ML18101A219
| ML18101A219 | |
| Person / Time | |
|---|---|
| Site: | Salem, Hope Creek  |
| Issue date: | 09/07/1994 |
| From: | Ruland W, Richard Skokowski NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML18101A217 | List: |
| References | |
| 50-272-94-18, 50-311-94-18, 50-354-94-18, NUDOCS 9409130298 | |
| Download: ML18101A219 (16) | |
See also: IR 05000272/1994018
Text
DOCKET/REPORT NOS:
LICENSEE:
FACILITY:
INSPECTION AT:
DATES:
SUBMITTED BY:
APPROVED BY:
U. S. NUCLEAR REGULATORY COMMISSION
REGION I
50-272/94-18
50-311/94-18
50-354/94-18
Public Service Electric and Gas Company
Salem 1 & 2 and Hope Creek Generating Stations
Hancocks Bridge, New Jersey 08038
Hancocks Bridge, New Jersey
August 8 - 12 and 18 - 22, 1994
RiCarA.so owskl;ReictorEngi neer
Electrical Section
Division of Reactor Safety
'f Se:or 94
Date
c;-7-9j
Date
Area Inspected: This was an announced inspection to review the licensee's
corrective actions of previously identified electrical .distribution system
functional inspection (EDSFI) findings.
Additionally, evaluations of the troubleshooting of the rod control process
signal noise at both Salem Units and the load fluctuations on the Salem IA
emergency diesel generator (EOG) identified during surveillance testing on
August 16, 1994, were performed~
Results: During this inspection, two previously identified deviations and one
unresolved item at Hope Creek and three unresolved items at both the Salem
Units were review and closed. The inspector considered the engineering
evaluation, associated with the potential failure of the Salem rod control
motor generator set flywheels, to be technically sound.
The acceptance criterion for the Hope Creek 125V battery service test was
found to be inadequate.
The same issue was identified by the inspector for
the 125V battery service tests at both Salem Units. These examples of
inadequate test acceptance criteria were considered a violation of 10 CFR 50
Appendix B, Criterion XI, "Test Control." The violation is of concern because
the acceptance criteria for the 125V battery service test at Hope Creek and
Salem Units 1 and 2 were inadequate to assure the functionality of safety-
related equipment. Specifically, the acceptance criteria provided in the test
procedures were not consistent with design documents and were not
9409130298 940907
ADOCK 05000272
G
conservative. The inadequate acceptance criterion was identified as an
unresolved item at Hope Creek by the EDSFI in early 1992.
However, the
engineering staff failed to adequately address a similar problem with the
Salem test procedures.
The inspector concluded that when the PSE&G maintenance staff started around-
the-clock troubleshooting of the rod control process signal noise, the
troubleshooting was methodical and thorough. Additionally, the
troubleshooting associated with the EOG load fluctuations was found to be
adequate. The root cause analysis for the identified EDG component failures
was not completed at the conclusion of this inspection and was identified as
an unresolved item.
The inspector considered the independent review of the design change packages
for the upcoming refueling outage at Salem Unit 2, to be noteworthy, in that
it provided the licensee a chance to re-review packages that were prepared in
advance.
The inspector considered the changes to the
11 Engineering Assurance Self-
Assessment Process
11 procedure, and the use of team leader training for
collegial self-assessment team leaders to be good.
ii
DETAILS
1.0
PURPOSE
This inspection reviewed actions taken to address previously identified
electrical distribution system functional inspection (EDSFI) unresolved items.
In addition, this inspection evaluated the effectiveness of the root cause
investigations initiated in response to apparent malfunctions of the Salem
automatic rod control systems and the Salem IA emergency diesel generator
(EDG).
2.0
FOLLOWUP OF PREVIOUS IDENTIFIED FINDINGS (2515/111)
2.1
Salem Units 1 and 2
Three previously identified unresolved items were reviewed for both Salem
Units.
2.1.1 (Closed) Unresolved Item (50-272;311/93-82-03) EOG Output Voltage Below
Allowable Degraded Voltage
The EDSFI team identified that the EDG surveillance test procedures for both
Salem Units and the Unit 2 Technical Specification {TS) allowed the EDG to be
operated at a steady-state voltage lower than the degraded voltage setpoint.
The degraded voltage setpoint was established to ensure that adequate voltage
would be available to required electrical equipment.
