ML18102A445
| ML18102A445 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 10/01/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18102A443 | List: |
| References | |
| 50-272-96-12, 50-311-96-12, NUDOCS 9610080266 | |
| Download: ML18102A445 (33) | |
See also: IR 05000272/1996012
Text
Docket Nos:
License Nos:
Report No.
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved by:
U. S. NUCLEAR REGULATORY COMMISSION
50-272, 50-311
REGION I
50-272/96-12, 50-311 /96-12
Public Service Electric and Gas Company
Salem Nuclear Generating Station, Units 1 & 2
P.O. Box 236
Hancocks Bridge, New Jersey 08038
August 11, 1996 - September 14, 1996
C. S. Marschall, Senior Resident Inspector
J. G. Schoppy, Reside,nt Inspector
T. H. Fish, Resident Inspector
J. D. Noggle, Senior Radiation Specialist
J; C. Jang, Senior Radiation Specialist
J .. J. Kottan, Laboratory Specialist
N. T. McNamara, Emergency Preparedness Specialist
J. Laughlin, Emergency Preparedness Specialist
Larry E. Nicholson, Chief, Projects Branch 3
Division of Reactor Projects
9610080266 6~688~72
~DR ADOCK
EXECUTIVE SUMMARY
Salem Nuclear Generating Station
NRC Inspection Report 50-272/96-12, 50-311/96-12
This integrated inspection included aspects of licensee operations, engineering,
maintenance, and plant support. The report covers a 5-week period of resident inspection;
in addition, it includes the results of announced inspections by regional radiation,
emergency preparedness, and chemistry inspectors.
Operations
During the inspection period, the inspectors found a significant failure of the Salem line
organization to take corrective action. In December 1995, operators filled the refueling
cavity and detensioned the reactor head without insuring that Salem Unit 2 met the
refueling reactivity requirements specified in Technical Specification 3.9.1. An operator
identified the failure after the fact and appropriately initiated a Condition Report. In
response to the report, however, the operations staff inappropriately made a change to the
refueling cavity fill procedure that effectively changed implementation of Technical
Specification 3.9.1 and 4.9.1.1 requirements. The 1 OCFR50.59 applicability review failed
to identify that the procedure change required a Technical Specification change. In
addition, the operations staff failed to identify that procedures used to prepare the reactor
coolant system and refueling cavity for entry into mode 6 (refueling) did not insure that
plant conditions met the more restrictive of the reactivity requirements stated in TS 3.9.1.
The inspectors concluded that the operations and staff acted to serve the outage activities,
rather than insuring safety and quality in refueling activities (Section 03.1 ). The Salem
staff promptly initiated corrective action for minor discrepancies in meeting administrative
requirements for Station Operating Review Committee documentation.
The plant staff had
already implemented corrective action for a self-identified violation (Section 02.1 ).
Although operators caused an unexpected depressurization of a service water header, it
resulted in no safety consequence, since it did not diminish the supply of service water
from the redundant header. The inspectors will assess the results of licensee corrective
actions in the next inspection period (Section 04.1 ).
Maintenance
Inspectors noted several examples of poor maintenance staff performance. They included:
planning service water pump repacking steps out of sequence (Section M4. 1); failure to
properly secure temporary control air fittings (Section M4.2); and swapping high and low
pressure freon sensing lines following a chiller instrument calibration (Section M4.3).
During Emergency Diesel Generator post-maintenance testing, technicians discovered that
the fuel injector test rig did not work properly. The technicians also learned that, since
they did not und*erstand the operation of the test rig, they misinterpreted results obtained
while using it. The technicians subsequently discovered that ineffective foreign material
exclusion caused a minor fuel oil leak from a fuel line. The inspectors concluded that
neither training or procedures insured quality maintenance in these instances (Section
M4.4). Ineffective maintenance practices have become increasingly evident during the
outage. As documented in NRC Inspection Report 50-272&311 /96-08, during this
ii
reporting period Nuclear Business Unit and Salem senior management initiated a major
effort to provide training for all Salem maintenance staff (Section M4.5).
Engineering
Although the quality in engineering activities varied somewhat, inspectors concluded that it
was generally good during the inspection period. The system manager did not inform the
Management Review Committee (MRC) that RHR minimum flow valve 22RH29 continued
to malfunction. As a result, the MRC inappropriately accepted the package for closure
(Section E1 .1 ). The Salem staff developed and implemented a satisfactory corrective
action plan for the Salem Unit 2 PORV problems, and planned to implement the actions for
Unit 1 PO RVs (Section E2.1)
Salem staff completed effective corrective action for the
Unit 2 positive displacement pump (PDP) reliability problems, however, they have not yet
completed action for the Unit 1 PDP pump (Section E2.3). The quality of MRC reviews, an
NRC concern identified in previous inspections, improved significantly during the
inspection period (Section E7. 1).
Plant Support
In general, the plant support organizations effectively supported outage activities.
Chemistry technicians accurately quantified hydrazine, ammonia, and copper in the NRC
standards during an inspection (Section R1 .1 ). Sufficient radiological safety resources
have been planned for the Salem Unit 1 steam generator replacement project. The Salem
staff continued to formulate the radiological safety planning with less than two months
remaining before the project, however, the inspector did not detect any significant planning
deficiencies (Section R3.3). A radiation protection technician did not meet managements
expectations for control of access to the radiologically controlled area.(Section R4.1 ). The
NRC will document the details of an inspection of the emergency preparedness program in
NRC Inspection Report 50-354/96-07.
iii
,\\
TABLE OF CONTENTS
EXECUTIVE SUMMARY ............................................. ii
TABLE OF CONTENTS .............................................. iv
I. Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
II. Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Ill. Engineering
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12
IV. Plant Support . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17
V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
iv
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.
02
Operational Status of Facilities and Equipment
02.1
Stetion Operations Review Committee (SORC)
a .
Inspection Scope (7*1707)
The inspector reviewed procedures governing the Station Operations Review
Committee (SORC) activities, and reviewed examples of SORC meeting minutes and
the distribution of those minutes.
b.
Observations and Findings
The inspector found that procedure NC.NA-AP.ZZ-0004(0), Revision 6, Statiof!
Operations Review Committee, Step 5.5.3 states:
"If changes to a document are required before a recommendation for approval will
be made, then the recommendation for approval may be granted contingent upon
such changes being incorporated. The specified changes should be entered in the
meeting minutes and a statement made that approval is predicated upon these
changes being made. The SORC Chairman or an assigned designee should verify
that the changes are correct before the document is submitted to the General
Manager."
During his review, the inspector found that required changes for a SORC reviewed
document, Design Change Package (DCP), 2EC-3266, Pkg. 1, Rev. 0, were properly
entered in the SORC meeting minutes # 96-034. However, one of the comments
which required a change to section 3.2 of the DCP's 1 OCFR50.59 evaluation, was
never incorporated. The inspector concluded that the omission did not affect the
results of the 1 OCFR50.59 evaluation. Through review of an additional thirteen
required changes for other SORC-reviewed documents, the inspector found that all
had been properly incorporated.
2
The inspector also found that the SORC procedure, step 5.6.8, states:
"The Secretary should have the minutes copied and submitted to the TOR
[Technical Document Room] for distribution within 30 working days of the SORC
meeting." ,
The inspector learned through discussions with document room personnel that
SORC no longer sends meeting minutes to the TOR. The inspector confirmed that
plant staff distributed SORC minutes directly via E-mail as directed in a memo
initiated by the Salem Project Manager. Although this change was intended as an
improvement to the method of distribution, it is not in compliance with the current
revision of the SORC procedure.
The inspector also learned PSE&G had identified a procedural noncompliance in that
SORC meeting minutes were not being distributed to required recipients within the
30 day requirement. Additional staff has been assigned to reduce the backlog and
the problem is being tracked to closure utilizing the Salem site deficiency tracking
system.
c.
