ML14181A642
| ML14181A642 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 12/29/1994 |
| From: | Christensen H, William Orders NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML14181A640 | List: |
| References | |
| 50-261-94-27, NUDOCS 9501110459 | |
| Download: ML14181A642 (25) | |
See also: IR 05000261/1994027
Text
VRGo
UNITED STATES
0
NUCLEAR REGULATORY COMMISSION
REGION II
0
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
Report No.:
50-261/94-27
Licensee:
Carolina Power and Light Company
P. 0. Box 1551
Raleigh, NC 27602
Docket No.:
50-261
-
License No.: DPR-23
Facility Name: H. B. Robinson Unit 2
Inspection Conducte
Oct ber 23 - December 3, 1994
Lead Inspector: ;
A
-__------------
/2 2J
/
T. Orders, Senior Resident Ingpector
Date S gned
Accompanying Inspectors:
C. R. Ogle, Resident Inspector
J. L. Starefos, Project Engineer
A. W. Salyers, Region II Inspector
Approved by:
_______________
/ Z44f
C
.'Cpristensen, Chief
Dat Si ned
Reactor Projects Section 1A
Division of Reactor Projects
SUMMARY
SCOPE:
This routine, unannounced inspection was conducted in the areas of operational
safety verification, surveillance observation, maintenance observation, plant
safety review committee activities, emergency preparedness assessment, and
followup of previously identified items. The inspection effort included
reviews of activities during non-regular work hours on October 31,
November 1, 2, 7, 8, 15, 16, and 22.
RESULTS:
In the area of Plant Operations, one violation was identified which deals with
the mispositioning of the control switch for one of the control room
ventilation fans. This configuration control issue was caused by operator
inattention to detail which led to his failing to follow the requisites of a
surveillance procedure and resulted in the system being degraded. The system
remained degraded for four days even though the control room panels were
walked down by operators once per hour during the four day period. Operator
failure to follow procedure and inattention to detail are chronic problems.
9501110459 941229
PDR ADOCK 05000261
0
2
In the area of Maintenance, one violation, three non-cited violations, and two
unresolved items were identified. The violation deals with inadequacies
associated with the licensee's power range calorimetric program, specifically
with calibration of instrumentation, control of assumptions and assessment of
errors. One of the non-cited violations concerns the licensee's failure to
adequately test redundant series mounted control room ventilation system
dampers. The second non-cited violation concerns inadequacies identified in
the procedure employed by the licensee to calibrate a component cooling water
transmitter. The third non-cited violation deals with the licensee's failure
to have a procedure to facilitate maintenance on safety-related auxiliary
feedwater flow control valves. The first unresolved item concerns the use of
unqualified oil in safety related equipment. The second unresolved item
concerns the resolution of feedwater nozzle performance
In the area of Engineering, one non-cited violation was identified which deals
with the licensee's failure to control the modification of the main control
room panels.
In the area of Plant Support, one unresolved item was identified involving the
modification of the TSC/EOF building and the resultant effect on the
ventilation system.
The licensee conducted an annual emergency preparedness exercise on
November 15, 1994. No exercises weakness, violations or deviations were
identified.
A representative from the Boise Interagency Fire Center visited Robinson on
November 30, 1994, as part of a contract to provide the NRC emergency
communications equipment should the need arise.
The objective of the site
visit was to collect logistics information for preplanning purposes.
REPORT DETAILS
1.
PERSONS CONTACTED
Licensee Employees:
W. Brand, Supervisor, Environmental Radiation Control
M. Brown, Manager, Design Engineering
- A. Carley, Manager, Site Communications
- B. Clark, Manager, Maintenance
- D. Crook, Licensing/Regulatory Programs
C. Gray, Manager, Materials and Contract Services
D. Gudger, Licensing/Regulatory Programs
- S. Hinnant, Vice President, Robinson Nuclear Project
- P. Jenny, Manager, Emergency Preparedness
- K. Jury, Manager, Licensing/Regulatory Programs
J. Kozyra, Licensing/Regulatory Programs
- R. Krich, Manager, Regulatory Affairs
- B. Meyer, Manager, Operations
D. Taylor, Plant Controller
G. Walters, Manager, Support Training
- R. Warden, Manager, Plant Support Nuclear Assessment Section
W. Whelan, Industrial Health and Safety Representative
- D. Whitehead, Manager, Plant Support Services
T. Wilkerson, Manager,Environmental Radiation Control
L. Woods, Manager, Technical Support
- D. Young, Plant General Manager
Other licensee employees contacted included technicians, operators,
engineers, mechanics, security force members, and office personnel.
NRC Personnel
- W. Orders, Senior Resident Inspector
C. Ogle, Resident Inspector
- J. Starefos, Project Engineer
- G. Salyers, Region II Inspector
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2. PLANT STATUS AND ACTIVITIES
Operating Status
The unit operated for the entire report period with no major operational
perturbations. As of the end of the report period, the unit had been on
line for 112 days.
3.
OPERATIONS
a.
Plant Operations (71707)
The inspectors evaluated licensee activities to determine if the
facility was being operated safely and in conformance with
regulatory requirements. These activities were assessed through
direct observation, facility tours, interviews and discussions
with licensee personnel, evaluation of safety system status, and
review of facility records. The inspectors reviewed shift logs,
operation's records, data sheets, instrument traces, and records
of equipment malfunctions to assess equipment operability and
compliance with TS. The inspectors evaluated the operating staff
to determine if they were knowledgeable of plant conditions,
responded properly to alarms, adhered to procedures and applicable
administrative controls, were cognizant of in-progress
surveillance and maintenance activities, and were aware of
inoperable equipment status. The inspectors performed instrument
channel checks, reviewed component status, and reviewed safety
related parameters to determine conformance with TS. Shift
changes were routinely observed to determine if system status
continuity was maintained and that proper control room staffing
existed. Access to the control room was well managed, and in
general, operations personnel carried out their assigned duties in
an effective manner. Control room demeanor and communications
were appropriate.
Routine plant tours were conducted to evaluate equipment
operability, assess the general condition of plant equipment, and
to verify that radiological controls, fire protection controls,
physical protection controls, and equipment tagging procedures,
were properly implemented.
b.
