ML18102A347
| ML18102A347 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 08/26/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18102A345 | List: |
| References | |
| 50-272-96-08, 50-272-96-8, 50-311-96-08, 50-311-96-8, NUDOCS 9609030374 | |
| Download: ML18102A347 (39) | |
See also: IR 05000272/1996008
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
50-272/96-08, 50-311 /96-08
Public Service Electric and Ga::, Company
Salem Nuclear Generating Station, Units 1 & 2
P.O. Box 236
Hancocks Bridge, New Jersey 08038
June 30, 1996 - August 10, 1996
C. S. Marschall, Senior Resident Inspector
J. G. Schoppy, Resident Inspector
T. H. Fish, Resident Inspector
R. A. Rasmussen, Resident Inspector
S. T. Barr, Operations Engineer
E. H. Gray, Technical. Assistant, Division of Reactor Safety
Larry E. Nicholson, Chief, Projects Branch 3
Division of Reactor Projects
9609030374 960826
ADOCK 05000272
G
...
EXECUTIVE SUMMARY
Salem Nuclear Generating Station
NRC Inspection Report 50-272/96-08, 50-311 /96-08
diis integrated inspection included aspects of licensee operations, engineering,
maintenance, and plant support. The report covers a 6-week period of resident inspection.
Operations
Operators continued to demonstrate increased ownership for the plant. For example, the
Senior Nuclear Shift Supervisors (SNSS) continued to provide focus on safety at the
General Manager's morning meeting. In addition, senior operations staff klentif_ied less
than adequate material conditions and pursued resolution of the conditions. Control room
opera~ors demonstrated significantly improved plant knowledge. In one case, however, the_
control room operators did not understand the design function of a service water common
header pressure control valve. The operations staff readily accepted observations
concerning areas for improvement, and took a leading role in holding the entire Salem staff
to high standards. Senior Salem managers also demonstrated the ability to perform and .
act on candid self-assessment. For example, they concluded that the maintenance staff
continued to produce poor quality results. As a result, the managers extended the Salem
Unit 2 outage schedule to the end of 1996, shifted the focus of outage activities to
restoring equipment (rather than meeting deadlines), and initiated a major effort to obtain
significant improvem~nt in the performance of all Salem maintenance personnel. In
addition, the Salem General Manager reduced the number of weekly meetings to allow
increased manager time for field observations, reorganized the work control and
maintenance organizations to provide improved leadership, and increased the focus on .
safety and quality during morning meetings. Through their actions, the Salem managers
demonstrated determination to address and resolve work control and maintenance related
equipment and staff performance deficiencies. (Sections 01.1 and 04.1 l
The Operations staff continued, however, to evidence weak performance in some areas.
For example, operators failed to update the Salem Tagging Request Inquiry System, a
database used to control and monitor valve and breaker positions. As a result, inspectors
and plant staff found service water valves out of their expected positions. In one case, the
mis-positioned valves could have resulted in damage to a safety-related pump.
Significantly improved vigilance by an operator, technician, and system engineer prevented
damage to the pump. Operators did not demonstrate consistently appropriate response to
the potential that mis-positioned valves resulted from tampering. In one case, operators
did not act on the possibility of tampering until the inspectors questioned their actions. In
a second case, the Nuclear Shift Supervisor and the Senior Nuclear Shift Supervisor SNSS
immediately recognized the potential for tampering and took prompt and appropriate action.
(Section 01.2)
ii
.*
..
Salem significantly improved the operability determination process through recent
revisions. Inspectors found m_inor *weaknesses, and determined that operations and system
engineering had not completed training on their respective processes (Section 02.1 ).
On
two *Jccasions, operators did not consider the possjbility that identified equipment failures
could apply to similar plant equipment. In one of these cases, operators did not question
the generic applicability for a failure of a safety-related auxiliary oil pump supplying a
chargin~ pump. As a result, they did not prevent a second failure when subsequently
another charging pump (Section 02.2).
Inspectors continued to identify weaknesses in operating procedures. The procedures did
not contain information needed to protect plant equipment and personnel. F\\ ;;.cedure
weaknesses allowed a service water pressure perturbation, and could have permitted
residual heat removal pump vortexing, potential injury to maintenance personnel, and a
potential reactor vessel overpressurization. Operations management initiated actions to
strengthen these procedures (Section 03.1 ).
The Emergency Operating Procedure (EOP) Group recognized the problems that existed in
the former set of EOPs, implemented an effective process to resolve those problems, and
produced a set of significantly improved EOPs and bases. PSE&G had not completed
operator training on the new EOPs or implemented EOP maintenance tools in order to
maintain the EOPs at this high level of quality (Section 03.2). _The.Salem training staff
significantly improved the training programs through implementation of the Salem Training
Restart Action Plan. The PSE&G staff made significant improvements in training program
self-assessments and line management involvement in the training programs (Section
05.1 ).
.
.
.
The Management Review Committee (MRC) did not consistently inS?ure closure packages
for identified technical and programmatic concerns demonstrated that plant staff had
completed essential corrective actions. (Section 07.2). For example~ plant staff had not
completed the corrective actions for the Salem Unit 2 trip of June 7, 1995, and the MRC
did not identify the lack of evidence of corrective action (Section 07.1 ).
Maintenance
Ineffective maintenance frequently resulted in rework. * As a result, Nuclear Business Unit
and Salem senior management planned to test the maintenance staff to determine the
areas of training weakness and conduct retraining. The intervention, schedule to occur
offsite beginning in September, will require that qualified contractors perform maintenance
during the PSE&G maintenance staff requalification process (Section M1 .2).
In addition to ineffective maintenance, inspectors and plant staff found other problems
with the performance of maintenance. For example, although PSE&G has improved the
Foreign Material Exclusion (FME) program, significant problems continue to exist with
implementation of .the program. (Section M2.1) Inspectors identified one technician failure
to perform a required post-maintenance test (PMT) on safety-related valves, and a second
example revealed itself. (Section M4.1) In addition, the Operations staff identified
iii
numerous deficiencies with the planning, scheduling and performance of PMTs. The senior
Nuclear Business Unit managers and the inspectors independently identified that plant staff
and contractors have not kept Salem clean. The inspectors identified that workers did not
comply with requirements for storage of safety-related materials. The managers promptly
took measures to clean the plant, dispose of the poorly controlled materials, and emphasize
their expectations for housekeeping and material controls (Section M7 .1).
Engineering
An independent assessment conducted by the Salem Integrated Readiness Assessment
team concluded that, in general, Engineering appeared on the right track to support restart
in a safe manner. Inspectors noted that, in one case, the Engineering staff appeared
reluctant to document performance problems using the Corrective Action Program.
Although the team identified four examples of inadequate engineering performance, the
engineering staff did not initiate a Condition Resolution, as required, until questioned by an
inspector. (Section E7. 1 ) . Engineering staff did not demonstrate strong ownership for
plant systems in some cases. Although they provided a detailed list of recommendations
for laying up various systems and components they did not actively identify and resolve
deviations from their recommendations (Section E8.4).
Engineering took adequate corrective action to address a number of NRC restart inspection
items, including the 21RH10 valve (Section E2.1), and the information provided in the
PSE&G response regarding potential for Control Rod Drive Mechanism penetration cracking
(Section E8.1 ). In some cases, such as safety injection pumps and closure of the main
steam isolation valves, effectiveness of the corrective actions remains open until plant staff
can test the corrective measures (Sections E2.2 and E2.3).
iv
TABLE OF CONTENTS
EXECUTIVE SUMMARY
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TABLE OF CONTENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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I. Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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II. Maintenance
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Ill. Engineering
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V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
32
v
Report Details
Summary of Plant Status
Unit 1 and Unit 2 remained defueled for the duration of the inspection 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. Operators continued to demonstrate increased ownership
for the plant. For example, the Senior Nuclear Shift Supervisors (SNSS) continued .
to provide focus on safety at the General Manager's morning meeting. In addition,
senior operations staff identified less than adequate material conditions and pursued
resolution of the conditions. Control room operators demonstrated significantly
improved plant knowledge. The operations staff generally seemed to accept
observations concerning areas for improvement more readily, and took a leading role
in holding the entire Salem staff to high standards. Senior Salem managers also
demonstrated the ability to perform and act on candid self-assessment. For
example, they concluded that the maintenance staff continued to produce poor
quality results. As a result, the managers extended the Salem Unit 2 outage
schedule to the end of 1996, shifted the focus of outage activities to restoring
equipme.nt (rather than meeting deadlines), and initiated a major effort to obtain
significant improvement in the performance of all Salem maintenance personnel. In
addition, the Salem General Manager reduced the number of weekly meetings to
allow increased manager time for field observations, reorganized the work control
and maintenance organizations to provide improved leadership, and increased the
focus on safety and quality during morning meetings. Through their actions, the
Salem managers demonstrated determination to address and resolve equipment and
staff performance deficiencies.
01.2 Operator Control of Safety-related Equipment
a.
- Inspection Scope (71707)
The inspectors toured accessible plant areas to assess plant and equipment
conditions. Inspectors discussed plant configuration control with Operations
management, operating shifts, and Security personnel.
b.
Observations and Findings
On July 18, 1996, the inspector discovered 21SW161, a normally closed and
locked valve, open and unlocked; The 21SW161 valve provides an emergency
service water (SW) supply to the auxiliary feedwater (AFW) system. The Tagging
Request Inquiry System (TRIS) listed the 21SW161 as closed and locked. The
2
operating shift promptly closed and locked the valve, however, they did not
. immediately react to the possibility of tampering until the inspector contacted the
Operations Manager. The operating shift subsequently determined that an operator,
on an approved work order, repositioned the valve on July 15. The operator failed
to update TRIS in accordance with management expectations. Poor communication
between Operations and Maintenance contributed to <?Perators maintaining the
21SW161 in the abnormal position after maintenance technicians completed work
on July 15. There was no safety consequence to this lack of configuration control
due to plant condition (no other applicable SW or AFW work).
