ML20129F721
| ML20129F721 | |
| Person / Time | |
|---|---|
| Site: | Byron  |
| Issue date: | 10/18/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20129F685 | List: |
| References | |
| 50-454-96-07, 50-454-96-7, 50-455-96-07, 50-455-96-7, NUDOCS 9610290199 | |
| Download: ML20129F721 (15) | |
See also: IR 05000454/1996007
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U. S. NUCLEAR REGULATORY COMMISSION
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REGION III
Docket Nos:
50-454, 50-455
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Report No:
50-454/96-07,50-455/96-07
Licensee:
Comed Company
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Facility:
Byron Generating Station, Units 1 & 2
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Location:
Opus West III
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1400 Opus Place
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Downers Grove, IL 60515
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Dates:
August 21 - September 26, 1996
Inspectors:
S. D. Burgess, Senior Resident Inspector
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N. D. Hilton, Resident Inspector
C. K. Thompson, Illinois Department of Nuclear Safety
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Approved by:
Lewis F. Miller, Jr., Chief,
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Division of Reactor Projects
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9610290199 961018
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ADOCK CH5000454
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EXECUTIVE SUMARY
Byron Generating Station, Units 1 & 2
NRC Inspection Report 50-454/96-007,50-455/96-007
This inspection included aspects of licensee operations, engineering,
maintenance, and plant support. The report cover: a six week period of
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resic it inspection.
DoeratLg_qi
In general, the conduct of operations was professional and
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safety-conscious. The addition of a separate control room briefing for
maintenance, radiation protection, chemistry, and the extra operating shift
effectively eliminated personnel and outage activity distractions from the
main control room shift briefing (Section 01.1).
Operators responded promptly and effectively to a turbine trip and the
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equipment failures subsequent to a resulting reactor trip (Section 01.2).
The inspectors identified a violation regarding inadequate procedures that
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resulted in running the 2A chemical and volume control pump without
essential service water to the pump's lube oil cooler (Section 01.5).
The inspectors identified poor heusekeeping in the 2A and 28 diesel oil
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storage tank rooms that resulted from fire protection system testing on
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July 22,1996 (Section 02.1).
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Maintenance
Maintenance and surveillance activities were completed thoroughly and
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professionally with maintenance supervisors and system engineers monitoring
activities (Sections M1.1 and M1.2).
Enaineerina
Engineering department personnel provided sound and thorough safety
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evaluations regarding the Unit 2 steam generator (SG) A and SG C loose part
retrieval plan and the evaluation of all four Unit 2 SG tube inspections
(Section E2.1).
Plant Support
The inspectors noted good radiological controls and ALARA briefings in the
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Unit 2 refueling outage. Sound radiological protection controls and
careful radiological work practices were also noted during the performance
of surveillances and maintenance activities (Section RI).
The identification and confiscation of a .38 weapon and ammunition
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indicated the licensee's search techniques were effective (Section S1.1)
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REPORT DETAILS
S- ry of Plant Status
Unit 1 operated at power levels up to 97 percent until September 11, 1996,
when a reactor trip occurred as a result of a turbine trip. The unit was
returned to service at 6:48 a.m. on September 12, 1996. The unit has since
operated at power levels up to 97 percent.
Unit 2 was in a refueling outage (B2R06) during this entire inspection period.
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I. Operations
01 Conduct of Operations
01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent
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reviews of ongoing plant operations.
In general, the conduct of
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operations was professional and safety-conscious. Early in the outage,
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the licensee implemented a new control room briefing format where
personnel from the extra operating shift, radiation protection,
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chemistry, and maintenance were briefed separately in the shift
engineer's office. The main control room briefing only included the
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on-duty operators for both units. The inspectors noted that the new
briefing format significantly reduced the number of personnel in the
main control room and distractions from outage activities. Specific
events and noteworthy observations are detailed in the sections below.
01.2 Unit 1 Reactor Trio as a Result of a Turbine Trio
a.
Inspection Scope (93702)
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On September 11, 1996, at 12:17 a.m. (CDT), a Unit I reactor trip
occurred due to a turbine trip. While performing a monthly turbine trip
surveillance, a non-licensed operator inadvertently placed an operating
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tool on the manual turbine trip lever instead of the turbine trip bypass
lever as required. The operator realized the error; however, in
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attempting to remove the operating tool, the operator caused a manual
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b.
Observations and Findinas
All safety related equipment automatically actuated as designed.
