ML18102A643
| ML18102A643 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 12/03/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18102A641 | List: |
| References | |
| 50-272-96-15, 50-311-96-15, NUDOCS 9612090265 | |
| Download: ML18102A643 (50) | |
See also: IR 05000272/1996015
Text
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Docket Nos:
License Nos:
Report No.
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved by:
U. S. NUCLEAR REGULATORY COMMISSION
50-272, 50-311
REGION I
50-272/96-15, 50-311/96-15
Public Service Electric and Gas Company
Salem Nuclear Generating Station, Units 1 & 2
P.O. Box 236
Hancocks Bridge, New Jersey 08038
September 15, 1996 - November 2, 1996
C. S. Marschall, Senior Resident Inspector
J. G. Schoppy, Resident Inspector
T. H. Fish, Resident Inspector
E. B. King, Physical Security Inspector
E. H. Gray, Project Manager
Larry E. Nicholson, Chief, Projects Branch 3
Division of Reactor Projects
9612090265 961203
ADOCK 05000272
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EXECUTIVE SUMMARY
Salem Nuclear Generating Station
NRC Inspection Report 50-272/96-15, 50-311 /96-15
This integrated inspection included aspects of licensee operations, engineering,
maintenance, and plant support.
Operations
Operators* isolated service water to an available emergency control air compressor.
Operators missed several opportunities to identify the degraded condition. The operations
corrective action staff performed an inadequate evaluation of the occurrence and failed to
identify that operators ran the emergency control air compressor without service water
(SW) cooling (Section 02.1 ).
Inspectors discovered that operators used informal methods to control valve manipulations,
and an incorrect procedure revision to perform charging pump performance testing.
Operators also performed procedure steps out of sequence when removing a vital bus from
service, did not adhere to the alarm response procedure for the no. 1 station air
compressor, and did not document degraded equipment condition. Operations managers
initiated appropriate corrective measures in each of the above circumstances, however,
poor operator performance in procedure adherence and use remains an NRC concern
(Section 04. 1 ) .
Due to inadequate preparation and incomplete system knowledge, operators did not
anticipate depressurizing the no. 4 SW header. In response, the operators failed to follow
procedures to restore pressure, and prevented safety related equipment from automatically
functioning to mitigate the pressure loss. Instead, they restored pressure through
application of inappropriate. procedures and use of SW support systems in an unevaluated
manner. The operator performance and the initial corrective action was poor (Section
04.2).
The LERs and supplements identified in Section 08.13 identify 26 Technical Specification
(TS) related problems exemplary of a programmatic failure. Taken collectively, they form
the basis for concern regarding the adequacy of Salem procedures and controls to assure
compliance with TS requirements. The PSE&G initiative to identify and correct similar
deficiencies via the Technical Specification Surveillance Improvement Project (TSSIP)
indicates a positive attitude toward corrective action. Notwithstanding, the adequacy of
procedures and controls, as identified in NRC restart inspection item 111.3 remains to be
resolved (Section 08. 13).
Maintenance
Operators and technicians accomplished a carefully controlle~ test of the Salem Unit 2
phase "A" containment isolation valves. They precisely recorded the minor discrepancies
observed during the test. The plant staff did not thoroughly insure resolution of
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disagreement between plant design and Technical Specification 3.6.3 requirements for
- valves 2CV68 and 2CV69.(Section M1 .2)
Engineering
The Salem Steam Generator Replacement Project staff demonstrated effective control of
planning and transportation of the steam generators (Section E1 ). The inspectors
considered the corrective action taken to date to resolve concerns with the Emergency
Diesel Generator Air Start System acceptable. The Salem staff produced a thorough and
technically sound resolution for this restart issue.
Engineering acknowledged continued station air and control air deficiencies, however, they
did not affect corrective measures to ensure reliable operating performance (Section E8.1 ).
Plant Support
Radiation Protection took prompt and appropriate action in response to contamination
found outside the radiologically controlled area (Section R2.1 ).
The Salem Unit 1 steam generators met most of the requirements for an SCO class II
shipment. The contamination level on the channel head and tube sheet areas appeared to
be above the DOT limits and the steam generators were not packaged into IP~2 containers.
Accordingly, the licensee applied for exemption to these requirements, which were
subsequently approved by the DOT.
Security personnel complied with the requirements of the security plan for access control
in response to door alarms. Although security supervisors and managers might have been
more aggressive in implementing compensatory measures and initiating maintenance
efforts, the inspectors did not find any degradation of access control (Section S2.1).
During receipt of replacement steam generators, Salem security staff properly and
effectively implemented compensatory measures associated with temporary changes to the
perimeter intrusion detection systems, and protected area barrier. Additionally, the
inspector determined that measures were in place to ensure proper restoration of the
barriers and intrusion detection systems as required by the approved security plan (Section
S8.1).
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TABLE OF CONTENTS
EXECUTIVE SUMMARY
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TABLE OF CONTENTS .............................................. iv
I. Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
II. Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
16
Ill. Engineering
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
IV. Plant Support . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
28
V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
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Report Details
Summary of Plant Status
Unit 1 and Unit 2 remained defueled for the duration of the inspection period.
I. Operations
01
Conduct of Operations
01 . 1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of
ongoing plant operations. In general, the conduct of operations was professional
and safety-conscious; specific events and noteworthy observations are detailed in
the sections below.
01.2 (Update) LER 50-311196-009 : fourteen day follow-up report regarding 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
shifts for operations personnel. This Licensee Event Report (LER) identified a
conflict between Salem's practice of 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> work shifts for operations personnel
versus an Operating License requirement of 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> shifts. PSE&G presently utilizes
this work schedule for operations personnel at the Hope Creek plant and the Hope
Creek Technical Specification (TS), Section 6, permits that practice. PSE&G has
submitted* a Licensing Change Request to address this issue for Salem and is
tracking a commitment to resolve this issue with the NRC prior to entering Mode 2.
The inspector found the resolution to this specific licensing condition issue
satisfactory.
Part of the corrective action for this LER required PSE&G to review all Salem Unit 2
license conditions to verify they have been, or are being satisfied.
The inspector
learned that a report was being prepared to document the review and the results
but the final report was not available at the time of the inspection. This LER will
remain open pending review of the final report.
02
Operational Status of Facilities and Equipment
02.1
Emergency Control Air Compressor Control, NRC Restart Items Ill. 7 and 111.10
(Open)
a.
Inspection Scope (71707)
b.
The inspector reviewed the Salem corrective action in response to an operator-
identified near miss involving the no. 2 emergency control air compressor (ECAC).
Observations and Findings
On September 26, 1996, in preparation for starting no. 2 ECAC, the Unit 2 reactor
operator (RO) reviewed the off-normal Tagging Request and Inquiry System (TRIS)
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report in accordance with S2.0P-SO.CA-0001, Control Air System Operation. The
RO identified that technicians had previously tagged out essential service water
(SW) supply valves to the ECAC on September 13, 1996. The operator placed the
no. 2 ECAC in manual to prevent an automatic start and initiated a corrective action
request (AR 960926067).
Operations management preliminarily attributed the root cause of the tagged SW
valves to a tagging process deficiency. An Operations Planning and Scheduling
Senior Reactor Operator (SRO) reviewed the SW tagout and failed to identify the
impact on no. 2 ECAC. Operations staff believed that the no. 2 ECAC was in
automatic when equipment operators (EO) tagged the SW valves on September 13
and remained aligned without SW cooling until September 26. They believed that
operators did not run the ECAC during this period. On September 27, the station
management team assigned a significance level 1 condition resolution (CR) to AR
960926067, requiring plant staff to complete a root cause investigation within 3.0
days.
Early in the evaluation, the operations reviewer determined that this event had
similarities to 18 other tagging events subject to a level 1 root cause evaluation
initiated in January 1996 (960109205).
On day 26 of 30, the specialist had
completed a one page justification that this event did not require a separate root
cause evaluation. He planned to present the justification to station management on
day 27 of 30. As a result of this conclusion, the reviewer had not identified several
conditions adverse to quality. The inspector noted that the "specialist" assigned to
perform the root cause analysis had not completed the PSE&G root cause training,
and had never performed a level 1 root cause analysis.
Based on independent review, the inspector identified the following facts not found
as a result of the root cause:
On 9/2 and 9/12, the Operations Planning and Scheduling SRO approved a
SW tagging request (103109) that isolated cooling to the no. 2 ECAC. The
SRO failed to identify that the no. 2 ECAC remained available to start
automatically on low air header pressure.
Unit 2 operators placed no. 2 ECAC in manual at 5: 11 a.m. on September
13, in preparation for a no. 2C vital bus outage. Fortuitously (due to the
vital bus outage), the ECAC was unavailable prior to tagging the SW valves
on September' 13.
On 9/15, following restoration of no. 2C vital bus the operators ran no. 2
ECAC for six minutes without cooling water available. The operator did not
insure the availability of SW to cool the ECAC, as required by S2.0P-SO.CA-
0001.
On 9/16, prior to removing no. 1 station air compressor (SAC) from service,
operators verified valves 2SW401 and 2SW119 open to ensure SW available
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to no. 2 ECAC. They did not identify that upstream SW valves (2SW300
and 2SW90) were tagged and isolated SW to the ECAC.
Procedures SC.OP-AP.ZZ-0107, Revision 3, Shift Turnover Responsibilities,
step 3.7.1 and S2.0P-D2.ZZ-0014, Revision 4, Shift Routines, step 5.14.2
require the RO to review the Tagging Request Inquiry System off-normal
report. From September 13 to September 26, no RO identified that 2SW300
and 2SW90 were tagged closed.
On October 24, the inspector presented the above observations and findings to
station management. Operations management promptly provided additional
guidance on procedure compliance and management expectations concerning less
than adequate operator performance to all operators. The engineering staff
determined that running the no. 2 ECAC for six minutes without SW cooling did not
adversely affect the ECAC. Operations management maintained the ECAC CR as a
level 1.
The inspector determined that the tagged SW valves and operators failure to
identify the condition in a timely manner resulted in running the ECAC without SW
cooling and increased outage risk. From September 17-19, both ECACs and two
out of three SACs were unavailable. SC.SA-AP.ZZ-0055, Outage Risk
Management, requires a contingency plan for this degraded condition. Failure to
identify and take prompt and appropriate actions to correct conditions adverse to
quality is a violation of 10 CFR 50, Appendix 8, Criterion XVI (VIO 50-272&311 /96-
15-01 ).
Conclusions
An alert operator prevented operation of the no. 2 ECAC without cooling water. He
identified that several barriers to insure cooling water had failed. In response to the
identified failure, the plant staff did not effectively implement the corrective action
program. As a result, the reviewers did not identify that operators had previously
run the compressor for six minutes without cooling water. In addition, the
reviewers did not identify that operators missed several opportunities to identify
that the compressor remained available to start automatically without available
cooling water.
02.2 (Closed) LER 50-272/96-011: pressurizer safety relief valves found outside of
technical specifications limit. The TS requires the relief valve lift point to be within
plus or minus 1 percent of the set point. Three of the pressurizer relief valves failed
this requirement during testing. The deviations were plus 1.28, 1.32, and 3.90
percent. The inspector reviewed documentation that verified the valves were
refurbished and successfully retested. The inspector reviewed the approved root
cause analysis for this event and found it acceptable. The corrective actions
resulting from this are either complete or are being tracked to completion by
Performance Improvement Number 960621244. The inspector considered the
corrective actions appropriate. This LER is closed.
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04
Operator Knowledge and Performance
04.1
Procedure Use and Adherence
a.
Inspection Scope (71707)
b.
The inspector observed control room activities to ensure operators adhered to
approved procedures and that procedures were of the correct revision, useful, and
complete.
Observations and Findings
During the inspection period, the inspectors observed daily operator activities to
assess operator use and adherence to procedures. The Salem operators typically
used approved procedures to control equipment manipulations, responses to alarms,
and other safety related activities. The operators appropriately used procedures and
closely adhered to the procedures in most instances. The inspectors noted that in
the following examples, however, operators did not adhere to procedures.
On September 18, 1996, Unit 2 operators conducted S2.0P-PT-CVC-0002,
Charging Pump Flow Test. The inspector observed that operators did not sign off
each procedure step as they completed it. Subsequently, the reactor operator
documented all completed steps in the procedure. In addition, the operators used a
"post-it" note attached to the procedure to control closing two valves
(2SJ12/2SJ13). Operators closed the valves during shift turnover to preclude
gravity fill of the refueling cavity from the refueling water storage tank. The
Operations Manager directed operators to annotate the control room narrative log to
indicate operator action, reason for action, and senior reactor operator concurrence
when conducting activities not specifically covered by procedures. The inspector
determined that the 2SJ 1 2/2SJ 13 narrative log entry provided adequate control for
the closed valves. The inspectors considered operator use of informal control of
plant equipment an example of poor performance.
On October 1, 1996, the inspector found that Unit 2 operators performed
approximately half of procedure TS2.0P-PT.CVC-0002, Troubleshooting on 21 or
22 Charging Pump With Temporary Modifications of Plant Configuration, without
noting that it contained a combination of revision 0 and revision 1 . The Unit 2 SRO
promptly stopped the troubleshooting activity and initiated a CR report (CR
961002063). The SRO found that the operators missed an independent verification
of an instrumentation alignment as a result of the mixture of procedure revisions.
