IR 05000266/1994006
| ML20029D984 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 05/04/1994 |
| From: | Farber M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20029D982 | List: |
| References | |
| 50-266-94-06, 50-266-94-6, 50-301-94-06, 50-301-94-6, NUDOCS 9405130222 | |
| Download: ML20029D984 (24) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Report Nos. 50-266/94006(DRP); 50-301/94006(DRP)
Docket Nos. 50-266; 50-301 License No. DPR-24; DPR-27 l
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Licensee: Wisconsin Electric Company l
231 West Michigan l
Milwaukee, WI 53201 Facility Name:
Point Beach Units 1 and 2 Inspection At:
Two Rivers, Wisconsin Dates: March 1 through April 18, 1994 Inspectors:
J. Gadzala A. McMurtray A. llansen J. Neisler R. Mendez Approved By:
I!'/' f M. J. Farber, Chief Date
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Reactor Projects Section 3A Inspection Summarv
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Inspection from March 1 through April 18. 1994 (Recorts No. 50-266/94006(DRP): No. 50-301/94006(DRP)
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Areas Inspected:
Routine, unannounced inspection of plant operations, maintenance, engineering, plant support, and corrective actions on previous findings.
Results:
No cited violations of NRC requirements, one noncited violation, one inspector followup item, and three unresolved items were identified.
An Executive Summary Follows.
Plant Operations
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Unit I was shut down for refueling outage 21 on April 1.
This 30-day outage included a complete core offload to inspect the "A" steam generator primary side hot leg for a loose part.
Nothing abnormal was found.
(Section 1.a)
On March 23, plant engineers identified that Unit 2 had been operating about 1.5% higher than indicated power level.
This condition apparently existed 9405130222 940506 PDR ADOCK 05000266
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t since 1991 and was due to measurement inaccuracies in feedwater flow.
Mthough thermal limits were not exceeded, the plant had operated above its licensed rated power of 1518.5 MWt.
(Section 1.c)
Inadequate control over the Unit 1 pressurizer steam space sample line isolation valve prevented degas of the reactor coolant and caused a minor delay in outage activities. Although this specific event was of minimal safety concern, it characterized a number of similar events involving configuration control.
(Section 1.d)
Point Beach continued to implement additional controls to prevent inadvertent introduction of foreign material or debris into plant systems.
However, the inspector observed that compliance with these initiatives was not yet universal.
(Section 1.f)
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A special NRC assessment conducted during the week immediately following the close of this inspection report identified areas of weak control room operator performance, including informal communications, inattention to main control board panels, high control room traffic, and overloading of shift supervision with administrative matters. A management meeting to discuss these observations and licensee corrective actions has been scheduled.
Maintenance Timely replacement of a service water pump sequencing relay was aggressively pursued.
Good engineering coverage was also noted. A positive safety attitude was demonstrated when a tap change on the 1X04 station transformer was delayed.
Rather than have the next shift crew perform this complex evolution, plant management postponed it 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to allow the crew that had been trained on this evolution in the simulator to perform it.
(Section 2.a)
l In an effort to improve maintenance work prioritization and reduce the l
administrative burden associated with maintenance work request processing, a minor maintenance program was recently initiated.
(Section 2.b)
l The inspector observed various items such as nuts, studs, washers, and debris
in the immediate vicinity of an open Unit I containment sump suction to the l
residual heat removal pump. Operations planners had not considered use of I
foreign material exclusion requirements during performance of this test.
l (Section 2.c)
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l Enaineerina
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Installation of two new emergency diesel generators continued.
The inspector i
noted that some welding deficiencies associated with this project may not'have been adequately documented.
For certain minor deficiencies, the contractor's quality control inspectors could direct appropriate rework of the weld and not have to consider it as rejectable.. The issue of rejectable weld threshold for
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documentation purposes remains unresolved.
(Section 3.a)
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One of the two series check valves to each Unit 1 steam generator that serves as the containment boundary was found to be leaking excessively on April 11.
Two new valves were procured and the valves were replaced.
A justification to continue operating Unit 2 with a potentially similar condition was approved by i
the supe.visory staff.
(Section 3.b)
Point Beach Unit I voluntarily became the first U.S. nuclear plant to undergo eddy current testing of the reactor vessel control rod drive mechanism
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Initial data analysis revealed no flaws.
(Section 3.c)
Plant Support A limited emergency preparedness drill was held with the primary focus on
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training inexperienced staff.
(Section 4.a)
i On March 23, an intrusion detection zone alarm was not reset for 26 minutes
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after a patrol set it off.
No compensatory actions were initially taken.
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Region III security specialists discussed this event with plant management and appropriate corrective actions were taken.
(Section 4.b)
Plant Imorovement Initiatives During the recent Unit I refueling outage, Point Beach initiated a work control center to provide a central area for processing work control documents and ease control room crowding. The plant's initial effort met with only
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limited success, The inspector noted that many work activities continued to
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be processed in the control room, significantly occupying the duty shift superintendents to the point that only minimal attention was being given to supervising unit operation.
(Section 5.b)
Issue Followuo The inspector observed significant deterioration of the grcut underlaying the Unit 1 containment recirculation sump's protective screens.
Concerns were raised regarding flow bypass channels being likely to form in the grout and loose grout potentially being drawn into the pump suction.
(Section 6.a)
Intermittent leakage in the Unit 2 A steam generator developed into a small continuous leak following the autumn refueling outage.
Overall primary to secondary leakage increased slightly to about 18 gallons per day (gpd).
After
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performance of Unit 2 turbine stop valve testing on December 23, 1993, the leak rate increased to about 24 gpd. Average leakage continued increasing to 27 gpd by iaid March. The licensee exhibited a responsive attitude towards addressing this issue and has adequate controls in place for monitoring and evaluating this leakage.
