IR 05000352/1993024
| ML20059J659 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 11/01/1993 |
| From: | Della Greca A, Easlick T, Ruland W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20059J656 | List: |
| References | |
| 50-352-93-24, 50-353-93-24, NUDOCS 9311150002 | |
| Download: ML20059J659 (52) | |
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION I
REPORT / DOCKET NOS.
50-352/93-24 50-353/93-24
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LICENSE NOS.
NPF-39 NPF-85 LICENSEE:
Philadelphia Electric Company
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Post Office Box 195
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Wayne, Pennsylvania 19087-0195 FACILITY NAME:
Limerick Generating Station, Units 1 and 2 INSPECTION DATES:
September 8 - September 14, 1993 i
MANAGEMENT MEETING:
October 4,1993
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INSPECTORS:
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X. L. Della Gfeca, Sr. Reac/or I!hgineer,
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Electrical Section, EB, DRS oft N
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T. A. Easlick, Resident Ir(sp6 dor,
/ @ ate Limerick 1 and 2, RPS 2B, DRP N!/!f)
APPROVED BY:
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W. H.' Ruland, Chief, Eectrical Section, Date Engineering Branch, DRS 9311150002 931104 SI PDR ADOCK 05000352 G
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i Areas Inspected: The inspectors reviewed the causes leading to the loss of one offsite i
electrical power source and subsequent reactor scram at the Limerick site, on September 7,
1993, the response of personnel and equipment during and following the transient, and the corrective actions to resolve the issues identified by the licensee's review.
Results: The inspectors' review of the licensee's activities to identify and resolve the causes and deficiencies pertaining to the loss of one offsite source and reactor scram concluded that they were adequate. However, concerns were raised regarding the licensee's control of routine maintenance activities not directly related to the operation of the plant. The NRC's l
l review of the causes leading to the event concluded that the event was the result of the I
licensee's inadequate control of these activities heightened by poor communications among
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various working groups and between working groups and management. Another contributor to the event was the licensee's decision to assign responsibilities to the facilities group that-l were apparently beyond their capabilities and training. Two issues pertaining to the root
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cause of a breaker failure to reclose and to the licensee's long term corrective actions were
unresolved.
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DETAIIS
1.0 SCOPE OF INSPFLTION
On September 7,1993, the Limerick Generating Station, Unit 1, experienced a plant trip in
conjunction with the loss of one offsite electrical power source. The inspection was initiated to: determine the circumstances and events which led to the loss of the offsite source; i
evaluate the response of the plant systems to the event; evaluate the licensee's actions in response to the event; and to determine whether potential generic issues associated with the -
event existed.
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2.0 EVENT DESCRIPTION On September 7,1993, at 2:32 p.m., Limerick Generating Station (LGS) experienced a loss of one of the two independent sources of offsite electrical power. The loss occurred when
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one of the supply cables from station auxiliary transformer 10 shoned to ground, causing the i
supply breakers to the 13.2 kV station auxiliary bus 10 to trip.
i The loss of station auxiliary bus 10 caused an electrical transient on both LGS operating units
resulting from the transfer of the supplied safeguard loads to the standby source. Unit 2 recovered from the transient without any appreciable impact. In Unit 1, however, a 480 V
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load center circuit breaker that supplies power to various components in the feedwater level control system failed to reclose following restoration of power to the bus from the alternate supply. The loss of power to the feedwater level control components resulted in a feedwater transient and ultimately in the Unit I reactor scram on low water level (level 3) and in the
main turbine trip on high water level.
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3.0 HUMAN PERFORMANCE j
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3.1 Initiating Activity The licensee had determined that three fire hydrants within the protected area, Nos. 5, 7, and
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12, were leaking and required repair to prevent freezing. The work entailed the repair of the
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remote valves, the replacement of hydrants and connecting pipes, and the restoration of the dminage area surrounding the remote valve. The work associated with the installation of the
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hydrants was' to be performed by the Philadelphia Electric Company (PECo) West Chester fire shop. For the excavation and backfilling work PECo had secured the services of a contractor who was familiar with and experienced in this process. Work packages, including l
work orders, procedures and drawings, had been prepared; work had been planned.
