ML14181A582
| ML14181A582 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 08/15/1994 |
| From: | Christensen H, Ogle C, William Orders NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML14181A580 | List: |
| References | |
| 50-261-94-17, NUDOCS 9408290038 | |
| Download: ML14181A582 (17) | |
See also: IR 05000261/1994017
Text
s
REG(
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
0
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
Report No.:
50-261/94-17
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 Conducted: June 25 - July 23, 1994
Lead Inspector:
ders
enrRs//Ipct
W.
ders
en' r Resident Inspector
Dite'Signed
Other Inspectors:
.
'z/
0. t.
e,/esi bnt Inspector
Dfte'Signed
Approved by:
H. 0. Christensen, Chief
Date Signed
Reactor Projects Section 1A
Division of Reactor Projects
SUMMARY
Scope:
This routine, announced inspection was conducted in the areas of operational
safety verification, surveillance observation, maintenance observation, and
followup.
Results:
A violation was identified involving inadequate procedures governing equipment
control, paragraph 3.e. A second violation was identified involving the
licensee's failure to correct improperly routed instrument sensing lines,
paragraph 3.b.1. A third violation was identified involving the licensee's
failure to include wide range penetration pressurization flowmeters in a
calibration program, paragraph 4; a non-cited violation was identified
involving an operator's failure to adequately monitor plant status, paragraph
3.d; and an unresolved item was identified involving RHR system flow
indication concerns, paragraph 3.b.2.
9408290038 940815
PDR ADOCK 05000261
0
REPORT DETAILS
1.
Persons Contacted
- R. Barnett, Manager, Projects Management
S. Billings, Technical Aide, Regulatory Compliance
- J. Brown, Manager, Design Engineering
A. Carley, Manager, Site Communications
- B. Clark, Manager, Maintenance
D. Crook, Senior Specialist, Regulatory Compliance
J. Eaddy, Manager, Environmental and Radiation Support
- D. Gudger, Specialist Regulatory Affairs
S. Farmer, Manager, Engineering Programs, Technical Support
- B. Harward, Manager, Engineering Site Support, Nuclear Engineering
Department
- S. Hinnant, Vice President, Robinson Nuclear Project
- K. Jury, Manager, Licensing/Regulatory Programs
J. Kozyra, Acting Manager, Licensing/Regulatory Programs
- R. Krich, Manager, Regulatory Affairs
- F. Lowery, Manager, Work Control
- J. Lucas, Instructor, Technical Training
A. McCauley, Manager, Electrical Systems, Technical Support
- R. Moore, Acting Operations Manager
- J. Moyer, Manager, Nuclear Assessment
- D. Nelson, Manager Outage Management
- M. Pearson, Plant General Manager
M. Scott, Manager, Reactor Systems, Technical Support
E. Shoemaker, Manager, Mechanical Systems, Technical Support
D. Winters, Shift Supervisor, Operations
- D. Whitehead, Manager, Plant Support Service
L. Woods, Manager, Technical Support
Other licensee employees contacted included technicians, operators,
engineers, mechanics, security force members, and office personnel.
NRC Personnel
- H. Christensen, Acting Chief, Reactor Project Branch 1, was on site
July 22-23, 1994, to tour site and meet with resident inspectors.
- Attended exit interview
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2. Plant Status
The unit operated at or near full power for the duration of the report
period with no major problems.
2
3. Operational Safety Verification (71707)
a.
General
The inspectors evaluated licensee activities to confirm that the
facility was being operated safely and in conformance with
regulatory requirements. These activities were confirmed by
direct observation, facility tours, interviews and discussions
with licensee personnel and management, verification 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 verify equipment operability and compliance with TS. The
inspectors verified the staff was knowledgeable of plant
conditions, responded properly to alarms, adhered to procedures
and applicable administrative controls, cognizant of in-progress
surveillance and maintenance activities, and aware of inoperable
equipment status through work observations and discussions with
Operations staff members. The inspectors performed channel
verifications and reviewed component status and safety-related
parameters to verify conformance with TS. Shift changes were
routinely observed, verifying that system status continuity was
maintained and that proper control room staffing existed. Access
to the control room was controlled and operations personnel
carried out their assigned duties in an effective manner. Control
room demeanor and communications were appropriate.
