ML18102B431
| ML18102B431 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 07/01/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18102B428 | List: |
| References | |
| 50-272-97-12, 50-311-97-12, NUDOCS 9707110369 | |
| Download: ML18102B431 (31) | |
See also: IR 05000272/1997012
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
50-272/97-12, 50-311 /97-12
Public Service Electric and Gas Company
Salem Nuclear Generating Station, Units 1 & 2
P.O. Box 236
Hancocks Bridge, New Jersey 08038
April 27, 1997 - June 21, 1997
C. S. Marschall, Senior Resident Inspector
J. G. Schoppy, Resident Inspector
R. K. Lorson, Resident Inspector
T. H. Fish, Operations Engineer
P. H. Bissett, Senior Operations Engineer
E. H. Gray, Project Manager
L. A. Peluso, Radiation Physicist
J. D. Noggle, Senior Radiation Specialist
James C. Linville, Chief, Projects Branch 3
Division of Reactor Projects
9707110369 970701
ADOCK 05000272
G
EXECUTIVE SUMMARY
Salem Nuclear Generating Station
NRC Inspection Report 50-272/97-12, 50-311 /97-12
This integrated inspection included aspects of licensee operations, engineering,
maintenance, and plant support. The report covers an 8-week period of resident
inspection; in addition, it includes the results of announced inspections by regional health
physics and engineering inspectors.
Operations
The inspectors observed good operator performance during routine plant evolutions and
during response to several emergent equipment problems (Section 01 . 1 l.
The Operations Technical Support Superintendent effectively eliminated operator reliance
on Technical Specification interpretations. The operations staff placed needed operator
guidance in plant operating procedures. In a few cases, however, the staff did not
thoroughly review resultant procedure revisions to ensure strict Technical Specification
compliance, alignment with the design basis, and clear operator guidance. The staff
initiated appropriate action to correct these procedure weaknesses (Section 01.3).
Operators did not comply with station procedures requiring operators to update Tagging
Request and Inquiry System (TRIS). Operators did not meet operations management's
expectations in conducting TRIS reviews. The operating shift failed to take adequate
action to document the deficient conditions to prevent recurrence. Operations
management, when presented the aggregate problem, initiated corrective actions to
address operator weaknesses in this area (Section 02.1 ).
Plant personnel maintained the *unit 2 containment in very good condition and ready to
support the plant mode change to Mode 4 (Section 02.2).
Station personnel were using the corrective action system to identify and report quality
issues. The inspectors identified a few minor performance issues where condition reports
were not self-initiated indicating a need for continued focus in this area (Section 07.2).
Maintenance
A reactor operator used a good questioning attitude to identify degraded auxiliary
feedwater alternate supply piping. Maintenance and operations supervision, however,
failed to ensure prompt and appropriate corrective actions (Section M2.1 ).
Two inspectors reviewed Salem's implementation of the maintenance rule during May 27 -
June 3, 1997. The inspectors concluded that Salem's implementation of the maintenance
rule involving scoping and performance criteria was acceptable. Inspectors concluded that
Salem staff completed significant efforts in these areas, and that problems similar to those
identified at the Hope -Creek station did not exist at the Salem plant (Section M3. 1 ) .
ii
Engineering
System managers were actively involved in the resolution of several emergent equipment
problems (Section E2.1 ).
For the construction and engineering aspects of the SGRP, the inspections found a
generally high level of project performance in the areas inspected and identified no safety
significant project deficiencies. The planning for and initial steps of the turnover to the
plant were in progress (Section E2.2).
The licensee implemented adequate corrective actions to support Unit 2 restart in response
to the concerns regarding operation of the emergency core cooling systems(ECCS)
identified in NRC Inspection Report 50-272&311 /97-07 (Section E8.1 ).
Plant Support
Based on the direct observations, discussions with personnel, and examination of
procedures and records for calibration of equipment, the inspector determined that, overall,
the licensee effectively maintained and calibrated the meteorological monitoring
instrumentation. The data were available as required and were easily accessed from
several locations, including the control room and the EOF as specified in the UFSAR. The
licensee's actions to complete a DCP were not timely, and require further review. (Section
R1 .1)
The licensee implemented adequate measures to monitor the areas affected by the cable
tray fire wrap concerns documented in NRC Inspection Report 97-09 (Section F1 .1 ).
The solid radwaste program oversight was good for off site shipment review,
however, some improvements are needed for providing QA audits of radwaste
processing vendors.
The solid radwaste/transportation procedures generally met the new DOT
requirements, however, one violation was identified in shipping paper
documentation of contaminated laundry shipments. Some improvements are
needed in the Process Control Program and implementing procedures to ensure that
essential solid radwaste processing parameters and criteria that are contained in
federal, state and burial license requirements are captured and properly referenced.
Retired solid radwaste processing equipment was verified to be drained, isolated,
and in proper long-term laidup condition. Low solid radwaste volume generation
and efficient shipping efforts at Salem have resulted in no onsite storage of solid
radwaste .
iii
TABLE OF CONTENTS
EXECUTIVE SUMMARY ............................................. ii
TABLE OF CONTENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv
I. Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
II. Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8
Ill. Engineering ........ * . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12
IV. Plant Support . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . .
17
V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
25
iv
Report Details
Summary of Plant Status
Unit 1 remained defueled for the duration of the inspection period.
Unit 2 began the period in Mode 5, Cold Shutdown. On June 15, operators increased
average coolant temperature above 200°F and entered Mode 4, Hot Shutdown. Operators
maintained Unit 2 in Mode 4 for the remainder of the period.
I. Operations
01
Conduct of Operations
01 . 1 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.
01.2 Routine Operator and Plant Performance Observations (71707)
The inspectors observed good control room operator performance during normal
plant evolutions including a plant depressuriz*ation and recovery to support a battery
bus maintenance outage, containment fan cooler unit modification testing, and
routine surveillance testing. The control room operators demonstrated good
procedure adherence, communications, and plant control during these evolutions.
The control room operators responded properly to plant alarms and equipment
problems including a safeguards equipment cabinet test circuit lock-up, a pressurizer
relief stop valve failure, and an overheated 1 B EOG field flash circuit. In each case,
the operators made conservative operability determinations and initiated prompt
actions to address the equipment problems.
The plant material condition and housekeeping conditions were good. The
inspectors identified some minor material deficiencies such as a missing service
water system valve handwheel, and a watertight door blocked open by a temporary
electrical cable. The operations staff responded promptly to correct the identified
concerns.
01.3 Technical Specification lnteroretations
a.
Inspection Scope (71707)
The operations staff previously established technical specification (TS)
interpretations to aid operators in understanding TS requirements. Such TS
interpretations risked changing the wording, meaning, or intent of a TS requirement.
2
The inspector reviewed the remaining Unit 2 TS interpretation and TS-related
procedure revisions to ensure guidance did not conflict with TS requirements.
b.
Observations and Findings
The Operations Technical Support Superintendent eliminated 16 of 17 TS
interpretations. The licensee retained a TS 3.8.2.1 interpretation to provide
operator guidance concerning the "D" vital instrument bus (VIB) inverter. The TS 3.8.2.1 interpretation provides more restrictive operating guidance for the "D" VIB
than imposed by TS 3.8.2.1. Licensing initiated a License Change Request (LCR
95-18) to permanently incorporate "D" VIB guidance into TS 3.8.2.1.
