ML18101B093
| ML18101B093 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 11/06/1995 |
| From: | Larry Nicholson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18101B091 | List: |
| References | |
| 50-272-95-17, 50-311-95-17, NUDOCS 9511140028 | |
| Download: ML18101B093 (24) | |
See also: IR 05000272/1995017
Text
Report Nos.
License Nos.
Licensee:
Facility:
Dates:
Inspectors:
Approved:
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
50-272/95-17
50-311/95-17
Public Service Electric and Gas Company
P.O. Box 236
Hancocks Bridge, New Jersey 08038
Salem Nuclear Generating Station
August 13, 1995 - October 14, 1995
C. S. Marschall, Senior Resident Inspector
J. G. Schoppy, Resident Inspector
T. H. Fish, Resident Inspector
C. D. Beardslee, Reactor Engineer
S. Barber, Project Engineer
S.Chaudhary, Senior Reactor Engi_neer
B. Welling, Reactor Engineer
Leanne
arrison~R:;c1'°r Engineer
[' /k{/(__
Inspection Summary:
This inspection report documents inspections to assure public health and
safety during day and back shift hours of station activities, including:
operations, radiological controls, maintenance, surveillances, security,
engineering, technical support, safety assessment and quality verification.
The Executive Summary delineates the inspection findings and conclusions .
9511140028 951106
ADOCK 05000272
G
...
i
EXECUTIVE SUMMARY
Salem Inspection Reports 50-272/95-17; 50-311/95-17
August 13, 1995 - October 14, 1995
OPERATIONS
(Module 60710, 71707, 93702) Early in the inspection period,
inspectors observed several examples of plant staff performing low priority
work that imposed increased risk to equipment essential to decay heat removal.
In response, Salem management improved supervisory oversight of work and
implemented measures to effectively manage outage risk.
As a result of these
measures, assessment and control of outage risk improved during the remainder
of the inspection period.
The inspectors considered Operations' strategy and
training for filling the diesel day tanks a particularly good example of
contingency planning.
In response to inadequate electrical bus fasteners, the senior nuclear shift
supervisor (SNSS) appropriately declared all vital 230 volt motor control
centers (MCCs) inoperable.
In addition, operators appropriately established
containment integrity for Unit 2.
In response to evidence of possible overheating of the no. 2A emergency diesel
generator exciter resistor bank, operators inappropriately relied on
surveillance results to determine operability. Although technicians performed
checks that effectively supported operability of the resistor bank, they did
not effectively communicate the information to the operators.
After the SNSS and other senior reactor operators identified several examples
of workers failing to meet Salem managements' expectations for performing
work, the SNSS ordered a complete work stand down for both Salem units. The
Nuclear Business Unit senior managers endorsed the operators' actions. The
inspectors noted that this action demonstrated significant operator ownership
for the performance of Salem workers, and a willingness to demand that station
personnel meet higher expectations for performance.
MAINTENANCE and SURVEILLANCE
(Modules 61726, 62703)
Several tagging errors
occurred during the inspection period.
In response, the Operations Manager
stopped tagging for more than a week.
A team of Salem personnel and a
contractor with expertise in failure and root cause analysis evaluated the
tagging problems and recommended changes to the tagging program.
Tagging
problems have recurred in each Salem outage over the past two years.
In each
case, Salem management stopped work and based on problem evaluations by Salem
staff, implemented changes to the tagging program.
The effectiveness of this
latest attempt to prevent tagging problems has not yet been demonstrated.
Inspectors noted that maintenanc~ personnel hung red blocking tags for a 460
volt breaker on the cubicle door of the wrong breaker as a result of failing
to adhere to requirements of the Safety Tagging Program .
ii
I -
EXECUTIVE SUMMARY (Continued)
Inspectors identified several examples of ineffective control of maintenance.
The examples included work not*controlled by procedures, and work not within
the scope of a work order. Salem management's measures to rectify work
control deficiencies yielded limited results.
Although Salem management has recently developed performance indicators that
allow them to monitor some maintenance backlog trends, the indicators do not
provide indication of the impact on safe plant operation or shut down
conditions.
ENGINEERING (Module 37551, 71707) The inspectors concluded System Engineering
disposition of issues relating to vital 230 volt MCCs was timely, thorough,
and provided the SNSS with adequate information for him to assess system
operability.
A reactive inspection of the Salem Steam Generator Eddy Current Testing (ECT)
program was conducted. Three issues were identified by Salem staff. Salem
staff found that ECT evaluators missed nine bobbin* probe indications the
should have resulted in eight plugged tubes during the 1993 refueling outage.
During the current Salem Unit 1 ECT, contractors inspected dented steam
generator tubes using a rotating pancake coil probe not qualified for the
task.
In addition, Cecco-5 data analysis results did not correlate well with
PlusPoint probe data analysis results. The inspector concluded that PSE&G
aggressively pursued the issues once they identified them.
However, they will
remain unresolved until the inspector obtains additional information necessary
to determine whether PSE&G met regulatory requirements.
The System Readiness Reviews and the oversight by the Management Review
Committee provided a sound method for determining the focus of maintenance and
modifications to improve plant safety.
PLANT SUPPORT (Module 71707, 71750) The inspectors concluded licensee response
to the partial participation annual emergency.preparedness exercise scenario
was very good and the post exercise critique was effective and candid.
Inspectors also determined the licensee met the exercise objectives described
in the scenario.
The inspectors discovered that a letter to the NRC dated July 26, 1978 stated
that PSE&G planned to install concrete curbs at the entrance to each emergency
diesel generator room.
No curbs are presently installed. This was another
example of a previously identified weakness in commitment and action tracking.
This is an unresolved item pending NRC review of present requirements for the
curbing.
Safety Assessment and Quality Verification
Inspectors found that management control of overtime for Salem Operations,
Maintenance, and Radiation Protection personnel met the requirements of Salem
Technical Specification 6.2.2.d and procedure NC.NA-AP.ZZ-0005 requirements.
i i i
TABLE OF CONTENTS
EXECUTIVE SUMMARY
TABLE OF CONTENTS .
1.0
OPERATIONS
. . . . . . . .
I.I
Summary of Operations ....... .
I.2
Shutdown Risk and Contingency Planning ........ .
I.3
Inoperable Vital 230 Volt Motor Control Centers (MCCs)
I.4
Work Stand Down ........... .