Channel A of the digital rod position indication (DRPI) failed during
the trip; however, channel B indicated all rods were fully inserted.
Other non-safety equipment failures during the transient included nine
failed open feedwater (FW) heater relief valves, and the starting of the
startup FW pump due to a breaker failure.
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DRPI troubleshooting showed that there was a reduced coil voltage for a
single coil on the A train coil stack for two rods. . The reduced voltage
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caused DRPI to spuriously misinterpret the location of the rod cluster
control assembly for A train only. This in turn caused DRPI urgent
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failure and DRPI alarms. As interim corrective action, the licensee
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removed several cards in the A train, which disabled that train for the
two rods. Train B still provided indication for the operators.
Final
problem resolution requires the plant to be shut down and the integrated
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head package partially disassembled. This repair will be completed
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during an outage of appropriate duration.
The feedwater heater relief valves, installed as thermal relief valves,
experienced severe service and failed during the pressure increase
accompanying main feedwater isolation following the_ turbine trip. The
licensee's engineering department had been pursuing a potential
modification to alleviate the lifting and damaging of the FW heater
relief valves. The nine FW relief valves were replaced prior to unit
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startup. The startup FW pump breaker failure was due to the roller and
can mechanism failing to latch. The breaker was replaced. As
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corrective action for the turbine trip, the licensee placed a barrier
over the hub of the turbine trip lever to physically prevent the
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operating tool from fitting on the lever.
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01.3 Unit 1 Startuo Observations 0 1707)
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The inspectors observed startup activities in the Unit I control room on
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September 12, 1996. The startup was characterized by clear operator
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communications, attentive reactor engineering oversight, and effective
control by shift supervision. A shift turnover near the point of
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criticality was well-planned and controlled. The inspectors concluded
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that the overall startup was performed effectively.
01.4 Both Source Ranae Monitors Out of Service
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a.
Inspection Scone (93702)
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The inspectors reviewed the licensee's actions in identifying both Unit
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2 source range monitors out of service (00S).
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b.
Observations and Findinas
On September 22, 1996, in Mode 5, the licensee identified that both
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source range (SR) detectors were 00S for approximately 18 minutes during
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surveillance testing. The SR detector N32 Level' Trip Bypass switch and
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the High Flux At Shutdown alarm were blocked during the performance of
surveillance 2BOS 3.1.1-21, " Train B Solid State Protection System
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Bi-Monthly Surveillance," due to excessive detector spiking. At the
time, N32 was considered inoperable as it was de-energized to perform
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the surveillance test. When the test for B train was completed, N32 was
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left blocked due to continued excessive spiking and placed on the
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degraded equipment list. N32 was considered operable, because the
spiking did not preclude count rate trending, could input to the boron
dilution prevention system, and the reactor trip breakers were open.
The licensee identified that a shift change occurred without an apparent
turnover on the status of SR detector N32. The new shift performed
surveillance 2BOS 3.1.1-20, " Train A Solid State Protection System
Bi-Monthly Surveillance." During the train A surveillance, SR N31 was
inoperable due to being de-energized, the reactor trip breakers were
closed, and SR detector N32 High Flux Level trip was in bypass. The
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test lasted approximately 18 minutes, after which the reactor trip
breakers were open and SR detector N31 was energized and returned to
service.
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Technical Specification (TS) 3/4.3.1, Table 3.3-1, identified two
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shutdown conditions for which requirements were given for SR detector
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operability:
(1) the reactor trip breakers closed and the control rod
drive system (CRDS) capable of rod withdrawal, or (2) the reactor trip
breakers open. During the train A surveillance, the CRDS was disabled
such that rod withdrawal was not possible and the reactor trip breakers
were closed. Therefore, the plant was in a configuration where no TS
action was required. However, TS interpretation 3/4.3.3.1-2, written by
the licensee to cover this configuration, stated to default to the TS
actions required in (1), and considered both SR monitors 00S. The
licensee stated that the TS interpretation was inappropriate and that
the TS was satisfied, in that, the plant was in a configuration not
covered by TS. The issue regarding the authority of TS interpretations
is considered an inspector follow-up item (50-455/96007-01(DRP)).
01.5 Inadeauate Coolina to Chemical and Volume Control Pumn Lube Oil Cooler
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a.
Inspection Scope (71707)
The inspectors reviewed a test where the 2A chemical and volume control
(CV) pump was run without essential service water cooling to the pump
lube oil cooler for 27 minutes.
b.
