IR 05000334/1993004
| ML20035F736 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 04/15/1993 |
| From: | Lazarus W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20035F733 | List: |
| References | |
| 50-334-93-04, 50-334-93-4, 50-412-93-04, 50-412-93-4, NUDOCS 9304220219 | |
| Download: ML20035F736 (18) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Repon Nos.
93-04
Docket Nos.
50-334 50-412 License Nos.
DPR-66 I
NPF-73 Licensee:
Duquesne Light Company One Oxford Center
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301 Grant Street Pittsburgh, PA 15279 Facility:
Beaver Valley Power Station, Units 1 and 2 Imcation:
Shippingport, Pennsylvania i
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Inspection Period:
March 2 - April 5,1993 Inspectors:
Lawrence W. Rossbach, Senior Resident Inspector Peter P. Sena, Resident Inspector
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Approved by:
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W. JGLefarus,Mf, Reactor Projects Section 3B Date Insoection Summarv l
This inspection report documents the safety inspections conducted during day and backshift hours of station activities in the areas of: plant operations; radiological controls; surveillance ~
i and maintenance; emergency preparedness; security; engineering and technical support; and safety assessment / quality verification.
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j 9304220219 930416 PDR ADOCK 05000334 l
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EXECUTIVE SUMMARY Beaver Valley Power Station J
Report Nos. 50-334/93 04 & 50-412/93-04 Plant Operations Overall, both units were operated safely. Good command and control by operating crews was evident during the Unit I shutdown for refueling. Thorough preparations were made,
including additional relief personnel, for a major winter storm on March 13-14.
Radioloeical Controls Steam generator mockup training of health physics technicians and contractors for the Unit 1
refueling outage was planned and presented well.
l Maintenance and Surveillance
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Troubleshooting of control room and containment radiation monitors was controlled and documented well. Spiking on these monitors had previously resulted in entry into Technical Specification 3.0.3. The licensee determined that a potentially generic solid state protection system wiring discrepancy did not apply to either unit.
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Refueling surveillances completed by system engineers were properly conducted. A surveillance procedure for reactor coolant pump undervoltage relay calibrations did not alert technicians that the bistable input to solid state protection would be rendered inoperable during the calibration. Operator attentiveness to this surveillance ensured technical
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specification requirements were satisfied and the procedure was subsequently revised.
Emergency Prenaredness
An Unusual Event was declared due to the transportation of a potentially contaminated, injured man to an offsite hospital. The licensee's emergency squad effectively responded to the victim's injury.
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Security
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The licensee has maintained good ability to respond to land vehicle intrusion threats, showing
recent sensitivity to related events by reviewing procedures, holding training exercises, and visiting other sites.
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(EXECUTIVE SUMMARY CONTINUED)
l Engineering and Technical Supcon Two " pinhole" leaks were discovered in the Unit I river water system. The licensee appropriately applied Generic Letter 90-05 guidance in performing a temporary non-ASME Code repair of this piping.
The licensee performed a good technical review of a potential single failure that could result t
in inadequate core cooling after switchover to hot leg injection. The licensee also demonstrated a good safety perspective in being the first in the industry to repon this issue.
Adequate corrective actions and compensatory measures were instituted by revising emergency operating procedures.
r Safety Assessment /Ouality Verification Outage risk management has been implemented at Beaver Valley using a defense in-depth approach for the Unit I refueling outage. Shutdown safety is inherent in the development of
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the outage schedule. The Independent Safety Evaluation Group completed a pre-outage shutdown safety review to ensure the level of defense-in-depth for key shutdown safety functions is consistent with licensee policy. Licensee event reports were of high quality with good documentation of event analysis, root cause determinations, and corrective actions.
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TABLE OF CONTENTS EXECUTIVE SUMMARY ii
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1 TABLE OF CONTENTS
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1.0 MAJOR FACILITY ACTIVITIES
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2.0 PLANT OPERATIONS (71707, 93702).......................... 1 2.1 Operational Safety Verification........................... 1 2.2 Unit i Shutdown.................................... 2 2.3 Winter Storm Preparation
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3.0 RADIOLOGICAL CONTROLS (71707).......................... 3 3.1 Steam Generator Mockup Training......................... 3
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4.0 MAINTENANCE AND SURVEILLANCE (62703,61726,71707)
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4.1 Maintenance Observations.............................. 4
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4.2 Solid State Protection System Inspection
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4.3 Surveillance Observations
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5.1 Declaration of Unusual Event............................ 7 6.0 S EC U RITY (71707)...................................... 8
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6.1 Land Vehicle Intrusion Contingency Plan..................... 8 7.0 ENGINSERING AND TECHNICAL SUPPORT (37700,37828, 71707)...... 9 7.1 Unit 1 River Water System Pinhole Leak..................... 9 7.2 Unit 2 Part 21 Report of Potential for Inadequate Core Cooling.....
