ML18102A872
| ML18102A872 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 02/19/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18102A870 | List: |
| References | |
| 50-272-96-18, 50-311-96-18, NUDOCS 9702250014 | |
| Download: ML18102A872 (46) | |
See also: IR 05000272/1996018
Text
.. '\\
Docket Nos:
License Nos:
Report No.
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved by:
l;J. S. NUCLEAR REGULATORY COMMISSION
REGION I
50-272, 50-311
50-272/96-18, 50-311/96-18
Public Service Electric and Gas Company
Salem Nuclear Generating Station, Units 1 & 2
P.O. Box 236
Hancocks Bridge, New Jersey 08038
Decemb.e~ .15, 199.6 - January 25, 1997
C. S. Marschall, Senior: Resident Inspector
J: G. Schoppy, Resident lrispector
T. H. Fish, Resident Inspector
R. K. Lorson, Resident Inspector
J. Laughlin, Emergency Preparedness Specialist *
E. H. Gray, Technical Assistant
G. S. Barber, Project Engineer
P. D. Kaufman, Emergency Response Coordinator
Larry 'E. Nicholson,* Chief, Projects Branch 3
Division of Reactor Projects
9702250014 970219
ADOCK 05000272
G
POR
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EXECUTIVE SUMMARY
Salem Nuclear Generating Station
NRC Inspection Report 50-272/96-18, 50-311 /96-18
This integrated inspection included aspects of licensee operations, engineering,
maintenance, and plant support. The report covers a six week period of resident
inspection; in addition, it includes the results of announced ~team generator replacement,
emergency preparedness, and corrective action inspections.
Operations
During the inspection period operators completed four major evolutions for Salem Unit 2.
They refueled the reactor, filled and vented the reactor coolant system (RCS), established
a bubble in the pressurizer, and started each of the reactor coolant pumps (RCPs)*. In
completing;-.the evolutions, operators demonstrated a strong emphasis on nL!Clear and
personnel safety. In each case, operators added a great deal of quality to the process
through their careful review of procedures for adequacy, and through pre-evolution briefs
focused on critical safety parameters. In each case, they delayed starting the evolution to
deal with and remove *other plant activities that could cause distraction. In some cases, .
they stopped the evolution to insure safety in their activities. Although Salem workers
caused loss of containmenfclosure for two days during refueling and *an operator failed to
correctly align two valves during the RCS fill and vent process, the inspectors considered
operator performance generally good for the four evolutions. The inspectors noted
specifically that operator safety focus, willingness to put pl_ant safety before schedule
. adherence, and questioning attitude had improved significantly in comparison to 'their
performance prior to June 1995. The operators demonstrated effective communications,
proper procedure use and adherence, good safety focus, and improved senior reactor
operator oversight ~f activities during the complex evolutions (Sections 01.1 and 04.1 ).
Chemistry technicians maintained reactor.coolant chemistry within the required limits.
They took appropriate action in response to slightly elevated chloride levels in Unit 2
reactor coolant. Salem Unit *2 operators did n_ot know* of the elevated chloride and did not.
routinely review chemistry sample results. The chemistry department superintendent and
the operations manager previously identifred the weakness, and initiated corrective actions
(Section 04.2).
Inspectors reviewed progress in addressjng operator workarounds and control room
deficiencies, and effectiveness of the Quality Assurance (QA) program. The inspectors
also reviewed operations staff progress in implementing the Operations Restart Plan, and
assessed the effectiv~ness of the Corredive Action Program (CAP).
Aside from minor program weaknesses, the operations staff established adequate controls
to identify, track, and correct operator workarounds and control room deficiencies.
Operations and maintenance staff made significant progress in reducing the number of
operator workarounds and control room deficiencies. *inspector!? considered actions by the
Salem staff to address these deficiencies adequate to support Salem unit 2 restart (Section
02.2).
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- Overall, the QA program performance was acceptable to support the restart of Salem Units
1 & 2. The organization is well staffed and capable of providing oversite for th'e Salem
site activities, and has demonstrated the ability to identify and track corrective action
items. The QA staff has conducted thorough and rigorous audits and assessments of
operations, maintenance,* engineering and support _activities. (Section 07. 2)
Operations personnel made significant progress toward operations department restart
readiness. Operations personnel established themselves as leaders in the organization and
resumed ownership of the facility. Operations management established high standards for
department performance and made steady progress to improve operations' performance
relative to those standbetween supporting departments (Section 08.1 ).
The Nuclear Business Unit has significantly improved, and continues to improve the
corrective action program. They implemented appropriate C?Ontrols to .maintain CAP.
performance. The inspectors considered actions to improve the corrective action program
and the corrective action resta~t plans adequate to support Salem Unit 2 restart. (Section
08.3)
Maintenance
Although Salem Unit 2 has a sizeable backJog of corrective maintenance, inspectors
considered the total impac~ minor in scope. Also, with a single minor exception in a
sample of about 100 work orders, the plant staff had properly classified the work orders
as post restart.
The inspector concluded that the Salem staff properly managed the
b~cklog, and considered it acceptable to support the restart of Salem Unit 2* (Section
M1 .2)
As a result of ineffective work control, the Salem staff failed to maintain containment
integrity while conducting Unit 2 core reload. Plant management responded promptly and
appropriately to address associated weaknesses. Excepting the loss of containment
integrity, the plant staff completed Unit 2 refueling safely and effectively (Sec~ion M2. l) .
. Engineering
During the inspection period, *the engineering staff continued to produce many good
engineering products. For example, the inspectors concluded that PSE&G satisfactorily
managed the engineering backlog. The PSE&G staff effectively prioritized _emergent items
and knew the content of the backlog. Based on review of a sample of the backlog items,
the inspector determined that the Salem staff had appropriately designated the items as
"post restart." (Section E1 .2) The Salem Unit 1 steam generator replacement project
produced results characterized by good quality, few deficiencies, improved planning, work
control, and adherence t.o procedure requirements (Section E1 ..4) *. The Salem staff
- effectively corrected Unit 2 safety injection pump deficienci"es and subsequently
demonstrated that pump performance met surveillance requirements. In addition, they
completed modifications to *the steam dumps and implemented related EOP changes. The
inspector considered these corrective actions adequate for restart of Salem Unit 2
(Sections E2.1 and E2.2). The plant ~taff also took comprehensive corrective action to
improve ~uxiliary Feedwater performance and reliability. The inspectors considered the
iii
action adequate to support restart. The inspectors will observe pump testing during the
Salem restart (Section E2.5.) The MRC performed a thorough review and eval~ation of the
Operations Department *and System Engineering restart issue (Section E2.3.). The Nuclear*
Engineering Desig*n department started to develop a modification to prevent service water
voiding in. Containment Fan Coil Unit heat exchangers and piping-following a design basis
loss of coolant accident (Section E1 .3.)
The inspectors also saw examples of less than adequate engineering performance during *
the inspection period. During re-analysis of inadvertent safety injection, PSE&G failed to
evaluate the PORV accumulator check valves for suitability of use, and failed. tq revise the
IST check valve leak test procedure. An Offsite Safety Review g*roup revie.wer concluded
- that the reanalysis posed an unreviewed safety question that req.uired a change to
Technical Specification 3.4.5. In addition, the Salem staff identified that the safety
evaluation incorrectly concluded that no safety evaluation existed .due to the reanalysis.
The Salem staff initiated corrective action, including a license change request (Section
E1 .1.) In addition, the inspector identified that PSE&G mis-classified valves SJ4 and SJ5
- as passive components and, as a result, had not included them in the IST program for
exercise and stroke testing in the closed dir~ction. The inspector determined that the
valves must close to stop charging flow to the RCS during a steam generator ~ube rupture.
event, and Salem should have included them in the IST program (S~ction E2.4.)
Plant Support
The licensee took adequate.correc;:tive actions for three violations resulting from the
October, 1995 loss of annunciator event at Salem Unit 1. Emergency Response
Organization (ERO) members demonstrated g~>od *overall performance during mini-drill
sc::enarios. The efforts to improve the Emergency Response Program were found to be
sufficient to support Salem restart. The inspectors noted several deficienc;:ies with the
emergency preparedness department's implementation of the action item tracking system
(Sections P3 through PS.5.)
The inspectors observed certain examples of violations of the access control process as
described in the NRC approved Salem and Hope Creek Security Plan. Further, the
inspectors concluded that while station personnel took appropriate immediate corrective
actions for each of the* observed events, weaknesses still existed in implementation of
access co.ntrols at both Salem and Hope Creek. (Section S 1 . 1)
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TABLE OF CONTENTS
EXECUTIVE SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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TABLE OF CONTENTS ....................... : .................... .
I. Operations ................................................... .
II .. Maintenance ................................................ .
Ill. Engineering .............................. ~ .... ; ........ .- .... .
IV .. Plant Support ........................................ * ....... * ..
V. Management Meetings
v
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21
33
39
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Report Details
Summary of Plant Status
Salem Unit 1 remained defueled for the duration of the inspection period.
Salem Unit 2 began the inspection period defueled. On December 16, 1996, operators
commenced refueling and entered mode 6. On December 21, operators completed
refueling. On December 26, when plant staff finished tensioning the reactor head, Salem
Unit 2 entered mode 5. Unit 2 remained in mode 5 for the remainder of the inspection
period.
01
01.1
I. Operations
Conduct of Operations
General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of
ongoing plant operc;1tions. . In general, the op'erators demonstrated professional and
safety-conscious performance. During the inspection period operators completed
four major evolutions for Salem Unit 2. They refueled the reactor, fiHed and vented
the reactor coolant system (RCS), established a* bubble in the pressurizer, and
started each of the reactor coolant pumps (RCPs). In completing the evolutions,
operators demonstrated a strong emphasis on nuclear and personnel safety. In
each case, operators added a great deal of quality to the process through their
careful review of* procedures for adequacy, and through pre*-evolution briefs focused
on critical safety parameters. In each case, they delayed starting the evolution to
deal with and remove other plant activities that cou.ld cause distraction. In some.
cases, they stopped the evolution to insure safety in their activities. Although
Salem workers caused loss of containment closure for two days during refueling
and an operator failed to correctly align two valves during the RCS fill and vent
process, the inspectors considered operator performance generally good for the four
evolutions. The inspectors noted specifically that operator safety focus, willingness
to put plant safety before schedule adherence, and questioning attitude had
improved significantly in comparison to their performance prior to June 1995. *.
01.2 Reactor Coolant System Fill and Vent
a.
Inspection Scope (7-1707)
b.
The inspectors monitored and assessed operator performance during an infrequently
performed evolution;
Observations and Findings
After completion .of refueling, plant staff completed reassembly of the reactor and
transitioned from mode 6 into mode 5. Subsequently, they made preparations to fili
...
2
and vent the reactor coolant system {RCS) and draw a bubble in the pressurizer. In
previous outages, the plant staff used repeated starts of the reactor coolant pumps
(RCPs) to remove non-condensible gases from the RCS .. In this case, plant
managers decided to fill and vent by reducing the RCS water level to just above
mid-loop, drawing a partial vacuum through the top of the pressurizer, then refilling
the RCS from the reactor water storage tank (RWST).
The plant staff, especially operators, prepared for the first-time evolution* with great
care. They assigned a test manager to oversee the evolution because operators
had not previously applied vacuum to fill and vent the RCS. Operators discovered
several problems with the procedure during their review prior to implementation.
For example, the operators initiated condition report (CR) 961229068 to document
that the fill and vent procedure directed operators to isolate the manual isolation ..
valves for cold leg safety injection, but did not direct the operator to reopen the ..
valves in the event of a loss of RHR. They delayed implementation of the fill and
vent procedure until they corrected .all the problems they identified. The operators
also conducted thorough shift briefings prior to starting to implement the procedure
and used shift test managers to provide oversight and coordination during the
course of the test. The briefings focused in detail* on the critical points in the fill
and vent process, and.the expected plant response to.variqus 9ctivitles. Operators
paid particular attention to the potential for inadvertent dilution, *loss of RHR, and
the need to insure reliable RCS level indication .
Despite the efforts to insure they completed the procedure correctly, a control roqm
operator incorrectly performed a portion of the valve alignment in the control room.
Procedure S2.0P-SO.RC-0002 (Q), Vacuum Refill of the RCS, Rev. 1, step 2.9
required the operator to verify pressurizer spray valves PS-1 and Ps-*3 open. 1!1 the
reduced RCS inventory condition, opening the valves would have .allowed vacuum
to equaJly affect the RCS hot legs and cold legs. With the valves closed, however,
.all of the RCS level indications immediately indicated a significant increase in level
when operators applied vacuum. Within two minutes, the Senior Nuclear Shift
Supervisor directed the operators to stop the vacuum pump and break vacuum.
