IR 05000277/1993080
| ML20036A116 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 04/12/1993 |
| From: | Matthew R, Ruland W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20036A106 | List: |
| References | |
| 50-277-93-80, 50-278-93-80, NUDOCS 9305100064 | |
| Download: ML20036A116 (33) | |
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O U.S. NUCLEAR REGULATORY COMMISSION
REGION I
REPORT / DOCKET NOS. 50-277/93-80 50-278/93-80 LICENSE NOS.
DPR-44 DPR-56 LICENSEE:
Philadelphia Electric Company Post Office Box 195 Wayne, Pennsylvania 19087-0195 FACILITY NAME:
Peach Bottom Atomic Power Station, Units 2 and 3 INSPECTION DATES:
January 25 through February 12,1993 Inspection Team:
B. Pendlebury, AECL/NRC consultant L. Cheung, Sr. Reactor Engineer, RI M. Goel, AECL/NRC consultant L. Kay, Reactor Engineer, RI R. Mathew, Team leader, RI Prepared By :
ke3 k RLend 3-S-93 R. K. Mathew, Team Izader Date Electrical Section, EB, DRS APPROVED BY:
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I W. H. Ruland, Chief, Electrical Section, Date Engineering Branch, DRS Areas Insnected: Announced team inspection by regional and contract personnel to review the functionality of the electrical distribution system.
Results: Refer to the Executive Summary.
9305100064 930430 DR ADOCK 05000277 PDR
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l l s SUMMARY During the period between January 25 and February 12, 1993, a Nuclear Regulatory Commission (NRC) inspection team conducted a partial electrical distribution system functional inspection (EDSFI) at the Philadelphia Electric Company Corporate Offices and at the Peach Bottom Atomic Power Station (PBAPS) Units 2 and 3 to determine if the electrical
distribution system (EDS) was capable of performing its intended safety functions, as designed, installed and configured.
Based upon the sample of calculations, drawings and studies reviewed and plant equipment inspected, the team's conclusions were that the electrical distribution systems at PBAPS Units 2 and 3 were capable of performing its intended safety functions. The team noted tight margins for the EDG and a marginal 4.16 kV bus transfer logic scheme. The team also noted that the transformer load tap changers (LTC) play an essential part in the maintenance of adequate voltage at the various loads, and failure of this item should be identified in a timely manner.
The team observed that the corporate engineering and site personnel were knowledgeable and provided quality responses to the team's questions in a timely manner. A good interface
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between corporate and site engineering was evident. The plant staff conducting relay testing
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and diesel testing were familiar with test, and EDS equipment and followed appropriate test
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procedures.
I As a result of this inspection, one violation of NRC requirements, as cited in Appendix A,
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was identified regarding the lack of adequate programs to functionally test safety-related 120 Vac breakers and 120 Vac Topaz inverters to assure that they would perform satisfactorily in service. Another violation, which involved documentation for the equipment qualification of core spray pump motors, was not cited due to licensee's prompt corrective actions and minor safety significance. In addition, seven issues remained unresolved and several other findings were reported as observations.
Other design and operational weaknesses that needed further licensee assessment and attention include: the effects of an unwanted start of the electric-driven fire pump on the EDG starting sequence; seismic qualification of EDG room heaters and steam piping; adequacy of the existing EDG tests to envelope the accident load profile; adequacy of EDG fuel storage capacity; and tornado protection for emergency diesel storage and day tank vents.
A summary of the team's findings is contained in Attachment 1. This attachment also identifies the sections of the report which address the specific issues.
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1.0 INTRODUCTION During recent inspections, the Nuclear Regulatory Commission (NRC) staff obsen'ed that, at several operating plants, the functionality of safety-related systems had been compromised by design modifications affecting the electrical distribution system (EDS). The obsen'ed design i
deficiencies were attributed, in part, to improper engineering and technical support.
Examples of these deficiencies included: unmonitored and uncontrolled load growth on j
safety-related buses; inadequate review of design modifications; inadequate design
calculations; improper testing of electrical equipment; and use of unqualified commercial I
grade equipment in safety-related applications.
In view of the above, the NRC initiated electrical distribution system functional inspections
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(EDSFI). The objectives of these inspections were to assess: (1) the capability of the electrical distribution system power sources and equipment to adequately support the operation of safety-related components and (2) the adequacy of the engineering and technical
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support in this area.
The capability of the Peach Bottom Units 2 and 3 EDS was partially evaluated during the special electrical inspection conducted in 1989 and the capability of engineering and technical suppon functions was reviewed during routine engineering inspections. In consideration of the results of the previous reviews, this inspection evaluated areas which had not been previously reviewed.
To achieve the objective of this inspection, the team reviewed calculations, design documents and test data, paying particular attention to those attributes which ensure that quality power is
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delivered to those systems and components that are relied upon to remain functional during and following a design basis event. The review covered portions of onsite and offsite power sources and electrical distribution equipment including transformers, normal and emergency buses, emergency diesel generators, safety-related unit substations and motor control centers, containment electrical penetrations, inverters, and 120 Vac vital distribution system.
l The team verified the adequacy of the emergency on-site and off-site power sources for the EDS equipment and mechanical systems which interface with and support the EDS. A physical examination of selected EDS equipment verified their configuration and ratings. In addition, the team reviewed maintenance, calibration and surveillance activities for selected EDS components.
The inspection considered conformance to the General Design Criteria and other regulatory requirements and to the licensee's commitments contained in applicable portions of the plant Technical Specifications, the Update Final Safety Analysis Report (UFSAR) and the safety evaluation reports.
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Section 2 of this report provides a general description of the Peach Bottom electrical systems.
The details of the specific areas reviewed, the team's findings and the applicable conclusions are described in Sections 3.1 through 5.4 2.0 ELECTRICAL SYSTEMS Peach Bottom Atomic Power Station (PBAPS) Units 2 and 3 generate power at 22 kV and transmit it to their respective North and South 500 kV switchyards. For each unit, a main transformer bank, comprising three, single-phase transformers each, is used to step up the voltage from 22 kV to 500 kV for outward transmission. Two independent sources of 220 kV power, one from the Graceton/Nottingham, and the other from the Newlinville/ Muddy Run sources, provide the off-site power supplies to the plant in accordance with GDC-17.
l Also, an autotransformer with a 13.8 kV tertiary winding interconnects the 500 kV and 230 kV grids.
l During normal unit operation, the required power for the unit auxiliary loads is supplied by a
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45 MVA unit auxiliary transformer (UAT), having two 13.8 kV secondary windings, which step down the voltage from 22 kV to feed two 13.2 kV buses. In the event of a loss of a l
unit generator, the auxiliary buses are shifted to two station start-up transformers (SSTs) #2 and #343 by an m 'matic fast transfer scheme. These transformers are powered by the 230 kV off-site grids, and each have adequate capacity to supply the 13.2 kV auxiliary buses as well as the emergency buses during start-up, shutdown and normal full load operation.
Another possible source of supply is from the autotransformer tertiary winding through #3 Start-up and Emergency Auxiliary Regulating Transformer supplying 13.8 kV power at the start-up bus OOA04.
Each unit includes four Class IE emergency 4.16 kv buses normally aligned, two each, to the two off e.e sources. In the event that one of the off-site sources is lost, the associated buses are transferred to the other off-site source by an automatic dead bus transfer scheme.
l If both off-site power sources are lost, the four buses are supplied by four 2600 kW EDGs which are automatically started and loaded. The 480 Vac emergency power is supplied by four load centers and associated MCCs. Power for vital instruments is provided by four 120 Vac buses supplied from the 480 Vac vital MCCs and the reactor protection system (RPS) by motor-generator sets.