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8.0 SAFETY ASSESSMENT AND QUALITY VERIFICATION (40500,71707, 90712, 91700).........................................
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8.1 Shutdown Risk Management............................
8.2 Review of Written Reports.............................
9.0 ADMINISTRATIVE.....................................
9.1 Preliminary Inspection Findings Exit
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9.2 Attendance at Exit Meetings Conducted by Region-Based Inspectors...
9.3 NRC Staff Activities
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DETAILS 1.0 MAJOR FACILITY ACTIVITIES l
Unit 1 operated at 90% power from the beginning of this inspection period until March 20, l
1993, when power was reduced to 47% for an end of fuel cycle power reduction and to remove some secondary plant equipment from service for maintenance. Unit I shut down on March 26, as previously scheduled, to begin the units ninth refueling outage. Mode 5 (cold shutdown) was entered on March 28. The shutdown and outage scope are described in more detail in Section 2.2. An Unusual Event was declared on April 4 due to the transportation of a potentially contaminated injured person to a local hospital as described in Section 5.1.
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Unit 2 operated at full power throughout this inspection period without any abnormal i
l operational events. The licensee identified a single failure that could result in inadequate core cooling after switchover to hot leg injection. This is discussed in Section 7.2. The
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annual emergency preparedness exercise was held on March 17, 1993.
2.0 PLANT OPERATIONS (71707,93702)
l 2.1 Operational Safety Verification l
Using applicable drawings and check-off lists, the inspectors independently verified safety l
system operability by performing control panel and field walkdowns of the following systems: quench spray, auxiliary feedwater, emergency diesel generators, and river water.
These systems were properly aligned. The inspectors observed plant operation and verified that the plant was operated safely and in accordance with licensee procedures and regulatory requirements. Regular tours were conducted of the following plant areas:
Control Room
Auxiliary Buildings
Service Buildings
Switchgear Areas
Turbine Buildings
Access Control Points
Intake Structure
Protected Areas
Yard Areas
Containment Penetration Areas Spent Fuel Buildings
Diesel Generator Buildings
Unit 1 Containment
Safeguard Areas
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l During the course of the inspection, discussions were conducted with operators concerning knowledge of recent changes to procedures, facility configuration, and plant conditions. The inspectors verified adherence to approved procedures for ongoing activities observed. Shift turnovers wem witnessed and staffing requirements confirmed. The inspectors found that control room access was properly controlled and a professional atmosphere was maintained.
Inspectors' comments or questions resulting from these reviews were resolved by licensee personne.
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Control room instruments and plant computer indications were observed for correlation between channels and for conformance with technical specification (TS) requirements.
Operability of engineered safety features, other safety related systems, and onsite and offsite power sources were verified. The inspectors observed various alarm conditions and confirma! that operator response was in accordance with plant operating procedures.
Compliance with TS and implementation of appropriate action statements for equ:pment out of service was inspected. Logs and records were reviewed to determine if entries were
accurate and identified equipment status or deficiencies. These records included operating logs, tumover sheets, system safety tags, and the jumper and lifted lead book. The inspectors also examined the condition of various fire protection, meteorological, and seismic monitoring systems.
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Plant housekeeping controls were monitored, including control and storage of flammable
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material and other potential safety hazards. The inspectors conducted detailed walkdowns of accessible areas of both Unit I and Unit 2. Housekeeping at both units was acceptable.
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2.2 Unit 1 Shutdown On March 26,1993, Unit 1 performed a controlled shutdown and commenced its ninth refueling outage. Major activities scheduled for the 70-day outage include: complete core offload for refueling,100% eddy current inspections for each steam generator, reactor coolant pump 1B motor refurbishment, river water valve replacement, auxiliary feedpump overhaul, low pressure turbine number 1 overhaul, containment type 'A' test, recirculation spray heat exchanger replacement, steam generator feedwater thermal sleeve installation, and Unit 1/2 diesel generator cross-tie installation. The inspector observed operators conduct the shutdown per operating manual procedures 1.52.4, " Decreasing load from 40% to Turbine Shutdown," and 1.51.4A, " Station Shutdown - Minimum Load to Startup Mode or Hot Standby Mode." Good command and control by the Nuclear Shift Supervisor (NSS) and Assistant Nuclear Shift Supervisor was evident. The NSS clearly communicated his expectations of the operating crew during the pre-evolution briefing. ' Additional manpower was assigned where appropriate. For example, manual steam generator water level control was maintained with the assistance of two additional licensed reactor operators. A licensed operator simulator instructor was also stationed in the control room to monitor the step-by-step sequence of events during the shutdown. This additional monitoring was done so that procedural enhancements to the station shutdown procedures could be identified for future revisions. The inspector considered this a good initiative by operations management to fmther improve the quality of procedures beyond the current procedure upgrade program.
