IR 05000334/1993013
| ML20046C272 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 07/30/1993 |
| From: | Lazarus W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20046C266 | List: |
| References | |
| 50-334-93-13, 50-412-93-14, NUDOCS 9308100071 | |
| Download: ML20046C272 (20) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
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Report Nos.
93-13 93-14 Docket Nos.
50-334 50-412
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License Nos.
DPR-66 NPF-73 Licensee:
Duquesne Light Company One Oxford Center 301 Grant Street Pittsburgh, PA 15279
Facility:
Beaver Valley Power Station, Units 1 and 2 Location:
Shippingport, Pennsylvania i
Inspection Period:
June 15 - July 20,1993 Inspectors:
I2wrence W. Rossbach, Senior Resident Inspector Peter P. Sena, Resident Inspector
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Scot A. Greenlee, Resident Inspector Approved by:
A 7393 WTJ. Lazarus, Chief, Reactor Projects Section 3B bath
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t inspection Summarv i
This inspection report documents the safety inspections conducted during day and backshift
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hours of stajon activities in the areas of: plant operadons; maintenance and surveillance -
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engineering; plant support; and safety assessment / quality verification.
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9308100071 930730 PDR ADOCK 05000334-G PDR
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b EXECUTIVE SUMMARY Beaver Valley Power Station Report Nos. 50-334/93-13 & 50-412/93-14 Plant Operations An automatic letdown isolation occurred due to low pressurizer level during the Unit I startup. All systems responded as designed; however, this engineered safety feature (ESP)
actuation could have been avoided by greater operator attentiveness to changing plant conditions.
Plant personnel demonstrated a strong safety perspective in the identification and evaluation
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of a primary grade water header leak in the Unit 2 containment.
The licensee identified instances of a non-licensed operator not properly performing one series of checks during his rounds. This issue was left unresolved pending further NRC assessment.
The licensee showed good safety perspective in their response to the Salem rod control issue and subsequent actions to assure safe operation of both units.
Maintenance An example of poor procurement support of maintenance was found involving a stock change of nuclear instrument fuses which was never implemented. This resulted in the application
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of incorrect control power fuses to a power range drawer. The fuses do, however, fail
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conservatively upon drawer energization.
Several planned maintenance and surveillance items on the Unit 2 supplementary leak
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collection and release system were not planned to minimize outage time. Duquesne Light Company is reviewing the maintenance work coordination for possible improvements.
The inspectors identified a deficiency associated with a clearance on the Unit 2 supplementary leak collection and release system. The deficiency did not present any l
immediate safety problems. Duquesne Light Company is evaluating the occurrence via their
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problem report system.
Engineering Engineering's evaluation of a Westinghouse safety advisory letter was found to be thorough.
This issue involved a non-conservatism in the development of the low temperature overpressure protection setpoint analysis.
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(EXECUTIVE SUMMARY CONTINUED)
The licensee took proper action to ensure that emergency core cooling system containment suction strainers would not be clogged by fibrous materials in the event of a loss of coolant accident (LOCA).
Licensee event reports reviewed were of high quality. The completion of long-term corrective actions was confirmed through the review of several older event reports.
Plant Support A technical specification surveillance of safety injection accumulator boron samples was
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missed. The licensee's existing surveillance controls for chemistry samples were not
effective in ensuring all required samples were taken prior to plant mode changes. This self-identified violation is not being cited because ofits minor safety significance and the licensees prompt corrective actions.
High concentrations of suspended particulates were detected in the Unit 2 diesel fuel oil-storage tanks and received close management attention. Cycling the fuel oil through a
filtration unit was effective in reducing the particulate concentrations. This issue was left l
unresolved pending the determination of the source of contamination, subsequent corrective actions, and evaluation of the sampling technique.
The licensee's emergency squad effectively responded to a heat stress victim inside
containment.
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Several transient material control deficiencies were identified by the inspectors. Duquesne Light Company promptly corrected each deficiency.
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TABLE OF CONTENTS Page EXECUTIVE SUMMARY ii
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TABLE OF CONTENTS
.......................................iv 1.0 MAJOR FACILITY ACTIVITIES I
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2.0 PLANT OPERATIONS (71707)............................... 1 2.1 Operational Safety Verification........................... 1 2.2 Unit 1 Letdown Isolation............................... 2 2.3 Unit 2 Supplemental Leak Collection and Release System (SLCRS)
Fl ow Bal an ce...................................... 3 2.4 Abnormal Unit 2 Containment Sump Pump-Out Rate
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2.5 Response to Salem Rod Control System Failure................. 3 2.6 Plant Records Verification Follow-up....................... 4 i
3.0 MAINTENANCE (62703, 61726, 71707, 93001).................... 4 3.1 Maintenance Observations.............................. 4 3.2 Motor Actuator De-Clutch Lever.......................... 6 3.3 Unit 2 Supplemental I2ak Collection and Release System (SLCRS)
Maintenance / Surveillance
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3.4 Surveillance Observations.............................. 7 L
4.0 ENGINEERING (71707, 90700, 90712, 92700)..................... 8 4.1 Review of Written Reports.............................. 8 4.2 Low Temperature Overpressure Protection Non-conservatism
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4.3 Prevention of Debris Plugging of Emergency Core Cooling System S train ers........................................
