ML20138D565
| ML20138D565 | |
| Person / Time | |
|---|---|
| Site: | Byron  |
| Issue date: | 04/23/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20138D524 | List: |
| References | |
| 50-454-97-02, 50-454-97-2, 50-455-97-01, 50-455-97-1, NUDOCS 9705010166 | |
| Download: ML20138D565 (20) | |
See also: IR 05000454/1997001
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- U. S. NUCLEAR REGULATORY COMMISSION
REGION lit
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Docket Nos: 50-454, 50-455
Report No: 50-454/97002(DRP); 455/97002(DRP)
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Licensee: Commonwealth Edison Company
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Facility: Byron Generating Station, Units 1 & 2
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- Location
- 4450 N. German Church Road <
Byron, IL 61010 l
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Dates: February 1 through March 13,1997
Inspectors: S. D. Burgess, Senior Resident inspector
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N. D. Hilton, Resident inspector
S. K. Orth, Radiation Specialist
C. K. Thompson, Illinois Department of Nuclear Safety
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Approved by: Roger D. Lanksbury, Chief,
Reactor Projects, Branch 3
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9705010166 970423
PDR ADOCK 05000454
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EXECUTIVE SUMMARY
Byron Generating Station, Units 1 & 2
- NRC Inspection Report 50-454/97002, 50-455/97002
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This inspection included aspects of licensee operations, engineering, maintenance, and ,
, plant support. The report covers a 6-week period of resident inspection.
} Operations
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The Unit 1 shutdown demonstrated very good operator performance.
- Communications, command and control, and operator control of equipment were all
j performed well (Section 01.2).
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The operator performance during the Unit 1 startup was excellent. Strong
l command and control of all reactivity changes was demonstrated by the startup I
senior reactor operator (Section 01.3).
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Radweste operators operated in a nonconservative manner by relying on level
, alarms for primary levelindications. Conflicting standards apparently existed
between non-licensed operators and licensed operators. The failure to follow Byron
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Operating Procedure (BOP) WX-121 was a violation of Technical Specification 6.8.1.a (Section 01.4).
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Maintenance
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Appropriate actions were taken to restore the diesel generators (DGs) to fully
! operable after the identification of missed diesel oil storage tank (DOST) hydrostatic
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tests. Although the first required alternate ac sources surveillance was missed, the
operators identified the error and immediately performed the surveillance. The
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missed alternate ac sources surveillance was a licensee identified and corrected
i violation and therefore was treated as a Non-Cited Violation. The missed DOST
, hydrostatic test was a licensee identified and corrected violation and therefore was
- also being treated as a Non-Cited Violation (Section M1.3).
- The inspectors agreed with the licensees conclusion that since 1985-1986, the 1 A
. residual heat removal (RH) and 1B containment spray (CS) pumps were technically l
i inoperable due to an error in the thrust bearing installation. Two violations were l
Issued for failure to meet the action statements of TS 3.5.2 and TS 3.6.2.1. The
inspectors also concluded that the maintenance performed during this inspection
period on the residual heat removal and containment spray pumps was poor. The
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foreign material intrusion events had precursors identified by the NRC. The
inspectors concluded that SMP-M-04 " Foreign Material Exclusion" was inadequate
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to prevent foreign materialintrusion. A Notice of Violation was issued for failure to
meet the requirements of 10 CFR 50 Appendix B Criterion V. The inspectors
considered the post-job critique a very good self-assessment by the maintenance
department (Section M1.4).
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The Unit 2 pressurizer spray valve oscillation work package failed to identify to the
operators that power operated relief valve (PORV) actuation was possible, although
not expected. Additionally, the operators could have prevented the event by a
complete and thorough review of the work plan. The failure of the work package to
identify the PORV as potentially affected by the card removal and replacement was ;
considered a violation of 10 CFR Part 50, Appendix B, Criterion V, " Instructions,
Procedures and Drawings," (Section M1.6).
Engineering
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Proactive performance was demonstrated in diagnosing an essantial service water
flow degradation to the reactor containment fan coolers (RCFCs) through monthly
surveillance trends. The modification design change package met design and
regulatory requirements. The modification and installation and testing was
l accomplished in an appropriate manner (Section E2.1). ;
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The inspectors noted that a field change located on the service air system in Unit 1 l
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containment did not rr,ceive a seismic evaluation. Failure to ensure field changes i
i are subject to design control measures commensurate with those applied to the :
original design is a violation of 10 CFR Part 50, Appendix B, Criterion lil, " Design
Control," (Section E2.2).
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Failure to enter the essential service water limiting condition for operation for I
l flushing auxiliary feed water as required by the original modification safety
evaluation was a violation of 10 CFR 50, Appendix B, Criterion lil, " Design
Control," (Section E8.1).
