ML20129D089
| ML20129D089 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 10/18/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20129D067 | List: |
| References | |
| 50-354-96-07, 50-354-96-7, NUDOCS 9610240196 | |
| Download: ML20129D089 (40) | |
See also: IR 05000354/1996007
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket No:
50-354
License Nos:
Report No.
50-354/96-07
Licensee:
Public Service Electric and Gas Company
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Facility:
Hope Creek Nuclear Generating Station
Location:
P.O. Box 236
Hancocks Bridge, New Jersey 08038
Dates:
August 4,1996 - September 21,1996
Inspectors:
R. J. Summers, Senior Resident Inspector
S. A. Morris, Resident inspector
N. T. McNamara, Emergency Preparedness inspector
F. J. Laughlin, Emergency Preparedness Inspector
A. L. Della Grecca, Senior Reactor inspector
D. A.Jaffe, Senior Project Manager
Approved by:
Larry E. Nicholson, Chief, Projects Branch 3
Division of Reactor Projects
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9610240196 961018
ADOCK 05000354
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EXECUTIVE SUMMARY
Hope Creek Generating Station
NRC Inspection Report 50-354/96-07
This integrated inspection included aspects of licensee operations, engineering,
maintenance, and plant support. The report covers a 7-week period of resident inspection;
in addition, it includes the results of announced inspections by regional inspectors in the
Emergency Preparedness area; follewup inspection activities in engineering support and
operations; and, a program assessment of the 50.59 process by the NRR project manager.
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During the report period, a security program inspection was conducted by region-based
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specialist inspectors; however, the details of that inspection are contained in NRC
Inspection Report 50-354/96-08.
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Operations
Operators responded appropriately to an inadvertent reactor core isolation cooling system
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isolation. Despite their inability to establish a definitive root cause, good engineering
department involvement in troubleshooting the suspected instrument drawer ensured
prompt restoration of the RCIC system to operability. A strong determination to promptly
identify the component failure mechanism was also evident. (Section 01.2)
Station operators exhibited good awareness and questioning attitude in the identification of
a minor steam leak in a normally inaccessible area of the reactor building. Engineering
personnel developed an appropriate safety evaluation to address an abnormal valve
configuration that temporarily minimizes the impact of the noted steam leak. (Section
01.3)
Although the initial response to a potential tampering event at Salem appeared to be
minimal, subsequent actions, including direct communication of management expectations
and the development of an operational directive for reacting to suspected tampering events
were thorough. Verification of the operability of remote shutdown equipment following a
suspected sabotage event at another utility was timely and comprehensive. (Section 04.1)
Though a plant operator failed to self-check prior to implementing an important step in a
procedure, no damage to safety related equipment resulted and licensee response to the
event was good. (Section 04.2)
SORC activities were conducted in accordance with plant technical specifications. In
addition, SORC questions were of sufficient depth to ensure that station activities were
conducted safely. (Section 07.1)
The corrective action program performance indicators were effective for monitoring
problems identified by station personnel and in ensuring that timely corrective actions were
taken. (Section 07.2)
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Maintenance / Surveillance
Control and conduct of maintenance and surveillance activitics was good. Similarly,
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procedure adherence was good. Schedule adherence, especially for significant on-line
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activities, like the "A" emergency diesel generator, and response to emergent work was
good. (Section M1.1)
Plant operators exhibited a timely and conservative response to indications of improper oil
in two residual heat removal pump motor bearings. Good coordination with maintenance
technicians resulted in the prompt restoration of affected equipment. Root cause
assessment and corrective actions were comprehensive. (Section M2.1)
The backlog of corrective maintenance activities is high; however, licensee management
has continuously assessed the backlog for impact on Operations and prioritization of
maintenance. (Section M2.2)
Operator recognition of inoperable drywell leak detection system instrumentation that
required a plant shut down was not timely; however, the condition was subsequently
recognized avoiding any violation of the plant technical specifications. Subsequent
response was appropriate, including prompt implementation of TS-required actions and
documentation of the event in accordance with the corrective action program. (Section
M4.1 )
Enaineerina
PSE&G's framework for the 10 CFR 50.59 program was generally good. Two examples of
changing the plant without an appropriate 10 CFR 50.59 evaluation were identified and
resulted in a violation of NRC regulations. (Section E1.1, E1.2 & S8)
Plant operators modified the controls of a safety related component (valve 1EGHV-2522E),
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without use of proper engineering support to assess if this resulted in either a necessary
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change to the plant technical specifications or an unreviewed safety question. Once this
concern was identified, operators restored the valve to its normal configuration in a timely
manner. (Section E1.2)
Operators exhibited a good, conservative desire to maximize overall service water system
reliability due to the impending severe weather by requesting engineering personnel to
devise a means to restore the function of an associated subsystem made inoperable by
partialimplementation of a design change package. However, a review of the
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documentation associated with the modification to satisfy the operations department
request highlighted weaknesses in the process for controlling and justifying design change
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package revisions. (Section E2.1)
The NAP-59 procedure for addressing the 10 CFR 50.59 process is well written, provides
clear assignment of responsibility, and provides the user with good directions. (Section
E3.1)
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Certain aspects of the training program for 10 CFR 50.59 were good; however,
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qualification requirements had not yet been developed to ensure that personnel involved in
the use of 10 CFR 50.59 had been appropriately trained. (Section E5.1)
The Offsite Safety Review Group review of safety evaluations were not consistently-
performed. PSE&G's corrective actions for similar prior findings were ineffective at Hope
Creek in that sponsoring organizations at Hope Creek continued to be inconsistent in
providing safety evaluations for OSRG review. Finally, the OSRG lacked reasonable
initiative in ensuring that they received these safety evaluations from the sponsoring
organizations. (Section E7.1)
Plant Suooort
The inspectors conducted numerous tours of the facility and noted that all required
radiological postings and locked areas met regulatory requirements. Further, areas were
clear of unnecessary equipment, wellilluminated and free of safety hazards. (Section R2)
While some activities associated with effluent grab sampling and analysis were not
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conducted in a timely manner, overall performance of radiation protection program
requirements were good. (Section R4)
A QA department audit of the radioactive waste program met the requirements of the Hope
Creek technical specifications and provided good self-assessment of this area. (Section
R7)
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PSE&G maintained an adequate emergency preparedness program. The emergency plan
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and implementing procedures were current and effectively implemented. The emergency
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facilities, equipment, instruments and supplies were maintained in a state of readiness. All
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required 1995 and 1996 surveillance tests were completed. In the past six months, there
have been EP management and organizational changes and it appears that these changes
have not had an adverse effect on the EP program. A sampling of emergency response
organization (ERO) personnel training records indicated that training qualifications were
current. Routine verification that specified ERO personnel have maintained respirator
requalification training was not being conducted. Reports indicated that quality assurance
audits were thorough and satisfied NRC requirements. (Section P)
PSE&G's implementation of a design change package to replace the Hope Creek fire
protection computer was generally acceptable, although interim compensatory measures
were not properly evaluated to ensure that no unreviewed safety question existed.
(Section F2)
Based on observed drill response, the inspectors concluded that the compensatory
measures were effective in providing appropriate fire panel indication and alarm information
-to the control room for response to postulated fires in the f acility. (Section F4)
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TABLE OF CONTENTS
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EX EC UTIV E S U M M ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii
TABLE O F CO NTENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vi
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1. O pe r a t io n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
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11. M a i nt e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
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lli. Engineering
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I V. Pl a nt S u ppo rt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
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V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
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Report Details
Summarv of Plant Status
Hope Creek began the inspection period at 100 percent power. Full power operations were
maintained throughout the period spanning August 4,1996 to September 21,1996,
except for minor power reductions to support maintenance and testing activities.
1. 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
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and safety-conscious; specific events and noteworthy observations are detailed in
the sections below.