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5.0 PLANT SUPPORT (71707, 90712, 93001).......................
5.1 Radiological Controls................................
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5.2 S ecu ri ty........................................
5.3 Housekeeping........
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5.4 Ch e mi stry.......................................
5.4.1 Missed Unit 1 Accumulator Sample..................
5.4.2 Unit 2 Emergency Diesel Fuel Oil Particulates...........
5.5 Emergency Squad Response............................
6.0 ADMINISTRATIVE.....................................
i 6.1 Preliminary Inspection Findings Exit
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6.2 NRC Staff Activities
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DETAILS 1.0 MAJOR FACILITY ACTIVITIES Unit I entered Mode 2 (Startup) on June 15. The reactor was brought critical on June 16.
The refueling outage ended on June 18 when the main generator output breakers were closed.
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The unit reached full power on June 28 and operated at full power through the end of this inspection period.
Unit 2 operated at full power throughout this inspection period except for a power reduction to about 46 percent power from July 3 to July 7 to maintain the scheduled length of the fuel cycle and several reductions to between 92 percent and 95 percent power due to the influence of hot weather on plant efficiency.
2.0 PLANT OPERATIONS (71707)
P 2.1 Operational Safety Verification Using applicable drawings and check-off lists, the inspectors independently verified safety system operability by performing control panel and field walkdowns of the following systems: recirculation spray, supplemental leak collection and release,125 Vdc vital power, high-head safety inject'on and main feedwater. These systems were properly aligned except as noted in Section 3.1 of this report. 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 o
Spent Fuel Buildings
Safeguard Areas Auxiliary Buildings
Switchgear Areas
Service Buildings
Access Control Points
Turbine Buildings
Protected Areas
Intake Structure Diesel Generator Buildings
Yard Areas
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 were witnessed and staffing requirements confirmed. The inspectors found that l
control room access was properly controlled and a professional atmosphere was maintained.
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 confirmed that operator response was in accordance with plant operating procedures.
Compliance with TS and implementation of appropriate action statements for equipment out
of service was inspected. Imgs and records were reviewed to determine if entries were
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accurate and identified equipment status or deficiencies. These records included operating logs, turnover 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.
2.2 Unit 1 Letdown Isolation On June 19,1993, an automatic letdown isolation of the chemical and volume control system occurred due to low pressurizer level. At the time of this event, reactor power was at 9 percent and operators were preparing to synchronize the main unit generator to the distribution grid. The letdown isolation valves are engineered safety features (ESP)
components and a licensee event report is being prepared.
Prior to this event, the licensee stationed an additional reactor operator at the main control -
board for steam generator water level control. The bypass feedwater regulating valves were in manual control. However, the actuation of the main condenser steam dumps was affecting the operator's ability to maintain stable steam generator water level. The steam dumps were actuating as designed in the steam pressure mode at 1,005 psig (equivalent to a no-load average reactor coolant system temperature (Tave) of 547*F). Accordingly, the operator placed the steam dumps in manual control with two dump valves open (PCV-MS-106A and B). This was not sufficient to remove the primary heat load and the Tave began to increase.
The shift supervisor later informed the inspectors that a mismatch between Tave and reference average temperature (Tref) was desired so that the effect of main unit generator synchronization (i.e., increased steam demand) on the primary system was minimized.
However, Tave increased to about 559 F (12*F Tave/ Tref deviation) and thus increased steam generator pressure to 1,060 psig. At this point, two steam generator atmospheric dump valves (PCV-MS-101 B and C) opened to provide a heat sink. This increased steam flow rapidly reduced Tave. The operators noticed the Tave decrease, but were unaware that it was due to the opening of the atmospheric steam dumps. The decrease in Tave was further magnified by the subsequent main unit generator synchronization. Unit generator output increased to 50 MW upon output breaker closure. Thus the increased steam demand from the atmospheric steam dumps and unit generator decreased Tave to about 540 F. This cooldown caused pressurizer level to shrink to 14 percent and initiate the letdown isolation.
Following the ESF actuation, the operators immediately recovered Tave to greater than 541*F per technical specifications and restored letdown within 3 minutes. The plant was stabilized at about 8 percent power.