The inspector was informed that the station startup would be monitored by a training instructor for the same purpose.
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2.3 Winter Storm Preparation The Pittsburgh office of the national weather service issued a winter storm watch on March 12, 1993. A major winter storm with high winds, heavy snow, and cold temperatures was forecast for the weekend of March 13 and 14. Upon receipt of the warning, the licensee
initiated winter storm preparations. Equipment and materials staged for the Unit I refueling outage was secured or moved. Operations personnel toured the site and secured or removed any loose items identified. Various departments were notified of the forecast. Temporary
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sleeping quarters were set up for essential personnel. The inspector observed that the
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licensee's preparations were thorough.
The storm that occurred resulted in a record snow fall of 24 inches and 30 mph sustained
winds with gusts to 45 mph. The wind caused severe drifting. The swing shift slept in
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temporary quarters the evening of March 13 to assure that a relief shift was available on March 14; however, car pooling with four wheel drive vehicles assured adequate relief staffing. Both units operated at steady state power throughout the storm without incidents.
3.0 RADIOIDGICAL CONTROLS (71707)
Posting and control of radiation and high radiation areas were inspected. Radiation work
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I permit compliance and use of personnel monitoring devices were checked. Conditions of step-off pads, disposal of protective clothing, radiation control job coverage, area monitor operability and calibration (portable and permanent), and personnel frisking were observed on a sampling basis. Licensee personnel were observed to be properly implementing their
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radiological protection program.
3.1 Steam Generator Mockup Training The inspector observed primary steam generator mockup training by health physics personnel
and contractors. The licensee had recently purchased steam generator mockups for training l
purposes. Activities observed included health physics coverage for steam generator primary j
side worker and platform worker entry / exit, dosimetry placement / removal, anti-contamination clothing (air fed bubble suits) dress in/out, and hot particles frisks. Bechtel boilermakers performed a channel head wash and Babcock and Wilcox (B & W) technicians
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installed the robotic steam generator remote tool handling device (" COBRA"). The training j
was observed to be of good quality. Simulation was minimized as much as possible in order j
to provide a very realistic scenario. Based on observations and interviews with the trainen, j
the inspector concluded that the training should particularly benefit the junior health physics j
technicians and the boilermakers who have had limited experience in this area. The training j
benefit for the B & W personnel may not be as extensive since this contractor has their own
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steam generator mockups. The training should still provide B & W personnel with a better i
understanding of the Beaver Valley health physics rules and practices.
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4.0 MAINTENANCE AND SURVEILLANCE (62703,61726,71707)
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4.1 Maintenance Observations The inspectors reviewed selected maintenance activities to assure that: the activity did not v:olate 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; activities were accomplished by qualified personnel; radiological and fire prevention controls were adequate and implemented; QC hold points were established where required and observed; and equipment was properly tested and returned to service.
Maintenance work requests (MWRs), maintenance planning and scheduling (MPS), and preventive maintenance (PM) activities reviewed included:
MWR 012873 Adjust Setpoint on Main Steam Code Safety SV-MS-102A
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MWR 018182 Auxiliary Feed Pump (FW-P-2) Terry Turbine Governor Replacement MWR 017143 Auxiliary Feed Pump (FW-P-2) Terry Turbine Overhaul
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MWR 018365 Repair of River Water Header Pinhole Ink (see Section 7.2)
MWR 018138 &
Unit 2 Solid State Protection System Inspection (see Section 4.2)
018139 MWR 018140 &
Unit 1 Solid State Protection System Inspection (see Section 4.2)
018142 017302 Troubleshoot Containment High Range Radiation Monitor RM-219A
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M%R 017301 Troubleshoot Control Room Ventilation Radiation Monitor RM-218A The inspector observed instrumentation and control personnel perform troubleshooting activities on the train 'A' control room and containment radiation monitors (RM-218A and 219A respectively). A radiation spike had previously occurred on RM-218A when RM-219A was placed in test. This spurious radiation spike resulted in a control room emergency bottled air pressurization system actuation (see NRC inspection report 93-01).