Plant tours were conducted to verify 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.
Residual Heat Removal Flow Indicator FI-605 Reading Erroneously
At approximately 1:00 p.m. on July 1, 1994, the inspectors
questioned Operations management on the impact of a failed FI-605,
Residual Heat Removal Total Flow Indicator, on Operation's
capability to execute their End Path Procedures. With the RHR
pumps secured, the indicator registered approximately 1000 gpm
flow. The inspectors were concerned that since the instrument is
used during End Path Procedures, EPP-9, Transfer To Cold Leg
Recirculation, and EPP-10, Transfer to Long Term Recirculation,
the erroneous reading could impact the plant's ability to enter
recirculation. This erroneous flow indication had been noted by
Operations following RHR pump operation during OST-251, RHR
Component Test, earlier that morning. In response to the
inspector's question, the plant entered an operability
determination on the RHR system at 2:15 p.m. Additionally,
Maintenance personnel accelerated their efforts to vent FT-605 in
accordance with a work request generated after the instrument
3
failure was noted by Operations personnel.
At 2:35 p.m.
transmitter venting was completed and FI-605 indicated zero flow
with the RHR pumps off. At 8:24 p.m., the operability
determination was completed, concluding that the RHR system was
"...operable with erroneous indication of 1000 gpm on FI-605."
The inspectors reviewed the operability determination, interviewed
personnel involved in its generation, and reviewed the maintenance
history associated with FI-605. Based on this review, the
inspectors concluded that:
-
similar failures of FI-605 had occurred previously
-
neither the engineering evaluation nor the operability
determination specifically addressed the impact that the
erroneous indication would have on the operator's
implementation of the End Path Procedures
-
the engineering memo contained a technical error regarding
the failure of instrument.
Supporting rationale is provided in the following discussion.
1)
FT-605 Maintenance History
The inspectors requested a list of previous WR/JOs
accomplished to correct deficiencies in RHR flow indication
observed on FI-605. Twelve such work requests were
identified in the licensee's electronic database.
(This
database contains maintenance histories for approximately
the last 4 years.)
The inspectors reviewed the 12
completed work packages and noted that 4 of the work
requests described FI-605 anomalies markedly similar to that
observed on July 1, 1994. These 4 WR/JOs, dated May 18,
1991; May 15, 1992; January 23, 1993; and April 21, 1994,
described flow indications as high as 1800 gpm on FI-605
with the RHR pumps secured. In each of these 4 work
requests, the transmitter was equalized or vented to remove
the erroneous flow indication. Three of the WR/JOs
specifically mention air in the sensing lines.
On November 22, 1993, ACR 93-315 was written to address flow
oscillations on FI-605 with RHR in service. The condition
description section of the ACR noted that FT-605 required
its sensing lines to be vented, and that the condition was
repetitive. The ACR evaluation concluded that improperly
sloped sensing lines between the transmitter and the flow
sensing element could exist. The ACR theorized that gas or
air in the lines could be trapped, thereby, causing improper
operation of the transmitter. In response to this
situation, WR/JO 94-ADAIl was generated on February 9, 1994,
to adjust the sensing lines to eliminate any gas or air
4
traps. However, the WR/JO specifically prohibited the
maintenance technicians from moving any sensing line clamps
or fittings. As of July 1, 1994, the WR/JO was scheduled
for performance the following week. On July 8, 1994, the
inspectors independently verified that the sensing lines for
FT-605 failed to rise continuously from the transmitter to
the sensing element. This confirmed licensee observations
made earlier that week. This arrangement was contrary to
the transmitter manufacturer's recommendation that the
sensing lines rise approximately one inch for every foot of
run between the transmitter and the flow sensing element.
At the end of the inspection period, the licensee was making
plans to properly route the sensing lines.
The inspectors noted that the two most recent failures of
FI-605 on April 21, 1994, and July 1, 1994, both occurred
after ACR 93-315 identified gases trapped in improperly
routed FI-605 sensing lines as a potential cause of the
erratic operation of FI-605.
