ML18101A358
| ML18101A358 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 11/28/1994 |
| From: | Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18101A356 | List: |
| References | |
| 50-272-94-24, 50-311-94-24, NUDOCS 9412060124 | |
| Download: ML18101A358 (21) | |
See also: IR 05000272/1994024
Text
,*
Report Nos.
License Nos.
Licensee:
Facility:
Dates:
Inspectors:
Approved:
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
50-272/94-24
50-311 /94-24
Public Service Electric and Gas Company
P.O. Box 236
Hancocks Bridge, New Jersey 08038
Salem Nuclear Generating Station
September 18, 1994 - November 5, 1994
C. S. Marschall, Senior Resident Inspector
J. G. Schoppy, Resident rn*sp,,ector
T. H.
F~~h, ~esident Inspector
~~:zf'..f_!_~~~~Z':::~~------------------
J.
ll~ White, Chief, Reactor Projects
/
Section 2A
Inspection Summary:
_!..'.L-_~i..LL __
Date
This inspection report documents inspections to assure public health and
safety during day and backshift hours of station activities, including:
operations, radiological controls, maintenance and surveillance testing,
emergency preparedness, security, engineering/technical support, and safety
assessment/quality verification. The Executive Summary delineates the
inspection findings and conclusions .
9412060124 941128
ADOCK 05000272
Q
SALEM EXECUTIVE SUMMARY
Salem Inspection Reports 50-272/94-24; 50-311/94-24
September 18, 1994 - November 5, 1994
OPERATIONS
(Modules 40500, 60705, 60710, 71707, 92701, 92901)
Salem management took appropriate action in response to an operator
_
inadvertently closing two Main Steam Isolation Valves.
The inspector observed
good housekeeping in containment, excellent radiation protection pre-job
briefings and coverage, and thorough inspection and detailed deficiency
documentation by the Containment Walkdown Team.
The licensee took appropriate
corrective actions for peeling paint in containment and lube oil leakage from
reactor.coolant pump oil collection systems.
Plant staff conducted fuel
handl.ing activities safely. Inspectors noted management oversight of
refueling activities. For an hour and 32 minutes during irradiated fuel
movements, the licensee failed to assure containment integrity as required by
Technical Specification 3.9.4. This is an apparent violation .. In response to
identification of missed check valve surveillances, operations performed an
operability determination of significantly improved quality over previous
efforts.
MAINTENANCE AND SURVEILLANCE
(Modules 61726, 62703, 92902, TI 2515/125)
PSE&G did not take adequate corrective action to preclude recurrence of work
control inadequacies that occurred during the Salem Unit 1 fall 1993 refueling
outage.
As a result, on three occasions during the reporting period, workers
improperly performed outage work activities which contributed to the potential
for serious personnel injury.
The plant staff did not adequately address vacuum pump inlet valye
deficiencies.
As a result, valve mis-operation caused a reduction of
condenser vacuum.
Quick response by operators precluded a reactor trip.
The inspectors con~uded that Salem had adequate controls to prevent foreign
materials from entering and remaining in safety systems.
Plant staff properly
planned, controlled and conducted complex main steam safety relief valve
testing.
Operators failed to perform a nuclear instrumentation calorimetric within the
time required by Technical Specifications. This is an apparent violation.
Maintenance staff and supervisors performed outage maintenance on the 2C
diesel generator carefully and appropriately.
Poor communication between
system engineers and operations concerning centrifugal charging pump
vibrations resulted in a requirement for operators to conduct an accelerated
Salem Unit 2 shut down to comply with Technical Specifications .
ii
ENGINEERING AND TECHNICAL SUPPORT (Modules 37551, 71707, 92700,)
The licensee initially failed to critically evaluate a condition that had the
potential to involve corrosion on the auxiliary feedwater (AFW) piping.
Once
they initiated an investigation, the licensee thoroughly and adequately
addressed the piping concerns.
Marginal control air system performance continued to challenge normal plant
operation.
The inspectors concluded that the licensee responded appropriately
to the inadequately tapped fuel header bolt holes and inadequately torqued
fuel oil header bolts.
The licensee developed a reasonable basis to conclude that sustained Salem
Unit 2 operation at levels up to 102.6% did not compromise plant safety.
However, failure to consider the worst case implications of increased electric
generation indicated weaknesses in problem identification, resolution, and
safety perspective. Failure to promptly identify and correct the overpower
condition is a apparent violation.
PLANT SUPPORT (Modules 71707, 71750, 92700)
Radiation Protection demonstrated consistently strong performance throughout
the inspection period.
Inspectors noted a large number of corrective
maintenance activities for the plant radiation monitors, though the trend has
been decreasing for the last three years.
The inspectors concluded that the
frequent degraded condition of the radiation monitors tended to be a constant
distraction to operators and required frequent compensatory action.
The
inspectors also noted that plant management recently increased efforts to
improve radiation monitoring equipment reliability through improved
maintenance and greater emphasis on developing a long term solution.
A security guard failed to control, access to a vital area. This- is an
apparent violation of security plan requirements.
On September 7, PSE&G
announced that they had named Mr. Leon Eliason President and Chief Nuclear
Officer of the newly formed PSE&G Nuclear Business Unit.
In addition, on
September 8, PSE&G announced that they had named Mr. John Summers to the
position of Salem Mechanical Maintenance Manager for a one year period.
The inspectors noted that Salem and Engineering and Plant Betterment (E&PB)
managers had performed various levels of analysis to identify areas for
performance improvement.
