ML18152A534
| ML18152A534 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 11/02/1992 |
| From: | Branch M, Fredrickson P, Tingen S, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A535 | List: |
| References | |
| 50-280-92-20, 50-281-92-20, NUDOCS 9211180143 | |
| Download: ML18152A534 (13) | |
See also: IR 05000280/1992020
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report Nos.:
50-280/92-20 and 50-281/92-20
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
e
Inspection Conducted:
September 5 through October 3, 1992
Inspectors:
Accompanying
Approved by:
M.~~i~dent Inspector
J.W~~t~or
c:::7
~
S. G. Ting~ent Inspector
Intrl~---,,
P. E. Fredrickson, Section Chief
Division of Reactor Projects
SUMMARY
Scope:
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Dat'e Sined
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Dati! Stgne
/.?'/30/P2
Date S1gned
This routine resident inspection was conducted on site in the area of
operations, maintenance, surveillance, quality verification, licensee event
review, and action on previous inspection items.
During the performance of
this inspection, the resident inspectors conducted review of the licensee's
backshifts or weekend operations on September 6, 7, 16, 26, 27 and October 1,
and 3.
Results:
In the operations area, the following items were noted:
The noise level in the control room has been reduced through a
modification to the Gaitronic system and the control room is much
quieter (paragraph 3.a).
9211180143 921102
ADDCK 05000280
8
2
Management's sensitivity to recent operator errors was noted.
A recent
increasing performance trend of operator errors indicates a low problem
identification threshold and appears to warrant the current level of
management attention in order to turn around this trend (paragraph 3.b).
In the maintenance/surveillance functional area, the following item was noted:
Communications between operations and I&C was considered good while
troubleshooting the Unit 1 rod control urgent failure alarm (paragraph
4.a).
In the safety assessment/quality verification area, the following items were
noted:
The post-trip review process clearly has a positive effect on the safe
return of the plant to power operation (paragraph 6).
The licensee identification of a steam flow scaling error during
special testing resulted in the correction of a safety issue associated
with steam flow trip setpoints that had gone unnoticed since a 1977
modification.
The safety significance of the issue was somewhat
mitigated since the actual setpoints, although not in accordance with TS
limits, were bound by the accident analysis.
The failure to satisfy the
TS limits for the steam flow setpoints was identified as a non-cited
violation (paragraph 7.a).
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
2.
- R. Allen, Supervisor, Operations
- W. Benthall, Supervisor, Licensing
R. Bilyeu, Licensing Engineer
H. Blake, Superintendent of Site Services
- B. Bryant, Licensing
R. Blount, Superintendent of Engineering
- H. Collar, Supervisor, Quality Assurance
- D. Christian, Assistant Station Manager
- J. Downs, Superintendent of Outage and Planning
D. Erickson, Superintendent of Radiation Protection
- R. Gwaltney, Superintendent of Maintenance
- M. Kansler, Station Manager
A. Meekins, Supervisor, Administrative Services
J. McCarthy, Superintendent of Operations
- R. MacManus, Supervisor, System Engineering
- A. Price, Assistant Station Manager
- R. Saunders, Assistant Vice President, Nuclear Operations
E. Smith, Site Quality Assurance Manager
- B. Stanley, Supervisor, Station Procedures
J. Swientoniewski, Supervisor, Station Nuclear Safety
G. Thompson, Supervisor, Maintenance Engineering
A. Wheeler, Shift Supervisor, Nuclear
NRC Personnel
- M. Branch, Senior Resident Inspector
- S. Tingen, Resident Inspector
- Attended Exit Interview
Other licensee employees contacted included control room operators,
shift technical advisors, shift supervisors and other plant personnel.
On September 11, the inspectors accompanied Dr. Thomas Murley, Director
of NRR, on a tour of the Surry facility. The major emphasis of the tour
was a familiarization of plant equipment vulnerability to internal
flooding that was identified during the NRC IPE review.
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
Plant Status
Unit 1 began the reporting period with the reactor at approximately 5% *
power with the main turbine off-line to repair a leaking transformer
bushing on the C station service transformer.