Although this event was of minor safety significance and the plant responded as designed, the licensee conducted training because the event could have been avoided by greater operator attentiveness to the changing plant conditions. Additionally, the manual control of both steam generator water level and steam dumps further increased the burden on the operators while attempting to maintain reactor power and synchronize the main unit generato :
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2.3 Unit 2 Supplemental Leak Collection and Release System (SLCRS) Flow Balance During a walkdown of the Unit 2 SLCRS, the inspectort noted that some of the air flow
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rates indicated on the valve operating number diagram did not match actual system flow rates. The inspectors presented this observation to the SLCRS system engineer. The system engineer found that the flow rates in the SLCRS had been elanged in 1988; however, the valve operating number diagram had not been updated to reflect the change. The system engineer stated that he would generate the required paperwork to have the drawing updated.
The Unit 2 Final Safety Analysis Report (FSAR) correctly reflected the post-1988 system flow rates.
2.4 Abnormal Unit 2 Contaimnent Sump Pump-Out Rate
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On June 7 and 11,1993, plant operators noted an increase in the containment sump pump-
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out rate. Chemistry samples showed that the sump water was not reactor coolant.
Additionally, containment airborne radiation levels and containment leak rate calculations were normal.
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On June 12, plant operators again noted the increased pump-out rate, but this time they correlated the occurrence with pressurization of the containment primary grade water header.
The primary grade water header is periodically pressurized to allow make-up to the reactor coolant pump seal vent pots.
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On June 15, a containment entry was made. A body-to-bonnet leak was found on the containment isolation check valve for the primary grade water header (2RCS-72). The valve was declared inoperable, and the penetration was isolated as required by technical specifications. An operability evaluation was subsequently performed. It was determined that the valve leakage did not effect the valve's ability to act as a containment isolation.
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Consequently, the containment primary grade water header was returned to normal service.
The valve will be repaired during the September 1993 refueling outage.
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The inspectors followed Duquesne Light Company's actions to identify and resolve the cause of the intermittent increase in containment sump pump-out rate. The inspectors noted that I
the plant operators paid close attention to plant parameters and were determined in l
identifying the leakage source. Additionally, Duquesne Light Company showed-conservatism and good safety perspective in the verification and evaluation of the leakage
source.
2.5 Response to Salem Rod Control System Failure
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Operators at the Salem Nuclear Generating Station, Unit 2, experienced problems with the
rod control system on May 27,1993. In response to this event the NRC issued Information
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Notice 93-46 on June 10 and Generic Letter 93-04 on June 21. Duquesne Light Company j
became actively involved in this issue by sending staff to assist the Westinghouse owners
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group. This involvement, in turn, helped Duquesne Light Company develop an understanding of this event and its safety significance prior to the Unit 1 startup. The Unit I startup received the additional evaluation, oversight, and staff briefings that station administrative procedures require for an infrequently performed test or evolution. The Salem rod control issue was discussed with the operators at these briefings and the Westinghouse technical bulletin was read by the operators. The inspectors observed that the operators were very attentive to rod motion and direction throughout startup and power escalation. The Unit 2 operators were also informed of this issue and were attentive to rod motion and direction.
The inspectors concluded that the licensee actively pursued this issue with a good safety
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perspective and that the additional operations controls taken were appropriate. At the end of this inspection period the licensee was preparing a response to the Generic Letter.
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2.6 Plant Records Verification Follow-up Duquesne Light Company's actions in response to NRC Information Notice 92-30,
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" Falsification of Plant Records," were inspected in September 1992 as reported in NRC inspection report 92-18/18. In November,1992, the licensee's Quality Services Unit completed an additional assessment of operator tours which identified one non-licensed operator who, on two occasions, did not properly perform his rounds. Specifically, Unit 2
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Operations Manual Log L-4, Turbine Building Log, requires that battery rooms 2-1,2-2,2-
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3, and 2-4 be checked each shift for fire and air flow. This is a procedural requirement of the licensee, not a technical specification required surveillance. The operator logged these checks as completed, although on two occasions access records show that the operator did
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not enter the battery rooms. The operator told the licensee that he thought it was proper to do the check from the switch gear room side of the battery room doors and access records show that the operator entered the switchgear room as part of his rounds. Disciplinary action was taken against the individual and all operators received instruction:: clarifying how to conduct operator tours. This issue is unresolved pending further NRC assessment.
(Unresolved item 93-412/93-14-01)
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3.0 MAINTENANCE (62703, 61726, 71707, 93001)
3.1 Maintenance Observations The inspectors reviewed and observed 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; activities were accomplished by qualified personnel; radiological and fire prevention controls were adequate and implemented; quality control hold points were established where required and observed; and equipment was properly tested and returned to service.
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Maintenance work requests (MWRs) reviewed included:
PMP-75-4KV Unit 2 Service Water Pump Motor Preventive Maintenance MWR 21338 Investigate Cause of Loop 3 Hot Leg Temperature Detector Change MWR 18195 Ventilation Exhaust Monitor (RM-IVS-109) Calibration MWR 21250 Terry Turbine Steam Supply Trip Valve (TV-MS-105B) Air Leak Repair MWR 21384 Emergency Diesel Generator 2-2 Governor Performance Monitoring MWR 21308 Power Range Channel N-43 Fuse Failure On June 25,1993, during the calibration of Unit 1 power range neutron flux channel N-43, the as-installed 5 ampere control power fuses blew due to normal end-of-life conditions. The reactor protection system bi-stables were already in a tripped condition due to in progress surveillance testing. However, a second set of fuses also blew after installation and drawer re-energization. The inspectors reviewed this event after questioning if these fuses were identical to those which failed during a Unit 2 nuclear instrument (N-44) calibration on July 16,1992 (see NRC inspection report 50-412/92-18).