Onsite Response to Events (93702)
Control Room Ventilation Misalignment
At 8:35 p.m. on November 15, 1994, an operator found the control
switch for control room air conditioning system fan HVA-1B in the
"STOP" position instead of the required "AUTO" position. The
switch was immediately placed in the "AUTO" position which
returned the fan to operable status. In this mis-configuration,
the fan would not have auto started during certain design basis
accident scenarios.
Background
The control room air conditioning system, is comprised of two sub
systems; an environmental control system and air cleanup system.
The system is nuclear safety related and redundancy is provided
for safety-related active components.
3
The environmental control system operates continuously during
normal and emergency conditions. This system consists of two
redundant 100 percent capacity centrifugal fans and gravity
dampers arranged in parallel, and a stainless steel housing
containing a medium efficiency filter and redundant cooling coils.
Redundant safety-related equipment and controls are powered from
separate safety-related power supplies. A nonsafety-related fan
provides exhaust from the control room through the kitchen and
toilet areas to the outdoors during normal operation.
The air cleanup system normally operates only during emergency
conditions. This system consists of redundant centrifugal fans
and gravity dampers arranged in parallel, and a stainless steel
housing containing filter and charcoal absorber banks. The system
contains a single outside air intake with connecting duct work
containing redundant parallel air operated control dampers. The
control room kitchen and toilet exhaust duct work contains
redundant air operated control dampers arranged in series.
The system is designed to provide three operational modes, normal
ventilation, emergency pressurization, and emergency
recirculation.
During normal ventilation, one train of the environmental control
system is in operation in conjunction with the kitchen and toilet
area exhaust fan.
During emergency pressurization, a single train of both the
environmental control system and the air cleaning system are in
operation. The kitchen and toilet air exhaust fan is shutdown and
exhaust dampers closed. A positive pressure is maintained in the
control room envelope with respect to adjacent areas and the
outdoors. A safety injection signal or a signal from the control
room radiation monitor will automatically place the system in the
emergency pressurization operating mode. The emergency
pressurization mode may also be manually initiated.
The emergency recirculation mode of operation is achieved by first
placing the system in the emergency pressurization and then
closing both outside air intake dampers via their control switches
in the control room. This mode of operation is not a design basis
requirement, but is provided to allow isolation of the control
room outside air makeup.
Event Details
On the morning of November 15, 1994, an operator found the control
switch for control room air conditioning system fan HVA-1B in the
STOP position instead of the required AUTO position. The switch
was immediately placed in the AUTO position which returned the
system to operable status. In this erroneous configuration, the
fan would not have automatically started during design basis
- 0'
4
accident scenarios. The licensee determined that the switch had
been placed in the STOP position on November 11, 1994, when an
operator, who was performing operations surveillance test OST-750,
Control Room Emergency Ventilation System, placed the switch in
STOP when the procedure required that he verify that the fan was
OFF. Since the fan was already off, he should have merely verified
that the fan was not running.
As described above, the system is designed to automatically align
to the emergency pressurization mode upon the receipt of either a
safety injection or control room high radiation signal.
Upon the
receipt of either of these signals, one of the redundant air
cleanup fans start, the redundant control room exhaust dampers
close, and outside air is used to pressurize the control room. To
perform this pressurization function, at least one of the
environmental control fans HVA-1A or HVA-1B must also be in
operation. Although these fans do not get a direct AUTO start
signal, one of the two redundant fans is always running, and the
other is designed to start upon the receipt of a low flow signal
from the opposite fan. With the switch for the HVA-1B fan in the
STOP position, and assuming the single active failure of the A
diesel generator, the system would not have been capable of
pressurizing the control room without manual action by the
operators to start fan HVA-1B.
It should be noted that the inspectors verified that current, in
place, emergency procedures would have prompted the operators to
verify that the system was operating properly and take action, if
necessary, to initiate system function.
Concl usion
The operator performing OST-750 on November 11, 1994, failed to
follow the requisites of the procedure which resulted in making
the B train of the system inoperable.
The inspectors noted that even though the reactor operators
performed a control panel walkdown once per hour during the period
in question and the STA performed a control panel walkdown once
every four hours, the mispositioned switch was not detected for
four days. This event is of concern to the NRC because it is an
example of inattention to detail on the part of the operating
staff. It should also be noted that operators failing to follow
procedures and not being aware of the status of controls and
indications in the control room is a chronic problem.
Technical Specification 3.15.1 requires that during all modes of
plant operation, the control room air conditioning system shall be
operable with two trains of active safety-related components and
shared safety-related passive components.
5
Technical Specification 3.15.1 requires the control room air
conditioning system be operable during all modes of plant
operation, including two trains of active safety-related
components and shared safety-related passive components.
OST-750, Control Room Emergency Ventilation System requires in
step 7.2.1 that HVA-1B be verified to be OFF but does not require
the operator to take the switch to the STOP position.
On November 11, 1994, an operator failed to follow the requisites
of operations surveillance test OST-750, Control Room Emergency
Ventilation System, when he placed the control switch for idle
control room air conditioning system fan
HVA-1B in STOP when the
procedure required that he verify that the fan was OFF. This mis
configuration resulted in the B train of the system being
inoperable for four days, and rendered the system incapable of
performing its intended safety function, assuming an active single
failure in the opposite train.
This is a Violation, VIO 94-27-01:
Operator Procedure Non-Compliance Results In Control Room
Ventilation Inoperability.
c.
Effectiveness of Licensee Control in Identifying, Resolving, and
Preventing Problems (40500)
The inspectors evaluated certain activities of the PNSC to
determine whether the onsite review functions were conducted in
accordance with TS and other regulatory requirements. In
particular, the inspectors attended the PNSC meeting held on
November 18, 1994, which dealt with a NAD audit of operations. It
was determined that provisions of the TS dealing with membership,
review process, frequency, and qualifications were satisfied. The
inspectors also reviewed selected previously identified PNSC
activities to independently determine if that corrective actions
were progressing satisfactorily.
Based on the information obtained during the inspection, except as noted
above, the operations program was adequately implemented.
4.
MAINTENANCE
a.