(Section 7.e)
A contractor failed to advise Wisconsin Electric of a contractor employee's past positive drug tests. Therefore this employee was not given the required i
evaluations of fitness for duty prior to being granted access to Point Beach.
This violation is not being cited. Subsequent enforcement action has been
taken against the contractor security manager for deliberately providing falsified documents.
(Section 7.1)
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DETAILS 1.
Plant Operations (71707) (60710) (40500) (93702)
The inspectors evaluated selected activities to confirm that the facility was being operated safely and in conformance with regulatory requirements. These activities were confirmed by direct observation, i
facility tours, interviews and discussions with licensee personnel and management, verification of safety system status, and review of facility i
records, lhe inspectors observed control room operations, reviewed applicable logs and conducted discussions with Operations staff members.
During these discussions and observations, the inspectors ascertained that the staff was knowledgeable of plant conditions and was aware of inoperable l
equipment status. The inspectors performed walkdowns of the control
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boards to verify the operability of selected emergency systems, reviewed tagout record 3 and verified proper return to service of affected i
components. Shift changes were observed, verifying that system status I
continuity was maintained and that proper control room staffing existed.
l Although operations personnel carried out their assigned duties in an l
effective manner, the inspector noted a gradual decline in the formality l
of control room operations.
A special NRC assessment was conducted during the week immediately following the close of this inspection report as part of a pilot program to redefine the NRC inspection program and develop a customized l
inspection program unique to Point Beach. During this assessment the i
inspectors identified areas of weak control room operator performance, l
including informal communications, inattention to main control board I
panels, high control room traffic, and overloading of shift supervision i
with administrative matters. Additional information on these issues will be included in a docketed trip report by the assessment team.
This report is scheduled to be issued in the near future. A management meeting to discuss these observations and licensee corrective actions has been scheduled.
Plant tours and perimeter walkdowns were conducted to verify equipment
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operability, assess the general condition of plant equipment, and to verify that radiological controls, fire protection controls, physical protection controls, and equipment tag out procedures were properly implemented.
During facility tours, inspectors noticed few signs of leakage and that all equipment appears to be in good operat eng condition.
Overall, plant cleanliness has remained acceptable.
a.
Unit 1 Operational Status The unit operated at full power until March 22 when reactor coolant boron concentration reached zero. A power coastdown then
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commenced at about 1.5% per day.
Power was reduced to about 86%
by April I when the reactor was shut down for refueling outage 21.
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Major activities scheduled for this 30 day outage included a complete core offload, reactor vessel head inspection (CRDM penetration eddy current inspection for axial and circumferential flaw - pilot program),
"A" coolant loop inspection, safeguards bus transformer IX04 tap change, fuel inspection, main feed check valve modification, and as-built walkdowns.
b.
Unit 2 Operational Status The unit continued to operate at full power until March 23 when power was reduced by three percent following discovery of an error in the method used to calculate power.
Details appear in section 1.c below.
Power was restored to 99% on March 25 after adjusting affected instrumentation.
c.
Unit 2 Operation Above Licensed Power level On March 23, plant engineers identified that Unit 2 had been operating about 1.5% higher than indicated power level.
This condition apparently existed since 1991 and was due to measurement inaccuracies in feedwater flow. Although thermal limits were not exceeded, the plant had operated above its licensed rated power of 1518.5 MWt.
The cause of the power measurement inaccuracy was degradation of transducers in the plant's Leading Edge Flow Meter. This device provides precision measurement of feedwater flow, which is used to calibrate the feedwater flow venturies.
The corrected venturi feedwater flow is a principal factor in the reactor thermal output calorimetric calculation that determines reactor power.
The flow error was found as part of the process to identify a difference in electrical output between Unit 1 and Unit 2.
Electrical Generation Disparity Between Units 1 and 2 In 1991, plant personnel noted that electrical output of Unit 1 and Unit 2 had differed slightly, even though both units generated the same thermal energy. Unit 2 electrical output exceeded that of Unit 1 by a few megawatts.
An evaluation was initiated to identify what, at the time, was a perceived loss of efficiency in Unit 1.
This effort initially met with little success.
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As part of the process however, a vendor was contracted to assess i
l the Point Beach flow measurement system, l
l Feedwater Flow Measuring System and Its Transducer Degradation i
Point Beach employs a Westinghouse model 601 Leading Edge Flow Meter. This is an ultrasonic flow measurement instrument which
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t was installed in the early 1980s.
The system contains transducers arrayed around the feedwater pipe that transmit sound pulses through the feedwater to each other.
Each pulse consists of several cycles of sound at a set frequency traveling as a sine wave.
When the leading edge of the sine wave strikes the opposite transducer, it activates that transducer and the receipt of the
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pulse is recorded. The time difference between transmission of the pulse and its receipt is used to calculate flow through the pipe.
Using a new microprocessor based flow instrument, the vendor identified that the Unit 2 flow measurement system had degraded.
The transducer would intermittently transmit a pulse whose leading edge was degraded such that the first cycle of the sine wave would not trigger the receiving transducer.
Because the degradation was
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intermittent and the device integrates the data received over a set time period, the error due to the transducer degradation was
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only about one percent.
The intermittent nature of this degradation also prevented its detection during periodic system calibration.
Since the pulse was analyzed using an analog oscilloscope, the intermittent degraded sine wave was masked by the correct signal that was produced the majority of the time.
Additional Error Introduced by Leaking Feedwater Bypass Valve In addition to the error caused by the degraded flow instrument, feedwater flow was found to be bypassing the flow meter through a leaking feedwater regulating valve bypass.
This caused some feed flow to bypass the measuring system completely.
However, the error introduced by this bypassed flow was only 0.25%.
The placement of the feed flow measuring system in a section of pipe capable of being bypassed was necessitated by other factors such as a sufficiently straight run of piping to allow proper flow characteristics for the flow measurement system to work properly.