I.5
Emergency Diesel Generator (EDG) Operability
2.0
MAINTENANCE AND SURVEILLANCE .... .
2.I
Maintenance .......... .
2.2
Tagging ............ .
2.3
Control of Maintenance ... .
l.4
Maintenance Backlog Inspection
2.5
Surveillance .......... .
ii
iv
I
I
I
2
3
3
4
4
5
6
7
8
3.0
ENGINEERING . . * . . . . . . . . . . . . . . . . . . . . . . . .
9
4.0
5.0
3.1
Vital 230 Volt Motor Control Center (MCC) Fasteners .
9
3.2
System Readiness Review Inspections - Salem Unit 1
10
PLANT SUPPORT . . . * . . . . . . . . . . .
4.1
Emergency Preparedness Exercise ... .
4.2
Fire Protection ........... .
SAFETY ASSESSMENT AND QUALITY VERIFICATION
15
I5
I6
6.0
REVIEW OF REPORTS AND OPEN ITEMS
I6
17
7.0
EXIT INTERVIEWS/MEETINGS
. . . .
. . . .
17
7.1
Resident Exit Meeting . . . * . . . . *
. . . .
17
7.2
Specialist Entrance and Exit Meetings * . . . . . * . . .
17
7.3
Nuclear Business Unit Organization Changes
. . . . .
18
ATTACHMENT 1 - Eddy Current Testing of Steam Generator Tubing
Inspection
. . . . . . . . . . . " . . . .
e
- .
1
iv
DETAILS
1.0
OPERATIONS
The inspectors verified that Public Service Electric and Gas (PSE&G) operated
the facilities safely and in conformance with regulatory requirements. The
inspectors evaluated PSE&G's management control by direct observation of
activities, tours of the facilities, interviews and discussions with
personnel, independent verification of safety system status and Technical
Specification compliance, and review of facility records. The inspectors
performed normal and back-shift inspections, including 34 h_ours of deep back-
shift inspections.
1.1
Summary of Operations
Unit 1 remained defu.eled for the duration of the inspection period. Salem
Unit 1 declared an Alert as a result of a loss of overhead annunciators on
October 5. A special inspection effort will address the cause of the
annunciator failures and the emergency response organization's response to the
Alert in a separate NRC inspection report 50-272/95-81.
Unit 2 operators maintained Unit 2 in mode 5 (Cold Shutdown) for the duration
of the period.
1.2
Shutdown Risk and Contingency Planning
Early in the inspection period, inspectors observed several examples of plant
staff performing low priority work that imposed increased risk to equipment
essential to decay heat removal.
In response, Salem management improved
supervisory oversight of work and implemented measures to effectively manage
outage risk.
As a result of these measures, assessment and control of outage
risk improved during the remainder of the inspection period.
The inspectors
considered Operations' strategy and training for filling the diesel day tanks
a particularly good example of contingency planning.
.
During the inspection period, the inspectors observed the following examples
of work that posed increased risk to equipment essential for decay heat
removal:
On August 14, 1995, maintenance personnel conducted penetration seal
work in the vicinity of no. 12 component cooling heat exchanger (CCHX).
At the time, Unit 1 was defueled with the core in the spent fuel pool,
no. 11 CCHX was out of service for maintenance, and operators relied on
no. 12 CCHX to remove heat from the spent fuel pool heat exchanger.
On August 17, technicians performed work on Unit 1 service water piping
with the potential to adversely affect Unit 2 service water piping (see
section 2.3).
On August 23,
~n electrical contractor opened a control cabinet on an
operable diesel generator .
.
2
On August 31, workers began to erect scaffolds next to the no. 11 spent
fuel pool (SFP) cooling pump.
At the time, no. 12 SFP pump was
unavailable due to a vital bus outage, and operators relied on no. 11
SFP pump for spent fuel pool cooling.
Inspectors identified each of the above activities. in each case the
inspector observed that control room operators did not know of the activities,
and that there was minimal supervision at the work site. In each case the
operators, once notified, appropriately stopped the work to preclude further
unnecessary risk to essential plant equipment.
On August 31, operators established protected equipment areas in the plant.
The senior nuclear shift supervisor (SNSS) controlled access to areas
containing equipment essential to decay heat removal.
The inspector noted a
significant reduction in high risk maintenance and a marked improvement in
operator awareness of activities in these protected areas. Salem management
assigned two managers per shift, six days a week, to provide oversight of
work.
In addition, operations management placed greater emphasis on plant
tours by senior reactor operators.
The operator tours yielded numerous
safety-conscious observations and resulted in two operator initiated work
stoppages.
Salem staff planned a no. 18 diesel generator and vital bus outage that
removed power to one of two fuel oil transfer pumps.
Outage planners
developed a contingency plan to fill no. lA and no. lC diesel generator fuel
oil day tanks.
On August 29, operators conducted an unannounced drill to test
. the contingency plan.
The contingency plan contained sufficient detail and
control to fill the day tanks. The inspector concluded that the drill
demonstrated operator focus on safety and effective contingency planning.
1.3
Inoperable Vital 230 Volt Motor Control Centers (MCCs)
On September 14, in response to inadequate fa~tener material, the senior
nuclear shift supervisor (SNSS) appropriately declared all vital 230 volt
motor control centers (MCCs) inoperable for both units." In addition,
operators conservatively established modified containment for Unit 2.
Unit 1
was defueled, and therefore, no containment required.
- '
As part of the electrical system readiness review, system engineers reviewed
NRC Information Notice 88-11 that described the bolt failures at Brunswick
Nuclear Station.
As a result, the engineers found bolts manufactured from
silicon bronze material installed in the safety related MCCs.
The engineers
determined that stress corrosion cracking had affected bolt strength and
therefore, could not assure operations that the MCCs could withstand a seismic
event.
As a result of the engineers' determinations the SNSS declared the
Inoperability of the MCCs also led the SNSS to declare all
emergency diesel generators (EDGs) inoperable because of inoperable EOG
support systems such as fuel oil transfer pumps.
Unit 2 operators
appropriately established containment integrity .
3
At the end of the inspection period, technicians had replaced the bolts
associated with the IB vital 230 volt MCCs and all bolts in Unit 2 vital MCCs.
Operators declared these components operable. Technicians planned to replace
the remaining bolts on IA and IC vital 230 volt MCCs after operators restored
the IB vital bus to service.
