ML18152A255
| ML18152A255 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 04/19/1994 |
| From: | Belisle G, Branch M, Tingen S, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A256 | List: |
| References | |
| 50-280-94-08, 50-280-94-8, 50-281-94-08, 50-281-94-8, NUDOCS 9405230037 | |
| Download: ML18152A255 (19) | |
See also: IR 05000280/1994008
Text
Licensee:
Docket Nos. :
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
50-280/94-08 and 50-281/94-08
Virginia Electric and Power Company
5000 Dominion Boulevard
Glen Allen, VA
23060
50-280 and 50-281
License Nos.:
Facility Name:
Surry 1 and 2
Inspection Conducted:
March 6 through April 2, 1994
Inspectors:
J.
s.
Approved by: ~- A. B lisle, Section Chief
Divisi
of Reactor Projects
SUMMARY
Scope:
4/,t{q~
Dategned
- l
- 112 /24-
Dae S-Ygned
4-J 1~/ 94-
Date(gned
This routine resident inspection was conducted on site in the areas of plant
status, operational safety verification, maintenance inspections, surveillance
inspections and Licensee Event Report followup.
Inspections of backshift,
holiday, and weekend activities were conducted on March 6, 8, 10, 13, 21 - 27,
30 and April 1, 1994.
Results:
Plant Operations functional area
The failure to open the Unit 1 B reactor coolant loop hot leg stop valve
within the 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> as required by technical specification 3.17.5.c was
identified as a violation (paragraph 3.c) .
9f25230037 940419
Pun
ADOCK ~5000280
G
.
- pDR
2
The Unit 1 reactor heatup and startup after the refueling outage were executed
in a professional manner with the appropriate amount of management oversight.
Additionally, the initial approach to criticality was cautious and attention
to detail and self-checking was evident {paragraphs 3.d and 3.e).
Maintenance functional area
The overtime worked by Virginia Power and contractor personnel during the Unit
1 refueling outage was within established guidelines {paragraph 3.g).
Although a satisfactory post maintenance test was performed after maintenance
on accumulator check valves, the testing referenced as the post maintenance
testing requirements was not considered a meaningful test due to the low flow
rate achieved (paragraph 5.a).
Engineering functional area
The change (PAR 94-210) to the procedure used to test the accumulator check
valves was defective and resulted in a water hammer to the reactor coolant and
safety injection system piping.
The defective procedure was identified as a
non-cited violation (paragraph 5.b).
Plant Support functional area
--
*
---n
--* ---
-
--
-* **
-
- -
Material was found in the containment sump after sump closure.
Foreign
material exclusion controls were ineffective and were identified as a weakness
{paragraph 3.b) .
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- W. Benthall, Supervisor, Licensing
- R. Bilyeu, Licensing Engineer
- M. Biron, Radiological Protection Engineer
H. Blake, Jr., Superintendent of Nuclear Site Services
- R. Blount, Superintendent of Maintenance
- M. Bowling, Manager, Nuclear Licensing and Programs
- 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. Fletcher, Assistant Superintendent of Engineering
- 8. Hayes, Supervisor, Quality Assurance
- M. Kansler, Station Manager
C. Luffman, Superintendent, Security
- J. McCarthy, Superintendent of Operations
- J. O'Hanlon, Vice President, Nuclear Operations
- A. Price, Assistant Station Manager
R. Saunders, Assistant Vice President, Nuclear Operations
- E. Smith, Site Quality Assurance Manager
T. Sowers, Superintendent of Engineering
J. Swientoniewski, Supervisor, Station Nuclear Safety
G. Woodzell, Nuclear Training
Other licensee employees contacted included plant managers and
supervisors, operators, engineers, technicians, mechanics, security
force members, and office personnel.
NRC Personnel
- M. Branch, Senior Resident Inspector
- S. Tingen, Resident Inspector
J. York, Resident Inspector
- A. Belisle, Section Chief
- Attended Exit Interview
- Participated in Exit Interview via telephone conference call
Acronyms and initialisms used throughout this report are listed in the
last paragraph .
2
2.
Pl ant Status
Unit 1 completed a planned refueling outage during the reporting period.
The Unit achieved criticality on March 24 and was placed online on March
26.
The Unit was at 100% power at the end of the period.
Unit 2 began the reporting period at 98% power and was at 96% power at
the end of the period.
Power level was reduced during the period in
order to minimize level oscillations in the C SG.
The level
oscillations were attributed to partially blocked quatrefoils in the SG
upper tube support plates.
3.
Operational Safety Verification (71707)
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.
Review of Unit 1 Core Map
b.
The inspectors reviewed the video map of the fuel pool where fuel
assemblies were temporarily stored prior to being loaded into the
Unit 1 core.
The video displayed fuel assembly, burnable poison,
and flux suppression rod identification numbers.
The inspectors
also reviewed the Nuclear Material Handling Report for Surry 1,
Cycle 13 core onload. This report identified the control,
burnable poison, and flux suppression rods to be installed in the
individual fuel assemblies.