10 CFR 50 Appendix B, Criterion XVI requires in part that
measures be established to ensure that conditions adverse to
quality are promptly identified and corrected. Furthermore,
Criterion XVI requires that corrective action be taken to
preclude repetition of significant conditions adverse to
quality.
Contrary to the above, the licensee failed to take
corrective action for repetitive failures of Flow Indicator,
FI-605, Residual Heat Removal Total Flow, between May 18,
1991; and July 1, 1994. A proposed corrective action to
reroute the associated transmitters sensing line was
identified in February 1994, but was not implemented before
the two most recent failures of the instrument on July 1,
1994; and April 21, 1994. This is identified as a
violation, VIO: 94-17-02, Failure To Correct Improperly
Routed Instrument Sensing Lines While Troubleshooting
Repetitive Gas Binding of RHR Flow Indicator.
On July 15, 1994, the inspectors requested that the licensee
evaluate the potential that the previous instances of
venting FT-605 may be symptomatic of air trapped in the dead
leg of RHR piping immediately downstream of flow element.
This request was based on the inspectors concern that the
upwardly sloping RHR line and lack of a high point vent on
the RHR piping downstream of the flow element could create a
potential water hammer situation. The licensee stated that
this would be evaluated in their ACR addressing the July 1,
1994, failure of FI-605. The inspectors will monitor this
effort as an unresolved item, URI: 94-17-03, RHR System
Concerns Resulting From FI-605 Inspection Effort.
- 0
5
2)
RHR System Operability
The inspectors reviewed an engineering memo dated July 1,
1994, which evaluated the erroneous FI-605 flow indication
on RHR system operability. The memo, which served as the
technical basis for Operability Determination, OD# 94-26,
concluded that the system was operable despite the 1000 gpm
flow indicated in the idle RHR system.
The inspectors noted that neither the engineering memo nor
the operability determination explicitly discussed the
potential impact the erroneously reading instrument would
have on the operator's ability to implement emergency
procedures. Instead, focusing on the Regulatory Guide 1.97
designation of FI-605, the memo concludes that FI-605's only
function is to provide an indication that the RHR system is
operating. Further, it concludes that Regulatory Guide 1.97
instruments with a higher ranking of significance, such as
core exit thermocouples and loop temperatures would provide
this same information. The inspectors concluded that this
argument was mis-focused, and neglected steps in EPP-9 and
EPP-10 which specifically require the operators to take
actions based on numerical values taken from FI-605. The
inspectors acknowledge licensee arguments that degraded or
improperly adjusted ECCS flows would eventually result in
inadequate core cooling and hence, elevated primary
temperatures and would thus call for the use of functional
restoration procedures which exist to counter this
situation. However, the inspectors concluded that this
approach was less conservative than using properly
operating, installed plant instrumentation to progress
through the pre-defined End Path Procedures. On July 6,
1994, after inspector discussions with the licensee,
Operations management issued a memo to the operators on
these concerns. This memo outlined the potential that
FI-605 could read erroneously following RHR pump
recirculation and that the operators should consult
alternate confirmatory indications of RHR pump performance.
The engineering memo also contained a technical error. It
states that while FI-605 was reading erroneously, ERFIS
indicated the actual flow of zero gpm. The memo attributes
this purported divergence in readings to the operation of a
square-root extractor in the circuit which only modifies the
transmitter signal to the indicator. The engineering memo
notes that the square root extractor is not involved in
other circuit functions such as the RHR pump low flow alarm
annunciator or control of the RHR heat exchanger bypass flow
control valve, FCV-605. Based on this, the memo concluded,
the erroneous reading would not impact RHR system operation
in the cooldown mode.
6
In fact, an ERFIS printout requested by the inspectors,
revealed that the ERFIS input from the FT-605 transmitter
was also approximately 1000 gpm for almost 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> on
June 30, 1994; and July 1, 1994. A significant portion of
this period overlapped the period when FI-605 also indicated
1000 gpm. The inspectors determined from a review of the
shift supervisor logs, that Operations personnel questioned
the divergent ERFIS/FI-605 statement in the Engineering memo
on July 1 and July 2, 1994. When apprised of this error,
the log states that engineering management determined that
the engineering memo conclusions on RHR system operability
remained valid. The inspectors were informed that this
error was not subsequently corrected in the engineering
memo, but would be evaluated in the ACR review of this
issue.
