ML18100B180
| ML18100B180 | |
| Person / Time | |
|---|---|
| Site: | Salem, Hope Creek  |
| Issue date: | 06/28/1994 |
| From: | Calvert J, James Trapp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18100B177 | List: |
| References | |
| 50-272-94-07, 50-272-94-7, 50-311-94-07, 50-311-94-7, 50-354-94-05, 50-354-94-5, NUDOCS 9407070093 | |
| Download: ML18100B180 (27) | |
See also: IR 05000272/1994007
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
DOCKET/REPORT NOS:
50-272/94-07
50-311/94-07
50-354/94-05
LICENSEE:
FACILITY:
INSPECTION AT:
DATES:
INSPECTORS:
SUBMITIED BY:
APPROVED BY:
Public Service Electric and Gas Company
Salem 1 & 2 and Hope Creek Generating Stations
Hancocks Bridge, New Jersey 08038
Hancocks Bridge, New Jersey
March 28-May 20, 1994
J. A. Calvert, Reactor Engineer, ES, DRS
R. A. Skokowski, Reactor Engineer, ~'DRS
A. L. Della Greca, Senior Reactor Engineer, ES, DRS
~~
~ 3. C,VLvt--e-/-
fohllCalvert, ~tor Engineer
Electrical Section
Division of Reactor Safety
James
app, Acting Chief
Electrical Section
Division of Reactor Safety
Areas Inspected: This was an announced inspection of the Salem and Hope Creek stations'
engineering program by regional personnel to: (1) to determine the effectiveness of the
licensee's engineering staff in providing technical support to the safe operation of the Salem
and Hope Creek Nuclear Generating stations; and (2) to review the corrective action
associat¢ with the Salem Unit 2 overhead annunciators, as described in the Augmented
Inspection Team (AIT) Report 92-81.
Results:
The 10 CPR 50.59 procedure was improved over the previous revision, in particular,
by the incorporation of the applicability review and safety evaluation guidance
~~~7070093 940629
G
ADOCK 05000272
attachments. However, a violation of the 10 CFR 50.59 requirements was identified
that was associated with the replacement of the Salem lA 460V vital bus
transformers. Specifically, no written safety evaluation was performed for a change
to the 1A-460V vital bus transformer.
Two system interface design inadequacies were major contributors to a reactor scram
during startup testing of the installed Hope Creek digital feedwater modification.
However, the engineering process of the analog to digital requirement translation was
well planned and executed. Appropriate software verification and validation (V&V)
activities were well planned and implemented, as were independent design reviews.
The temporary modification procedures for both the Salem and Hope Creek stations
provided good guidance to the engineering staff. The added considerations of
microprocessor equipment and erosion/corrosion 1P. the specialty review checklists was
considered noteworthy.
The corrective action program performance was effective. Particularly noteworthy
was the appropriate set of corrective actions for the overhead annunciator (OHA)
issues for Salem Station. Also noteworthy was the engineering management
leadership in initiating organizational changes that addressed generic digital issues in
response to the OHA event.
The engineering and operational organizations interacted and communicated
effectively. The station morning reports and the Salem system engineer presentations
were considered particularly noteworthy.
E&PB engineering had established programs to reduce the engineering backlogs and
progress was observed in the backlog reduction.
The recent E&PB engineering self-assessment initiative was good and will provide
appropriate information to improve the process of engineering performance
assessment.
ii
TABLE OF CONTENTS
1.0
PURPOSE ............................................ 1
2.0
ENGINEERING ORGANIZATION .......... ~ ................. 1
3.0
STAFFING AND ENGINEERING BACKLOG REDUCTION ............ 2
3. 1
Staffing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
3.2
Engineering Backlog Reduction . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
3.2.1 Engineering Design Discrepancy Backlog . . . . . . . . . . . . . . . . 2
3.2.2 Engineering Work Request Backlog . . . . . . . . . . . . . . . . . . . . 3
3.3
Conclusions .................................... : . . 4
4.0
DESIGN CHANGES AND MODIFICATIONS ..... * ................ 4
4 .1
Design Change Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
4 .1.1
Design Change Packages . . . . . . . . . . . . . . . . . . . . . . . . . . 4
4.1.1.1 Hope Creek Analog Feedwater Control System
Replacement (DCP 4HC-0154) . . . . . . . .
5
4.1.1. l. l Analog to Digital Engineering Process . . . . . . . . . . . . . . . . 5
4.1.1.1.2 Start-up Testing Anomalies .......... *. . . . . . . . . . . . . 6
4.1.1.2 Salem Emergency Diesel Generator Field Flash Supervisory
Circuit (2EC-3155) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
4.1.2
Small Design Change Packages . . . . . . . . . . . . . . . . . . . . . 8
4.1.2.1
Hope Creek Relief Valve Discharge Flange Engineering
Change Authorization 4EC-3285 (4/24/94) . .
9
4.1.2.2 Salem 2A 460V Vital Bus Transformer Replacement
(2EC-3219) ......... *. . . . . . . . . . . . . . . . . . . . . . . . 9
4.2
10 CFR 50.59 Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10
4.3
Temporary Modification Program . . . . . . . . . . . . . . . . . . . . . . . .
11
4.3.1
Hope Creek Battery 1DD447 Cell No. 13 Jumpered Out
{TM#94-010) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12
4.3.2
Salem Unit 2 Temporary Breaker Replacement (TM#92-040) . . .
12
4.4
Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12
5.0
CORRECTIVE ACTION PROGRAM . . . . . . . . . . . . . . . . . . . . . . . . . .
13
5 .1
Licensee Event Reports . . . . . . . . . . . . . . . . . . . . . . . . . *. . . . . . .
14
5.2
Overhead Annunciators (OHA) Followup . . . . . . . . . . . . . . . . . . . .
14
5.3
10 CPR Part 21 Potential Defect . . . . . . . . . . . . . . . . . . . . . . . . .
15
5.4
Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
15
6.0
QUALITY ASSURANCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
16
iii
7.0
ORGANIZATION INTERACTIONS . . . . . . . . . . . . . . . . . . . . . . . . . . .
16
7 .1
Station Morning Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
16
7 .2
Daily Morning Meeting
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
16
7. 3
System Engineer Presentations . . . . . . . . . . . . . . . . . . . . . . . . . .
17
7.4
Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17
8.0
PLANT W ALKDOWNS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17
9.0
ENGINEERING SELF-ASSESSMENT AND PERFORMANCE
INDICATORS
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17
9.1
Engineering Assurance and Self-Assessment Process . . . . . . . . . . . . .
18
9.2
Engineering Performance Indicators . . . . . . . . . . . . . . . . . . . . . . .
18
9.3
Offsite Safety Review of 10 CFR 50.59 Safety Evaluation Reviews . . . .
19
9.4
Design Change Process Improvement Team . . . . . . . . . . . . . . . . . .
19
9.5
Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
20
10.0
ENGINEERING ISSUES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
20
10.1
Prioritization of Engineering Issues . . . . . . . . . . . . . . . . . . . . . . .
20
10.2
Operational Experience Feedback ............ : . . . . . . . . . . .
