IR 05000335/1991003
| ML17223B188 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 05/16/1991 |
| From: | Hunt M, Shymlock M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17223B187 | List: |
| References | |
| 50-335-91-03, 50-335-91-3, 50-389-91-03, 50-389-91-3, NUDOCS 9105290121 | |
| Download: ML17223B188 (59) | |
Text
1 p,S REGIr~
v eo UNITED STATES NUCLEAR REGULATORY COMMISSI
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323 Report Nose I 50-335/91-03 and 50-389/91-03 Licensee:
Florida Power and Light Company 9250 West Flagler Street Miami, FL 33102 Docket Nos.:
50-335 and 50-389 Facility Name:
St. Lucie 1 and
License Nos.:
DPR-67 and NPF-16 Inspection Conducted:
February 19-22, March 4-8, and March 18-22, 1991 Inspectors:
)
unt earn ea er e
gne Team Members:
M. Miller R. Moore M. Scott NRC Consultants:
H. Singh, AECL I. Kuperman, AECL J. Hailer, AECL Approved by:
ym oc
,
se Plant Systems Section Division of Reactor Safety 6=AC-)>
ate igned SUMMARY Scope:
This special announced inspection was conducted in the areas of design of electrical systems and related engineering and maintenance activities.
NRC Temporary Instruction 2515/107;
"Electrical Distribution System Functional Inspection (EDSFI),"
issued October 9, 1990, provided guidance for the inspection.
Results:
In the areas inspected, violations or deviations were not identified.
The Electrical Distribution System (EDS) at St. Lucie was capable of performing its intended function under normal and accident conditions.
Adequate controls were in place to maintain the EDS in an operable configuration.
9105290121 910517 PDR ADQCK 05000335
~
g V
A SUMMARY A Nuclear Regulatory Commission (NRC) team conducted an Electrical Distribution System Fun'ctional Inspection (EDSFI) at the St. Lucie nuclear plant.
This inspection was performed by the Region II staff and consultants during February 19 to March 22, 1991.
The objective of this inspection was to assess the capacity of the EDS to perform its intended functions durin'g all plant operating and accident conditions.
A secondary objective was to assess the performance and capabilities of the licensee's engineering and support groups responsible for design, maintenance, and operability of the EDS.
The team s inspection activities addressed a review of design, calibration, maintenance, and the
"as installed" configuration of the electrical distribu-tion system including mechanical systems and equipment associated with the EDS.
The areas inspected by the team were the 240 kV transmission system and switchyard; the 6.9 kV system; the 4. 16 kV system; the 480 VAC system; the 125 VDC system; and the 120 VAC instrument buses.
The team's conclusions and findings for these systems and areas inspected are summarized in the following paragraphs.
The team did not identify any operability problems and concluded that the:
240 kV transmission system provided an acceptable offsite preferred power source.
The design of the 4. 16 kV Class 1E electrical distribution system was adequate.
The equipment was properly sized.
The required terminal voltages were demonstrated to be available.
Protection and coordination schemes were good.
In the area of using one startup transformer for both units, the team identi-fied a finding.
The licensee did not have procedures to control the sharing and loading of a startup transformer between units as described in the FSAR.
The team did not identify any findings with the 480 VAC system and the 120 VAC instrument buses.
One finding with the 125 VDC system was identified in the motor-operated valves (MOVs) area.
Although there was no operability concern, the power cable sizing for MOVs needed to be addressed.
For mechanical systems and equipment associated with the EDS,,the team did not have any findings.
Although there were no immediate operability concerns, the team identified a
number of minor observations that indicated additional calculations and procedural changes were required.
In addition, a recommenda-tion was made that additional testing be performed to verify the underground carbon steel piping for diesel fuel lines is not corroding.
The team observed that the licensee's i'nternal audit resulted in the necessary changes to the mechanical systems.
In the area of ventilation, the team identified a finding concerning procedural control.
The licensee did not; have procedures to control the operation of the non-safety cooling fan in the, emergency diesel generator rooms.
In the areas of maintenance, testing, calibration, and configuration control, the team identified four findings.
Two findings were for fuse control and relay setting drawings where engineering had not issued the required controlled documents or drawings.
One finding addressed the need to enhance (upgrade)
the relay setting calibration procedure.
The final finding commended the licensee
'
for performing preventive maintenance to detect failed molded case circuit breakers.
Overall, the team considered the EDS to be well maintained, tested, and c'alibrated.
The licensee's Electrical. Maintenance Department and the System Protection Group were extremely knowledgeable and acted in a profes-sional manner.
The engineering technical support and design groups supporting the EDS were adequate.
Their performance in areas reviewed demonstrated involvement in problem identification and resolution as well as routine activities in main-tenance, testing, operations, and procurement.
Plant modifications to the EDS were performed in accordance with acceptable requirements.
I The licensee initiated a self audit of the EDS.
Significant resources were expended to identify and correct weaknesses in the program.
These actions greatly reduced the number of findings identified by the team.
In summary, it is the consensus of the team.that the EDS at St. Lucie will perfor'm its intended function under normal and accident conditions.
The licensee had adequate controls in place to maintain the EDS in an operable configuration.
I
'
1.0 INTRODUCTION Previous,'inspections of nuclear power plants by NRC teams, and various licensee event reports have identified conditions in the electrical distribution systems at various operating plants that could compromise the design safety margins of the plants.
These deficiencies were the'esult of unmonitored and uncontrolled load growth on safety related electrical buses, inadequate engineering modifications, faulted design calculations and inadequate testing of EDS equipment.
In addition, the NRC identified examples where the configuration of the EDS equipment did not adhere to the intended design.
Consequently, the NRC initiated a special inspection program to evaluate the adequacy of the EDS to perform its safety function.
The objective of this inspection was to assess the performance capability of the St. Lucie EDS by reviewing the design parameters as they relate to onsite and offsite emergency power sources and associated equipment re'lied on during and following design basis events to support the plant's safety-related equipment.
Additionally, the performance of the licensee's engineering and technical support and configuration control was examined.
Inspection activities included review and -walkdown of the 240 kV switch-yards, 6.9 kV system, safety-related 4. 16 kV system, Emergency Diesel Generators and supporting systems, 480 VAC system, 125 VDC system and the 120 VAC instrument buses.
The components examined included buses, switchgear, transformers, circuit breakers, distribution centers, motor control centers, batteries, chargers, inverters, fuses, and protective relays.
The review of systems'esign included the following:
Short circuit analysis Circuit loading calculations Breaker Coordination Fuse Sizing Cable Sizing Protective Relay setting As-insta11ed configuration versus design drawings Mechanical systems required to support the EDS were also reviewed.
These included the EDG's,air start system, lube oil system, fuel oil system, and the jacket water cooling system.
The Heating, Ventilating, and Air Conditioning (HVAC) systems for the rooms containing major EDS equipment were evaluated.
The licensee conducted two self audits in anticipation of this EDSFI.
The first audit was started July 1990 and was ongoing up to this inspection.
A second audit was performed by a consultant during January and February 1991.
Over 13,000 man-hours were expended during these audits.
As a
result of these audit findings the licensee identified and corrected issues that would have reflected any major concerns during this NRC inspection.
The team considered these self-audits efforts to be positive
actions toward further self improvement.
(See Appendix A, Finding 91-03-09)
Within this report FINDINGS are identified and are defined as follows:
FINDINGS are facts or conclusions related to how well the electrical distribution system meets its intended function.
FINDINGS may indicate a
requirement or an accepted industry practice that was not fully implemented.
FINDINGS may indicate discrepancies or omissions in documents where these problems could credibly result in the intended function being compromised; The licensee's working knowledge of the design as well as their control of design documents may be the subjects of FINDINGS.
FINDINGS typically make statements about the need for corrective actions, or they may indicated an area where the licensee excels.
2.0 ELECTRICAL SYSTEMS The St.
Lucie plant was connected to the FP8L high voltage grid transmis-sion system by three 240 kV transmission lines.
Connections to the station were made in a common switchyard for both units.
The switchyard was of the
"breaker -and-a-half" design and included four bays and eight connecting circuits.