The technical support staff eliminated the 16 TS interpretations through license
change requests, procedure revisions, and deletions. The inspector identified that
three resultant procedure revisions contained guidance that conflicted with TS
requirements, did not align with design basis requirements, and did not provide clear
operator guidance. In each case, the operations staff initiated procedure revisions
to correct procedure weaknesses~
The inspector noted that S2.0P-ST.MS-0002,Revision 7, lnservice Testing Main
Steam and Main Feedwater Valves, step 5. 7.5.D did not require operators to.
comply with TS 3.3.2.1 action 20 if any two inoperable MS169 or MS171 valves
(MSIV vent valves) were associated with the same MSIV. Action 20 allows 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />
to restore a channel (MSIV vent valve) prior to requiring a shutdown to mode 4. In
the case of two inoperable vent valves on one MSIV, step 5.7.5.E directs operators
to TS 3. 7. 1 . 5, which allows continued operation in mode 2 if operators shut the
associated MSIV. The inspector noted that in this case shutting the applicable
MSIV completes the MSIV safety function, however, does not comply with TS 3.3.2. 1 requirements. The Shift Technical .Advisor (STA) initiated CR 970424309
to affect a procedure change to correct this discrepancy. The inspector determined
that the failure to ensure TS 3.3.2.1 compliance constitutes a violation of minor
significance and is being treated as a- non-cited violation, consistent with Section IV
o_f the NRC Enforcement Policy. (NCV 50-272&311/97-12-03)
Operating Procedure, Revision 7, Service Water System Operation, Attachment 2
Section 6.0 allowed operators to consider both containment spray (CS) pumps
operable with one CS room cooler inoperable provided service water (SW)
temperature ~ 79~6 °F. Section 9.2.1.2 of the FSAR states that the SW pumping
requirements are based on a maximum river temperature of 90 °F. The total
capacity of the room coolers in a given area, in conjunction with the exhaust air
flow rate, is designed to limit the area temperature to the design values. The
operations staff used engineering calculation S-C-ABV-NDC-0750 to support
operation of the CS pumps with one inoperable CS room cooler, however, the
inspector concluded that procedure S2.0P-SO-SW-0005 permitted operability of the
CS pumps under service water operating conditions less conservative than
described in the FSAR. The Operations Technical Support Superintendent viewed
the guidance as conditional operability and initiated a procedure revision to require
appropriate TS 3.6.2.1 entry given an inoperable CS room cooler.
3
Operating procedure S2.0P-SO.SW-0001, Revision 7, Service Water Pump
Operation, Attachment 1 Section 4.0 provided guidance to operators concerning
manual operation of SW traveling screens and strainers to ensure sufficient diesel
load margin. The procedure provided ambiguous guidance and had the potential to
adversely affect diesel load margin. The operations staff initiated a procedure
revision to improve the procedure.
c.
Conclusion
The Operations Technical Support Superintendent effectively eliminated operator
reliance on TS interpretations. Operations staff placed needed operator guidance in
plant operating procedures. In a few cases, however, the staff did not thoroughly .
review resultant procedure revisions to ensure strict TS compliance, design basis
alignment, and clear operator guidance. The staff initiated appropriate action to
correct these procedure weaknesses.
02-
Operational Status of Facilities and Equipment
02.1
Configuration Control Deficiencies
a.
Inspection Scope (71707)
Salem operators use, update, and audit a Tagging Request and Inquiry System
(TRIS) database to assist in the establishment and maintenance of configuration
control. Operators use TRIS for information on normal valve lineup, current
position, and tagging status. The inspector reviewed TRIS "off-normal and off-
normal tagged" reports and evaluated operator's ability to maintain the TRIS
database to ensure adequate configuration control.
b.
Observations and Findings
The inspector noted the following TRIS discrepancies:
Breaker 2BDC1 AX22, "B7G (Reg) and A7G (Erner) 125 VDC distribution
panel"
Actual Position: open
TRIS Position: closed
Breaker 2CY1AX10Y-1, "2A2 125 VDC Batt. Chg"
Actual Position: open
TRIS Position: closed
Valves PS48, PS49, PS52, PS53 (pressurizer spray valves used for RCS
vacuum fill)
Actual Position: closed
TRIS Position: open
Breaker 2BDC1AX15 (Unit 2 backup power supply to Unit 1 circulating water
460Vl
Actual Position: open
TRIS Position: closed
4
Blank flange 21 PAEXFN-BLK, "Penetration Area Exhaust Fan Suction"
Actual Position: flange removed
TRIS Position: flange installed
Valve 2CS14, "Containment Spray Additive Tank Isolation Valve"
Actual Position: closed
TRIS Position: open
Valves 21SW23,22SW23, "SW Header Cross Connect Valves"
Actual Position: closed
TRIS Position: open
Valve 21 SW593 "21 SW Accumulator Header Isolation Valve"
Actual Position: open
TRIS Position: closed
Desired position: closed
Valves 21 SW465, 21SW468,22SW465, 22SW468, 22SW464, 22SW472,
2SW932,2SW931,22SW413,22SW414
Actual Position: off-normal
TRIS Position: normal
On May 9, inspectors presented the initial seven observations to operations
management. On May 13, operations staff initiated CR 970513226 to document
the TRIS discrepancies.
In the above cases, operators did not follow guidance provided in section 5.4.7 of
SC.OP-AP.ZZ-0103, revision 5, TRIS Configuration Control to update TRIS. In
addition, Unit 2 control room operators did not discover these discrepancies even
though section 5.14.2 of S2.0P-DL.ZZ-0014, revision 6, Shift Routines, requires
operators to review the TRIS off-normal report once per shift. Following inspector
identification, operators promptly updated TRIS, however, in each case operators
failed to document the deficiencies via the Action Request (AR) process to ensure
corrective action to prevent recurrence. Inspectors previously noted TRIS
performance problems in NRC Inspection Report 50-272&311 /96-0Sand Inspection
Report 50-272&311 /96-15. Failure to identify and take prompt and appropriate
actions to correct conditions adverse to quality is a violation of 10 CFR 50,
~ppendix B, Criterion XVI. (VIO 50-272&311/97-12-02)
The inspector noted that the configuration control deficiencies resulted in no safety
consequence. In one case (21 SW593) operators actually lost configuration control.
Maintaining valve 21 SW593 closed ensured isolation between modified SW
accumulator piping and an operating SW header. On May 11, operators performed
a temporary release on 21 SW593 with guidance to maintain the valve closed except
as needed to fill no. 21 SW accumulator. On May 13, the inspector found valve
21 SW593_open with no accumulator fill in progress. The operating shift did not
know the status of 21 SW593. (Operators had left the valve open after filling no.
21 accumulator on May 11 .) Inspectors concluded that leaving the valve open had
no immediate safety consequence for the existing plant conditions. In the remaining
cases, operators appropriately positioned components per approved procedures,
although TRIS status did not reflect correct position .
5
c.
Conclusions
Operators failed to comply with station procedures requiring operators to update
TRIS. Operators did not meet operations management's expectations in* conducting
TRIS reviews. The operating shift failed to take adequate action to document the
deficient conditions to prevent recurrence. Operations management, when
presented the aggregate problem, initiated corrective actions to address operator
weaknesses in this area.
02.2 Unit 2 Containment Closeout Inspection (71707)
The inspectors toured the Unit 2 containment prior to the plant mode change to
Mode 4. The tour involved approximately 10 inspector-hours of effort and included
the pressurizer, annulus, reactor sump area, reactor cavity, and inside the biological
shield. The inspectors identified a small number of minor housekeeping and material
deficiencies. The Director - Salem Operations initiated prompt actions to address
the deficiencies. The inspectors concluded, based on the extent of the tour and the
limited number of findings that plant personnel maintained the containment in very
good condition and ready to support the plant heat up.