Maintenance Observation (62703)
The inspectors observed safety-related maintenance activities on
systems and components to ascertain that these activities were
conducted in accordance with TS, approved procedures, and
appropriate industry codes and standards. The inspectors
determined that these activities did not violate LCOs and that
required redundant components were operable. The inspectors
verified that required administrative, material, testing,
6
radiological, and fire prevention controls were adhered to. In
particular, the inspectors observed/reviewed the following
maintenance activities detailed below:
WR/JO 94-BWP471
Calibrate The Component Cooling Loop
Flow Instrumentation (FT-613 only)
WR/JO 94-CBY003
End Of Core Life (EOL) Calibration
Of Rod Insertion Limits
WR/JO 94-AQQJ1
Assist Tech Support In Testing
Control Room Ventilation System
CCW Flow Transmitter Calibration
The inspectors witnessed calibration of FT-613 Component Cooling
Water Flow transmitter accomplished in accordance with Process
Instrument Calibration Procedure, PIC-002, D/P Electronic
Transmitter (4-20 mA Output). While the overall conduct of the
calibration was adequate, the inspectors noted several procedural
deficiencies.
The generic transmitter isolation and restoration sequence
specified in Attachment 8.3 of PIC-002 was inadequate. The valves
shown on the valve manifold sketch in this attachment are labelled
"A", "B", and "C."
No designation is provided as to which letter
represents the high and low pressure isolation valves. The
generic isolation and restoration sequence is provided in terms of
the "A", "B", and "C" designations only. The inspectors observed
that the physical arrangement of these valves does vary in the
plant between transmitters. This lack of specificity coupled with
the in-plant variations in manifold configuration could result in
a transmitter isolation or restoration in the reverse of the order
specified.
The inspectors also noted that PIC-002 fails to provide
instructions on repositioning the equalizing valve in the interval
between instrument isolation and calibration as well as between
calibration and restoration. Following instrument isolation, the
equalizing valve is open. No procedural guidance exists in PIC
002 to shut this valve when the calibration is performed. (The
equalizing valve must be shut in order to apply a differential
pressure to the transmitter.)
Likewise, following calibration
nothing in PIC-002 prompts the technician to open the equalizing
valve prior to performing the manifold block restoration sequence.
The inspectors also noted that the transmitter tolerance specified
on the calibration data sheet was incorrect.
Instead of a 20
millivolt tolerance, the calibration data sheet specified a 200
millivolt tolerance.
The inspectors noted that none of these errors was especially
significant and the technician was able to accomplish the
calibration in spite of the procedural deficiencies.
7
Nevertheless, the inspectors concluded that the procedure was not
correct as written. The licensee committed to correcting the
procedure to address the items identified above.
Technical Specification 6.5.1.1, Procedures, Tests, and
Experiments, requires in part, that written procedures be
established, implemented and maintained for the activities
specified in Appendix A of Regulatory Guide 1.33, Rev. 2, February
1972, including maintenance.
Process Instrument Calibration Procedure, PIC-002, D/D Electronic
Transmitter (4-20 mA Output) is provided for calibration of
differential pressure transmitters including FT-613, Component
Cooling Loop Flow.
On November 21, 1994, PIC-002 was inadequate in that not only did
it not contain all necessary steps to perform the calibration, but
if followed as written, it would have resulted in valving out the
transmitter in reverse sequence.
This NRC identified violation is not being cited because criteria
specified in Section VII.B of the NRC Enforcement Policy were
satisfied.
This item is identified as a non-cited violation NCV
94-27-02: Inadequate FT-613 Calibration Procedure.
The inspectors noted that FT-613 was also isolated at the
instrument root stops in accordance with a local clearance and
test request. The inspectors were advised that instruments are
not always isolated at the root stops for calibration. However,
when they are, the inspectors were informed that Operations
personnel do not manipulate the manifold block equalizing valve
when hanging or removing the clearance. (The operator who removed
the FT-613 root valve clearance told the inspectors that he did
not manipulate the equalizing valve when removing the clearance on
the FT-613 root isolation valves.)
The inspectors concluded that
as a minimum this strategy can defeat the licensee's isolation and
restoration sequence at the manifold valves. At worst, the
manipulation of the root stops by Operations has the potential to
subject one side of the transmitter to system pressure without
corresponding system counter pressure on the other side of the
transmitter diagram.
The inspectors also questioned the licensee's method for
transmitter restoration and isolation. The inspectors were
advised that the I & C technicians are trained that when isolating
a differential pressure transmitter, the licensee's sequence is to
shut the high side valve, open the equalizing valve, and shut the
low pressure side valve. Conversely on restoration, the sequence
is to open the low pressure side valve, close the equalizing
valve, and open the high side valve. The inspectors were advised
that this method is specified consistently in the licensee's
procedures.
8
Following inspector questions on this technique, the licensee
received the manufacturer's recommended practice for valving
differential pressure transmitters in and out of service. The
manufacturer recommends that when isolating a transmitter the
desired sequence is to open the equalizing valve and then shut the
low and high side valves. When restoring the transmitters to
service, the manufacturer's recommended sequence is open the
equalizing valve, open the high side and low side valves, and shut
the equalizing valve. The manufacturer's letter on this subject
stated that this technique "...insures that neither the
transmitter high or low side will be subjected to an overpressure
condition during the valve in and valve out process."
Further,
the letter stated that failure to properly equalize the
transmitter "...can result in an overpressure condition which will
cause a shift in transmitter zero." The manufacturer stated that
this overpressure condition would not damage the transmitter. The
inspectors were advised that the licensee's valve operating
sequence was in part, developed to minimize potential consequences
which could occur as a result of equalizing the two sides of the
transmitters. The inspectors acknowledge that in some situations,
use of the manufacturers' technique may have undesirable side
effects. However, these potential shortcomings do not apply to
the FT-613 configuration. Further, the licensee was unable to
furnish any historical analysis of the consequences of potential
zero shifts on transmitters resulting from the licensee's
procedure. The licensee is evaluating the potential for
transmitter zero shifts using their technique. The inspectors
will monitor this effort.
Use Of Unqualified Oil In WCCU
During the morning of November 30, 1994, the inspectors observed
that the Texaco Capella Premium 68 oil being used in the ongoing
maintenance on WCCU-1A was not designated as to its.procurement
quality. The inspectors questioned this and following a
subsequent licensee review were advised that the oil was non-Q.
