ML18101A827
| ML18101A827 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 07/13/1995 |
| From: | Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18101A825 | List: |
| References | |
| 50-272-95-10, 50-311-95-10, NUDOCS 9507210061 | |
| Download: ML18101A827 (21) | |
See also: IR 05000272/1995010
Text
Report Nos.
License Nos.
Licensee:
Facility:
Dates:
Inspectors:
Approved:
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
50-272/95-10
50-311/95-10
Public Service Electric and Gas Company
P~o. Box 236
Hancocks Bridge, New Jersey 08038
Salem Nuclear Generating Station
May 7, 1995 - June 23, 1995
C. S. Marschall, Senior Resident Inspector
J. G. Schoppy, Resident Inspector
T. H. Fish, Resident Inspector
K. S. Kolaczyk, Operations
neer
L. L. Scholl, Reactor Ery_g;: eer
A. E. Finkel
eni or
act
gi
Inspection Summary*
. ;:;"-
~
This inspection report documents inspections to assure public health and
safety during day and back shift hours of station activities, including:
operations, radiological controls, maintenance, surveillances, security,
engineering, technical support, safety assessment and quality verification.
The Executive Summary delineates the inspection findings and conclusions .
9507210061 950714
ADOCK 05000272
nnn
EXECUTIVE SUMMARY
Salem Inspection Reports 50-272/95-10; 50-311/95-10
May 7, 1995 - June 23, 1995
OPERATIONS
{Module 71707)
Based on preliminary assessment, operators
responded effectively to a Salem Unit 2 trip on June 7.
Operators failed to
fully consider the implications and the risk associated with their actions to
render an enti.re service water bay inoperable, instead of just removing
control power from the affected component. Operators appropriately assessed
emergency diesel generator (EDG) operability after operation with essentially
no fuel to one of the EDG cylinders.
-1*
Ineffective corrective action in response to failures of Residual Heat Removal
(RHR) pump minimum recirculation flow valves resulted in operation of Salem
Unit 2 from February 9, 1995 until June 7, 1995 with both trains of RHR
In addition, when plant staff recognized the degraded conditions
on June 6, they performed an incomplete and incorrect operability
determination for the valve associated with the no. 22 RHR pump.
The
incorrect operability determination, endorsed by the plant management
personnel, demonstrated weaknesses in the plant staff's ability to perform
The plant staff did not identify that the December 1994 failure of a supply
fan for safety-related switchgear placed Salem Unit 1 at variance with
conditions stated in the Updated Final Safety Analysis Report (UFSAR).
Further, when a second switchgear supply fan failed on May 12, 1995, plant
staff did not recognize that they operated the plant in an unanalyzed
condition.
As a result, the safety related switchgear could have failed under
design basis accident conditions. Plant staff did not take the appropriate
action to shut the plant down until May 16, 1995.
MAINTENANCE/SURVEILLANCE
(Modules 61726, 62703)
Plant staff responded
appropriately to Hagan module fuse configuration issues and implemented a
comprehensive Hagan module fuse inspection program.
Technician inattention to
detail contributed to Maintenance returning IC EDG to service with a cylinder
fuel pump inadvertently left out of service. Operations failure to ensure the
fuel system was reset, as required by procedure, resulted in reduced emergency
diesel generator reliability. Despite extensive troubleshooting and
installation of a modification, maintenance staff continued to experience
recurrent problems due to a safeguard equipment control auto test fault.
Plant staff did not determine the cause, take ade~uate corrective action, or
preclude recurrence of three leak rate test failures for the Salem Unit 1
outer airlock door.
The plant staff initiated an Incident Report after the
third failure, in response to questions by the inspector, and discovered that
the airlock gasket was deformed, not merely dirty as had been supposed by the
organization due to inadequate root cause performance.
i i
ENGINEERING (Module 71707)
Based on their identified probable cause, system
engineering correctly evaluated the effect of mis-operation of the output
breaker on EOG operability. However, they did not rigorously investigate and
evaluate other less probable, but more safety consequential causes of the
diesel generator output breaker failure.
Design engineering installed new design high-speed circulating water traveling
screen motors without detecting an inherent design problem.
Consequently, an
operator work-around was devised relative to the manual operation of the
screen in lieu of designed automatic operation.
The action challenged the
licensee's ability to affect event-free operation.
In addition, design
engineering failed to adequately analyze and evaluate the recurring motor
failures prior to returning them to automatic operation.
Engineering thoroughly assessed the consequences of operating IC EOG with
essentially no fuel to one cylinder and provided operations a reasonable basis
for declaring the emergency diesel generator operable.
Engineering's auxiliary feedwater pump cavitation calculations were found to
be technically adequate.
The licensee appropriately identified the cause for installing incorrect
internals in the Salem Unit 2 PORVs, and took appropriate corrective action.
PLANT SUPPORT (Module 71707) The Radiation Protection staff took comprehensive
measures to prevent the recurrence of the problems involving entry into high
radiation areas.
SELF ASSESSMENT/QUALITY VERIFICATION (Module 71707)
In 1992, the licensee
identified cyclic impact noises coming from an RHR pump discharge valve.
Although they took some corrective actions in 1993, they did not determine the
cause or thoroughly evaluate the potential effects on the operability of the
valve and its affect on the RHR system.
In response to inspector concerns on
this matter, the licensee performed an acceptable operability determination
that provided reasonable assurance of the valve's ability to function and
committed to inspect the valve to confirm the conclusion during the current
outage.
Notwithstanding, the inspector determined that, in 1992, the licensee
failed to take timely and appropriate corrective action in response to
identification of the degraded condition.
Engineering conducted an acceptable root cause determination for recurrent
jacket water instrument line leakage that affected one or more of the
In view of several similar failures that
occurred since February 1992, the inspector determined that the licensee
previously failed to determine root cause and effect lasting corrective
action.
i i i
TABLE OF CONTENTS
EXECUTIVE SUMMARY .
TABLE OF CONTENTS .
I.O
SUMMARY OF OPERATIONS .
2.0
3.0
4.0
OPERATIONS
. . . . . . . . . . . . . . . . . . . . . . . . .
2.I
Operator Response to the Salem Unit 2 Trip
...... .
2.2
Service Water Operability
........ .
2.3
Operation of IC EDG with a Latched Fuel Pump Rack ..