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Excavation activities were completed in late August in accordance with established procedures and without difficulties. However, according to the licensee, due to a decision to
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reduce reliance on vendor labor, on August 27,1993, the contractor's work force was called
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off the job and the backfilling work assigned to the Limerick facilities group. During the
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excavation process, the contractor work force identified a concrete vault containing power.-
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cables near fire hydrant No. 5. This information was provided to the PECo fire protection
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personnel responsible for the repair of the hydrants, but not directly to the faciEties group.
However, the nature of the vault was physically recognizable from a yellow cye painted on its upper surface. In addition, as a result of the transfer of responsibilities to the PECo
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facilities group, the contractor changed the work order status from "in progress" to " ready,"
thus requiring that new or revised work orders be prepared prior continuation of the effort.
New or revised work orders were never prepared.
Following the transfer of responsibilitier to the facilities group, licensee personnel raised some concerns regarding the adequacy and compliance to OSHA standards of the shoring
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erected in the excavated areas. As a result of these concerns, the licensee decided to use pre-fabricated aluminum shoring components. However, the use of these components
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required additional excavation to " square off" the hole to accommodate the new shoring.
The responsibility for these activities was undertaken by the facilities group.
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Fire hydrant No. 5 had been installed a,few inches from the cable vault with concrete forming an arch around the vertical pipe. Therefore, installation of the new shoring required the chipping away of some concrete. For this purpose, the licensee used back-hoe equipment j
with a hydraulic hammer. During the concrete chipping process, approximately three feet of the conduit housing a phase "C" cable from station auxiliary transformer 10 to start-up bus 10 was crushed and the cable itself was pierced and damaged in one area. The licensee
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determined that grounding of the cable conductor to the cable shield was the initiating event
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that resulted in the scram of the LGS Unit I reactor.
The inspectors' review of the activities preceding the event concluded the following:
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The original work packages prepared by the contractor were appropriate and in
compliance with Installation Procedure IP 5.16 and Specification 803-C-5.
Excavation activities were conducted in accordance with the established procedures y
and were completed without difficulties, j
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Although the decision to assign the responsibility of completing the work to the PECo i
facilities group may have been appropriate to reduce the licensee reliance on l
contracted work force, inadequate training was provided to the responsible personnel to plan and complete the remaining work. Discussions with craft personnel involved
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in the work activities indicated that they were not familiar with backfilling a'
requirements. Back. filling was the original scope of their involvement.
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The facilities group supervisors were aware that a work order and necessary
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instructions were needed for all work activities affecting the plant, including the
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backfilling operation. Yet, none were prepared or secured from the contractor, who
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was originally responsible for the operation.
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Communications among the contractor, the facilities group, and the Fire Protection (on-site and West Chester shop) organizations were inadequate. The facilities scope of work, as known at that time, was discussed at least twice, including during a walkdown of the excavation areas. Yet, the nature of the concrete block near fire hydrant No. 5 was neither requested nor discussed. Instead, the relocation of the
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hydrant away from the concrete was proposed. At that time, both the contractor and fire protection personnel were aware of the cable vault. Furthermore, once the responsibility of the ground activities changed from the contractor to PECo, the two PECo organizations never discussed who had the responsibility for the effort and for obtaining the required work order.
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The change in the facilities scope of work from backfilling to shoring and excavation was not recognized by the facilities personnel, even though the first and second line supervisors were at the excavation site while work was being conducted. At least one supervisor was familiar with work control at the Limerick site.
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When the chipping of the concrete commenced to square off the hole, the upper.
I surface of the vault was covered with dirt caved in as a result of rains > Ug preceding days. Therefore, the yellow dye on the upper surface of tne concrete was not immediately evident. No attempt was made to remove the dirt and verify that the concrete was a pad left over from construction days, as it was assumed. One of the PECo facility mechanic involved in the operation was familiar with the use of yellow
dye and could have recognized its significance, had he seen it.
