ML14178A293
| ML14178A293 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 11/04/1992 |
| From: | Christensen H, Garner L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML14178A291 | List: |
| References | |
| 50-261-92-27, NUDOCS 9211180130 | |
| Download: ML14178A293 (18) | |
See also: IR 05000261/1992027
Text
1
<
tRUNITED
STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
C
Report No.:
50-261/92-27
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 Conducted: September 5 - October 9, 1992
Lead Inspector:
1-,(i
"
/// /
L.
. Gartr,
Senior Resident Inspeptor
Date Signed
Other Inspector* C. R. Ogle, Resident Inspector
Approved by:___
5
H. 0. Christensen, Chief
Dat4 Sined
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
meeting with local officials.
Results:
Two violations were identified concerning inadequately established procedures
and failure to implement procedures for reduce RCS inventory operations. In
addition, a number of weaknesses and deficiencies were identified with reduced
inventory operations. These included inadequate technical knowledge,
inadequate-communications, an -ineffective Operating Experience Feedback
program, and incomplete logkeeping (paragraph 3).
A violation was identified for failure to secure a containment penetration
with a deactivated closed containment isolation valve within four hours as
required by limiting condition for operation of Technical Specification 3.6.3.
(paragraph 3).
9211180130 921104
PDR ADOCK 05000261
G0
2
A non-cited violation was identified for failure to establish as adequate
maintenance procedure in that the procedure identified the incorrect isolation
amplifier to be installed in a safety-related circuit (paragraph 5).
The licensee's emergency preparedness response to an Alert condition
associated with a CO2 release in a vital area was good (paragraph 3).
Insufficient procedural precautions and poor configuration control resulted in
the inability to remotely reopen the shutdown cooling isolation valve during
inservice inspection testing (paragraph 3).
Operations conducted a less than thorough RCS leak check (paragraph 4).
1.
Persons Contacted
- R. Barnett, Manager, Outages and Modifications
- C. Baucom, Senior Specialist, Regulatory Compliance
- R. Chambers, Plant General Manager, Robinson Nuclear Project
B. Clark, Manager, Maintenance
T. Cleary, Manager, Technical Support
C. Dietz, Vice President, Robinson Nuclear Project
R. Femal, Shift Supervisor, Operations
W. Flanagan, Manager, Operations
- W. Gainey, Manager, Plant Support
- G. Grant, Acting Manager, Operations
- W. Hammond, Engineer, Quality Assurance
- J. Harrison, Manager, Regulatory Compliance
- R. Howell, Senior Specialist, Nuclear Assessment Department
P. Jenny, Manager, Emergency Preparedness
D. Knight, Shift Supervisor, Operations
A. Padgett, Manager, Environmental and Radiation Control
D. Seagle, Shift Supervisor, Operations
- D. Stadler, Onsite Licensing Engineer, Nuclear Licensing
G. Walters, Operating Event Followup Coordinator, Regulatory Compliance
- A. Wallace, Shift Operations Coordinator
D. Winters, Shift Supervisor, Operations
Other licensee employees contacted included technicians, operators,
engineers, mechanics, security force members, and office personnel.
NRC Managements Visits
S. Ebneter, Regional Administrator - Region II, E. Merschoff, Division
Director - DRP, E. Adensam, Director -
Project Directorate II-1, R.
Trojanowski - Regional State Liaison Officer, and H. Christensen,
Section Chief - DRP Section 1A were onsite September 24 to visit the
facility, present the SALP to the licensee, and meet with local
officials.
- Attended exit interview on October 14, 1992.
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2.
Plant Status
The unit began the report period in cold shutdown for removal of foreign
material from the SI system and associated safety-related components.
On September 6, decay heat removal was interrupted for a longer period
than anticipated during RHR-750 valve stroke time surveillance testing.
Once closed, the RHR-750 valve could not be reopened remotely due to an
open permissive unknowingly being defeated by the system clearance
established for RWST foreign material inspection activities. The RCS
temperature increased from 136 to 140 degrees F in the time,
approximately 35 minutes, required to manually reopen RHR-750.
2
Inspection, flushing, and cleaning activities of the SI system were
completed on September 10. Modification and SI system performance tests
were also satisfactorily completed on September 10.
After management
review, the A and B SI pumps and the SI system was declared operable on
September 12.
Excessive seal leakoff from the B RCP resulted in reduced
inventory operation from September 12 to 17 while the seal package was
repaired. Bonnet-to-body leak repairs to the CVCS letdown isolation
valves CVC-460A and B and replacement of the control room ventilation
compressor for WCCU 1A subsequently delayed restart until September 23.
The turbine generator was placed in service on September 24 and 100%
power operation was obtained on September 26. At 3:33 a.m. on September
30, an Alert was declared due to a slow release of carbon dioxide fire
suppressant (considered a toxic gas) into pipe alley (mechanical CV
penetration area).
