT
EDSFA -
EFPM -
ESK
F
FEMA -
FWRV -
GL
GPM
HHS! -
HSD
LER
NRC
NSSS -
PSIA -
RTB
RTBB -
SNS
SNSOC -
ss
TS
VPAP
ELECTRICAL DISTRIBUTION SYSTEM FUNCTIONAL ASSESSMENT
EFFECTIVE FULL POWER MONTH
ENGINEERED SAFETY FEATURE
ELECTRICAL SKETCH
FAHRENHEIT
FEDERAL EMERGENCY MANAGEMENT AGENCY
FEEDWATER REGULATING VALVE
GENERIC LETTER
GALLONS PER MINUTE
HIGH HEAD SAFETY INJECTION
HOT SHUTDOWN
INSTRUMENTATION AND CALIBRATION
INDEPENDENT PLANT EVALUATION
LICENSEE EVENT REPORT
MICROBIOLOGICAL INDUCED CORROSION
MOTOR OPERATED VALVE
NUCLEAR REGULATORY COMMISSION
NUCLEAR STEAM SUPPLY SYSTEM
PARTS PER MILLION
POUNDS PER SQUARE INCH
POUNDS PER SQUARE INCH ABSOLUTE
PERIODIC TEST
QUALITY ASSURANCE
RELIABILITY CENTERED MAINTENANCE
REFUELING OUTAGE
REACTOR TRIP BREAKER
REACTOR TRIP BYPASS BREAKER
SAFETY INJECTION
STATION NUCLEAR SAFETY
STATION NUCLEAR SAFETY AND OPERATING COMMITTEE
SHIFT SUPERVISOR
TURBINE BUILDING
TECHNICAL SPECIFICATION
VIOLATION
VIRGINIA POWER ADMINISTRATIVE PROCEDURE
WORK ORDER
WORK REQUEST