Operators subsequently performed the independent verification and found the
instrumentation properly aligned. The inspector noted that the operating shift did
not demonstrate a questioning attitude when presented several opportunities to
identify an incorrect procedure revision. The inspector considered the lack of
attention to detail an additional example of poor operator performance.
On October 21, 1996, the inspector observed that, when removing the no. 1 C
460V/230V vital bus from service, the RO performed procedure S1 .OP-S0.4KV-
0003, 1C 4KV Vital Bus Operation, step 5.2.4 before performing step 5.2.3. The
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RO and SRO determined that they should reverse the sequence to protect plant
equipment. The inspector concluded that no immediate threat to equipment existed
and the operators proceeded without using an approved method to change the
procedure. The inspector noted that performing the steps out of sequence resulted
in an additional 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> without the no. 1 emergency control air compressor, 1
hour without no. 11 and no. 12 service water pumps, and 40 minutes without no.
1 C emergency diesel generator. The reduced availability did not impact plant safety
due to the Unit 1 condition (shutdown and defueled). Operations management
counseled the RO and SRO concerning procedure adherence. Operators submitted a
request to change S1 .OP-S0.4KV-0003 to provide additional equipment protection.
Failure to adhere to procedures for control of safety related equipment is a violation
of TS 6.8.1 requirements (VIO 50-272&311/96-15-02).
On October 23, 1996, personnel in Unit 1 turbine building reported a high water
level in separator alarm on no. 1 SAC. The EO informed the RO that he performed
the steps in the alarm response procedure (ARP), and could not resolve the problem.
The SRO and RO recalled previous problems with the drain line clogging and that
cycling the drain valves closed then open again had successfully cleared the
blockage. The SRO directed the EO to cycle the drain valves. The EO cycled the
drain valves and reported that the alarm cleared. The inspector observed that,
although not specified by the alarm response procedure, the EOs routinely cleared
the alarm by cycling SAC valves 11SA1 5 and 11 SA 17 to dislodge corrosion
products from the drain lines. They did not initiate an AR to document the plugged
drain line on those occasions. In addition, the operators did not place another
compressor in service, and no. 1 SAC in manual, when they could not control
separator water level, as required by procedure SC.OP-AR.SA-0001, Revision 5,
Station Air Compressors Control And Alarm Panel. On October 23, 1996, the
inspector presented the above observations to the Senior Nuclear Shift Supervisor
(SNSS). *As of October 24, the operating shift did not initiate an action request (AR)
to document the degraded SAC piping, or the ARP non-compliance. This is an
additional example of failure to identify degraded plant conditions.
Conclusions
In most cases during daily plant activities, operators closely adhered to procedures.
Inspectors discovered that operators used informal methods to control valve
manipulations, and an incorrect procedure revision to perform charging pump
performance testing. Operators also performed procedure steps out of sequence
when removing a vital bus from service, did not adhere to the alarm response
procedure for the no. 1 station air compressor, and did not document degraded
equipment condition. Operations managers initiated appropriate corrective
measures in each of the above circumstances, however, poor operator performance
in procedure adherence and use remains an NRC concern.
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- 04.2 Service Water (SW) Bay Depressurization, NRC Restart Items Ill. 7 and 111.10.1
(Open), Inspector Follow-up Item 50-272 and 311 /96-12-02 (Closed)
a.
Inspection Scope (92901 l
The inspector evaluated corrective actions for an operator-induced SW bay
depressurization.
b.
Observations and Findings
On September 3, 1996, Unit 2 operators closed 22SW17, SW pump discharge
header crossover valve, in preparation for 21SW17 valve maintenance. Due to the
SW system alignment, closing the 22SW17 resulted in no. 4 SW bay
depressurization. Within an hour, operators restored no. 4 SW bay pressure and
reopened the 22SW17. Operators cross-connected the SW nuclear headers in the
auxiliary building prior to closing 22SW17 and did not expect to depressurize no. 4
SW bay. Operators did not account for a SW check valve that prevented flow
backward from the auxiliary building to the SW bay. Cross-connecting the SW
nuclear headers in the auxiliary building prevented depressurization of the no. 22
SW nuclear header and resulted in no safety consequence. The Unit 2 SRO initiated
a CR report (960903068). The inspector considered the item open pending
operations' completion and NRC review of corrective actions .
On October 16, 1996, operations staff completed an apparent cause evaluation.
The evaluator attributed the apparent cause to control room crew failure to use
procedure S2.0P-SO.SW-0005, Service Water System Operation, or SW system
drawings for guidance in closing 22SW17 and ensuring adequate SW flow to no. 4
SW bay. He noted that failure of the Planning and Scheduling Group to consider
the 22SW17 closure a complex evolution and the resulting lack of special
instructions in the maintenance tagging request ( 10481 2) a contributing cause.
He
also identified the failure of the control room crew to follow the ARP for overhead
annunciator (OHA) B-24 (no. 24-26 SW pumps low bearing cooling pressure) a
contributing cause. The B-24 OHA ARP directed operators to open 22SW250 to
restore bearing cooling, however, operators opened both 21 SW250 and 22SW250
to re-pressurize no. 4 SW bay. The operations staff concluded that the SW bay
depressurization had no safety significance due to the plant condition (shutdown
and defueled with no. 2 SW bay supplying both nuclear headers), and since the
control room crew took immediate action to restore no. 4 SW bay pressure.
Operations management took corrective action for human performance deficiencies.
The Operations Department newsletter emphasized the need for personnel to
comply with procedures. Operations supervision planned to provide all Operations
Department personnel a copy of the Apparent Cause Report as required reading to
reinforce management expectations regarding station operating practices. In
addition, they planned to provide additional instructions on 22SW17 tagging
requests.
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Inspectors found that apparent cause evaluation by the operations staff overlooked
or failed to address a number of significant concerns. These included:
The Unit 2 operator, after closing the 22SW17, took no. 24 SW pump out of
automatic as SW header pressure started to decrease. The operator believed
that SW pressure would stabilize and did not want an automatic pump start
(pump auto starts at 95.5 psig). The automatic pump start would have
prevented no. 4 SW bay depressurization.
Operators did not comply with OHA 8-14 ARP. When the bay depressurized,
OHA 8-14 ARP directed operators to abnormal procedure S2.0P-A8.SW-
0001, Loss of Service Water Pressure. Procedure S2.0P-A8.SW-0001 step
3.5 directs the operator to start a service water pump to restore pressure.
Operators did not start a service water pump to restore pressure.
The on-shift SRO was not familiar with the availability of safety related
equipment. He stated that the degraded condition of the no. 4 bay pumps
(pumps 24, 25, 26) prevented operators from placing these pumps in
service. Contrary to his belief, SW pumps no. 24 and no. 26 SW were
available and no. 24 SW pump was in automatic when the operators closed
22SW17.
Operators did not fully understand operation and design of the SW system .
The Unit 2 operator and NSS did not anticipate that 24" check valve 24SW5
would prevent SW flow from the pressurized auxiliary building nuclear
headers back to the no. 4 SW bay. Several operators stressed the
importance of providing SW for no. 24 SW pump motor upper bearing
cooling. The upper bearing is air-cooled and needs no SW supply. In
addition, 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after bay depressurization, the SRO did not know if any of
the no. 4 SW bay pumps were in automatic prior to 22SW17 closure.
Operators did not realize that they connected the Unit 2 SW system to the
Unit 1 SW system. The operating shift reviewed Unit 1 and Unit 2 SW
system prints and created a method to re-pressurize the SW bay through the
21 SW250 and 22SW250. These valves are normally locked closed and
operated individually under abnormal conditions, to provide alternate SW
pump bearing cooling. Although OHA 8-24 ARP directed-operators to open
only the 22SW250, operations opened 21 SW250 and 22SW250 in an
attempt to re-pressurize the bay. The SRO and RO stated that they knew
that the 8-24 ARP directed opening only the 22SW250, however, they
considered the bay re-pressurization a priority. The inspector identified that
opening the 21 SW250 and 22SW250 placed the SW system in an
Operators did not adequately document the transient in control room
narrative logs. The logs stated: Closed 22SW17, no. 4 bay depressurized to
11 psig, opened 21 and 22SW250s. Re-opened 22SW17, no. 4 bay re-
pressurized, closed 21 and 22SW250s."
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On September 10, plant staff used special tagging instructions to control
22SW17 closure. The inspector noted, however, that no controls exist in
maintenance procedures, the tagging process, or operating directives to
ensure that operators use these special tagging instructions in the future for
similar valve strokes that impact plant operation.
The inspectors concluded:
Some operators involved did not understand the requirements for procedure
adherence, as required by TS 6.8.1.
Operators inappropriately allowed the perceived urgency to restore SW
header pressure to override their safety focus. Even with no. 4 SW bay
depressurized the SW system continued to supply adequate cooling for plant
conditions (shutdown and defueled). Operators had no reason based on
plant or worker safety to deviate from procedure requirements.
Operations and plant managers did not insure appropriate or timely corrective
action. It took 7 days to initiate a significance level 2 CR. Once assigned as
a level 2, the evaluator took 36 days to complete the evaluation. Licensee
procedure NC.NA-AP.ZZ-0006, Corrective Action Program, states that
management expects that evaluators complete level 2 evaluations within 30
days .
The Condition Resolution evaluator was not qualified to determine the cause
or corrective action for the inappropriate operator performance. He had very
little operations experience and less than one year experience at the Salem
station.
PSE&G failed to identify and evaluate operator action taken to disable
automatic actuation of a safety-related component during an operational
transient. Failure to identify and correct conditions adverse to quality is a
violation of 10 CFR 50, Appendix 8, Criterion XVI "Corrective Action"'
requirements (VIO 50-272&311 /96-15-01 ).
On October 24, the inspectors discussed the above observations and findings with
station management. Operations management acted promptly to address corrective
action program concerns. A significance level 1 CR was initiated on the adequacy
of operations corrective action process (961025129) and issued a Standing Order
was issued on performance of fact-finders following significant events. (SOD-96-
122). On October 28, the operations manager issued a memorandum to all
personnel concerning procedure use and adherence, and detailed the many
operations shortcomings over the inspection period (see sections 02.1, and 04.1 ).
The memorandum provided candid self-assessment and focused lessons learned.
The October 24 Standing Order directed operations personnel to perform the
following steps for all human performance errors that result in the issuance of a CR:
c.
04.3
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( 1)
(2)
(3)
9
Notify one of the four senior operations department representatives,
assemble a fact finding team, and
interview involved individuals prior to end of shift and before individuals
leave site.
The inspector noted that the Standing Order provided adequate interim guidance,
however, it did not adequately ensure a long-term solution to operations'
performance weaknesses. Reliance on four personnel does not ensure appropriate
operating shift response during operational transients and provide real time safety
focus twenty-four hours a day. On October 29, Unit 2 operators attempted to start
no. 21 containment spray pump. The pump did not start because.the pump's 125
VDC control power breaker was open and its 4KV breaker was racked down. The
operating shift identified human performance issues and initiated a CR
(961029270), however, contrary to management's expectations the fact finding
team did not interview involved individuals before individuals departed the site. In
addition, the involved SNSS and SRO were members of the fact finding team. The
inspector noted that this approach, similar to the initial 22SW17 fact finding, did
not contain sufficient independence.
Conclusions
Due to inadequate preparation and incomplete system knowledge, operators did not
anticipate depressurizing the no. 4 SW header. In response, the operators failed to
follow procedures to restore pressure, and prevented safety related equipment from
automatically functioning to mitigate the pressure loss. Instead, they restored
pressure through application of inappropriate procedures and use of SW support
systems in an unevaluated manner. The operator performance and the slow and
ineffective corrective was cause for concern. Although plant staff initiated the
corrective action process, the resulting apparent cause investigation failed to
identify multiple operator performance problems. In addition, the corrective action
process did not involve the appropriate levels of management. As a result, the
initial corrective actions were incomplete and ineffective. Plant managers
implemented measures to address the performance deficiencies and to insure
appropriate management involvement in future operator performance problems.
(Closed) LER 50-311195-001: manually initiated engineered safety feature actuation
to effect a main steam isolation signal in order to increase reactor coolant system T-
avg above 541 degrees (F). While reducing power, operators allowed the reactor
coolant system Tavg to decrease below the TS minimum value, 540.5 degrees
versus 541 degrees (F). The operators responded by initiating a manual main steam
isolation from the "Safeguards" bezels to increase Tavg. The operators were able
to return Tavg above the TS minimum value in approximately one minute, well
within the 15 minutes allowed by TS 3.1.1 .4.
The inspector determined that this event was minor and did not constitute a
violation of NRC requirements. This LER is closed.