1.4
Work Stand Down
After the SNSS and other senior reactor operators identified several examples
of workers failing to meet Salem managements' expectations for performing
work, the SNSS ordered a complete work stand down for both Salem units. The
Nuclear Business Unit senior managers endorsed the operators' actions. The
inspectors. noted that this action demonstrated significant operator ownership
for the performance of Salem workers, and a willingness to demand that station
personnel meet higher expectations for performance.
The following are selected examples of personnel failing to meet expectations
that operators identified:
I.
A senior reactor operator (SRO) discovered two system engineers
conducting an inspection on equipment without first contacting the
affected Unit's shift supervisor for permission to perform the
inspection.
2 .
An SRO noted that maintenance personnel propped open a door without
posting fire impairment documentation, although the fire impairment
notice was in the work package.
- 1.s
Emergency Diesel Generator (EOG) Operability
After a test run of the no. IB EOG, plant staff discovered a burn mark on the
exciter cabinet. Further investigation revealed that the exciter resistor
bank showed signs of overheating. Operators declared the EOG inoperable and
initiated inspection of the remaining five EOGs at Units I and 2.
Plant staff
found signs of overheating on the exciter resistor bank for the no. 2A EOG.
Operators initially concluded that the EOG remained operable based on results
from recent surveillance tests that demonstrated the EOG reached the required
voltage and frequency within the time prescribed by Technical Specifications.
The operators did not, however, determine whether the surveillance adequately
demonstrated the ability of the resistor bank to perform its specified
function. Although the surveillance may have demonstrated the ability of the
resistors to develop a voltage drop when the control circuitry applied I25 voe
__ to the resistor bank, they did not determine whether the surveillance
adequately demonstrated the resistor bank's capability to dissipate heat.
Although technicians had verified resistance which yielded results within
vendor specifications for the resistor bank, this information was not
adequately communicated to the control room operators.
The inspectors concluded that the no. 2A EOG remained operable, although the
operators did not thoroughly address the effects of resistor bank overheating,
and that operators relied inappropriately on the results of the previous
_., *
4
surveillance test to determine operability. Additionally, the technical staff
did not effectively communicate the results of their efforts to the control
room operators.
2.0
MAINTENANCE AND SURVEILLANCE
2.1
Maintenance
The inspectors observed portions of the following safety-related maintenance
to learn if the licensee conducted the activities in accordance with approved
procedures, Technical Specifications, and appropriate industrial codes and
standards.
The inspector observed portions of the following activities:
Unit .
Salem 1
Salem I
Salem I
Salem 1
Salem I
Salem I
Salem I
Salem 1
Work Order(WO) or Design
Change Package CDCP)
DCP lEC-3321
DCP IEC-3206
Description
Piping replacement for
service water intake bay
no. 1
IC emergency diesel
generator (EDG) turbo
boost troubleshooting
18 emergency diesel
generator slip ring
resurfacing
Inspect service water
cross-tie line
18 emergency diesel
generator combustion air
modification
pump inspection
Analog feedwater control
system replacement
18 emergency diesel
generator 18 month
inspection and cylinder
liner replacement
Salem 2
Salem 2
Salem 2
Common
5
No. 22 spent fuel pit
cooling pump discharge
pressure gauge
No. 26 service water
pump replacement
No. 26 service water
pump strainer repair
230 volt bus bar bolting
replacement
The inspectors observed that the plant staff performed the maintenance
effectively within the requirements of the station maintenance program.
2.2
Tagging
Unit 1 Maintenance electricians removed a red-tagged 460 volt breaker from its
cubicle to conduct maintenance activities inside the cubicle. Subsequently,
an operator discovered the tags for the breaker attached to the cubicle door
of an adjacent 460 volt breaker.
The inspectors concluded the tags were on
the wrong door as a result of maintenance personnel failing to adhere to
NC.NA-AP.ZZ-0015(Q), Revision 2, Safety Tagging Program (NAP-15) .
On September 25, an equipment operator discovered red blocking tags (RBTs) for
breaker AX6X attached to the cubicle door for breaker AXlOX.
The operator
moved the RBTs to the correct location (breaker AX6X) and reported the tagging
error to the Unit 1 Nuclear Shift Supervisor. Subsequently, an electrical
maintenance supervisor concluded that the electricians mistakenly shifted the
RBTs to the AXlOX cubicle door when they removed breaker AX6X from its
cubicle.
The tagging procedure permits electricians to move RBTs from a breaker when
the breaker is to be removed from its cubicle. The procedure also directs
that, when reinstalling the breaker, electricians should reinstall the RBT on
the racking device handle if the tag has not been released. Since the RBTs
for breaker AX6X had not been released, when electricians reinstalled the
br.eaker they also should have reinstalled the RBTs on the racking device
handle.
However, as evidenced by the equipment operator discovering RBTs for
AX6X on the door of AXlOX, electricians did not do this. The inspectors
concluded that the electrician failure to reinstall tags is a failure to
adhere to the_ requirements of NAP-15.(VIO 50-272&311/95-17-01) Section 2.3 _
describes additional examples of failure to adhere to procedures.
Another tagging problem occurred on September 18, when Unit 1 operators
cleared tags to return no. 11 service water (SW) pump to service. Although
the operators and electrician followed tagging procedures, the procedure
permitted an electrician to work on a breaker without measures to block
operator or automatic action from closing the breaker, with the potential for
risk of personal injury or damage to equipment. A control room operator
attempted to start the SW pump during the work.
The*pump did not start
6
because the procedure used by the electrician, SC.OP-S0.4KV-000l(Z); 4KV
Breaker Operation, required him to turn the control power for the breaker off
while performing the work, however,*the control power was not tagged during
the work.
In response to the tagging errors at Salem, the Operations Manager stopped
tagging for more than a week. A team of Salem personnel and a contractor with
expertise in failure and root cause analysis evaluated the tagging problems
and recommended changes to the *tagging program. Although Salem and Hope Creek
implement a common tagging program, the recent probl~ms with tagging at Hope
Creek were not incorporated into the Salem tagging review.
Inspectors noted
that tagging problems have recurred in each Salem outage over the past two
years.
In each case, Salem management stopped work and, based on problem
evaluations by Salem staff, implemented changes to the tagging program.
Inspectors noted that maintenance personnel hung red blocking tags for a 460
volt breaker on the cubicle door of the wrong breaker as a result of failing
to adhere to requirements of the Safety Tagging Program.