2.4
Inoperable Salem Unit 2 Residual Heat Removal (RHR) pumps
2.5
Salem Unit I Degraded Switchgear Ventilation System
MAINTENANCE AND SURVEILLANCE
. . . . . . . . . . .
3.I
MAINTENANCE . . . . . . . . . . . . . . . . . . .
. ....
3.2
Hagan Module Fuses .............. .
3.3
Emergency Diesel Generator (EDG) Maintenance .. .
3.4
Safeguard Equipment Control (SEC) Troubleshooting .... .
3.5
SURVEILLANCE ..................... .
3.6
Inadequate Corrective Action of Salem Containment Airlock
ENGINEERING . . . . . . . . . . . . . . .
o
4.I
Emergency Diesel Generator Output Breaker .....
4.2
Circulating Water (CW) Traveling Screen Motors ..
4.3
Operation of IC EDG with a Latched Fuel Pump Rack
4.4
Auxiliary Feed Pump Cavitation . . . .
. ...... .
5.0
PLANT SUPPORT ............. .
5.I
Radiological Controls ....... .
i i
iv
I
I
I
2
3
3
5
7
7
7
8
9
9
11
I2
I2
I4
I4
6.0
Self Assessment and Quality Verification . . . . . . . . . . .
14
6.1
Historical Problem Identification and Resolution at Salem
14
7.0
REVIEW OF REPORTS AND OPEN ITEMS
7.1
Licensee Event Reports
8.0
EXIT INTERVIEWS/MEETINGS ... .
8.I
Resident Exit Meeting ....... .
8.2
Specialist Entrance and Exit Meetings
8.3
Salem Management Changes ..... .
iv
I6
I6
I7
I7
I7
I7
-
DETAILS
1.0
SUMMARY OF OPERATIONS
Unit 1 began the period operating at 48% power to support modifications to the
steam generator feed pumps.
Operators began raising power on May 14, 1995.
On May 16, with the unit at 95% power, operators entered Technical
Specification 3.0.3 and began a plant shutdown, due to inoperable switchgear
ventilation supply fans.
The operators put the plant in Mode 5 (Cold
Shutdown) on May 17, where it remained through the end of the reporting
period.
Unit 2 began the period at 100% power.
On May 7, 1995, operators reduced
power to 88% due to the loss of moisture separator reheater drain tank level
indications.
On May 8, with the no. 238 circulating water pump out of service
for maintenance, operators reduced power to 78% due to high temperatures in
the no. 23A circulating water traveling screen motor.
On May 11, operators
increased power to 90%.
Maintenance on the no. 21 heater drain pump and
level swings in no. 2B heater drain tank level prevented a further power
increase until May 15, when operators returned Unit 2 to 100% power.
On
May 25, operators reduced power to 88% due to circulating water pump
unavailability and anticipated loss of an additional circulating water pump.
On May 30, operators returned Unit 2 to 100% power.
On June 3, operators
reduced power to 90% due to an extended outage of no. 238 circulating water
pump and unreliability of circulating water traveling screen motors.
On June
4, operators returned Unit 2 to 100% power.
On June 7, Unit 2 operators
commenced a shutdown required by Technical Specification 3.0.3 due to the
inoperability of both trains of residual heat removal (RHR).
During the shutdown, Unit 2 experienced an automatic reactor trip from 10%
power due to a 500 kV breaker failure and subsequent loss of two of the four
operating reactor coolant pumps.
On June 8, operators placed Unit 2 in mode 5
and maintained it in that condition for the remainder of the inspection
period.
2.0
OPERATIONS
The inspectors evaluated PSE&G's management control by direct observation of
activities, tours of the facilities, interviews and discussions with
personnel, independent verification of safety system status and Technical
Specification compliance, and review of facility records. The inspectors
performed normal and back-shift inspections, including 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> of deep back-
shift inspections.
2.1
Operator Response to the Salem Unit 2 Trip
Based on preliminary assessment, operators responded effectively to a Salem
Unit 2 trip on June 7. *
On June 7, during a Salem Unit 2 shut down required by Technical Specification 3.0.3, a reactor trip resulted from spurious protective relay actuation on the
500 kV ring bus.
With the plant at 10 percent power, the protective relaying
caused loss of the 4160 volt buses supplying power to the nos. 23 and 24
- ..
2
reactor coolant pumps.
As a result, the reactor tripped, from low reactor
coolant system flow with reactor power greater than or equal to 10 percent.
The protective relaying also caused loss of power to other plant equipment
including the control air compressors.
The vital bus transfer to its
alternate source of offsite power occurred successfully, and the emergency air
compressors started and restored air pressure. All plant equipment functioned
as designed in response to the existing conditions.
The inspectors concluded
that the operators responded appropriately to the trip. Salem management
convened a Significant Event Response Team (SERT) to review operator action
and plant response to the trip. The SERT had not completed its review at the
conclusion of the inspection period. The inspectors will review the completed
SERT findings when they become available, as a matter of routine NRC
inspection activities.
2.2
Service Water Operability.
The inspector noted that operators unnecessarily rendered a service water bay
inoperable while waiting for post-maintenance testing of a service water pump.
Operators failed to fully consider the increased risk of unnecessarily
maintaining a service water bay inoperable, instead of merely removing control
po.wer from the affected service water pump breaker.
At 04:51 a.m. on May 26, 1995, operators restored 125 VDC control power to the
no. 25. service water (SW) pump breaker while waiting for a post-maintenance
test on the SW pump.
At the time, the operators considered the no. 25 SW pump
inoperable but available.
The operators recognized that the restoration of
control power to the pump would set-up a condition that would cause the no. 2C
safeguard equipment control (SEC) system to attempt to start the no. 25 SW
pump in the event of a loss of offsite power (LOP); and that if the no. 25 SW
pump breaker failed to close, the 2C SEC would attempt to start the 26 SW
pump, in accordance with design.
The inspector noted that if the operators had not restored control power to
the no. 25 SW pump, 2C SEC would have started the operable no. 26 SW pump,
directly in response to a LOP.
However, as a result of making the no. 25 SW
pump available with restored control power, an SEC actuation under accident
conditions could result in 2C SEC closing the no. 25 SW pump breaker before
the pump was demonstrated as operable by post-maintenance testing.
In such
condition, the pump may not have been able to perform its intended function.
In such case, the potential existed for not having any pumps in the affected
SW bay that would start in response to a LOP.