Conclusions
The licensee promptly initiated corrective action for inspector identified violations of
procedure requirements for SORC administration.
Plant staff had already
implemented corrective action for a self-identified violation. These minor examples
of procedural noncompliance will be treated as a Non-Cited Violation, consistent
with Section IV of the NRC Enforcement Policy.
03
Operations Procedures and Documentation
03.1
Refueling Cavity Fill
a.
Inspection Scope (71707)
The inspector reviewed control room narrative logs, operating procedures, and plant
status concerning fill of the Unit 2 refueling canal.
b.
Observations and Findings
On September 11, 1996, Unit 2 operators used S2.0P-SO.SF-0003, Revision 7,
Filling the Refueling Cavity, to commence filling the refueling cavity. The operating
shift demonstr~ted a good questioning attitude. The shift appropriately used the
"on-the-spot change" process to improve the procedure and subsequently stopped
filling the cavity due to a question concerning available instrumentation.
The inspector noted that S2.0P-SO.SF-0003 step 5.1.8 could be strengthened to
provide additional guidance. Step 5.1.8 specifies actions "when desired fuel
transfer canal level is reached," however, the procedure does not specify a desired
level. Two operating shifts interpreted "desired level" differently, resulting in tw-o
3
different approaches to cavity fill. In both cases, the shift operated within
procedure guidance and maintained good control of the evolution. A specified
minimum level minimizes the potential for high airborne activity due to excessive
spill-over (splashing) from the vessel to the canal. A specified maximum level
minimizes potential foreign material exclusion (FME) concerns involved with
overflowing the refueling canal into the reactor vessel. The Senior Nuclear Shift
Supervisor (SNSS) initiated a procedure revision request to improve the procedure.
The inspector noted that operators did not perform an independent verification (IV)
of repositioned valves, required by 'step 5.1.10, in a timely manner. The Nuclear
Shift Supervisor (NSS) acted promptly to ensure IV completion following inspector
reminder.
Technical Specification 3.9.1 requires that Salem maintain the boron concentration
of all filled portions of the reactor coolant system and the refueling canal uniform
and sufficient to ensure thi;it the more restrictive of the following reactivity
conditions is met: (a) either a Keff of .95 or less, or (a) a boron concentration of
greater than or equal to 2000 ppm. Technical Specification (TS) 4.9.1.1 requires
that the more restrictive of the above reactivity conditions be determined prior to
removing or unbolting the reactor vessel head and withdrawal of any full length
control rod in excess of three feet from its fully inserted position. The inspector
identified that on July 22, 1996, operations staff added step 3.6 to procedure
S2.0P-SO.SF-0003. Step 3.6 provided guidance to operators that "filling the
transfer canal in preparation for flooding the refueling cavity does not constitute a
filled portion of the refueling canal and therefore TS surveillance requirement 4.9.1.1 is not applicable." The inspectors determined that the fuel transfer canal
consists of the lower portion of the refueling canal below the level of the reactor
cavity. As described in the Salem UFSAR, section, 9.1 .4.1.4, the refueling canal
encompasses the transfer canal. The inspectors concluded that step 3.6 to
procedure S2.0P-SO.SF-0003 contradicts TS 3.9.1 and the UFSAR. The inspectors
reviewed the 1 OCFR50.59 review associated with the addition of step 3.6 and
determined that the licensee incorrectly concluded that the addition of step 3.6 to
procedure S2.0P-SO.SF-0003 did not require a Technical Specification change.
In addition, the inspectors determined that the operations management changed
procedure SF-0003 in response to a condition that existed in December 1995. On
December 7, 1995, a SNSS questioned whether operators violated TS 3.9.1
because operators failed to ensure that they maintained adequate boron
concentration in the refueling canal prior to entering the refuel mode on December*
6, 1995 (Condition Report 951207066). Salem licensing staff stated that "since
the refueling canal was not filled at the tirne, there was no communication link with
the reactor .coolant system and therefore no potential to affect reactor criticality"
(Memo CR-1955746). Operations management determined that if the refueling canal
is not filled and the vessel head has not been removed, then TS 4. 9. 1 . 1 is not
applicable. In addition, operations' response to CR 95120766 stated "A more
conservative approach would be to require verification that any water in the
refueling canal is greater than 2000 ppm boron prior to head detensioning. An
4
uncontrolled RCS dilution and inadvertent criticality with all rods inserted and the
reactor head studs detensioned could result in a serious accident with severe
consequences" (PIR 951207066).
The inspector determined that operators did, in fact, fail to meet TS 3.9.1
requirements on December 6, 1995. Operators did not ensure that the filled portion
of the refueling canal (eight inches of demineralized water) met the more restrictive
of the TS 3.9.1 reactivity conditions prior to detensioning the reactor head and
entering the refueling mode. In addition, by their failure to take thorough and
effective corrective actions, Salem licensing and operations staff failed to identify
that procedures S2.0P-SO.SF-0003, 2-IOP-7, Revision 10, "Integrated Operating
Procedure Cold Shutdown to Refueling and S2.0P-IO.ZZ-007, Revision 0, Cold
Shutdown to Refueling" did not require operators to meet the more restrictive of the
two reactivity conditions required by TS 3.9.1. Inspectors concluded that
operations management, expected to implement high standards for corrective
action, failed to take appropriate corrective action for a TS violation identified by an
operator. Failure to take action to preclude repetition of a violation of Technical
Specification requirements is a violation of 10 CFR 50, Appendix B, Criterion XVI,
Corrective Action(VIO 50-272 & 311 /96-12-01 ).
c.
Conclusion
By failing to ensure required boron concentration prior to entering the refueling
mode in December 1995, operators failed to meet TS 3.9.1 requirements. In
addition, in July 1996, Salem staff failed to determine, as required by 10 CFR
50.59, that a proposed cavity fill procedure change in contradiction to the UFSAR
and the requirements of TS 3.9.1 required a TS change approved by the NRC. In
addition, the operations staff response to the Condition Report that documented the
failure to meet TS 3.9.1 did not identify and correct conditions adverse to quality.
Specifically, the cavity fill procedures did not insure that boron concentration met
the more restrictive of the TS 3.9.1 reactivity requirements. The inspectors
concluded that the operations staff justified the incorrect operator actions of
December 1995, rather than taking action to prevent the repetition of those actions.
04
Operator Knowledge and Performance
04.1
Service Water Bay Depressurization
a.
Inspection Scope (71707)
The inspector reviewed control room narrative logs and strip chart recordings
following an unexpected operator-induced service water (SW) bay depressurization.
In addition, the inspector conducted a SW system walkdown and interviewed the
operating shift.
b.
5
Observations and Findings
At 3:55 a.m. on September 2, 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. At 4:53 a.m. 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. The cross-connect of 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 senior
reactor operator initiated a condition resolution (CR) report.
c.
Conclusions
The inspector considered this item open pending Operations' completion and NRC
review of corrective a~tions. (IFI 50-272&311 /96-12-02)
07 .1
(Closed) LER 50-272/95-001: both trains of Solid State Protection System (SSPS)
inoperable due to inadequate design. In February 1995 Salem staff learned that
Diablo Canyon identified a possible common mode failure of SSPS wiring near high
energy lines in the non-seismic turbine building .. Although the NRC initially granted
enforcement discretion to allow Salem to make changes at power, the NRC
1
rescinded the enforcement discretion in response to SSPS power supply failures.
The power supply failures resulted from lack of preventive maintenance resulting in
age related component failures.
The licensee attributed the inoperable SSPS to inadequate design and lack of
preventive maintenance. 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.
07 .2 (Closed) LER 50-272/95-003: four planned Technical Specification entries to
support correction of Analog Rod Position Indication (ARPI) system drift affecting
rods 2SA 1, 2SA4, and 2SA2.