Additionally, the EDSFI
team noted that there was no specified limit on EDG running voltage in the
Unit 1 TS.
The inspector verified that Public Service Electric and Gas Company (PSE&G)
completed the corrective actions described in their response letter to the
NRC, NLR-N94013, dated February 7, 1994, regarding the EDSFI findings.
The
corrective actions included:
changing the Unit 2 minimum steady state EDG voltage Technical
Specification surveillance requirement to greater than or equal to
3950V;
adding a Technical Specification requiring Unit 1 minimum steady state
EDG voltage to be greater than or equal to 3950V; and
revising the appropriate surveillance procedures to reflect this minimum
required value for steady state EDG voltage.
The inspector found the licensee's actions appropriate and considered this
item closed .
2
2.1.2 (Closed) Unresolved Item (50-272;311/93-82-11) Potential Damage of Vital
Buses from a Failure of a Rod Control Motor-Generator Set Flywheel
The EDSFI team identified a concern regarding the potential damage to safety-
rel ated vital buses from a failure of the rod control motor-generator {MG) set
flywheels.
These MG sets are classified as nonsafety-related.
The concern
was that the disintegration of the flywheel could damage 4kV vital buses.
PSE&G developed Engineering Evaluation S-C-RCS-SEE-0866,
11 Rod Control System
MG Set Flywheel Failure,
11 January I2, I994, to determine the potential of a
failure of the Rod Control MG Set flywheel. This evaluation concluded that a
failure of the flywheel could damage both vital buses A and B.
However, the
evaluation determined that the flywheel disintegration was not credible. This
determination was based on information provided by Westinghouse, that the
flywheels, which were design-procured and fabricated under closely controlled
quality standards, have such a high degree of structural integrity that a
postulated failure was not credible.
The inspector reviewed the associated engineering evaluation and determined
that it was technically sound.
The evaluation used a methodology similar to
that used in Regulatory Guide 1.14, "Reactor Coolant Pump Flywheel Integrity,
11
to determine the integrity of the rod control MG set flywheels.
Additionally,
the evaluation stated that there has never been a reported Westinghouse
nuclear unit MG set flywheel structure failure.
The engineering evaluation
also stated that the flywheels are enclosed by steel casings and that there
are marinite board barriers between the MG sets and the vital buses.
These
barriers would deflect any missiles generated by the postulated flywheel
failure.
The inspector performed a walkdown on the MG sets and surrounding
area and verified the installation of these barriers.
The inspector determined this engineering evaluation to be technically sound.
Unresolved Item 50-272;3Il/93-82-1I is considered closed.
2.1.3 (Update) Unresolved Item (50-272;311/93-82-15) Potential High
Temperature Aging of Vital Batteries lC and 2C
The EDSFI team identified that the IC and 2C batteries may have experienced
accelerated aging due to high ambient battery room temperatures.
The EDSFI
noted that surveillance test data indicated that the IC and 2C batteries had
operated with ambient room temperatures ranging from 70°F to 96°F.
The other
station vital batteries normally were within a three or four degrees band of
the nominal operating temperature of 77°F.
The team also noted other
indications of potential accelerated aging of the IC battery, such as an
abnormal operating characteristic, the failure of Cell No. 47 and the build up
of sediment in the jar bottoms of several IC battery cells.
To address this issue, PSE&G replaced the IC battery in April I994.
The
battery vendor perform a root cause analysis of the failed cell.
In addition,
PSE&G performed a review of the battery surveillance test temperatures and
evaluated the impact of these temperatures on the aging of batteries IC and
3
2C.
The results of this evaluation were provided to the NRC in a May 7, 1994,
letter from PSE&G regarding the EDSFI findings, and concluded that the 2C
battery did not need to be replaced at this time.
This evaluation stated that according to the vendor, that the operation of the
batteries in an increased temperature will decrease the life expectancy of the
battery cells. The vendor stated that for every l8°F above 77°F will decrease
the battery life by 50%.
However, the increased temperature does not increase
the potential for a sudden catastrophic battery failure.
PSE&G also stated
that the existing surveillance program adequately monitors the battery status.
Therefore, any degradation of the battery life due to varying temperatures
will be detected before it leads to battery failure.
The inspector performed a walkdown of the battery rooms and reviewed the
vendor's information and determined that it was consistent with PSE&G's
evaluation.