The E&PB and Operations analyses and improvement
plans, in particular, demonstrated thorough analysis and carefully mapped out
action plans. Other departments had less formal plans with fewer means to
track improvement.
Senior management stated that measures had been initiated
to establish a more uniform approach to improving performance .
iii
TABLE OF CONTENTS
TABLE OF CONTENTS . * * .
1.0
SUMMARY OF OPERATIONS ..
I.I
Salem Units I and 2 .
. . .
'
iv
I .
I
. 2. 0
OPERATIONS
- * . * * * . .
. . * . . . . . . . . . .
I
3.0
4.0
5.0
6.0
7.0
2.1
Inspection Activities ..*..**..... ~ . . . . * . .
I
2.2
Inspection Findings and Significant Plant Events
. . . .
I
MAINTENANCE AND SURVEILLANCE TESTING
. * . *
3.1
Maintenance Observations ...*.
3.2
Surveillance Observations
3.3
Inspection Findings .
ENGINEERING . . . . . . . . . .
PLANT SUPPORT . . . . . * . . . . . . . . .
5.1
Radiological Controls and Chemistry .
5. 2 * Emergency Preparedness . . . . . .
. . . . . . . .
5.3
Security .......
-............. .
5.4
Safety Assessment and Quality Verification ... .
LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS, AND
OPEN ITEM FOLLOWUP
. . .
6.1
LERs and Reports ... .
6.2
Open Items .... .
EXIT INTERVIEWS/MEETINGS
.
. . . . . .
- 7.1
Resident Exit Meeting .......... .
7.2
Salem Specialist Entrance and Exit Meetings
7.3
Management Meetings ......... .
iv
4
4
5
5
10
13
13
14
14
14
15
15
16
16
16
17
17
1.0
1.1
SUMMARY OF OPERATIONS
Salem Units 1 and 2
DETAILS
Unit 1 operated at power throughout the report period.
Unit 2 began the period at 100% power.
On September 22, 1994, as a result of
high centrifugal charging pump vibration, operators shut the unit down to
comply with a Technical Specification action statement.
On September 27,
operators commenced a reactor startup.
On September 29, operators manually
tripped the reactor when an operator inadvertently closed two main steam
isolation valves at 30% power.
On September 30, operators again commenced a
reactor startup and returned the unit to 100% on October 3.
On October 13,
operators commenced a shutdown for the eighth refueling outage.
The unit
remained in the outage through the end of the report period.
2.0
OPERATIONS
2.1
Inspection Activities
The inspectors verified that Public Service Electric and Gas (PSE&G) operated
the facilities safely and in conformance with regulatory requirements.
The
inspectors evaluated PSE&G 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 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> of deep back
shift inspections.
2.2
Inspection Findings and Significant Plant Events
A.
Inadvertent Main Steam Isolation Valve (MSIV) Closure
On September 29, with Salem Unit 2 at 30% power during a startup, a control
room operator inadvertently closed two of the four MSIVs.
The operators
recognized the error as the valves began to close, and manually tripped the
reactor in anticipation of a reactor trip on high reactor coolant system
pressure in the pressurizer.
The plant responded as designed. Operations
management reviewed the event and the performance of the operators. They
concluded that the operator had been instructed to close the MSIV warming
valves.
He had correctly repeated back the instructions to close the warming
valves, then removed a protective cover intended to prevent inadvertent MSIV
closure, and closed the valves.
Management concluded that operator
recognition of the error and action to trip the reactor had been prompt and
appropriate.
Based on past performance of the operator making the error,
including an evaluation of previous performance, and at the request of the
operator, operations management removed the operator from duties involving
direct control of plant equipment.
The inspectors considered operations
management actions appropriate.
..
2
B.
Conta;nment Walkdown
On October 14, 1994, the licensee conducted 52.0P-PT.CAN-0001, Containment
Walkdown, at the onset of their refueling outage.
The inspector observed good
housekeeping in containment., excellent radiation protection pre-job briefings
and*coverage, and thorough inspection and detailed deficiency documentation by
the Containment Walkdown Team.
The inspector noted that peeling paint on
walls and floors posed a potential for containment sump clogging. The
inspector determined that the licensee identified the peeling paint, and
planned to address it during the outage.
The inspector observed good
management oversight and attention in this area.
In addition, the inspector noted a significant amount of lube oil coating the
reactor coolant pump {RCP) platforms in containment.
The oily platforms
presented a personnel safety concern, and a thin coating of oil on the stator
windings presented a potential reliability concern.
The inspector noted that
NRG Information Notice 94-58, .Reactor Coolant Pump lube Oil Fire, identified
that some RCP oil collection systems present fire hazards.
Oil leaking from
- the lube oil system may come in contact with either {l) surfaces that are hot
enough to ignite the oil, or {2) an electrical source of ignition. The
licensee removed the oil to address the personnel safety hazard, and planned
to take action to address the oil leaking from the collection system.
The
inspector noted good communication between maintenance, engineering, and
vendor representatives and considered that the licensee had tak~n appropriate
action.
c.
Refuel;ng Act;v;t;es
At 11:38 p.m. on October 24, 1994, operators began to move fuel from the
reactor core to the spent fuel pool.
At 2:35 p.m. on October 27, operations
completed core offload.
On October 31, reactor engineering, with Westinghouse
support, commenced fuel rod ultrasonic and visual inspection for the offloaded
core.
At the end of the inspection period they had inspected 153 of 193
assemblies. Westinghouse preliminary findings indicated eight leaking
peripheral fuel rods.
The inspector noted that the position of the failed
rods correlated to Westinghouse findings from the Unit 2 seventh refueling
outage.