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01.2 , Reactor Core Isolation Coolina System Isolation
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a.
insoection Scope (71707,62707)
The inspectors observed PSE&G's response to an engineered safety feature
actuation that resulted in an automatic isolation of the reactor core isolation cooling
(RCIC) system,
b.
Observations and Findinas
On August 21,1996, the RCIC system steam inlet valve and turbine trip throttle
valve both closed in response to an isolation signal generated by the steam leak
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detection system. Station operators surmised that the actuation was the result of
an instrumentation failure since a prompt inspection of the RCIC equipment room
indicated that all conditions were normal. Operators verified that the system
responded as expected to the isolation signal, implemented the applicable LCO
action statements per TS 3.7.4, and reported the occurrence to the NRC operations
center as required by 10 CFR 50.73. The inspectors witnessed appropriate concern
by station management in response to this event, specifically because members of
the TS surveillance improvement project were coincidentally reviewing the adequacy
of past operability testing of the high pressure coolant injection system.
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Initial troubleshooting by maintenance technicians identified multiple hardware
problems on various cards internal to the RCIC system "NUMAC" instrumentation
and control drawer, the device which houses the steam leak detection and actuation
logic. However, the engineering department system manager subsequently
determined that none of the discrepancies identified should have resulted in the
observed RCIC system isolation. Discussions with the NUMAC vendor and a search
of industry operating experience data, though a good initiative, did not assist in
finding the root cause of the condition. Additionally, a search of maintenance
history on other installed NUMAC drawers at Hope Creek determined that no
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adverse equipment performance trend was evident. In order to minimize the duration
of the unplanned RCIC system outage, station management elected to replace the
entire NUMAC drawer with a spare. The inspectors observed that subsequent
instrument calibration and testing was completed satisfactorily. The RCIC system
was inoperable for less than two days.
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PSE&G engineering personnel stated that, because of the inconclusive
troubleshooting, and because much of the internal functional design of the
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component is proprietary, the suspect NUMAC drawer would be shipped to the
vendor for additional testing and root cause analysis.
c.
Conclusion
Operators responded appropriately to an inadvertent reactor core isolation cooling
system isolation. Despite their inability to establish a definitive root cause, good
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engineering department involvement in troubleshooting the suspected instrument
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drawer ensured prompt restoration of the RCIC system to operability. A strong
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determination to promptly identify the component failure mechanism was also
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evident.
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01.3 Steam Leak From Main Steam Line Drain Pioina
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a.
Insoection Scoce (71707,37551)
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The inspectors observed the process by which a small steam leak in the steam
tunnel was identified and (temporarily) resolved, including the steps taken by the
operations department to locate the source of the leak and the follow up analysis
performed by engineering personnel to justify a temporary change in an established
isolation valve line up.
b.
Observations and Findinas
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On August 7,1996, sYation operators detected a slight rising trend on the reactor
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building exhaust ventilation radiation monitor. Operators subsequently correlated a
slowly rising steam tunnel temperature indication to the reactor building exhaust
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readings. Suspecting a steam leak, operations, engineering, and radiation protection
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department personnel coordinated an effort which ultimately resulted in a
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determination that the source of the leak was from main steam line drain piping.
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Operators closed the drain line outboard containment isolation valve,1 ABHV-F019,
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and placed it under administrative control (caution tag); this action resulted in an
immediate reduction in steam tunnel temperature and reactor building exhaust
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radiation levels.
Because thorough investigation and repair of the drain line piping would result in
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relatively high exposures to personnel in the vicinity, station management elected to
defer the corrective maintenance until an outage of sufficient duration. As a result,
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since the UFSAR indicates that the 1 ABHV-F019 valve is open during normal
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operation, engineering appropriately prepared a 10 CFR 50.59 safety evaluation for
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the extended temporary condition during which the valve would remain closed. The
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inspectors reviewed the evaluation and observed the station operations review
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committee (SORC) deliberations on the merits of the assessment, and judged both
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to be appropriately focused on the design and safety implications. The evaluation
was approved primarily since the valve remained operable (even though closed), and
that it was placed in its design basis (safe) position.
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c.
Conclusion
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Station operators exhibited good awareness and questioning attitude in the
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identification of a minor steam leak in a normally inaccessible area of the reactor
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building. Engineering personnel developed an appropriate safety evaluation to
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address an abnormal valve configuration that temporarily minimized the impact of
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the noted steam leak.
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Operator Knowledge and Performance
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04.1 Station Response to Potential Tamoerina Events
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Insoection Scope (71707. 71750)
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The inspectors reviewed the Hope Creek operations department response to reports
and indications of suspected or actual tampering events at other commercial nuclear
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b.
Observations and Findinas
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On August 7,1996, just prior to shift turnover, the Hope Creek senior nuclear shift
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supervisor-(SNSS) was informed by his Salem station counterpart that Salem
operators discovered mis-positioned valves (closed versus locked open) in a safety
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system, and that tampering was being considering as a possible explanation. The
inspectors initially learned of the event from the relieving SNSS during his plant
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status briefing to station management. Based on a initial perception of minimal
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interest in this issue, the inspectors subsequently questioned the operating shift on
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their response to this issue, and, upon noting little appreciation of the nature of the
issue by shift personnel, expressed the concern to senior PSE&G management.
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Before substantive actions could be implemented, Hope Creek management learned
that the Salem issue had been traced to a status control error in the tagging system.
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However, shortly afterward, the operations department issued a draft directive that
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provided specific guidance for expected operations response to suspected tampering
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events. Additionally, the inspectors noted that management expectations for
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handling tampering concerns were clearly expressed to the operating shifts,
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including an entry in the " night orders."
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On August 15,1996, Hope Creek management learned that an Unusual Event was
declared at the St. Lucie plant in Florida because of suspected sabotage of the
remote shutdown system (glue found in various keylock switches, rendering them
inoperable). The inspectors witnessed an excellent response to this event.
Specifically, the event was promptly communicated to appropriate station personnel
with emphasis on its potential consequences, and, more significantly, the operations
department conducted a comprehensive walkdown of all remote shutdown
equipment at the station using the applicable integrated operating procedure as a
guide. No discrepancies were found.
Later, on August 28,1996, Salem reported to the Hope Creek SNSS that mis-
positioned switches on safety-related battery chargers at Salem appeared
suspicious, and that tampering had not been ruled out. The inspectors noted that,
despite a subsequent determination that tampering was not involved, the Hope
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Creek operations department response was prompt and thorough, and followed the
expectations outlined in the newly established directive,
c.
Conclusions
Although the initial response to a potential tampering event at Salem appeared to be
minimal, subsequent actions, including direct communication of management
expectations and the development of an operational directive for reacting to
suspected tampering events were thorough. Verification of the operability of
remote shutdown equipment following a suspected sabotage event at another utility
was timely and comprehensive.
04.2 Ooerator Error Durina Post-Maintenance Testina of the "A" Emeraency Diesel
Generator
The inspectors reviewed an event on September 4,1996, involving an operator
error. At the time, post-maintenance testing was in progress on the "A" emergency
diesel generator. An equipment operator was about to remove the EDG from
service, which involved opening the output breaker. However, instead of opening
the output breaker, the operator erroneously pressed the engine stop button. This
caused the engine to stop with the generator output breaker still closed.
Subsequently, the output breaker opened automatically on a reverse power
condition (as designed). No damage to the equipment occurred as a result of this
event because the automatic breakers controls performed appropriately.
The inspector observed that the licensee treated this condition seriously and
performed an acceptable review of the causes for the operator error and to establish
the extent of damage to the equipment.
The inspector concluded that while the operator failed to self check prior to
implementing an important step in a procedure, no damage to safety related
equipment resulted and licensee response to the event was good.
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06
Operations Organization and Administration
06.1 Operations Department Manaaement Chanae:
Just after the close of the inspection period, the licensee announced that the
Operations Department Director resigned from the organization. The department
management responsibilities will be temporarily charged to the Operating Engineers.