Three of the connecting circuits were for the 240 kv transmission lines; a fourth 240 kV transmission circuit was for local offsite distribution.
The four remaining circuits were used for connections to the two nuclear units.
Two circuits received power from the two units'ain generator step-up transformers.
The two remaining circuits each served two start-up transformers; one from each unit.
The start-up transformers, two per unit, served to supply the offsite preferred power to the two units'lass 1E Electrical Distribution Systems.
The 4. 16 kV portion of the distribution system consisted of two non-safety related buses each feeding a safety-related 4. 16 kV bus.
Each safety bus had independent switchgear and distribution equipment to provide power to safety loads from either the offsite source or the onsite emergency diesel generator which is connected to each safety bus.
During normal operation with the main generator supplying power, the plant safety and non-safety loads for each unit were supplied by a dedicated auxiliary 'transformer which was connected to the unit generator output bus.
Upon a main generator trip a fast bus transfer will connect the start-up transformers to the plant safety and non-safety loads thus providing offsite power.
The 4. 16 kV safety-related buses for each unit supplied the accident mitigation motors and 480 VAC load centers.
The load centers supplied power to the safety-related motor control centers which supplied power to the various safety related motor operated valves, motors, and battery charger The Uninterruptable 120 VAC instrument power to Reactor Protective System and Engineered Safety Featured Actuation System was supplied by two redundant inverters on each. train.
Each 'inverter was rated
KVA with 120 VAC, 60 Hertz output.
Units 1 and 2 had similar Class 1E 125 VDC power systems.
Two redundant lead calcium 'type batteries, each with 2400 Ampere-hours capacity for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, supplied power to trains A and B buses on each unit.
Buses A and
were extended to connect to buses AA and BB respectively.
A swing bus, AB, was connected between busses A and B.
Two redundant battery chargers on each of the trains kept the batteries charged and supplied the station with normal DC power demand.
One battery charger connected to swing bus AB served as back up for, the four'ormally operating battery chargers.
A'll,battery chargers were rated 300 amps DC.
2.1 Conclusions The inspection team did not identify any operability problems and concluded that the 240 kV transmission system provided an acceptable offsite preferred power source for the 4. 16 kV Class 1E electrical distribution system.
Based on the inspection of the documentation provided and the load path or vertical slice selected, the team did not identify any operability problems with the 4. 16 kV Class 1E systems.
Thus, the team concluded that the design of the 4. 16 kV Class 1E electrical distribution systems was adequate.
Equipment associated with the preferred and the Class 1E onsite power sources was properly sized and adequate terminal voltages were demonstrated to be available for the 4. 16 kV safety-related loads.
Protection coordination schemes for the 4. 16 kV Class 1E systems and their loads were demonstrated to be adequate.
A finding identified by the team was the lack of procedures to control the sharing and loading of a start-up transformer between units.
The team had no findings in the 480 VAC system and the 120 VAC system.
One finding was identified in the 125 VDC System which involved the sizing of power cables for motor operated valves (NOV).
The team concluded that the electrical systems as installed will perform their intended safety functions.
2.2 Transmission System The team reviewed the characteristics of the 240 kV transmission system and found.that voltage was maintained between 234 kV and 246 kV.
The reported minimum and maximum voltages for the past two years were 236.3 kV and 245.4 4V.
The frequency range for the same period was maintained between 59.75 hertz to 60. 1 hertz.
The team was advised that the present 240 kV system short circuit capacity at the switchyard buses was 9477.9 NVA.
The licensee operated the transmis-sion system in a manner to handle the first contingency, such as a
transmission line trip, using a security analysis system which
analyzed the system conditions every 15 minutes and alerted the system load 'dispatcher if corrective actions were required.
2.3 Medium Voltage Class 1E Systems The medium voltage or 4. 16 kV Class lE electrical distribution system for each of the two units included two circuits from the offsite preferred power source (240 kY transmission system via the start-up transformers),
two redundant switchgear buses, two Class lE redundant onsite (standby.or emergency)
power sources and power distribution circuits to serve accident mitigating loads.
A 4.16 kV Class 1E swing bus was provided to serve installed spare accident mitigating loads.
Each unit had two redundant and independent 4. 16 kV EOGs to provide emergency onsite power to the Class lE power systems.
Connections to each of the 4. 16 kV Class 1E Buses included the following circuits:
Main supply (preferred source)
from a start-up transformer via a non-safety related 4. 16 kV bus,
Supply from the associated EDG,
Tie to the 4. 16 kV Class 1E swing bus,
Feeders to accident mitigating pump motors (also to fan motors for Unit 2),
Feeders to 480 VAC Class 1E load center transformers and
Feeder to a pressurizer heater 480 VAC load center transformer.
Connections to the swing bus and to the non-safety related 4. 16 kV-bus were implemented using two circuit breakers in series.
To assess the adequacy of the "as-installed" 4.16 kV Class 1E systems for each unit to perform their safety functions, the team reviewed:
The ratings of the preferred source or start-up transformers and their connections to the 4. 16 kV buses based on worst case loading, The adequacy of the switchgear based on continuous, interrupting and 'momentary current ratings versus anticipated loadings and potential fault current levels, Protective relay settings and protection coordination to evaluate system reliability in the event of an electrical fault or overloads,
- EDG characteristics versus the requirements of accident mitigating loads--to evaluate the adequacy of the EDG capacity and capability to start and accelerate the assigned safety loads
'in the required time sequence, and
The capability of the systems to ensure adequate starting and running voltage conditions for the 4. 16 kV safety-related loads under degraded 240 kV system conditions.
The "as-installed" configuration was adequate as determined by.review of the above information.
The team assessed the design of the 4. 16 kV Class 1E system by review of calculations and documentation which were intended to demonstrate the capacity and capability of the 4. 16 kV C'lass lE system design.
These inc1uded equipment loading, short circuit and voltage regula-tion studies.
Calculations and analyses, in general, were recently updated or regenerated to consider the present 4.l6 kV system configuration and design.
The maximum calculated fault current levels and voltage regulation, including equipment terminal voltages considering degraded 240 kV system, were demonstrated to be accept-able.
EDG steady state loading, transient sequential loading including voltage and frequency regulation were demonstrated to be acceptab1e.
The team noted during the above review that the'ecent calculation
. activity did not specifically address the acceptability of the electrical equipment loading in the 4. 16 kV systems other than the loading of the EDGs until requested by the team.
The licensee identified an undocumented EBASCO calculation, circa 1983, and a
portion of EBASCO calculation WHL-l, Revision 5, dated March 8, 1983
- "Electrical Auxiliary System Study" which demonstrated acceptable loading at the time for Units 1 and 2, respecti'vely.
As a result of the team's queries regarding present loading acceptability, the licensee performed calculations PSL-1-FJE-91-006, Revision 0, for Unit
and PSL-2-FJE-91-007, Revision 0, for Unit 2, both dated March 19, 1991 and titled
"Comparison of Anticipated Electrical Loading Conditions to Equipment Ratings."
The latter two calcula-tions.indicated higher worst case loadings than the earlier EBASCO calculations, however, acceptable loadings.
were demonstrated.
The team did not consider the licensee's failure to update or evaluate the EBASCO loading calculations a "finding" but rather an example of where more attention could have been given to updating design information.
The team noted that with the installation of Unit 2 equipment, two non-safety related, but redundant, 4. 16 kV buses were provided to facilitate the sharing of a start-up transformer between the two units should the need arise.
These buses also provided a means to supply the 4. 16 =kY systems of both units from one of the redundant
2.4 EDGs of one unit during a station blackout scenario.
Operation of the switchgear, associated with these buses, to implement use of these features was to be under administrative control.
However, investigation by the team revealed that procedures to control start-up transformer sharing and loading between units did not exist.
(See Finding 91-03-01 in Appendix A.)
The team reviewed calculations and coordination curves that established the protective relay settings and demonstrated protection coordination of devices applied in the 4.16 kV system.
Particular attention was given to devices associated with the team's selected load path and included the relaying associated with circuit breakers for bus main supply, bus tie, motor feeders, load center transformer feeders and diesel generator electrical protection.
Protection and protection coordination schemes were found to be acceptable.