Level indication immediately returned to normal. The operators completed proper.*
system alignment, as required by procedure, then successfully completed filling and
venting the RCS* witho.ut a problem.
During the two minutes while vacuum affected only o_ne side of the level indicators,
operators could not monitor RCS level while in mid-loop ope.ration. Although they
had lost some of the means to anticipate loss off RHR due to pump vortexing, they
still had the means to detect it through fluctuation in RHR pressure and pump
current. Since RCS level did not actually ch~nge, the RHB pumps did *not *
experience vortexing during the evolution. The inspectors concluded that the
situation had no safety consequence and minor safety significance.
The operators responded quickly to the abrupt change in indicated level due, in part,
to the importance they had associated with level indication. The control room staff
immediately recognized .the cause of the level change, and took the proper
corrective actions. They completely verified pr.aper system alignmei;it. During initial
c.
02
02.1
a.
b.
3
assessment *of the problem, the test manager noted that the procedure lacked
independent verification of initial conditions. The operations manager also noted
that the operating shift did not successfully employ teamwork, since several other
shift personnel failed to take advantage of the opportunity to identify and correct
the incorrectly positioned valve.
In addition to the immediate corrective actions to open PS-1 and PS-3 and verify
the proper alignment, the oper~tors initiated CR 9701020.85. In addition, the
operations manager initiated an operator self-check practice. The operations
manager required the operators to check each other's work for critical steps in
many activities. He expected the operators to verify most activities such as valve
alignments until the operations staff could incorporate specific requirements irito
the appropriate procedures. The operations manager also directed the procedure
writers to review operating procedures to incorporate independent verification
requirements.
Conclusions
Although the operators experienced a problem with RCS level _indication as a result
of a valve mis-alignment during the RCS fill and vent, the operator~. immediately
recognized the problem.* The problem had no safety consequence. Operators
immediately recognized and responded to the problem as a result of their focus on
RCS level, the critical safety parameter during mid-loop operation. In addition, the
operators and operations manager immediately took comprehensive corrective
action. This licensee identified and corrected violation is being treated as a Non-
Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy.
Operational Status of Facilities and Equipment
Operator Workarounds and Control Room Deficiencies, NRC Restart Item 111.8
(Closed)
Inspection Scope *(92901)
Operator workarounds exist to compensate for degraded plant conditions.
Operators often implement compensatory measures that distract them from their
normal duties and may seriously complicate their response to a plant transient. The
inspector reviewed Salem's program to address operator workarou_n.ds.
Observations and Findings
Salem Operations staff developed SC.OP-AP.ZZ-0030, Operator Workaround
Program, to identify, track, and manage operator workarounds and burdens. The
operations workaround supervisor developed an effective tracking program and
worked with maintenance staff to prioritize and schedule actions to correct the
causes of operator workarounds and burdens. Since January 1996, Salem reduced
the total number of Unit 2 operator workarounds and burdens from 134 to 21 .
During this time, Instrument and Controls technicians reduced the number of Unit 2
c.
4
control .room indication deficiencies from 280 to 185. Plant staff appropriately
prioritized the planned work by operating mode to insure they i:epair control room
indicators as required by plant conditions. For example, little deficient control room
instrumentation affected the operator's ability to monitor required plant parameters
in mode 5. Emergent deficiencies and repetitive abnormal alarms received prompt
and appropriate attention. The inspector concluded that maintenance staff support
of work to remove operator workarounds had improved since July 1 996. (See
. Inspection Report 50-311 /96-o'7 section M 1 .4)
The operations work control manager established challenging performance goals
based on industry standards. The inspector noted a few minor weaknesses in the*
operator wo~karound program. *For example, several minor deficiencies that
required compensatory operator action did not appear on the workaround list. hi
addition, several out of service control room indicators did not appear in the
Managed Mainten~nce Information System (MMIS) work orde*r printout nor in the
control room operator's supplemental control room instrumentation tracking log.
The SNSS initiated a c.onditiori resolution report (CR 9701 24254) to correct this
deficiency.* The inspector also noted that operators did not routine!y update* work
- orders to reflect changes in the workaround or burden status, and plant staff did
not include compensatory measures resulting from corrective actions iil the
workaround program (see Section 08.3). The operations staff initiated CR
970120173 to address this weakness. Overall, however, the inspector concluded
that the operations staff had significantly reduced workarounds and burdens, and
had implemented ~n effective program to identify and *address them.
Conclusions
Aside from minor program weaknesses, the operatio.ns staff established adequate
controls* to identify, track, and correct operatqr workarounds and cpntrol room
deficiencies. Operations and mainten~nce made significant progress in reducing the
number of operator workarounds and control room deficiencies.
04
Operator Knowledge and Performance
04.1
Procedure Use and Adherence (92901)
The inspectors observed Unit 2 operator's use and ad'1erence to operating
procedures. Control room operators demon~trated effective communications and .
good attention-to-detail while controlling several complex evolutions. Senior reactor
operators (SRO) maint.ained effective awareness of safety system status and
demonstrated appropriate safety focus. In addition, the ~ROs increased oversight
and control of activities in the field. Operators consistentl.y and accurately
implemented procedures and properly documented completion of procedure steps.
The operators demonstrated a good questi.oning *attitude by identifying needed
procedure improvements. In each case, they safely placed the process on hold and
implemented appropriate procedure changes using the approved process. The
inspectors observed good operator procedure use an.d adherence* during the
following evolutions:
- S2.0P-SO.RC-0005:
- S2.0P-SO.SF-0004:
- S2.0P-SO.PZR-0006:
- S2.0P-IO.ZZ-0001:
- S2.0P-SO.RC-0002:
- S2.0P-SO.RC-0001:
5
draining the reactor coolant system (RCS) to ;;::: 101
feet elevation
draining the refueling cavity
RCS venting
refueling to cold shutdown
vacuum fill of the reactor coolant system (preparations
for establishing a pressurizer steam bubble)
-reactor coolant pump operation (preparations* for
starting 23 reactor coolant pump)
04.2 Reactor Coolant Chemistry C~ntrol
a.
Inspection Scope
The inspector reviewed recent Unit 2 reactor coolant chemistry sample results and
interviewed chemistry department personnel and several control room operators to
determine the effectiveness of the licensee's chemistry control program.
b.
Observations and Findings
The reactor coolant chemistry limits are speCified in the Updated Final Safety
Analysis Report (USFAR) section 5.2.3.4 and in Technical Spe_cification (TS) 3.4.9.
The chemistry limits ensure adequate water quality to minimize corrosion of reactor
coolant system components and limit radioactivity levels of reactor coolant. The
inspector reviewed a number of reactor coolant chemistry sa_mple results and
determined that they did not exceed the applicable limits. In addition, the inspector
noted that a chemistry technician had identified and initiated corrective action .for a
slightly elevated Unit 2 reactor coolant chloride concentrati.on. * *
The inspector noted a minor weakness in that the Unit 2 control ro~m operating
personnel questioned did*not know about the elevated reactor coolant chloride
levels. Additionally, the operators did not routinely review the readily available
chemistry sample results .. The acting chemistry department superintendent and the
operations manager stated that they also identified th~ weakness and had initiated
corrective actions.
c. * Conclusions
Chemistry technicians maintained reactor coolant chemistry within the required
limits. They took appropriate action in response to slightly elevated chloride levels
in Unit 2 reactor coolant. Salem Unit 2 oper(Jtors did not know of the elevated
chloride and did not routinely review chemistry sample results. The chemistry
department superintendent and the operations manager previously identified the
weakness, and initiated corrective actions.
.,.
6
07
Quality*Assurance in Operations
07.1
(Closed) LER 50:.272/96-018 - potential performance impact ori emergency core
cooling system due to non-safe:ty related refueling. water storage tank (RWST)
piping. In July 1996, a design review conducted by PSE&G identified that the
refueling water purification loop was normally aligned to the RWST rather than
isolated. Since the non-safety related purification loop is not seismically qualified,
part of the RWST inventory would be lost in a seismic event, reducing the ability to
maintain core cooling.
In response, operators immediately isolated the purification loop from *the RWST.
The long term corrective actions include upgrading an isolation valve to a safety
related classification, revising procedures to clearly document limitations of
op~r::iting the purification system, and to review other systems for similar
conditions.
The discovery of this condition had minor safety significance because the
purification system pipe consisted of the same material as the ECCS suction piping .
. Although failure to* control operation of the purification loop to preclude adversely
affecting emergency core cooling is a violation of 10 CFR 50, Appendix 8, Criterion
V, "Instructions, Procedures, and Drawings," this licensee-identified violation is as
.Non-Cited Violation, consistent with Section Vll.B.I of the NRC Enforcement Policy .
07.2 Adequacy of QA Program NRC Restart Item 111.20 (Closed)
a.
Inspection Scope
b.
To determine the effectiveness, the inspector reviewed samples of Quality *
Assurance (QA) audits and assessments .of Salem activities, a self assessment of
QA performance and an example of the QA monthly report. In addition, the
inspector reviewed two audit reports selected from the 1996 audit schedule and
corrective action documents that resulted from the audits. Finally, the inspector
held discussions with the Salem QA supervisor to assess the staffing.
Observations and Findings
The inspector considered QA staffing acceptable to support restart of the Salem
units. The QA organization has the capability to perform detailed design reviews.
for: selected plant modifications to help assess the acceptability of the design
.
.
p~ocess. Also, the QA staff employs several personnel with previous* experience in
line organizations. The inspector learned that QA had filled nearly all staff positions*
for transition to a proposed new organization under review by the NRC.
Based on a review of six audits and assessments and the number and nature of
corrective action items identified c;turing tho~e activities, the inspector considered
QA audits rigorous and com.prehensive. The inspector noted, in particular, that the
audits identified significant performance and. program deficiencies and entered them
in the corrective action program to insure the appropriate corrective action. For .
c.
7
example, in* a 1996 assessment of work control and tagging, QA auditors identified
enough significant problems to conclude that these areas were. not acceptable to
support the restart of Salem Unit 2. The audit of the in-service inspectfon program
identified problems that resulted in 26 Action Requests (i.e., corrective action
documents) and 57 observations. The inspector also concluded that QA use, in
more recent audits, of technical experts from outside the company resulted in
improved assessment.
The inspector found that performance *indicators and the monthly Quality
Assessment Report provided line managers with useful tools to monitor completion
of corrective actions. Executive managers, directors, and department managers
- 'and dir.ectors use the QA report to manage the corrective action backlog. In a
review of 10 corrective action documents that identified 50 specific corrective *
actionis: the inspector found that plant staff had resolved the significant issues in a
timely manner; Ttie departments had appropriately scheduled procedure changes to
address minor issues for the next scheduled biannual procedure review.
In a review of the audit schedule, the inspector found that QA conducted 13 audits
- in the past year and planned 16 for the upcoming year. The 16 audits cover most
functional areas of the plant and support organizations. In addition, *QA staff
allotted time for the performance of contingenc'y audits. The QA department also
conducted less formal assessments for problem areas indicated by the corrective
action program. The inspector concluded that QA scheduled and conducted
appropriate audit activity to provide meaningful assessment of line organization
activities.
The inspector noted that PSE&G has a stated corporate policy of receptiveness to
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.
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valid safety concerns. In addition, PSE&G has an employee concerns department
that encourages employees .to communicate t.heir concerns, anonymously if desired,
for investigation and resolution. The* inspector found information regarding the
employee concerns program prominently displayed in several locations. This
provides adequate guidance for employees to *contact the employee concerns
department by telephone, mail or in person. During this inspection, the inspector
found that PSE&G tracked t_he number of employee concerns submitted each month
and provided that information in the QA monthly report. From this data, the
inspector found that.the number of concerns submitted each month had dropped
steadily over the past eleven months, from a high of 27 in January to a low of 2 in .
November 1996. The inspector considered the employee concerns program
effective in surfacing an~* ameliorating the concerns.
Conclusions
Overall, the inspector concluded that the PSE&G's QA program is fully acceptable
to support the restart of Sa'lem Units *1 & 2. The organization is well staffed and is
capable of providing oversite for the Salem site activities, and the tools are in place
to enable identification and tracking of corrective action items. QA has
demonstrated the ability to conduct thorough and rigorous audits and assessments
of operations, maintenance, engineering and support -activities. This item is closed.
8
07.3 Corrective Actions for Salem Unit 2 Trip - NRC Restart Inspection Item 11.43
(Closed)
a.
Inspection Scope (71707)
Inspectors reviewed the corrective actions to determine if they adequately
addressed the causes of the Salem Unit 2 Trip on Juhe 7, 1995.
b.
Observations and Findings
The inspectors previously reviewed licensee corrective actions in NRC Inspection
Report 50-272&311 /96-08. The inspectors concluded, in that report, that plant
staff had not completed the actions necessary to insure E:iffective corrective* action.