3.9 ELECTRICAL DESIGN To assess the adequacy of PBAPS electrical design, the team reviewed the features and components of the electrical distribution system (EDS). The design was evaluated for compliance with specifications, industry standards, and regulatory requirements and commitments. The documents were reviewed for accuracy and conformance with accepted engineering practices. The scope of the review included drawings, design calculations, and studies associated with:
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The ac system loading, including steady-state and transient load profiles of diesel generators; 2.
Voltage regulation during normal and degraded conditions; 3.
Bus transfers and transformer load tap changer functions; 4.
Diesel generator voltage regulations and sequencing functions; i
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Equipment sizing; 6.
Degraded voltage and undervoltage relay settings; 7.
Containment electrical penetration protection;
The team's findings are described in the paragraphs below.
3.1 4.16 kV Emergency Bus Undervoltage and Degraded Bus Relays The team reviewed calculation PE-88, " Medium Voltage Switchgear Protective Devices,"
Revision 3, and schematic diagram 6280E-71 to determine the adequacy of the protective relay design. During the review of the undervoltage protection scheme for each 4.16 kV emergency bus, the team noted that four initiating relays (127,127Z,127Y and 127E) were connected to the source side of each 4.16 kV bus breaker. These relays are used to trip and prevent automatic re-closure of the source breaker, in the event of an undervoltage situation at the source. In addition, an initiating relay (127-bus) energized from the bus, is used for load shedding and automatic bus transfer, either to the alternate source if this is available, or to the EDG.
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The team's review determined that an adequate coverage of undervoltage/ degraded condition was provided by these relays, and that the system was well designed and achieved good
coordination.
3.2 Load Tap Changers (LTCs)
Load tap changers are fitted to the secondary sides of #2 and #3 start-up and emergency auxiliary transformers, and to the secondary side of start-up transformer #343. At Per:L Bottom, LTCs play an essential role to maintain adequate voltage at the ch ss 1E loads at the 4.16 kV,480 Vac and 120 Vac levels during a design basis event (DBE). Operating time of the LTC is 3 to 5 seconds between adjacent taps, after a delay on start of 30 seconds; these values are referenced to the time setting of the undervoltage relays at the 4.16 kV leve. ____- -.
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i The team observed that weekly surveillance (Procedure RT 9.19-3) to monitor load tap changer operation was not adequate to detect LTC failures in a timely manner and to provide timely warning to the operating personnel. In response, the licensee upgraded a minor alarm j
to major alarm status which will require immediate operator action to maintain adequate voltage. The licensee also stated that additional alarm points to indicate loss of control
power and controls not in the ' AUTO' position are being considered. Subsequent to the inspection, the licensee performed a design change to reduce the LTC dead time from 30 to
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15 seconds to reduce the probability of an undesired repeated bus transfer. This issue is discussed further in Section 3.3.1.
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3.3 Automatic Bus Transfer Schemes 3.3.1 4.16 kV Bus Transfer Scheme The team examined the bus transfer scheme in existence at the 4.16 kV emergency bus E12.
This consists of a normal feed from #2 emergency auxiliary transformer (EAT) through breaker CB-1508; an alternate feed from #3 EAT through breaker CB-1501; and a feed from
- 1 EDG through breaker CB-1503. Other emergency buses are similar or have the normal and altemate feeds from #3 EAT and #2 EAT respectively. The planned sequence of operations is to supply the bus from the normal source. When this is no longer adequate, the bus feed is transferred to the alternate source. When both off-site power sources are outside acceptable limits, the bus feed is then transferred to the EDGs. Because of the symmetry of the closing / tripping logic for both the normal and alternate breakers, the team investigated the possibility of cycling between the breakers, and thus not fulfilling the desired design function.
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I The team noted that for the case where the normal source voltage has a sustained failure, bus transfer would take place successfully. Specifically, the bus would be energized from the alternate source breaker, provided the source was available and within operating limits; otherwise, transfer would be to the EDG source.
The team reviewed cases where the source voltages are degrading. For this to happen during l
l a LOCA and an ESF load sequence start, the 4.16 kV bus voltage must degrade to a 0.6 p.u.
value (on a 4.16 kV base) for a very short time, or to a 0.89 p.u. value for 10 seconds or
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more for the source breaker (CB-1508) to trip and initiate bus transfer. Based on the l
operating history of PBAPS, the team noted that the grid was stable and no grid voltage l
swing that would cause a bus transfer had occurred.
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The team examined possible worst-case voltages seen at the source prior to and during a LOCA. At the request of the team, the licensee ran studies for a number of cases involving variations in the number of off-site power sources available, different off-site line voltages, and failure of the LTC. In all cases except one, the licensee showed that the degraded bus l
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relays would not actuate and cause a bus transfer. That one situation involved the plant operating with a single off-site source, LTC out of service and failed in the minimum voltage tap (buck) position, a LOCA in one unit with the grid at the minimum voltage, significant load from the non-accident unit, and an initial 4.16 kV bus voltage of 0.98 p.u. Under these conditions, the degraded voltage relays would operate to trip the supply breaker at approximately 35 seconds and could cause repeated bus transfers. However, the team agreed with the licensee that this sequence of events was of low probability and was outside the licensing and design basis of PBAPS, due to the number and particular types of failure required to occur simultaneously.
The team also reviewed the design of a LOCA relay (14A-K39A) that actuates a permissive in the degraded bus voltage logic. This relay actuates and bypasses a 0.98 p.u. undervoltage relay (127E) during a LOCA for two 4.16 kV emergency buses. The licensee was asked to i
evaluate the impact of a postulated failure of the LOCA relay during a LOCA assuming the
worst case voltage and accident loading conditions. In response, the licensee stated that 0.98
p.u. degraded bus relays for two 4.16 kV buses will not be bypassed and will remain in the
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degraded voltage protection circuits. Therefore, during a LOCA a degraded bus voltage condition of 0.98 p.u. will trip the feeder breaker in 60 seconds. The team noted that the action of a functioning LTC will start to raise bus voltage after 30 seconds. The team considered that there is a marginal case for the assumption that the undervoltage relay will trip in this situation that could cause repeated bus transfers.
I After examining the conditions suitable for the initiation of bus transfers, the team next l
discussed the action of a bus transfer, on the presumption that conditions were favorable. It l
was noted that cycling of breakers could occur with the existing design. The team determined that the existing 4.16 kV bus transfer design is weak in that the existing logic could allow unacceptable repeated bus transfers under certain limiting conditions. The licensee implemented a modification to change the LTC deadband time from 30 seconds to j
15 seconds in the interim to address the potential repeated bus transfer concerns. This setpoint change would improve the response time of LTCs to adjust voltages above the degraded relay trip settings. The licensee is committed to review this issue in detail and take l
appropriate corrective actions to modify the existing logic if warranted. The team had no l
further questions at this time.
3.3.2 13.2 kV Bus Transfer Scheme The team selected the 13.2 kV buses 20A01 and 20A02 and associated breaker circuits to tssess the bus fast transfer scheme. During startup, when the generator is running, transfer is made manually from off-site sources to #2 unit auxiliary transformer by closing and opening their respective breakers. When the generator trips, the generator lockout relay provides two signals, one to open the normal supply breaker and the other to close the start-
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l up bus supply breakers simultaneously.
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The team observed that there was no calculation or test results available that showed the
effects of varying generator voltage or of varying voltage at the start-up buses due to LTC actions during a fast bus transfer. However, the licensee stated that a successful fast bus
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transfer had been achieved on a number of occasions without apparent problems. On request by the team, the licensee provided details of the phase angle difference between the normal
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source and the start-up buses for each unit and approximate transfer times. The results showed acceptable conditions. The team concluded that there was no concern with the
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existing fast bus transfer.
3.4 Transformer Loading The loading calculations showed that five of the eight 4.16 kV/480 Vac,500 kVA safety-related load center transformers could experience an overload either during normal plant
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operation or long term operation after a design basis event. The worst-case overload was l
approximately 20% for transformer 20B10 after a LOCA.
l The licensee knew of the potential overloads and, by administrative controls, was containing
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the problem. The team examined procedure RT-0-55E-775-2, which addresses the administrative controls and found it to be acceptable to monitor and control the overload i
conditions.