20
11.0
EXIT MEETING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
21
ATTACHMENT 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
iv
DETAILS
1.0
PURPOSE
The purpose of this inspection was: (1) to determine the effectiveness of J>ublic Service
Electric & Gas Company's (PSE&G's) engineering staff in providing technical support to the
safe operation of the Salem and Hope Creek Nuclear Generating stations; and (2) to review
the technical issues associated with the Salem Unit .2 overhead annunciators, as described in
the Augmented Inspection Team Report 92-81.
2.0
ENGINEERING ORGANIZATION (37700)
The inspectors reviewed documents and conducted interviews to determine the quality of
engineering and technical support for Salem and Hope Creek, which is provided by corporate
engineering, known as engineering and plant betterment (E&PB) and the onsite system
engineering groups. The corporate engineering department is located in the engineering
building just outside the Hope Creek plant. The engineering program and the responsibilities
for the engineering and design support for the nuclear facilities at Artificial Island are
described in Procedure NC.VP-PO.ZZ-0006(Q), Revision 2, "Engineering Program."
Engineering* and plant betterment performed major engineering efforts, such as plant
modifications and design bases reconstitution. The onsite engineering groups supported
operations, maintenance, testing, and temporary plant modifications.
Each plant has an onsite engineering group that provides technical support and is known as,
"Technical Department (System Engineering)." The technical departments are located within
the protected area and headed by the technical manager. The technical manager reports
directly to the station manager, who has the overall responsibility for the station operation.
The technical department consists of six groups: reactor and plant performance, electrical
engineering, instrumentation and control, nuclear steam supply systems, balance of plant
systems, and administration and planning. This department is responsible for temporary
modification.s, plant system specific engineering, day-to-day operations technical support, and
maintenance support. A system engineer is assigned to each plant system.
E&PB is the source of technical support for the technical departments. The E&PB
organization is headed by the vice president, nuclear engineering, who reports directly to the
vice president and chief nuclear officer. E&PB is responsible for engineering support of
plant operations not covered by system engineering, such as: licensing; specialized technical
expertise and programmatic activities, such as environmental and seismic qualifications; plant
configuration control; management and engineering for major modifications at each plant;
and projects common to all plants .
2
3.0
STAFFING AND ENGINEERING BACKLOG REDUCTION (37700)
3.1
Staff"mg
The inspectors determined by review of documents and interviews of engineering personnel,
the staffing complement of E&PB. The E&PB has 266 PSE&G professional and technical
staff members [this does not include licensing, nuclear engineering and project services
(NE&PS) and estuary enhancement]. Included in this total are 33 supervisors and managers
and 39 supporting personnel. In general, all engineering and management personnel in
E&PB have degrees in the appropriate disciplines. In addition, there are approximately 70
individuals holding advanced degrees, including 10 individuals who have doctorate degrees.
The average experience of the E&PB staff is about 13 years in the nuclear industry. At the
time of this inspection, only eight positions in E&PB were unfilled.
In addition to the PSE&G staff, E&PB is supplemented by 94 contractors. This includes
both technical and support staff personnel, who are distributed throughout E&PB. Salem
Projects contains 52 % (23 of 45) contractor personnel, and electrical engineering contains
26 % (23 of 89) contractor personnel. The remainder of the E&PB departments contain
significantly smaller percentages of contractor personnel. Discussions with the E&PB
management indicated that the majority of work performed by the contractor personnel is
routine. This is to ensure that plant knowledge and expertise remains with the PSE&G staff.
PSE&G also contracts out a significant amount of engineering projects. Approximately 47%
of the E&PB capital and operation and maintenance (O&M) budget for the current year is
dedicated for external contracted work. This is a 13 % decrease from two years ago, and
PSE&G plans to reduce significantly their contractor budget for E&PB between now and
1998.
There are 132 technical and supporting personnel in Salem and Hope Creek system
engineering. At the time of the inspection, there were about 15 unfilled positions at Salem
and four unfilled positions at Hope Creek.
3.2 . Engineering Backlog Reduction
3.2.1 Engineering Design Discrepancy Backlog
The inspectors reviewed the licensee's control of engineering design discrepancies identified
by nuclear department personnel. The procedure covering this process is "Engineering
Discrepancy Control," NC.DE-AP.ZZ-0018(Q), Revision 4, which describes the
identification, documentation screening, prioritization, evaluation, resolution, and closure of
engineering discrepancies. The originator uses a discrepancy evaluation form (DEF) and
provides an initial assessment of any safety or regulatory concerns. The DEF is reviewed by
a supervisor and sent to the station systems engineer. The station systems engineer performs
the initial assessment of any action that involves safety or regulatory concerns. The
3
engineering assessment group then reviews the initial assessment, categorizes a discrepancy
based on its safety, regulatory or economic significance, and ensures that the reasons are
documented. Then, a discrepancy is time-prioritized into immediate, near-term, long-term,
or low priority categories. The time priorities cover the time required for evaluation and
resolution of the discrepancy. The inspectors determined that the procedure had adequate
reviews for the determination of safety significance, operability, technical specification,
licensing commitment, and incident reporting concerns before time priorities are assigned.
The licensee stated that it is possible, during the discrepancy evaluation and resolution phase,
that additional information or conditions could be discovered that could impact system
operability or plant safety. Less than 5 % of the discrepancies have resulted in any additional
corrective action. However, no discrepancies initially _screened as nonreportable have turned
into reportable issues during the evaluation and resolution stages.
The inspectors reviewed the monthly engineering management performance indicator
statistics for engineering discrepancies. The mechanical engineering area comprises 75 % of
the backlog of discrepancies. These involve long-term or low priority discrepancies, such as
minor drawing corrections, design clarifications, and missing signatures. The total number
of discrepancies has decreased from 2088 to 1952 during the period of January to
April 1994, with 84% of the April backlog classified as long-term or low priority. The 1994
goal is to complete 1000 discrepancies total, with 500 from the long-term and low priority
categories. -As of April 1994, the cumulative number of all discrepancies completed was
increasing and was within 71 % of the April goal. The long-term, low priority cumulative
number completed was increasing and was within 57% of the April goal. The inspectors
concluded that the backlog of discrepancies was addressed by engineering management, and
that the backlog was being steadily reduced.
3.2.2 Engineering Work Request Backlog
The inspectors reviewed the engineering work request (EWR) process at PSE&G and the
associated backlog of EWRs. The EWR process is used for the control of emergency work
and work requiring less than $50,000, or less than 1,000 man-hours. It is the responsibility
of E&PB to close EWRs. All EWRs are prioritized upon initiation, with emergency EWRs
having priority over other work. -
PSE&G tracks the backlog of EWRs on a monthly basis, with respect to the total number of
EWRs and the number of new EWRs initiated and closed each month. This information is
trended for all the nuclear engineering organizations. There were 364 open EWRs being
worked by E&PB as of March 1994, with a work-in-progress goal of 174 EWRs. In
addition, the inspectors noted that, for the previous two months, the number of open EWRs
has been reduced by approximately 20 each month .
