IR 05000289/1993022
| ML20058A457 | |
| Person / Time | |
|---|---|
| Site: | Crane  |
| Issue date: | 11/09/1993 |
| From: | Rogge J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20058A452 | List: |
| References | |
| 50-289-93-22, NUDOCS 9312010092 | |
| Download: ML20058A457 (22) | |
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i U. S. NUCLEAR REGULATORY COMMISSION REGION 1 Report No.
93-22
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Docket No.
50-289 License No.
DPR-50 Licensee:
GPU Nuclear Corporation P.O. Box 480 Middletown, PA 17057 Facility:
Three Mile Island Station, Unit 1 Location:
Middletown, Pennsylvania inspection Period:
September 10, 1993 - October 25,1993 Inspectors:
Michele G. Evans, Senior Resident inspector
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David P. Beaulieu, Resident inspector Ronald W. Hernan, Project Manager Approved by:
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fd n F. Rogge, @(#
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Reactor Projects Section No. 4B
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kupection Summary
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The NRC Staff conducted safety inspections of Unit 1 power operations. The inspectors -
reviewed plant operations, maintenance, engineering, radiological controls, and security activities as they related to plant safety.
Results: An overview of inspection results is in the executive summary.
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9312010092 931115 PDR ADOCK 05000289.
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EXECUTIVE SUMMARY Three Mile Island Nuclear Power Station Report No. 50-289/93-22 Operations l
Overall, the licensee's outage activities, including the' shut down and start up evolutions,
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l performance of reactor physics testing, and conduct of refueling activities, were well planned j
and coordinated. The licensee had experienced some problems with performance ofinfrequently
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performed evolutions during the last outage, and clear improvement was noted this outage.
However, there were numerous instances where there was a problem with the understanding or control of plant conditions which resulted in inadvertent losses of electrical equipment or inadvertent transfers of water. The licensee is in the process of determining all the incidents that occurred during the outage and intends to evaluate the events to find commonality and take appropriate corrective actions.
The inspectors will review the licensee's evaluations and corrective actions in these areas. (Unresolved item 50-289/93-22-01)
While the plant was shut down and in mid-loop operation, the licensee shifted electrical power supplies to support maintenance activities, and caused an inadvertent increase in core thermocouple temperatures of about 11 F due to a decrease in cooling now to the decay heat removal heat exchanger. The operators responded to the unanticipated situation in a reasonable amount of time. This incident revealed a number of weaknesses in the scheduling process and implementation of the Outage Fuel Protection Criteria.
Due to weak communications between the operating crew and an auxiliary operator, the 'A'
emergency diesel generator air start isolation valve was not closed, resulting in an inadvertent start of the diesel.
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Maintenance Overall, the licensee's conduct of maintenance activities was good. However, weak test controls were demonstrated during conduct of a post-modification test on a newly installed reactor coolant system narrow range pressure detector. RPS channel 'D' tripped because the shutdown bypass bistable was not reset before coming out of Manual Bypass. The safety significance of this incident was minimal, however, as discussed in Inspection Report 50-289/93-19, weak test controls has been a recurring weakness.
Engineering The procedure quality and overall test implementation for the Integrated Leak Rate Test (ILRT)
were good. Quality Assurance personnel involvement in the test was good. However, the licensee failed to perform temperature surveys as required by ANSI N45.4-1972, section 7.4, which is a violation. The safety significance of this violation is minimal since the licensee performed a temperature survey and demonstrated that the test results were acceptable. This ii
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Executive Summary
violation will not be subject to enforcement action because the licensee's efforts in correcting
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the violation met the criteria speciGed in Section VII.B of the Enforcement Policy, dated January 1,1993.
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The licensee's evaluation of fuel defects was good.
The licensee post-modi 0 cation test for decay heat closed cooling water system valves was weak
in that it did not completely test the control circuit for a loss of power.
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The licensee's analysis and corrective actions taken to address three control rods which did not I
's meet the rod drop time criteria during surveillance testing were appropriate.
Safety Assessment and Ouality Verification f
The licensee's independent Onsite Safety Review Group (IOSRG) is closely monitoring plant.
operations, engineering, and maintenance activities. Since many comments are given verbally, i
the IOSRG reports do not always reflect the extent ofIOSRG involvement. Although there are i
few speciOc recommendations in the Monthly Reports, the descriptions of various plant
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incidents, as well as a number of IOSRG findings, demonstrates that they are aware of the
significant safety issues. The IOSRG special reports for engineering were of high quality and
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recommendations made were sound. The IOSRG HPES Coordinator, who reviews the most
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signi0 cant plant events, is only partially effective due to the limited control he has over the
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content or threshold for Plant Experience Reports and therefore, this reduces the effectiveness of the 10SRG. The licensee's General Office Review Board has an Action Item to address this
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issue.
The initial response by Plant Operations Management to the inadvertent reactor coolant system heatup during mid-loop operation was weak because they did not plan to take corrective actions prior to re-entering mid-loop operation later in the outage. However, the licensee's preliminary l
Transient Assessment Report in response to the event was comprehensive and reflected good
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self-assessment. The licensee's planned corrective actions should be adequate to prevent recurrence of similar problems.
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The inspector discussed the similar incidents involving failure to reset the RPS bistables with licensee management. The inspector was concerned that this appeared to be an example of recurring human performance errors which the licensee had not identified. The licensee is
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currently in the process ofimproving their program for evaluation of human performance errorsc
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SUMMARY OF FACILITY ACTIVITIES 1.1 Licensee Activities The licensee shut down Unit 1 on September 10,1993 to begin the 10R refueling outage. The outage lasted approximately 35 days and the Unit was returned to service, with criticality achieved on October 15. At the end of the period, the Unit was at 100% power.
1.2 NRC Sinff Activities The inspectors assessed the adequacy of licensee activities for reactor safety, safeguards, and radiation protection, by reviewing information on a sampling basis. The inspectors obtained information through actual observation oflicensee activities, interviews with licensee personnel, and documentation reviews.
The inspectors observed licensee activities during both normal and back shift hours: 38.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> of direct inspection weic conducted on back shift. The times of back shift inspection were adjusted weekly to assure randomness.