At 2:00 p.m., that day, the licensee declared WCCU-1B out-of
service due to the fact that the oil installed in the unit was
also non-Q. Since WCCU-1A was inoperable for ongoing maintenance,
the licensees entered TS 3.15.1b. This TS required that at least
one WCCU be restored to an operable status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or the
unit be placed in hot shutdown within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. At 9:07 p.m., that
evening, the licensee exited TS 3.15.1b when the WCCU-IB was
declared back in service. This declaration occurred following the
licensee's dedication of the Texaco Capella Oil Premium 68
installed in the WCCUs. This was based on analysis of samples of
the Texaco Capella Oil Premium 68.
Pending a review of the licensee's procurement practices for oil
for the WCCUs this item is identified as an unresolved item, URI
94-27-03: WCCU Oil Procurement Practices
9
Failure to Provide Procedure For Maintenance On Auxiliary
Feedwater Valves
On November 9, 1994, during a routine inspection of the motor
driven auxiliary feedwater pumps, the inspectors noted that the
jam nuts designed to assist in securing the valve stem to actuator
coupling on flow control FCV-1424 and FCV-1425 appeared to be
improperly adjusted. Valve FCV-1424 had four jam nuts, all of
which were located at the actuator end of the threaded coupling.
Valve FCV-1425 had only three jam nuts, one of which was located
at the valve end of the coupling and the other two were located at
the actuator end. The licensee later determined that the nuts
were loose.
The inspectors notified the system engineer of the observation,
and reviewed the technical manual for the ITT Barton (Hydramotor)
actuators. The manual clearly identified the correct location of
the jam nuts as being two at either end of the coupling and
specified a torque value of 100 inch pounds to be applied to the
nuts. This meant that both FCV-1424 and FCV-1425 were set up
incorrectly.
The system engineer contacted the vendor for the valve actuators
to determine the significance of the as-found configuration.
According to the engineer, the vendor stated that in the case of
valves FCV-1424 and FCV-1425 which employs an ITT Barton NH-91
actuator with a Grinnel gate valve, the jam nuts were not
necessary since no torque is applied to the coupling which could
cause valve stroke misadjustment if the coupling become loosened.
During their inspection to determine why the actuator couplings
were found improperly adjusted, the inspectors determined that
these same jam nuts had been found loose on FCV-1424 in January
1991, and on FCV-1425 in June 1992. The inspectors also determined
that although the valves are safety-related equipment, no
procedure existed for maintenance on their actuators despite the
fact that a request for a procedure was generated in September of
1993. The need for a procedure had also been identified in
September of 1994, when an operability determination (94-035) was
performed after it was determined that the flow controllers
associated with the valves had been calibrated without a
procedure.
The licensee has committed to write a procedure to provide
specific instruction for the installation and required maintenance
of the actuator/valve assemblies.
Failure to have a procedure for maintenance on safety-related
equipment is a violation of TS 6.5.1.1.
However, since this event
meets the criteria specified in Section VII.B of the NRC
Enforcement Policy, the violation will not be cited. This item
10
will be tracked as non-cited violation NCV 94-27-04, Failure To
Provide Procedure For Safety-Related Maintenance.
b.
Surveillance Observation (61726)
The inspectors observed certain safety-related surveillance
activities on systems and components to ascertain that these
activities were conducted in accordance with license requirements.
For the surveillance test procedures listed below, the inspectors
determined that precautions and LCOs were adhered to, the required
administrative approvals and tagouts were obtained prior to test
initiation, testing was accomplished by qualified personnel in
accordance with an approved test procedure, test instrumentation
was properly calibrated, the tests were completed at the required
frequency, and that the tests conformed to TS requirements. Upon
test completion, the inspectors verified the recorded test data
was complete, accurate, and met TS requirements, test
discrepancies were properly documented and rectified, and that the
systems were properly returned to service. Specifically, the
inspectors witnessed/reviewed portions of the following test
activities:
OST-010
Power Range Calorimetric During Power
Operation
Control Room Exhaust Dampers
Unresolved Item, URI 94-23-05, documents the resident inspectors'
concerns associated with testing of the control room exhaust
dampers, CR-D1A and CR-D1B. These in-series redundant dampers
automatically close as part of the control room emergency
pressurization sequence. Though both dampers were tested together
during existing surveillance tests, the licensee performed no
routine test of the capability of a single damper to close and
facilitate control room pressurization.
On November 9, 1994, the licensee conducted testing which
demonstrated the capability of the exhaust dampers to individually
seal, thereby permitting adequate control room pressurization.
This testing was performed using a revised version of EST-023,
Control Room Emergency Ventilation System. The inspectors
witnessed portions of the test and reviewed the completed EST and
observed that the control room was pressurized adequately using
either damper individually.
The failure of the licensee to test the capability of the
individual control room exhaust dampers to individually permit
control room pressurization is a violation of 10 CFR 50,
Appendix B, Criterion XI, Test Control, which requires in part
that a test program be established to assure that all testing
required to demonstrate that systems will perform satisfactorily
in service is identified and performed in accordance with written
test procedures which incorporate the acceptance limits contained
in the applicable design documents.
The licensee's Updated Final Safety Analysis Report (UFSAR)
sections 6.4 and 9.4.2 require, in part, that the control room
ventilation system be capable of maintaining the control room at a
positive differential pressure with respect to adjacent areas and
the outdoors when the system is operated in the emergency
pressurization mode of operation.
Further, this reference
specifies that the system will remain operable given the failure
of a single active component. Each exhaust damper is an active
component.
From February 1, 1991, until November 9, 1994, the licensee did
not implement adequate testing to verify that the control room
ventilation system was capable of performing its design function.
Specifically, testing did not demonstrate that a positive pressure
could be maintained in the control room assuming that a single
exhaust damper failed to shut. This NRC identified violation is
not being cited because criteria specified in Section VII.B of the
NRC Enforcement Policy were satisfied. This item will be tracked
as a non-cited violation NCV 94-27-05, Inadequate Testing Of
Control Room Ventilation Dampers.
Assessment Of Calorimetric Program (61726, 61706)
The inspectors reviewed the licensee's power range calorimetric
program. This inspection effort consisted of witnessing
performances of OST-010, Power Range Calorimetric During Power
Operation; verification of portions of the logic and assumptions
used in the ERFIS calorimetric calculation; and a review of
calibration of instruments used in the calorimetric.