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07
Quality Assurance in Operations
07 .1
Operating Experience Feedback (OEFJ, NRC Restart Inspection Item 111.9 (Closed)
Inspectors previously reviewed the OEF effectiveness in NRC Inspection Report 96-
06. The inspector did not close the NRC Restart Inspection item as a result of
discrepancies between the requirements of procedure NC.NA-AP.ZZ-0054(Q),
Operating Experience Program and actual program implementation. The inspector
reviewed NC.NA-AP.ZZ-0054(Q), Revision 4, dated 10/24/96 and determined that
plant staff had effectively revised section 3.8, responsibilities of the General
Managers, Salem and Hope Creek to reflect the actual practice. In addition, the
inspector reviewed the OE program response to NUREG CR-6245, NUREG 1522,
and Westinghouse Owners Group recommendations for EOPs. The inspector
considered the OE program treatment of these items appropriate. The NRC Restart
item is closed:
08
Miscellaneous Operations Issue
08.1
(Closed) Unresolved Item 50-272 and 311 /92-12-01: EO log falsification. The issue
remained open pending resolution of EO tour conduct and security card system
effectiveness. Salem Quality Assurance (QA) conducted frequent assessments of
EO conduct and log-taking. Quality Assurance inspectors stated that EOs
demonstrated good performance in this area. Security supervisors determined that
no deficiency existed within the security key card system. The NRC inspector
reviewed station QA Surveillance Report 92-666, conducted over the period
September 16, 1992 - September 21, 1992, and concluded that QA appropriately
determined that equipment operators conducted proper rounds and security key
card readers functioned as designed. The inspector frequently reviewed EO logs
and observed EO tours. The inspector found no evidence of EO misconduct and
observed that the security key card system functioned to record access information.
This item is closed.
08. 2
(Closed) Unresolved Item 50-27 2 and 311 /93-21-03: potential technical
specification noncompliance due to solid state protection system (SSPS) train B in
operability. Operators had indications that SSPS train B did not function properly,
however, they failed to pursue those indications in a timely manner commensurate
with the potential safety consequence. This is a violation of 10 CFR 50 Appendix B
Criterion XVI, Corrective Action, requirements. Since the NRC has taken significant
enforcement action for Salem's failure to identify and correct conditions adverse to
quality, and since PSE&G voluntarily maintained both Salem units shut down to
address equipment and enforcement deficiencies, the NRC will not take additional
enforcement action in these cases. In particular, Salem management took extensive
measures to retrain all licensed operators to improve plant knowledge, operator
performance, and safety culture. This item is closed.
08.3 (Closed) Violation 50-311/94-06-01: failure to comply with TS for power operated
relief valves (PORVs). Operation's management determined that inadequate
procedural guidance directly attributed to the TS noncompliance. The inspector
I
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08.4
11
reviewed PSE&G's response to the violation and determined that the licensee took
appropriate corrective actions. The inspector verified that the licensee completed
the associated TS amendment and operating procedure changes addressed in their
response letter. This violation is closed.
(Closed) Violation 50-272&311 /94-80 (EA 94-112-03013): loss of control room
command and control. The control room senior reactor operators (SNSS, NSS) did
not maintain appropriate command and control of the reactor at all times.
Management took actions to improve shift supervisory personnel performance,
especially with regard to control room leadership. Management reinforced
command and control expectations through written guidance, shift training, and
control room observations. In particular, Salem management took extensive
measures to retrain all licensed operators to improve plant knowledge, operator
performance, and safety culture. The inspector reviewed shift guidance provided
through Night Order Book entries and observed SROs at the training center and in
the control room. The inspector concluded that management affected significant
improvements in SRO performance relative to command and control. The NRC
restart inspection issue will address any additional issues of command and control
prior to restart. This violation is closed.
08.5 (Closed) Unresolved Item 50-272&311 /94-13-02: repeated entry into Technical
Specification LCO. This item remained unresolved pending inspector review of the
details of previous SA-118 valve manipulations. T.he inspector could not
substantiate any TS 3.6.3.1 noncompliance associated with opening SA-118. The
inspector discussed repeated entries into TS LCOs with operations personnel and
concluded that personnel maintained an appropriate safety awareness to such
potential LCO abuse. This item is closed.
08.6 (Closed) Violation 50-272&311 /95-07-01: control room emergency air conditioning
system TS noncompliance. Operations management determined that the Nuclear
Shift Supervisor and Nuclear Control Operator failed to properly verify redundant
channel operability and failed to adequately maintain administrative control of
inoperable control room instrumentation. The licensee initiated actions to improve
procedural guidance, control room console log TS references, and TS tracking. The
inspector verified that operations revised console logs to provide appropriate TS
references and implemented a TS tracking log. The inspector determined that the
licensee took appropriate corrective actions. This violation is closed.
08. 7
(Closed) Deviation 50-272&311 /95-07-02: concurrent testing of redundant
emergency diesel generators (EOG) during normal plant operation. Operations made
procedure changes to prohibit operation of more than one EDG paralleled to the
electrical grid at any one time. This practice is consistent with Regulatory Guide
1.108 recommendations. The inspector verified that operations revised the
associated EDG procedures for both units to preclude concurrent testing of the
EDGs. This deviation is closed.
e.
A
.
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08.8 (Closed) Follow-Up Item 50-272&311 /94-19-01: definition of controlled leakage.
08.9
08.10
08.11
Salem TS defined controlled leakage as " ... seal water from the reactor coolant
pump seals." This definition differed from other Westinghouse plants TS that
defined controlled leakage as " ... seal water to the reactor coolant pump seals."
The Salem staff addressed this issue through a TS amendment that eliminated the
term controlled leakage and established a new TS that limits seal injection flow
rather than seal leakoff flow. The NRC approved the amendments October 30,
1995, and the inspectors confirmed Salem staff implemented the amendments in
station procedures. This item is closed.
(Closed) Unresolved Item 50-311/94-08~01 : steam generator depressurization
during simulator scenario. NRC examiners observed operators perform a simulator
scenario that involved steam generator depressurization. During the exercise, the
Emergency Operating Procedures (EOPs) directed the operators to depressurize an
intact steam generator by opening its associated atmospheric steam dump.
Although the crew performed this step, they first shut all main steam isolation
valves (MSIVs), an action not in the step. Subsequently, the examiners questioned
operator compliance with the EOP step. The noncompliance did not constitute a
violation, however, because the operators were operating the simulator, not the
plant. The examiners also questioned the technical adequacy of the EOP step
because an unmonitored release could occur if operators used atmospheric steam
dumps instead of available main condenser steam dumps .
Salem staff addressed the procedure compliance aspects of this item through
operator requalification training. In addition, NRC Restart Issue Ill. 7, Operator
Performance, also addresses procedure adherence as well as other generic aspects
of operator performance. The staff addressed EOP technical aspects through a
major revision to the EOPs (NRC Inspection Report 96-08 has details), including the
steps that give operators direction on steam generator depressurization and whether
to close the MSIVs. The inspectors determined the revisions were adequate and
that the operators completed training on the revised procedures. This item is
closed.
!Closed) Violation 50-272&311 /96-05-01: failure of Offsite Safety Review
(OSR) and Onsite Safety Review Group personnel to meet the number and
qualification requirements of Technical Specification 6.5.2.2. The inspector
determined the corrective actions described in PSE&G's response letter,
dated May 22, 1996, were acceptable. This item is closed.
(Closed) Violation 50-27 2&311/95-17-01 : failure of electricians to reinstall
tags. This item concerned a maintenance activity where electricians
removed a red-tagged 460 volt breaker from its cubicle, but failed to reinstall
the tags on the breaker racking device handle. In response, Salem staff
revised the tagging procedure to clarify tagging requirements, and to restrict
moving red blocking tags to Operations personnel only. The inspectors
determined Salem operators implemented the revised procedure. This item is
closed.
I
08.12
08.13
13
(Closed) Violation 50-272&311/96-08-01: failure of plant staff to update the
Tagging Request Inquiry System (TRIS). This item concerned two examples
where operators repositioned valves but did not update TRIS to reflect the
off-normal position. In response, Salem staff initiated a TRIS training course
for operators and limited TRIS system use to those qualified on the system.
The inspectors verified Salem staff implemented TRIS training and that only
operators qualified on TRIS can update the system. This item is closed.
Review of Licensee Event Reports related to Technical Specification
Implementation
a. Inspection Scope
The inspectors reviewed the following LERs to determine whether the licensee took,
or planned to take, appropriate corrective action to resolve the issues. The
inspectors also assessed adequacy of the licensee response to the events, and
determined if the licensee complied with regulatory requirements.
Unit 1
Number
LER 95-004
LER 96-003
LER 96-004
LER 96-005
Event Date .
May 15, 1995
February 20, 1996
March 7, 1996
March 25, 1996
Description
Unacceptable approach to
determine containment air
temperature for TS requirement
TS radiation monitor sampling non-
compliance
Containment isolation valve missed
TS surveillance
Failure to perform channel checks
for Tavg as required by TS
Note : LER 96-005, Supplements 1. through 5 to documented additional TS related
incidents identified by the Salem Technical Specification Surveillance Improvement
Program (TSSIP)
LER 96-006
April 21, 1996
LER 96-007
May 24, 1996
Missed independent verification of
release lineup on waste gas decay
tanks required by TS
Engineered Safety Feature
Actuation System (ESFAS) above
TS value
'
14
LER 96-008
June 13, 1996
Failure to meet TS requirement
while in Mode 5 for natural -
recirculation
LER 96-016
July 19, 1996
Missed surveillance for residual
heat removal pump dynamic head
prior to entering Mode 4
LER 96-017
July 25, 1996
Missed surveillance for plant vent
flow
LER 96-022
September 1 2, 1996
Containment radiation monitor
setpoints not in accordance with
technical specifications
LER 96-023
August 22, 1996
Surveillance for MSIVs not
performed prior to entry into Mode
3 as required by TS
LER 96-024
August 28, 1996
Surveillance requirement not met
for time response of motor driven
auxiliary feedwater pumps
Unit 2
LER 95-007
May 3, 1995
Missed diesel surveillance required
by TS
LER 95-008
December 15, 1995
Missed verification of containment
isolation as required by TS
LER 96-001
January 9, 1996
Failure to perform chemistry
sampling within TS required time
frame
LER 96-002
July 1, 1996
Waste gas decay tank oxygen
concentration exceeded TS limit
LER 96-003
May 15, 1996
Failure to perform surveillance for
fuel handling building ventilation
system auto start
LER 96-004
May 15, 1996
Missed TS action statement,
compensatory survey
LER 96-005
June 27, 1996
Missed TS surveillance of fuel
I
handling building ventilation
system charcoal
- 6
I
15
LER 96-007
July 16, 1996
LER 96-010
August 19, 1996
Missed TS surveillance of
containment penetration over-
current protection device
Missed TS surveillance for two
pressurizer welds
Inspectors selected these LERs for a collective review because each involved some
degree of failure to implement TS requirements. The inspector also reviewed the
Salem Technical Specifications Surveillance Improvement Program (TSSIP) scope,
and reviewed related TSSIP documents provided by PSE&G.
b. Observations and Findings
Salem Unit 2 LER 95-008 discussed the TSSIP. The licensee initiated the program
due to previous LERs that indicated a weakness in TS compliance. The program
consists of two stages of implementation. The licensee designed the first stage to
improve TS surveillance testing administrative controls, and to assure adequate
scheduling and tracking of surveillance requirements. The TSSIP first stage also
validates that implementing procedures contain adequate purpose statements and
adequately maintained and updated acceptance criteria. In the TSSIP second stage,
Salem staff plans to review applicable licensing and regulatory basis and design
documents to verify the technical adequacy of TS surveillances. The licensee
required completion of the first stage of TSSIP prior to restart. The plant managers
targeted completion of the second stage for late in 1997.
To date, TSSIP has identified many problems; some have resulted in LERs listed
above. The inspector reviewed thirty deficiency documents initiated as a result of
the TSSIP. The inspector found examples of the following problems:
Some TS surveillance requirements had no implementing procedure.
In some cases, TS surveillance procedures had inadequate purpose and/or
acceptance criteria.
Operating procedures did not adequately reference TS surveillances required
for the associated plant conditions.
Scheduling or tracking mechanisms did not assure TS surveillance
implementation.
In some instances, procedure revisions inappropriately deleted TS
surveillance requirements.
Some Technical Specification surveillance requirements existed for features
not installed in the plant.
Personnel errors resulting in missed TS surveillance.
The inspector reviewed the TSSIP charter and scoping document. The program
included plans to evaluate and enhance station processes, administrative
procedures, and controls that govern the TS program. Plant staff intends to review
the TS surveillance cross reference matrix to verify that implementing procedures
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16
exist for all TS requirements. The inspector found the program provided a
comprehensive and thorough approach to resolving the problems identified.
The inspector's review of the LERs did not identify new problems or problems that
would not be resolved by effective implementation of the TSSIP. The inspector
considered the licensee responses to the individual events adequate. Since the
licensee implemented acceptable corrective actions for each of the identified
problems the LERs identified above are closed.
The inspector determined that Unit 1 LERs95-004, 96-007, and 96-023; and Unit 2
LERs96-003 and 96-007, described examples of problems that the second stage of
the TSSIP is designed to identify and correct; that is, they are examples of design
information not adequately captured by TS implementing documents.