2.0 PLANT OPERATIONS (71707, 71710, 71715)
2.1 Operational Safety Verification The inspectors observed overall plant operation and verified that the licensee operated the plant safely and in accordance with procedures and regulatory requirements. The inspectors conducted regular tours of the following plant areas:
--Control Room
--Auxiliary Building-Switch Gear Areas
--Turbine Building
--Access Control Points
--Intake Structure
--Protected Area Fence Line
--Intermediate Building
--Fuel liandling Building
--Diesel Generator Building The inspectors also conducted tours of the Reactor Building during the outage andjust prior to startup. and found the overall condition to be good.
The inspectors observed plant conditions through control room tours to verify proper alignment
of engineered safety features and compliance with Technical Specifications. The inspectors reviewed facility records and logs to determine if entries were accucate and identified equipment
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status or deficiencies. The inspectors conducted detailed walkdowns of accessible areas to L
inspect major components and systems for leakage, proper alignment, and any general condition f
that might prevent fulfillment of their safety function.
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The inspectors observed the shut down and start up evolutions, performance of reactor physics testing, and conduct of refueling activities (discussed in Section 4.2).
The licensee had experienced some problems with performance ofinfrequently performe_d evolutions during the
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last outage. During the current outage, the inspectors observed that these activities were well a
coordinated and controlled, and that licensee performance clearly improved since the last outage.
Licensee management oversight of the activities was extensive.
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During this outage the licensee implemented the Outage Fuel Protection Criteria (OFPC) which was developed to define an adequate safety margin for protection of the fuel. The criteria applies the Critical Safety Function approach to different Plant Conditions that exist during the outage. The five Critical Safety Functions are reactivity, heat removal, inventory, containment, and electrical. The inspectors did note that the licensee's use of the OFPC was positive and
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provided a net safety benefit. However, weaknesses were noted in the coordination of some outage activities, including management of electric power and decay ~ heat removal systems
availability (discussed in Section 2.3). It is recognized that this is the first outage in.which the licensee has had the opportunity to use the OFPC and that they plan to incorporate lessons learned from this outage.
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2.2 Engineered Safety Features System Walkdown The inspector verified the operability of the decay heat removal (DHR) system for its emergency
standby mode by performing a detailed walkdown of accessible portions of the system during i
the period October 15 through October 25,1993. The inspector reviewed Operating Procedure
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1104-4, " Decay heat Removal System," and Drawing No. 302-640, " Decay Heat Removal Flow Diagram." The inspector reviewed OP 1104-4, Enclosure I, "Startup Valve Checklist,"
performed on October 14, 1993 and independently verified valve positions for a _ sampling of valves on both DHR trains. The inspector also toured the 'B' DHR vault with an auxiliary operator who verified valve positions in the vault.
The inspector confirmed that the DHR components and system, both electrical and mechanical, j
were in the required emergency standby alignment, instrumentation was valved-in, as-built prints reflected the as-installed systems, and the overall conditions observed were satisfactory. The inspector noted a few human factor type improvements that could be made to OP 1104-4 and discussed these with the procedure owner. The licensee promptly addressed the inspector's comments by adding them to the latest Procedure Change Request (PCR) form.
2.3 Inndvertent Reactor Coolant System lleatup while in Mid-Loop Operation On September 10, 1993, the licensee shifted the power supply for vital bus ~B' (VBB), from inverter 'B' to the regulated power supply in accordance with Operating Procedure (OP) 1107-2,
" Emergency Electrical System." The licensee was shifting the power supply for VBB to support maintenance on inverter 'B'
The plant was shutdown and in mid-loop operation with a reactor coolant system (RCS) temperature band of 100 10 F. RCS level was 18 inches above cold leg centerline and 5 feet 6 inches above the top of the core. DHR train 'B' was operating and l
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i DHR train 'A' was available in standby. The shifting of the VBB power source requires that.
VB3 be temporarily deenergized. When thelicensee reenergized VBB from the regulated power J
supply, the decay heat closed cooling water (DCCW) system inlet valve, DC-V-2B, to the DHR
heat exchanger unexpectedly throttled closed. The reduction in closed cooling water flow i
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resulted in core thermocouple temperature increasing from 109.3*F to 120.8 F in approximately 10 minutes. The Control Room Operator (CRO) noted that DC-V-2B had strcked partially closed and opened the valve to restore DCCW flow and RCs temperature returned to the normal
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temperature band.
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2.3.1 Event Description The Shift Supervisor reviewed the bus outage schedule and noted that the 'B' inverter was to be deenergized to allow for preventive maintenance on the inverter. To accomplish this, VBB,
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which was being powered from the 'B' inverter, needed to be transferred to TRA, its alternate
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source. OP 1107-2, Enclosure IV, provides instructions to strip the loads from VBB, deenergize VBB, reenergize VBB from TRA, and reestablish loads on VBB.
The two CROs assigned to perform the transfer reviewed the procedure in advance. The first section of OP 1107-2. Enclosure IV, is titled " Components Affected and No Action Required."
Within this section, up 1.m directs the operators to Operating Procedure 1105-11, " Auxiliary j
instrumentation and Control Systems," for a specific list of ' Al' and 'A2' instrumentation that j
would be lost while VBB was deenergized. This is a procedural error since the step should J
actually refer the operators to a list of 'Bl' and 'B2' instruments located in OP 1105-11, Enclosure llB. The procedural error did not cause any confusion since neither the Shift l
Supervisor nor the CRO performing the transfer ever referred to tN instrumentation list.
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Although the operators do not specifically recall, the title of the section, " Components Affected j
and No Action Required," may have led the operators to minimize the importance of reviewing OP 1105-11.
Because operators did not review the instrumentation list, this led to the unexpected loss of DHR 'B' temperature instrumentation. In addition, OP 1107-2 was written to be performed at power.
Since the licensee performed the procedure during mid-loop operations, there were specific operator actions delineated in the OFPC related to the loss of the -
DHR instrumentation that were not accomplished.
