ML16154A792
| ML16154A792 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 05/24/1995 |
| From: | Crlenjak R, Harmon P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16154A790 | List: |
| References | |
| 50-269-95-06, 50-269-95-6, 50-270-95-06, 50-270-95-6, 50-287-95-06, 50-287-95-6, NUDOCS 9505310076 | |
| Download: ML16154A792 (15) | |
See also: IR 05000269/1995006
Text
REGU'
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
Report Nos.:
50-269/95-06, 50-270/95-06 and 50-287/95-06
Licensee:
Duke Power Company
422 South Church Street
Charlotte, NC 28242-0001
Docket Nos.:
50-269, 50-270 and 50-287
License Nos.:
Facility Name:
Oconee Units 1, 2 and 3
Inspection Conducted:
March 26 - April 29, 1995
Inspector:
(e-i-Cv
2/#
P. E. Harmon, Senioi'Resident Inspector
Date Signed
W. K. Poertner, Resident Inspector
L. A. Keller, Resident Inspector
P. G. Humphrey, Resident Inspector
R. E. Carroll, Project Engineer
Approved by:
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R. V. Crlenjak, Chief
Date Signed
Reactor Projects Branch 3
SUMMARY
Scope:
This routine, resident inspection was conducted in the areas of
plant operations, maintenance and surveillance testing, onsite
engineering, plant support, and inspection of open items.
Inspections were performed during normal and backshift hours and
on weekends.
Results:
A violation was identified in the area of plant operations
concerning inadequate corrective actions for controlling Keowee
operating limits (paragraph 2.d).
Knowledgeable of a
probabilistic risk assessment study, operations personnel took
conservative action to preclude a high risk maintenance situation
(paragraph 2.f).
Unit 2 tripped from 100 percent power due to a
disturbance on the system grid (paragraph 2.c).
Previously
identified problems with slow rod drop times resulted in a
shutdown of Unit 1 (paragraph 2.e).
ENCLOSURE 2
9505310076 950524
PDR ADOCK 05000269
G
2
In general, maintenance activities were accomplished in an
acceptable manner with appropriate procedure use and adherence.
One instance was observed where maintenance personnel were not
using procedures appropriately (paragraph 3.a.(2)).
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
B. Peele, Station Manager
- E. Burchfield, Regulatory Compliance Manager
- D. Coyle, Systems Engineering Manager
- J. Davis, Engineering Manager
T. Coutu, Operations Support Manager
W. Foster, Safety Assurance Manager
J. Hampton, Vice President, Oconee Site
D. Hubbard, Maintenance Superintendent
C. Little, Electrical Systems/Equipment Manager
- J. Smith, Regulatory Compliance
- G. Rothenberger, Operations Superintendent
R. Sweigart, Work Control Superintendent
Other licensee employees contacted included technicians, operators,
mechanics, security force members, and staff engineers.
- Attended exit interview.
2.
Plant Operations (71707)
a.
General
The inspectors reviewed plant operations throughout the reporting
period to verify conformance with regulatory requirements,
Technical Specifications (TS), and administrative controls.
Control room logs, shift turnover records, temporary modification
logs, and equipment removal and restoration records were reviewed
routinely. Discussions were conducted with plant operations,
maintenance, chemistry, health physics, instrument & electrical
(I&E), and engineering personnel.
Activities within the control rooms were monitored on an almost
daily basis.
Inspections were conducted on day and night shifts,
during weekdays and on weekends.
Inspectors attended some shift
changes to evaluate shift turnover performance. Actions observed
were conducted as required by the licensee's Administrative
Procedures. The complement of licensed personnel on each shift
inspected met or exceeded the requirements of TS. Operators were
responsive to plant annunciator alarms and were cognizant of plant
conditions.
Plant tours were taken throughout the reporting period on a
routine basis. During the plant tours, ongoing activities,
housekeeping, security, equipment status, and radiation control
practices were observed.
.2
b.
Plant Status
Unit 1 operated at or near full power until April 27, 1995, when
the Unit was taken off-line for control rod drive testing. The
Unit remained shutdown the remainder of the reporting period for a
control rod drive mechanism refurbishment outage.