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The communications between the facilities personnel and management were also inadequate. The presence of supervisory personnel at the excavation site was due to a concerns of the facilities personnel that the work activities may be beyond their capabilities and training. These concerns were not raised to the proper management level. Instead, work continued at hydrant No. 5 for approximately twenty minutes beyond the grounding of the cable, until it was recognized that the color, structure and weight of the concrete being chipped was different from other concrete found in the ditch and that the concrete being chipped contained reinforcing steel bars.
l Excavation activities were then transferred to another hydrant and work was stopped only after a nonsafety-related instrument air pipe was severed.
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The calibration and functional tests performed concurrent with plant operations and in accordance with surveillance test procedures were not the initiating cause of the event.
Work was completed at 2:30 p.m., two minutes before power from one offsite source was lost. Emergency bus Dil is normally supplied by the lost offsite source.
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3.2 Operator Actions
At the onset of the event, the Unit 1 operators implemented emergency operating procedures,
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Trip (T)-101, "RPV Control," and T-99, " Post Scram Restoration," and conducted a controlled shutdown. Excellent command and control was evident on the part of shift -
management throughout the event. The decision to have the control room shift supervisor assume command of Unit 1 and the assistant control room shift supervisor assume command
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of Unit 2 allowed for a clear delineation of command and control between the two units, both of which were affected during this event.
The immediate operator response to the decreasing reactor water level was to attempt to
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reduce reactor recirculation flow, in accordance with Operational Transient Procedure (OT)-100, " Reactor Imw Ixvel." However, before the operator could reduce recirculation flow, a unit scram occurred on low reactor water level. The scram occurred approximately 30 seconds after the loss of the 10 station bus. During the electrical panel walkdown l
following the event, an operator observed that the D114-G-D load center feeder breaker i
failed to reclose following the re-energization of Safeguard Bus D11. He immediately reclosed the breaker. The inspectors had no concerns with the operators' response to this event.
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The immediate operator response to this event was good and in accordance with plant procedures. The restoration of electrical power and the resulting plant isolation were well organized and performed in a effective manner.
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3.3 Post-Trip Review
In response to this event, PECo management immediately commenced an investigation to i
determine the root cause for the loss of the 10 station auxiliary bus that resulted in a reactor j
scram. The investigation initially centered on the cause of the ground fault on the 10 bus.-
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not a clear connection between that work and the loss of the 10 bus. It wasn't until the following morning, when some of the dirt and debris were removed from the work site, that the excavation was confirmed as the cause of the 10 bus ground fault. PECo initiated two investigations, one to review the excavation of the fire hydrant and the associated control of work in the yard, and the other to review the plant response to the partial loss of offsite power and the feedwater transient that caused the reactor scram. The scope of these investigations included interviews with responsible individuals, and procedure and drawing reviews. The investigation incorporated root cause analysis methodology, including events and causal factor analysis. At the completion of the inspection, both investigations were still ongoing with preliminary findings provided to the inspectors at time of the exit interview.
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With respect to the excavation and work control issue, PECo determined that fire hydrant #5 was one of three hydrants being repaired during work week 9332. The scope of work for
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this repair included considerable excavation in and around the hydrants to allow hydrant drain repair. This work had been assigned to a contractor who assumed overall job foreman
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control for the excavation activities. Following excavation, the shoring and backfilling responsibilities were assigned to the facilities group. However, supervision went beyond their anticipated and authorized work scope and commenced additional excavation around
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Hydrant #5 During the attempts to chip concrete away from the hydrant, the conduit housing of the 10 startup bus "C" Phase was crushed and a fault created on the "C," phase at 2:34 p.m., which led to a trip of Unit 1. This issue is further discussed in Section 3.1.
i With respect to the issue of the plant response to the event, PECo determined that the failure of the D114-G-D feeder breaker to reclose exacerbated the feedwater transient due to loss of
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electrical power to various components of the feedwater level control system; however, the feedwater system responded properly to this loss of power. PECo also concluded that re-energization of safeguard buses D11 and D13, via the safeguard bus fast transfer, occurred per design, and that operations personnel responded appropriately to the loss of additional equipment due to the electrical transient on both units.