The Outage Fuel Protection Criteria (OFPC) defines what an adequate safety margin is for the 13 plant conditions that occur during outages. For each plant condition, there is a " Desired" level of protection which is the amount of protection (generally related to equipment availability)
that is desirabic to maintain. This " Desired" level' of protection may be reduced to the -
" Minimum" with Director level approval. _While in mid-loop operation, the " Desired"-level is
. j that one DilR temperature indicator in each operating loop be available. Since the licensee unknowingly deenergized both DHR temperature indicators in the operating loop ('B' DHR pump suction temperature and the 'B' DHR cooler), the licensee did not get Director. level approval j
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OP 1107-2 indicates that the DHR flow instrument and source range NI-2 would be lost while
.I VBB is deenergized and the Shift Supervisor was aware of this. The Shift Supervisor indicated that he did not normally review the OFPC, because he considered this to be a Shift Technical Advisor (STA) function. The STA noted that the loss of NI-2 would place them at the
" Minimum" level and the STA and Shift Supervisor verbally obtained authorization from the Director of Operations. The STA did not recognize that the loss of the 'B' DHR flow j
instrument also placed them at the " Minimum" level and therefore did not seek ~ specific I
authorization. The Shift Supervisor made an announcement to control room personnel that NI-2 would be lost and that this placed them at the " Minimum" level.
When VBB was deenergized, the STA monitored the 'B' decay heat systems and trended the two remaining incore temperatures using the safety parameter display system. Nobody noticed that the DHR temperature indicators were unexpectedly lost. The STA thought he was observing 90*F on the 'B' decay heat cooler outlet, but this was actually 00 F.
When the signal
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conditioning cabinets, which are supplied by VBB, were deenergized to shed loads, DC-V-2B,
the DCCW supply inlet, and DC-V-65B, the bypass for the decay heat cooler, lost their control
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power and the valves failed to their engineered efeguards position (DC-V-2B fully open, DC-V-
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65B fully closed.) This provided full DCCW flow through the decay heat cooler and the STA
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observed a decrease in core thermocouple temperatures from 109.78"F to 109.31 F during the i
44 minute period that the signal conditioning cabinets were deenergized.
When VBB was re-powered from TRA, the Control Building ventilation dampers unexpectedly
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shifted, drawing the attention of the Shift Supervisor and the CRO assigned to the VBB transfer.
While they were distracted, the signal conditioning cabinets were reenergized. Reestablishing control power to DC-V-28 unexpectedly caused the valve to move to a position that was more
closed than it had been originally, reducing closed cooling water flow to the decay heat cooler.
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When the signal conditioning cabinets were reenergized, a number of alarms actuated, one of which was "DC-P-1B Flow Low," indicating that closed cooling water flow was less than 2500
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GPM. The plant operators did not identify the alarm, possibly because they were distracted by -
the unexpected shift in ventilation.
The alarm response for low flow would have directed the operator to verify the position of DC-V-2B and DC-V-65B. Within two minutes after DC-V-2B stroked partially closed, the decay
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cooler high outlet temperature for DHR alarmed at 105.75 F. The CRO and STA observed a-rising decay heat cooler outlet temperature for DHR and attempted to Gnd the cause. The CRO
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found that DC-V-2B had stroked closed farther than it was originally. The CRO told the Shift l
Supervisor and retumed the valve to its original position. Incore temperatures peaked at
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120.8"F. The CRO stabilized incere temperatures within their control range. OP 1107-2 has -
j the operators verify the proper position of DC-V-2B and DC-V-65B, but the step was located
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in the latter stages of the enclosure during restoration of power and the operators had not gotten to that step.
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The operators on shift did not log that this incident had occurred, because they did not believe that it was significant. Plant management became aware of the incident by an STA log book entry, i
2.3.2 Event Followup Plant Engineering evaluated why DC-V-2B did not return to its original position after the control circuit for the valve was reenergized. The Foxboro control module is designed to " remember" the previous position of the valve by storing the output voltage from the control module on a integrating capacitor so that in the event of a power loss of one second or less, the output will automatically return to its previous value. However, with power losses of greater than one i
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second, (in this case 44 minutes) the integrating capacitor slowly discharges and the valve will return to a position corresponding to the lower voltage. The circuit was designed for a short.
duration power fault recovery.
The licensee performed a plant modification in 1991 to add control circuits for DC-V-2A/B and-
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DC-V-65A/B to allow control of these valves from control room versus local control. During post-modification testing, the licensee verified the response of the valves to a loss of control power. However, the licensee lifted power leads downstream of the control module integrating capacitor, instead of deenergizing the entire control circuit. Therefore, the licensee was unaware
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that the valves would not return to their original position until the September 18,1993, incident.
The licensee is in the process of preparing a Transient Assessment Report which describes this.
l incident and provides several root causes. The preliminary report indicates that the primary root cause was that OP 1107-2 failed to identify how DC-V-2B would be affected by this transfer, i
there was a lack of procedural precautions and the procedure was not written for current plant
conditions. A contributing cause for this event was the fact that the outage planning process and
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safety review failed to recognize the impact that this evolution would have on the DHR system, and the attendant risks. If this had been recognized, this work would have been rescheduled to
a period where risks were lower. Another contributing cause was that instrumentation which l
was affected by the transfer was not identified by the operators in advance.
l The inspector interviewed several licensee personnel to determine how the guidance provided in the OFPC is incorporated into daily plant operations. The Integrated Scheduling Manager indicated that he did not review the electrical bus schedule against the OFPC, because scheduling.
personnel do not have the technical expertise to perform the review, in addition, the electrical.
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bus schedule was prepared before the OFPC was issued..The Plant Review Group (PRG)
reviewed the schedule against the Outage Fuel Protection Criteria and made several changes to the schedule.
However, the PRG Chairman indicated that the review was from a broad perspective. The PRG review was not sufficiently detailed to identify the. loss of specific instrumentation, especially if the loss was only temporary.
Therefore, the proper implementation of the OFPC was not sufGciently preplanned in advance.
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Then inspector then evaluated how the criteria is implemented by shift personnel. OP 1104-4, j
" Decay Heat Removal System," contains an outage checklist that is filled out each shift and used j
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to verify that current equipment availability satisfies the OFPC. However, if equipment availability changes during the shift, control room personnel would have to refer to the criteria to verify that the loss of the equipment was acceptable. The Shift Supervisor indicated that he did not routinely refer to criteria during the shift, because he considered this to be an STA-
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function. The inspector interviewed several STAS who indicated that they reviewed most, but not all, equipment availability changes against the OFPC. Therefore, problems with equipment unavailability that were not discovered during the scheduling process, may not be discovered by -
shift personnel.