Later that morning, at 9:01 a.m., the Alert was
exited after the supply of carbon dioxide to the leak was depleted and
oxygen levels in the immediate vicinity of the leak, as well as adjacent
areas, were verified to be normal.
The unit continued full power
operation for the remainder of the report period without further
significant operational events.
3. Operational Safety Verification (71707)
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.
To verify equipment operability and compliance with TS, the inspectors
reviewed shift logs, Operation's records, data sheets, instrument
traces, and records of equipment malfunctions. Through work
observations and discussions with Operations staff members, 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.
The
inspectors performed channel verifications and reviewed component status
and safety-related parameters to verify conformance with TS. Shift
changes were 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 generally carried
out their assigned duties in an effective manner. Control room demeanor
and communications were typically adequate.
Plant tours and perimeter walkdowns 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.
3
Foreign Material Removal From The SI System
Foreign material in the SI system and associated components has
previously been discussed in IR 92-21 and 92-24. During this report
period, the licensee completed implementation of their SI System
Recovery Plan and returned the SI system to service on September 12,
1992. Activities completed included: installation of M-1134, Install
Permanent Strainers In SI Pump Recirculation Lines, for the A and B SI
pumps; inspection of selected SI and RHR piping and components; and,
perform system tests to demonstrate operability. In addition, as
required by Confirmation Of Action Letter, dated September 1, 1992, a
meeting was conducted with Region II management to discuss results of
recovery plan activities and root cause of the event. This meeting was
conducted in the Region II Office on September 8, 1992. After review of
the licensee's presentation, regional management determined that the
actions taken to remove foreign material from the safety-related systems
and components and the inspections performed of these systems and
components provided a reasonable level of confidence that these systems
and components would perform their safety functions if required. Also,
it was determined that the licensee had complied with the conditions of
the Confirmation Of Action Letter and thus could proceed, when ready,
above hot shutdown conditions. During the meeting, the licensee
committed to perform, during the next refuel outage, additional flushes
(or inspections) of piping sections which were deemed impractical to
flush with fuel in the core.
The inspectors inspected selected activities associated with the SI
System Recovery Plan. The inspection activities included: observation
of video camera inspections; verification that foreign material controls
were implemented around open systems, review of post maintenance test
requirements to ensure that reassembled components would function
properly; and, observation of maintenance and modification work
activities. In particular, the inspectors observed the disassembly and
inspection of the A SI pump recirculation line orifice. No foreign
material was found in the line or orifice. The licensee's review of
previous recirculation flow data revealed that the data point used to
determine that a 10% flow reduction had occurred in the A SI pump
recirculation flow was abnormally high. The licensee provided no
explanation for the abnormity. The inspectors agreed that the data was
approximately 2 to 3 gpm higher than normal.
However, since both the A
and B SI pump data was offset by about the same amount and the same
measuring equipment was utilized, it is possible that one of the other
SI system test valves, such as SI-895K or SI-895U, was not fully closed
when the higher than normal data was obtained. The inspectors also
reviewed the material presented during the September 8 meeting and have
no further questions at this time.
Unanticipated Extension Of Loss Of Decay Heat Removal During Testing
On September 6, 1992, during valve stroking per of OST-703, ISI Primary
Side Valve Test, the shutdown cooling supply line isolation valve, RHR
750, could not be reopened using the RTGB control switch. The valve was
4
subsequently manually opened by an operator who had been stationed at
the valve to observe stem travel.
During the approximate 35 minutes it
took to reopen the valve, the observed RCS coolant temperature rise
attributed to the inability to remotely open the valve was approximately
4 degrees F, i.e., 136 to 140 degrees F. For comparison, the similar
temperature rise attributed to securing RHR shutdown cooling was
approximately 13 degrees F.
Subsequent investigation revealed that an open permissive interlock
associated with the RHR pumps' RWST suction isolation valves, SI-862 A
and B, was not present due to the control circuits for these valves
being de-energized. These valve control circuits had been de-energized
to establish a clearance boundary for foreign material inspection
activities of the RWST and associated ECCS pumps' supply piping.
ACR 92-339 was issued to address the root causes of this event.
Immediate corrective actions to preclude this particular event included
identification of a procedure change request to provide a precaution
note in OST-703 to address the valve interlocks associated with RHR-750
and RHR-751 (the redundant isolation valve to RHR-750).
During clearance development, personnel did not identify that the SI-862
A and B control circuit de-energizations would open opening permissive
contacts in the RHR-750 control circuitry. The inspectors verified that
a thorough review of CWD B-190628 sheets 248 and 249 (SI-862A and B
control circuits respectively) would have identified that the opening
control circuit on sheet 212 (RHR-750) was disabled by de-energizing the
SI-862 A and B control circuits. Failure to identify adverse equipment
impacts during the clearance development process was an example of poor
configuration control. The inspectors plan to review the final ACR
package, when available, to verify that adequate corrective actions are
taken.