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A Ner.-Cited Violation was identified for failure to maintain design control of
480 voit air circuit breakers (ACBs). A licensee event report documented the
identification of 480 volt ACBs in the removed position vice the qualified disconnect
position (Section E8.2).
l Plant Suonort
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The overpressurization and damage of the regen waste drain tank (RWDT) did not
l result in significant radiological effects and the radiological protection cleanup
l activities were appropriate (Section R4.1).
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REPORT DETAILS
Summary of Plar't Status
Unit 1 operated at or near full power until February 13,1997, when a steam leak on the
1C main feedwater pump gland water retum line forced the operators to reduce power to ,
approximately 20 percent. On February 14,1997, the licensee shut down Unit 1 to repair
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the gland water pipe and began a scheduled 12-day maintenance outage. The outage was
scheduled to clean and inspect the essential service water heat exchangers in the 1C and
1D reactor containment fan coolers. During the cooldown, the 1 A residual heat removal
- (RH) pump developed a mechanical seal leak. The thrust bearings for the 1 A RH and 1 A
and 1B containment spray pumps were subsequently identified to be installed incorrectly.
Repairs extended the outage to March 5,1997. Unit 1 operated at or near full power for
the remainder of the inspection period.
! Unit 2 operated at power the entire inspection period. On March 11,1997, a circulating
l water box leak required the Unit to reduce power to approximately 60 percent for
- chemistry control. The leak was repaired and the unit returned to full power.
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1. Operations
01 Conduct of Operations
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l 01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of
ongoing plant operations. In general, the conduct of operations was professional
! and safety-conscious. Observations indicated that the control room staffing levels
l were appropriate and operations staff was knowledgeable of plant conditions,
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responded promptly and appropriately to alarms, and performed thorough turnovers.
Specific events and noteworthy observations are detailed in the sections below.
Additionally, Section M1.5 discusses an unexpected Unit 2 pressurizer PORV
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momentary lift that operators could have prevented.
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l 01.2 Unit 1 Shutdown and Cooldown Activities (71707)
On February 14,1997, the inspectors observed significant portions of the Unit 1
shutdown. The inspectors observed that operators adhered to procedures, and
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were cognizant of system configuration and applicable precautions. Operator
j communication and annunciator response was very good throughout the activities
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observed. The inspectors concluded that the shutdown demonstrated very good
operator performance.
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01.3 Unit 1 Starton OWations (71707)
The inspectors observed significant portions of the Unit 1 startup. On March 5,
1997, Unit 1 achieved criticality. A comprehensive briefing was held prior to the
startup that included detailed responsibilities and several lessons leamed. The
inspectors observed the operators perform a slow and deliberate approach to
criticality. Strong command and control was demonstrated by the startup senior
i reactor operator (SRO) Nuclear engineer support was utilized in a non-intrusive
! manner and all other activity was minimized. A very conservative approach to the
l control of reactivity was observed, including a dedicated reactivity manager, formal
approval of the startup SRO for each reactivity change, and small reactivity
changes followed by a period of time sufficient to allow the changes to take effect.
l The inspectors considered the operator performance observed during the startup to
be evcellent.
01.4 Reoen Waste Drain Tank Overfilled /Overoressurized
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a. Insoection Scone (84750)
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The inspectors reviewed the operational aspects of the RWDT overpressurization
event that occurred on February 17,1997. The inspectors interviewed rsdweste 1
operators involved in the event and reviewed Byron Operations Procedure (BOP) I
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WX 121, " Release Tank Transfer to 22,000 Gallon Regen Waste Drain Tank,"
Revision 3.
b. Observations and Findinas
On February 17,1997, the licensee determined that the activity of the water in
release tank, OWXO1T (4x104 microcuries per cubic centimeter gross gamma) was
somewhat high and that the contents should be sent back to radweste for further
processing. The 30,000 gallon release tank was filled to about 85 percent
(i.e.,25,000 gallons). Radwaste operations staff planned to transfer the contents
of the tank to the RWDT, a 20,000 gallon capacity tank. During the transfer
lineup, the operators conducted a tumover. The replacement operator indicated
that the tumover was very comprehensive and that the course of the evolution was
understood. The operator was fully aware that the volume of water in the release
tank was greater than the capacity of the RWDT.
Based on the operating practices at the radwaste panel, the operator did not
monitor level indications of the tank (analog readout and chart recorder). Operating
practice at the radweste panel was to use the high level alarm as the primary
m ens of full level indication. However, the operator did not realize that the low
!cual alarm (at 29%) for the RWDT had been activated and not reset.
Consequently, the RWDT high lovel alarm (at 80%) was disabled by the presence of
the low level alarm. Procedure BOP WX-121, Step 15, required operators to
monitor the release tank ar's the regen waste tank level recorders. Failure to follow
procedure BOP WX-121 is a violatico of Technical Specification (TS) 6.8.1.a
(50-454/455-97002-01(DRP)). ,
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I Approximately 30 minutes into the transfer operation, the operator heard a muffled
bang. About 3 minutes later, the operator heard another muffled sound and
received a low alarm on the release tank at a level of 12% or about 3500 gallons. '
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The operator secured the transfer at this point. Based on the change in level of the
release tank, approximately 22,000 gallons had been transferred to the RWDT.