The inspector discussed with the Director of Plant Operations the concern that no one was assigned to review all changes in equipment availability to ensure that the guidance in the OFPC is met. The inspector was concerned that Plant Operations Management had not identified and did not have plans to address this concern prior to the next mid-loop operation, later in the outage. The inspector later learned that Technical Functions was also reviewing the incident and identifying corrective actions. After further discussions, the licensee held a PRG meeting to develop some immediate and long term corrective actions. The immediate corrective actions included revising OP 1107-2 and the OFPC to reflect the experience gained from this event; discussing the event with the STAS; making a Night Order Log entry, which emphasized the need to log and call attention to unexpected events; and reviewing the outage schedule against the OFPC prior to the next RCS drain down. The change to OP 1107-2 included moving the step which verifies the position of DC-V-2A/B and DC-V-65A/B immediately after the step which reenergizes VBA/VBB. The change in the OFPC primarily involved clarifying the
" Desired" electrical bus availability guidelines. The licensee also reviewed the electrical bus schedule and rescheduled one bus outage. As a long term corrective action, the licensee plans to incorporate the OFPC guidelines into the plant operating procedures where practical. The inspector discussed the corrective actions further with the licensee and the licensee made another Night Order Log entry which stated that the Shift Supervisor has the primary responsibility for insuring compliance with the criteria with an independent assessment from the STA.
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2.3.3 Conclusions The inspector concluded that there was a weakness in the implementation of the OFPC, in that-no one was responsible for reviewing all changes in equipment availability in sufficient detail-to ensure that the criteria guidelines were met. In addition, Plant Operations Management did not initially plan to take corrective action to correct this weakness prior to entering mid-loop operation later in the outage. This incident also revealed weaknesses in the scheduling process.
for bus outages, in the quality of OP 1107-2. 2nd in the post-modification test for valves DC-V-2A/B and DC-V-65A/B. With regard :s operator performance, the inspector concluded that although plant operators should have recognized the closed cooling water system low flow alarm, they still responded to the unanticipated situation of DC-V-2B stroking partially closed in a
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reasonable amount of time. The inspector found that the licensee's preliminary Transient Assessment Report was comprehensive and reflected good self-assessment. The licensee's planned corrective actions should be adequate to prevent recurrence of similar problems.
2.4 Control of Plant Condition Changes (Unresolved Item 50-289/93-22-01)
During the refueling outage, there were a number ofinstances where there was a problem with the understanding or control of plant conditions which resulted in inadvertent losses of electrical equipment or inadvertent transfers of water.
The incidents related to electrical equipment included: the inadvertent loss of VBB while
securing the TRA and TRB cross tie; the inadvertent loss of inverters 'A' and 'E' when
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transferring 'IP' 480 V from its cross-tie from 'lS' 480 V to its normal feed from 'lD' 4160 V; the inadvertent closure of the Fuel Handling Building ventilation dampers during refueling operations when the 'lC' ESV MCC was deenergized and; inadvertent loss of VBA while
returning the static switch to service. These incidents reflect a weakness in the control and understanding of off-normal electrical lineups and bus transfers. Several of these incidents were caused because the operating procedure was written for power operation and did not account for the abnormal electrical lineups that occur during outages. The inspector also noted that there
were instances where changes in electrical lineups resulted in problems with plant equipment (especially the ventilation systems) that were unanticipated by plant operators. In the inadvertent reactor coolant system heatup incident described in section 2.3, the unexpected shift in Control
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Building ventilation distracted the Shift Supervisor from addressing the plant heatup.
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The incidents related to inadvertent transfers of water included the following:
On September 15, 1993, while performing surveillance testing, 250 gallons of water leaked from the 'C' makeup pump casing drain valve, MU-V-172C, because the valve had
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been inadvertently left open approximately 1.5 turns.
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On September 22,1993,4600 gallons of water were inadvertently transferred from the
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reclaimed water storage tank to the Reactor Building sump over a 90 minute interval.
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Maintenance personnel had opened the reclaimed water supply valve, CA-V-194, to the reactor coolant drain tank (RCDT) which in turn overflowed to the Reactor Building sump
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via the opening from the removed.RCDT relief valve. Operators were not alerted to the rising level in the RCDT, because the level instrument and high level alarm were out of a
service.
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On September 24, 1993, due to a level difference, about 4000 gallons of water were
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inadvertently transferred from the fuel transfer canal to the pressurizer when the pressurizer code safety relief valve, RC-RV-1 A, was removed from' the pressurizer, thereby opening the vent path. Pressurizer level increased from 180 inches to 355 inches,
while fuel transfer canal level decreased only a small amount due to its large volume.
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On October 8,1993, while filling the 'A' condensate storage tank (CST) from the million J
gallon tank, 300 to 400 gallons of water spilled through the CST vent. The CST was indicating higher than normal level due to the head of the transfer pump. The operator was aware of this and periodically isolated How to determine the actual level. However, at higher levels, the difference in actual level versus indicated level became less, which resulted in the overflow.
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The inspector discussed the above incidents with the Director of Operations and Maintenance who indicated that they were in the process of determining the incidents that occurred during the outage and that they would evaluate these events to Dnd commonality and take appropriate corrective actions. The inspector will review the licensee's evaluations and corrective actions
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in these areas. (Unresolved Item 50-289/93-22-01)
2.5 Inadvertent Start of the 'A' Emergency Diesel Generator On September 25,1993, while deenergizing 125/250 VDC distribution panels 1E and DCA in accordance with Special Test Procedure 1-93-0028, "125/250 VDC Distribution Panels," the licensee inadvertently started the 'A' emergency diesel generator (EDG). When DC bus lE is deenergized, the 'A' EDG air start solenoid valve opens and starts the diesel. The Shift
.J Supervisor was aware that they needed to shut EF-V-15A, the 'A' emergency diesel generator air start isolation valve, to prevent starting the diesel when DC bus lE was deenergized. EF-V-15A is a ball valve which has a limit switch in contact with the valve operator to sense when the valve is not fully open to provide a Diesel Generator Blocked alarm in the control room. The Ccsntrol Room Operator (CRO) contacted an Auxiliary Operator (AO), via radio, to go to_ EDG
'A' to shut EF-V-15A. Due to weak communications, the AO never understood that the CRO wanted EF-V-15A shut. The operating crew, assuming that EF-V-15A was shut, questioned the
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valve position, because they did not receive the Diesel Generator Blocked alarm in the control room. The operating crew thought that there may be a problem with the valve limit switch.