When this matter was brought to the attention of the operating personnel, the
operators reacted initially by considering the SW bay inoperable and
appropriately entering Technical Specification 3.7.4. while continuing to wait
for the performance of a post-maintenance test that was planned for the next
shift.
The next morning, the inspector questioned the advisability of the operators
rendering the entire SW bay ino~erable while waiting for a post-maintenance
test for a single pump.
The Operations Manager concluded that the decision to
render the entire SW bay inoperable was inappropriate and unnecessary.
.(
3
Subsequently, the operations manager took prompt action to ensure the
operating shift removed breaker control power for the affected SW pump until
maintenance was prepared to perform the post-maintenance test.
The inspector determined that the operators failure to consider the
implications of their approach a contributor to the potential for rendering a
portion of SW unable to respond to a LOP; and demonstrated a weakness in
understanding and assessing aggregate risk.
2.3
Operation of lC EDG with a Latched Fuel Pump Rack
Operators appropriately considered the emergency diesel generator (EOG)
inoperable after operation with essentially no fuel to one of the EOG
cylinders. Later,-they appropriately declared the EOG operable after review
of information provided by system engineering.
On June 15, during a surveillance of IC EOG, operators identified abnormally
low no. 4R cylinder exhaust temperature (165 °F).
Normal cylinder exhaust
temperatures for a loaded EOG range from 860 to 960 °F.
Subsequently, a
maintenance supervisor found the 4R cylinder fuel pump latched, essentially
eliminating fuel flow to the 4R cylinder.
The supervisor unlatched the fuel
pump, returned the cylinder to service, and operators completed the EOG
surveillance run with no apparent degradation in engine performance.
Following the surveillance, the Senior Nuclear Shift Supervisor (SNSS)
declared the EOG inoperable pending engineering evaluation of running the EOG
with no fuel to cylinder 4R.
On June 16, engineering provided operations with
information indicating the EOG had not experienced damage.
The SNSS declared
the EOG operable.
(Sections 3.3 and 4.3 pertain)
2.4
Inoperable Salem Unit 2 Residual Heat Removal (RHR) pumps
Ineffective corrective action in response to failures of Residual Heat Removal
(RHR) pump minimum recirculation flow valves resulted in operation of Salem
Unit 2 from February 9, 1995 until June 7, 1995 with both trains of RHR
In addition, when plant staff recognized the degraded conditions
on June 6, they performed an incomplete and incorrect operability
determination for the valve associated with the no. 22 RHR pump.
The
incorrect operability determination, endorsed by the plant engineering and
operations management, demonstrated fundamental weaknesses in the plant
staff's ability to perform operability determinations.
On January 26, 1995, as operators decreased flow from no. 22 RHR pump into the
reactor vessel, the RHR minimum recirculation flow bypass valve (22HR29)
failed to open.
Operators noted that, as flow decreased, the valve did not
open at 500 gpm, as expected.
At 200 gpm flow, operators manually opened the
motor operated valve (MOV).
In consultation with the system engineer,
operators manually stroked 22RH29 to verify manual operation of the valve.
They initiated a work order stating that the valve failed to open
automatically, but considered the valve operable without any basis.
On
February 9, 1995, the minimum recirculation flow bypass valve (21HR29) also
failed to open automatically in response to a low flow condition. However,
4
since the operators were able to stroke the valve manually, they continued to
considered the component operable without any other basis. Notwithstanding, a
work order to investigate and repair was initiated.
No significant priority
was assigned to the work orders. Consequently, the actions became part of the
licensee's work order backlog even though the work orders described an
operability concern.
On June 6, 1995, during a review of open safety related work orders, plant
staff identified that the work orders for the 21 and 22 RH29 valves identified
unresolved degraded conditions potentially affecting RHR pump operability.
Plant staff noted that for certain loss of coolant accidents (LOCAs) the RHR
pumps would start but would not immediately inject into the reactor coolant
system (RCS) due to elevated system pressure. Those conditions would require
that the 21 and 22 RH29 valves open to assure adequate flow through the RHR
pumps to prevent pump failure due to over-heating or excessive vibration.
With the plant at full power, operators started the nos. 21 and 22 RHR pumps
individually with the RH29 valves closed.
The 22RH29 opened in response to
the low RHR flow; the 21RH29 valve failed to open.
The operators, with
management concurrence, declared the no. 21 RHR pump inoperable.
However,
with no other basis than this single functional test, the operators continued
to consider the no. 22 RHR pump operable.
On June 7, 1995, the inspectors questioned the basis for operability of
22RH29.
In response to the inspector's questions, the General Manager
confirmed that the plant engineering and operations management considered
22RH29 operable based solely the functional test and engineering assurance.
When challenged by the inspector, neither the general manager nor the
engineering or operations staff could provide the basis for this operability
determination.
Follow-up revealed that the plant operations and engineering
managers assumed that the system engineer, in response to the 22RH29 failure
on January 26, 1995, had engineering assurance that permitted him to conclude
that the valve was operable at that time.
On June 7, the managers considered the single functional test as sufficient
reasonable assurance of operability to arbitrarily established a deadline of
5:00 p.m. to supply further basis for a positive operability determination for
22RH29.
However, at 6:27 p.m. on June 7, engineering was unable to provide a
rationale for operability. Subsequently, the operations organization declared
the no. 22 RHR pump inoperable, and commenced a Unit 2 shutdown, as required
by Technical Specification 3.0.3.
In summary, the inspector found that the plant staff did not identify a root
cause for either 22RH29 or 21RH29 functional failures in January and February,
1995. Though operability of the RHR system was recognized as an issue, no
basis for operability was ever established, and no significant priority was
assigned to work efforts to investigate and resolve the matters.
Consequently, the issues remained unresolved until June 7, when the licensee
finally determined that neither valve could be considered operable.
Following
shutdown of Unit 2, the licensee still unable to demonstrate the proper
functioning of the valves, confirming that both trains of the RHR system were
inoperable since January/February 1995, during which time the plant was at
5
full power.
Unit 2 shutdown on June 7, 1995.
Power operation of the Salem
Unit 2 for prolonged periods with both trains of RHR inoperable is an apparent
violation.
2.5
Salem Unit 1 Degraded Switchgear Ventilation System
The plant staff did not identify that the December 1994 failure of a supply
fan for safety related switchgear placed Salem Unit 1 at variance with
conditions stated in the Updated Final Safety Analysis Report (UFSAR).