On July 19, an equipment operator discovered a normally chained and locked 18-
foot step ladder removed from its designated position. Operators needed the ladder
to align temporary air compressors to provide a backup air supply. The operating
shift did not respond to evaluate potential tampering until the inspector contacted
the Operations Manager. The Operations Mariager initiated a condition report and
night order book entry identifying Operations' insensitivity to potential malicious
tampering. The Operations staff drafted a "Response to Potential Tampering"
procedure to provide guidance in* this area.
In addition, while running no. 22 safety injection pump maintenance* retest on
August 8, workers found 2SW162 and 2SW181 closed. Operators expected to find
the valves, used to isolate service water to the lube oil cooler, in their normally
locked open position. The equipment operator began to reopen the valves,
however, when the shift supervisor learned of the mis-positioned valves he
terminated the pump test, directed operators to quarantine the area, and requested
security to help determine the cause of the mis-positioned valves. The Senior
Nuclear Shift Supervisor (SNSS) also notified plant managers, the Hope Creek_
SNSS, and the inspectors. Later that day, Operations staff determined that on July
31, an operator releasing a safety tags had opened the valves, as directed by the .
release order. He identified a service water leak and appropriately shut the valves.
The inspector verified that the operator also marked the release documents, as
required, to indicate that he left the .valves in an abnormal condition due to the
service water leak. The inspector verified that the independent verification also
. documented that the operator left the valves in an abnormal condition (closed). The
- operations staff concluded that plant staff had not accurately updated the TRIS to
reflect the actual valve positions after the manipulations on July 31 . Procedure
SC.OP-DD.ZZ-0008(0), TRIS Tagging Operations, Rev. 6, step 2.1.7.C. requires
that operators sign and date that T.RIS has been updated on the Tagging Request
Worksheet. Failure to update TRIS is a violation (VIO 50-272&311 /96-08-01 ).
The inspectors observed that vigilance by plant staff during the pump run prevented
damage to the safety injection (SI) pump. Failure to update TRIS, however, resulted
in unnecessarily risking damage to the pump.
The inspectors noted that the Salem unit 2 nuclear shift supervisor and the SNSS
promptly identified that mis-positioned valves represented a potential indication of
tampering. They took prompt, aggressive, action to determine the cause, while
simultaneously verifying that other systems did not have indications of tampering.
3
They also appropriately notified Hope Creek. The Hope Creek staff, however, did
not demonstrate appropriate sensitivity to the potential for tampering, and took no
action other than to mention the Salem problem to Hope Creek staff during morning
meetings.
c.
Conclusions
Operations staff failed to update the Salem TRIS. As a result, an inspector found
one service water valve out of its expected position and operators foung two
'
_,
additional valves out of position during a safety injection pump test. In the latter
case, the mis-pt1~;tioned valves risked damage to ~he no. 22 safety injection pump ..
In the first instance, operators did not respond to the potential for tampering until
questioned by the inspectors. In the last instance, the Salem Unit 2 Nuclear Shift
Supervisor and the Senior Nuclear Shift Supervisor placed the pump in a safe
condition and took immediate action in response to the potential for tampering.
02
Operational Status of Facilities and Equipment
02.1
Review of Operability Determinations, NRC Restart Item 111.6 (Open)
a.
Inspection Scope (71707)
The inspectors performed a review of PSE&G's methodology for assessing the
operability of degraded or nonconforming structures, systems and components and
how these issues were tracked through resolution. This effort included an
evaluation of current programmatic guidance and a sampling of "active" operability
determinations (OD), as well as an assessment of a recently completed safety
review group audit of the OD process.
b.
Observations and Findings
Based on a review of NRC inspection reports issued for Salem in the last two years,
the inspectors noted several prevalent themes regarding the performance of OD's.
Specifically, there has been:
- *
a lack of clear guidance for performing operability evaluations
weak documentation of the technical bases of operability
a weak review and approval process
- inadequate training for operators and supervisors
weak engineering department support
The inspectors noted that PS.E&G management has acknowledged each of these
deficiencies, and has taken several steps to address and resolve them.
Of primary *significance was the .development of clear procedural guidance that
systematically guides the implementation of the OD process. The inspectors
reviewed the applicable procedures (SC.OP-AP.ZZ-0006 (0) revision 2, "Operability
Determination" and SC.SE.AP.ZZ-0001 (Q) revision 0, "Follow-up Operability
4
Assessment") in detail and judged that they adequately addressed the above noted
prior performance concerns. Specifically, these documents strictly define what an
OD is, how orie is made, where it is documented, and what compensatory
measures are necessary. Further, the procedures mandate added levels of
concurrence, including *a Station Operations Review Committee (SORC) review
within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of making an OD. Finally, clear standards are provided for when an
OD can be considered resolved.
Despite these programmatic improven;ients, the inspectors determined that the new
guidance did not require an evaluation of the generic applicability of identified
degraded or nonconforming conditions* to similar plant or opposite unit components,
a feature that had appeared in earlier versions of the OD procedure. The inspectors
also noted that, though the new OD process requires a monthly audit to ensure (in
part) that the aggregate effect of open OD's has not caused a system to become
inoperable, no documentation of previous audits was available for review and no
standard for aggregate impact assessment is provided.
In addition, the inspectors learned that the operations department was employing an
informal software database tracking system for managing "inactive" OD's (i.e.
degraded or nonconforming equipment not required in ttie current plant operating
mode), a process which was not governed by either of the controlled OD
procedures. This process was developed to reduce the number of OD's shift
personnel were forced to manage, as well as to code each of them with their
technical specification operational mode applicability to ensure that they would be
"re-activated" prior to plant entry into a mode in which the associated equipment
was required. While the stated basis appeared to be sound, the inspectors judged
that the operations department's use of an uncontrolled OD management process *
increased the potential for error. in monitoring the existing backlog and tracking
- individual items to closure.
The inspectors reviewed a sample of six of the seventeen "active" OD's listec:l in the
operating shift's log book. Of those reviewed, the documented technical bases
appeared to adequately support a conclusion of "operable but degraded." Further,
the inspectors verified that OD-required compensatory measures were being
properly implemented. However, of these six OD's, two qualified for immediate
closure under the SC.OP-AP.ZZ-0006 procedure (95-080,95-140), and three*
qualified for transfer to "inactive" status under the informal program described
above .(95-043,95-128, 95-140). Additionally, one OD (96-001) included
inconsistent guidance for required compensatory actions and another (95-080) had
incomplete documentation to support the OD. Finally, PSE&G's most recent OD
performance indicator listed nineteen outstanding issues, two greater than tracked
in the operations department active log. Collectively these discrepancies indicated .a
lack of rigor in implementing programmatic controls.
On May 23, 1996, the Salem safety review group (SRG) completed an assessment
of the OD process. In their report, the SRG concluded that while OD programmatic
controls were capable of supporting station restart, further management attention
was necessary to ensure that implementation of program requirements would be.
c.
5
effective. The inspectors generally concurred with the SRG report findings,
especially with regard to a noted weakness in OD and follow-up review. training for
plant operators and system engineers. The inspectors learned that most operators
have received training on the newly revised OD process, but have not had recent
"performance-based" training on how to evaluate degraded conditions in order to
establish system operability. Additionally, no training had yet been conducted for
system engineering personnel regarding the expectations of the newly issued
SC.SE-AP.ZZ-0001 procedure for OD follow-up assessments.
Conclusions
PSE&G's recently revised operability determination process provides clear guidance
for documenting and tracking the operability of degraded or nonconforming
systems, structures and components, and adds additional levels of station review to
ensure that associated technical bases and compensatory measures adequately
support a conclusion of "operable but degraded." However, management of
"inactive" operability determinations, while technically adequate, lacked formal
procedural controls and increased the potential for tracking* errors. The
documentation associated with several "active" operability determinations did not
consistently implement established guidance.
Additionally, plant operators and
system engineers had not received recent training on how to appropriately evaluate
degraded and non-conforming conditions.
02.2
Equipment Status Awareness
a.
Inspection Scope (71707), NRC Restart Item Ill. 7 (Open)
The inspector performed control room walkdowns and operator log reviews to
assess availability and operability of plant equipment.
b.
Observations and Findings
On August 1, 1996, Unit 2 operators noted that the auxiliary oil pump for no. 21
centrifugal charging (CVC) pump did not start iri auto as required (CR 960801362)~
Operators placed the auxiliary oil pump in manual run. On August 2, Unit 2
operators noted that the auxiliary oil pump .for no. 22 CVC pump did not start in
auto as required (96082073). The operating shift did not consider the potential for
common mode failure until the inspector noted the auxiliary oil pump failures.
Operation of the no. 22 CVC auxiliary oil pump in auto without an understanding of
the failure of no. 21 eve auxiliary oil pump represented a lack of questioning
attitude on part of the operating shift. The system manager stated that operation
without the auxiliary oil pump increased bearing wear, but did not threaten pump
operability.
- In the early morning hours of August 2, 21 SW21, a diesel generator service water
- header supply valve, failed to stroke from the control room during a planned post
maintenance test (PMT). (See section 4.1) At 5:47 a.m., Unit 2 operators
discovered that 2SJ68, safety injection minimum flow valve, could not be opened
c.
6
from the control console. (See section 4. 1) The operating shift did not consider the
potential for common cause failure of the motor operated valves until the inspector
noted the degraded condition during a morning control room walkdown. Both
valves have common 230 VAC, 28 VDC, and 125 VDC power supplies. Failure to
question potential common mode failures of safety-related valves represents a lack
of questioning attitude on part of the operating shift. Instrumentation and Controls
(l&C) technicians determined that the valves failed for different mechanical reasons.