The
inspectors concluded that, prior to Salem Unit 2 restart, the NRC should assess the
acceptability of the basis for not completing the second phase of TSSIP in
conjunction with NRC restart inspection item 111.3, Procedure Adequacy and
Adherence.
c. Conclusions
The LERs and supplements identified in Section (a) above identify 26 TS related
problems exemplary of a programmatic failure. Taken collectively, they form the
basis for concern regarding the adequacy of Salem procedures and controls to
assure compliance with TS requirements. The PSE&G initiative to identify and
correct similar deficiencies via the Technical Specification Surveillance Improvement
Project (TSSIP) indicates a positive attitude toward corrective action.
Notwithstanding, the adequacy of procedures and controls, as identified in NRC
restart inspection item 111.3 remains to be resolved.
II. Maintenance
M 1
Conduct of Maintenance
M 1 . 1 General Comments
a.
Inspection Scope (62707)
The inspectors observed all or portions of the following work activities:
Unit 2 WO 960712062:
No. 22 fuel handling building exhaust
filter/replace charcoal filters
Unit 2 WO 960912219:
No. 22 component cooling water pump - correct
oiler size
Unit 2 WO 950407193:
service water bay station air filter replacement
The inspectors observed that the plant staff performed the maintenance effectively
within the requirements of the station maintenance program.
I
b.
17
Inspection Scope (61726)
The inspectors observed all or portions of the following surveillances:
- *
S2.0P-ST.DG-0003:
S2.0P-ST.DG-0001:
2C diesel generator surveillance test
2A diesel generator surveillance test
The inspectors observed that plant staff did the surveillance safely, effectively
proving operability of the associated system.
M1 .2 Testing of Containment Isolation Valves
Inspection Scope (71707)
The inspectors reviewed the surveillance procedure to determine compliance with
Technical Specification requirements. In addition, they observed the test to verify
that Salem staff performed it in accordance with the procedure, that plant
equipment operated as designed, and that plant staff appropriately documented the
test results.
Observations and Findings
Operators proceeded carefully and deliberately during the test. The Senior Nuclear
Shift Supervisor and the Salem Unit 2 Nuclear Shift Supervisor conducted a test
brief that included operators and technicians. Operators held up start of the test to
make several changes to the procedure for clarity.
The procedure had two other problems previously identified by plant staff. It
permitted Salem operators to perform the test in mode 5 (shutdown), mode 6
(refueling) and defueled. Technical Specification 4.6.3.2 requires that plant staff
perform the test in mode 5 or mode 6. Although Salem Unit 2 remained defueled at
the time of the test, Salem managers decided to do the test to determine if the
isolation valves functioned as designed after the extensive outage activities. Plant
staff also identified that the test procedure did not verify that valves 2CV68 and
2CV69 close on a phase A isolation signal. The staff changed the procedure to
note that it tested the phase A isolation valves with the exception of 2CV68 and
2CV69. In addition, PSE&G submitted a license change request to remove
Technical Specification Table 3.6.-1, Phase A Containment Isolation Valves, out of
the Technical Specifications and into the Updated Final Safety Analysis Report. The
NRC had not approved the LCR at the time of the test, and approval of the LCR will
not resolve the conflict between the TS and the plant design. Inspectors observed
that the operators and technicians carefully conducted the test and precisely
documented the minor equipment discrepancies.
In response to identifying that 2CV68 and 2CV69 did not receive a phase "A"
isolation, the plant staff did not thoroughly insure resolution of the discrepancy
between plant design and NRC requirements. Until questioned by the inspector, the
1
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plant staff did not insure that they would demonstrate the operability of valves
2CV68 and 2CV69 as required by Technical Specification 3.6.3.
Conclusions
Operators and technicians accomplished a carefully controlled test of the Salem Unit
2 phase "A" containment isolation valves. They precisely recorded the minor
discrepancies observed during the test. The plant staff did not thoroughly insure
resolution of disagreement between plant design and Technical Specification 3.6.3
requirements for valves 2CV68 and 2CV69.
M2
Maintenance and Material Condition of Facilities and Equipment
M2.1 (Closed) LER 50-311 /96-008: inoperable battery chargers due to manufacturing
discrepancies. The inspectors did not identify any failures to meet regulatory
requirements. The inspector verified, by a documentation review, that the
deficiencies have been corrected for Unit 2 and the corrective action implementation
documents are being tracked for Unit 1 . The licensee completed reporting required
by 1 OCFR21. This LER is closed.
M2.2 (Closed) LER 50-272/96-009: potential common mode failure for 4KV Magna-Blast
breakers. This event was the subject of an NRC inspection in June 1996. That
inspection was documented in Inspection Report 50-272&311/96-07. No new
issues were revealed by the LER. This LER is closed.
MS
M8.1
Miscellaneous Maintenance Issues
(Closed) LER 50-272/95-013: On July 3, 1995, Instrumentation and Controls (l&Cl
technicians performed TS 4.3.3.3.1 surveillance requirements approximately 6.5
hours late. Technicians satisfactorily completed TS 4.3.3.3.1 and demonstrated
continued operability of the instruments. The licensee attributed the occurrence to
personnel error. The l&C TS surveillance coordinator did not understand
surveillance tracking codes and the Station Planning and Scheduling Group failed to
adequately review the TS surveillance schedules. The licensee human-factored the
surveillance tracking codes, identified clear responsibilities for TS tracking, and
established. a station Planning and Scheduling Group TS coordinator.
The inspector reviewed the TS tracking codes and discussed TS surveillance
tracking with the surveillance coordinator. The licensee took appropriate actions to
prevent recurrence. Failure to perform the required surveillance within the
appropriate interval is a violation of TS 4.3.3.3.1. 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.
M8.2 (Closed) LER 50-272/95-018: improper range gauges used for inservice testing. In
July 1995, QA inspectors identified that inservice testing (IST) technicians did not
use properly ranged gauges for pump testing. The licensee identified this deficiency
I
19
as a violation of TS 4.0.5 in that IST technicians did not test certain components in
accordance with ASME Section XI requirements.
The licensee attributed the root cause to less than adequate IST program
maintenance, implementation processes, and associated controls. On July 31,
1995, QA issued a stop work order for all IST surveillance testing. On December
12, 1995, QA lifted the stop work order, specifying interim work controls until IST
made needed procedure revisions to IST controlling documents. The licensee
conducted an assessment of the entire IST program and implementing procedures
and identified numerous deficiencies, however, the deficiencies did not constitute
reportable conditions. The licensee planned to revise the IST manual prior to
restart.
The inspector reviewed the licensee's IST program assessment. The licensee
initiated appropriate corrective actions. The licensee-identified violation of TS 4.0.5
requirements is being treated as a non-cited violation, consistent with Section
Vll.B.1 of the NRC Enforcement Policy.
M8.3 (Closed) Unresolved Item 50-311194-14-01: Flange Leak Repair Root Cause
Analysis
In July, 1994, the licensee attempted to perform an inservice temporary leak repair
for Unit 2 on a small steam leak from a flange joint on a one inch pipe connected to
No. 22 reactor coolant pump seal. During the repair, the leak quickly increased to
14 gallons per minute. The leak was unisolable, so the workers terminated the
repair. Personnel exited the containment, and the operators proceeded with a
reactor coolant system (RCS) cooldown to cold shutdown as required by Technical
Specification 3.4.7.2. Inspectors *concluded that operators and management
responded appropriately to the event, and subsequently implemented an acceptable
flange repair. Inspectors considered the problem unresolved pending NRC review of
the licensee's root cause investigation.
The inspector reviewed the root cause analysis and considered it satisfactory. The
analysis conclusion stated that loss of the joint preload over the 1 5 year service life
combined with the increased internal pressure on the flange face from the leak
repair sealant injection caused the sudden increase in leakage. The root cause
analysis also specified corrective action that included procedure changes and
contingency plans. The inspector reviewed procedure SC.MD-GP.ZZ-0188(Q),
lnservice Temporary Leak Repair, Revision 0, dated April 28, 1996 and found that it
satisfactorily addressed actions to prevent potential problems similar to those
encountered during the failed leak repair. This item is closed.
E1
a.
b.
20
Ill. Engineering
Conduct of Engineering
Inspection Scope (50001)
Inspectors reviewed the steam generator replacement project (SGRP) to obtain an
overview of current and planned work, related procedures, documentation, quality
inputs and progress of the Salem Unit 1 SGRP. This inspection included
.observation of the replacement steam generator (RSG) staging area, walking the
haul routes for both the RSGs and old steam generators (OSG) with the responsible
engineers and observation of conditions inside the containment building.~ Inspection
on October 29, 1996, focused on the analysis, planning and controls on piping
stress related to the SGRP process. It included ASME Code related inspection of
the project and the oversight (self-assessment) process.
Observations and Findings
By October 29, 1996, the four RSGs had been prepared for shipment at the
Seabrook site, transported by barge to the Salem plant, offloaded and moved to the
RSG staging area. The primary and secondary sides of each steam generator were
maintained under a nitrogen inert gas purge until the start of nozzle machining to
minimize material degradation. Work in the RSG staging area and preparations in
the containment building were observed to be proceeding in an orderly manner with
appropriate supervision and work control packages. A walkdown of the OSG and
RSG haul paths with the responsible reviewing engineers indicated that
consideration had been given to potential haul route problems and related factors.
The inspector reviewed the licensee stress analysis considerations given the steam
generator and its related piping system to ascertain conformance with ASME Code
requirements. The review resulted in the following observations:
The "spring back" of the piping to the OSG was small (0.022-0.038") when
the reactor coolant piping (RCS) was cut loose from the first steam
generator. This movement, when coupled with the relatively low level of
jacking force present during cutting, indicates that significant piping loads
have not been exerted on OSGs during operation.
The inspector observed the computer-based locating equipment used in
matching the steam generator nozzles with corresponding pipe system
attachment such that stresses due to welding of the pipe to the nozzles
would not require excessive cold springing of the pipe. This locating system
is state-of-the-art and has been used successfully in other critical alignment
applications. Alignment of multi-nozzle components with this system allows
precision adjustments to be made that satisfy all locations simultaneously.
Consideration has been given to the weld shrinkage in computing the
dimensions and alignment of the matching parts.
21
The stresses resulting from installation of the RSGs are limited to a small
fraction of the ASME Code operational levels. Conservative analyses have
been performed by the licensee to show that the effect of the loadings on
the RSG shell is small.
Independent design reviews scheduled include the feedwater and RCS
thermal hydraulic modifications, haul path, and an overall 10 CFR 50.59
project review.
c.
Conclusions
E2
The inspections found a generally high level of project performance in the areas
inspected and identified no safety significant project deficiencies.
Engineering Support of Facilities and Equipment
E2.1
NRC Restart Issue 11.5 - Moisture in the Emergency Diesel Generator Air Start
System (Open Unit 1 , Closed Unit 2)
The EOG Air Start System has a history of repetitive maintenance problems that
PSE&G has attributed to rust entrained in the system. This includes problems such
as leaking drain valves and check valves. In addition, the air receivers had a low air
pressure alarm setting of 90 psig, yet past testing indicated that a least 140 psig is
required for successful start testing. The NRC documented these problems in
Inspection Report 50-272,311/94-19, dated October 12, 1994. The licensee has
initiated a significant redesign of this system to reduce or eliminate these and other
operating problems, and to replace obsolete components and parts. PSE&G
submitted this change to the NRC pursuant to 1 OCFR50.90, and the NRC accepted
this alternate design in a letter dated March 21, 1996.
a. Inspection Scope
The inspectors reviewed the closure package that had been reviewed and accepted
by the Salem Management Review Committee. The package identified six Design
Change Packages (DCPs) for implementation on Salem Unit 1 and 2. The inspectors
reviewed the DCPs to determine the scope of the design and to identify related
procedural changes necessitated by the design changes. The inspectors reviewed
the work orders and toured the EOG rooms to determine the status of
implementation of the DCPs. The inspectors also reviewed the test results for
testing performed on the Salem Unit 2 EDGs following implementation of the design
changes. Finally, the inspectors sampled related procedures to determine if the
required changes had been incorporated.
b. Observations and Findings
The inspectors considered the scope of the design change extensive. In addition to
resolving the problems identified by the NRC, PSE&G addressed other maintenance
and operational problems that they had experienced with the Air Start and Turbo
22
Boost systems. For example, the redesign added replacement compressor
start/stop pressure switches to improve setpoint stability and eliminate unwanted
relief valve lifting. Also, they replaced obsolete model EDG air start motors with a
newer model used at Diablo Canyon. PSE&G considers the newer model an
improved design.
The scope of the six DCPs includes:
1.
Installs improved Starting Air and Turbo Boost Compressor
pressure control switches.
2.
Installs flexible hose to isolate the switches from compressor
vibration.
1 .
Adds an air receiver low air pressure alarm with a 182 psig
setpoint.
1 EC-3401 and 2EC3349
1 .
Replaces all air receiver drain valves with stainless steel ball
valves.
2.
Upgrades piping and valves between the Air Start and Turbo
Boost compressor and receiver tanks to stainless steel.