Salem Unit 1 Technical Specification 3.1.3.2.1
required the ARPI system to provide rod position indication within twelve steps of
the respective rod group demand counter. The Technical Specification did not allow
any Limiting Condition of Operation action time for corrective action. The control
rod indication drift resulted from temperature related instrument drift. Salem staff
subsequently submitted and the NRC approved a Technical Specification change
request to allow short periods to perform instrument adjustments. These licensee-
identified and corrected violations are being treated as Non-Cited Violations,
consistent with Section Vll.B.I of the NRC Enforcement Policy.
6
08
Miscellaneous Operations Issue
08.1
(Closed) LER 50-272/95-025: single failure conditions that could have
compromised the ability of the service water system to complete its safety function
during the recirculation phase; During the Salem system Restart Readiness
Reviews, Problem Reports (PRs) were identified describing conditions which could
have resulted in Service Water System (SW) alignments with the potential for
runout/cavitation. The licensee concluded that the applicable mode of operation
was not clearly defined in plant design basis documents. Further, normal and
emergency operating procedures did not provide adequate operating instructions for
this mode of operation.
PSE&G initiated Performance Improvement Request No. 9510122244 to document
the problem and to identify the corrective action items to resolve the issue. The
inspector has determined that Salem has corrected the procedural deficiencies and
initiated. a design change notice to revise the system Configuration Baseline
Document to clarify the design basis.
The inspectors concluded that the procedural inadequacies constitute a violation of
10 CFR 50, Appendix 8, Criterion V, "Procedures." The inadequate design basis
document constitute a violation of 10 CFR 50, Appendix 8, Criterion Ill, "Design
Control." These licensee-identified and corrected violations are being treated. as
Non-Cited Violations, consistent with Section Vll.8.1 of the NRC Enforcement Policy.
08.2 (Closed) LER 50-272/95-026: main steam safety valves failed lift set test. During
scheduled surveillance testing, it was discovered that nine out of twenty Salem Unit
1 Main Steam Safety Valves (MSSVs) exceeded the allowable lift set pressure
tolerance specified in Technical Specification Table 4. 7-1. The causes of this event
were ring setting adjustments made without post adjustment lift setpoint testing,
and the prior use of test equipment that was inaccurate. PSE&G reviewed the work
history of the Salem Unit 2 MSSVs and determined that although they had
undergone ring settings, setpoints had been corrected as appropriate utilizing
alternate test equipment. PSE&G concluded that the problems identified on the
Salem Unit 1 MSSVs do not exist on the Salem Unit 2 MSSVs.
PSE&G initiated Performance Improvement Request No. 951023245 to document
the problem and to identify the corrective action items to resolve the issue. The
inspector has determined that Salem has discontinued the use of the inaccurate test
equipment and an action item has been identified to revise procedure SC.MD-
ST.MS-0001 (0) to require lift set testing following ring sitting changes. The
inspector verified that work orders have been issued for the removal, testing, and
replacement of the Salem Unit 1 MSSVs. These work orders are in various stages of
completion.
The inspectors concluded that the original procedures were inadequate in that post
maintenance testing was not required following ring setting. This procedural
inadequacy constitutes a violation of 10 CFR 50, Appendix 8, Criterion V,
7
"Procedures." This licensee-identified violation is being treated as a Non-Cited
Violation, consistent with Section Vll.B.1 of the NRG Enforcement Policy.
08.3 (Closed) LER 50-272/95-027: operation of Positive Displacement Pump (PDP) during
a safety injection could have resulted in exceeding 1OCFR100 and GDC ,19 dose
limit criteria. Previous analyses assumed that the PDP tripped after a safety
injection (SI) signal. However, the PDP trips after a safety injection signal only with
a concurrent loss of offsite power. During a LOCA, in the recirculation mode, the
PDP seal leakage can increase the total contaminated leakage to the auxiliary
building.
Additionally, the original dose evaluation was determined to be in error in that it
assumed the Auxiliary Building Ventilation (ABV) system charcoal filter was aligned
to provide filtration during the cold leg recirculation phase of a LOCA. The ABV
system charcoal filter is not automatically aligned.
The cause of this event is-inadequate design basis information. This resulted in the
development and use of inadequate procedures regarding operation of the PDP and
the ABV system.
PSE&G initiated Performance Improvement Request No. 951026244 to document
the problem and to identify the corrective action items to resolve the issue. The
corrective action items include a proposed revision to the Emergency Plant
Implementing Procedures to manually place the Auxiliary Building Ventilation
System charcoal absorber in service following a LOCA, and a proposed modification
to the Auxiliary Building Ventilation System design to provide local manually
operated valves to operate the charcoal absorber outlet dampers in the event of a
control or mechanical failure. Another corrective action is identified to conduct a
compr~hensive review to ensure consistency between design assumptions, plant
configuration, and operations. The inspector confirmed that these activities are
being tracked in the corrective action tracking system. The inspector also verified
that changes have been made to emergency operating procedures 1-EOP-LOCA-3 &
2-EOP-LOCA-3, "Transfer to Cold Leg Recirculation" to require operators to trip the
PDP prior to placing the plant in the recirculation mode.
Although not all corrective action activities are complete, the licensee has
committed to complete 'these items prior to Restart as stated in the LER corrective
action section. The inspector has concluded that the corrective action tracking
system and the documented commitment in the LER provide reasonable assurance
that the activities will be tracked to completion.
The procedural inadequacies constitute a violation of 10 CFR 50, Appendix B,
Criterion V, "Procedures." The inadequate design basis documentation constitute a
violation of 10 CFR 50, Appendix B, Criterion Ill, "Design Control." These licensee-
identified violations are being treated as Non-Cited Violations, consistent with
Section Vll.B.I of the NRC Enforcement Policy.
8
08.4 (Closed) LER 50-272/95-28: lack of effective leakage monitoring program required
by TS 6.8.4.a. The technical specification requires a program to monitor and
reduce leakage from those portions of systems outside containment that could
contain highly radioactive fluids during a postulated accident. PSE&G determined
that although elements of this leakage monitoring program exist, they had not been
controlled as an integrated program which would meet the requirements.
PSE&G initiated Performance Improvement Request No. 950920589 to document
the problem and to identify the corrective action items to resolve the issue. The
inspector has determined that procedure SC.SA-AP.ZZ-0051 (Q), Leakage
Monitoring Program, has been developed and issued. As a result of discussions with
PSE&G personnel, and a brief review of this procedure, the inspector was able to
conclude that it was designed specifically to satisfy the requirements of TS 6.8.4.a.
The inspectors concluded that prior to this event, adequate procedures were not in
place to prescribe activities necessary to meet the requirements of the technical
specifications. This procedural inadequacy constitutes a violation of 10 CFR 50,
Appendix 8, Criterion V, "Procedures." This licensee-identified and corrected
violation is being treated as a Non-Cited Violation, consistent with Section Vll.8.1 of
08.5 (Closed) LER 50-272/95-029: GE S8M Control Switch Degradation. During the
Salem Unit 1 outage, a design change for the replacement of mechanical linkages *
on 4KV vital bus breakers was implemented. Post modification testing revealed an
electrical failure of the 1 A vital bus high limit switch. Subsequent inspections by
the licensee revealed subsurface cracking on the cam follower. During additional
investigation, cracks were found on other switches. As a result, all 4KV vital
busses were declared inoperable for Salem Unit 1 and 2.
The licensee's corrective action for this event is to replace all switches in the 4KV
vital busses prior to mode 6 and 4KV group busses prior to mode 2. Additional
corrective action is planned to locate and replace any suspect switches used in
other applications.
The cause of this event was identified as an inadequate design of the component by
the manufacturer. The inspector determined that this event did not constitute a
violation of NRC requirements. This LER is considered closed.