The operating shifts will continue to report to H. Hanson, Acting Operations
Manager and current SRO-license holder. The licensee plans to recruit a
replacement for the Operations Department Director.
07
Quality Assurance in Operations
07.1 Station Operations Review Committee (SORC) Meeting Observations
The inspectors observed several routine SORC meetings during the inspection
period. The inspectors verified that the SORC membership requirements of the
plant technical specifications were met. The observed discussions were of
excellent quality. Noteworthy examples included discussions on: operability
determinations; the aggregate impact of degraded, but operable equipment; review
of an event involving observed leakage from the emergency overboard discharge
line of the service water system; and, review of the plans for retiring certain
radioactive waste handling equipment.
The inspectors concluded that the SORC activities were conducted in accordance
with plant technical specifications. In addition, SORC questions were of sufficient
depth to ensure that station activities were conducted safely.
07.2 Station Corrective Action Proaram (CAP) Performance Indicators
The inspectors reviewed the current CAP performance indicators for the months of
July and August,1996. Improved performance was noted in schedule adherence
for corrective actions, for example 98 percent of the scheduled corrective actions
for August were completed on time. The average time to complete corrective
actions (57 days) remained within the licensee's goals; and, the number of overdue
corrective actions was reduced from 60 in July to 10 in August.
The inspectors concluded that the licensee's CAP performance indicators were
effective for monitoring problems being identified by station personnel and in
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ensuring that timely corrective actions.
08
Miscellaneous Operations issue
08.1 (Closed) LER 50-354/96023: Reactor Core Isolation Cooling system isolation due to
a failed steam leak detection monitor. This issue is discussed in detail in section
01.2 of this report. No new issues were revealed by this LER.
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08.2 (Closed) URI 50-354/93-11-01: This item involved apparent deficiencies in the
licensee's corrective action program. The licensee subsequently modified this
program in July 1995, with additional minor improvements being noted by the
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inspector since that time. The NRC has evaluated the licensee's program
implementation and determined that the deficiencies identified in this prior
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inspection have been corrected.
08.3 (Closed) Violation 50-354/94-09-04: mis-operation of the refueling bridge. The
inspector verified the corrective actions described in the licensee response letter,
dated December 8,1994, to be reasonable and complete. Further, it was noted
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during the most recent refueling outage that no similar event occurred.
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08.4 _(Closed) Soecial Reoort 50-354/94-003-01: operation of the facility in excess of the
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licensed thermal power limits. This was a required supplemental report of two
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events of operation above licensed thermal power limits. While additional
assessment of the significance of these events and revised corrective actions were
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provided, no new significant issue were revealed by the supplemental report. The
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inspector considered the corrective actions to be reasonable and complete.
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11. Maintenance
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Conduct of Maintenance
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M1.1 General Comments
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a.
Insoection Scope (62703 and 61726)
The inspectors observed all or portions of the following work activities:
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"D" service water pump replacement
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1CD-447125 Volt battery cell equalizing charge
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service water traveling screen on-line maintenance
high pressure coolant injection jockey pump repairs
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"A" emergency diesel generator on-line maintenance
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modification of the Hope Creek fire protection computer per DCP 4EC-3296
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Bailey module replacement affecting allindication and control for non-1E
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breakers
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reactor core isolation cooling system NUMAC drawer replacement
south plant vent flow monitor repairs
electrical backseating of valve 1 ABHV 2016B
The inspectors observed all or portions of the following surveillance procedure (s):
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high pressure coolant injection jockey pump check valve in-service test
"B" service water pump in-service test
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b.
Observations and Findinas
in general, the inspectors found that the work performed during the conduct of the
above noted maintenance and surveillance activities were in accordance with
approved station procedures and work control programs.
Pre-job work briefings were observed to be appropriate for the planned tasks. The
inspectors frequently observed maintenance supervisors and system engineers
monitoring the activities and providing necessary support. When applicable
appropriate radiation protection controls were observed to be followed.
The inspectors noted that on-line maintenance activities were conducted in
accordance with pre-approved risk-based work schedules and LCO maintenance
plans. For example, the "A" emergency diesel generator on-line maintenance
activities were completed an hour prior to the planned activity schedule.
The inspectors observed that the licensee continued to self-assess the
implementation of the work week schedules and when necessary, provide corrective
actions to prevent recurrence of significant scheduler problems.
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Emergent work activities, like the repeat failures of the south plant vent monitor,
and the failure of the RCIC NUMAC drawer, were appropriately controlled, and
where applicable, associated plant technical specification action statements
implemented. While some planned activities were interrupted by the emergent
work, the inspectors noted that overall schedule adherence was very good
throughout the inspection period.
The licensee appropriately implemented 10 CFR 50.59 controls in support of the
electrical backseating of valve 1 ABHV-20168. This valve is a main steam system
valve that provides steam flow to the "B" steam jet air ejector. The licensee
determined that the valve packing had a steam leak that was worsening. The
backseating of the valve reduced the steam leakage considerably and restored
environmental conditions in the steam tunnel and turbine building to normal. The
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inspector observed the SORC review of the associated 10 CFR 50.59 safety
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evaluation and found the level of questioning to be appropriately detailed.
c.
Conclusions
The inspectors concluded that the control and conduct of maintenance and
surveillance activities was good. Similarly, procedure adherence was good.
Schedule adherence, especially for significant on-line activities, like the "A"
emergency diesel generator, and response to emergent work was good.
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M2
Maintenance and Material Condition of Facilities and Equipment
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M2.1 Imorooer Oil Discovered in Residual Heat Removal Pumos
a.
Insoection Scope (62707)
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The inspectors reviewed and evaluated PSE&G's response to a self-identified
condition in which an incorrect oil type was discovered in the residual heat removal
(RHR) system pumps.
b.
Observations and Findinas
On August 14,1996, while performing a post-maintenance surveillance run of the
"C" RHR pump, operators observed an abnormal oil level condition on the pump's
upper motor bearing concurrent with a " burning" smell. The pump was promptly
secured and declared inoperable. Technicians determined that a small amount of oil
had leaked down from the upper bearing area into the motor. This condition was
subsequently corrected. In addition, oil samples were taken from both upper and
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lower bearing oil sumps. This analysis identified that the lower bearing sump
contained an oil type not permitted by station configuration control documents.
Upon learning of the discrepancy, maintenance technicians replaced the improper oil
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with the correct type. Operations initiated an action request to address causal
factors and required the oil in the redundant RHR pump motors (as well as core
spray, SACS and service water) be sampled to determine the extent of the adverse
condition. It was later determined that the "A" RHR pump motor was similarly
affected. Concurrently, specialty engineering personnel provided an assessment of
pump motor operability and concluded that the use of the incorrect oil in the RHR
motor bearings would not adversely impact pump reliability or functionality. In spite
of this assessment, plant operators, upon restoration of the "C" RHR pump,
voluntarily removed the "A" RHR pump from an operable status to replace the
improper oil in the motor bearing. The inspectors observed good coordination
between operations and maintenance personnel during the ensuing work and the
RHR pump was promptly restored to service.
The inspectors reviewed the root cause assessment performed by engineering
personnel in response to this event and concluded that it thoroughly addressed the
relevant issues in their recommended corrective actions. Specifically, engineering
determined through a search of work order history that the wrong oil had been used
during recent motor bearing oil changes. Several factors that likely contributed to
this improper oil substitution, including the use of similar oil storage containers and
storage locations, were all adequately addressed to preclude recurrence of this
condition. Use of the wrong oil was considered a violation of station procedures;
however, the oilin question did not adversely affect the equipment and the concern
was both timely identified and corrected by the licensee. This licensee-identified
and corrected violation is being treated as a Non-Cited Violation, consistent with
Section Vll.B.1 of the NRC Enforcement Poliev.