During troubleshooting of N-44 in July 1992, the licensee identified that incorrect fuses were being used in the power range nuclear instrument drawers. Specifically, the fuse vendor (Bussman) had changed the internals of the MTH-5 fuse without changing the part number.
Therefore, fuses ordered by the licensee per the original part number resulted in the receipt and use of these redesigned fuses. The change in the fuse internals affected the fuse inrush
. capacity, not the 5 ampere rating. When these redesigned MTH-5 fuses were installed in the power range drawer, the current inrush from the drawer upon energization caused the fuses
to blow. Westinghouse had been aware of this change, but had not informed the licensee.
The current spike upon drawer energization is expected and was determined to be about 25 amperes for about 5 milliseconds. As corrective action in July 1992, technical evaluation
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report (TER 6981) evaluated the use of new 5 ampere fuses with sufficient inrush current capacity (25 amperes with a 80 millisecond time delay). Per Westinghouse recommendation, Bussman fuse F02A-250V-5A (Military Specification Mil-F-15160/02) was determined to be acceptable. All power range drawers were changed out with these fuses.
j During the recent event involving N-43, the inspectors were informed that the incorrect fuse design (Bussman MTH-5) had not been removed from stock. Additionally, the master equipment list (MEL) was also not updated with the correct military specification part number. The TER specifically required engineering to send a completed spare parts list or memo to the procurement group identifying the parts change, since stock items were affected by the TER. However, the communications between engineering and procurement personnel
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were only verbal, and no action was initiated by procurement to change the stock of MTH-5 fuses. Thus, the instrument and controls technician obtained the wrong style fuse from the warehouse after obtaining the old part number from the MEL which was not updated. The original fuse which blew on June 25 was of the correct fuse design. After determining that the incorrect fuses had been reinstalled, the correct fuses were obtained and N-43 was returned to service within the allowed outage time.
The safety significance of using the wrong fuses is minor since the MTH-5 fuses fail conservatively. Additionally, the fuses only fail upon drawer re-energization during which time the reactor protection bi-stables are already tripped. However, the procurement department support of maintenance activities in this instance was poor. The procurement department failed to act after being informed of the needed parts change. This event may
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also have been avoided if engineering personnel had properly documented the desired parts change to the procurement department. The licensee's current practice is to forward all TERs to the procurement department for review of parts changes vice generating additional memos. The inspectors considered this change to be acceptable.
3.2 Motor Actuator De-clutch Lever During the inspector's walkdown of the Unit 1 main feedwater system, several Limitorque motor actuators were identified as having the de-clutch shaft lever incorrectly installed.
These include the main feedwater pump discharge isolation valves (MOV-FW-150 A and B)
and bypass feed regulating valve isolation valve (MOV-FW-155A) at Unit I and feed regulating valve isolation valve (MOV-FW-154A) at Unit 2. The failure to preload the de-clutch shaft during reassembly (for SMB 0 through 4 actuators) does not functionally affect the operation of the actuator in either the manual or automatic mode. However, if the de-clutch lever is not depressed during spring cartridge cap installation, then the de-clutch level drum roll pin will be on the wrong side of the spring cartridge cap roll pin. The first time the unit is placed in manual, the roll pin will be damaged. The inspectors were informed that maintenance was not performed on these valves during the recent outages. The licensee indicated that the identified deficiencies will be corrected during the next scheduled maintenance period for these actuators. The inspectors considered this to be acceptable.
3.3 Unit 2 Supplemental Leak Collection and Release System (SLCRS)
Maintenance / Surveillance On June 28,1993, Duquesne Light Company placed train 'B' of the Unit 2 SLCRS out of service to accomplish the following maintenance / surveillance items:
2BVT 1.16.7 SLCRS Train 'B' Filter Efficiency Test i
2BVT 1.16.8 Main Filter Bank Charcoal Test Sample Removal MWR 020971 Top Off 2HVS-FLTA208B with Charcoal
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BVT 1.33.1 SLCRS Filter and Auxiliary Feedwater Pump Sprinkler Air Flow Test 2PMP-75-HTR-9E Electric Air Handling Heater Maintenance 2PMP-75-CENT-FAN-1E Centrifugal Fan Maintenance The inspectors reviewed and observed selected parts of the procedures associated with the above maintenance / surveillance items. Additionally, the adequacy of associated clearances was also checked. The inspectors had the following observations:
One of the clearance points for clearance No. 152344 appeared to be inadequate. The
vortex damper for the SLCRS train 'B' filtered exhaust fan was tagged in the shut position in the control room; however, the damper's power supply was subsequently tagged in the off position, causing the damper to fail open.