Observations and Findt.ngi
On September 14, 1996, the licensee identified that surveillance
procedure 2BVS 1.2 3.1-1, "ASME Surveillance Requirements for
Centrifugal Chargir.g Pump 2A and Chemical and Volume Control System
Valve Stroke Test,' kevision 12, was performed with essential service
water (SX) isolated to the CV pump lube oil cooler for 27 minutes. The
discovery was made approximately five hours after the surveillance was
completed.
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The inspector identified that procedure 2BVS 1.2.3.1-1, failed to
provide adequate steps to ensure that SX provided cooling to the 2A CV
pump lube oil cooler. This is considered a violation of 10 CFR 50,
Appendix B, Criterion V (50-455/96007-02(DRP)).
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The licensee addressed the effects of having SX isolated to the 2A CV
lube oil cooler for 27 minutes. The inspectors reviewed the point
history for the 2A CV pump which revealed that the bearing temperatures
were within the ASME surveillance requirements.
c. Conclusions on the Conduct of Operations
Operators responded promptly and effectively to the turbine trip and to
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the equipment failures subsequent to the reactor trip.
The inspectors
determined that the licensee's short and long term corrective action for
equipment failures experienced after the reactor trip were appropriate.
The inspectors identified concerns with configuration controls during
the conduct of surveillance tests.
In one instance, the inspectors
identified an inadequate procedure that resulted in the 2A CV pump being
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run without essential water to the lube oil cooler.
In the other
instance, the lack of a thorough shift turnover resulted in both SR
monitors being 00S.
02 Operational Status of Facilities and Equipment
02.1 Enaineered Safety Feature (ESF) System Walkdowns (71707)
The inspectors used Inspection Procedure 71707 to walk down accessible
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portions of the following ESF systems:
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Unit 2 Emergency Diesel Generators A & B
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Equipment operability, material condition, and housekeeping were
acceptable except in the diesel oil storage tank rooms. The inspectors
nMed that valve 2D0003D, the 2D diesel oil transfer pump discharge
check valve, was not labelled. They also noted a large amount of dried
fire suppression foam on several fire nozzles in the 2A and 2B diesel
oil storage tank rooms, the floor, and some equipment. The fire
protection system engineer stated to the inspectors that the foam was
residue from a once-every-three-year surveillance of the foam spray
headers and deluge nozzles. This test was conducted on July 22, 1996.
The inspectors concluded that the two month delay in cleaning up the
residue was an example of poor housekeeping. The licensee initiated
corrective actions to label the valve and clean the rooms. The
inspectors had no further concerns.
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Miscellaneous Operations Issues (92901)
08.1
(Closed) Violation 50-454/455-05013-03:
Inadequate procedures for
the boric acid and diesel oil transfer systems. The inspectors
reviewed the corrective actions as described in a letter from the
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licensee dated April 17, 1996. The actions appeared adequate.
However, the inspectors noted that there were minor
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inconsistencies between procedures 2BVS 0.5-3.DO.1, " Unit 2 ASME
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Requirement for Test of the Diesel Oil Transfer System," Revision
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M1.2 Surveillance Observations
a.
Inspection Scone (61726)
The inspectors observed all or parts of the following surveillance and
special test procedures:
. IBVS 0.5-3.CC.1-1
Surveillance Requirements for Component Cooling
(CC) Pump ICC01PA
2BVS 8.2.1.2.E-2
125V Battery Bank 5-Year Capacity Test
2BVS 8.1.1.2.f-14
2B Diesel Generator Sequencer Test
. IBVS 1.2.3.1-2
ASME Surveillance Requirements for Centrifugal
Charging (CV) Pump IB and Chemical Volume
Control System Valve Stroke Test
. IBVS 5.2.f.3-1
ASME Surveillance Requirements for Residual Heat
Removal (RH) Pump 1RH01PA
. SPP 96-055
Dual Train Auxiliary Feedwater Suction Transient
Hydraulic Test
b. Observations and Findinas
During the observation of surveillances, the inspectors questioned the
use of a dedicated non-licensed operator to reposition manual valves
when systems / trains were not considered out of service during the test.
The licensee stated that the use of dedicated operators was utilized for
systems that do not receive an automatic actuation.
The inspectors reviewed Byron operating procedure B0P RH-5, "RH System
Startup for Recirculation," Revision 9.