Specifically, the package did l"!Ot include evidence that plant staff had replaced the
SBF-1 relays, identified as the cause of the trip. In addition, enginee*ring had not
completed their evaluation of the process for review, receipt, evaluation and routing
of vendor and industry notifications.
During the current inspection period, the inspectors reviewed completed work
orders demonstrating that the Salem staff had *replaced the SBf-1 relays with
upgraded versions for all four south 13KV ring bus breakers and all eight 500KV
ring bus breakers. The north 13KV ring bus does not use *sBF-1 relays. The
inspectors also review~d the completed Vendor Manual Program Assessment
Report. The review documented, us.ing the station Corrective Action Program, a
number of required corrective actions. These included:
Establish a vendor doc.ument process owner.
Establish a baseline for vendor document informati.on.
Modify vendor contr~ct c'ommitment to a three year cycle
Perform a .sar:nple of vendor re-contacts to provide a basis f9r Salem restart
affirmation.
Establish an enhanced vendor *re-contact program.
Evaluate vendor document backlog prior to Restart for* potential safety
significant issues.
The licensee completed implementation _of these actions on August 8, 1996. The
Nuclear Engineering Design department performed a thorough review of the vendor
manual program and developed comprehensive corrective actions. They completed
implementation of the corrective actions required for restart. The inspector
considered the corrective* actions effective.
- c.
Conclusions
The inspectors concluded that the licensee implemented appropriate correc'tive
actions to address the cause of the June 1995 Salem Uriit 2 reactor trip.
9
08
Miscellaneous Operations Issue
08.1
Operations Restart Action Plan (Open)
a.
Inspection Scope (92901 l
The Salem Operations Restart Action Plan established a performance based
approach to specify and control the actions required to demonstrate operations
readiness for* restart of both Salem units. The Operations Restart Action Plan aimed
to improve the fundamental conduct of operations to ensure safe and controlled
operation of the Salem units. The inspector reviewed operations progress. toward
restart readiness for Salem Unit 2.
b.
Observations and Findings
The Operations Manager identified six major areas for improvement, an~ dev.eloped
six problem statements to describe the weaknesses and outline corrective actions.
On January 4, 1997, the Salem Management Review Committee (MRC) approve*d *
. the operations department affirmation of readiness for restart based on completion
of all but eight rnDde-dependent actions. The operations staff developed condition
resolution corrective action (CRCA) reports to track completion of the remaining
items .
Problem statement no. 1 identified deficient operations department leadership. The
operations manager found weak direct supervision of activities in the control room
and in the plant. In response, he strengthened shift_ resources through increased
shift technical ~dviso.rs (ST A) staffing, hiring seven previously licensed SROs with
significant operating experience, and balancing operating crews based on strengths,
weaknesses, and personalities. The operators improved their leadership skills
through peer visits to SALP I plants, establishment of shift mentors, and operator
restart training. To improve oversight of. plant activities, the operations manager
created an~ staffed a field supervisor position, increased shift manning, and
improved operations standards.
The inspector observed significantly improved operator performance. The ST As
contributed additional independent safety focus and provided effective technical
specification tracking. The newly hired SROs provided fre.sh *insight allowing them
to identify process and procedure deficiencies. Ope.rations management routinely
evaluated control roorn crews and took appropri~te and timely action to improve
crew performance in the simulator and in the plant. * Operator ownership and *
leadership improved substantially. The SNSS's led the shift turnover meeting,
directed the maintenance briefing and maintained strict control of the control room.
Control room operators demanded reliable equipment, *carefully controlled
evolutions, and displayed. improved professionalism. Although the operations*
manager had not developed a way to insur~ compliance with this expectatiori, the
inspectors observed that th~ SNSS and SROs spent more time in the plant. As a
result, field supervisors identified equipment' deficiencies,* procedure inadequacies, .
scaffolding shortcomings, and housekeeping issues.
The inspector concluded th~t
. '
10
'
.
operations mana'gement adequately staffed the operating shifts to support Unit 2
restart. The inspector considered the actions to address problem statement no. 1
adequate to support restart.
Problem statement no. 2 identified deficient operations standards for plant and
personnel performance. To address this deficiency, operations management
developed SC.OP-DD.ZZ~0004, Operations Standards, and SC.OP-AP.ZZ-0002,
Organization and Responsibilities. Operators received significant tra.ining and re-
enforcement of these standards during the restart training program .. fn addition,
operations management frequently provided guidance reg*arding adherence to
standards in Night Order Book entries. The operations supervisors received
Management Action Response Checklist (MARC). train.ing to provide the tool to
enforce department and station standards.
The inspector concluded that the new standards and organizational *responsibilities
documents provided practical guidance consistent with high standards of
excellence. Sirice completion of restart training, the operators demonstrated
improved adherence to procedures, vigilant monitoring and control of safety
significant evolutions, conservative decision making, a~tention-to:..detail, prompt
identification of degraded conditions, a:ld heightened professionalism. *(See.
sections M2.1, and 04.1 of this report and sections 02. 1,. 03.1, and 04.1 of
Inspection Report 9(3-17 .) The Night Order Book entries and shift mentor
observation~* provided clear, concise and timely re~enforcement of the standards
and discussion of operator performance that fell short of the standard. The
inspector considered the actions to address problem statement no. 2 adequate to
support restart.
Problem statement no. 3 identified that operator ownership of the plant,
corrimunic.ation of *priorities and leadership in problem resolution needed
improvement. Teamwork between operations, maintenance, engineering and
planning also required improvement. To improve operator ownership of the plan.t,
the operations manager .assigned SROs as managers for each plant system. Each
system manager inspected the assigned system, conducted readiness reviews, and *
coordinated with system and design engineers. As a result of their assigne.d
system responsibilities, the SROs demonstrated significant ownership for their
systems. For *example, they documented degraded c9nditions, tracked work order
status, verified post-maintenance tests, and concurred in system *restart readiness.
The control room modifications resulted in more direct SRO involvement and control
of plant activities and improved SNSS oversight of both Salem units.
The plant managers implemented comprehensive control room modifications to
enhance operating shift communications and SRO command and control. Operator
restart training and operations standards implementation resulted in improved
communications within the department and with other plant organizations. For
example, the RO, SRO, SNSS, and STA turnovers incorporated improved
communication of plant status, planned evolutions, and degraded conditions .
. Operators made timely and appropriate calls to operations management of
equipment, process, and human performance problems. They aggressively
- -~
11
documented* deficiencies, communicated concerns to management, and involved
the appropriate disciplines to address and resolve problems: The inspector
concluded that operators demonstrated satisfactory plant ownership, acceptable
leadership, and effective communications. The inspector considered the actions -to
. address problem statement no. 3 acceptable to support restart.
Problem Statement No. 6 identified weaknesses in operator emergency
preparedness that resulted in an ineffective emergency response organization (ERO)
response during the October 5, 1995 Salem Alert. Inspectors reviewed the
effectiveness of the ERO as part of NRC restart inspection .item 111.13 (see section
PS of this report.) The inspector considered the actions to address problem.
statement no. 6 acceptable to support restart.
The actions to add_ress probl~m statements nos. 4 and 5 remain-0pen pending NRC
review.
- '
c.
Conclusions
The operations staff made significant progress toward operations department
restart readiness. Operators established themselves* as leaders in the organization
and demonstrated plant ownership. Operations management established high
.
standards and made. steady progress .to improve operator performance as measured
against those standarqs. Operators demonstrated improved communications within
the department and between supporJ:ing departments.
08.2 (Closed) LER 50-272/95-019: operability functional test not performed prior to
mode entry. On July 26, 1995, PSE&G identified that on July 25, 1995, Salem
Unit 1 operators entered mqde 6 with containment purge* in service and
containment purge valves inoperable. This is a violation of TS 3.9.9. The licensee
attributed the failure. to ensure purge valve operability to* an inadeq~ate Integrated
Operating Procedure,. inadequate operability status tracking, and inadequate
tracking and follow through of maintenance activities.
Upon discovery,* _operators stopped the containment purge and satisfactorily_ stroked
the purge valves to ensure operability. Operators determined that the plant staff
did not perform any core alterations in ll)ode 6 prior to the discovery. The plant
staff revised procedures to ensure adequate review of outstanding work orders,
condition resolution reports, operability determinations, technical specification
LCOs, and surveillances prior to *a mode change.
The inspector verified procedure revisions to the integrated operating and operability
.determination procedures. The inspector determined that the violation had minimal
safety consequence. based o.n purge valve operabiiity and discovery prior to core
alterations. This licensee identified and corrected violation is being treated. as a .
non-cited violation, consistent with se.ction Vll.B.1 of the NRC Enforcement Policy.
12
08.3 NRC Restart Item 111.a.10 - Corrective Action Program (Closed)
NRC Restart Item 111.b. 7 - Licensee Restart Plans, Corrective Action (Closed)
a.
Scope
The inspectors assessed the overall effectiveness of the licensee's corrective action
program (CAP) by reviewing: program consolidation; action requests coding;
program interfaces; timeliness of corrective actions; CAP backlog; control room
deficiencies; operator workarounds; root cause analysis and corrective action
effectiveness; and audits. The inspectors also reviewed the licensee's progress in
completing their Corrective Action (CA) Restart Action Plan*, Rev. 7, dated October
10, 1996.
b.
Observation and Findings
Corrective Action Program - Overview & Consolidation
The licensee's Corrective Action Program begins with the submission of an Action
Request (AR) for an actual or potential problem. This results in one (or more) of the
following: a Condition Report (CR), a Corrective Maintenance (CM~ *.work request, or
a Business Practice* (BP) evaluation. The Nuclear Business Unit (NBU) *uses Civls to
fix equipment degradations and failures .. The NBU uses a CM, CR, or both to
resolve problems that involve safety related structures, systems, or c.omponents
(SSCs). The NBU uses BPs to address problems that involve non-safety related
SSCs or to enhance organizational performance. In general, plant staff must
evaluate CRs and formulate the necessary corrective actions (CAs) within 30 days.
The plant staff then schedules the actions for completion over the next six months.
Salem divided Condition Reports into three level~ based on their safety significance.
Level 1 CRs have the most significance and require completed root cause
evaluations prior to prescribing CAs. Level 2 CRs*have moderate significance, and
receive less rigorous apparent cause analysis. Level 3 CRs represent minor
significance problems trended by the staff. The NBU uses various management
reviews to improve the. quality of level 1 and 2 CRs. They have developed
performance indicators to assess CR timeliness and trend quality.
Prior to the current CAP, the NBU distributed multiple corrective action processes
among separate programs. Some of the primary methods used for identifying and
correcting problems at the station consisted of Incident Reports (IRs) and Document
Evaluation Forms (DEFs). The Corrective Action Program consolidated and replaced
the previous programs. Procedure NC.NA-AP.ZZ-0006(0), "Corrective Action
Program," Revision 14 describes the licensee's current consolidated CAP.
Action Request Classification
From the number of ARs initiated on a daily basis by* the various depa'rtments, the
inspectors concluded that all staff levels used the CAP. The inspectors found that
the staff initiated ARs to identify potential conditions adverse to quality and
1
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13
appropriately classified them as CRs based on their significance. Department
managers screened the significance level 2 and 3 CRs and significance level 2 CMs
for the previous 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. With few exceptions, managers ensured appropriate
significance* levels. However, a recent NRC inspection (50-311 /96-16) identified
some weaknesses.
A self-assessment report (SA-96-05) revealed that plant staff
incorrectly coded four ARs with conditions adverse to quality as Business Process
(BP) instead of CRs. In *addition, during the current inspection period, inspectors
identified additional similar problems associated with the PORV accumulators (see
section E1 .1.)
Program Interfaces
The inspectors reviewed a list of Condition Reports (CRs) to verify that all of the *
departments used the CAP. The inspectors determined that the operations,
maintenance, and engineering departments consistently initiated ARs for plant
problems. Additionally, radiation protection, security, and emergency preparedness
(EP) staff had increased AR initiation' from the marginal levels of the past two
months. The EP staff had started training a root cause specialist to improve the
department's abil!tv to do root cause evaluations. The_ inspectors considered
continued management emphasis necessary to Qssure that_ support orcanizations
use the CAP ..
Occasionally~ coordination problems occurred when using the CAP. For example,
engineering and licensing improperly scheduled completion of corrective actions for
inappropriate greasing of doubled shielded motor bearings (see NRC Information
Notice 94-51) for a time after the projected Salem Unit 2 restart. Although* the
inspector found that plant staff had previously satisfactorily resolved this issue, the
CR did not accurately reflect the overall status, and all of the parties did not know
its status .. **
Timeliness of Corrective Actions
Although the CAP performance indicators through November 1996 indicated that *
the average for level 1 and 2 CR evaluations exceeded the 30 day timeliness goals,
the inspector noted a generally improving trend in timeliness. This is noteworthy
considering the large number of ARs entering the sys~em. P.lant staff routinely
completed corrective actions within approximately 180 days, the *industry norm.
