ML18102A744
| ML18102A744 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 01/08/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18102A742 | List: |
| References | |
| 50-272-96-17, 50-311-96-17, NUDOCS 9701130122 | |
| Download: ML18102A744 (45) | |
See also: IR 05000272/1996017
Text
Docket Nos:
License Nos:
Report No.
Licensee:
Facility:
Location:
Dates:
~
Inspectors:
Approved by:
U. S. NUCLEAR REGULATORY COMMISSION
50-272, 50-311
REGION I
50-272/96-17, 50-311196-17
Public Service Electric and Gas Company
Salem Nuclear Generating Station, Units 1 & 2
P.O. Box 236
Hancocks Bridge, New Jersey 08038 .
November 3, 1996 - December 14, 1996
C. S. Marschall, Senior Resident Inspector
J. G. Schoppy, Resident Inspector
T. H. Fish, Resident Inspector
J. D. Noggle, Senior Radiation Specialist
E. H. Gray, Steam Generator Project Inspector
Larry E. Nicholson, Chief, Projects Branch 3
Division of Reactor Projects
9701130122 970108
ADOCK 05000272
G
EXECUTIVE SUMMARY
Salem Nuclear Generating Station
NRC Inspection Report 50-272/96-17, 50-311 /96-17
This integrated inspection included aspects of licensee operations, engineering,
maintenance, and plant support. The report covers a 6-week period of resident inspection;
in addition, it includes the results of inspections of radiological controls and steam
generator replacement by regional specialists.
Operations
During this inspection period, conservative decisions characterized operator performance.
Several of the decisions demonstrated the operators' high standards for equipment
availability prior to commencing core reload (Section 01 . 1). Operators demonstrated
improved performance in procedure adherence and inifa1ted- appropriate measures -to*
improve procedure quality. Senior reactor operators maintained good control over control
room evolutions and remained aware of equipment and safety system status (Section
03.1 ).
Before the start of refueling the unit 2 core, .inspectors confirmed that Salem
refueling. procedures insured compliance with the design basis and Technical Specification
requirements for fuel handling (Section 01.2). The Salem Senior Nuclear Shift Supervisors
maintained high standards for equipment and staff readiness in preparing for Salem Unit 2
refueling(Section 04.1) The operating shift demonstrated good safety focus in insisting
upon a procedure to control a total station air outage. The plant staff, however, did not
perform a 10 CFR 50.59 safety evaluation until prompted by the inspector. (Section 02.1 ) .
The plant staff made significant progress in addressing station air and control air reliability
concerns. The inspectors noted that plant staff continued to implement actions to improve
station and control air reliability. Although performance problems continued to occur with
the station and control air systems, the inspectors concluded that plant staff completed
adequate corrective actions to support plant startup (Section 02.2)
Maintenance
Inspectors observed improved maintenance performance during the inspection period. For
example, workers demonstrated ownership for their work by identifying additional small
jacket water leaks, a thermocouple that needed to be replaced, and demonstrated the
ability to effectively and safely diagnose and repair the EDG jacket water leak. During no.
23 service water strainer filter replacement, workers displayed familiarity with contents of
the procedures and the work package. They maintained current documentation of the
work and identified three items in the procedure that required clarification. The workers
took steps to obtain the clarification. The inspectors noted close supervision of the SW
work, and a good questioning attitude on the part of the workers (Section M 1. 1) In
response to learning that the Salem preventive maintenance (PM) program did not prevent
inappropriate lubrication of double-shielded bearings in the past, plant staff initiated
changes to the PM program in June 1996 that effectively controlled bearing lubrications
(Section M1 .2). Plant staff appropriately identified use of instruments with insufficient
accuracy during EDG surveillances, appropriately incorporated use of more accurate
ii
i.
instruments, and revised the EDG surveillance procedures to insure use of the new
instruments (Section M 1 .3)
Engineering
As a result of development and use of safety evaluation procedures and training, the safety
evaluations presented to the Station Operations Review Committee (SORC) showed
significant improvement in comparison with the quality of safety evaluations in early 1995.
They supplied comprehensive bases for concluding the changes did not constitute
unreviewed safety questions. In addition, the SORC reviews of safety evaluations also
improved (Section E1 .1 ). The engineering staff had not resolved the effect of operating
the penetration cooling system with air flows different than assumed design basis flows
(Section E1 .2).
The region-based steam generator replacement project (SGRP) Project Manager performed
inspections at the Salem site and the contractor's engineering office *:o cbtain an overview
of current and planned work, related procedures, documentation, quality inputs and
progress of the Salem Unit 1 SGRP. The inspector found generally high quality
performance in the areas inspected and identified no safety significant project deficiencies.
The inspector noted problems, however, with some first time evolutions that indicate a
potential deficiency in planning, work control, or full understanding of procedure
requirements by those performing work. The Salem SGRP management initiated corrective
and preventive actions to improve project performance (Section E1 .3).
The Salem staff implemented appropriate and timely corrective actions in response to
identification of improperly installed welds during implementation of the control room
ventilation modification (Section E1 .4).
Plant Support
The inspector determined that the licensee met and exceeded the planned radiation
protection (RP) staffing levels to support the steam generator replacement project (Section
R1 .2).
The additional remote surveillance capability of the RP command center was effectively
used to review work areas. The inspector observed conservative use of the remote
surveillance approach utilizing on-the-job RP technician resources to engage normal work
control situations. Also, the containment clean areas and radioactive material outside of
containment were effectively monitored and controlled during this inspection (Section
R1 .2).
An effective mockup training for installation of steam generator seal plates was performed.
Important sequencing of work details was established and an understanding of the scope
of work and radiological implications of the work were effectively discussed and
communicated to those present. However, the licensee had not established a requirement
that only those in attendance of the mockup training could perform the work and task
qualification controls had not been established for the seal plate installation work (Section
R1 .3).
iii
Contamination was well controlled and minimized. Through the use of temporary shielding
and filling of steam generators, radiation levels of principal work areas were maintained at
low levels without significant dose rate gradients. The inspector determined that excellent
radiological conditions were established for conducting the steam generator replacement
project (Section R2.1 ).
Although work packages were not all completed at the time of this inspection, general
work descriptions of all radiologically significant work had been researched and individual
RP job guidelines for each had been developed to provide some advance RP planning and
to communicate a level of RP technician job performance expectation. These RP job
guidelines provided a moderately effective vehicle for orienting and guiding the RP
technicians in preparation for radiologically significant project work evolutions (Section
R3.1).
The licensee had not dedicated specific quality assurance (QA) oversight review of the RP
program performance during the SGRP and only routine QA surveillance activities were*
being provided. In response to this finding, the licensee obtained an additional member of
the SGRP QA oversight group tasked with specific responsibility for radiation protection
oversight (Section R7).
The inspector identified overall effective radiological controls for Salem Station radiological
work activities, including preparation and transfer for disposal of the Unit 1 No. 14 steam
generator. Internal exposure controls, including contamination controls, were very good.
Augmentation of the staff was good with good training and qualification of personnel
noted. Self-identification of radiological concerns was very good. However, a noteworthy
weakness was identified in review and resolution of all issues identified in radiological
occurrence reports. Further, improvement in the identification and control of alternate
access paths to locked high radiation areas appeared warranted .
iv
TABLE OF CONTENTS
EXECUTIVE SUMMARY
ii
TABLE OF CONTENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
v
I. Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
II. Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9
Ill. Engineering
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
14
IV. Plant Support .... '. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . .. . . . 24
V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . 38
v
Report Details
Summary of Plant Status
Salem Unit 1 remained defueled throughout the inspection period. Late in the period,
workers removed the last of the four original steam generators from containment. The
plant managers expect to move the first replacement steam generator into containment in
early January 1997.
Salem Unit 2 staff neared completion of refueling preparations at the end of the inspection
period.
01
01.1
I. Operations
Conduct of Operations
General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of
ongoing plant operations. In general, the conduct of operations was professional
and safety-conscious; specific events and noteworthy observations are detailed in
the sections below. The inspectors noted several examples of conservative
decisions by operators. Several of the decisions demonstrated the operators' high
standards for equipment availability prior to commencing core reload.
01.2 Preparations for Unit 2 Refueling
a.
Inspection Scope (60705)
The inspector reviewed procedures and administrative requirements for refueling
Salem, Unit 2.
b.
Observations and Findings
The inspector reviewed Salem refueling procedures to determine whether they met
the design basis of the plant as described in the Updated Final Safety Analysis
Report (UFSAR). For example, the UFSAR states that, prior to refueling, the reactor
is borated to refueling concentration. This requirement is captured in S2.0P-10.ZZ-
0009(Q), Defueled to Mode 6. The UFSAR also describes the capabilities and
safety features of the manipulator crane, such as bridge, trolley and hoist interlocks.
Maintenance procedure SC.MD-ST.CRN-0001 (Q), Fuel Handling Crane Periodic
Inspections, Operational Tests and limit Switch Adjustment, tests these features.
The inspector confirmed the refueling procedures adequately supported the Salem
facility as described in the UFSAR .
2
The inspector also reviewed refueling procedures to determine whether they
identified the Technical Specification requirements for entering Mode 6.
Attachment 2 of Integrated :Operating Procedure (IOP-) 9 lists the surveillance
requirements that demonstrate operability for equipment required by Technical
Specifications, including, for example, the emergency diesel generators, control
room ventilation, and the radiation monitoring system.
The inspector confirmed
refueling procedures insured compliance with the Technical Specification
requirements for entering Mode 6.
c.
Conclusions
Inspectors confirmed that Salem refueling procedures insure compliance with the
design basis and Technical Specification requirements for fuel handling.
02
Operational Status of Facilities and Equipment
02.1
Total Station Air Outage
a.
Inspection Scope (71707)
b.
The inspector observed operators' implementation and restoration of a total station
air outage.
Observations and Findings
On November 1 2, 1 996, Salem operations commenced a total station air (SA)
outage. When tagging instructions for the SA outage expanded to five pages, the
operators insisted that the staff develop a new procedure, TSC.OP-SO.CA-0101,
Maintaining Control Air System During Station Air System Manifold Replacement, to
control the work. The plan involved use of temporary station air compressors to
supply Unit 1 safety-related control air, the station blackout (SBO) air compressor to
supply Unit 2 safety-related control air, taking the safety-related emergency control
air compressors (ECAC) out of automatic control, and bypassing a check valve to
supply non safety-related control air from the safety-related piping. The inspector
found that operations staff did not consider these to be changes to the facility as
described in the safety analysis report. As a result, they did not perform a safety
evaluation as required by 10 CFR 50.59. (VIC 50-272&311196-17-01) In response,
operations management appropriately ensured safe plant configuration and
completed a thorough safety evaluation. The inspector determined that the safety
evaluation appropriately concluded that the changes did not result in an unreviewed
safety question (USQ).
The inspector noted that the procedure unnecessarily limited operators to use of
only two of the three available temporary air compressors. The unnecessary
restriction made operators more vulnerable to station air equipment problems. The
Senior Reactor Operator (SRO) initiated an on-the-spot-change to correct this
3
deficiency. Operators subsequently needed the third temporary air compressor
when one of the other temporary air compressors could not handle the load.