Eliminates the air dryers and provides moisture separators.
3.
Increases air receiver relief valve setpoint and replaces relief
valves.
4.
Upgrades piping and components between air receiver and air
start motors to corrosion resistant materials. Adds flexible
connections in the system piping at the EDGs to isolate the
system from engine vibration.
5.
Upgrades air start motors and pressure regulators to a newer
design.
6.
Upgrades inlet check valves to a soft seat design for improved
leak tightness. A pulsation damper was added to the Turbo
Boost compressor discharge to prevent check valve chatter
(The Air Start compressor is already equipped with this
device).
The engineers identified procedure changes required as a result of the DCPs. The
inspectors sampled three procedures identified in 2EC-3349 and found that plant
staff had incorporated the required changes. For 2EC3456, the inspectors verified
that plant staff revised the pressure switch calibration data sheets to reflect new
setpoints. The implementing work orders were also included in the DCPs. The work
order documentation indicated that plant staff completed the work for Unit 2 and
had not completed the work for Unit 1. The inspectors performed a field walkdown
of the Air Start and Turbo Boost System and confirmed that the licensee had
completed modification installation for Unit 2. Inspectors also confirmed that a
significant amount of work still remained to complete the Unit 1 modifications.
23
The inspectors determined that DCP-2EC3349, Package #1, contained test
procedure STP-3349-001, Special Test Procedure, designed to verify that all
affected portions of the 2A Diesel Generator Air Start and Turbo Boost Air systems
function properly following the modifications. The inspectors verified that Package
- 2 and #3 contained similar procedures for the 2B and 2C systems. The test
procedures included component functional tests for valves, switches and
instruments, as well as integrated start tests to demonstrate the ability of the EDG
to start and come up to speed within 10 seconds. The inspectors reviewed the
completed test results for the 2A, 2B, and 2C systems and found that the
acceptance criteria had been satisfied.
From discussions with the system manager, the inspectors learned that the work
reduced system air leakage, reduced air compressor run time, and that blowing
down the air receivers yielded very little water.
c. Conclusions
E3
E3.1
E8.1
The inspectors considered the corrective action taken to resolve the identified
concerns with the EDG Air Start System adequate. In addition, PSE&G took steps
to correct other problems in order to reduce maintenance and to improve operability
and reliability of the EDG Air Start and Turbo Boost System. The inspectors
concluded that PSE&G produced a thorough and technically sound resolution to this
restart issue. This NRC restart issue is closed for Salem Unit 2. However, the issue
will remain open for Unit 1 because a substantial amount of modification installation
work and post modification testing has yet to be completed.
Engineering Procedures and Documentation
(Closed) LER 50-311195-003 : failure to perform type C local leak rate testing
following piping modification to 21. containment spray piping system. This failure
occurred in March, 1989. In April, 1990, Salem staff performed routine type C
leak rate testing on the new piping section. The result was satisfactory.
Salem management determined that a design change preparer did not properly rout
a design change interface sheet to the In-Service Inspection (ISi) group.
Consequently, they did not identify the test requirement. Since the event, Salem
enhanced the procedures to clearly identify specialty reviews such as ISi
requirements. Additionally, plant engineering management stressed the importance
of design change package quality and attention to detail to engineering personnel.
This licensee identified and corrected violation is being treated as a Non-Cited
Violation consistent with Section Vll.B.1 of the Enforcement Policy.
Miscellaneous Engineering Issues
Reliability of Station Air Compressors, NRC Restart Item 11.2 (Open)
On October 7, 1996, no. 2 SAC tripped on high vibration. The no. 1 ECAC and no.
2 ECAC started automatically as designed. The no. 2 ECAC tripped on low lube oil
,'
) w
E8.2
24
pressure 22 seconds after the auto start. The no. 1 and no. 2 SACs started
automatically. Control air pressure fluctuated slightly (4 psig drop) and quickly
stabilized at normal operating pressure. Operators initiated action requests to
resolve 'the deficient conditions (961007058 for no. 2 ECAC and 961007060 for
no. 2 SAC). Engineering planned corrective measures for both previously
documented deficiencies. They had not yet implemented the corrective actions.
The inspector noted that Salem had not yet established sustained reliable station air
and control air operating performance.
(Closed) Unresolved Item 50-272 and 311 /93-15-03: Salem Unit 2 fuel rod defects.
This item was unresolved pending licensee's evaluation, assessment and
reportability review. Reactor engineering determined that flow induced vibration
caused the fuel rod failures. The vibration only manifested itself on core peripheral
locations due to the clearances required. Fuel manufactured after May 1993 is not
susceptible to flow induced vibration due to Westinghouse V5H fuel redesign (mid-
grid rotation). Engineering determined that a 10 CFR 21 report was not required
because the leaking fuel rods and coolant activity levels were adequately addressed
by Technical Specifications and did not present a substantial safety hazard. Since
1993, the licensee has not experienced additional fuel rod defects due to mid-grid
fretting. The inspector discussed the failures with reactor engineers and observed
failed fuel inspections for Salem Unit 1 and 2. The inspector considered the Salem
response to the fuel rod defects acceptable. This item closed .
E8.3
(Closed) LER 50-272/95-014: safety injection throttle valve inoperability. In
November 1995, engineering determined that erosion of the intermediate head
safety injection (IHSI) throttle valves, in service after a large break loss of coolant
accident (LOCA), could lead to loss of IHSI to the cold legs and hot legs and
potentially impact adequate core cooling.
In 1985 and 1986, Salem maintenance replaced a total of eight high head safety
injection (HHSI) throttle valves due to failures .. In October 1985, engineering
determined that the IHSI valves were not susceptible to accelerated erosion because
they believed that none of the valves were adjusted to a position less than 50%
open. In August 1995, engineering identified that all of the cold leg IHSI throttle
valves at Salem Units 1 and 2 were open less than 30%, and three of the four hot
leg IHSI valves were open less than 50%. At the time of the 1985 HHSI throttle
valve replacements, most of the IHSI throttle valves were less than 50% open. In
1985, engineering failed to take appropriate corrective action to preclude IHSI
throttle valve degradation.
In 1996, maintenance installed orifices in the hot and cold legs to eliminate the
need to throttle the IHSI less than 50% (DCP 2-EC-3461 ). Engineering evaluated
throttling valves in safety-related systems.
In addition, engineering conducted
lessons-learned training and reviewed related safety injection throttle valve
operating experience feedback (OEF).
E8.4
25
The inspector concluded that engineering, in 1985, relied on unproven assumptions
and failed to take appropriate corrective action to preclude IHSI throttle valve
degradation. Since the NRG has taken significant enforcement action for Salem's
failure to identify and correct conditions adverse to quality, and since PSE&G
voluntarily maintained both Salem units shut down to address equipment and
enforcement deficiencies, the NRG will not take additional enforcement action in
these cases. The inspector discussed throttle valve degradation and corrective
actions with the safety injection system manager. The inspector determined that
engineering, in 1996, thoroughly evaluated throttle valve concerns and took
appropriate actions to prevent recurrence.
(Closed) LER 50-272/95-017:failure of control room emergency air conditioning
system to meet GDC 19 criteria.
On July 18, 1995, engineering determined that
Salem Unit 1 would have exceeded the GDC 19 requirements for control room
habitability following a LOCA.
The UFSAR assumed value for control room air in-leakage, used to calculate thyroid
dose, was much less than expected in-leakage. In 1988, engineering reconstituted
the emergency air conditioning design basis, however, they did not provide
supporting information for the assumed air in-leakage. In 1994, engineering
calculated the air in-leakage, using Standard Review Plan guidelines, and determined
that the in-leakage value was much higher than originally assumed in the UFSAR.
Engineering did not determine the effect on thyroid dose from the calculated higher
air in-leakage.
Engineering identified an alternative operating mode for the emergency air
conditioning system to ensure compliance with GDC 19 requirements. Engineering
planned to implement those changes prior to restart. Quality Assurance made
changes to NC.NA-AP.ZZ-0000, Action Request Process, to ensure senior reactor
operator approval of action requests and senior nuclear shift supervisor notification
of potential operability concerns.
The inspector reviewed NC.NA-AP.ZZ-0000 and engineering's 10 CFR 50.59
evaluation and determined that engineering took appropriate corrective action
following their July 1995 identification of the issue. Engineering's failure to take
appropriate actions to resolve the issue in 1988 and 1994 is a violation of 10 CFR
50 Appendix B Criterion XVI, Corrective Action, requirements. Since the NRG has
taken significant enforcement action for Salem's failure to identify and correct
conditions adverse to quality, and since PSE&G voluntarily maintained both Salem
units shut down to address equipment and enforcement deficiencies, the NRG will
not take additional enforcement action in these cases. This LER is closed.
E8.5
(Open) Inspector Follow-up Item 50-272&311 /95-21-02: service water reliability
issues. This item remained open pending NRG review of (1) licensee's siltation
control program, (2) susceptibility of SW traveling screens to debris clogging, (3)
licensee's interpretation of UFSAR (section 9.2.1.2) statement "The SWS is
r
1
designed for class I (seismic) conditions except for the turbine area service water
"
piping outside of the service water intake structure" relative to seismic classification
E8.6
E8.7
' *
26
of SW components in the intake structure. This item remains open pending NRC
review of Restart Plan Ill 19.2, Service Water Reliability.
(Open) Inspector Follow-up Item 50-311 /94-24-02: auxiliary feedwater (AFW) pump
surveillance adequacy. This item remained open pending inspector review of the
licensee's evaluation of the AFW pump surveillance activity. This item remains
open pending NRC review of Restart Plan II 42, AFW Performance and Reliability.
(Open) Inspector Follow-up Item 50-272&311 /96-07-03: breaker testing and
analysis. Inspection Reports 50-272/96-07, 50-311 /96-07 discussed "failure to
latch closed" the problems experienced with General Electric (GE) 4.16kV Magne-
Blast circuit breakers. To alert other licensees of this problem, the NRC issued
Information Notice 96-43, "Failure of General Electric Magne Blast Circuit Breaker,"
on August 2, 1996. To correct this problem at Salem, the licensee adjusted (1) the
opening spring tension, (2) the length of the opening spring, and (3) the primary
contact wipe. GE's proposed action to correct the same problem was a
combination of ( 1) replacing the current second prop spring with a stiffer one, (2)
installing a prop stop block to restrict the prop movement on the left hand side, and
(3) adjusting the wipe on the main contacts.
On September 23-24, 1996, NRC inspectors witnessed GE Philadelphia Operations
(GE PO), where the circuit breakers were manufactured, conduct life tests on two
4.16kV GE circuit breakers that had been in operation at Salem and failed to latch
closed earlier this year. The purpose was to (1) determine if GE PO's proposed
modification to correct "the failure to latch closed" problem will enable the breaker
to close reliably, even if the breaker is adjusted to worst-case (but still acceptable)
tolerances, and (2) determine if adjustments made by the licensee are sufficient to
provide reliable breaker operation without implementing GE's hardware modification.
The details of the breakers are as follows:
Breaker #1: Serial No. 0224A6259-007. This breaker had been in service at Unit 2
first to operate a reactor coolant pump motor and then as a Vital Bus 1 A 41 60/480-
230V transformer breaker, when it failed to latch closed in March 1996. Salem
used this breaker at its training center to demonstrate the "failure to latch closed"
syndrome before it was sent to GE PO for testing. After adjusting the primary
contact wipe to 1 /4" and the opening spring tension to intentionally make the
breaker fail to latch closed, GE PO installed their proposed modification.
This
breaker was installed in a skeleton cubicle during tests. GE PO was operating the
breaker at two cycles per minute.
Breaker #2. Serial No. 0224 A 6257-003. On January 5, 1996, while this breaker
was being used as the 15 service water pump, it failed to latch closed on demand.
Salem was unable to duplicate this failure (non-repeatable) when this breaker was
initially tested. However the breaker did fail after subsequent testing. Salem sent
this breaker to GE PO where the ML-13 operating mechanism was completely
rebuilt using new parts. The breaker was aged by operating it for 4,000 cycles to
E8.8
27
represent a typical breaker installed at Salem. After aging, GE PO incorporated the
Salem modification. GE PO was operating the breaker at two cycles per minute.
On October 4, 1996, after GE PO completed the aging operations, the NRC
inspectors witnessed the continuation of the life cycle testing of the two Magne
Blast circuit breakers. GE PO performed routine maintenance on the two breakers
every 1,000 cycles. GE PO tested the two breakers and captured the motion of the
prop and the prop pin to demonstrate that the breakers did not fail to latch close
after 4000 cycles. As of October 22, 1996, the two breakers operated more than
5,000 cycles without a failure demonstrating that both the modifications were
reliable.
The limiting conditions of acceptability of the reliable operation of the circuit breaker
are:
The opening and closing velocities of the breaker should be more than 15 and 14
feet per second respectively.
The high speed video should indicate that ( 1) the prop pin bounce does not occur in
the wrong place, (2) the prop bounce should not be excessive, (3) the prop kick
back should be limited, and (4) the prop stop pin is fully forward.