Further, when a second switchgear supply fan failed on May 12, 1995, plant
staff still failed to recognize that they had operated the plant in an
The inspector identified that in such condition, the
safety related switchgear could have failed under design basis accident
conditions. Plant staff did not take the appropriate action to shut the plant
down until May 16, 1995.
The UFSAR, section 9.4.6, states that the switchgear ventilation system is
designed for continuous operation to maintain safe levels of temperature and
cleanliness in the 64' and 84' switchgear rooms as well as the 78' lower
electrical penetration and 100' upper electrical penetration rooms.
The
UFSAR, section 9.4.6.2.2 further states that the ventilation system consists,
in part, of three 50 percent capacity fans to supply filtered air through
supply ducts, with two of the three supply fans operating and the third as a
standby.
The switchgear ventilation system supplies cooling to all safety
related 4160V, 460V, and 230V switchgear.
On December 11, 1994, the no. 12 control area switchgear supply fan motor
breaker tripped on overload due to mechanical failure of the motor bearings.
Plant staff wrote work order (WO) 941211094 to investigate and correct the
condition. However, the fan remained unrepaired due to the lack of available
parts (the fan motors were obsolete).
On May 12, 1995, with Salem Unit 1 at power, the no. 13 control area
switchgear supply fan motor tripped on overload.
Plant staff initiated a Work
Order (950512188).
On May 14, 1995, at 7:00 p.m., operators completed an
initial operability determination.
The determination concluded that the
switchgear remained operable based on the expectation that ambient outside air
temperature would remain less than the design assumption of 95°F, that.low
initial temperatures in the affected areas would limit the rate of temperature
rise from the onset of an accident permitting timely restoration of at least
one fan before reaching the design inside air temperature limit of 105°F.
Engineering considered the limit of 105°F to be a long term reliability
concern.
On May 15, 1995, system engineering provided a memorandum to operations
documenting their basis for concluding that the switchgear ventilation
remained operable.
The memorandum stated that the switchgear ventilation was
designed to maintain switchgear ambient air temperature within 65°F - 105°F,
but did not state that the UFSAR indicated that the fans were 50 percent
capacity, that two were assumed to be running, and the third fan was expected
to be available in standby.
The memorandum described the assumption that all
of the Unit 1 exhaust fans were available when, in fact, one of six was out of
6
service due to parts problems.
System engineering also assumed that a fan
could be restored within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, even though some of the components were
obsolete.
For compensatory measures, engineering advised operations to rely
on the Unit 2 switchgear exhaust fans, and proposed that the fire doors
between Unit 1 and Unit 2 switchgear rooms be propped open to allow Unit 2 to
serve as a source of outside air for Unit 1.
The memorandum did not address
the affect of reduced ventilation on Unit 2, or evaluate the condition
relative to fire protection requirements and the existing Appendix R analyses.
To accommodate this proposal, engineering's memorandum suggested that
operations disable the C02 automatic function for the 84' switchgear rooms.
The memorandum further stated that the ambient switchgear temperatures were
acceptable assuming that the ambient temperatur~ did not exceed 80°F.
Operations received the memorandum on the evening of May 15.
In the morning
on May 16, the assistant operations manager noted that the predicted high
ambient temperature for the day was expected to exceed 80°F.
Subsequently,
the operations organization rejected engineering's proposal as unacceptable.
Design engineering began a 10CFR50.59 evaluation to determine if the
switchgear could be accepted as meeting the design basis cooling assumptions
in its present condition. Later in the afternoon of May 16, design
engineering informed operations that they had determined that operation with
only one switchgear supply fan constituted an Unreviewed Safety Question .
Subsequently, the design engineering organization initiated a effort to
develop a Justification for Continued Operation (JCO).
The operations
organization set a deadline of 9:00 p.m. on May 16, to have the JCO, or to
begin to initiate plant shutdown.
Shortly after 9:00 p.m. on May 16,
operations initiated a plant shutdown after it became evident that the
engineering organization would not be able to prepare a JCO on schedule.
At 11:10 p.m., design engineering completed the JCO.
It relied on use of
Unit 2 switchgear ventilation supply fans, specified daytime temperatures to
be less than or equal to 80°F and nighttime temperatures to be less than or
equal to 60°F.
The JCO was based on the proposition that the fire doors
between Units 1 and 2 would be blocked open, and that the automatic operation
of the C02 fire suppression system would be disengaged.
The JCO concluded
that Unit 1 could be safely shut down with loss of the third switchgear
ventilation supply fan, provided that the ambient air temperature limitations
and the blocked open fire door conditions were met.
The Salem Operations
Review Committee reviewed the JCO and rejected it at approximately 2:30 a.m.
on May 17.
In summary, the licensee's response to the December 11, 1994 failure of the
no. 12 switchgear supply fan failed to evaluate switchgear operability or the
effect on the design basis assumptions (as requir~d by 10CFR50.59).
The plant
staff did not recognize that they did not meet design basis assumptions
specified in the UFSAR.
As a result, they did not promptly obtain repair or
replacement parts for the disabled components.
Further, they did not
recognize that the design basis assumption of 95°F ambient air temperature
assumed that there were at least two operating supply fans.
The engineering
analysis to support operability relied on Unit 2 equipment for operability of
Unit 1 systems, yet assumed that Unit 2 would be unaffected by a loss of
offsite power affecting Unit 1, even though the last two switchyard problems
7
that perturbed offsite power affected the vital buses for both units. System
engineering's memorandum to the operations organization failed to specify and
an engineering basis for concluding that Unit 2 ventilation would provide
adequate motive force for both units. Also, the memorandum failed to provide
an evaluation of the affect of propping fire doors open and disabling
automatic functions of C02 systems.
Additionally, when design engineering concluded that operation with a single
supply fan constituted an unreviewed safety question, Salem management failed
to recognize that they could not support continued plant operation, since
design engineering had clearly told them that they were operating the plant
outside of the design basis. Although it could have been more timely,
operations finally took control, established a deadline, and acted in the
absence of engineering support of switchgear operability. Engineering's
rationale as documented in their memorandum to operations and in the proposed
JCO was dubious and based on invalid assumptions.
The SORC appropriately
rejected the JCO, however, plant management's judgement to consider a JCO,
after being informed that the design basis assumptions could not be met, is
questionable.