9
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:
WO 960515214:
WO 960727074:
no. 26 service water pump strainer
troubleshooting
no. 1 C emergency diesel generator engine low
lube oil level alarm troubleshooting
The inspectors observed that the plant staff performed the maintenance effectively
within the requirements of the station maintenance program.
b.
Inspection Scope (61726)
The inspectors observed all or portions of the following surveillance:
S2.0P-ST.RHR.0001:
no. 21 residual heat removal pump performance
test
The inspectors observed that plant staff did the surveillance safely.
M4
Maintenance Staff Knowledge and Performance
M4. 1 Proper Pre-Job Planning
0-n September 2, technicians removed no. 25 SW pump from service and repacked
the pump. On September 3, a maintenance supervisor identified a planning
deficiency. Planning issued a work order (960805200) to repack *no. 25 SW pump
with another work order (960517060) in the system to add a sixth ring of packing
in accordance with the SW pump design change package. After repacking the
pump but prior to installing the sixth packing ring, a Salem worker initiated an
additional work order to repack the pump due to packing leakage. Planners did not
identify that they should have expected the leakage and implemented the work
order to install the sixth packing ring. Instead, they planned to develop another
work order to repack the pump. The maintenance supervisor demonstrated a good
questioning attitude and initiated a condition report (960903102) to document the
problem. The inspector concluded that poor maintenance planning resulted in
increased SW pump outage time .
10
M4.2 Equipment Restoration
On September 5, 1996, the inspector observed an unattended temporary control air
connection blowing air in the Unit 2 turbine building. Technicians believed that they
isolated the connection on September 3, when they last performed work under
work order no. 950110121. The Unit 2 Senior Reactor: Operator (SRO) entered
SH.OP-AP.ZZ-0007, Revision 0, Suspected Tampering. The SRO determined that
no malicious intent existed concerning the control air leakage. Technicians removed
the temporary connection from' the control air source. The. inspector concluded that
technicians' failure to properly secure equipment following maintenance represented
a poor maintenance practice.
M4.3 Configuration Control
On September 8, 1996, Unit 2 operators placed no. 21 chiller in service following
maintenance. Operators stopped the chiller when the chiller condenser relief valve
opened unexpectedly. The relief valve discharged approximately 10 pounds of
Freon to the atmosphere. The work supervisor determined that technicians
inadvertently switched the chiller compressor suction and discharge pressure
sensing lines following instrument calibration. The vendor determined that the high
discharge pressure did not damage _the chiller unit. Maintenance initiated corrective
maintenance (CM 9608096) and an action request (CR 9608096) to address the
performance issues. The inspector determined that maintenance supervisors failed
to ensure proper configuration control following pressure sensing line work. In
addition, unlabeled compressor suction and discharge valves contributed to the
misalignment.
M4.4 Quality of Maintenance
a.
Scope
The inspectors observed portions of the 28 emergency diesel generator (EDG)
engine overhaul and reviewed the controlling procedures to assess procedure
adequacy.
b.
Observations and Findings
On August 18, maintenance technicians completed an eighteen-month overhaul on
the 28 l;DG and performed a post-maintenance test run. During the test, operators
noted four cylinders leaking small amounts of fuel around the injector seats.
Technicians removed the injectors to inspect and perform a pressure test on them.
Although the technicians did not see any defects, all four injectors failed the
pressure test. The staff subsequently removed and tested the remaining fourteen
injectors; twelve failed.
Maintenance personnel investigated the cause of the injector seat leakage and the
failure of 1 6 of 18 injectors during the pressure test. The technicians noted that all
injectors had passed the pressure test prior to installation. Technicians determined
11
that inadequate seating caused the leaking. The technicians also determined that
the injectors failed pressure tests because the test pump leaked. In response, they
added a procedure requirement to perform a blue check of the injector seating
surface and replaced the test pump and associated piping. Technicians retested the
injectors and all but one passed. Personnel replaced the defective injector and,
following satisfactory blue checks, reinstalled all injectors.
On August 22, operators commenced a second post-maintenance run and noted
that no injector seat leakage. Operators did detect, however, a slight fuel oil leak
from the fuel line fitting on top of a fl:Jel pump. Technicians found three small paint
chips on the seat area of the tubing. The subsequent EDG run was satisfactory.
The inspectors reviewed the procedure governing the overhaul, SC.MD-PM.DG-
0019 (Q), Diesel Engine Overhaul, Revision 21 and concluded technicians complied
with the procedure. Based on the problems noted above, however, the inspector
noted several deficiencies. The procedure had no guidance for technicians to
calibrate or check for proper operation of the pressure test pump; it lacked adequate
direction to achieve proper injector nozzle seating; and it lacked requirements for
fuel pump fitting cleanliness. The inspectors noted these deficiencies contributed to
EDG unavailability and also permitted a fuel line fitting to become fouled, a
condition that could lead to a clogged fuel line and therefore adversely affect EDG
performance.
The deficiencies are a violation of the requirements of Technical Specification 6.8.1
for written procedures. The inspectors did not cite the non-compliance, however,
because NRC Inspection Report 50-272 & 311 /96-08 issued a violation for other
examples of procedure deficiencies and Salem staff has not had the opportunity to
respond to this issue.
c.
Conclusions
Although maintenance personnel complied with the EDG overhaul procedure,
deficient procedures combined with poor foreign material exclusion, lack of fit
testing for injector seating, and inadequate training for fuel injector testing
contributed to delayed EDG restoration. Salem staff initiated actions to improve the
procedure and Salem management implemented a maintenance training interv~ntion
intended to address training and workmanship deficiencies.
M4.5 Maintenance Staff Knowledge and Performance Conclusions
During the inspection period, maintenance staff demonstrated several examples of
poor planning, workmanship, training, and procedures. Ineffective maintenance
practices have become increasingly evident during the outage. As documented in
NRC Inspection Report 50-272&311 /96-08, during this reporting period Nuclear
Business Unit and Salem senior management initiated a major effort to provide
training for all Salem maintenance staff.
12
Ill. Engineering
E1
Conduct of Engineering
E1 .1
Reliability of Residual Heat Removal (RHRl Valves, NRC Restart Item 111.30 (Open)
a.
Inspection Scope (37551 l
Inspectors reviewed the basis for closure of this package to determine if Salem staff
had corrected valve reliability problems.
b.
Conclusions
Although the MRC accepted this package for closure, the system manager did not
inform them that 22RH29 did not perform reliably during testing on or about August
15, 1996. The 22RH29 valve malfunctioned again on August 30. The inspectors
concluded that plant staff had not determined and corrected the cause for 22RH29
valve malfunctions. This NRC Restart Item remains open pending resolution of
22RH29 malfunctions.
E2
Engineering Support of Facilities and Equipment
E2.1
Pressure Operated Relief Valve (PORVl Seat Leakage, NRC Restart Issue 11.22
(Closed)
a.
Inspection Scope
An inspection of PORV's by PSE&G in April 1994 revealed degradation of the
internal components. The condition included cracking, significant unexpected wear,
and galling. The inspector reviewed the closure package which was prepared by
Salem staff and reviewed by the Salem Management Review Committee (MRC) on
August 20, 1996. The package included root cause analysis documentation,
laboratory test results, industry reliability data and summary information regarding
two Design Change Packages (DCPs). In addition to the closure package
documents,. the inspector also reviewed the completed work documents for the
valve internal replacement work, engineering and vendor information, and test
documents related to post modification testing.
b.
Observations and Findings
The inspector found that the root cause analysis indicated that degraded conditions
of the PORV internals was primarily due to the selection of materials being utilized.
The inspector found that PSE&G had extensive testing conducted in December
1994, where 5 different valve designs were cycled open and closed 2000 times
each. The valve designs varied in the selection of materials used and differed
slightly in physical configuration.
The inspector noted that PSE&G evaluated the
test results and selected the valve design which exhibited the most favorable test
results as replacement components for the Salem Unit 1 & 2 PORV internals.