Troubleshooting was performed with the assistance of the vendor representative. The licensee controls its troubleshooting by the maintenance work request system. Specific work instructions for the craft personnel were developed by the responsible component engineer (maintenance engineering and assessment department) and were specified within the MWR.
Generic troubleshooting guidelines are provided in the licensee's maintenance manual for the development of troubleshooting procedures. The Nuclear Shift Supervisor reviewed and
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l authorized the MWR prior to initiating the troubleshooting activities. The work instructions provided specific information regarding removing the equipment from service, installing temporary monitoring equipment, and recording the as found and as left conditions of the
equipment. Changes to the troubleshooting procedure were initiated by the component
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engineer at the scene in consultation with the vendor representative. These changes were i
formalized on the MWR and approved by the shift supervisor before proceeding. Following the completion of the troubleshooting, the radiation monitors were satisfactorily tested and retumed to their normal configuration. Ove-rall, the observed troubleshooting activities were
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properly controlled and well dccumented with good support by the component engineer.
4.2 Solid State Protection System Inspection On February 23,1993, the Braidwood and Byron Nuclear Stations (Commonwealth Edison
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Company) discovered a wiring discrepancy in their solid state protection system (SSPS). It was diccovered that the actuation logic test lead for phase 'B' containment isolation (CIB)
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actuation logic was landed on the containment spmy actuation logic (terminal TB501-5 vice
TB501-6). These test points are associated with the " semi-automatic tester" which is used to j
perform a complete check of the solid state components required for reactor trip or i
safeguards actuation. This wiring discrepancy resulted in two test monitoring points bemg wired to containment spray actuation output and none to the CIB output. Therefore, during the monthly SSPS actuation logic surveillance, the CIB logic was not tested while the containment spray logic was tested twice instead. The same problem was subsequently j
identified at the McGuire and Catawba Nuclear Power Plants (Duke Power Company) and j
may have generic applicability to Westinghouse four loop 7300 series SSPS.
j The inspector discussed this issue with the instrument and control engineering supervisor for applicability to Beaver Valley. The licensee had also just been informed of this potential wiring discrepancy via Westinghouse Energy Systems Infogram 93-03, dated March 9,1993.
Beaver Valley Unit I has a Westinghouse three loop 7100 series SSPS, while Unit 2 has a Westinghouse three loop 7300 series SSPS. Licensee personnel from the maintenance engineering and assessment (MEA) department reviewed with the inspector the Beaver Valley SSPS wiring diagrams and SSPS logic cabinet terminal block wire lists. Additionally, a field
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verification of the Unit I and Unit 2 SSPS wiring was performed (MWR 018138,018139, 018140, and 018142). The licensee verified that the proper wires were landed from terminal TB501 pin 5 to relay K505 (spray actuation) and from terminal TB501 pin 6 to relay K506 (CIB). Accordingly, the licensee confirmed that the Beaver Valley SSPS was wired
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satisfactorily. Overall, MEA personnel demonstrated a good safety perspective by promptly and thoroughly investigating a potentially generic SSPS wiring discrepancy. Also, good communication with Westinghouse Energy Services was evident.
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4.3 Surveillance Obsenations The inspectors witnessed / reviewed selected surveillance tests to determine whether properly i
approved procedures were in use, details were adequate, test instrumentation was properly
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calibrated and used, Technical Specifications were satisfied, testing was performed by qualified personnel, and test results satisfied acceptance criteria or were properly dispositioned. The following operational surveillance tests (OSTs), maintenance surveillance procedures (MSPs), and Beaver Valley Tests (BVTs) were reviewed:
OST 1.26.4 Turbine Pedestal Checks
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OST 1.1.13 Channel Check of Group Demand Counters within a Bank and Overlap Verification OST 1.24.4 Steam Turbine Driven Auxiliary Feed Pump Test OST 2.1.1 Control Rod Assembly Partial Movement Test OST 2.36.7 Offsite Power Breaker Alignment Verification BVT 1.39.8 Number 3 Station Battery Capacity Test BVT 1.21.02 Trevitest Method for Checking Main Steam Safety Valve Setpoint The inspector observed the verification of five main steam line code safety valves lift setpoint per BVT 1.21.02. This test was performed during power operations (Mode 1) with a main steam pressure of about 875 psig. The trevitest system uses mechanical and hydraulic assemblics to provide a valve opening force in addition to main steam pressure. All valves passed the technical specification acceptance criteria of +1% -3% ofits desired setpoint. All five valves were, however, less than -l% (as found) of desired setpoints and were subsequently adjusted to within +/-1%. Personnel from the maintenance engineering and assessment (MEA) department properly performed this procedure and followed all applicable precautions and limitations. For example, the lead test engineer ensured that the Nuclear Shift Supervisor was informed prior to the first lift of each safety valve and after each acceptable setpoint was obtained since each valve was rendered inoperable during each lift.