Reduced Inventory Operation
The inspectors' observations and review of reduced inventory evolutions
revealed several deficiencies. Each of these items are discussed in
more detail in subsequent paragraphs. Associated with the inventory
reduction of September 12, the identified deficiencies included: 1)
inadequate procedures to preclude loss of decay heat removal during
inventory reduction; 2) inadequate technical knowledge to analyze the
consequences of draining the RCS with the PRT pressurized; 3) failure of
the pre-evolution shift briefing to define under what conditions the RCS
inventory was to be accomplished; 4) inadequate communications between
management levels which allowed the inventory reduction to be performed
in a manner other than that envisioned by the Acting Operations Manager;
and, 5) an ineffective OEF program which failed to familiarize
Operations personnel with industry events involving level
instrumentation errors associated with inventory reduction with the RCS
pressurized. On September 13, a subsequent inventory reduction from -25
inches to -34 inches demonstrated a lack of sensitivity by the operating
shift to potentially violating procedure requirements, in that, the
5
inventory reduction was accomplished utilizing only one instrument
channel.
In addition, refilling the PRT on September 16 resulted in the
following findings: 1) the procedure failed to provide precautions
concerning the potential impact of pressurizing the PRT if the PRT is
refilled too rapidly; 2) incomplete logkeeping was demonstrated, in
that, the logs did not record that the initial operator response to an
unexpected reactor vessel water level increase due to the PRT
pressurization was to add more water to the vessel; and, 3) the
Operations corrective action program was poorly implemented in that the
initial response by the operator was not entered into the program for
subsequent analysis and management review. Although a number of
deficiencies were identified during specific reduced inventory
evolutions, no safety significant plant transients resulted from these
items.
ACR 92-343 was issued to document the event sequence associated with the
September 12 inventory reduction and to determine root causes and
required corrective actions. The event sequence as extracted from the
ACR, relevant documentation, and from inspectors' observations of
evolutions in progress follows. On September 10, while performing
preliminary checks to support starting the B RCP, it was discovered that
the no. 1 seal leakoff flow exceeded the 5 gpm procedure maximum
limitation of OP-101, Reactor Coolant System And Reactor Coolant Pump
Startup And Operation. Subsequent attempts to correct the condition
were unsuccessful.
On September 11, plant management, after
consultation with the NSSS, determined that the seal should be removed
and repaired.
Seal removal required the RCS system inventory to be
reduced to below the pump flange, i. e.,
-25 inches below the reactor
vessel head flange. On September 12, prior to the 7:15 a.m. shift
briefing, the inspectors discussed with the Acting Operations Manager
the problem experienced at another utility with vessel water level
instrumentation accuracy due to the RCS being pressurized. The
inspectors were shown the procedure steps which would be used to vent
the RCS system to the CV atmosphere during system draining. At the end
of the shift briefing, the Acting Operations Manager conducted a Case I
briefing, as designated in PLP-037, Conduct Of Infrequently Performed
Test and Evolutions, concerning the scheduled RCS partial draining. The
briefing emphasized that draining the RCS system too rapidly would
result in instrumentation errors. However, the PLP-037 briefing did not
inform the operating crew that the draindown was to be performed with
the RCS vented to the CV atmosphere nor did it include the industry
event discussed by the inspectors. Subsequent to this briefing,
discussions among the operating crew and a chemistry technician resulted
in the decision by the SS to draindown with 5.0 psig nitrogen pressure
on the PRT, an option allowed by GP-008, Draining The Reactor Coolant
System. The decision was based on the desire to minimize corrosion
product formation due to increased oxygen concentrations. The Acting
Operations Manager was not informed of this decision. In preparation
for draining the RCS, the PRT level was lowered to a point at which the
PZR relief line discharge nozzles inside the PRT were uncovered and the
PZR PORVs were blocked open. This allowed the PZR to be vented directly
to the PRT gas space.
6
At 9:40 a.m., draining of the RCS was initiated in accordance with GP
008. At approximately 4:30 p.m. with PZR water level at 15%, the
draindown was stopped while the loop 2 and 3 RCS water level
instruments, LT-403 and LT-404, were placed in service. At this time,
the shift SRO expressed concern to the SS that having nitrogen pressure
on the RCS with the standpipe instrumentation (LT-403 and LT-404 which
feed RTGB level indicators LI-403 and LI-404 respectively) vented to the
CV atmosphere would force water up the standpipes and provide erroneous
indications. He was aware of the rule of thumb that 33 feet of water is
equal to 15 psig. Several people on shift, including the SS, did not
remember that there had been large variations between the instrument
readings when nitrogen pressure was used and when the pressure was
subsequently vented off. The fact that the procedure allowed the system
to be drained in this manner was further construed as evidence that this
would not be a problem. The decision was made to resume the draindown
with 5 psig nitrogen pressure on the PRT and verify that LI-403 and LI
404 would come on scale (zero reading) when vessel level decreased to
the vessel flange top as by indicated RVLIS (flange top is 83.3% on
RVLIS).