The inspector determined that maintenance's failure to perform timely PMTs applied
to both valves. (See section 4.1)
Conclusions
The operating shift failed to evaluate charging pump auxiliary oil pump and safety~
related motor *operated valve failures for potential common mode failures.
03
Operations Procedures and Documentation
03.1 * Procedure Quality, NRG Restart Item 111.3 (Open)
a.
Inspection Scope (71707)
The inspector observed plant activities and reviewed the controlling procedures to
assess procedure adequacy.
b.
Observations and Findings
.
.
.
Control* room operators* maintained Unit 2 defueled and at the mid loop position
using S2.0P-SO-CVC-0007, revision 4, Fill and Vent of CVCS. The CVC-0007
procedure did not provide water level limitations to preclude residual heat removal
. (RHR) pump vortexing. In addition, S2.0P-SO.RHR-0001, revision 4, Initiating RHR,
did not provide similar limitations. Despite the procedure weakness, all operators
interviewed knew and und_erstood RHR pump operating restrictions. The Unit's*
defueled status made this a RHR pump reliability concern and not an immediate*.
safety concerri. Operations management initiated a procedure revision for the CVC-
0007 and RHR-0001 procedures (R15102).
Unit 2 operators used S2.0P-SO.CC-0002, revision 7, 21 and 22 Component
Cooling Heat Exchanger Operation, to remove no. 21 component cooling heat
exchanger (CCHX) from service. The CC-0002 procedure did not provide specific
guidance to control this evolution resulting in a SW pressure perturbation. (See
section 04.1) Step 5.2.3 instructed the equipment operator to slowly close the
CCHX SW inlet (SW122) and SW regulating (SW127) valves. The procedure
provided no guidance on coordinating the above SW flow reduction with use of the
pressure control valves (SW308/SW311 l and the SW bypass valves (SW50s) to
preclude excessive SW pressure swings. Operations management initiated actions
to improve operator CC system training and to revise the CC-0002 procedure .
7
Unit 2 operators used S2.0P-SO.CA-0001, revision 2, Control Air System
Operation, to control realignment of SW spool pieces needed to support an
emergency control ciir compressor (ECAC) chill water outage. The CA-0001
procedure did not provide controls to protect maintenance personnel. In particular,
the procedure tagging ensured use of an ECAC breaker danger tag to protect the
ECAC, however, it did not re'iluire SW valve danger tags to protect personnel from
pressurized SW piping. Mis-operation of the closed SW valves could also result in a
SW pressure transient. Operations management initiated a procedure revision for
CA-0001 (R15078) and initiated a search for additional operation procedures with
similar safety tagging controls. On August 10, the operating shift made an on-the-
spot change to S1 .OP-SO.CA-0001 to require use of SW safety tags dl.riihg the
alignment of no. 1 ECAC SW spool pieces.
Maintenance personnel used SC.MD.FR.FH-0006, revision 9, Reactor Vessel Head
Reassembly, to reset the head under various plant conditions. The FH-0006
procedure did not provide precautions to ensure brittle fracture prevention for the
reactor vessel. Technical Specification (TS) 3.5.3 requires that a maximum of one
safety. injection pump or one centrifugal charging pump shall be operable whenever
the temperature of one or more of the reactor coolant system cold legs is less than
or equal to 31 2 degrees F and the head is on the reactor vessel. As a scheduled
reactor head lift approached, Unit 2 operators maintained one charging pump in
service and two safety injection pumps available. Although TS 3.5.3 did not apply
to Salem's undefined mode, the potential for reactor vessel over pressurization is a
vessel integrity concern. In addition, operators could use the FH-0006 procedure
under similar circumstances with fuel in the vessel. Vessel overpressurization with
fuel in the vessel presents a nuclear safety concern. Operations management
initiated actions to provide an additional barrier to vessel overpressurization.
In addition to the NRC identified examples, the operations staff identified numerous
improvements to procedures. Operations staff consistently implemented the "On-
The.:Spot Change" (OTSC) process when applicable. The shift's intolerance for poor
quality procedures improved significantly and resulted in many procedure revisions.
Operator awareness to problems with guidance "within" procedures increased,
however,, identification of needed guidance "left out" of procedures, as noted
above, remained a weakness. The absence of adequate guidance in the above
procedures is a violation (VIO 50-272 & 311/96-08-05). NRC Restart Item 111.3,
Procedure Quality, remains open pending implementation of corrective actions to
ensure adequate guidance is contained in the operating procedures.
c.
Conclusions
Several Salem procedures did not contain essential information needed to protect
plant equipment and personnel. Procedure weaknesses permitted potential RHR
pump vortexing, a SW pressure perturbation, potential injury to maintenance
personnel, and a potential reactor vessel overpressurization. Operations
management initiated actions to strengthen these procedures.
8
03.2 Adequacy of Emergency Operating Procedures, NRC Restart Item 111.15 (Closed)
a.
Inspection Scope 192903)
Emergency operating procedures (EOPs) provide operating instructions for plant
conditions requiring a reactor trip and/or safety injection actuation. EOPs
incorporate stabilization and recovery strategies for various postulated events, both
within and outside the plant .design basis, and include critical safety function
recovery strategies designed to protect the physical barriers that prevent fission
product release.
PSE&G had various Salem EOP improvement efforts underway since 1 994. New
company management reorganized these efforts into a comprehensive EOP Group in
January .1996, and that group completed the revision of all Salem EOPs, along with
the respective EOP bases, by June 1996. The inspector reviewed the EOP Group
process used to revise the Salem EOPs, several of the completed EOPs, the
performance of EOPs in the Salem simulator, and PSE&G management oversight of
the EOP program. In addition, the inspector compared the EOP program to the
requirements of the Salem UFSAR.
. b. *
Observations and Findings
The EOP Group process for improving the Salem EOPs included a detailed
comparison of each. EOP against its associated Emergency Response Guideline
(ERG). This comparison also involved a review of the ERG bases to validate the
assumptions of the ERG to ensure applicability to the Salem facility. The EOP
Group performed this review for all 41 Salem EOPs. The depth of the PSE&G effort
was indicated by their submittal of approximately two dozen direct work requests to
the vendor, Westinghouse, which proposed revisions and corrections of the generic
ERGs and their bases. In addition to the technical review of the EOPs, the EOP
program included the streamlining of individual EOP steps and the flowchart for
each EOP. Where EOP steps are common between EOPs, the program standardized
the format and language of the step to provide consistency between the EOPs .. The
EOP G; oup coordinated with PSE&G Engineering to identify all setpoints and
numerical values used in the EOPs. All values were calculated by Westinghouse
using data provided by PSE&G, appropriately placed in the EOPS, and then
consolidated into an "EOP Setpoint Document." In addition to the EOPs
themselves, the EOP Group redesigned and reformatted the Salem EOP bases
documents to ensure consistent treatment of the Salem-specific procedures when
compared. to the generic documents.
The inspector performed an in-depth review of five of the new Salem EOPs:
EOP-TRIP-1, "Reactor Trip or Safety Injection",
EOP-SGTR-1, "Steam Generator Tube Rupture",
EOP-LOCA-1, "Loss of Reactor Coolant",
EOP-LOPA-1, "Loss of All AC Power", and
EOP-FRHS-1, "Response to Loss of Secondary Heat Sink".
- ,
9
The inspector compared the new Salem procedures to the corresponding
Westinghouse ERG and the previous PSE&G revision, and analyzed the
effectiveness of the procedure to properly mitigate the intended abnormal or
accident condition. As an.additional means to determine procedure adequacy, the
inspector observed several simulator scenarios conducted with both initial operator
training candidates and previously licensed operators in requalification training.
During the observation of the use of the EOPS, the inspector identified a problem in
EOP-LOCA-1 in which the procedure had a continuous action step which instructed
the operator to not stop any ECCS pumps, yet within the next few steps the
procedure had the operator stop a residual heat removal pump. The licensee
acknowledged the inconsistency, revised the Salem EOP to remove the first
instruction as a continuous action step, and submitted an additional direct work
request to Westinghouse to* identify the inconsistency as a potential generic
concern. Other than this one inconsistency in EOP-LOCA-1, the inspector
determined that the Salem staff noticeably improved the EOPs' consistency,
accuracy and usability, and that the procedures provided the necessary steps arid
strategies for operators to respond to plant transients and accidents ..
In order to assess management oversight of the EOP program, the inspector
attended the SORC meeting for the approval of the "EOP Setpoint Document" and
the Management Review Committee (MRC) meeting for the closeout of the EOP
NRC R~start Item. The SORC acknowledged the setpoint document effort as a
good initiative and had a number of questions regarding the effect of any new
setpoints on Salem Technical Specifications and other Salem procedures. The
SORC concluded that the 1 OCFR50.59 review associated with the EOP Setpoint
Document had not adequately addressed the safety impact of the setpoint analyses
and sent the review back for revision before it would accept the new setpoint
process used to develop the new EOPs, how the new EOPs were to be maintained
accurate and consistent, and the schedule for training licensed operators on the
new EOPs. The EOP Group leader explained that all operators would receive
training on the new EOPs prior to standing watch following plant startup and that
the EOP usage guidance and maintenance documents would be completed and
approved before plant startup.* -With these assurances given, the MRC accepted the
EOP restart issue as closed. The inspector concluded that both the SORC and the
MRC showed a good questioning attitude and maintained the proper oversight role
and safety perspective while deliberating the EOP restart issue.