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c.
Conclusions
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Plant operators exhibited a timely and conservative responce to indications of
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with maintenance technicians resulted in the prompt restoration of affected
improper oil in two residual heat removal pump motor beaiings. Good coordination
equipment. Root cause assessment and corrective actions were comprehensive.
M2.2 Maintenance Backloas
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The inspectors reviewed the maintenance backlog during the inspection period and
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the licensee's response in order to maintain the outstanding workload to a
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a
reasonable level. As of September 9,1996, the non-outage backlog of corrective
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maintenance (CM) activities was about 1400 activities, with a goal of about 400 by
}
Refueling Outage 7 (currently scheduled for September 1997). The backlog of
overdue non-outage preventative maintenance (PM) activities was about 130
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activities, with a goal of O overdue by November 1996. Due to recent emphasis on
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reducing the overdue PM backlog, the CM backlog remained about the same over
the last few inspection periods. Of the non-outage backlog activities, approximately
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450 of the work orders were on-hold for various reasons, including: about 100 on-
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hold for parts, and about 250 on-hold for engineering support. This exceeded the
station goal of having no more than 150 work orders on-hold.
,
While the backlogs were consistently above the licensee's expectations throughout
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I
the inspection period, the inspectors noted the following: (i) work-week schedule
adherence has improved and remained above 90% adherence throughout the
inspection period; and, (ii) licensee efforts to reduce the overdue PM backlog has
been effective. Once the overdue PM backlog is eliminated, additional resources
will be available to begin a reduction of the CM backlog, in the interim period, the
inspectors observed increased management focus and assessment to ensure that
the backlog is a station priority and to assess the impact of the outstanding work on
safe operations. As an example, all cms associated with control room indicators
and alarms are considered a high priority and receive special management.
However, the number of control room deficiencies remains high.
The inspectors concluded that the outstanding corrective maintenance work is high;
however, licensee management has continuously assessed the backlog for impact
on operations and prioritization of maintenance.
M4.1 Both Channels of Drvwell Leak Detection Inocerable
a.
Insoection Scooe (71707,62707,61726)
The inspectors reviewed and evaluated the operations department response to a
self-identified event in which both channels of the drywellleak detection system
instrumentation were discovered to be simultaneously inoperable.
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b.
Observations and Findinas
On August 23,1996, while Hope Creek maintenance technicians were performing a
surveillance test on the drywell leak detection (DLD) system noble gas radiation
monitor, radiation protection department personnel noted that the drywell floor drain
sump flow instrument indicated an " operate failure." After receiving this report,
plant operators reviewed the alarm chronology print out in the control room and
determined that the floor drain sump flow monitor had failed 36 minutes earlier.
The shift supervisor quickly determined that, as a result of this instrument failure, in
combination with the redundant channel of DLD being inoperable (due to the in-
progress surveillance on the noble gas monitor), the station did not satisfy the
requirements of TS 3.4.3.1 (RCS Leakage Detection Systems). Action "d" of this
TS mandates that the plant be placed in hot shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
Despite the good questioning attitude exhibited by radiation protection personnel in
this event, the inspectors judged that plant operators failed to recognize the
inoperable floor drain instrument in a timely manner. The shift supervisor
determined that 36 minutes had passed from the time when the station should have
recognized the hot shut down action statement until the condition was recognized.
An additional twenty minutes passed until maintenance technicians could
successfully complete the DLD noble gas monitor surveillance, effectively
terminating the hot shut down requirement about an hour after it began.
Operations department follow up to this adverse condition was appropriate. The
" pre-planned manual calculation" for quantifying floor drain cump in-leakage per TS 3.4.3.1 action a.1 was properly implemented until the floor drain monitor was
repaired. In addition, the operators involved in this event initiated an action request
in accordance with PSE&G's corrective action program, and developed a list of
" lessons learned" from the event that was promptly communicated to all of the
other operating shifts. Significant among the issues raised in this "self-assessment"
was a reinforcement of the expectation that reactor operators question the validity
of each alarm received on the radiation monitoring system display; in the noted
event the inspectors learned that an operator acknowledged the alarm indicating the
initial failure of the floor drain instrument but (in part) assumed that it was attributed
to the in progress surveillance on the noble gas monitor,
c.
Conclusions
Operator recognition of inoperable drywell leak detection system instrumentation
that required a plant shut down was not timely; however, the condition was
subsequently recognized avoiding any violation of the plant technical specifications.
Subsequent response was appropriate, including prompt implementation of TS-
required actions and documentation of the event in accordance with the corrective
action program.
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M8
Miscellaneous Maintenance issues
M8.1 (Closed) Violation 50-354/94-09-01: containment integrated leak rate test (Type A>.
The inspector verified the corrective actions described in licensee response letter,
dated December 8,1994, to be reasonable and complete.
M8.2 (Closed) LER 50-354/96005: inadequate surveillance testing for the residual heat
removal system suppression pool and spray modes of operation due to unaccounted
for RHR heat exchanger bypass valve leakage. This even' was discovered by the
licensee during the last refueling outage and involved en inadequate surveillance
test procedure. The procedure failed to consider design leakage through the RHR
i
heat exchanger bypass valves in determining the flow through the heat exchangers.
1
Since actual flow from the RHR pumps was about 10,000 gallons per minute total,
the flow through the heat exchanger (about 9650 gpm) was calculated to be less
than the technical specification minimum (10,000 gpm) required for the suppression
1
pool cooling test. The licensee deermined that this event was caused by the lack
'
of a rigorous design review when developing the plant technical specifications. The
licensee also determined that the Operational Experience Feedback process had an
'
opportunity to identify this poblem in 1992 based on the report of a similar problem
at the Limerick Generating Station.
The licensee provided corrective actions, including: a proposed change to the
technical specifications to correctly account for the design leakage through the RHR
bypass valves; changes to the OEF process that should better screen such
information to determine if external issues are applicable to Hope Creek; and,
incorporating lessons learned from this event into the Technical Specification
Surveillance improvement Process. The inspector had no further questions and
found the licensee's corrective actions to be reasonable and complete.
M8.3 (Closed) LER 50-354/96020: operations prohibited by technical specification -
failure to perform actions for inoperable radioactive gaseous effluent monitoring
instrumentation. This event involved less than timely actions to the grab sampling
requirements due to a failed South Plant Vent radiation monitor. On several
occasions grab samples were not taken within the specified 12-hour requirements.
The licensee implemented corrective actions to ensure more timely sampling and
analysis for conditions required by the plant technical specifications. 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. This LER is closed.
M8.4 (Closed) LER 50-354/95-033. Sucolements 7. 8. 9 and 10: technical specification
surveillance requirement implementation deficiencies identified by the TSSIP.
These LER supplements document additional findings of the licensee's long-term
!
corrective action for surveillance testing inadequacies originally described in LER 95-
033. While different surveillance requirements were identified in these reports as
not having been appropriately demonstrated, the associated root causes and
corrective actions were the same as previously identified in addition, the
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equipment was subsequently tested and determined to be operable. No other new
issues were revealed by the supplements.
111. Enaineerina
E1
Conduct of Engineering
E1.1
10 CFR 50.59 Activities
a.
Insoection Scope (37551)
,
The inspector reviewed those 10 CFR 50.59 activities described in Table 1 for Hope
Creek. The 10 CFR 50.59 activities were conducted at Hope Creek during the
period of January 1995 to June 1996 with an emphasis on more recent activities.
.
b.