The procedure noted that, in
Mode 4, the normally locked-closed RH recirculation to reactor water
storage tank isolation valve, RH8735, may be opened provided that a
dedicated operator stationed nearby will close the valve in the event of
a safeguards actuation to ensure adequate flow is available to all four
cold legs. The inspectors were concerned that the dependance of the
operator created two new failure mechanisms:
(1) the failure of the
operator to close the valve, and (2) the failure of the valve to close.
The inspectors discussed this issue with the NRC technical staff and
determined that the use of the dedicated operator was not an unreviewed
safety questions since the bases for TS 3/4.5.3, ECCS Subsystems - T,,, <
350'F, allowed one operable ECCS subsystem without single failure
consideration in Mode 4 on the basis of the stable reactor reactivity
condition and the limited core cooling requirements. The inspectors had
no further concerns with the use of dedicated operators for performance
of this procedure.
M1.5 Conclusions on Conduct of Maintenance and Surveillances
Maintenance and surveillance activities were completed thoroughly and
professionally with maintenance supervisors and system engineers
monitoring activities.
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III. Encineerina
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Engineering Support of Facilities and Equipment
E2.1 Unit 2 Steam Generator Tube Leak & Tube Repair So-ary
a.
Inspection Scope (37551)
The inspectors reviewed procedures and documents related to the Unit 2
steam generator (SG) A loose part retrieval and subsequent tube repairs.
Also reviewed were the non-destructive examination results for all four
Unit 2 SGs performed during B2R06 refueling outage.
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Observations and Findinas
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On August 9,1996, Byron Unit 2 was brought to cold shutdown due to a
primary-to-secondary leak in SG A.
Byron engineering developed a
comprehensive plan to investigate the location, extent, and cause of the
leak. The source of the leak was found to be in tube 16-110 located on
the cold leg side of SG A approximately one inch above the tube sheet.
During eddy current examination, the licensee determined that the tube
was damaged by a piece of metallic debris approximately 1-1/2" x 1" x
1/32" in size and triangular in shape. The loose part was retrieved and
sent offsite for analysis. The licensee plugged four tubes in SG A as
corrective action. The licensee also retrieved a previously identified
loose part in SG C.
The SG C loose part was identified as
" wedge-shaped" metallic debris and was also sent offsite for further
analysis. The loose part was located in an area where the tubes were
plugged in previous outages. The part had not moved; therefore, no
further tube plugging was necessary.
A total of 30 SG tubes were plugged during the Unit' 2 forced outage and
the Unit 2 B2R06 refueling outage. All tubes were inspected from the
hot leg tube end to the cold leg tube end using a bobbin eddy current
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inspection. Additional inspections included 25 percent top of tubesheet
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(hot leg) using the rotating pancake coil (RPC), 25 percent row I and
row 2 U-Bend using Point Plus, and 25 percent preheater expansion region
using RPC in SG A.
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c.
Conclusions
Engineering personnel made sound and thorough safety evaluations
regarding the Unit 2 SG A and SG C loose part retrieval plan and.
evaluation and the evaluation of all four Unit 2 SG tube inspections.
E8
Miscellaneous Engineering Issues (92902)
E8.1
(Closed) LER 50-455/96-003: Missed TS surveillance regarding SG tube
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inspections. On September 4,1996, the licensee identified that 26
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tubes in SG D and 4 tubes in SG B were not inspected and analyzed in
accordance with the original inspection plans for previous refueling
outages B2R03 and B2R05. The tubes were not inspected because they were
misencoded with the wrong tube number. The licensee performed a review
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of previous and subsequent refuel outage tube inspections and determined
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that the 30 tubes contained no detectable degradation. The licensee's
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corrective actions were appropriate and the safety consequences were
minor. This licensee identified and corrected violation is being
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treated as a non-cited violation, consistent with Section VII.B.1 of the
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NRC Enforcement Policy. This item is closed.
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IV. Plant Supoort
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Radiological Protection and Chemistry (RP&C) Controls
The inspectors noted good radiological controls implemented in the Unit
2 refueling outage during frequent tours of the radiologically protected
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area and ALARA briefings. The inspectors also noted sound radiological
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protection controls and careful radiological work practices during the
surveillances and maintenance observations.
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RP&C Procedures and Documentation
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R3.1 Review of License Conditions
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The inspectors reviewed the license conditions and the TS administrative
controls section for discrepant conditions or practices. The inspectors
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identified minor discrepancies in section 6.12, "High Radiation Area"
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and section 6.14, "Offsite Dose Calculation Manual (00CM)." Both
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sections had not been updated to reference the applicable sections of 10
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CFR Part 20. Section 6.12 also defined the high radiation area dose
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equal to or less than 1000 mR/hr at 45 cm instead of 30 cm.