The inspectors verified that the
correct control, burnable poison; or flux suppression rods were
installed in the applicable fuel assembly.
The inspectors also reviewed the video tape that displayed the
fuel assemblies after being loaded into the core.
The video
showed the fuel assembly identification number and location for
each fuel assembly loaded into the core.
The inspectors verified
that the fuel assemblies were loaded into the core as specified by
the Nuclear Material Handling Report.
No discrepancies were
identified.
Containment Walkdown and Sump Inspection
On March 10, while inspecting the containment sump area, the
inspectors noted a plastic mop handle lying between the trash
racks and the outside of the vertical screens. There was no
~====-~~=========~------------- ~ -----
c.
3
apparent work activity in progress in this area.
Further inquires
by the inspectors revealed that this was designated as an FME area
and that the final containment sump FME inspection and
installation of the circular screens and trash rack panels had
been performed on March 2.
The mechanical maintenance procedure 1-MPT-1205-01, Unit One
Containment Sump Inspection and Test Setup, dated December 30, _
1993, provided instructions for assembly and closure of the sump
with necessary controls to maintain the required TS cleanliness
and restoration criteria. The procedure contained QC hold points
for verifying sump cleanliness which were signed off after the
maintenance activity had been performed.
Through a review of the sequence of events associated with this
issue, the inspectors determined that after maintenance and QC
closed out the sump on March 2, the HP group had unlocked the high
radiation area gates in this area. They placed a sock over a
drain to the sump in order to contain radioactive material that
was flushed into the area from cleaning the fuel transfer canal.
This sock (that had greater than 1,000 R meter reading) was
handled with the mop handle.
Discussions with HP personnel
revealed that the mop handle had been left in the sump area until
it was determined whether another flush of the fuel transfer canal
would have to be conducted. This decision had not been made at
the time the inspectors discovered the mop handle.
There was no documentation of the HP group's reentry into the FME
area. During discussions between the inspectors and the licensee
it was pointed out that 1-GOP-1.1, Unit Startup, RCS Heatup From
Ambient To 195 F, contained an operator signoff that the
containment sump was clean and free of foreign material prior to
final containment closure. Attachment 3, Containment Readiness
Verification, has a step with a sign off that states, "Sump
troughs and the DA Sump are clear of debris and floor grating is
in pl ace."
The inspectors determined that for this specific case, the
provisions of the GOP procedure would have ensured that a final
walk down would have been performed in the area where the mop
handle was left. However, not maintaining formal FME controls of
an area after it has been verified clean appeared to be a weakness
in training or program controls. This issue was discussed in
detail with licensee management at the exit meeting.
Placing Unit 1 Loop B In Service
On March 1, 1994, Unit 1 RCS loop B was filled in accordance with
l-OP-RC-002, RCS Fill, revision 3, and the loop was declared full
at 8:40 a.m.
TS 3.17.5.c required that the loop B hot and cold
leg stop valves be fully opened within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after filling a
loop from the RCS.
Therefore, the Bloop stop valves were
4
required to be open by 10:40 a.~.
The cold leg loop stbp valve
was opened within two hours; however, the Bloop hot leg loop stop
valve was not opened until 10:50 a.m.
Operators were aware that
the Bloop stop valves had to be opened within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and were
tracking the time. Operations identified that a violation of TS 3.17.5.c occurred when the Bloop hot leg stop valve was not
opened within two hours and initiated a DR.
The inspectors
reviewed this event and concluded that the following factors
contributed to exceeding the two hour limit:
The SRO did not adequately manage the time allotted in the
two hour LCO.
The initial attempt to open the loop B stop
valves was made with only ten minutes remaining in the two
hour LCO.
Obtaining satisfactory boron samples delayed opening the
loop stop valves.
Procedure l-OP-RC-002 required boron
samples be obtained prior to opening the loop stop valves.
The procedure required that the boron concentration in the
loop be equal to or greater than RCS boron concentration.
Several sets of boron samples were obtained and the
concentration of boron in the loop was consistently 10 ppm
less than RCS concentration.
Resolution of this issue
delayed opening the loop stop valves.
TSs did not require
that boron samples be obtained .
Procedure l-OP-RC-002 did not provide detailed instructions
for opening the hot leg loop stop valve.
The cold leg loop
stop valve is interlocked to the hot leg loop stop valve
such that the cold leg stop valve must be shut before the
hot leg valve will open.
The cold leg loop stop valve was
not fully shut when the procedure directed that the hot leg
loop stop valve be opened; therefore, the hot leg valve did
not open on the initial try. Electricians were called and
jumpered the interlock to open the hot leg loop stop valve.
Procedure l~OP-RC-002 was subsequently changed to delete the boron
sample requirements and also was changed to shut the cold leg loop
stop valve prior to opening the hot leg loop stop valve.
The TS purpose for unisolating a loop within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after filling
the loop from the RCS is to prevent the addition of positive
reactivity to the core by means of cold water or diluted boron
concentration.
In a safety evaluation prepared by the licensee,
the licensee concluded that a loop startup at Cold Shutdown would
not result in an inadvertent criticality regardless of the
temperature differential between the loops.