The Salem UFSAR has minimal requirements relating to EOPs. UFSAR Paragraph
13.5.3 requires the Salem plant manual to "include those emergency instructions,
with the exception of fire and medical emergency response procedures, necessary
to ensure that proper action is taken to handle any malfunction that may occur at
either of the Salem units." The inspector verified that the revised set of Salem
EOPs met this requirement. In addition, the inspector reviewed the 1 OCFR50.59
applicability review for EOP-FRHS-1, specifically the review and explanation of why
the procedure revision did not change a procedure as described in the UFSAR. The
inspector reviewed the description of the procedure steps used to attempt
restoration of feed flow to the steam generators. The inspector concluded that the
10
systems and setpoints described in EOP-FHRS-1 complied with the assumptions and
limits described in the Salem UFSAR ..
c.
Conclusions
Overall, the inspector concluded that the Salem EOPs were now more than
adequate; the EOP Group had recognized the problems which had existed in the
former set of EOPs, implemented a good process to resolve those problems, and
produced a very good set of EOPs and bases as a final product. The inspector
noted that PSE&G had not completed operator training on the new EOPs or
implemented the EOP maintenance tools in order to maintain the EOPs at this high
level of quality. The inspector concluded that the new Salem EOPs fully support
Salem restart; this item is closed.
04
Operator Knowledge and Performance
04.1
Awareness of Plant Conditions, NRC Restart Item Ill. 7 !Open)
a.
Inspection Scope 171707)
b.
~he inspector discussed plant configuration and plant activities with control room
operators to assess operator awareness and knowledge .
Observations and Findings
For a short period, _one SW bay supplied both nuclear headers and the cross
connected header supplied the sole source of emergency diesel generator (EDG) SW
cooling. The Unit 2 control room operator fully understood the potential to lose all
EDG SW cooling and properly evaluated. leak isolation response to preclude such a
loss.
With Unit 2 defueled, operators filled the reactor coolant system (RCS) to the
mid loop position. The control room operator maintained a good awareness *of RCS
level and the status and accuracy of available level indications. Improper RCS level
could result in reactor coolant pump (RCP) seal fouling or RHR pump cavitation. In
addition, control room operators demonstrated a good knowledge and practical
application of RCS level requirements necessary to preclude RHR pump vortexing.
A Unit 2 control room operator did not know the function nor the setpoint of a SW
bay common header pressure control valve. This confributed to a drop in SW
pressure to 70 psig ( 105-1 25 psig normal operating range) when operators removed
a component cooling heat exchanger from service. The operator responded
promptly to restore SW pressure. Through informal interviews, the inspector
determined that most operators knew the setpoint, but did not fully understand the
function of the pressure control valve. The inspector discussed. this training
weakness with the Operation's staff. Operation's staff initiated actions to include
the pressure control feature in operator requalification training and discussed the
knowledge deficiency in a night order book entry.
11
c.
Conclusion
Operator knowledge concerning plant configuration and operation was generally
good, however, the inspector identified a training deficiency involving the function
of a service water common header pressure control valve.
05
Operator Training and Qualification
05. 1 Adequacy of Training, NRC Restart Item 111.16 (Closed)
a.*
Inspection Scope (92903)
In March 1995, reviewers identified numerous weaknesses in the Salem Operations
Training program affecting every aspect of training. They subsequently conducted
two root cause evaluations, one performed by PSE&G personnel, and the other by
an independent team of industry peers, consultants and PSE&G personnel. The
findings, causal factors and recommendations of the two teams formed the basis.
for the PSE&G Accredited Training Restart Action Plan.
The inspector reviewed the actions taken by PSE&G in accordance with the Training
Restart Action Plan to assess its adequacy and completeness. The inspector also
assessed the actions taken by PSE&G in response to Problem Statement 4 of the
Engineering Restart Action Plan. Problem Statement 4 documented inadequate
training of engineering staff to assure high quality of work and lack of clearly
estab.lished or maintained staff qualifications.
In addition to the review of the Training Restart Plan itself, the inspector also
assessed PSE&G management oversight of the restart issue and their performance
in accepting the plan for closure. As part of an ongoing NRC initiative, the
inspector compared the training programs with the description of and requirements
for the programs contained in the Salem UFSAR.
b.
Observations and Findings.
The Salem Training Restart Action Plan identified nine problem statements which
each had several associated corrective actions intended to resolve the deficiencies
in that area. The topics covered by the nine problem statements were:
1 .
PSE&G management had not established expectations for line and training
ownership of training programs;
2.
Line and training management had not identified all root causes for training
program deficiencies;
3.
Open positions in the training staff had adversely impacted the quality of
training;
4.
Quality of training materials had adversely impacted classroom instruction;
5.
Instructor performance weaknesses, including poor student evaluations,
reduced the effectiveness of training; *
6.
7.
8.
9.
12
Personnel had been performing tasks before their qualification for those tasks
had been completed;
Training program self-evaluations had not provided critical assessment of the
training programs;
Internal training oversight and industry peer evaluations had not been
properly utilized to identify training weaknesses; and
PSE&G had to concur with readiness for accreditation renewal.
The inspector reviewed the PSE&G evaluations which had led to the development of
the problem statements and the proposed corrective actions for them.
The
~nspector performed this assessment for all problem statement areas except for the
ninth problem statement, which was beyond the regulatory scope of the inspection.
Using a sampling method, the inspector selected at least three corrective actions
from each of the first eight problem statements and assessed those actions for
adequacy and completeness.
The inspector found that PSE&G Training Restart Action Plan had done a thorough
job in evaluating the deficiencies of the training program and had provided effective
corrective actions as well. PSE&G performed a number of self-evaluations and had
made a number of management changes in the Nuclear Training Department,
including the Director of Nuclear Training, the Operations Training Manager, the
Maintenance Training Manager, and the Technical Training Manager. Over the past
year the new management team had brought in over a half dozen industry peer
review teams to assist in assessing the progress in improving the training programs.
PSE&G also issued new expectations for line management involvement in the
training process and participation in each training department's Training Review
Groups (TRGs). The inspector reviewed minutes from the last half year's TRG
meetings for operations and technical training and interviewed several members of
training, operations and engineering management, and concluded that line
management's involvement in the training process had greatly improved and
resulted in better self-assessments of the training programs.
In the interviews with Training Department management, the inspector determined
that PSE&G took positive steps to resolve the weaknesses ii"' training staff manning
and performance. PSE&G had brought in a number of over-hires to supplement the
previous training staff and instill a new perspective in the training staff. The
inspector observed a number of licensed operator training sessions, both in the
classroom and in the simulator, and concluded that the training staff performed well
and that line management was very involved throughout the entire process. As one
of the checks on training. restart plan completion, the inspector verified the
completeness of several qualification cards. The inspector compared the job
- assignments of several non-licensed operators, maintenance technicians and
engineers with the qualifications .and training completed by each person. The
inspector determined that none of the personnel sampled were assigned* to positions
or responsibilities for which they were not qualified by documented training.
13
PSE&G addressed Problem Statement 4 of the Salem Engineering Restart Action
Plan with corrective actions very similar to the actions of the training restart plan.
In fact, responsibility for completing a majority of the engineering corrective actions
had been assigned to the Nuclear Training Department. In order to improve
_
engineer training and qualification, PSE&G planned on bench marking all engineering
personnel qualifications, completing an engineering personnel job analysis, and
developing a resultant engineering training and qualification matrix. PSE&G also
intended to improve the engineering training programs to maintain the qualific.ations
of the engineering staff at a high level. The inspector noted that the Nuclear
Engineering Department had developed a training coordinator within the department,
and that the Nuclear Ti'aining Department had moved the engineering training staff
- from the training center to the building which housed nuclear engineering staff in
order to promote closer coordination between the training and line staffs. The
inspector reviewed the new qualification and training matrix and the training
programs PSE&G had developed to maintain the engineers' qualification and
performance. The inspector determined that engineering personnel had been
assigned to positions for which they were trained and qualified and that engineering
and training management were coordinating and tracking engineer, training in a
manner to improve engineering performance.
The inspector attended the MRC meeting when the training staff presented the -
Training Restart Action Plan to the MRC-for acceptance and closure. The Training
Restart Action Plan was the first of the nine Salem restart plans to be brought
before the MRC for closure. The training department intended the same
presentation to be adequate to close the "Adequacy of Training" NRC Restart Issue.
The inspector noted that the training department presentation was exceptionally
brief (approximately 10 minutes) and only addressed the shortcomings of the
licensed operator training program. The MRC did not ask any probing questions and
- yet accepted the training restart plan and the NRC restart issue as closed. The
inspector concluded that the MRC performance had been relatively weak and did
not justify the closure of the training plan. Subsequent to the MRC meeting, the
inspector met with the Salem Projects Manager, who coordinates MRC act.ivities,
and discussed the inspector's concerns. The Projects Manager acknowledged the
apparent shortcomings of the MRC performance but explained to the inspector the
existence of extenuating circumstances. The Salem MRC had yielded responsibility
for this restart plan to the Nuclear Training Oversight Committee (NTOC), a separate
management team with a higher level of management on it than the MRC and
whose sole responsibility was the oversight of the training programs. Through a
review of MRC documentation, the inspector determined that the NTOC had
maintained oversight of the training restart plan progress and had kept the MRC
informed of their assessment of that progress. The inspector concluded that
PSE&G management had in fact displayed the proper oversight of the
implementation of the Training Restart Action Pla*n. Notwithstanding the inspector's
conclusion, the Salem Projects Manager acknowledged the appearance of the MRC
performance relative to restart action plan review and closure, and the Projects
Manager issued new criteria for the MRC to use in assessing the closure of restart
plans in the future.
-
14
The Salem UFSAR Section 13.2, "Training Program," states that the Nuclear
Department training program is detailed in the training procedures manual. One of
the procedures specifically referenced in Section 13.2 is Training Procedure 304,
which describes the senior reactor operator training program. The inspector
determined this reference was referring to training procedure TQ-TP.ZZ-0304(0),
"Senior Reactor Operator (SRO) Training Program." The inspector reviewed this
procedure and determined that all assumptions and requirements of this procedure
were being met by the Training Department's current programs. The inspector
therefore concluded that this part of the training program complied with the UFSAR.
c.