The operating crew told the AO to manually move the limit switch on EF-V-15A and the Diesel Generator Blocked alarm went in and out. Assuming that EF-V-15A was closed, the Shift Supervisor determined that there must be a limit switch problem and decided to deenergize DC bus lE, even though the Diesel Generator Blocked alarm was not in. When the licensee deenergized DC bus 1E, the ' A' EDG started. The licensee found no problems with the EF-V-1511 limit swicch.
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The inspector discussed this incident with the Director of Plant Operations who agreed that it was caused by weak communications between the operating crew and the AO. The Director of Plant Operations discussed the incident with the individuals involved and stressed the importance
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of good communications.
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2.6 Fire in Condensate Pump 'C'
On September 30,1993, at 11:30 a.m., the licensee declared an Event. of Potential Public Interest due to a small fire in the 'C' condensate pump, which is k)cated in the first floor of the turbine building. The motor heater, which is used to drive out moisture when the pump is not operating, ignited some oil that had built up near the heater. A licensee contractor first noticed the fire (6-8 inches high) and smoke and called the control room. The control room dispatched the fire brigade who put out the fire with a portable carbon dioxide fire extinguisher. No offsite assistance was necessary. The licensee meggered the motor and found that there was no
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damage. Also, the licensee cleaned the oil buildup near each of the condensate pump motor heaters. The inspector concluded the licensee's actions in extinguishing the fire and evaluating the pump and motor for possible damage were good.
3.0 SI AINTENANCE (61726, 62703, 71707)
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3.1 Maintenance Observations The inspector reviewed selected maintenance activities to assure that: the activity did not violate Technical Specification Limiting Conditions for Operation and that redundant components were operable; required approvals and releases had been obtained prior to commencing work; procedures used for the task were adequate and work was within the skills of the trade; maintenance technicians were properly qualified; radiological and fire prevention controls were adequate; and, equipment was properly tested and returned to service, Maintenance activities reviewed included:
Preventive Maintenance Procedure E-26 " Vital Power Inverter Maintenance" on inverter
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Preventive Maintenance Procedure E-4 "Switchgear, Bus Duct, Motor Control Center and, j
Transformer Inspection and Cleaning on IC ESV MCC.
Preventive Maintenance Procedure IC-2 " Pressure Loop Calibration" on RC-B&r-2.
- Refueling Procedure 1502-1 " Refueling Operations."
- Job Order No. 79386, " Oil Soaked Insulation Fire Required Feed Pump Turbine 'B' to
be taken Out Of Service. Investigate and Repair Oil Leak."
H The inspector found that the overall conduct of the above maintenance was good and had no concerns. The licensee's refueling activities are described further in section 4.2.
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3.2 Surveillance Observations -
The inspectors observed conduct of surveillance tests to verify that approved procedures were being used, test instrumentation was calibrated, qualified personnel were performing the tests, and test acceptance criteria were met. The inspectors verified that the surveillance tests had been properly scheduled and approved by shift supervision prior to performance, control room operators were knowledgeable about testing in progress, and redundant systems or components were available for service as required. The inspectors routinely veriGed adequate performance
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of daily surveillance tests including instrument channel checks and reactor coolant system
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leakage measurement.
Surveillance activities reviewed included:
Surveillance Procedure 1303-5.2, "RPS High and Low Reactor Coolant Pressure-l Channels."
- Surveillance Procedure 1303-6.1, " Reactor Building Integrated Leak Rate Test."
Surveillance Procedure 1303-11.1, " Control Rod Drop Time."
e Surveillance Procedure 1303-11.19, " Turbine Overspeed Testing."
- Surveillance Procedure 1300-3Y, " Main Steam Isolation Valve Closure IST."
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In general, the inspectors found that the surveillance activities were performed in a controlled manner using appropriate procedures. However, the inspectors had several concerns with the conduct of the testing as described in Sections 3.3 and 4.1. In addition, the licensee's evaluation of control rod drop time testing is discussed in Section 4.2.
3.3 Inadvertent Trip of Reactor Protection System Channel 'D'
On September 20,1993, during post-modification testing on a newly innalled reactor coolant system narrow range pressure detector, an inadvertent trip of Reactor Protection System (RPS)
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Channel 'D' occurred.
While taking the 'D' RPS channel out of Manual Bypass, the
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Instrumentation and Controls (l&C) technician placed the channel in normal and the RPS channel tripped. This placed the RPS in a one of three rather than a two or.t of four logic. The I&C technician and the Shift Supervisor checked the RPS cabinet and fotmd that the shutdown bypass bistable was not reset. The licensee reset the shutdown bypass histable and the two out of four logic was restored.
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Since the pressure detector required post-modification testing as well as surveillance testing, the licensee had decided to perform Surveillance Procedure 1303-5.2, "RPS High and low Reactor Coolant Pressure Channels," as the post-modiGcation test. SP 1303-5.2, section 8.1, performs.
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a pressure transmitter calibration. Following the calibration, Step 8.1.16 takes the RPS channel
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out of Manual Bypass by first resetting any tripped bistables. Steps 8.1.16.2 through 8.1.16.5 performs an independent verification that all associated bistables including the shutdown bypass bistable (step 8.1.16.4) are reset. The Startup and Test Engineer instructed the I&C technician to remove the meters that were connected to the RPS cabinets for the test and take the channel out of Manual Bypass. The Startup and Test Engineer then returned to his office outside the protected area. The 1&C Technician indicated that he knew that he. needed to reset all tripped bistables prior to coming out of Manual Bypass, but he failed to reset the shutdown bypass bistables. Since the Startup and Test Engineer was not at the job site and the I&C technician did not have a copy of SP 1303-5.2 at the RPS cabinet, they did not perform the independent.
verification.
SP 1302-5.2, Step 8.1.16.6, has the technician obtain Shift Supervisor permission to take the channel out of Manual Bypass. The Shift Supervisor stated that he looked in the RPS cabinet and thought that the shutdown bypass bistable lights looked dim (bistabic reset.) After the 'D'-
RPS channel tripped, it took a couple minutes for the I&C Technician and Shift Supervisor to
understand why the channel tripped. They opened the 'B' RPS cabinet to compare indications.
The shutdown bypass bistable is designed to trip the RPS at 1720 psi to prevent plant startup while the RPS is in shut down bypass. When coming out of Manual Bypass while the plant is at power, which is the routine situation, plant personnel are accustomed to observing the shutdown bypass bistables in a tripped state. Since the plant was shut down, this may have contributed to this incident. However, since the independent verification specifically checks the shutdown bypass bistables, the incident should have been averted.