The licensee informed the team that a modification (MOD # 5099) had been issued to replace the existing eight Class IE 500 kVA,480 Vac gas-filled emergency load center transformers with new 1000 kVA,480 Vac dry-type transformers. A purchase order, PECO #NE380064, l
had been issued, with a planned replacement schedule of two units per year for the years
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1993 to 1996. The team inspected the project plan, design input document and the purchase order requirement, and was satisfied that implementation of this change was proceeding.
The team concluded that the transformer loading issue would be adequately resolved by the replacement of the transformers.
The team reviewed information regarding the maximum loading on the 230 kV/13.8 kV start-up transformers OOX03, OOX04 and OOX11, and the 13.8 kV/4.16 kV emergency auxiliary transformers OAX04 and OBX04 and concluded that the maximum loadings were within the ratings of these transformers.
3.5 Motor Control Center (MCC) Control Circuits The team reviewed calculations PE-048, "MCC Control Circuit Maximum Cable Length,"
Revision 1, and PE-058, " Determine Maximum 120 Vac Control Wire," Revision 0, which considered the adequacy of the coil pick-up voltage for the MCC line contactors. The calculations approached the problem by deriving an equation for the maximum length of
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cable that could be used between the MCC starter and the initiating or process contact in the field. An allowable voltage of 0.85 p.u. of the contactor coil nominal voltage was used as a reference point, and this value was guaranteed by the manufacturer for reveral sizes of NEMA starters.
A review of the calculation for the limiting cable length showed that the resistance of the
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control circuit transformer secondary fuse had not been included in the calculation. Since the
fuse sizing had been chosen for overload and not short circuit conditions, the fuse resistance was a significant factor (up to 20% of the transformer resistance) in calculating secondary
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output voltage. Therefore, the team was unable to confirm the adequacy of the selected lengths for the safety-related MCC control circuits. This item is unresolved pending the licensee revising the calculations to show the maximum allowable control circuit length considering the fuse resistance (50-277,278/93-80-08).
3.6 Voltage Regulation The team reviewed calculation PE-120, " Voltage Regulation Study," Revision 1, to determine voltages at loads on the 4.16 kV, 480 Vac and 120 Vac systems during start-up, normal and abnormal operation and shutdown with one or two off-site power sources available. The calculation used Bechtel computer program "VOLTDROP" which is a PC version of the mainframe "VOLTANAL" program.
The team checked the assumptions used in obtaining the results and found them to be generally conservative. The team noted that the licensee had used a minimum source voltage
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of 0.934 p.u. on a 230kV base. A review of the historic figures for the off-site voltages for three years indicated that the grid voltages normally remained in the 1.00 to 1.05 p.u. range.
The team noted that due to the LTC, the voltages at the various buses and loads will all tend towards nominal values over time, and undervoltage conditions at the loads will usually be transitory in nature. Hence, the team was interested in motors which had starting voltages less than 0.8 p.u., which is in general the value to which the motors were procured. For
non-motor loads, voltages at the line contactors may not be adequate to pick-up and there will be a delay of several seconds in starting the load. In addition, running motors would experience a dip in voltage as the transient occurred, and in this case, the concern is that the motors will draw more current with the reduced voltage and possibly trip the associated breaker or line contactor on overload or that, for MCC starters, the line contactor may drop out on undervoltage.
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The team noted that for some 460 Vac motors, the calculated minimum starting voltage is below 0.8 p.u. by up to 10%, but the licensee produced motor torque characteristic curves which showed that these motors had adequate starting torque with the available voltage.
MCC loads with starting voltages too low for the line contactors to pick-up have had their starting times adjusted to avoid low voltage conditions. The team accepted the approach by the licensee and had no concerns. The team randomly selected the RHR compartment cooler fan 2AV25 as an example, and requested confirmation that the reduction in motor voltage during running down to 0.734 p.u. would not cause an overload trip condition. The licensee produced a coordination curve showing that this would not happen during the transient. The team concluded that the voltages at the loads were adequate for operation but observed that starting and running at reduced voltages could reduce the lifetime of the motors.
Calculation PE-93, " Verification of 480/120 V Transformer," Revision 0, was reviewed to determine the minimum voltages at the safety-related 120 Vac components. The team noted that adequate voltage was available in all cases, but inquired if there were any loads with voltages lower than the manufacturer's specified figure. The licensee reported that four circuits in the Containment Atmospheric Dilution system had adequate operating voltages but were lower than the manufacturer's recommended values. The licensee was addressing this issue through an NCR, PB-93-00059. The team had no further questions.
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3.7 Emergency Diesel Generators (EDGs)
3.7.1 Transient Leading The team reviewed calculation PE-123, " Diesel Generator lead Profiles and System Voltage Regulation," Revision 0, to determine the transient capability of EDGs. The transient loading was accomplished well within a time interval of 0-10 minutes with satisfactory voltage and frequency. Transient analyses were obtained using a computer program
"VFDIPS" owned by the EDG vendor, Colt Industries.
The team checked the accuracy of the program by comparing the results with a test conducted by Colt Industries, in which measured values of frequency were compared with calculated values. Results of a fully instrumented test by the licensee were also examined, which displayed the variation in voltage and frequency during the start of each load. The Colt test gave an excellent correlation between measured and calculated parameters of EDGs.
In studying the results of the transient loading sequence #3 in calculation PE-123, the team questioned a note in the calculation which stated that the engine will probably not sustain the load because of the coincident start of two 460 Vac ventilation fans and an ESW pump at 26 seconds into the starting sequence. The licensee stated that sequences #1 and #3 in the calculation were not representative of the actual loading sequence, and that the computer program had a built-in limit of 3250 kW (EDG 30 minute rating). The team noted that the I
loading sequence was revised to achieve successful sequencing.
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During the review of automatic sequenced loads for EDGs, a potential for automatic starting of the motor-driven 250 HP fire pump was identified by the team. This could happen on receipt of a signal from a non-safety-related pressure switch that the pressure in the fire protection header was decreasing. This load was not considered by the licensee as a sequenced load. This pump is supplied from a load center energized from bus E2, the most heavily loaded EDG. The postulated load ranged from 203 kW for pump shutoff to 239 kW for rated flow. In response to the team's concern, the licensee stated that failure of non-lE equipment causing an actuation was outside the licensing and design basis for Peach Bottom.
Otherwise, non-lE equipment is assumed to be non-functional. However, the team noted that the licensee did not consider other failures such as undetected failure of the jockey pump to maintain the header pressure. Also, the licensee did not consider the additional loading on the EDG resulted from this load. This is further discussed in Section 3.7.2.
The licensee, nevertheless, produced a loading table for the E2 EDG which included an
i allowance of 203 kW for a start of the fire pump at step 2 in the loading sequence; on the assumption of prior failure of the switch and a wait time until the load center is energized at step 2. This approach showed that the 30 minute rating would be exceeded by 6 kW for a LOCA in Unit 3 and a failure of E4 EDG to start. The licensee stated that, based on the discussions with the manufacturer and review of the past EDG overload event at Peach Bottom, the EDGs would handle the additional load with the existing design. However, the
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team was not provided with any supporting documentation. The team was concerned that a random failure could start the pump at any time during the ESF load sequence, and that such a condition had not been analyzed. This was considered an unresolved item pending further analysis by the licensee of this possible event and further NRC review oflicensee's design and licensing basis (50-277,278/93-80-05).