Conclusions
The inspector concluded that the Salem training programs had been greatly
improved via the implementati~n of the Salem Training Restart Action Plan. Most
notable were the improvements in the area of training program self-assessments
and in the area of line management involv~ment in the training programs. PSE&G
had evaluated the* deficiencies in the training programs well and developed the
training restart plan accordingly. The inspector's review determined that PSE&G
had implemented that plan effectively and completely. In implementing the Training
Restart Action Plan PSE&G had also satisfied the requirements of the Engineering
Restart Action Plan Problem Statement 4. Despite the marginal performance of the
MRC, the inspector concluded that the PSE&G completion and implementation of
their Training Restart Action Plan was acceptable, and therefore, NRC Restart Issue
Ill. i 6, "Adequacy of Training," is closed.
07
Quality Assurance in Operations
07.1
Corrective Actions for Salem Unit 2 Trip, NRC Restart Item 11.43 (Open)
a.
Inspection Scope (92901)
Inspectors reviewed the corrective actions to decide if they adequately addressed
the causes of the Salem Unit 2 trip on June 7, 1995. The licensee review focused
on the equipment-related causes specific to the Salem Unit 2 trip. The Salem
Restart Plans address the broader issues leading to poor plant and staff
performance.
b.
Observations and Findings
Plant staff concluded that an actuation of Salem Unif 2 protective switchgear
caused a turbine trip resulting in the reactor trip. The staff further concluded that
an ineffective Operating Experience Feedback (OEF) program and ineffective
response to vendor technical information resulted in failure to replace Struthers-
Dunn SBF-1 relays prior June 1995. Salem addressed OEF corrective actions
- *separately since a separate NRC inspection item addresses it and because different
organizations have responsibility for OEF and vendor technical document reviews.
15
As a result, the package focused primarily on the vendor technical document
reviews. The Significant Event Response Team (SERT) 95-02 report, the addendum
to the report and the associated Licensee Event Report (LER) 95-04-01 identified a
significant number of recommended actions, including the following with respect to
vendor technical document review:
Evaluate the history of all Struthers-Dunn relays and create a PM program;
Perform an engineering review of the process for receipt, evaluation and
routing of vendor and industry notifications;
Replace all SBF-1 breaker failure relays on 13KV BS A-8, B-C, C-D, D-E with
. upgraded relays prior to restart; replace* ai!-.SBF-1 breaker failure protection
relays on 500KV breakers with upgraded relays with higher surge capability
by 3-31-96;
Perform a root cause evaluation for lack of prompt implementation of vendor
recommendation to install upgraded relays (due 1-31-96);
The inspector found that the Management Review Committee considered the
package closed without evidence that the plant staff completed the recommended
actions. For example, the scheduled completion (7-15-96) for engineering review of
the process for receipt, evaluation and routing of vendor and industry notifications
occurred two weeks after MRC accepted closure of the package. The results of the
review remained unavailable at the end of the inspection period. The inspector also
noted that the closure package documented an audit of completion of the actions
recommended in the SERT report and addendum, and in the LER. The inspector
noted that the reviewers performed a thorough audit, and documented a number of
discrepancies and incomplete recommendations. The MRC did. not note or question
the discrepancies.
c.
Conclusions
Inspectors concluded that plant staff had not completed the actions. to insure
- corrective action for the Salem Unit 2 trip of June 7, 1995. In addition, the
Management Review Cornmittee did not effectively insure a basis for closure of this
issue.*
07 .2 Quality of MRC Reviews
a.
Inspection Scope (71707)
Inspectors assessed the MRC review effectiveness for closure of Salem technical
and programmatic issues.
b.
- Findings and Observations
The MRC* reviewed the closure package for NRC Restart Inspection Item 11.18, Poor
Reliability of Positive Displacement Charging Pumps in meeting 96-045 and
approved it June 6, 1996. A subsequent review by the NRC lead to the following
observations: Seven of fifteen corrective actions identified in the closure summary
16
as complete had no closure documents such as work orders, design changes,
procedure changes, etc., to allow the MRC to confirm completion. The closure
summary identified an additional seven of fifteen corrective action items as
incomplete but provided no technical basis to justify closure of the issue or restart
of the plant without their completion. In addition, the root cause analysis
documents contained six recommended corrective actions with no discussion
included in the package to explain whether these actions would be implemented.
As discussed in section 07. 1 , the MRC accepted the closure package for the Salem
Unit 2 trip with no evidence (such as Work Orders) that plant staff completed
corrective actions for SBF-1 relay problems. In adc:Hfam, the closure package
-contained evidence that engineering had not completed an essential corrective
action, assessment of the vendor technical document review program, yet MRC
accepted the package.
c.
Conclusions
The MRC did not consistently insure closure packages for identified technical and
. programmatic concerns demonstrated that plant staff had completed essential
corrective actions. -
07 .3
Operating Shifts
a. .
Inspection Scope (71707)
Inspectors reviewed a report made to comply with operating license requirements.
b.
Observations and Findings
On August 8, Salem reported to the NRC that they had not submitted a license
amendment when their operating shifts switched from eight hour shifts to twelve
hour shifts. During a review of the license requirements (DPR-75 for Salem Unit 2)
the license*e discovered that license condition 2.C. (24). a. required that, by June 3,
1981, PSE&G establish an eight hour operating shift to comply with NU REG 0737,
item 1.A.1.3.
Salem Unit 2 complied with the requirement, however, in 1993
Salem Unit 2 transitioned to a twelve hour operating shift without requesting that
the NRC change the license condition. The operating license for Salem Unit 1 did
not conta_in the same condition. This item is unresolved pending further NRC review
of the Salem licensee conditiqns (URI 50-272&311 /96-08-06).
07.4 Corrective Action Plan - Rules and Responsibilities, NRC Restart Item 111.10.2
(Closed)
a.
Inspection Scope (92903)
The inspector reviewed the licensee's actions to address problem statement No. 2
of their Corrective Action Restart Plan regarding: Roles and Responsibilities. This is
17
one of six subsections implemented to address weaknesses in the Corrective Action
Program.
b.
Observations and Findings
The inspector observed the Corrective Actions Group (CAG) presentation of this
issue to the Management Review Committee (MRC) on May 30, 1996. Problem
statement no. 2 identified that the Corrective Action Program (CAP) had no single .
point of accountability with *respect to management ownership and oversight. It
also noted that managers had not clearly defined roles, authorities, and
responsibilities for administration of the program
In the spring of 1995, the NBU formed the CAG under a single manager, the
Manager - Corrective Action and Quality Services (CA/OS) with a staff strictly to
provide corrective action program oversight. Revision 9 of NAP-006, Corrective
Action Program, initially defined their roles. The CAG discussed additional changes
at the MRC and planned to further refine the CAG staff's roles and responsibilities.
c.
Conclusion
Regarding problem statement No. 2, the inspector concluded that Manager, CA/OS
satisfies the requirement for a single point of contact. The roles and responsibilities
defined in NAP-006 are sufficient to address the second part of the problem
statement . Since both of these items have been adequately addressed, this restart
item (111.10.2 only) is closed.
II. Maintenance
M 1
Conduct of Maintenance
M 1 . 1 General Comments
Inspection Scope (62703)
The inspectors observed all or portions of the following work activities:
- *
960729212:
960314180:
960701200:
960701177:
125 voe battery charger inspection/repair of terminal
lugs
No. 21 spent fuel pit cooling pump motor bearing
replacement
Rotation of no. 11 SI pump
Rotation of no. 21 SI pump
The inspectors observed that the plant staff performed the maintenance effectively
within the requirements of the station maintenance program.
18
M1 .2 Conduct of Maintenance
a.
Inspection Scope (62703)
Salem maintenance staff continued to perform repairs that required a large amount
of rework.
b.
Observations and Findings
During the report period, Salem staff identified numerous examples of inadequate
maintenance activities. Condition Resolutions (CRs) documented the following
examples:
Repeat work on the redundant air panel associated with 21 MS 1 71, CR
960806101;
Repeat work on the Lunkenheimer valve associated with 22MS169, CR
960806125;
Repeat work on the 2CVC excess letdown heat exchanger inlet valve
(2CV131 ), CR 9960806081;
Repeat corrective maintenance for the no. 2 polar crane pendant controls, CR
960806090; and
Repeat work to replace the diaphragm for the 21 SW63 valve, CR
960807210.
These CRs represent a small portion of the ineffective maintenance requiring repeat
work. *Salem management recognized the lack of maintenance effectiveness, in
part, as a result of the Salem Integrated Readiness Assessment (SIRA), and
documented the lack of effectiveness in CR 960801205. In addition, on July 22,
1996, PSE&G announced that the Salem unit 2 outage would continue well into the
fourth quarter of 1 996 to insure that the staff completes necessary work to insure
safe, reliable plant operation. During the week of August 5, Salem managers
initiated a plan to retrain all maintenance personnel during the remainder of 1 996.
In the interim,_ qualified contractors and Salem employees that pass performance
examinatic?.s will perform Salem maintenance.
c.
Conclusions
Salem and senior managers acknowledged continued poor maintenance staff
performance. In response, the managers demonstrated their commitment to
insuring safe reliable plant performance. The managers extended the Salem outage
well into the fourth quarter of 1996, and initiated a program to retrain and re-qualify
. the entire Salem maintenance organization.