Additionally, the inspectors attempted to conduct a rudimentary
cross-check of reactor power using diverse indications as a check
on the validity of the calorimetric calculation.
Operations
While witnessing the performance of OST-010, the inspectors
observed that the auxiliary operators collect differential
pressure data from Barton differential pressure instruments
installed in the turbine building. For feed flow, the
operators record three differential pressure readings one
minute apart, while for blowdown flow, a single differential
pressure reading is taken. Using these readings, a control
room operator calculates the average feed flow Barton
differential pressures. This information is subsequently
entered into the ERFIS calorimetric program to calculate the
flow. The inspectors noted that the three-minute averaging
of feed flow is not specified in the procedure. Further, the
Barton readings are recorded on a scrap piece of paper which
is not retained, hence eliminating any second check or
12
review of the data or the averaging process. The inspectors
also noted that the timing of the reading of the Bartons and
the automatic acquisition of other data points performed by
the calorimetric program was not procedurally specified and
varied among operators. While the calorimetric procedure
specifies that plant power be held constant, the inspectors
noted that slight variations in-plant parameters used in the
calorimetric do occur. The inspectors concluded that given
these variations, the lack of procedural guidance to specify
the timing of these two separate steps in the data
acquisition process could introduce errors.
The inspectors also observed that the computer generated
data sheet for OST-010 states that F,, the feed flow nozzle
thermal area factor, is obtained from Attachment 8.3. No
such attachment exists for OST-010. This error does not
impact the performance of the calorimetric.
Instrument Calibration
The inspectors reviewed the licensee's calibration of
instruments which provide inputs to the calorimetric. The
following deficiencies were noted:
The inspectors observed that the feedwater temperature RTDs,
used in the calculation of feedwater enthalpy are not
included in the licensee's calibration program. A portion
of the feedwater temperature signal path in ERFIS is
calibrated, however, this calibration would not detect
degradation in the sensors or the remaining portion of the
circuits.
The inspectors also determined that no routine verification
of feedwater flow nozzle performance is performed. The
inspectors were advised by the licensee that a visual
inspection of the three nozzles is conducted on a refueling
interval basis. Further, the licensee advised the
inspectors that these inspections have not detected problems
with the nozzles. The inspectors reviewed the nozzle
inspection work packages from the last outage and noted that
the inspection results consisted of a single sentence which
described the nozzles as being in a satisfactory condition.
The licensee was unable to provide any quantitative data to
demonstrate that feedwater flow nozzle characteristics have
not changed over the last 24 years of service. The
inspectors concluded that the lack of a quantitative
assessment of feedwater nozzle performance could prevent
detection of gradual feedwater flow nozzle degradation.
Given the dramatic direct impact that even small changes in
feedwater flow have on the calorimetric results, this
shortcoming represents a key vulnerability in the licensee's
13
calorimetric program. This potential shortcoming was
identified to the licensee. Pending the licensee's
resolution of feedwater flow nozzle performance, this item
will be tracked as an unresolved item, URI 94-27-06:
Resolution of Feedwater Nozzle Performance and Impact On
Calorimetric.
The inspectors reviewed completed calibration data sheets
for the instruments used in the calorimetric.
From this
review, the inspectors determined that the licensee has not
applied consistent controls to these instruments if an out
of tolerance condition is identified. Specifically, the
calibration data sheet for the feedwater flow Bartons
requires that an operating supervisor be notified if the
instrument is found out of calibration. However, no similar
requirement exists for the steam generator blowdown Bartons.
In fact, on January 7, 1994, DPI-1328B, Steam Generator B
Blowdown Differential Pressure, was found out of tolerance
during a licensee calibration.
An assessment of this out
of tolerance condition on the bottom of the calibration data
sheet stated: "Indicating needle had moved; possibly due to
a pressure shock, non-Q application non-reportable." No
documentation existed which shows that the effect of this
out of tolerance condition had on the calorimetric was
considered at the time .
During the course of the
inspection, the inspectors were advised that data sheets for
the blowdown Barton calibration are being revised to require
review if out of tolerance conditions are detected.
Additionally, the inspectors were advised that the licensee
has implemented a post-calibration review for data sheets
for trending purposes. A subsequent licensee assessment
determined that this instrument miscalibration introduced an
error of less than 1.5 megawatts thermal.
The inspectors also noted from their review of the
calibration data sheets that the licensee is calibrating the
feedwater flow and steam generator blowdown Bartons to a
tolerance four times less restrictive than that specified by
the manufacturer. (Manufacturer +1/2%; licensee + 2%.) A
review of the completed calibration sheets revealed that all
three steam generator blowdown Bartons have exceeded the
more restrictive manufacturer's tolerance on at least one
calibration point during the most recent calibration.
(All
three Bartons met the licensee's less restrictive
calibration tolerance.)
Furthermore, DPI 1328B, Steam
Generator B Blowdown Differential Pressure, has been
readjusted during each of the last four calibrations (June
1991 to June 1994).
It was not apparent to the inspectors
that the impact on the calorimetric of this relaxed
instrument tolerance or the repetitive adjustment had been
evaluated by the licensee.
14
On October 20, 1994, the inspectors observed that the ERFIS
indication for steam generator pressure for loop 3 channel 2
differed by approximately 40 psig from the corresponding
RTGB indication.
Steam generator pressure as recorded in
ERFIS is used in the calorimetric. Similar, but smaller
deviations between the RTGB indication and ERFIS existed on
all other steam generator pressure channels. Subsequent
licensee reviews on October 26 and October 27, 1994,
indicated a deviation of between 47 psig and 48 psig for the
loop 3 channel 2 steam generator pressure indicators. The
licensee subsequently determined that the deviation was a
result of signal isolator PM-494D (ERFIS input) being out of
tolerance low and PI-494 (RTGB indicator) being out of
tolerance high. This condition was corrected by the
licensee on October 31, 1994. Simultaneous licensee
calorimetrics performed with RTGB steam generator pressures
versus ERFIS values performed on October 26, 1994, revealed
that this disparity in pressure readings for all steam
generators translated into a little less than a 2 megawatt
difference in core thermal power.