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concluded that PECo was performing a thorough and comprehensive reviews of this event.
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PECo's initial decision to divide this event into two distinct investigations was viewed as a positive initiative by the inspectors since it allowed for an effective use of time and
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manpower.
4.0 EQUIPMENT PERFORMANCE l
4.1 Electrical Systems
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4.1.1 Electrical System Description
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During plant operation, the power for the station auxiliary loads is supplied by two unit auxiliary transformers, one per unit, that step down the voltage from 22 kV and feed their respective 13.8 kV buses, two per unit. In the event of a loss of a unit auxiliary transformer source, the associated auxiliary buses are shifted to two station auxiliary transformers, No.10 and No. 20, by an automatic fast transfer. These two transformers, fed by the 220 kV and 500 kV offsite grids, respectively, during normal plant operation, also supply power to the emergency safeguard buses through two additional station auxiliary buses,
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No.10 and No. 20, respectively.
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i The Limerick safeguard bus system comprises four emergency buses per unit, normally j
aligned, two each, to the two offsite sources. In the event that one of the offsite sources is
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lost, the resulting loss of voltage on the affected safeguard buses causes the respective i
emergency diesel generators to start. Two timers, set at 0.5 and 1 second, respectively, select the next available sources between the diesel generator and the second offsite source.
l The setting of the timers gives preference to the diesel generator source, if available.
The four emergency buses supply power to all safety-related and vital ac systems. Protective relays and overcurrent devices of various sensitivity and function are provided at all voltage i
levels to protect equipment and buses from overloads and system faults. Simplified single
line diagrams of the Limerick electrical system are included in Attachment A.
4.1.2 Electrical System Response During Event l
The LGS Unit I reactor scram and subsequent main turbine trip were the result of the accidental loss of one of the two independent offsite sources combined with the failure of a
circuit breaker in one of the 480 V load center buses. As later determined by the licensee, the loss of the offsite source was the result of a ground fault in a 13.8 kV underground cable (phase C) supplying power from the 10 station auxiliary transformer to the 10 station auxiliary bus. The ground fault was sensed and isolated by an instantaneous voltage differential relay, General Electric type PVDilD. This relay tripped and locked out the 10 station auxiliary bus supply breaker No.106, the 101 safeguard transformer supply breaker No.101, and the 10 start-up bus supply breaker No.10.
The loss of power to the 101 safeguard transformer resulted in the loss of voltage on 4.16 kV safeguard buses D11 and D13, in Unit 1, and D22 and D24, in Unit 2, and the initiation of the bus transfer logic. As designed, after one second delay, the buses were
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l transferred to the available alternate offsite source. The associated four diesel generators, j
l after 0.5 seconds, received their signal to start, started and remained in a standby mode.
i Restoration of power to the safeguard buses initiated the re-energization of the loads that were shed when power was lost according to the preset sequence.
j Each 4.16 kV safeguard bus supplies power, among other loads, to a safeguard 480 V load center bus. This, in turn, supplies power to various loads and motor control centers (MCC).
Bus D1I supplies power to load center bus D114 and this to MCC D114-G-D and its loads.
l The circuit breaker feeding MCC D114-G-D is designed to trip on undervoltage and to reclose when voltage is restored. The failure of this breaker to reclose five seconds after the -
restoration of power to the safeguard buses prevented the re-energization of a local feedwater control panel and ultimately resulted in the reactor scram.
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9-4.1.3 MCC D114-G-D Supply Breaker Failure As indicated above, the air circuit breaker supplying power to MCC D114-G-D is designed
to trip on loss of voltage and to reclose on power restoration. The tripping function is provided by an integral undervoltage device that actuates the trip mechanism of the circuit breaker when voltage to the coil drops below a preset point, approximately 30 to 60% of nominal voltage. The device also prevents reclosure of the breaker until the voltage to the coil is restored to above 80%. Reclosure of this circuit breaker is initiated by a 5-second timer, provided that no accident signal is present. The five second time delay is provided to
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allow time for the breaker closing springs to recharge, following a breaker trip.