The inspector also reviewed the battery performance test and
service test procedures. These tests were found to be performed in accordance
with the guidance provided in the Institute of Electrical and Electronics
Engineers (IEEE) Standard 450-1987, "IEEE Recommended Practice for
Maintenance, Testing and Replacement of Large Lead Storage Batteries for
Generating Stations and Substations." However, the acceptance criterion for
the service test was found to be inadequate.
Prior to the completion of this
inspection, PSE&G took actions to ensure the proper acceptance criterion was
reflected in the procedures. This issue is described in Section 2.1.4 of this
report.
The written root cause analysis for the failed lC Battery Cell No. 47 had not
been provided to PSE&G at the conclusion of this inspection.
However, the
battery vendor had verbally informed PSE&G of the analysis results.
PSE&G
stated that the root cause was determined to be a random failure that allowed
for an internal plate-to-plate short-circuit. This failure caused the cell to
become degraded, but testing performed by both the licens.ee and the vendor
indicated that it was not a complete failure of the cell.
Based on the conclusion of PSE&G's evaluation that the high ambient
temperatures do not increase the potential for a sudden catastrophic battery
failure, and PSE&G's actions to correct the 125V battery service test
acceptance criteria to ensure the detection of degradation of battery life,
the inspector considered Unresolved Item 50-272;311/93-82-15 closed.
2.1.4 Inadequate Acceptance Criteria for the Battery Service Test
The inspector identified that the acceptance criterion established in
Procedure SC.MD-ST.125-0004(Q), "125 Volt Station Batteries 18 Month Service
Test and Associated Surveillance Testing using BCT-2000," Revision 3, was
inadequate.
The acceptance criterion of 105V did not appropriately include
the voltage drop between the battery terminals and the attached safety-related
equipment.
Based on the PSE&G Calculation ES-4.003Q, "125V VDC System Study,"
the acceptance criteria should have been 113.4V for the "A" batteries and
112.8V for the "B" and "C" batteries. Service test results less than the
voltages determined by the calculation indicate that the battery would not be
capable of supplying the necessary voltage to assure safety-related equipment
4
functionality required for accident mitigation. The inspector verified that
the results of the last service test for each battery indicated a voltage
level greater than the newly determined acceptance criteria.
PSE&G developed
a procedure change request to address this issue, requiring that the
procedures be changed prior to the next use.
Battery testing was not reviewed
during the Salem EDSFI.
However, this issue was identified as an unresolved
item during the Hope Creek Station EDSFI in I992.
The Hope Creek issue is
described in Section 2.2.1 of this report.
The inadequate acceptance criteria for the I25V service testing is considered
a violation of IO CFR 50 Appendix B, Criterion XI, "Test Control," (50-
272;3Il/94-I8-0I). This violation will be combined with the same issue
identified at Hope Creek Generating Station (HCGS) as described in Section
2.2.I of this report.
The technical issues associated with this violation are
complete; however, there still is a concern in that the item was identified at
Hope Creek during the EDSFI in early 1992, but was not addressed in the Salem
Station procedures.
2.2
Hope Creek
Two previously identified deviations and one previously identified unresolved
item for Hope Creek Generating Station.were reviewed.
2.2.1 (Closed) Unresolved Item (50-354/92-80-04) Inadequate Battery Service
Testing Acceptance Criteria.
The EDSFI team identified a concern regarding the adequacy of the 125V and
250V de battery service test acceptance criteria as stated in both the TS and
surveillance procedures.
The acceptance criteria failed to include the cable
voltage drop.
PSE&G revised the associated voltage drop calculations to include the cable
voltage drop, and to determine the appropriate service test acceptance
criteria.
PSE&G determined that the previously identified acceptance
criterion of 2IOV was acceptable for the 250V batteries. However, PSE&G
determined that the previously identified acceptance criterion of lOSV for the
I25V batteries was inadequate to assure the functionality of safety-related
equipment.
PSE&G determined the appropriate acceptance criterion to be 108V.
On March 3, I994, this new acceptance criterion was incorporated in the
appropriate surveillance test, HC.IC-ST.PK-0002(Q), "I8 month surveillance &
service test of the I25 Volt Batteries Using BCT-2000."
PSE&G was also
preparing a license amendment request to change the associated TS surveillance
test acceptance criterion.