Unit 2 operated at or near full power until April 8, 1995, when an
observed loss of efficiency was attributed to a ruptured steam
extraction expansion joint in the main condenser. The Unit
continued operation with reduced secondary output until a fault on
the transmission grid resulted in a generator lockout and
subsequent reactor trip on April 14, 1995.
The unit was restarted
on April 16, 1995.
On April 21, 1995, Unit 2 began experiencing
problems with tube leaks in the main condenser. The unit
continued to operate throughout the remainder of the reporting
period while coping with power reductions for condenser water box
outages as necessary for on-going condenser tube repair/plugging
activities.
Unit 3 operated at or near full power throughout the inspection
period.
c.
Unit 2 Reactor Trip
The Unit 2 reactor tripped at 9:59 a.m., on April 14, 1995.
The
reactor trip was attributed to a main generator lockout that
occurred as a result of a fault on the electrical grid system.
The following is a sequence of the event:
(1) A fault on the 100KV electrical transmission system occurred
when a tree fell across the Pickens Black 100KV line.
(2) A failed trip coil in the Pickens Black 100KV supply breaker
prevented the breaker from opening and isolation of the
fault. This resulted in system disturbances upstream of the
100KV lines and into the 230KV portion of the system grid.
(3) The fault was detected by the Oconee Unit 2 main generator
Loss of Field protective relays, which tripped the generator
off-line prior to the fault being cleared by the Central and
North Greenville substation breakers located between the
failed 100KV breaker and the Oconee generating units. The
circuit timer was set at 0.8 seconds for the generator trip
signal.
The licensee indicated that a modification would be
proposed to change the generator trip signal timer to 30
seconds when the signal does not involve a loss of voltage.
The increased time delay will allow time for generator
recovery without damage to the generator and will serve to
avoid unnecessary unit trips.
3
All 3 Oconee units were operating at the time of the Unit 2 trip.
Units 1 and 2 were tied to the 230KV grid which was supplying the
faulted 100KV system. Unit 3 was connected to the 525KV system
and was less affected by the fault. Unit 2 experienced the most
effect from the fault since it was operating with its generator
voltage regulator in automatic and attempted to follow the grid
load. This resulted in the generator lockout followed by a
reactor trip. Unit 1 had previously experienced problems with
operating the voltage regulator in the automatic mode and had
switched control to manual prior to the event.
The inspectors were in the control room immediately following the
reactor trip and observed operator responses. The unit trip was
well controlled by the control room operators.
Control rod drop times were recorded on the events recorder at the
time of the reactor trip and 12 rods required more than 1.40
seconds to drop into the core. One of the 12 rods (Group 2, Rod
6) had a drop time of 1.842 seconds, which is greater than the
1.66 seconds allowed by Technical Specification (TS) Section
4.7.1.
Based on previous experience, the type A control rod drive
mechanisms that exceed 1.40 seconds appear to significantly
increase in drop times during the operating cycle. (Note: Units 1
and 2 have the type A control rod drive mechanisms).
Unit 2 was
restarted (critical) at 3:47 p.m., on April 15, 1995, with the
inoperable rod as allowed by TS 3.5.2.
The inspectors reviewed the licensee's trip report and attended
the Plant Operating Review Committee meeting for evaluating the
trip and authorization for restart.
d.
Inadequate Control of Keowee Load Limits
The licensee reported by Licensee Event Report (LER) 269/93-01
that under certain conditions the emergency power supplied by the
Keowee Hydro Station to the Oconee Station could be lost. If an
emergency start was initiated while a Keowee unit was generating
to the system grid at high load, the Keowee unit could trip or
load reject on overspeed. To prevent this problem, Procedure
OP/0/A/2000/041, Keowee-Mode of Operation, was revised on January
15, 1993, to administratively limit the maximum output to 60 MW
for a Keowee unit generating to the system grid.
On June 2, 1993, based on the results from load rejection tests
and on revised calculation OSC-6003, "Keowee Operating Limits to
Prevent Overspeed Due to Load Rejection", the licensee's Keowee
Station Manager issued a memorandum to the Keowee Operators that
raised the maximum permissible output of the Keowee unit gener
ating to the grid, from 66 to 75 MW. Although calculations were
performed to verify maximum load limits, the controlling
procedure, OP/0/A/2000/041 was not revised. As a result, the
Keowee units were operated for a period of time in excess of the
4
official limit. The failure to revise this procedure was
identified as Violation 50-269,270,287/93-20-03: Failure to Follow
Procedures at Keowee.