At the time of the
event, fuel was being loaded into the reactor vessel,
approximately 32 fuel assemblies were installed, and the A and C
loops were isolated and drained.
In addition, boron samples
obtained approximately 20 minutes prior to unisolating the Bloop
indicated that RCS and loop B boron concentration were within 10 ppm.
5
The failure to open the Unit 1 Bloop hot leg stop valve within
2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after filling a loop from the RCS in accordance with TS 3.17.5.c was identified as VIO 50-280/94-08-0l, Failure To Open
The Unit 1 B Loop Hot Leg Stop Valve Within 2 Hours.
d.
Unit 1 RCS Heatup
On March 22 and 23 the inspectors witnessed the Unit 1 heatup from
250 degrees F and 320 psig to 430 degrees F and 650 psig.
Procedures utilized for the heatup were l-GOP-1.2, Unit Startup,
RCS Heatup From 195 to 345, revision 5, and l-GOP-1.3, Unit
Startup, RCS Heatup From 345 to HSD, revision 7.
The inspectors
verified that the following were performed during the heatup:
The heatup rate was controlled in accordance with TS Figure
3.1-1 and was less that 40 degrees F per hour.
The containment spray, outside recirculation spray, and
inside recirculation spray systems were place in service
prior to exceeding 350 degrees F and 450 psig in accordance
with TS 3.4.
The motor driven AFW pumps were placed in automatic start
and AFW MOVs were open prior to exceeding 350 degrees F and
450 psig in accordance with TS 3.6.
When RCS temperature exceeded 350 degrees F the PORV low
pressure lift settings were disabled and the PORVs placed
into operation in accordance with TS 3.1.G.
The inspectors concluded that the heatup was accomplished
utilizing good command and control. Procedures 1-GOP-1.2 and 1.3
were adhered to and these procedures appeared to work well in that
operators understood them and accomplished the individual steps as
required.
e.
Unit 1 Startup From Refueling
On March 24, the inspectors witnessed the Unit 1 startup and
withdrawal of control rods to achieve criticality. Procedure
1-0P-RX-006, Withdrawal of The Control Banks to Critical
Conditions, revision 0, controlled activities up to criticality.
After the reactor was critical, reactor power was controlled at
10-s amps.
At that point, reactor physics testing commenced as
directed by the Reactor Engineer.
. .
6
During the approach to criticality, the inspectors performed
independent 1/M multiplication determinations to ensure that
criticality would be achieved within the procedure requirements.
The inspectors noted that the approach to criticality was cautious
and RO attention to detail and self-checking was evident.
Additionally, two independent groups were monitoring the operators
approach to criticality and independently calculating criticality
prediction measurements.
On March 25, the inspectors monitored physics testing including
the rod swap method of determining rod bank worth.
When the
C control bank worth was measured, the value was outside the minus
15% tolerance specified in the procedure.
The C control bank
worth was remeasured and again it was less than predicted by
approximately 15.7%. A DR was written and by procedure,
engineering and SNSOC were required to review the data prior to
increasing reactor power.
The inspectors attended the SNSOC
meeting in which the issue was discussed.
The SNSOC review was
thorough, and it was determined after discussions with NAF that
the most likely cause of the deviation of measured bank worth from
that predicted was the core model itself.
SNSOC also determined
that it was acceptable to increase reactor to< 30% so that the
in-core flux map could be performed.
NAF determined that the 30%
flux map would verify that no rods were unlatched and that no core
anomalies existed.
The flux map taken at 28.1% reactor power on March 26, was
analyzed by NAF and it was concluded that power distribution, hot
channel factors, control rod alignment, etc., were normal.
Within the areas inspected, one violation was identified.
4.
Maintenance Inspections (62703)
During the reporting period, the inspectors reviewed the following
maintenance activities to assure compliance with the appropriate
procedures.
-
a.
Rework on the Unit 1 Reactor Head Venting Subsystem
During this outage, the licensee replaced the inboard reactor head
vent valves, valve nos. 1-RC-SOV-100-Al and Bl, and repaired the
two outboard reactor head vent valves, valve nos. 1-RC-SOV-100-A2
and B2.
These valves are normally shut when the unit is at power
and a small amount of leakage through these valves has occurred
during past operations.
Work order nos. 00277612-02 and
00277614-02 were used by the mechanical maintenance group to
perform the work.
Mechanical corrective maintenance procedure
O-MCM-0409-01, Target Rock Model 79AB-008 Solenoid Operated Valve
Overhaul, dated January 25, 1994, was used for repairing the two
outboard valves.
The inspectors discussed repairing the two
valves with the system engineer and reviewed the maintenance
7
activity documentation.
No discrepancies were identified.
b.
Unit 1 Pressurizer PORVs
The inspectors reviewed WO nos. 00269833-01, 00267643-01,
00274963-01, and 00269799-01 that were used to repair the PORVs.
Maintenance personnel installed new diaphragms, replaced gaskets,
checked packing, replaced or lapped the valve seats, checked the
contact areas with a blue test, and checked the stroke and lift
points.