07
Quality Assurance in Operations
07. 1 Commitment Management. NRC Restart Item Ill. 14 (Closed)
In NRC Inspection Report 50-272/97-03, 50-311197-03, the inspectors kept NRC
Restart Item 111.14 open pending licensee completion of improvements to the
commitment management procedures.
The NRC has reviewed the following procedures as they apply to commitment
management:
Commitment Management, NC.NA-AP.ZZ-0030(0) - Rev. 2
Licensing Department Commitment Management Program, NC.LR-AP.ZZ-
0030(0) - Rev. 0
Nuclear Licensing and Reporting, NC.NA-AP.ZZ-0035(0)- Rev. 7
Action Tracking Program, NC.NA-AP.ZZ-0057(0) - Rev. 4
The review of the above procedures indicates that responsibility for commitment
tracking is assigned within the licensee's organization, that the licensee has
established requirements that commitments will be properly tracked from
establishment to completion of any modifications, and that commitments can be
reevaluated and changed in an orderly fashion with appropriate documentation.
Based upon the above, Commitment Management, NRC Restart Item 111.14, is
closed.
6
07.2 Corrective Action Program Review
a.
Inspection Scope (71707)
The inspector compared the plant activities to the initiated condition reports (CRs)
to determine whether the plant staff was appropriately identifying and entering
potential quality issues into the corrective action system.
b.
Observations and Findings
The plant staff generated approximately 550 condition reports (CRs) over a one
month period indicating a low threshold for use of the corrective action program.
The plant staff primarily identified significance level three (low significance) issues.
The inspector reviewed the condition report summary list and noted that the CRs
covered a wide range of plant activities.
The inspector identified that in a few minor programmatic or human performance
issues wherein the plant staff did not initiate a CR including:
The operator secured the 1 8 EOG during a post-maintenance test run on May
31 upon receipt of a "pre-lube pump failure" alarm and a low lubricating oil
header pressure indication. The field supervisor investigated and attributed
the apparent EOG oil pressure problem to an isolated lubricating oil pressure
gage. The gage had been isolated during the EOG maintenance outage and
the operator should have unisolated and vented the gage during the test run.
The inspectors determined that the operators did not maintain good
configuration control of the gage.
The Unit 2 control room operator attempted unsuccessfully to reset the "A"
train of the control area ventilation system during modification testing on
May 17. The train did not reset since its electrical supply breaker had been
blocked open for a maintenance activity. The operator's attempt to reset the
~rain while it was blocked demonstrated a weakness in the control of plant
equipment.
The inspector's identified several examples noted where the actual position
of a plant component differed from the position documented in the Tagging
Request and Inquiry System (TRIS). The shift operations staff corrected the
individual deficiencies but did not initiate a CR as discussed in Section 02.1.
The inspectors discussed the above findings with the Operations Manager and the
Corrective Actions Program Supervisor to ensure a proper review of the issues.
c.
Conclusions
Inspectors concluded that station personnel routinely used the corrective action
system to identify and report quality issues. For a few performance issues,
inspectors found that plant staff did not initiate condition reports. The inspectors
- 08
08.1
7
concluded that achieving a low reporting threshold for adverse conditions warranted
continued management focus.
Miscellaneous Operations Issue
(Closed) LER 50-272/96-026: inadequate testing of residual heat removal (RHR) hot
leg flow path. On October 2, 1996 the Salem staff identified inadequate full flow
testing through the RH27 check valves in the RHR hot leg injection lines. The RH27
valves are in two parallel lines that are fed from a common header. The check
valves full-stroke testing was performed by measuring flow in the common header.
Position 1 of NRC Generic Letter 89-04 states that knowledge of only the total flow
through multiple parallel lines does not provide verification of flow rates through the
individual valves and is not a valid full-stroke exercise." The Salem staff found that
they disassembled the valves on a 36 month frequency to satisfy recommendations
in INPO SOER 86-03. Although the surveillance procedure contained an inadequate
test method, the disassembly and the full flow testing provides confidence that the
check valves remained functional and the safety consequences and implications
were minor. Forward flow testing was satisfactorily performed for the Unit 2 RH27
check valves on October 24, 1996 using a temporary change to the test procedure.
A revision request was initiated to permanently revise the test procedure.
Since the NRC has taken significant enforcement actions for Salem's performance
problems, and since PSE&G voluntarily maintained both Salem units shut down to
address equipment and personnel performance deficiencies, the NRC will not take
additional enforcement action in this case. In particular, Salem management took
extensive measures to correct IST program deficiencies as part of NRC restart issue
11-16, NRC & QA identified numerous IST program deficiencies. This item is closed.
08.2 (Closed) LER 50-311 /94-015:waste gas holdup tank not sampled in accordance
with Technical Specification 3.3.3.9. During testing activities, the Gas Analyzer
Sample Isolation Valve was placed in the closed "off normal " position. On 9/27 /94
a.nd 10/1 /94, the associated Waste Gas Decay Tank was placed in service with the
sample isolation valve still in the closed position and sampling was not performed as
required.
The cause was attributed to personnel error with regard to inadequate review of the
tagging list. Since the NRC has taken significant enforcement actions for Salem's
performance problems, and since PSE&G voluntarily maintained both Salem units
shut down to address equipment and personnel performance deficiencies, the NRC
will not take additional enforcement action in this case. In particular, Salem
management took extensive measures to enhance the tagging program as part of
NRC Restart Issue 111-12, Tagging. This item is closed.
8
II. Maintenance
M 1
Conduct of Maintenance
M 1 . 1 General Comments
a.
Inspection Scope (62707)
b .
The inspectors observed all or portions of the following work:
- * * *
970321239:
970513280:
970320074:
980407016:
950731104:
pressurizer heater bus cable modification
no. 26 SW strainer repairs
no. 21 reactor shield vent fan installation
no. 2 reactor protection system safeguards emergency
cabinet vital bus 28 panel relay and time response
testing
condenser outlet flange leak repair
The inspectors observed that the plant staff performed the maintenance effectively
within the requirements of the station maintenance program.
Inspection Scope (61726)
The inspectors observed all or portions of .the following surveillances:
S2.0P-ST.ZZ-0003:
S2.0P-ST.PZR-0002:
S2.0P-ST.DG-0001:
S2.0P-ST.DG-0005:
S2.RE-ST.ZZ-0002, rev.9:
SC.OP-ST.CAV-0001:
SC.OP-ST .CAV-0002:
SC.OP-ST.CAV-0003:
S2.0P-ST.RC-0008:
S2.0P-ST.CS-0001:
inservice testing miscellaneous valves,
inservice testing PORV and PORV block valves*
modes 1-6,
2A diesel generator surveillance test,
diesel generator auxiliary no. 22 fuel oil transfer
system operability test,
shutdown margin calculation,
plant systems control room ventilation,
control room emergency air conditioning system,
control room emergency air conditioning system
manual operation,
reactor coolant system water inventory balance,
and
inservice testing - 21 containment spray pump.
The inspectors observed that plant staff did the surveillances safely, effectively
demonstrating operability of the associated system.
9
M2
Maintenance and Material Condition of Facilities and Equipment
M2.1 Auxiliary Feedwater Alternate Su.pply Piping Corroded
a.
Inspection Scope (71707)
The inspector toured accessible plant areas and evaluated the licensee's
performance in identifying, tracking, and correcting deficiencies.
b.
Observations and Findings
On January 23, 1997, a reactor operator identified corroded auxiliary feedwater
(AFW) piping upstream and downstream of 1 AF71 and 1 AF72 (AR 970123203).