3.7.2 Steady State Loading
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The team asked the licensee to explain the UFSAR table 8.5.2, which showed that for
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particular EDG failures, the worst-case loading of the in-service EDGs would exceed the continuous rating of 2600 kW for an unspecified time. In reply, the licensee referred to a commitment to stay within the 2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> rating of 3000 kW, except the first 10 minutes for the E2 EDG, as discussed with the NRC on March 12, 1991. After further discussions with the licensee, the team was informed that, after 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> into the DBE, the EDG loads can be maintained below the 2600 kW rating until the next maintenance cycle by stopping the core
spray pump and placing the RHR and HPSW pumps on different EDGs. However, the team noted that the licensee did not document the actual long-term loading and duration of operation for the EDGs in their licensing documents.
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Based on review of steady-state loading for the EDGs, the team noted that the FSAR and loading calculation are less conservative and needed further review and revisions to show the maximum EDG loading. The review showed that the EDG loading could be increased by 277 kW (30 kW for core spray pump,8 kW for CRD pump and 239 kW for fire pump).
I His item is umesolved pending the licensee completing a review of the EDG loading and revising the FSAR and EDG loading calculation. (50-277,278/93-80-07). This is further
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discussed in Section 4.1.
3.8 120 Vae Class IE System PBAPS uses four 120 Vac Class lE panels to supply power to various safety-and non safety-related loads. These panels are fed from four independent, electrically and physically isolated, Class lE 480/120 Vac diesel-backed MCCs. There are no uninterruptible power sources connected to these panels.
The team reviewed transformer sizing, loading, short circuit levels and protective coordination for Class lE vital distribution panel 20Y34 and components. The review indicated that equipment were sized and protected adequately.
i Since the Class IE 120 Vac system was not uninterruptible, the team questioned the adequacy of the power supply for the safety-related instruments and protective systems until the power was restored by the diesel generator during a LOOP event. The licensee stated that vital loads were also powered from "T<. 'az" inverters which were backed-up by class lE de batteries. In addition, the sizing, rating, a 'Th and low trip setpoints, and coordination of protective devices for the HPCI and ECCS Topaz inverters were reviewed. No unacceptable conditions were noted during this review.
3.9 Electrical Penetration Sizing and Protection The team reviewed calculation number PE-Oll, Revision 0, " Evaluation Of Electrical Penetration Circuit Protection," and equipment specification 6280-E-106, Revision 1, to evaluate the adequacy of the electrical containment penetration design. This review determined that the penetrations, supplied by General Electric Corporation, had been
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designed to withstand the temperature increase and mechanical forces developed during continuous and fault currents without impairing containment integrity and without any detriment to the penetration. Additionally, qualification testing had been performed by the manufacturer of prototype units to demonstrate their capabilities.
The team noted that no coordination curves existed for any penetration assembly and the associated upstream protective breakers. However, all the pertinent information was given in calculation PE-011. The team funher noted that the adequacy of primary protection could not easily be determined with this information without coordination curves. In response to
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1 this concern, the licensee generated protective coordination curves for five selected j
penetrations to demonstrate that proper protection existed. The team concluded that the j
electrical penetrations had been properly sized and protected.
3.10 Cable Separation The team reviewed the licensee's cable separation criteria as described in the PBAPS UFSAR
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and applicable electrical drawings describing cable routing information. This review was
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I conducted to ensure that the independence of redundant class 1E circuits was maintained with the existing Peach Bottom cable routing practices and documentation.
The team also reviewed a sample of cables that were routed through the termination cabinets (that were terminated in intermediate terminal blocks) and the licensee's cable management computer system, "INDMS," to verify the cable routing documentation. The team verified the cable report for all circuits associated with the E-2 bus. The circuits sampled were consistent with electrical schematic drawings and the cable routing for safety-related trains i
were routed in their respective trays and conduits and nonsafety-rehited cables were found to be routed through only one division. The team noted that the licensee's software program was "Q" classified and that a 100% walkdown verification for all cables was completed.
Within the scope of the above review, the team identified no concerns pertaining to the licensee's cable routing practices or the documentation using the INDMS software program.
3.11 Conclusions Based on the sample review of PBAPS EDS design attributes, the team concluded that, with the exception of the specific findings noted above, the EDS was generally adequate and no f
safety concerns existed. However, the team did identify some areas which needed to be verified by the licensee. These areas include the EDG loading study,4.16 kV bus transfer logic design, the MCC control circuit calculation and the effects of an unwanted start of the motor-driven fire pump on the EDG starting sequence.
The team noted that the LTCs play an essential part in the maintenance of adequate voltage
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at the various loads. LTC failures should be identified in a timely manner. The undervoltage relay protection scheme for the 4.16 kV buses is well designed, but will not prevent the bus breakers from cycling under the particular circumstance of a degraded source condition. For the EDGs, the team noted that the loading was marginal and would require operator actions
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in order to remain below the allowable limits.
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4 4.0 MECHANICAL SYSTEMS To verify the loading on the emergency diesel generators, the team reviewed the power demands of major loads (selected pumps) and the translation of mechanical into electrical j
i loads used as input into the design basis calculations. To determine the ability of the
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mechanical systems to support the operation of the EDGs during postulated design basis accidents, the team reviewed documentation and conducted walkdowns of the fuel storage and transfer system, starting air system, lube oil and jacket water systems, and service water system. The team also reviewed the heating, ventilation and air conditioning (HVAC)
systems that ensure adequate operating em'ironment for the safety-related equipment.
l 4.1 Power Demands for MMor Loads The team reviewed the manufacturers' pump performance curves and motor efficiencies to determine the power demand on the emergency diesel generators under various accident scenarios.
The team noted that the core spray pumps could be operating near runout conditions at a peak load of 637 BHP. This corresponds to a motor power requirement of 511 kW at 93%
efficiency. The EDG loading calculation, PE-0123, Revision 0, had assumed only 481 kW.
In response to the team's finding, the licensee issued an Action Request (A/R A0718386) to review this item.
The team noted that the control rod drive (CRD) pump could be operating at a maximum flow of 200 GPM with a peak load of 269.6 BHP. This corresponds to a motor power l
requirement of 219.8 kW at 91.5% efficiency. The EDG loading calculation assumed only
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l 212 kW. The licensee stated that the CRD pumps were manual loads and the operator would
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confirm adequate EDG capacity prior to alignment. The licensee further stated that the above additional loading would be reviewed and, if appropriate, the EDG loading calculation and UFSAR Table 8.5.2.B would be revised.
Based on the above, the team concluded that the loading calculation and UFSAR tables need l
to be reviewed and revised to determine the maximum EDG loading. This item is unresolved pending the licensee completing the EDG loading review and revising the loading calculation and UFSAR tables (50-277,278/93-80-07).
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I 4.2 Emergency Diesel Generator and Auxiliary Systems
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4.2.1 Fuel Oil Storage and Transfer System The fuel oil storage and transfer system was reviewed to ascertain that sufficient fuel was available for the EDG operation. The current Technical Specification (TS), section 3.9.A.2
requires that with all four EDGs operable, there must be a minimum of 104,000 gallons of diesel fuel on site. This storage capacity was intended to represent the amount of fuel to
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I support seven-day operation of all four EDGs with the post-accident loads specified in UFSAR Table 8.5.2. The current TS also provides a special action statement that, to keep four EDGs operable with I fuel tank out of use, a minimum of 104,000 gallons of fuel is available in the three remaining tanks. The system consisted of four 36,000 gallon storage tanks and four fuel oil transfer pumps to transfer fuel from associated storage tank to any day tank. The team identified several concerns, as described below.
Non-Conservative Fuel Oil Specific Gravity In calculation PM-123, " Diesel Generator Fuel Oil Consumption for 7-day Operation with LOCA Time Dependent leads," Revision 2, the licensee determined the fuel oil consumption rate based on a fuel oil specific gravity of 0.887. Technical Specification 3.9.8 permits specific gravity to be as low as 0.83. In response to the team's concern, the licensee
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assessed the impact of using worst-case specific gravity of 0.83. The licensee's preliminary I
calculations indicated that, for seven-day operation of four EDGs with LOCA time-dependent loads, the volume of fuel required would be increased to 109,502 gallons. Calculation PM-046, " Diesel Generator Fuel Oil Storage Tank Volume Determinations," Revision 1, showed that the highest practicable transferable volume which could fit into each storage tank without submerging and damaging the level indicator float was 36,000 gallons. Therefore, with one fuel storage tank out of use, the three remaining tanks could hold only 108,000 gallons of fuel.