The inspectors reviewed the installation of new relief valves
1-IA-RV-114 and 115.
DCP 92-043, Pressurizer Safety Valve and
Loop Seal Modification/Surry/Unit 1, dated August 27, 1993,
covered installing the new relief valves. These valves were
installed specifically to protect the PORV air domes from
overpressure if the bottled air system pressure regulator should
fail. The inspectors also reviewed results for setting the lift
pressure for these two relief valves.
No deviations were
identified.
c.
Unit 1 Rod Control System Repairs
__________________________ :As noted in NRC Inspection Report Nos. 50-280, 281/94-02, rod
control card failures affected system reliability. During this
RFO, the licensee made a concerted effort to improve system
reliability through card replacement and refurbishment.
Rod
control improvements were performed per PM procedure
O-IPM~RD-CAB-002, Cleaning and Inspection of Rod Control Cabinets,
---dated January 21, 1994, and a WO written to cover each cabinet.
The repairs included replacing all 20 firing cards. The
inspectors noted that these cards were severely degraded and heat
damaged.
Additionally, the phase control, regulating circuit and
- failure detector cards were inspected. The inspection of these
-rod control cards identified several loose solder connections and
-
_____ ::..,.:. __ -=-.:.. -=.C.---~~-'--::_-_--*aamaged components.
The cards were refurbished and reinstalled in
-the cabinets.
The loose solder connections were described by the I&C personnel
as being typical of defective cards produced by the vendor during
the 1980s and early 1990s.
The I&C personnel stated that as part
of the printed circuit board (card) production process, a form of
"wave soldering" was used to connect the individual components to
the printed circuit boards. The boards with the components
loosely attached were passed over a vat of molten solder and flux
solution at a controlled pace by a belt.
An agitating device in
the vat caused a wave of solder and flux solution to contact the
connections and form the bond.
Process variables such as
temperature, time, speed were difficult to control and resulted in
.cold soldered connections.
Cold soldered connections come loose
after time and movement and can result in card failure.
-*
d.
e.
8
Subsequent to the above repairs, several refurbished cards failed
upon initial energizing and during the Rod Control System PMT.
After the initial failures were repaired, the Rod Control System
performed without problems during the many rod movements
associated with physics testing. The licensee plans similar
repairs to the Unit 2 Rod Control System during the next RFO.
C CCHX Replacement
The inspectors monitored activities associated with removing and
replacing the C CCHX.
This was the last of the four CCHX to be
replaced by a heat exchanger with titanium tube material. The
original heat exchangers contained many plugged copper-nickel
tubes that failed due to the river water environment.
The CCHXs
were replaced using DCP 87-29, Component Cooling Heat Exchanger
Replacement.
The inspectors witnessed portions of the heat
exchanger rigging evolution and FME controls that were invoked for
open systems.
No problems were noted and the rigging and FME
controls were found acceptable.
Unit 1 B Reactor Coolant Pump Vibrations
The inspectors observed RCP 1-B being started from the control
room.
When the RCP was started on March 18, shaft vibrations
exceeded the alert level on the Bently-Nevada RCP vibration
monitor.
The alert limit is 15 mils and the danger limit is 20
mils.
With shaft vibration approximately 15 mils the operator
stopped the RCP.
The inspectors held discussions with maintenance personnel and
determined that during the present RFO the motor from the C pump
was installed on the B pump.
The licensee's review indicated that
there was a question as to the status of the balancing weights on
the coupling.
The existing weights were removed from the coupling
to establish a known condition for balancing. Several attempts to
balance the pump were unsuccessful and the data provided by the
keyphasor (reference) probe was questioned.
On March 22, the reference mark on the coupling which the
keyphasor probe monitors was ground deeper.
The keyphasor probe
was adjusted to provide a stronger reference signal and the B RCP
was restarted. The vibration readings obtained were analyzed by
the vendor representative and information was provided to the
craft as to where to place the balance weights. Several
additional runs of the RCP were necessary to complete the
balancing and the as-left readings were approximately 10 mils
vibration on the shaft and approximately 1.0 mil on the frame.
The vendor concurred that the readings obtained were acceptable.
The inspectors considered the licensee's control of vendor
activities acceptable.
However, the lack of detailed knowledge of
the vibration monitoring equipment by licensee personnel delayed
f.
9
balancing the RCP and contributed to a higher than usual number of
starts and stops of the RCP.
Coating Flaking Examination on Unit 1 HVAC
In 1977 the licensee made a design change (DC 77-32) which was
used to add ventilation ductwork to the containments. This
modification was made for both units. During later outages,
coating inspections on Unit 1 revealed areas of blistering and
delamination. These modified HVAC areas in Unit 2 only had a few
areas of blistering and delamination.
The inspectors reviewed EWR 88-517 which evaluated the potential
for transporting peeling paint from containment ductwork into the
containment sump and blocking the sump screens during a LOCA.
The
dynamic analysis showed that the floor water velocity was not
enough to transport the paint chips to the sump screens.