Corrective Action Upon determining the measurement error on March 23, Unit 2 power was reduced by three percent.
Nuclear instrumentation was adjdsted to correspond to the correct power level. Over-temperature and overpower 6T setpoints were adjusted based on the newly identified operating conditions. Once the analysis was verified on March 25, Unit 2 power was raised to 99%.
A recent Unit 2 technical specification change that reduced the minimum allowable reactor coolant flow, necessitated lowering of
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the overtemperature and overpower 6T setpoints.
Because a two
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degree margin to the overtemperature runback setpoint was desired, 100% power could not be achieved with the lower 6T setpoints.
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Significance of Operating 1.5% Above Rated Power Periodic core flux mapping conducted throughout the affected period showed that thermal limits were not exceeded.
Point Beach accident analysis assumes a 2% error in power level measurement.
The plant's analysis determined that this was not exceeded.
Therefore, the reactor remained within its analyzed condition.
The power measurement error resulted in one of the four overtemperature 6T and overpower 6T setpoints (red) having been set above the technical specification limit by about 0.2 F.
However, three other channels remained operable to initiate the two out of three trip circuitry required for reactor protection.
This issue remains unresolved pending completion of its evaluation by the NRC (301/94006-01).
A related condition occurred July 26, 1991.
Both units were found to have been operating above their licensed power level by about one MWt.
This was due to an incorrect conversion factor in a computer algorithm. The NRC determined the safety significance of that condition to have been inconsequential.
d.
Inadeauate Pressurizer Sample Valve Control Delays Unit 1 Outaae Shortly following Unit I reactor shutdown, pressurizer steam space sample line isolation valve ISC-956A, was found shut. This normally open valve was found shut when attempting to identify the cause of a rising Unit 1 coolant hydrogen concentration.
The valve's being shut prevented degas of the reactor coolant and caused a minor delay in outage activities.
The cause for this valve not having been properly positioned was
.due to inadequate coordination between the operations and chemistry groups regarding its operation.
The valve was routinely operated by chemistry and did not appear in the operations degas procedure.
It was also shown as a normally open valve on the engineering drawing. The operations group was undertaking procedure revisions to improve control over this valve during degas evolutions.
Although this specific event was of minimal safety concern, it
characterized a number of similar events involving plant -
configuration control during this inspection period, such as inadvertent draining of ammonia from a chemical addition tank and inappropriate partial draining of the pressurizer relief tank.
The inspector discussed this concern with plant management.
Initiatives have been undertaken by the licensee to improve
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performance in this area.
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e.
Enaineered Safeauards Features (ESF) System Walkdown (71710)
The inspectors performed a detailed walkdown of portions of the auxiliary feedwater (AFW) system in order to independently verify operability. The AFW system walkdowns included verification of the following items:
Inspection of system equipment conditions.
Confirmation that the system check-off-list (COL) and operating procedures are consistent with plant drawings.
Verification that system valves, breakers, and switches are properly aligned.
Verification that instrumentation is properly valved in and operable.
Verification that valves required to be locked have appropriate locking devices.
Verification that control room switches, indications and controls are satisfactory.
Verification that surveillance test procedures properly implement the Technical Specification surveillance requirements.
Several minor deficiencies, such as a missing electrical junction box cover and a missing handwheel nut, were identified.
Additionally, a hanger for a section of AFW recirc piping was found partially disconnected and a loose nut was found on another hanger. These conditions did not impact system operability.
The deficiencies were conveyed to the licensee for correction.
f.
Foreian Material Control Proaram Initiatives Point Beach continued to implement additional controls to prevent inadvertent introduction of foreign material or debris into plant systems. One such recent initiative was' creation of a foreign material exclusion buffer around the reactor vessel refueling cavity.
Its intent was to prevent material from falling into the open reactor vessel. This was to be accomplished by restricting material in the vicinity of the refueling cavity and implementing controls over items brought into the control buffer.
Although the inspector noted a improved controls and a reduction in the amount of material near the refueling cavity, compliance with the exclusion buffer requirements was not universal.
For example, repair of a fuel manipulator crane light was accomplished over the cavity using tools without a lanyard attached, despite a l
nearby sign warning against such a practice.
l The inspector identified a scaffold that was improperly erected about 40 feet above and adjacent to the exclusion buffer, with minimal consideration of the impact its use would have on
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refueling operations.
This scaffold was subsequently struck by j
the containment polar crane after completion of fuel motion.
None i
of the falling pieces struck anyone or fell into the refueling
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cavity.
Plant management stated that they will continue to pursue j
improvement in this area.
2.
Maintenance (62703) (61726)
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a.
Maintenance The inspectors observed safety related maintenance activities on systems and components to ascertain that these activities were conducted in accordance with technical specifications, approved procedures, and appropriate industry codes and standards. The inspectors detarmined that these activities did not exceed limiting conditions for operation and that required redundant components were operable. The inspectors verified that required
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administrative, material, testing, and radiological and fire
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prevention controls were adhered to.
Selected portions of the following maintenance activities were i
observed and reviewed:
Replacement of P-328 service water pump sequencing relay
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l TDR-14 This relay was found inoperable while performing inservice testing.
Even though only four of the six service water pumps were required by technical specifications, plant staff j
aggressively pursued replacement of the faulty relay. The relay was replaced the day following discovery of the fault.
i Technicians were observed to be knowledgeable on the equipment being worked and the inspector noted effective
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engineering supervision during the course of this evolution.
SMP 1155 (Revision 0), IXO4 Tap Change
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A tap change was performed on station power supply j
transformer IX04 to raise safeguards bus voltage 2.5% in
response to degraded grid voltage concerns.
This evolution involved a complex series of electrical bus alignments to
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maintain power to safeguards busses during work.
Voltage adjustments were well coordinated between operations, electrical maintenance and component engineers.