Procedure ST4100-012-2, Revision 1, " Daily Surveillance leg," indicated that a minimum of 32,500 gallons of fuel was maintained in each storage tank, giving a total administrative limit of 130,000 gallons. Therefore, the practical storage value with all four tanks available was conservative. The team noted that in the licensee's proposed Technical Specification Change Request (TSCR) No. 88-08, the seven day requirement for four EDGs opemble was 108,000 gallons. In response to the team's finding, the licensee agreed to evaluate whether the proposed Technical Specification value of 108,000 gallons should be maintained or increased. This would involve an assessment of the merits of further refinement of the EDG load tabulation, or the imposition of additional procedural constraints for EDG post-accident load management. Therefore, this item is unresolved pending licensee's further evaluation to determine the adequacy of existing fuel oil storage capacity and revising the TS accordingly and further review of this information by the NRC (50-277,278/93-80-09).
Excessive Cycling of Fuel Oil Transfer Pumos The team noted that the day tank was operated in a narrow band to maintain 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> of fuel at full load. Consequently, the transfer pump would cycle on and off approximately 1000 times during a 7-day operating period. The team questioned the adequacy of this design and the reliability of the component to support the operation of the EDGs during a design basis accident. In response to the team's concern, the licensee stated that they are planning to refine the day tank setpoints in accordance with ANSI N195-1976 to minimize excessive cycling. The team had no further question f
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12ck of Tornado-Generated Missile Protection of the EDG Siqrage and Day Tank Vents Section 8.5.2,4 of the UFSAR states that each diesel generator unit is housed in a seismic l
Class I structure, and located such that the equipment is protected against other natural
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phenomena such as flood, tornado, rain, ice, snow, and lightning. During a walkdown, the team noted that the fuel oil storage and day tank vents were exposed to tornado-generated missile hazard.
l In response, the licensee issued an NCR (P-93-00086) and performed a preliminary evaluation. This indicated that due to the physical location of the vents, multiple missiles would be required to disable both venting paths to a given EDG and was not likely that tornado missiles would bend both vent pipes in such a manner as to create an air tight seal such that air in leakage through a damaged pipe would not occur. The licensee stated that a formal engineering design analyses and calculations would be performed to address this concern. This issue is unresolved pending licensee's further analysis and calculations to determine the adequacy of existing fuel oil storage and day tank vent design to withstand tornado-generated missile hazard (50-227,278/93-80-02).
4.2.2 Air Start System The licensee's SSFI report indicated that the leakage rate acceptance criteria for the inlet air check valves to the air start receivers was not finalized. The licensee stated that these valves were recently upgraded from single swing check valves to lift check valves with a soft seat under modification No. 2071. The team noted that a field test was conducted on the E3 EDG in December 1992 which showed that a single air receiver contained enough air to start the engine nine times without compressor assistance. The licensee stated that other test data acquired from the test would be analyzed and calculation No. PM-432 would then be revised to document the proper leakage rate. The team determined that the licensee was taking l
appropriate actions to resolve this issue. The team had no further concerns in this area.
l 4.2.3 Diesel Generator Cooling i
Emergency power for the engineered safeguards equipment was provided by four Fairbanks
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Morse Model 38TD8-1/8 turbocharged and opposed-piston diesel engine generator sets. The heat rejected to the air cooler, lubricating oil cooler, and jacket coolant systems was removed by the emergency service water system through shell and tube heat exchangers arranged in l
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The team found that heat exchanger performance was monitored during EDG monthly surveillance tests and that the data obtained was included in the EDG trending program. The
trended data included the air receiver temperature, lubricating oil cooler and jacket water cooler inlet and outlet temperatures, and emergency service water flow to coolers. The team concluded that the design and surveillance of this system were acceptable.
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The team noted that Arkansas Power reported a mismatch in heat duty between the air cooler heat exchanger and jacket water heat exchanger that could affect the diesel performance.
During full load, significant cross flow from jacket water to air cooler occurred. The manufacturer, Coltec, filed a Part 21 report describing the problem. The team found that, in response to the Part 21 report, plant personnel conducted thermography testing. The thermography test data did not conclusively prove the presence or absence of cross flow.
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PECO is planning to perform additional tests to determine the heat exchanger duty during the l
scheduled tests for the Generic Letter 89-13, " Service Water System Problems Affecdng Safety-Related Equipment," in the summer of 1993. The team determined that the licensee was taking appropriate actions to resolve this issue. The team had no further concerns in this area.
4.3 Class 1E IIVAC 4.3.1 EDG Rooms The diesel engines took combustion air from the EDG room. The EDG manufacturer had specified a maximum combustion air temperature of 110*F for the 3250 kW rating.
Calculation PM-498, Revision 1, " Emergency Diesel Generator Building Cooling Load and Ventilation Requirements," indicated that the maximum predicted temperature in the EDG rooms would be 107.1 F. The team noted that the calculation had assumed air density based on a temperature of 70 F, whereas the outside air design temperature was 95*F. The licensee was asked to determine the maximum temperature in the room based on the air density of 95*F. In response to the team's question, the licensee revised the calculation for the air density changes which showed that the maximum predicted EDG room temperature remained below the design temperature of 110"F with an outside air temperature of 95 F.
The licensee is planning to carry out testing during the second quarter of this year to determine an accurate room temperature profile.
The team was concerned that during worst summer months with outside air above the design basis temperature of 95 F, the EDG room temperature could exceed the design temperature of 110 F. The licensee stated that the EDG high temperature alarm, set at 107 F, would alert the control room operator to take appropriate actions in accordance with the Alarm Response Card #0A (B.C.D) C097 B-4. The team had no further concerns in this area.
4.3.2 Emergency Switchgear Rooms Calculation PM-727, Revision 0, " Emergency Switchgear and Battery Room Maximum Temperature with IAss of Instrument Air," showed that the fan room return air temperature was assumed to be 105 F, whereas the air from the switchgear room recirculated via the fan room was assumed to be 118*F. The team questioned the accuracy of assumptions used in the calculation. In response to the team's concern, the licensee carried out an analysis which
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showed that the fan room temperature would be 110.8*F when considering the heat addition from the recirculating switchgear room ventilation air and taking credit for conductive losses l
out of the fan room. This resulted in an insignificant increase in the overall switchgear room temperature which had a negligible impact on the existing electrical equipment in the room.
i The team had no further concerns in this area.
4.3.3 Battery Rooms The battery room HVAC is part of the emergency switchgear and battery room HVAC system. The team noted that there was a low temperature alarm set at 65'F to annunciate in the control room. Review of P&ID M-399 indicated that, based on the actual flows recorded on the P&ID, two of the battery rooms could be at slightly positive pressure while two switchgear rooms could be at slightly negative pressure with respect to their surroundings.
This could affect the hydrogen concentration in the battery room and switchgear rooms. In response to the team's concern, the licensee revised calculation PM-736, " Battery Room Hydrogen Calculation," to show that hydrogen concentration remained well below the 2%
concentration specified in Regulatory Guide 1.128. The licensee stated that failure of the operating supply or exhaust fan would cause an alarm and also automatically start the l
standby fan. The team had no further concerns in this area.
4.3.4 Emergency Service Water Pump Room l
There was no calculation to determine the minimum temperature on loss of non-qualified l
steam heating to the pump room. However, a low temperature alarm set at 35*F was provided to alert the control room operator to take appropriate actions to maintain pump room temperature above the freezing point. Also, a high temperature alarm set at 120 F, to annunciate in the control room, was also provided to alert the operator to high temperature conditions.