19
M2
Maintenance and Material Condition of Facilities and Equipment
M2.1 Adequacy of the Foreign Material Exclusion (FMEl Program, NRC Restart Inspection
Item 111.5 (Open)
a. Inspection Scope
Inspectors reviewed procedure changes, training records, completed work
packages, and made field observations to assess the effectiveness of the licensee
corrective actions regarding the FME program.
b. Observations and Findings
The licensee described previous FME related performance with the following
problem statement: "Weaknesses in our Foreign Material Exclusion (FME) practices
had the potential to introduce foreign material into fluid systems or electrical
components. Insufficient understanding of good FME practices by station
supervisors and workers and inadequate FME procedures contributed to the
problem."
PSE&G initiated several corrective actions to resolve the FME program
shortcomings. Among the corrective actions:
Revision of procedures which describe the FME process;
Development and implementation of specialized FME training for new
employees;
FME training for the existing maintenance work force;
Reinforcement of expectations on FME to the work force;
Periodic reviews of FME practices; and
Performance indicators to measure program effectiveness.
The FME closure package included a request to revise SC.MD-GP.ZZ-0006(0),
"Foreign Material Exclusion (FME) and Closure Control", to ensure an Action
Request (AR) is written whenever FME integrity has been violated or is suspect.
Procedure SC.MD-GP.ZZ-0006(0), revision 7, dated July 1, 1996, however,
requires an AR only "If the non-conformance CANNOT either be restored to an
acceptable condition or replaced in kind". PSE&G responded to the inspectors'
observation by initiating a procedure change request to require an AR for all FME
non-conformances. (Reference Change Request R-1 5036)
The inspector reviewed FME trending information included in the closure package.
This trend indicated a reduction in the number of FME occurrences per month since
September, 1995. However, discussions with PSE&G personnel revealed that input
data for the trending came from information contained in Action Requests which
had been initiated since September. During that time period, there had been no
requirement to initiate ARs for FME occurrences, therefore, the inspector considered
the trend information inconclusive.
.*
20
The inspector reviewed training records to verify that all maintenance department
personnel had received the self-study material as indicated in the FME closure
package. The records were difficult to retrieve, and in several cases, it was not
possible to locate the records. PSE&G initiated AR 960801169 to identify and
track resolution of this problem. PSE&G produced other training records that
provided documentation that those personnel in question had received FME training
other than the self-study material.
The inspector reviewed several field completed maintenance work packages. For
each package, the documentation indicated FME controls and practices had been
adequately implemented.
The inspector made observations of ongoing work activities within the plant. The
inspector noted two examples where FME protective devices were used which were
not authorized by procedure SC.MD-GP.ZZ-0006(0), "Foreign Material Exclusion
(FME) and Closure Control". Although the equipment involved was not safety
related, the inspector concluded that since the procedure applied uniformly
throughout the plant, there was potential for impact on safety related components.
PSE&G responded to this observation by initiating AR 960801140 to identify and
track this problem to resolution.
The inspector also found that entry control at the reactor vessel cavity FME
boundary was not in strict compliance with procedures. The FME monitor at the
boundary was allowing an individual with binoculars to enter and exit without being
logged in or out, except for the initial entry at the beginning of the shift and final
exit at the end of the shift. PSE&G corrected the immediate problem and initiated
AR 960806222 to identify and track the procedure noncompliance issue.
The inspector noted two FME occurrences identified by PSE&G during the
inspection period. One involved a hand tool which was dropped into the spent fuel
pool as a result the tool not being secured properly. The second involved the
discovery of pieces of carbon and stainless steel wire found in the reactor cavity
following drain down. Both incidents are being tracked for resolution/corrective
action by ARs.
The procedure violations noted above are considered additional examples of the
failure. to comply with procedure requirements which was identified in Notice of
Violation 50-27 2,311/96-07-01 transmitted to PSE&G in a previous inspection
report.
c.
Conclusions
Although PSE&G has improved the FME program, significant problems continue to
exist with implementation of the program.
As a result, this inspection item remains
open .
21
M4
Maintenance Staff Knowledge and Performance
M4.1 Post Maintenance Testing (PMT)
a.
Inspection Scope (62703)
The inspector reviewed Maintenance's restoration of plant equipment following
maintenance.
b.
Observations and Findings
On June 3, 1996, maintenance technicians completed relay work on 21 SW21, a
diesel generator service water header supply valve. Maintenance returned the valve
to Operations on June 5. On August 2, maintenance technicians performed a PMT
and discovered the valve did not stroke from the control room. On August 2, the
inspector identified that maintenance technicians did not perform the PMT prior to
returning the 21 SW21 valve to Operations. Failure to perform the required PMT is a
violation of NC.NA-AP.ZZ-0009, Work Control Process, step 5.9.1.a. (VIO 50-
272&311/96-08-02) Instrumentation and Controls (l&C) technicians determined
that a*single phase condition caused tripping of the motor operated valve thermal
overloads.
Maintenance technicians completed a PM inspection on 2SJ68, safety injection
minimum flow valve, on May 15, 1996. On August 2, Unit 2 control room
operators discovered that they could not stroke the valve from the control room.
An l&C supervisor identified that technicians did not conduct the PMT in May 1996.
Technicians marked the PM procedure step not applicable (NA) that required valve
stroke because the valve was tagged. Failure to perform the required PMT is
another example of a violation of NC.NA-AP.ZZ-0009 as noted above.
Instrumentation and Controls technicians identified a loose limit switch spring
contact and attributed that condition to a weakness in the maintenance procedure.
In addition, the operations staff identified deficiencies with the planning, scheduling
and performance of PMTs.
For example, the staff initiated AR 96061 2155 (28 *
EOG PMT activities missing) and AR 960703142 (Inadequate PMTs for RVLIS and
EHC system). The Operations Manager assigned a senior reactor operator to lead a
20-man task team to identify and correct PMT program deficiencies.
c.
Conclusions
Maintenance technicians failed to perform required PMTs on safety-related valves.
The Operations staff identified numerous deficiencies with the planning, scheduling
and performance of PMTs.
22
M7
Quality Assurance in Maintenance Activities
M7. 1 Housekeeping and Storage of Safety Related Materials
a.
Inspection Scope (71707)
Inspectors toured the site to assess the adequacy of housekeeping and to determine
compliance with the UFSAR section 17.2.2 commitment to Regulatory Guide 1.38,
Quality Assurance Requirements for Packaging, Shipping, Receiving, Storage, and
Handling of Items for Water Cooled Nuclear Power Plants.
b.
Observations and Findings
c.
During the inspection period the inspectors found numerous examples of poor
housekeeping at Salem. Examples included trash, rain water, tools, litter, and
miscellaneous equipment throughout the plant. The turbine deck contained make-
shift storage areas that contained main generator parts completely immersed in
water. The inspectors observed electrical extension cords too numerous to count.
The inspectors found numerous chemical storage containers (spray cans, etc.),
many of ttiem empty, throughout the plant. On August 1, inspectors discovered
numerous safety-related spare parts stored in a building near the service water
intake structure. The parts included valve stems, bearings, gaskets, valve bodies,
pipe, and other parts associate with the Service Water system. Many of the parts
had labels requiring storage level C conditions, and a few parts required storage
level B conditions. For example, the inspectors found a safety related shaft bearing,
part J50207-000-220, associated with WO 90082011. The Regulatory Guide
requirements for storage of level B and C materials include a fire resistant, tear
resistant, weather tight, and well-ventilated building or equivalent enclosure. The
building (and the storage racks outside of the building) was not fire resistant,
weather-tight, or well-ventilated and did not protect the parts from the possibility of
damage or lowering of quality due to corrosion, contamination, deterioration, or
physical damage. Failure to meet the requirements for storage of level B and C
safety-related materials is a violation. (VIO 50-272&311/96-08-03).
Salem and Nuclear Business Unit (NBU) managers independently identified poor
housekeeping and gave considerable attention to it. In response, they initiated
action to clean up the plant, dispose of the parts, and to emphasize supervisor. and
worker responsibility for plant cleanliness and safety. They also initiated CR
. 960731134, as required, to document a condition adverse to quality, and insure
that they correct it.
Conclusions
The senior NBU managers and the inspectors independently identified that plant
staff and contractors have not kept Salem clean. The inspectors identified that
workers did not comply with requirements for storage of safety-related materials.
The managers promptly took measures to clean the plant, dispose of the poorly
23
controlled materials, and emphasize their expectations for housekeeping and
material controls.
Ill. Engineering
E2
Engineering Support of Facilities and Equipment
E2.1
NRC Restart Issue 11.31 - Residual Heat Removal Discharge Valve (21 RH10) Banging
Noise (Closed)
a.
Scope
The inspectors reviewed Salem engineering staff's determination for 21RH10
banging noises with no. 21 residual heat removal loop in service.
b.
Observations and Findings
Salem engineers determined the cause was an out of tolerance valve stem arm
combined with coolant flow through the valve. The flow rattled the valve disc
against the valve seat. Engineers also noted, based on their review of work history
documents, that disc noise was not unique to 21RH10.
All RH10's exhibited
rattling noises, with 21RH10 being the loudest.
The RH10 is a normally-open, eight inch, double disc (split wedge) gate valve.
When the valve is open, the discs sit in the upper part of the valve body and have
room for movement due to the loose tolerances due to the body casting. With flow
through the valve, the bottom of the discs touch the flow stream and consequently
the discs rattle against the downstream valve seat.
Plant staff took vibration data on all RH 1 O's; 11 & 12RH10 on Unit 1 , and
21&22RH10 on Unit 2. Based on the data, they opened and inspected 11, 21, and
22RH10. Valve 11RH10 dimensions checked out satisfactorily. The 21RH10 body
was satisfactory, however, the disc stem arm dimensions were out of tolerance.
Also, technicians could not weld repair wear indications on the downstream valve
seat. They subsequently replaced valve 21RH10 with valve 11RH10. Technicians
performed minor repairs to 22RH10, including replacement of a worn stem arm.