3.0
MAINTENANCE AND SURVEILLANCE
3.1
MAINTENANCE
The inspectors observed portions of the following safety-related maintenance
to determine if the licensee conducted the activities in accordance with
approved procedures, Technical Specifications, and appropriate industrial
codes and standards.
The inspector observed portions of the following activities:
Work Order(WO) or Design
!ln.i1
Change Package CDCP)
Description
Salem 1
RCP Seal Inspection
Salem 1&2
Hagan Module Fuse Inspection
Salem 1
Emergency Diesel Generator no.
IC periodic maintenance
The inspectors observed that the plant staff performed the maintenance
effectively within the requirements of the station maintenance program.
3.2
Hagan Module Fuses
Plant staff responded appropriately to Hagan module fuse configuration issues
and implemented a comprehensive Hagan module fuse inspection program.
Between May 20 and May 21, 1995, Unit 1 Instrument and Controls technicians
identified at least six incorrect fuses installed in Hagan modules.
The
modules, used in safety-related and non-safety related applications, provide a
8
I20 VAC output that energizes or de-energizes downstream relays. The fuses.
protect the signal input to the Hagan modules, the power supplies, and the -
output to the relays.
The licensee identified two fuse misapplications: I) incorrect voltage ratings
(installed 32 V or I25 V ratings vs. specified 250 V), and 2) incorrect fuse
current ratings (installed .2A vs. specified SA; and installed SA vs.
specified .2A).
On May 23, the licensee initiated a program to inspect all
Hagan module fuses installed in both Salem units. The inspection placed
priority on safety-related systems, but included non-safety related systems.
At the end of the inspection period, Unit I technicians completed_ inspection
of approximately 350 of II39 fuses, with approximately IO percent of the fuses
found to be incorrect. Unit 2 technicians completed inspection of
approximately 440 of II33 fuses, with approximately 5 percent of the fuses
found to be incorrect.
Salem management expected to complete inspections of safety-related systems by
the end of July. They had not yet determined the completion date for
inspections of the remaining non-safety system modules.
NRC inspectors will
continue to follow-up on the licensee's resolution of this configuration
control problem.
3.3
Emergency Diesel Generator (EOG) Maintenance
Technician inattention to detail contributed to Maintenance returning IC EOG
to service with a cylinder fuel pump inadvertently left out of service. The
inspector also discovered that operations failed to insure the emergency
diesel generator fuel rack linkage had been properly repositioned following a
surveillance. Although this did not render the diesel inoperable, it reduced
reliability of the emergency diesel generator.
Both matters represent
examples of failure to follow procedures.
As described in Section 2.3, maintenance technicians inadvertently left
cylinder 4R fuel pump latched after completing compression checks on IC EOG.
The licensee determined that technicians failed to comply with the procedure
SC.MO-ST.OG-0003, Eighteen Month Diesel Engine Inspection Maintenance, step
5.I5.8.G, which requires the technicians to unlatch the fuel pump rack and
allow the rack to return to its normal position following compression pressure
checks on the cylinder.
The inspectors concluded technician inattention to detail contributed to the
fuel pump rack being left latched, and resulted in operators running the EOG
without fuel to the cylinder.
Failure to correctly implement the maintenance
procedure is an example of failure to follow procedures.
At 5:55 a.m. on May I6, I995, operations declared the 2C emergency diesel
generator (EOG) operable after completing a surveillance. At approximately
IO:OO a.m. on May I6, the inspector discovered the 2C EOG fuel rack linkage
was not in the open position. The shift supervisor appropriately restored the
fuel rack linkage to the correct position.
In addition, operations ensured
that the fuel rack was properly lubricated and functional.
9
The licensee determined that an equipment operator's failure to follow
procedural requirements for EOG restoration was the root cause. Step 5.3.45
of S2.0P-ST.DG-0003, 2C Diesel Generator Surveillance Test, required EOG
restoration in accordance with Attachment 6. Attachment 6 to S2.0P-ST.DG-0003
required positioning of the fuel rack linkage to the open position.
Engineering determined that the incorrectly positioned fuel rack did not
affect emergency diesel generator operability since hydraulic pressure would
be expected to automatically open the fuel racks during the starting sequence.
The inspector verified that operations successfully tested the automatic
feature on December 4, 1994, during S2.0P-ST.DG-0021, 2C Diesel Generator Hot
Restart Test.
The inspector concluded that Attachment 6 to procedure S2.0P-
ST.DG-0003 provided a redundant means to assure open fuel racks prior to
diesel starts. The licensee's failure to adhere to S2.0P-ST.DG-0003 step
5.3.45 and procedure SC.MD-ST.DG-0003 step 5.15.8.G, as discussed above,
constitutes an apparent violation of Technical Specification 6.8.1.
(VIO 50-272&311/95-10-02)
3.4
Safeguard Equipment Control (SEC) Troubleshooting
Despite extensive troubleshooting and installation of a modification, the
maintenance organization has been unsuccessful in preventing recurrence of
safeguard equipment control auto test faults.
Previous inspection reports (NRC Inspection Reports 50-272&311/94-31,
50-272&311/94-35, and 50-272&311/95-02) documented recurring problems with
Unit 1 SEC power supplies, particularly frequent Automatic Test Insertion
(ATI) test faults and spurious alarms.
To address the problems, the licensee
installed modified SEC power supplies on May 22 and made improvements to
reduce electromagnetic interference.
The licensee also planned modifications
to the ATI card to reduce sensitivity to noise.
On June 13 and June 20, the IA SEC again experienced ATI test faults.
Initial
analysis indicated that the new power supplies had degraded.
At the end of
the inspection period, the licensee continued to troubleshoot the power
supplies.
3.5
SURVEILLANCE
The inspectors performed detailed technical procedure reviews, observed
surveillances, and reviewed completed surveillance packages. The inspectors
verified that plant staff performed surveillance tests in accordance with
approved procedures, Technical Specifications and NRC regulations.
The inspector reviewed the following surveillances:
Unit
Salem 1
Salem 2
Salem 2
Procedure no.
Sl.RE-ST.ZZ-0002
S2.0P-ST.RC-0008
S2.IC-FT.RCP-0068
10
Test
Shutdown Margin Calculation
' Reactor Coolant System Water Inventory
Balance
Containment Pressure Protection Channel 2
The inspectors observed that plant staff did the surveillances safely, and
that the tests were effective in confirming operability of the associated
systems.