The main generator was
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reconnected to the grid on September 6, and the unit was at power at the
end of the inspection period, day 27 of continuous operation.
Unit 2 began the reporting period in power operation.
The unit was at
power at the end of the inspection period, day 77 of continuous
operation.
Both units periodically ramped power to allow cleaning of condenser
water boxes.
The water boxes were being clogged by hydroids and other
marine life.
3.
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 operations safety and
compliance with TSs and to maintain awareness of the overall operation
of the facility.
Instrumentation and ECCS lineups were periodically
reviewed from control room indication to assess operability. Frequent
plant tours were conducted to observe equipment status, 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.
Control Room Environment Improvement
b.
The gaitronics is utilized for colllllunications throughout the
plant. During the inspection period, the licensee modified the
operation of the gaitronics colllllunication system in order to
decrease the overall noise level in the control room.
Prior to
the modification, paging personnel over the gaitronics would be
broadcasted throughout the plant including the control room.
This
created a lot of unnecessary background noise in the control room.
The licensee modified the gaitronics so that paging of only
control room personnel would be heard in the control room.
This
resulted in a significantly decreased noise level in the control
room.
Operational Errors
On October 2, the inspectors met with the Surry Operations
Superintendent to discuss what appeared to be an increasing trend
in the number of operational errors.
Errors occurring during the
period September 14 through September 29 which resulted in
deviation reports were evaluated by the inspectors. The
inspectors discussed the following four station deviations with
the Superintendent:
-OR No. S-92-1514 - The lA CC heat exchanger was returned to
service with its CC side outlet valve (valve no. l-CC-583)
still closed. Procedure O-MOP-51.17 step 5.1.3 was signed
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off for valve l-CC-583 being open.
Another operator noticed
the error. Operations management discussed the error with
the operator and discussed the necessity to think about the
procedural instructions.
-DR No. S-92-1578 - The remote alarm cutout switch was found
in the silenced position which would prevent the control
room from receiving indications of an alarm condition on TS
heat trace circuits. The probable cause was human error by
operations or maintenance. A check showed that maintenance
had been performed two weeks previously but did not identify
the responsible department.
To correct this potential
problem, a check for the position of this switch has been
added to the operators' check list.
-DR No. S-92-1610 - The Unit 2 outside RS train was tagged
out for repair of the service water pump 1-SW-P-SB return
line. The operator closed MOV-SW-205C instead of
MOV-SW-205B for isolation purposes.
The on-shift RO
researched the prints, but the SRO did not independently
review the decision as required by the OPS guidelines. The
error was identified through the second check process prior
to release of work.
-DR No. S-92-1617 - The Unit 1 SRO and the shift supervisor
erroneously decided that opening~ particular valve
(l-CH-98) would bypass the boric acid filter.
The shift
supervisor decided it was not necessary to use the
maintenance procedure, l-HOP-8.27, Removal of Boric Acid
Filter from Service, to remove the filter from service .
. This alignment resulted in the flow from the B to the A BAST
and later in the shift a high level alarm in the A BAST was
received.
The error was realized and the correct valve
line-up was performed using the MOP.
While none of the events caused a serious safety concern, the
number of errors over the two week period seemed to indicate an
increasing trend in operational errors.
The concern was discussed
with the Operations Superintendent who indicated that operations
management had also noted the trend.
The inspectors confirmed
that meetings had been held with the shift supervisors and that
operations management was in the process of briefing all of the
shift personnel concerning these events and the trend.
Management's sensitivity to recent operator errors was noted by
the inspectors.
Recent performance trends denoting an increase in
operator errors indicate a low problem identification threshold
and appears to warrant the current level of management attention
in order to turnaround this trend.
The inspectors will continue
to follow the licensee's activities in this area .
4
c.
Evaluation of Opening in Charging Pump Cubicle Walls
While touring the auxiliary building, the inspectors noted that
the concrete walls that enclosed the charging pumps contained
unsealed penetrations. Several holes approximately six inches in
diameter and other openings existed around piping or ventilation
ducting that passed through the walls.