The staff did not open 12RH 10 because the vibration data did not indicate
dimensions had deteriorated.
Engineers established a monitoring program for the valves. Technicians will open
and inspect one valve, starting with 12RH 10, each refueling outage. The
inspections will continue unless the results indicate the inspections are
unnecessary .
b.
24
Conclusions
The inspectors concluded Salem engineers identified the cause of the banging noise
for 21RH10 and took appropriate corrective action. Also, plant staff adequately
addressed the generic issue and inspected the discharge valves for the remaining
RHR loops, where warranted. This technical issue is closed.
E2.2
NRC Restart Issue 11.34 - Safety Injection !Sil Pump Deficiencies (Open)
a.
Scope
The inspectors reviewed Salem engineers' resolution of SI pump deficiencies.
b.
Observations and Findings
Salem engineers reviewed the maintenance history, in service test data, and
outstanding work items to determine whether the Salem staff had corrected SI
pump deficiencies. The engineers noted the staff had corrected the deficiencies,
and concluded the SI pumps would perform reliably.
Motor and pump vibration data were satisfactory for both Units' pumps, however,
during this review engineers identified that no preventive task existed to periodically
refurbish the motors. Engineers requested a recurring task for refurbishment every
10 years. As an immediate action, the staff refurbished two of the four motors. Of
the remaining two motors, the staff will refurbish one prior to Unit 1 restart; the
other does not warrant refurbishment (done in 1992).
Engineers also responded to industry experience with improperly fastened impeller
locknuts. The staff disassembled all SI pumps and verified technicians had correctly
fastened all locknuts. During reassembly, mechanics noted excessive shaft run out
on both Unit 2 pumps. They successfully replaced both pumps and subsequently
initiated a recurring task to rotate the SI pumps. monthly until operators restart the
respective Units.
The inspectors confirmed satisfactory SI pump and motor vibration data and that
plant staff implemented monthly shaft rotations for idle SI pumps (Work Order 960701200 for no. 11 SI pump and Work Order 960701177 for no. 21 SI pump).
c.
Conclusions
The inspectors concluded plant staff identified SI pump deficiencies. This item is
still open, however, pending the results of operators conducting pump performance
tests .
- .
25
E2.3
NRC Restart Issue 11.17 - Main Condenser Steam Dumps Malfunction (Open)
a.
Scope
b.
During a requalification training program inspection, NRC examiners observed
operators on the simulator shut all main steam isolation valves (MSIVs) at a point
where the EOPs did not direct them to do so. The operators acted, in part, because
operation of the Salem units using the main condenser steam dumps causes an
uncontrolled plant cooldown~ The inspectors reviewed Salem staff's resolution of
the operator performance and plant design issues.
Observations and Findings
\\
Historically, balance of plant .steam leaks were significant enough to cause the
reactor cooldown rate to approach the Technical Specification limit of 100 degrees
per hour.
To compensate for this condition, operators adopted the unwritten
practice .of closing the MSIVs after a reactor trip to maintain the cooldown rate
within regulations. The inspectors also noted that secondary plant steam leaks
forced operators to perform plant startups with the MSIVs closed (instead of open,
with the turbine stop valves closed).
The Salem staff addressed the procedure compliance and staff performance aspects
of this restart issue through operator training. To correct EOP. inadequacies, the
staff revised steps that gave operators direction on whether to close the MSIVs.
The staff validated the revision and trained the operating crews. The inspector
reviewed the new steps of the EOPs and concluded th_ey were adequate, however,
Salem staff has not yet issued the revision. The staff expected to issue the revision
by September 1st.
c.
Conclusions
Although the revised EOPs direct operators when. to shut the MSIVs, the operators
do not yet have the revision.
Also, the Salem staff did not address why the
operators could not operate the plant as designed following a reactor trip.
Therefore, this item remains open.
E7
Quality Assurance in Engineering Activities
E7 .1
Independent Assessment
a.
Inspection Scope (71707)
Inspectors reviewed the results of the* SIRA team to determine whether the team
identified any safety or compliance concerns. *
b.
26
Observations and Findings
During the period June 3 to 23, an independent team assessed Salem performance
in the areas of Operations, Maintenance and Surveillance, Engineering and Technical
Support, and Management Programs and Independent Oversight.
The team concluded that five of the sixteen assessed En_gineering areas were ready
for restart. The team expected that another nin*e areas would be ready for restart.
The two remaining areas, revalidation of the design bases and engineering staff
knowledge of the design basis required significant improvement. In the details of
_ the engineering assessment, the team identified several *a.-~amples of engineering
failure to meet code and regulatory requirements. The examples included:
No evaluation for thermal expansion of chrome-moly replacement feed water
piping as required by UFSAR commitment to ANSl-831.1.
Equivalent replacement of spiral wound asbestos filled gaskets with flexi-carb
gaskets without a safety evaluation required by 1 OCFR50.59.
Use of ASTM A-563 nuts in place of ASTM A-307 nuts without design
reconciliation, as required by ASME XI.
- *
A temporary modification (removal of the moior operated valve 2SW26)
without supporting calculations, and without consideration of the seismic
effects on piping for the duration of the modification.
From June 21, when the SIRA team presented their findings until the inspector
questioned the lack of a Condition Report on July 1 ~,the Engineering staff failed to
document *the deficiencies as required by procedure NC.NA-AP.ZZ-OOOO(Q), Action
Request Process, Rev. 0, step 5.2.6. This is a violation (VIO 50-272&311/96-08-
04).
c.
Conclusions
EB.1
An independent assessment conducted by*the Salem Integrated Readiness
Assessment team concluded that, in general, Engineering appeared on the right
track to support restart in a safe manner. Although the team identified four
examples of inadequate engineering performance, the engineering staff did not
initiate a Condition Resolution, as required, until questioned by an inspector.
Miscellaneous Engineering Issues
Potential for Vessel Head Cracking Due to Sulphur Intrusions in the Reactor Coolant
System
Early in 1994, an inspection to identify any Primary Water Stress Corrosion
Cracking (PWSCC) at the Jose Cabrera plant in Spain identified reactor vessel head
penetration cracks which were apparently initiated by high sulfate levels in the
reactor coolant system. In a letter to LR. Eliason, dated May 9, 1996, NRC Region
1 requested that PSE&G conduct inspections or investigations as necessary to
alleviate concerns on this topic regarding Salem Units 1 & 2.
27
a.
Sco"pe
PSE&G responded to the May 9, 1996 letter in a letter to the NRC dated June 10,
1996. ln_,order to evaluate PSE&G's resolution of this concern, the inspector
reviewed the response, documentation supporting the response, and plans for future
actions.
b.
Findings and Observations
The following items are from the itemized responses in the PSE&G letter and are
organized to correspond to that letter. The descriptions are abbreviated for th.:
purpose of this inspection report.
Item I.A.
"No high sulfur concentration as described in NSAL-94-028 or NRC
Information Notice 96-11 have existed at Salem 1." (Note: NSAL-94-028 is a
Westinghouse Report which addresses the same issue)
Item l.B
"Two sulfur intrusions did occur at Salem 2." .... "These sulfur intrusions
were from the equivalent of 7 liters of cation resin compared to the 200-300
liters reported at the Jose Cabrera plant."
The inspector reviewed PSE&G letter NE-95-0724 from R. Dolan, Principle Engineer
- Ch~mistry Support which documented the history of the sulfur intrusions at Salem.
The inspector found that the letter supported the information in Items I.A and l.B.
Item l.C
"Salem 1 does have the Alloy 600 (lnconel) material described in NSAL 94-
028, which experienced cracking at the Jose Cabrera plant, in the control
rod qrive mechanisms (CROM) penetration." " ... the Alloy 600 used in Salem
1 is more susceptible to sensitization than the alloy used in Salem 2."
"PSE&G Engineering is monitoring experience from other plants with alloy
600, especially detailed inspection results, to determine if any additional
actions are appropriate for Salem 1 and 2."
The inspector reviewed Westinghouse Report NSAL-94-028 and PSE&G letters
MEC-95-528 and NE-95-0724 on the subject of PWSCC. In addition, the inspector
met with engineering personnel regarding the monitoring of experience from other
plants regarding this subject. The inspector found that information contained in the
letters was consistent with the response letter and that the plan for monitoring
- experience at other plants on this issue is adequate .
28
Item l.D
" ... the Salem In service Inspection (ISi) Department performs visual
inspections and ultrasonic testing of the reactor vessel head during refueling
outages to provide assurance that any cracks or leaks are identified."
"VisuaLinspections of the reactor vessel for leakage are also performed in
Mode 3 during plant startups ... "
The inspector reviewed procedure SC.RA-IS.ZZ-0006(Q), VT-2 System Leakage
Visual Exams for Nuclear Class I. II, & Ill Systems and procedure OP-PT.CAN-0001,
Containment Walkdown. The inspector noted that although these procedures
provided adequate guidance for leakage detection, neither procedure provides for
crack detection by ultrasonic testing, dye penetrant testing or eddy current testing
for the CROM penetrations. Further research determined that the NRC has accepted
the position that visual inspection is acceptable for crack detection regarding the
CROM penetrations. This position was stated in an NRC letter dated November 19,
1993 from William T. Russell to NU MARC.
The inspector discussed the results of past inspections for vessel head
- 1eaks/cracking with a member of the ISi Group in Specialty Engineering and learned
that, to date, no cracking has been found.
Item l.E
"CROM penetration cracking has been analyzed by Westinghouse and it has
been determined that even if such cracking is present it is not a substantial
safety hazard (NSAL-94-028)."
The inspector confirmed that the NRC has previously agreed with the position that
there are no unreviewed safety questions associated with CROM penetration
cracking. That position is documented in the NRC November 19, 1993 letter
referred to in the discussion of Item l.D above. The inspector agrees that the CROM
penetration cracking issue is* not a substantial safety hazard.
c.