On November 15, the operating shift experienced several problems with station and
control air components that delayed system restoration until November 20. These
problems included: (1) no. 1 ECAC trip on start demand, (2) no. 1 station air
compressor (SAC) would not stay latched in auto, (3) no. 2 SAC would not start,
then experienced excessive amp swings, (4) no. 3 SAC lube oil reservoir heater
controller malfunctioned, and (5) a temporary air compressor could not handle the
load. The system manager initiated corrective action for each of the above
deficiencies.
c.
Conclusions
The operating shift demonstrated a good safety focus in insisting upon a procedure
to control a total station air outage. The plant staff, however, did not perform a 10
CFR 50.59 safety evaluation until questioned by the inspector.
02.2 Reliability of Control Air (NRC Restart Issue 11.2) (Closed)
a.
b.
Inspection Scope (71707)
The reliability of the control air system, the control air dryers, and the service air
system compressors that supply the control air system has been a long standing
concern at Salem. Distractions caused by degraded control air conditions have
frequently challenged operators. The NRC documented control air reliability
concerns in NRC Inspection Reports 50-272, 311/94-19, 94-24, and 94-34.
PSE&G initiated design changes, conducted refurbishment and performed preventive
maintenance activities to address these long standing issues. Plant staff
documented these actions in the Control Air System Reliability closure package,
dated November 6, 1996. The inspector reviewed the closure package as well as
related work documents, design change packages, test results, operating
procedures, calculations, and Performance Improvement Requests (PIRs). In
addition, the inspector conducted field observations to evaluate the material
condition of portions of the service and control air systems.
Observations and Findings
From the review of the closure package, the inspector found that Salem staff
identified the following issues as contributi~g to the control air reliability concerns:
Control Air D~yers - Air header pressure decreases during dryer maintenance,
resulting in auto start of the ECACs and low pressure alarms in the power operated
relief valve (PORV) accumulators.
PORV Accumulators - Low pressure alarm resulted in operators closing the PORV
block valves.
4
Station air compressors (SACs) - Numerous high vibration trips and other problems
resulted in concerns with SACs availability and reliability.
Plant staff completed the following actions:
To address the overall reliability of the control air system, plant staff completed the
air dryer pre-filter PMs on schedule. Delaying this activity in the past compounded
the effects on the control air system because the other pre-filter degraded during
the delay. Subsequent removal of the first pre-filter from service for cleaning
caused increased air flow through the remaining air dryer, resulting in an increased
differential pressure across the air dryer, further degrading the control air header
pressure. Prompt pre-filter maintenance will ensure control air pressure is
maintained within acceptable limits during maintenance. In addition, plant staff
refurbished the dryer skids, inspected and/or replaced the desiccant, rebuilt the
switching valves, and replaced the control solenoid poppits. Maintenance staff
issued a repetitive task PM for the control solenoid poppits to require annual
inspection or rebuild.
The actions taken for the control air dryers will also preclude having to close PORV
block valves as a result of degraded control air header pressure. In addition, plant
staff discovered a problem with the PORV alarm and solenoid setpoints on Unit 2.
They implemented DCP 2EC-3416 to correct this condition.
To address high vibration tripping of the SACs, Salem staff installed a design
change (DCP 1 EE-0324) to eliminate vibration trips as a result of displacement
during compressor startup.
Workers had not completed implementation of SAC design change package DCP
1 EC-3651 at the close of the inspection period. Installation of this DCP will address.
the following SAC issues, to further improve the reliability of the station air system,
and thus the control air system:
Condensate removal problems with the coolers and moisture separators will
be corrected by installation of automatic drain valves. This condition has
resulted in two (2).compressor trips due to high moisture levels in the
moisture separators
Rust in the discharge piping between the compressor and the aftercooler
contributes to pre-filter clogging resulting in increased maintenance on the
control air dryer skids. Plant staff will replace the degraded piping.
The blowoff valves are too far from the compressor. The location has
resulted in compressor surge conditions, reducing compressor overall. Plant
staff will replace and relocate the blowoff valves.
The SACs remain susceptible to vibration trips during load carrying
conditions due to the cyclic loading and unloading of the compressors.
Engineers expect installation of a constant pressure control option to provide
5
compressor stability during operation by significantly reducing the cycles
imposed on the valves, relays, and switches.
During the review of the closure package, the inspector identified questions about
past operation of the containment penetration cooling system. These are
documented in section E1 .2 of this report.
c.
Conclusion
The inspectors concluded that plant staff made significant progress in addressing
station air and control air reliability concerns. The inspectors noted that plant staff
continued to implement actions to further improve station and control air reliability.
For example, plant staff continued installation of DCP 1 EE-0324 to convert the
compressors to constant pressure operation, further reducing station air compressor
trips. Although performance problems continued to occur with the station and
control air systems (see section 02.1 ), the inspectors concluded that plant staff
completed corrective actions and the measures to insure prompt air dryer
maintenance were adequate to support plant startup.
03
Operations Procedures and Documentation
03.1
Procedure Use and Quality
The inspector observed control room operator use and adherence to implementing
procedures. During the inspection period, operators demonstrated consistent
attention to procedure compliance. Operators made a conscientious effort to use
procedures to control activities whenever possible. Operators insisted upon new
procedure development when required to perform complex evolutions that did not
have adequate guidance. An example of this behavior was operations' staff
development of TSC.OP-SO.CA-0101 to control an abnormal station air outage (see
section 02.1 ). In addition, the operating shift, including the test engineers, stopped
control room activities to implement procedure improvements. The inspector noted
that the operating shift repeatedly sacrificed productivity to ensure the procedure
was correct and appropriate. This was evident in "B" vital bus testing as the
operating shift implemented no fewer then seven on-the-spot-changes. The
inspector observed detailed shift briefings prior to complex evolutions and
significant SRO involvement in all control room activities. The inspector concluded
that operators demonstrated improved performance in procedure adherence and
initiated appropriate measures to improve procedure quality. Senior reactor
operators maintained good control over control room evolutions and remained aware
of equipment and safety system status .
04
04.1
a.
b.
07
07.1
6
Operator Knowledge and Performance
Operator Standards for Plant Equipment
Observations and Findings (71707)
During the inspection period, operators demonstrated high standards for equipment
acceptability on a number of occasions. For example, they identified generic
aspects of a failure of the operator for the service water inlet valve to the no. 28
EOG lube oil cooler. They insisted on acceptable resolution prior to entering mode
6. When they learned about a hinge pin corrosion problem in an EOG service water
check valve, they declared the associated EOG inoperable. In a meeting with the
Management Review Committee, the Senior Nuclear Shift Supervisors (SNSSs) from
the fm~r crews slated to restart Salem Unit 2 identified several issues that required
resolution prior to reloading the core. The issues included repair of the no. 28 EOG
jacket water leak, complete review of the Technical Specification Limiting Condition
for Operation (LCO) tracking log by each SNSS, and completion of training for the
design change packages (DCPs) required for mode 6. In order to determine operator
readiness for mode 6, the SNSS for each crew assessed the readiness of each
member of their crew through interviews and observation. In addition, each SNSS
reviewed surveillance results, outstanding operator workarounds, temporary
modifications, and degraded control room indicators for equipment required for
mode 6. In this manner, the SNSS for each crew determined the readiness to begin
refueling operations.
Conclusions
The Salem Senior Nuclear Shift Supervisors maintained high standards for
equipment and staff readiness in preparing for Salem Unit 2 refueling.
Quality Assurance in Operations
(Closed) Violation 50-272&311 /96-12-01: failure to take adequate actions for a
significant condition adverse to quality to preclude repetition. Inadequate
procedures allowed operators to enter Mode 6 without ensuring that they met the
reactivity requirements of TS 3.9.1. Although an operator identified and
documented the failure to meet TS 3.9.1 requirements, the licensee failed to take
adequate corrective actions. In response to the violation, operations staff revised
the integrated operating procedure for Mode. 6 to require proper boron concentration
sampling. Operations staff revised the reactor cavity fill procedure, S2.0P-SO.SF-
0003, and issued the violation response to the Operations and Licensing
Departments as required reading. The inspector verified the S2.0P-SO.SF-0003
procedure revision and the required reading material.
The inspector noted that the response did not discuss the licensee's Quality
Assurance (QA) program practices and procedures. The licensee did not review QA
oversight practices to determine if QA should have identified the violation and what,
08
08.1
7
if any, measure need be taken to strengthen the QA program. The *inspector
observed that an inadequate procedure and inappropriate condition resolution (CR)
corrective actions contributed to the violation. The inspector reviewed the QA
Monthly Reports from December 1995 to August 1996 and noted limited QA
oversight of procedure adequacy and corrective action thoroughness. During
discussions with the inspector, QA managers stated that they had implemented
measures to adjust the QA program based on observed weaknesses in plant staff
and equipment performance. They also stated that they planned to continue to
improve adjustments to QA program focus.
The inspectors concluded that the licensee implemented adequate corrective action
for-entering mode 6 without insuring compliance with TS 3.9.1. The inspectors will
continue to monitor the QA adjustment to performance problems as part of normal
inspector follC1wup of violation responses.
Miscellaneous Operations Issue
(Closed) Violation 27 2&311 /94-24-03
During a Salem Unit 2 shutdown in October 1994, plant staff failed to perform a
daily heat balance calibration of the power range neutron flux functional unit. The
plant staff determined that operators incorrectly interpreted daily as meaning once
per day, as opposed to once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. In response, plant staff revised the shift
routine procedure, SC.OD-DD.ZZ-OD40, to clarify the surveillance frequency and
separate actions required by Technical Specifications from actions required for other
reasons. In addition, the operators received training specific to the missed heat
balance calibration. The inspector verified implementation of the corrective* actions
and considered them adequate to prevent recurrence.
08.2 (Closed) Violation 50-272&311 /94-24-05
In October 1994, a security guard permitted two persons to enter the Salem Unit 2
no. 2C emergency diesel generator (EDG) room without verifying proper
authorization prior to granting access. Security staff attributed the violation to
personnel error. In response, they immediately relieved the guard, retrained and
certified the guard in performance of control access in an emergency or on a
compensatory post, and discussed the incident with guard force personnel during
shift briefings. The inspectors considered the corrective actions adequate to
address the cause of the violation. Inspectors and plant staff identified broader
security performance weaknesses during routine inspection in August 1996. The
NRC documented the broader issues separately and proposed escalated
enforcement. The NRC will assess the effectiveness of corrective actions for those
problems during subsequent inspection .
.*
8
08.3 (Closed) Violation 50-272&311/95-10-01
Jn June 1995, a technician failed to unlatch the no. 2R cylinder fuel pump rack on
the no. 1 C EOG. As a result, plant staff operated the EOG during a surveillance
without fuel supplied to the affected cylinder. The EOG did not suffer damage as a
result. Plant staff concluded that personnel error caused the violation. In response,
maintenance managers counseled the technician, reviewed the applicable
maintenance procedure for adequacy, and revised the procedure to add independent
verification that the fuel racks are unlatched. The inspector reviewed the
procedure, SC.MO-ST.OG-0003(0) to ensure the procedure required independent
verification that technicians unlatched all fuel pump racks.