The inspectors reviewed
Chapter 10, Section 8, of the licensee's 10 CFR 50 Appendix R
Report and concluded that the charging pump cubicle concrete walls
were classified as non-rated fire barriers.
The issue of openings
in non-rated fire barriers was discussed in detail with the
licensee.
The inspection concluded that these openings were
acceptable, since the charging pump cubicle concrete walls were
not classified as fire rated boundaries, and an alternative means
of safe plant shutdown was available in the event of a fire in
this area.
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.
On October 2, a Unit 1 control rod urgent failure alarm occurred while
the inspectors were in the control room.
Upon receipt of the alarm
operators placed the rod control system in manual and entered a TS LCO
to restore the control rods to an operable status within the next two
hours or be in Hot Shutdown within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
The inspectors witnessed troubleshooting activities associated with
urgent failure alarm.
The troubleshooting was accomplished by l&C
technicians in accordance with IMP-C-EPCR-46, Maintenance of Rod Control
System, dated June 26, 1989, and WO 3800133273.
Troubleshooting
identified faults in the moveable-phase-control card and moveable-
firing-circuit card.
These cards were replaced and the urgent failure
alarm cleared.
The control rods were satisfactorily tested and the LCO
was exited. Testing of the control rods is further discussed in
paragraph 6.b.
The inspectors attended the prejob brief and reviewed
the completed work package and post-maintenance test requirements.
The
inspectors noted that col11llunications between operations and l&C was
good.
Also, the inspectors noted that there were operator aids in the
form of uncontrolled vendor drawings taped to the interior of the rod
control power cabinet doors.
The drawings were not used during these
troublshooting activities. A recent QA audit, 92-11, identified the use
of operator aids as inappropriate, and as a result, corrective actions
are scheduled to be implemented to remove and restrict the use of
operator aids.
Within the areas inspected, no violations were identified.
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5.
Surveillance Inspections (61726, 42700)
During the reporting period, the inspectors reviewed surveillance
activities to assure compliance with the appropriate procedure and TS
requirements.
The following surveillance activities were reviewed:
a.
Calibrations of Pressure Indicators
On September 27, the inspectors observed the partial calibration
of pressure indicator 2-CH-Pl-1104 which is the discharge pressure
indicator for boric acid transfer pump l-CH-P-2D.
The l&C
technicians were using procedure 2-IMP-CH-Pl-001, Charging System
ASME Section XI Pressure Indicator Calibrations, dated July 18,
1991.
The technicians took the as-found readings on this pressure
indicator. These readings were within the acceptable range for
the instrument, but at the high end.
The indicator was later
adjusted to the mid-range and another set of satisfactory as-left
readings were taken.
The inspectors later reviewed the
calibration documentation.
No discrepancies were identified.
b.
Unit 1 Rod Control System Testing
On October 2, the inspectors witnessed testing of the rod control
system in accordance with l-PT-6.0, Control Rod Partial Movement,
dated July 23, 1992. This testing was performed as a result of
maintenance on the rod control system that effected shutdown bank
B, and control rod banks Band D. In order to prove operability,
the affected control rods were moved 18 steps in and then back out
18 steps.
The inspectors witnessed the testing from the control
room.
No discrepancies were identified.
Within the areas inspected, no violations were identified.
6.
Review of Unit 1 Reactor Trip Report (40500)
VPAP-1404, Reactor Control, Revision 0, requires that a formal
report be prepared for each reactor trip. The purpose of the
report is to confirm the preliminary findings, and sulllllarize or
identify corrective actions associated with the reactor trip. The
report is required by YPAP-1404 to be approved by SNSOC within
thirty days following a reactor trip. The inspectors reviewed the
trip report, dated June 16, 1992, for the Unit 1 automatic reactor trip that occurred on May 7, 1992. This Unit 1 automatic reactor
trip was previously discussed in NRC IR 280,281/92-11.
The
inspectors noted that although the report was not approved by
SNSOC within thirty days, it was thorough and accurate.