The performance indicators showed fewer overdl!e corrective actions over the past
couple of months. The inspectors considered corrective action timeliness
acceptable.
Corrective Action Program Backlog
The inspectors reviewed the Incident Reports (IRs) and Document Evaluation Forms
(DEFs) backlog through November 1996. Salem management requires that plant.
staff complete evaluations of all backlogged Incident Reports for restart of the
. Salem Units. The number of open IR evaluations for Salem 1 and 2 decreased from
approximately 500 in July 1995, to 2 during the inspection. The in"spectors *
.-.
14
considered the reduction significant. The total number of open DEFs decreased
from 1386 in June 1995, to approximately 318 as of September 1996. Of these,
engineering must resolve 203 before Salem Unit* 2 restart.
As a result of the DEFs,
engineering has the oldest and largest number of backlogged CAP items. The *
inspector reviewed nine safety significant DEFs to ensure that engineering correctly
assessed the backlogged DEFs for Salem Unit 2 restart.
lnspe~tors noted only one
minor deficiency.
- In November 1996, 3,055 Unit 2 CRs remained open. lri January 19971 310
significance level 1 and 2 CRs remained to be resolved for prior to Mode 4 for
Salem Unit 2. Based on review of a sample of open level 1 and 2 CRs, the
- inspectors determined the licensee appropriat~ly eval.uated CRs *as a Mode 4.
restrai.nt or *a post-,restart CR.
The inspectors concluded that the NBU adequately tracked and monitored the
corrective action backlog.
Control Room Deficiencies
The inspector observed control room activities and indications, and reviewed
control room logs and Other source documents to *assess whether the use of the
CAP has effectively eliminated control room deficiencies. The inspector noted that
operators appropriately identified out of tolerance conditions and included
explanations in the December 30 through January 5 operator logs. The inspectors
noted a minor example of poor shift turnover concerning work on a ground on the
28 125 VDC bus. .In another case, technicians attempted to repair control room
indication of steam generator blow.down flow on three separate occasions. Each
repair attempt resulted in a failed retest~ The inspector discovered that the plant
staff had not involved engineering with the rework or initiated a CR to address .the
failed retests.* The inspector also, noted that NAP-6 does not require a CR for
multiple fai!ed n~tests, and the CM to correct the incorrect blowdown flow
indication remained open. The .inspector concluded that, although lack of a CR f.or
multiple failed retests do.es not viplate any requirements, it reduces the opportunity
to identify design and human performance deficiencies .
Operator Workarounds
The inspector reviewed the licensee's management of operator wo~karounds in
relationship to the Corrective Action Program. Inspectors docume.nted assessment
of the workaround program in section 02.1, above.
As of January 8, Salem Unit 2 had 10 open operator workarounds ~and 10 *open
operator burdens. Workarounds may result in the initiation of a plant transient or
reduce mitigation effectiveness, whereas a burden typically requires compensatory
action for* a minor hardware deficiency. The inspector determined that the plant
staff understood the nature of the open items and had entered each of the items.
into the CAP. The* inspector noted, however, that operators considering the
feasibility of lowering the Diesel Generator (DG) jacket water temperature alarm set
15
point to account for expected low service water (SW) temperatures did not review
the UFSAR or other licensing documents. The inspector noted that Hope Creek
previously identified cooling water temperatures below those assumed in the
system design basis. The inspector reviewed the Salem UFSAR and found no
specific temperature limitations. The licensee issued a CR to co'nsider the generic .
implications of this observation.
The inspector noted that the Salem staff developed the list .of workarounds from a
review of CMs and did not include CRs. The inspector noted that,* as a result, the
licensee may not have included corrective actions, such as compensatory
measures, resulting from CRs. This would constitute an operator burden or
workaround. For example, operators previously performed a workaround for the
atmospheric relief valves, and past ventilation problems documented in incident *
reports (a precedent of CRs) required workarounds in the form of open doors.
Although plant staff had documented the problems in incident reports, plant staff
did not recognize them as workarounds, and did not correct the deficiencies. The
licensee plans to revise their program to address this concern.
Root Cause/Corrective Action
Root cause analysis skills have improved as the corrective action pro~ram has
matured. The Root Cause Manual (RCM) provides detailed in~tructions for apparent
and root cause evaluations: The Corrective Action Review Board (CARB), a
management team, reviews Level 1 CRs, to assure quality of corrective actions
commensurate with safety significance,. The Corrective Action Review Committee
(CARC) performs a similar review for level 2 CRs. The inspector noted that the
CARB and CARC routinely rejected inadequate CRs, effectively ensuring high
standards for corrective actions. Management also used CARB and CARC rejection
rate trends to assure personal accountability and improve performance.
QA Audits
In 1996, Quality Assessment (QA) performed two audits of the corrective action
program, and the Sale~ Integrated Readiness Assessment (SIRA) team performed a
third audit. Based on a review of 10 level l CRs containing numerous examples of
weak or inadequate performance, the first QA audit (96-190-1, May 13 to June 10)
concluded that the .CAP was ineffective. Weaknesses in these CRs included
inadequate corrective actions, insufficient corrective action* records, incomplete or
unperformed corrective actions. The SIRA report also assessed the CAP as not
ready for restart. The second QA audit noted improvement .in the* quality of level 1
CRs. It also identified improved use of ARs to identify plant problems; better
control of documentation, including record transmittal and retention; and less
maintenance staff reluctance to submit ARs for human. performance issues. The
audit identified timeliness of operability reviews for level 1 & 2 ARs, feedback to
employees on the results of ABs that they initiated, and condition resolution
verification as areas needing further improvement.
'(.
. c.
) .
16
The inspector considered both QA audits and the SIRA audit comprehensive. The
inspector also determined that the audit teams provided independent assessment.
The audits 'probed the corrective action program in detail and contained appropriate
observations and findings to support their conclusions.
Restart Plan
The corrective action program restart plan contains eight problem statements that
relate to the following areas: program consolidation, roles/responsibiliti~s, backlog,
timely completion of CA, root cause analysis (RCA) and CA effectiveness, trending
and common cause analysis,. operating experience feedback (OEF) effectiveness,
and the SIRA CA conclusion follow up.
lnspe~tor$* previously found the CAP roles and responsibilities acceptable. As noted
above, the CAP consolidated the previous corrective action program to provide a
single point of entry by initiating an. Action Request. The CAP has a very low
threshold for problem reporting, demonstrated by more than 1000 ARs per month ..
Inspectors found that the managers verified appropriate AR classification, and
evaluation managers demonstrated improved accountability. Root cause analyses
and CA implementation have continued to improve as a re~ult of *strong CARC and
CARB quality oversight. The QA audits provided comprehensive assessment with
well supported conclusions.
Managers used performance indicators effectively to .
monitor CAP perfprmance. The inspectors concluded that the NB.U effectively
implemented the important elements of the restart plan.
Conclusion
The corrective action program has continued to improve.. The CAP has a low
thresho.ld for entry and, using it, the Salem staff rou~inely identified plant problems.
Although* some departments did not routinely use the program in the past, the
number of ARs* that they have written has increased over the two *months
preceding the inspection. Except for open DEFs in the process of conversion into
ARs, the backlog of items from old*corrective action systems items is lqw.
Control room operators willingly initiate ARs for observable deficiencies. The
operators effectively entered bur.dens and workarounds in the *corrective action
program. The inspectors noted that, in one case, ope.rators did not review the
UFSAR or other licensing basis information prior to proposin.9 CAs.
Root cause analyses and CA implementation continued to improve. The .CARC and
CARB provided very effective oversight. Th~ QA audits provided comprehensive
assessment of the CAP with well supported conclusions. The auditors found that
many AR initiators did riot receive feedback on the disposition of. their concerns. *
Deferrals of .work to post restart periods appeared appropriate. Evaluation
managers understood their responsibilities to the CAP and their performance has
improved. Performance indicators provided an effective way for managers to
monitor departmental CAP performance. The quality of level ~ and i CR
evaluations continued to improve.
. 17
In summary,. the licensee has. significantly improved, and continues to improve, the
corrective action program. They implemented appropriate controls to maintain CAP*
performance. The inspectors considered actions to improve the corrective action
program and the corrective action restart plans adequate to support Salem re*start.
II. Maintenance
M 1
Conduct of Maintenance
M 1 . 1 General Comments
a.
Inspection Scope (62707)
b.
The inspeGtors observed all or. portions of the following work activity:
- 960904263:
22 RHR pump .upper motor bearing oil leak
The inspectors observed that the pla.nt staff performed the r:naintenance effectively
within the requirements of the station maintenance program.
Inspection Scope (61726)
The inspectors observed all or portions of the following surveillances:
- S2.0P-ST.DG-0001 :*
- S2.0P-ST.DG-0002:
- S2.0P-ST.SW-0011:
- S2.RE-ST.ZZ-0002:
- S2.0P-ST.CS-0006:
- S2.0P-ST,.DG-0003:
- s2.op.:sr.PZR-0002:
- S2.0P-ST.SSP-0011:
- S2.0P-ST.AF-0004:
2A diesel generator surveillance test
2B diesel generator surveillance test
In service testing of service water--2SW26 valve,
modes 5-6
shutdown margin calculation
containment spray valve verification modes 1-4
2C diesel generator surveillance test
. In service testing PORV and PORV block valves modes
1-6
engineered safety features - response time testing
In service testing auxiliary feedwater valves modes 1-6
The inspectors observed that plant staff did the surveillances safely, effectively
proving operability of the associated system.
M1 .2 Maintenance Department Backlogs, NRC Restart Item 111.4'.2 (Open Unit 1, Closed
Unit 2)
a.
. Inspection Scope
Before the* shutdown of the Salem units, Salem staff consistently operated the
plants with a large (i.e., approximate*ly 3500) backlog of corrective maintenance
work orders. This contributed to the degraded material conditions arid. to the failure
18
to properly *identify and set priorities for work. To resolve this problem, PSE&G
developed a formal plan to reduce the corrective maintenance .bac.klog.
The Inspector discussed the plan with Salem planning personnel; reviewed the tools
to monitor the backlog size, aging, and work-off rate; and evaluated the backlogged
work orders for Unit 2. The inspector also evaluated the screening process for
work orders. Finally, the insp~ctor reviewed a sample of post restart backlog items
. to determine if the system engil")'eer appropriatelx categorized them.
- *
b. Observations and Findings
System managers determined Whether a work order is restart required or post
restart using the screening criteria in procedure SC.SE-DD.ZZ-0001 (Z), System *
Readiness Review Program. The inspector had previously reviewed the criteria and
found it satisfact<;>ry (see section E1 .2 of this report.) The system managers
performed the screening process formally three times per that procedure prior to
restart. From this screening, system managers may categorize work orders as post
restart and the work orders then become a part of the maintenanc~ backlog. At the
- time of inspection, the backlog consisted of more than 3000 work orders.
The maintenance department plan .for reducing* this backlog focused on. Unit 2 at
the time of the inspection. Maintenance management developed the plan to reduce
the backlog to 400 corrective maintenance work orders before the next refueling
outage. As part of this plan, the majntenance department reviewed and verified the
validity of the work orders by performing field walkdowns. This process confirmed *
the post restart categorizations, and insured accuracy and sufficient detail in the
problem descriptions. Plant staff stated that they h.ad completed the walkdowns
for the backlog. The maintenance staff plans another review to evaluate the work
- orders for planning pi:Jrposes and. parts requir~ments in early March. The
maintenance manager expected to rec;tuce the backlog by about l,000 work orders
by early March.
' *
The inspector reviewed the entire list of backlog work orders to independently
determine* if plant staff had. correctly characterized the work as post restart, and to
assess the resources required for completion. No work items required significant
manpower (i.e., overhauls or replacements for major plant components) but 16
work orders appeared to meet the screening criteria for restart required work. The *.
system readiness manager provided information that justified the post restart*
classification for 15 of th*e work orders. However, one post restart work order
required verification of .U-bolt torque values for 31 seismic restraints. Following
engineering reevaluation, plant staff reclassified the wor~ as restart required, *and
rescheduled implementation. prior to Mode 4. The inspector noted that the torque
. verification had minor significance, and plant staff had correctly classified the great
majority of post restart wo'rk.
The inspector found that Salem planning had implemented a comprehensive
database to monitor the backlog reduction effort an.d various stages of work order
processing, such as planning, work restraints, work status, retesting, and closure.
<.
19
The database enables managers to identify and correct problem areas that reduce
the effectiveness of the backlog reduction effort.
c. Conclusions
Although Salem Unit 2 has a sizable corrective maintenance backlog, the work
would not impact plant safety or maintenance resources. Also, with one minor
exception, plant staff properly classified the work orders as post restart: The
inspector concluded that Salem staff adequately managed the backlog ~o support *
the restart of Salem Unit 2.