ACR 93-315 made reference to RHR system flow anomalies
documented in a 1990 engineering analysis by Horace Cofer
Associates. The ACR further stated that RHR system
enhancements recommended by the study were not implemented
but instead, alternate improvements were pursued. Near the
end of the inspection period, the inspectors requested that
the licensee provide additional information on historical
RHR system performance problems and efforts implemented to
correct them. At the conclusion of the inspection period
this effort was not complete. The inspectors will track
this effort as part of URI 94-17-03.
c.
Failure To Complete Area Fire Watch Inspection Log
At 2:30 p.m. on July 5, 1994, the inspectors observed that The
Area Fire Watch Hourly Inspection Log posted on the blocked open
EDG A fire door had not been initialled since 10:00 a.m. that
morning. The door had been blocked open to facilitate maintenance
efforts on the EDG earlier that day. The inspectors noted four
initials to document the performance of the hourly fire watches
required by FP-12, Fire Protection Systems Minimum Equipment and
Compensatory Actions, were missing. Following notification of
this observation, the licensee alerted fire protection personnel
and updated the log to reflect the previously undocumented hourly
entries.
The licensee generated an ACR regarding the event and
the plant's Human Performance section also performed an
investigation.
The inspectors reviewed the licensee's investigation and
interviewed one of the maintenance technicians present for the
ongoing maintenance in the EDG A room. Based on this, the
inspectors concluded that the EDG A room probably remained
occupied throughout the 10:00 a.m. to 2:30 p.m. timeframe in
question.
(Since the EDG A room is not a unique security zone,
this conclusion was based upon the ACR and maintenance technician
interview.)
7
The inspectors conclude that the safety significance of the
observation was minimal and most probably reflected a failure to
document the continuous presence of an area fire watch in the
room. The ACR concludes that the failure to designate a single
individual the responsibility for the sheet was a key contributor
to this event. The inspectors concur with this assessment. In
addition to training and counseling on the event, the ACR also
states that the log will be revised to designate a responsible
individual for the hourly reviews.
d.
Operator Failure To Adequately Monitor Plant Status
At 2:19 p.m. on July 7, RCS Loop 2 Flow Indicator, FI-424, failed
to "0".
No annunciator alarms or bi-stable indicator lights were
received. At approximately 2:40 p.m. the Reactor Operator (RO)
started his review of control room indications per Operations
Directive 93-016, Control Room Indicator Review. After completing
his review at approximately 3:15 p.m. he initialed the cover sheet
of the ERFIS printout and initialed the Hot Operation Log. He did
not detect that FT-424 was indicating "0", or that the ERFIS
"Current Quality" code for the ERFIS ID Point Number for FI-424
had printed out as "BAD", or that the 3:00 p.m. ERFIS reading for
that point had printed out as "0".
While doing the 4:00 p.m. Control Room Indicator review, the same
Reactor Operator found FI-424 reading "0"
and asked the Senior
Control Operator (SCO) if he knew of any reason for the "0"
reading. The Reactor Operator checked the 4:00 p.m. ERFIS
printouts and found the quality code for 3:00 p.m. indicating
"BAD" and the reading for FI-424 to be "0".
The Shift Supervisor
was notified of the failed indicator. The Reactor Operator then
went back to the 3:00 p.m. ERFIS printout and found that the
quality code for the point had printed out "BAD" at that time, and
that it was also indicating "0".
He initialed the 3:00 p.m. "BAD"
indication at this time, but did not document that it was a late
entry. After management reviewed the event, the Reactor Operator
was relieved of his watch at 5:40 p.m., and was subsequently
terminated.
Work Request 94-AJNL1 was written and I&C was notified. FT-424
was taken out of service (bi-stable tripped) per Operations Work
Procedure, OWP-31-LFT-4, at 4:25 p.m. A blown fuse was found in
the isolation amplifier for FI-424. All protective functions
remained operable for the channel before and after the bi-stable
was tripped. FI-424 was placed back in service at 7:19 p.m. that
evening.