Several items associated with the reactor trip were identified as
needing further review in the trip report. These items involved the
turbine driven AFW pump response time and emergency procedure guidance
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for ensuring adequate TS shutdown margin.
The inspectors reviewed the
licensee's actions to resolve these issues and concluded that the issues
were satisfactorily resolved or that the licensee was satisfactorily
pursuing this issues. The licensee's post-trip review process clearly
has a positive effect on the safe operation of the plant, in that
transient response characteristics were verified and the thoroughness of
the process was considered a strength.
Within the area inspected, no violations were identified.
7.
Licensee Event Review (92700)
The inspectors reviewed the LERs li~ted below and evaluated the adequacy
of corrective action. The inspector's review also included followup on
the licensee's implementation of corrective action.
a.
(Closed) URI 280,281/91-21-02 and LER 280,281/91-014, Steam Flow
Transmitter Scaling Errors. This issue involved the licensee's
discovery that TS limits associated with steam flow protection
setpoints were violated due to personnel errors associated with a
1977 modification that rescaled the steam flow instruments. The
initial discovery of this issue is documented in detail in NRC IR
50-280,281/91-21.
In that report the inspectors documented that
the licensee investigated the effect of the incorrectly scaled
steam flow transmitters on the overall accuracy of the steam flow
instrumentation and on reactor protection and ESF setpoints.
Midway through the investigation for Unit 2, the licensee
concluded that the Unit 1 MS flow transmitters were also
incorrectly scaled.
The licensee determined that the incorrectly
scaled transmitters affected the MS flow reactor protection and
ESF setpoints in a nonconservative direction. The magnitude of
this error was unknown, but the current settings were within the
limits of the safety analysis.
On July 22, 1991, the bias on each of the Unit 2 ESF MS flow
channels was adjusted to compensate for the nonconservative error
introduced by the improperly scaled transmitters.
On July 24,
1991, the bias on the Unit 1 ESF MS flow channels was adjusted for
the same reason. The magnitude of the ESF MS flow channel bias
adjustments was based on engineering judgment to ensure that the
settings were within the TS limits.
On July 24, 1991, as a result
of an investigation, the licensee concluded that prior to the
July 22, 1991, setting adjustments, the Unit 2 ESF high steam flow
setpoints exceeded the limits specified in TS, but were within the
design safety analysis.
The special flow measurements (ST-302) in 1991 that provided the
basis for the Unit 2 bias was not conducted for Unit 1.
At the
end of that inspection period documented in NRC IR 50-280,
281/91-21, the licensee was investigating the magnitude of the
error introduced by the incorrectly scaled steam flow transmitters
b.
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on the Unit 1 ESF setpoints. Since ST-302 was not performed on
Unit 1, in the interim, on July 26, 1991, the bias on each of the
Unit 1 ESF MS flow channels was adjusted based on the worst case
Unit 2 setpoints error.
The licensee also concluded that the
effect of the scaling error on the MS flow transmitters did not
adversely affect the low SG water level with a steam/feedwater
flow mismatch reactor trip circuitry.
To develop steam flow instrument setpoint scaling valves for Unit
1, the licensee conducted special testing during the 1992
scheduled refueling outage.
The inspectors reviewed the licensee
test results conducted on February 3, 27, 28 and 29, 1992.
The
testing was performed using the Combustion Engineering's CHEMTRAC
feedwater flow tracer process.
The results of the test were
reviewed by engineering, and calculations were performed to
translate the test results into instrument scaling and setpoint
changes.
The inspectors reviewed calculation EE-0419 which
assigned correction factors that were applied to the indicated
feed flow values.
The instrument accuracy was corrected by the
performance of the feed flow calibration PT which was revised
prior to accomplishment based on the new values provided by
engineering.
The inspectors consider the licensee actions
acceptable and this item is closed.
Since the LERs discussed above identified that the original
setpoints were nonconservative in respect to the TS required
values the licensee was in violation of TS 3.7.D.