M2
Maintenance and Material Condition of Facilities and Eq.uipment
M2.1 Unit 2 Refueling Activities
a.
Inspection Scope (607101
b.
The inspectors observed refueling activities from various locations to ensure plant
staff properly controlled and conducted the activities.
Observations and Findings
.
.
On December 16.1996, Unit 2 operators commenced refueling and entered mode
6. The control room operating shift properly controlled fuel handling activities using
disciplined 3-point communications and safety-conscious monitoring of important
control room parameters. In particular, operators controlled* the pace of the core
reload and verified source range counts and startup rate as each fuel assembly
entered the core. In past Salem refuelings, operators monitored refueling activities
for compliance with regulato.ry -requirements, but c_ol')tractors directed the refueling.
During the December 1996 refueling, operators clearly controlled all facets of the
evolution .and demonstrated their ownership of the plant. For example, the
.
operators appropi-iately suspended fuel movement to replace a faulty clutch
mechanism that affected. slow speed operation of the fuel handling crane. Reactor
engineers and the Reactor Engineering Manager provided substantial oversight of
fuel handling activities* at each watch station. The inspector observed good
maintenance technician control of foreign material exclusion, and radiation
protection technicians ensured proper implementation of radiological controls.
At 10:05 a.m. on December 19, while walking down Unit 2 containment
penetrations, the inspector identified that maintenance technicians removed a
service water (SW) valve (24SW223) that p<;>tentially affected containment
integrity. The Senior Nuclear Shift Supervisor (SNSS) promptly dispatched an
equipment operator to verify loss of containment closure and at *10: 18 a.m. the
SNSS suspended fuel handling. With 24SW223 removed from the piping, a release
path existed from the atmosphere inside containment (thrnugh tagged open valves
24SW269 and 24SW63) to the atmosphere outside containment (thr~ugh
24SW223). The pathway violated the containment integrity r:equirements of
Technical Specification 3.9.4.
20
- Preliminary Salem investigation revealed significant weaknesses in the work control
process. Initial investigative results indicated that on December 7, the work control
center (WCC) authorized the work on 24SW223. The job sup*ervisor signed on the*
work order on December 9. On December 13, technicians removed the actuator for
24SW223. On December 15, operators verified the 24SW223 valve intact in
accordance with S2.0P-ST.CAN-0007, Refueling Operations - Containment Closure,
in preparation for moving fuel. On December 17, technicians removed the
24SW223 valve to inspect the internals. The licensee also identified pilot holes
drilled in 21 . and 24 CFCU SW piping that the WCC authorized ori December 5 for
design change package (DCP) 2EC-3590. These holes added additional :vent paths *
outside containment.
The licensee initiated a significance level 1 root cause analysis of the event (CR
961219244) and reestablished containment integrity. The actions .included
reinstalling 24SW223, closing additional SW containment isolation valves
(21 SW58, 21 SW72, 24SW58, 24SW7.2), performing S2.0P-ST.CAN-0007J
reviewing all work in progress, and inspecting containment penetrations. In
addition, the Salem general manager implemented a requirement that all workgroup
leads brief the SNSS twice daily on the specific items they intend. to work that
shift. The operations manager provided immediate "lessons learned" to all*
operations personnel. At 10:29 p.m. on December 20, Unit 2 _operators
recommenced fuel handling activities. At 2:51 p.m. on December 21, Unit 2
operators completed core reload with no further problems.
The event had no actual safety consequence, since* the fuel handling accident did
not occur during the period of time that the licensee failed to maintain containment
integrity. The potential existed to release radioactive material to the auxiliary
- building if a fuel handling accident had occurred. In that case, the release* could not
have met design requirements for a filtered flow path, but the plant vent radiation
monitors would have _monitor_ed the release. The inspectors noted that since Salem
unit 2 had not operated for 18 months,. the spent fuel involved had very little decay
heat or*f~el gap radioactivity. The inspector concluded that movement of irradiated
- fuel in the containment building without containment closure is a violation of
Technical Specification 3.9.4 (VIO 50-311/96-18-02).
. c.
Conclusions
The licensee failed to maintain containment closur~ while conducting Unit 2 core
reload. Plant manag~ment responded promptly_ and appropriately to address the
associated weaknesses; Excepting the loss of containment closure, the operating
shift demonstrated improved plant ownership in the professional and safety-
conscious conduct of fuel handling activities.
M2.2 (Closed) LER 50-272/96-014 - potential hydrogen embrittlement on 4KV breaker
parts. In July 1996 during 4KV ,breaker m.aintenance, technicians found a broken
roll pin. Each breaker has .two roll pins. The breaker would still operate with the
failure of one* pin but would not open or close with the failure of both pins. The
plant staff determined that hydrogen embrittlement, resultin'g from zinc plating*
21
during vendor refurbishment, caused the roll pin failure. The corrective action plan
included removing affected breakers, and sending them for the appropriate repairs.
Prior to the repair work, PSE&G QA placed a stop work on the vendor until
subsequent inspections demonstrated that they had resolved the problems .. The.
licensee planned to complete the repairs prior to considering any of the breakers
operable. The inspector noted that the breakers did not affect plant safety due to
plant conditions, and consider~d the completed and planned corrective actions
appropriate to resolve the problems. This LER is closed.
Ill. Engineering
E1
. Conduct of Engineering
E1 .1
Undersized Power Operated Relief Valve (PORVl Accumulato.rs (NRC Restart Issue
11.23 - Unit 2 only)(Openl
a.
Inspection Scope
To determine the acceptability of PORV accumulator sizing, the inspector reviewed
the restart item closure package, the 10 CFR 50.59 safety evaluation, the UFSAR
change notice, engineering evaluations, calculations, test procedures, training
records, condition reports, and work orders.
b.
Observations and Findings
In the original safety analysis of an inadvertent saf~ty injection (SI), a Condition II
event, i:>SE&G assumed operators would act to terminate the event prior to the
- pressurizer completely filling with water. As .a result of reanalysis, and since Salem .
had not qualified the code safeties to .operate with water flow, PSE&G determined
that the pressurizer PORVs would have to actuate automatically to control RCS
pressure. A stuck open code safety valve resulting frorn water flowing through it
would result in a sm~ll-break loss of coolant accident (LOCA), a Condition Ill event.
One desig*n requirement for a Condition II event is that it should not propagate into
or cause a more serious fault (e.g., a Condition Ill event).
Two air accumulators per PORV provide air to open the pressurizer PORVs. Check .
valves in the accumulator air piping prevent the air pressure from bleeding down,
thus preserving the air for PORV operation. During reanalysis, PSE&G determined
that mitigating. an inadve'rte.nt SI may require the PO RVs to automatically cycle 220
times. Based on this determination, PSE&G did an evaluation of the adequacy of
the PORVs, including supporting systems and equipment~.*
Engineering Review
The engineering evaluation of the PORVs included a review of the thermal-hydraulic
effects and piping loading, determination of operato.r action times, verification of
accumulator adequacy, evaluation of controls and air system adequacy, and
22 .
evaluation of PORV endurance. Engineering evaluation S-2-RC-MEE-1108, Salem
Unit 2 Evaluation of the Pressurizer PORVs for Inadvertent SI; Rev. 0, dated August
23, 1996, documented this review. The engineers calculated that the PORV air
accumulators could support 305 full strokes and an additional 486 part.ial strokes
(50% or greater opening). The calculation credited RCS system pressure in
assisting the PORV opening and assumed the accumulator check valves would not
leak more than 147 standard cubic centimeters per minute (seem.) The inspector
reviewed the engineering evaluation and other related documents and identified the
following issues:
In a review of the testing and maintenance history on the Unit #2 accumulator
check valves from 1993 through 1996, the inspector identified repetitive fa!lures of
the valves to meet leak rate acceptance criteria. As a re.suit of leakage, Salem
replaced two out of four check valves in 1993, one of fo'ur in 1994, and two of
four again in 1996. The inspector concluded* that PSE&G had not considere.d the
past failure history of the check valves during the re-analysis of the event.
The inspector determined that PSE&G had not revised the accumulator check valve
leak test procedure, SC.RA-IS.PZR-0024(0), Leakage Test of PORV Accumulators,
Rev. 3, dated March 15, 1996, to compensate for the maximum func!ion pressure
across the accumulator check valves as required by ASME Section XI, Pump and
Valve lri service Test Program, 1983 Edition. The test procedure specifies
conducting the check yalve seat leak test at a pressure differential of five psid. The
inspector determined that the test should consider a*n actual pressure differential
during the inadvertent SI, of eighty-five psid. The ASME code Section XI,
.
Subsection IWV, paragraph IWV-3420, Valve Leak Rate Test, Step IWV-3423 (e)
permits reduced pressure differential leakage testing provided the test compensate
the results to the function maximum pressure differential.* The Salem staff failed to
compensate the results as required.
The failure to conside.r the adequacy of the accumulator check valves for suitability
of application, and the failure to revise* the accumulator ~eak test procedure as a
result of the re-analysis of the inadvertent SI .at power event, *is considered a
violation of 10 CFR E!O, Appendix B, Criterion Ill~ Design Control (VIO 50-
272&311'/96-18-03)
Review of* 10 CFR 50. 59 Safety Evaluation Process
The Offsite Safety Review (OSR) Group initiated CR 970106283, documenting a
conflict between the inadvertent SI event safety evaluation (S96-125) and the
Salem PORV TS basis. The previous analysis of inadvertent SI concluded that
operators would terminate SI flow before the pressurizer filled with water. The*
reanalysis concluded that the operators would not.terminate the SI flow before the
pressurizer filled with water. As a result, the re-analysis took credit for the
automatic operation of the PORVs in c'ontrolling RCS pressure and preventing the
pressurizer code safety valves from opening. Since Salem *qualified the PORVs for
operation with water flow and had not qualified the pressurizer code safety valves
23
for water flow, the reanalysis credited automatic operation of the PORVs to prevent
a small break LOCA resulting from a stuck open pressurizer code safety valve.
The OSR reviewer concluded, however, that the reanalysis required a change to
Technical Specification for PORVs. Salem Unit 2 Technical Specification 3.4.5
allows continuous operation in Modes 1, 2, and 3 with one or both PORVs .
inoperable and capable of being manually cycled, provided the associated block
valve is shut. The TS bases state that the PORVs may be inoperable due to
automatic control problems as long as the cause does not prevent manual use or
create the possibility for a small break LOCA. The reviewer correctly concluded
that the reanalysis r~quired a change to TS 3.4.5 to prohibit continued plant
operation with both PORVs inoperable due to loss of automatic function. At the
close of the inspection, development of a License Change Request neared
completion.
The inspector determined that the safety evaluation incorrectly concluded no
unreviewed safety question existed for the following. reasons:
1.
The probability of an accident previously evaluated ,in the SAR increased. In
the previous analysis, operators terminated the inadvertent SI before it filled
the pressurizer and presented the*potential that a code safety valve would
.stick open as a result of water flow through the valves. In the new analysis,
the operators did not terminate the SI before it filled the pressurizer. The
safety evaluation did not identify increased probability of an accident
previously evaluated.
2.
The probability of occurrence of a malfunction of equipment important to
safety previously evaluated in the SAR slightly increased. Since the SI filled
the pressurizer in th~ reanalysis, the probability of malfunction of a code
safety increased, *since.* Salem has not qualified the code safeties for
operation with water flowing through them. The safety evaluation did not
ide~tify increased probability of occurrence of a malfunction of equipment
important to safety previously evaluated in the SAR.
3.
The change creates a possibility of a malfunction of a different type than any
evaluated previously in the SAR, since the SAR did not previously credit
automatic operation of the PORVs to mitigate an inadvertent safety injection.
The PORVs are not safety related equipm~nt, and, although credited as
active compon~nts, do not have the ability to withstand a single active
failure. The safety evaluation c;lid not identify the possibility *of a malfunction
of a different type than any evaluated previously in the SAR.
4.
The proposal results in a reduction in the margin of safety as defined in the
basis for the PORV technical specification due to the fact the basis does not
consider the requirement ~or PORV ~utomatic control availability. The safety
evaluation did not iqentify a reduction in the margin of safety for Technical
Specification 3.4.5.
24
The engineering 'staff failed to recognize that it changed the licensing basis for an
inadvertent safety injection, and therefore required prior NRC review and approval.
The NRC clearly stated this guidance in NRC Inspection Manual Part 9900 Guidance
on 10 CFR 50.59, dated 4/9/96. The Salem QA staff identified the USQ and the
requirement to change Technical Specification 3.4.5.