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As designed, the circuit breaker tripped when voltage on the load center bus D114 dropped below the setpoint of the undervoltage device. However, it failed to reclose, as designed.
The ensuing continuity checks and functional tests performed by the licensee found no loose connections. In addition, the circuit breaker and associated control components were
determined to be functional and operating within expected tolerances. Therefore, the cause-
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of the circuit breaker failure to reclose was not immediately evident.
i To address the immediate concern, the licensee performed the required preventive l
maintenance of the circuit breaker and replaced the control switch and the two timers used in
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i the closing circuit (the second timer is used to remove the closing signal after a two second
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delay). In addition, the control circuits of three additional breakers, one in Unit 1 and two in Unit 2, were functionally tested to ensure the breakers reclosure capability. The timers
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and control switch of the failcd breaker were sent to a laboratory for further analysis. Plans
were also made to test the circuits of the four affected breakers every six months using a
portable spare breaker.
Discussions with the licensee indicated that, in 1991, the other Unit 1 breaker using the same
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reclosing feature, D124-G-D, had failed to reclose following a switchyard breaker failure that resulted in a voltage transient on its load center bus (Event Investigation Report 91-01-09).
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At that time, the failure was quickly identified by the operators and the breaker manually closed from the control room. Subsequent tests found one of the two timers in the reclosing
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circuit of the breaker to be defective and to operate intermittently. The timer was replaced.
The immediate corrective actions performed by the licensee to address the breaker failure
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were considered to be adequate as an interim solution to the problem. However, considenng
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that (1) another breaker with the same control circuit failed to reclose earlier; (2) a root
cause of the breaker failure during the current event was not identified; and (3) a laboratory i
analysis of the control components was incomplete at the end of the inspection, the acceptability of the corrective actions as fm' al resolution of the issue is unresolved pending completion of analyses and appropriate reviews by the licensee (50-352/93-24-01 and 50-353/93-24-01).
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4.2 Mechanical Systems
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4.2.1 Feedwater System Response
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The loss of the 10 station auxiliary bus pmduced an electrical transient on both Unit I and
't Unit 2. Unit 1 experienced a more significant transient caused by the failure of the D114-G-D safeguard load center feeder breaker to reclose per design, following the re-
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energization of safeguard bus D11 via the fast transfer. During this event, the failure'of the
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D114-G-D breaker to reclose caused a feedwater tensient due to loss of electrical power to various components in the feedwater level control system. This feedwater level transient resulted in a low reactor water level scram.
l The initial fast transfer of safeguard buses D11 and D13 in Unit I resulted in a slight
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feedwater flow decrease (1 Mlb/hr) from 1 A and 1C reactor feedwater pumps (RFP). The
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1 A RFP decreased flow sl:ghtly and remained at a constant speed when power to lighting
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panel 10Y105 was lost. Panel 10Y105 receives power from motor control center (MCC)
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D114-G-D. The 1 A RFP flow decrease was an expected response to the deenergizing of its motor control unit (MCU) local feedpump turbine control logic, which receives power from -
10Y105. In addition to the decreased flow rate, the failure of the breaker to reclose prevented the 1 A RFP from responding during the level trasient. It appears that this failure was a significant contributor to the feedwater system inability to prevent the low water level
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i Lighting panel 10Y105 also supplies power to the condensate recirculation valve control system logic. The loss of power to this logic caused the condensate recirculation valve to open, diverting condensate flow (6000 gpm) from the feedwater system to the main condenser. The diversion of condensate flow resulted in a decrease in RFP suction header a
pressure by 75 psig, and also contributed to the feedwater system's inability to respond to the transient.