Good interface with the health physics department was also apparent as a gaseous radioactive waste discharge permit was prepared in order to quantify the offsite dose contribu+ ion associated with the.05 gallon per day primary to secondary 'B' steam generator leak.
IMSP-36.05B-E IB Reactor Coolant Pump 4KV Bus Undervoltage Relay Test Electricians were performing Unit I reactor coolant pump (RCP) IB undervoltage relay testing to determine the drop out voltage of the relay. The as-found drop out voltage was 91.2 VAC; greater than the acceptance criteria of 89.0 to 91.0 VAC. The electricians
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proceeded to remove relay 27-VB100 from its installed case per the surveillance procedure in order to calibrate the relay. At this time, the reactor operator noticed that status light 64-B1,
" Bus IB Undervoltage" unexpectedly changed status from "on" to "off." This indicated that the solid state protection system trip signal for IB RCP undervoltage was no longer being maintained while the relay was removed from its case. Technical Specification (TS) 3.3-1 specifies that the minimum number of channels operable is two, provided that the third channel is placed in a tripped condition within I hour. The electricians performing the relay calibration were not aware that removing the relay from its case would remove the IB RCP undervoltage signal. No precaution was specified in the sunreillance procedure to alert the electricians of this fact. Additionally, the procedure only references TS 3.3-1 (action 7) and did not explicitly state the 1-hour time limit associated with placing the third channel in a tripped condition.
Operators were knowledgeable of this 1-hour requirement, but not the electricians. Operator attentiveness and oversight of the surveillance ensured that TS requirements were satisfied.
The surveillance procedure was completed within 34 minutes. The inspector and the Nuclear Shift Supervisor discussed this issue with the electrical maintenance and relay supervisors
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who agreed that the surveillance procedure could be improved by alerting technicians and j
operators that the bistable for RCP undervoltage would reset if the relay is removed from its case. Additionally, a precaution and limitation was added which states that if the relay cannot be returned to service within I hour, then the electricians shall notify the shift supervisor, and the channel shall be placed in a tripped condition. The inspector was satisfied with this procedural enhancement. The inspector noted that the reactor operator
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demonstrated an excellent questioning attitude which helped to ensure technical specifications were satisfied. Good follow-up by the shift supervisor ensured that future RCP undervoltage relay calibrations would not result in a reduction of coincidence logic beyond the 1-hour TS limits. The remaining observed surveillance activities were properly conducted.
5.0 EMERGENCY PREPAREDNESS 5.1 Declaration of Unusual Event On April 4,1993, at 1:50 p.m., the licensee declared an Unusual Event due to the transportation of a potentially contaminated injured man to a local hospital. A worker inside the Unit 1 containment was struck on the head with a 12.5 pound piece of angle iron which fell about 20 feet from a jib crane. This resulted in a severe head injury accompanied by heavy bleeding. Hardhats are not worn inside containment per licensee policy. The control room was immediately notified and dispatched the emergency squad to provide assistance.
The emergency squad entered containment through the equipment hatch and were on-scene j
within 4 to 7 minutes of the event. Health physics personnel laid down a canvas pathway
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from the equipment hatch to the injury scene in order to provide a radiologically clean area so as to minimize the spread of contamination. With the assistance of the Bechtel nurse, first aid was administered to the victim. The man was removed from containment by stretcher
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and loaded into an awaiting ambulance within about 20 minutes of the injury. Due to the l
need to transport the worker to an offsite medical facility as quickly as possible and the background radiation at the injury scene, the licensee was unable to survey the individual for contamination. Accordingly, the victim was considered contaminated. The shift supervisor
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appropriately declared the Unusual Event when the ambulance departed the site for the Medical Center of Beaver County. All required notifications to state, local, and federal
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government agencies were satisfactorily completed within the prescribed time limits.