13
The inspector reviewed the Design Change Package No. 2EE-0083 for the Unit 2
PORV modification and found the information adequate for the proposed change.
The inspector also reviewed the completed work documentation, Work Order No.
950919133 and Work Order No. 950919136, for the installation of the Unit 2
PORV internals. The inspector found the documentation to be adequate. The
inspector reviewed the applicable design drawings and vendor fabrication records to
verify that the internals which were installed were fabricated of the desired material.
Finally, the inspector confirmed that operability testing will be required prior to the
Restart of the Salem Units.
c.
Conclusions
Based on the review of related documents, the inspector concluded that PSE&G has
developed and* implemented a satisfactory corrective action plan for the Salem Unit
2 PORV wear related problems. Corrective action documentation such as the work
orders and DCPs have been generated for the Salem Unit 1 PORV work and
provides reasonable assurance that the PORV internal wear problem will be
satisfactorily resolved for Unit 1 as well. This item is closed.
E2.2
(Closed) Inspector Follow-up Item 50-311/94-11-01, PORV Operability
This issue pertains to the excessive wear and the cracking of the PORV internals. It
is identified as Item 11.22 of the NRC Restart Action Plan for Salem.
The NRC conducted a review of the licensee's actions to address this issue and
found them acceptable. The details of the NRC review are contained in Section
E2.1 of this Inspection Report. This item is closed.
E2.3
Poor Reliability of the Positive Displacement Pumps, NRC Restart Issue 11.18 -
(Open .-Unit 1 , Closed-Unit 2)
a.
Inspection Scope
The Salem Unit 1 & 2 Positive Displacement Pumps (PDPs) have a history of
maintenance and operating problems. In order to improve operational reliability, a
root cause analysis was performed to identify the cause or causes and to prescribe
corrective action for short and long term implementation. The inspector reviewed
the closure package prepared by Salem staff and had been reviewed by the Salem
Management Review Committee (MRC) on June 21, 1996. The package included
the PSE&G root cause analysis documentation and the recommended corrective
action plans and a root cause analysis conducted for PSE&G by an independent
technical consultant. The inspector also met with the Chemical and Volume Control
System (CVCS) system manager to obtain additional information such as
implementing document numbers for maintenance work orders and design change
packages. The inspector reviewed a sample of these implementing documents to
verify completion of the work.
14
b. Observations and Findings
The root cause analysis included a review of the maintenance history for the period
from January 1, 1987 to April 24, 1995. The analysis concluded that the failures
resulted from numerous failure mechanisms. The 'analysis identified five
primary areas for corrective action as follows:
Packing Failures
Pump Valve Cracking Failures
Pump Valve Seat Cracks
PDP Cylinder Block Cracking Failures
Failure of the Suction Stabilizer
The inspector learned that the most frequent failure mode was packing failure.
Packing failures accounted for 49 PDP failures in approximately nine years. Design
changes, DCP 1 S00402 and DCP 2S00303, were implemented early in 1994 to
change the packing style. The inspector reviewed* the operating data and confirmed
that this has resulted in a significant improvement in continuous running time
between packing failures for Unit 2. Running time has increased to over 2500
hours, an increase of about a factor of two. However, the operating data for Unit 1
indicates that although one 3900 hour0.0451 days <br />1.083 hours <br />0.00645 weeks <br />0.00148 months <br /> run was achieved between packing failures,
two subsequent packing related problems indicate that the problem is not resolved.
The inspector reviewed maintenance procedure SC.MD-CM.CVC-0001 (Q),
"Charging Pump Repacking, Plunger & Valve Repair or Replacement", and verified
that changes had been incorporated per the corrective action plan to aid in ensuring
that packing installation is correct and that the initial run-in was successful.
Numerous corrective action items were identified in the closure package which are
intended to reduce the frequency of problems in the other four areas. These include
the following:
Activity
Plans to change the material used for valve
disks.
Design changes to reduce pump nozzle stress
loading.
Procedure changes to S1 (2).0P-SO.CVC-
0002(0), Charging Pump Operation, to
provides a method for venting the pump
discharge.
Design changes to reduce the failure suction
stabilizers.
Status
Design Change Package
identified, not yet complete.
Complete for Unit 2, not
necessary for Unit 1 .
Complete for both Units.
Complete for Unit 2, work
started for Unit 1 .
15
During a review of work order history for Unit 1 and Unit 2 PDPs, the inspector
found there were numerous work orders incomplete for Unit 1, *including one for an
inspection of the pump internals and one for the inspection of the suction stabilizer.
The inspector also found that the Unit 1 pump discharge valves were replaced early
in January, 1993. Because the system manager had pointed out that these valves
have experienced cracking failures after 2 to 3 years of operation, the inspector
noted that these valves were likely to be near the end of their service life. By
comparison, the Unit 2 pump discharge valves were replaced in April, 1995.
The inspector verified that the PDP will be tested to verify proper operation prior to
core load as part of the Salem Restart Test Plan. In addition, future pump
performance will be monitored and trended to assess whether the corrective action
items have been successful in achieving reliable PDP operation.
c. Conclusions
The inspector considered the root cause analysis comprehensive and the corrective
action plan aggressive. Although the effectiveness of the corrective action plan can
only be determined by monitoring future performance, the inspector concluded that
the PDP reliability issue received satisfactory attention and that for Salem Unit 2,
the corrective action items which are complete provide reasonable assurance that
PDP operating reliability will be improved. Because of the continued packing
problems on Salem Unit 1, and because of the incomplete work orders and the
length of time the discharge valves have been in service, the inspector was not able
to reach the same conclusion for Unit 1 . This technical issue is closed for Unit 2
but will remain open for Unit 1 .
E7
Quality* Assurance in Engineering Activities
E7 .1
Management Review Committee (MRC)
a.
Inspection Scope (37551)
b.
Inspectors assessed MRC review of NRC restart inspection item closure packages,
final system readiness reviews, and system affirmations to determine the
effectiveness of the reviews.
Observations and Findings
Early in the inspection period, the MRC inappropriately approved closure of RH29
valve closure package without determining that the controls for the 22RH29 valve
had recently malfunctioned. Later in the period, the MRC did not approve final
affirmation of the radioactive waste gas system readiness, since the system review
team reviewed an uncontrolled operability determination list instead of reviewing the
controlled Condition Resolution Operability Determinations. The MRC appropriately
concluded that the service water system readiness depended on demonstration of
reliable system performance. As recommended by the System Manager, the MRC
concluded that service water was not ready for the final system readiness review
16
since they had not yet observed reliable service water performance.
Members of
the MRC also deferred approval of the final affirmation of 4KV system readiness,
since they identified that each vital bus did not have at least one spare breaker
cubicle in good working order.
c.
Conclusions
The MRC improved the quality of reviews during the inspection period. They
accomplished the improved performance by insuring that MRC membership
consisted of senior Salem managers and through use of specific closure package
review criteria.
Miscellaneous Engineering Issues
E8.1
RHR Pump Minimum Flow Instruments (37551)
a.
Observations and Findings
Inspectors discovered that the Updated Final Safety Analysis Report (UFSAR),
section 6.3.5.3, Flow Indication, Residual Heat Removal Pump Minimum Flow,
states that a flow indicator is installed in each RHR pump minimum flow line. The
inspectors noted that the RHR pump minimum flow line does not have a flow
indicator. The inspectors discussed the lack of a flow instrument with plant staff
from licensing, system engineering, the operations staff (an SRO), and the Salem
General Manager's staff. The licensing staff and the General Manager's staff
appropriately concluded that procedures required them to initiate an Action Request
(AR). The Salem managers concluded that failure to initiate an AR constituted an
additional condition adverse to quality; they initiated an AR to address it.