{Refer to NRC Inspection Report 50-272&311/93-15)
The inspector observed good control of preparations for refueling, new fuel
inspection, core off-load, and failed fuel inspection.
The inspector noted
that, contrary to an internal commitment, the training program for refueling
operators did not review previous fuel handling problems experienced at during
the Hope Creek outage. Operations identified a weakness in the tracking and
implementation of this training, took short-term actions to provide additional
focused training, and initiated a review of refueling training practices for
long-term improvement.
The inspector noted Operations management and Quality
Assurance direct involvement in refueling activities. _However, on two
occasions inspectors identified minor fuel handling equipment deficiencies
known by equipment operators, but not conveyed to management.
3
With the unit defueled, operations relied upon the spent fuel cooling system,
and the ability to connect the Unit 1 spent fuel pool (SFP) cooling to Unit 2.
The licensee failed to implement a procedure change dated October 24, 1993,
following an overflow of the Unit 2 SFP while operating with SFP cooling
systems cross connected (See NRC Inspection Report 50-272&311/93-23).
Upon
recognition, the licensee immediately implemented the procedure change.
The
inspector noted that workers expertly conducted the fuel handling activities.
The inspector observed good communication and coordination between the control
room, containment, and the fuel handling building. The licensee, with
-Westinghouse support, safely off loaded the Unit 2 core.
D.
Containment Isolat;on Dur;ng Core Alterat;ons
At 11:38 p.m. on October 24, 1994, operators began core alterations for the
Unit 2 eighth refueling outage.
At 1:10 a.m. on October 25, operations
suspended core alterations upon discovery of open service water.valves that
provided access from containment directly to the auxiliary building. -A
Bechtel supervisor, working in containment, identified a release pathway from
open service water vent valves in containment to open service water drain
valves outside of containment. - Previously, operators tagged the service water
valves open for planned outage work on containment fan cooling units.
The licensee immediately suspended fuel handling operations upon
identification of the potential release pathway affecting containment
integrity. Operations isolated the service water drain valves outside
containment and verified service water piping intact between isolation valves
and containment. Operations reviewed all maintenance activities and conducted
two independent reviews of tagged valve reports to insure containment
integrity. Operations made an on-the-spot change to S2.0P-ST.CAN-0007,
Refueling Operations - Containment Isolation, to require these independent
reviews.
At 6:05 a.m. on October 25, operations resumed fuel handling
operations.
The irispector noted that the Bechtel supervisor demonstrated good oversight .
The inspector determined that the licensee took prompt and appropriate
corrective action to restore containment integrity. However, the inspector
noted that the licensee took action to preclude recurrence that duplicated
requirements exi~ting at the time of the occurrence.
The SRO failed to
conduct an adequate review prior to the commencement of fuel alterations. The
inspector determined that management did not clearly convey their expectations
concerning the depth of review required to fully satisfy containment integrity
under these conditions. The inspector concluded that failure to assure
containment integrity during the performance of core alterations was a
violation of Technical Specification 3.9.4.
(VIO 50-311/94-24-01)
E.
1PR25 Operab;1;ty
As documented in NRC Inspection Report 50-272&311/94-21 on October 17, the
licensee determined that they had not performed surveillances to verify the
ability of check valves 1PR25 and 2PR25 to permit flow under design
conditions.
The referenced report provides details of the surveillance
requirements and the licensee failure to include the flow verification in the
4
In Service Testing {IST) program.
As a result of the missed surveillance, the
resident inspectors questioned whether the licensee concluded that valve
1PR25 for Salem Unit 1 could perform its design function, and how its
potential inability to perform its intended function affected the associated
ECCS systems (Containment Spray, Safety Injection, Residual Heat Removal).
At
the time, Salem Unit 2 was in a refueling outage.
-The licensee completed an operability determination, and inspectors reviewed
the analysis. The inspectors noted that the licensee, in performing the
determination, had not identified the design flow and pressure conditions for
valve operability. The licensee did not identify a basis to establish that
the valve could permit required flow.
In addition, the licensee did not
establish the effect of insufficient flow through the valve on the associated
ECCS systems.
In response to the inspector questions, the licensee
demonstrated that during quarterly ECCS testing the valve had permitted flow
greater than the expected flow under worst case conditions.
The licensee
concluded that the missed surveillance did not result in plant operation with
undetected degradation of ECCS systems.
The inspectors concluded the licensee appropriately determined that ECCS
remained operable. The inspectors noted that the operability determinations
utilized the recently established operations department guidance.
The
inspectors found that the operations department had significantly increased
the quality of operability determinations.
The inspectors also noted,
however, that lack of consideration of the design conditions (such as
pressur~, flow, etc) required for operability of a compon~nt reduced the
quality of the operability determination process.
3.0
MAINTENANCE AND SURVEILLANCE TESTING
3.1
Maintenance Observations
The inspectors observed selected maintenance activities on safety-related
equipment to ascertain that the licensee conducted these 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
Unit
Change Package CDCPl
Description
Salem 2
Replacement of Pressurizer
Spray Valve Internals
Salem 2
Change out of Trim Set for
Pressurizer Relief Valves
Salem 2
Inspection of Reactor Vessel
Head Bolting
Salem 2
CCHX Tube Inspection
Salem 2
Salem 2
Salem 2
Salem 2
5
Service Water Pipe Inspection
21 Auxiliary Feedwater Pump
Suction Check Valve Inspection
Modifications to 21 Station
Power Transformer
Modify Diesel Generator
Intake/Exhaust Piping~
The maintenance activities inspected were effective with respect to meeting
the safety objectives of the maintenance program.