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Subsequent surveys of the victim at the hospital, as well as the emergency room and ambulance, indicated no contamination. All personnel involved in the treatment and handling
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of the victim were surveyed and determined to be free of contamination. A dose assessment
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was also completed on the Bechtel nurse who had entered containment without dosimetry in order to rapidly attend to the victim. The nurse was assessed 0 mrem for the event. The
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Unusual Event was terminated at 2:37 p.m based on hospital custody and responsibility for i
the victim and preliminary surveys which indicated no contamination. Overall, the i
emergency squad demonstrated effective response to this event. The health physics support
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was also good as the potential spread of contamination from inside containment was minimized and a radiological clean access for the emergency squad was quickly established.
6.0 SECURITY (71707)
Implementation of the physical security plan was observed in various plant areas with regard to the following: protected area and vital area barriers were well maintained and not
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compromised; isolation zones were clear; personnel and vehicles entering and packages being delivered to the protected area were properly searched and access control was in accordance
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with approved licensee procedures; persons granted access to the site were badged to indicate whether they have unescorted access or escorted authorization; security access controls to j
vital areas were maintained and persons in vital areas were authorized; security posts were adequately staffed and equipped, security personnel were alert and knowledgeable regarding position requirements, and that written procedures were available; and adequate illumination was maintained. Licensee personnel were observed to be properly implementing and
following the Physical Security Plan.
6.1 Land Vehicle Intrusion Contingency Plan The inspector confirmed that plans and contingency procedures for responding to a land vehicle intrusion event are contained in the licensee's Physical Security Plan and Contingency Event Procedures. These plans and procedures have been in place since the licensee responded to Genei.c letter 89-07 in 1989. These plans and procedures were previously reviewed by NRC and found to be adequate as reported in NRC inspection report 50-334/412-90-17/17. Since then, the licensee has included these plans in their routine training.
During the current inspection period, the incensee's staff re-reviewed these procedures and conducted successful drills involving the security force and operations department. Also, the
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i Nuclear Security Department Manager and the Vice President of Nuclear Services visited the Three Mile Island site to discuss these issues. These initiatives showed good sensitivity on l
the part of the licensee to recent offsite events. The inspector toured the site with a security l
supervisor and found the site access points and barrier inventory to be consistent with the
assumptions of the licensee's plans. Although the licensee has never physically verified the
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ability to complete installation of all barricades shown in their plans within the desired time, during Desert Storm, the licensee erected access restrictions similar to those in their contingency plans in less than the desired time. The licensee evaluated their barricade plans
and concluded that their entire plan could be in place within the desired time. The inspector
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concluded that the licensee currently has the ability to respond to land vehicle intrusion threats as described in their security plans.
7.0 ENGINEERING AM) TECIINICAL SUPPORT (37700,37828,71707)
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7.1 Unit 1 River Water System Pinhole Leak On March 22,1993, a Unit 1 primary auxiliary building operator discovered two pinhole leaks on an 18-inch carbon steel river water (RW) header downstream of RW-190. This
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header is located on the outlet of the reactor plant component cooling water heat exchangers.
The pinholes are located just below a welded patch plate that was installed in 1986. A potential violation was previously identified by an NRC inspector (see inspection report i
93-02) for performing a non-ASME code repair of this header with the installation of three welded patch plates. As a result of this potential finding, the licensee committed to
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performing a visual inspection of these areas every shift. The identified pinholes are about 3/32 and 1/32 of an inch across. No outleakage of water was apparent as the piping at this
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L location is under vacuum.
The licensee has completed a basis for continued operability and concluded that the river water system is operable and that the structural integrity of the piping is satisfactory. The
i ultrasonic (UT) examination results of the river water piping downstream of RW-188,189, and 190, taken in February 1993, were reviewed by the inspector. The minimum wall
thickness for this piping is specified as.051 inches. The minimum readings found on these three sections of piping were.304,.244, and.204 inches. The inspector discussed the UT
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examination results with NRC Region I specialist inspectors and agreed with the licensee's conclusion that the structural integrity of the piping was satisfactory. A second set of UT examinations was also completed after discovery of the pinhole leaks. These results were similar to the February inspection results. The licensee believes that the most likely cause of these leaks is corrosion / cavitation.
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The licensee has applied NRC Generic Ixtter (GL) 90-05, " Guidance for Performing
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Temporary Non-Code Repair of ASME Code Class 1,2, and 3 Piping," to this issue.