Shortly after 5:00 p.m., the inspectors, while verifying that
the inventory reduction was being accomplished in accordance with GP
008, noted that the RCS vent valve to the CV atmosphere, RC-572, was
closed and the alternate method with 5.0 psig nitrogen pressure on the
PRT was being utilized. At this time, the cold calibrated PZR water
level instrument, LI-462 was off-scale low and LI-403 and LI-404 were
not yet on scale. The inspectors discussed the observation with the
Acting Operations Manager who was in the control room at the time. He
was unaware that the PRT and, consequently, the RCS was pressurized.
The inspectors re-iterated that pressurization of the RCS would non
conservatively effect LI-403, LI-404 and their associated tygon tube
indicators inside the CV since these were vented to the CV atmosphere.
Initially, the inspectors were informed that hydraulic losses between
the PRT and the instrumentation would reduce the effect of the pressure
in the PRT and that previous experience had indicated that there was
little difference between level readings taken with the system
pressurized and the system vented. The inspectors indicated that
hydraulic losses would be small and that the system should be considered
a static system. The inspectors requested the licensee to provide the
correction and the basis for the correction which would be used to
adjust LI-403 and LI-404 readings. Subsequent discussions among the
Acting Operations Manager, the SS, the SRO, and I & C technicians
resulted in the decision to stop the draindown, secure nitrogen to the
PRT, and vent the RCS to the CV atmosphere. During the venting process,
the tygon tubes associated with LI-403 and LI-404 were observed to
determine the effect the pressurization had on this instrumentation.
The indicated water level in the vessel was observed to decrease from
approximately 15 feet above the vessel flange to approximately 5 feet
above the vessel flange when the RCS was fully depressurized. The
draindown was then resumed. Later that evening, the licensee discovered
that WR/JOs 92-ANNW1 and 92-ANNX1 which had calibrated LI-403 and LI-404
level indicators prior to initiating the draindown had failed to
specify, as required by GP-008 step 5.1.8, that the associated alarm
switches also be calibrated. The complete instrumentation loops were
- 0
7
subsequently calibrated. Draindown to -25 inches was completed on the
morning of September 13.
As noted above, inspection activities identified several significant
deficiencies associated with the evolution. The inspectors noted that
with RVLIS not required to be inservice per TS or by GP-008, draining of
the RCS with 5.0 psig of nitrogen on the PRT in accordance with GP-008
would result in loss of decay heat removal.
With a 10 foot non
conservative error in the indicated level verses the actual RCS level,
LI-403 and LI-404 would not come onscale until the actual RCS water
level reached -120 inches below the vessel flange top. However, the RHR
pump providing decay heat removal would cavitate and have to be shutdown
before that level would be reached since the middle of the loop is at
72 inches below the vessel flange. The planned evolution was to stay
about -36 inches so that the provisions concerning midloop operations
(as committed in the licensee's responses to GL 88-17, Loss Of Decay
Heat Removal) would not be required to be implemented. Subsequent NAD
review of previous GP-008 revisions revealed that a typographical error
had apparently occurred during revision 13 (issued April 29, 1988).
Earlier revisions to GP-008 had specified 0.5 psig nitrogen pressure be
used. There was no documentation that the change to 5.0 psig had been
intentional.
The fact that GP-008 was inadequately established so that
compliance with the procedure could potentially cause a significant
operational event is a VIO: Failure To Adequately Establish GP-008 To
Preclude The Loss Of Decay Heat Removal During RCS Inventory Reduction,
92-27-01.
Significant deficiencies were also identified in the OEF program. The
inspectors reviewed the outstanding change request to GP-008 and the
current revision being processed. There was no indication that lessons
learned from the industry event described in IN 92-16 supplement 1,
i.e., a February 1992 loss of decay heat removal event due to inventory
reduction with the PRT pressurized, had been identified to be
incorporated in GP-008. A review of the OEF process revealed that IN 92-16 supplement 1 had been received onsite on June 10, 1992, and at the
time of the inspection, had not been reviewed for applicability to the
site and distributed for action. The large backlog of OEF items had
previously been identified as an issue in June 1992 by the Regulatory
Compliance subunit, which is responsible for the OEF program
implementation. NAD had also previously identified this as a program
weakness and ACR 92-314 had been initiated on August 17, 1992. However,
due to resource limitations, a plan to correct the problem was not
submitted to management until October 8, 1992. At the end of the report
period, the licensee had not established a schedule to work off the
backlog.
The inspectors reviewed training records which revealed, via personnel
initials, that the operating shift involved in the draindown had read
about the industry event as part of the real time training process. A
Westinghouse letter, detailing the event which was later the subject of
IN 92-16 supplement 1, had been included with the reading material
associated with IN 92-16. This material had been distributed during
8
April and May to licensed personnel for their onshift review. An
interview with the SS revealed that he had no previous recollection of
the IN 92-16 supplement 1 event. The procedure writer, who holds an NRC
license and was assigned the preparation of the GP-008 revision 25, had
also reviewed the real time training material.
Thus, the OEF program
was demonstrated to be ineffective in familiarizing personnel with a
significant industry event.