As in the case of the 1 A RFP, the IC RFP decreased flow slightly and remained at a constant speed when power to panel 10Y201 was momentarily lost. Panel 10Y201 receives power from MCC D134-R-E, which lost power when safeguard bus D13 swapped feeds from the 101 to the 201 safeguard bus. The IC RFP flow decrease also was an expected response to the deenergizing of its MCU local turbine control logic. The momentary loss of power to the IC RFP motor gear unit (MGU) logic, also supplied by Panel 10Y201, caused the IC i
RFP control signal failure (CSF) interlock to actuate. Since this interlock needed to be manually reset, the IC RFP was prevented from responding during the tmnsient following the re-energizing of the D13 bus.
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The master feedwater level controller, the IB MGU controller, and the IB MCU were unaffected by the loss of power since they receive power from safeguard bus D12, which was not affected during this event. This enabled the IB RFP to respond to the feedwater level control system. However, cince panel 10Y201 also supplies power to the feedwater level control system logic, the input to the master controller failed down scale. This caused the master controller's output to saturate upscale. The IB MGU controller output tracked the master controller output as designed and the IB RFP increased feed flow above the calibrated limit of 7 Mlb/hr. This resulted in an over feed (16 Mlb/hr) condition.
When power was restored to the master controller, the feedwater level control system, sensing that the feed flow was greater than the steam flow and that the reactor water level was higher than normal, demanded a decrease in total feed flow to restore normal reactor level. The 1 A and IC RFPs were unable to respond, but the IB RFP decreased flow. The feedwater logic did not sense the immediate ficw reduction since the IB RFP flow remained above the calibrated range of 7 Mlb/hr for a short time. Therefore, it continued to demand a decreased total feed flow, even though reactor level had returned to normal. The resulting IB RFP rapid decrease in flow, combhed with the low reactor level, caused the feedwater logic to demand an increased total feed flow (the IB RFP flow did not reduce low enough to
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l actuate a recirculation pump runback with reactor water level concurrently below 27.5 I
inches). Since only the IB RFP was responding the required flow demand was not met and level continued to decrease until the reactor scrammed on low level.
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Unit 2 experienced a swap of the feeds for safeguard buses D22 and D24 when the 101 safeguard bus was lost. This resulted in a momentary loss of power to safeguard bus D22,
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MCC D224-G-D, and lighting panel 20Y106, that supplies power to the 2B RFP MCU. The 2B RFP flow decreased slightly, as in the case of the 1A and IC RFPs of Unit 1; however, l
I upon restoration of power, the 2B RFPs flow automatically increased to its original flow rate. The 2A and 2C RFPs were unaffected during this event, since they receive power from D21 and D23 buses, respectively. D21 and D23 are normally aligned to the 201 safeguard
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4.2.2 Plant Response Following the reactor scram on low level, the Unit I reactor operator took manual control of the reactor feedwater pumps. Reactor water level had decreased to approximately -36 inches before level control was established. Therefore, the level did not reach the -38 inch actuation setpoint for the high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) systems. The main turbine tripped on high reactor water level, +54 inches, following the post-scram reactor refill and reactor inventory swell. This in turn caused the loss of the 11 :.tation auxiliary bus due to the fast transfer of the bus to the now deenergized
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10 station bus. The 11 bus is normally aligned to the main turbine, which carries' the in-
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house loads during operation. With the loss of the 11 bus, several pieces of plant equipment
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experienced an electrical power loss including: the 1 A and 1C condensate pumps, the IC
reactor water cleanup pump, and the reactor enclosure HVAC and fuel pool cooling and cleanup systems.
In addition to the feedwater level control logic problems, two other deficiencies were
identified during the post-trip reviews. In the first deficiency the 1A condensate pump trip was not accompanied by the anticipated discharge valve closure. This problem had been identified prior to this event and the valve already had an equipment trouble tag attached.
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PECo is investigating this problem. The second deficiency involved a failed reed switch on
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the position indicating probe (PIP) for control rod 26-43, at control rod position 00. This failure caused the loss of all position indication for rod 26-43, following normal post-scram settling, and led to some indication inconsistency observed by the operators during the event.