.*
4
3.3
Conclusions
The inspectors concluded that the licensee had adequate staffing in E&PB and onsite system
engineering to provide engineering and technical support to the stations. E&PB engineering
had established programs to reduce the engineering backlogs. Progress was observed in
these backlog reduction programs, although it was slow and not on management's targets.
4.0
DESIGN CHANGES AND MODIFICATIONS (37700)
The inspectors reviewed PSE&G's design change process. This included a review of the
procedures governing the design change process, the 10 CFR 50.59 process, and the
temporary modification process. In addition, the inspect'lrs reviewed a sample of design
change packages (DCPs), small DCPs, and temporary modifications for both stations.
4.1
Design Change Process
The inspectors reviewed the licensee's design modification process, which is described in
Procedure NC.NA-AP.ZZ-008(Q), "Design Modification," Revision 6, approved
March 30, 1994. This procedure establishes a uniform method for design and configuration
changes, and tests and experiments for the Salem and Hope Creek stations. It is used as a
road map to determine the appropriate change package workbook. Attachment 2 to this
procedure is used by the licensee's project engineer to aid in this determination. In the form
of a flowchart, it directs the user to the proper workbook from a series of six books that
discuss the following types of changes: facilities test/experiment change, standard design
- change, engineering change authorization, equivalent replacement, obsolete piece part
replacement, document only change, conformance to documentation, and as-built
documentation. Other attachments are available for technical department prepared change
packages. The inspectors noted that the text portion of these attachments discussed each
major step required and directed the user to the implementing level procedure for more
detailed guidance. Each text portion is accompanied by a flowchart. The flowcharts clearly
indicate the responsible individual for completing each task and refer back to the section
number of the text that describes the task.
4.1.1 Design Change Packages
The inspectors reviewed the changes made to Procedure NC.DE-WB.ZZ-OOOl(Q),
"Workbook 1, Standard Design Change," Revision 4, since it was last reviewed by the NRC
in Inspection Report 93-14. The major changes to this procedure were: the inclusion of
guidance regarding microprocessor equipment and systems in the design considerations
checklist, and specialty review checklists for the erosion/corrosion monitoring program.
The inspectors reviewed one example of a Workbook 1 modification for each station, and the
results of these reviews are described in the sections below.
5
4.1.1.1 Hope Creek Analog Feedwater Control System Replacement (DCP
During the previous refueling outage, PSE&G had replaced the existing analog-type
feedwater control system with a new solid state, fault-tolerant, digital control system. The
analog feedwater system had experienced recurrent hardware and operational problems that
had contributed to nine plant scrams during the previous seven years. The new digital
system has been installed to improve plant performance and capacity factor. The digital
system includes Foxboro Intelligent Automation hardware/software and new microprocessor-
based Woodward governors for the reactor feed pump (RFP) turbines.
4.1.1.1.1 Analog to Digital Engineering Process
The inspectors reviewed documents and interviewed engineering, operations, and training
staff to determine the quality of the engineering process for the digital feedwater
modification. The E&PB engineering staff developed a bid specification and selected a
vendor team of SAIC and Foxboro to supply the fault tolerant digital feedwater control
system.and three digital feedwater pump speed controllers. The E&PB engineering staff then
wrote a system requirements specification jointly with the team. Foxboro developed the
software/hardware functional diagrams and implemented the software. SAIC developed the
static and dynamic factory acceptance tests (SFAT, DFAT) and also the site acceptance test
(SAT). The control room CRT screens were designed by E&PB and implemented by
Foxboro. The E&PB staff wrote the preconstruction and startup power ascension tests.
The SFAT provided 100% testing of all static parameters of the system. All inputs, outputs,
internal logic, and live screen information were tested. System redundancy and health
reporting was tested. The DF AT simulated various plant disturbances and tested the
response of the digital system. The SAT was a subset of the DF AT and verified that the
system performed correctly at the site. The preconstruction tests involved verification of
approximately 13,000 connections. The startup power tests are designed to demonstrate the
functionality of the system for normal and selected transient conditions. The anomalies that
occurred during the startup testing is discussed below in Section 4.1.4.
The digital systems group had a consultant perform an independent review of the digital
system and the software capabilities of the SAIC/Foxboro at the post-bid phase. This review
also identified some concerns about the data communication links. A test was conducted to
characterize the data communication links for a broadcast storm scenario. The test results
showed that for the present system configuration, data communications would not be
hampered, but would be a consideration if the system were to be expanded. Another
independent office of SAIC.performed the independent verification and validation (V&V) of
the control software. An independent design review of the DCP documents, analyses, and
safety evaluation was performed by an outside consultant familiar with GE feedwater
systems.
6
The inspectors concluded that the analog to digital requirement translation process was well
planned and implemented. Appropriate software V&V activities were planned, as well as
independent design reviews.
4.1.1.1.2 Start-up Testing Anomalies
Although the digital system performs the same primary function of controlling feedwater
flow as the analog system, it includes several features intended to provide reliability, self-
checking capability, and redundancy. One of these features involved the transfer of the RFP
from the automatic to the manual mode if the flow exceeded its setpoint. Another feature,
involving an intermediate reactor recirculation pump (RCP) runback on a combination of low
reactor water level and *any RFP trip, was revised to include redundant input signals. A
reactor scram that occurred during the inspection on May 15, 1994, was primarily the result
of design inadequacies related to these two features and the failure of the licensee
engineering to fully evaluate and correct these discrepancies when identified.
RFP Transfer to Manual Mode
The inspectors determined that the RFP transfer to manual mode transfer setpoint had not
received an adequate review. Feed water flow to the vessel is supplied by the
condensate/feedwater system, composed of three process loops, each with a primary
condensate pump, a secondary condensate pump, and a reactor feedwater pump. Normal full
power operation involves the use of all three loops, each supplying an average of
approximately 11,050 gallons per minute (gpm) to the reactor vessel. For operation with
two RFPs, the applicable procedure requires lowering the reactor power to 95 % * The
procedure does not discuss or prevent restoration of reactor power to 100 % after stopping
one of the three RFPs.
The inspectors determined that in the analog design, flow transmitters downstream of each
pump provided the required input to the feedwater control system. The transmitters were
calibrated for a maximum differential pressure of 283.5" of water, equivalent to a flow of
approximately 16,200 gpm. Since operation of the plant at 100% requires a flow of
approximately 16,550 gpm for each of two RFPs, the transmitter calibration indicated that
the original design was based on a 95 % maximum power operation with two RFPs. The
licensee stated that they had encountered no problems when occasionally operating at 100%
power with two RFPs.
The digital feedwater control system design used these same transmitters for the transfer of
the RFPs from the automatic to the manual mode on high feed water flow. PSE&G
apparently did not evaluate the transmitter calibration when, during the design of the
feedwater modification, they selected 102% of the transmitter output as the setpoint for the
transfer feature. The value of 102 % of the transmitter output corresponds to approximately
16,360 gpm feedwater flow and; therefore, to less than the required flow of 16,550 gpm for
100% power operation.