Through discussions with PSE&G staff members and a sample review of
Calculations E-4.2(Q), Revision 3, "Hope Creek Generating Station IE DC
Equipment & Component Voltage Study," and E-4.2(Q), Revision 3, "Hope Creek
Generating Station I25V & 250V CL IE DC System:
Short Circuit & Voltage Drop
Studies," the inspector verified the acceptance criteria for both the I25V and
250V batteries .
5
The inspector also reviewed Procedure HC.IC-ST.PK-0002(Q), Revision 1,
11 18
month surveillance & service test of the 125 Volt Batteries Using BCT-2000,"
approved March 18, 1994. This procedure included the acceptance criterion of
108V.
Based on the inspectors review, and PSE&G's commitment to complete the
associated license amendment request, Unresolved Item 50-354/92-80-04 is
considered closed. However, the inadequate acceptance criterion for the 125V
service testing is considered a violation of 10 CFR 50 Appendix B, Criterion
XI, "Test Control," (50-354/94-18-01).
This violation will be combined with
the same issue identifi.ed at Salem Generating Station as described in Section
2.1.4 of this report.
The technical issues associated with this violation are
complete; however, there still is a concern in that the item was identified at
Hope Creek during the EDSFI in early 1992, but a similar deficiency was not
addressed in the Salem Station procedures.
2.2.2 (Closed) Deviation (50-354/92-80-05) EDG Fuel Oil Storage was Not
Consistent With Seven Day Updated Final Safety Analysis Report (UFSAR)
Cammi tment
The EDSFI team identified that each dedicated EDG fuel reserve could not
independently sustain seven days of worst-case EDG operation, as described in
Section 9.5.4 of the UFSAR.
Section 9.5.4 of the UFSAR stated that "each set
of storage tanks can store a quantity of diesel fuel oil that is sufficient
for 7 days of continuous operation of one EDG unit under rated operating loads
as described in EDG loading Tables 8.3-2 through 8.3-6.
11
The EDSFI team's
review of applicable calculations indicated a shortage of 5579 gallons to meet
the seven-day commitment of 151,979 gallons when three EDGs were operating
(assuming one EDG inoperable).
-
The inspector reviewed the licensee's responses to this deviation as provided
in letters to the NRC dated July 10, 1992 and November 19, 1992.
In their
initial response, PSE&G indicated that they would review and revise their
UFSAR loads tables to demonstrate that there was sufficient fuel oil to power
the required loads for seven days following the worst case conditions.
In
their second response to this deviation, PSE&G indicated that revising the
UFSAR load tables would limit the operators' ability to load nonsafety-related
loads on the EDGs in accordance with the current emergency operating
procedures (EOPs).
PSE&G determined that there were more safety benefits for
leaving the operators with the ability to load nonsafety-related loads on the
EDGs.
Therefore, PSE&G requested that*the NRC provide relief from their HCGS
UFSAR commitment to the Standard Review Plan, Section 9.5.4.
The relief from this UFSAR commitment was made in the form of a license
amendment request, dated December 23, 1993.
A license amendment was required
because the change involved an unreviewed safety questions as identified by
the licensee. This license amendment request was reviewed by the Office of
Nuclear Reactor Regulation (NRR) staff and found acceptable as documented in
the Safety Evaluation related to Amendment Number 59 to facility Operating
License Number NPF-57.
6
The bases for PSE&G's license amendment was that since the quantity of fuel
oil was only a concern in the case where one EDG is not available, the fuel
oil from the two storage tanks associated with the inoperable EDG could be
used to ensure an adequate fuel oil supply. Since the fuel oil cross-tie
lines are designed as non-seismic Category I, Quality Group D, the licensee
proposed to pre-stage equipment necessary to maintain fuel oil transfer
capability should the fuel oil cross-tie lines not be available following an
accident. Additionally, procedures were to be in place for the transferring
fuel between fuel oil storage tanks when the cross-tie lines are intact ..
The inspector verified a selected sample of items addressed in the Safety
Evaluation. This included a walkdown of the pre-staged fuel transfer
equipment and storage tanks, a review of the related procedures and
discussions with members of the HCGS operating staff. These items were found
to meet the intent of the Safety Evaluation.
During the_walkdown of the pre-staged fuel transfer equipment and subsequent
discussions with the Hope Creek Operation Management, the inspector noted that
the ends of the pre-staged hoses were not sealed to prevent the introduction
of dirt.