These valves are check valves in the emergency backup water supply piping from
the demineralized water storage tanks and fire protection storage tanks,
respectively. The reactor operator recommended that engineering perform an
ultrasonic (UT) pipe wall thickness test. On March 12, inservice inspection (ISi)
engineers performed an UT on 1 AF71 and maintenance supervisors closed work
order 970123203 on April 13.
On May 16, *1997, the inspector identified the following deficiencies associated
with this activity to the Operations Superintendent:
Following work completion, maintenance technicians failed to remove the
associated equipment malfunction information system tag (EMIS 47569) as
required by work standards.
Technicians closed the work order with no UT inspection of the 1 AF72
piping.
The technicians closed the work order even though the 1 AF71 UT inspection
identified a thickness reading less than the nominal wall thickness. This
required an engineering evaluation.
The STA closed a TS 3.7.1.3 tracking item (97-040T) on the degraded AFW
piping based on the closed work order.
The Operations Superintendent initiated actions to address the above deficiencies
(AR 970604181 ). Technical Specifications did not require operable AFW piping
during the time frame in question. On June 18, ISi engineers completed a UT
inspection and determined that the AFW piping in question possessed adequate wall
thickness. Failure to take appropriate actions to correct conditions adverse to
quality is another example of violation of 10 CFR 50, Appendix B, Criterion XVI.
(VIO 50-272&311 /97-12-02)
10
c.
Conclusions
A reactor operator used a good questioning attitude to identify degraded auxiliary
feedwater alternate supply piping. Maintenance and operations supervision,
however, failed to ensure prompt and appropriate corrective actions.
M3
Maintenance Procedures and Documentation
M3.1 Maintenance Rule Overview
a.
Inspection Scope
b.
The inspectors reviewed parts of Salem's maintenance rule program to determine
whether deficiencies previously identified at the Hope Creek Generating Station also
existed at the Salem facility.
Observations and Findings
The inspectors focused their inspection on two areas of the maintenance rule
program that were the subject of apparent violations (action pending) at Hope Creek
(NRC Inspection Report 50-354/97-80). These areas were 1) failure to establish
adequate performance criteria for monitoring the effectiveness of preventive
maintenance on several systems; and 2) failure to include appropriate SSCs within
the scope of the rule.
The Hope Creek report documented ten examples of safety significant and standby
systems that did not have performance criteria established (e.g., reactor protection,
control rod drive, control air, and remote shutdown). In some cases, the systems
had reliability performance criteria, but did not have unavailability performance
criteria; in other cases, systems did not have performance criteria established at the
system/train level. The inspectors reviewed the analogous systems at the Salem
plant and determined that the Salem staff had established appropriate performance
c_riteria. The inspectors also reviewed a large sample of the remaining safety and
standby systems and noted they all had performance criteria. There was however,
one instance in which the inspectors identified one system not having designated
unavailability performance criteria. Reliability performance criteria for the reactor
controls and protection system had been established, but unavailability performance
criteria had not been designated. The Salem maintenance rule manager
subsequently provided to the inspectors appropriate unavailability performance
criteria for this system and also stated that a complete review of the performance
criteria area was scheduled for completion by July 3, 1997. As a result of not
identifying any other omissions of performance criteria, the inspectors considered
this as an isolated instance.
The inspectors also reviewed those SSCs at the Salem plants that were determined
to be "in-scope" and "out-of-scope" in regard to the maintenance rule. A total of
148 SSCs had been identified, of which, 86 were determined to be "in-scope" and
62 were "out-of-scope." The inspectors reviewed documentation that supported
c.
11
the facility's decision to include or not include a SSC under the maintenance rule.
These decisions were adequately documented under station procedure
SE.MR.SA.02 "System Functional Level Maintenance Rule Scoping vs. Risk
Reference." Maintenance rule scoping efforts were outlined in the maintenance rule
scoping document DTG-NSE-030. This document specifically defined the
evaluations needed to be performed by system engineers in determining whether an
SSC fell under the maintenance rule requirements. As specified in the regulations,
each SSC was evaluated against 5 specific criteria, which included the following:
Safety-related SSCs.
Non safety-related SSCs that are relied upon to mitigate accidents or
Non safety-related SSCs that are used in station emergency operating
procedures and provide a substantial mitigation function.
Non safety-related SSCs whose failure could prevent safety-related SSCs
from fulfilling their safety-related function.
Non safety-related SSCs whose failure could cause a reactor scram or
actuation of a safety-related system.
The inspectors determined that all of the above evaluations, for each function of
each SSC had been adequately evaluated and subsequently documented in
The inspectors also reviewed expert panel meeting minutes which documented final
disposition of an SSC's status in regard to the maintenance rule. The inspectors
determined that the documentation of the various meetings were very detailed and
comprehensive; however, it was noted that several changes to various evaluations
on SSCs maintenance rule functions, as approved during expert panel meetings, had
not been updated in SE.MR.SA.02. These discrepancies were brought to the
attention of the maintenance rule manager, who stated that a complete review of all
meeting minutes would be made to ensure that SE.MR.SA.02 reflected final
approved changes. There were no instances in which the inspector noted a SSC
function was incorrectly designated "out-of-scope" in regards to maintenance rule
applicability.
The inspectors also held discussions with system managers, responsible for several
SSCs, in an effort to assess their knowledge of their responsibilities under the
maintenance rule.
The inspectors found the system managers to be knowledgeable
of the rule and well informed of their responsibilities as a result of the rule.
I
Conclusions
The inspectors determined that the Salem engineers had established performance
criteria for safety and standby systems and have also appropriately scoped
structures, systems, and components for maintenance rule applicability. The
inspectors concluded that the Salem staff was complying with the maintenance rule
in those areas reviewed and that maintenance rule program issues identified at Hope
Creek in February 1997 did not exist at Salem.
12
MS
Miscellaneous Maintenance Issues
M8.1 (Closed) LER 50-272/96-031: plant in unanalyzed condition due to qualification of
Magnacraft-Struthers Dunn Series 8255 relays. PSE&G became aware bf this
condition when they were notified by the relay supplier that one of two test relays
failed during seismic testing. Investigation determined that the failure resulted from
a design change which inadvertently reduced the latching force.
The corrective action was a redesign of the relay and replacement of all relays at
Salem Units 1 and 2. The inspector reviewed test certification documentation for
the redesigned relays to verify the new design was satisfactory. The inspector also
reviewed documentation and held discussions with the PSE&G staff to verify the
relays have been replaced for Salem Unit 2 and are in the process of being replace
for Unit 1. This LER is closed.
Ill. Engineering
E2
Engineering Support of Facilities and Equipment
E2. 1
System Manager Support For Operating Plant Conditions
The inspector reviewed the system manager support for the resolution of several
emergent plant conditions including: a 2A safeguards equipment cabinet automatic
test circuit lock-up, a failure of the pressurizer stop valve (2PR7) to operate, and an
inadvertent energization of the 1 B emergency diesel generator field flash circuit.
The inspector interviewed the system managers for each problem and determined
that they knew about the equipment problems, and became actively involved in the
troubleshooting and follow-up corrective actions. The inspector concluded that the
system managers provided good support for the resolution of plant equipment
problems.
E2.2 Steam Generator Replacement Project (50001 l
a.
Inspection Scope
Inspections were performed 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).