The tests demonstrated that the separate corrective actions implemented by Salem
and GE PO eliminated the failure to latch closed problem and enabled the breakers
to operate reliably. This item will remain open until Salem has had sufficient
operating experience to conclude that breaker performance problems do not recur.
GE PO issued a service advice letter (SAL) 351 .1 A on October 18, 1996 on this
subject. GE PO estimates that it will take a few weeks before it could translate the
corrective actions into design drawings and manufacture the items for installation.
(Closed) LER 50-272/96-001 : insufficient thermal overload relay heater margin. In
January 1996, the licensee issued a calculation to perform sizing determinations for
selected rotating equipment thermal overload heaters (TOLs). The results of the
calculation showed that 36 electrical loads had undersized TOLs. The original sizing
of TOLs was performed by selecting the heater from the vendor catalog using
vendor recommended selection criteria. That method did not fully consider the
possibility of degraded voltage conditions or high ambient temperatures within
cabinets. The inspector verified that PSE&G engineering has issued a Technical
Standard providing guidance for design and sizing of motor starters, circuit
breakers, and thermal overload relay heaters. Additionally, the inspector verified
that engineering issued calculations for the sizing of all TOLs for safety related
rotating equipment loads and for all safety related motor operated valve loads.
The
inspector also confirmed that the incomplete modifications are being tracked as
"required for restart" for Salem Unit 1 and 2.
Since the NRC has taken significant enforcement action for Salem's failure to
identify and correct conditions adverse to quality, and since PSE&G voluntarily
maintained both Salem units shut down to address equipment and enforcement
E8.9
28
defici.encies, the NRC will not take additional enforcement action for the previous
failure to adequately size thermal overload heaters.
(Closed) LER 50-272/96-010 : inadequate pressurizer relief tank (PRT) supports.
During an engineering review, it was determined that the support design provided
by Westinghouse for the PRT did not consider hydrodynamic loads that would be
created if all three safety relief valves lift simultaneously. The locked reactor
coolant pump rotor and loss of turbine load accident analysis take credit for the
safety relief valves operating at the same time.
The corrective action for this LER was to revise the design and to install the
modification prior to entering mode 3. Also, since the design was provided by a
supplier, the shortcoming was reported in accordance with 1 OCFR21 .
The inspector reviewed documentation that verified the Salem Unit 2 modification is
installed and the Unit 1 modification is scheduled for installation prior to mode 3.
This LER is closed.
IV. Plant Support
R2
Status of RP&C Facilities and Equipment
R2.1
Radioactive Material Found Outside of the Radiological Controlled Area !RCA)
a.
Inspection Scope (71707)
Inspectors verified radiation protection (RP) controls .and corrective measures
following a RP technician's discovery of contaminated material outside of the RCA.
b.
Observations and Findings
At 1 :00 a.m. on October 16, a Salem radiation protection technician, performing a
normal quarterly survey of plant areas outside the RCA, discovered six discrete
areas in one location of fairly high contamination. Technicians had not discovered
contamination on previous quarterly surveys, however, recent construction activities
necessitated a change in survey location. Technicians identified contamination
down to about 4 inches deep at direct frisk levels of 5,000 to 80,000 dpmiprobe
area (32,000 - 500,000 dpm/100 cm 2) with one area reading 2 mrem/hr on contact.
The material was not readily dispersible and required mechanical means for removal.
No personnel contaminations resulted.
The SNSS determined that the discovered contamination was not reportable in
accordance with Salem Emergency Classification Guide (ECG) Section 7.
Technicians surveyed the surrounding area and found no contamination. By 10:00
a.m. on October 16, technicians removed the radioactive material from the area,
performed a 100 percent direct frisk, and released the area. Radiation Protection
management assessment indicated that the material had been present in this
29
location for some time based on the stable and nondispersible nature of the
material. Radiation Protection management initiated action to perform more
comprehensive site surveys to provide complete site coverage on a biennial
periodicity.
The inspector verified the radioactive material area posting and SNSS ECG
classification and reviewed contamination surveys. Radiation Protection personnel
acted promptly to post the area, remove the contamination, investigate possible
sources, and enhance contamination surveys. In addition, they planned to modify
the survey process to insure that they survey all areas of the protected area outside
the radiologically controlled area in each two year period.
c.
Conclusions
R3
R3.1
a .
b.
Radiation Protection took prompt and appropriate action in response to
contamination found outside the radiologically controlled area.
RP&C Procedures and Documentation
DOT Exemption Request and Steam Generator Characterization Documentation
Scope(86750)
On April 1, 1996, a new revision to Title 49 Code of Federal Regulations became
effective. A new radioactive shipment classification, Surface Contaminated Objects
(SCO) was established by the new regulations. 49 CFR 173.403 defines SCO and
stipulates the limits for SCO I and SCO II. The SCO II definition provides for
contamination concentration limits for both accessible and .inaccessible areas. As
the steam generators will be seal welded shut, only the inaccessible area SCO II
limit applies. The limit is 20 microcuries/cm 2 total contamination (fixed and non-
fixed) beta/gamma and 2 microcuries/cm 2 alpha averaged over 300 cm
2
The inspector reviewed documentation submitted to the DOT which requested
approval for shipment of 4 steam generators under the SCO II classification. This
report documents the NRC review of the licensee's characterization and a
determination of applicability of the SCO II classification and related requirements.
Observations and Findings
On August 5, 1996, the licensee submitted to the DOT an exemption request from
the packaging requirements of 49 CFR 173.427(b)(1) for the shipment of four
steam generators as SCO 11 from Salem Generating Station Unit 1 . This refers to
the requirement that surface contaminated objects are to be packaged in industrial
packaging (for greater than A 2 quantities). The exemption application, stated that
the steam generators themselves offered equivalent or better packaging than that
required for an IP-2 package and requested relief from that requirement. Also
contained in the August 5th exemption request was the licensee's characterization
basis for demonstrating compliance with the limits of SCO II.
30
The information provided indicated that a swipe sample was taken for complete
radiochemical analysis of radionuclide content and a series of contact radiation
surveys were taken along the external surfaces of each steam generator. This data
was used to determine an average surface area concentration inside of each steam
generator.
The inspector indicated that the licensee utilized a simplified computer model of the
steam generator. The steam generator geometry was simplified to that of a cylinder
containing a homogenous source mixture of air and' iron molecules. The total curie
values were calculated from the maximum external contact dose rate determined
from each steam generator. Total activities of 143, 129, 122, and 126 curies were
calculated for the four steam generators. The inspector calculated the total A 2
quantities for each steam generator and determined that they ranged from 7.45 to
8.8 times A 2 quantities. The DOT regulations require an IP-2 package for SCOs
with quantities greater than 1 A 2 quantity not to exceed 100 times the A 2 quantity
limit. Based on knowledge of the total primary side internal surface area of a
Westinghouse Model 51 steam generator, the licensee derived an average
contamination concentration for each steam generator. The steam generators were
determined by the licensee to represent an average surface contamination level of
approximately 3 microcuries/cm 2 beta/gamma and 2.24E-4 microcuries/cm 2 alpha.
The inspector questioned the evaluations of uncertainty in the results and the
availability of benchmarking the results by comparison to steam generator tube
- samples in order to validate the characterization.
Revision 1 of the Salem Unit 1 Steam Generator Characterization Report was issued
on August 20, 1996. This report stated that "It is impossible to quantify the
percent error associated with an analysis of this type without additional empirical
data." The report continued providing a benchmark evaluation using dose rate data
obtained from individual tube samples from Salem's steam generators and compared
these dose rates with a computer-derived estimate of dose rates based on the
previously determined surface contamination level of 3 microcuries/cm 2 * This
comparison indicated that the actual dose rates were between 2 and 27 % higher
than predicted.
The inspector questioned the variability of contamination inside the steam
generators. Thus far, the licensee had only made an average surface contamination
determination, however, the regulations specify that the sea limits apply to each
300 cm
2
- The inspector referred the licensee to EPRI Report NP-3107, May 1983,
entitled, "Gamma-Ray Exposure Rate Distribution in a Steam Generator". This
report indicated that contamination is not uniformly distributed inside of a steam
generator, but that the contamination on the channel head bowl and tube sheet
regions was approximately 14 times greater than the contamination found in the
steam generator tubes. The inspector indicated that if the licensee's average
contamination level was 3 microcuries/cm 2, then this study suggests that the
channel head bowl and tube sheets may be expected to exceed the SCO II limit of
20 microcuries/cm 2 *
31
The licensee issued revision 2 of the Salem Unit 1 Steam Generator Characterization
Report on September 20, 1996 to address the variability of contamination inside
Salem's steam generators. Based on a review of the EPRI report, the licensee
revised their characterization approach into a two-step process. The original dose-
to-curie calculation approach was used to determine the activity in the tube bundle
areas and a separate set of calculations (following the EPRI methodology) was
utilized to determine the contamination levels outside the tube bundle areas. The
licensee's results indicated that the tube bundle contamination level was 3
microcuries/cm 2 and the channel head bowl area was 15 microcuries/cm
2
- Both
sets of calculations utilized the radionuclide ratios determined from a swipe sample.
Due to the close proximity to the SCO II limit, the inspector reviewed the use of the
swipe sample for radionuclide characterization. The inspector noted that, due to the
dominance of the radionuclides of Co-58 and Co-60 found in the swipe sample, and
the relatively short half-life of Co-58 (70.8 days versus 5. 7 years for Co-60), the
variability of the cobalt 58 constituent could greatly affect the contamination
concentration found in the steam generators, particularly since Salem Unit 1 had
been shut down for 20 months. The inspector noted that, the licensee back-
decayed the swipe data to the April 18, 1995 shutdown date and used this
information as the basis for all other characterization results. At shutdown, the
Co-58/Co-60 ratio was 3.15; at 20 months, 0.01.
The inspector questioned whether a swipe sample would accurately represent the
total contamination radionuclide ratios. Reason suggests that deeper into th_e
corrosion film may represent older corrosion deposits and much less Co-58.
Therefore, a higher percentage of longer lived radionuclides may be expected in the
total contamination layer corresponding to a higher surface contamination level at
the time of shipment.
The licensee indicated that a metal hand-held implement was used to abrade the
surface and then a swipe of this material was taken. Therefore, the swipe sample
was intended to represent the total contamination present. The inspector
questioned whether the previously utilized steam generator tube samples could be
utilized for direct gamma analysis of the total contamination present. On
October 7, 1996 the licensee provided the inspector with this information and
additional swipe samples. Comparisons of Co-58/Co-60 ratios of these samples are
provided below.
Sample Description
Tube sheet swipe
Channel head bowl swipe
Divider plate swipe
Abraded swipe used for S/G characterization
Shot peen swipe (abrasive blasting)
Tube sample direct gamma scan
Co-58/C0-60
3.87
3.38
3.36
3.15
2.79
2.41
c.
32
In utilizing the direct gamma scan data for the gamma contributors and the
radiochemical results of the abraded sample for the difficult-to-measure
radionuclides, the inspector (utilizing the same EPRI methodology as the licensee)
calculated that the channel head bowl and tube sheet area contamination levels
were approximately 30 microcuries/cm 2 over an area of 2.1 E5 cm
2 for each steam
generator. Therefore, the channel head bowl and tube sheet portions of the steam
generators are apparently above the limits for SCO 11. These findings were
discussed with the licensee (J. Burford, H. Cruickshank), NMSS (E. Easton, J. Cook,
R. Lewis), and DOT (R. Boyle) on October 8, 1996 via telephone conference. As a
result of the discussion, the licensee submitted a letter dated October 10, 1996 to
DOT requesting relief from the SCO 11 limits in the channel head sections for all four
steam generators as these areas comprise less than 1 % of the surface
contaminated area of each steam generator. On November 6, 1996 the DOT issued
an exemption approval (DOT-E-11745), which allows the licensee to transport the
four Salem steam generators as surface contaminated objects with exemptions to
the industrial packaging requirement and contamination level limits in the channel
head sections.
Conclusions
The inspector determined that the Salem Unit 1 steam generators met most of the
requirements for an SCO class II shipment. The contamination level on the channel
head and tube sheet areas appeared to be above the DOT limits and the steam
generators were not packaged into IP-2 containers. The licensee applied for
exemption to these requirements, which were subsequently approved by the DOT.
P1
Conduct of Emergency Preparedness (EP) Activities
P1 .1
Effectiveness of Licensee Controls
a.
b.
Inspection Scope (82701 l
The inspectors reviewed the licensee's tracking systems used for tracking EP related
action items. Also, the EP self-assessment program was reviewed to determine the
effectiveness of licensee controls.
Observations and Findings
Procedure NC.NA-AP-ZZ-000(0), PSE&G Nuclear Business Unit, Action Request (AR)
Process, describes the licensee's method for reporting conditions requiring corrective
action, program enhancement or interdepartmental support. A newly developed
automated system called the Performance Improvement Review System (PIRS) tracks
ARs. The system is maintained by the audit department staff who screen, classify and
distribute the ARs. ARs are assigned significance levels (one to four, in descending
priority) depending on circumstances, conditions or at management discretion. All ARs
are given significant management attention and the highest significance levels (one and
two) require a root cause analysis .