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interiors of the high and low side transformer bus ducts were observed and no abnormalities or foreign material were
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noted.
Initiation of work was delayed due to problems encountered with reactor coolant system degassing during shutdown.
However, rather than have the next shift crew perform this complex evolution, plant management postponed it 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to allow the crew that had been trained on this evolution in the simulator to perform it.
Performing the evolution safely was considered ahead of the resultant outage delay.
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Unit 1 feedwater check valve replacement
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Minor Maintenance Proaram
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In an effort to improve maintenance work prioritization and reduce
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the administrative burden associated with maintenance work request i
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processing, a minor maintenance program was recently initiated.
i The intent of this program was to remove minor maintenance activities from under the formal controls of the normal maintenance program and thereby reduce the time needed to process and complete them. At the same time, this would allow increased emphasis to be placed on the more significant maintenance actions.
Minor maintenance was the defined by plant management as work that does not involve safety related equipment, does not affect operation or operability of equipment essential for plant operation, does not require trending, and can be worked within the skill of the craft.
Examples include lighting and receptacle repairs, motor vehicle and landscaping equipment maintenance, plumbing, painting, and miscellaneous fabrication. The inspector will continue to follow progress in this area.
c.
Surveillance The inspectors observed certain safety related surveillance activities to ascertain that these activities were accomplished by qualified personnel in accordance with an approved test procedure, test instrumentation was properly calibrated, the tests were completed at the required frequency, and that limiting conditions for operation were met. Upon test completion, the inspectors verified the recorded test data was complete, accurate, and met technical specification requirements; test discrepancies were properly documented, reviewed and resolved by appropriate management personnel; and that the systems were properly returned to service.
Selected portions of the following test activities were observed and reviewed:
RESP 6.1 (Revision 13), Core Power Distribution and Nuclear
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Power Range Detector Calibration RESP 6.3 (Revision 4), RCS Flow Measurement
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IT-531 (Revision 2), Containment Sump B Suction Line Leak
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Test (Refueling Shutdown), Unit 1 Performance of this test involves opening of the containment sump suction valves to the residual heat removal (RHR)
i pumps. This constitutes opening of the RHR system for potential debris intrusion.
The inspector observed various items such as nuts, studs, washers, and debris in the
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immediate vicinity of the open RHR suction.
Being flush with the containment floor makes the suction opening a likely receptacle for any of these items were they to be inadvertently brushed by workers in the area.
Operators performing the test promptly removed loose items from the immediate vicinity of the opening upon being informed of the inspector's concerns.
Procedure PBNP 3.4.25, " Exclusion of Foreign Material From Plant Components and Systems", established a program to prevent introduction of foreign material into open systems and applies to all systems at Point Beach.
This procedure was written as part of the corrective action in response to previous concerns in this area.
However, operations planners had not considered use of foreign material exclusion requirements during performance of this test.
Following discussions with the instretor, l
operations management stated that this area would ue
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reviewed and appropriate changes made to the test procedure to implement foreign material control requircments. The inspector will continue to follow this issue and document corrective actions in a future report (266/94006-02).
No other discrepancies were noted during the observance of any of the above tests.
3.
Enaineerina (71707) f(3782811
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The inspectors evaluated engineering and technical support activities to determine their involvement and support of facility operations. This was accomplished during the course of routine evaluation of facility events and concerns, through direct observation of activities, and discussions with engineering personnel.
a.
Construction of New Emeraency Diesel Generator Buildina Construction of the building to house two new emergency diesel generators (EDGs) and the new diesel fuel oil system began the week of June 7, 1993.
Initial observations of this activity are discussed in Inspection Report 266/301/93011. During this inspection period, the inspectors determined that excellent quality control coverage was demonstrated over this project.
The following activities were inspected.
Concrete The inspector observed the final scheduled safety related concrete placement of approximately six yards used to fabricate two removable beams for the west wall openings in the diesel generator rooms. The licensee used the same mix design as for the other seismic category I structures.
Test samples indicated that the
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slump and air entrainment were within specifications.
Compression test cylinders were prepared for curing and testing at the contractor test laboratory off site.
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The inspectors noted that the existing EDG load calculations did i
not take cable losses into account. The physical separation of the new EDG building introduces significantly longer cable runs from the generators to their loads. Under worst loading conditions, a margin of only 54 kW exists between the generator's
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200-hour rating and the load requirements.
The licensee stated
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that preliminary calculations indicated maximum cable losses of
about 23 kW. The load flow program for the EDGs was being modified to account for cable losses in the loading calculation.
The inspector observed the installation of one electrical panel in
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the diesel building. The panel was set in place and welded to floor embeds to comply with seismic design requirements.
Review of welder qualifications indicated that the welder was qualified to AWS Dl.1 and the weld procedure specification.
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Electrical cable pulling and termination was in progress in the
diesel building. The inspector observed four cable pulls and two cable terminations. Adequate inspection of both cable pulls and terminations was provided.
Quality Inspectors verified each pull and inspected each termination before and after landing the
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termination legs on terminals.
No discrepancies were identified.
l During observation of cable tray installation in manholes in the duct bank between the diesel building and the plant, the inspector noted that torquing of bolts in the tray installation was 100%
quality inspected.
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An undervoltage relay being prepared for startup testing was incorrectly set at 90% dropout.
The temporary system protection
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setpoint data sheet specified a value of 99%.
This relay was subsequently reset after its identification.
Piping and Welding The inspector noted that some welding deficiencies may not have been adequately documented.
If a discontinuity or other indication was noted during the course of a weld inspection, the
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contractor's quality control inspectors were allowed discretion on deciding what constituted a rejectable weld.
If the weld could be reworked to bring it into a code acceptable condition by ordinary means, such as filing or wire buffing, and significant material removal was not required, the QC inspector did not have to consider the weld rejectable. Therefore, no documentation was made of the defect, corrective actions, or identification of the welder. However, welds that did not meet specific criteria were
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rejected and documentation was made of the rework.