10 CFR Part 20.1008, " Implementation," states, in part, that the 10 CFR Part 20
requirements must be used in lieu of the requirements that are cited in
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the licensee's TS. The inspectors confirmed that the licensee was in
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full compliance with the more restrictive requirements of 10 CFR Part
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20. The licensee was already aware of the discrepancies and had made
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the necessary changes to their proposed Improved Technical
Specifications. The inspectors had no further concerns.
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P1
Conduct of Emergency Protection Activities
Pl.1 Yearly Emeraency Preparedness Meetina
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On September 19, 1996, the inspectors attended the annual emergency
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preparedness meeting. The meeting was attended by the licensee's
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station management, Comed corporate management, and state and local
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officials. The meeting presented the 1997 EP pians for Byron Station.
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The inspectors noted no concerns.
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Conduct of Security and Safeguards Activities (11750)
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Identification and Confiscation of a Weapon
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On September 5,1996, a contractor attempted to bring a .38 caliber
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revolver, a speed loader, and 62 rounds of ammunition into the protected
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Conduct of Security and Safeguards Activities (71750)
S1.1
Identification and Confiscation of a Weacon
On September 5, 1996, a contractor attempted to bring a .38 caliber
revolver, a speed loader, and 62 rounds of ammunition into the protected
area. The weapon and ammunition was identified during a lunchbox search
after detecting a undefinable mass in the x-ray machine.
Since the
contractor did not have a permit for the weapon, the Ogle County
authorities were notified.
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The licensee's investigation determined that the contractor did not have
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a harmful intent in bringing'the weapon into the protected area. The
individual had placed the weapon in the lunchbox after showing it
outside the owner controlled area the previous night and had forgotten
to remove it prior to entering the facility.
Security implemented an aggressive program to improve search techniques
as a result of recent SQV audit findings. The identification and
confiscation of the weapon and ammunition indicated the program's
effectiveness. The inspectors had no further concerns.
F8
Miscellaneous Fire Protection Issues (92904)
F8.1
(closed) Violation 50-454/455/94020-01:
Failure to follow fire
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protection procedure requiring tags be placed on fire doors that
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were impaired.
In August 1994, the inspectors identified two fire
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doors that were apparently impaired because the door sills had
been temporarily removed and two doors that were impaired by being
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blocked opened. None of the doors were tagged as required by
procedure BAP 1100-3, " Fire Protection Systems, Fire Rated
Assemblies, Radiation, Ventilation, and Flood Seal Impairments."
The inspectors reviewed the licensee's corrective actions as
discussed in letters dated October 31, 1994, and March 15, 1996.
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The responses stated that the door sills were subsequently
reinstalled, returning the doors to an unimpaired state. The
responses also stated that the two blocked open fire doors were
not considered impaired if personnel were nearby to close the
doors in the event of a fire. However, the licensee acknowledged
that BAP 1100-3 did nct specifically exempt tagging of impaired
fire doors if personnel were stationed nearby. As part of
corrective action:,, fire marshall office personnel were counselled
on management expectations regarding procedure adherence. The
fire marshall also stated that fire door impairment requirements
would be emphasized in annual station training and that procedure
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BAP 1100-3 would be revised to clearly state the exemption.
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08.2 (Closed) Violation 50-454/455/95009-04:
Failure to follow fire
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protection procedure requiring tags be placed on fire doors that
were impaired. On September 18, 1995, the inspectors identified
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Conduct of Security and Safeguards Activities (71750)
S1.1
Identification and Confiscation of a Weapon
On September 5,1996, a contractor attempted to bring a .38 caliber
revolver, a speed loader, and 62 roud s of ammunition into the protected
area. The weapon and ammunition wa'
Jentified during a lunchbox search
after detecting a undefinable mast
. the x-ray machine.
Since the
contractor did not have a permit
i the weapon, the Ogle County
authorities were notified.
The licensee's investigation determined that the contractor did not have
a harmful intent in bringing the weapon into the protected area. The
individual had placed the weapon in the lunchbox after showing it
outside the owner controlled area the previous night and had forgotten
to remove it prior to entering the facility.
Security implemented an aggressive program to improve search techniques
as a result of recent SQV audit findings.