As part
of this engineering analysis, the coating was visually examined
and it was revealed that only the epoxy topcoat was flaking and
that the zinc primer coat remained intact. The analysis indicated
that an improper cure time of the primer coating would cause this
type of failure. It was recommended that engineering personnel
inspect the ducts during outages and have the blistered paint
_removed.
_ _ ______ _
The inspectors accompanied the licensee during the walkdown of
Unit 1 containment HVAC ductwork to ensure that no excessive
amount of loose or flaking epoxy topcoat was present. The
inspectors, in conjunction with licensee personnel, performed a
visual inspection of most of the coating on the ducts. The amount
of areas that had flaked paint varied from duct to duct. Only an
occasional, small nonadhering edge was noted.
The licensee
performed an inspection of these ducts shortly after the unit was
shutdown and any loose pieces were removed.
The inspector
concluded that the licensee had performed an adequate job in
removing the loose particles.
g.
Overtime Usage During Refueling Outages
TS 6.8.10 requires that procedures be established to insure that
the NRC policy statement guidelines regarding working hours
established for employees are followed.
This TS also requires
_documentation of authorized deviations from-those guidelines and
that the documentation be available for NRC review. Station
administrative procedure VPAP-0103, Working Hours And Limitations,
revision 3, implements TS 6.8.10. For station personnel
performing safety-related activities, VPAP-0103 step 6.5 requires
overtime hours (excluding shift turnover time) in excess of 16
hours, 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in any 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period, 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />
period, and 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any 7 day period be approved by the
Station Manager and documented on Attachment 1, Request To Exceed
Overtime Hours.
Non-station personnel must adhere to their
10
department's overtime policies and obtain verbal approval from
their department superintendent, director or manager before
working more than 50 hours5.787037e-4 days <br />0.0139 hours <br />8.267196e-5 weeks <br />1.9025e-5 months <br /> per week.
These procedural
requirements were consistent with the NRC guidelines contained in
GL 82-16, NUREG-0737 Technical Specifications, and GL 82-12,
Nuclear Power Plant Staff Working Hours.
By letter dated
March 1, 1983, the NRC informed the licensee that TS 6.B.10
complied with the requirements of GL 82-16.
The inspectors reviewed records and available information to
determine if excessive overtime was routinely being utilized at
the site. For VEPCO employees, the licensee provided the
following information for the period January 1 through March 12,
1994:
Work
Percent
Max. Actual
Avg. Actual
Group
Overtime
Hrs/wk/person
Hrs/wk/person
Mechanical
29.5
31
25
Maintenance
El ectri ca 1
27.0
28
24
Maintenance
**- ---*----- *-***-*- -----
-
- ----- ----
-
Radiation
22.7
18
17
Protection
Operations
19.7
17
18
JSI/NDE
8.5
14
9
Engineering
2.2
4
I
-
To focus on overtime utilization during the present Unit I
refueling outage, three weeks of work hour information for
_
approximately 660 licensee employees were reviewed by the
----:-----=--*inspectors.
The weeks reviewed were, January 23 - 29,
--February 13 - 19, and February 20 - 26, 1994, designated week I,
week 2, and week 3 respectively.
In general, most employees
directly involved in outage activities, were working between 60
and 65 hours7.523148e-4 days <br />0.0181 hours <br />1.074735e-4 weeks <br />2.47325e-5 months <br /> a week on a six day/IO hours per day or
five day/12 hours per day work schedule.
For weeks I, 2, and 3,
the number of personnel working 65 to 69 hours7.986111e-4 days <br />0.0192 hours <br />1.140873e-4 weeks <br />2.62545e-5 months <br /> were 29, 28, and
26, respectively; 70 to 74 hours8.564815e-4 days <br />0.0206 hours <br />1.223545e-4 weeks <br />2.8157e-5 months <br /> were 30, 32, and 32,
respectively; 75 to 79 were 13, 9, and 19, respectively; and 80 to
84 were O, 0, and 4, respectively. That is, approximately 10 to
12% of the licensee's workforce worked 65 or more hours per week.
From this data and from completed VPAP-0103 Attachment I forms, 49
employees who had worked at some time in excess of the guidelines
were selected for additional analyses for the period January 23
through March 5, 1994. This period covered the beginning of the
Unit 1 outage until the end of the pay period immediately
11
preceding this inspection.
The personnel selected represented
various functions, i.e., operations, mechanical maintenance,
electrical maintenance, instrumentation and control, nuclear
material control, health physics, and engineering.
The sample
included both salaried and non-salaried personnel.
In this sample
there were 25 examples, approximately 50%, in which VPAP-0103
Attachment 1 forms had been approved in anticipation of exceeding
the guidelines; however, work records indicated the guidelines
were not exceeded.
The inspectors identified only three examples
in which personnel were authorized to exceed the guidelines in two
or more consecutive seven-day periods. Since no QA personnel were
involved in the sample, the inspectors discussed overtime
utilization by QA personnel with the Manager QA - Surry.
He
indicated that, as of March 17, 1994, he had authorized no
personnel to exceed the guidelines contained in VPAP-0103. *
Based upon these inspection activities, involving the review of
over 2,000 individual records, the inspectors determined that
licensee personnel were not routinely working excessive overtime.