HCGS Operation Management stated that they will address this issue.
Also noted was that the pre-staged fuel oil transfer pump was used by the
operating staff to transfer other fuel oil. This operation, while not
considered scheduled testing, did provide some periodic assurance of the
ability of the pump to work.
The PSE&G licensing staff stated that the proposed UFSAR changes associated
with this deviation were currently scheduled to be included in the Spring 1996
UFSAR revision.
The corrective actions taken were appropriate and Item 50-
354/92-80-05 is closed.
2.2.3 (Closed) Deviation (50-354/92-80-06) EOG Day Tank Does not meet UFSAR
Conunitment
'
The EDSFI team identified that the EDG tank fuel oil capacity was not
consistent with the Hope Creek UFSAR.
Paragraphs 9.5.4.2 and 1.8.1.137
described that the EDG fuel oil storage system was sized in accordance with
the requirements of Regulatory Guide 1.137, "Fuel-Oil Systems for Standby
Diesel Generators," Revision 1, which in turns refers to American National
Standards Institute (ANSI} Standard Nl95-1976.
This standard requires the day
tank for each EOG to be sufficient to maintain at least 60 minutes of EOG
operation at the level where fuel oil is automatically added.
This capacity
is based on the fuel consumption at a load of 100% of continuous rating of the
diesel plus a minimum margin of 10%.
At the time of the EDSFI, the licensee
estimated the day tank capacities to be about 47 minutes.
The inspector reviewed the licensee's responses to this deviation as provided
in letters to the NRC dated July 10, 1992 and November 19, 1992.
In their
initial response, PSE&G indicated that.they would be to revise the start
setpoint of the EDG fuel oil transfer pump to meet the requirements of ANSI
Standard Nl95-1976, and.submit a change to the TS to revise the minimum fuel
oil day tank level to correspond to the revised setpoint.
In their second
response to this deviation, PSE&G indicated that revising the start setpoint
7
of the EDG fuel oil transfer pump to meet the requirements of the ANSI
Standard would increase the cycling of the transfer pump seven times and
increase the probability of pump motor failure. Therefore, PSE&G requested
that the NRC provide relief from their commitment to Regulatory Guide 1.137 as
stated in HCGS UFSAR Section 1.8.1.137. The revised HCGS UFSAR would take
exception to Regulatory Guide 1.137 and provide administrative controls to
ensure that the EDG day tanks were adequately filled following the operation
of an EDG.
Additionally, the fuel oil transfer pump start setpoint was
increase to a level that provides approximately 55 to 60 minutes of EDG
operation at full load.
The relief from this UFSAR commitment was made in the form of a license
amendment request, dated December 23, 1993. A license amendment was required
because the lic~nsee determined that the change involved an unreviewed safety
questions. This license amendment request was accepted by the NRR staff as
documented in Amendment Number 59 Safety Evaluation.
The inspector verified a selected sample of items addressed in the Safety
Evaluation.
This included a walkdown of the EDGs and the associated day
tanks, a review of fuel consumption calculations, a review of the fuel oil
transfer pump starting relay calibration and a review of the EDG day tanks
levels from July 1, 1994 to August 10, 1994.
The information reviewed was
determined to be consistent with the Safety Evaluation.
Discussions with the PSE&G licensing staff indicated that the proposed UFSAR
changes associated with this deviation were scheduled to be incorporated in
the Spring 1996 UFSAR revision. Additionally, the TS change associated with
the EOG fuel oil transfer pump start setpoint was submitted to NRR on
April 25, 1994.
The inspector concluded that the licensee actions to address
the deviation were acceptable and Item 50-354/92-80-06 is closed.
3.0
TROUBLESHOOTING - SALEM GENERATING STATION (92903)
3.1
Rod Cont~ol Process Signal Noise - Salem Units 1 and 2
The inspector assessed various aspects of PSE&G's troubleshooting of the rod
control process signal noise.
Background
On May 30, 1994, PSE&G started troubleshooting a problem at Unit 2 with the
automatic rod control system.
The problem was that the control rods would
step in half steps without appropriate process demand signals. The trouble
shooting continued off and on, due to various plant shutdowns and work
priorities, until August 1, 1994.
On August 1, 1994, around-the-clock
monitoring and troubleshooting began.
This troubleshooting identified noised
on the average temperature (Tav.} and nuclear instrument (NI} signals to rod
control.