As described in the event narrative above, LT-403 and LT-404 and their
associated alarms were not calibrated as required by GP-008 step 5.1.8
prior to placement in service. This constituted a failure to implement
procedures as required by TS 6.5.1.1.1.a and is a VIO: Failure To
Implement GP-008 In That RCS Water Level Instrumentation Loops Were Not
Calibrated As Required, 92-27-02.
The shift's inability to correctly resolve a technical question
concerning the impact of RCS pressurization on instrumentation
demonstrated a lack of technical expertise, especially in the area of
hydraulics. Furthermore, the failure to request assistance from other
organizations such as Technical Support or to consult the next
management level to resolve a technical difference of opinion among
licensed crew members was considered a weakness.
Communications of management's expectations were not successfully
accomplished. Communications between the SS and the Acting Operations
Manager were inadequate in that the Acting Operations Manager assumed
that the SS knew that the draindown was to be performed with the RCS
vented to the CV atmosphere. When the decision was made to use nitrogen
pressure in the PRT, the SOM was informed but Operations management was
not notified of the decision. Also, the shift PLP-037 briefing was
inadequate, in that, when GP-008 provided instructions for different
methods to be used for inventory reduction, the specific method to
accomplish the task was not discussed. Also, the PLP-037 briefing
failed to discuss significant industry events such as that described in
IN 92-16 supplement 1.
On September 13, it was necessary to further reduce RCS level to allow
additional inspection of the B RCP pump shaft for possible scoring.
This additional draindown involved lowering water level approximately to
a level just above -36 inches, the trigger point for entering midloop
operation. Midloop operation required additional procedural controls
and equipment to be in service.
For example, 2 independent RCS level
channels, one SI pump, and midloop CV integrity were required for
midloop operation. Because meeting these requirements would extend the
outage and level reduction below -36 inches was not necessary, the
decision was made to maintain RCS water level above this trigger value.
At the time of the additional reduction in RCS inventory, LI-403 was
inoperable, reading low by approximately 10 inches, and RVLIS with an
error tolerance of 6% was not sufficiently accurate to perform the
draindown. The draindown was accomplished with use of only one
instrument channel, LI-404. During the morning, the inspectors observed
that RCS inventory as indicated on LT-404 was approximately -33 inches.
9
When the inspectors asked what the indicated RCS level was on the tygon
tubes attached to the LT-403 and LT-404, operating personnel were
unaware of their present reading. Since the tygon tube readings were
known to be approximately 2 inches lower than LT-404, the inspectors
were concerned that midloop operation may have inadvertently been
entered. The SS directed that the tygon tube readings be obtained.
Both tygon tubes were reported to be slightly below -35 inches.
The
tygon tubes were not monitored when the draindown was performed. The
inspectors noted that the control operator's log had recorded at 0:05
a.m. that RCS level had been lowered to -34 inches by LI-404. Thus
based on the fact that at -33 inches on LI-404 the tygon tubes were
below -35 inches, it was possible that at -34 inches on LI-404, the
tygon tubes could have been below -36 inches. However, do to accuracy
of the data it was not possible to say that midloop operation had been
entered for a limited time without the procedural requirements for
midloop operation being met. However, Operations' reliance on one
instrument channel, which was non-conservative relative to other
available indications, to perform an inventory reduction near to a
procedural limitation reflected a lack of sensitively to the potential
to violate procedural requirements.
On September 16, during preparations to refill the RCS, the PRT was
filled from 12% to 70%. During the PRT filling, one and/or both PW
pumps were used. Rapid filling caused the gas volume to be reduced and
the PRT to pressurize. After the PRT high pressure alarm was received,
the PRT vent was opened. However, due to the small size of the vent
path, the control operator also adjusted the fill rate to control the
pressure increase. Approximately 12 minutes after securing the PRT
fill, the control operator observed that LI-404 indicated that RCS level
had changed from -24 increased to -12 inches. Believing that RCS water
level needed to be increased, he opened HCV-121. Within approximately 2
minutes, while observing VCT level and discussing his actions with the
SRO, he realized that HCV-121 should be closed to decrease RCS
inventory. He subsequently restored RCS level to -17 inches, the level
designated by the SS. The event review determined that the PRT pressure
had been allowed to increase to the point at which the elevation
difference between the PRT and PZR was overcome and water had been
forced out of the PRT back into the PZR through the blocked opened
PORVs. The inadvertent water addition to the RCS reflected a lack of
technical knowledge and a failure to pursue the implications of an
observed phenomena. Procedure reviews revealed that precautions or
notes were not provided to warn of this potential consequence when the
PRT is refilled. In addition, the inspectors noted that the initial
operator action which could have compounded the causality was not logged
or entered into a corrective action program. Failure to log the initial
operator action represents inadequate logkeeping. Furthermore, the
failure to capture the operator's response in the Operations corrective
action program for subsequent analyses and management review was
considered a weakness.