On August 18, 1993, a similar incident occurred when an I&C Technician failed to reset the flux / flow / imbalance bistable on RPS channel 'A'. The inspector discussed these incidents with the Manager of Plant Maintenance who agreed to review the incidents with all I&C personnel.
The inspector concluded that the trip of RPS channel 'D' was caused by the failure to properly impicment SP 1302-5.2 as written. The safety significance of this latest incident is minimal since the plant was shut down and the RPS was in a one of three logic for only a short time.
However, as discussed in Inspection Report 50-289/93-19, weak test controls during the performance of surveillances has been a noted weakness in the past. The inspector discussed the similar incidents involving failure to reset the RPS bistables with licensee management. The inspector was concerned that this appeared to be an example of recurring human performance errors which the licensee had not identified. The licensee stated that they are currently in the process of improving their program for evaluation of human performance errors.-
4.0 ENGINEERING (71707,40500)
4.1 Reactor Building Integrated Leak Rate Test On September 14,15 and 16,1993, the inspector observed portions of Surveillance Procedure (SP) 1303-6.1, " Reactor Building Integrated Leak Rate Test." The Reactor Building was tested to 51.5 psig, which is greater than the design basis peak pressure of 50.6 psig. This surveillance i
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procedure had been upgraded as part of the enhancement process for infrequently used procedures. The inspector found the quality of the procedure to be good. It was a good
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initiative for the beensee to mcorporate lessons learned from past ILRTs into the procedure.
The inspector verified that selected prerequisites were completed in accordance with the procedure. The inspector found that Shift Supervisors and Shift Foremen were informed not to authorize repairs on containment boundaries so that the containment could be tested as close to the "As Found" condition as practical. If repairs or adjustments had been necessary, the licensee
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had provisions to record the "As Found" and "As Left" local leak rates. The inspector verified
that the ILRT test instrumentation had been calibrated within 6 months. The licensee built an
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air conditioned enclosure around the test equipment in the intermediate building to minimize the affects of temperature changes on instrument accuracy. During the closcout inspection.of the Reactor Building the licensee inspected for pressurized containers and removed temixnary air conditioners which contained approximately 60 psig freon. The inspector observed the licensee conduct a portion of the valve lineup of Reactor Building boundary valves. The inspector found that Quality Assurance personnel performed a thorough independent verification of ILRT
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prerequisites including valve lineups. The inspector verified that the decay heat removal system
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was in operation, the reactor building sump was drained to the minimum level, and the reactor building fans, AH-E-1 A/B/C, were operating in slow speed. The inspector determined that the-
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ILRT prerequisites were performed as written.
On September 14,1993, at 2:32 p.m. the licensee commenced Reactor Building pressurization.
After pressurizing to 12 psi and being briefed by the ILRT test director, five persons entered the Reactor Building for 0.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> to perform visual inspections. SP 1303-6.1, Enclosure 3,
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provided specific guidance for the pressure protection of Reactor Building entry personnel which
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included a check of air quality. After pressurizing to approximately 51.5 psig, the licensee performed a number of local leak rate tests using Reactor Building pressure as the pressure l
source.
The four hour temperature stabilization period commenced at 1:45 p.m. on September 15. The inspector independently verified that the average temperature variation during the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> l
stabilization did not vary by more than 0.5 F/ hour from the average temperature change over.
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the last hour. The licensee and inspector received values of 0.008 F/ hour. The reactor building ILRT commenced immediately following the stabilization period and continued for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The licensee collected pressure, dew cell and,- RTD readings every 15 minutes. Two dew cells, one in the basement and one on the polar crane were deleted from calculations due to _ erratic
- behavior. All 24 RTDs remained operable throughout the test. The licensee recorded major.
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plant parameters, that could influence the ILRT test results, on an hourly basis.- These plant
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parameters included pressurizer level, borated water storage tank level, decay heat removal exit -
temperature and once-through-steam-generator levels. The licensee completed the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> test
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on September 16,1993, at 6:45 p.m..
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The inspector performed independent calculations to determine the mass of air in containment at several points during the test. After disregarding the data from two erratic dew point instruments, the inspector's calculations matched the licensee's results. The Gnal 95% upper confidence level leak rate that was calculated by the licensee was 0.0718 weight percent per day; the acceptance criteria is 0.075 weight percent per day.
After test completion, the licensee superimposed a known leak rate of 6.02 ft'/ minute on the calculated leakage for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The licensee calculated that the total leakage during this instrument verification test was 0.1487 weight percent per day. The difference between the superimposed test and the type "A" ILRT was 0.0199 weight percent per day; the acceptance criteria required a difference of less than 0.025 weight percent per day.
The inspector had several concerns on whether the licensee had been conducting the ILRT in -
accordance with the requirements speci6ed in 10 CFR 50, Appendix J.10 CFR 50, Appendix J, requires that all Type A tests be conducted in accordance with the requirements of American National Standard Institute (ANSI) N45.41972, " Leakage Rate Testing of Containment Structures for Nuclear Reactors."
ANSI N45.4-1972, section 7.4,
" Temperature Measurements " requires that area surveys within the structure be made in advance of the leakage-rate testing to establish any tendencies to regional variations in temperature. ANSI N45.4-1972 states further that the temperature pattern revealed by survey shall be employed in determination of the mean representative temperature for the absolute method of leakage rate testing. The location of reference vessels shall be made with consideration of the temperature pattern to reflect representative temperatures.
The inspector asked the licensee for the temperature survey to verify that RTD locations measured a representative temperature for the containment sub-volume in which they were located. The licensee could not provide any documentation to demonstrate that the temperature survey had ever been performed and personnel involved in the past ILRTs did not believe that the surveys were done.
After discussion with the inspector, the licensee indicated that the temperature surveys were not necessary because: the air inside the Reactor Building is continually recirculated by the installed ventilation system; there are very few cubicles inside the Reactor Building; there is a free communication between all levels of the building and also between cubicles and the Reactor.
Building; almost all of the equipment in the Reactor Building, with exception of the recirculation i
fans and required instrumentation, was deenergized during the test, thereby eliminating local hot i
spots; no stratification has been observed during past ILRTs and; the 24 RTDs and 10 dew cells I
were placed in the test position in accordance with Drawings GAI E-311-850,851, and 852 and these locations have been the same for each ILRT.