7
Before the scram event, the licensee had placed the "A
11 RFP in the recirculation mode and
was in the process of increasing power to 100%, when the first RFP transferred to the
manual mode at 102 % of the transmitter output. The second RFP transferred to the manual
mode shortly thereafter. The transfer of the RFPs to the manual mode resulted in a slow
decrease in reactor water level and eventually resulted in the actuation of the Level 4 alarm
setpoint. The transfer of the RFP to the manual mode was not annunciated. The subsequent
intermediate runback of the reactor RCPs, and the inability of the operator to control reactor
water level following the RCPs runback, ultimately resulted in the reactor scram on low-low
water level (Level 3).
The inspectors determined that the above design inadequacy was apparently discovered on
April 20, 1994, approximately three weeks.before the event. On April 19, 1994,
Discrepancy Report No. H-DFW-062 was written to identify the swapping to manual of a
RFP when a second RFP tripped, with the third RFP in the manual mode. The swapping
was discovered during simulator training. In the response of April 20, it was stated that
swapping occurs by design when the pump discharge flow exceeds 16,100 gpm.
Reactor Recirculation Pump Runback
As stated above, the intermediate RCP runback on low reactor water level, in conjunction
with any RFP trip, was a feature of the analog feedwater system design. The input signals
and the control functions were provided by electrical mechanical devices with dry contact
output. In the digital design, the control function remained the same, but the input signals,
i.e., reactor water level and reactor feed pump status, were changed from dry contacts to
digital-type field bus modules (FBMs). In addition, redundancy of the input signals was
added to provide greater reliability. The input/output devices used in the application were
FBM-10 modules. Three FBMs, connected in parallel, were used to provide the required
control function.
During the plant startup process, the reactor recirculation pumps received three anomalous
intermediate runback signals. Each time, no pump runback occurred because the reactor
power, at that time, was below the required 65 % . The first runback signal was received on
April 29, 1994. In this case, the initiating event was the tripping of reactor feed pump
11C.
11
The anomaly of this signal was due to its being received without a low reactor water level
(Level 4) alarm. The other two anomalous signals were received on April 30, 1994. The
first of these two signals was caused by a Level 4 alarm only, without a reactor feed pump
trip .. The second was caused by the tripping of RFP
11C,
11 again without the Level 4 alarm.
The licensee troubleshooting was unable to duplicate the signal and attributed the symptoms
to the feedwater system tuning. The vendor developed a computer file to capture any
subsequent transients, but the troubleshooting software was never turned on. During the
subject scram event, another anomalous signal caused the reactor feed pumps to runback to
their intermediate setpoint. As described above, the signal was caused by the drop of reactor
water level below the Level 4 alarm setpoint, but no RFP trip had occurred.
8
- Troubleshooting following the event determined that the FBM logic signals did not reset
when the input was reset. Therefore, only one input signal was needed to satisfy the AND
logic and initiate the intermediate runback. Immediate corrective actions resulted in the
deletion of two FBMs and the use of software to perform the AND logic in the remaining
FBM. Testing of the revised circuit provided satisfactory results. In addition, subsequent
discussions of the licensee with the vendor indicated that equipment application deficiencies
may have prevented the logic from resetting when the input signal was reset. The licensee
indicated that the equipment design may not be capable of driving three FBMs as in the
Hope Creek application. The change of the logic signals from hardware to software-type
were, hence, reasonable, and believed to have resolved the problem.
The investigation of
the event was continuing at the end of the inspection.
4.1.1.2 Salem Emergency Diesel Generator Field Flash Supervisory Circuit
(2EC-3155)
The inspectors reviewed Design Change 2EC-3155, titled, "2A Diesel Generator KlC Relay
Supervisory Circuit." The purpose of this modification was to install a supervisory circuit
for indicating the status of the 2A emergency diesel generator (EDG)* field flash relay (Kl C)
to ensure that failures to reset do not go undetected. This DCP was developed in response to
Institute of Nuclear Power Operations (INPO) significant event report (SER) 23-91,
regarding failures of the EDG field flash controls circuits to reset rendering the generators
inoperable once stopped.
The inspectors verified that both the DCP and 10 CFR 50.59 applicability review contained
the appropriate reviews and approvals. The failure mode affects and analysis was found to
provide adequate detail to ad.dress the installation of the supervisory circuit. However, the
inspectors' review of the resistor sizing calculation, associated with the modification,
identified that the resistor tolerances were not taken into consideration. As a result, the lead
engineer for the modification reperformed the calculations to verify that the selected
resistors, including their tolerances, were acceptable. The inspectors also performed a
walkdown of the modification to verify that the circuit was installed as designed.
The inspectors considered PSE&G's effort to respond to the industry information to be good,
but considered their failure to include the resistor tolerances an indication of less than
expected rigor in both the design and review of a Class IE modification.
4.1.2 Small Design Change Packages
The inspectors reviewed the small change design process by document examination and
interviews. The plant engineering group of E&PB produces small design packages in
response to the needs of the plants. The small design scope of work is defined as less than
$100,000 or 2,000 man-hours. This group was formed in 1991 in order to relieve the
technical departments of minor modifications.
9
The inspectors reviewed the small design change procedure, "Engineering Change
Authori7.ation - Workbook 6," NC.DE-WB.ZZ-0006(Q), and noted it had suitable direction
that restricts its use to those modifications that do not affect the design basis. Furthermore,
the procedure requires that a 10 CPR 50.59 review confirm and clearly document that there
was no change to the design basis. However, the procedure states that, if a 10 CPR 50.59
safety evaluation is required (which can indicate that a change was made to the design basis),
SORC and station general manager approval is all that is required for installation. The above
two statements appear inconsistent since* the evaluation can represent whether the design basis
was not changed or was changed. However, the fact that a 10 CFR 50.59 evaluation is
completed will ensure proper safety considerations are taken into account. The inconsistency
was pointed out to the licensing staff and they agreed to address it.
The inspectors interviewed Salem and Hope Creek technical staff members and determined
that the interface with the plant engineering group was very responsive and effective in
scheduling and implementing the engineering change authori7.ation modifications.
The inspectors reviewed two small design packages that were covered by the engineering
change authori7.ation Workbook 6 procedure, which are summarized below.
4.1.2.1 Hope Creek Relief Valve Discharge Flange Engineering Change Authorization
4EC-3285 (4/24/94)
The inspectors reviewed the important-to-safety engineering change authori7.ation design
package for a relief valve discharge flange modification in the RHR pump discharge line.
The change allowed a local leak test to be conducted after the lift setpoint test of the relief
valve. The 10 CPR 50.59 evaluation stated that the FSAR drawing would be changed and
that a requirement to perform Type A integrated leak rate tests would be eliminated. The
inspectors determined that the rationale and conclusion of the 10 CFR 50.59 review showed
that there was no safety concern.