On August 8, 1994, by Plant Manager request, a Task Force was
developed to address the concerns with rod control process signal noise.
The
goal of this task force was to understand if the noise from Tave and Nis was
expected, and what should be done to address it.
8
Task Force
Until the development of the task force, the maintenance department was the
only organization involved with the troubleshooting.
The PSE&G staff
justified this by stating that the maintenance department needed to gain an
understanding of the problem, and an opportunity to correct the problem before
getting outside assistance. With the development of the task force,
engineering and vendor support was provided.
The inspector attended* the task force daily meeting on August 14, 1994, and
held discussions with members of PSE&G regarding the troubleshooting. Through
these discussions, the inspector ascertained the following information:
Even though the troubleshooting started May 30, 1994, the maintenance
department determined, through discussions with the operation staff,
that rods have been half stepping for approximately nine years in both
units.
Both units went to low leakage cores approximately nine years ago.
The
low leakage core caused the NI signal to be cut in half, while the noise
level stayed the same.
Therefore, twice as much noise for the same
signal was being transferred to rod control.
The licensee stated that
this noise could be enough to cause rod movement.
Westinghouse provided PSE&G with information about other utilities
experiencing similar noise problems and the possible solutions to these
noise problems.
Troubleshooting
During the troubleshooting, both units were instrumented to gain information.
This troubleshooting and monitoring provided PSE&G with information
specifically for the rod control process signal concern, and also allowed for
the identification of several hardware deficiencies.
With respect to the rod control process signal concern, PSE&G determined the
following:
Since the plants operate with the control bank control rods fully
withdrawn, all rod motion observed was in the "IN" direction. However,
the information gained through monitoring, revealed that there was
enough noise to exceed the designed threshold to cause outward rod
motion on both units.
Noise was observed on both the Tave and NI signals to the rod control
compensated temperature error summator.
The combination of noise on
these signals .created spikes that exceeded the threshold required for
rod movement.
- ,
9
The Tave/Terr (temperature error) calibration tolerances prevented inward
rod motion at Unit 1, but noise did exist, and if not for these
calibration tolerances, inward rod motion would have occurred at Unit 1.
The root cause analysis associated with the Tave and NI noise will be addressed
by PSE&G in a root cause analysis report. This report was not completed by
the conclusion of this inspection.
In addition, during troubleshooting activities, PSE&G identified the following
hardware problems:
double grounds on shielded cables;
Unit 1, recorder switch and Tave defeat switch relay operation resulting
in signal spiking;
Unit 1, nuclear instrument N41 signal spiking; and
Unit 1, loose pin
11M
11 on summator module QM412J.
The licensee stated that these hardware problems would be addressed by
individual work orders. The inspector was concerned with the proposed cause
of the rod movement on Unit 1, August 16, 1994, which was determined to be the
loose pin on summator module QM412J.
PSE&G was able to recreate the event by
manipulating a wire in series with the pin.
Conclusion
The inspector concluded that when the PSE&G maintenance staff started around-
the-clock troubleshooting of the rod control process signal noise, the
troubleshooting was methodical and thorough.
3.2
Load Fluctuations on
EOG lA - Salem Unit 1
On August 16, 1994, during the monthly surveillance run of the Salem IA EDG
the operator noticed approximately lOOkW load fluctuations from the target
value of 2600kW.
The review of this event was described in NRC Inspection
Report 50-272/94-19.
The subsequent troubleshooting performed by PSE&G was
evaluated during this inspectidn.
Troubleshooting performed by the Salem Technical Department on
August 16, 1994, indicated a malfunction in the load control feature for the
electrical portion of the governor controller (EGA).
The load control feature
of the EGA is only used during parallel operations of the EOG.
When the EDG
is in stand alone operation, as it would be during a loss of offsite power,
the speed control feature is utilized. During the troubleshooting on
August 16, 1994, the Technical Department verified that the speed control
feature operated properly. Therefore, the EDG was considered operable.
However, the malfunction in the load control feature still needed to be
corrected.
After discussing the indications with the governor vendor, PSE&G decided to
perform a realignment of both the electrical (EGA) and mechanical (EGB)
portions of the governor controller.
On August 2I, I994, during this governor
realignment, PSE&G determined that the EGA amplifier was the cause of the
malfunction.
PSE&G replaced the EGA and completed an alignment of both the
EGA and EGB.