The maintenance / surveillance procedures were not planned to minimize the time spent
in a technical specification action statement. Portions of three eight-hour shifts were used to perform these activities. The total outage time was three days of an allowed seven-day limiting condition for operations.
The inspectors observation concerning the fan vortex damper clearance point was immediately brought to the Shift Foreman's attention. It was determined that the position of the damper presented no immediate plant or personnel safety problems. A problem report was generated to review the cause of the deficiency and determine corrective actions.
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The inspector's observation concerning the lack of planning to reduct, outage time was discussed with the Unit 2 Operations Manager. The Operations Manager initiated a review of the work coordination to determine where improvements could be made.
3.4 Surveillance Observations
The inspectors witnessed / reviewed selected surveillance tests to determine whether properly approved procedures were in use, details were adequate, test instrumentation was properly calibrated and used, technical specifications were satisfied, testing was performed by qualified personnel, and test results satisfied acceptance criteria or were properly dispositioned. The operational surveillance tests (OSTs), Beaver Valley Tests (BVTs), and maintenance surveillance procedures (MSPs) listed below were reviewed. The observed surveillance activities were properly conducted without any notable deficiencies unless otherwise indicated.
BVT 1.36.1 Emergency Diesel Generator Loading Evaluation BVT 1.06.01 Reactor Coolant System Total Flow Measurement
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BVT 2.2.1 Post Refuel Physics Testing i
BVT 8.3.1 Incore Movable Detector Flux Mapping The inspectors observed the incore flux mapping performed at 100 percent power and reviewed the results of the flux maps previously obtained at 70 percent and 85 percent power. The licensee had identified that the measured radial heat flux hot channel factor (with nuclear uncertainty factors applied), Fxy(C), exceeded Fxy(RTP-rated thermal power)
as defined in the core operating limits report. Fxy(RTP) was exceeded for the upper axial zone only. The allowable limit, Fxy(LIM), is calculated using a technical specification formula. Although Fxy(RTP) was exceeded, Fxy(LIM) was not. Thus technical specifications required that a flux map be obtained every 31 days. Based on the flux map data, the inspector calculated both Fxy(LIM) and FQ(Z) for various core planes and verified these limits had not been exceeded. Sufficient margin to the FQ(Z) limits was available.
For the 100 percent power flux map, Fxy(C) was found to be within Fxy(RTP). Overall, the reactor engineers were properly performing the flux maps and correctly implementing the technical specifications based on measured and calculated results.
OST 2.24.4 Turbine Driven Auxiliary Feed Pump Test OST 1.26.1 Turbine Throttle, Governor, Reheat and Intercept Test Per Westinghouse recommendation, the licensee cycles the main turbine throttle and governor valves on a monthly frequency. This was the first performance of this test following the
completion of the refueling outage at Unit 1. When operators transferred turbine control from partial arc admission to full arc admission, 30 MW (electric) load swings were experienced. This in turn affected steam generator steam and feed flows and reactor coolant
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Tave. Operators aborted the surveillance test and placed turbine control in manual to stop the load swings. The transfer back to partial arc admission was completed without incident.
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The inspectors concluded that operators took appropriate action, in consultation with the proper operations engineer and management supervision, to minimize and eliminate the effects of the oscillations. A maintenance work request has since been initiated to investigate
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the observed electro-hydraulic control system anomalies while in full arc admission.
4.0 ENGINEERING (71707, 90700, 90712, 92700)
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4.1 Review of Written Reports The inspectors reviewed Licensee Event Reports (LERs) and other reports submitted to the NRC to verify that the details of the events were clearly reported, including accuracy of the description of cause and adequacy of corrective action. The inspectors determined whether y
further information was required from the licensee, whether generic implications were indicated, and whether the event warranted further onsite follow-up. The following LERs were reviewed:
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93-07 Condition Outside Design Basis - Original Piping Did Not Conform To Design Code During the scheduled replacement of the 30 inch river water header (component cooling water heat exchanger outlet), the licensee discovered that the 0.5 inch thick end plates did not have adequate thickness. ANSI B31.1 required the en. plates to be 1.26 inch thick.
Followup inspection of similar piping headers identified two additional headers with end plates that did not meet the code requirements. No end plate leakage was previously identified on the affected headers since original installation in 1976. Additionally, these end plates had previously passed the required inservice inspections. The affected headers have since been fitted with the proper end plates and have since passed pressure testing.
The inspectors concluded that the corrective actions were adequate and have no additional comments on this event.
93-08 Check Valves Not Included In ASME Testing Program The licensee identified that the river water check valves in the chlorine injection lines were not included in the ASME section IX testing program when the program was developed.