Contractor overtime utilization during the outage was also
reviewed.
Work hour information involving approximately 525
contract personnel for two consecutive weeks, February 13 - 19 and
February _20 -._26, 1994_, .designated week 4 and week 5 respectively,
were reviewed.
For weeks 4 and 5, the number of personnel working
65 to 69 hours7.986111e-4 days <br />0.0192 hours <br />1.140873e-4 weeks <br />2.62545e-5 months <br /> were 21 and 15, respectively; 70 to 74 hours8.564815e-4 days <br />0.0206 hours <br />1.223545e-4 weeks <br />2.8157e-5 months <br /> were
25 and 24, respectively; and 75 to 79 hours9.143519e-4 days <br />0.0219 hours <br />1.306217e-4 weeks <br />3.00595e-5 months <br /> were 2 and 4,
respectively.
No individual worked more than 78 hours9.027778e-4 days <br />0.0217 hours <br />1.289683e-4 weeks <br />2.9679e-5 months <br /> per week in
this two week sample. That is, approximately 8 to 10 % of the
contractor workforce worked 65 or more hours per week.
From the
group that worked more than 65 hours7.523148e-4 days <br />0.0181 hours <br />1.074735e-4 weeks <br />2.47325e-5 months <br /> in one week, information for
34 contractors were examined in additional detail to determine the
daily work hour distribution. The sample included electricians,
ironworkers, welders, mechanics, valve technicians, sheetmetal
workers, insulators, painters, and lead personnel associated with
these groups.
Personnel in this sample worked between 120 and 150
hours in the two we*ek period with 13 contractors working 10 or*
more days consecutively. Records for 15 of the 34 contractors for
the subsequent week were randomly chosen to be reviewed.
The
three weeks of data for these 15 contractors revealed 2 additional
people who had worked greater than 10 days in a row.
Two
individuals, a crane mechanic and a crane supervisor, that were
previously identified as working more than 10 consecutive days
were determined to have worked at least 18 and 19 days in a row
without a day off. This was discussed with plant management.
The inspectors determined that contractor personnel were not
routinely working excessive overtime and that the overtime worked
was within established guidelines.
A review of 100 Attachment 1 forms revealed that 10 of the forms
had approval signatures dated two weeks or later than the end of
12
the time period that involved the overtime. Since verbal
approvals were sometimes obtained during nights and weekends with
the Attachments 1 subsequently completed, the inspectors were
unable to determine whether these examples represented a failure
to approve the overtime prior to its performance or reflected only
a documentation problem.
These examples were provided to the
licensee for additional review as warranted. A computer printout
was routinely provided to management to identify station personnel
that exceed the administrative limits provided in VPAP-0103.
Administrative services personnel reviewed this printout and
verified that Attachment 1 forms have been received by
Administrative Services.
When discrepancies were identified,
actions were taken to obtain the required documentation.
Within the last two years, QA performed audit no. 92-11 that
addressed Operations' overtime compliance with VPAP-0103.
The
audit report concluded that Operations personnel had received
prior approval from the Station Manager before exceeding the
limits in VPAP-0103.
One example, considered an isolated case,
was identified in which the overtime form was approved by the
Station Manager after the overtime was worked.
The audit report
also stated that substantial progress had been made by the
Operations Department in obtaining approval prior to working
overtime.
Within the areas inspected, no violations or deviations 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.
a.
Partial Stroke Testing of Accumulator Check Valves
On March 22 the inspectors witnessed the performance of 1-PT-18.3,
Refueling Testing of Accumulators Check -valves and MOVs,
revision 1.
The purpose of this procedure was to partially stroke
the accumulator check valves and verify local and remote positions
and ERFCS indications for the accumulator MOVs.
The inspectors
witnessed the test from the control room.
The accumulators were pressurized to 650 psig and RCS pressure was
reduced until level in each accumulator decreased the required
amount.
Each accumulator discharge MOV was shut after level in
the respective accumulator decreased the required amount.
Level
in the B accumulator only dropped four percent and DR S-94-0740
was written. The inspectors reviewed the DR response which stated
that a four percent drop was acceptable.
Procedure 1-PT-18.3 was
revised to accept a four percent level decrease for one time only.
The inspectors noted that after level initially started to
13
decrease it took approximately thirty to forty minutes for level
to decrease four to five percent in each accumulator.
The
inspectors were informed that one percent of level in each
accumulator corresponds to an approximate volume of 24 gallons.
The accumulator check valves are 12 inches in diameter.
The
inspectors calculated that the flow rate through each check valve
was approximately three to four GPM during the test. The
inspectors concluded that a three to four GPM flow rate through a
12 inch check valve was not a meaningful partial stroke test due
to the low flow rate.
The accumulator check valves were full stroked tested utilizing
non-intrusive acoustic test equipment at the beginning of the RFD.
The Band C accumulator check valves were subsequently
disassembled and reassembled during the RFD.
The check valves'
discs were manually stroked during this maintenance.