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'Ihe team reviewed calculation 18247-M-033, Revision 0, " Emergency Service Water Pump l
Room Ventilation Evaluation," and noted that the heat load from the supply fan was not included and the motor efficiencies used were non-conservative. The licensee revised their
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calculation to reflect these changes which showed that the pump room maximum temperature would increase from 110.7*F to 115.l*F during a design basis accident. This was found to be below the design basis temperature of 120 F. The team had no further concerns in this area.
4.4 Emergency Service Water System The emergency service water (ESW) system supplies cooling water to the EDGs. The system consists of two full capacity, vertical, single-stage, turbine type pumps, each rated at 8000 gpm and 96 feet head. The pump sucion is normally from the Conowingo pond and the normal discharge is to the pon.
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The team noted that a 6 in. open vent line was provided at high elevation to prevent vapor
pocket formation following a pump trip. However, no analysis was preformed to verify the adequacy of this vent. The licensee stated that routine monthly surveillance tests were performed to verify the system performance including the pump trip conditions. A review of l
the test data indicated acceptable system performance. The team had no further concerns in this area.
l 4.5 Seismic Qualification i
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i The team reviewed the seismic qualification of a selected portion of the EDS (fuel oil piping, air start system and EDG room steam piping) and conducted walkdowns.
Review of seismic qualification documentation revealed that the EDG room steam piping and heaters were upgraded to seismic qualification under modification No. 2 in 1974, The team asked for confirmation ofinstallation in accordance with the drawings. In response, the licensee preformed a field walkdown on February 10, 1993, which indicated that the modification was not installed. The licensee analyzed the condition of the existing piping using the walkdown information. Preliminary results indicated that the piping was capable of
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withstanding a safe-shutdown earthquake without failure of the piping pressure boundary.
The original heating units (two per room) were seismically qualified. However, the above walkdown revealed that certain heater units were replaced with unqualified units for unknown reasons (El-two new units, E2-one new unit, E4-one new unit). On February 12,1993, the valves supplying steam to all of the unqualified units except the unit in the El compartment
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were closed. This action eliminated the concern for the potential heater failures during a seismic event in EDG E2, E3, and E4 rooms until appropriate corrective actions could be
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implemented. In the event of a failure of a heater in the El compartment due to a seismic event, mitigatmg measures were available to take timely corrective action to restore or maintain diesel generator operability. The team noted that an alarm was provided in the i
control room to alert the operator for a high temperature condition in the EDG rooms. In addition, routine operator rounds were performed on a periodic basis to verify the equipment operability. The licensee initiated a non-conformance report (NCR PB 93-00096) to resolve j
discrepancies between the design drawings and the installed conditions of the auxiliary steam j
piping, pipe supports and unit heaters. This item is unresolved pending licensee's completion of final seismic evaluation / qualification of EDG steam piping, piping supports and unit heaters and further NRC review of this information (50-277,278/93-80-04).
The team reviewed Information Notice 90-18, " Potential Problems with Crosby Safety Relief Valves used on Diesel Generator Air Start Receiver Tanks," which was issued to alert the licensees about the potential problems with unqualified Crosby relief valves that could result
in a loss of starting air to the EDGs. The licensee's evaluation of this Information Notice indicated that the Crosby-style relief valves described in the Information Notice were not in l
place at PBAPS. During the inspection, the team identified that one Crosby relief valve (not
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one of the models that was mentioned in the Information Notice) was installed on the manual t
air receiver of the El diesel generator. The licensee's discussions with the manufacturer l
could not confirm that this valve was seismically qualified. In lieu of an extensive document search, the licensee replaced this valve with a qualified Anderson Greenwood valve on February 6,1993. The team had no further concerns in this area.
l The licensee stated that PBAPS is a Seismic Qualification Utility Group (SQUG) plant and l
they are addressing the seismic qualification issue in accordance with Generic Letter No.
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87-02 to address the unresolved safety issue (USI) A46.
4.6 Environmental Qualification of Core Spray Pump Motors j
During the review of the core spray pump curve, the team noted that the core spray pump j
t motors were required to operate at 106% of their rated horsepower during post-LOCA conditions. The test report in the Peach Bottom environmental qualification (EQ) file indicated that these motors were tested at 100% of rated horsepower. At the time of the j
inspection, there was no engineering analysis or calculation in the EQ file to demonstrate that
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they were qualified for operation greater than 100% of rated horsepower.
Upon notification, the licensee promptly revised their EQ file to include a calculation which j
provided the qualification data of the core spray pump motor up to 115% of rated horsepower. The post-LOCA environment of the pump motors is relatively mild (nonsteam environment at 126*F) except for radiation (total integrated dose = 2.99 x 10' rads). On l
l February 16,1993, a copy of the revised portion of the EQ file was transmitted to NRC, Region I for the team's review. The team determined that the licensee's corrective action I
was adequate and the qualification of the core spray pump motors was established.
The team concluded that the lack of engineering analysis or calculation in the EQ file to i
show the qualification of the motor for 106% of rated horsepower at the time of the inspection represents a violation of 10 CFR 50.49 (f) and (g). However, the violation is not being cited because the criteria specified in 10 CFR 2, Appendix C, Section V of the Enforcement Policy was satisfied. Specifically, this is Severity I2 vel V violation and the corrective action was taken promptly before the inspection ended. Therefore, this constitutes a non-cited violation (50-277,278/93-80-03).
4.7 Conclusions The team concluded that the design of the mechanical systems supporting the EDS was l
adequate. However, the team identified a number concerns in the areas of EDG loading,
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l fuel storage, fuel transfer pump operation, seismic qualification of steam piping and unit heaters, and tornado / missile protection for storage and day tank vent pipes.
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The team considered the licensee's mechanical engineering staff technically competent and l
knowledgeable of the mechanical supporting systems.
5.0 EQUIPMENT OPERATION, MAINTENANCE, AND TESTING The scope of this inspection element was 1) to assess the effectiveness of the controls that
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were in place to ensure that the design bases for the electrical system were properly tested l
and maintained; and 2) to ascertain whether proper operation procedures were in place for j
the EDS. This effort was accomplished through field walkdown and verification of the as-
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built configuration of electrical equipment as specified in the electrical single-line diagrams
i and site procedures. In addition, EDS operation procedures, and the maintenance and test programs developed for electrical system components, were also reviewed to determine their technical adequacy.
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5.1 Equipment Walkdowns t
The team inspected various areas of the plant to verify the "as-built" configuration of the installed equipment. Areas inspected included the diesel generators, 4160 Vac switchgears, j
battery and battery chargers, and 480 Vac load centers.
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During the walkdown of the battery charger rooms and the relay rooms, the team observed i
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several 4 kV breakers and 4 kV ground trucks (electrical grounding devices) resting on the floor without being chained. These devices rested on wooden blocks. The team also i
observed a battery maintenance cart in the battery room in similar condition. The team was l
concerned that during a seismic event, movement of these equipment might damage safety l
equipment. In response to the team's concern, the licensee's engineering evaluated each case
individually and determined that they would not affect the surrounding safety equipment i
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during a seismic event. The licensee also provided the team with a housekeeping procedure
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(procedure A.30) which permit equipment to be restrained by wooden block at the bottom.
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l While in the EDG rooms, the team observed space heaters (two in each EDG room) with
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auxiliary steam supplies. The auxiliary steam system was not seismically qualified. The
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team's concern was that, should the steam pipe break during a seismic event (non-LOCA condition), steam discharge into the EDG rooms might affect operation of the EDGs.
Resolution of this concern was discussed in Paragraph 4.5 of this report.
Except as described above, the walkdown indicated that adequate measures were in place to i
effectively control system configuration. The electrical equipment inspected was found to be l'
generally well maintained with surrounding areas clear of safety hazards.