Effectiveness of
this latest attempt to prevent tagging problems has not yet been demonstrated.
2.3
Control of Maintenance
The inspector identified several examples of ineffective maintenance control,
including continued weak maintenance contractor procedure adherence.
Maintenance management promptly increased emphasis on proper work standards.
The inspectors noted, however, that the measures to correct control
deficiencies yielded limited results.
On August 14, the inspector observed maintenance.contractors performing
service water (SW) pipe installation in SW bay no. 1.
The inspector noted
that, contrary to* lEC-3323, No. 11 Service Water Header Piping Replacement,
step 8.5.5, workers began to install service water pipe prior to returning the
valve from refurbishment. Maintenance supervisors determined that the intent
of the procedure was to require that the valves be refurbi~hed prior to valve
installation. After the inspecto~ questioned adherence to the procedure,
. maintenance supervisors changed the procedure to provide the appropriate
guidance.
On August 17, the inspector observed maintenance contractors aggressively
removing a spool piece as part of a Unit 1 Generic Letter 89-13 work activity.
The inspector noted that no specific work activity (procedural guidance)
existed for the spool piece removal.
In addition, the workers had begun work
on service water valves SW457 and SW458 without verifying completion of the
prerequisites, as required by procedure SC.MD-PM.SW-0007, Disassembly,
Inspection and Reassembly of C&S Butterfly Valve, step 5.1.1. The contract
technicians had attached a horizontal rigging sling to the operable Unit 2
They had not seen their supervisor for hours and did
not know how to contact him.
Control room operators ~ere unaware of the
activity in this service water bay.
Additionally, contrary" to the
requirements of Salem procedure NC.NA-AP.ZZ-0023, Scaffolding and Transient
loads Control, workers erected a scaffold that did not have the required
clearance from safety related equipment, and had no engineer's approval for a
needed variance.
7
The Senior Nuclear Shift Supervisor (SNSS), when notified of the above .
conditions by the inspector, promptly stopped work.
In addition, the SNSS
concluded that the spool removal subjected three of the four service water
bays to a potential flooding condition.
Due to other Unit 1 service water
work, flooding in any one of the three bays could have spread into the other
two bays.
At the time, ventilation concerns made*the fourth service water bay
available but inoperable. Workers reinstalled the spool and installed a blank
flange in service water bay no. 1 to preclude flooding of multiple bays.
On September 14, 1995,.the inspector noted that workers did not adhere to *
maintenance procedure SC.MD-EU.SW-0002, Johnston Service Water Pump Removal
and Installation.
The workers failed to complete a required attachment,
performed a step out of sequence, and did not document corrective action to
remove and install the correct coupling (after the wrong coupling was
installed) in the work package.
The technicians added the missing activities
to the documentation and recovered from the out-of-sequence step. * The
inspector determined that minimal safety consequence existed since the lack of
procedure adherence did not result in inadequate pump maintenance.
The
failures to adhere to procedures, described above, were additional examples of
procedure non-compliance described in section 2.2, above.
The inspector noted that maintenance management reacted promptly in each of
the above circumstances to reinforce their work control expectations and to
attempt to gain better control of the activities. Salem management stopped
all outage work following the service water bay spool piece removal problems *
Management took several outage days to reinforce safety work standards,
procedure compliance, and scaffold and rigging protection.
Subsequently, operators stopped work twice to address work control issues.
Salem management dedicated two managers to provide around-the-clock coverage
of work in the plant. The management rovers caused improved worker knowledge
of work standard fundamentals.
The inspectors noted, however, that the *
results of the rovers were only limited improvements in overall work control
and procedure compliance.
Management inspection of field activities consisted
of asking a series of questions to verify worker knowledge of work standards
and to verify the presence of procedures at the job site. Managers did not
routinely evaluate procedure use and compliance, interaction with operation,
or impact of the work on shutdown risk.
2.4
Maintenance Backlog Inspection
Salem management, through previous self-assessment and independent assessment,
identified weakness in the ability to monitor equipment and personnel
performance trends.
Salem staff developed weekly maintenance inventory
performance indicators to monitor the maintenance backlog.
The performance
indicators provided illustration of a general increase for restart work
orders, and a decrease for non-restart work orders. Salem staff also
developed performance indicators for work order planning status and Salem Unit
1 Restart Scope Summary.
The work order planning status indicators, initiated
September 22, did not indicate a clear trend for work order activities; the
..
"
._,.
8
Salem Unit I Restart Scope Summary illustrated restart activities broken down
into preventive maintenance, *surveillances, design changes, corrective
maintenance, action requests, and other activities.
The inspectors concluded that Salem managers could use the performance
indicators, still in the early stages of development, to monitor the growth or
reduction in workload, and progress of.disciplines iti various stages of the
planning and work process. The performance indicators also prdvided evidence
of success in the approach to readying the Sal em Uni.ts for restart in terms of
the number of remaining restart items.
The inspectors noted, however, that
the performance indicators did not provide clear assessment of the impact of
the work backlog on plant safety. The inspector observed that, although
restart work consisted, in part, of safety related activities, it also
included non-safety activities.
In addition, post-restart and work not coded
for restart might include activities associated with safety related systems.
Plant staff indicated that, although the work order data could be sorted for
safety related or non-safety related work orders, they did not routinely
perform sorts on this basis.
In summary, although plant staff trended
maintenance backlog information, Salem managers did not have indication of the
impact of the backlog on safe plant operation or shut down conditions.
2.5
Surve;11ance
The inspectors performed detailed technical procedure reviews, observed
surveillances, and reviewed completed surveillance packages. The inspectors
verified that plant staff did the surveillance tests in accordance with
approved procedures, Technical Specifications and NRC regulations.
The inspector reviewed the following surveillances:
Unit
Procedure No.
Test
Salem I
SI.OP-ST.DG-OOOI
Monthly Surveillance
Salem I
SI.OP-ST.DG-0003(Q)
Surveillance Test
Salem 2
S2.0P-ST.DG-0003(Q)
2C Emergency Diesel "Generator
Surveillance Test
Salem 2
S2.RE-ST.ZZ-0002
Shutdown Margin Calculation
Salem 2
S2.0P-ST.DG-0002
28 Diesel Generator
Surveillance Test
The inspectors observed that plant staff did the surveillances safely,
effectively proving operability of the associated systems .