The Control Room Indicator Review includes monitoring of the RTGB
indicators, recorders, lighted annunciators, Control Room panels,
scheduled ERFIS printouts, alarm printouts, and the Fire Alarm
Computer display. The operator stated that several activities
were in progress at the time of the review, including the
8
performance of MST-021, "Reactor Protection Logic Train "B" at
Power", and maintenance work on feedwater heater level control
switches. He also stated that two individuals were standing at
the RTGB recording information related to FI-605, and that he
stepped around them to continue his review. FI-605 is located in
the same area of the RTGB as FI-424. It appears that the RO
missed reading the indicator as he moved around the individuals at
the RTGB. In any case, the review was inadequate.
Once the RO completed his 3:00 p.m. RTGB review, he started his
review of the ERFIS printouts. The printout is typically 10-12
pages.
On the Hourly Hot Log there were two indications that
problems existed with the FI-424 reading. This log provides a
"Current Quality" code for each of the data points and the actual
hourly reading of each indicator over the last 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period.
The report listed the Current Quality code as "BAD"" and the
3:00 p.m. reading as "0" for FI-424.
The RO indicated that his normal method of reviewing the log was
to check the quality codes and then compare the current reading to
the previous hours. He was uncertain as to how both indications
could have been missed during his review.
Operations Directive 93-016 requires the individual performing the
review to initial the Hot Operations Log Sheet once the hourly
Control Indicator Review is complete. While no other initials are
required, there is a standard practice of initialing the ERFIS
printout cover sheet to indicate that the logs have been reviewed.
The RO indicated that he typically initials the first time that an
indication is "BAD". In this particular case the RO did not
identify that FI-424 had failed to "0" until he performed his
4:00 p.m. RTGB review. Once he noted the failed indicator, he
asked the Senior Reactor Operator if there was any reason the
indicator should be reading "0".
He also reviewed the 4:00 p.m.
ERFIS printout and noted that the indicator read "0" at 3:00 p.m.
and 4:00 p.m. He then retrieved the 3:00 p.m. ERFIS printouts and
determined that the printout indicated that the FI-424 Current
Quality code had been "BAD" and the reading had been "0".
He then
initialed the 3:00 p.m. printout to indicate that this was the
first time that code was listed as "BAD". In an interview with
the Operations Manager and Shift Operations Manager immediately
following the event he admitted that he did not detect the bad
indication at 3:00 p.m., but initialed the 3:00 p.m. quality code
after it was identified during the 4:00 p.m. review. Licensee
management, after reviewing the circumstances of the event,
relieved the Reactor Operator of his watch at 5:40 p.m., and
subsequently terminated him.
Technical Specification 6.5.1.1, Procedures, Tests and
Experiments, requires in part, that written procedures be
established, implemented and maintained covering the activities
9
specified in Appendix A of Regulatory Guide 1.33, Rev. 2, February
1972, including power operation and process control.
Operations Directive 93-016, Control Room Indicator Review
provides instruction to the operators concerning the performance
of control room indication review. Implicit in this requisite is
the expectation that the operators know the status of the plant.
Contrary to the above, at 2:19 p.m. on July 7, 1994, RCS Loop 2
Flow Indicator, FI-424, failed to "0".
At 3:15 p.m., the operator
completed a control room indicator review per Operations Directive 93-016, Control Room Indicator Review. The operator failed to
detect that FI-424 was indicating "0", that the ERFIS "Current
Quality" code for the ERFIS ID Point Number for FI-424 had printed
out as "BAD", or that the 3:00 p.m. ERFIS reading for that point
had printed out as "0".
After careful consideration of the circumstances associated with
this event, foremost being the safety significance, this violation
will not be subject to enforcement action because the licensee's
efforts in identifying and correcting the violation meet the
criteria specified in Section VII.B of the Enforcement Policy.
This event will be tracked as NCV: 94-17-04, Operator Failure To
Adequately Monitor Plant Status.
e.
Followup on Previous Operation Findings
(Closed) URI 94-16-02 Inoperable Post Accident Containment Vent
Path.