Temporary non-code repairs are not permitted on ASME Code piping without prior relief I
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from the NRC, and the flawed area must be code repaired no later than the next refueling outage. The NRC may grant relief for temporary non-code repair of code Class 3 piping i
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where impracticality exists in performing an ASME Code repair while the facility is operating. The licensee's "through wall flaw" evaluation, per GL 90-05, determined that the flaws satisfied the acceptance criteria (critical stress intensity factor) and a non-code repair was proposed. This non-code repair involved installing an external red rubber patch (MWR 018365) to protect nearby 480V motor control centers from possible water spray.
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Verbal permission to perform the non-code repair was granted by Mr. W. Butler, Director of Project Directorate I-3, Office of Nuclear Reactor Regulation. This river water header has already been scheduled for replacement during the current refueling outage. Augmented UT examinations of five additional suspectable locations have also been completed as pan of the relief acceptance criteria. Overall, the guidance of GL 90-05 was properly followed by the licensee.
7.2 Unit 2 Pad 21 Repod of Potential for Inadequate Core Cooling By letters dated January 8,1993 to NRC and January 13,1993 to the licensee, Westinghouse provided a Part 21 report of a single failure of a valve in the low head safety injection system which could result in inadequate core cooling. The valve, 2 SIS-MOV-8889, is a normally closed valve on the only line providing low head safety injection flow to the hot legs of the reactor coolant system. Approximately fourteen hours after a large break LOCA,
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the safety injection system is transferred from the cold leg recirculation mode to the hot leg recirculation mode. Recent analysis by Westinghouse has determined that adequate core
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cooling cannot be assured if this valve fails to open. Unit I has two lines from the low head safety injection system to the hot legs and so it is not susceptible to this single failure.
Westinghouse reponed that this issue is applicable to several plants; however, plant specific Emergency Operating Procedures (EOPs) may advise the operator to take adequate actions to mitigate this event.
On March 4,1993, the licensee determined and reported to NRC that this issue applied to
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Unit 2 and that EOPs did not direct operators to mitigate it. Duquesne Light Company was the first licensee to report this issue and an events briefing was held by NRC headquarters on l
March 10 to discuss this issue. The licensee took immediate actions to administratively
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prevent the scenario by preventing switchover to low head hot leg recirculation by tagging shut valves 2 SIS-MOV-8887A & B upstream of valve 2 SIS-MOV-8889. The licensee took long-term corrective actions by revising their EOPs to direct the operators to immediately re-esudish low head cold leg injection if hot leg injection cannot be established. The control
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tags wei-subsequently removed from the control switches for the 8887A & B valves. The inspector concluded that the licensee performed a good technical review of the Westinghouse notification and demonstrated an excellent safety perspective in being the first licensee to report this issue. The inspector also concluded that these corrective actions were adequate.
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8.0 SAFETY ASSESSMENT AND QUALITY VERIFICATION (40500,71707, 90712, )1700)
8.1 Shutdown Risk Management j
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The Duquesne Light Company shutdown risk management plan for Beaver Valley Unit 1 incorporates the guidelines and recommendations of NUMARC 91-06, " Guidance for Industry Actions to Assess Shutdown Management." The shutdo vn management plan for the
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l ninth refueling outage will apply defense-in-depth principles to ensure that key safety
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functions and contingencies are available throughout the outage. The licensee has l
implemented a new procedure, Nuclear Group Administrative Manual 8.26, " Shutdown
Safety / Outage Management," which addresses the concepts of NUMARC 91-06. The l
l shutdown safety concepts were previously informally implemented during the Unit 2 third i
refueling outage in May 1992.
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The outage plan will implement this defense-in-depth philosophy by providing a minimum of
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"N+1 levels of redundancy for the key safety functions of decay heat removal capability, reactor coolant system inventory control, and power availability. "N" is defined as the t
components needed to remain operable for each of the key safety functions in order to satisfy the technical specifications for a particular mode.
"N+1" indicates the amount of components available for one level of redundancy above the technical specification minimum.
i The plan to minimize shutdown risk is based on following the refueling outage schedule as
written. The outage schedule has been planned and reviewed with the intent of optimizing
the availability of key safety function equipment. The Independent Safety Evaluation Group (ISEG), Unit 1 Operations Department, and the Outage Management Department have i
reviewed the outage schedule and compliance with NUMARC 9106 guidelines to ensure the i
I adecuacy of defense in depth by examination of system interactions, suppon system availability, and the impact of temporarily installed equipment.