The 2 inch diameter RWDT overflow line was incapable of relieving the overfill of
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the RWDT. As a result of the pressure buildup, the RWDT was grossly deformed
and pulled away from its concrete support pedestal. A weld located on the top of
the tank fractured spilling .e small amount of radioactive water in the tank room.
Although some contents went onto the floor, radiological contamination was
minimal, and the floor drain handled the volume. No personnel injury,
overexposure, or contamination resulted from the event.
Although this event occurred on a nonsafety-related system, the inspectors were
concerned that the non-licensed operators operated with different standards than
licensed operators. Since non-license operators have post accident response
activities that directly affect the ability to safely shutdown and sustain the
shutdown of the reactor, expectations and conduct of operations should be the
same for both licensed and non-licensed operators.
Through operator interviews, Byron operation's management determined that
expectations for the radweste operators had not been clearly defined and were
indeed perceived as different. Radwaste operator meetings were held to discuss
the event with radwasts operation expectations clearly stated. Radweste operators
were not to rely on level alarms as primary level control measures in lieu of
monitoring panel parameters per procedures. The licensee initiated a root cause
investigation for the event and upon evaluating the tank damage, determined to
replace the tank.
c. Conclusions
Radweste operators operated in a nonconservative manner by relying on tank level
alarms for primary level indications. The inspectors were concerned with the
conflicting operating standards that existed between the radweste control room and
the main control room, since non-licensed radwaste operators performed many
post-accident activities under the direction of licensed operators. Although ,
significant tank damage occurred, the overpressurization created little radiological l
effect in the area. The contamination from the overfill was minimal. l
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11. Maintenance !
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i M1 Conduct of Maintenance l
M1.1 Maintenance Observations (62703)
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The inspectors observed all or portions of the following work activities:
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. WR 960113747 Troubleshoot DG Ventilation System Temperature indicator i
Controller
. WR 97002062 Clean Containment Spray cubicle cooler
. WR 960119251 Clean Essential Service Water strainer
WR 970025538 Pressurizer Pressure Control Appears to Drift
. WR 970014351 Troubleshoot and Repair 2A Component Cooling Water Pump
inboard Motor Bearing
b. Obmarvations and Findinas ,
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The inspectors found that the observed maintersance activities were conducted in
accordance with approved procedures and were in conformance with technical
specifications. The inspectors observed maintenance supervisors and system
engineers monitoring job progress. Quality control personnel were also present.
When applicable, appropriate radiation control measures were in place.
M1.2 Surveillance Observations (61726)
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a. Insoection Scone !
The inspectors observed the performance of all or parts of the following
surveillance procedures. The inspectors also reviewed plant equipment and
surveillance activities against the Updated Final Safety Analysis Report (UFSAR)
descriptions.
2BOS 3.2.1-816 Unit 2 Train B Automatic Safety injection - K611 Slave
Relay Surveillance
2BOS 8.1.1.2.a-2 2B Diesel Generator Operability Semi annual Surveillance
1 BVS 0.5-3.CC.1-1 Unit 1 ASME Surveillance Requirements for Component
Cooling Pump 1CC01PA
1BOS 4.9.1.1-1 Unit 1 Reactor Coolant System Pressure / Temperature Limit
Surveillance
1BOS 4.9.2-1 Unit 1 Pressurizer Temperature Limit Surveillance
1BVS XPT-12 inverse Count Rate Ratio Procedure
1 BIS 3.1.1-226 92-Day Surveillance Calibration for Nuclear Instrumentation j
System Power Range N41 - N44 i
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I b. Obaarvations and Findings ,
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The inspectors routinely noted proper authorization from the control room SRO prior !
to the start of each surveillance. Components removed from service were identified
prior to the surveihnce and the proper TS limiting condition for operation (LCO)
was ontored. At the ct. repletion of the surveillance and after independent ,
verification of system r6storation, the TS LCO was cleared. Test instruments used '
were verified by the in$.:. ors to be calibrated as applicable. The inspectors
reviewed completed surveillances and verified the surveillances met the acceptance
criteria and conformed with the UFSAR.
M1.3 Missed Surveillance on 1 A. 2A and 2B Dinaal Oil Storage Tanks
s (Cic. sed) LER 50-454-97-01:
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- s. Insoection Scone (61726. 92700 and 92903)
- The inspectors reviewed the application of TS 4.0.3 after the licensee identified a
j missed surveillance that caused 3 diesel generators (DGs) to be inoperable. The
I inspectors independently developed a chronology and interpretation of TS 4.0.3 as
] applicable to the DG. The inspectors also reviewed the licensee event report (LER)
j documenting the event.