The team noted that each of the two units'uxiliary electrical power distribution systems, including the 4. 16 kV Class 1E system buses, were supplied from their respective unit auxiliary transformers (connected to the unit's generator leads)
during normal power operation.
Following a unit trip the auxiliary system buses, including the 4. 16 kV Class 1E buses, were automatically transferred, using a fast dead bus transfer scheme, to the start-up transformers.
The team noted that the transfer scheme did not include synchro-check logic to supervise the transfer.
Therefore; the team questioned the potential for damage to motors during a transfer.
The licensee demonstrated by calculations, using an industry accepted method, that motor stres'ses, following the fast dead bus transfer, were acceptable.
Class 1E 480 VAC System The configuration of Class lE 480 VAC power distribution system was similar to the one followed at 4. 16 kV level.
Unit I had two redundant 480 VAC load center buses 1A-2 and 1B-2 received power from the 4.16 kV safety buses 1A-3 and 1B-3 respectively through 1500 KVA service transformers 1A-2 and 1B-2.
A 480 VAC swing bus 1AB could be connected to either bus'A-2 or 1B-2 through two circuit breakers (in s'eries)
and must follow the 4. 16 kV swing bus alignment.
A misalign-ment generates an alarm in the control room.
Each of the load center buses ( 1A-2 and 1B-2) were split into two sections by connecting a
current limiting reactor between them.
The first section rated 30,000 Amps (symmetrical)
received power from the service trans-former, fed larger motor loads ( 100 - 250 HP)
and supplied the swing bus 1-AB.
The second section with reduced symmetrical short circuit ratings (14,000 Amps) supplied the motor control centers.
The MCC's distributed safety power throughout the plant either directly -or through transformers and power panels.
Motors up to 100 HP were supplied directly from the NCC's.
Each motor starter in
~
~
the MCC was equipped with magnetic trip circuit breaker, a contactor
'nd a thermal overload for motor protection, Class lE 480 VAC power distribution system on Unit 2 was similar to
'.Unit 1 with minor deviations.
2,5 The team reviewed the
"Short Circuit Voltage Drop and PSB-1 Analysis".
(Gale.
Ho. PSL-1-F-J-E-90-0026 REV 1).
Also the team selected a 'vertical slice in the power distribution system involving safety related circuit breakers in trains A and B for review of the coordination of circuit breakers.
The licensee performed a calcula-tion entitled "Overcurrent Coordination for Selected Breakers" dated l1arch 1, 1991 on both units which covered the vertical slice.
The team noted that the calculations were acceptable.
The calculated short circuit levels on all buses were within the ratings of the equipment.
Cables were adequately sized and breaker coordination was acceptable.
The team had no concern in this area.
Class 1E 120 VAC System Two static inverters on each train received power from 125 VDC buses and delivered regulated 120 VAC output to two pairs of safety related instrument buses.
Output from each inverter passed through a
transfer switch and an isolating transformer connected to its respective instrument buses.
An alternate source of power for these buses were the safety r'elated 480 VAC NCCs.
These NCCs supplied power through step down transformers and voltage regulators to the transfer switch located on the output of each inverter.
The instru-ment buses supplied uninterruptable power to Engineered Safety Featured Actuation System and Reactor Protective System ins'trumentation.
2.6
.To establish the.adequacy of the Class 1E 120 VAC distribution system, the team requested voltage drop and cable sizing calculations for the system.
The licensee did not have such a
document and explained that the inverters supplying Class 1E 120 VAC power were equipped with current limiting devices.
The cables were sized by the plant A/E to meet the ampacity and voltage drop design criteria.
The team selected four Class 1E loads and requested the licensee to produce short circuit and voltage drop calculations. to prove the adequacy of the cables.
The calculations verified that cable sizing was acceptable.
The team had no further concern.
Class 1E 125 VDC Syste~
The team reviewed design documentation, calculations, and evaluations which demonstrated sizing and loading for the 125 VDC system and equipment.
This documentation included short circuit and low voltage calculations, HOV design studies, high voltage analysis and coordina-tion studies.
The documentation appropriately verified DC equipment was adequately sized.
Hinor documentation errors were identified by
the the are (2)
(3)
team.
The licensee investigated the errors and agreed to correct documents in the forthcoming revisions..
Examples of such errors as below:
L Safety related batteries (calc. PSL-1-F-E-90-0015)
(A)
EDG 1A control panel load (120A) did not agree with the load shown on FSAR Table 8-3-4.
(B)
Inverter loads (37 A) shown on Table 1 was not consistent with load shown on Attachment 9.
Battery short circuit current shown on Calc.
EC-034-EC039,
"DC Short Circuit for Appendix R circuit" and on vender correspon-dence did not agree with one another.
full load current for some of the DC NOV's shown on DWG 2998-G-275-SH3
.was not consistent with values shown on Calc.
FL0-124-37-5000.
2.6. 1 Battery Protection Batteries were connected to the respective buses using circuit breakers (switches)
which were not equipped with protective devices against overcurrent or short circuit.
The team had a
concern that a short circuit at the battery bus may draw approximately
KA of current.
In the absence of any protec-tive device the battery connecting cables and battery bus may have to withstand this heavy current indefinitely.
This may cause permanent damage to the battery and present a fire hazard.
The licensee stated the cables were well separated to guard against short circuit, and that it is an accepted industrial practice to provide circuit breakers without any protective devices for isolating the batteries.
Applicable standards do not mandate such protection.
The team considered that even though applicable regulations or standards do not require the licensee to provide such protection, it is imprudent to leave a
vital part of the safety system unprotected.
There is no operability concern because the battery systems were redundant.
2.6.2 DC MOV Valves The team reviewed design documentation to verify the appropriate sizing of DC Motor Operated Valves (NOV).
The normal operating voltage for NOV's was 120 VDC.
The MOVs were required to function satisfactorily under minimum battery terminal voltage.
of 105 VDC.
The recommendation from the NOV vender (on both units) stated that valves could perform at reduced voltage
~
~
of
percent
{i.e., at 120 x.85
= 102 VDC).
Vendor
, recommendations also indicated that the cables for MOV's be sized to allow for five times the full load motor current at the minimum voltage.
The team noted that:
(A)
The preliminary calculation performed by the licensee showed that the voltage available at the terminal of all DC MOV's was low under minimum battery terminal voltage conditions.
(B)
On some of the MOV's for both units the cables did not meet the present day vender's recommendation for cable size.
However the team considered that cables might have been sized to the recommendation in the past, but recommenda-tions might have been revised over the years.
(C)
The maximum MOV motor current draw in all cases was less than the recommended values resulting in reduced available torque for valve operation.
r The licensee presented the results of calculations on both units to the vender for comments.
On unit 1, the vender confirmed
{with a letter dated February 21, 1990) that the DC YiOV motors produced enough torque to operate valves at the stated condi-tions.
The licensee confirmed that calculations for unit 2 were sent to the vender and vender's comments were awaited.
There is no operability concern in this area.
However the licensee must assure that the cables; which are not sized to the vender recommendations, are not stressed further as a result of future torque switch modifications and equipment replacement in this area.
(See Appendix A, Finding 91-03-02)
2.7 Station Grounding Grid To evaluate the station grounding grid, the team requested the documentation on the grid design.
The licensee produced the grid layout drawings and a letter from EBASCO dated March 6, 1991 'which indicated that it was 'the policy of A/E to follow guidelines established in IEEE-80 when calculating grounding grid design values.
No such calculations were available for verification.
The licensee agreed to produce a design calculation to ju'stify the design of the grounding grid as per guidelines established in IEEE-80.
The team considered that since the grounding grid was a maintenance free, passive piece of equipment with no access for visual inspection, its design should be verified.
In the event of lightning strike or a
serious system ground fault, it should be able to dissipate the ground current without compromising equipment operation and personnel safet I
'I
"3.0 MECHANICAL SYSTEMS The team reviewed and evaluated the adequacy of selected mechanical systems to support the EDS during normal and postulated accidents.
These systems included the diesel fuel oil transfer, the air start system, lube oil system, jacket cooling water system, and combustion air systems for the diesel generators, along with the ventilation systems for the Class 1E equipment and diesel rooms.