As reported in Inspection Report 5-261/94-16, on May 31, 1994,
during a routine tour of the BIT room, the inspectors observed
that the inlet and outlet dampers for the B PACV filter were
closed with clearance tags attached. The inspectors questioned
the shift supervisor on the operability of the system since the
dampers blocked flow through the B train PACV flowpath.
Specifically, the inspectors were concerned that access to these
dampers would be restricted following a LOCA due to prohibitive
radiation levels from adjacent piping in the room which would
contain reactor coolant. Later that day, the clearance tags were
removed and the dampers were returned to the open position.
On June 8, 1994, the inspectors were advised that licensee
analysis indicated that calculated radiation exposures would not
have precluded restoring the system to service following a LOCA.
Based on times obtained to restore the dampers during trial runs
and calculated radiation levels, the licensee stated that the
train could be returned to service with an exposure of about 150
mRem.
During this report period, the inspectors reviewed the regulatory
requirements associated with the PACV system as well as the
description of the system's function and design basis as
delineated in the UFSAR.
The Post-Accident Venting System consists of two full capacity
supply lines through which hydrogen-free air can be admitted to
the containment, two full capacity exhaust lines through which
hydrogen bearing gases may be vented from the containment, and
associated valving and instrumentation.
Operation of the Post-Accident Venting System does not require the
use of fans during venting. Rather, based on the containment
hydrogen concentration and on the hydrogen generation rate, the
operator will determine the flow rate required to maintain the
hydrogen concentration at three percent by volume by venting the
containment. The operator will determine the containment pressure
necessary to obtain the required vent flow, and hydrogen-free air
will be pumped into the containment, using either the station air
compressor or one of the two instrument air compressors, until the
required containment pressure is reached. The air supply will
then be stopped and the supply line isolated. Venting will then
be started by opening the containment exhaust line to the plant
vent through the B train of PACV, and adjusting the throttling
valve to obtain the required flow. Operation will continue as
required to maintain the hydrogen concentration at approximately
three percent by volume.
Operation of the Post-Accident Venting System is performed via
Operating Procedure OP-922, Post Accident Containment Hydrogen
Reduction/Venting System. Although the preferred method of
hydrogen abatement is through the use of a shared hydrogen
recombiner which is normally stored at another facility, in the
event the recombiner was not available, the technique described
above would be employed. In such an event, OP-922 directs the
operators to align the system such that containment would be
vented through the B PACV filter unit, which during the time in
question, would have been isolated by the aforementioned dampers.
The inspectors reviewed the circumstances which lead the operators
to render the PACV filter unit inoperable, yet take no
compensatory measures, or limit the time the system would be
The applicable Technical Specification 3.3.5, requires only that
the valves in the system be operable before the unit is critical.
Although it could be argued that implicit in this requirement is
the requisite that the system be maintained operable during the
operation of the plant, the licensee disagrees. The licensee
stated that the PACV system would not be required to be used until
approximately 30 days after the accident, and that time would be
sufficient to make any necessary repairs to the system if needed.
The inspectors do not totally disagree with the licensee's
position, but surmised that the position was predicated on the
belief that the portions of the system in need of repair would be
readily accessible in the post LOCA environment. This may not be
the case, depending on the component in need of repair.
The inspectors reviewed OMM-005, Clearance And Test Request,
OMM-004, Operations Work Procedure, OMM-007, Equipment Inoperable
Record and OMM-008, Minimum Equipment List And Shift Relief and
interviewed a number of Senior Reactor Operators to
comprehensively evaluate the means employed by the operators in
removing equipment from service. From this review, the inspectors
concluded that there exists no procedural guidance to assist the
operators in properly evaluating and/or removing a piece of
equipment from service if that piece of equipment does not have a
specific TS action statement associated with its removal.
This is
true even if the equipment may be called upon to function during
or after an accident. Two examples of such equipment are the
AMSAC and PACV systems.
10 CFR 50 Appendix B Criterion V requires that activities
affecting quality shall be prescribed by documented instructions,
procedures, or drawings of a type appropriate to the
circumstances, that these instructions, procedures or drawings
include appropriate acceptance criteria, and that the activities
be performed in accordance with these instructions, procedures, or
drawings.