As a result, the licensee
initiated a License Change Request to change Technical Specification 3.4.5, and
obtain NRC review of the proposed change. Since both Salem units have remained
shut down since June 1995, inability to mitigate inadvertent SI had no immediate
safety consequence. This licen.s.ee identified and corrected violation of 10 CFR
50.59 is being treated as a non-cited violation, consistent with Section Vll.8.1 of
In addition to the above, the inspector identified the follo.wing weaknesses in the* 10
CFR 50.59 safety evaluation:
The safety evaluation described the required operator action for the PORV block
valves differently from the assumptions in the FSAR re-analysis. The re-analysis
assumed that the operators would verify the block valves opened within ten
minutes of the onset of the event. The safety evaluation described this as making
one PORV available by opening its associated bl.ock va.lve.
The safety. evaluatiqn inappropriately implied that NRC Generic Letter 90-06
approved ul)e of the PORVs and block valves for safety related functions, including
steam generator tube rupture (SGTR) accident mitigation. Although Generic Letter
S0-06 stated that some plants rely upon the PO RVs for safety related functions,* it
did not provide NRC approval of PORV and block valve use for these functions.
The inspector further noted that Salem PORV use to mitigate the SGTR event
differed significaritly from PORV use to mitigate the Inadvertent SI event. The
inspector j::onsidered c*omparison of the two events *Without describing the
differences misleading.
EOP and Training Review
The inspector reviewed the EOPs. and Operator Training to determine how PSE&G
met the requirement that the PORV block valves had to be opened within ten
minutes from an inadvertent SI initiation.* The contin~ous action steps of 2-EOP- .
- TRIP1, Reactor Trip or Safety Injection, Revision 20, direct the operators* to verify
that the PORV block valves were opened.
The il'.lspector found that the four Unit 2
restart operating shifts had completed training. on the new requirements for
inadvertent SI. The operators successfully completed an inadvertent SI event on
the* simulator in October 1 996 with no preparation. The operator performance
times during the test varied from seven to nine minutes. The inspector concluded
that the combination of EOP requirements and operator proficiency training provided
confidence* that the PORV block valves would be opened within ten minutes of an
inadvertent SI event.
25
c. Conclusions*
Engineering staff failed to evaluate the PORVaccumulator check valves suitability
for use and failed to revise the IST check valve leak test procedure. An OSR
reviewer identified that re.analysis of the inadvertent SI involved an unreviewed
safety question and required a change to Technical Specification 3.4.5. This restart
issue remains open until resolution of the above issues.
E1 .2
Management of the Engineering Backlog, NRC Restart Item 111.4.1 (Closed)
a.
Inspection Scope
The inspector reviewed PSE&G's methods to monitor th~ backlog size, assess the
significance of backlog items on plant operation and safety, and to keep
management informed of emergent issues. The inspector reviewed the technical
adequacy of screening criteria used. to categorize items as post restart. The
inspector also reviewed a sample of backlog items categorized as post restart to
determine if any should have been categorized as restart required.
b.
Observations and Findings
The inspector found.that managers used several tracking methods to monitor the
number of outstanding corrective action work items, design change packages and
engineering work requests. The managers also used performance indicators to
monitor work schedule completion. The engineering performance monitoring .
system tracks open work items in four categories; Design Engineering, System
Engineering, Projects, and Fuel Engineering. This tracking system provided warning
indicators when backlog exceeded acceptable levels. The inspector observed red *
indicators for Design Engineering, representing a larger than acceptable backlog.
The manager of Des.ign Engineering knew of the "red" status and, although focused
on the items required. for Mode 4, he also addressed the total backlog. in meetings
held three times weekly.
The inspector reviewed the screening criteria in procedure SC.SE-DD.ZZ-0001 (Z),
System Readiness Review Program. The criteria provided sufficient .guidance to
correctly Classify engineering work as re_quired for restart or post restart. The
inspector also reviewed a list of approximately one-hundred post restart Design
Change Packages (DCPs) and found two with descriptions that lead the inspector to
suspect that they might be required for restart. The. inspector reviewed the two
DCPs and concluded that one had minor safety significance, was not critical for
restart and was categorized satisfactorily. The other DCP (DCP-2EC-3546), related
.to Appendix R requi~ements, and is the subject of NRC restart inspectipn Item 111.1.
.
.
During a previous inspection, inspectors reviewed a sample pf work documents
(Action Requests) assigned to engineering and concluded that Salem staff had
appropriately deferred only items of minor safety signjficance until after restart.
Also as part of that inspection, inspectors found that the Salem Engineering
Department had integrated key engineering personnel into daily plant meetings to
26
ensure that emerging engineering issues and problems were presented to system
engineering staff for review, prioritization, and resolution. The inspector concluded
that the Salem Engineering Staff successfully implemented a process for ensuring
identification and appropriate corrective action for emerging technical issues. The
inspector determined that the processes insured management awareness of
emerging technical issues and the content of the backlog. (Reference Inspection
Report 50-272,311 /96-16)
The inspector reviewed two PSE&G self-assessments conducted to* evaluate the
technical adequacy of the Nuclear Engineering Backlog Reduction Project (Report
95-17 and 96-03). The assessments identified many questions for response and
resolution by PSE&G Engineering. The inspector found that PSE&G had eith~r
resolved the issues or initiated appropr~ate corrective measures to address the
concerns. Th.e inspector determined that none .of the questions posed a significant
safety concern.
c.
Conclusions *
The engineering staff effectively managed the engineering backlog. Engineering
managers actively participated in prioritization of emergent iterris and, in so doing,
remained aware of *the content of the backlog. For those items samp~ed, the
inspector considered the post restart categorization either acceptable or, in one
example, not yet finalized. This restart item is closed.
E1 .3
Containment Fan Coil Unit Operability
The purpose. of the CFCUs is to cool the containment atmosphere during post
accident conditions. There are six two-speed (slow and fast) CFCUs. Normally,
three of the CFCUs run in fast speed to cool the. containment during power
conditions. Post-LOCA conditions require all six CFCUs to run at slow speed to
provide long term containment cooling.
During accident .conditions, all running service water (SW) pumps trip and resta'rt in
the prescribed load sequence. Prior to restoration of power, *service water will drain
from the elevated CFCU heat exchangers down toward the river elevation. This
causes voids to form in the CFCU heat exchangers and SW piping. * When the SW
system restarts on restoration of power, the voiding causes rapid acceleration of
flow through the system piping, in turn causing severe water hammer at the 90
degree pipe bends. .If the water hammers cause failure of the SW pipe in
containment, a containment breach would result, providing a release path to outside
of containment. 'Isolation of the affected SW pipe would also result in loss of the
containment cooling function.
The PSE&G Nuclear Engineering Design department started to develop a standpipe
modification to address this co.ncern. The standpipe will preclude CFCU cooler and
pipe voiding during the time delay prior to restarting* SW pumps.
27
E1 .4
Steam Generator Replacement Project (SGRPl
a.
Scope (50001 l
The inspector reviewed current and planned work, related procedures,
documentation, quality inputs and progress of the Salem Unit 1 steam generator
replacement project (SGRP). The site inspection included observations of
conditions and work in and outside the *containment structure;
The inspector reviewed project nonconformance reports (NCRs), and temperature
limits on lifting equipment and SGs. The inspector observed original steani
generator (OSG) shipping preparation area, struc~ural steel welding in containment,
and the weld rod ovens and weld rod issue conditions at the fabrication shop and in
containment. The-restoration process including sea-van and Hope Creek storage of
equipment and plant components was examined. The SGRP related tasks including
project self assessment, Quality Assurance by PSE&G, Raytheon Nuclear (RNI) and
Framatome Technologies (FTI); the FSAR Project relation to SGRP engineering data *
inputs, SGRP improvement progress, fire control and the work package closeout
process were rev_iewed.
b.
Observations *and Findings
By January. 1 7, 1997, the licensee had shipped two OSGs off site for burial and
prepared the remaining two for shipping in the preparation area. During the
inspection, workers transported the first replacement steam generator (RSG) to the
Unit 1 containment building. Project staff had substantially completed work in the
RSG staging area, with work package documentation and review in progress.
The inspector reviewed nonconformance reports (NCRs) written as of 1 2/23/96 to
determine the scope of identified nonconformances and related corrective actions.
Welding of lower support structural steel for the RSGs used proper preheating and
welding techniques. The supervisors controlled work packages in the work area.
The inspector verified appropriate implementation of temperature limits to prevent
brittle fracture or low *temperature equipment failure of steam generator rigging,
lifting and movement in the winter months. The work planr.1ing identified a low
temperature limit of 1 5 degrees above zero, Fahrenheit, for the lower runway
system.
The project staff initiated the component restoration process in .the work packages
for' component removal early in the SGRP sequence. The inspector sampled
removal work packages, the lists of removed components and examined the sea-
van and Hope Creek storage of equipment and plant components to establish the
level of control on removed components. Although the manufacturer's manual for
snubbers (PA88780) provides a prolonged storage temperature ra~ge of 40 to 170
degrees F for hydraulic snubbers, the inspector found the hydraulic snubbers stored
.. in a sea-van subject to temperatures less than 40 degrees F. The snubber
manufacturer indicated that for the short storage term involved, exposure to*the
- .
. 28
lower temperature should cal!se no degradation of the snubbers. The inspector
identified no. other potentially environmentally sensitive components stored .in a
condition outside the recommendation of the manufacturer.
The inspector found no areas of concern with the SGRP related tasks including
project self assessment, Quality Assurance by PSE&G, RTI and FTI, the SGRP
improvement progress, fire control or the work package closeout process.
Engineering
The project contractor FTI performed a major portion of .the engineering evaluations *
to determine the effect of differences between the OSGs (Model* 51) and RS Gs
(Model 'Fl on* Unit 1 plant performance, with Westinghouse and PSE&G doing part
of the work. Inspection of SGRP engineering work as discussed_ in NRC Inspection
Report 50-272/96-017 noted that the Analysis Input Data prepared for FTi *
engineering had not been compared against the findings of the PSE&G FSAR project
applicable to steam generators. The inspector reviewed PSE&G letter SG-96-0309,
dated 12/20/96, summarizing the PS.E&G review of FSAR P~oject findings (Problem
Reports) against the SGRP Design Calculation Inputs. The PSE&G review
concluded that the .FSAR Project had identified no adversely affected Design
Analysis Inputs for the SGRP engineering evaluations;
c.
Conclusions
Inspections of current and planned work, related procedures, documentation,
quality inputs and progress of the Salem, Unit 1 steam generator replacement
project found generally good performance and identified no safety significant
deficiencies. The management-initiated corrective and preventive actions improved
project performance. In the area of engineering, PSE&G compared the FSAR
.
project findings against the SGRP Design Inputs with no input changes resulting.
E2*
Engineering. Support of Facilities.and Equipment
E2.1
N_RC Restart Issue 11.34 - Safety Injection (Sil Pump Deficiencies !Closed; Unit 2
QDJy}_
a.
Scope
b.
NRC Inspection Report 96-08 documented Salem staff's reso_lution *of SI pump
deficiencies, however, the issue remained open because the operators had not
tested the pumps by the end of the inspection period. Subsequently, operators
completed pump performance tests. The inspectors observed portions of the tests
and reviewed performance data.
Observations and Findings
The inspectors previously documented SI pump deficiencies. For example, no
preventive task existed for technicians to periodically refurbish SI pump motors, the
-29
Salem staff had not addres_sed industry experience regarding improperly fastened SI
pump impeller locknuts, and both pumps exhibited excessive shaft run out during
pump reassembly. Salem staff appropriately resolved these issues (NRC Inspection
Report 50-27 2&311 i96-08 has details).
Subsequently, during pump performance tests, system engineers noted that the no.
22 pump discharge pressure was higher than no*. 21 pump for the same test flow
rate. The engineers, with support from Westinghouse, determined no. 22 pump
was a slightly stronger pump than no. 21. This condition also resulted in no. 22
pump motor drawing *more current than no. 21 pump motor. (51 amperes compared
to 4 7 amperes). Salem staff appropriately determined that the higher load would
not exceed the no. 2C emergency diesel generator c_apacity.
The operators performe<;I surveillance testsion both SI pumps in accordance with
S2.0P-ST.SJ-0001 (2)(0), 21(22) SI Pump Surveillance Test, arid S2.0P-ST.SS-
0002(4)(0), Engineered Safety Features Manual Safety Injection 2A Vital Bus. _The
inspectors observed portions of the.tests; reviewed test data, and determined pump
performance met Technical Specificatio_n surveillance requirements. *
.
.
Inspectors also reviewed::restart-required work orders for the SI pumps and noted
that 32 minor items remained open. Plant staff had completed most of these items;
final closure awaited retests that required the p*lant to be in Mode 4 or 3 (for
example, valve leak tests that require reactor system pressure of 1000 psig). The
inspector did not find any items that would preclude safe plant restart or challenge
pump reliability.
c.