Inspectors learned from the SRO that flow indication had previously existed for the
RHR minimum flow line, .but plant staff removed it. The inspectors could not
determine, prior to the end of the inspection period, why Salem staff had not
updated the UFSAR to reflect current RHR configuration. This issue will remain
unresolved pending assessment of licensee compliance with 10 CFR 50.59 and 10
CFR 50.71 (e) (UNR 50-272&311/96-10-03).
b.
Conclusions
When inspectors discovered a minor discrepancy between UFSAR description of
RHR minimum flow line instrumentation and actual plant configuration, only two of
four plant staff recognized this as a condition adverse to quality that required them
to initiate an AR. Plant managers subsequently initiated an AR to address the
failures to initiate an AR. The discrepancy between the UFSAR and RHR
configuration will remain unresolved pending inspector assessment of compliance
with 10 CFR 50.59 and 10 CFR 50.71(e) .
17
IV. Plant Support
R1
Radiological Protection and Chemistry {RP&C) Controls
R1 .1
LWR Water Chemistry Control and Chemical Analysis (79701 l
a.
Inspection Scope
Standard chemical solutions were submitted to the licensee for analysis. The
standards were prepared by the Oak Ridge National Laboratory (ORNL) for the NRC
and were analyzed by the licensee using current routine methods and equipment.
The analysis of standards is used to verify the licensee's capability to monitor
chemical parameters in various plant systems (steam generators in the case of this
inspection) with respect to Technical Specifications and other regulatory
requirements. In addition, the analysis of standards is used to evaluate the
licensee's analytical procedures with respect to accuracy and precision. The
standards were submitted to the licensee for analysis in triplicate at three
concentrations spread over the licensee's normal calibration and analysis range.
However, the ammonia standards were analyzed at five concentrations in order to
duplicate the concentrations normally analyzed by the licensee.
b.
Observation and Findings
The results of the standards measurements comparisons indicated that all of the
measurement results were in agreement or qualified agreement under the criteria
used for comparing results. (See Attachment 1 to Table I.) The data are presented
in Table I. The hydrazine and copper analyses were performed in both the primary
laboratory and the secondary laboratory, while the ammonia analyses were
performed in the secondary laboratory only. The primary laboratory is the
laboratory used to analyze reactor systems samples and the secondary laboratory is
the laboratory used to analyze non-reactor systems samples such as steam
generator samples. During shutdown conditions steam generator samples are taken
in containment, and, therefore, the primary laboratory is sometimes used to analyze
these samples for hydrazine and copper.
c.
Conclusion
R2
The licensee accurately quantified the hydrazine, ammonia, and copper in the NRC
standards. Therefore, the licensee can accurately quantify these analyses in steam
generator samples.
Status of RP&C facilities and Equipment
During this inspection, the inspector conducted tours of the plant during outage
conditions and noted that all required radiological postings and locked areas met
regulatory requirements and that the areas were free of safety hazards.
R3
18
RP&C Procedures and Documentation
During this inspection period, the steam generator replacement project staff (SGRP)
was engaged in a planning preparation phase and a review was made with respect
to the radiological safety plans for the project. The SGRP project is intended to
effect the complete replacement of four steam generators at Salem Unit 1 during
the fall of 1996, utilizing replacement steam generators from the mothballed
Seabrook Unit 2 nuclear power plant.
R3.1
a.
Scope (50001)
The inspector reviewed the licensee's planning documents and interviewed
cognizant project staff to determine the adequacy of radiation protection (RP) and
ALARA preparations for conducting the SGRP.
b.
Observations and Findings
The inspector reviewed the licensee's resource commitments and radiological
control plans for the SGRP. The planning documents included incorporation* of
lessons learned from the following SGRPs: Millstone, V.C. Summer, Surrey,
North Anna (1 &2), and Ginna.
\\
At the time of this inspection, the licensee had completed a preliminary exposure
estimate of 164 person-rem. The inspector reviewed the details of the estimate and
determined that no contingency was built into the estimate and that it consisted of
a mixture of detailed project-based estimating and historical information derived
from other SGRPs. As it now exists, this preliminary exposure estimate represents
a challenging exposure standard for the project.
To allow the additional personnel access to the Salem Unit 1 containment, the
SGRP will provide a temporary access facility (T AF) adjacent to the Unit 1 Service
Building to include protective clothing change facilities, RP briefing location, RP
Command Center, and a radiological control area (RCA) access control station.
Additional electronic dosimeters, readers, and electronic turnstiles are planned for
the TAF. In addition, cellular phones will be issued to the work groups to allow for
direct communication with the RP group from the TAF's RP Command Center.
Extensive video camera monitoring of containment work areas is also planned with
three remote monitoring stations located in the RP Command Center.
Mockup training is planned for pipe cutting, beveling, and welding; pipe end
decontamination; and feedwater thermal sleeve modifications. Mockup training and
schedule details were not available for review during this inspection.
At the time of this inspection, approximately 20,000 pounds of temporary lead
blankets were installed in the Unit 1 containment to shield many of the transit paths
and miscellaneous sources. SGRP plans call for an additional 25,000 pounds of
19
lead to be installed around the primary piping, inside severed primary piping, and
around the steam generator platform areas to further reduce working area dose
rates.
The licensee has recently been piloting the use of radiation work permits (RWPs) to
focus on limiting individual RCA entry doses via customized electronic dosimetry
setpoints, and through RP technician dialogue before and after RCA entries with the
workers. This approach is planned to be continued during conduct of the SGRP.
Individual administrative exposure limits have been established at 500 mrem per
year:
The radioactive material control organization has elected to not pursue large-scale
onsite equipment decontamination. The SGRP is considering offsite vendor services
for the decontamination and release of project .equipment and materials.
Work package design included the incorporation of ALARA requirements. Hold
points and records of hold point signoffs were made available to RP/ALARA for use
in the work packages. At the time of this inspection, the work packages had not
been approved and were not available for review.
Detailed RP contingency planning had not been evaluated by the licensee at the
time of this inspection.
For reducing internal exposure hazards, the licensee plans on utilizing eight
2000 cfm HEPA ventilation units for the reactor cooling system (RCS) loop areas.
At the time of this inspection, the licensee had not established a plan for providing
investigational whole body count measurements. Currently-the licensee does not
have the measurement capability onsite, however a memorandum of understanding
exists for providing bioassay services at Brookhaven National Laboratory in
Long Island, New York.
c.
Conclusions
R3.2
a.
The inspector determined that sufficient radiological safety resources have been
planned. The radiological safety planning was ~till being formulated with less than
two months remaining before the project, however, the inspector did not detect any
significant planning deficiencies.
Shipment Classification of Old Steam Generators
Scope (50001)
As of April 1, 1996, the DOT radioactive material shipping regulations were
significantly revised. In particular, a new shipping category of surface contaminated
object (SCO) was defined. The licensee has determined that the four old steam
generators meet the new SCO II definition and can be transported under the new
DOT regulations. The inspector reviewed the licensee's SCO evaluations, DOT
correspondence, and conducted interviews with cogn-izant licensee personnel.
- I
b.
20
Observations and Findings
The licensee determined that the steam generators met the contamination
concentration limits for SCO II through utilizing external dose rate measurements
from the outside of each steam generator and* by taking smear scrapings from the
inside of a steam generator primary manway. The fixed contamination
concentration was determined by computer modeling the steam generator as a
simple cylinder with homogenous air/iron contents and utilizing the highest external
dose reading, and calculating the source radioactivity estimated to produce the
external dose readings. The resultant source activity was divided over the known
surface area of the steam generator tubes and channel heads to determine the
surface contamination concentration. The smear scrapings were analyzed by an
offsite laboratory to determine radionuclide constituents, which were also utilized in
the radioactivity calculations. The licensee determined that the average total
surface contamination for the worst-case steam generator was 3.01 uCi/cm
2 as
compared to the SCO II limit of 20 uCi/cm 2 * The licensee had also determined,
through analysis, that the highest unshielded dose rate at three meters was
410 mrem/hr as compared to the DOT limit of 1000 mrem/hr.