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A minimum availability of "N+1" for all key safety functions is scheduled to be maintained throughout the outage. Any schedule change which reduces key safety function availability to the "N" level requires the approval of the General Manager Nuclear Operations, as well as the Outage Manager's and Operations Manager's approval. The department outage coordinators and outage overview personnel are kept appraised of the level of shutdown l
safety via a safety function / equipment status report. This report is updated every shift and
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reviewed by all personnel at the outage coordinator meetings (held three times a day) and the daily manager meeting. The level of defense-in-depth for all key shutdown safety functions, as well as reactivity control, spent fuel pool cooling, and containment status, is maintained
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on this report. The ISEG also performs an independent review of shutdowm safety status twice per day. This additional review by the ISEG is an initiative beyond the scope of the licensee's administrative procedure. The licensee is considering whether to formally incorporate this initiative into the shutdown safety program. Overall, the shutdown safety philosophy adopted by the licensee is intended to enhance safety of the unit throughout the outage.
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The licensee has also identified one " higher risk evolution" to be performed during the outage. These evolutions arc outage activities, plant configurations or conditions during
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shutdown where the plant is more susceptible to an event causing a loss of a key safety function. This activity involves the removal from service of the reactor plant component cooling water system and one train of the river water system due to maintenance. A temporary modification will be used to maintain the temperature in the spent fuel pool with the entire core off-loaded. The maintenance activities associated with these systems and the implementation of the teinporary modification will be monitored by the inspectors during the outage.
8.2 Review of Written Repods The inspectors reviewed Licensee Event Reports (LERs) and other repons submitted to the NRC to verify that the details of the events were clearly reported, including accuracy of the description of cause and adequacy ol' corrective action. The inspectors determined whether
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furtl'er information was required from the licensee, whether generic implications were indicated, and whether the event warranted further onsite followup. The following LERs were reviewed:
MalLl:
93-01 Condition Outside Design Basis - Main Steam Isolation Valve Closure not Considered in Original Design 93-02 Engineered Safety Features Actuation - Inadvertent Tripping and Automstic Start of Reactor Plant River Water Pumps 93-03 Control Room Habitability Air Bottle Subsystem Manually Isolated
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These events were previously reviewed in NRC inspection report 93-01/01. The main steam j
line desigr. issues in LER 93-01 were also inspected as described in inspection report 93-06/06.
Unit 2:
93-02 Rcactor Trip and Safety Injection Due to Comparator Card Failure in a Main Steam Pressure Channel
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This event was reviewed in NRC inspection report 93-01/01. A revised LER was subsequently issued after the inspector informed the licensee that information regarding the number of emergency core cooling system actuations experienced to date, as required by Technical Specification 6.9.2, was omitted.
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The above LERs were reviewed with respect to the requirements of 10 CFR 50.73 and the
guidance provided in NUREG 1022. Generally, the LERs were found to be of high quality
with good documentation of event analyses, root cause determinations, and corrective l
actions.
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9.0 ADMINISTRATIVE
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9.1 Preliminary Inspection Findings Exit l
At periodic intervals during this inspection, meetings were held with senior plant
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management to discuss licensee activities and inspector areas of concern. Following (
conclusion of the report period, the resident inspector staff conducted an exit meeting on l
April 7,1993, with Beaver Valley management summarizing inspection activity and findings
for this period.
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9.2 Attendance at Exit Meetings Conducted by Region-Based Inspectors
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During this inspection period, the inspectors attended the following exit meetings:
Inspection Reporting Dates Eubiect Reoort No.
Insoector 3/18/93 Annur.1 Emergency Preparedness Exercise 93-03/03 J. Laughlin
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4/02/93 Troubleshooting and Maintenance Quality 93-05/05 F. Bower Assurance 9.3 NRC SiaiT Activities Inspections were conducted on both normal and backshift hours: 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br /> of direct inspection were conducted on backshift; 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> were condacted on deep backshift. The times of backshift hours were adjusted weeldy to assure randomness.
i R. Barkanic, Nuclear Fngineer, Pennsylvania Department cf Environmental Resources j
(DER) visited the site and inspectors on March 3,17,18, 30, and 31 and discussed
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inspection activities and the licensee!s performance. On March 31, Mr. Barkanic accompanied the inspector on an inspec6on e ' &. i 1 cor.tainment building and other
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Messrs. J. Calvo, Assistant Director, Region I Reactors, NRR, M. Johnson, Chief, f
Inspection and Licensing Policy Branch (ILPB), NRR, and M. Shannon. ILPB, NRR, visited the site and the inspectors on March 10 to review the inspection program and meet with j
licensee management.
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On March 16 and 17.-Mr. T. Reeves, Ohio Emergency Management Agency, visited the site
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and the inspectors and observed the inspection of the annual emergency preparedness exercise.
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