The calorimetric is equipped with routines which verify that
the input data falls within acceptable ranges. Typically,
the acceptable range is the instrument span. Additionally,
the calorimetric will flag unacceptable deviations between
the redundant steam generator pressure channels input to
ERFIS or unacceptable deviations from the average feedwater
temperature by any feedwater temperature instrument.
However, no mechanism exists by which to detect deviations
such as that which developed in the loop 3 channel 2 steam
generation pressure instrument between different indicators.
The inspectors also determined that the licensee's
calibration program does not verify the signal from the
instrument loops to the ERFIS computer. Hence, portions of
the feedwater temperature and steam generator pressure
circuitry which feed the calorimetric program are not
verified in any licensee calibration program. The failure
to conduct a verification of the entire ERFIS signal path
for the steam generator pressure instruments was previously
identified during a Regulatory Guide (RG) 1.97 inspection
documented in NRC Inspection Report 90-08. The licensee did
conduct testing to verify the entire signal path during SP
1150,
Process Analog Indications Comparison To ERFIS Point
Indication For RG 1.97 Commitments on July 22, 1992.
However, this was not incorporated into a routine
verification of the entire ERFIS path. The inspectors were
advised that the licensee has implemented steps to verify
the ERFIS outputs during instrument loop calibrations until
complete verification of the ERFIS loop can be procedurally
implemented.
15
Calorimetric Program
The inspectors reviewed the calorimetric program. The
following items were observed.
The inspectors were advised by ERFIS personnel that input
data for the 12 ERFIS points used in the calorimetric
program are obtained from an instantaneous update when the
program is activated. This strategy makes the calorimetric
susceptible to errors as a result of normal variations in
plant parameters. No adjustment, compensation, or
administrative controls exist to correct for any error
introduced as the result of this methodology.
Thermal power is calculated in the calorimetric program
assuming a letdown flow of approximately 45 gpm. Though
this is'the normal letdown flow, the licensee does
occasionally conduct power operations with approximately 100
gpm of letdown flow. There is no adjustment made to the
calorimetric for this increased letdown. In fact, the
assumed letdown flow is not discussed in the calorimetric
procedure. Using licensee calculations of heat loss
associated with letdown flow, the inspectors determined that
this increased letdown could introduce almost a 3 megawatt
thermal error into the calorimetric.
The calorimetric program uses a value of component heat loss
obtained from testing performed in 1970. Discussions with
plant personnel indicates that portions of the original
asbestos containing lagging on some components in the CV
were replaced in the mid 1980's.
The impact in terms of
calorimetric performance of this lagging replacement was not
readily apparent from the information reviewed by the
inspectors. However, the inspectors reviewed a 1987
insulation contractor's trip report which stated that
following the insulation changeouts ".. the average
containment air temperature reportedly increased from about
1050 F to about 1200 F."
The inspectors did not
independently verify this statement. The inspectors
acknowledge that the component heat loss at 1.2 megawatts is
a small part of the thermal power. Nevertheless, the
inspectors concluded that relying on a heat loss calculation
performed 24 years ago, in the face of even partial
insulation changeout, may introduce errors into the
calorimetric.
It was not apparent from the inspector's review of the
calorimetric program that the overall accuracy of the
calorimetric has been identified by the licensee.
Instrument accuracies, errors introduced as a result of
(curve fits) used in the calorimetric and gradual
degradation of the component performance will affect the
16
accuracy of the alorimetric. This error has not been
translated into a strategy which monitors the accuracy of
the calorimetric and makes necessary changes or compensation
to plant operations so as not to violate licensed thermal
power limits.
Conclusion:
The inspectors acknowledge that the potential errors
introduced into the calorimetric as a result of the items
above, except for potential feed flow nozzle inaccuracies,
are probably small.
Additionally, conservatisms introduced
into the calorimetric as a result of steam quality and
feedwater enthalpy considerations may more than offset these
items. Nevertheless, the inspectors observed that control
of the calorimetric is weak. This weakness was reflected in
deficiencies observed in the calibration of instrumentation,
control of assumptions and initial conditions, and
assessment of errors contained in the calorimetric.
Overall, the inspectors concluded that the calorimetric
program does not contain controls commensurate with its
safety significance.
10 CFR 50, Appendix B, Criterion II, Quality Assurance
Program, requires that the quality assurance program provide
control over activities affecting quality of structures,
systems, and components, to an extent commensurate with
their importance to safety. Further, Criterion II requires
that these activities be accomplished with the use of
appropriate equipment and that all prerequisites have been
identified and satisfied. Further, the program is required
to take into account the need for special controls, test
equipment, and the need for verification of quality by
inspection or test.
On November 28, 1994, the inspectors determined that
inadequate controls were applied to the licensee's
calorimetric program. Deficiencies identified included use
of uncalibrated instrumentation, failure to control the
plant condition prerequisites under which the calorimetric
program results were valid, failure to specify a method or
timing for acquiring manually input data, lack of
verification of automatically input data, and inconsistent
controls on the instruments used in the calorimetric. This
is identified as a violation, VIO 94-27-07: Failure To
Adequately Control Calorimetric.
The inspectors attempted to independently assess the
accuracy of the calorimetric using diverse indicators or the
results of tests other than OST-010. However, the
inspectors observed that most of the readily available
information could be impacted by errors common to the
17
calorimetric. Given this limitation, the inspectors
reviewed historical plant performance data which indicated
that the current electrical output at an indicated power of
100 percent is consistent with that for similar conditions
during the last three cycles.
Based on the information obtained during the inspection, except as
noted above, the maintenance program was adequately implemented.
5.
ENGINEERING
a.
Onsite Engineering (37551)
RTGB Design Control
At approximately 3:00 p.m, on the afternoon of October 31, 1994,
the inspectors were monitoring I & C work associated with the
calibration of instrumentation on the RTGB, when they detected a
piece of 1/2" electrical conduit attached by plastic tie wraps to
two horizontal structural supports inside the panel.
The piece of
conduit had itself been used as a structural member to which
bundles of wiring had been secured. The inspectors discussed
their observations with the shift supervisor who in turn, notified
the engineering department.