3.2
Surveillance Observations
The inspectors performed detailed technical procedure reviews, witnessed in
progress surveillance testing, and reviewed completed surveillance packages.
The inspectors verified that the surveillance tests were performed in
accordance with Technical Specifications, approved procedures, and NRC
regulations.
The inspector reviewed the following surveillance tests with portions
witnessed by the inspector:
Unit
Procedure No.
Test
Salem 1
Sl.OP-ST.CBV-0003
Containment Systems - Cooling
Systems
Salem 1
Sl.OP-ST.SW-001
Inservice Testing Service
Water Valves
Salem 1
Sl.OP-ST.CBV-0003
Containment Systems - Cooling
Systems
Salem I
SI.OP-ST. SW-001
Inservice Testing Service
Water Valves (CFCUs)
The surveillance testing activities inspected were effective with respect to
meeting the safety objectives of the surveillance testing program.
3.3
Inspection Findings
A.
Maintenance Performance Deficiencies
During the inspection period, the licensee reported several instances of
deficient maintenance performance.
No event had nuclear safety significance.
However, the potential existed for serious industrial safety consequences .
..
6
On October 29, electricians cut through the wrong 4KV electrical cable. The
work procedure directed the electricians to cut existing circulating water
(CW} pump feeder cables into 4 foot sections. The modification package
directed the electricians to remove the section from the cable tray prior to
making the cut.
As a result of interference of other cables and cable trays,
the electrician decided to make a cut without removing the entire length of
cable from the cable tray. Although he believed he had identified the correct
cable, he incorrectly cut a 4KV feeder to the Chemical Treatment building.
Fortunately, operators previously tagged out the feeder to support another
work activity. Fortuitously, the electrician did not sustain any injury.
On November 4, the site services personnel loaded Salem CW trash racks onto a
flatbed truck, using a 55 ton crane.
When the crane swung the load over the
truck, it tipped over slightly injuring the crane operator. The licensee
determined that the crane tipped due to inadequate implementation of controls
designed to insure the outriggers were properly extended.
Also on November 4, a contractor working in the containment on a reactor
coolant pump seal attempted to lower his tool box using improper rigging.
The
box slipped out of the sling and dropped 20 feet to the floor.
The incident
did not result in injury or damage to plant equipment.
The contractor told
the maintenance manager that he knew the rigging method was inadequate because
he had dropped the tool box on two other occasions.
The maintenance manager
immediately removed the contractor from the job and stopped all work on the
reactor coolant pump seal activity.
In response, the licensee stopped all work to review the events with workers,
and reinforce the need to understand and adhere to work controls.
In
addition, the licensee took disciplinary action against responsible
individuals, and emphasized the requirement for effective pre-job briefs. The
inspectors noted that the above mishaps represent additional examples of poor
work control similar to problems previously identified in NRC Inspection
Report 50-272 and 311/93-23 and the subject of NRC Notice of Violation dated
March 9, 1994.
The inspectors noted that the examples described above and the
~xamples. described in NRC Inspection Report 93-23 demonstrate that lice'nsee
- corrective action efforts have not been totally eff~ctive in precluding
recurrences.
B.
At 5:43 a.m. on October 4, 1994, equipment operators removed the no. 24
condenser vacuum pump from service for preventative maintenance.
Control room
operators noted decreasing condenser vacuum and reduced power.
At 5:46 a.m.
equipment operators returned the no. 24 vacuum pump to service. Control room
operators initiated S2.0P-AB.Cond-0001, Loss of Condenser Vacuum.
At 5:50
a.m. operators restored vacuum to normal and stopped the power reduction.
The
licensee determined that the no. 24 vacuum pump inlet valve (24AR25} failed to
close when the vacuum pump was removed from service and subsequently caused
the loss of vacuum.
7
The inspector observed that the west-side vacuum indication did not accurately
reflect condenser pressure, complicating the response to the valve failure.
The inspectors noted that operators identified the instrument problem on
November 16, 1993, and further determined that on August 14, 1993, a work
order was generated to investigate 24AR25, as the valve did not close when the
pump was removed from service. The valve was presumed fixed, and the work
order closed out, when yet another work order was generated for 24AR25 on July
3, 1994.
The work order generated on July 3, 1994 remained open on October 4,
1994.
The inspector concluded that plant staff had not adequately resolved
.this recurrent balance of plant equipment failure.
As a result, it continued
to unnecessarily challenge plant operation.
C.
Foreign Material Exclusion (FME) Controls Temporary Inspection (TI
2515/125)
The inspectors reviewed licensee FME controls to determine if the licensee had
adequate measures to prevent foreign material from inadvertently entering
safety systems during maintenance activities, outages, and routine operations.
The inspectors found that Nuclear Administration Procedure (NAP) 21, System
Cleanliness Program, provided instructions on proper cleaning methods and
provided instructions to prevent the intrusion of debris into the reactor
vessel and into the primary system.
Salem Maintenance Procedure GP.ZZ-6, Tool
and Miscellaneous Items Accountability and Closure Control, provided
instructions that prevent introduction of foreign material (debris, tools)
into open systems.
The procedure-also provided instructions to account for
tools, parts, and material during maintenance, testing, and inspection
activities. Reactor Engineering (RE) procedures for refueling, fuel handling,
and fuel repair referenced NAP-21 and ZZ-6 for controlling debris.
The RE
procedures include additional guidance for controlling activities involving
the spent fuel pool and transfer pool.