The review included selected portions of the FSAR, operating and maintenance procedures, pre-operational tests, calculations, drawings and system modification packages.
Several walkdown inspections of these selected systems were conducted.
3.1 Conclusions The engineering staff was knowledgeable of the mechanical systems and sufficient information was available to review and assess the operability of the mechanical systems.
Although no immediate operability concerns were found, the team identified a
number of observations that indicated additional calculations or procedural changes were required to ensure proper operation of the EDG and their support systems.
In addition, a
recommendation was made that additional testing should be performed to verify the underground carbon steel piping for the diesel fuel lines is not corroding.
One finding in the ventilation area for the diesel generator rooms was identified.
There were no procedures to control the non-safety cooling fan, although this fan contributes to maintaining adequate ambient temperature in the EDG room.
The team found that communication between the engineering and operation groups was good and this ensured complete reviews of design and operational changes.
The team felt that the licensee's internal self assessment was valuable and resulted in various system enhancements being performed prior to this inspection.
3.2 EDG Fuel Oil Transfer System The system consisted of two storage tanks and four day tanks (two for each diesel unit) along with two pumps and the interconnecting piping to allow for transfer between the storage and day tanks.
The licensee, as part of their self assessment, made calculations to confirm the adequacy for fuel'torage quantities and tank set points.
The team reviewed these calculations and found them adequate.
Each diesel unit had underground corrosion protected carbon steel piping connecting the diesel fuel oil storage tank to the day tank.
Similar piping connected the Unit 1 and 2 Diesel fuel oil systems.
The licensee identified corrosion in the buried piping for both diesel units and the interconnecting lines.
Corrective action
included replacing the corroded lines and performing pneumatic tests for two consecutive refuelling outages.
This corrective action was only implemented for Unit 1.
The-corroded interconnect pipe between the two units was completely, replaced by double walled pipe.
Although the corrective action taken by the licensee was appropriate, the team recommended that the underground piping for the DFOT system be tested more frequently than the present schedule required by the IST program, once every ten years.
The Team's recommendation was
'ased on the knowledge that corrosion had also been found in under-ground carbon steel pipe for other systems.
The team noted that the diesel fuel oil storage tanks had flame arrestors, however the day tanks had none.
The licensee prepared a
preliminary calculation which demonstrated that the concentration of fuel vapors above the day tank did not represent a hazardous environ-ment thus justifying not having flame arrestors.
The team found this evaluation to be acceptable.
The Technical Specification requires that at least once every eighteen months the licensee should verify that the DFOT system transfers fuel from each fuel storage tank to the day tank of each diesel via the installed cross connection lines.
The implementing procedures for this TS requirement did not specifically address the system configurations to be verified.
Plant procedures, Periodic Integrated Test of the Engineered Safety Features, OP1-400050 and OP2-400050, did not identify the cross-connect configuration which should be tested.
The licensee agreed to revise the test procedure to clarify the test configurations and requirements to properly satisfy the Technical Specification.'his resolved the team's concern regarding this issue.
The licensee, as part of their internal self-assessment, had revised the NPSH calculations for the DFOT pumps for both units.
The associated system head loss calculations were not revised.
The head loss calculation for Unit 2 did not accurately address actual field configuration or pre-operational test values.
The were no system
,
head loss calculations for Unit 1.
This was primarily a design documentation concern because pre-operational testing verified adequate flow was provided from the storage tanks to the diesel generators.
The licensee agreed to develop accurate calculations to address design system head loss for both units.
The head loss calculation would include the normal alignment, the interconnection
.between the two diesels and the cross tie between the two units.
In reviewing Chemistry Procedure No. C-05 "Diesel Fuel Oil Inventory, Receiving Shipments and Periodic Sampling" Revision 16, the team noted that there was no specific acceptance criteria for the cloud point or wax appearance point.
Instead the procedure referred to the ASTN standard D-975-81 which has various values for different areas of the United States for different months.
The licensee agreed to
3.3 revise the procedure to identify specific cloud point acceptance values applicable to the St-Lucie Plants.
This was a documentation concern; the specification is fixed for a geographical area and should have been specifically stated in the procedure.
Review of chemical documentation demonstrated the specifications have been met.
EDG Support Systems The EDG support systems consisted of the cooling water, air starting, lubricating oil and combustion air intake and exhaust systems.
Each Unit had two diesel generators, and each diesel generator had two diesel engines, a
12 and a
16 cylinder engine.
I The cooling water system was self contained and each diesel engine consisted of forced water circulation to cool the 'ngine and an air-cooled radiator system to remove heat from the cooling water.
The cooling water pump and radiator fan were driven directly from the engine crank shaft.
An expansion tank which operated at above atmospheric pressure was connected to the suction side of the cooling water pumps.
Each EDG air starting system consisted of four sets of two air start motors, two air compressors, one electric the other diesel driven,'nd four air receivers sized for 5 air start capability.
The lube oil system for each diesel engine was a self contained system composed of a lube oil pump located at the base of the engine, various circulating lube oil pumps, filter, strainer, heat exchanger and associated piping.
The lube oil heat exchanger was cooled by the diese1 generator cooling water system.
The diesel generator took combustion intake air from the surrounding ambient air through an air intake filter/silencer to the turbocharger.
The exhaust air, consisting of an exhaust silencer and ducting, exited outside the EDG building.
The air starting system was required to be seismically qualified.
For Unit 2, the system was seismically qualified and the licensee had design reports for the relief valves on each air receiver tank.
For Unit 1, there was a seismic analysis for the air starting skid but no seismic report for the relief valves.
The team was concerned that fai lure of these relief valves during a
DBE/LOOP event would prevent'oth Unit 1 diesels from starting, The licensee performed a
calculation which demonstrated that if the relief valves failed completely open, there was sufficient air available immediate1y after the event to start the diesels.
The calculation resoIved the Team's concern on this issue.
The team was concerned that the starting air compressor relief valves were not regularly tested or incorporated into a
PH program.
Although the valves were rated as non-safety related components the
~a e
team was concerned the failure of.the valves could impair the operation of the EDG.
The electric and diesel driven compressors were regularly tested and entered in the PM program.
These relief valves, SR-59-1A,-18,-2A,-28, were located downstream of the compres-sors.
The licensee agreed to review the function of these va'Ives and to prepare a preventative maintenance procedure if required.
The team accepted this resp'onse as appropriate.
The FSAR for Unit 2 stated that the maximum air cranking duration was 5 seconds and that the air receivers were sized for five 2 second starts.
In fact, the cranking duration as determined by the actual timing relay set point is 9 seconds and the air recei'vers are sized for 5 starts only.
The licensee agreed to evaluate this discrepancy and to change the FSAR as necessary.
The safety relief valves on the diesel cooling water expansion tank-were safety class and seismically qualified.
However, the team found no record to indicate that the valves were tested or maintained regularly to ensure proper relief set point.
Failure of these valves could impair the diesel cooling system.
The licensee agreed to include the valves in the preventative maintenance program, the frequency still to be determined, to ensure proper operation of these relief valves.
The team accepted this approach.
The FSAR for Unit 2 required the diesel exhaust system to be seismically qualified.
The Unit
FSAR required the diesel generator set to be seismically qua'lified.
The team was concerned that failure of exhaust piping in a seismic event could result in hot exhaust gases (approximately 700 to 800 degrees F) entering the EDG room and
., damaging the "diesel equipment.
Also, seismic failure of the exhaust si 1 encer internal s cou'l 4 effeet the EDG performance.
The Unit
exhaust ducting had been seismically qualified however. for Unit 1 no
. seismic calculation existed.
The licensee made a
new calculation which indicated that the Unit
exhaust piping was seismically qualified.
No documentation was available to determine if the exhaust silencer were seismically qualified.
The licensee stated that the seismic. analysis for the ducting modelled the silencer as a
structural member.
The analysis showed that the member could carry the applicable loads which, were within the limits stated by the Unit 2 manufacturer.
Based on this reasoning the exhaust silencer could be considered as seismically qualified.
This analysis resolved the Team's concern regarding this issue.