There are two check valves in each header and are designed to limit river water back-leakage in the event of a chlorine injection piping break. The as found leakage was 18 gpm for train A check valves and was negligible for train B check valves. The licensee determined that this leakage did not affect river water system operability. The check valves have subsequently been added to the ASME testing program and the leakage has been corrected.
The inspectors concluded that the corrective actions were adequate and have no additional comments on this event.
93-09 Unlocked High Radiation Area Barrier This event was reviewed in NRC inspection report 93-12/13. The licensee's corrective actions will be reviewed as part of the response to violation 93-09-01.
Unit 2:
92-08 Quench Spray Pump Breaker Failed to Close This LER was previously reviewed as reported in NRC inspection report 92-28/27. The inspectors revisited the item and verified that long-term corrective actions involving a sample inspection of other 4KV breakers, and the revision of maintenance procedure 1/2 PMP-36 NNS-SS-BKR-lE were completed. The inspectors concluded that corrective actions were properly completed and have no additional comments on this event.
92-11 Inadvertent De-activation of CIA Signal From Two Containment Isolation Valves
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This LER was previously reviewed as reported in NRC inspection report 92-28/27. The inspectors revisited this item and verified that the long-term corrective action of revising the 125VDC load list for Train 'B' breaker 8-27 was completed and that similar action was completed on the corresponding Train 'A' breaker 8-20. The inspectors concluded that corrective actions were properly completed and have no additional comments on this event.
93-03 Steam Generator Blowdown Isolation on High Blowdown Tank Level This steam generator blowdown isolation occurred when the steam generator blowdown system was being returned to service following a surveillance. The isolation signal was generated by high level in the steam generator blowdown tank. This was properly reported as an engineered safety feature actuation since the isolation included closure of the steam generator blowdown containment isolation valves, an engineered safety feature. At the time of the isolation, level was being controlled manually and the indicated level was below the high tank level trip setpoint. It was subsequently determined that the tank level transmitters are not compensated for normal operating temperature and pressure, and this resulted in an
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inaccurate indication of tank level. The level trip signal comes from a separate device.
Corrective actions included revising the tank level transmitter calibration procedure and recalibrating the instrument. The inspectors concluded that the corrective actions were adequate and have no additional comments on this event.
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 thorough event analyses, root cause determinations, and corrective actions.
4.2 Low Temperature Overpressure Protection Non-conservatism On April 2,1993, Duquesne Light Company received a Nuclear Safety Advisory Letter (NSAL 93-05) from Westinghouse regarding a non-conservatism in the low temperature overpressure protection (LTOP) setpoint development. The non-conservatism concerned the pressure differences between the hot leg wide range pressure transmitters (which actuate the power operated relief valves (PORVs)) and the reactor vessel beltline region (where the
10 CFR 50, Appendix G limit is defined). This pressure difference results from the static elevation difference between the hot leg and vessel beltline and from the dynamic pressure differences due to reactor coolant flow. These factors were not previously considered by Westinghouse in the LTOP setpoint analysis. This pressure difference effectively results in the reactor vessel pressure being greater than that sensed by the pressure transmitters.
- Accordingly, the potential to violate the Appendix G limit exists during a cold overpressure event. The inspectors reviewed the licensee's evaluation of this issue (engineering memorandum 105000) after being informed by the NRC Office for Analysis and Evaluation of Operational Data (AEOD) that Duquesne Light Company was one of several Westinghouse plants which had not submitted a licensee event report on this issue.
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The Westinghouse NSAL stated that 69 psid could exist under the following plant conditions:
low reactor coolant temperature (70oF); no pressurizer steam bubble (solid water conditions);
and all three reactor coolant pumps running. An Appendix G violation could occur during a cold overpressure event with a design basis mass injection transient (600 gpm). The static elevation difference was identified by Westinghouse as 5 psig. Sufficient margin exists for this static difference at Beaver Valley since both units maintain the PORV setpoint less than the technical specification LTOP setpoint (22 psig for Unit I and 24 psig for Unit 2). To account for the dynamic pressure difference, the licensee determined that adequate conservative margin to the Appendix G limit exists based on a separate Westinghouse analysis performed for Beaver Valley. The " Pressurizer Bubble Cold Overpressure Analysis" determined that the PORV pressure overshoot can be eliminated during a cold overpressure event by limiting the mass injection to less than 250 gpm and maintaining initial pressurizer water level to less than 50%. The pressure overshoot during the delay time before the valve starts to move and during the time the valve is full open can result in a maximum reactor vessel pressure higher than the set pressure. This overshoot could be as much as 77 psig during a design basis mass injection with solid water conditions. The margin between the minimum Appendix G limit (516.6 psig for Unit 1 at 85 oF) and the technical specification LTOP setpoint (423 psig - Unit 1) accounts for this pressure overshoot. The licensee has in place administrative controls to eliminate this overshoot and thus recapture the margin between the Appendix G limit and the technical specification limit.