-Specific areas inspected included observation of the restoration of affected
components including insulation and the condition of SG snubbers including the
hydraulic oil reservoirs. The inspector reviewed the replacement steam generator
report, identification of and plans for testing of SGRP affected components and
systems, the transition of responsibilities from the SGRP team to the respective
systems managers and plant operations, the 10 CFR 50.59 process for the SGRP,
instrumentation reinstallation planning, the selection and controls for bolting
materials, post weld heat treatment of feedwater and main steam piping welds, a
13
sample of completed work control packages, a sample of project nonconformance
reports, differences and similarities between the original Model 51 (OSG) and the .
replacement steam generators Model F (RSG), and the operational plant water
chemistry conditions for the primary and secondary sides of the plant.
The site inspection included observations of conditions and work in and outside the
containment structure.
b.
Observations and Findings
By May 6, 1997, the four replacement steam generators were in place in the Unit 1
containment building with welding of the steam generator nozzles to the reactor
coolant piping, feedwater and main steam piping complete and accepted by
radiographic examination. Post weld heat treatment (PWHT) of the feedwater and
main steam piping welds was complete. Restoration or replacement of items
removed as a part of the SGRP including thermal insulation was continuing. The
installation of instrumentation components was defined in work control packages
but deferred to the plant for completion and testing.
The Replacement Steam Generator Report (77-1258763-00)summarizes the
. differences between the OSGs and replacement Model F (RSG) steam generators
and provides references to more detailed en'gineering analysis. From this report, its
references and discussions with project staff, including the Principal Chemist, there
is a reasonable basis from which to expect an improvement in performance of the
RSGs over that of the OSGs. These factors include the presence of thermally
treated alloy 600 tubes that have been shown to be more resistant to intergranular
stress corrosion (IGSCC) than the mill annealed alloy 600 of the OSGs, type 405
stainless steel support plates to minimize support plate degradation, an
improvement in secondary side water chemistry over that initially used in Unit 1, the
elimination of copper bearing alloys in secondary side heat exchangers including the
main condenser and moisture separator reheaters, and a slight reduction in
operating tube temperature.
The tracking and processing of work control packages was examined. The work
control packages sampled were found to be appropriate for the work tasks and
provisions were in place to check and close out work control packages at the
completion of work. A review of a sample of completed work packages identified
no safety significant problems.
The hydraulic snubbers, the associated hydraulic reservoirs and pipe lines for the
upper supports of the steam generators were observed. The snubbers, hydraulic oil
reservoirs and oil lines were in place although the lines were disconnected from the
snubbers. The snubbers and oil lines examined were properly capped to prevent
fluid loss or intrusion of moisture.
Bolting materials for permanent plant components including manway studs and nuts
were purchased as new safety related material.
'
c.
14
The SGRP inspections found generally good steam generator project performance
and identified no safety significant project deficiencies. Overall, the steam
generator replacement, restoration of affected components and systems (except for
instrumentation) and the related engineering evaluations to establish the extent of
changes resulting from the replacement as a part of the 10 CFR 50.59 process were
effective. The reinstallation and testing of instrumentation was-planned and work
package inputs developed for turnover as tasks to be completed by the plant
outside the SGRP work scope. Actual changes to plant operating and maintenance
procedures, training of plant operators to the specific parameters of the new steam
generators and testing are to be handled by existing processes for design change
packages (DCPs) by the plant organization. Transfer of the replaced steam
generators and related systems to the plant with involvement of the plant system
engineer/managers was in progress.
Conclusions
The replacement project staff properly controlled the SGRP replacement and the
followup work, including instrumentation installation, procedure changes and testing
were appropriately turned over to the plant for completion as part of the operational
readiness process.
Miscellaneous Engineering Issues
E8.1
(Closed) LER 50-272/97-009 and (Closed) NRC Restart Inspection Item 11.44, ECCS
Swapover: This LER discussed the past operation of the ECCS outside of the plant
design basis. These issues had been previously identified and discussed in NRC
Special Inspection Report 50-272 & 311/97-07. Based on the NRC's findings, the
licensee determined that prior to March 1996, Salem operated in a condition that
was outside the design basis of the plant for the following reasons: 1) potential
excessive RHR system flows during the recirculation mode of loss of coolant
accident (LOCA) mitigation, and 2) the inability to ensure the successful completion
of the switchover from the injection to the recirculation mode of LOCA mitigation
without the potential for interruption of the ECCS pump flow since the installation of
the semiautomatic switchover modification in 1989.
The inspectors intended to determine whether the licensee took acceptable
corrective actions to support Salem Unit 2 restart. The licensee identified the
following corrective actions to resolve the concerns identified with ECCS operation
outside of the design basis: (Note: The following items correspond to the numbered
corrective actions in LER 50-272/97-009)
1.
The licensee performed a new NPSH calculation (S-C-RHR-MDC-1711,
Revision 1) that demonstrated adequate available NPSH for the RHR pumps
without reliance on containment air pressure. The inspectors reviewed the
calculation and its associated safety evaluation (SE) (S97-117, Revision 1)
and found them acceptable. The inspector noted a minor error in the
calculation in that engineers did not include two of six pipe elbows in the
Unit 2 line loss input to the NPSH calculation. The licensee initiated a
2.
3.
4.
5.
6.
7.
8 .
15
condition report and determined that despite a small decrease in NPSH, the
RHR pumps would still have adequate NPSH. The inspectors agreed with
this assessment.
To eliminate the potential for exceeding RHR pump flow requirements during
hot leg recirculation, the licensee, in 1994, eliminated the use of the hot leg
flow path through valve RH26 by revising the LOCA EOPs.
The licensee revised the Unit 2 RWST drain-down evaluation to ensure the
operators had sufficient time to complete the manual actions for switchover
-*tram the injection to recirculation mode without interruption of ECCS pump
flow. The inspector reviewed the revised RWST drain down safety
evaluation (S97-165), and UFSAR change notice 97-071, and concluded that
the licensee's evaluation was acceptable. Additionally, the inspector
considered the operator action times specified the evaluation consistent with
the times specified in the proposed corrections submitted to the safety
evaluation report (SER) for TS Amendment 69.
The licensee revised and validated Unit 2 emergency procedure, 2-EOP-
LOCA-3, Revision 21, Transfer to Cold Leg Recirculation, to support the
RWST drain down re-evaluation. The inspector reviewed the revised
emergency procedure and found it acceptable.
The licensee trained all operating crews on the revised 2-EOP-LOCA-3
procedure. The NRC Restart Assessment Team Inspection observed an
operating crew satisfactorily perform the transfer to recirculation evolution
on the plant simulator. The inspector reviewed the 2-EOP-LOCA-3 simulator
training results _and found the measured operating crews critical action times
for various LOCA accident scenarios satisfactory.
The licensee performed a root cause investigation for the safety evaluation
deficiencies identified with this issue, as well as other NRC and self-identified
safety evaluation problems. The licensee documented corrective actions
were in a supplemental package for NRC Restart Issue 111-11, dated May 23,
1997. The NRC determined the licensee's actions were acceptable as
documented in Inspection Report 50-272 & 311 /97-08.
The licensee attributed the failure to report the RHR deficiencies (potential
runout condition) in 1 994 to corrective action programmatic deficiencies. An
improved corrective action program was implemented in July 1995 which
provides guidance for performing a more vigorous initial operability and
reportability assessment. The NRC found the changes to the licensee's
corrective action program acceptable during the review of Salem Restart
Issue 111.10, as documented in NRC IR 50-272& 311/96-08and 96-18.
The licensee took action to address performance issues associated with the
RWST drain down evaluation. Training on the issues discussed in the LER
was given to the appropriate engineering personnel. The inspector reviewed
16
a memorandum from the NSSS/BOP Design Engineering Supervisor
documenting the lessons learned training and found it acceptable.
9.