At 3:22 p.m. that afternoon, the shift supervisor initiated an
operability determination on the RTGB due to the possible loss of
associated controls and indications during a seismic event. The
Licensee detected four other examples of unanalyzed wiring support
material in the RTGB including a 6 foot length of one inch steel
piping. An assortment of hardware had been used to secure these
supports to the framework of the RTGB including 1/4" cable ties,
3/16" cable ties and metal clamps. The licensee's investigation
failed to determine how or when the unanalyzed supports had been
installed in the RTGB.
The licensee performed Operability Determination 94-01 which
indicated that installation was acceptable, in that, the tie wraps
provide sufficient structural support to resist the loadings which
would occur during a design basis seismic event. The licensee's
current plans are to replace the tie wrap supports with
appropriately designed fasteners. This work is to be performed in
compliance with the licensee's process for the modification of
safety-related equipment.
10 CFR 50, Appendix B, Criterion III, Design Control requires in
part, that design changes, including field changes, undergo the
same review and meet the same standards as those applied to the
original design. This review includes, but is not limited to the
verification or checking the adequacy of the design.
18
The RTGB was modified with no review or verification of the
adequacy of the design.
This NRC identified violation is not being cited because criteria
specified in Section VII.B of the NRC Enforcement Policy were
satisfied. This issue will be tracked as a non-cited violation,
NCV 94-27-08; Unreviewed RTGB Modification.
Calibration Of Rod Insertion Limits
During post-calibration review, the inspectors noted that the
control bank D end of life rod insertion limits specified on curve
1.98, "Rod Insertion Limits," were incorrect. At 100 percent
power, the curve specifies a control bank D insertion limit of
164 steps.
However, the fuel vendor analysis for cycle 16
specifies 165 steps for this limit.
The inspectors noted that the
safety significance of this observation was minimal since alarms
are provided prior to reaching this level of rod insertion.
Further, the licensee routinely operates with the rods withdrawn
well in excess of this limit.
The inspectors concluded that this
error represented a lack of attention to detail on the part of the
engineering technical support personnel.
Based on the information obtained during the inspection, except as noted
above, the engineering program was adequately implemented.
6.
PLANT SUPPORT
a.
Plant Support Activities (71750)
Annual Exercise (82301)
In Section 5.6.1.2.2, Exercises, of their RCP, the licensee
committed to perform an off-hours exercise between midnight and
06:00 A.M. once every six years. This off-year annual exercise
which started on November 15, 1994, at 2:30 A.M. satisfied that
commitment.
This was the first exercise in which the licensee used the "Team"
concept in staffing the ERO. A "Team" would be analogous to a
"Crew" in staffing the control room. The "Team" concept appeared
to work well.
The exercise scenario consisted of: a fire lasting greater than
ten minutes resulting in a NOUE; a loss of annunciators resulting
in an SAE; a radiation spill; and the declaration of a General
Emergency due to multiple spent fuel assemblies being damaged when
a spent fuel cask dropped into the spent fuel pool.
Security commenced their security search procedure for
incorporating the TSC and EOF into the protected area at the NOUE
declaration. The security search took 51 minutes to complete.
19
The licensee activated the TSC and EOF when the search was
complete and after the Alert Emergency declaration.
The Control Room crew exhibited good communication skills.
The
crew was alert and actively pursued resolution to plant problems
and potential plant problems that were scenario driven. From the
control room, emergency event classifications were correct,
activation procedures were followed, and offsite notifications
were timely and complete. The SEC in the control room exhibited
good command and control.
The SECs used procedures when
transferring SEC responsibilities from the Control Room to the
TSC. The transfer was clear and concise.
The TSC was activated in a timely manner, approximately 44 minutes
after the Alert Emergency declaration. In the TSC, briefings were
held on the hour and half hour. The SEC exhibited good command
and control.
The TSC staff communicated effectively among
themselves and with the OSC. Once activated, event declarations
were made from the TSC.
Event classifications were correct and
procedures were followed.
The OSC prioritized missions. In forming a team, work missions
were planned, radiation levels and plume exposure were considered.
Once teams were formed, they were briefed on their mission, plant
conditions, and radiation levels. Once deployed, teams were
tracked and debriefed when missions were complete.
The EOF was activated in a timely manner, approximately 45 minutes
after the Alert Emergency declaration. The EOF held their own
briefings in addition to monitoring TSC briefings. The EOF staff
functioned satisfactorily together as a team. Dose assessment
personnel identified radiation levels increasing before the rest
of the EOF staff was aware that the spent fuel cask had dropped
into the spent fuel pool.
The dose assessment individual
immediately applied the data pertaining to increasing radiation
levels to the appropriate general emergency EALs and PARs.
Overall communications among ERFs were satisfactory.
Once activated, the EOF had responsibility for offsite
notifications. During the exercise, a total of nine initial and
follow-up offsite notifications were transmitted offsite. The
inspector reviewed the nine notifications for timeliness and
message content. The inspector concluded that all of the
notifications were timely. The inspector determined that although
adequate, several notifications should have contained additional
pertinent information. Examples are:
Offsite facilities were not informed when the fire was
extinguished or when the annunciators alarm were back in
service.
20
In Notification message number 8, offsite agencies were not
informed as to why the basis for the offsite dose release
changed from an elevated release to one at ground level.
This caused confusion with offsite agencies.
The inspectors noted that the licensee's press releases raised
more question than they provided answers.
The inspectors observed the licensee's evaluator critique of the
exercise. The inspectors noted that the critique was thorough and
objective.
In IR 94-11, an EW was identified for delayed initial offsite
notifications. Based on the inspector's review of the nine
notifications for timeliness, the inspector considers EW 94-11-01:
Delayed Initial Notification, closed.
While touring the EOF/TSC mechanical equipment area, the resident
inspectors noted several uncapped cable penetrations in an outer
wall.
Additionally, the resident inspectors noted that the iodine
channel of the R-38 radiation monitor was being carried in a
source check log as out of service. While reviewing the EOF/TSC
drawing, the inspectors also noted that the building may have been
modified from the original design. The inspectors were concerned
that each of these items may degrade the capability of the
buildings ventilation system to perform its design function.
These items were identified to the licensee. Pending further
review by the inspectors, this concern is identified as an
Unresolved Item, URI 94-27-09: Impact Of Potential System
Deficiencies On EOF/TSC Ventilation System Design.