Conclusions.
Inspectors determined that Salem staff effectively corrected Unit 2 SI pump
deficiencies and subsequently demonstrated pump performance met surveillance
requirements. The inspector considered the corrective actions adequate for restart
of Salem Unit 2.
E2.2
NRC Restart Issue 11.17 - Main Condenser Steam Dumps Malfunction (Closed)
a.
Scope
Inspectors documented, in NRC Inspection Report 50-272&311 /96-08, action by
th_e Salem staff's resolution of main steam dump deficiencies. The issue remained
open, however, oecause Salem staff had not completed modifications to the
system or implemented a revision to. the Emergency-Operating Procedures (l;OPs).
b.
Observations and Findings
'
Salem staff completed modifications to steam dump components. Modifications
in~luded valve upgrades and valve positioner linkage improvements. The inspector
noted that Salem staff included the steam dumps in the startup and power
ascension sequencing program. Operators will test the system in Mode 5 per
30
procedure TS2.SE-SU.RCP-0002(Q), Steam Dump Control Loop Functional Test
(Mode 5 Portion) and again in Mode 3 or 2 per procedure TS2.SE-SU.RCP-0008(Q),
Steam Dump Control Loop Functional Test.(Mode 3 or 2 Portion). Operators will
also monitor system performance during advanced digital feedwater control system
testing.
In addition to completing the field modifications, Salem staff implemented an
appropriate EOP revision, effective October 21, 1996. The inspector considered
this issue acceptable for restart1 however, inspectors will observe resta~t testing.
- (IFI 50-311196-18-04)
c.
Conclusions
E2.3
a.
b.
c.
The Salem staff completed modifications to the steam dumps ar.id**implemented
related EOP changes. The inspector considered the corrective actions for the steam
dump deficiencies comprehensive and sufficient for restart of Salem Unit 2. *The
inspectors will observe operation of the steam dumps during plant operation.
Management Review Committee (MRC)
.Inspection Scope 137551 l
.
.
The inspector assessed MRC review of NRC restart item closwe packages, the
Operations Department and System Engineering Depa.rtment restart affirmations,
and the operator workaround and control room indicator restart issue, to determine
the effectiveness of the reviews.
Observations and Findings
The inspector verified that Salem senior managers representing op~rations,
engineering, maintenance, radiation protection, licensing,. special projects, and
quality assurance met MRC quorum requirements* for the January 4, 1997, meeting.
The MRC members and the presenters engaged in spirited and extensive. discussion,
and thoroughly explored each *subject prior to voting on approval. The MRC opened
action items to obtain additional information or require additional action as
appropriate. For example, during. the restart affirmation presentation by system
engineering, the MRC determined that design engineering had not affirmed
readiness to support Salem restart. The MRC opened an action item to require
design engineering affirmation prior to Salem Restart. The MRC reviewed and
approved NRC Restart Issue 111.8, "Operator Workarounds, Including Control Room
_Deficiencies," the system engineering restart. affirmation, and several operations
department restart plan items.
Conclusions *
The MRC performed a thorough review and evaluation of the Operatio.ns
Department and System .Engineering Department restart affirmations, and the
- -
. 31
operator workaround and control room indicator restart issue. The MRC initiated
Action Items as appropriate:
E2.4
In Service Testing (ISTl of Valves SJ4 & SJ5
a.
Scope
The inspector reviewed IST testing of SI valves SJ4 and $J5, inlet isolation valves
to the boron injection tank during a review of NRC Restart Issue 11.23 ..
b.
Observations and Findings
.. c.
Salem FSAR; Chapter 15, Accident Analysis for a SGTR event, requires several
operator actions, within fifty minutes of event initiation, to terminatec*steam release
from the faulted steam generator (SG) and primary to secondary leakage. The
required operator actions include termination of SI flow.
The inspector reviewed emergency operating procedure (EOP) 2-EOP-SGTR-1 ,
Steam Generator Tube Rupture, Revision 20, and discussed th.e SGTR event with *
Salem operators and training department personnel From this review, the
inspector learned that the operators terminate SI flow by closing valves SJ4 and
SJ5 from the control board, as required by the SGTR EOP.
Salem TS 4.0.5 requires in service inspection and testing of ASME compone*nts in
accordance with Section XI of the ASME Boiler and Pressure Vessel Code and
applicable Addenda. Article IWV-3000 of ASME Section XI requjres category A and
B valves to be exercised to the position required to fulfill their functfon and requires
full-stroke time testing. Salem's in service testing program defines valves SJ4 aod
SJ5 as category B valves, but only requires testing in the open position. Salem's
IST program states that valves SJ4 and SJ5 have no safety function in the closed
position and. that.inlet isolation of the boron injection tank is not required for
accident mitigation. The .inspector concluded that failure to include tes~ing of SJ4
and SJ5 in the closed direction is a violation of TS 4.0.5. The IST staff initiated CR
970118091 tp address the inspector's findings (VIO 50-272 & 311/96-18-05.)
Conclusions
The inspector identified that PSE&G mis-classified valves SJ4 and ~J5 as passive
components and, as a result, had not included them in the IST program for exf!!rcise
and stroke testing in the closed direction. The inspector determined th.at the valves
must close to stop charging flow to the RCS during* a steam generator tube rupture
event, and Salem should have included the1T1 in the IST program.
F~ilure to* exercise
and stroke test valves SJ4 and SJ5 as part of the Salem's IST program is a
violation .
..
I
32
E2.5
NRC Restart Issue 11.42 - Auxiliary Feedwater (AFW) Performance and Reliability
(Open Unit 1 , Closed Unit 2)
E8.1
Inspectors documented review of this restart item in NRC Inspection Report 50-.
272&311 /96-17. In that report, the inspector considered the actions taken by the
licensee to improve Auxiliary Feedwater performance and reliability effective, but
the inspector did not close the. issue at that time because of the large number of
outstanding items that remained to be tested. S!nce the plant staff imple.mented *
acceptable corrective action and because they must operate the system to perform
the testing, this issue is conside.red closed for Salem Unit 2 restart. The NRC will
monitor completion of testing during the plant restart. (IFI 50-272&311/96-18-06'}
- Miscellaneous Engineering Issues
(Closed) LER 50-272/95-016: difference between containment design parameters
and accident analysis. On July 20,. 1995, engineering identified a discrepancy
between the design basis for the containment structure as described in TS, the
Updated Final Safety Analysis Review (UFSAR) Chapter 1 5 accident analysis, and
- the *containment structure design calculations.
Engineers determined that, following a main steam line break accident, .the
containment liner plate may yield, however, the containment would still perform its
function because the pressures and temperatures would not overstress the
reinforced concrete. The engineers concluded that the liner would maintain leak
tight integrity. In addition, they identified a potential limited failure of Unit 1 .
containment spray piping supports and identified that the reactor coolant pump
(RCP) platform supports_ would yield for both units .. The licensee identified that
enginee_ring did not consider all sections of the TS and UFSAR in evaluating
- previous changes in containment temperature profiles.
The licensee modified *Unit 1 containment spray piping supports. Engineering
modified the Unit. 2 RCP platforms (D.CP 2-EF0097). On June 18, 1996, licensing
submitted LCR 59606 to address the peak containment temperature discrepancies
between the design basis and that stated in TS. Engineering conducted training on
10 CFR 50.59 safety evaluations and revised their 10 CFR 50.59 program guidance
to require a text search when performing safety evaluations.
The inspector verified the DCP and LCR status, and the 10 CFR 50.59 program
guidance. The ins.pector *determined that the licensee took appropriate corrective
actions. The licensee identified and corrected failure to properly evaluate previous
changes in containment temperature profiles, as required. by 10 CFR 50.59, is being
treated as a non-cited violation, consistent with Section \\ill.B.1 of the NRC
33
IV. Plant Support
P3
EP Procedures and Documentation
a.
Inspection Scope (92904)
The inspector reviewed various Emergency Plan (Plan) and Emergency Plan
Implementing Procedure (EPIP) revisions to determine if the changes reduced the
effectiveness of the Plan.
b.
Observations, Findings and Conclusions
Based on the licensee's determination that the changes do not decrease the overall
effectiveness of the Plan, and that it continues to meet the standards of 1_ 0 CFR *
50.47(b) anq the requirements of Appendix E to Part 50, the changes did' not
require NRC approval. The inspector determined that'the changes met the
requirements of 10 CFR 50.54(q).
P4
Staff Knowledge and Performance in. EP
a.
Inspection Scope (92904)
The inspectors observed table-top mini-drills for Salem/Hope Creek (S/HC) *
operators, S/HC Technical Support Center (TSC) grou.ps, and Emergency Operations
Facility (EOF) groups (common to S/HC), to determine EP training effectiveness, and
to ensure that eryiergency response organization* (ERO) managers* co~ld correctly
classify emergency events using the new Nuclear Management and Resources.
Council (NUMARC) emergenc;:y action levels (EALs).
b.
Observations and Findings
Licensee responder~ demonstrated good overall performance during the mini-drill
scenarios. Simulated emergency event classifications were accurate and timely.
Offsite notifications w~re* also timely, and professionally -completed.- Protective
- action recommendations (PARs) were formulated in accordance with licensee
procedures, and were appropriate for the scenarios. Emergency responders
routinely double-checked each other regarding EAL usage and event classifications.
Post-drill critiques were held, were generally open and self-c.ritical, and ident'ified
- most items identified by the inspectors.
The inspectors determined that the fission product barrier .(FPB) table ass.ociated
with the NUMARC EALs was not consistent with the PAR flowchart found in the
Event Classification Guide (ECG), Attachment 4, "General Emergency." The FPB *
table identified criteria for determining a loss or a partial loss of a barrier, whereas
the PAR flowchart used only the loss o! barriers for the determination of a PAR.
This caused confusion for some Emergency Coordinators (ECs) during. PAR
formulation. For example, both of the Salem Senior Nuclear Shift Supervisors
observed by the inspectors, determined a PAR. based on the loss of i=ill three FPBs;
34
when in reality two barriers were lost, and one was partially lost. The FPB table*
gave discretion to ECs to declare a barrier lost if they felt that the loss was
imminent, and both managers exercised that discretion for the partially lost barrier.
In both cases, the result was a .PAR that recommended a more extensive
evacuation than was necessary, and that was inconsistent with the expected PAR
on the licensee-approved scenario. The inspectors concluded that these PARs were
acceptable. However, one of those managers stated that he had been trained to
treat a partial loss of a barrier as a loss for PAR formulation.
Licensee drill observers also observed this inconsistency between the FPB* table and
the PAR flowchart, a~d pointed it out during the mini-drill critiques. The acting EP
manager stated that the PAR flowchart would be revised to be consistent with the
FPB table, thus, resolving the inconsistency, as well as the above training issue
concerning partially lost barriers.
Inspectors also concluded that ERO managers generally found their respqnse .
procedures to be cumbersome, in that they were required to use and sign off on
two checklists concurrently, one from an EPIP, and one from an ECG attachment .
. This sometimes resulted in emergency actions being somewhat delayed. For
example, one TSC EC was not as timely as he could have been in initiating
accountability after he had declared a site area emergency. This was self-identified
during the ensuing critique. In another case, an EOF EC could have been more
timely in announcin*g a general emergency (GE) declaration to the EOF staff, and in
notifying the TSC of the event.* In assessing these delays, the inspectors took into
consideration the *fact that the emergenc*y groups observed did not have the full
team of responders that would normally be present during an emergency. The
delayed events could have been prompted by the additional responders, e.g., the
Security Team Leader could have prompted the initiation of accountability, since he
is the person responsible for its completion.
The licensee stated tha*t it had.initiated a.procedure upgrade program to address
this issue. * Implementing procedures were being revised to incorporate all required
mana.ger actions into one procedure. The.revised procedures are scheduled for
implementation in early 1997.
The licensee used enlarged laminated copies of the NUMARC EAL tables during the
mini-drills. These were well-received by the ECs who gene.rally found them easy to
use. However, these laminated copies were present13d in a different format than .
those in the ECG. The ECG presents the EALs in a flowchart format, with events
.
.
progressing from an Unusual Event (UE) to GE. The laminated copy presents the
EALs in a tabular format, with GEs in the left-hand column, progressing to UE, from*
left to right. This was an improvement since ERO managers routinely review the
EALs from the most severe classification level to the least severe, to ens~re that
the highest level applicable to an event is declared. The inspectors questioned
whether these copies would be formally con~rolled and marked with the appropriate
revision number when distri~uted for general use and whether the laminated copies
would be included in or referenced in the Plan. The licens*ee s~ated that they
would.
,.
35
c.
Conclu.sions.
PS
P8.1
a.
b.
Licensee ERO responders demonstrated that EP training was effective through good
mini-drill performance. The ERO managers demonstrated the ability to accurately
classify emergency events using the NUMARC EALs.