The licensee established a Salem Engineering Review Team (SERT) to provide
ongoing additional multi-disciplinary review of engineering SEs. The NRC
found the licensee's supplemental corrective actions associated with the
1 OCFR50.59 SE process effective and documented this in NRC IR 50-272 &
311 /97-08.
10.
The licensee attributed the failure to report the deficiencies associated with
the RWST drain down analysis in 1996 to human error (misjudgment).
Specifically, the personnel failed to issue a condition report to document the
deficiencies, and thus did not perform a reportability evaluation. The failure
to initiate a condition report by the engineering staff was previously cited by
'*
the NRC in IR 50-272 & 311 /96-08-04. The corrective actions from this
violation also addressed the failure to initiate a CR associated with the RWST
drain down analysis. This violation was closed in NRC IR 50-272 & 311 /97-
07.
11.
The licensee will review the Unit 1 drain down analysis and re-evaluate Unit
1 NPSH calculation to determine whether any additional corrective actions
are necessary to support the restart of Unit 1 .
12.
The licensee determined that use of the RHR26 hot leg flowpath during a
Mode 4 LOCA was necessary to maintain RHR flowpath redundancy. The
licensee approved these changes under SE S97-158 and UFSAR CN#97-069.
The inspector reviewed these documents and found them acceptable.
13.
The licensee revised the shutdown LOCA procedure S2.0P-AB.LOCA-
0001 (0) to recognize the use of the RH26 flowpath if the safety injection
flowpath is not available. The inspector reviewed this procedure and found it
acceptable.
14.
The licensee reinstated valve RH26 in the IST program for use during a Mode
4 LOCA. This inspector verified that the IST testing included RH26.
15.
The licensee notified the NRC, by letter (LR-N970293 dated May 27, 1997),
of proposed corrections to License Amendment 69 SER. The corrections
included: 1) revising the available switchover operator action times from
"approximately 18 minutes" to "approximately 8.5 minutes", 2) correctly
characterizing fOP actions associated with-the switchover evolution, 3)
clarification of uninterrupted flow to the core, and 4) revision of PSE&G's
commitment on operator omission and commission as it relates to the semi-
automatic switchover design.
16.
The licensee submitted a LCR on April 25, 1997 to clarify TS 3.5.2 regarding
hot leg injection flow paths required for Modes 1 through 3 .
I
17.
17
The licensee obtained a revised RHR pump curve that expands the NPSH
curve to 5500 gpm confirming the extrapolation performed by Westinghouse
was accurate. The inspector reviewed the revised pump curve and
determined that the revised curve supported the previous extrapolated
values.
The inspector considered the licensee's completed corrective actions acceptable to support
Salem Unit 2 restart.
IV. Plant Support
R 1
Radiological Protection and Chemistry (RP&C) Controls
R 1 . 1
Meteorological Monitoring Program (MMP)
a.
Inspection Scope (84750)
b.
)
The MMP was inspected against Sections 2.3.3.2 and 7.7.1.13 of Salem UFSAR
and Sections 2.3.3 and 7. 7 .1.11 of Hope Creek UFSAR. The following activities
were conducted to assess the licensee's ability to implement the program.
Review of calibration procedures, calibration results, and channel check logs;
Review of calibration results of individual sensors;
Discussion of data acquisition and availability of data;
Observation of the material condition of meteorological equipment; and
Reviewed status of the meteorological monitoring facility drawings.
Observations and Findings
The inspector observed the contractor, J. Healy Co., perform the quarterly
calibration of the meteorological monitoring instrumentation. The inspector noted
that the licensee performed the calibrations according to the implementing
procedures. The licensee does not submit the wind speed sensors to a wind tunnel
test. The licensee relies on the contractor's knowledge and experience to ensure
the sensors are performing properly. Every quarter, the contractor performs a visual
check for cup damage and performs shaft alignment tests at the logic board from -
the sensor, zero and span checks are performed, and known signals generated by a
calibrated Fluke digital voltmeter are traced through the loop and the bearings are
replaced semi-annually to assure the low starting speed threshold is met. The
results of this calibration were within the acceptance criteria. The inspector
reviewed calibration data from 1995 to 1997. The calibrations were performed
quarterly, checks were performed monthly, and the results were within the
acceptance criteria as required by the procedure ND.RS-SC.MET-1201 (Q) Rev. 3,
18
Artificial Island Meteorological Monitoring Program Calibration and Maintenance
Procedure.
The inspector reviewed the UFSAR for Salem and Hope Creek and the
meteorological administrative procedure. Hope Creek received approval from the
NRC to transfer the meteorological program requirements from the TS to the Hope
Creek UFSAR on September 25, 1996. Administrative procedure ND.RS-AP.MET-
1201 (Q), Artificial Island Meteorological Monitoring Program Administrative
Procedure, dated July 1995 had not been changed to reflect the transfer. In
response, the licensee initiated actions to update the administrative procedure.
The inspector reviewed the status of thirty one (31) meteorological monitoring
facility drawings and noted that the drawings were in the process of revision. The
31 drawings consisted of electrical, mechanical, piping, and instrument drawings.
The inspector noted that the licensee had not taken action to complete a design
change package (DCP 1AE-1075) relative to making corrections (red-line) to the
drawings since the DCP had been initiated. The DCP had been initiated in 1994 in
response to an action request opened during the 1 993 quality assurance audit. The
1993 audit identified deficiencies in 31 meteorological monitoring facility drawings.
The 1995 quality assurance audit identified, during follow up of corrective actions
relative to the 1993 action request, that DCP 1EA-1075 had not been completed
and that no action had been taken by the responsible department. Another action
request was opened and the auditor received a completion commitment date of
November 15, 1995. The inspector noted, as of May 16, 1997, that DCP 1 EA-
1075 had remained open, the revised drawings were not validated, and were not
considered controlled drawings. The inspector discussed this issue with the auditor
and Technical Services and noted that no action had been taken to complete the
DCP. The licensee representatives stated that they planned to review the drawings
and the current configuration applicable to the drawings to ensure the current
revisions are correct, make further revisions if necessary, and complete the DCP
after the restart of the Salem Unit 2.
The inspector noted that these drawings may not be related to the safety of the
plants, but have been used on at least two occasions to make repairs to the tower
(i.e., a power transmitter relay and an inverter). Notwithstanding, without
controlled drawings in place, potential exists for improper or inadequate repair,
modification, or design change to components and systems that affect the
meteorological monitoring program.
Based on the above findings, the inspector determined that completion of the DCP
was not timely and that this matter represented a weakness in the licensee's ability
to effect timely corrective action for self-identified deficiencies. This matter is
considered an unresolved item pending review of the licensee's process and
procedures for maintaining control of configuration and design relative to this
matter. (URI 50-272197-12-01;50-311197-12-01;AND 50-354197-03-02)
T
,.
c.
19
Conclusions
Based on the direct observations, discussions with personnel, and examination of
procedures and records for calibration of equipment, the inspector .determined that,
overall, the licensee's performance of maintaining and calibrating the meteorological
monitoring instrumentation was very good. The data were available as required and
were easily accessed from several locations, including the control room and the EOF
as specified in the UFSAR. The licensee's actions to complete the DCP were not
timely, and require further review.
R1 .2 * Liguid-To:..Solid Radwaste Processing
a.
Inspection Scope (86750)
b.
c.
Through review of liquid radwaste processing documents, radwaste system
walkdowns, and interviews with licensee staff, the inspector reviewed Salem
Station liquid radwaste processing and resulting solids generation with respect to
requirements.