Based on a licensee search of the Incident Report data base, the inspectors
concluded that no documented instances of foreign material intrusion occurred
within the previous year, nor did the inspectors recall the occurrence of
foreign material intrusion problems.
The inspectors observed maintenance
activities to determine if foreign material exclusion control procedures were
available and being followed.
The inspector noted acceptable intrusion
control during maintenance activities on the 2C emergency diesel generator,
during fuel handling in the containment, and various other outage related
activities. At the end of the report period, the licensee had completed less
than half of the Salem Unit 2 refueling outage.
Based on the amount of
outage related equipment and material in containment, the inspectors concluded
that effective containment closeout played a central role in preventing loose
material from affecting safety. The inspectors could not assess the
effectiveness of containment closeout prior to the end of the inspection
report due to the duration of the outage.
Based on these observations, the inspector concluded that the licensee
adequately prevented foreign material from entering safety systems during
maintenance outage and routine activities .
8
D.
Auxiliary Feed Pump Trip
- On October 7, 1994, the No. 23 Auxiliary Feedwater (AFW) pump tripped during
surveillance test 52.0P-SP.AF-003, Inservice Testing - No. 23 Auxiliary
Feedwater Pump.
Operators determined that the trip latch was not fully
engaged and vibration on pump startup caused the trip valve to actuate.
Prior to running the pump, the procedure required the operator to ~ress the
emergency trip lever to manually trip the valve through the overspeed trip
mechanism, insuring overspeed protection.
On resetting the trip, the
operator failed to properly engage the trip mechanism.
The licensee
determined that the procedure did not provide sufficient operator guidance to
ensure that the operator fully seated the overspeed trip mechanism (OTM).
The
procedure provided additional verification only if the operator had not
properly seated the OTM.
The procedure had previously required the operator
to properly seat the OTM, and the operator had no reason to suspect that he
had not properly seated the OTM.
The licensee changed the procedure to
require the mechanical check to positively verify trip linkage engagement.
The inspector noted that the No. 23 AFW pump tripped in exactly the same
manner on September 9, 1993.
(See Inspection Report 50-311/93-21)
Following
that occurrence, the licensee made an "on-the-spot" change to the surveillance
to ensure proper trip mechanism engagement.
However, as noted above, the
modified procedure did not require adequate engagement verification.
The inspector determined that the October 7, pump trip had no safety
consequence since the pump was inoperable for the surveillance test. However,
the inspector noted that similar misalignment upon resetting the trip valve at
the conclusion of the surveillance could result in an AFW pump trip for a pump
start under accident conditions. The inspector observed that improper OTM
engagement following completion of a surveillance would be masked by the
requirement to manually trip the pump at the beginning of the next
surveillan,ce. The inspector planned to continue to review the adequacy of the
licensee's evaluation of the AFW pump surveillance activity. (IFI 50-311/94-
24-02)
E.
Missed Surveillance for Nuclear Instrumentation System (NIS)
At 7:45 a.m. on October 13, during a Unit 2 shut down in preparation for the
outage, a technician asked the operating crew for permission to perform a heat
balance calibration of the NIS.
Technical Specifi~ation (TS) 4.3.1.1.1, Table
4.3-1 requires plant staff to perform the calibration once each 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when
- power is above 15%.
Plant staff performed the previous calibration at 9:51
a.m. on October 12. Believing, incorrectly, that the calibration was a daily
requirement, the shift supervisor stated that he expected power to be below
15% by the end of the day, therefore, the calorimetric would not be required.
The operators continued the plant shutdown, reducing plant power below 15%
after 9:51 p.m., and did not perform a calorimetric during a period of more
than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.
Failure to perform the NIS heat balance calibration is a
violation of TS 4.3.1.1.1.
(VIO 50-311/94-24-03)
9
F *.
. Main _Steam Safety Relief Valve Testing
On October*14, 1994, the inspector observed main steam safety valve testing in
place. The inspector noted that plant staff properly planned, carefully
controlled, and safely conducted the complex evolution.
In addition, the
inspector noted good coordination and involvement by maintenance, system
engineering, quality assurance, operations, and maintenance management.
G.
2C Emergency Diesel Generator Maintenance Activities
On October 16, 1994, Salem maintenance staff began a 2C emergency diesel
generator (EOG} outage to perform preventative maintenance, slip ring
machining, air start system piping and valve replacement, and cylinder liner
replacement. Maintenance technicians successfully completed all scheduled
maintenance.
On October 30, operations declared the 2C EOG operable following
satisfactory post-maintenance and operability testing.
Maintenance personnel replaced both 2C diesel air start receiver check valves
and drain valves.
In addition, maintenance replaced the carbon steel piping
between the air compressor and air start receiver in kind. Maintenance
replaced 8 cylinder liners, which were previously replaced in January 1994,
following discovery of a cracked liner in the 2C EOG (see NRC Inspection
Report 50-272&311/93-27).
The replacement liners used in January arrived
without qualification documentation.
In January, maintenance bored several
small holes in a low stress area to qualify the liners for safety-related use.
The licensee planned to evaluate the removed liners for stress iriduced
cracking.
The results of this evaluation has the potential of affecting 18
EOG which also contains cylinder liners with bored metallurgic sample holes.
The inspector determined that the licensee properly planned and conducted the
maintenance.
The inspector observed good work practices, excellent foreign
material exclusion (FME) practices, good procedure use, and effective PSE&G
supervision in the field.
H.
Maintenance of No. 21 Centrifugal Charging Pump
On September 19, plant staff identified inadequate coupler spacing in the No.
21 charging pump speed increaser. After adjustirig the spacing, engineering
staff noted elevated vibration readings during the post maintenance test
- (PMT}.