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5.2 Equipment Maintenance and Testing
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The team reviewed various maintenance and testing procedures for such equipment as the diesel generator, switchgear,120 Vac circuit breakers, HPCI and ECCS inverters, and
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protective relays. Licensee personnel were interviewed to assess their understanding of the testing and maintenance programs. The team's observations are described below.
5.2.1 Emergency Diesel Generator and Sequencer Testing Periodic surveillance testing of the emergency diesel generators (EDG) is conducted to assure
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their operational availability and capacity to perform their emergency shutdown functions.
The Technical Specifications require the EDGs to be tested monthly to demonstrate
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operational readiness and once every refueling outage for each unit (test of ECCS loading) to demonstrate their capability to accept and start each emergency load within the specified time limit.
In addition to the above, three other tests were also provided, two at three-month intervals, and one at eighteen-month intervals. Each of the three-month tests was to demonstrate that the EDG could be started using different air-start systems (two air-start systems per EDG).
The above tests also involved loading the EDG with about 2600 kW (continuous rating) at 0.93 power factor (pf) for two hours.
The eighteen month test is to demonstrate the EDGs capability for providing maximum LOCA load. Under certain accident conditions, EDG E2 is required to provide a LOCA load of 3035 kW at 0.89 pf for 10 minutes. The eighteen month test, procedure RT-0-052-252-2 requires that the EDG be loaded with 3100 kW at unknown pf for one minute or less, and then at rated load (about 2600 kW) for two hours. The team determined that this test would not demonstrate the maximum LOCA load capability of the EDG in that 1) during the one minute test, the EDG temperature may not have reached steady-state (higher operating
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temperature usually causes the EDG output to decrease), and 2) the pf of the tested load does not match that of the LOCA load. In response, the licensee provided evidence that the EDGs had been tested once on March 6,1970, for one hour at the factory with loading exceeding 3100 kW at unity pf, and a preoperational testing on May 21,1978, for four hours with 3100 kW at unknown power factor.
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The licensee was reluctant to increase the test duration of maximum loading exceeding
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one minute, because testing at this load would have adverse effect on the reliability of the
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EDG. This is a generic issue currently being evaluated by the NRC office of NRR. The team considered this to be an unresolved item pending completion of NRR's evaluation and the recommended actions (50-277,278/93-804)6).
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During the inspection, the team witnessed a monthly testing of E3 diesel generator. This test
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involved starting the EDG manually and loading the EDG for two hours with 2500-2700 kW
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and 900-1100 KVAR. The team observed that the test was conducted in accordance with test
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procedure RT-0-052-203-2, "E3 Diesel Generator Slow Start," and that the test personnel l
were knowledgeable of the system and familiar with the procedure.
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Peach Bottom does not use an integral load sequencer. Time delay relays are used to stagger the starting of the emergency core cooling system (ECCS) pumps and associated load centers
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at predetermined intervals. Test procedure ST-0-012-110-2, "D/G Simulated Auto Actuations and Load Acceptance," is used to verify the load sequences. This test is to be conducted during each unit outage. The team reviewed the test records and verified that the sequence intervals were adequate to prevent simultaneous motor starts.
5.2.2 120 Vac Molded Case Circuit Breakers Molded case circuit breakers (MCCB) were found to be extensively used at Peach Bottom to protect ;20 Vac Class lE buses. Most of these breakers were installed at the time of the plant construction, about twenty years ago; some of them are used to isolate nonsafety-related loads from safety-related buses.
A review of the licensee's program for the periodic testing of these breakers determined that none had been developed to ensure that they would trip within the time-current band specified by the manufacturer and used in the system protection coordination. The trip characteristics of most breakers had never been verified during their installed life. Tripping of the MCCBs at the appropriate time-current values is important to ensure that electrical faults are isolated by the protective device closest to the fault. This is particularly important when a safety-related bus can be affected by a failure of nonsafety-related equipment, since the capability of the nonsafety-related equipment to withstand accident conditions was not verified and, therefore, multiple failure affecting redundant buses should be assumed. The team noted that since the 120 Vac system breakers are not tested to verify the design trip functions, the electrical coordination of 120 Vac power system is not assured to provide reliable power sources for safeguard instruments and inboard and outboard isolation valve relays.
10 CFR 50, Appendix B, Criterion XI, test control, states, in part, that "A test program shall be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in applicable design documents. The test program shall include, as appropriate, proof tests prior to installation, pre-operational tests, and operational tests dming nuclear The lack of periodic testing of the MCCBs to ensure that they were capable of performing their safety function constitutes a violation of the above requirement (50-277,278/93-80-01).
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5.2.3 Inverter Testing I
Peach Bottom Units 2 and 3 do not have a safety-related 120 Vac uninterruptible power supply system. However, the licensee uses Topaz inverters to convert 125 Vdc to 120 Vac for power supplies to the HPCI and ECCS instrumentation and control equipment.
The licensee did not have a program to provide periodic testing and preventive maintenance
for these inverters. Review of the technical manual of these inverters indicated that the input voltage trip setpoints had been changed for the specific application. These setpoints were factory set at 105 Vdc (low) and 140 Vdc (high). The setpoints of the installed inverters had been adjusted to 100 Vdc (low) and 147 Vdc (high). These trip setpoints were selected in accordance with a General Electric Service Information I.etter (SIL #418), " Topaz Inverter IAw Voltage Shutoff," dated May 31,1985. However, these trip setpoints were never calibrated or tested since installation. Adequate trip setpoint verification is required to assure
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that the inverters are tripped when they reach high trip setpoint values to prevent any damage to the inverters and the connected loads due to high voltage. Also, to prevent premature tripping of inverters at low trip setpoints during a LOCA. The team determined that lack of periodic testing of these inveners constitutes a violation of 10 CFR 50, Appendix B, Criterion XI, Test Control, which states, in pan, that "A test program shall be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in applicable design documents. The test program shall include, as appropriate, proof tests prior to installation, pre-operational tests, and operational tests during nuclear power plant or fuel reprocessing plant operation of structures, systems, and components" (50-277,278/93-80-01).
The licensee's engineering staff agreed that periodic cleaning of the air intake filter and periodic testing of the trip setpoints should be implemented for the Topaz inverters. On February 4,1993, the licensee issued a " Preventive Maintenance Request and Approval Form," requesting these activities to be performed once per refueling cycle. This request was still being reviewed by the plant management.
5.2.4 Degraded Voltage Relays The Technical Specifications require the degraded voltage relays to be tested monthly and calibrated once every operating cycle. There are four levels of degraded voltage to initiate a bus transfer to the alternate power source. These four levels are: 98% with 60 sec. delay (non-LOCA), 89% with 9 sec. delay (LOCA), 87% (tested at 70%) with 30 sec. delay, and
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60% (tested at 0%) at 1.8 sec.
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The team observed the surveillance tests of degraded voltage relays of emergency buses E33 and E34 to ascertain whether the tests were conducted in accordance with procedures S13K-
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54-E33-XXFM and SI3K-54-E43-XXFM, respectively. Each level of degraded voltage
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consists of an undervoltage relay and one or more time-delay relays. The test results indicated that all relays tripped within the allowable limits. No deficiencies were observed.
The team also reviewed the calibration records of protective relays of emergency buses E12 and E22. No unacceptable conditions were identified.
5.3 Operation Procedums The team reviewed operating procedures (normal, abnormal, and special event) to confirm that the operating instructions and administrative controls were adequate to ensure operability of the electrical distribution system under all plant operating conditions. In addition,
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operators were interviewed to ensure that they were familiar with the selected procedures and l
knowledge of plant equipment. The procedure review included a walkdown of the control room and of applicable plant areas to ensure that the sampled procedures were accurately written and to verify that the instructions could be accomplished using the installed
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equipment, instrumentation, and controls.