The licensee
identification of the steam flow scaling error during special
testing resulted in the correction of a safety issue associated
with steam flow trip setpoints that had gone unnoticed since a
1977 modification.
The safety significance of the issue was
somewhat mitigated since the actual setpoints, although not in
accordance with TS limits, were bounded by the accident analysis.
This licensee identified violation (NCV 50-280,281/92-20-01) is
not being cited because criteria specified in Section VII.b of the
NRC Enforcement Policy were satisfied.
(Closed) LER 280/91-012, Pressurizer Level Channel Not Placed in
Trip Within Six Hours Due to Personnel Error. This issue involved
the failure to place pressurizer level indicator l-RC-Ll-1461 in
trip because its indicated value exceeded channel check acceptance
criteria specified in the surveillance procedure.
The TS allows
six hours to place the channel in trip.
The operations trainee
did not recognize that the value exceeded the acceptance criteria
and neither the reactor operator responsible for the surveillance
nor the shift supervisor reviewed the PT.
The reactor operator
was counseled on his responsibility for the accuracy of recorded
data and for the proper supervision of assigned trainees. Further
corrective actions taken included providing the description of the
event and lessons learned to the class of RO/SRO's that were being
trained at the time of the event and developing enhanced
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instructions for future classes. All of the corrective actions
have been implemented.
c.
(Closed) LER 280/91-009, Technical Specifications Surveillance
Requirements Violated for Inservice Inspection of Unit 1 Reactor
Vessel Due to a Cognitive Personnel Error.
This issue involved a
missed ASME Section XI ISi inspection. Unit 1 was at 100 percent
power on May 9, 1991, when the licensee discovered that a visual
inspection of the reactor vessel partial penetration welds and the
bottom of the reactor were not performed during the 1990 refueling
outage.
An administrative oversight, whereby the inspections were
inappropriately removed and not returned to the ISi plan, was
identified as the cause of the event. The intent of this test is
to monitor the reactor vessel integrity. Daily leak rates were
calculated for Unit 1 to ensure that TS allowed unidentified
leakage was not exceeded.
Containment air sampling was increased
from weekly to daily to assist in leak detection.
On January 8,
1992, during an unscheduled outage, the visual examination, VT-2,
was performed on the bottom of the reactor vessel and the partial
The inspectors examined the ISi program for
Unit 1 and noted that the visual examination had been returned to
the program.
d.
(Closed) LER 280/92-001, Dropped Rod Due to Personnel Error
Followed by a Required Manual Reactor Trip. This event occurred
after control rod E-5 dropped into the core.
(It was later
determined that its coil stack failed.)
As a result, trouble
shooting was performed.
The trouble shooting guide required the
removal of fuses.
One of the removed fuses was co11111on to the
movable coils of E-5 and H-2.
When the control rods were manually
stepped to control delta flux, H-2 dropped into the core because
its stationary coil deenergized and its movable coil did not
energize.
The reactor was manually tripped in accordance with
procedure. This event is discussed more fully in NRC IR
50-280,281/91-37.
The dropping of the second rod was attributed
to an inadequate trouble shooting guide procedure.
The licensee's
corrective action to prevent recurrence of this type of event
included changes to procedures and training.
An evaluation
sampling was performed of the corrective actions by reviewing
procedure changes and various training lesson plans. Corrective
actions that are not complete, such as some craft training and
development of a new electrical maintenance procedure for rod
control trouble shooting, are being tracked by the licensee's CTS.
Procedures reviewed were AP-1.01, Control Rod Misalignment, and
IMP-C-EPCR-46, Maintenance of Rod Control System.
Steps and
caution notes concerning ramification and actions required for
stepping control rods with control rod trouble shooting in process
were incorporated into these procedures.
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Lesson plans reviewed were TSMT-92.1-LP-l, TSCT-92-LP-1,
ECT-1-LP-8 and NITCTP-l-LP-14.
These lesson plans covered the
subjects of test controls, conduct of infrequently performed tasks
and root cause determinations, and included the above event, its
cause, and lessons learned.
Within the areas inspected, no violations were identified.
8.