-1
c .
33
The inspectors requested a demonstration of the PIRS but the licensee was not able to
locate any recently closed ARs. The licensee stated that PIRS is not user-friendly and
has the potential for losing data if a user incorrectly inputs information. Due to these
problems, the EP staff utilizes three other internal office systems for tracking repetitive
EP activities required by E-Plan commitments, procedure/E-Plan changes, drill/exercise
critiques, training classes reviews and EP administrative review items. The inspectors
discussed the problems noted during the demonstration of the PIRS with members of the
audit department. They stated that they were aware of the computer program problems
and are currently modifying the program for easier and more efficient use. Once the
problems are resolved, it is the licensee's inte.nt that the PIRS will become the sole
tracking system for Salem and Hope Creek.
The inspectors reviewed several ARs and found th~m to be very detailed, thorough and
were reviewed by management.
The licensee had recently implemented an "EP Group Planned Self-assessment Program"
to evaluate the effectiveness and performance of the EP program. The inspectors
reviewed several self-assessment reports and found them to include evaluation plans,
strengths, weaknesses and/or potential areas for improvement. As the self-assessment
program develops, the licensee plans to become more self- critical, establish trending
data and closely evaluate repeat findings.
Conclusions
The EP staff uses the AR process plus three other automated systems for tracking issues
such as audit findings, procedure changes and self-assessment findings. The systems
are effective and ensure adequate management attention. The recent addition of a self-
assessment program is a good initiative for the EP program.
P1 .2
Relationship with Offsite Agencies
a.
Inspection Scope (82701)
The inspectors interviewed state and county representatives from the States of
New Jersey and Delaware to assess the licensee's relationship with offsite agencies.
b.
Observations and Findings
The inspectors interviewed the Radiological Administrator for the Delaware Emergency
Management Agency, and the Manager, Bureau of Nuclear Engineering (BNE),
New Jersey, and contacted by telephone, the Deputy Coordinator for the Department of
Emergency Services, Salem County, New Jersey, to discuss the licensee's relationship
with those agencies. Both Delaware and Salem County, NJ representatives stated that,
overall, the licensee worked hard to maintain an excellent rapport with their agencies.
However, the Manager, BNE stated that while the communications and information flow
between the licensee and the State has improved since October, 1995, further
improvement is needed in the following areas: 1) planning of the Emergency Operational
c.
34
Facility (EOF) renovation; 2) quality of the station status checklists used for transmitting
event information; and 3) the verification of information contained in press releases from
the licensee's emergency news center. He further stated that recent communications
with the licensee on the proposed NUMARC EALs was constructive.
Conclusions
Overall, the licensee maintained good rapport with the offsite agencies. However, the
Manager, BNE identified some issues where coordination and communication between
the licensee and the State of New Jersey could be improved.
P2
Status of EP Facilities, Equipment, and Resources
P2. 1
Operational Readiness of Emergency Facilities
a.
Inspection Scope (82701 l
b.
The inspectors toured the following Salem facilities: the EOF, Control Room (CR),
Technical Support Center (TSC), Operations Support Center (OSC), and Control Point.
The Hope Creek facilities were evaluated during the May, 1996 annual exercise and
found to be operationally ready. The inspectors also reviewed 1996 facility equipment
inventories and surveillance tests for completeness and accuracy .
Observations and Findings
The inspectors checked the inventory of several emergency equipment lockers and one
field monitoring team emergency kit for completeness and equipment readiness. One
locker contained two radiation survey instruments with dead batteries, that were
immediately replaced. All other survey meters inspected were calibrated and operational.
The inspectors found two unshielded Cesium-137 check sources in supply lockers
located in the EOF and TSC, used for verifying instrument response. The check sources
are routinely stored near a supply of personnel thermo-luminescent dosimeters (TLDs)
used for offsite field monitoring teams. These sources could potentially produce an
erroneous radiation dose to the field TLDs prior to use in an actual emergency. The
licensee acknowledged this problem and agreed that the check sources and TLDs should
be stored in separate lockers.
While touring the TSC, the inspectors noticed that a key for a radiation protection (RP)
locker was missing. Apparently, an RP staff member had changed the lock, without
informing the EP staff, and stored the key at the Salem control point. According to the
licensee's emergency plan implementing procedure (EPIP) 203S, the key is to be stored
near the locker. Relocation of the key could potentially result in the locker being
inaccessible to field teams during an emergency. The licensee initiated a procedure
change to ensure that during emergency conditions, an RP technician, assigned to the
TSC, would bring the locker key from the control point and unlock the locker.
35
The licensee was in the process of constructing a new OSC inside the CR ventilation
boundary and renovating the existing EOF. During construction, a temporary OSC,
outside the CR, was being utilized in case of an actual emergency event. The inspectors
concluded that the EOF and temporary OSC were adequate if needed for this purpose.
The inspectors determined that equipment inventories, communication surveillance tests,
and siren surveillance tests were conducted at correct frequencies, and inventory
checklists were properly completed and reviewed. Identified deficiencies and corrective
actions were well documented.
c.
Conclusions
The inspectors concluded that the licensee maintained an effective inventory and
surveillance test program and that the Salem/Hope Creek emergency facilities and
equipment were operationally ready.
P3
EP Procedures and Documentation
a.
Inspection Scope (82701)
The inspectors reviewed emergency plan (E-Plan) and EPIP revisions in the regional
office, prior to the inspection, to determine if the changes reduced the effectiveness of
the E-Plan. While onsite, the inspectors reviewed the documentation for the last E-Plan
changes.
b.
Observations and Findings
The inspectors reviewed the licensee's 10 CFR 50.59 safety evaluation and 10 CFR
50.54(q) licensee review for Revision 5 to Section 2 of the E-Plan. The inspectors
concluded that these were thorough, well-documented, and adequate for making this
revision. EPIP revision changes were documented in NRC Inspection Report 50-354/96-
01, 50-272 & 311 /96-01 and no additional revisions were reviewed prior to this
inspection.
c.
Conclusions
The inspectors determined that the reviewed E-Plan and EPIP changes did not reduce the
effectiveness of the E-Plan. Also, the licensee's procedure change process was good.
P5
Staff Training and Qualification in EP
a.
Inspection Scope (82701)
The inspectors reviewed EP training records, training procedures, lesson plans, EPIPs and
the licensee's E-Plan to evaluate the licensee's EP training program. The inspectors also
conducted interviews with Salem Senior Reactor Operators (SROs) to assess the
licensee's EAL classification training.
b.
"
36
Observations and Findings
The EP off-site supervisor maintained the EP training records for emergency response
organization (ERO) responders. The inspectors randomly selected the training records of
approximately 75 responders from Salem and Hope Creek and verified that the ERO
responders were qualified to fill their assigned emergency response positions.
Approximately a quarter of the responders are required to have respirator training that is
provided by RP. EP does not routinely track the RP training to ensure that all responder
training requirements are met. In early 1996, the EP off-site supervisor, accidently
discovered that respirator training for 9 out of 16 maintenance workers on the ERO list
had elapsed. Also, in August 1996, it was reported in the licensee's morning
management meeting, that an Instrument and Control technician was reported not to
have current respirator qualifications and was listec:l on the current ERO list. The EP staff
appeared to be unaware of this incident and committed to writing an AR for further
review.
The inspectors stated to the licensee that although the RP Department is responsible to
provide respirator training, the EP staff is responsible to ensure that all members on the
ERO list meet the required qualifications stated in the Emergency Plan and EPIPS. The
licensee initiated a review of the RP records to ensure that all individuals on the current
ERO list meet all training requirements. Additionally, the licensee mentioned plans to
have one automated training tracking system for better utilization by the EP staff .
The licensee had made changes to their EP training program due to problems identified in
drills and exercises. The licensee was conducting quarterly unannounced call-out muster
drills, weekly pager tests, and were completely revising procedures and EP overview
lesson plans. In addition, a letter was sent from upper management to the ERO
members addressing their EP roles and responsibilities.
The inspectors interviewed two Salem SROs to assess the quality of the licensee's
present EAL training. Both SROs stated that the NUMARC EAL training was good,
however, they did not think the one-hour training session on the present EAL scheme
was very thorough or detailed. They both stated that if the NUMARC EALs are not
approved prior to restart of Salem 1 & 2, they would expect comprehensive retraining on
the present EALs. *
The inspectors stated to the licensee that until the NUMARC EALs are approved,
adequate and appropriate training should be provided to the SRO's for classifying events
using the present EALS.
The inspectors reviewed training records for annual offsite emergency response training
for medical, fire-fighting, and media personnel. The inspectors found that the required
drills had been conducted and were well-documented. Media training was offered by the
licensee, but may not have been implemented in accordance with the E-Plan (see Section
PS). With this one exception, all on-site and off-site required drills, exercises and
training were conducted in 1995 and 1996 in accordance with the licensee's E-Plan .
37
The licensee conducted monthly pager drills for all four duty ERO teams and weekly drills
for the on-call duty team. Additionally, they conducted quarterly muster exercises where
the duty team must actually report to the site, alternating between Salem and Hope
Creek. The inspectors noted that documentation regarding these drills and exercises
indicated an overall improvement in ERO response. However, in May 1996, NRC
inspectors attended an unannounced call-out drill and observed poor drillmanship and
command and control. (See Section P8.3)
The inspectors reviewed the training records for annual EAL training with the states and
counties and found them to be satisfactory.
c.
Conclusions
The inspectors determined that the ERO members, for whom training was reviewed,
were currently qualified. However, the licensee needs to ensure that individuals listed on
the ERO list meet all training requirements to fill their position. Training of offsite
agencies and support organizations is of good quality and completed as required.
The inspectors concluded that the periodic pager tests and mustering drills, as well as
holding ERO responders accountable for their responsibilities is a positive step to upgrade
their overall emergency response capability. Overall, the inspectors assessed this area
as adequate .
PG
EP Organization and Administration
a.
Inspection Scope (82701)
The inspectors reviewed the licensee's EP staffing and management to determine the
changes that have occurred since the last program inspection (August 1994), and to
assess if those changes had any adverse effect on the EP program.
b.
Observations and Findings
The EP Department has had several management and organization changes in the past
year. In January 1996, the Manager, EP & Radiological Safety was replaced. In
September 1996, this position is being eliminated and split into two management
positions. The intentions are to add an experienced EP manager and an experienced
radiological health manager. In July, the EP and Radiological Support Division was
moved from Site Support Services and placed in the Nuclear Training Center (NTC)
Division. The Director, NTC reports directly to the Sr. Vice President, Nuclear
Operations. The licensee is planning additional changes in the responsibilities of the EP
staff members.
Discussions with the Sr. Vice President and Director, NTC indicated that management is
committed to bringing a serious EP attitude to the ERO members. They also stated that
the addition of a manager with EP experience will enhance EP staff performance .
c .
38
Conclusions
Discussions with the members of the EP staff, the inspectors determined that the recent
organizational changes have not had an adverse effect on the EP staff. At this time, it
does not appear that these changes have reduced the ability to administer the EP
program effectively.
P7
Quality Assurance in EP Activities
a.
Inspection Scope (82701)
The inspectors reviewed Audit Reports No.95-030 and 96-030, of the EP Department,
conducted in 1995 and 1996, respectively. The inspectors also reviewed audit plans,
checklists procedures and interviewed personnel from the QA Department regarding the
process for conducting a program audit.
b.
Observations and Findings
c.
Based on document review and interviews, the inspectors determined that the audits
were conducted utilizing an audit plan and checklists, and that the audit team included
several technical specialists from other nuclear utilities with EP experience. The audit
reports were appropriately detailed and met the requirements specified in 1 0 CFR
50.54{t)._ No programmatic problems were identified .
Conclusion.
The audit reports were comprehensive and the audit plan was extensive. The use of
independent technical specialists is particularly noteworthy. The reports met the
requirements of 10 CFR 50.54(t) and the inspectors assessed this area as very good.
PS
Miscellaneous EP Issues
P8.1
Updated Final Safety Analysis Report (UFSARl Inconsistencies
A recent discovery of a licensee operating its 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 description. Since the UFSAR
does not specifically include EP requirements, the inspectors compared licensee activities
to the E-Plan, that is the applicable document. The following inconsistences were noted
between the E-Plan and licensee activities by the inspectors.
1.
Section 9, paragraph 4.4 of the E-Plan discusses additional radiological
instrumentation located in the licensee's Training Center laboratory to be available
as backup to the EOF. The inspectors determined that the instrumentation had
never been calibrated and the laboratory is currently being dismantled .
2.
39
The inspectors discussed this with the licensee, and an E-Plan change has been
submitted to delete the use of the Training Center laboratory as a backup to the
EOF. (URI 50-272&311/96-15-03)
Section 8, paragraph 3.0 of the E-Plan, states that annually, an information program
is provided to local news representatives and covers specific outlined topics on
nuclear energy, radiation and emergency planning. It also states that this program
may take place as part of the annual exercise. A public information (Pl)
representative stated that media training actually consisted of an information
calendar sent to local media personnel, followed by a phone call, inviting them to
the licensee's annual exercise. This is inconsistent with the commitments in the E-
Plan. A change to the E-Plan describing the current media training program has
been submitted. (URI 50-272&311/96-15-04).