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sufficient level of detail to ensure that the procedure objectives could be accomplished satisfactorily even though there were some minor weaknesses. The operators interviewed i
were found to be familiar with the procedures and with the equipment, instruments, and controls involved. The team noted that the licensee formed a steering committee consisting of personnel from the Operations and Technical Departments with the objective of enhancing the operating procedures.
5.4 Conclusions I
Based upon the above review, the team concluded that the licensee has an acceptable maintenance and test program for Peach Bottom. The technicians performing the EDG testing and the protective relay testing were familiar with their work and knowledgeable of the procedures. Two deficiencies were identified in the equipme71 test areas. They were 1) the licensee did not have test pre;;:ams for periodic testing of 120 Vac molded case circuit breakers and safety-related Topaz inverters; and 2) the EDGs were required to operate beyond the normal rated load (continuous rating) following a postulated LOCA condition.
The team was not convinced that the maximum load testing (18 month test) demonstrated the EDG capability of carrying post-LOCA load.
The operating procedures reviewed contained a sufficient level of details to ensure the operability of the EDS under all operating conditions.
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6.0 UNRESOLVED ITEMS AND OBSERVATIONS i
Unresolved items are matters about which more information is requiral to ascertain whether
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they are acceptable items or violations. Unresolved item (s) identified during this inspection
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are discussed in Sections 4.5, 3.7.1, 5.2.1, 3.7.2, 4.1, 3.5 and 4.2.1.
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Observations are conditions that do not constitute regulatory requirements and are presented j
to the licensee for their consideration.
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j 7.0 EXIT MEETING
The inspectors met with licensee personnel, denoted in Attachment 1, at the conclusion of the
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inspection on February 12,1993, and summarized the scope of the inspection and the l
l inspection nndings.
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Attachment 1
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NITACHMENT 1 l
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SUMMARY OF INSPECTION FINDINGS
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A.
Violations Section 50-277 & 50-278 l
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1.
No periodic test program for 120 Vac 5.2.2 93-80-01 l
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circuit breakers and inverters.
5.2.3
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B.
NON-CITED VIOLATION l
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Lack of adequate EQ documentation for core spray pump motor.
4.6 93-80-03
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C.
Unresolved Items I
1.
No tornado protection for EDG fuel oil
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storage and day tanks.
4.2 93-80-02 l
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Non-seismic steam piping and room heaters j
d installed in EDG rooms.
4.5 93-80-04
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Potential overloading of EDGs due to possible
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loading of fire pump.
3.7.1 93-80-05
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The existing EDG surveillance tests do l
q not envelope accident load profile.
5.2.1-93-80-06
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Additional EDG loads from pumps.
3.7.2 93-80-07-l
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4.1 i
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Control circuit length did not account fuse resistance.
3.5 93-80-08
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7.
The EDG fuel oil storage capacity calculation
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needs to be revised.
4.2.1 93-80-09 d
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Attachment 1
D.
OBSERVATION Section 1.
Weak design for 4 kV bus transfer logic.
3.3.1 2.
Load center transformers are overloaded.
3.4
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3.
Starting and running voltages below nominal values.
3.6 i
No study exists to verify the n kV bus transfer. 3.3.2 5.
The existing design allows cycling of diesel 4.2.1
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fuel transfer pump.
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ATTACIIMENT 2
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PERSONS CONTACTED
e Philadelphia Electric Company j
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h H. Abendroth Contractor
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V. Aggarwul Bmnch Head l
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Austin Project Manager i
- J.
Basilio Branch Head, Licensing j
j W. Baxter Superintendent, Quality Engineering j
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G. Beck Manager, Licensing Section
G. Becknell System Engineer
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W. Boyer Manager, Electrical Plant Section i
R. Brower Technical Section
B. Chambers Maintenance /I&C J.
Cotton General Manager, NQA r
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J.
Coyle Branch Head - PBAPS Technical
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G. Cranston General Manager, Nuclear Engineering J.
Dobbs Maintenance R. Dourte Quality Assurance
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A. Dycus Superintendent, ISEG l
D. Foss Regulation Engineer l
A. Fulvio Supervisor, Regulatory
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L. Fusegni Engineer, SWEC
G. Gellrich Manager, Operations
A. Giancatarino Sr. Engineer, NQA
A. Giangiulio Branch Head, NED i
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Hallenbeck Technical Section
A. Hartman EDSFI - NED Coordinator i
R. Hess NED/ Mechanical Systems
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S. Hutchins EDSFI Preparation Manager
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M. Kray Engineer, NSD
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McElwain Superintendent, Outage
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W. McFarland Engineer, NED
R. McKinley Engineer, Operations Support D. Meyers Superii.tendent Technical
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Mihael Pratt Manager, NQA W. Mindick Branch Head, Power Engineering
T. Niessen Superintendent, Operations
- P. Ott PSE&G Site Rep.
K. Powers Plant Manager H. Ryan Engineer, NED
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Rogenmuser Supervisor, Training
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R. Smith Regulatory Section D. Spamer Engineer
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Attachment 2
C. Schwanz Shift Manager, OPS C. Snowden Document Control A. Stuart Branch Head, Technical
- K. Tom NED P. Tutton NED
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- D. Wartel NED
- C. Wiedersen Branch Head, Site Engineering T. Wilson PRA Engineer U.S. Nuclear Regulatory Commission C. Anderson Chief, Reactor Projects Section 2B
P. Bonnett Resident Inspector B. Korona Reactor Engineer Intern
- J.
Durr Chief, Engineering Branch,
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Lyash Senior Resident Inspector W. Ruland Chief, Electrical Section
State of Pennsylvania S. Maingi Nuclear Engineer Indicates present at the Exit Meeting
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Attachment 3
ATTACIIMENT 3 ABBREVIATIONS J
l A or Amp Amperes AC or ac Alternating Current ANSI American National Standards Institute ASME American Society of Mechanical Engineers BHP or Bhp Brake Horsepower BIL Basic Insulation Level CRF Containment Recirculation Fan CB Circuit Breaker CFR Code of Federal Regulations CONED Consolidated Edison CS Core Spray CVT Constant Voltage Transformer DBA Design Basis Accident DBE Design Basis Event DC or de Direct Current DEMA Diesel Engine Manufacturers Association EAT Emergency Auxiliary Transformer ECCS Emergency Core Cooling System EDG Emergency Diesel Generator EDS Electrical Distribution System
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FLA Full Load Amps i
FSAR Final Safety Analysis Report FTOL Full Term Operating License GDC General Design Criteria l
GE General Electric GM General Motors GPM or gpm Gallons per Minute HV High Voltage HVAC Heating Ventilation and Air Conditioning IEEE Institute of Electrical and Electronics Engineers kV kilovolts kVA kilovolt-amperes kW kilowatts
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LC Imad Center LOCA Loss of Coolant Accident LOOP IAss of Off-site Power i
LTC Imad Top Changer LV Irw Voltage MCC Motor Control Center MOV Motor Operated Valve l
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I Attachment 3
i MS or ms Milliseconds
MVA Mega Volt-Amperes f
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NCR Non Conformance Report NEC National Electrical Code
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NEMA National Electrical Manufacturers Association i
PR Protective Relay (s)
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PSI or psi Pounds per Square Inch
RCP Reactor Coolant Pump RG USNRC Regulatory Guide RHR Residual Heat Removal.
SCR Silicon Controlled Rectifier i
SEP Self Evaluation Program SF Service Factor SI Safety Injection
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STD or Std Standard SUT Startup Transformer-
TS Technical Specification UAT Unit Auxiliary Transformer UL Underwriters Laboratories
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UPS Uninterruptible Power Supply USNRC United States Nuclear Regulatory Commission UST Unit Service Transformer (s)
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j UV Undervoltage V
volt (s)
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Vac volts alternating current
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Vdc volts direct current W
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