Therefore, sufficient margin exists between the Appendix G limit and the LTOP setpoint to account for the 69 psid due to dynamic flow conditions.
The administrative controls are contained in station startup and shutdown procedures as well as reactor coolant pump (RCP) startup procedures for both units. Specifically, prior to starting a RCP with LTOP in service and a charging pump running, the following conditions must be met:
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pressurizer level less than 50%;
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total mass input to the reactor coolant system must be limited to s 250 gpm from any combination of the following flowpaths:
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fill header seal injection o
high head safety injection; and (3)
steam or nitrogen bubble in the pressurizer.
The inspector concluded that the licensee's determination of no substantial safety hazard exists, for both Beaver Valley Units 1 and 2, was appropriate. The evaluation was assigned an appropriate priority and completed in a timely manner, considering LTOP was in service
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at Unit 1 between March 27 and April 20,1993 and due to be returned to service following refueling activities.
4.3 Prevention of Debris Plugging of Emergency Core Cooling System Strainers In response to several industry events involving the plugging of emergency core cooling system suction strainers the NRC issued Bulletin 93-02 ' Debris Plugging of Emergency Core Cooling Suction Strainers' on May 11, 1993. This bulletin required licensees to take actions to remove from the primary containment building any fibrous air filters or other temporary sources of fibrous materials not capable of withstanding a LOCA. These prompt actions were required before startup from the refueling outage for Unit I and within 120 days (by September 8) for Unit 2.
Prior to startup, Duquesne Light Company identified that the Unit I containment iodine filtration system prefilters were the only installed fibrous material that was not adequately contained. These prefilters were removed before startup. The inspectors accompanied the licensee on a walkdown of the Unit I containment building which verified that no temporary sources of fibrous materials were installed or stored in the containment building. This walkdown also verified the general cleanliness of the containment and the Emergency Core Cooling System containment sump suction strainers.
The Unit 2 iodine filtration system is of a different design than Unit 1. The licensee's evaluation of Unit 2 concluded that the Unit 2 iodine filtration system prefilters were adequately contained and did not need to be removed. The licensee's evaluation also concluded that no temporary sources of fibrous materials were installed or stored in the Unit 2 containment building.
The inspectors reviewed the Duquesne Light Company June 10,1993 response to Bulletin 93-02. The fibrous filter volume reported for Unit 2 in that letter was for an individual filter element in cach filter train. Since each filter train has a three by three array of filter elements the actual filter volumes are a factor of nine higher than reported. The licensee confirmed the inspectors observation and also identified errors in the Unit I data. Duquesne Light Company plans to submit a corrected response.
5.0 PLANT SUPPORT (71707,90712,93001)
5.1 Radiological Controls Posting and control of radiation and high radiation areas were inspected. Radiation work 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
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on a sampling basis. Licensee personnel were observed to be properly implementing their radiological protection program.
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5.2 Security 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 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 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 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 ill mination was maintained. Licensee personnel were observed to be properly implementing and
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following the Physical Security Plan.
5.3 Housekeeping Plant housekeeping controls were monitored, including control and storage of flammable 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 generally acceptable; however, on at least three occasions, the inspectors noted deficiencies in the control of transient material. In all cases, the problems involved test equipment, in the
vicinity of safety related equipment, which was not properly secured. Additionally, housekeeping in the Unit 1 blender cubicle was noted to be particularly poor. A significant amount of transient material (tools, general debris) was within the cubicle even though no maintenance was in progress. Each of the deficiencies was promptly corrected by the licensee.
5.4 Chemistry 5.4.1 Missed Unit 1 Accumulator Sample On June 14, 1993, the licensee's chemistry supervisor identified that a Unit 1 technical specification surveillance had not been completed prior to plant entry into Mode 3 (hot standby). Specifically, Technical Specification 3/4.5.1 requires each safety injection accumulator to be sampled at least once per 31 days and within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after each solution volume increase of greater than 1 percent of tank volume. This sample verifies a boron concentration of between 1,900 and 2,000 ppm. This surveillance is applicable in Modes 1, 2, and 3 (above 1,000 psig).
The plant entered Mode 3, 21,000 psig, on June 9 at 5:35 a.m. The licensee's review of sample records determined that the boron concentration of the accumulators had not been verified by this time. The accumulators were filled with borated water earlier in May and June but were not sampled since they were not required to be operable for those existing
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plant conditions. The 'B' accumulator was sampled with satisfactory results on June 9 at
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10:30 p.m. The 'A' and 'C' accumulators were not sampled until after the licensee discovered this error on June 14. Subsequent samples indicated proper boron concentration.
The inspectors discussed this issue with the chemistry supervisor and questioned the basis for the chemistry department sign offin the startup checklist. The inspectors were informed that the verification of completed surveillances to support plant operation is based on existing surveillance program controls and chemist knowledge and experience. The chemistry department did not maintain a separate startup checklist exclusively for technical specification and non-technical specification chemistry samples. As long-term corrective action, the licensee has now developed a comprehensive startup checklist to ensure surveillance requirements to support mode changes are satisfied.