In May 1995, inspectors discovered that operators had not ensured the no. 2C EOG
fuel rack linkage remair.arl ~n the open position after completion of a surveillance.
Plant staff determined that personnel error was the most probable cause. They also
determined that EOG design features automatically positioned the fuel racks to
supply full fuel on an EOG start. As a result, plant staff concluded the procedure
requirement for operators to reposition the fuel racks was not required for proper
EOG operation. In response, the plant staff deleted the procedure requirements to
manually position the fuel racks .. In addition, operations staff reviewed department
procedures to insure that the procedures included appropriate measures for
independent verification. The inspectors verified that the operations staff deleted
the requirement for manual fuel rack positioning from the applicable procedures and
that the procedures contained appropriate requirements for independent verification.
08.4 (Closed) Violation 50-272&311/95-10-02
In May 1995, the licensee completed a shutdown of Salem Unit 1, and did not
report the shutdown within 30 days as required. The Salem staff determined that
inadequate focus on reporting requirements, lack of follow up by plant staff on a
known commitment, lack of ownership and accountability for the Licensee Event
Report (LER) process, and a flawed submittal strategy contributed to the failure. In
response, the licensee completed and submitted all overdue LERs, counseled plant
staff concerning ownership and accountability, and modified the LER process to
include timely scoping meetings. In addition plant staff initiated a report to identify
the status of LERs in process to insure proper management attention to completing
LERs. The inspector verified the use of the reporting system, including the
Licensing LER Performance Indicators. In addition, the inspector noted discussion of
the status of LERs at the Salem General Manager's staff meeting with appropriate
attention to insuring timely submission of the reports .
.*
9
II. Maintenance
M 1
Conduct of Maintenance
M 1 . 1 General Comments
a.
Inspection Scope (62707)
The inspectors observed all or portions of the following work activities:
WO 961206309, procedure SC.MD-CM.DG-0002(0), Emergency Diesel
Generator Cylinder Head Replacement, Rev. 0, dated 1 /28/91, and procedure
SC.MD-PT.DG-0002(0), Post Maintenance Diesel Engine Break-in Run, Rev.
0, dtd 12/13/96
WO 961202133, procedure SC.MD-PM.SW-0003(0), Service Water
Automatic Strainer Adjustment, Inspection, Repair, and Replacement,
Revision 13 dtd 1 2/5/96
While running the no. 28 EOG for testing, Salem operators observed a slow
decrease in level in the jacket water expansion tank. Maintenance staff determined
that jacket water leaked into the no. 1 R cylinder at about 25 cc/min. They
determined that the cylinder head had developed a small leak, and decided to
replace the cylinder head and liner. Although the EOG had performed within
acceptance criteria in recent tests, and although industry experience indicated that
the EOG would continue to operate reliably for months with the minor leak, they
decided to replace the cylinder head. After removing the head, the maintenance
staff found that jacket water leaking into the cylinder had apparently caused
polishing of the cylinder liner. Although they did not consider the liner significantly
degraded, they replaced the liner also. During the replacement of the EOG cylinder
head, inspectors noted that the workers had the work package on site and in use.
Although maintenance staff concluded that the cylinder head and liner met design
requirements for continued use, they conservatively decided to replace the liner and
head. Workers demonstrated ownership for their work, as demonstrated by
identifying additional small jacket water leaks, a thermocouple that needed to be
replaced, etc. As a result of their efforts, the maintenance staff demonstrated the
ability to effectively and safely diagnose and repair the EOG jacket water leak.
Inspectors also observed technicians replacing the filter elements in the no. 23 SW
strainer. During discussions with the inspector, workers demonstrated familiarity
with contents of the procedure and the work package. The workers maintained
current documentation of the work and identified three items in the procedure that
required clarification. The workers took steps to obtain the clarification. The
inspectors noted close supervision of the work, and a good questioning attitude on
the part of the workers.
.*
b.
10
Inspection Scope (61726)
The inspectors observed all or portions of the following surveillances:
52.0P-ST.FHV-0001:
S2.0P-ST.RM-0001:
S2.0P-ST.SSP-0002:
S2.0P-ST.RHR-0004:
52.0P-ST.SSP-0004:
52.0P-ST.DG-0002:
52.0P-ST.DG-0014:
52.0P-ST.DG-0021:
SC.MD-ST.CRN-0002:
refueling operations - fuel handling building
ventilation
radiation monitors - check sources
engineered safety features manual safety
injection 2A vital bus
in service testing - residual heat removal valves
engineered safety features manual safety
injection 2C vital bus
2B diesel generator surveillance test
2C dieseJ g<;nerator endurance tun
2C diesel generator hot restart test
manipulator crane periodic inspections and
operational tests
The inspectors observed that plant staff did the surveillance safely, effectively
proving operability of the associated system.
M1 .2 Double-shielded Bearing Inspection
a.
Inspection Scope (62707)
The inspector reviewed lubrication preventive maintenance (PM) tasks for selected
safety related motors that contain double-shielded bearings.
b.
Observations
The inspector audited the lubrication PMs for the switchgear penetration area
ventilation (SPAV) fan motors, the boric acid transfer (BAT) pump motors and the
fuel handling ventilation (FHV) fan motors to determine whether technicians were
performing the appropriate PM for the type of motor bearing . The bearing type --
double shielded, single shielded, or open -- determines the PM task. In particular,
the PM program directs technicians not to lubricate double shielded bearings
because this activity could pressurize the grease cavity, causing grease to inject
into the motor. (NRC Information Notice 94-51, Inappropriate Greasing of Double
Shielded Motor Bearings, of July 15, 1994 has additional details.) The inspector
reviewed the PM history for SPAV, FHV, and BAT motors and found that, prior to
improvements in the PM program, technicians inappropriately lubricated the double
shielded bearings in nos. 11 and 12 BAT pumps (September, 1994, and January,
1995). Maintenance engineers inspected these bearings and did not find degraded
conditions. Motor vibration data was also acceptable .
.*
11
In June, 1996, Salem Maintenance staff wrote an Action Request (AR 960618077)
that identified the PM schedule inadequately controlled bearing lubrication tasks.
Subsequently, maintenance engineers identified the types of bearings for motors
installed in both units, including the BAT pump motors, SPAV and FHV fan motors,
and revised the lubrication tasks where applicable to clearly reflect that technicians
are not to lubricate double shielded bearings.
Failure of Salem staff to identify and correct lubrication deficiencies in a timely
fashion is a violation of the requirements in 10 CFR 50 Appendix B, Criterion XVI,
Corrective Action. Since the NRC has taken significant enforcement action for
Salem's failure to identify and correct conditions adverse to quality, and since
PSE&G voluntarily maintained both Salem units shut down to address equipment
and enforcement deficiencies, the NRC will not take additional enforcement action
in this case.
c.
Conclusions
Although the Salem preventive maintenance program did not prevent inappropriate *
lubrication of double-shielded bearings, the inspector found that changes to the PM
program initiated in June 1996 effectively controlled lubrication of bearings.
M1 .3 Emergency Diesel Generator !EDG) Surveillance
a.
Inspection Scope (617261
The inspector reviewed the engineering staff response to an operations department
identified concern regarding the adequacy of using an installed watt meter to
perform EDG surveillance testing (ST).
b.
Observations and Findings
The operators, in accordance with pre-existing surveillance procedures, utilized an
installed watt meter to satisfy several EDG technical specification (TS) surveillance
requirements (SRs) including: monthly load testing (SR 4.8.1.1.2.a.2), semi-annual
load testing (SR 4.8.1.1.2.c), 18 month load testing (SR 4.8.1 .1.2.d.7) and hot
restart testing (SR 4.8.1.1.2.f). The above SRs required the operators to maintain
EDG loading between 2500 and 2600 KW. The installed watt meter, however, had
an accuracy range of approximately +I- 65 KW. As a result, an indication of 2550
KW would indicate actual power somewhere within the range 2485 KW to 2615 *
KW. Operators, therefore, could not certify that the EDG had developed rated load
during the surveillance.
The inspector reviewed the 2C EDG 18 month endurance run test procedure
(S2.0P-ST.DG-0014(0)) and noted that the test procedure had been revised on
November 26, 1996 to incorporate the use of higher accuracy instrumentation. The
operators utilized the revised procedure to perform testing on all three Unit 2 EDGs.
The inspector observed portions of the 28 and 2C EDG testing and noted that the
operators maintained the EDG output within the required band.
.*
12
The operators subsequently revised remaining EOG test procedures to require the
use of the high accuracy load instrumentation in order to satisfy the other SRs listed
above. The operators performed the EOG tests in accordance with the revised
procedures.
During the 2C EOG 18 month endurance testing, the system manager compared the
load indicated by the installed watt meter to the load indicated by the high accuracy
test instrumentation to better quantify the accuracy of the installed watt meter.
The system manager determined, based on this comparison, that the previous 2C
EOG endurance test run had exceeded the required TS range. The inspector
independently reviewed the applicable test data and agreed with this conclusion.
The EOG test load restrictions had been incorporated into TSs by amendments 148 *
and 126 in November 1993. The inspector noted that TS ami:mrlment and the **
applicable EOG test procedures had not been properly reviewed at that time to
insure that the TS load requirements would be satisfied during testing.
Previously performing surveillances with inadequate instruments had minor safety
consequence, since, based on use of the less accurate instruments, the EDGs* had
been loaded during testing to within 2.5% of the required limits. This licensee
identified and corrected issue meets the criteria specified in Section Vll.b of the
NRC Enforcement Manual and is considered a Non-Cited Violation.
c.
Conclusions
Plant staff appropriately identified use of instruments with insufficient accuracy
during EOG surveillances. They appropriately incorporated use of more accurate
instruments, and revised the EOG surveillance procedures to insure use of the new
instruments.
MS
Miscellaneous Maintenance Issues
M8.1 NRC Restart Issue 11.36 - Safety Injection (SI) Relief Valves Performance History of
Leakage and Lifting !Closed - Unit 2. Open - Unit 1)
a. Inspection Scope
The inspector reviewed the corrective actions which were taken to resolve a
problem regarding repetitive Safety Injection system relief valve leakage. The
inspector reviewed the Restart Issue T-36 Closure Package. The package included
the closure summary, the root cause analysis for the probiem, and PIR Nos.
,
950901391 and 960321090. The inspector also reviewed a design change package
for Salem Unit 2 which increased the relief valve set points (DCP 2EC3582), and
procedures which provided direction for setting and testing them. The design
change package for the Salem Unit 1 change was not yet available.
13
b. Observations and Findings
The root cause analysis specified corrective action to reduce the risk of safety relief
valve failures. One corrective action was to increase the relief valve set point. This
was necessary because during safety injection pump startup, the pressure spike
would at times be sufficient to lift the relief valve causing unnecessary wear. The
inspector reviewed the design change engineering analysis and found it adequate.