The readings had not reached the required action range specified in
t.he IST program.
As a result system engineers concluded that the pump met the
post maintenance acceptance criteria for operability, since the PMT did not
include acceptance criteria for vibration associated with the speed increaser.
The system engineers did not inform operations staff of the increased
vibration. The system engineers did, however, request that operations run the
pump again on night shift to permit gathering more extensive vibration data.
During a two hour run, the system engineering staff found that the vibration
had significantly increased. After approximately two hours of data review,
they informed the operations staff that the pump should be considered
As a result of the system engineering staff input, operations
declared the pump inoperable. They concluded that the pump had been
inoperable since they entered the Technical Specification LCO action statement
10
to begin maintenance, three days earlier. As a result, operations staff
performed an accelerated shut down of Salem Unit 2 to meet the requirements of
Technical Specification 3.0.3.
The inspectors concluded that operations staff, when informed of the vibration
concerns, properly interpreted Technical Specification requirements and
appropriately shut down Salem Unit 2.
The inspectors also concluded that
system engineering unnecessarily imposed the requirement for an accelerated
shut down on the operations staff. The system engineers failed to promptly
and appropriately assess the impact of high vibration on the operability of
the centrifugal charging pump.
The surveillance procedure did not consider
vibration of the speed increaser as part of the acceptance criteria. The
inspectors concluded, however, that system engineering and planning staff
inappropriately failed to consider vibration as part of the required
acceptance criteria, since maintenance with the potential for adversely
affecting the speed increaser had been performed.
4.0
ENGINEERING
A.
Suspected Auxil;ary Feedwater Piping Degradation
On September 6, 1994, the inspector informed the system engineer of watermarks
running down the wall beneath the no. 22 auxiliary feedwater. (AFW) piping
penetration in the main steam isolation valve (MSIV) room on Salem Unit 2.
The engineer considered the leakage normal and attributed it to ground water
leakage past the Williamson penetration seal.
On September 9, the inspector
observed standing water in the MSIV room beneath the AFW penetration.
The
inspector obtained rust from between the AFW piping and the penetration walls.
Based on the presence of rust, the system engineer examined the piping and
penetration more closely and determined that ground water leakage might be
eroding the AFW pipe coating. The system engineer initiated ultrasonic
testing (UT) to evaluate AFW piping wall thickness.
On September 19, the inspector requested an operability evaluation. The
licensee appropriately evaluated AFW operability.
On September 21, the Plant
Manager ordered a detailed evaluation of the AFW piping.
On September 22, UT
examination found the wall thickness greater than the minimum required wall
thickness and within manufacturing tolerances. Chemical analysis of water and
dirt samples from the pipe penetration were inconclusive. During excavation
of the outside area around the penetration the licensee observed evidence of
water infiltration into the penetration, and determined that the seals were
inadequately installed. Engineering did not find any indication of pressure
boundary leakage or degradation.
The licensee replaced the penetration seals
and declared the AFW piping operable.
The inspector concluded that the licensee demonstrated weak safety focus in
their initial lack of timely response to a potential safety issue.
Subsequently, the licensee conducted a very thorough AFW piping evaluation.
The inspector noted that the penetration still leaked after completion of the
seal repairs, but determined that no immediate AFW piping concern existed .
11
B.
Control Air Abnormalities
The inspectors documented control air system problems in NRC Inspection Report
50-272 and 311/94-19.
The inspectors noted the three additional examples of
control air degraded performance during this inspection period.
On October 5, 1994, during the performance of a control air surveillance test,
the no. 2 emergency air compressor tripped immediately on low oil pressure due
to an initial oil pres.sure fluctuation. Subsequent maintenance testing
demonstrated acceptable oil pressure, within the required time, to prevent
tripping of the compressor on startup.
On October 28, while preparing to
remove the no. 2 station air compressor (SAC) from service, for corrective
maintenance, the no. 3 SAC failed to properly load. Maintenance completed
prolonged maintenance (16 days) on no. 3 SAC on October 19.
The station air
and control air header pressures dropped, the no. 1 emergency control air
compressor auto started, and the operators began to restore no. 2 SAC.
Within
25 minutes, operators restored the no. 2 SAC and returned no. 3 SAC to standby
status.
On October 31, maintenance took the no. 11 control air dryer out of
service for preventive maintenance and "B" control air header pressure dropped
to 86 psig.
Normal control air pressure is 90-I20 psig.
The inspectors determined that plant staff took immediate corrective actions
in response to control air problems as required by procedure and Technical
Specification requirements.
However, marginal control air system performance
continues to provide challenges to plant operation.
C.
Diesel Generator Fuel Oil Supply Header Bolt Problems
During the 2C emergency diesel generator (EDG) maintenance outage, maintenance
personnel discovered that the diesel vendor had not tapped some fuel supply
header bolt holes sufficiently to permit full bolt insertion.
(Each cylinder
has two such bolts.) The licensee experienced previous problems with the fuel
header bolts.
On three occasions (April 30, 1993; November I3, 1993; and
September 25, I994) workers found bolts broken in two pieces following diesel
runs. A PSE&G Research and Testing laboratory evaluation, dated March IO,
I994, determined that fatigue caused the first two failures.
As a result of
the discovery, engineering suspected that inadequately tapped bolt holes
caused the fatigue failures. Maintenance tapped the holes deeper in the 28
and 2C EDGs and planned to take the same action for 2A EOG during its outage
window.
The maintenance staff verified the full insertion of all fuel supply
header bolts in the Salem Unit I EDGs by visual and physical inspection.