3.4, Ventilating Systems The electrical equipment and battery rooms were ventilated by a once through system where unconditioned air is supplied to the rooms via intake louvers, filters,and two supply fans, then exhausted to the outside through exhaust fans or roof ventilator ~
~
Radiator fans provided ventilation for the EDG room when the diesels were in operation.
When the diesels are not in operation, a manually controlled roof ventilator provided the cooling to the EDG room.
There was on1y one main supply air duct providing ventilation to the division A and 8 electrical equipment rooms.
The team was concerned that failure of this duct due to tornado effects or a random failure would 'result in loss of adequate cooling to the electrical equipment rooms.
The licensee agreed to revise the plant's off-normal procedures and plant annunciator summary to provide for appropriate corrective actions should a high temperature condition (greater than 110 degrees F) occur in the electrical rooms.
These revisions will require the operator to, verify the supply and exhaust fans for the electrical equipment and battery rooms are running.
If venti.lation flow cannot be restored, compensatory action should be considered.
The licensee approach to this issue resolved the Team's concerns.
The licensee's self-assessment activity identified the Unit I supply and exhaust fans providing ventilation for the electrical equipment rooms did not automatically start on high ambient space temperatures.
Additionally it was identified the FSAR did not agree with the as-built condition.
Lack of automatic start could result in room temperatures exceeding the FSAR specified value of 104 degrees F.
and approach 116 degrees F after 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />.
The Unit 2 supply and exhaust fans would start automatically after a
LOOP therefore this situation did not apply to Unit 2.
The licensee prepared a safety evaluation which concluded that these resu1ts did not involve an unreviewed safety question.
The licensee initiated a revision to the Emergency Operating Procedures (EOP) to ensure that the electrical equipment supply and exhaust fans are restarted manually within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> which would reduce the room temperature to below 110 degrees F (the room alarm condition) after I hour.
A1so, an engineering package would be prepared to document revised as built conditio'ns.
The team reviewed the above information and concluded that the changes were acceptable.
The EDG building had a non-safety roof fan required for room cooling during diesel standby.
The Unit 2 fan was seismically mounted and wa's protected against tornado missiles, however for Unit 1 although seismically mounted, no such tornado protection existed.
The team was concerned that a tornadic missile could enter the'DG building and cause damage to the diesel equipment.
The licensee performed a
probabilistic risk assessment (PRA) which concluded that a tornado generated missile entering the EDG building through the roof ventilator is not of significant importance in relation to the overall effect on the plant.
The team reviewed this analysis and concluded that a tornado missile entering the EDG building through ventilator is an improbable event.
During wa1kdown in EDG room, the team noted that, there was no temperature indication or control in the EDG room.
The FSAR stated
that the temperature in the room does not exceed 104'F.
The ventilation in the room was provided by one manually operated non class 1E fan with no remote indication to show its status.
The electrical equipment in the room was designed to an ambient temperature of 104'F with an occasional allowable temperature rise to 120'F.
The team had a concern that in event of fan failure, the electrical equipment could be subjected to elevated temperature for an indefi-nite peri,od.
There was no procedure identified to address that concern.
The licensee agreed to identify procedural control to address fan failure and to monitor room temperature regularly.
(See Appendix A, Finding 91-03-03)
4.0 MAINTENANCE, TESTING, CALIBRATION, AND CONFIGURATION CONTROL The team performed walkdown inspections of the EDS to identify the material condition of the electrical equipment.
The
"as installed" configuration of the EDS was examined to determine its compliance with design drawings and documents.
The electrical maintenance program, procedures, and work orders were reviewed to ensure the EDS was being properly maintained to function for the life of the plant.
Data sheets from completed 'rocedures, calibration procedures, and surveillance procedures were reviewed to verify the EDS functions in accordance with design specifications.
The calibration drawings for the protective relay settings, were reviewed to verify the licensee had adequately addressed this program.
The fuse control program was reviewed to ensure the sizes and types are properly used.
4. 1 Conclusion The team determined the EDS was well maintained as demonstrated by the excellent material condition of electrical cabinets and equip-ment.
The
"as installed" configuration agreed with the design drawings and documents.
The EDS equipment was found to be adequately tested and calibrated.
The Electrical Maintenance Department had a
good program to ensure the EDS functions as required.
The System Protection Group implemented an adequate calibration program for the switchgear protective relays.
Overall, the licensee has recognized and provided the necessary maintenance to calibrate, test, and maintain the EDS.
Although the team identified some minor issues, the licensee had established a
comprehensive program for the maintenance, testing, and calibration of EDS equipment.
4.2 Equipment Walkdowns The electrical components examined on inspection walkdowns included fuses, motor starters, molded case circuit breakers, metal clad circuit breakers, switchgear breakers, switchyard circuit breakers,
protective relays, timing relays, batteries, wiring, cables, cable trays, panels, and transformers.
The associated components, equip-ment and panels in the following electrical systems were inspected for both Units 1 and 2:
The four circuit bays in the 240 kV switchyard
The protective relays, control panels and communication equipment for the 240 kV switchyard The two main step-up transformers and associated hardwar e
The two auxiliary transformers and associated hardware
The 6.9 kV switchgear panels, cubicles, and distribution centers
The safety-related 4. I6 kY switchgear, panels, cubicles, and distribution centers
The two 4. 16 kV emergency diesel generators and associated hardware
The safety-related 480 VAC load centers and motoi control centers
The safety-related batteries, battery charges, 120 VAC instrument inverters and distribution centers for the 125 VDC system.
During the w'alkdown inspections, design drawings and documentation were used to reflect the
"as installed" configuration.
Specific attention was paid to the protective relays and their settings for the 4. 16 kV and 6.9 kV switchgear.
The timing relay settings for the emergency diesel generators load shedding and sequencing were verified.
The material condition of the electrical equipment was good.
The equipment appeared to be well maintained, clean, and few deficiency tags were observed.
The equipment was labeled, easily identifiable, and accessible, adequate separation existed in the plant for all EDS equipment observed by the team.
Overall, the EDS equipment material condition was good, however some minor issues were noted during the walkdown.
Large electrical equipment such as battery load test banks, ground testing devices and spare switchgear breakers were observed being stored in the vicinity of safety-related equipment.
The potential exists for this stored equipment to damage installed equipment or be damaged itself when moved.
The 'icensee stated that a
more secure area for long-term storage of such equipment would be considere "17 I
In another area, the team examined the lip of the concrete floor was not even with the trim at the front of the Unit I safety-related 4. 16 kV switchgear cubicles.
This concrete was wearing away causing, the breakers to wobble from a straight line of travel when being racked out.
The licensee identified this condition and was taking, appropriate'orrective action to prevent any future damage in this area.
,4.3 Overall the team determined the results of the walkdown inspections
. were very satisfactory.
Equipment Maintenance, Testing, and Calibration The team inspected the main'tenance program to ensure the EDS was being properly maintained to function for the life of the plant.
The testing and calibration was reviewed to verify the EDS was operating within design requirements and technical specifications.
The team reviewed the program and activities of the Electrical Maintenance Department relating to testing, life of components, electrical noise, and preventive maintenance.
In addition, the team reviewed the switchgear protective relay calibration program of the onsite System Protection Group.
The Electrical Maintenance Department had an extensive preventive maintenance program for servicing the switchgear.,
The team verified all the safety-related switchgear breakers for both units had been properly serviced.
The licensee had also developed and implemented a
"breaker life cycle" program which required the metal clad switchgear (breakers)
be overhauled every nine years.
The first cycle of breaker overhaul was initiated for both units and will be completed during the next unit outages.
Overhaul included complete breaker disassembly and examination.
Additional commendable breaker maintenance activity was demonstrated by maintenance performed on non-safety related breakers.
Two work orders documented non-safety related molded case circuit breakers failures which were detected by the licensee.
(See Appendix A,
Finding 91-03-04)
In the testing area, the team reviewed the testing requirements for the emergency diesel generators load sequencing relays.
Data was reviewed to verify the load sequencing relays were cal,ibrated.
For Unit I, the team identified one minor discrepancy for a minor load that did not agree with Table 8.3-2 of the FSAR.