Containment Spray Relief Line Leak
10
On September 25, 1992, while performing routine inspection activities,
the inspectors observed leakage from the CS piping. This was reported
to Operations personnel who determined that the leak, approximately 1
drop per 5 seconds, originated at a weld on relief valve SI-871
tailpipe. The tailpipe was repaired on September 26. The inspectors
verified that TS 3.3.2.2.b LCO was entered and that TS 3.3.2.2.c
provisions were complied with when the repair was performed.
Furthermore, the inspectors verified that OST-355, Containment Spray
System Integrity Test (Annual) was successfully performed prior to
returning the system to service.
Failure To Implement TS Action Within Required Time
On October 2, 1992, at approximately 1:30 p.m., while performing OST
701, Inservice Inspection Valve Test (Quarterly), RC-553, a 3/8 inch air
diaphragm operated CV isolation valve on the gas analyzer sample line
from the PRT, failed to open. The valve was left in the closed position
and WR/JO 92-AQGB1 was initiated at 3:59 p.m. to repair the valve. At
approximately 9:00 p.m. on the same day, the SS while performing a
review of the completed OST-701 identified that this valve was a CV
isolation valve and TS 3.6.3 LCO action statement should have been
performed. TS 3.6.3 required that with one or more automatic
containment isolation trip valves inoperable, either: a. restore the
inoperable valve(s) to operable status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, or b. isolate the
affected penetration(s) within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> by use of a deactivated automatic
valve(s) secured in the isolation position(s), or c. isolate the
affected penetration(s) within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> by use of a closed manual
valve(s) or blind flanges(s), or d. be in cold shutdown within the next
36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.
At 9:16 p.m., the penetration was isolated as required by TS 3.6.3, in that, RC-553 and RC-516 (the redundant CV isolation valve)
were verified to be closed and the power was removed from the valves to
deactivate them in the isolated position. ACR 92-363 was issued on
October 2 to investigate the event and determine corrective actions to
preclude recurrence. Failure to isolate the gas analyzer sample CV
penetration (designated as P-1) with deactivated isolation valves within
4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> as required by TS 3.6.3 is a VIO: Failure To Isolate Gas
Analyzer CV Penetration Within 4 Hours With Deactivated Isolation Valves
As Required By TS 3.6.3, 92-27-03.
Alert Due To CO2 Release In Pipe Alley
On September 30, 1992 at 3:33 a.m. an Alert was declared due a slow leak
of fire suppressant, CO2 gas, into pipe alley. The Alert was terminated
at 9:01 a.m. that same day after the effected CO2 bottles were verified
to be empty and the oxygen concentrations in pipe alley and adjacent
spaces were verified to be normal.
The CO2 gas was discharged to the
plant stack via means of the normal auxiliary building ventilation
system. Oxygen concentrations measured a few feet away from the leak
location never decreased to more than approximately 90% of the normal
oxygen concentration in air.
The event was initiated when personnel reconnected a refilled CO2 bottle
into slot 1 of the north and south cable vault fire suppression system.
The CO2 bank for these areas was located in the south pipe alley. When
a pilot head discharge hose containing a stuck open solenoid valve, CD
13, was sufficiently reconnected to the pilot head to open the spring
loaded outlet check valve, the fire technician heard the CO2 discharge
into the header and immediately attempted to loosen the connection.
However, this attempt was abandoned when the fire technician heard the
discharge valves on other bottles in the CO2 bank open. The other non
pilot head CO2 bottles opened when the discharge header pressure
exceeded their outlet check valve setpoint. Since there was no valid
fire suppression system actuation signal, the discharge valves into the
north and south vault area remained closed. Therefore, the only release
points from the pressurized system was from leakage associated with the
discharge piping components, i.e., the partially engaged hose
connection. The fire technician left the area and reported the event to
the control room. Actions were then taken to secure the area, evaluate
the potential impact on plant equipment and operations, monitor the
oxygen concentrations within the affect and potentially affected areas,
establish required fire watches, and develop recovery actions. At 8:44
a.m., by using a specially assembled pressure gage (none was available
on the discharge header) each effected CO2 bottle was verified to be
depleted.
ACR 92-358 was initiated on September 30 to investigate the
solenoid valve failure and the resultant event. The inspectors will
review the completed ACR, when available, as part of the routine
inspection program.
The Alert was declared in accordance with OMM-031, Emergency Action
Level Procedure User's Guide, step 5.1.17 which defines CO2 as a toxic
gas. This step states that the decision to declare an Alert for a toxic
gas release should be based upon factors such as the release rate and
the effected area's volume with the intent to determine whether the
release would endanger personnel that require access to equipment
required to safely operate the plant. It was prudent to consider this
event as an Alert since the effected area was the mechanical CV
penetration area and under some plant conditions, personnel would
require rapid access to this area for manual equipment operation. Also,
it was uncertain whether the partially disengaged coupling would remain
together or become separated, i.e., release rate would substantially
increase.