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b. Observations and Findings
i The inspectors reviews determined that the licensee identified on January 31,
, 1997, that a TS surveillance had not been completed within the allowed frequency
for the 1 A DOST. TS 4.8.1.1.2.h.2 required a hydrostatic test to be performed
i overy 10 years. At 3:40 p.m. on January 31,1997, the licensee declared the 1 A
! DG inoperable. TS 3.8.1.1.a required restoration of a single inoperable DG within
- 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. At the time the 1 A DG was declared inoperable, the hcensee believed
- that the 18 and both Unit 2 DOSTs were operable based on verbal reports from
{ construction engineers. The enginsors believed the hydrostatic tests had been
l performed about 1986. However, the quality assurance records retrieved on
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February 1,1997, indicated that the 2A and 28 DOSTs had not met the required
i TS surveillance frequency. The licensee then declared both 2A and 28 DGs
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- TS 4.0.3 allowed a 24-hour delay in the action requirements to permit the
i completion of the surveillance when the allowed outage time limits of the action
l requirements are less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. TS 3.8.1.1.c.2 required the other unit's A DG l
J to be operable if the affected unit's inoperable DG was the power supply to the
j motor-driven auxiliary feedwater pump. The TS allowed 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> to restore a DG or
j be in hot standby in the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Since both 1 A and 2A DGs were inoperable
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due to the missed surveillance, TS 4.0.3 was appropriately applied and 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for
completion of the required surveillances was allowed.
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Additionally, TS 3.8.1.1.e required restoration of one of the two Unit 2 DGs to
operable within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or be in hot standby within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
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. TS 4.0.3 was also appropriately applied to delay the action requirement for
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
At 4:52 p.m. on February 1,1997, the licensee pirced the 2A DG in "Mentenance
Outage" to prevent its start while the fuel transfe' system was being teste1.
During the shift change, the licensee determined that the action requirements of
TS 3.8.1.1.s were applicable because the DG v,as inoperable for reasoru other than i
the missed surveillance. With a DG inoperable, the normal altamate ac sources
surveillance required by TS 3.8.1.1.a was required to be completed within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. ;
The licensee did not complete the normal rjternate ac sources surveillance until ;
approximately 2% hours after placing the 2A DG in Maintenance Outage.
The hcensee determined the cause of the missed hydrostatic test to be deleting the
surveillance from the surveillance tracking system based on relief granted for the
inservice inspection requirements. However, at the time, the licensee did not
identify that the hydrostatic test requirement existed in the TS also. Later
identification of the conflict and appropriate resolution was prevented by confusion
over the frequency start time for ASME requirements versus TS surveillance j
requirements.
The inspectors reviewed the licensee's LER and corrective actions. Corrective
actions included a change to require review of the TS surveillance list prior to
deleting a surveillance from the general surveillance list. The inspectors discussed
the corrective actions with the licensee. The licensee noted that there was
additional corrective action to search for additional instances where an ISI
requirement was deleted and a TS surveillance still existed that was undocumented
in the LER.
The missed DOST hydrostatic test was a licensee identified and corrected violation
of TS 4.8.1.1.2.h.2 and therefore is being treated as a Non-Cited Violation,
consistent with Section Vll.B.1 of the NRC Enforcement Policy
(50-454/455-97002-02(DRP)).
The missed altamate ac surveillance was a result of misunderstanding TS 4.0.3.
Section 4.0.3 clearly allowed TS action requirements to be delayed for up to
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> if the allowed time was less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. However, Section 4.0.3 is
not clear on the action to take when performing the required surveillance actually
makes the equipment inoperable. Corrective actions committed to by the licensee
included improving the TS 4.0.3 guidance, improving the TS 4.0.3 pages during the
improved Technic)I Specification project, and a review of the interpretation with all
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SROs.
The missed altamate ac sources surveillance was a licensee identified and corrected
violation and therefore is being treated as a Non-Cited Violation, consistent with ,
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Section Vll.B.1 of the NRC Enforcement Policy (50-454/455-97002-03(DRP)).
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. c. Conclusions
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The inspectors concluded that the licensee took appropriate actions to restore the i
DGs to fully operable after the identification of the missed hydrostatic tests. The :
inspector also concluded that although the first required alternate ac sources l
survedlance was missed, the operators identified the error and immediately
performed the surveillance. .
M1.4 Unit 1 Pa=Wai Heat Removal and Containment Snrav Pumn Saal and Thrust l
Branna Replacements
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a. kuoection Scone
The inspectors reviewed maintenance performed on the 1 A residual heat removal
(RH) and 1 A and 1B containment spray (CS) pumps, including current and past
work instructions, station procedures, and the post-job critique. The inspectors
also had several discussions with maintenance management during the work
process.
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h. Observations and Rndings
During the Unit 1 shutdown and subsequent cooldown on February 15,1997, the
1 A RH pump mechanical seal failed. Tne licensee completed the cooldown using
the 1B RH pump and replaced the seal on the 1 A RH pump. During reassembly, the
pump impeller galled the pump shaft. While the licensee was removlng the
impeller, they identified that the axial end play for the shaft exceeded the vendors
allowed tolerance. After additional investigation, the licensee identified that the
upper thrust bearing was installed upside down, allowing excessive upward
movement of the rotor during pump starts. This was based on axial end play as a
confirmation criteria for proper thrust bearing assembly. The inspectors agreed
with the licensee's conclusion that the upward motion of the motor shaft was the
root cause of the seal failure.