The CVCS did not start at its required time of 21 seconds.
It started at 30 seconds.
The licensee issued a work order to initiate the appropriate correc-tive action.
In the another area, the Electrical Maintenance and I8C are investigating electrical noise in the 120 VAC instrument buses.
This noise may require design changes.
A summary of the electrical noise problem(s) is discussed belo During 1990, an investigation was initiated by the licensee of random noise in the 120 Volt AC instrument buses.
The noise in the form of short duration voltage spikes had been seen particularly on the 2MB bus.
The spikes had been causing some minimal system perturbation with the potential of increasing the failure rate of system subcomponents.
The licensee had been systematically trouble shooting the source of the noise.
Utilizing power monitors and temporary filters, the maintenance staff developed a methodology to identify the source of the spikes.
The elimination of the noise will require installation of features such as metal oxide varistor and/or a
resistor/capacitor network at point(s)
in the subcircuits via a
qua'lified I-E engineering package.
The efforts to date are commendable.
The Electrical Maintenance Department initiated a
fuse control program in 1988.
The team generally considered this a good program although engineering had not yet provided a controlled document for each unit listing the fuses by size and type.
(See Appendix A, Finding 91-03-05)
The Team reviewed the protective relay calibration program developed and implemented by the System Protection Group (SPG).
The protective relays are used to sense faults in the EDS such as short circuits and undervo'itage conditions and to trip the switchgear breakers.
The SPG is a semi-ind'ependent service group located on site to perform the unique function of servicing and calibrating all the protective relays onsite and in the 240 kV switchyard.
The advantage of having such an independent, onsite group is that the safety-related switchgear is
. tested by another group after the Electrical Maintenance Departments performs'verhauls and preventive maintenance during outages.
The team noted'hat both the System Protection and Electrical Maintenance worked well together with this arrangement.
The team reviewed the protective relay calibration procedures, the preliminary protective relay setting drawings and the latest calibration data sheets for both units.'he team determined the calibrations were performed correctly, but the procedures needed to be upgraded.
Test data sheets did not clearly state acceptance criteria, tolerances, and MSTE record data.
(See Appendix A, Finding 91-03-06)
The preliminary protective relay setting drawings were reviewed but had not been issued.
In 'addition tolerances were not listed.
(See Appendix A, Finding 91-03-07)
5,0'NGINEERING AND TECHNICAL SUPPORT The team assessed the licensee's capability and performance regarding engineering technical support associated with the electrical distribution system.
The basis for this assessment included the following areas; technical organizations and interfaces, problem identification and
resolution, modifications, and routine technical support of EDS related activities.
5.1 Conclusion 5,2 The engineering technical support and design controls provided for EDS activities at St. Lucie were appropriate to monitor and maintain the integrity of the EDS as designed.
The various engineering organizations providing technical support were appropriately staffed,,
interfaces defined, and working relationships established.
Perfor-mance demonstrated involvement in problem identification and resolution as well as routine activities in maintenance, testing, operations, and procurement.
Modifications were implemented in accordance with regulatory guides and industry standards.
Organization and Interfaces Engineering and technical support for the EDS was provided by various onsite and offsite engineering organizations.
All design change activity was accomplished by the corporate design engineering organization, JPN.
Another corporate engineering group, SPG, accomplished all maintenance and testing of protective relays down to the s'afety-related 480 V buses.
Maintenance =and testing of all remaining protective relays and EDS equipment was accomplished by the plant electrical maintenance organization.
This organization included an electrical engineering support group.
JPN had field offices at the plant and at the local A/E organization office.
One system engineer was directly involved with the EDS, the Diesel Generator system engineer.
Review of documentation associated with maintenance, testing, and root cause analysis activities demonstrated interfaces and working relationships between technical support and plant organizations were defined and established.
Team discussions with various technical and plant organizations on interfacing issues such as modifications and root cause analysis further demonstrated effective communications.
5,3 Problem Identification and Resolution The engineering organizations were involved in various
'levels of problem identification and resolution.
Many equipment problems were identified as a result of Planned Maintenance activity.
A specific example was the implementation of a required overhaul schedule for circuit breakers based on age rather than operating cycles. 'n engineering evaluation of breaker failu'res and PN information indicated age was the greater contributing factor to breaker failures.
Diagnostic activity such as battery capacity testing, thermography, and motor vibration trending was also provided by EN technical groups.
Special programs were established to address
CFR 21 concerns regarding YiOV Limitorque actuators, 480 VAC circuit
breakers and current transformers, reactor trip breakers, and safety rel ated rel ays.
Involvement by all engineering organizations was evident in formal root cause analysis programs such as In-House Event Reports, Problem Reports, LERs, and Non-confo'rmance Reports.
An example of root cause analysis activity was the evaluation of end-of-life degradation of large electric motors at St.
Lucie.
Interface with vendors and evaluation of operating history and environmental conditions of these safety-related motors
'demonstrated an aggressive approach by the technical staff on this issue.
Review of inter-office memorandum and discussions with electrical maintenance staff demonstrated root cause analysis activity on corrective maintenance issues which were not formally documented.
The design engineering organization was in the process of developing controlled. documents for relay setpoints and fuses.
Industry issues identified in generic communications were reviewed and processed by the STA group in conjunction with the corporate licensing organiza-tion..
The ISEG performed 15 evaluations of specific EDS issues since 1987.
Overall, the engineering and technical support provided by corporate and plant technical staffs related to EDS problem identi-fication and resolution was good.
Routine Technical Support Routine technical support was demonstrated by the plant engineering staff in maintenance, operations, testing, and procurement.
A direct interface with maintenance activity was provided by the EN technical support groups which were involved in the collection and evaluation of information related to EDS equipment performance and planning and oversight of maintenance activity.
Additionally, the technical staff had established a process to transform the vendor manuals to a
more user friendly format for craft usage.
Operational events related to EDS equipment issues and temporary leads and jumpers were evaluated by the STA staff.
The Diesel Generator system engineer monitors the EDG and related system performance.
Responsibility for performance monitoring of other EDS
. related equipment was assigned the EM technical staff.
Routine maintenance and testing of protective relays was provided by SPG.
A Procurement Engineering group'as recently established to ensure implementation of appropriate material and equipment procurement controls.
Appropriate procurement controls were implemented on PWOs a'nd modifications reviewed by the Team.
One exception, was the installation of inappropriate pipe connectors on the EDG starting air receiver relief valves.
This issue was identified by the licensee and corrective action was being initiated.
In 'general, the responsible engineering and technical support organizations have demonstrated appropriate involvement in routine
'plant activities associated with the ED ~
~
5.5 Modifications The Team's review of EDS related modifications included electrical and EDG.mechanical modifications developed and implemented over the previous 5 year period.
This sample included the Station Blackout modification which v/as partially implemented.
Design change documentation was readily retrievable and the te'chnical staff was knowledgeable of the design change process and the specific modifications reviewed by the team.
These modifications further demonstrated the effective interfaces between the corporate, A/E, and plant engineering organizations.
Two issues were noted during the modification review.
The latter will be identified as a. report finding.
The first issue was the improper material piping connec-tions insta11ed on the Unit 2 EDG air receiver tank relief valves.
This issue was recently identified by the licensee gC organization-prior to closure of the P/CM package.
The initiated corrective actions were adequate therefore this issue will not be identified as a finding.
The second issue involved protective relay settings on circuit breakers on the 4. 16 kV 2A3 Bus.
This bus was modified to feed two'. 16 kV/480 V transformers via separate circuit breakers rather than a
common circuit breaker.
Although the original settings were within engineering specifications, lowering the protective relay settings on the dual breaker arrangement wouId have provided more effective protection for the transformers.
(See Appendix A, Finding 91-03-08.
6,0 EXIT MEETING An exit meeting was held on March 22, 1991, at the plant site.
The findings of the team were discussed at that time.
There were no dissenting comments received.