The overall response to the event was good. The OSC and TSC were
activated at 4:30 and 4:43 a.m., respectively. Shift turnover among OSC
and TSC organizations were successfully performed when day shift
personnel arrived at approximately 7:00 a.m..
The initial state and
counties' notifications were issued within 15 minutes (at 3:45 a.m.) and
subsequent followup messages were issued at approximately one hour
intervals (at 4:43, 5:33, 6:43, 7:45, and 8:36 a.m.).
The state and
counties were notified at 9:07 a.m. of the event termination. The NRC
was notified of the event within one hour, at 4:17 a.m.. A press
release was issued at 6:35 a.m. which resulted in several calls to the
12
main switchboard from the general public.
Public relations personnel in
the victors center were utilized to help respond to these inquires.
The South Carolina Emergency Preparedness Department activated a portion
of their facility at 5:42 a.m. and a South Carolina Department Of Health
And Environmental Control representative arrived onsite at 7:30 a.m..
He was briefed by the licensee and visited the effected area. The
inspectors asked the state representative if he had any concerns. He
indicated that he had none.
The inspectors were notified at approximately 3:45 a.m., via the
licensee's beeper system, that an Alert had been declared and that the
TSC and OSC was being activated. The inspectors arrived in the control
room at approximately 4:05 a.m. and monitored the licensee's response to
the event from either the control room or TSC until the Alert was
terminated. The inspectors verified that: the event was properly
classified; notifications were timely and adequate; appropriate measures
were taken to ensure equipment and personnel were not adversely affected
by the release; the TSC was adequately staffed; appropriate
communications were maintained among both onsite and offsite emergency
response organizations; recovery actions were developed considering
ALARA and contingency actions as necessary; and, recovery actions were
properly implemented.
Management Changes
During the inspection period a number of organizational reassignments
became effective. The Technical Support Manager was assigned to NED in
the corporate office. His position was filled by the Technical Support
engineering support supervisor. The NED and NAD onsite unit managers
were transfered to the Brunswick facility. The Technical Support
mechanical supervisor assumed the NED site unit manager position. Until
the NAD site unit manager position is filled, the NAD site unit
engineering assessment manager has been designated as acting manager.
Three violations were identified. Except as noted above, the
area/program was adequately implemented.
4. Monthly 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 procedure listed below, the inspectors determined that precautions
were adhered to and the required administrative approvals were obtained
prior to test initiation. Upon test completion, the inspectors verified
the recorded test data was complete, accurate, and test discrepancies
13
were properly documented and rectified as appropriate. Specifically,
the inspectors witnessed/reviewed portions of the following test
activity:
OST-052
RCS Leakage Test And Examination Prior To Startup
Following An Opening Of The Primary System
OST-052
On September 21, 1992, the inspectors conducted a CV housekeeping and
RCS leakage inspection, as well as, observing Operations personnel
perform part of OST-052. Miscellaneous debris (paper, tape, paint
chips, rubber gloves, etc.) observed by the inspectors were removed by
the HP accompanying the inspectors. Approximately one-quarter cubic
foot of debris was collected. Operations personnel identified and
initiated work requests to repair the following items: pipe cap leak on
A accumulator piping drain line, boric acid buildup on primary sample
valve PS-954A packing gland, boric acid buildup on the connector to the
B loop RCS flow instrument root isolation valve RC-513, and boric acid
buildup on a seal table isolation valve. In addition to these, the
inspectors also noted a pipe cap leak on the C accumulator piping drain
line and a packing leak on FW-45, B S/G wide range level instrument LT
487 root isolation valve. The FW-45 packing leak had caused a small
puddle of water under the B hot leg piping. Based upon the puddle size
and the leak rate, this water puddle was there when Operations personnel
performed their leak check. Failure to detect the puddle indicated that
a less than thorough inspection had been performed by Operations. In
addition, the inspectors observed several areas in which there were
water on the floor due to OSTs and maintenance activities which had been
performed earlier. Since small leaks are easier to detect by the
presence of water on the floor, performing a leak check with water on
the floor due to other activities could easily result in small leaks not
being detected. Thus, the failure to wipe up spilled water prior to
performing a leak check constituted a poor work practice. Primary
leakage is typically maintained low at the site, 0.05 to 0.1 gpm.
No violations or deviations were identified. Except as noted above, the
area/program was adequately implemented.
5. Monthly 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, radiological, and fire
prevention controls were adhered to. In particular, the inspectors
observed/reviewed the following maintenance activities:
WR/JO 92-AMWN1
Support To Video Inspection Of SI Piping
14
WR/JO 92-AMRB2
Install SI Pump Recirculation Strainers
Installation Of Incorrect Isolation Amplifier
On September 24, 1992, power increase was stopped at 40.5% due to the
high steam line flow bistable FC-495 actuating.
Initial troubleshooting
by I & C indicated that the channel had spiked and would not reset due
to loop width at this load.
Load was reduced approximately 1% to clear
the bistable.
At 41% power, FC-495 again actuated.