Observations and Findings
The liquid radwaste processes as described in the UFSAR were verified. At the time
of this inspection, the licensee was completing installation of a tubular ultra filtration
unit (down to 0.01 micron particles). This equipment was designed to reduce the
radioactivity level of liquid discharges from the station. The licensee targeted
equipment startup for July 1997. The inspector questioned the method of sampling
the solid effluent from this new filtration process. The licensee indicated that they
would develop a solid radwaste sampling procedure prior to system startup, The
solids recovered by this reverse osmosis filtration equipment will be added to spent
resins and dewatered. The plant staff did not expect the additional radwaste to
increase the volume of solid radwaste generated at Salem Station, however, the
radioactivity level of the solid radwaste should increase, while returning cleaner
water to the Delaware River. The solid radwaste burial volume for Salem Station for
1996 was 1633 cubic feet, down from 2083 cubic feet in 1995.
Conclusions
The licensee is installing an ultra filtration to improve the quality of liquid effluent
discharges from the station without any expected increase in solid radwaste burial
volumes. This is an excellent radwaste system improvement .
' .
20
R2
Status of RP&C facilities and Equipment
R2.1
Onsite Radwaste Storage
a.
Inspection Scope (86750)
The inspector reviewed the condition and radwaste storage inventory of the low
level radwaste storage facility (LLRWSF).
b.
Observations and Findings
c.
The inspector noted an accumulation of 24, 200 cubic foot resin liners being stored
in the LLRWSF. However, this material came from Hope Creek Station and Salem
Station generated none of the solid radwaste materi~I. The inspector reviewed
records indicating plant staff had performed quarterly surveillances of the resin
liners as specified by procedures. The inspector reviewed a video tape of the latest
LLRWSF vault inspection performed by robot on May 30, 1997. Although the
inspector considered this method of surveillance an excellent approach, it may
require some enhancements. The enhancements may include different placement of
resin liners to allow an access path for the robot to perform complete vault
inspections and adjustment to the camera arm to allow viewing into the drainage
trench located inside the vault area. Review of the robot surveillance indicated no
deterioration of the resin liners stored in the facility .
Conclusions
The inspector noted that the RP technicians properly locked and controlled the
LLRWSF, met required facility surveillances, and the radiation levels associated
with the LLRWSF were well below regulatory requirements.
R2.2
Radwaste Equipment
a.
Inspection Scope (86750)
b.
The inspector reviewed the status of formerly utilized radwaste processing
equipment for safe long-term lay up. This review was made with reference to the
US FAR and interviews with licensee staff. The inspector verified of equipment
status through observations in the plant.
Observations and Findings
The Unit 1 waste evaporator was shutdown in 1983 after approximately one year of
use. Through a site-glass, the inspector verified that this equipment was drained.
The Unit 2 waste evaporator was never connected to the plant liquid waste systems
and never used. The two Unit 1 waste monitor tanks were drained with lower
manways ajar. The two Unit 2 waste monitor tanks were tagged-out and these
tanks were verified to be empty .
21
c.
Conclusions
The inspector verified that all of the laid-up solid radwaste processing equipment
was properly drained and laid-up for long-term storage.
R3
RP&C Procedures and Documentation
R3.1
RadwasteCTransportation Procedures
a.
Inspection Scope (Tl 133)
Due to a major revision of Title 49 CFR 171-178 effective April 1, 1996, a
comprehensive procedure review was conducted at the Salem Nuclear Generating
Station.
b.
Observations and Findings
The inspector reviewed the following procedures:
Salem Process Control Program, Rev. 2
Salem TUF Process System Operating Procedure, SALEM-TUF-01, Rev. 1
Salem TUF Cleaning Procedure, SALEM_TUF-02, Rev. 0
Shipment of Radioactive Materials Excluding Waste for Burial, NC.RP-RW .zz-
0909(0), Rev. 1
Shipment of Radioactive Waste for Burial, NC.RP-RW.ZZ-0906(0), Rev. 1
Shipment and Receipt of Laundry, NC.RP-Tl.ZZ-091 5 (0), Rev. 2
Radioactive Waste Packaging, SC.RP-RW.ZZ-0806(0), Rev. O
Sluicing of Spent Resins to a Shipping Container, SC.RP-RW.ZZ-0807(0), Rev. 0
Radioactive Waste Sampling and Classification, SC.RP-RW.ZZ-0902(0), Rev. 0
Use of the Radwaste Computer Code, SC.RP-RW.ZZ-0903(0), Rev. 1
Doserate to Curie Conversion Calculations, SC.RP-RW.ZZ-0904(0), Rev. 0
Use, Dewatering, and Handling of CNS/ 14-215 or Smaller Liners, SC.RP-RW.ZZ-
0908(0), Rev. 0
Use of the 14-210or 14-215Radioactive Materials Shipping Package, SC.RP-
RW.ZZ-0911 (0), Rev. 1
Laundry Shipment Preparation, SC.RP-RW.ZZ-0913(0); Rev. 0
The Process Control Program did not specify the regulatory and burial license waste
processing parameters and criteria. _Although the implementing radwaste
dewatering procedures provided appropriate methods, these procedures were not
defined as part of the Process Control Program and did not reference the regulations
and burial license requirements that they were designed to meet. Most of the above
procedures were not affected by the revision in the DOT regulations. Procedure
errors were minor and were discussed with the licensee during a detailed inspection
debrief. One exception was procedure NC.RP-Tl.ZZ-0915(0), Rev. 2, "Shipment
and Receipt of Laundry." This procedure did not include the new requirement to
classify LSA shipments as LSA-1, LSA-11, or LSA-111. In addition, dose conversion
factors were poorly documented and referenced.
22
c.
Conclusions
Radwaste transportation procedures were generally adequate, and revised DOT
regulations were effectively represented. The Process Control Program and
implementing procedures should be enhanced to ensure waste form processing
parameters are consistently and properly controlled.
R4
Staff Knowledge and Performance in RP&C
R4. 1
Radwaste Sampling and Characterization
b.
Observations and Findings
The inspector verified that the transport characterization tables (A 1 /A2 values) had
been updated to reflect current regulations.
Four solid radioactive waste streams (CVCS resin, radwaste resin, filters, and dry
active waste) were properly sampled and subsequently characterized by an outside
radiochemical laboratory between September 1995 and May 1996. These waste
stream characterizations were appropriately applied to each waste shipment to
account for non-gamma emitting radionuclides, while using direct waste shipment *
sample gamma spectral analyses for reporting radioactivity of the gamma emitters.
c.
Conclusions
R4.2
b.
The waste stream characterizations were timely and appropriately utilized by the
licensee to report radionuclide activities of each radioactive material/waste shipment
during the 1996 - May 1997 timeframe.
Radioactive Material Shipping Documentation Review
Observations and Findings
The inspector reviewed selected radioactive material shipping records since April 1,
1996. The shipping papers were well documented, included an independent QC
inspection review (for all but excepted quantity shipments), and all consignee
licenses and shipping cask certificates of compliance were on file as required. The
inspector noted that all shipment records except contaminated laundry shipment
records were printed using the Radman computer code. These shipping records
were found to be complete and accurate. The contaminated laundry shipping
records were produced manually in-accordance with procedure NC.RP-Tl.ZZ-
0915(0), Rev. 2, and these shipping records, failed to correctly specify the LSA
group specification on any of the laundry shipments since April 1, 1996, as required
by 49CFR172.203(d)(11 ). Examples include: Salem shipment Nos.97-108, 97-103, and 97-101. This is a violation of regulatory requirements (VIO 50-272&
311/97-12-03). The inspector also noted that the dose conversion factors used to
determine radioactivity content of the laundry shipments were not included in the
ship.ping papers nor was the date of derivation of these conversion factors.