10 CFR 50, Appendix B, requires that deficiencies and resultant corrective actions be documented. The issue of rejectable weld threshold for documentation purposes remains unresolved pending further evaluation by the inspector (266/94006-03).
The inspector observed safety related pipe installation for the new diesel generators including fit up and welding of joints in the starting air, coolant, lubrication and fuel oil piping systems.
Each fit up was inspected by quality control before welding began. Non destructive examinations (NDE) consisting of either liquid penetrant or magnetic particle examinations were performed on each safety related weld. The inspector reviewed welder qualification documentation pertaining to each welder observed welding on safety related systems; all were qualified to the appropriate weld procedure specification (WPS), technique and material.
Review of NDE records indicated that deficiencies found in the welds had been repaired and re-examined.
The inspector observed fit up and welding of the glycol coolant piping in both diesel rooms.
Each fit up was inspected by quality verification personnel prior to welding. Magnetic particle examination of the completed welds indicated that the welds observed by the inspector were acceptable. The installation of fuel, lubricating oil and diesel starting air piping including pipe supports was also inspected.
No visual discrepancies were noted.
The inspectors will continue to monitor progress of this construction.
b.
Feedwater System Containment Isolation Valve AdeauacY Following installation of a bypass piping modification around feedwater check valves to the Unit I steam generators April 11, one of the two series check valves to each steam generator was found to be leaking excessively. A representative diagram for the
"A" steam generator is shown in figure 1 below.
AFW steam v
L--CS-466BB-CS-466AA 4 feedwater generator
contairvnent
[ figure 1.]
The feedwater check valve outside containment was found to be leaking in each of the two feedwater lines (CS-466AA in figure 1).
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The outer check valves are identified as the containment isolation valves in the Point Beach Final Safety Analysis Report.
Because there was no previous capability to test these valves separately, l
they had always been tested in series.
The previous test i
performed on these valves had been satisfactory.
Leakage problems in the late 1970s resulted in replacement of the inner check valve
to each steam generator.
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In their third 10-year interval ASME Section XI Inservice Testing l
Program submittal, Wisconsin Electric had requested relief from testing these valves separately. The NRC denied this request and directed that the valves be modified to allow individual testing by October 1994. This was the modification recently installed in
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Unit I that led to discovery of the leaking check valves.
Plant management decided to pursue prompt replacement of the affected Unit 1 valves.
Replacement valves were found to be available from a cancelled nuclear plant and were expeditiously procured for both units.
The Unit 1 valves were replaced during this outage.
Installation of the Unit 2 feedwater bypass modification and testing of the Unit 2 feedwater valves is j
scheduled for the autumn 1994 outage.
The licensee justified continued operation of Unit 2 based on the entire length of feedwater piping inside containment being missile protected and the inner check valve remaining operable as
l demonstrated by the most recent series test of the check valves.
c.
Peactor Vessel Head Penetration Testina Pilot Proaram i
Point Beach voluntarily became the first U.S. nuclear plant to undergo eddy current testing of the reactor vessel control rod drive mechanism penetrations.
This testing was in response to a concern with possible circumferential cracking in these penetrations as had been identified in some European reactors.
Foint Beach Unit 1 vessel head was tested the week of April 11 during the current refueling outage.
Personnel from NRC
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Headquarters (NRR and AE00) and Region III observed this testing.
l All 49 penetrations were tested at least partially.
Peripheral penetrations were the most difficult to test due to clearance obstructions for the test probe. However, circumferential testing of at least 210 degrees was accomplished on them.
Forty-one of the 49 penetrations were tested around their entire 360 degree circumference.
Initial data analysis revealed no flaws on any penetration.
Based on the test results, Wisconsin Electric does not intend to test the corresponding Unit 2 penetrations.
Detailed information will be provided in future NRC reports on this topic.
All activities were conducted in a satisfactory manner during this inspection period.
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4.
Plant Sucoort (71707)
The inspectors routinely observed the plant's radiological controls and practices during normal plant tours and the inspection of work j
activities.
Inspection in this area includes direct observation of the
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use of Radiation Work Permits; normal work practices inside contaminated barriers; maintenance of radiological barriers and signs; and health
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physics activities regarding monitoring, sampling, and surveying.
The inspectors also observed portions of the radioactive waste system
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controls associated with radwaste processing.
i From a radiological standpoint the plant is in good condition, allowing
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access to most sections of the facility.
During tours of the facility,
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the inspectors noted that barriers and signs also were in good
condition. When minor discrepancies were identified, the health physics staff quickly responded to correct any problems.
a.
Emeraency Preparedness Trainina Drill-This was a limited drill utilizing the Emergency Operations Facility with the primary focus on training inexperienced staff.
Many of the players in this drill were new and therefore were not initially focused.
However, as the scenario progressed, players assumed their assigned roles, and performance improved. The controllers provided very good direction, and were readily available to answer questions and resolve issues.
b.
Security Detection Zone not Reset On March 23, an intrusion detection zone alarm was not reset for 26 minutes after a patrol set it off.
No compensatory actions were taken during this time.
After the alarm was reset, the protected area was searched and no abnormal conditions were found.
Delays were encountered with security personnel reporting this event to their supervision. This contributed to a late notification to the NRC of this event.
Region III security specialists discussed this event with-plant management and
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appropriate corrective actions were taken.
Security specialists i
will followup this event, and document their findings, during a future security inspection.
All other activities were conducted in a satisfactory manner during this inspection period.
5.
Plant Improvement Initiatives (40500)
Wisconsin Electric's process improvement programs were inspected to assess the implementation and effectiveness of programs associated with management control, verification, and oversight activities.
Special consideration was given to issues which may be indicative of overall
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management involvement in quality matters such as self improvement programs, respcnse to regulatory and industry initiatives, management
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presence and direction, and management personnel's attendance at technical and planning / scheduling meetings.
a.