The licensee's review of the Unit 1 RH and CS pump wor c history indicated that
the work packages used to assemble these pumps did nr.t address the installation
of the thrust bearings. Based on excessive axial and play, both the 1 A and 1B CS
pumps were disassembled and the thrust bearings replaced. The axial end play for
the 18 RH pump was acceptable.
The licensee identified that the work instructions for the Unit 2 RH and CS pumps l
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were significantly improved compared to the original work instructions used for
Unit 1. The procedures for Unit 2 had specific directions for installation of the
thrust bearings. The licensee did not have plans to immediately inspect the Unit 2
RH and CS pumps based on the improved procedures. The inspectors reviewed the
procedure differences and agreed with the licensee.
Based on the incorrectly installed thrust bearings, in combination with the type of
seal installed, the licensee determined that the 1 A RH and 1B CS pumps were
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a considered to be inoperable since the 1985/1986 time frame when these bearings
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were installed. Technical Specification (TS) 3.5.2 required that two independent
- emergency core cooling system (ECCS) subsystems shall be operable, with each
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subsystem including one operable RH pump in Modes 1,2, and 3. Action
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statement a. required that with one ECCS subsystem inoperable, the licensee must
restore the inoperable subsystem to operable status within 7 days or be in at least
hot standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Failure to follow TS3.5.2.s is considered a '
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violation (50-454/97002-04(DRP)). TS 3.6.2.1 action statement required that with !
one CS system inoperable, the licenses must restore that inoperable spray system
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to operable status within 7 days or be in at least hot standby within the next
6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Failure to follow the requirements of TS 3.6.2.1 is also considered a ,
violation (50-454/97002-05(DRP)).
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4 However, based upon operational history, which included over 11 years of
j successful ASME p.4mp runs, surveillances, and other required operation (shutdown
- cooling) of the 1 A RH and 1B CS pumps, the licensee and the inspectors concluded
i that the pumps were considered available. 1
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The inspectors reviewed maintenance and operating records for instances when the
j 1B RH and 1 A CS trains were taken out of service. For example, the inspectors
- identified that on August 5,1996, the 1B RH pump was out of service for
approximately 10.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> for maintenance. During this time both trains of RH were
l considered inoperable. The inspectors also identified that on August 5,1996, both
j the 1 A and 1B residual heat removal pumps were inoperable from 3:00 a.m. until
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1:30 p.m. Additionally, from 10:20 p.m. on August 7,1996, until 3:55 p.m.
August 9,1996, both the 1 A and IB RH pumps were inoperable. This was outside
the LCO of TS 3.A.2.1 that one CS pump be operable. TS 3.0.3 required that
j when an LCO was not met, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, action shall be initiated to place the unit
- in a mode in which the sp6cification does not syply. Since there was no evidence
l st the time indicating the violation of TS 3.0.3 to the licensee and the violations
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i (50-454/97002-04 and 05(DRP)) above address the TS's, no additional citation will
i be issued for violation of TS 3.0.3.
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- During the 1B CS pump post maintenance runs on February 28,1997, operators
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identified that excessive thrust bearing temperatures existed. The licensee
- disassembled the pump and identified a piece of foreign material (later identified to
be a piece of paint coated cork gasket approximately 1 inch wide,3 inches long
l and 0.050 inches thick) between the seating surfaces of the bearing housing. This
caused a misalignment of the thrust bearing and was considered by the licensee to i
be the cause of the high bearing temperatures.
The licensee also identified a piece of foreign materialin the 1 A CS pump while
restoring the pump to service after the thrust bearing replacement. Excessive seal
leakage was noted by the operators while filling the system on March 2,1997.
_ The licensee disassembled the 1 A CS pump again and identified a piece of paint
i
approximately 1/2 inch long and 3/8 inch wide between the mechanical seal seating
] surface and carbon insert.
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s The inspectors had discussed foreign material exclusion (FME) weaknesses with the
licensee recently. NRC inspection reports 96-04 and 96-12 documented the
i inspectors review of a new corporate FME procedure, SMP-M-04, " Foreign Meterial
l Exclusion," Revision O. The inspectors had several discussions at the time with the
l licensee about weaknesses in SMP-M-04, specifically FME area controls and
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practices that were implemented only at the maintenance supervisor's discretion.
'
Several poor FME practices were identified during observations during that period;
! however, the licensee was not concerned because any foreign material would be
identified in a close-out inspection after maintenance performance. The inspectors
considered this to be a poor practice for implementing FME controls.
The inspector considered the foreign material events on February 28 and March 2,
1997, two examples of an inadequate FME procedure; specifically, the controls of
SMP-M-04 failed to prevent the entrance of foreign material into the 1 A and 1B CS
pumps. The inspectors considered this an example of a violation of 10 CFR
Part 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings,"
(50-454/455-97002-06a(DRP)).