The change package also contained satisfactory documentation of setting and
installation of the relief valves and documentation of satisfactory test results of the
post installation functional testing. The inspector learned from discussions with the
system engineer that there was no evidence of valve leakage during testing.
The root cause analysis also attributed a faulty test stand filter as a contributing
cause. The filter was not well maintained and as a result, particleTtsand and rust)
would be introduced into relief valves and cause seat wear. The inspector verified
that the filter was being periodically maintained as evidenced by work order
documentation.
Another corrective action was a procedure change to require leak testing before and
after set point verification on the test stand. This would provide evidence of the as
found condition and assurance that the valve was leak tight prior to installation.
Although the long term effectiveness of corrective actions taken has not yet been
determined, the inspector did verify that PIR No. 960321090 contained an action
item to verify the effectiveness by periodically reviewing relief valve lift and leak
test data.
c. Conclusions
From his review, the inspector was able to conclude that it was reasonable to
expect that implementation of the corrective actions would resolve the long term
problem of leaking relief valves. This item is closed for Salem Unit 2 but will remain
open for Unit 1 pending implementation of the design change and subsequent
testing and installation.
M8.2 (Closed) LER 272/96-027-00: This LER described the use of the installed EOG watt
meter to perform EOG testing as discussed in Section M 1 .3 of this report. No new
issues were identified by the LER.
.*
E1
E1 .1
E1 .2
a.
14
Ill. Engineering
Conduct of Engineering
Safety Evaluations*
Observations and Finding
During the inspection period, plant staff prepared several safety evaluations required
by 10 CFR 50.59, and presented them for SORC review. The safety evaluations
included:
DCP 1 EC-3453, package 1 of 3, Unit 1 EDG Fuel Oil Day Tank Setpoint
Change.
Minor modification S-96-023, Removal of 22123 CCW Pump Room Door.
UFSAR change notice 96-169, Change Temperature Range in UFSAR for
SPA V System.
The safety evaluations, prepared using procedure NC.NA-AP.ZZ-0059 (Q), 10 CFR
50.59 Safety Evaluation, included references to Technical Specification and UFSAR
sections reviewed for applicability, and other documents referenced by the
evaluator. The evaluations also listed plant procedures, affected parameters and
systems, and credible failure modes associated with the change.
The inspectors reviewed the safety evaluations and observed their presentation at
SORC. As a result of training and use of procedure NC.NA-AP.ZZ-0059 (Q), the
preparers developed consistently thorough safety evaluations that included broad
consideration of the. effects of the proposed change on plant operation. In addition,
the inspector observed that the SORC obtained a reasonable basis for approving the
safety evaluations through review of the package and questioning the presenters.
Conclusions
The inspector concluded that the safety evaluations supplied reasonably
comprehensive bases for concluding the changes did not constitute unreviewed
safety questions. In addition, the inspector observed that, as a result of the safety
evaluation procedures and training, the quality of safety evaluations and SORC
reviews has increased significantly in comparison with that observed by NRC
inspectors in early 1995.
Containment Penetration Cooler Issues
Inspection Scope (37551)
- The inspector reviewed design calculations, test data, system descriptions, work
orders, UFSAR Section 9.1 (Compressed Air Systems), and Configuration Baseline
15
Documentation (CBD), to assess the material condition of the containment
penetration cooling system.
b.
Observations and Findings
UFSAR Section 3.8.1.6.5, Containment Penetrations and Openings, states in part:
"Cooling, by both free and forced convection, is provided where necessary to
maintain concrete temperatures adjacent to hot pipe penetrations below 1 50
degrees F. The potential heat transfer [for radial conduction] ... can be significant.
The heat is removed by compressed air flow in plate type heat exchangers (coolers)
installed within the penetration sleeves. It has been shown that for constant
exposure of concrete to temperatures up to 150 degrees F, the loss in strenyth is
quite small; and for temperatures as high as 500 to 600 degrees F, the deterioration
in structural properties is tolerable. Considering the redundancy in air supply lines,
the only cause of loss of penetration cooling would be complete loss of the station
air compressors, a condition which would not be permitted to persist long enough
to cause significant localized concrete deterioration."
During an NRC inspection of Salem's licensing basis in May, 1996, the NRC
requested the licensee provide the basis for the minimum penetration cooler throttle
valve positioning to ensure the proper flow of compressed air to the penetration
coolers .
PSE&G located a calculation that provided the basis for the throttle valve positions,
but determined that the calculation was not reproducible and was not officially part
of the CBD. The basis was re-developed in calculation S-C-PC-MDC-1657,
Penetration Cooling Valves Adjustment, Revision 0. The inspector reviewed the
calculation and determined that the minimum throttle valve positions for the
penetration coolers had been determined. The calculation also documented the
actual position of the penetration cooler throttle valves in the field. In all cases the
documented field throttle valve positions were at least the minimum specified in the
calculation.
Based on concerns the inspector had with the number of penetrations equipped with
forced air cooling, the inspector reviewed the following documents to determine
how the penetration cooling air flow rates were accounted for in the station air
consumption calculations.
UFSAR Section 9.3.1, Compressed Air Systems
CBD DE-CB.CA-0014(0), Configuration Baseline Documentation for Control
Air and Station Air Systems, Revision 3;
Calculation S-C-CA-MDC-1639, Integrated Air Load Management Program
Update, Revision 0;
Calculation S-C-SA-MDC-0525, Station Air System Load Study, Revision O;
16
Calculation S-C-CA-MDC-0549, Station Air and Control Air Systems
Analytical Flow Model and Test, Revision O;
System Description SD-M946, Containment Penetration Cooling, Revision O;
and,
Data Acquisition DCP 1 SX-2286, Determination of Air Consumption Rates
and Operating Pressures for CA and SA Systems, Revision 0.
Based on these reviews, the inspector made the following observations:
1.
The Integrated Air Load Management Program Update calculation provided
documentation that a single station air compressors (SAC) capacity was
4232 scfm and the worst case load demand was 4439 scfm. A note
contained in this calculation stated: "The total load of 4439 scfm, exceeds
the capacity of a single SAC (4232 scfm) by 207 scfm or 5%. This is well
within the conservative margin inherent in the development of the individual
loads as discussed in Section 5.1 and 5.2 of Reference 11 [Station Air
System Load Study calculation). Therefore, based on the results of this
evaluation, it is concluded that a single SAC is capable of supporting the
worst case continuous and intermittent loads."
To account for the penetration cooling system contribution to the SAC air
load, PSE&G uses an air consumption value of 636.8 scfm per Unit (1273.6
scfm total) based on the penetration cooling throttle valves being positioned
at their minimum throttle setting. The minimum required throttle valve
positions were listed in the original Containment Penetration Cooling system
description. Further, the inspector determined that the penetration cooling
air consumption value of 636.8 scfm per Unit (1273.6 scfm total) was based
on air flow through a total of 20 penetration coolers per Unit and did not
account for penetrations No. 30, 36, 54, and 55. The documented field
position for the additional throttle valves (eight per Unit) for these
penetrations were "full open". The inspector estimated that the additional air
consumption due to air flow through these open throttle valves would be
300 - 400 scfm per Unit (600 - 800 scfm total), which would exacerbate the
worst case air load consumption values used in the Integrated Air
Management Program calculation. Based on ~his estimate, the total worst
case air load would exceed a single SAC by 1J! - 24% as compared with the
~% stated in the calculation (discussed above). The inspector's estimate
was based on information- contained in the original Penetration Cooling
system descrrption and the Penetration Cooling Needle Valve Adjustment
calculation.
Salem UFSAR, Section 9.3.1, Compressed Air Systems, Paragraph
9.3.1.2.2, states: "The dual station service air headers are fed by three 100
percent capacity air compressors, any one of which can supply the total
service and control air requirements for both units." Based on the
inspector's observation, the accuracy of this UFSAR statement is in
2.
3.
4.
17
question, which may impact the operation and maintenance practices with
regard to the station air compressors.
The Station Air System Load Study calculation was performed on September
18, 1990. Section 5.2.4 of this calculation contained information that
reflected Unit 1 "as found" penetration cooling air flow measurements
significantly below the stated design flow rate (250 scfm versus 636.8
scfm). Engineering's actions documented in response to this condition was a
recommendation that the throttle valve settings be checked, and where
necessary, adjusted to the design position. At the conclusion of the
inspection period, PSE&G personnel were unable to provide a documented
engineering evaluation to show that the reduced flow through the Unit 1
penetration cooling system had not adversely degraded the containment
concrete surrounding these penetrations as a result of the reduced air cooling
flow, and whether operations had found the throttle valves out of position,
thus requiring repositioning or further flow evaluation.
The Station Air System Load Study calculation also contained information
that reflected Unit 2 as found penetration cooling air flow operating at flow
rates in excess of their design capacity. The magnitude of the air
consumption could not be established because the measuring instrument
was damaged by the excess flow. Again, engineering's recommendation
was to check the throttle valve settings, and where necessary, adjusted to
the design position.
Based on discussion with the operations staff, the inspector determined that
the operation of the pressure regulators that supply the penetration cooler air
headers are not contained in operating procedures. Valves associated with
the station air and penetration cooling systems are included in the Tagging
Request Inquiry System (TRIS) which requests the performance of system
valve alignments on a rolling 3 year basis. According to PSE&G, the Unit 2
penetration cooling regulators and the penetration cooling valves had last
been aligned by TRIS lineup in May of 1993. The operations staff does not
require routine monitoring of the penetration air regulator outlet pressure to
ensure they are operating properly, nor are there any routine PM tasks
conducted on the air regulators.
During a search of the corrective action data base the inspector found three
(3) corrective maintenance work orders (WOs) that had been written on
August 8, 1996 to correct problems .with the penetration cooler air regulating
valves for Units 1 & 2. Specifically, the normal and backup air regulator for
Unit 1 and the backup air regulator for Unit 2 were found to be maintaining
1.§ psig to the penetration coolers instead of the required 75 psig. The 75
psig setting requirement was included as part of the assumptions in the air
load calculations to ensure the proper amount of air flow to the penetration
coolers. After the inspector questioned the commonality of the three (3)
WOs, PSE&G personnel initiated a Condition Report to document the failures.
At the close of the inspection period, the WOs were still open. After
18
questioning by the inspector, the Unit 2 WO was changed from "post restart
required" to "restart required".
The inspector noted, that while the Action Request Process did not
specifically require the improper regulator settings to be identified as a
condition report, the fact that all three regulators were identified in the same
condition on the same day should have been questioned and result in the
issuance of a condition report. This missed opportunity to identify a
Condition Report issue represents a continued weakness in the corrective
action process.
c.
Conclusions
Based on the above observations, the inspector concluded that there are unresolved
questions associated with the penetration cooling system, including:
1.
The affects of the additional air consumption on the UFSAR and the CBD,
including the Integrated Air Load Management and the Station Air Load
calculations.
2.
The affects the additional air consumption has on plant operations and
maintenance activities.