The
licensee is evaluating the condition for reportability under IO CFR Part 2I.
On October 30, I994, while running the IA EOG to demonstrate operability after
corrective maintenance, an equipment operator emergency tripped the IA EDG due
to fuel oil spraying out from under the fuel injection pump covers. Operators
were running the IA EOG to satisfy Technical Specification requirements due to
corrective maintenance on the IC EDG.
Maintenance found two fuel header bolts
backed completely out on one cylinder. Although the fuel oil supply line was
still aligned for that cylinder fuel injection, fuel oil leaked out, and
overflowed eight adjacent fuel injector pump cover plates. The licensee noted
no affect on engine performance, however, the fuel spraying on the running
12
engine presented a threat of fire.
The licensee concluded that the bolts were
not adequately tightened previously and vibrated loose.
In response, the
licensee verified that all the fuel supply header bolts had been torqued to
14-16 ft-lbs.
The inspectors concluded that the licensee responded appropriately to the
inadequately tapped fuel header bolt holes and inadequately torqued fuel oil
header bolts.
D.
Susta;ned Operation of Salem un;t 2 above 3411 Megawatts (thermal)
As documented in NRC Inspection Report 50-272&311/94-01, the licensee found
that they had operated Salem Unit 2 at thermal power levels up to 101.4% (3459
MWth) power for sustained periods during operating cycle 7, and at sustained
thermal power levels up to 102.58% (3499 MWth) + or - 7% during operating
cycle 8.
The licensee attributed the immediate cause of the overpower
operation to inaccurate feedwater flow indication.
The licensee concluded
that they did not immediately recognize the overpower condition because they
attributed the increased electric output to plant improvements and calculation
uncertainties.
The licensee, with assistance from Westinghouse, performed extensive
evaluation of the effects of sustained operation at 104.5% power (3565 MWth).
The licensee concluded that sustained operation at 104.5% power did not
compromise plant safety since it did not affect some analyzed accidents, and
detailed analyses for the remaining analyzed accidents concluded that
sufficient margin existed to offset the adverse consequences resulting from
overpower operation.
The licensee also concluded that they did not recognize
the possible connection between increased generator output and decreased
calculated reactor coolant system (RCS) flow rate. The licensee identified a
number of corrective actions, including inspection and root cause analysis of
the inaccurate feedwater flow indication, replacement of the feedwater flow
nozzles, establishing a trending program for statepoint and calorimetric data,
and improved use of operating experience feedback.
The inspectors concluded that the PSE&G assessment of the safety significance
of operating at greater than 100% power reasonably concluded that the safe
operation of the plant had not been compromised.
However, since the licensee
did not assess the operation at 102.58% power until after the fact, the
licensee operated the plant in an unanalyzed condition for sustained periods
during operating cycle 8.
In addition, the licensee did not promptly identify
that the increased electric output resulted from increased reactor power, a
potential safety problem.
The licensee had sufficient empirical data
available (RCS flow and core temperature change) to allow them to challenge
the accuracy of the feedwater flow indication during operating cycle 7 and 8.
The analysis, however, failed to question the accuracy of feedwater flow
indication.
The lack of questioning was due, in part, to the expectation that
the increased electric generation resulted from recent improvements in balance
of plant equipment.
In summary, the licensee failure to consider the worst
case implications of the increased electric generation indicated weaknesses in
13
problem identification, resolution, and safety perspective.
Failure to
promptly identify and correct a significant condition adverse to quality is a
violation of 10 CFR 50, Appendix B, Criterion XVI.
(VIO 50-272&311/94-24-04)
(CLOSED: URI 50-272&311/94-01-02)
5.0
PLANT SUPPORT
5.1
Radiological Controls and Chemistry
5.1.1 Inspections Findings
A.
Radiation Protection Outage Activities
The inspector observed consistently strong Radiation Protection performance
throughout the inspection period. Radiation protection staff conducted good
radiation worker briefings, properly posted radiation and contaminated areas,
and generally assured excellence in radiological worker practices. Radiation
protection technicians actively monitored the radiologically controlled area,
were very knowledgeable of plant conditions and- radiological practices, and
strictly controlled access point entries and exits. The inspector noted good
radiation protection management supervision involvement at the control points
and in the plant, especially in containment .
B.
Radiation Monitoring System Reliability
During the past year, inspectors have noted a large number of corrective
maintenance activities for the plant radiation monitors.
Based on a review of
documented work activities, the inspectors noted the following numbers of
corrective maintenance activities for the Salem radiation monitors:
RMS Corrective Maintenance
Salem 1
Salem 2
1/1/91 - 12/31/91
383
379
1/1/92 - 12/31/92
280
365
10/1/93 - 9/30/94
216
305
The inspectors concluded that the frequent degraded condition of the radiation
monitors posed unnecessary distraction to operations and maintenance staff,
even though the frequency of repair trended down over the past three years.
The inspectors also noted that plant management recently increased efforts to
improve radiation monitoring equipment reliability through improved
maintenance and increased emphasis on developing a long term solution.
5.2
5.2.1 Open Item Followup
14
(Closed) Unresolved Item (50-272 and 311/92-17-01)
Following an unplanned loss of shutdown cooling at Hope Creek in October 1992,
the inspectors reviewed the event and PSE&G's evaluation of reportability
under 10 CFR 50.72 requirements.
The inspector also reviewed Salem's relevant
reporting requirements.
The inspector reviewed PSE&G's current procedures and expectations concerning
reportability under 10 CFR 50.72 for loss of shutdown cooling and decay heat
removal.