--- - -- --
'"-'
9
3.0
ENGINEERING
3.1
Vital 230 Volt Motor Control Center (MCC) Fasteners
During the vital 230 volt System Readiness Reviews (SRRs), system engineers
reviewed NRC Information Notice (IN) 88-II which documented Brunswick Nuclear
Station experience with failures of silicon-bronze bolts at the shank head due
to stress corrosion cracking (SCC).
In I99I, in response to IN 88-II, the
system engineer initiated work *orders to replace the 230 volt vital MCC bolts
with all steel bolts. Plant staff scheduled the work for the I996 refueling
outage.
The 230 volt system was designed to provide reliable power to 230 volt plant
auxiliaries (e.g., diesel generator circuits, service water, charging)
necessary for normal, shutdown, and emergency modes of plant operation.
The
vital portion of the system was designed as Seismic Category I. The fasteners
in the 230 volt vital MCCs were designed to insure electrical contact between
bus bars and the main bus, not to provide structural integrity. During the
system readiness review, the system engineer discovered the work order and,
due to concern over bolt failure during a seismic event, initiated immediate
action to inspect the bolts.
On September I4, during inspection of a vital
230 volt MCC, plant staff found that 5 of 48 carriage bolts connecting the bus
bars to the main bus failed-when torqued.
PSE&G sent a sample of bolts to
their metallurgical lab to determine the cause for bolting failures.
Lab
technicians attributed bolt failure to stress corrosion cracking.
Based upon the high rate of complete bolt failure, the engineers determined
that the bus bar connection probably would not remain intact during or after a
Two carriage bolts hold each vertical bar to the
horizontal main bus, with a single good bolt adequate to secure the bus bar
during a design basis earthquake. Therefore, a failure would only occur if
both bolts in the connection were defective.
At of the end of the report period, maintenance staff had replaced all silicon
bronze bolts for both units, with the exception of IA and IC vital busses.
Maintenance staff expected to replace bolts for these buses after operators
restore the IB bus to service.
The inspectors concluded that in I991 Salem staff did not insure timely
corrective action in response to the industry experience with fastener
materials noted in NRC Information Notice 88-II. However, since the NRC has
previously taken escalated enforcement for Salem's inadequate corrective
action; since these instances of inadequate corrective action stem from a
period prior to the escalated enforcement, and in view of the voluntary
extended outage of both Salem Units to correct these and other performance
problems, the NRC will not take additional enforcement action in these
instances. The inspectors noted that, upon rediscovering the concern over
fastener materials at Salem, the system engineers took timely and thorough
corrective action and provided the SNSS with adequate information for
assessing system operability .
10
3.2
System Readiness Review Inspections - Salem Unit 1
3.2.1 Background
On May 16, Salem Unit 1 shutdown due to inoperable switchgear supply fans.
On
June 7, Salem Unit 2 entered TS 3.0.3 and began to shutdown due to inoperable
RHR trains. During the shutdown, a 500 KV breaker failure and a subsequent
loss of two of four operating reactor coolant pumps caused a reactor trip from
10% power.
Because of ongoing hardware and management concerns related to the
continuing operation of both Salem units, the NRC issued a Confirmatory Action
Letter, (CAL), dated June 9, 1995, that confirm commitments between the NRC
and PSE&G.
The CAL specified, in general terms, the conditions that must be
satisfied prior to restart of the Salem units.
To address long standing hardware deficiencies, the licensee initiated a three
step review process to assure the readiness of key plant systems.
The first
step involved a detailed hand-over-hand walkdown of the affected system. It
also included a review of system design and licensing basis documents, as well
as, open action items. These items were documented, analyzed, and coded in a
system initial readiness report (IRR).
Items coded as "restart required" are
to be addressed prior to plant restart, other items will be addressed on some
other predefined basis. The second step requires the system manager (SM) to
present the IRR to the System Readiness Review Board (SRRB).
The SRRB
critiques the thoroughness of the review, as well as, the specific content of
the IRR.
After the SM satisfies the SRRB, the IRR is presented to the
Management Review Committee (MRC).
This is the third and final step of the
process.
Once the MRC is satisfied, it approves the IRR, and the appropriate
open items are scheduled to be worked in the system outage window.
The scope
of work for 46 key plant systems was defined with this process. This process
was documented in the licensee's System Readiness Review (SRR) Program
procedure (SC.TE-TD.ZZ-0023(Z)).
3.2.2 Scope
The NRC reviewed and verified the thoroughness and the effectiveness of system
readiness reviews (SRRs), including the presentation of the results to
management by performing a number of system readiness inspections. This
review also considered management's activities to ensure a complete assessment
of system readiness prior to plant startup and power ascension.
Four region
based NRC inspectors conducted independent inspections of the following four
systems: safety injection (SI), emergency diesel generators (EDGs), auxiliary
feedwater (AFW), and 125 & 28 VDC systems.
In addition, resident inspectors
observed and evaluated SRRB and MRC meetings that reviewed a number of other
systems.
These reviews and inspections were conducted in August and September
1995.
3.2.3 Observations and Findings
Management Review
During the AFW and 125 & 28 VDC system review, the inspectors noted that
the System Readiness Review Boards (SRRBs) were generally thorough in
,-- --
11
their review of system readiness reports and presentations. The
questions raised by the board members were detailed and technically
oriented toward the particular system being presented.
The questioning
also revealed that the board members performed some independent system
review and walkdown.
Typically, through questioning, the board members
assigned numerous action items to the system managers during the SRRBs.
For example, the AFW system manager was assigned 38 action items to be
performed prior to the MRC presentation. System managers were
challenged by the board to justify why some "post-restart" items should
not be "restart required" items.
In addition, the board expected the
system managers to display a strong sense of system ownership.
On August 14, the SRRB assessed a System Manager's second presentation
of the Control Air Ventilation (CAV) system readiness, and a System
Manager's presentation of Main Generator system readiness.
The SRRB had
previously rejected the CAV presentation for quality not meeting the
SRRB standards.
System Managers presented summations of the basis for
developing assessments of system health and required maintenance and
modifications prior to restart. The bases included documented
deficiencies (such as open Work Orders, Deficiency Evaluation Forms,
etc.), Operating Experience, Design and Licensing Basis, and system
walkdown results. The SRRB asked challenging questions to insure that
the System Managers had performed a comprehensive determination of
system condition, fully understood design and licensing basis
requirements for the system, and that the System Managers felt a strong
sense of ownership for their systems.