The inspectors observation of the exercise concluded the exercise
was fully successful.
No exercises weaknesses, violations or
deviations were identified.
b.
Site Visit By Boise Interagency Fire Center Representative
The NRC maintains a contract with the Boise Interagency Fire
Center in Boise, Idaho, for providing emergency communications
assistance. One of the terms of the contract is that the Boise
personnel visit each site every five years. The purpose of the
site visits is to collect information for preplanning which will
give responding Boise Personnel advanced information about what
emergency communications equipment would be required. The NRC
contract with Boise requires that from the time of initial
notification, Boise has twelve hours to respond to a site and be
operational.
Boise schedules the site visits around times when major national
or international emergencies such as hurricanes and forest fires
are not anticipated.
21
A Boise representative visited the Robinson facility on
November 30, 1994.
The actual visit lasted approximately an hour
during which the Boise representative met the resident inspector
and the Emergency Response Coordinator, and was provided copies of
the 10 and 50 mile EPZ maps, the EOF and TSC layout, and FSAR
sections 2.1 and 2.2 (Geography and Demography).
c.
Followup -
Plant Support (92904)
Closed EW 50-261/94-11-01: Delayed initial notification
IFI 93-15-01, 261/93-15-01: Review Licensee Evaluation Of TI
2515/112 Weakness
In Inspection Report 93-15, the inspectors documented a review of
the licensee's program for identifying, evaluating, and
documenting changes in population distributions, or industrial,
military, or transportation hazards on or near the site that may
have occurred since the plant was originally licensed. As a
constituent of this inspection, the licensee's program for
updating the FSAR was also reviewed.
The FSAR is required to be updated annually, pursuant to
CFR 50.71(e).
The inspector reviewed Robinson Administrative
Procedure AP-021, Development, Review, and Approval of Changes To
The Safety Analysis Report, as well as, higher tier procedures
such as NED-3.2 and NGGM 304-01, which describe the licensee's
program intended to ensure that updates to the FSAR are
accomplished. The inspectors noted that the guidance provided in
those procedures dealt almost exclusively with the mechanism of
processing the paperwork associated with an FSAR update, but did
not embody the more universal instruction such as how, when, or
why, an update is to be originated. This was not a formal
documented program in place to facilitate the routine update of
the FSAR.
The licensee indicated that they would evaluate their existing
program for updating the FSAR. This item was identified IFI
261/93-15-01:
Review Licensee Evaluation of TI 2515/.112
Weakness.
The licensee has since modified Administrative Procedure AP-021,
Development, Review and Approval of Changes To the Updated Final
Safety Analysis Report to require that a review of the UFSAR is
performed within six month of the last refueling outage and
annually, and to assure that identified changes result in a
revision. This IFI is closed.
Based on the information obtained during the inspection, except as noted
above, the plant support program was adequately implemented.
22
7.
EXIT INTERVIEW
Preliminary exit findings regarding the EP drill inspection effort were
communicated to the licensee on December 16, 1994, upon completion of
inspection activities by the Regional Inspector.
Preliminary exit findings were communicated to the licensee regarding
Project Engineer open item followup inspection efforts on November 18,
1994.
The inspectors met with licensee representatives (denoted in
paragraph 1) at the conclusion of the inspection on December 6, 1994.
During this meeting, the inspectors summarized the scope and findings of
the inspection as they are detailed in this report. The licensee
representatives acknowledged the inspector's comments and did not
identify as proprietary any of the materials provided to or reviewed by
the inspectors during this inspection. No dissenting comments from the
licensee were received
Item Number
Status
Description/Reference Paragraph
VIO 94-27-01
OPEN
Operator Procedure Non-Compliance Results
In Control Room Ventilation Inoperable
(paragraph 3)
NCV 94-27-02
OPEN
Inadequate FT-613 Calibration Procedure
(paragraph 4)
URI 94-27-03
OPEN
WCCU Oil Procurement Practices (paragraph
4)
NCV 94-27-04
OPEN
Failure To Provide Procedure For Safety
Related Maintenance (paragraph 4)
NCV 94-27-05
OPEN
Inadequate Testing Of Control Room
Ventilation Dampers (paragraph 4)
URI 94-27-06
OPEN
Resolution of Feedwater Nozzle Performance
and Impact On Calorimetric (paragraph 4)
VIO 94-27-07
OPEN
Failure To Adequately Control Calorimetric
(Paragraph 4)
NCV 94-27-08
OPEN
Unreviewed RTGB Modification (Paragraph 5)
URI 94-27-09
OPEN
Impact Of Potential System Deficiencies on
EOF/TSC Ventilation System Design
(Paragraph 6)
URI 94-23-05
CLOSED
Control Room Exhaust Dampers (paragraph 4)
23
EW 94-11-01
CLOSED
Delayed Initial Notification (paragraph 6)
IFI 93-15-01
CLOSED
Review of Licensee Evaluation of TI
2515/112 Weakness (paragraph 6)
ACRONYMS AND INITIALISMS
CFR
Code of Federal Regulation
CV
Containment Vessel
Control Room Vandalization System
DPI
Digital Position Indicator
Emergency Action Level
Emergency Planning Zone
Emergency Response Facility
EST
Engineering Surveillance Test
ERFIS
Emergency Response Facility Information System
EW
Exercise Weakness
Flow Control Valve
Final Safety Analysis Report
FT
Flow Transmitter
gpm
Gallons Per Minute
High Effective Particulate Absolute
HVE
Heating Ventilation Exhaust
Instrumentation & Control
LCO
Limiting Condition For Operation
Ma
Milliamp
NAD
Nuclear Assessment Department
NED
Nuclear Energy Division
NGGM
Nuclear Generation Group Manual
Notice of Unusual Event
Operations Surveillance Center
OST
Operations Surveillance Test
Protective Action Recommendation
Pressure Indicator
Process Instrument Calibration
Preventative Maintenance
psig
Pounds per square inch-gauge
Reactor Coolant Pump
Resistance Thermal Device
Reactor Turbine Gauge Board
Site Area Emergency
SEC
Site Emergency Coordinator
Special Procedure
Updated Final Safety Analysis Report
Unresolved Item
Violation