The inspector questioned the accuracy of the computer model method of deriving
the contamination concentration and unshielded dose rate values. In response, the
licensee committed to provide an uncertainty analysis. Also, due to the possibility
of fairly large uncertainty values, the inspector asked if a benchmaking calculation
had been considered utilizing an independent method. The licensee indicated that
there were available steam generator tube samples and that direct measurements
would be made and those survey results would be compared to the computer
calculation results. Future evaluation of this additional information will provide the
basis for evaluating the adequacy of the licensee's classification of the steam
generators as SCO II. The licensee has issued a letter ta the Department of
Transportation (DOT), dated August 5, 1996, providing the preliminary waste
characterization information mentioned above, and an engineering evaluation
concluding* that the steam generators can meet the one-foot drop test as specified
for an Industrial Package 2 package. This letter also requested DOT approval for an
exemption to the packaging requirement of SCOs as specified in 49 CFR
173.427(b)(1 ).
.
c.
Conclusions
While no significant weakness in the licensee's assessment and approach for
handling the eventual shipment of steam generators was detected, additional study
by the licensee and regulatory review of additional characterization remains to
assess the adequacy of the licensee's determination of shipping classification.
21
R3.3
Steam Generator Water Chemistry
a.
Inspection Scope (79701)
The inspectors reviewed the following analytical procedures:
SC.CH-CA.ZZ-0332(Z), Hydrazine by PE Lambda-2 Spectrophotometer,
SC.CH-CA.ZZ-0348(0), Metals by Perkin-Elmer Model 5100 PC Atomic
Absorption Spectrometer, and
SC.CH-Tl.ZZ-0351 (Q), Ion Chromatograph Applications.
b.
Observation and Findings
c.
R4
R4.1
a.
The inspector noted that the above procedures were well written, easy to follow,
and contained sufficient level of detail. The inspector also noted that these
procedures contained QC requirements for verifying analytical results.
Conclusion
Based on the above reviews, the inspector determined that the licensee had very
good analytical procedures to quantify hydrazine, copper, and ammonia in steam
generator water samples.
Staff Knowledge and Performance in RP&C
Radiation Area Access Control
Inspection Scope (71707)
The inspector observed radiologically controlled area access controls and postings.
b.
Observations and Findings
c .
On August 26, 1996, the inspector observed the radwaste truck bay door open, the
associated gate unlocked, and no radiation protection personnel monitoring the
access point. Failure to maintain access point vigilance did not meet radiation
protection managements' expectations for the area. Although the assigned
radiation protection technician lost visual contact of the access point, technicians
had established proper radiation area postings. Radiation protection management
counseled the technician.
Conclusions
A radiation protection technician did not meet managements expectations for
control of access to the radiologically controlled area.
R5
a.
22
Staff Training and Qualification in RP&C
Scope (83750)
Since June 25, 1996, the Salem Radiation Protection Manager (RPM) has been
assigned to a ter:nporary position in the Salem Unit 2 Outage Management group.
The RPM designated the Senior ALARA Supervisor as the acting RPM in his stead.
In addition, the acting RPM has been designated as an alternate RPM member of the
SORC. The inspector reviewed the individual's qualifications for RPM with respect
to regulatory requirements.
b.
Observations and Findings
Salem TS 6.3.1 specifies the RPM qualifications as those contained in Regulatory
Guide 1.8, September 1975. These requirements specify a bachelor's degree in
science or engineering or equivalent, and five years professional experience in
applied radiation protection. The inspector reviewed an RPM qualification evaluation
dated June 26, 1996 that was signed by the current RPM. This evaluation
indicated that a bachelor's degree had not been' completed and indicated that the
individual had accrued nine years of supervisory experience including one year as
the Senior ALARA Supervisor. The inspector noted that the RPM qualification
evaluation form (NC.NA-AP.ZZ-0014-4) required the general manager or a director's
signature when education exemption was granted based on experience. -The
evaluation form was not signed as specified by the procedure. Upon further review
of the individual's resume, it was determined that he acted as an RP Operations
Supervisor and an ALARA Supervisor for a combined period of eight years and that
he has held the position of Senior ALARA Supervisor for the past one year. Based
on the inspector's knowledge of the Salem RP organization, ALARA supervisors are
the technical lead for an RP support area, known at other power plants as lead
technicians. The inspector was not provided enough details of the individual's
activities/duties while acting as a RP Operations and ALARA Supervisor to enable
the inspector to make a specific determination of professional -RP experience. The
need for additional information has resulted in an unresolved item (50-272/96-12-
04), which was communicated by telephone to the station licensing engineer on
August 27, 1996.
The inspector also reviewed the use of RPM duty delegation as applied to SORC
membership. Station procedure (NC.NA-AP.ZZ-0004(0)) indicates that SORC
alternate members should meet the* same qualification requirements as SORC
members. The inspector reviewed a letter dated April 25, 1995 that designated the
subject acting RPM individual as an alternate RPM representative on the SORC.
This letter was supported with a verification of qualification form for RPM dated
April 28, 1995 that referenced ANSI N18.1-1971 as the standard of comparison as
requiring eight years in responsible positions. The subject individual has, since that
time, represented the RPM at SORC meetings.
23
c.
Conclusions
The inspector reviewed two evaluations of an acting RPM individual that determined
the individual to be RPM qualified that were based on two different standards. The
correct standard, Regulatory Guide 1.8, September 1975, was most recently used
with the result that bachelor's degree equivalency was given and a determination
that five years of professional level experience had been met. Station procedure
requirement for General Manager or Director approval was not evidenced. Details of
experience as an RP supervisor require further review in order to verify and validate
the qualifications of the individual.
R6
RP&C Organization and Administration
The inspector reviewed the SGRP staffing plans for the project. The licensee plans
on providing approximately 58 contractor senior RP technicians and 24 contractor
junior/decon RP technicians to provide the additional RP control for the project. The
inspector noted that the licensee intends on utilizing 10 permanent station RP
technicians in lead technician positions and that there will exist an additional pool of
25 contractor RP technicians, assigned to the Unit 2 restart, that may be available if
necessary. The inspector did not note any discrepancy or lack of manpower
associated with the above plans.
R7
Quality Assurance in RP&C Activities
a.
Inspection Scope (79701 l
The laboratory QA/QC programs were reviewed in order to evaluate the licensee's
control with respect to analyzing and evaluating data for the implementation of the
chemical analysis program.
The inspectors reviewed the licensee's Quality Assurance (QA) and Quality Control
(QC) Programs for analytical measurements of chemical parameters in various plant
water samples including, interlaboratory and intralaboratory comparison programs.
The following procedures were reviewed:
- SC.CH-DD.ZZ-0001 (Z),
- SC.CH-DD.ZZ-0006(Z),
- SC.CH-DD.ZZ-0009(Z),
- SC.CH-Tl.ZZ-0901 (Q),
- SC.CH-Tl.ZZ-0902(Q),
- SC.CH-Tl.ZZ0904(Q),
- SC.CH-Tl.ZZ-0905(0),
b.
Observation and Findings
Salem Chemistry Data Trending Program Roles and
Responsibilities,
Technical Calculation Preparation and Validation,
Salem Chemistry Independent Verification Program
Guidelines,
Laboratory Quality Control Program,
Chemical Shelf Life Program,
Laboratory Quality Control Chart Preparation, and
Laboratory Quality Control Chart Evaluation and
Corrective Actions.
The laboratory maintained internal/external QA/QC programs including: (1 l spike
samples; (2) blind samples; (3) intralaboratory comparisons; (4) instrument and
24
procedures control charts; (5) trending and tracking analyses; and (6) QC Reports.