An inspector attended several presentations of the readiness review
results for various systems, principally EDG, to assess the quality of
the technical inquiry and the thoroughness of the review.
The inspector
observed that the IRR reflected a thorough understanding of the purpose
of the review, a probing attitude by the review board members, and the
system knowledge and competence of the system manager/principal
contributor to the review package.
Based on the above observations and findings, the inspector concluded
that the licensee's readiness review of the EOG system was comprehensive
and thorough.
The resolution of the restart issues will enhance the
readiness and reliability of the system to perform its design safety
function.
In some cases, MRC declined to review items scheduled for presentation
due to unavailability of the sponsor for the presentation (e.g., the
Engineering Action Plan on September 1). The MRC occasionally added
items to the "required for restart".not recommended by the System
Manager due to schedule considerations.
The MRC conducted especially
high quality reviews when chaired by the Salem General Manager.
System Manager and Technical Staff Performance
An inspector reviewed open items for the auxiliary feedwater system and
found that the items were generally well screened and categorized
,._, I
. 12
appropriately per the restart criteria. The system manager identified
over 120 items as required for restart. However, the inspector noted
some inconsistencies in the documentation of the restart categorization
on the open item data base.
For example, Action Request 941018143, to
examine and excavate auxiliary feedwater piping, was coded as post-
restart, but the item description stated that it was required for
restart. Similarly, DCP lEEOOOOll was coded as required for restart,
but the item description stated that it was a recommended restart item.
An inspector verified that open issues for the 125 and 28 VDC systems
had been categorized.appropriately and approved without changes by the
MRC for resolution. The DC systems manager had reviewed selected
dispositions of NRC Gls, INs, and Bulletins associated with batteries,
chargers, and inverters, although not required. Thus, comprehensive
assessments were completed by the system manager for both DC systems
(same manager} to ensure that problems were appropriately identified and
accurate assessments of systems status were made.
An inspector performed a walkdown inspection of EOG lA and lC.
This
walkdown confirmed that a thorough and detailed inspection was performed
by the licensee's readiness review team.
The items, such as a loose nut
on the baseplate mounting bolt on EOG lC, missing fasteners on crank
case pressure device on EOG 1, and a missing junction box screw on EOG
lA were identified by tags and labels, and these items were listed in
the readiness review package.
The housekeeping and material condition
of the area and equipment was satisfactory. The drawing included in the
package was valid and showed the design configuration of the EDGs.
The
EOG package reviewed by the inspector was comprehensive and thorough.
The package contained a summary of the design basis as documented in
various design basis documents, results of the readiness review by the
system engineers/managers, summary of findings, and a summary of
recommended actions for disposition of identified work items.
Additionally, the package included several appendices of detailed data
to support the conclusions.* These items indicated good performance by
the system manager.
The SI system manager and related technical staff performed a very
thorough SRR; however, they were occasionally unaware of the details
certain deficiencies listed in the System Index Database (SID} when they
were listed as "restart recommended or not applicable". Thus, they were
unable to explain why an item was not restart required.
Some of these
deficiencies had the potential to affect long term system operability.
An inspector conducted a walkdown of the Unit 1 auxiliary feed system
with the system engineer.
The inspector noted a thorough SM walkdown
since over 20 EMIS (Equipment Malfunction Identification System} tags
were found on the system.
One minor, untagged deficiency, a missing oil
sightgl ass protector on the auxiliary feedwater storage tank heating
pump, was noted by the inspector. Corrective maintenance had been
recently performed on this component to correct a minor oil leak
discovered during the system readiness review walkdown .
13
Process Quality
The system readiness review process was noted to be a detailed approach
for identifying system deficiencies that required resolution prior to
plant restart. Open items and deficiencies were screened against
specific, objective restart criteria. System managers identified many
items which were determined to require work or corrective action prior
to restart, such as system modifications, configuration issues, and
corrective maintenance.
Based on interviews with system engineers and system engineering
management, an inspector concluded that the readiness review process is
providing system managers additional authority and accountability for
correcting deficiencies on their systems.
The process is permitting the
system managers to have more control over the condition of their
respective systems.
The system readiness reviews included comprehensive reviews of selected
design basis documents such as the FSAR.
However, some important design
basis documentation such as the Configuration Baseline Documentation
(CBD) did not receive an in-depth review.
Since the design bases of
some systems have been called into question, the lack of thorough review
of significant design basis documents may indicate a weakness in the *
system readiness review process .
The day-to-day activities were being handled by other engineering groups
onsite to afford system managers the time needed to evaluate systems and
prepare the SRRs.
Good communications had been established between the system manager and
operations staff to better understand each other's needs and desires for
effectively maintaining the systems.
The review criteria for system readiness reviews (SRRs) did not require
review of MMIS database information.
The MMIS database is the all
inclusive system that contains all open and closed information including
LERs, Regulatory and operating experience review (OER) tracking, work
orders, etc.
A number of SI and related rooms were not inspected.
No explanation was
provided for this decision.
Operations did not consistently provide a member to the SRR team, as
such, certain deficiencies that could have affected system operability
were not consistently identified.
System Status and Hardware Conditions
During April 1991, the NRC issued a notice of violation due to various
deficiencies that were not addressed in the EOG loading calculations,
such as:
cable losses for all loads connected to EDGs were not
considered; battery charger limiting conditions were not accounted for;
14
hydrogen recombiner full load kW loading was not considered, etc.
In
Inspection Report 50-272/95-11, the NRC closed the violation based on
the adequacy of the licensee's corrective actions.
In 50-272/95-13, the
NRC documented an additional concern with EDG loading margin due to an
apparent misrating of Service Water (SW) sump motors.
An Action Request
(AR) identified the possibility that Salem had installed 14 horsepower
(HP) Service Water bay sump pump motors rather than the specified 11.5
HP motors for Unit 1 and 11.0 HP motors for Salem Unit 2. This AR
concluded that 14 HP sump pump motors could challenge EDG operability
during accident loading because of extremely small available margins.
In addition, the inspectors noted that engineering had previously
identified concerns about EDG accident loading as a result of continuous
manu~l operation of SW ~raveling screens and strainers. During the SI
system review, an inspector questioned the disposition of an apparent
non-conservatism with the horsepower rating of an SI pump based on
information in the SI IRR.