Manaaer's Suoervisory Staff Meetino The inspector observed several sessions of the Manager's Supervisory Staff.
Issues discussed included degraded grid voltage and associated tap change on the safeguards bus transformers.
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b.
Establishment of Work Control Center to Ease Control Room Crowdina During the recent Unit I refueling outage, Point Beach delegated an area outside the control room as a work control center.
The purpose of this activity was to provide a central area for processing work control documents and maintain a secondary area for monitoring equipment configuration status.
The intent was to ease the control room crowding inherent during heavy workload periods, such as refueling outages.
The licensee's initial effort met with only limited success.
Despite many work documents being processed through the work control center, only the peak control room crowding associated with shift turnover was reduced to any significant degree. The inspector noted that many work activities continued to be processed in the control room, significantly occupying the duty shift superintendents to the point that only minimal attention was being given to supervising-unit operation.
Plant management intends to continue development of this activity to improve its effectiveness.
6.
Follow up of Information Notices (90700)
The effectiveness of the company's program for handling Information Notices (IN) was evaluated on a sampling basis.
Select ins were examined to verify that the company performed reviews for. applicability, that they received appropriate distribution at the site and corporate levels, and that scheduling or performance of any necessary corrective actions was conducted. The following IN was examined:
a.
(Closed) IN 89-77. Supplement 1:
Debris in Containment Emergency Sumps and Incorrect Screen Configurations Wisconsin Electric reviewed the information contained in this IN and concluded that, based on the system design at Point Beach, there is no way for water to' bypass the containment sump screens.
Additionally, there are no conduit or other penetrations through the screens to affect screen integrity. No deformation or defects were noted in the screens.
The inspector observed the physical arrangement of the sump suction and protective screens while the screen was removed and
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1 noted significant deterioration of the underlaying grout.
Although the screen arrangement is such that most of the damaged grout is covered by a steel plate, two concerns were raised.
Flow bypass channels are likely to form in the grout.
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Loose grout could be drawn into the pump suction.
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The extent of grout deterioration indicates that flow bypass channels are likely to form in the near future, which could allow
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foreign material to enter the suction of the residual heat removal pump. Additionally, the loose grout itself would likely be drawn into the pump suction during the recirculation phase of a postulated accident.
Plant management indicated that the grout would be inspected prior to completion of the current Unit I outage and repaired as necessary. A work request was prepared to schedule inspection and repair on the Unit 2 containment sump screen support.
This item remains unresolved pending completion of the licensee's actions and subsequent review by the inspector (266/94006-04).
7.
Corrective Action on Previous Inspection Findinas and Licensee Event Reports (92701) (92702 (92700) (90712)
a.
(Closed) Inspection Follow Up Item (266/91010-01: 301/91010-01):
Isolation of RG 1.97 Instrumentation from Plant Process Computer and Between Indicators and Controllers The adequacy of isolation devices between Foxboro H-line instrumentation and post accident monitoring indicators was questioned. Additionally, the lack of isolation devices between indicators and controllers in the secondary current loop did not strictly meet Regulatory Guide 1.97 recommendations.
As documented in a letter from J. Zwolinsky, NRR, to G. Grant, NRC Region III, dated January 26, 1994, the NRC's evaluation determined that RG 1.97 instrumentation at Point Beach is
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adequate.
b.
(Closed) Inspection Follow Vo Item (266/91010-03: 301/91010-03):
Unique Identification of RG 1.97 Instruments in the Control Room Certain instruments in the control were not uniquely identified as recommended by Regulatory Guide 1.97.
Labels have since been installed on all appropriate control room indications to identify them as non-qualified instrumentation for post accident use. The NRC subsequently determined that RG 1.97 instrumentation at Point Beach is adequate, as documented in a letter from J. Zwolinsky, NRR, to G. Grant, NRC Region III, dated January 26, 1994.
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(Closed) Violation (266/92009-01):
Inadequate Work Control -
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Drawings Not Updated; Inadequate Precautions in Work Procedure
I Two examples of inadequate work control were identified.
A vent i
valve was inadvertently left open during a. hydrostatic test, resulting in a spill of contaminated water. This vent valve had
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i been installed during a recent modification and did not appear on an informal sketch in the hydrostatic test package.
The second
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example involved opening the wrong potential. transformer cubicle
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while inspecting safeguards bus 1A06.
This resulted'in deenergization of bus 1A05 and starting of its associated diesel generator. Although the cubicle panels were labeled, there were
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no precautions in the procedure alerting operators to the fact
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that both bus' cubicles were in the same cabinet.
j Corrective Action For Improper Hydrostatic Test
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Procedure PBNP 3.2.5, " Pressure Test Programs", was revised to require use of an approved drawing'for defining test boundaries
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hydrostatic testing.
Corrective Action For Improper Potential Transformer Cubicle Entry The plant staff's evaluation of this event determined that the primary cause was human error.
The event was discussed with the individuals involved and.the details were included in training
sessions on operation and maintensnce of switchgear.
Additionally, a caution statement was added to several maintenance
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procedures to alert personnel that the potential transformers for both safeguards busses are in the same cabinet behind individual
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panels.
The licensee's corrective actions were considered appropriate.
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The inspector reviewed the various procedure changes and training
records and discussed the events with plant management.
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Procedures clearly specify the new requirements and interviews with personnel indicate they are aware of the new processes.
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Although the above corrective actions addressed the specific
issues identified here, other examples of inadequate work control continue to appear. A violation was recently cited for improper maintenance on a diesel generator as discussed in sectich 7.g bel ow. Wisconsin Electric is continuing to confront these individual issues and remains in the midst of a multi-year maintenance procedure upgrade project'to address the generic issue.
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d.