The inspector also noted that when discrepancies were found, reasons for the
discrepancies were investigated, resolved, and reported in QC Reports. During the
review, the inspector noted that the licensee used actual matrix samples (e.g., SIG
water) for preparing QC spike samples. The inspector stated that this was the best
method to evaluate analytical technique and capability because the analyst could
encounter the chemical interferences present in actual samples.
During a discussion with the Chemistry staff, the inspector noted that the
responsible individuals had very good knowledge in the areas of: ( 1) importance of
QA/QC; (2) plant water systems; (3) potential chemical interference in various
system water samples; and (4) validating of measurement results.
c.
Conclusion
Based on the above reviews and discussions, the inspectors determined that the
licensee had excellent laboratory QA/QC programs.
RS
Miscellaneous RP&C Issues
RB. 1
Other Issues Previously Identified
(Closed) Violation 50-272/96-01-05:
During late 1995, the licensee reported several instances of entering the RCA
without electronic dosimetry monitoring and other related access control procedure
violations. The repetitive nature of these procedure violations resulted in issuance
of a violation against 10 CFR 50 Appendix B, Criteria XVI, failure to provide
effective corrective actions to prevent recurrence.
a.
Scope (83750)
During this inspection, the inspector reviewed the licensee's root cause and
corrective actions associated with the violation as well as verified completion of the
corrective actions.
b.
Observations and Findings
The result of the licensee's investigation determined that there had been 17
recorded instances of RCA access control procedure violations during 1995.
Several root causes were identified that were all associated with human
performance weaknesses. Corrective actions included incorporating two software
changes in the electronic dosimeter reader program that resulted in producing
dosimeter alarms if an electronic dosimeter is removed from the battery charger rack
and is not placed into a reader within three minutes, and in causing the dosimeter to
alarm if the dosimeter is left in the reader for more than four seconds after
completing sign-in to the RCA. Additionally, positive control electronic turnstiles
were installed at the entrance to the RCA and at the exit from the protective
25
clothing change area. To access the station radiological controlled area requires
passage through an electronic gate turnstile. In order to unlock the turnstiles, an
electronic dosimeter must be inserted and if the dosimeter is found to be activated
and functional, the gate is unlocked permitting entry. During this inspection, the
inspector verified that the above changes had been completed.
To alert the workers of this plant access change, a training video will be developed
to be shown to radiation workers during general employee training. The training
video had not been completed at the time of this inspection. The licensee projected
a completion date of September 15, 1996 for producing the video training aide.
c.
Conclusions
The inspector determined that establishing the electronic locking turnstiles at the
RCA entrance provided substantial positive control over workers accessing the RCA
to ensure each worker's exposure is monitored by an electronic dosimeter. Two
software system modifications were made that served to enhance worker
performance during RCA entry procedures. Although the training video has not
been completed, the inspector determined that all of the controls necessary to
prevent recurrence of the violation have all been completed and were verified to be
in place. This violation is closed.
R8.2
Review of UFSAR Commitments
A recent discovery of a licensee operating their facility in a manner contrary to the
Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a
special focused review that compares plant practices, procedures and/or parameters
to the UFSAR descriptions.
While performing the inspection discussed in this report, the inspector reviewed
Section 12.3 of the Salem Station UFSAR that related to the areas inspected. The
inspector verified that the UFSAR wording was consistent with the observed plant
practices, procedures and/or parameters.
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 September 18, 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 .
TABLE I
Salem Chemistry Test Results
Chemical
Method of *
NRC Known **
Analysis
Analysis
Hydrazine
(Secondary Lab
Analysis)
Ammonia
(Secondary Lab
Analysis)
(Secondary Lab
Analysis)
Hydrazine
(Primary Lab
Analysis)
(Primary Lab
Analysis)
- Methods:
AA= Atomic Absorption
IC= Ion Chromatography
Value
34.1 +/-0.5
56.1+/-1.0
68.2+/-1.0
22.0+/-0.8
30.5+/-0.8
48.2+/- 1.2
110+/-4
305+/-8
40.4+/-0.6
80.6+/-1.2
162+/-3
34.1 +/-0.5
56.5+/-1.0
85.2+/-1.2
40.4+/-0.6
80.6+/-1.2
162+/-3
SP= UV-Vis Spectrophotometry
Licensee **
Value
' 34.97 +/- 0.15
55.9+/-0.7
68.8+/-0.4
22+/-2
31.0+/-1.1
48.3+/-0.5
102+/-2
283'+/-6
34.3+/-1.5
89+/-2
167+/-3
34.8+/-0.4
57.1+/-0.4
86.9+/-1.1
41+/-3
76.3+/-1.5
160+/-4
All reported uncertainties are +/- one standard deviation (1 s).
Comparison
Agreement
Agreement
Agreement
Agreement
Agreement
Agreement
Agreement
Agreement
Qualified
Agreement
Agreement
Agreement
- Agreement
Agreement
Agreement
Agreement
Agreement
Agreement
ATTACHMENT 1 TO TABLE I "
Criteria for Comparing Analytical Measurements from Table II
This attachment provides criteria for comparing results of capability tests. In these criteria
the judgement limits are based on data from Table 2.1 of NUREG/CR-5244, "Evaluation of
Nonradiological Water Chemistry at Power Reactors". Licensee values within the plus or
minus two standard deviation range { +/- 2Sd) of the ORNL known values are considered to
be in agreement. Licensee values outside the plus or minus two standard deviation range
but within the plus or minus three standard deviation range { +/- 3Sd) of the ORNL known
values are considered to be in qualified agreement. Repeated results which are in qualified
agreement will receive additional attention. Licensee values greater than the plus or minus
three standard deviations range of the ORNL known value are in disagreement. The
standard deviations were computed using the average percent deviation values of each
analyte in Table 2.1 of the NUREG.
The ranges for the data in Table I are as follows.
Agreement
Qualified Agreement
Analyte
Range
Range
+/- 8%
+/- 12%
Fluoride
+/- 12%
+/- 18%
Sulfate
+/- 10%
+/- 15%
Silica
+/- 10%
+/- 15%
+/- 14%
+/- 21 %
+/- 10%
+/- 15%
+/- 10%
+/- 15%
+/- 2%
+/- 3%
Ammonia
+/- 10%
+/- 15%
Hydrazine
+/- 10%
+/- 15%
+/- 14%
+/- 21%
IP 50001:
IP 61726:
IP 62707:
IP 71707:
IP 79701:
IP 83750:
INSPECTION PROCEDURES USED
Steam Generator Replacement
Surveillance Observations
Maintenance Observations
Plant Operations
LWR Water Chemistry Control and Chemical Analysis-Program
Occupational Radiation Exposure
ITEMS OPENED, CLOSED, AND DISCUSSED
50-272&311 /96-12-01
50-272&311 /96-12-02
50-272&311 /96-12-03
50-272&311/96-12-04
IFI
Ineffective corrective action
Inspector followup of SW operation
RHR flow instrument not present as stated in UFSAR
Acting radiation protection manager qualifications
Closed
50-272/96-01-05
Repetitive RCA access control procedure violations
'*
IV
NRC
PSE&G
RP&C
sco
SNSS
SORC
TS
LIST OF ACRONYMS USED
As Low As Reasonably Achievable
- Department of Transportation
Independent Verification
Nuclear Shift Supervisor
Nuclear Regulatory Commission
Oak Ridge National Laboratory
Public Document Room
Public Service Electric and Gas
Quality Assurance
Quality Control
Radiological controlled area
Radiation Protection
Radiological Protection and Chemistry
Radiation Protection Manager
Radiation Work Permits
Surface Contaminated Object
Steam Generator Replacement Project
Senior Nuclear Shift Supervisor
Station Operations Review Committee
Senior Reactor Operator
Temporary Access Facility
Thermoluminescent dosimeter
Technical Specification
Updated Final Safety Analysis Report
Work Order