The licensee conducted a post-job critique and noted numerous problems during the
work on the RH and CS pumps. Licensee identified issues included the galled
impeller, poor rigging practices, poor FME practices, weak procedures, and a loss of
oversight function by the foreman. The critique also identified corrective actions
for all of the issues.
c. Conclusions
The inspectors agreed with the licensees cor. zion that since 1985-1986, the 1 A
residual heat removal (RH) and 1B containment spray (CS) pumps were technically
inoperable due to an error in the thrust bearing installation. Two violations were
issued for failure to meet the action statements of TS 3.5.2 and TS 3.6.2.1. The
!aspectors also concluded that the maintenance performed during this inspection
period on the RH and CS pumps was poor. The foreign material intrusion events
had precursors identified by the NRC. The inspectors concluded that SMP-M-04
was inadequate to prevent foreign materialintrusion. A notice of violation was
issued for failure to meet the requirements of 10 CFR Part 50, Appendix B,
Criterion V. The inspectors considered the post-job critique a very good
soif assessment by the maintenance department.
M1.5 Unexnected Plant Transient Due to Unit 2 Pressurizer PORV Lift
a. Insoection Scone
,
The inspectors observed the results of an inadvertent pressurizer PORV lift on
'
Unit 2. The inspectors were observing the Unit 1 startup and noted the
l annunciators and activity on Unit 2. The inspectors then discussed the event with
the operators and instrument maintenance (IM) personnel involved. Additionally,
the inspectors reviewed the original and revised work packages for troubleshooting
the oscillating spray valve.
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o b. Observations and Findings
)
l On March 5,1997, the licensee identified that the pressur!zer spray valves were
osedleting while in automatic control. The operators notified IM personnel who
, prepared WR 970025538 to troubleshoot the oscillation. The troubleshooting
l procedure required the spray valves to be placed in manual.
The IMs removed the circuit card to inspect for heat damage. When the card was
replaced, PORV 2RY455A lifted for approximately 1 second. The inspectors
observed that the operators immediately determined that the cause was not actual
pressure.
The inspectors reviewed the drawings with both the IMs and the operators. The
drawings indicated that the control signal for the PORV could be interrupted.
However, the inspectors noted that the work request the IMs were working under
and had discussed with the operators did not mention anything other than placing
the spray valves in manual. The inspectors considered the failure of the work
package to identify the PORV as potentially being affected by the card removal and
replacement an inadequate procedure and an example of a violation of 10 CFR
Part 50, Appendix B, Criterion V, " Instructions, Procedures and Drawings,'
(50-454/455-97002-06b(DRP)).
The inspectors also noted that the operators could have identified the potential for
the PORV to lift during the work review and authorization process. Although the
work package did not identify the PORV, the prints showed that the PORV could be
affected by work on the spray valve circuit.
On March 7,1997, after appropriate review, the IMs connected a recorder to the
suspect circuit card, verified the card required replacement, then replaced and
calibrated the card using Byron Instrument Surveillance (BIS) 3.1.1-206,
" Calibration of Pressurizer Pressure Protection Channel 1, Test Report Package."
The inspector verified the revised procedure required the PORV to be placed in
" Closed" and pressurizer heaters in manual control. ,
!
c. Conclusions
The inspectors concluded that the work package failed to identify to the operators
that PORV actuation was possible, although not expected. Additionally, the
operators could have prevented the event by a complete and thorough review of
the work plan.
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Ill. Engineerina
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E2 Engineering 8. pport of Facilities and Equipment
E2.1 Review of Unit 1 Rametor Containment Fan Coolers C and D Modification (37551)
a. Inanection Scone
The inspectors reviewed design change package (DCP) 9700039, which replaced
existing 3/4 inch drain valves to allow back flush of the essential service water (SX)
cooling coils in the C and D reactor containment fan coolars (RCFC). The ,
modification installation was the main purpose for the Unit 1 forced outage. The l
inspectors also reviewed and followed the associated special plant procedure';
associated with the implementation and testing of this modification.
b. Observations and Findinas
During the last 3 months, the licensee noted a marked decrease in the thermal
performance of the C and D RCFCs during monthly surveillance testing. The
licensee suspected that the degraded thermal performance was due to debris
limiting the flow of SX, which provided cooling water to the RCFCs where heat was
transferred from the containment atmosphere to the SX system. As documented in
NRC inspection report 96-09 the SX cooling tower was found to contain excessive
levels of silt and broken pieces of cooling tower clay tile fill material had been found
in the SX strainers and various heat exchangers that were cooled with SX. The
installation of the 4 inch drain valves allowed for better back flush capability of the j
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cooling coils.
The inspectors reviewed the licensee's 10 CFR 50.59 evaluation, the UFSAR, and i
'
TS. The modification package adequately addressed maintaining system design
basis and the inspectors determined that the modification did not introduce an
unreviewed safety question.