Observations and Findinos
,
For each activity, the inspector requested that the licensee provide a NAP-59 safety
evaluation or a NAP-59 Applicability Review. Test procedure, THC.OP-SO.GO-
0002, (item 3 of Table 1), was determined by the licensee to require a safety
evaluation. However, the inspector found that the safety evaluation had not been
prepared until after the activity had been initiated which is a violation of 10 CFR 50.59(a)(1). The requirements of 10 CFR 50.59(a)(1) allow the licensee to make
changes in the facility, as described in the FSAR, provided that the change does not
involve a USQ or a change to the TSs. Since the licensee did not prepare a safety
evaluation to determine if the activity involved a USO, or to determine if a change
to the TSs was involved, prior to undertaking this activity, this is a violation of 10 CFR 50.59(a)(1). The inspector noted that the licensee identified this violation and
terminated use of the procedure until a safety evaluation was prepared and
approved, which was considered an effective corrective action. This licensee-
identified and corrected violation is being treated as a Non-Cited Violation,
consistent with Section Vll.B.1 of the NRC Enforcement Policv.
The inspector found that the licensee did riot prepare a NAP-59 Applicability Review
or NAP-59 safety evaluation in connection with a March 18,1996 revision to the
design change package,4EC-3546, Package 12, Revision 1, (item 13 of Table 1).
The inspector noted the revision involved changing the leak test method from
" hydrostatic" to "in-service leak test." The inspector noted that, while a procedure
to perform a test associated with a design change may be included in a design
change package, the procedure change should still be subjected to the 10 CFR 50.59 process in that the new test may pose its own safety issues, independent of
the design change. Although the example discussed here did not result in a
violation of 50.59, it does point to a vulnerability in the process that governs
revisions to design changes.
The remaining activities reviewed by the inspector (see Table 1) were observed to
be of generally good quality and in accordance with NRC requirements.
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c.
Conclusions
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The inspector concluded that, in general, PSE&G had a good framework for the 10 CFR 50.59 program.
"
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E1.2 Station Auxiliary Coolino System Valve 1EGHV-2522E Operation
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a.
Insoection Scope (71707 and 37551)
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The inspectors observed PSE&G's response to a possible oilleak in the hydraulic
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operator associated with safety auxiliaries cooling system (SACS) valve 1EGHV-
2522E.
b.
Observations and Findinos
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On August 13,1996, operators suspected that the hydraulic operator of valve
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1EGHV-2522E had an internal oil leak. This condition, if left uncorrected, could
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lead to the valve not operating properly and possibly resulting in a transient
condition due to a loss of turbine auxiliaries cooling system (TACS) water.
'
Based on a review of the UFSAR Sections 9.2 and 9.5, the inspectors determined
7
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that TACS is a non-safety related " load" that is cooled by the safety-related SACS
sy. stem. The TACS system is designed to lesser quality standards than the SACS
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aystem and, as a result, during the initial licensing of the facility, PSE&G considered
the effects of a postulated break in the TACS pipe. To account for the
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hydrodynamic effects, accumulators were placed in the SACS lines to act as
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dampeners for possible water hammer. To account for possible inventory losses to
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the SACS system, two fast-acting hydraulically-operated isolation valves (1EGHV-
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2522E and F) were installed in series in the TACS supply piping. The 2522E and F
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valves are automatically closed on any indicated low pressure in the SACS to TACS
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supply line that possibly results from a catastrophic failure of the TACS line.
Normally, one of the two SACS subsystems is lined up to supply cooling water to
TACS. While there are no logical or physical barriers preventing the operators from
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lining up both SACS subsystems to provide TACS cooling, the system operating
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procedure does not permit this alignment. In addition, such an alignment could lead
to sluicing water inventory from one SACS head tank to the redundant counterpart
in the other subsystem, which could lead to operational transients. The TACS
system is isolated from the SACS system by two pairs of isolation valves on the
supply side (one pair from each SACS subsystem) and by a pair of isolation valves
on the return side of SACS. All of these valves receive automatic closure signals in
response to LOCA or LOP actuations. These valves are similar to the TACS
isolation valve 2522E, except their closure response time is significantly longer
(about 20 seconds vs.10 seconds for 2522E).
It is not clear in the UFSAR that the TACS isolations valves (2522E and F) provide a
safety function; although, they do perform a required isolation function to limit
SACS coolant inventory loss on a postulated TACS line break. In addition, while
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14
the isolation valves are considered part of the safety-related portions of the SACS
system, the instrumentation that initiates closure of the valves are not safety
related.
On August 13,1996, in response to the possible valve operator hydraulic leak,
station operators " locked" open the 2522E valve by blocking its fluid vent port.
This action was not a specified action in either the system operating or alarm
response procedure. As such, it resulted in the system not being able to operate as
described in the UFSAR and no safety evaluation was conducted to determine
whether that change in the component operation constituted an unreviewed safety
question. While the inspectors noted that the valve function did not include
automatic response to LOCA or LOP accident signals, it was designed to mitigate a
large or complete break of the largest non-safety related TACS line and prevent a
functional failure of the associated safety-related SACS system. Once the
inspectors communicated this concern to the operators, the valve controls were
restored to a normal configuration (for a total of about three hours in the abnormal
,
configuration). This issue was considered a violation of 10 CFR Part 50.59(a)(1).
(VIO 50-354/96-07-01)
c.
Conclusions
The inspectors concluded that plant operators modified the controls of a safety
related component, valve 1EGHV-2522E, without use of proper engineering support
to assess whether this action resulted in either a necessary change to the plant
technical specifications or an unreviewed safety question. Once this concern was
identified, operators restored the valve to its normal configuration in a timely
manner.
E2
Engineering Support of Facilities and Equipment
C
E2.1
Station Service Water Travelina Screen Controls Modification
a.
Insoection Scope (37751)
The inspectors reviewed the documentation associated with a modification to an
approved design change package for the station service water system traveling
screen controls. The inspectors interviewed appropriate licensee representatives
associated with this modification, using established station procedures governing
design changes and safety evaluations as a basis for assessment.
b.
Observations and Findinas
During July 1996, Hope Creek maintenance technicians implemented an approved
design change package which upgraded the station service water system traveling
screen controls to resolve long-standing performance problems and improve overall
system reliability. On July 12,1996, with the work on the "D" screen controls only
partially completed, operations personnel requested that the engineering department
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devise a means to restore the function of the screen temporarily due to the
anticipated arrival of Hurricane Bertha the next day.
Since the "D" service water subsystem was already inoperable due to the in-
progress design change, engineering management concluded that a temporary
modification and associated 10 CFR 50.59 evaluation was not necessary to make
the traveling screen available for operation, but not operable. Instead, a manual
change request (MCR #78) was approved that modified the original screen control
design change package (DCP 4EC-3599) permitting the installation of jumpers in the
control logic to allow manual high speed operation of the traveling screen. The
inspectors reviewed the MCR and judged that the supporting documentation was
weak, specifically because the technical basis for justifying the revision to the
original design change package was not provided.
Based on this review, the inspectors noted that the MCR process (defined in design
engineering procedure NC.DE-AP.ZZ-0017 (O)) requires that a " revision justification
sheet" be completed and approved. This justification sheet implements a screening
process like that mandated by 10 CFR 50.59, but does not require a documented
basis for why revisions to a design change package do not invalidate the original
safety evaluation. As a result, though MCR #78 of DCP 4EC-3599 met the
requirements of the governing station procedure, it was not clear to the inspector
that the implementation of jumpers in the traveling screen control logic was not
considered a major revision to the overall design change package, and therefore
invalidate the conclusion of the original supporting safety evaluation.
]
During interviews with engineering department supervision, the inspectors agreed
that MCR #78 was technically adequate and met the requirements of station
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procedures, primarily because this design change package revision also ensured that
the screen control logic jumpers would be removed from the affected service water
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subsystem prior to returning the subsystem to an operable status. In spite of the
'
licensee's assurance that the MCR provided sufficient control to ensure the design
change would be appropriately installed, the inspector noted that the MCR resulted
in a change to the system configuration different than analyzed. While noting that
the system was not considered operable during the time that the MCR was in
effect, the inspector considered the supporting analysis to be weak,
c.