Licensee event report (LER) 92-12 reports on a Unit 2 reactor coolant system dissolved oxygen sample that was missed on October 23,1992. This LER was previously reviewed as reported in NRC inspection report 92-28/27. The inspectors re-reviewed the corrective actions reported in this LER following the missed Unit 1 accumulator sample. The Technical Specification Tracking Sheet was implemented as committed to in LER 92-12.
However, the LER 92-12 corrective actions were developed for samples involving a recurring surveillance whereas the missed Unit 1 accumulator sample involved a sample required for a mode change. The inspectors concluded that the missed Unit I accumulator sample was not preventable by corrective actions taken for the LER 92-12 event.
Overall, this incident was of minor safety significance as the accumulators were found to be within their required boron concentration. However, the licensee's controls in this instance were not effective in ensuring the completion of technical specification requirements. The failure to obtain accumulator samples prior to increasing reactor coolant system pressure above 1,000 psig in Mode 3 is a violation of Technical Specification 4.0.4. However, this violation is not being cited because the criteria of Section VII.B of the Enforcement Policy were satisfied.
5.4.2 Unit 2 Emergency Diesel Fuel Oil Particulates High concentration of suspended particulates with a high carbon content have periodically been detected in the Unit 2 emergency diesel generator fuel oil storage tanks. Following the last refueling outage both 58,000 gallon fuel oil storage tanks were completely drained, cleaned, and refilled with fresh fuel oil. Fresh fuel oil averages about 0.6 milligrams per liter (mg/1) particulates. The source of the particulates and corrective actions are under review by the licensee but the source is believed to be combustion products or lube oil in fuel oil which returns to the storge tanks from the diesel engine via a drain line. The Unit 2 emergency diesels are 5,900 horsepower Type 12PC2V400 diesel engines manufactured by the Fairbanks Morse Division of Colt-Pielstick. The Unit 1 emergency diesels are made by a different manufacturer and have not experienced this problem.
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Technical Specification 4.8.1.1.2 requires that the emergency diesel fuel oil be sampled monthly to verify that particulate concentrations are less than 10 mg/1. If the concentration exceeds 10 mg/1, technical specifications require reducing the concentrations below 10 mg/l within seven days. Particulate concentrations in the A fuel oil tank measured above this limit on June 24. Two verification samples taken on June 28 were below the limit but high.
Particulate concentrations in the B fuel oil tank were below the limit but also high when measured on July 7. As a result, the licensee fabricated a fuel oil filtration unit, prepared Temporary Operating Procedure 93-05 ' Diesel Fuel Oil Processing', and cycled the fuel oil through the filtration unit to clean it up. The inspectors observed that the fuel oil cleanup operation was performed in accordance with Temporary Operating Procedure 93-05, with continual staffing by operations and maintenance and frequent monitoring by chemistry staff.
Site management was closely involved with this issue beginning with the first reports of high particulates.
The inspector observed the fuel oil tank sampling which was done on July 21 after the cleanup had been completed. This sample, which was taken with a copper sample bomb as were the earlier samples, showed that the cleanup operation had been successful in reducing the particulate concentration levels to between 5.8 mg/l in the A tank and 7.1 mg/l in the B tank. Samples taken using a sample pump measured 2.9 mg/l in the A tank and 1.0 mg/l in the B tank. The chemistry department is evaluating their sampling techniques to reduce the variability of results. This item is unresolved pending determination of the source of contamination, subsequent corrective actions, and evaluation of sampling technique.
(Unresolved item 50-412/93-14-02)
5.5 Luergency Squad Response
On July 9,1993, the inspectors observed the licensee's " emergency squad" respond to a heat stress victim. A' worker exhibited symptoms of heat stress while performing maintenance within the Unit I subatmospheric containment. At the time of this event, the plant was at 100% power. The average containment temperature was 10loF (ambient) and the workers were outfitted in full cotton anti-Cs, with ice vests and respirators. The metabolic work demand was considered as moderate to heavy. A three-hour stay time was planned based on radiological conditions. The worker had been inside containment for about 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> (excluding decompression time in the personnel airlock). The inspectors noted good integrated response by the operations, health physics, and security personnel, including the
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on-site nurse. The worker was properly and rapidly removed from his anti-Cs, frisked for contamination, iced down, rehydrated, and transported to a cooler environment. No offsite medical attention was necessary.
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6.0 ADMINISTRATIVE 6.1 Preliminary Inspection Findings Exit At periodic intervals during this inspection, meetings were held with senior plant 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 July 28,1993, with Beaver Valley management summarizing inspection activity and findings for this period.
6.2 NRC Staff Activities Inspections were conducted on both normal and backshift hours: 25.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> of direct inspection were conducted on backshift; 6.7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> were conducted on deep backshift. The.
times of backshift hours were adjusted weekly to assure randomness.
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