If no
practical means exists to partial stroke test the valves, then
this manually stroking was an acceptable PMT.
GL 89-04, Guidance
on Developing Acceptable Inservice Testing Programs, states that,
if possible, check valves should be partial stroked following
reassembly.
At the end of the inspection period the licensee was
reevaluating this test. Options to enhance test performance and
the practicality of performing accumulator check valve partial
stroke testing were being reviewed.
b.
Close Test of Accumulator Discharge Check Valves
Procedure l-OPT-SI-010, Close Testing of Accumulator Discharge
Check Valves, revision 1, provides instructions to test the
backflow seat tightness of the two check valves in the flow path
between each accumulator and RCS cold leg. This test, was
performed on March 23 and the backflow leakage through two check
valves, l-Sl-130 and l-SI-147, Band C accumulators, respectively,
was measured at greater than 5 gpm.
The test was performed at 950
psig RCS pressure.
Based on the above tests results, the licensee decided to retest
the failed valves at a higher pressure.
Procedure l~OPT-SI-010
was changed by PAR 94-210 to test accumulator Band C check valves
at normal operating pressure.
At 2250 psig, the valves were
retested by closing the discharge MDV and measuring leakage
between the two series check valves through a test line. This
test depressurized and partially drained the piping between the
two check valves. Seat leakage test indicated that the check
valve closest to the RCS loop was seated with O flow indicated.
After completing the C accumulator check valve test, the
C accumulator isolation valve, l-SI-MOV-1865C, was reopened
according to procedure and the following was observed:
The C SI accumulator level dropped approximately 25%.
' ...
14
The 1-C RCP oil reservoir hi-lo level annunciator (B-F-7) came in and locked in.
All 3 channels of C loop low flows came in and cleared.
The 1-C RCP frame alert and danger annunciators came in and
cleared when reset.
Vibration/thud was felt in TSC and reported to the operator.
DR S-94-0755 was written to document the occurrence and the
licensee's engineering walkdown of the piping and supports did not
identify any damage.
The inspectors reviewed the operator logs and procedure, which had
been changed to retest the check valves.
The inspectors noted
that PAR 94-210, that had been approved by SNSOC prior to use,
deleted a caution from the test. The deleted caution read, "The
accumulators MOVs must be slowly jogged open in order to prevent a
possible hydraulic shock with consequent damage to system piping."
Also the procedure step to open 1-SI-MOV-1865C was changed from
"Slowly open 1-SI-MOV-1865C by jogging the control switch", to
"Open 1-SI-MOV-1865C and de-energize the valve motor operator".
In reviewing .the event., . the 1 i censee determined that a very ..
similar event had occurred on Unit 2 during the same test and the
procedure caution was to prevent recurrence.
TS 6.4.A.2 and section 17.2.5 of the QA Program Topical Report
VEP-1-5A Amendment 5 (updated 6/92) requires that technically
adequate procedures be developed and implemented as required by
Regulatory Guide 1.33, QA Program Requirements.
Regulatory Guide
1.33 invokes ANSI NlS.7-1976, Administrative Controls and Quality
Assurance for the operational phase of nuclear power plants.
Section 5.3.2(5) of ANSI NlS.7-1976 requires that procedures
contain precautions to alert individuals performing the task to
those important measures which should be used to protect equipment
and personnel.
The SNSOC approved procedure change initiated by
PAR 94-210, deleted necessary precautions which resulted in an
inadequate procedure being used and could have resulted in
equipment damage.
This was identified as NCV 50-280/94-08-02,
Inadequate Procedure Associated with Accumulator Check Valve
Testing.
The licensee initiated a root cause analysis to
identified actions to preclude recurrence. This violation will
not be subject to enforcement action because the licensee's
efforts in identifying and correcting the violation meets the
criteria specified in Section VII.B of the Enforcement Policy.
Within the areas inspected, one NCV was identified.
---------------=~----------------
__ ,_______._.:.-~-------------------------------
.
- 6.
15
Licensee Event Report Followup (92700)
The inspectors reviewed the LERs listed below and evaluated the adequacy
of the corrective action.
The inspectors' review also included followup
of the licensee's corrective action implementation.
a.
(Closed) LER 50-280/93-002, Unit 1 Reactor Trip During Reactor
Protection System Surveillance Testing.
On February 9, 1993, a
Unit 1 reactor trip occurred due to the failure of the
A reactor trip breaker shunt trip relay during a surveillance
test. The reactor trip and the subsequent corrective actions to
restart the unit were discussed in NRC Inspection Report Nos.
50-280, 281/93-05.
In order to prevent recurrence,
a failure
analysis for the failed relay was performed and an engineering
evaluation was performed to identify single point relay failures
that could result in reactor trips. The inspectors reviewed the
failure analysis, RCE 93-03, for the failed relay. The failure
analysis was performed by the relay vendor.
The vendor concluded
that one of the relay coils was not properly insulated during the
manufacturing process which resulted in a short in the coil and a
premature relay failure.