Proprietary information is not contained in this repor APPENDIX A FINDINGS
'Findin 91-03-01:
Start-up Transformer Sharing (paragraph 2.3)
DESCRIPTION:
Both Unit 1 Updated FSAR, Amendment 9 - July 1990, Section'.2.1.3 and Unit 2 Updated FSAR, Amendment 5 - April 1990, Section 8.2.1.5 state that in the event that a start-up transformer of either unit were to be removed from service a
manual switching arrangement was provided which permitted paralleling the 4.16 kV electrical distribution systems of the units to facilitate continued operation of both units.
Note
on EBASCO Diagram 2998-G-275, Sheet 19, Revision I, dated August 6, 1985 - "4.16 kV Switchgear No.
2AB, No.
2A4 and No.2B4 One Line Diagram," which shows the equipment provided, implied that a
single start-up transformer would not be capable of accepting both units'oadings and that the paralleling would overduty the switchgear (i.e.,
exceed fault duty ratings)
in the event of an electrical fault.
The Unit 2 Updated FSAR document stated that should it be necessary for one start-up transformer to supply 4.16 kV power to both units, appropriate operating procedures were developed to assure that the start-up transformer was not overloaded should and accident condition arise.
Contrary to the foregoing, the licensee stated that the procedures did not exist.
Further, it had not been their intention to operate the station in such a manner.
However, the licensee agreed to develop the procedures to preclude start-up transformer overloading and exceeding switchgear fault duty ratings in the event the alignment were to be implemented.
TECHNICAL RE(UIREMENTS:
Criterion 17 - "Electrical Power Systems,"
included in Appendix A to 10 CFR 50 implies that the safety function of the electrical power distribution system shall be to provide sufficient capacity and capability to assure acceptable operation of their nuclear safety-related loads.
SAFETY SIGNIFICANCE:
l/ithout loading procedures, the potential existed for overloading a shared start-up transformer resulting in increased voltage regulation or voltage drop condition through that transformer that had not been analyzed.
This worst case loading condition may cause voltage degradation on the Class IE buses to a
degree that acceptable operation. of the safety-related loads, when served from the preferred offsite power source, could not have been assur ed.
In addition, without appropriate procedures, the potential would also have existed for increased fault duty on Class 1E switchgear, which had not been analyzed.
The integri,ty of the Class 1E electrical power distribution system could have been jeopardized.
A-I
Findin 91-03-02:
DC NOV's Undersized Cables. (paragraph 2.6.2)
DESCRIPTION:
The DC motor operated valves could be required to function towards the end of the battery loading cycle when the batteries have run down to 105 VDC.
Results of the calculation performed by the licensee showed that, in addition to the motor terminal voltage and consequent minimum current draw being below the vendor recommended values, the cable sizes used on some of the motors were smaller than the recommended sizes.
The vender comments on the calculations for Unit 1 indicated that motors will perform satisfactorily.
The comments on Unit 2 HOVs were not received to date.
The team considered that vender recommendation on cable sizing might have been revised over the years.
However the licensee should exercise care while making any torque switch modifications or equipment replacements in this area.
TECHNICAL RE(UIRENENT:
Vender recommendation that cables for the motors should be sized to allow for five times the full load current.
SAFETY SIGNIFICANCE:
The cables as installed are acceptable as determined by the supplier.
However, future modifications to the torque switch settings or motor replacement on the valves should be evaluated to insure that there is sufficient current carrying capacity in the power cables as they are now installed.
A-2
l1
~.
Findin 91-03-03:
EDG Room Temperature (paragraph 3.4)
DESCRIPTION:
Electrical equipment in EDG room was designed to operate at an ambient tempera-ture of 104 F with occasional allowable rise to 120'F.
A manually controlled Non-Class 1E fan.provided ventilation for the room.
There was no local or remote indication to show the status of the fan.
The fan was not equipped with a thermostatic control or an alarm circuit to indicate against its failure to ventilate.
There was no temperature monitoring device in the room and no procedure identified to take compensatory action if the ventilation fan is in-operative.
The team raised concern that under these conditions, the electrical equipment in EDG room may be subjected to temperature higher than the allowable ambient temperatures for indefinite periods.
The licensee agreed to monitor EDG room temperature regularly and identify some procedural control to address fan inoperability.
TECHNICAL REQUIREMENTS:
FSAR stated that the temperature in the EDG room does not exceed 104'F.
SAFETY SIGNIFICANCE:
Safety-related electrical equipment in EDG room, if subjected to temperatures higher than allowable limit indefinitely, may damage the equipment or shorten its life span.
The safety related equipment may not operate when needed in emergency conditions.
A-3
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Findin 91-03-04:
Molded Case Circuit Breakers (paragraph 4.3)
DESCRIPTION:
The testing of molded case circuit breakers is a generic issue that is being evaluated by the NRC for industry wide action.
The licensee's Electrical Maintenance Department preventive maintenance program requires that non safety related molded case circuit breakers are functionally tested.
A functional check of periodically cycling these breakers several times to ensure they will open and close is performed.
This functional check of cycling the breakers by toggling them
"open" and
"close" several times exercises the trip and latching mechanism within the breaker.
'I The licensee informed the team that during the last refueling outage for Unit 1 thirteen non safety related breakers for the 480 VAC pressurizer heaters failed to close (reset)
when functionally tested.
The team reviewed two completed work orders that required functional testing of the 480 VAC pressurizer heater breakers in Bus 1A3 and Bus 1B3.
Work Orders XA900228104346 for Bus 1A3 and XA900228104628 for Bus 1B3 both dated'February 28, 1990 were reviewed by the team.
In both work orders
"Journeyman's Work Report Continuation Detail Sheet";
it is specifically stated that the failed breakers were taken apart, the hinge lubricated inside, then put back together, and functionally tested (checked)
tlgood(t The team considered the licensee's periodic functional checking of the molded case circuit breakers an excellent example of preventive maintenance detecting and preventing failures in the EDS.
SAFETY SIGNIFICANCE:
Although these breakers are
"non safety",
molded case circuit breakers in safety related circuits may exhibit similar characteristics.
A-4
Findin 91-03-05:
Fuse Control Program (paragraph 4.3)
DESCRIPTION:
The licensee's Electrical Maintenance Department identified in a management concern that incorrect fuses were installed.
- A preliminary investigation was performed in June I988.
A full investigation was performed during July 11-28, 1988 that indicated 56 of 983 installed fuses had the incorrect ampere rating.
As a result of these findings, the Electrical Maintenance Department initiated a "fuse control" program to address and correct the deficiencies with fuses.
However, the fuse control program has not been completed.
At the present time, the fuse sizes and types are only listed in "Bill of Material" (BM) drawings which are referenced on the controlled wiring drawings.
The BM drawings are not readily available th'roughout the plant and are diffi-cult to obtain in the field.
For these reasons the Electrical Maintenance Department submitted REAs (Request for Engineering Assistance)
to design engineering requesting fuse sizes and types be placed on controlled documents for each unit.
The team agreed with Electrical Maintenance that fuse sizes and types need to be placed on readily available controlled documents such as fuse lists or wiring drawings.
The licensee's design engineering stated that fuse sizes and types will be placed on controlled documents.
REQUIREMENT:
CFR Part 50, Appendix B, Criterion V,
"Instructions, Procedures, and Drawings" requires activities affecting quality shall be prescribed by documented instructions, procedures, or drawings....
SAFETY SIGNIFICANCE:
Incorrect fuse sizes and/or types could cause a failure in the EDS.
A-5
Findin 91-03-06:
Protective Relay Setting Procedure (paragraph 4.3)
DESCRIPTION:
The protective relays are calibrated by an on-site System Protection Group that is part of 'the Power Supply Technical Services Department.
These relay calibration procedures were developed by the System Protection Group.
The team reviewed, these procedures identified by the numbers OI-6-PS-XXX and the completed data sheets for the calibrated relays.
The team found the relays were properly calibrated although the calibration procedures need improvement.
The team identified that the following items need to be addressed for these calibration procedures:
The N&TE type by manufacture and/or accuracy needs to be specified The Electronic Test Box needs to be specified by manufacture and model The tolerance for the input signals setpoint should be removed since all settings are digital The "data sheet" Acceptance Criteria needs to be addressed to ensure the
"As Left" condition will be set to prevent drift exceeding the tolerance.