3.6
Inadequate Corrective Action of Salem Containment Airlock
Plant staff failed to determine the cause, take adequate corrective action, or
otherwise preclude recurrence of three successive leak rate test failures for
the Salem Unit 1 outer airlock door.
Although plant staff initiated an
Incident Report after the third failure, in response to questions by the
inspector the plant staff discovered that the airlock gasket was deformed as
opposed to their initial presumption that dirt in the seal area was the cause
of the recurrent test failures .
On March 6, 1995, the Salem Unit 1 100 foot elevation outer airlock door
failed a routine leak rate test. Plant staff cleaned the gasket with Maselin
(oil impregnated) cloth and satisfactorily completed the retest. They
concluded that dirt on the gasket had caused excessive leakage during the
first test.
On May 3, 1995, the outer airlock door again failed a routine
surveillance. Plant staff again cleaned the gasket, and satisfactorily
retested the door.
On May 8, 1995, the door again failed surveillance, and
plant staff again cleaned the gasket with a Maselin cloth, and satisfactorily
retested the door.
Though the plant staff wrote an Incident Report, they considered the airlock
door operable for purposes of containment integrity.
The inspectors
questioned the adequacy of the corrective action, the basis for operability,
and the licensee's ability to preclude recurrence.
In response,
the licensee
thoroughly inspected the gaskets, and found one of the two gaskets
sufficiently deformed to cause the excessive leakage.
The licensee replaced
the damaged gasket and successfully retested the door.
The inspectors concluded that the licensee had not adequately determined the
cause of the airlock failure on March 6, May 3, and May 8, 1995, with the
result that they took inadequate corrective action in each instance.
4.0
ENGINEERING
4.1
Emergency Diesel Generator Output Breaker
System engineering performed a thorough operability evaluation based on their
identified most probable cause of recurring unsuccessful diesel generator
output breaker operation. However, the inspector determined that engineering
11
did not rigorously investigate other potential causes that were factors in, or
contributed to, a previous similar diesel generator breaker failure, and other
related breaker failure events. The inspector noted that engineering readily
dismissed other possible causes with more safety consequence.
On June 2, 1995, the 4KV emergency diesel generator (EOG) output breaker
failed to close on the first attempt while performing Sl.OP-ST.DG-0002, 18
Diesel Generator Surveillance Test.
The licensee experienced similar failures
on May 15, 1995, and March 1, 1995, on the lC EOG and the 2A EOG respectively.
In all cases, the breaker closed on the second attempt.
In each case, the
licensee attributed the failures to the Qperator improperly timing the attempt
to close the 4KV breaker.
Engineering concluded that the operators must not
have satisfied the synchronization permissive required to effect breaker
closure. Operations concluded that the breaker failures, that occurred during
diesel paralleling, affected only the test portion of the EOG breaker closing
circuit.
The inspector determined that plant engineering performed a thorough analysis
of the affect on operability of a faulty synchronization permissive circuit.
The inspector also noted that on April 12, 1994, engineering determined that
increased contact resistance in position switch 52HL caused successive breaker
failures on March 29, 1994.
The inspector also found that plant engineering
did not fully consider potential intermittent failures of relays and contacts
in the synchronization permissive circuit and the safeguard equipment control
(SEC) EOG starting circuit. Although they concluded that 52HL caused the
failure in March 1994, engineering did not consider increased 52HL contact
resistance as a cause for the failures in March, May, and June 1995.
In
addition, engineering did not evaluate other failures of similar 4KV breakers.
The licensee previously attributed four previous failures of 4KV breakers to
close on the first attempt to dirty, pitted or misaligned permissive switch
contacts.
The inspector determined that engineering's recommended corrective actions
were appropriate if the cause of the breaker failing to close was confirmed to
be associated with mis-synchronization.
The inspector noted, however, that
the licensee did not specifically confirm synchronization as the cause, nor
investigate other possible causes.
4.2
Circulating Water (CW) Traveling Screen Motors
Design engineering installed new design high-speed circulating water traveling
screen motors that resulted in an operator work-around (i.e., required manual
screen operation) and had the potential to challenge event-free operations.
In addition, design engineering failed to adequately analyze and evaluate the
recurring motor failures prior to returning them to automatic operation.
The licensee installed new CW traveling screen motors designed to operate in
low speed automatic operation, with automatic speed increases (2nd, 3rd, and
4th speeds) in response to increasing traveling screen differential pressures.
Shortly after installation, the licensee observed extremely high CW traveling
screen motor temperatures while operating the motors in low speed automatic
operation.
On May 3 and May 6, motor failures occurred due to overheating.
I2
On May 8, Unit 2 operators reduced reactor power to 78% due to high
temperatures on the no. 23A CW traveling screen motor while the no. 238 CW
pump was out of service for maintenance.
Based on engineering
recommendations, operations placed the screen motors in manual and in 2nd
speed to reduce the potential for overheating.
Engineering determined that poor workmanship and insufficient end-turn winding
insulation caused the motor failures. Engineering had two of the motors
rewound and properly insulated. Prior to making this modification to all new
motors, however, engineering recommended that operations place all motors back
in low speed automatic operation. Engineering based the recommendation on a
grease and bearing evaluation and on motor desi~n specifications. Despite the
failures experienced, engineering determined that the motors should have
performed as designed.
On May I7, operators placed all the traveling screen
motors in low speed automatic operation.
On May 25, operators reduced power
to 88% due to an overheating failure of no. 23A traveling screen motor and
anticipated loss of additional motors due to overheat. Subsequently,
operations returned the motors to 2nd speed manual operation.
4.3
Operation of lC EDG with a Latched Fuel Pump Rack
Engineering thoroughly assessed the consequences of operating IC EDG with
essentially no fuel to one cylinder and provided operations a reasonable basis
for declaring the emergency diesel generator operable.
System Engineering assessed the impact of running the EDG with the fuel pump
latched (described in Section 2.3 and 3.4). Engineers evaluated torsional
resonance res~lting from one cylinder not firing, and thermal loading on the
I7 operating cylinders and the non-operating cylinder. They discussed these
issues with the EDG vendor, a consulting firm, and three other utilities.