4.1.2.2 Salem 2A 460V Vital Bus Transformer Replacement (2EC-3219)
The inspectors reviewed small design change package 2EC-3219, titled, "2A Vital Bus
Transformer Replacement." The purpose of this modification was to replace.the 4160 V/460
V transformer with a new transformer having increased capacity. A similar modification was
performed for Salem Unit 1, Change No. lEC-3264. The new transformer has a capacity of
1000 kVA ambient air-cooled (AA) and 1333 kVA forced air-cooled (FA) at an 80°C
temperature rise. The original transformer had a capacity of 750 KV A (AA) and 1000 KV A
(FA) at a 150°C temperature rise. This transformer was replaced to increase transformer
life expectancy and reliability. The new transformers were carrying the same load as the
original transformers.
The inspectors verified that the DCP contained the appropriate reviews and approvals. The
inspector also reviewed the applicable calculations including: the short circuit calculation;
--~~----------------------------------
10
load flow calculations; and the coordination study to verify that the new transformer ratings
- were included and acceptable. The inspectors performed a walkdown of the modification to
verify that the transformer was installed as designed.
The inspectors reviewed the 10 CFR 50.59 applicability review for the transformer
replacements for both Salem units, and found them to contain the appropriate reviews and
approvals. For both unit's transformer replacements, PSE&G determined that the
modification did not change the facility, as described in the safety analysis report (SAR).
Contrary to PSE&G's review of the SAR, the inspectors' review of the SAR found that the
original KVA rating for the Salem Umt 1 transformer included in Figure 8.3-4, "460V. Vital
Buses One Line - Unit 1." Furthermore, the inspector questioned how PSE&G handles
situations similar to this, where both units are identical, aµd only one unit is described in the
SAR. As a result, PSE&G had committed to perform the appropriate 10 CFR 50.59 safety
evaluations for both design changes.
The inspectors concluded that-the replacement of the lA and 2A 460V vital bus transformers
described above is an example of the licensee's failure to perform and document 10 CFR
50.59 safety evaluations, and constitutes a violation of 10 CFR 50.59- requirements (50-272
& 50-311/94-07-01).
4.2
10 CFR 50.59 Process
The inspectors reviewed Procedure NC.NA-AP.ZZ-0059 (Q), "10 CFR 50.59 Reviews and
Safety Evaluations," Revision 2, approved May 16, 1994. The inspectors found this
procedure was based on the guidance provided by Nuclear Safety Analysis Center (NSAC)
125, "Guidelines for 10 CFR 50.59 Safety Evaluations." The latest revision to NC.NA-
AP.ZZ-0059 (Q) included guidance at~chments for both the preparation of 10 CFR 50.59
reviews and the preparation of 10 CFR 50.59 safety evaluations. The 10 CFR 50.59 review
preparation guidance gives several examples illustrating when 10 CFR 50.59 safety
evaluations would be required. The 10 CFR 50.59 review preparation guidance also includes
an example regarding the replacement of equipment with nonequivalent equipment, where the
replacement changes the performance or design of the plant, as described in the SAR. The
10 CFR 50.59 safety evaluation preparation guidance provides both general and detailed
guidance regarding the determination of an unreviewed safety question. One of the general
guidance statements included, "If the proposal is a design change involving conversion from
analog to digital technology or a digital upgrade, refer to Electric Power Research Institute
(EPRI) TR-102348, 'Guidelines on Digital Upgrades'." The inspectors considered the 10
CFR 50.59 procedure improved over the previous revision, in particular, the incorporation of
the two guidance sections.
The inspectors reviewed another change to the 10 CFR 50.59 procedure, included in
Revision 2, for an optional peer review associated with the 10 CFR 50.59 applicability
review. The text of the procedure states that the peer review for the Applicability Review is
optional at the approver's discretion; however, if it is made optional, then the approver
11
accepts the responsibilities of the peer reviewer. The inspectors were concerned that the
signature sheet associated with the applicability review only states that the peer review is
optional, and may not provide appropriate notice to the approver that the peer review is still
required. This was discussed with the licensee's engineering standards staff, and they agreed
to address the issue.
4.3
Temporary Modification Program
The inspectors determined that temporary modifications at Salem and Hope Creek stations
are normally performed by the technical departments. The inspectors reviewed Procedure
NC.NA-AP.ZZ-0013(Q), "Control of Temporary Modifications," Revision 1. This
procedure was found to contain adequate guidance for the development, installation, and
removal of temporary modifications. Additionally, the procedure provided sufficient
guidance for the periodic review of the installed temporary modifications.
The inspector noted that the procedure allows the control of extending the removal date up to
the responsible system engineer. There was no guidance provided regarding the justification
for the extending of the removal dates, nor was there guidance provide4 regarding how the
station management is informed that a temporary modification removal date has been
extended. The inspectors discussed this concern with the appropriate station personnel and
determined that each station had a different method for extending temporary modifications,
but these methods were not controlled by procedure at either station. The inspector reviewed
the temporary modification log and various temporary modification reports for both stations,
and determined that the temporary modifications that were extended were adequately justified
and reported to the station management. Discussions with the licensee indicated that the
temporary modification procedure was scheduled for revision in the near future, and the need
to provide a controlled mechanism for the extension of temporary modifications will be
considered at that time.
At the completion of this inspection, the Salem station had 56 temporary modifications
installed, and the Hope Creek station had 22 installed. The inspector also noted that the
percentage of safety-related temporary modifications installed was extremely small. The
inspectors' discussions with PSE&G staff indicated that their goal was only to allow
temporary modifications to be installed until the next refueling outage. Strides toward this
goal were evidenced to the inspector by evaluating PSE&G's trending of temporary
modifications and a review of the ages of installed temporary modifications.
The inspectors concluded that the temporary modification programs for both the Salem and
Hope Creek stations were good.
The inspectors reviewed one example of an installed temporary modification for each station
and the results of these reviews are described in the sections below .
12
4.3.1 Hope Creek Battery 1DD447 Cell No. 13 Jumpered Out (TM#94-010)
The inspectors reviewed Hope Creek Temporary Modification 94-010, "Battery 1DD447 Cell
No. 13 Jumpered Out." Battery Cell No. 13 was found to have low voltage and was
degraded below the allowable technical specification value of 2.13 vdc. To address this,
Hope Creek installed Temporary Modification 94-010 on April 14, 1994. The inspectors
verified that the TM contained the appropriate reviews, approvals, and the 10 CPR 50.59
safety evaluation. Additionally, the inspector reviewed the supporting calculations, and
found them acceptable and performed, in accordance with the guidance provided in Institute
of Electrical and Electronics Engineering (IEEE) Standard 485.
4.3.2 Salem Unit 2 Temporary Breaker Replacement (TM #92-040)
The inspectors reviewed Salem Unit 2 Temporary Modification 92-040, "Temporary Breaker
Replacement." Two molded case circuit breakers for safety-related motor-operated valves
were found to lack the required documentation, and there were no exact replacement
breakers on site. To address this, Salem replaced the original circuit breakers, which were
rated at 480V, with circuit breakers rated at 600V. In additional to the voltage rating
difference, the response time for the replacement circuit breakers varied slightly from that of
the originally installed equipment, but coordination was still maintained. The inspectors
verified that the TM contained the appropriate reviews, approvals, and 10 CFR 50.59
applicability review. Additionally, the inspector reviewed the supporting calculations and
found them acceptable.