On May 31, 1994, the inspectors concluded that there exists no
procedural guidance to assist the operators in properly evaluating
and/or removing a piece of equipment from service if that piece of
equipment does not have a specific TS action statement associated
with its removal, (examples are fire protection equipment, RETS
equipment, and dedicated shutdown equipment), even though the
equipment in question may be called upon to function during or
after an accident.
Two examples of such equipment are the AMSAC and PACV systems.
This lead operators to render the B train of the PACV system
inoperable with no time limit on the time the equipment could
remain inoperable or if the equipment could be returned to
service, during or after an accident. This is identified as a
violation, VIO: 94-17-01, Inadequate Procedures Governing
Equipment Control.
URI 94-16-02, Inoperable Post-Accident
Containment Vent Path, is closed.
4.
Maintenance Observation (62703)
a.
General
The inspectors observed safety-related maintenance activities on
systems and components to ascertain that these activities were
conducted in accordance with TSs and approved procedures. The
inspectors determined that these activities did not violate LCOs
12
and that required redundant components were operable. The
inspectors verified that required administrative, material,
testing, radiological, and fire prevention controls were followed.
In particular, the inspectors observed/reviewed the following
maintenance activities detailed below:
WR/JO 94-BYG191
Calibrate Narrow Range PPS Flow
Transmitters
WR/JO 94-ABAW1
Repair Air Leak On Solenoid For
EDG B
WR/JO 94-AJCQ1
Repair Air Leak Between DA-19B and
DA-20B
b.
PPS Wide Range Flow Instruments
The inspectors witnessed performance of a portion of WR/JO 94
BYG191 Calibration Of Narrow Range Flow Transmitters on June 23,
1994. The conduct of the calibration was satisfactory.
During the post-maintenance review of the work, the inspectors
questioned the licensee on why no calibration was performed on the
wide range flow indicators. These wide range rotameters were
installed in May 1992 by MOD-1094 to expand the range of PPS flow
rates which could be monitored by installed plant instrumentation.
Though the "C" train PPS wide range instrument had been in service
at least since the end of RFO-15 (in
excess of three months),
neither it nor any of the other wide range PPS flow instruments
were included in the licensee's calibration program. Given that
the licensee utilizes the PPS system to accomplish 10 CFR 50
Appendix J and Sensitive Leak Rate Testing per TS 4.4.1.2.a, the
inspectors were concerned that required testing was being
accomplished using instruments outside the calibration program.
In response to their questions, the inspectors were provided
Engineering Evaluation 93-065, Rotameter Calibration and Range
Evaluation dated July 26, 1993.
This EE concluded that
calibration of the wide range PPS rotameters was not necessary
unless improper operation of the instruments was suspected.
Instead, the EE recommended an inspection of the rotameters at
least every refueling outage.
The inspectors reviewed the EE and concluded that the logic
presented to not routinely calibrate the wide range flow
transmitters was weak. Specifically, the EE:
-
cited contacts with other utilities, many of which
calibrated rotameters used in alternate applications
-
failed to address the implications of a TS 4.4 bases
sentence which states that the PPS flow measurement
13
accuracy is within plus or minus one percent.
(This
was noted in a licensee review of the EE but dismissed
by stating that the PNSC had approved a then proposed
TS basis change.)
-
failed to resolve a conflict with a requirement in
Section 8 of the corporate QA manual that instruments
used to verify data points required by TS be in a
calibration program. (This issue was also raised by a
licensee review of the EE but no clear rebuttal was
made by the NED author.)
-
failed to document consideration of the fact that
ANSI/ANS 56.8-1987, Containment System Leakage Testing
Requirements, recommends specific calibration
frequencies for flow instruments used in Type B
testing.
(The licensee is not committed to this
standard.)
10 CFR 50 Appendix B Criterion XII requires that measures be
established to assure that instruments used in activities
affecting quality are properly controlled and calibrated.
Contrary to the above, on June 23, 1994, the penetration
pressurization system wide range flowmeters were not included in
the licensee's calibration program. At the time of this
observation, the C train penetration pressurization system
flowrate was being monitored by the wide range instrument. This
is a violation, VIO 94-17-05: Failure To Include Wide Range
Penetration Pressurization Flowmeters In Calibration Program.