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The inspector reviewed the temperature data from the 24 RTDs to determine if there.were localized areas where the temperature did not appear to be representative of the sub-volume they_
were measuring. The inspector found two RTDs, TE-655U and TE-655S, that were located on the Grst floor of the Reactor Building which read 4 to 5 F lower than the other first floor RTDs. The licensee reperformed the cak rate calculation by eliminating these two low RTDs and averaging the remaining 22 RTDs.
The licensee found that although the average-
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temperature increased by only 0.2 F, this resulted in a decrease in the calculated leak rate of.
approximately 10 percent. Since a small change in average Reactor Building temperature resulted in a relatively large change in calculated leakage and since the official test results showed Icakage to be just below the acceptance criteria (95% upper confidence level leak rate -
0.0718 weight percent per day versus an acceptance criteria of 0.075 weight %/ day), the inspector requested the licensee to perform the required temperature survey.
On October 11, 1993, the licensee performed the temperature survey of the Reactor Building.
For each RTD, the licensee averaged two temperature measurements at the RTD and averaged approximately seven temperature measurements from alternate locations and compared these two
averages. The licensee then applied this difference to the actual measured temperatures from the ILRT and recalculated the leak rate. The licensee found that the temperature averages were within 0.5 F except for four locations which were affected by local fan flows or by proximity to energized heaters that are off during the ILRT. The bulk average temperature decreased by 0.2 F which resulted in the calculated leak rate increasing by 0.21 %. Even with this increase,
the licensee's ILRT test results remained within the acceptance criteria. Based on the results of
the temperature survey, the licensee determined that the current sensor locations are
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representative and that the two temperatures detectors that were reading low were accurate measurements in an area that was not well mixed. The licensee determined that it was appropriate to include those two sensors in the leak rate calculation.
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The inspector concluded that the procedure quality and overall test implementation were good.
Quality Assurance personnel involvement in the test was good. The failure of the licensee to
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perform the temperature surveys as required by ANSI N45.A1972, section 7.4, is a violation.
The safety significance of this violation is minimal since the i. perature survey performed on
October 11,1993, demonstrated that the temperature sensors were representative of containment i
conditions and the ILRT results remained acceptable. This violation will not be subject to l
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enforcement action because the licensee's efforts in correcting the violation met the criteria specified in Section VII.B of the Enforcement Policy, dated Jamiary 1,1993.
4.2 Refueling Activities The inspector observed refueling activities from the control room, Reactor Building and, Fuel
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Handling Building. The inspector fotmd that pre-evolution briefs by Nuclear Engineering were comprehensive. Overall control and communications during fuel movements was good.
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On September 28, 1993, the licensee completed ultrasonic testing (UT) of 177 cycle 9 fuel assemblies using the Babcock and Wilcox Nuclear Services ECHO 330 system. The cycle 9 core consisted of 173 Babcock and Wilcox Fuel Company (BWFC) assemblies and fo~ur Westinghouse Lead Test Assemblies. The UT results indicated that all four Westinghouse-assemblies and 10 BWFC assemblies had failed (9 Mark B4s and 1 Mark B8 fuel designs.)
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The licensee performed a visual exam of two faces on each Westinghouse assembly and found that one of the assemblies had a fuel pin with a missing upper end plug with the spring protruding out the top of the fuel pin. The licensee found the upper end plug on top of the fuel pins in the adjacent row. The licensee's visual inspection could not identify any of the other defects that were shown by the UT since they were all interior pins. The four Westinghouse fuol assemblies were not reinserted and were replaced with four BWFC once-burned fuel assemblics that are very similar in reactivity. The licensee is planning further inspections of the
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Westinghouse assemblies to assess the cause of the failures.
The licensee did not perform a visualinspection of the BWFC assemblies. The licensee suspects that grid-rod fretting is the cause of the defects in the 9 Mark B4 fuel assemblies. The Mark 114 fuel assemblies, which are from an earlier vintage, have inconel grids which tend to wear the softer zircaloy-4 fuel pins. The failed Mark B4 fuel assemblies were all located on the periphery of the core and 16 of the 17 fuel pin defects were on pins in the peripheral row. None of the Mark B4 assemblics v the failed Mark B8 assembly were planned to be reinserted and therefore no reconstitution was required.
The reactor reload began on September 30 and was completed on October 3. Just prior to plant startup, a Nuclear Engineer performed a detailed briefing to Operations personnel which focused on the changes that operators would experience due to the greater fuel enrichment. Nuclear Engineering described in detail the slightly positive moderator temperature coefficient that would be observed during the first stage of low power core physics testing.
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The inspector concluded that overall conduct of refueling activities and the licensee's evaluation of the fuel defects were good.
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4.3 Control Rod Drop Testing j
On October 14, 1993, the licensee performed control rod drop testing in accordance with i
Surveillance Procedure 1303-11.1 " Control Rod Drop Time " There were seven control rod i
groups to be tested, and each control rod group contains eight rods. One rod in each of rod groups 1,3, and 4 initially failed to meet the rod drop (flight) time of 1.66 seconds from the time the rod mechanism was deenergized to the time that the rod reached the 25% withdrawn
level. The rods that initially failed the criteria were 1-3.(group 1, rod 3),3-6, and 4-5, and the
- actual drop times were in the range of 1,72 to 1.83 seconds.
Plant Engineering became aware, through a Babcock & Wilcox representative., that one of the Oconec plants had experienced a similar problem in 1991. The Plant Review Group (PRG) met to decide a course of action based on this Oconce experience.
At Oconce, the out-of-specification rod was able to eventually pass the drop time criteria by dr'opping the rod a number of times to free the four ball check valves in the thermal barrier portion of the rod mechanism.
The licensee suspected that corrosion or corrosion products may have been preventing some or several of these ball check valves from fully opening, thereby extending the rod drop time. The; licensee decided to continue testing the remaining rod groups and then retest any rods that failed
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to meet the criteria. Then they would assess if the problem was sluggish ball check valves, as indicated by improvement in the drop time with each successive test and a smooth position versus time curve. Such curves were available from Duke Power on the Oconee experience.
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The inspector observed the retesting of the three rods in question following the PRG meeting.