This temporary modification was installed on June 26, 1992, and was scheduled for removal
October 31, 1993, during refueling outage No. 8. One replacement circuit breaker was
received on site and replaced on May 21, 1993.
The second circuit had not been received
as of May 20, 1994, but the inspectors noted that the target removal date for the temporary
modification was extended until November 5, 1994. A written justification was included in
the temporary modification package stating that the correct replacement part has not yet been
received on site, that the proper circuit breaker will be installed, and the temporary
modification will be removed as soon as the parts arrive.
4.4
Conclusion
The inspectors concluded that the modification process provided good guidance to the
preparer of the modification package. The guidance added to the design considerations
checklist regarding microprocessor equipment, and to the specialty review checklists
regarding the erosion/corrosion monitoring program, were considered noteworthy. The.
inspectors also concluded that the temporary modification programs for both the Salem and
Hope Creek stations were good.
The inspectors considered the 10 CPR 50.59 procedure improved over the previous revision,
in particular, the incorporation of the applicability review and safety evaluation guidance
- '
13
attachments. However, inspectors were concerned that the signature sheet associated with
the applicability review only states that the peer review is optional and may not provide
appropriate notice to the approver that the peer review is still required. Additionally, a
violation of the 10 CFR 50.59 requirements was identified associated with the replacement of
the lA and 460V Vital Bus Transformer described in Section 4.1.2.2 of this report.
The inspectors concluded that the two system interface design inadequacies were major
contributors to a reactor scram during startup testing of the completed Hope Creek digital
feedwater modification. The interface inadequacies were: (1) the upper range of the RFP
loop flow transmitters were not compatible with the actual full flow conditions; and (2) the
hardware logic for the RCP runback caused false runbacks. However, the engineering
process of the analog to digital requirement translation was well planned and executed.
Appropriate software verification and validation (V & V) activities, as well as independent
design reviews, were well planned and implemented.
5.0
CORRECTIVE ACTION PROGRAM (37700)
The inspectors reviewed the licensee's top level corrective action program, as described in
Procedure NC.NA-AP.ZZ-0058(Q), Revision 1, which provides direction and guidance to
nuclear department personnel for the identification and correction of conditions adverse to
quality. The procedure calls for identification, classification, documentation, causal analysis,
root cause analysis, corrective action, and follow-up for the varied quality conditions and
classifications that are possible for the nuclear department.
There is a sub-tier of procedures and forms that implement the program for the stations,
E&PB, procurement, material control, QA, security, and radiation protection. Each sub-tier
independently tracks its unique forms through its unique resolution process.
The licensee has partially implemented a corrective action database (CADB) within the
managed maintenance information system (MMIS) that will serve as the central identification,
processing, and tracking mechanism for the sub-tier procedures. The first phase of the
CADB program has implemented the sub-tier processes for the procurement function.
Various independent processes for the identification of discrepancies in receiving, warehouse,
vendor programs/processes, procurement documents, and QA were consolidated into a single
problem reporting system. The next phase is to be implemented in June 1994, which will
support the station and E&PB corrective action processes. Electronic signature approval,
with suitable security, is also planned.
The inspectors found the implementation of the CADB to be noteworthy because of its
potential benefits for the comprehensive processing and tracking of significant conditions
adverse to quality .
. ~
14
5.1
Licensee Event Reports
The inspectors verified the implementation of the corrective action process by the review the
following sample of licensee event reports (LERs):
LER 93-014-01, "4 kV Vital Bus Second Level Undervoltage Protection Dropout
Setpoint Concern," for Salem Units 1 and 2; and
LER 94-001-00, "Engineered Safety System Actuation - Isolation and Loss of
Shutdown Cooling Due To Personnel Error," for Hope Creek.
The inspectors determined that the LERs were analyzed correctly, the safety significance was
accurate, and the corrective actions were appropriate.
5.2
Overhead Annunciators (OHA) Followup
The inspectors reviewed the major technical issues and associated corrective action
concerning the overhead annunciators used in the Salem station. These issues are described
in NRC AIT Report 92-81, and the licensee's Report 92-05 of the significant event response
team (SERT) concerning the control room overhead annunciator lock-up on
December 13, 1992. The SERT report provided recommended corrective action items that
were in consonance with the root causes of the AIT report.
The corrective actions of the SERT report were translated to 23 action items on the action
tracking system (ATS). After the event, the E&PB computer systems group obtained
independent assessments of the OHA system design and the design change process used for
the OHA. The independent assessments were a factor in determining some of the details of
the corrective actions.
The inspectors reviewed the ATS close out reports to determine the quality of the corrective
actions. The three ATS items that remain open involve: OHA preventive/corrective
maintenance procedures completion; ensuring that operator training and walkthrough are
provided for all significant to operation modifications; and providing software review for
modifications involving software. The closed items resolved the issues of system
- redundancy, system status indication, failure detection/indication, false operation due to
noise, and physical security for system access devices.
The inspectors concluded that the corrective actions covered the appropriate areas, such as
system status, spurious operation, human-machine interface, access security, maintenance,
operator training, and engineering processes.
The inspectors interviewed members of the digital systems group on lessons learned from the
original OHA event. The topics covered areas such as: requirements and bid specifications;
critical design review of the architecture, software, and failure modes and effects analysis
15
(FMEA); plant interfaces, procedures, maintenance; design verification; testing and
validation; and operation. One major corrective action was that the digital systems group
was formed to provide digital expertise and leadership throughout the life cycle of digital
equipment.
The inspectors concluded that the management leadership and understanding of digital issues
in response to the OHA event was the most significant corrective action.
5.3
10 CFR Part 21 Potential Defect
The inspectors reviewed a 10 CFR Part 21 report of a potential defect in software used in
radiation monitors to verify the corrective action program. The report was written on
February 10, 1994, by the vendor. The problem was a microprocessor stack overflow
anomaly that could lead to unanticipated subroutine Calls that could cause the microprocessor
to perform unanticipated tasks. The vendor determined that the anomaly could be fixed by
software changes.
On March 9, 1994, an evaluation request was put on the ATS network, which is part of the
corrective action program. On April 28, 1994, the evaluation was completed and the
recommendation was made that the software change be purchased for 17 types of radiation
monitors in Hope Creek and the three types in Salem .
The E&PB digital systems group also identified one other software problem that needed to be
corrected by the vendor. The vendor stated that probability of software anomalies actually
occurring in the installed radiation monitors was low. The Salem and Hope Creek stations
were advised to increase their surveillance until the new software could be ordered and
installed.
The inspectors verified another corrective action, by interviews, that pertained to the
radiation monitor vendor. Based on the lessons learned from the OHA event, the E&PB
digital systems group initiated an independent design review of the vendor for a new
radiation monitor purchase and found problems in the new product line software. The digital
systems group initiated corrective action th~t culminated in the cancellation of the purchase
order for the new product line.
5.4
Conclusion
Based on the reviews of the LER's, the OHA corrective actions, and the 10 CFR Part 21 for
the radiation monitors, the inspectors concluded that the licensee's corrective action program
was well implemented .