The identification and
confiscation of the weapon and ammunition indicated the program's
effectiveness. The inspectors had no further concerns.
F8
Miscellaneous Fire Protection Issues (92904)
F8.1
(Closed) Violation 50-454/455/94020-01:
Failure to follow fire
protection procedure requiring tags be placed on fire doors that
were impaired.
In August 1994, the inspectors identified two fire
doors that were apparently impaired because the door sills had
been temporarily removed and two doors that were impaired by being
blocked opened. None of the doors were tagged as required by
procedure BAP 1100-3, " Fire Protection Systems, Fire Rated
Assemblies, Radiation, Ventilation, and Flood Seal Impairments."
The inspectors reviewed the licensee's corrective actions as
discussed in letters dated October 31, 1994, and March 15, 1996.
The responses stated that the door sills were subsequently
reinstalled, returning the doors to an unimpaired state. The
responses also stated that the two blocked open fire doors were
not considered impaired if personnel were nearby to close the
doors in the event of a fire. However, the licensee acknowledged
that BAP 1100-3 did not specifically exempt tagging of impaired
fire doors if personnel were stationed nearby. As part of
corrective actions, fire marshall office personnel were counselled
on management expectations regarding procedure adherence. The
fire marshall also stated that fire door impairment requirements
would be emphasized in annual station training and that procedure
BAP 1100-3 would be revised to clearly state the exemption.
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08.2 (Closed) Violation 50-454/455/95009-04:
Failure to follow fire
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protection procedure requiring tags be placed on fire doors that
were impaired. On September 18, 1995, the inspectors identified
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two untagged fire doors that were blocked open during flushing of
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some floor drains. As discussed above, the violation occurred
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because of an inappropriate interpretation of procedure
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BAP 1100-3.
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The inspector concluded that the fire door problems in 1994 and 1995
were isolated events and that adequate corrective actions had been
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taken. During the current inspection, the inspectors observed that
impaired fire doors were tagged as required.
V. Management Meetinas
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Exit Meeting Summary
The inspectors presented the inspection results to members of licensee
management at the conclusion of the inspection on September 26, 1996.
The inspectors asked the licensee whether any materials examined during
the inspection should be considered proprietary. No proprietary
information was identified.
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PARTIAL LIST OF PERSONS CONTACTED
Licensee
K. Graesser, Site Vice President
K. Kofron, Station Manager
D. Wozniak, Site Engineering Manager
T. Gierich, Operations Manager
P. Johnson, Technical Service Superintendent
E. Campbell, Maintenance Superintendent
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. Colglazier, NRC Coordinator
B. Gossman, Chemistry Supervisor
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S. Gackstetter, Thermal Group Leader
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R. Wegner, Shift Operations Supervisor
M. Rasmussen, Operations Engineer Unit 2
W. Kouba, Long Range Work Control Superintendent
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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
IP 92901:
Followup - Plant Operations
IP 92902:
Followup - Engineering
IP 92903:
Followup - Maintenance
IP 92904:
Followup - Plant Support
IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors
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ITEMS OPENED, CLOSED, Alm DISCUSSED
Opened
50-455/96007-01
IFU
Both Unit 2 source range monitors out of
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service.
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50-455/96007-02
Inadequate procedure regarding SX cooling to the
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2A CV pump lube oil cooler,
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Closed
50-454/455/95013-03
Inadequate procedures for the boric acid and
diesel oil transfer systems,
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50-454/455-94010-01
IFI
Weakness in the emergency operating procedure
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verification and validation process.
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50-454/96-017
LER
Unit I trip due to personnel error during
surveillance activities.
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50-455/96-003
LER
Missed TS surveillance regarding SG tube
. inspections.
50-454/455/94020-01
Failure to follow fire protection procedures..
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50-454/455/95009-04
Failure to follow fire protection procedures,
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LIST OF ACRONYMS USED
As Low As Reasonably Achievable
American Society of Mechanical Engineers
BOS
Byron Operating Procedure
BVS
Byron Surveillance Procedure
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Component Cooling Water System
CRDS
Control Rod Drive System
CV
Chemical and Volume Control System
DRPI
Digital Rod Position Indication
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Emergency Core Cooling Systems
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E0P
Emergency Operating Procedure
Engineered Safety Feature
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Feedwater System
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Out of Service
RH
Residual Heat Removal System
RPC
Rotating Pancake Coil
SR
Source Range
Essential Service Water
TS
Technical Specification
Verification and Validation
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