The testing was conducted in a very controlled and professional manner. The chart recorder traces were compared to the similar traces for Oconee and with simultaneous traces from a rod in the same group that did meet the drop time criteria. The traces were very similar to the
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acceptable rod and showed no discontinuities that would indicate some type of binding. Each test resulted in shorter drop times on all three rods to the extent that the Gnal tests fell well
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within the acceptance criteria. The final drop times for control rods 1-3, 3-6, and 4-5 were 1.34,1.34, and 1.38 seconds, respectively.
Following this testing, the PRG met to review and assess the final test results and. concluded that
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in.: cause of the initial test failures was likely due to sluggish ball check valves. The. PRG also looked for correlations with control rod drive mechanisms (CRDMs) that had experienced high temperatures during the last operating cycle and with maintenance or modification work that had been performed on control rods, core assemblies, and CRDMs during the 10R refueling outage.
No correlations were found. The PRG also noted that the safety analyses that establish the rod drop time criteria assume that the average of the rod drop times is 1.66 seconds. Therefore,
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since the vast majority (53 out of 56) of the rods dropped well below the required time, there would significant margin to reduce reactivity during an accident even with three rods slightly higher than 1.66 seconds.
The inspector concluded the licensee's analysis and actions taken to correct this condition were appropriate. The inspector also noted extensive and very good management oversight of the activities.
5.0 PLANT SUPPORT (71707)
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5.1 Radiological Cont rols
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The inspectors examined work in progress in Unit 1 to verify proper implementation of health physics (IIP) procedures and controls. The inspectors monitored ALARA implementation,-
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dosimetry and badging, protective clothing use, radiation surveys, radiation protection instrument
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use, and handling of potentially contaminated equipment and materials.
In addition, the inspectors observed personnel working'in RWP areas and veriGed compliance with RWP re-quirements. During routine tours of the unit, the inspectors varified a sampling of high radiation q
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5.2 Security The inspectors monitored security activities for compliance with the accepted Security Plan and associated implementing procedures. The inspectors observed security staffing, operation of the Central and Secondary Alarm Stations, and licensee checks of vehicles, detection and assessment aids, and vital area access to verify proper control. On each shift, the inspectors observed pro-
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tected area access control and badging procedures. In addition, the inspectors routinely inspec-ted protected and vital area barriers, compensatory measures, and escort procedures.
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The inspectors concluded that the Security Plan was being properly implemented.
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6.0 SAFETY ASSESSMENT AND QUALITY VERIFICATION
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6.1 Independent Onsite Safety Review Group
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The inspector performed a review of the Independent Onsite Safety Review Group (IOSRG) to evaluate their overall effectiveness. Technical Speci6 cation 6.5.4 requires the licensee to
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maintain an IOSRG.
The IOSRG is a committee that functions independent of the line organizations, is composed of senior technical individuals, and reviews plant and industry data
from a technical perspective.
Based on the review of the IOSRG Monthly Reports, as well as special reports that address specific issues, the IOSRG is closely monitoring plant operations, maintenance, and engineering activities and is aware of the significant safety issues. In addition, the IOSRG reviews industry experience and refers the issues to cognizant personnel. The 10SRG does not routinely follow j
up on whether the industry experience was incorporated.
The IOSRG Monthly Reports document issues related to human performance, operations,
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engineering, and maintenance. The writeups describe what they reviewed and the specific safety concern. However, there are few independent root causes that were determined by the IOSRG and there were few specine IOSRG recommendations. The IOSRG members indicated that many times comments are made verbally because they believe they are the most effective when
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comments are given while work is being performed or during the plant's ' decision making
process, i
The IOSRG member responsible for engineering often writes special reports. The inspector reviewed several of these reports including the review of the erosion / corrosion program and the ~
procurement program. The inspector found the reports to be comprehensive and of high quality.
i The IOSRG member points out specific weaknesses and makes recommendations and gets a formal response from the responsible plant engineering manager.
The majority of his
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The Human Performance Evaluation System (HPES) Coordinator plays a key role in the IOSRG because he reviews all the HPES evaluations associated with the most significant events that
occur. Prior to 1992, the HPES Coordinator performed independent reviews of plant events,
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developed a root cause using HPES techniques, and made recommendations. Beginning in 1992, the licensee decided to have the plant perform their own HPES evaluations and include this evaluation into Plant Experience Reports (PERs). The IOSRG HPES coordinator trained 35 plant personnel in HPES, but 10SRG has noted that only one of the PERs has been written using HPES techniques. Since the PERs are a plant report rather than an IOSRG report, the IOSRG
has very limited control over the threshold for a report or the content of the report. Valid IOSRG comments to the plant's report, such as the true root cause was not identified and the
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corrective actions do not correct the root cause, were not incorporated. IOSRG believes that since HPES reports are very time consuming, the threshold for PERs has increased and the number of reports has decreased (11 in 1992, 3 in 1993). The plant has not responded to
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IOSRG suggestions that a PER be written on several lower threshold incidents.
Plant Management does not agree that the threshold for writing PERs has increased. The General
Office Review Board has an Action item to address this problem.
The inspector concluded that the IOSRG is closely monitoring plant operations, engineering, and l'
maintenance activities. Since many comments are given verbally, the IOSRG reports do not always reDect the extent of IOSRG involvement.
Although there are few specific
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recommendations in the Monthly Reports, the descriptions of various plant incidents, as well as a number ofIOSRG findings, demonstrates that they are aware of the significant safety issues.
The IOSRG special reports for engineering were of high quality and recommendations made i
were sound. The IOSRG HPES Coordinator, who reviews the most signi6 cant plant events, is only partially effective due to the limited control he has over the content or threshold for PERs
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and therefore, this reduces the effectiveness of the IOSRG.
7.0 NRC MANAGEMENT MEETINGS AND OTHER ACTIVITIES
At periodic intervals during tnis inspection, meetings were held with senior plant management
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to discuss licensee activities and areas of concern to the inspectors. At the conclusion of the
.i reporting period, the resident inspector staff conducted an exit meeting with licensec
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management summarizing inspection activities and findings for this report period. Licensee comments concerning the issues in this report were documented in the applicable report section.
No proprietary information was identified as being included in the report. The inspectors also
attended the entrance and/or exit interviews for the following inspections during the report j
period:
Date Subject Report No.
Inspector 9/20-24/93 Inservice inspection 93-16 Kaplan
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10/4-8/93 Radiological Controls 93-23 Nick
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10/18-22/93 Security 93-24 Smith
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