.l The post-scram review determined that all control rods had inserted per design to
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position 00, following the scram.
j 5.0 CORRECTIVE ACTIONS
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5.1 Immediate Corrective Actions On the evening of September 7,1993, PECo determined that a coincidental tie between the excavation work and the bus fault existed. At about 7:30 p.m., a site "stop work" was ordered by the Limerick Vice President for all site excavation work. On September 8,1993, following confirmation that the excavation work was the cause of the cable fault, clarifications were issued indicating that the excavation stop work continued to be in effect until further notice. Exceptions to this order would only be granted by the site manager responsible for this program on a task and work group specific basis, after a careful review of the work scope, knowledge and work controls was conducted. On September 9,1993, a safety stand down was conducted with facilities management supervision, building mechanics I
and the Director of Site Support. PECo also published a "near miss" report concerning the personnel safety aspect of the event, and current information was passed on to the Limerick's counterparts at Peach Bottom within two days of the event.
Intermediate corrective actions included: 1) incorporating the excavation process into the plant permit process; 2) providing increased training for site specific supervision in the excavation clearance process; 3) developing station shoring implementing procedures and ensuring appropriate personnel are trained in shoring techniques; and 4) developing station implementing procedures or guidance for excavation direction.
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5.2 Equipment Repair As indicated previously, the cause or causes leading to the failure of circuit breaker D114-G-D were not positively identified because subsequent tests found the breaker and
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associated control components to function within design tolerances. At the end of the inspection period a failure analysis of the control components was still ongoing. In the interim, the licensee replaced all control components, performed the required preventive maintenance of the breaker, and planned to conduct, at six months intervals, functional tests
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of the failed breaker as well as of three more breakers with similar function and controls.
These acuons were considered adequate.
Regarding ihe damaged cable, the licensee removed the damaged section and replaced it with
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a new section. As described in the work request, NCR number LG-93-00370, the section of cable used to replace the damaged section is 1750 kemils as opposed to the 2000 kemils of the existing cables. Also, the thickness and type of insulation materials for the two cables were different,175 mils cross-linked polyethi!ene vs. 220 mils ethylene propilene. The analysis contained within the NCR as well as discussions with the licensee concluded the use of a different size cable and insulation did not adversely affect the rating and function of the offsite source. The two splices, performed in accordance with approved PECo procedures, were found to be acceptable as was the safety evaluation in accordance with 10 CFR 50.59.
No concerns were identified with the repair of the conduit and concrete vault performed in accordance with NCR Number LG-93-00371.
6.0 MANAGEMENT MEETING
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The licensee's preliminary evaluation of the causes leading to the loss of one of the two offsite sources recognized that the control of the activities relating to the excavation work, as well as the turnover of unfmished work between contract and PECo personnel were inadequate. However, their full investigation of the event was still incomplete at the end of the inspection.
In a management meeting with the NRC, on October 4,1993, the licensee confirmed that the control of excavation activities were inadequate and identified the causes leading to the event and the actions that were or would be taken to address the issues involved. A copy of the
'
slides used by the licensee at the meeting is enclosed as Attachment A.
The adequacy and implementation of the corrective actions identified by the licensee are
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unresolved pending the NRC's review of the results of the licensee's completed evaluation repons (50-352/93-244)2 and 50-353/93-24-02).
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Unresolved Items are matter about which additional information is necessary to determine
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in detail under Sections 4.1.3 and 5.3, above.
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8.0 EXIT MEETING
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P The inspectors met with the licensee's personnel denoted in Attachment C of this report at the conclusion of the inspection period on September 14, 1993. At that time, the scope of t
the inspection and the inspection results were summarized. The licensee concurred that the
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control of the excavation activities was less than adequate.