They also reviewed event reports and industry data to identify other examples
of diesel engines running with a cylinder not firing.
Based on the collective
experience of the engine manufacturer, consultants, other utilities, and broad
industry experience, engineering concluded the IC emergency diesel generator
suffered no damage from running with a fuel pump rack latched.
4.4
Auxiliary Feed Pump Cavitation
The inspector reviewed auxiliary feedwater pump cavitation calculations and
found them to be technically adequate.
The licensing basis of the Salem auxiliary feedwater (AFW) system is described
in section I0.4.7.2.I of the Updated Final Safety Analysis Report (UFSAR).
The AFW system serves as a backup for supplying feedwater to the secondary
side of the steam generators at times when the main feedwater system is not
available, thereby maintaining the heat removal capabilities of the steam
generators.
Each unit is equipped with one turbine-driven and two motor-
driven auxiliary feed pumps.
Steam for the turbine driven pump is taken from
two of the four steam lines upstream of the steam generator stop valves.
The
motor-driven pumps receive power from the 4I60 volt Class IE vital buses.
The
system provides an alternate to the main feedwater system during startup, hot
standby, and also functions as an engineered safeguards system.
In the latter
\\I-
...
13
case, the AFW system is directly relied upon to prevent core damage and
reactor coolant system over pressurization, in the event of transients, such
as loss of feedwater or a secondary system pipe rupture. It also provides a
means for plant cooldown following any plant transient.
The inspector reviewed four auxiliary feedwater cavitation calculations. The
purpose of these calculations was to predict AFW configurations that were
bounded with respect to pump cavitation.
Calculation DOl.6-835, "Limiting Condition for AFW Pump Cavitation Using
Best Estimate Calculations," dated July 27, 1992;
Calculation DOl.6-836, "Best-estimate AFW Pump Cavitation Durinri the
First Ten Minutes of a Split Steam Line Break," dated August 8, 1992;
Calculation S-C-F400-MDC-0225-l, "AFW Flow Rate after Main Steam Line
Break and a Single Active Failure," dated July 10, 1992; and
Calculation lEC-3220, "AFll and AF21 Modification (Trim Replacement),
Package no. l," dated December 15, 1993.
PSE&G 10CFR50.59 Review and Safety Evaluation no. S-O-AF-MSE-0812 dated
September 17, 1992, evaluated the consequences of potential auxiliary
feedwater pump cavitation on Salem's licensing basis by reevaluating the UFSAR
Chapter 15 analyses of steam line break (SLB) and feedwater line break (FWLB)
accidents. The reevaluation (above calculations) conservatively assumed the
turbine driven auxiliary feed pump was not available for mitigation of the SLB
or FWLB events.
Percent cavitation was defined as the percentage reduction in
net positive suction head (NPSH) below that required by the pump during the
design basis event.
The purpose of the safety evaluation was to document that
the postulated worst case of 20% cavitation of one or two auxiliary feed pumps
for 10 minutes or less under postulated SLB and FWLB accident events did not
involve an unreviewed safety question.
The inspectors noted that Byron Jackson Pump Division letter dated August 7,
1992, documented a research test project that was completed by Byron Jackson
in 1967.
The purpose of this test (Byron Jackson Test Curve and Data no. T-
28925-1, dated 21 June 1967) was to determine if extreme cavitation conditions
over a period of time would cause pump seizure, bearing failure, and loss of
pump performance.
The test pump, which was the same model (though a different
size) as Salem's auxiliary feed pump eight-stage DVMX model pump, was selected
to undergo a test program.
The test pump was run for a period of one hour
with 20% cavitation (i.e., available NPSH was equal to 80 percent of what was
required) and there was no appreciable pump noise increase nor bearing
temperature rise. Further, the tested pump resumed its normal performance
after one hour of cavitation.
PSE&G has analyzed 23 postulated cases of main steam line and feedwater line
break accident scenarios. The worst case, a postulated FWLB, has concluded
that one motor-driven auxiliary feed pump and is expected to cavitate 3%
(available NPSH of 97%) at two minutes into the accident, and 19% at the end
of 10 minutes when the faulted loop was isolated by the operator.
Y-
14
Simultaneously, the turbine driven auxiliary feed pump is expected to cavitate
in the range of 4-16% from six minutes into the accident until the faulted
loop is isolated.
In above scenario, both pumps were postulated to cavitate
less than 20% for less than ten minutes.
Based on the Byron Jackson research
pump test, PSE&G concluded that the Salem auxiliary feed pump performance,
with less than 20% cavitation for less than 10 minutes, would not affect pump
performance. Therefore, PSE&G concluded that these conditions were acceptable
and do not involve an unreviewed safety question.
5.0
PLANT SUPPORT
5.1
Radiological ~ontrols
In response to previously identified problems with control of entry into high
radiation areas, the radiation protection (RP) staff made significant changes
to the process for entry into the radiologically controlled area (RCA).
The
changes included positive measures to insure that RP technicians inform each
person entering the RCA of the radiologically conditions in the specific areas
entered by the workers.
The RP staff also revised the Radiation Work Permits
to require that each radiation worker read and sign a summary of the problems
with control of entry into the high.radiation areas.
The inspectors concluded
that the RP staff took comprehensive measures to prevent recurrence of the
problems with entry into high radiation areas.
6.0
Self Assessment and Quality Verification
6.1
Historical Problem Identification and Resolution at Salem
A.
In 1992, the licensee identified cyclic impact noises coming from a
Residual Heat Removal (RHR) pump discharge valve. Although they took
some corrective actions in 1993, they did not determine the cause or
thoroughly evaluate the potential effects on the operability of the
valve and the RHR system until the problem resurfaced in 1995.
The
inspector identified a loss of RHR capability scenario that the licensee
had not considered.
In response, the licensee performed an acceptable
operability determination and committed to thoroughly inspect the
suspect valves during the current outage.
The inspector also determined
that Salem plant staff performed an acceptable operability determination
in response to a lB Emergency Diesel Generator (EOG) jacket water leak
on June 1, 1995.
However, the licensee did not adequately address
previous similar failures that had occurred since February 1992.
Although Salem staff recently took appropriate corrective action, these
two recurring problems demonstrate that previous inadequacies in root-
cause and corrective action determination sontinue to impact current
plant operations.
On July 11, 1992, Engineering identified a loud clanking noise internal
to 21RH10, the no. 21 residual heat removal pump discharge gate valve.