The inspectors were advised at the end of the inspection period,
that the an engineering evaluation will be performed to address
the appropriate calibration interval for the PPS wide range
flowmeters. Additionally, the licensee stated their intention to
generate an ACR to review this event.
5. Surveillance Observation (61726)
a.
General
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 procedure 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, and test
14
instrumentation was properly calibrated. Specifically, the
inspectors witnessed/reviewed portions of the following test
activity:
OST-252
RHR Component Test (Quarterly)
b.
RHR System Component Test
On July 6, 1994, the inspectors witnessed performance of
Operations Surveillance Test, OST-252, RHR Component Test
(Quarterly). This test cycles various RHR system related valves
to assess their performance and operational readiness.
Overall, the inspectors concluded that the performance of the test
was satisfactory. Strengths noted included consistent use of the
licensee's self-check program by the operators, identification and
documentation of procedural deficiencies by control room
watchstanders, and involvement of the SCO and STA in overseeing
and monitoring the test.
During performance of the test, the inspectors questioned the
shift supervisor on the need to declare an entry into a TS LCO
action statement based on the cycling of the RHR-752 A and B and
RHR-759 A and B valves. These valves isolate the appropriate RHR
pump suction and RHR heat exchanger discharges, respectively. The
valves are normally open and do not receive a signal to open when
an SI is initiated. The inspectors were concerned that if an SI
signal were actuated with any of the 4 valves shut, a train of RHR
would be unavailable for automatic injection. Following this
discussion and after a review of the system drawing, the SS
entered and exited the appropriate TS LCO action statement prior
to cycling these valves.
The inspectors noted that entry into a TS LCO action statement was
not documented for the last two performance of this surveillance
test contained in the vault. However, the inspectors are aware
that action statements are routinely entered for some other safety
system surveillances. During followup discussions on this issue
on July 7, 1994, licensee management indicated they had generated
an ACR to evaluate the need for a consistent approach to TS LCO
action statement entry for surveillance testing as a result of a
recent, similar NAD finding. The inspectors will monitor licensee
efforts in this area during monitoring of surveillance testing.
6.
Exit Interview (71701)
The inspection scope and findings were summarized on July 22, 1994, with
those persons indicated in paragraph 1. The inspectors described the
areas inspected and discussed in detail the inspection findings listed
15
below and in the summary. Dissenting comments were not received from
the licensee. The licensee did not identify as proprietary any of the
materials provided to or reviewed by the inspectors during this
inspection.
Item Number
Description/Reference Paragraph
VIO: 94-17-01
Inadequate Procedures Governing Equipment
Control/paragraph 3.e.
VIO: 94-17-02
Failure To Correct Improperly Routed Instrument
Sensing Lines/paragaph 3.b.1.
URI: 94-17-03
RHR System Concerns Resulting From FI-605
Inspection Effort/paragraph 3.b.2.
NCV: 94-17-04
Operator Failure To Adequately Monitor Plant
Status/paragraph 3.d.
VIO: 94-17-05
Failure To Include Wide Range Penetration
Pressurization Flowmeters In Calibration
Program/paragraph 4.
. 7. List of Acronyms and Initialisms
ACR
Adverse Weather Condition
ATWS Mitigating System Actuation Circuitry
Adverse Condition Report
Anticipated Transient Without Scram
BIT
Boron Injection Tank
Equipment Core Cooling System
EE
Engineering Evaluation
End Path Procedure
ERFIS
Emergency Response Facility Information System
FI
Flow Indication
FT
Flow Transmitter
gpm
Gallons Per Minute
Instrument & Control
LCO
Limiting Condition For Operation
Loss of Coolant Accident
Maintenance Surveillance Test
NAD
Nuclear Assessment Department
Non-Cited Violation
NED
Nuclear Engineering Department
OMM
Operation Management Manual
PACV
Post Accident Containment Vent
Penetration Pressurization System
Quality Assurance
Radiological Environmental Technical Specifications
Reactor Turbine Gage Board
16
Shift Technical Adviser
TS
Technical Specification
Updated Final Safety Analysis Report
Unresolved Item
WR/JO
Work Request/Job Order