Conclusions
,
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Operators exhibited a good, conservative desire to maximize overall service water
system reliability due to the impending severe weather by requesting engineering
personnel to devise a means to restore the function of a an associated subsystem
made inoperable by partial implementation of a design change package. However, a
review of the modification engineering personnel developed for installation to satisfy
the operations department request highlighted weaknesses in the process for
controlling and justifying design change package revisions.
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E3
Engineering Procedures and Documentation
E3.1
10 CFR 50.59 Reviews and Safety Evaluations
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The inspector reviewed procedure NC.NA-AP.ZZ-0059(O) Rev. 4, "10 CFR 50.59
j
Applicability Reviews and Safety Evaluations," referred to as NAP-59. The strategy
of NAP-59 is to apply the procedure to a wide range of activities where 10 CFR 50.59 may, or may not, be applicable. The user is required to first perform an
,
" Applicability Review" to determine if a particular activity is within the scope of 10
,
CFR 50.59. If the results of the Applicability Review show that 10 CFR 50.59 is
4
not applicable, the Applicability Review form is saved for future reference. If the
j
Applicability Review indicates that 10 CFR 50.59 is applicable, the user is required
to perform a safety evaluation. The NAP-59 procedure also provides procedural
i
interfacing with the FSAR update program of NAP-35, should the subject activity
require a change to the FSAR.
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The NAP-59 procedure is based on the industry guidance in NSAC-125, " Guidance
for 10 CFR 50.59 Safety Evaluations," draft dated June 1989. Consequently, NAP-
>
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59 indicates that a smallincrease in the probability or consequences of an accident
i
or malfunction previously evaluated in the safety analysis report may not indicate
that the activity involves an Unreviewed Safety Question (USQ). The NRC issued
guidance on this issue in an April 9,1996 revision to the NRC Inspection Manual,
Part 9900, " Interim Guidance on the Requirements Related to Changes to Facilities,
Procedures and Tests." The guidance indicates that a smallincrease in the
j
probability or consequences of an accident or malfunction previously evaluated in
i
the safety analysis report does indicate that the activity involves an Unreviewed
Safety Question (USQ). The licensee's memorandum of July 12,1996 informs
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those involved in the 10 CFR 50.59 process of NRC's April 9,1996 positions on 10 CFR 50.59.
a
In summary, the inspector found that NAP-59 is well written, provides clear
assignment of responsibility, and provides the user with good directions for
,
addressing the 10 CFR 50.59 process.
E5.1
Staff Trainina and Qualification on 10 CFR 50.59 Reviews
!
The inspector reviewed the 10 CFR 50.59 aspects of the training program. The
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lesson plans for initial training (L.P. No. 0905-300.20-5059ZZ-03) and periodic
i
retraining (L.P. 0905 300.99N-5059-03) were reviewed. The lesson plans were
l
found to be clearly written with good examples to demonstrate the use of NAP-59.
Conversations with the licensee indicated that periodic 10 CFR 50.59 training is not
1
a program requirement.
With regard to qualifications, the inspector ascertained through conversations with
the licensee that no PSE&G-wide qualifications have been established for those
<
individuals involved in the 10 CFR 50.59 process. The licensee also stated that a
1
soon-to-be-released revision of NAP-59 will provide additional guidance on this.
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The inspector concluded that certain aspects of the training program for 10 CFR 50.59 were good; however, qualification requirements had not yet been developed
to ensure that personnel involved in the use of 10 CFR 50.59 had been
appropriately trained.
4
E7
Quality Assurance in Engineering Activities
E7.1
Safety Review Committee Activities for 10 CFR 50.59 Evaluations
Hope Creek TS 6.5.1.6.e requires that the Site Operations Review Committee
(SORC) perform a review of the safety evaluations that have been completed under
the provisions of 10 CFR 50.59. In reviewing the activities described in Table 1
i
(attached to this report), the inspector noted evidence that the SORCs had
performed the required safety evaluation reviews. Attendance at a Hope Creek
,
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SORC meeting gave the inspector the impression that the SORCs set a fairly high
standard for approval of 10 CFR 50.59 safety evaluations. ' The rejection rates for
,
i
safety evaluations presented to SORCs is trended and varied from approximately 10
to 20 percent during the period of August 1995 to January 1996 with an improving
trend at the end of the period; during the same period, the Hope Creek SORC
rejection rate varied from approximately 5 to 35 percent, also with an improving
trend at the end of the period.
The Hope Creek Offsite Safety Review Group (OSRG) also has a role in reviewing
10 CFR 50.59 safety evaluations as required by Hope Creek TS 6.5.2.4.2.a. The
inspector requested that the licensee provide evidence that the activities described
in Table 1 had been reviewed by the OSRG. In response, the licensee indicated that
activities 1,3,18,19 and 20 in Table 1 had not been reviewed by OSRG because
,
they had not been received from the sponsoring organizations. Hope Creek TS 6.5.2.4.2.a requires that the OSRG review all safety evaluations prepared pursuant
to 10 CFR 50.59. The failure of the OSRG to review the noted activities in Table 1
is a violation of the facility technical specifications. (VIO 50-354/96-07-02)
The inspector determined that the OSRG had previously known that sponsoring
organizations were not consistently forwarding safety evaluations for OSRG review.
A memorandum dated October 19,1994, from Nuclear Safety Review to the Salem
and Hope Creek General Managers, noted this fact.
The inspector concluded that OSRG review of safety evaluations were not
consistently performed. This led to a violation of NRC requirements. The inspector
further concluded that the licensee's corrective actions for similar prior findings
were ineffective at Hope Creek in that sponsoring organizations at Hope Creek
continued to be inconsistent in providing safety evaluations for OSRG review.
Finally, the inspector concluded that the OSRG lacked reasonable initiative in
ensuring that they received these safety evaluations from the sponsoring
organizations.
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E8
Miscellaneous Engineering issues
l
E8.1
(Closed) Unresolved item (50-354/96-03-05): on January 31,1996,PSE&G
declared four Hope Creek radiation detectors inoperable. PSE&G had found that the
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detectors were being used outside their design temperature range. The detectors
monitor beta radiation in the intake of the control room ventilation system and on
high radiation, initiate an alarm and redirect the control room air from the outside to
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a filter train.
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)
PSE&G's subsequent review of the detector design determined that, besides low
temperature, high humidity was also an issue requiring resolution. As described in
,
1
NRC inspection report 50-354/93-06, after consultation with the detector vendor,
PSE&G concluded that the low temperature was not a concern. Regarding
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humidity, calculations performed by PSE&G determined that a film of vapor droplets
4
could form on the aluminum foil end of the detector, limit the amount of beta
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radiation entering the detector, and attenuate the radiation signal. PSE&G
calculated that the maximum film thickness could be 0.0048 inches, correspondinD
to an attenuation coefficient of 44%. This attenuation, when included in the
detector error analysis, was accepMble and within the current beta allowable
settings for the control room.
l
To confirm the calculations, PSE&G hired a consultant to build a full scale mockup
of the control room ventilation ducting and test the detector within the postulated
'
limiting environmental conditions. In this experiment two beta energy sources were
1
used and the temperature and relative humidity were slowly changed. In the end
)
the film thickness was less than that calculated and the measured attenuation
<
coefficients due to moisture were 38% with the low energy beta source, and 26%
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with the high energy source. Based on the results of their analyses and experiment,
PSE&G concluded that the installed detectors were always operable over all
,
temperature and humidity ranges.
'
As a result of the above review, PSE&G found that exposure to moisture could
cause pitting of the foil. Therefore, they decided that the foil should be changed
each time the detectors would be calibrated. The 18-month period between
calibrations, and foil changes, was based on the results of their surveillance of the
detectors as well as calculations.
Based on a review of the above calculations and test results, the inspector
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concluded that PSE&G had properly addressed and resolved the issue.