(Closed) Violation (266/92015-01):
Red Tagged Equipment Improperly Reconnected by Contractor Employee
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On July 24, 1992, a battery cable on the G-501 auxiliary diesel was found_ connected to its battery despite its being red tagged.to preclude such connection. A contractor who was working on this equipment connected the cable after completing his work, without obtaining proper clearance' authority to remove the red tag.
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had not received adequate training to understand the plant's red tag requirements. No injuries or equipment damage occurred.
As corrective action, procedure PBNP 4.13, " Equipment Isolation Procedure", was revised to include a requirement that the contractor liaison, who is responsible for oversight of contractor work activities, sign the equipment isolation tag record sheet.
This is' intended to alert the contractor liaison to provide either equipment isolation training or an orientation brief, as i
appropriate, to contractors involved in work on tagged equipment.
Subsequently, PBNP 4.13 was replaced by a new procedure (0M 3.16,
" Equipment Isolation Procedure"), which further enhanced the
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equipment isolation process by defining high energy systems and specifying redundant barriers for their isolation The inspector reviewed these procedure changes and had no further-concerns.
e.
(00en) Inspection Follow Vo Item (301/93006-02): Unit 2 "A" Steam Generator Tube Leakage
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On January.12, 1993, the Unit 2 A steam generator began exhibiting intermittent slight increases in-its primary to secondary leakage rate. This was noted by elevated radiation levels detected by the 2RE-219 common steam generator blowdown monitor. These " burps" occurred about three times per week and continued until the autumn Unit 2 outage. Chemistry analysis estimated the volume of coolant l
released during one of these " burps" at about one gallon. The technical specification limit is 500 gpd.
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The mechanism causing this phenomena was believed to be a tight crack in a plugged steam generator tube with leakage past the plug. The plant discussed this phenomena with the steam generator vendor and believes there-is no immediate safety concern over tube failure.
l Leakage Increased _after 1993 Refueling Outage l
A pressure test was performed on the steam generators during the autumn 1993 refueling outage but no leakage was identified past any of the plugs. When the unit was subsequently returned to service, the " burps" did not resume as before. There were a few minor perturbations of radioactivity on the steam generator
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blowdown monitor reminiscent of the " burps", but on a much smaller scal e.
However, overall primary to secondary leakage increased
slightly, to about 18 gpd, from values experienced prior to the outage. An administrative limit of 40 gpd exists to trigger increased sampling of the leak rate.
Further Rise in Leakage after Turbine Stop Valve Testing After performance of Unit 2 turbine stop valve testing on l
December 23, 1993, the leak rate increased to about 24 gpd. The cause was attributed to the thermal transient associated with the power reduction accompanying the test. Additionally, although the
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data scatter is quite large (i.e., ranging from 13 to 33 gpd), a I
slight upward trend in the leak rate developed.
Average leakage increased from 24 gpd in January to 27 gpd by mid March.
An unrelated power reduction performed on February 27 was larger than that associated with turbine stop valve testing and yet this power reduction did not appear to affect the leak rate.
Inspector's Evaluation The licensee exhibited a responsive attitude towards addressing this issue. A heightened awareness of this leakage was present among responsible personnel and the chemistry manager was l
i knowledgeable of the details. Additional controls exist for l
increased monitoring if leakage exceeds the 40 gpd administrative I
limit. The inspector believes that the licensee has adequate l
controls in place for monitoring and evaluating this leakage.
l This issue will continue to be followed to determine any further
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changes in leak rate. Unit 2 steam generator replacement is scheduled for 1996, f.
(Closed) LER 266/301/94-001:
Failure to Perform a Fire Watch at the Technical Specification Frequency Fire rounds were not performed at the required technical specification frequency during a period when the Halon fire suppression system for the auxiliary feedwater pump room and the vital switchgear room was disabled in support of modifications.
Twice per shift vice hourly fire rounds were performed.
As discussed in Inspection Report 266/93002, this violation was
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not cited. Operators subsequently commenced hourly fire rounds l
and shortly thereafter, restored the halon system to operation.
l A review of this event determined that appropriate procedures were in place to ensure compensatory actions were carried out. Due to
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the lack of history of a similar occurrence, this was considered
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i an isolated event. The inspector discussed this issue with plant
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management and had no further concerns.
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(Closed) LER 266/301/94-002:
Inoperability of Both Emergency i
Diesel Generators An emergency diesel generator failed during daily testing while the second diesel was already out of service for maintenance.
The diesel generator failure was due to improperly performed maintenance that caused an excitation field cable to contact the generator rotor. The rotor's rubbing against this cable wore off the insulation and caused a short circuit.
An Unusual Event emergency classification was declared based on the loss of both trains of standby emergency power.
As discussed in Inspection Report 266/94002, the NRC granted
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enforcement discretion to allow additional time to return one I
diesel generator to service. The failed diesel was repaired about two hours after granting of the enforcement discretion.
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A violation was cited for improper maintenance because of the safety significance of both diesels being rendered inoperable at the same time and because multiple work process controls that j
could have prevented this event were not adequately folled.
Safety Assessment Contained Minimal Details The safety assessment of this event was not thoroughly developed.
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l Minimal details were provided regarding the implications of both diesels being inoperable. The failure mode of the diesel was evaluated and its operational capability was determined based on total run time to failure.
However, no evaluation was made regarding the implications of the diesel only being able to run 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> when the safety analysis assumes 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
The inspector
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discussed this facet with the report's author. Wisconsin Electric engineers had separately provided additional requested information
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to the NRC to facilitate assessment of this event.
h.
(Closed) LER 266/301/94-003:
Reactor Coolant Sample System Containment Isolation Valve Testing One of two automatic isolation valves on a 3/8 inch coolant sample line was found to not be missile protected. A manual valve in the same line, designated in the FSAR as a backup isolation valve, was
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not in the plant's containment valve leak testing program.