---
----------- ---- - ------- --
. *
16
6.0
QUALITY ASSURANCE (37700)
The inspectors reviewed the quality assurance (QA) department involvement in engineering
activities. The QA department performs engineering technical support audits on a biennial
basis, with the next audit scheduled in June 1994. In addition to their regular audit of
specific engineering areas, the QA department has started to perform special assessment
audits that involve engineering in certain areas, such as: licensing and regulation; testing of
redundant components; erosion/corrosion; and balance of plant process controls.
The inspectors reviewed documents related to the special assessment audit of the testing of
redundant components. The audit was concerned with the principle that redundant devices
should be tested independently and not jointly. The con~rn surfaced after the licensee
determined that independent testing of redundant devices could possibly have avoided or
mitigated eertain past incidents at the stations. The methodology identified both safety and
non-safety systems of significant concern. The testing criteria of the srstems were examined
for independence. A search was conducted by the reliability and assessment group to
determine and assess industry events on the testing of redundant devices. The final report of
the assessment was not yet completed. The inspectors concluded that the methodology used
will allow assessment of any generic implications in the testing of redundant devices.
7.0
ORGANIZATION INTERACTIONS (37700)
Through observation of, and discussions with PSE&G staff, the inspectors evaluated several
methods by which the organizations within PSE&G interact and communicate. The areas
reviewed included the following:
station morning report;
daily morning meeting; and
system engineer presentations.
7.1
Station Morning Report
The inspectors observed the station morning report telephone call held on March 29, 1994.
This telephon,e call is between the stations and E&PB, discusses recent plant problems,
ongoing work, and upcoming licensing events. The inspectors considered this to be a good
method of communicating recent plant problems to the engineering department, and allowed
the engineering department to provide prompt additional expertise, if required.
7.2
Daily Morning Meeting
The inspectors also observed the nuclear engineering daily morning meeting held on
March 29, 1994. This meeting starts shortly after the station morning report telephone call,
and provides the engineering department the opportunity to discuss several topics, including:
17
Support required to assist the stations with recent plant problems;
Review station forced outage list;
Training issues; and
DCP progress.
Discussions with Salem technical staff identified similar daily meetings for both the Salem
and Hope Creek stations. These meetings allow the various departments within the stations
to discuss recent problems and upcoming events.
7.3
System Engineer Presentations
The inspectors interviewed members of the technical staff and identified a Salem station
program where system engineers present the status of their systems to plant management. A
different system is presented every other week, which allows for every system to be covered
in a little over a year. Some of the major areas addressed during each presentation are the
long- and short-term problems; recent and upcoming modifications; tracking and trending of
related parameters and maintenance and obsolete parts issues. The inspectors considered this
to be a good method to periodically update plant management on the details associated with
each system .
7 .4
Conclusion
The inspectors evaluated several methods by which the organizations within PSE&G interact
and communicate, and found them to be appropriate. The station morning reports and the
Salem system engineer presentations were considered particularly noteworthy.
8.0
PLANT W ALKDOWNS (37700)
The inspectors performed plant walkdowns of both Salem and Hope Creek stations to assess
their housekeeping efforts. These walkdowns included the diesel generator rooms, the
battery rooms, the switchgear rooms, and various pump rooms for both plants.
The material condition for both stations was found to be good. However, during the
walkdown of Hope Creek Station, which was midway through a scheduled refueling, a few
exceptions were noted where gear was not stored appropriately. These exceptions were
brought to the attention of the licensee, and were corrected the same day.
9.0
ENGINEERING SELF-ASSESSMENT AND PERFORMANCE INDICATORS
(37700)
The inspectors reviewed the following self-assessment programs and initiatives used by
E&PB to improve safety, quality, productivity, and cost-effectiveness .
..*
18
engineering assurance and self-assessment process;
engineering performance indicators;
offsite safety review (OSR) of 10 CFR 50.59 safety evaluation reviews; and
design change process improvement team.
9.1
Engineering Assurance and Self-Assessment Process
The inspectors reviewed PSE&G's engineering assurance and self-assessment process. This
process, as defined in Procedure ND.DE-PS.ZZ-0022(Z), Revision 0, divides the self-
assessments process into four elements: engineering professionalism, individual-initiated
self-assessment, collegial self-assessment, and integrated performance data. The focus of this
procedure is on the collegial self-assessment process, and provides guidance for the
scheduling and performance of those assessments. The self-assessments are formal, planned
reviews that are coordinated by the nuclear engineering standards group. The self-
assessment teams use root cause techniques, as necessary, in their reviews and track all open
items through the ATS. In addition, these assessments are coordinated with other reviews,
such as QA audits and other inspections to maximize the unitization of resources. The
inspectors also reviewed the 1994-1996 nuclear engineering self-assessment schedule, and
found it covered a wide range of well-defined topics.
The inspectors considered PSE&G's engineering self-assessment process to be proactive;
however, since this program is relatively new, future evaluation is required to determine the
overall effectiveness of the program.
9.2
Engineering Performance Indicators
The inspectors reviewed documents and interviewed engineering staff to determine how
PSE&G tracks and trends engineering performance. The licensee monitors in excess of 40
engineering and engineering-related functions through their performance indicator program to
monitor their effectiveness. Included in the areas monitored are:
DCP backlog;
DCP closure performance;
DCP performance;
DEF backlog;
Drawing/document updating performance;
Plant systems downtime; and
Safety evaluation quality.
The inspectors noted that PSE&G did not track the number of modification concern
resolutions (MCRs) per modification as an indication of the quality of the up-front
engineering. Discussions with the PSE&G staff indicated that the number of MCRs per
modification was tracked as recently as September 1992, with an average of less than one
MCR per modification; and, therefore, this item was removed from the trending program.
19
However, prior to this inspection, PSE&G was in the process of developing specific quality
measures for the tracking of MCRs issued against modification packages during the up-
coming Salem Unit 2 refueling outage scheduled for fall 1994.
The inspectors observed the graphical representations of this information posted in the lobby
of the engineering building. The graphs were broken down by station or by engineering
discipline, and often indicated engineering management's desired goals of each area. The
inspectors considered these performance indicators to be a good method of providing both
management and staff a centrally located quantitative measure of their composite
performance.
9.3
Offsite Safety Review of 10 CFR 50.59 Safety Evaluation Reviews
The inspectors evaluated the offsite safety review (OSR) program for the review of 10 CFR
50.59 safety reviews and evaluations. The Salem and Hope Creek technical specifications
require that the OSR conduct an independent review of the 10 CFR 50.59 safety evaluations
to verify that such changes do not involve an unreviewed safety question. The process used
by the OSR includes reviewing the safety evaluations and accompanying documents, and
reporting the results to department managers, the vice president, and chief nuclear officer.
During the OSR review of the safety evaluations, the evaluations are rated on a scale of one
to four, with one being acceptable with no comments, and four being unacceptable. Ratings
of two and three are both acceptable, with a varying degree of comments. In cases where
the safety evaluations are unacceptable, action requests are issued to request corrective
actions. All other comments are formally transmitted monthly to the appropriate department
manager.