E8.2 (Closed) Violation 50-354/95-10-01: failure to update the Hope Creek Generating
Station FSAR in accordance with 10CFR50.71(e)(4). The licensee responded to the
violation by letter dated September 11,1995 providing the following corrective
j
actions: (1) elimination of the change notice backlog, (2) update of the Salem and
Hope Creek FSARs and (3) review of procedures to assure proper assignment of
responsibility.
C
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19
The inspector reviewed PSE&G procedure NC.LR-AP.ZZ-0013(Z) - Revision 0,
"UFSAR Maintenance Process", dated February 1,1996. The inspector found the
procedure to be well written with clear assignment of program responsibility and
correctly reflecting the requirements of 10 CFR 50.71(e). The inspector interviewed
the UFSAR Coordinator and found this individual to be knowledgeable concerning
program requirements. The UFSAR Coordinator indicated that the change notice
backlog had been eliminated and the Hope Creek UFSAR had been brought up-to-
date with UFSAR Revision 7, dated December 28,1995. The next Hope Creek
UFSAR update is scheduled for September 25,1996, which is 6 months following
restart from the refueling outage in accordance with 10 CFR 50.71(e). The UFSAR
Coordinator indicated that the Salem change notice file was also current, the last
FSAR update having been made on June 10,1996. The schedule for Salem UFSAR
update is uncertain due to the continuing unit outages.
The inspector reviewed UFSAR update packages associated with activities 6,8 and
16 of Table 1 for Hope Creek. The inspector concluded that PSE&G had taken
effective corrective action for this violation.
1
E8.3 (Closed) Violation 50-354/94-13-0_2: RHR system suppression pool suction valve
(BC-HV-F004A) could not be controlled properly from the remote operating switch
in accordance with plant design. The inspector verified the corrective actions
described in licensee response letter, dated October 18,1994, to be reasonable and
complete. No similar examples were identified.
IV. Plant Support
R2
Status of RP&C Facilities and Equipment
During this inspection, the inspector conducted numerous tours of the facility during
operating conditions and noted that all required radiological postings and locked
areas met regulatory requirements. Further, areas were clear of unnecessary
equipment, well illuminated and free of safety hazards.
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R4
Staff Knowledge and Performance in RP&C
During this inspection, the licensee identified neveral missed technical specification
required sampling and analysis activities due to poor tracking of such, coincident
with inoperable effluent monitoring equipment. This matter is described in Section
M8.3 of this report. The licensee has directed all departments to decrease the
required action times for technical specification action statements in order to better
achieve requirect results. For example,12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> actions will be scheduled every
eight hours, etc.
In addition, Hope Creek operators observed a minor increase on two of the effluent
radiation monitors associated with the turbine building exhaust. The inspectors
considered the troubleshooting of the associated detectors and investigation of the
.
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-.
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20
possible causes of the minor increase in radiation levels to be appropriate. The
inspectors also noted that no releases were made in excess of technical
specification requirements. Further, once the licensee corrected the minor packing
leak in the steam tunnel associated with main steam valve,1 ABHV-2016B,
monitored turbine building exhaust ducting returned to normal conditions.
The inspector concluded that while some activities associated with effluent grab
sampling and analysis were not conducted in a timely manner, overall performance
of radiation protection program requirements were good.
R7
Quality Assurance in RP&C Activities
The inspectors reviewed Audit Report 96-151/152, Radioactive Material Control,
issued September 9,1996. The inspector observed that the audit scope was
sufficiently detailed to ensure that the Hope Creek Process Control Program and
implementing procedures for processing and packaging radioactive wastes was
successfully maintained. Several concerns were identified, including: deficiencies in
radiation monitoring system equipment and missed compensatory sampling;
deficient QA oversight of the program; deficient procedure adherence. All of the
deficient conditions were appropriately entered into the licensee's corrective action
program. One positive attribute was identified associated with technical knowledge
,
of responsible individuals and ownership of the radioactive waste transportation
'
program.
The inspector concluded that the QA audit of the Hope Creek radioactive waste
program met the requirements of the Hope Creek technical specifications and
provided good self-assessment of this area.
P1
Conduct of Emergency Preparedness (EP) Activities
P1.1
Effectiveness of Licensee Controls
a.
Inspection Scoce (82701)
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.
b.
Observations and Findinas
Procedure NC.NA-AP-ZZ-0000(Q), PSE&G Nuclear Business Unit " Action Request
(AR) Process," describes the licensee's method for reporting conditics requiring
,
corrective action, program enhancement or interdepartmental support. ARs are
tracked by a newly developed automated system termed the Performance
improvement Review System (PIRS), which is maintained by the audit department
staff who screen, classify and distribute the ARs. ARs are assigned significance
.
.
21
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.
The inspectors requested a demonstration of the PIRS but the licensee was not able
to locate any recently closed ARs. Licensee individisals 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
j
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 intent that the PlRS will become the sole tracking
system for Salem and Hope Creek.
The inspectors reviewed several ARs and found them to be very detailed, thorough
,
and were reviewed by management.
i
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.
)
c.
Conclusions
)
1
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.
j
P1.2 Relationshio with Offsite Aaencies
a.
Insoection 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.
i
b.
Observations and Findinas
The inspectors interviewed the Radiological Administrator for the Delaware
Emergency Management Agency, the Manager, Bureau of Nuclear Engineering
(BNE), New Jersey, and the Deputy Coordinator for the Department of Emergency
Services, Salem County, New Jersey, to discuss the licensee's relationship with
.
e
22
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 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.
c.
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 Emeraency Facilities
a.
Insoection Scope (82701)
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.
b.
Observations and Findinas
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, which
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
thermoluminescent 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,
/
.
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23
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.
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.
l
C.
Conclusions
j
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 Findinas
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.
.
.
24
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.
Insoection 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.
Observations and Findinas
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 which 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, 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 tech.. :ian was reported not to have current respirator qualifications and
was listed on the current ERO list. The EP staff appeared to be unaware of this
incident.
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 plans to review this area of concern and to review the
RP records to ensure that allindividuals 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.
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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
i
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
,
i
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 P8). With this onc 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.
l
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 EP department was not fully effective at
ensuring 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.
._
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26
P6
EP Organization and Administration
a.
Insoection 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 Findinas
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.
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 (QA)in EP Activities
a.
Insoection 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 Findinas
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.
_ . _ _ _ _ _ _ _ _ .._ _ _ _
.
,
27
The audit reports were appropriately detailed and rnet the requirements specified in
10 CFR 50.54(t). No programmatic problems were identified.
c.
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.
P8
Miscellaneous EP issues
P8.1
Updated Final Safety Analysis Report (UFSAR) 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, which 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.
Section 8, paragrbph 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 (PI) 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.
The inspectors discussed these issues with the licensee, and E-Plan changes have
been submitted to delete the use of the Training Center laboratory as a backup to
the EOF and to provide a better description of media training. These concerns are
considered unresolved pending NRC review and approval of the proposed changes.
(URI 50-354/96-07-03)
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28
P8.2 Missed Alert Declaration
During this inspection, the inspectors reviewed the missed alert declaration for an
event that occurred at Salem on June 7,1995. Details of this inspection are
contained in Salem inspection report 50-272,311/96-15.
S1
Conduct of Security and Safeguards Activities
Du@g this inspection, the inspector observed some conditions that were not in
accordance with the licensee's security plan and its implementing procedures.
These activities are fully discussed in NRC Inspection Report 50-354/96-08.
S8
Miscellaneous Security and Safeguards issues
S8.1
(Closed) Followuo item 50-354/93-28-01: inspection followup of perimeter
assessment aid upgrades. The upgrade project has been completed on the Hope
Creek site. The inspectors have noted that routine maintenance is now effective at
maintaining these aids available. Some additional planned work is still to be
completed on the Salem upgrades and those issues will be reviewed separately;
however, the Hope Creek portion of this item is considered closed.