Investigation
revealed that a recently replaced isolation amplifier, PM-447D,
associated with AMSAC was the incorrect model.
This had placed an
additional 200 ohm resistor into the current loop; thereby, causing the
entire loop to be adversely affected. The isolation amplifier will be
replaced when the correct model can be obtained from the vendor. During
instrumentation data sheet preparation associated with the AMSAC
installation modification, the isolation amplifier model number had been
incorrectly entered on the data sheets for AMSAC modules PM-446D, PM
447D, LM-474B, LM-485B and LM-496B. The correct model number was EIP
E013DD-37 whereas EIP-EO13DD-1, the model number for all other isolation
amplifiers used at the site, was provided on the MMM-006 Appendix B data
sheets. The licensee has initiated procedure changes to correct the
data sheets, as well as, update EDBS with the correct model numbers.
Failure to specify the correct model number on the data sheets
constituted a violation for failure to adequately establish procedures.
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. Hence,
this item is identified as an NCV: Failure To Adequately Establish
Maintenance Procedures For Replacement Of AMSAC Isolation Amplifiers,
92-27-04.
One NCV was identified.
Except as noted above, the area/program was
adequately implemented.
6. Meeting With Local Officials (94600)
On September 24, 1992, the Regional Administrator, the DRP Division
Director, the Regional State Liaison Officer, the Section Chief
responsible for the site, and the inspectors met with local officials
representing the cities of Darlington, Florence, and Hartsville, the
town of Bishopville, and the emergency preparedness organizations for
the State of South Carolina, Chesterfield, Darlington, Florence, and Lee
counties. The local officials expressed no concerns about the operation
of the facility.
7. Exit Interview (71701)
The inspection scope and findings were summarized on October 14, 1992,
with those persons indicated in paragraph 1. The inspectors described
the areas inspected and discussed in detail the inspection findings
listed below and in the summary. In response to the inspectors'
conclusion involving inadequate logkeeping (see paragraph 3), the
15
licensee indicated that recent emphasis on logkeeping had resulted in an
improving trend in this area. Also, the licensee stated that the root
cause determination to be developed for OMM-027 no.92-046, inadvertent
vessel level increase associated with the PRT repressurization, would
capture the operator's response. The inspectors did not agree that
investigation into why an event occurred would necessarily address the
response to an event. Excluding these items, no additional dissenting
comments were 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
92-27-01
VIO - Failure To Adequately Establish GP-008 To
Preclude The Loss Of Decay Heat Removal During
RCS Inventory Reduction (paragraph 3)
92-27-02
VIO - Failure To Implement GP-008 In That RCS
Water Level Instrumentation Loops Were Not
Calibrated As Required (paragraph 3)
92-27-03
VIO - Failure To Isolate Gas Analyzer CV
Penetration Within 4 Hours With Deactivated
Isolation Valves As Required By TS 3.6.3,
(paragraph 3)
The following NCV was identified and reviewed during this inspection
period.
Item Number
Description/Reference Paragraph
92-27-04
NCV - Failure To Adequately Establish
Maintenance Procedures For Replacement Of AMSAC
Isolation Amplifiers (paragraph 5)
8.
List of Acronyms and Initialisms
a.m.
Ante Meridiem
ACR
Adverse Condition Report
As Low As Reasonably Achievable
ATWS Mitigating System Actuation Circuitry
Anticipated Transient Without Scram
CFR
Code of Federal Regulations
CV
Containment Vessel
CVC
Chemical & Volume Control
Chemical and Volume Control System
CWD
Control Wiring Diagram
Division of Reactor Projects
0
EDBS
Equipment Data Base System
FC
Flow Control
16
gpm
Gallons Per Minute
F
Fahrenheit
GL
Generic Letter
General Procedure
Hand Control Valve
Health Physics
i.e.
That is
Inspection and Enforcement
Instrumentation & Control
IN
Inspection Notice
Inservice Inspection
LCO
Limiting Condition for Operation
Level Indicator
LM
Level Module
LT
Level Transmitter
MMM
Maintenance Management Manual
NAD
Nuclear Assessment Department
Non-Cited Violation
NED
Nuclear Engineering Department
NRC
Nuclear Regulatory Commission
Nuclear Steam System Supplier
OEF
Operating Experience Feedback
OMM
Operations Management Manual
OP
Operations Procedure
OST
Operations Surveillance Test
p.m.
Post Meridiem
PLP
Plant Program
Pressure Module
Power Operated Relief Valve
Pressurizer Relief Tank
Psig
Pounds per square inch - gage
PW
Primary Water
PZR
Pressurizer
RC
Reactor Coolant Pump
Reactor Turbine Generator Board
Reactor Vessel Level Instrumentation System
Refueling Water Storage Tank
Systematic Assessment of Licensee Performance
Safety Injection
SOM
Shift Outage Manager
Senior Reactor Operator
Shift Supervisor
TS
Technical Specification
Violation
Volume Control Tank
WR/JO
Work Request/Job Order
WCCU
Water Cooled Condensing Unit