Conclusions
The inspector found that the documentation reviewed at the Salem site validates
the information provided in the PSE&G response regarding potential for CROM
penetration cracking. In addition, the inspector concluded that the planned visual
inspections of the vessel head are adequate for detecting any cracks. This issue is
closed.
E8.2
Steam Generator Replacement
a.
Inspection Scope (37551)
Inspectors reviewed the Steam Generator Replacement Project (SGRP) and parts of
the Salem FSAR project on 7/23-7/26 and 8/8-8/9/96.
..
29
b.
Observations and Findings
On June 27, 1996, PSE&G met with NRC staff in Rockville, Maryland to present
their plan to replace the four steam generators of Salem Unit 1 with unused steam
generators from the canceled Seabrook Unit 2 plant. During the week of July 22,
. 1996 inspection was conducted at the Salem plant of the project staffing,
preliminary steam generator replacement (SGRP) planning, organization of the
project, engineering involvement and related project Quality Assurance. As of that
time, work had initiated at the Seabrook Unit 2 in preparation to remove the
replacement steam generators (RSG). The work scope at Seabrook includes tube
quality verification by eddy current testing, pipe cutting, machining, welding, rigging
and lifting, _and hydrostatic pressure testing. Onsite inspection by NRC of a portion
of the work on RSGs at Seabrook is planned during August and September. An
objective of the inspection at the Salem plant was to determine the project overview
and schedule for planning inspection coverage of the steam generator replacement
process.
At the Salem site, the project team had been established and preliminary planning
and scheduling of the SGRP work was in progress. The engineering/licensing
analyses work planned to establish the significance of chqnges induced by the
SGRP project includes a review of the FSAR Chapter 15 accident analyses; steam
generator performance calculations, qualification of the NSSS and support loads, an
evaluation of operational transients, operational evaluations, and operator training
support. At this preliminary stage of the SGRP, no firm conclusions were reached
by the inspector, however no items of concern were identified.
E8.3
Extended Layup of Unit 1 Systems
a.
Inspection Scope (92901)
The NRC reviewed licensee actions to preserve the Salem Unit 1 facility pending
replacement of the steam generators. Proper layup of plant systems during the
shutdown could reduce challenge*s to operators during the subsequent startup. The
licensee shut Unit 1 down in May, 1995 and expected it to remain shutdown
through the remainder of 1996. The inspector reviewed associated procedures and
documentation, performed system walkdowns and interviewed key personnel.
b.
Observations and Findings
In June, 1995, Salem assigned a chemistry supervisor the responsibility to
coordinate and implement the layup program. Chemistry staff developed a Salem
Department Directive SC.CH-DD.ZZ-0003(0), Plant Layup for Salem Chemistry, to
provide guidance for layup of the steam generators, the feed and condensate
system, and the demineralizer plant. System engineers developed recommendations
for layup of other portions of the facility and provided them to the layup coordinator
in a series of memos from the System Engineering Manager .
30
At the time of the inspection, plant staff had almost completely implemented the
secondary system drying with 20 desiccant dehumidifiers installed to control
system humidity. A staff of two full time technicians tended to the desiccant
dehumidifiers, perform walkdowns and)og performance data weekly. The
technicians trended flow rates and humidity readings from various system vent
points to assure dehumidification. One challenge to the secondary layup program
was maintaining the* correct system valve lineup.
Chemistry technicians established the secondary system lineups using a work
request and requesting operations to position specific valves. Operations positioned
the valves and updated the positions in the TRIS. However, no mechanism existed
to assure secondary system valves will remain in position for the remainder of the
outage. Problems resulted from small bore piping replacement where workers
removed and replaced valves, then returned to the normal system lineup vice the
layup position. Chemistry staff implemented technician walkdowns and system
performance trending to maintain the required system configuration.
NRC walkdown identified that plant staff had laid up the sections of piping from the
condensate pump suction to the hot well with. flow through a vent point as desired.
This configuration resulted in a significant section of piping in the low point of the
system with no flow through it to promote drying and without monitoring to assure
the piping remained dry and un-isolated. As a result of the inspector's observations
Chemistry staff requested that operators establish the vent point and added the
valves to their list for sampling and trending.
The inspector reviewed the system engineering recommendations and considered
them comprehensive. The layup recommendations acknowledged planned
maintenance activities prior to restart and summarized the systems required to
remain available during the layup period. However, the system engineering memos
made numerous recommendations that plant staff did not fully implement.
Examples included monthly rotation of various pumps such as auxiliary feed,
residual heat removal and containment spray; removal and dry storage of the
traveling water screens and circulating water pumps; heating and desiccant
- application in electrical cabinets; w_eekly operation of the turbine oil system and
rotation of the turbine. The layup coordinator continued to pursue implementing
procedures and work requests to establish the desired layup activities.' However,
. the inspector noted that the system engineering staff did not aggressively chase
completion of the recommendations or establishment of alternate conditions.
Operators had defueled the reactor and drained the primary system as much as
possible. Although system engineers recommended sampling of the stagnant water
remaining in the reactor vessel, plant staff had not yet developed a procedure to
obtain the samples. Engineers also re.commended that the reactor vessel level
indicating system (RVLIS) should have water on the process side to prevent damage
to the seals. The inspector noted that the current plant conditions did not provide
for wetting of the RVLIS seals. At the end of the inspection period, the licensee
had not determined the proper course of action regarding RVLIS layup ..
31
c.
Conclusions
The inspector concluded that engineering provided a detailed list of
recommendations for laying up various systems and components. However, plant
-
- .*
staff had not developed a comprehensive plan for plant layup that integrated the
various recommendations. The system engineers did not actively identify and
resolve deviations from their recommendations. Plant staff had nearly completed
layup and drying of secondary systems with a trending program in place to monitor
performance. However, the inspector identified a significant portion of piping in the
low point of the system that they had not included in the trending program.
- Although control of the valve lineup for system drying was weak, the trending
program should provide an adequate indication of system configuration.
E8.4
Spent Fuel Pool Cooling and Refueling Activities
a.
Findings and Conclusions
Inspectors performed a survey of spent fuel practices and spent fuel pool (SFP)
cooling system design and current licensing basis was performed on March 28 and
29, 1996. The NRC published the results of this survey in NRC Inspection Report
No. 50-272 and 50-311196-05. The survey identified four discrepancies .that the
licensee committed to resolve. A letter dated June 27, 1996, was sent to the
licensee requesting that the licensee confirm these commitments and indicate the
projected completion date for each of the actions.
Specifically, the licensee committed to:
( 1) Update the current licensing basis to state that a full core off-load is the routine
practice during refueling outages (IFI 50-272&311 /96-08-07).
(2) Perform an analysis of the SFP structures and associated systems to consider
SFP water temperatures above 180 F (IFI 50-272&311 /96-08-08).
(3) Develop a procedure for using the cross connect between th9 heat exchangers
to support the one unit with the SFP excess heat load (IFI 50-272&311 /96-08-09).
(4) Put in place procedural controls that will assure that the SFP heat load is
maintained below the analyzed value (IFI 50-272&311/96-08-10).
Inspectors will inspect licensee implementation of the commitments during routine
inspection activities .
-- J
,,
32
V. Management Meetings
X 1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at the
conclusion of the inspection on August 14, 1996. The license.a 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.
INSPECTION PROCEDURES USED
IP 61726:
IP 62703:
IP 71707:
Surveillance Observations
Maintenance Observations
Plant Operations
IP 92901:
IP 92903:
Followup - Plant Operations
Followup - Engineering
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-272&311/96-08-01
50-272&311 /96-08-02
50-272&311 /96-08-03
50-272&311/96-08-04
50-272&311 /96-08-05
50-272&311 /96-08-06
50-272&311 /96-08-07
. 50-272&311 /96-08-08
50-27 2&311 /96-08-09
50-272&311/96-08-10
Ineffective Tagging Request Inquiry System
updates
Failure to perform post maintenance testing
Inadequate safety-related material storage
Failure to initiate Condition Resolution reports
(App B, Criterion XVI)
Failure to Provide Adequate Operating
Procedures .
Review Salem License Conditions
IFls
Refuel Practices Commitments
IFls
Refuel Practices Commitments
IFls
Refuel Practices Commitments
IFls
Refuel Practices Commitments.
CAG
CA/OS
CCHX
CROM
CRs
eve
ECAC
l&C
ISi
LER
N/A
NBU
NRC
NTOC
OEF
OTSC
PSE&G
SERT
SIRA
SNSS
-SORC
SRG
TR Gs
TRIS
TS
LIST OF ACRONYMS. USED
Action Request
Corrective- Action Group
Corrective Action Program
Corrective Action and Quality Services
Component Cooling Heat Exchanger
Control Rod Drive Mechanisms
Condition Reports
Centrifugal Charging
Emergency Control_ Air Compressor
Emergency Operating Procedures
Emergency Response Gui~el_ine
Hilti Drop-In
Instrumentation and Controls
Institute of Nuclear Power Operations
lnservice Inspection
Licensee Event Report
Management Review Committee
Not Applicable
- Nuclear Business Unit
Nuclear Regulatory' Commission
Nuclear Training Oversight Committee
Operating Experience Feedback
On-The-Spot Change
Public Document Room
Post-Maintenance Testing
Public Service Electric and Gas
Primary Water Stress Corrosion Cracking
Reactor Coolant Pump
Reactor Vessel Level Indicating System
Significant Event Response Team
Safety Injection
Salem Integrated Readiness Assessment
Senior Nuclear Shift Supervisor
Station Operations Review Committee
Safety Review Group
Senior Reactor Operator
Technical Document Room
Training Revie_w Group
Tagging Request Inquiry System
Technical Specification
Updated Final Safety Analyses Report