The inspectors reviewed special plant procedures for draining and flushing the
RCFCs and followed limited portions of the testing. About 10 to 15 gallons of
debris was flushed out of each set of cooling coils. The debris removalincreased
service water flow through the cooling coils and the RCFCs flows returned to the
normal range.
c. Conclusion
The licensee was proactive in diagnosing a degradation in SX flow to the RCFCs
through monthly surveillance trends. The inspectors concluded that the
modification design change package met design and regulatory requirements and
l the modification and installation and testing was accomplished in an appropriate
j manner.
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l E2.2 Unauthorized Modification Found in Unit 1 Containment Buildina (375511
s. Insoection Scone
On February 28,1997, during a Unit 1 containment tour, the inspectors identified
an unauthorized modification connected to the service air system. The inspectors
reviewed applicable modification procedures and discussed the issue with the
licensee.
b. Observations and Findings
The inspectors identified an unauthorized modification on the service air system
downstream of field connection valve,1SA038A, located on the refueling deck
above the reactor. The station prints showed the valve normally capped; however,
the inspectors found the valve nipple removed with extensive piping and
compotents added to supply service air to the refueling machine. Refueling
personnel stated that the " temporary" equipment had been attached since initial
fuel loading. Although the service air system was not a safety-related system, the
inspectors noted that the location of this required a seismic evaluation because of
its close proximity to the reactor vessel. Because the equipment was added
without a modification, a seismic evaluation was never performed. The licensee's
design engineering concurred with this assessment. Failure to subject this Jesign
change to design control measures commensurate with those applied to the original
design is a violation of 10 CFR Part 50, Appendix B, Criterion Ill, " Design Control,"
(50-454-97002-07a(DRP)).
The licensee documented the issue on a problem identification form (PlF) and
removed the assembly rather than perform the seismic evaluation. A Unit 1
- modification was planned for the nest refueling outage, that would permanently
install instrument air to the refueling bridge similar to existing conditions on Unit 2.
c. Conclusion l
The inspectors concluded that the licensee took appropriate corrective actions once
the non-seismically qualified equipment was identified.
E8 Miscellaneous Engineering lasues (92902) i
E8.1 (Closed) Unresolved item 50-454/455-96012-04(DRP): Essential Service Water
l Supply to the Auxiliary Feedwater Pump Flush Line Modification. After observation
of 1BOS SX-M1, "1 A AF Pump SX Suction Line Monthly Flushing Surveillance," the
inspectors reviewed the modification that installed the flushing line, M6-1-88-060.
l
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The safety evaluation in the modification package stated that the flushing operation
would be performed while the appropriate SX train was in a TS LCO action
requirement. However, procedure 1BOS SX-M1 did not require an LCO entry for
! the flushing operation. The inspectors considered the failure to enter the SX LCO
l as required by the original modification safety evaluation a violation of 10 CFR
f Part 50, Appendix B, Criterion ill, " Design Control" (50-454/455-97002-07b(DRP)).
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l E8.2 (Closed) LER 50-454-97-02: 480 Vac Breakers Found in Removed Positior' instead
of the Qualified Disconnect Positir,n. On February 11,1997, the licensee identified
that 20 safety-related 480 voit type DS Air Circuit Breakers (ACB) were la the
remove position. The removcd position was not seismically qualified, oni r the
disconnect position was qualified. The licensee immediately placed all tha breakers
from the removed to the disconnect position. The effected breakers were either
spares or for abandoned-in-place equipment.
The inspectors discussed the issue with operators. The operators believed that the
breakers were left in the removed position after maintenance and not restored to
the disconnect position. The licensee's procedures did not specify the return to
service position. The licensee's LER was consistent with the operators' report.
The licensee's corrective actions included training for both operators and electrical
maintenance personnel and procedure changes for both operations and electrical
maintenance 480 volt ACB procedures. The inspectors considered this a failure to
maintain design control; however, this licensee identified and corrected violation is
being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC
Enforcement Policy (50-454/455 96002-08(DRP)). l
E8.3 (Closed) Unresolved item 50-454/455-95007-05: Operability Concem of Certain
Barton Transmitters. On July 24,1995, the licensee identified that the sensing
elements on a replacement transmitter was filled with the incorrect fluid. The
transmitter was required to be filled with silicon oil. The actual medium was
domineralized water. Silicon oil was required based on environmental qualifications
for severe containment atmosphere temperatures during post loss of coolant
accident conditions. Twelve transmitters had inconclusive documentation that the
transmitters were filled with the correct fluid. Field verification was completed by
the licensee on October 22,1996, and concluded that silicon oil was used in all the
Barton transmitters installed in the containment building. This item is closed, i
IV. Mant Sunnort
R4 Staff Knowledge and Performance in Radological Protection and Chemistry Controls
R4.1 Radioactive Waste Processino and Handlina (84750)
a. Scone
The inspectors reviewed the radiological consequences of two recent events
concerning the radwaste operations department.
b. Observations and Findings
!
l As described in Section 01.4, a radwaste operator overfilled and overpressurized
! the RWDT on February 17,1997. As a result, several hundred gallons of slightly
'
contaminated water spilled from the tank onto the RWDT room floor.
j Subsequently, radiation protection (RP) personnel performed radiological surveys
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l and posted the room as a contaminated area as required by procedure. The
j removable contamination in the room was limited to 1000 to 5000 disintegrations
i per minute per 100 cm2. The inspectors concluded that the event did not result in
significant radiological effects and the RP cleanup activities were appropriate.