3.
The adequacy of the operational configuration control of the penetration
cooling system, including throttle valve positions, air regulator status, and
system air flows.
4.
- The material condition of the containment concrete surrounding the affected
penetration due to potential long term overheating as a result of measured air
flows lower than design (250 scfm versus 636.8 scfm) and/or pressure
regulators maintaining pressure less than design (15 psig vetsus 75 psig).
This inspectors will review resolution of this issue in the next inspection period. (IFI
50-272&311/96-17-02)
E1 .3
Steam Generator Replacement Project CSGRP)
a.
Scope (37001, 50001)
Inspections were performed by the Region-based SGRP Project Manager to obtain
an overview of current and planned work, related procedures, documentation,
quality inputs and progress of the Salem Unit 1 steam generator replacement project
(SGRP). The site inspection included observations of work in progress at the
replacement steam generator (RSG) staging area, welding preparations, lifting and
rigging oversight; work packages and procedures; identified problems and corrective
actions; independent review of the site SG haul path; discussions with the
responsible engineers and observation of conditions and activities inside the
containment building.
19
An offsite inspection was conducted of SGRP engineering a.t the Framatome office
in Lynchburg to review the engineering task scopes, calculation methods, results
and documentation to confirm that acceptable engineering practices were applied in
development of information for safety evaluations required by the 1 OCFR 50.59
process.
b.
Findings
By December 14, 1996, one original steam generator (OSG) had been shipped
offsite by barge, two were in the preparation area for shipping and the fourth was
outside the containment building prior to movement to the shipment preparation
area. A significant portion of the pre-installation work on the RSGs was complete.
The movement of the OSGs by Chem Nuclear and Bigge transporters on the
designated haul paths was done per the planning without incident. Preparation for
the shipment of the first OSG was observed to be well planned and executed.
Work in the RSG staging area and preparations for lifting in the containment building
were observed to be generally proceeding in an orderly manner with appropriate
supervision and work control packages.
However, *the licensee has identified several problems during the progress of the
SGRP and has initiated root cause analysis, developed corrective actions and
selectively stopped work. The more significant problems were not nuclear safety-
related, but included a failure to field verify the orientation of the OSG support feet
which delayed the down ending of the first OSG, welding of T1 steel with a vertical
up technique not shown in the welding procedure, limiting only craft workers to
signing the Work Package logs of one contractor and not fully following the
procedure (WCP-2) in storing coated weld electrode in a rod heating oven. The root
cause analysis determined that problems were mostly associated with first time
activities. Corrective and preventive actions emphasized additional independent
review of first time sequences, increased PSE&G specialty oversight, and improved
pre-job briefings.
Engineering
A major portion of the engineering evaluations to determine the effect of differences
between the OSGs (Model 51) and RSGs (Model Fl on Unit 1 plant performance are
being performed by the project contractor, Framatome (FTI), with parts of the work
being done by Westinghouse and PSE&G. Inspection of a sample of SGRP
engineering work recently completed at FTI was initiated to confirm that reasonable
inputs were being developed for the safety evaluations required under the 50.59
process.
The inspector reviewed the FTI method and extent of engineering for the SGRP in
the 50.59 area. The engineering and related licensing scope are discussed in the
SGRP Work Scope Description dated August 15, 1996, and the SGRP Conduct of
Operation Plan, PSBP 322391, dated September 13, 1996. Included in the
engineering work scope is a review of the FSAR Chapter 1 5 Safety Analysis and
other Safety Analysis where the steam generators are involved; SG performance
b.
20
calculations; deadweight, thermal, seismic and high energy line break loads and
structural stress analysis; review and update of the affected parts of the FSAR,
Technical specifications and SER's; and operator training support.
The engineering process includes a Salem Unit 1 set of Analysis Input Data, an
Analytical Input Summary for each engineering task, the specific calculation
packages and guidelines for preparation and processing of calculations. The
inspector reviewed these and portions of the calculations on Low Temperature Over
Pressure Protection, SG performance and SG structural supports.
Engineering evaluations and design changes associated with steam generator (SG)
replacement reviewed during this inspection were found to be done in conformance
with requirements in the facility license, the applicable codes and standards,
licen-~ir;g commitments, and the regulations. Some minor issues were identified.
These included a lack of clarity on identification of some data curves in calculation
51-1258559-00 for design transients and the Analysis Inputs Data not having been
compared against the findings of the PSE&G FSAR project applicable to steam
generators. The licensee acknowledged both issues and proposed to review these
for appropriate action.
Conclusions
Inspections were performed at the Salem site and at the contractor's engineering
office by the Region-based SGRP Project Man~ger to obtain an overview of current
and planned work, related procedures, documentation, quality inputs and progress
of the Salem Unit 1 steam generator replacement project (SGRP). The inspections
found a generally high level of project performance in the areas inspected and
identified no safety significant project deficiencies. However, problems were noted
with some first time evolutions at the site that indicate a potential deficiency in
planning, work control or full understanding of procedural requirements by those
performing work. The Salem SGRP management initiated corrective and preventive
actions to improve project performance.
In the area of engineering activity that provides input to the required 1 OCFR 50.59 *
safety evaluations within the FTI work scope, the calculation process was found to
be well organized, significant factors were considered and no items of regulatory
concern were identified.
E1 .4
Modifications to Control Room Ventilation
As a result of a concern about the implementation of the control room ventilation
modification, the Salem staff inspected 1 00 percent of the welds completed during
installation of modification 1 EC-3505. The staff identified a number of welds that
workers had not installed in accordance with the final modification drawings. In
addition, they found that workers had used uncontrolled drawings to install portions
of the modification. Salem managers took disciplinary action with the contractor,
and resolved the incorrect welds through analysis and removing and replacing
welds. In addition, the Salem staff inspected a sample of welds for other ventilation
21
system modifications completed during the outage, and found no additional
examples of incorrectly completed welds. The inspectors concluded that the Salem
staff responded appropriately to the concern.
E2
Engineering Support of Facilities and Equipment
E2.1
(Closed) Inspector Follow-up Item 50-311194-24-02: Auxiliary Feedwater Pump
Trip Evaluation
This issue pertains to two trips of the turbine driven auxiliary feedwater pump. The
operators determined that in each case, the trip latch was not properly engaged and
vibration on pump startup caused the trip valve to operate. The inspector
conducted .:a r.eyiew of the licensee's actions to address this issue. The inspector
found that Salem staff made changes to procedure S1 /S2.0P-SO.AF-0001 (0),
Auxiliary Feedwater System Operation, to provide clear instructions to set and
verify proper trip latch engagement. The inspector also verified by a review of
corrective action data base that there have been no recurrences of this failure mode.
This item is closed.
E2.2
NRC Restart Issue 11.42 - Auxiliary Feedwater (AFW) Performance and Reliability
(Update)
a. Inspection Scope
The inspector reviewed the closure package for this issue as well as related work
documents, design change packages, surveillance test results and the AFW
operating procedure. The inspector held discussions with system engineering
personnel and inquired about recent AFW performance and state of readiness .. The
inspector also reviewed the system readiness exception list and performed a field
walkdown of the AFW pump rooms.
- b. Observations and Findings
From the review of the closure package, the inspector found that Salem staff
attributed most of the problems regarding AFW reliability to turbine driven pumps;
specifically, they were attributed to the turbine governor. The following factors
were identified as having caused failures of the turbine driven pumps:
Poor control of oil quality
Incorrect oil use
Governor valve stem corrosion
Governor internal *configuration incorrect
...
/
~
The inspector verified that corrective action had been taken to resolve each of those
problems. Salem has implemented a control oil sample program to ensure
satisfactory oil quality.
A minor modification has been made at the governor cooler
to ease governor removal and reduce the risk of water being introduced into the
22
governor during the removal process. A recurring maintenance task has been
initiated to periodically inspect the governor valve stem for' corrosion. Measures
have also been taken to control the governor control oil inventory and Salem
management has formally delegated responsibility to maintenance for administration
of the oil control program.
Salem staff attributed the governor internal configuration problem to parts being
installed which were not identical to those being replaced. The vendor had made
these replacements without PSE&G knowledge. (The issue of configuration control,
in general, is being addressed under NRC Restart Issue 111.2, Configuration Control.)
The corrective action for the turbine governor problem included sending the units
back to the vendor to have them inspected and, if required, rebuilt to assure their
configuration was in accordance with the Salem design specification. The inspector
verified by field inspectiQn and document review that the units had been returned to
the Salem site and, for Unit 2, had been reinstalled.
The inspector obtained a copy of the "AFW System Unit 2, System Readiness
Review Final Affirmation," dated November 13, 1996. This document had been
approved by the system manager and identified approximately 60 incomplete items
most of which were tests to demonstrate acceptability of components which had
been repaired or modified. Examples include a manual trip of the turbine driven
pump to demonstrate operation of the trip and throttle valve, flow instrumentation
operational check, valve indication verification, check valve operational check, and
an evaluation of potential over pressurization damage to the actuator of valve
2MS132 (Isolation valve for steam to the turbine). The inspector determined that all
of the system readiness items were a restraint to entering Mode 3 or Mode 4.
c. Conclusions
The inspector concluded from his inspection that the actions taken by the licensee
to improve AFW performance and reliability should be effective. However, because
of the large number of outstanding items which remain to be tested, this Restart
Item will remain open until satisfactory AFW performance has been demonstrated.
E2.3
(Closed) LER 50-272/96-015: inadequate Containment Fan Coil Unit (CFCU) heat
removal capability due to bio-fouling. During the first quarter of 1993, the
individual CFCUs had been tested and noted to be performing at less than the
acceptance criteria. However, the combined effect of poor performance of three
units was not addressed. The total heat removal capability requirement is 250.8
million BTU/hr. In July 1996, an engineering review determined that the actual
capability during the first quarter of 1993 was 201.2 million BTU/hr for Salem Unit
1 and 209.6 million BTU/hr for Unit 2. The LER documented that there was no
safety consequences because under worst case accident scenarios, the containment
spray pump would be available to provide sufficient additional heat removal
capability .
E2.4
23
PSE&G has determined that one cause of the CFCU performance degradation was
bio-fouling as a result of the service water chlorination system being inoperable
between June 1991 to at least June 1993. PSE&G has also determined that lack of
organizational and management sensitivity to the maintenance and operation of the
chlorination system was also a cause of this event. Additionally, the absence of
controlled and accurate test acceptance criteria in the test procedure was a cause.
The inspector reviewed the corrective action identified for this event. The
corrective action includes implementation of a CFCU monitoring plan, procedure
revisions to emphasize the importance of maintaining the service water chlorination
system, and procedure revisions to ensure the chlorination system is in service prior
to placing the Service Water System in service. In addition, training was developed
to stress the importance of maintaining the service water chlorination system in
service. The inspector confirm.ad that the procedure revisions are complete, training
has been conducted, and the CFCU performance monitoring program is being
developed with an expected completion scheduled for December 1996.