Miscellaneous EP Issues
Effectiveness of Licensee Controls
Inspection Scope (92904)
. The inspectors reviewed Condition Reports (CRs), generated by the licensee's
action item tracking system, to close outstanding items. They also interviewed EP,
licensing, and*qur;:ility assessment staff members concerning the use of the tracking
system.
Observations and Findings
The inspectors* reviewed the licensee's CRs, and in many of the cas~s, found that
they were not able to determine what actions had been taken to correct the
deficienCies. The inspectors often had to request additional documentation or
interview the individual responsible for closing the item, in order to understand the
corrective actions,
The inspectors informed the licensee that the depth of CR closure documentation
varied between reports .. The following items were i~entified: 1) the EP staff did
not have the opportunity to review corrective actions pertaining to their area, but
. assigned to and closed by other departments;. 2) the EP staff did not have a
dedicated tracking system coordinato~ like most other departments; 3) rio EP staff
member was qualified to perform high priority (level one) root cause analysis for EP
issues; and 4) discussions with EP staff members indicated that they did not fully
understand the capabilities and operation of the system. Licensee representatives
stated that they were aware of these problems and would review this area further
prior to the Salem Unit 2 restart.
The inspectors also found that in August, 1995, the .owner-controlled area siren*
system failed a surveillance test and was subsequently found to be inoperable from.
its remote actuation point', the security central alarm station. The licensee modified *
the system to *enable inanual actuation of the sirens in the evacuation mode by
plac.ing actuation switches on each of the three siren pol~s, and issuing a directive
for security force members to actuate the sirens manuall*{when directed. The
. modification, however, did not allow actuation in a previously existing second
mode--the assembly (relocation) mode. While the relocation mode would probably
have little use during an actual emergency and its function could be accomplished
by other means, that feature of the system, as originally designed, was essentially
- removed. The licensee could not produce any documentation to 'indicate that the
- removal of that feature was evaluated at the time it occurred or that it was entered
c.
36
into a corrective action/tracking system for later evaluation. The problem was
identified by the licensee and entered into the tracking. system on
December 13, 1996, but the inspectors noted that the entry failed to include the
need for review under 10 CFR 50.54(q). The licensee was advised of that need.*
Conclusions
The licensee's action item tracking system was adequate for tracking and resolving
EP issues, but inspectors noted several deficiencies with the implementation of the
system by the EP Department. The foregoing issues will be reviewed further in
conjunction with the Salem restart item 111.a.10 concerning the licensee's corrective
action system.
P8.2
(Closed) Violf,ltion 50-272/95-81-01: Al~rt for loss of annunciators not within time
limits.
The Unit 1 senior nuclear shift supervisor (SNSS) who failed to declare the Alert in
a timely manner was counseled in accordance with the Public 'Service Electric and
Gas (PSE&G) disciplinary process.
The loss of annunciators event was discussed with all SNSSs. During the
discussions, the proper use of the Salem ECG was stressed. This was also
.
reinforced at a SNSS 'Tleeting held on February 1, 1996. The inspector discussed
with the acting EP Manager, the Sal~m and Hope Creek licensed operator training
concerning management expectations for proper use of the ECGs. The inspector
also verified the Salem training by reviewing the lesson plan, handouts, and *
attendance sheets for the classes. Licensee representatives stated that Hope Creek
operators re*ceived similar training.
Proper use .of the.Sa_lem and Hope Creek (S/HC) ECGs arid lessons I.earned from this
event and selected pr.evious events were, and will continue to be, reviewed and
emphasized during the operator train.ing scheduled to support the restart of the
Salem Units, and during the continuing training program. The*inspector intervi~wed
the Salem Operation~ Manager and the acting Operations Training Manager, both of
whom stated that they personally communicated their expectations f.or ECG use
during licensed operator requalification t[aining (LORT) classes. *Additionally, the
managers stated, and the inspector confirmed, that during LORT training scenario
cycles, with full shift complements, event classifications and all necessary actions
required by the EPIPs would be performed during the. scenarios instead of at the
conclusion of the scenarios, that was the normal procedure for license
examinations. *This requirement was being incorporated into the present scenario
guides as they are routinely reviewed, and into new guides as they are generated.
The S/HC ECGs were evaluated and revised by *the licensee based on the NU MARC
National Environmental Studies Project (NESP) 007 guidance. The revisions were
submitted to the NRC for review and approval on August 24, 1995. The NRC
completed its review and issued a Safety Evaluation Report, approving the *
revisions, on December 19.; 1996. The States of New Jersey and Delaware
.
, ..
37
reviewed and concurred in the revisions. The training for implementation of the
NUMARC ECGs has been under way since August, 1996, and is almost complete.
The licensee planned to complete the training and implement the NUMARC ECGs,
prior to the Unit 2 startup. S/HC operators, TSC groups, and EOF groups were
evaluated in mini-drills during this inspection, on the correct use of the NUMARC
ECGs. (See Section P4.)
Additionally, the inspector reviewed documentation of other incidents that involved
missed/incorrect event classifications during training and actual events, and the
associated corrective actions. Some corrective actions were: 1) EP has r:einstated
the announced control room mini-drills .on an approximately biweekly basis, and.
unannounced mini- d.rills on a quarterly basis; 2) The lessons learned from these
incidents were being incorporated into EP and operator training lesson plans and; 3)
EP is now Involved.in. the review and validation of simulator scenarios to ensure
that proper event classifications are identified in the scenario guide.
Based on the findings of this inspection; this item is closed.
PR3 . (Closed) Violation 50-272/95-81-02: Emergency response.staffing.for loss of
.annunciators not within time limits .
. The licensee evaluated and tested its callout pager system and identified some
system deficiencies. The vendor corrected these problems, made enhancements,
and retested the system. The enhancements streamlined the automated pager
activati.on process and resulted in a reduction in time between the group pager
activations~ Additionally, the licensee conducted qu_arterly call-out muster drills
(with responders required to physically report to the ERFs), weekly on-duty team
pager tests (res.ponder call in with an estimated time of arrival), and monthly pager
tests for the entire ERO. The inspector r.eviewed the 1996 records for these
drills/tests and verified that all"were conducted. The inspector concluded that the
drill/test results indicated that.the licensee was able to fully staff and a"ctivate the
emergency facilities within the required time limits.
Individuals who failed to adequately respond to a pager test were contacted by
telephone. to determine if th~re was a system or pager problem. If not, ~hen an
"Emergency Response Callout Accountability Form" was sent to the individual's
supervisor, who was required to counsel the individual, and then return the form to
the EP group to document the inadequate performal"!ce. If that same individual .
fajled to respond a second time, the Vice President (VP)-Nuclear Operations pulled
.
.
the person's security badge to preclude site access.* The inspector reviewed th'e
1996 forms and noted that in the second half of 1996, the forms had significantly *
decreased in frequency. Also, trending reports for the monthly pager tests
indicated that there was a 100% callout response sinC"e April, 1996.
During this inspection, the licensee conducted* an unannounced pager test for the
.
'
- on-duty team responders. All responders were timely except one. That individual
stated that he* had a personal commitment a~ the time the test was initiated. An
accountability form was issued to the individual's supervisor. *
38
The licensee stated that in' the past eight months, senior management has been
very proactive in supporting the EP program and believed this to be the major
contributing factor to changing attitudes and improving responsiveness by ERO
personnel. The inspector reviewed a letter sent to ERO personnel from the Senior
VP-Nuclear Operations, in that management's expectations were clearly defined.
The letter also defined ERO roles, responsibilities, and proper cultural attitudes for
response personnel. This letter was added to all ERO responder packets distributed
at EP training sessions and is periodically reprinted in an EP monthly newsletter .
. .
Based on the findings in this inspection, this violation is*clbsed.
PS.4
(Closed) Violation 50-272/95-81-03: Changes to. EALs not discussed and agreed
on with state officials. After the October 4, 1995 loss of_ annunciator event, the ..
licensee appropriately revised the EALs covering such events. However, the
licensee failed to discuss and seek agreement with the states (New Jersey and
Delaware) prior to- the implementation of the revised EALs.
The licensee determined that the root cause of the violation was a misiriterpretatiori
of 10 CFR 50.54(q) and 10 CFR 50 Appendix E in that it believed that only an
annual review of the EALs with offsite officials was required. To prever.it
recurrence, the licensee planned to implement th~ following corrective actions:
1) conduct NUMARC EAL training with offsite officials; 2) conduct team-building
- sessions wi~h offsite offici.als to improve communications; 3) modify the change
review procedure to ensure state appr.oval for EAL changes is received prior to their
implementation and; 4) develop an EAL review form to be used for submittal of EAL
changes to the states, and to document state agreement or disagreement with the
proposed revisions.
The inspe~_tor reviewed documentation verifying that .representatives of off site
agencies (states and counties) attended the NUMARC EAL training. The inspector
determined that the training material was thorough and informative. The inspector
also reviewed documentation of the team- building sessions. Past sessions were
well attended and- future sessions are planned. The inspector reviewed .EPIP 1003,*
"Review and Approval of Plan/Procedures/ECG," and determined that, as part of the
.
'
change review process, the procedure reminded the reviewer that state agreement*
is required prior to EAL change implementation. The licensee informed the
inspector that EPIP* 1003 will be revised to include verification that state agreement
was received prior to implementation. Finally,* the. inspector reviewed the EAL
review form and several instances of its usage in communicating EAL changes with
the states. For example, the inspector verified that the states have agreed to the
NUMARC EALs that are to be implemented prior to the Salem Unit 2 reactor
startup.
The inspector also reviewed other aspects of the licensee interface with offsite
entities to ensure the existence of good communications and good .Program
.
implementation in areas affecting those entities. The inspector verified that letters
of agreement with offsite officials and support organizations have been maintained
current for the last three years. He also verified that annual EAL train*ing had been
.,.
39 .
conducted for offsite officials during the past three years. Lastly, the inspector
verified that the licensee had made the portion of the 10 CFR 50.54{t) audit reports
that assessed the licensee's offsite interfaces, available to offsi_te agencies. Thei
inspector reviewed the assessments of the offsite interfaces in the past three audit
reports, that indicated good performance.
The inspector verified that the corrective actions developed by the licensee were
complete, comprehensive and thorough. Therefore, this violation is closed.
P8.5
Updated Final Safety Analysis Report {UFSARl Review
A recent discovery of a licensee operating their facility in a manner contrary to the
UFSAR description highlighted the need for a special focused review that compares
plant practices, procedures, and/or parameters to the UFSAR descriptions. While
performing the inspections discussed in this report, the inspector reviewed the
. applicable portions of the Plan that related to the areas inspected, since the UFSAR
does not specifically include emergency preparedness matters. No deficiencies
were noted.
S 1
Conduct of Security. and Sa~eguards Activities
S 1 . 1
Protected AreaNital Area Access Controls
During* this inspection period, the inspectors observe*d several examples of
. inadequate implementation of the Salem and Hope Creek Security Plan. The
.
inspectors documented the observations and the associated Notice of Violation in
NRC Inspection Report 50-354/96-10. {VIO 50-272&311 /96-18-01; 50-354/96-10-
03)
V. Management Meetings
X1 *
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee* management at the
conclusion of the inspection ol'i"I January 29, 1997. The licensee acknowledged the
findings presented.
The inspectors asked the licensee whether any materials examined during the inspection
should be considered proprietary. No proprietary information was identified.
INSPECTION PROCEDURES USED
IP 61726:
IP 62707:
IP 71707:
Surveillance Observations
Maintenance Observations
Plant Operations
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-272&311 /96-18-01
50-311 /96-18-02
50-272&311 /96-18-03
50-311 /96-18-04
50-272&311 /96-18-05
50-272&311 /96-18-06
Closed
50-272/95-016
50-272/95-019
50-272/95-020
50~272/95-023
50-272/96-014
50-272/96-018
IFI
IFI
LER
LER
LER
LER
LER*
. LER
inadequate security plan implementation
lack of containment closure during refueling
design control of PORV accumulator chec;k
val'les
main condenser steam dump te::cing
SJ4 & 5 not included in IST program
AFW punip performance
differenc*e between containment design
parameters and accident analysis *
operability functional test not performed prior to
mode entry *
inoperable 230 volt motor control centers due to
failed bus bar bolting (discussed in IR 50-
272&311 /95-017)
failure to plug steam generator tubes due to
missed eddy current indications (discussed in IR.
- 50-272&311./95017 and 96010)
potential hydrogen embrittlement on 4kv breaker
parts
potential performance impact on ECCS due to
non-safety related RWST piping
NRC
PSE&G
LIST OF ACRONYMS USED.
Public Document Room
Nuclear Regulatory Commission
Public Service Electric and Gas
Senior Reactor Operator