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1. INTRODUCTION BOB BOYCE
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II. CHRONOLOGY OF EVENTS MIKE GALLAGHER
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SR. MANAGER,
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PLANT ENGINEERING l11. INITIATING EVENT CRAIG ADAMS, DIRECTOR SITE SUPPORT SERVICES IV. CABLE RESTORATION ACTIVITIES BILL MINDICK SR. ENGINEER, ELECTRICAL ENGINEERING V. PLANT RESPONSE WAYNE LEWIS MANAGER, ELECTRICAL
& HVAC SYSTEMS VI. OTHER INSIGHTS BOB BOYCE PLANT MANAGER Vll. SUMMARY AND MANAGEMENT DAVE HELWIG OVERVIEW VICE PRESIDENT, LGS
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EXCAVATION OF HYDRANT NO. 5 AUG 9 -
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FEEDER BREAKER i
D114-G-D MCC LOSS OF POWER CAUSED
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UFSAR LOSS OF FEEDWATER ANALYSIS VS.
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FAILURE OF D114-G-D RESULTED IN DEGRADED FEEDWATER RESPONSE ANALYSIS REVEALED FEEDWATER RESPONDED TO THE
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POWER INTERRUPTIONS AS EXPECTED OPERATION'S IMPLEMENTED OT-100," REACTOR LOW LEVEL"
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A'ITACHMENT B PERSONS PRESENT AT MANAGEMENT MEETING
Philadelohia Electric Comoany
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C. Adams Director Site Support Services R. W. Boyce Plant Manager F. DiGuglielmo T & D Service / Cable Engineer M. P. Gallagher Sr. Manager Plant Engineering D. R. Helwig -
Vice President J. G. Hufnagel ISEG Manager J. Kantner Experience Assessment Manager i
Fire Protect 1 System Manager J. Keenan
'
R. M. Krich Licensing I tanager W. Lewis Branch Manager, Plant Engineering D. MacFarland Philadelphia South Division R. C. Maiers PADER - BRP W. J. Mindick Nuclear Engineering /Sr. Electrical Engineer J. A. Muntz Director Site Engineering A. Romano, Jr.
Shift Manager J. Stott Building Mechanical Supervisor U.S. Nuclear Regulatory Commission C. J. Anderson Section Chief, DRP M. J. Boyle NRR/PD I-2
,
J. Caruso Reactor Operations Engineer R. Cooper Director, Division Reactor Projects J. P. Durr Chief, Engineering Branch, DRS -
R. Fernandez Reactor Engineer, DRP C. C. Miller DRS Deputy Director j
'
N. S. Perry Senior Resident Inspector, Limerick W. H. Ruland Engineering Section Chief R. R. Temps Project Engineer, DRP
,
E. Wenzinger Branch Chief, DRP
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ATTACHMENT C PERSONS CONTACTED Philadelohia Electric Company
- C. Adams Director Site Support Services
,
- R. W. Boyce Plant Manager
- B. Bowen Design Engineer M. Brewen Electrical Engineer
,
- P. Davison Feedwater System Manager
- M. P. Gal!agher Sr. Manager Plant Engineering G. Goldner Engineer
K. Grater Lead Modifications Engineer, Bechtel B. Heffner Document Control Coordinator, Bechtel L. Hopkins Operations Manager S. Hutchins Electrical Engineer A. W. Jones Electrical Engineer J. Kantner Experience Assessment Manager
- J. Keenan Fire Protection System Manager J. King Field Superintendent, Installation, Bechtel
- W. Lewis Branch Manager, Plant Engineering J. McCracken West Chester Fire Group D. McKelvey Operating Engineer, Bechtel S. Nave West Chester Fire Group D. Reitnauer Facilities Mechanic A. Romano, Jr.
Shift Manager
'
T. Shannon Electrical Systems Engineer A. Siapik Facilities Supervisor F. Smith Facilities Mechanic
- G. Stewart Regulatory Engineer J. Stott Building Mechanical Supervisor ILS. Nuclear Regulatorv Commission C. J. Anderson Section Chief, DRP
N. S. Perry Senior Resident Inspector, Limerick
,
- denotes attendance at exit meeting
,
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