The inspectors reviewed the Level 1 for
engineering to evaluate the reactor protection, safeguards, and
CLS logic to identify where single mode relay failures would
result in a reactor trip. The Level 1 engineering study
identified eight relays in each unit that would result in a
reactor trip if the relay failed.
The Level 1 recommended that
these relays be replaced every third RFO.
The station manager
directed that these relays be replaced ever other RFO and that the
relays be inspected during the alternate RFO.
The inspectors
reviewed the PM program and verified that the relays were
scheduled to be replaced or inspected every RFO.
Many of the Unit
1 relays were replaced during the current RFO.
b.
(Closed) LER 50-280, 281/93-006, SW Flow Path to Main Control Room
Chillers Inoperable Due to Pipe Leak.
This issue involved a
failure of strainer 1-VS-S-lA due to a leak in the strainers
backwash line. The-failed strainer resulted in an inoperable SW
flow path which resulted in entry into a six-hour LCO to HSD in
accordance with TS 3.0.1. The strainer was bypassed and the
six-hour LCO was exited.
As corrective action the strainer and
backwash line were replaced. This maintenance was inspected and
discussed in paragraph 4.a of NRC Inspection Report Nos. 50-280,
281/93-13.
c.
(Closed) LER 50-281/92-10, Relay Failure Results in Unplanned
Automatic Start of Turbine-Driven AFW Pump.
This issue involved
the unplanned start of the Unit 2 turbine drive AFW pump due to
the failure of a relay in the B train of the AFW auto start
circuit. The relay was replaced and satisfactorily tested on the
following day.
As corrective action the licensee performed CDE
131670 in order to determine why the relay failed. The CDE,
reviewed by the inspectors, concluded that the relay was original
..
16
installation and failed due to ageing.
The relay in the A train
turbine driven AFW pump auto start circuit was replaced and the
corresponding train A and B relays in Unit 1 were replaced.
Within the areas inspected, no violations or deviations were identified.
7.
Exit Interview
The inspection scope and findings were summarized on April 6, 1994, with
those persons indicated in paragraph 1.
The inspectors described the
areas inspected and discussed in detail the inspection results addressed
in the Summary section and those listed below.
I:ll!g Item Number
50-280/94-08-01
50-280/94-08-02
LER
50-280/93-002
LER
50-280, 281/93-006 LER
50-281/92-10
Status
Open
Closed
Closed
Closed
Closed
Description/{Paraqraph No.)
Failure to Open the Unit 1 B
Loop Hot Leg Stop Valve Within
2 Hours (paragraph 3.b).
Inadequate Procedure
Associated with Accumulator
Check Valve Testing
(paragraph 5.b)
Unit 1 Reactor Trip During
Surveillance Testing
(paragraph 6.a).
SW Flow Path to Main Control
Room Chillers Inoperable Due
to Pipe Leak (paragraph 6.b).
Relay Failure Results in
Unplanned Automatic Start of
Turbine-Driven AFW Pump
(paragraph -6.c).
Proprietary information is not contained in this report. Dissenting
comments were not received from the licensee.
8.
Index of Acronyms and Initialisms
ANSI
AMERICAN NATIONAL STANDARDS INSTITUTE
CCHX
COMPONENT COOLING HEAT EXCHANGER
CAUSE DETERMINATION EVALUATION
CLS
CONSEQUENT LIMITING SAFEGUARDS
DRAINS AERATED
DESIGN CHANGE PACKAGE
DR
DEFICIENCY REPORT
ERFCS
F
GL
GPM
HSD
l&C
IR
ISI/NDE
LCO
LER
NAF
NRC
R
SNSOC
TS
EMERGENCY RESPONSE FACILITY COMPUTER SYSTEM
ENGINEERING WORK REQUEST
FAHRENHEIT
GENERIC LETTER
GENERAL OPERATING PROCEDURE
GALLONS PER MINUTE
HEALTH PHYSICS
HOT SHUTDOWN
HEATING VENTILATION AND AIR CONDITIONING
INSTRUMENTATION AND CONTROL
INSPECTION REPORT
INSERVICE INSPECTION/NON DESTRUCTIVE EXAMINATION
LIMITING CONDITION FOR OPERATION
LICENSEE EVENT REPORT
LOSS OF COOLANT ACCIDENT
MOTOR OPERATED VALVE
NUCLEAR ANALYSIS AND FUELS
NON-CITED VIOLATION
NUCLEAR REGULATORY COMMISSION
PREVENTIVE MAINTENANCE
POST MAINTENANCE TESTING
POWER OPERATED RELIEF VALVE
PARTS PER MILLION
POUNDS PER SQUARE INCH GAGE
QUALITY ASSURANCE
QUALITY CONTROL
RADIATION EQUIVALENT MAN
ROOT CAUSE EVALUATION
REACTOR COOLANT PUMP
REFUELING OUTAGE
REACTOR OPERATOR
SAFETY INJECTION
STATION NUCLEAR SAFETY OPERATING COMMITTEE
SENIOR REACTOR OPERATOR
TECHNICAL SPECIFICATION
VIRGINIA ELECTRIC AND POWER COMPANY
VIOLATION
WORK ORDER