The criteria for making a non-emergency four hour report were, a}
the event was an engineered safety feature (ESF} actuation and b} the event
was one which alone could have prevented the fulfillment of a safety function
needed to remove residual heat.
The inspector determined that these criteria
met the applicable reporting requirements of 10 CFR 50.72, paragraph (b}(2}.
The inspector concluded that the licensee was in compliance with NRC
req~irements and adequate means existed to properly document loss of shutdown
cooling events. This item is closed.
5.3
Security
5.3.1 Inspection Findings
On October 24, 1994, a guard providing control of a temporary access to the
no. 2C emergency diesel generator room, failed to properly verify that the
inspectors had been authorized access to the EOG.
Post orders, issued to
provide instructions for access control, instructed the guard to verify that
each person needing access to the EOG room, had been granted authorization
prior to permitting entry.
In response to the inadequate performance, a
security supervisor took immediate action to insure compliance with the
requirement for verification of authorization to the vital area.
In addition,
the security contractor took appropriate disciplinary action and conducted
remedial training for the guard.
In addition, the contractor reviewed the
incident with the guard force.
Failure to insure proper authorization to a
vital area prior to granting access is a violation.
(VIO 50-272&311/94-24-05)
5.4
Safety Assessment and Quality Verification
5.4.1 Inspection Findings
A.
PSE&G Management Changes
On September 8, PSE&G management announced that they had acquired the services
of John Summers to fill the position of Manager, Salem Mechanical Maintenance
on a temporary basis (1 year).
In addition, on September 7, PSE&G announced
that the nuclear division had been re-established as a separate PSE&G business
unit headed by President and Chief Nuclear Officer, Leon Eliason .
15
B.
Management Assessment of Salem Performance
The inspectors interviewed the Vice President of Operations and Salem general
manager, the Salem department managers, and the Vice President and managers of
the corporate engineering organization. The inspectors conducted the
interviews to determine and assess the process for effecting change in the
performance of *the Salem staff and supporting organizations. The inspectors
requested that the managers relate the areas identified as most in need of
change, the basis for determining the areas needing change, and the action
planned to generate the required change.
The inspectors learned that corporate engineering managers had performed
extensive research specific to their organization to identify areas for
improvement.
The results identified weaknesses in leadership ability, the
need for process improvements, and the need for organizational changes.
Corporate engineering developed a comprehensive plan to address the identified
areas for improvement.
Some Salem managers also performed independent analysis of their organizations
to identify the areas in need of change.
The operations department, for
example, identified processes and personnel performance issues among the areas
for improvement.
The operations staff demonstrated significant ownership and
pride in the documented plan for improving operations performance.
Other Salem managers had also identified areas for improvement.
The sources
of the identification process included reports issued by the NRC and other
outside organizations, and Comprehensive Performance Assessment Team results.
The inspectors observed_ that the managers identified many fruitful areas for
improvement.
The inspectors also noted that some of the managers did not have
direct ownership for the source of the areas identified for improvement, and
had not established a plan for achieving the identified improvements.
Senior
management stated that they had initiated efforts to establish a more uniform
approach to improving performance.
6.0
LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS, AND OPEN
ITEM FOLLOWUP
6.1
LERs and Reports
The Salem Monthly Operating Reports for August and September were reviewed for
accuracy and content, and were determined to be acceptable.
The inspectors
also reviewed the following LERs to determine whether the licensee took the
corrective actions stated in the report, and to determine if licensee
responses to the events were adequate, met regulatory requirements conditions,
and commitments:
Salem.LERs
Unit 1
Number
LER 94-14
LER 94-08
Unit 2
LER 94-10
LER 94-11
16
Event Date
August 25, 1994
August 28, 1994
September 22, 1994
September 29, 1994
Description
Licensee entered Technical
Specification 3.0.3 to permit
maintenance on the Analog Rod
Position Indication System.
Late performance of quarterly
channel functional test.
Controlled reactor shutdown due to
no. 21 centrifugal charging pump
being inoperable greater than 72
hours.
Manually initiated reactor trip
following unplanned closure of two
For the LERs listed above, the inspectors determined that there were no
violations or deviations, and considered the LERs closed.
6.2
Open Items
The inspector reviewed the following previous inspection items during this
inspection. These items are tabulated below for cross reference purposes.
Number
272& 311/92-17-01 __ ,
272&311/94-01-02
Report Section
5.2.2.A
4.D
7.0
EXIT INTERVIEWS/MEETINGS
7.1
Resident Exit Meeting
Status
Closed
Administratively closed and
re-opened as a violation
(272&311/94-24-04)
The inspectors met with Mr. J. Hagan 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.
17
Based on NRC Region I review and discussions with PSE&G, it was determined
that this report does not contain information subject to 10 CFR 2
restrictions.
7.2
Salem Specialist Entrance and Exit Meetings
Inspection
Reporting
Date(s)
Subject
Report No.
Inspector
9/26-10/7/94
Engineering
50-272 and 311/94-27
Calvert
Inspection
10/17-28/94
MOV Inspection
50-272 and 311/94-26
Prividy
10/17-21/94
Effluents
Inspection
50-272 and 311/94-28
Peluso
10/24-26/94
Emergency
50-272 and 311/94-23
Laughlin
Preparedness
10/24 - 11/3/94
Radcon Inspection 50-272 and 311/94-30
Noggle
7.3
Management Meetings
On October 21, 1994, Charles W. Hehl, Director, Division of Radiation Safety
and Safeguards, NRC, Region I, visited Salem Units I and 2 in preparation for