The licensee agreed the above items would be incorporated to enhance the protective relay setting calibration procedures by July 1991.
REQUIREMENT:
CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings,"
requires activities affecting quality be prescribed by documented instructions, procedures, or drawings.
SAFETY SIGNIFICANCE:
Incorrect procedures could result in incorrect calibration of protective relays.
A-6
Findin 91-03-07:
Protective Relay Setting Drawings (paragraph 4.3)
DESCRIPTION:
The licensee determined that the protective relay settings were not listed on one drawing for each unit.
As a result of the pending NRC EDS inspection, the licensee developed a preliminary protective relay setting drawing for each unit, but had not issued these drawings.
The licensee informed the team that these drawings were complete.
The team reviewed the preliminary protective relay setting drawings, for each unit and found them very good except no tolerances were given.
The team ask the licensee when the drawing would be corrected and issued.
The licensee stated these drawings would be issued prior to the next refueling outage for each unit when they would be needed.
REQUIREMENT:
CFR Part 50, Appendix 8,
. Criterion ll,
"Instructions, Procedures, and Drawings" requires activities affecting quality shall be prescribed by documented instructions, procedures, or drawings...
SAFETY SIGNIFICANCE:
Incorrect relay settings could cause a failure in the EDS.
A-7
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Findin 91-03-08:
Plant Change Modification PC/M 58-285 (paragraph 5.5)
DESCRIPTION:
The licensee performed PC/M 59-285 in Unit 2 as part of 10 CFR 50, Appendix R
requirements.
Originally one 4. 16 kV switchgear breaker in Distribution Center 480 VAC 2A-3 fed both 480 VAC Power Centers 2A-2 and 2A-5 via their parallel connected 4. 16 kV/480 V station service transformers.
Since the 4. 16 kV 2A-3 and 480 VAC 2A-2 were located in an
"A" fire area and the 480 VAC 2A-5 was in a "8" fire area, an additional separate 4; 16 kV switchgear breaker was added in 2A-3 to feed the 480 VAC 2A-2.
During the modification the licensee used the same (original) protective relay setting for both breakers although the loads had changed.
The licensee stated that the settings were within protection guidelines'for one or two transformers in parallel due to protection on the 480 VAC load side.
However, the licensee a so agree l
d that it would be an enhancement to lower the protective relay
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st for se ings tt'or a single transformer.
The licensee initiated a
REA (Reque Engineering Assistance)
to lower the settings from Tap 10 dia p
10to Ta
Dial 7.
The team considered this enhancement to be more within the licensee's program.
REQUIREMENT:
CFR Part 50, Appendix 8, Criterion III, Design Control" requires in part that measures shall provide for verifying the adequacy of design.
SAFETY SIGNIFICANCE:
Protective relay settings could prevent significant damage and a potential fire in the station service transformers during certain fault conditions on the secondary side of the transformer and before the 480 VAC breakers.
A-8
Findin 91-03-09:
Licensee performed EDSFI Activity {paragraph 1.0)
DESCRIPTION:
The licensee had performed two self-audits of the Class 1E electrical distribu-tion system in anticipation of the EDSFI planned by the NRC.
The first, completed in late 1990 using "in-house" talent, addressed issues that had been identified as NRC concerns from EDSFI reports of inspections of other licensees including compliance with regulatory requirements, licensing commitments, configuration control and design control.
The second audit was performed in January 1991 using the services of an outside consulting firm.
The second audit fol'lowed the format used by the NRC on previous EDSFI inspections.
Findings identified by both efforts were promptly addressed by the licensee and resulted in the collection and evaluation of design documentation.
Corrective actions included design documentation revisions and updating.
New documenta-tion was generated when required..
The team noted that by these actions, the licensee greatly reduced the number of potential findings that would have otherwise been identified by the NRC EDSFI inspection team.
The team considered these self-audit efforts by the licensee to be a positive move toward self-improvement.
TECHNICAL RE(UIREMENTS:
Criterion 3 of Appendix B to 10 CFR 50 and Section 4 of ANSI N45.2 both address the establishment of measures for design control.
These measures, in part, are enhanced by design reviews and self-audits.
SAFETY SIGNIFICANCE:
The safety significance of the licensee's actions identified by this "Finding" includes, the enhancement of design basis identification, design control, configuration control and safety'argins of the electrical distribution system.
These efforts by the licensee will also aid in the implementation of future plant improvements, operations and maintenance programs.
A-9
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APPENDIX 8 ACRONYMS AND INITIALISMS A/E CVCS.
DFOT EDG EDS EDSFI EM FSAR Hp HVAC ISEG IST JPN kV KVA LER MCC MATE NPSH P/CM PRO SPG STA TS V
VAC VDC Architech Engineer
.
Chemical and Volume Control System Diesel Fuel Oil Transfer Emergency Diesel Generator Electrical Distribution System Electrical Distribution System Functional Inspection Electrical Maintenance (organization)
Final Safety Analysis Report Horsepower Heating Ventilation and Air Conditioning Independent Safety Engineering Group Inservice Testing Juno Plant Nuclear (engineering organization)
kilovolts Kilovolt Amperes Licensee Event Report Motor Control Center Measuring and Test Equipment Net Positive Suction Head Plant Change Modification Plant Work Order System Protection Group Shift Technical Advisor Technical Specification Volts Volts Alternating-current Volts Direct-current 8-1
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~ I APPENDIX C PERSONS CONTACTED Licensee Em lo ees
- p Gr
- W.
B
- G. 8 T.
B W;
B J.
C P.
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C
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'W.
- J.
G R.
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J.
- R
- K.
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- J B.
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R.
- L.
S T.
- G L.
- M.
K.
S.
D.
- R.
M.
- M
- T
- [
- A.
- D D.
- M
,P.
- E D.
J.
- D ames, Mechanical Supervisor, Production Engineering oup (PEG) - Nuclear ohlke, Vice President, Nuc'lear Engineering and Licensing oissy, Plant Manager, St. Lucie Plant (PSL)
ryant, Electrical Engineer, PEG usch,,Electrical Staff Engineer - Juno Beach hapman, Supervisor, Civil Engineering, PEG hristiansen, Electrical Engineer, PEG hurch, Chairman, Independent Safety Engineering Group Clark, Principal Engineer - Electrical, PEG Edwards, Electrical Engineer, PEG eiger, Vice President, Nuclear Assurance Gil, Chief, Civil Engineer, PEG Gilmore, Nuclear Engineer, PEG H. Goldberg, President-Nuclear Gouldy, Principal Engineer, Licensing Harris, Senior Vice President Hoge, Electrical/ISC Engineering Supervisor, PLS Husmer, Director,, Nuclear Engineering Kelly, Mechanical Maintenance Engineer, PSL Kulavich, System Engineer, PSL Leon, guality Assurance Protective Relaying Control Manager, ystem 'Protection Group/Power P'lanning and Delivery Luke, Mechanical Engineering Manager, PEG Madden, Engineering Licensing Supervisor, PSL McLaughlin, Plant Licensing Superintendent Migliaro, Staff Engineer, Juno Beach Mohindm, Production Engineering Group Supervisor Mohn, System Engineer, PSL Mumper, Engineer, PSL Parks, Project Site Manager Pearce, PTN Electrical Maintenance Support Supervisor Raldiris, Lead Electrical Engineer, PEG Roberts, Project Engineering Manager Roger', Electrical Maintenance Superintendent, PSL Saeed, Relay Setting Supervisor, PSL Sager, Plant Vice President Smith, Manager Electrical/I8C Engineering, Juno Beach Smith, System Protection Supervisor, PSL VanSmith, Relay Setting Engineer, PSL Weinkan, Licensing Section Supervisor West, Plant Technica'l Staff Supervisor West, Operations, Supervisor, PSL Wolf, Electrical/I8C Supervisor, PEG C-I
Other Or anizations
- A. Gibson, NRC, Region II, Atlanta, GA
- C. Julian, NRC, Region II, Atlanta, GA
- M. Shymlock, NRC, Region II, Atlanta, GA NRC Resident Ins ectors
- S, Elrod, Senior Resident Inspector
- M. Scott, Resident Inspector
"Attended exit interview.
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