The inadequate procedures constitute a violation of 10 CFR 50, Appendix B,
Criterion V, "Instructions, Procedures, and Drawings." The inadequate test
procedure constitutes a violation of 10 CFR 50, Appendix B, Criterion XI, "Test
Control". The failure to adequately maintain the service water chlorination system
constitutes a violation of 10 CFR 50, Appendix B, Criterion XVI, "Corrective
Action." In light of the fact that these problems are licensee-identified and
corrected and in recognition of the ongoing PSE&G efforts to address the generic
issues of management effectiveness, procedural shortcomings, and maintenance
problems as part of the Salem Unit 1 & 2 restart effort, these violations are being
treated as Non-Cited Violations, consistent with Section Vll.B.I of the NRC
(Closed) LER 50-272/96-012: potential loss of residual heat removal capability due
to inadequate valve design. The maintenance history for the residual heat removal
(RHR) flow control valves provided evidence that there have been seven
key/keyway failures since 1993. PSE&G engineering determined that the original
design provided little or no design margin. For reasons not known at the present
time, the original Westinghouse specification and data sheet did not specify any
flows or pressure drop across these valves.
PSE&G determined that these RHR valves wouJd need to be replaced prior to
entering Mode 6 for Salem Units 1 & 2. Also, a review was made to determine if
any other valves of the type installed at Salem had similar problems. That review
lead to the conclusion that adequate margin existed for other valves in use at Salem
and there was no record of the key/keyway failure mode for these valves.
The inspector verified that the Salem Unit 2 RHR flow control valves have been
replaced and a design change package is being prepared to replace those in Unit 1 .
The inadequate design is considered a violation of 10 CFR 50, Appendix B, "Design
Control." This violation is considered a Non-Cited Violation, consistent with Section
Vll.B.1 of the NRC Enforcement Policy.
- - -
-
24
IV. Plant Support
R1
Radiological Protection and Chemistry (RP&C) Controls
R1 .1
Exposure Goal/Status
The licensee's annual exposure goal for 1996 was 208. 745 person-rem and was
based, in part, on the restart of both Units 1 and 2. The goal however, did not
anticipate the Unit 1 steam generator replacement project. Not including the steam
generator replacement project, total Salem exposures for 1 996 through
December 12, 1996 was 202.408 person-rem. The steam generator replacement
project was originally estimated at 166. 733 person-rem with a project goal set at
158.253 person-rem. The SGRP estimata was revised on November 11, 1996, to
add an additional 31.529 person-rem resulting in a new project estimate of 198.262
person-rem. The reasons for the additional exposure included: additional detailed
planning was completed for the new steam generator structural support
modifications indicating significantly more work was required; the steam generator
downending ring required significant repair due to insufficient field verification prior
to fabrication; and overall project schedule delays have extended the SGRP an
additional 6 weeks. As of December 12, 1996, the SGRP had accrued 110.595
person-rem versus an estimated 178.444 person-rem to date. Total Salem Station
personnel exposures for 1996 through December 12, 1996 was 313 person-rem .
R1 .2
Radiological Work Controls
a. Inspection Scope
During inspection from 10/28 until 11 /4 of the Salem Unit 1 SGRP outage, the
inspector observed work control practices, interviewed workers and RP staff, and
reviewed licensee procedures. The inspector observed licensee postings, use of
contamination controls, and locked high radiation areas.
b. Observations and Findings
During the inspection period, all areas reviewed were properly posted,
contamination areas were controlled, and locked high radiation areas were found to
be locked as required.
Appropriate RP/worker interfaces were established during entry through the
temporary access facility (T AF) and upon entry to containment; and at the refueling
floor satellite RP control point and upon entry into the bioshield wall in the
basement of containment. The T AF provided dress out facilities, RWP sign-in,
cellular phone issue, and dosimetry issue. Once inside containment, cellular .phone
contact was made by each work party with the RP remote command center located
in the TAF. The TAF RP command center consisted of three remote monitoring
stations; one for the refueling floor, and one for each pair of steam generator
platforms. The RP monitoring stations consisted of remote video monitors of their
25
respective areas. During the inspection, approximately 9 different camera views
were simultaneously displayed at each RP monitoring station. The RP command
center RP technicians controlled the remote camera pan, tilt, and zoom functions
and could call the work parties and associated RP technicians in the areas of their
responsibility to provide additional RP oversight, and potential remote constant RP
coverage capability. During the inspection, no remote constant coverage use of the
RP command center was observed.
The licensee had identified four project tasks that would require continuous RP
coverage: pipe end decontamination, seal plate installation, pipe severance and
steam generator removal. The inspector questioned the positive control aspect of
the remote setup when audio communications relies on recognition of the worker
and dialing the applicable cellular phone number to establish contact to provide
direction to the workers. The inspector quest~~-':'ie,d the RP technicians ability.to
recognize the workers in containment (especially due to the uniform protective
clothing dress). The licensee resolved this concern by requiring each individual
carrying a cellular phone into containment to label the last two digits of the phone
number on their hard hat cover. This provided the visual reference needed during
remote surveillance to establish audio communications when necessary.
The inspector observed effective setup and controls associated with the clean area
side operations. The refueling floor inside containment consisted of a partial clean
area that extended out through the equipment hatch. The inspector noted that
appropriate contamination monitoring equipment and dedicated RP technician
resources were devoted to these clean areas to ensure personnel and radioactive
material control were maintained .. The clean areas mentioned and the "yard" areas
outside were effectively monitored and controlled during this inspection.
c. Conclusions
The inspector determined that the majority of the project work activities would be
conducted without the need to establish high radiation areas and associated
requirements. Sufficient RP technician resources were provided inside containment
to provide the surveying and radioactive material control aspects of the project.
The additional remote surveillance capability of the RP command center provided
another level of review of the work areas and was being considered for possible
applications involving remote surveillance of high exposure jobs. Also, the
containment clean areas and control of radioactive material outside of containment
were effectively monitored and controlled during this inspection. No discrepancies
or violations of any radiological work control requirements were identified.
R1 .3
Mockup Training
a. Inspection Scope
During inspection from 10/28 until 11 /4 the inspector observed mockup training for
installation of steam generator RCS seal plates and for RCS pipe end
26
decontamination. The inspector also interviewed applicable licensee personnel and
reviewed RP job guideline documentation.
b. Observations and Findings
Prior to removing the old steam generators, after severing the reactor coolant
piping, a steel plate is welded to the steam generator end of the reactor coolant
piping to provide a contamination boundary. Prior to performing this work
evolution, mockup training was performed. The mockup training involved 3-4
ALARA personnel, 3-4 pipefitters and 2 construction supervisors. The mockup
training session involved a good test of the planned work technique. The mockup
facility was full-scale as were the seal plate and welding *equipment. No protective
clothing or steam generator platforms were modeled and no communications
equipment were utilized as the actual work performance env.ironn:tent would entail.
Attendance was taken of the training participants for archival purposes only. The
inspector observed that no quality assurance personnel attended the seal plate
installation mockup training. Several days later, the RCS pipe end decontamination
mockup training was also performed. This training was conducted inside a
contaminated area inside the fuel handling building with appropriate RP, FTI,
ALARA, pipefitter, and quality assurance personnel in attendance.
c. Conclusions
An effective mockup training for installation of steam generator seal plates was
performed. Important sequencing of work details was established and an
understanding of the scope of work and radiological implications of the work were
effectively discussed and communicated to those present. The inspector noted that
important details of the work method that incorporated the radiological work
hazards were established during the mockup training.
Although the mockup
training was performed in street clothes and was unencumbered by protective
clothing, platform restrictions, and communication system usage, the inspector
determined that the most important aspects of the training were met. However, the
licensee had not established a requirement that only those in attendance of the
mockup training could perform the work. Task qualification controls had not been
established for the seal plate installation work. The lack of quality assurance
personnel in attendance was noted.
The licensee responded to this NRC identified weakness by delineating that the
responsibility for worker qualifications was with the work contractor (principally
Raytheon Nuclear Incorporated (RNI), and FTI). In response to this concern, RNI
included a worker qualification matrix into applicable work packages with a work
package step requiring review of personnel qualifications prior to commencement of
the mockup specific work. FTI had previously included their personnel* qualification
records in the applicable task deployment letter (work package) for review.
Approximately 12 local pipefitters' qualifications were not originally included in the
documentation packages. Late in the inspection, RNI and FTI mockup qualification
27
documentation records were completed and reviewed and verified by the inspector.
Later performance of pipe end decontamination mockup training incorporated these
enhancements.
R 1 .4 Pipe End Decontamination Controls
a. Scope (83750)
During inspection from 12/9 until 12/13, the inspector observed the setup,
implementation, and RP coverage controls associated with sponge-media blast
decontamination of RCS pipe ends of steam generator No. 12.
b. Observations and Findings
The inspector observed effective contamination controls and confirmation of
negative ventilation of the operating equipment before beginning the
decontamination work. The decontamination equipment was remotely operated
from a low dose rate area of containment by reference to closed circuit television
cameras inside the RCS pipe. Excellent air sampling was provided at several
locations on the steam generator platform and two CAMs were provided to allow
for the rapid detection of airborne radioactivity.
The inspector noted that the effectiveness of the pipe end decontamination dose
rates was monitored outside of the RCA in the temporary access facility RP
Command Center. A remote readout of dose rates was provided to the RP
technician providing oversight of the area. In order to understand decontamination
goals and hold points, the inspector asked the RP technician and an ALARA
radiological engineer where the dose rate detector was located and how the dose
rate information was used to determine when the decontamination operation was
completed. The inspector noted that such information was important in
understanding when decontamination was complete to the maximum extent
possible to avoid unnecessary personnel exposure. Both individuals did not know
where the dose rate detector was located and indicated that the vendor would
determine when the decontamination was completed. The inspector noted that the
dose rate detector configuration was accurately described in the applicable RP Job
Guideline that was available to the staff in the RP Command Center. In response to
this concern, the licensee implemented a read and sign order to ensure the
applicable RP technicians were knowledgeable of the decontamination monitoring
configuration. The inspector noted that the pipe end decon RP job guideline
provided only marginal guidance* on acceptance criterion for the decontamination
and also noted that the RP Job Guidelines were not station-approved procedures
and did not appear appropriate for control of work. The licensee responded by
modifying the pipe end decon work package to include an RP hold point before
completion of the decontamination work evolution .
28
c. Conclusions
RP surveying and monitoring of the pipe end decontamination operation were
effective and exposures were minimized. However, the control of decontamination
to maximize effectiveness was not well established. The licensee added an
appropriate RP holdpoint to the pipe end decontamination work package in response
to this concern.
R1 .5 * Internal Exposure Assessments
a. Scope (83750)
During inspection from 12/9 until 12/13, the inspector reviewed the investigational
whole body counts for 1996 and reviewed and verified calculations of internal
exposures recorded for 1996.
b. Observations and Findings
The inspector's review indicated that approximately 50 whole body counts (WBCs)
were performed during 1996 for investigational purposes as possible internal
exposures. Of these, 41 WBCs were determined to be below procedural action
levels. Several others represented low level contaminations that fell below
procedural action levels after a day later recount. Only two individuals indicated
detectable internal contamination. Both individuals were associated with steam
generator eddy current inspection work at Salem in June 1 996. One individual was
assessed a CEDE of 7 mrem as a result of the internal contamination. The 7 mrem
was below the 10 mrem level of recording. The other individual was assessed an
internal exposure of 32 mrem CEDE which was assigned to his personnel exposure
record.