The results of the OSR safety evaluation reviews are provided in both a nuclear safety review
monthly report and an off site safety review quarterly report. The inspectors reviewed the
January 1994 monthly report and the first quarter report for 1994 and found them to contain
detailed comments and useful trending information regarding the safety evaluation quality.
9.4
Design Change Process Improvement Team
The inspectors reviewed the design change process improvement team (DCPIT) report, dated
December 8, 1993. This team conducted many interviews with both customers and users of
the design change process, and obtained benchmark information through visits to four other
utilities and three nonutility organizations. The team generated 36 recommendations in five
areas: (1) scope; (2) review and approval; (3) modification and test instructions; (4) bills of
materials; and (5) documentation update. The inspectors considered this to be a good effort
and noted that a number of these recommendations were incorporated into the latest revisions
of modification-related procedures .
20
9.5
Conclusion
The inspectors considered PSE&G's engineering-related self-assessment initiatives to be
good. Particularly, the recently developed engineering assurance and self-assessment
process, which has the potential for providing PSE&G valuable information regarding the
performance of the engineering functions. However, since this program is relatively new,
future evaluation is required to determine its overall effectiveness.
10.0
ENGINEERING ISSUES (37700)
10.1
Prioritization of Engineering Issues
The inspectors reviewed an E&PB critical issues database printout and a top 20 critical issues
list. The printout contained 76 issues and identified: the date the issue was identified; an
issue title with a description; and an assigned manager. The descriptions were clear and
understandable, and the issues were sorted by responsible manager order and in ascending
log number, which roughly corresponded to the date the issue was identified. The top 20
critical issues list had 65% of the issues pertaining to Salem, 10% to Hope Creek, and 25%
unassigned. The unassigned items pertained to such issues as: bill of material database
validation for key equipment, engineering discrepancy backlog reduction, refrigerant (CFC)
replacement, and elimination of
11 Based upon the review of these two
documents, the inspectors concluded that engineering issues are documented as they occur,
and are then prioritized by engineering management.
10.2
Operational Experience Feedback .
The inspectors evaluated PSE&G's programs and initiatives for the handling of industry
information. The operational experience feedback (OEF) program is sponsored by the
reliability and assessment (R&A) staff at PSE&G. The OEF program consists of periodic
meetings with both the station and E&PB managers to discuss the incoming OEF items and
assigns responsibility for the disposition of each. Additionally, R&A issues a monthly OEF
report containing trending information and status on the open OEF items.
Throughout this inspection, the inspectors noted instances where industry information was
effectively utilized in the digital feedwater system upgrade and the Salem emergency diesel
generator field flash supervisory circuit (Sections 4.1.1.1 and 4.1.1.2).
The inspectors also reviewed PSE&G's use of industry information as an aid in the
development of proposed engineering projects. Guidance is provided in both Procedure
ND.OA-PJ.ZZ-0003(Z), "Project Scope Proposals,
11 and ND.OA-PJ.ZZ-0015(Z), "Project
Evaluation Packages, " to perform a review of industry experience to benefit from lessons
learned. The inspectors considered this use of industry information to be noteworthy.
---~----
21
11.0
EXIT MEETING
At the conclusion of the inspection on May 20, 1994, the inspectors met with licensee
- representatives denoted in Attachment 1. The inspectors summarized the scope and results of
the inspection at that time. The licensee acknowledged the inspection findings, and
confirmed the commitment, as detailed in Section 4.1.2.2 of this report, to perform certain
reviews per 10 CFR 50.59. Also, at this exit meeting, it was established that Mr. G. Englert
would be the PSE&G technical contact for future NRC discussions regarding the issues
covered by this report.
Attachment: Persons Contacted
ATTACHMENT 1
PERSONS CONTACTED
Public Service Electric and Gas Company
- C. Atkinson
- J. Bailey
B. Barkley
R. Bashall
P. Benini
- S. Bruna
- M. Burnstein
R. Chranowski
- J. Clancy
B. Conner
- A. Culliton
W. Daczkowski
L. Dyer
- G. Englert
S. Funsten
A. Garcia
- A. Giardino
W. Gott
M. Gray
- T. Haehle
C. Hudson
F. Kaminski
E. Karpe
- K. Kimmel
R. Klosek
C. Lambert
J. Lin
W. Lowry
D. Lyons
R. Malone
- C. Manges
T. McClave
- M. Metcalf
P. Morakinyo
C. Nentwig
D. Patel
L. Piotti
B. Preston
Instrumentation & Controls Supervisor, Hope Creek
Nuclear Engineering Science Manager
Senior Engineer, Reliability and Assessment
Fire Protection & Penetration Seal Supervisor
Principal Engineer, QA Audits
Vice President, Nuclear Engineering
Nuclear Electrical Engineering
Electrical Technical Engineer, Salem*'
Technical Manager, Hope Creek
Technical Department Engineer, Salem
Standard and Assurance Supervisor
Senior Engineer
Technical Department Administrative Clerk, Hope Creek
Nuclear Engineering Standards Manager
Maintenance Manager, Hope Creek
System Engineer, Salem
Manager, Quality Assurance Programs & Audits
Principal Nuclear Training Supervisor
Licensing Engineer, Hope Creek
Senior Staff Engineer, Nuclear Electrical Engineering
Technical Department Administrative Clerk, Salem
Technical Department Senior Engineer, Salem
Principal Engineer, QA Programs
Senior Staff Engineer, Nuclear Engineering Standards
Senior Staff Engineer
Nuclear Engineering Service Manager
Specialist Engineering Supervisor
Technical Department System Engineer, Salem
Technical Department Lead System Engineer, Salem
Staff Engineer, Nuclear Licensing
Licensing Engineer, Hope Creek
System Engineer, Salem
Nuclear Engineering Project Manager
System Engineer, Salem
Principal Engineer, Hope Creek
Civil Mechanical Engineer
Senior Staff Engineer, QA Programs
Manager, Nuclear Engineering Projects
.......
Attachment 1
2
Persons Contacted
PubHc Service Electric and Gas Company. (continued)
- J. Ranalli
- R. Ritzman
M; Quadin
B. Smith
D. Smith
K. Staring
S. Stives
C. Stokes
R. Swanson
- F. Thompson
R. Veideman
- J. Volence
- C. Waite
M. Woloski
Manager, Nuclear Mechanical Engineering
Lead Engineer, Nuclear Licensing
Senior Project Engineer
Lead Engineer, Salem
Principal Engineer, Nuclear Licensing
Technical Department System Engineer
Associate Engineer
Electrical Engineer
General Manager, QA/NSR
Licensing and Regulations Manager
Engineer, I&C
Senior Staff Engineer, Nuclear Engjneering Standards
Digital Systems Supervisor
Instrumentation & Controls Engineer
U.S. Nuclear Regulatory Commission
S.Barr
- T. Fish
- T. Liu
C. Marschall
- J. Shannon
- J. Trapp
Resident Inspector
Resident Inspector
Project Engineering, NRR
Senior Resident Inspector
Reactor Engineer, Region I
Acting Section Chief, Electrical Section, Region I
- Denotes those present at the exit meeting on May 20, 1994.