Action on Previous Inspection Items (92701,92702)
a.
(Closed) VIO 280/91-37-01, Failure to Follow the Requiremenis of
10 CFR 50.SSa(g). This issue involved whether it was necessary
for the licensee to request that the Co11111ission grant relief for
the repair or return to service of a Class 2 letdown line with a
leaking weld.
The licensee denied the violation and, after
further NRC review, the subject violation was withdrawn.
The
licensee had concluded that it was not necessary to request NRC
relief based upon the Surry TS and an ASME Code Inquiry.
The NRC
is continuing to review the adequacy of this interpretation.
b.
(Closed) P21 280,281/91-06, Overspeed Trip Tappets For
Terry Steam Turbine Pump Drivers in AFW Systems. This issue
involved Terry turbines equipped with a molded head type tappet.
Under high temperature and humidity, parts of the tappet would
swell preventing the tappet from reseating following a trip of the
Terry turbine.
The inspectors reviewed the design of the turbine
driven AFW pumps overspeed trip tappets utilized at Surry and
concluded that they were not the molded head type discussed in
this notice.
The Surry turbine driven AFW pumps utilize the ball
type tappets.
9.
Exit Interview
The results were summarized on October 7, with those individuals
identified by an asterisk in Paragraph 1.
The following suRVnary of
inspection activity was discussed by the inspectors during this exit:
Item Number
NCV 280,281/92-20-01
VIO 280/91-37-01
P21 280,281/91-06
Status
Closed
Closed
Closed
Description
Failure to Satisify TS Limits
Associated with Steam Flow Setpoints
(para 7.a).
Failure to Follow the Require-
ments of 10 CFR 50.SSa(g)
(para. 8.a}.
Overspeed Trip Tappets For
Terry Steam Turbine Pump
Drivers in AFW Systems (para 8.b).
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URI 280,281/91-21-02
Closed
Steam Flow Transmitter Scaling
Errors (para 7.a).
LER 280,281/91-014
Closed
Steam Flow Transmitter Scaling
Errors (para 7.a).
Closed
Pressurizer Level Channel not Placed
in Trip Within Six Hours Due to
Personnel Error (para 7.b)
Closed
Technical Specifications Sur-
veillance Requirements Violated for
ISi of Unit 1 Reactor Vessel Due to
Cognitive Personnel Error
(para 7.c).
Closed
Dropped Rod Due to Personnel Error
Followed by a Required Manual Reactor Trip (para 7.d).
Proprietary information is not contained in this report. Dissenting comments
were not received from the licensee.
10.
Index of Acronyms and Initialisms
-
BAST
-
cc
CFR
DR
-
GL
IR
LCO
LER
MOP
MS
NRC
RS
SNSOC -
-
AMERICAN SOCIETY OF MECHANICAL ENGINEERS
BORIC ACID STORAGE TANK
COMPONENT COOLING
CODE OF FEDERAL REGULATIONS
COMMITMENT TRACKING SYSTEM
DEVIATION REPORT
ENGINEERED SAFETY FEATURES
GENERIC LETTER
INSTRUMENTATION AND CONTROL
INDEPENDENT PLANT EVALUATION
INSPECTION REPORT
LIMITING CONDITIONS OF OPERATION
LICENSEE EVENT REPORT
MAINTENANCE OPERATING PROCEDURE
HAIN STEAM
NONCITED VIOLATION
NUCLEAR REGULATORY COMMISSION
OFFICE OF NUCLEAR REACTOR REGULATION
OPERATIONS DEPARTMENT
PERIODIC TEST
QUALITY ASSURANCE
REACTOR OPERATOR
RECIRCULATION SPRAY
STATION NUCLEAR SAFETY AND OPERATING COMMITTEE
SIGNIFICANT OPERATING EVENT REPORT
.,
'
TS
VPAP -
SENIOR REACTOR OPERATOR
TECHNICAL SPECIFICATIONS
UNRESOLVED ITEM
VIOLATION
e
VIRGINIA POWER ADMINISTRATIVE PROCEDURE
WORK ORDER