Later the same day, during testing of the newly installed EGA, PSE&G
experienced unexpected responses to load changes on the IA EOG.
Subsequent
troubleshooting identified some individual fuel injection pump racks sticking
and potential damage to the EGB.
The root cause analysis for the identified
problems was not complete at the conclusion of this inspection.
The inspector noted that the EGA amplifier is shared by both the load control
and speed control features.
The system engineer stated that the amplifier
malfunction did not appear to have an adverse effect on the speed control
function of the EGA, but the impact of the amplifier malfunction on the speed
control feature and the initial operability decision was being reviewed.
Following the conclusion of this inspection, PSE&G completed the repairs to
the IA EOG including the replacement of the EGB and required alignment, and a
lubrication of the fuel rack.
Post maintenance testing was performed
satisfactorily and the EDG IA was declared operable on August 23, I994.
Additionally, PSE&G had initiated actions to address the sticking fuel racks
including:
enhancing the procedures to include instructions to manipulate the
individual fuel racks to inspect for binding;
evaluating the lubricating oil used to lube the fuel racks;
planning an inspection of the individual fuel pump eccentric adjustment
lever pin connections for excess tightness that could have contributed
to the severity of the lack-of-lube binding; and
evaluating the remaining five EOGs for previous fuel injection rack
binding occurrences.
Through discussions with the system engineers, and a review of the
troubleshooting results, the inspector considered the troubleshooting
methodology adequate. This item will remain unresolved until the completion
of the licensee's root cause analysis for the identified failures and
subsequent NRC review (50-272/94-IS-02).
4.0
MANAGEMENT OVERSIGHT AND SELF-ASSESSMENT
The inspector assessed two areas associated with the management oversight and
self-assessment of the engineering organization.
The areas reviewed were:
the licensee's independent review of Salem Unit 2, Refueling Outage No. 8,
design changes; and the recent changes to the engineering assurance and self-
assessment process.
11
4.1
Independent Review of Salem Unit 2, Refueling Outage No. 8, Design
Changes
The inspector assessed PSE&G's initiative to perform independent reviews of
the issued design change packages (DCPs) for the upcoming 2R8 refueling outage
at Salem Unit 2.
The goal of these independent reviews, as stated in the
July 11, 1994, PSE&G internal memorandum from the Manager of Nuclear Engineer
Design (NED), was to ensure that the DCPs to be implemented during the
upcoming refueling outage meet the expectation of error-free designs.
These reviews began on July 25, 1994.
The review teams consisted of four to
six members of various disciplines and backgrounds. Action items identified
for each review are documented and maintained by the NED Manager.
Action item
responses are returned to the NED manager for tracking and closeout. The
PSE&G engineering staff stated that considerations were being made regarding
the need to compile and evaluate the findings of these reviews for future use.
The inspector attended a meeting to review DCP 2EC-3279, regarding the feed
pump pressure switch replacement.
The inspector found both the reviewers and
the presenters well prepared, allowing for a thorough review of the DCP.
The
emphasis of the review was placed on the installation and testing of the DCP.
In addition, several other areas were also addressed during this review,
including:
lessons learned from both industry and past PSE&G experience;
verification that no changes to the plant, since the issuance of the
DCP, adversely impact the DCP as designed;
operational impacts considered during the design; and
the first time application of any materials or technology.
The inspector determined that this was a strong engineering management
initiative to improve the quality of DCPs.
4.2
Engineering Assurance Self-Assessment Process
The inspector reviewed the revisions to the recently developed Procedure
ND.DE-PS.ZZ-0022(Z), "Engineering Assurance Self-Assessment Process" Revision
2, approved August 4, 1994.
The earlier revision of this procedure was
reviewed by the NRC in Combined Inspection Report 50-272/94-07; 50-311/94-07,
50-354/94-05. Since that inspection, PSE&G had completed their first two
collegial self-assessments.
Based on the lessons learned from those two
collegial assessments, PSE&G revised their procedure.
The inspector discussed the procedure revisions with the responsible PSE&G
staff member.
This discussion indicated that many of the procedure changes
~ere based on insight gained through a recently attended Team Leader Course.
The majority of the procedure changes focused on defining the responsibilities
of the Executive Sponsor, Team Leader, and Facilitator. Previously, the
12
functions of the Team Leader and the Facilitator were performed by the same
individual, this was determined to be less than ideal, and, therefore, was
changed.