23
c.
Conclusions
The inspector's review of selected radioactive material shipments made during
April 1996-1997 indicated that the shipments met regulatory requirements, except
for the laundry shipments which resulted in a violation.
RS
Staff Training and Qualification in RP&C
R5.1
Radwaste Transportation Training for Shippers and RP Technicians
b.
Observations and Findings
The Salem Station authorized radioactive material shippers, and QA personnel
attended a week-long regulations training course in February of 1995 which fulfilled
regulatory training requirements. In addition, in January 1996, a one day revised
shipping regulations update workshop was well attended by PSE&G RP and QA
personnel. The RP technicians were also provided a radioactive material shipping
training course during continuing RP technician training during the 3rd and 4th
quarters of 1996. Currently, the Services Group is planning for another week-long
regulations training course to be held during the summer of 1997.
c.
Conclusions
The licensee met the training requirements for radioactive material shippers and RP
technicians.
R7
Quality Assurance in RP&C Activities
b.
Observations and Findings
c.
The licensee conducted a radioactive material control audit between July 22, 1996
and August 13, 1996. The audit included shipping activities from both Salem and
Hope Creek Stations, included offsite technical expertise and appeared to be a
thorough program review. However, the audit tailed to identify the inadequacies in
the laundry shipment procedure. The QC organization continues to be active in
independently verifying all radioactive material shipments, except for the excepted
quantity shipments, to ensure regulatory requirements are met.
QA audits of radwaste processing vendors were inconsistently performed with
regard to NRC Bulletin 79-19 which directs licensees to establish and implement a
management controlled audit function of all transfers, packaging and transport
activities.
Conclusions
The licensee's audit program for the radwaste/transportation program was found to
be adequate. The licensee stated that the vendor audit program for this program
area would be reevaluated and modified as required.
1
. 24
RS
Miscellaneous RP&C Issues
RB.1 * Updated Final Safety Analysis Report (UFSARl
a.
Inspection Scope
The inspector reviewed current Salem Station practices with respect to
Sections 11.2 and 11.5 of the UFSAR.
c.
Conclusions
The UFSAR description of solid radwaste processing was accurate and correctly
reflected current plant operations.
F1
Control of Fire Protection Activities
F1 .1
Fire Barrier Compensatory Measures, NRC Restart Inspection Item 111.1 (Closed)
a.
Inspection Scope
The inspector reviewed the interim compensatory measures implemented in
response to the cable tray fire barrier wrap performance issues discussed in NRC
Inspection Report 50-272&311 /97-09. PSE&G described their compensatory
measures for the cable tray fire barrier wrap performance issues in a letter to the
NRC dated May 19, 1997. The primary compensatory measures consisted of hourly
roving fire watches in the affected areas.
b.
Observations and Findings
The inspector toured the affected areas with the assigned fire watches and
observed that the fire watches appeared knowledgeable regarding their duties, and
also noted that the licensee gave the fire watches written job instructions. The fire
watches toured the areas specified and documented their tours on round sheets.
The inspector reviewed the round sheets and noted that the fire watches satisfied
the one hour tour requirement.
The inspector noted a minor deficiency in that the fire watches could not inspect
the conditions inside the 21 waste holdup tank room due to radiological conditions.
The Loss Prevention Supervisor indicated that additional compensatory measures for
this area including: verification that the room was free of combustible material, and
that the room had operable smoke detection devices. The Loss Prevention
Supervisor implemented an additional measure by installing remote cameras in the
room. The inspector determined the compensatory measures for this room
adequate.
The inspector compared the areas listed on the round sheets to the fire wrapped
cable, conduit, and cable tray inspection locations listed in surveillance procedure,
S2.FP-SV-005, Revision 0. The inspector determined that the round sheets were
adequate to ensure that the proper cable tray locations were inspected.
c
25
c.
Conclusions
The licensee implemented adequate measures to monitor the areas affected by the
cable tray fire wrap concerns documented in NRC Inspection Report 50-
272&311 /97-09. In addition, as documented in NRC Inspection Report 50-
272&311 /97-09, the inspectors concluded that the licensee had completed
adequate corrective actions for alternative post-fire safe shutdown MOVs. Based
on these observations, the inspectors considered the licensee's corrective actions
adequate to support Salem Unit 2 restart.
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 June 26, 1997. 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.
X2
ManaQement Meeting Summary
On May 30, the Honorable Frank Lobiondo, Representative to the U.S Congress from the
second congressional district of New Jersey, toured the Salem facility. Mr. H. Miller,
Regional Administrator accompanied Representative Lobiondo during the visit.
Representative Lobiondo and Mr. Miller met with senior PSE&G management to discuss
Salem Unit 2 preparations for restart.
On June 13, representatives of the GAO toured the Salem facility and met with PSE&G
managers. Mr. J. Linville, Chief, Division of Reactor Projects Branch 3, Region I,
accomp~nied the GAO representatives on their tour.
On June 19, Mr. H. Miller, Regional Administrator, Region I, Mr. J. Zwolinski, Deputy
Director, Division of Reactor Projects-I/II, NRR, Mr. C. Hehl, Director, Division of Reactor
Projects, Region I, and Mr. J. Linville, Chief, Projects Branch 3, DRP, Region I, visited the
Salem site. They toured the facility and held discussions with plant personnel at all levels
to assess Salem Unit 2 readiness for restart. The NRC managers met with senior PSE&G
managers at the conclusion of the visit to provide their observations.
..
~
..
26
INSPECTION PROCEDURES USED
IP 50001:
IP 61726:
Steam Generator Replacement Inspection
Surveillance Observations
IP 62707:
Maintenance Observations
IP 71707:
Plant Operations
IP 84750:
Radioactive Waste Treatment, and Effluent and Environmental Monitoring
Opened
50-272&311/97-12-01
50-272&311 /97-12-02
50-272&311 /97-12-03
50-272&311/97-12-04
Closed
50-272/96-026
50-272/96-031
50-311.94-015
Discussed
50-272/97-009
ITEMS OPENED, CLOSED, AND DISCUSSED
procedures for maintaining control of configuration and
design
configuration control deficiencies 1 0 CFR 50 Appendix
B
minor procedure deficiences
Failure to include current LSA group specification (LSA-
1,11,or Ill) on all laundry shipping papers since April 1,
1996.
LER
inadequate testing of RHR hot leg flow path
LER
plant in unanalyzed condition due to qualification of
Magnacraft-Struthers Dunn Series 8255 relays
LER
waste gas holdup tank not samples in accordance with
LER
ECCS outside of the plant design basis
..
.~
.
CRs
cs
EMIS
ISi
LLRWSF
MMP
NRC
Nsss*
PSE&G
RP&C
SERT
SS Cs
TRIS
TS
VIB
27
LIST OF ACRONYMS USED
Action Request
Balance of Plant
Condition Reports
U.S. Department of Transportation
Design Change Packages
Equipment Malfunction Information System
lnservice Inspection
License Change Request
Low level radioactive waste storage facility
Loss of Coolant Accident
Meteorological Monitoring Program
Nuclear Regulatory Commission
Nuclear Steam Supply System
Public Document Room
Public Service Electric and Gas
Post Weld Heat Treatment
Radiation protection
Radiological Protection and Chemistry Controls
Safety Evaluation
Safety Evaluation Report
Salem Engineering Review Team
Steam Generator Replacement Project
Structures, Systems, and Components
Tagging Request and Inquiry System
Technical Specification
Updated Final Safety Analysis Report
Ultrasonic
Vital Instrument Bus