During questioning and further document
review, the inspector determined this had been adequately resolved;
however, the adequacy of the available diesel loading margin is still in
question.
The routine operation of the SW system in "manual" has the
potential to challenge diesel operability. There are no special
administrative controls to ensure that operators do not unintentionally
overload the EOG.
The adequacy of the EDG loading margin for current
and postulated conditions will remain unresolved pending further action
by the licensee and review by the NRC.
(URI 50-272/95-17-04)
Certain SI valves had repetitive packing leaks over long periods of
time. Three previously l~aking SI valves are to be repacked in the
current outage. This indicates weakness with the licensee threshold for
initiating a detailed root cause evaluation.
Potential deficiencies (PDs) related to SI and related system piping
supports were identified during the inside containment walkdown.
However, these PDs were not compared against a qualified drawing to
confirm the proper configuration nor documented as a potentially
deficient (in an AR) at the time of discovery.
An inspector confirmed acceptable physical conditions of both Unit 1 DC
systems during multiple system walkdowns.
3.2.4 Overall Conclusion
In general, the inspectors found the licensee's system readiness review
process to be thorough, comprehensive, and complete. Thorough SRRs were
performed by system managers to determine system status. This conclusion was
based on the good guidance established in readiness procedures, system
engineer's knowledge, resources provided to system managers (including the
development of the System Index Database system (SIDs) and support by Salem
licensing including reference validations of all open NRC issues), validation
of design basis and licensing information, discussion held by engineering with
operations to better understand their needs/desires; and the interfacing with
other system managers.
System managers were relieved of day to day
responsibilities to better focus their attention on the SRR process. System
- ~
. 15
managers performed conscientious and comprehensive walkdowns.
Noted hardware
deficiencies were generally well documented.
Some deficiencies were noted in
system IRR; however, they were generally very good. *Questionable EDG loading
margins was identified as an unresolved item.
During SRRB and MRC meetings, the inspectors observed that the both the SRRB
and MRC asked probing questions focused on determining the action needed to
assure the ability to operate the plant as designed during and after restart.
In particular, *management screened proposed restart items for safety or
operability issues. The MRC and SSRB also screened proposed maintenance or
modifications for impact on meeting regulatory requirements, repetitive
failures, design basis deficiencies, conditions that cause plant transi~nts,
derate, shutdowns, or inability to meet regulatory requirements.
The MRC
focused on operating the plant as designed, asked many thoughtful questions,
and, in many instan~es, required presenters to return to the MRC with answers
to questions. Overall, the SRRB and the MRC demonstrated sound technical
judgement and high standards in assuring the outage scope included actions
necessary for safe, reliable equipment performance after restart of Salem Unit
I.
4.0
PLANT SUPPORT
4.1
Emergency Preparedness Exercise
On October 5, the licensee conducted a partial participation annual emergency
preparedness exercise.
Inspectors observed the exercise from the simulator
control room, the Technical Support Center {TSC), and the Emergency Operations
Facility {EOF).
At the conclusion of the exercise inspectors attended the
post exercise critique. The inspectors determined that the licensee responded
effectively to the exercise scenario and conducted an effective and candid
post exercise critique. The licensee met the exercise objectives described in
the scenario.
The operating crew in the simulator control room correctly and promptly
identified, classified, and declared the event using the appropriate Emergency
Action Levels {EALs).
The exercise players made timely and correct offsite
notifications.
Inspectors noted excellent communications, repeat-back of
orders, self-verification techniques on the control panels, and sharing of
information among the crew.
Use of operating and alarm response procedures
was excellent. Communications to and from the other exercise emergency
facilities were good.
Command and control by the senior nuclear shift
_supervisor and the nuclear shift supervisor was good.
Work priorities for the
operational support center were clearly posted and communicated.
In the TSC, the inspectors noted the Emergency Director of Operations {EDO)
kept his teams informed of plant status, and provided thorough updates to the
EOF that assisted in making a smooth transition of event responsibility from
the EDO to the Emergency Coordinator.
Teams in the TSC demonstrated they were
equipped to provide engineering support, radiological monitoring, and
16
protective action recommendations (PARs).
They demonstrated effective
communications between emergency response facilities and offsite agencies.
The inspectors noted TSC members kept accurate and current status boards.
Inspectors in the EOF noted excellent teamwork, especially in anticipation of
potential plant problems and consequences.
The inspectors noted timely
activation of the facility and observed good turnover of event responsibility.
Inspectors determined licensee event classifications were timely and accurate.
The EOF members made accurate and independent PARs.
The licensee terminated
the drill early, somewhat limiting exercise of dose assessment field teams and
analysis of collected data.
4.2
Fire Protection
The inspectors discovered that a letter to the NRC dated July 26, 1978 stated
that PSE&G planned to install concrete curbs at the entrance to each emergency
diesel generator room.
This was another example of a previously identified
weakness in commitment and action tracking.
The inspector noted that fire protection failed to install concrete curbs at
the entrance to each emergency diesel generator room as they committed to in a
letter to the NRC dated July 26, 1978.
The inspector noted the failure
provided another example of a previously identified weak commitment action
tracking program, and that licensing engineers planned a thorough review of
commitments and action tracking items to identify other missed commitments as
part of their restart activities. The inspector determined that lack of
curbing is unresolved pending a complete review of the documentation
establishing the commitment.(URI 50-272 & 311/95-17-02)
5.0
SAFETY ASSESSMENT AND QUALITY VERIFICATION
Inspectors reviewed hours worked for ~upervisors and key personnel in the
following departments: Operations, Maintenance, and Radiation Protection. The
inspectors examined time sheets for all employees to determine if the controls
for overtime met the requirements of NC.NA-AP.ZZ-0005(Q), revision 5, section
5.6, Overtime Guidelines.
Paragraph 5.6.2 of the procedure applies to
licensed operators, nuclear equipment operators, and radiation protection
technicians.
It also applies to personnel performing maintenance, repair,
modification or calibration of safety-related structures, systems or
components, and their immediate supervisors. The inspectors verified that the
procedure met the requirements of Technical Specification 6.2.2.d for both
Salem Units. Technical Specification 6.2.2.d incorporated the guidelines of
The inspectors found that with a few exceptions, most employees worked fewer
than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> straight, 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in any 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period, 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any 48
hour period and 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any seven day period (excluding *shift turnover)
permitted by procedure.