The inspector reviewed the applicable bioassay measurement data and
independently performed an internal exposure assessment for the latter individual.
The inspector calculated 29 mrem CEDE, which agreed well with the licensee's
result.
c. Conclusions
There were few internal exposure incidents identified at the Salem and Hope Creek
Stations in 1996. One internal exposure of 32 mrem CEDE was recorded. This is
indicative of very good contamination controls at both Stations .
29
R2
Status of RP&C Facilities and Equipment
- R2.1 *Unit 1 Radiological Conditions
a. Inspection Scope
During inspection from 10/28 until 11 /4 the inspector toured the principal
radiological work areas of Salem Unit 1 during the steam generator replacement
project. Independent survey measurements were made, licensee surveys and log
book documentation were reviewed in order to assess the radiological hazards
presented to the workforce.
b. Observations and Findings
The Unit 1 containment radiological conditions were determined as follows.
Refueling floor: general area dose rates were < 1 mR/hr in most areas with areas
over the reactor head on the cavity deck grating of 1-6 mR/hr. Inside the upper
biological shields surrounding each steam generator were dose rates from
1-20 mR/hr. The refueling floor contamination levels were maintained to
approximately 1,000 dpm/100 cm 2 (the station clean area limit). Log entries
indicated that some structural steel was contaminated from 6,000-20,000 dpm/100
cm2* The steel was wiped down controlled to maintain area contamination levels to
approximately 1,000 dpm/100 cm 2*
Basement floor, inside the bioshield area (with steam generators full): general area
dose rates of 1-15 mR/hr were found, with steam generator platform dose rates of
5-15 mR/hr and reactor coolant pump catwalk dose rates of 5-15 mR/hr. The
reactor coolant piping averaged 30 mR/hr contact. Contamination levels in the
lower levels of containment were maintained between 1,000 to 2,000 dpm/100
cm
2
, although log entries documented occasional occurrences of contamination
excursions up to 350,000 dprn/100 cm 2* These were promptly decontaminated and
maintained at the low contamination levels, previously stated. *
Although, the containment was posted as a high radiation area, the principal work
areas were less than 1 5 mR/hr and contamination levels were maintained at very
low levels.
Shielding
The licensee provided approximately 70,000 pounds of temporary lead shielding to
provide the excellent dose rate environment previously mentioned. *Areas that were
shielded included: reactor head, pressurizer surge line, regenerative heat exchanger,
pressurizer spray line, safety injection lines, residual heat removal piping,
intermediate RCS loops, steam generator platforms, reactor coolant pump platforms,
and pressurizer relief tank .
30
c. Conclusions
Contamination was maintained at near clean levels, and through the use of
temporary shielding and filling of steam generators, radiation levels of principal work
areas were maintained at low levels without significant dose rate gradients. The
inspector determined that excellent radiological conditions were established for
conducting the steam generator replacement project.
R2.2
Unit 2 Radiological Conditions
a. Scope (83750)
The inspector toured the principal radiological work areas of Salem Units 1 and 2
during extended outage conditions. Independent survey measurements were made
and licensee surveys were reviewed.
b. Observations and Findings
During inspection tours of the Unit 2 containment from 12/9 until 12/13, the
inspector noted a variety of protective clothing dress by workers in the same areas.
The variations ranged from only shoe covers and gloves; to lab coats, shoe covers
and gloves; to full protective clothing dress. The licensee indicated that during the
extended outage period, both containments had been decontaminated in many areas
to below the clean area contamination limit. Survey documentation of floor areas
confirmed the low contamination levels. Survey documentation of the walls and
low hanging interferences in these areas were not well documented, although the
licensee believed these surfaces were also decontaminated and represented a low
risk to the workers. The inspector performed gross masslin wipedowns of the
easily accessible wall surfaces and low hanging overhead surfaces to evaluate the
contamination hazards. None of the inspectors' gross contamination samples
indicated any detectable contamination, confirming the licensee's understanding
that resulted in the reduced protective clothing dress practices in containment.
During a tour of the Unit 2 Auxiliary Building, the inspector noticed a posted locked
high radiation area at the entrance to the No. 21 waste holdup tank (WHT) room.
Entry to the room is obtained by climbing a 6-foot vertical ladder over a weir wall
and then down another ladder into the room. Access_ was prevented by a ladder
lock which covered the rungs of the ladder and successfully prevented access by
way of the ladder. The inspector noted an adjoining mezzanine platform at the
same level as the top of the weir wall that could allow a worker to circumvent the
ladder lock and gain access to the room from the mezzanine. A current survey of
the room indicated a maximum dose rate of 700 mR/hr at 30 centimeters, which did
not meet the Technical Specification requirement for locking to prevent
unauthorized access. In addition, there was no indication that any unauthorized
entries had been made into the room. The licensee immediately locked a gate
preventing access to this area and was evaluating a means to prevent access to the
No. 21 WHT room from the adjoining mezzanine. No violations were identified in
this area.
- '
31
c. Conclusions
R3
R3.1
a.
b.
c.
The inspector concluded that radiological controlled areas at the Salem Station were
properly posted. Further, locked high radiation areas were properly controlled.
However, a possible access path to the No. 21 WHT room was identified. The
licensee maintained contamination within the reactor containment to low levels.
This was a very good initiative.
RP&C Procedures and Documentation
RP Job Guidelines
Inspection Scope
During inspection from 10/28 until 11 /4 the inspector found that the licensee was
conducting the SGRP with very limited advance planning. The work package review
process was continuing during this inspection for work yet to be performed. It was
during this review that the ALARA and RP control requirements are specified in the
work package. In order to facilitate timely communication of expected RP job
performance during radiologically significant work evolutions, RP Job Guidelines
were often written for RP staff use before the work package was completed. The
inspector reviewed these documents to determine if adequate RP precautions and
considerations had been planned.
Observations and Findings
The RP job guidelines reviewed provided a good description of each job. The
guidelines included some RP setup requirements and specified some RP
requirements for surveying, monitoring, and air sampling. The RP job guidelines
provided clear definition of work steps that predicate changes of radiological
conditions. The inspector noted that there was no discussion of dosimetry
placement when working inside or in close proximity of open reactor coolant piping.
Also, no radiological contingency planning was built into the RP job guidelines.
Instead, there were occasional work control restrictions that caused work be
stopped for evaluation of conditions and controls.
During tours of the plant, the inspector noted that the RP job guidelines were only
available in the RP command center. RP technicians in the field were not provided
with this information. Later during the inspection, the licensee distributed the RP
job guidelines to all containment satellite RP *stations.
Conclusions
Although work packages were not all completed and detailed work requirements
were therefore not available for RP planning purposes, general work descriptions of
all radiologically significant work had been researched and individual RP job
guidelines for each had been developed to provide some advance RP planning and
32
to communicate a level of RP technician job performance expectation. These RP job
guidelines provided a moderately effective vehicle for orienting and guiding the RP
technicians in preparation for radiologically significant project work evolutions.
R3.2
Transportation Shipment of Old Steam Generator
a. Scope (86750)
On December 6, 1996, the inspector reviewed the licensee's shipping records and
preparations for shipment of the first Unit 1 steam generator to be shipped to the
Barnwell Low Level Radioactive Waste Disposal Facility. The shipment review was
made with respect to DOT regulations including specific DOT Exemption No. 11745
requirements.
b. Observations and Findings
In preparation for shipment, the licensee decontaminated Steam Generator No. 14
to below Station release limits. All exterior penetrations were sealed and the. RCS
pipe nozzles, in addition to being seal welded, had three-inch thick shield covers
welded in place. The generator was also painted. The lifting trunions were
defeated by welded gussets at each 90-degree location. The steam generator was
secured to a special flatbed trailer transporter that included steel plate shielding
around three sides covering approximately the lower 2/3 of the steam generator.
The inspector observed the licensee performing final survey measurements of the
shielded transport vehicle and the inspector performed independent dose rate
measurements. All contamination and dose rate measurements were within
regulatory requirements. The shipment was properly marked with the specific DOT
exemption number of the shipment as well as the shipping classification,
Radioactive-Surface Contaminated Object, and other required markings.
The inspector reviewed the shipping manifest (No.96-218) and noted that the
licensee accounted for the internal solid metal oxides residues and accounted for
any liquid remaining in the plugged steam generator tubes. All required information
was included and no discrepancies with regulatory requirements were identified.
c. Conclusions
The licensee properly prepared the No. 14 steam generator for shipment. Shipping
records were complete and met all regulatory requirements.
RS
Staff Training and Qualification in RP&C
a. Scope (83750)
During inspection from 12/9 until 12/13, the inspector reviewed applicable
procedures and lessons plans associated with contractor RP technician training and
qualification. The inspector also conducted interviews with the training staff.
.;
l
R6
33
b. Observations and Findings
The inspector determined that contractor senior RP technician candidates were
required to pass a generic RP technician screening examination within the past 3
years followed by station specific procedure training and testing. The contractor RP
technicians were also subjected to a practical evaluation performed by permanent
RP staff to complete the qualification process. The inspector reviewed the lesson
plan materials for the station specific procedure training and determined that they
were of good quality. The inspector also reviewed the station specific procedure
examination and noted that it had been upgraded since previously inspected.
c. Conclusions
The licensee maintained a good training and qualification program for contractor RP
technicians. No discrepancies were identified.
RP&C Organization and Administration
R6.1
Unit 1 SGRP Radiation Protection Organization
a .
b.
Inspection Scope
During inspection from 10/28 until 11 /4, the inspector reviewed the licensee's RP
staffing organization in support of the steam generator replacement project. The
review consisted of organization documentation review and observations of program
implementation during the project.
Observations and Findings
The original staffing plan called for 58 contractor senior RP Technicians and 24
contractor junior/decon RP technicians making use of 10 permanent station senior
RP technicians. The actual RP organization staffing utilized a total of 75 contractor
senior RP technicians and 24 contractor junior/decon RP technicians. An additional
7 radiological engineers were provided by RNI and FTI. The licensee utilized
existing PSE&G RP personnel in overall RP operations supervision capacities to
oversee all ALARA and RP operations functions. All major radiological work areas
were observed to be well staffed with cognizant RP staff.
c.
Conclusions
The inspector determined that the licensee met and exceeded the planned RP
staffing levels to support the steam generator replacement project. Through
observation, the inspector determined that very good RP staff resources were
available to provide the radiological survey and job coverage needs of the project .
-.