P8.2
Missed Alert Declaration
a.
Observations and Findings
On July 12, 1996, a new shift technical advisor (STA) reviewing a reactor trip event
report from June 7, 1995, found that the licensee had not made an alert declaration in
accordance with the emergency classification guide (ECG), Section 4A. The report
stated that, on that date, at 6:28 p.m., Salem Unit 2 began a reactor shutdown in
accordance with Technical Specification (TS) 3.03, due to the inoperability of both
Residual Heat Removal (RHR) trains. At 5:42 a.m., on June 8, 1995, Unit 2 entered
Mode 4, that, concurrent with the inoperability of both RHR trains, met the criteria for an
alert declaration. Although both RHR trains were inoperable by TS, they were functional,
and RHR was used for shutdown cooling. Based on the STA's finding, the licensee
made a "one-hour report" in accordance with ECG, Section 17D, "Emergency Conditions
Discovered After-the Fact," to inform the NRC of the missed classification and an AR
was written for additional review.
The inspectors reviewed the licensee's Significant Event Review Team (SERT) report that
followed the 1995 event and determined that the SERT did not identify the missed
classification. It was also noted, that the licensee's AR report did not address the
SERT's failure to identify the missed classification. The inspectors questioned the
licensee about this. The licensee believed that the SERT missed the classification due to
the confusion with the present EALS. Since this has been a continuing problem
identified for other missed classifications, the licensee did not address it in the AR. The
inspectors stated that the recent review of the SERT should have included investigation
into other possible contributors to the EAL classification problems, for example, the
quality of EAL training or if scenarios are realistic and challenging. The licensee initiated
an AR to review this matter further.
The missed alert declaration was licensee-identified. It could not have been prevented
by corrective actions for any previous violation. The licensee's AR, that initiated a
reevaluation of the event, prescribed adequate remedial and corrective actions to prevent
recurrence. Additionally, the safety significance of the event was negligible. Both RHR
trains were functional at all times, and RHR was used for shutdown cooling, i.e., to cool
I
,I
b.
40
the reactor core by removing decay heat, even though both RHR trains were inoperable
according to TS. The inspectors concluded that the licensee's ECG is restrictive by
using the term "inoperable" when referring to the RHR trains in the initiating conditions
for the alert. NUREG-0654, "Criteria for Preparation and Evaluation of Radiological
Emergency Response Plans and Preparedness in Support of Nuclear Power Plants," uses
the term "non-functional" when describing the initiating conditions for a loss of decay
heat removal capability (alert). This term is less restrictive in that a system can be
ii:ioperable, but still functional. The licensee had the capability at all times to use RHR
for decay heat removal, and protect the core from overheating.
Conclusions
The NRC Enforcement Policy states that the failure to declare an alert is a Level Ill
violation. However, due to the mitigating circumstances discussed above, this licensee-
identified item is being treated as a Non-Cited Violation, consistent with Section Vll.B.1
of the NRC Enforcement Policy.
P8.3
Unannounced Off-hours Call-out Drill
a.
Observations and Findings
On May 14, 1996 the licensee conducted an unannounced off-hours call-out drill for
staffing all Salem emergency response facilities. NRC inspectors observed player
performance at the EOF and the TSC. The licensee successfully staffed the facilities in a
timely manner. However, at the EOF, many of the players did not take play seriously
and some appeared unfamiliar with their position responsibilities. No command and
control was exhibited by the Emergency Director (ED) and that contributed more to a
"laissez-faire" atmosphere. A member of the technical support team was told to fill the
technical support manager position, and informed the ED that she had not received the
required training for filling that position.
The ED had her assume the role of technical
support manager anyway. Also, the EP staff played dual roles of observer and referee
that caused them to coach and demonstrate to players their responsibilities. Similar
observations were made at the TSC.
During this inspection, the inspectors reviewed the licensee's drill critique in that the
above observations were documented. In discussions with the licensee, the EP staff
believed many of the identified problems were due to the EP staff not stating the
objectives of the drill, therefore, many of the players thought it was just a "muster" drill.
They also stated that the lack of command and control was due to the ED being told
minutes prior to his arrival, that this was just a muster drill. No action report was
written for these observations.
The inspectors noted that* no additional training was provided to those players that
weren't familiar with the responsibilities of their position. Also, the licensee gave no
consideration to whether poor player performance was due to the fact that this drill was
"unannounced" .
b.
41
Conclusions
The licensee has performed numerous drills during the past year and licensee critiques
indicated that player performance was serious and responsible. However, for the May
1996 drill, players did not perform their duties seriously as they would if it were a real
event, until informed otherwise.
S2
Status of Security Facilities, Equipment, and Resources
S2.1
Security Door Material Condition
Inspection Scope (71707)
The inspectors reviewed the adequacy of the security staff's response to door alarms.
Observations and Findings
The inspector reviewed the record of alarms for security doors in some high traffic areas.
In one case, a door alarmed nineteen times in one day. The record indicated that, in
each case, security personnel responded to the alarms. Based on the record and
discussions with security and other plant personnel, a number of factors caused the door
alarms, including ventilation effects, equipment problems, and plant staff not correctly
operating the security features. The inspector noted that, after a few days of door
alarms, security managers implemented compensatory measures for the doors and
insured that maintenance staff corrected the identified hardware discrepancies. In the
case of one door, the staff replaced major components to insure proper door operation.
Conclusions
The inspectors concluded that security personnel complied with the requirements of the
security plan for access control. Although security supervisors and managers might
have been more aggressive in implementing compensatory measures and initiating
maintenance efforts, the inspectors did not find any degradation of access control.
S8
Miscellaneous Security and Safeguards Issues
S8.1
Security Support of Replacement Steam Generator Transportation
a.
Inspection Scope
On October 3, 1996, a regional security specialist was dispatched to the site to review
the security considerations associated with the movement of the RSGs. The RSGs were
received at the Salem barge slip, transported through the vehicle barrier system,
protected area barrier, and intrusion detection systems, into the protected area (PA),
maneuvered, transported out of the protected area and taken to the temporary storage
facility. Entry into, and then out of, the PA was necessitated to make use of an existing
construction roadway for the transporter vehicle .
b.
42
Observations and Findings
The inspector determined by observations, procedural reviews, interviews with security
force members, and discussions with security management, that security considerations
associated with the RSGs, as described in the Salem Unit 1 Steam Generator Entry
Security Plan, dated October 2, 1996, Revision 1, was properly implemented. The
inspector verified that compensatory measures associated with the removal of the
vehicle barrier system, perimeter intrusion detection systems, and protected area barrier
were effective and properly implemented. Additionally, the inspector determined by
reviewing Security Procedure SP12, dated March 9, 1996, Revision 9, and discussions
with security management, that measures were in place to ensure that the barriers
would be properly re-installed and that all applicable intrusion detection systems re-
installed and reactivated, and tested in accordance with the requirements of the NRC-
approved security plan prior to removing compensatory measures. No weaknesses or
discrepancies were noted.
V. Management Meetings
X 1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at the
conclusion of the inspection on November 8, 1996. The licensee acknowledged the
findings presented .
The inspectors asked the licensee whether any materials examined during the inspection
should be considered proprietary. No proprietary information was identified .
INSPECTION PROCEDURES USED
IP 50001:
IP 61726:
Steam Generator Replacement Inspection
Surveillance Observations
IP 62707:
Maintenance Observations
IP 71707:
Plant Operations
IP 86750:
Solid Radioactive Waste Management and Transportation of Radioactive
Material
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-272&311/96-15-01
50-272&311 /96-15-02
50-272&311 /96-15-03
50-272&311 /96-15-04
Closed
50-272&311/92-12-01
50-272&311/93-15-03
50-27 2&311 /93-21-03
50-311 /94-06-01
50-272&311/E03013
50-311 /94-08-01
50-272&311/94-13-02
50-272&311/94-14-01
50-272&311/94-19-01
IFI
50-272&311/95-07-01
50-272&311 /95-07-02
DEV
50-272&311 /95-17-01
50-272&311/96-05-01
50-272&311 /96-08-01
50-272&311 /96-12-02
IFI
50-272/95004
LER
50-272/95013
LER
50-272/95014
LER
50-272/95017
LER
Corrective action for operator performance problems
Operator failure to adhere to procedures
Acceptability of change to EOF backup facility
Acceptability of lack media training vs. E-plan
description.
equipment operator log falsification
Salem Unit 2 fuel rod defects
potential TS noncompliance due to SSPS train B
inoperability
failure to comply with TS for power operated relief
valves
loss of control room command and control
steam generator depressurization during simulator
scenario
repeated entry into TS LCO
flange leak repair root cause
definition of controlled leakage
control room emergency air conditioning system TS
noncompliance
concurrent testing of redundant EDGs during normal
plant operation
failure of electricians to reinstall tags
failure of Offsite Safety Review and Onsite Safety
Review Group personnel to meet the number and
qualification requirements of TS 6.5.2.2
failure of plant staff to update Tagging Request Inquiry
System
service water bay depressurization
inadequate containment air temperature surveillance
TS 4.3.3.3.1 surveillance requirements late
safety injection throttle valve inoperability
failure of control room emergency air conditioning
system to meet GDC 19 criteria
2
50-272/95018
LER
improper range gauges used for inservice testing
50-272/96001
LER
insufficient thermal overload heater margin
50-272/96003
LER
missed radiation monitor sampling
50-272/96004
LER
missed containment isolation valve surveillance
50-272/96005
LER
failure to perform Tavg channel checks
50-272/96006
LER
missed independent verification of waste gas alignment
50-272/96007
LER
ESFAS values greater than TS allowed
50-272/96008
LER
failure to meet mode 5 requirements for natural
circulation
50-27 2/9.6009
LER
potential common mode failure for 4KV Magna-Blast
breakers
50-272/96010
LER
inadequate pressurizer relief tank supports
50-272/96011
LER
pressurizer safety relief valves found outside of TSs
limit
50-272/96016
LER
missed RHR pump surveillance
50-272/96017
LER
missed plant vent surveillance
50-272/96022
LER
incorrect radiation monitor setpoints
50-272/96023
LER
failure to perform MSIV surveillances
50-272/96024
LER
failure to meet AFW pump response times
50-311/95001
LER
manually initiated engineered safety feature actuation
50-311 /95003
LER
failure to perform type C local leak rate testing
50-311 /95007
LER
missed emergency diesel generator surveillances
50-311 /95008
LER
missed verification of containment isolation
50-311/96001
LER
failure to perform chemical sampling when required
50-311 /96002
LER
waste gas decay tank oxygen greater than limit
50-311 /96003
LER
failure to perform fuel handling building auto start
surveillance
50-311 /96004
LER
description missed compensatory survey
. 50-311 /96005
LER
missed fuel handling building charcoal surveillance
50-311 /96007
LER
missed over current protective device surveillance
50-311 /96008
LER
inoperable battery chargers due to manufacturing
discrepancies
50-311/96010
LER
missed pressurizer weld surveillances
Discussed
50-311 /94-24-02
IFI
auxiliary feedwater pump surveillance adequacy
50-272&311 /95-21-02
IFI
service water reliability issues
50-272&311/96-07-03
IFI
breaker testing and analysis
50-311 /96009
LER
fourteen day followup report regarding 1 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> shifts
for operations personnel
LIST OF ACRONYMS USED
Action Request
Alarm Response Procedure
CR
Condition Resolution
Design Change Packages
Electric Power Research Institute
U.S. Department of Transportation
ECAC
Emergency Control Air Compressor
ECG
Emergency Classification Guide
Equipment Operator
Emergency Operating Procedures
ES FAS
Engineered Safety Feature Actuation System
GDC
General Design Criterion
GE PO
General Electric Philadelphia Operations
High Head Safety Injection
l&C
Instrumentation and Controls
Intermediate Head Safety Injection
IP
Industrial Packaging
ISi
In-Service Inspection
lnservice Testing
LCO
Limiting Conditions for Operation
License Change Request
LER
Licensee Event Report
Loss of Coolant Accident
NRC
Nuclear Regulatory Commission
OEF
Operating Experience Feedback
OSG
Old Steam Generator
OSR
Offsite Safety Review
OTSC
On-The-Spot-Change
Protected Area
Public Document Room
PO RVs
Power Operated Relief Valves
Pressurizer Relief Tank
PSE&G
Public Service Electric & Gas
Quality Assurance
Radiological Controlled Area
Reactor Coolant Piping
Reactor Coolant Pump
Reactor Operator
Radiation Protection
Replacement Steam Generator
SAC
Station Air Compressor
sco
Surface Contaminated Object
,,
SNSS
SSPS
TO Ls
TRIS
TS
TSSIP
2
Steam Generator Replacement Project
Senior Nuclear Shift Supervisor
Senior Reactor Operator
Solid State Protection System
Technical Document Room
Thermal Overload Heaters
Tagging Request Inquiry System
Technical Specification
Technical Specifications Surveillance Improvement Program
Updated Final Safety Analysis Report
Work Order