On April 16, 1993, maintenance performed an internal valve inspection
for wear and deterioration. Maintenance found two deep wear marks in
the downstream seat of the double-disk wedge gate valve.
Engineering
determined that the defects did not interfere with the valve function
- '
15
and were not within the "blue-dye" region that d~fines the seating
surface. Maintenance polished the valve seat and operations considered
the valve operable.
The licensee did not perform an operability
determination, root cause evaluation, or thorough potential failure
analysis.
On June 10, 1995, operations identified that 21RH10 made a loud noise
internally and that plant staff identified the same problem in 1992.
Operations, based on discussion with system engineering, determined that
the valve should be opened and inspected, but that the operability of
the no. 21 RHR pump was not effected. Engineering worked to document
the basis for the operability determination.
On June 11, the inspector
questioned the licensee's initial operability determination and
postulated a potential failure modes of the 21RH10 valve, i.e.,
detachment of the valve disk from the stem such that it impedes or
prevents RHR flow through the valve.
The inspector identified that the
licensee's plan to take the no. 22 RHR pump out of service to work on
the 22RH29 valve, coupled with the postulated failure of 21RH10, could
result in a complete loss of all RHR capability.
On June 16, 1995, system engineering and maintenance met with inspectors
to discuss RHlO operability. They concluded that the RHlO valves for
both trains of RHR remained operable based on a search of industry and
Salem data bases. The search revealed with no identified failures where
the disk actually separated from the stem.
In addition, plant staff
concluded that a fatigue induced separation of the disk from the stem
would require multiple failures at the most susceptible failure points.
Plant management stated that they planned to open and inspect 21RH10 to
evaluate the effect of the banging on the valve internals when plant
conditions permitted taking the no. 21 RHR system out of service. The
inspectors concluded that the plant staff was able to demonstrate a
reasonable basis for RHIO operability in this case, based on equipment
history and engineering judgement of the reliability of the valve
design.
The inspectors noted, however, that plant staff did not adequately
determine the root cause of the clanging and evaluate the effect on
operability in 1992 when first identified.
8.
On June 1, 1995, during a surveillance run of no. 18 EOG, the licensee
identified jacket water leaking from a pressure switch instrument pipe
nipple.
The workers secured the EOG to stop the leak and began
troubleshooting.
Laboratory analysis revealed that the nipple cracked completely through
the threaded area due to fatigue caused by vibration.
The licensee
confirmed this conclusion by performing resonance testing on EOG 18.
The testing found that the pressure switch instrument piping was
susceptible to resonance frequency of 90 cycles per second, a harmonic
of EOG steady state speed of 900 rpm (or 15 cycles per second). Similar
resonance testing on all remaining EOGs, including Unit 2, found EOG lC
also susceptible to resonance frequency vibration.
I6
As an interim measure to eliminate the resonance, engineering proposed
to change the length of the instrument tubing.
Engineering recommended
reorienting the tubing and moving the mounting brackets as permanent
solutions. At the conclusion of the inspection period, the licensee had
implemented the interim measure on EOG IC.
The inspector noted that during troubleshooting efforts the licensee
identified two previous pipe nipple failures that resulted in jacket
water leaks. The IC EOG experienced a jacket water leak in February
I992 and the I8 EOG leaked in December I993.
To address those failures
the licensee replaced the nipple on IC, and re-threaded and reinstalled
the nipple on the I8 EDG.
The inspector concluded the corrective
actions for the I992 nipple failure, since they were not based on any
established root cause, did not prevent recurrence of the degraded
condition for the IC or other EDGs.
The inspectors identified that the licensee's failure to thoroughly evaluate
and resolve the anomalous condition of the RHIO valve and to establish a root
cause of the EDG jacket water leakage problems when these conditions were
first apparent continues to result in potential challenges to safe plant
operation. Accordingly, failure to take adequate corrective actions regarding
the pipe nipple failures and resolution of the RHIO anomalous conditions are
considered as apparent violation of IO CFR 50, Appendix 8, Criterion XVI,
Corrective Action.
7.0
REVIEW OF REPORTS AND OPEN ITEMS
7.1
Licensee Event Reports
The inspectors reviewed the following Licensee Event Report {LER) to confirm
that the licensee took the corrective actions stated in the report, responded
to the event adequately, and met regulatory requirements and commitments:
Salem Unit I
Number
LER 95-007
Event Date
May 5, I995
Description
Emergency Diesel
Generators IA, 18,
and IC Paralleled Concurrently to
Electrical Grid {Assessed in NRC
Inspection Report 50-272&311/95-07)
The inspectors determined that the LER listed above did not identify any
violations beyond those previously identified in NRC Inspection Reports, and
considered the LERs closed.
17
Section 6.2 of this report provides details of inoperable Salem Unit 1
switchgear supply fans from December 12, 1994 until May 16, 1995.
As a result
of the inoperable fans, Salem Unit 1 operated in an unanalyzed condition
during that period.
On May 16, 1995, operators completed a shutdown of Salem
Unit 1 required by Technical Specification 3.0.3. However, the inspectors
confirmed that the licensee did not report the unanalyzed condition or the
shutdown required by Technical Specification 3.0.3 within 30 days as required
by 10 CFR 50.73. This is a violation (VIO 50-272&311/95-10-03)
8.0
EXIT INTERVIEWS/MEETINGS
8.1
Resident Exit Meeting
The inspectors met with Mr. J. Summers and other PSE&G personnel periodically
and at the end of the inspection report period to summarize the scope and
findings of their inspection activities.
Based on NRC Region I review and discussions with PSE&G, the inspectors
determined that this report does not contain information subject to 10 CFR 2
restrictions.
8.2
Specialist Entrance and Exit Meetings
Date(s)
5/11-12/95
Subject
EDS FI Foll owup
Inspection
8.3
Salem Management Changes
Inspection
Report No.
50-272 and 311/95-11
Reporting
Inspector
Cheung
PSE&G appointed Elbert (Bert) Simpson as senior vice president-nuclear
engineering, effective June 30, 1995.
Mr. Simpson will replace Stanley
LaBruna.
Mr. Simpson has served for the past two years as vice president-
nucl ear support for Arizona Public Service Company.
Also, the Nuclear
Licensing and Regulation Department was re-organized under the Quality
Assurance and Nuclear Safety Review organization.