As discussed in Inspection Report 266/93002, plant management justified continued operation, on an interim basis, based on the
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low orobability of a missile event damaging one automatic valve coincident with a failure of the other automatic valve.
An evaluation had already been in progress to reclassify the containment isolation valves in accordance with current design criteria: This project resulted in the identification of the
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current condition in this system. An update to the FSAR was planned for 1994. Additional evaluation by plant engineers will
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determine whether missile protection needs to be added for the valve identified in this report. Corrective actions and the inspector's evaluation will be tracked via the unresolved item regarding this issue (266/94002-03).
i.
(Closed) Licensee Event Report No. 91-S01-00:
Licensee Not Notified of Positive Drug Test Results for Contractor Employee On August 14, 1991, the licensee submitted the above report to advise the NRC that a contractor failed to advise them of a contractor employee's past positive drug tests. Therefore this employee was not given the required management and medical evaluations of fitness for duty (FFD) prior to being granted access to the Point Beach Nuclear Plant. Access had been granted on October 3, 1990 and January 11, 1991.
10 CFR 26.23(a)(2) prohibits a person denied access at any nuclear power plant from being assigned to work within the scope of 10 CFR Part 26 without the knowledge and consent of the licensee.
10 CFR 26.27(a) requires a management and medical determination of fitness for duty to be performed if an individual granted unescorted access had a prior positive FFD test result.
Contrary to this requirement, on July 15, 1991, a contractor (Nuclear Support Services, Inc.) requested access to the Point Beach Nuclear Plant for an employee who had past positive FFD test results and failed to advise the licensee of this fact.
This violation is not being cited because the criteria of 10 CFR Part 2, Appendix C, Section VII,B(2) were satisfied.
Subsequent enforcement action has been taken against the contractor security manager and the contractor (Nuclear Support Services, Inc.).
Wisconsin Electric initiated an investigation of the incident and followed up with aggressive corrective actions. The investigation results concluded that the contractor failed to advise the licensee of the employee's past positive test results.
An NRC Office of Investigations investigation was also completed and as a result NRC Orders were issued to both the contractor security manager and the contractor prohibiting the manager's participation in NRC licensed activities for at least 5 years.
. SYN 0PSIS OF 0FFICE OF INVESTIGATIONS RESULTS.
(NUCLEAR SUPPORT SERVICES. INC.)
On November 14, 1991, the Regional Administrator, U.S. Nuclear Regulatory Commission, Region III, requested an investigation concerning an allegation that Nuclear Support Services,
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Incorporated (NSSI), deliberately falsified documents.
These
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documents had been sent to corporate security representatives at Northern States Power Company (NSP) and Wisconsin Electric Power Company (WEPCo) to allow NSSI employees to gain unescorted access to the NSP Prairie Island Nuclear Generating Plant and WEPCo Point
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Beach Nuclear plant. An additional investigation was requested to determine if the alleged record falsification was the result of one person's independent action or the result of NSSI management's policies or practices. The investigation was also to determine if j
management of any of the involved parties was culpable in the i
transfer of false information.
The investigation revealed that the NSSI security manager deliberately provided falsified documents to NSP and WEPCo to allow NSSI employees to gain unescorted access to the NSP Prairie Island and WEPCo Point Beach nuclear plants. The
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investigation revealed that this action was the result of one
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person's independent action and not the result of NSSI management's policies or practice. The investigation determined that no management of any of the involved parties was culpable in
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the transfer of false information.
During the investigation,
however, an allegation surfaced that the manager of security for
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NSSI deliberately made material false statements to an Office of j
Investigations, RIII, investigator. The evidence developed during i
the investigation substantiated that the manager of security
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deliberately made material false statements to the NRC investigator.
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Inspection Follow UD Items l
Inspection follow up items are matters which have been discussed with Wisconsin Electric management, will be reviewed further by the inspector, and involve some action on the part of the NRC, company or
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both. A follow up item disclosed during the inspection is discussed in section 2.c.
Unresolved Item Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, items of
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noncompliance, or deviations. Unresolved items disclosed during the inspection are discussed in sections 1.c, 3.a, 6.a and 7.h.
8.
Exit Interview (717071 A verbal summary of preliminary findings was provided to the Wisconsin Electric representatives denoted in Section 9 on April 19, at the conclusion of the inspection.
Information highlighted during the meeting is contained in the Executive Summary. No written inspection material was provided to company personnel during the inspection.
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l The likely informational content of the inspection report with regard to i'
documents or processes reviewed during the inspection was also i
discussed. Wisconsin Electric management did not identify any documents
or processes that were reported on as proprietary, l
9.
Persons Contacted (71707)
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- J. E. Anthony, Quality Assurance Manager
- J. F. Becka, Regulatory Services Manager
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J. J. Bevelacqua, Manager - llealth Physics j
- A. J. Cayia, Production Manager i
- F. A. Flentje, Administrative Specialist
W. B. Fromm, Sr. Project Engineer - Plant Engineering
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- L. D. Halverson, Site Services Manager.
I F. P. Hennessy, Manager - Chemistry j
W. J. Herrman, Sr. Project Engineer - Construction Engineering l
N. L. Hoefert, Manager - Production Planning
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T. J. Koehler, Site Engineering Manager j
- G. J. Maxfield, Plant Manager
J. A. Palmer, Manager - Maintenance j
S. A. Patulski, Nuclear Engineering Manager
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J. C. Reisenbuechler, Manager - Operations
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l J. G. Schweitzer, Maintenance Manager
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j R. D. Seizert, Training Manager
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G. R. Sherwood, Manager - Instrument & Controls l
T. G. Staskal, Sr. Project Engineer - Performance Engineering
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Other company employees were also contacted including members of the
technical and engineering staffs, and reactor and auxiliary operators.
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- Denotes the personnel attending the management exit interview for summation of preliminary findings.
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