34
R6.2
Unit 2 Outage RP Organization
R7
a. Scope (83750)
During inspection from 12/9 until 12/13, the inspector reviewed the licensee's RP
outage organization responsible for support of Unit 2 restart outage activities and
Unit 1 steam generator replacement project activities. The review consisted of
review of organizational documents and observations of work area coverage during
the inspection.
b. Observations and Findings
The RP Department had increased the staffing of 36 permanent plant senior RP
technicians to include the contracted services of 86 senior RP technicians and 26
junior RP technicians. Approximately 30 contracted senior RP technicians were
utilized for radiological coverage of Unit 2 and the Unit 1 non-containment RCA
areas. The SGRP RP organization utilized the balance of the contracted RP
technicians to provide all Unit 1 containment RP support. Inspection tours of both
Unit 1 and 2 containments and Units 1 and 2 Auxiliary Buildings, the Solid
Radwaste Building and the "yard" RCA areas, indicated that all areas were
effectively monitored by radiological controls personnel.
c. Conclusions
Appropriate RP staffing levels were obtained and used to support the outage
activities of both Salem. Units 1 and 2.
Quality Assurance in RP&C Activities
R7. 1
a.
Inspection Scope
b.
During inspection from 1 0/28 until 11 /4, the inspector reviewed the resources
dedicated to providing oversight of the radiation protection program implementation
during the steam generator project. Applicable quality assurance documents were
reviewed and interviews with cognizant personnel were conducted.
Observations and Findings
The licensee provided a Quality Assurance (QA) steam generator replacement
project (SGRP) oversight plan, that provided for the identification of high risk events
and plans for assessing the adequacy of the contractor's QA controls over the high
risk planned activities. Four individuals were contracted by PSE&G for performing
this QA oversight work, each having had recent steam generator replacement
experience. Each major contractor (RNI, FTI) was required by contract to provide
their own QA monitoring and controls. The inspector noted that the SGRP did not
35
contract the RP function, that this function was supplied directly by PSE&G. No
additional QA oversight had been specifically planned to cover the RP area. One
PSE&G individual having normal responsibility for reviewing the RP and Chemistry
areas was involved due to normal job performance. Limited SGRP QA surveillance
observations had been documented by this individual during the project. Two days
of observations were documented during the project. These included observations
of RP command center remote monitoring of RCS pipe cutting of old steam
generator no. 12 and the review of one radiological occurrence report. No
discrepancies . .were recorded by the QA inspector. Also, a limited SGRP RP
preparation review was performed by an outside RP consultant, however the review
indicated that a comprehensive RP preparation audit should be conducted prior to
project commencement, which was not performed. The inspector questioned the
adequacy of QA oversight of the SGRP RP program. In response to this inspection
concern.**the licensee added a fifth member to the QA oversight group with specific
responsibility for radiation protection oversight.
c.
Conclusions
The inspector determined that the licensee had not dedicated specific QA oversight
review of the RP program performance during the SGRP and only routine QA
surveillance activities were being provided. In response to this finding, the licensee
obtained an additional member of the SGRP QA oversight group tasked with specific
responsibility for radiation protection oversight.
R7.2
Radiological Occurrence Reports (RORs)
. a. Scope (83750)
During inspection from 12/9 until 12/13, the inspector reviewed the licensee's
program for identifying, investigating, and correcting radiological occurrences at
Salem Station. The inspector reviewed selected RORs for 1996 to assess the
licensee's performance in this area. The inspector also conducted interviews with
applicable RP staff.
b. Observations and Findings
During 1996, the licensee recorded 154 level 1 RORs, 40 level 2 RORs, and 8 level
3 RORs (level 1 ROR indicates least significant and level 3 ROR the most
significant). The inspector observed that the level 1 RORs were predominantly
personnel contaminations. The inspector reviewed in detail selected level 3 and
- 1evel 2 RORs. Based on this review, the inspector noted that most of the
radiological occurrences were of low exposure consequence and that there was a
good low threshold for reporting radiological incidents. Also, the investigations of
the level 2 and 3 RORs were thorough and detailed. However, corrective action
resolution of the level 2 and 3 RORs frequently did not address all of the issues
identified in the investigations and the corrective actions were often limited to
counseling of the involved individual and informing the staff. The following two
examples are provided for illustration.
.J
36
ROR No.96-123 was written in response to a series of work control errors
associated with a valve repair that took place inside the unit 2 regenerative heat
exchanger room. The ROR identified that l&C technicians had entered the room to
perform work and were stopped due to a system tagging conflict. Mechanical
maintenance made several unnecessary entries into the room due to a failure to
drain the piping system, failure to bring valve parts, and rework of the valve repair
caused by failure to remove the old gasket before installing a replacement. The
ROR captured the various planning deficiencies. The one exception was the ALARA
prejob planning meeting that serves to ensure a radiologically significant job is
adequately prepared. In this case, an ALARA meeting was held and did not identify
the planning inadequacies prior to the start of the job. This was not captured by
the ROR. The *HOR assigned l&C and Mechanical Maintenance with corrective
action resolution. This consisted of holding departmental review meetings to
communicate this. incident tQ their respective staffs. The ROR corrective actions
were subsequently approved by the RPM. Planning and departmental interfaces
with operations and ALARA were not reviewed or evaluated to improve
maintenance practices.
ROR No.96-168 was written in response to a worker entering a high radiation area
(Unit 1 containment bioshield) without being monitored by a TLD (although his
exposure was monitored by EPD). The ROR investigation determined that when the
individual entered the security guardhouse, he was issued his security badge
without his TLD attached. The individual failed to notice the missing TLD and was
later admitted inside the bioshield of Unit 1 containment by an RP technician and
allowed to work. The ROR identified that the security guard, the individual, and the
RP technician, were inattentive to the missing TLD and the ROR also identified that
the security badge clasp or snap that held the TLD badge to the security badge was
weak and had failed. The ROR corrective actions consisted of counseling the
individual on the applicable RP procedures and receiving disciplinary action from his
supervisor. Also, the incident was a topic of discussion during a safety meeting.
The inspector determined that the ROR had identified several failure mechanisms
but had only pursued one. The inspector noted that the individual was issued his
security badge improperly since the TLD was found in the applicable security badge
slot. The slots are too small for the security/TLD badge assembly which cause the
badges to be folded and twisted into the badge slots. Repeated cycling apparently
caused the snap to fail. This was not addressed in the ROR. Also, entry into the
containment bioshield area requires RP technician permission to gain access. Plant
policy allows dosimetry to be placed inside or outside of protective clothing and
when dosimetry is placed inside of protective clothing, RP technicians cannot verify
that workers are in compliance with requirements prior to allowing access to certain
high radiation areas. Review and evaluation of this plant practice was also not
reviewed in the ROR.
c. Conclusions
The inspector concluded that; radiological occurrences were of low exposure
consequence, that there was a good low threshold for reporting radiological
-.
RS
RB.1
37
incidents; and that the investigations of level 2 and 3 RORs were thorough.
Corrective action resolution of the level 2 and 3 RORs frequently did not address all
of the issues identified in the investigations and the corrective actions were often
. limited. Additional attention in this area was warranted.
Miscellaneous RP&C Issues
(Closed) Violation 50-311196-01.-05:
During late 1995, the licensee reported several instances of entering the RCA
without electronic dosimetry monitoring and other related access control procedure
violations. The repetitive nature of these procedure violations resulted in issuance
of a violation against 10 CFR 50 Appendix B, Criteria XVI, failure to provide
effective corrective actions to prevent recurrence.
The inspector determined that establishing the electronic locking turnstiles at the
RCA entrance provided substantial positive control over workers accessing the RCA
to ensure each worker's exposure is monitored by an electronic dosimeter. Two
software system modifications were made that served to enhance worker
performance during RCA entry procedures. This violation is closed.
RB.2
(Closed) Unresolved Item 50-272/96-12-04:
Since June 25, 1996, until early November 1996, the Salem Radiation Protection
Manager (RPM) was assigned to a temporary position in the Salem Unit 2 Outage
Management group. The RPM designated the Senior ALARA Supervisor as the
acting RPM in his absence. During the previous inspection, sufficient information
was not available to determine if the individual met the applicable regulatory
requirements, specifically 5 years of professional radiation protection experience.
During this inspection, the licensee provided a breakdown of RP supervisory
experience for the acting individual that, in aggregate, equated to 5.5 years of
professional experience. As a result, the subject individual was found to meet the
regulatory requirements for the RPM position. This item is closed.
RB.3
Updated Final Safety Analysis Report (UFSAR)
The inspector reviewed current Salem Station practices with respect to Section
12.1.5 of the UFSAR. This section describes the semi-annual leak checks, control
and storage of radioactive sources. The inspector verified the source- inventory and-
reviewed documentation indicating successful completion of the semi-annual leak
checks. All sources were controlled in locked storage cabinets with keys controlled
by RP or RP instrumentation personnel. The inspector determined that the UFSAR
wording was consistent with the observed plant practices and procedures.
38
V. Management Meetings
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at the
conclusion of the inspection on December 24, 1996. The licensee acknowledged the
findings presented.
The inspectors asked the licensee whether any materials examined during the inspection
should be considered proprietary. No proprietary information was identified .
Opened
50-272&311/96-17-01
50-272&311 /96-17-02
Closed
50-272/96-12-04
50-311194-24-02
50-311196-01-05
50-272&311/95-10-01
50-272&311/96-10-02
50-272&311/96-12-01
50-272&311 /96-24-03
50-272&311 /96-24-05
50-272/96-012
50-272/96-015
50-272/96-027
ITEMS OPENED, CLOSED, AND DISCUSSED
IFI
LER
LER
LER
failure to perform required safety analysis report
possible degradation of containment penetrations
radiation protection manager qualification
auxiliary feedwater pump trip evaluation
repetitive RCA access control procedure violations
failure to relatch EDG fuel rack
failure to report shutdown required by Technical
Specification
failure to take ad<:;(j-uate actions for'"a significant
condition adverse to quality to preclude repetition
missed heat balance
inadequate access control
potential loss of RHR capability due to inadequate valve
design
inadequate CFCU heat removal capability due to bio-
fouling
diesel watt meter inaccuracies not accounted for in
surveillance testing
!
...
A LARA
BAT
CFCU
CR
ECAC
FHV
NRC
.PORV
PSE&G
RNI
RP&C
SAC
SPAV
SRs
TS
USO
LIST OF ACRONYMS USED
As Low As Is Reasonably Achievable
Boric Acid Transfer
Containment Fan Coil Unit
Condition Resolution
Emergency Control Air Compressor
Fuel Handling Ventilation
Framatome Technologies Incorporated
Nuclear Regulatory Commission
Public Document Room
Performance Improvement Request
Preventive Maintenance
Power Operated Relief Valve
Public Service Electric and Gas
Quality Assurance
Radiological Controlled Area
Raytheon Nuclear Incorporated
Radiation Protection
Radiological Protection and Chemistry
Station Air
Station Air Compressor
Station Blackout
Steam Generator Replacement Project
Safety Injection
Switchgear Penetration Area Ventilation
Senior Reactor Operator
Surveillance Requirements
Surveillance Testing
Temporary Access Facility
Technical Specification
Updated Final Safety Analysis Report
Unreviewed Safety Question