In the few cases where employees exceeded the limits
for hours worked, the appropriate manager had authorized a waiver, as
permitted by the procedure .
17
6.0
REVIEW OF REPORTS AND OPEN ITEMS
The inspectors reviewed the following Licensee Event Reports (LERs) to
determine whether the licensee took the corrective actions stated in the
report, detect if the licensee responded to the events adequately, and
ascertain if regulatory requirements and commitments were appropriately
addressed:
Unit 1
Number
.Event Date
LER 95-009.
June 1, 1995
LER 95-013
July 3, 1995
Description
Valid test failure of 18
EDG and subsequent
inoperability of 18 and
of common mode failure.
(Discussed in NRC
Inspection Report 95-10,
section 6.1.B)
Surveillance of seismic
monitoring
instrumentation
performed late .
The inspectors determined that the LERs listed above do not warrant further
- inspection or enforcement action and considered the LERs closed.
7.0
EXIT INTERVIEWS/MEETINGS
7.1
Resident Exit Meeting
The inspectors met with Mr. C. Warren and other PSE&G personnel periodically
and at the end of the inspection report period to summarize the scope and
findings of their inspection activities.
Based on NRC Region I review and discussions with PSE&G, it was determined
that this report does not contain information subject to 10 CFR 2
restrictions.
7.2
Specialist Entrance and Exit Meetings
Date Cs)
Subject
9/18-22/95
Radiological
Inspection
Report No.
50-272&311/95-18
Reporting
Inspector
Noggle
18
7.3
Nuclear Business Unit Organization Changes
During the inspection period PSE&G made the following personnel changes:
Name
Effective August 21:
David Garchow
Effective August 24i
Nick Conicella
Effective August 28:
Jay Laughlin
Christopher Bakken
Director, System Engineering
Manager, Salem Projects
Maintenance Manager
Operations Manager
Effective September 5:
Jerry McMahon
Director, Nuclear Training
Gary Overbeck
Director, Nuclear Design Engineering
Effective September 11:
Mark McGough
Director, Plant Engineering and Projects
Charles Munzenmaier
General Manager, Operations Servic~s
Charles Smith
Manager, Site Planning
,.
>>*' ..
, :.r'
ATTACHMENT l - Eddy Current Testing of Steam Generator Tubing Inspection
A reactive inspection was performed at Salem Unit l when NRC staff was
informed of several emerging issues. The issues dealt with eddy current
testing (ECT) of steam generator (S/G) tubing.
The purpose of the inspection
was to ascertain information related to the issues, review pertinent eddy
current data, and determine PSE&G's resulting actions.
Westinghouse, PSE&G's ECT vendor, performed ECT and data analysis during both
the current (1995) refuel outage, and the previous (1993) refuel outage.
During the 1995 refuel outage, PSE&G's quality assurance (QA) department
performed a surveillance at the ECT vendor's office, where ECT data analysis
was ongoing. A number of observations (i.e. weaknesses) were made during the
surveillance. The three issues described below are additional to the QA
surveillance observations.
Issue No. l
Nine bobbin probe indications were missed during the 1993 refuel outage that
should have been plugged.
During the 1995 ECT inspection, axial and circumferential cracking was
identified in some S/G tubing.
To determine crack growth rates, the
licensee's ECT contractor reviewed the applicable 1993 ECT inspection data.
As a result of that review, the vendor determined that there were nine
indications (located on eight tubes) that exceeded the Technical Specification
plugging limit of 40% through wall, and should have been plugged during the
1993 refuel outage.
The indications were located at the hot leg top of
tubesheet and at various tube support plates (TSP).
Problem report 950926331
was initiated as a result of this issue.
The NRC inspector reviewed the 1993 ECT bobbin probe data and verified that
there were indications that should have been identified in 1993.
PSE&G was
evaluating the situation to determine .the extent of ECT data reanalysis to be
performed.
Issue No. 2
Dented TSP intersections were tested with an RPC probe that was not qualified
for dented S/G tubing.
A rotating pancake coil (RPC) probe was being used for inspection of a
population (approximately 4000) of TSP intersections, some of which were
dented.
The RPC probe PSE&G authorized for use was 0.115" diameter.
Instead,
a 0.080
11 diameter RPC probe was used.
The 0.080" diameter RPC probe was not
qualified for use in dented S/G tubing. Although not part of a routine vendor
surveillance activity, it was PSE&G who obtained information which indicated
that an inappropriate probe was being used.
The ECT vendor reviewed the
available documentation, and reached the conclusion discussed above.
Problem
report 950925314 was initiated as a result. The vendor was in the process of
2
attempting to get the 0.080" diameter RPC probe qualified for dented
locations.
In addition, both PSE&G and the ECT vendor were evaluating the
issue to identify a cause.
Issue No. 3
Lack of correlation between Cecco-5 probe data analysis results and PlusPoint
probe data analysis results.
The Cecco-5 probe was used for initial screening of TSPs and top of tubesheet
locations. The PlusPoint probe was then used to analyze locations identified
as "possible indications" by the Cecco-5 probe.
The final tube integrity
evaluation was based on the PlusPoint data analysis.
PSE&G identified that
the correlation between the Cecco-5 probe analysis results and the PlusPoint
probe analysis results was around 35%.
Due to this lack of correlation and
several other factors, PSE&G brought several independent Level III ECT
analysts on-site to independently review the PlusPoint data. These analysts
had previous experience with analysis of PlusPoint data.
The independent
analysts identified additional indications that were not identified by the
original analysis.
PSE&G made the decision to reanalyze all Cecco-5 "possible
indications" (i.e. PlusPoint data).
As a result of these three issues and the QA surveillance observations, PSE&G
sent a quality assessment team to the ECT vendor's office. Also, a stop work
order for all ECT work was issued by PSE&G management until the issues are
resolved. Several other actions being taken by PSE&G are as follows:
obtaining the services of an independent Level III ECT Analyst for all ECT
work, arranging for an independent organization to perform the secondary
analysts function for reanalysis of ECT data, and development of site specific
analysis guidelines for all ECT probes (not just bobbin).
PSE&G was very aggressive in addressing the issues once they were identified.
However, more information is required to ascertain whether*they are
acceptable, a deviation, or a violation of regulatory requirements .
. Therefore, this will be an unresolved item (URI 50-272 l 311/95-17-03) .