On February 28,1997, a redweste operator moved a container of slightly
contammated steam generator blowdown ion exchange resins to a storage area.
As the container was lifted through an opening, it brushed against the top of the
wall to the storage area. The licensee indicated that the container was not
damaged and that no resins were spilled. Prior to this event, the licensee had
evaluated the transfer and was aware of the close tolerances between the
containers and the wall. However, the licensee determined that the clearance was
adequate using the existing equipment. As corrective actions, the licensee ordered
a lifting device to increase the distance.
c. Conclusions !
i
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The inspectors concluded that these 2 events did not result in significant
radiological effects; however, had the RWDT or radwaste container contents been
of higher activity and had a larger breech of the RWDT occurred, the potential
consequences would have been more severe.
V. Manaaement Meetinas
X1 Exit Meeting Summary
The inspectors presented the inspection results to members of licensee
management at the conclusion of the inspection on March 13,1997.
The inspectors asked the licensee whether any materials examined during the )
inspection should be considered proprietary. No proprietary information was l
identified.
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7 PARTIAL LIST OF PERSONS CONTACTED
Licensee
K. Kofron, Station Manager
D. Wozniak, Site Engineering Manager
T. Gierich, Operations Manager
P. Johnson, Technical Service Superintendent
E. Campbell, Maintenance Superintendent l
M. Snow, Work Control Superintendent
D. Brindle, Regulatory Assurance Supervisor
K. Passmore, Station Support & Engineering Supervisor
P. Donavin, Site Engineering Mod Design Supervisor
T. Schuster, Site Quality Verification Director
R. Colgiazier, NRC Coordinator ,
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! INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 61726: Surveillance Observations
IP 62703: Maintenance Observations
! IP 71707: Plant Operations
IP 71750: Plant Support Activities I
l lP 84750: Radioactive Waste Treatment, and Effluent and Environmental Monitoring
IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor
Facilities
IP 92902: Followup - Engineering l
lP 92903: Followup - Maintenance )
ITEMS OPENED, CLOSED, AND DISCUSSED
l
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Opened
50-454/455 97002-01 VIO failure to follow procedure BOP WX-121
50-454/455-97002-02 NCV missed TS surveillance (TS 4.8.1.1.2.h.2) ,
50-454/455-97002-03 NCV missed TS surveillance (TS 4.8.1.1.s) J
eel 50-454/97002-04 VIO failure to follow TS 3.5.2.a ,
l
eel 50-454/97002-05 VIO failure to follow TS 3.6.2.1
50-454/455-97002-06a VIO inadequate FME procedure 1
50-454/455 97002-06b VIO inadequate maintenance troubleshooting )
procedure
50-454/455-97002-07a VIO Unauthorized modification in Unit 1 containment
50-454/455-97002-07b VIO failure to transfer design requirements from mod
to surveillance 1
50-454/455 97002-08 NCV failure to maintain seismic qualification of 480
volt breakers
Closed
50-454/455-97002-02 NCV missed TS surveillance (TS 4.8.1.1.2.h.2)
50-454/455-97002-03 NCV missed TS surveillance (TS 4.8.1.1.a)
50-454/455-97002-06 NCV failure to maintain seismic qualification of 480 volt
breakers
50-454/455-96012-04 URI SX supply to AF flush modification
50-454-97-02 LER 480 V breakers found in removed position
50-454/455-95007-05 URI fluid medium in Barton transmitters
50-454-97-01 LER missed TS surveillances
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LIST OF ACRONYMS USED 1
1
ACB Air Circuit Breaker
BIS Byron instrument Surveillance i
BOP Byron Operating Procedure
BOS Byron Operating Surveillance
BVS Byron Surveillance Procedure
DCP Design Change Package
DG Diesel Generator
D'JST Diesel Oil Storage Tank
ESF Engineered Safety Feature
FME Foreign Material Exclusion
IM instrument Mechanic
LER Licensee Event Report
LCO Limiting Condition for Operation l
NSO Nuclear Station Operator
PlF Problem identification Form 1
PORV Power Operated Relief Valve l
RCFC Reactor Containment Fan Coolers
RG Regulatory Guide
RP Radiation Protection
RWDT Regen Waste Drain Tank
SRO Senior Reactor Operator
SX Essential Service Water
TS Technical Specification
UFSAR Updated Final Safety Analysis Report
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