These di.scussions also revealed that the scheduled team leaders for remainder
of the 1994 self-assessments have been to team leader training and that PSE&G
intends to have future team leaders trained.
The inspector considered the changes to the procedure positive enhancements
and the use of team leader training to be good.
5.0
UNRESOLVED ITEMS
Unresolved items are matters about which additional information is necessary
to determine whether they are acceptable, a deviation, or a violation.
Several unresolved items are discussed in detail under Sections 2.0, and 3.2.
6.0
EXIT MEETING
The inspector met with the licensee's personnel denoted in Attachment 1 of
this report at the conclusion of the first week of this inspection on
August 12, 1994, and then again at the conclusion of the inspection on
August 22, 1994.
The scope of the inspection and inspection results were
summarized during these meetings.
During these meetings, the licensee
acknowledged the inspection findings as detailed in this report. The.
commitment described in Section 2.2.1 of this report was confirmed during a
telephone call with Mr. F. Thomson, PSE&G's Licensing and Regulation Manager,
on August 23, 1994.
The technical contact for this report is Mr. Dave Smith.
The inspectors received no proprietary material during this inspection.
Attachment:
Persons Contacted
..
ATTACHMENT 1
PERSONS CONTACTED
Public Service Electric and Gas Companv
C. Atkinson
J. Bailey
+*D. Beckwith
A. Bel 1
P. Benini
A. Blum
- M. Burnstein
+*R. Chranowski
A. Cul 1 iton
G. Daves
S. Davies
D. Demarest
L. Dewolff
- G. Englert
L. Hajos
B. Hamilton
F. Hughes
S. Johnson
K. Kimmel
D. Kolasinski
- C. Lambert
- E. Lawrence
- C. Manges
L. Miceli
W. Mokoid
+ M. Morroni
+ G. Nagy
I. Owens
+ K. Petroff
J. Reistle
+*J. Rucki
- M. Quadin
R. Sandy
J. Shank
- D. Smith
D. Smith
K. Soumi
F. Thomson
H. Trenka
Instrumentation & Controls Supervisor, Hope Creek
Nuclear Engineering Science Manager
Station Licensing Engineer
Nuclear Electrical Engineer, E&PB
Principal Engineer, QA Audits
Principal Engineer, PAG
Manager, Nuclear Electrical Engineering
Electrical Technical Engineer, Salem
Standard and Assurance Supervisor
Acting Operation Manager, Hope Creek
System Engineer, Salem
Instrumentation & Controls Maintenance, Salem
Equipment Operator, Hope Creek
Nuclear Engineering Standards Manager
Acting Electrical Engineering Supervisor
Operations Engineer, Salem
Senior Shift Supervisor, Hope Creek
Technical Engineer, Salem
Senior Staff Engineer, Nuclear Engineering Standards
System Engineer, Salem
Manager, Nuclear Engineering Design
Senior Staff Engineer, QA
Licensing Engineer, Hope Creek
System Engineer, Salem
Maintenance Engineer, Controls, Salem Unit I
Maintenance Controls Manager, Salem
Maintenance Engineer, Controls, Salem Unit 2
Principal Engineer, Salem
System Engineer, Hope Creek
Instrumentation & Controls Maintenance, Salem
Technical Engineer, Hope Creek
Senior Project Engineer
Senior Project Engineer
.
Nuclear Electrical Engineer, E&PB
Principal Engineer, Nuclear Licensing
Engineer, Installation and Test
Senior Nuclear Maintenance Supervisor, Hope Creek
Manager, Li~ensing and Regulation
Senior Project Engineer
Attachment 1
2
U.S. Nuclear Regulatory Commission
S. Barber
Project Engineer, Section 2A, Region I
+ T. Fish
Resident Inspector, Salem
J. Laughlin
Acting Resident Inspector, Salem
c. Marschall
Senior Resident Inspector, Salem
+ S. Morris
Resident Inspector, Hope Creek
w. Ruland
Section Chief, Electrical Section, Region I
J. Schoppy
Resident Inspector, Salem
+ R. Summers
Senior Resident Inspector, Hope Creek
J. Trapp
Acting Section Chief, Electrical Section, Region
- Denotes those present at the meeting on August 12, 1994.
+Denotes those present at the exit meeting on August 22, 1994.
I