F2
Status of Fire Protection Facilities and Equipment
.
The inspectors toured various portions of the licensee facilities and observed that
fire protection response equipment was maintained appropriately. During this
inspection period, the licensee initiated a previously approved design change
package (DCP 4EC-3296) to replace the Hope Creek fire protection computer. This
activity was conducted on-line, which resulted in a temporary loss of the fire
protection alarm and indication function in the control room. As a result,
compensatory measures were established to provide fire watch monitors of local
fire panels for indication and alarm for all safety related portions of the facility.
These monitors included use of closed circuit television (CCTV) for certain local
panels in lieu of a watchstander.
The inspectors reviewed the use of CCTVs, which is described in procedure HC.FP-
AP.ZZ-0004(O), " Actions for inoperable Fire Protection - Hope Creek," dated
September 9,1996. In lieu of using a specific safety evaluation for installing the
CCTVs, the licensee relied upon acceptance criteria provided in a radiation
protection procedure for use of this same equipment. That procedure required
associated cables for the CCTVs not be placed within one inch of any safety related
cab le tray, cable or conduit. The inspectors walked down the installation of the
CCTV cables for this fire protection procedure change and observed that several
cables did not meet the established criteria. In addition, the licensee subsequently
informed the inspectors that the one inch criteria was not really meant to pre-
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29
j
approve installation of CCTV cables over open safety-related cable trays or
traversing multiple trains of safety-related cable trays, as was the condition
identified by the inspectors.
After the inspectors identified this condition, licensee individuals took immediate
corrective actions to remove all CCTV cables in close proximity to safety-related
cables, cable trays, and conduit.
The inspectors determined that the safety evaluation associated with this procedure
revision failed to address that use of CCTVs resulted in a hardware change to the
facility, especially regarding placing non-safety related cables over and in close
,
proximity to safety related cables, cable trays and conduit. These conditions were
not previously evaluated by the licensee per 10 CFR 50.59 (a) (1) as required to
ensure that the necessary cable runs for the CCTVs did not result in an unreviewed
!
. safety question. This matter was considered another example of a violation of 10
j
CFR 50.59. (VIO 50-354/96-07-01)
l
The inspectors concluded that the licensee's implementation of the design change
package to replace the Hope Creek fire protection computer was generally
-
acceptable; although interim compensatory measures were not properly evaluated to
,
ensure that no unreviewed safety question existed.
F4
Fire Protection Staff Knowledge and Performance
The inspectors observed two fire department drills to evaluate the effectiveness of
'
the previously described (section F2) fire alarm outage contingency plan. The drills
were appropriately developed and implemented. The inspectors concluded that the
compensatory measures were effective in providing appropriate fire panel indication
'
and alarm information to the control room for response to postulated fires in the
,
facility.
V. Manaaement Meetinas
X1
Exit Meeting Summary
A recent discovery of a licensee operating their facility in a manner contrary to the UFSAR
description highlighted the need for a special focused review that compares plant practices,
procedures and/or parameters to the UFSAR descriptions. While performing the
inspections discussed in this report, the inspectors reviewed the applicable portions of the
UFSAR that related to the areas inspected. The inspectors verified that the UFSAR
wording was consistent with the observed plant practices, procedures and/or parameters.
On October 1,1996, the inspectors presented the inspection results to members of
licensee management. Licensee management acknowledged the presented findings.
The inspectors asked the licensee whether any materials examined during the inspection
should be considered proprietary. No proprietary information was identified.
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PARTIAL LIST OF PERSONS CONTACTED
PSE&G
M. Bezilla, Hope Creek General Manager
C. Banner, Emergency Preparedness
J. McMahon, Director, Nuclear Training Center
.,
J. Polyak, Manager, Radiological Safety
L. Storz, Sr. VP, Nuclear Operations
J. Benjamin, Manager, Quality Assurance
New Jersev Bureau of Nuclear Enaineerina
K. Tosch, Manager
Delaware Emeraency Manaaement Acency
P
E. Falone, Radiological Administrator
Department of Emeraency Services. Salem County, New Jersey
C. Wentzell, Deputy Coordinator
I
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,g
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INSPECTION PROCEDURES USED
IP 61726:
Surveillance Observations
-
IP 62707:
Maintenance Observations
IP 71707:
Plant Operations
j
IP 37551:
Onsite Engineering
IP 71750:
Plant Support
IP 82701:
Emergency Preparedness Program
,
1
IP 92901:
Plant Operations Followup
- !
IP 92902:
Maintenance Followup
IP 92903:
Engineering Followup
l
IP 92904:
Plant Support Followup
IP 93702:
Event Response
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ITEMS OPENED, CLOSED, AND DISCUSSED
!
Opened
50-354/96-07-01
Two examples of licensee failure to evaluate changes to the
facility in accordance with 10 CFR 50.59, including temporary
installation of cables associated with fire protection
compensatory measures; and, blocking open a safety auxiliary
cooling system isolation valve.
l
l
50-354/96-07-02
Failure of the offsite safety review group to review safety
evaluations in accordance with technical specifications.
!
50-354/96-07-03
Media Training not being conducted in accordance to the E-
Plan (UFSAR item); and, Training Center Laboratory
radiological equipment not maintained to meet the intentions
stated in the E-Plan.
Closed
50-354/96023
LER
Reactor Core Isolation Cooling system isolation due to a failed
,
steam leak detection monitor.
'
50-354/93-11-01
This item involved apparent deficiencies in the licensee's
corrective action program.
!
50-354/94-09-04
Mis-operation of the refueling bridge.
50-354/94-003-01 SR
Operation of the facility in excess of the licensed thermal
!
power limits.
!
50-354/94-09-01
Containment integrated leak rate test (Type A) deficiencies.
l
50-354/96005
LER
Inadequate surveillance testing for the residual heat removal
system suppression pool and spray modes of operation.
50-354/96020
LER
Operations prohibited by technical specification - failure to
perform actions for inoperable radioactive gaseous effluent
monitoring instrumentation.
!
50-354/95-033
LER
Supplements 7,8,9 and 10: technical specification
surveillance requirement implementation deficiencies identified
,
l
by the TSSIP.
l
50-354/96-03-05
Event on January 31,1996, when PSE&G declared four Hope
Creek radiation detectors inoperable.
50-354/95-10-01
Failure to update the Hope Creek Generating Station FSAR in
accordance with 10CFR50.71(e)(4).
. _ _ . - . - _ . . _ _ .
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. - . . - - - . - . - . - . . ~ - . - . . . .
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50-354/94-13-02
RHR system suppression pool suction valve (BC-HV-F004A)
l
could not be controlled properly from the remote operating
switch in accordance with plant design.
50-354/93-28-01
IFl
Inspection followup of perimeter assessment aid upgrades.
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_- __
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._
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LIST OF ACRONYMS USED
Action Request
BNE
Bureau of Nuclear Engineering (NJ)
BP
Business Process
CR
Condition Resolution
e
CR
Control Room
Corrective Maintenance
Emergency Action Level
Emergency Director
,
EPlP
Emergency Plan Implementing Procedures
i
Emergency Response Organization
ECG
Event Classification Guide
Closed Circuit Television
j
l&C
Instrument & Control
~
Loss of Coolant Accident
Loss of Offsite Power
Nuclear Management and Resources Council
NTC
Nuclear Training Center
Operations Support Center
!
PIRS
Performance improvement Review System
Pi
Public Information
OA
Quality Assurance
i
Radiation Protection
SACS
Safety Auxiliaries Cooling System
SNSS
Senior Nuclear Shift Supervisor
Senior Reactor Operator
SERT
Significant Event Review Team
TACS
Turbine Auxiliaries Cooling System
TS
Technical Specifications
Thermoluminescent Dosimeter
Updated Final Safety Analysis Report
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