The 75 MW limit was later found to be in error by NRC reviewers
and revised to 69 MW maximum. To ensure the 69 MW limit would not
be exceeded due to the expected unit swing, an operational limit
of 64 MW was imposed by procedure.
On March 15, 1995, the licensee revised calculation OSC-6003 to
change the maximum operating limit for a Keowee Hydro Unit
generating to the grid from 69 to 68 MW. Upon revising this
calculation, the responsible engineer called Keowee Hydro
Operations and advised them of the analysis results which changed
the administrative operating limit from 64 to 63 MW. The Keowee
operator agreed that the unit would be run at 63 MW or less until
the procedure was changed (procedure limit was 64 MW).
The
procedure was changed on March 20, 1995.
The resident staff
reviewed the Keowee Operating Log for the period of March 15 - 20,
1995, and noted that on March 16 & 17, 1995, a Keowee Hydro Unit
was operated at 64 MW. The inspectors concluded that attempting
to change a Keowee operating limit based on a phone conversation
between a system engineer and a Keowee operator was both
inappropriate and ineffective, in that it did not include the
proper chain of command and did not achieve the desired result.
The inspectors determined that this was similar to Violation
93-20-03 in that the operating limit was inappropriately changed
(the first time by memo, the second time by phone).
The licensee
has initiated a Duke-wide study of Engineering to Operations
communication and whether it should be additionally formalized.
The inspectors.agree that more careful, formal communications are
needed. However, both the engineer involved and the Keowee
operators treated this issue as a Keowee issue rather than an
Oconee issue. As a result, the Oconee shift supervisor was not
contacted concerning the new limits. Keowee operations and chain
of command has officially been integrated into Oconee Operations,
but this incident indicates further efforts are needed. This
matter is identified as Violation 50-269,270,287/95-06-01:
Inadequate Corrective Action for Control of Keowee Operating
Limits.
e.
Unit 1 Shutdown
On April 27, 1995, Unit I was taken off-line to perform control
rod drive trip time testing. Testing revealed that 5 control rods
had trip times which exceeded the TS limit of 1.66 seconds.
The Unit had been operating with a conditional control rod
operability determination based on a statistical analysis which
determined that rod drop times would not exceed the Technical
Specification limit of 1.66 seconds. The conditional operability
statement expired on April 21, 1995. On March 30, 1995, the
5
licensee's Plant Operating Review Committee had reviewed this item
and determined that the Unit 1 control rods would be considered
operable for the remainder of the cycle. This decision was based
on the unit starting the cycle with no inoperable control rods,
and statistical analysis that showed that 1 rod may become
inoperable due to slow drop times at the 95/95 confidence level
during the cycle.
On April 14, 1995, Unit 2 tripped from 100 percent power. Review
of the rod drop times identified that 1 control rod's drop time
was greater than the Technical Specification limit of 1.66 seconds
and that 11 control rods exceeded 1.4 seconds, the value that the
licensee has established for replacing rod drives during a
refueling outage (see paragraph 2.c).
Based on the rod drop data
obtained during the Unit 2 reactor trip, the licensee decided to
re-evaluate the operability of the Unit 1 control rods.
This
decision was based on the knowledge that Unit 1 had been operating
longer than Unit 2 and that a greater number of control rod drive
mechanisms (CRDMs) had been refurbished during the Unit 2
refueling outage.
As a result of the re-evaluation, the licensee decided to take
Unit I off-line on April 27, 1995, and perform rod drop time
testing to confirm operability of the Unit 1 control rods.
The
testing identified five control rods with drop times greater than
the Technical Specification limit of 1.66 seconds and four control
rods with drop times greater than 1.5 seconds, but less than 1.66
seconds. After reviewing the Unit 1 rod drop data, the licensee
commenced a reactor cooldown to cold shutdown to allow
refurbishment of the slow CRDMs. At the end of the inspection
period the Unit was in cold shutdown with the loops dropped. The
licensee plans to refurbish nine CRDMs during the outage. The
inspectors will follow the licensee's repair efforts during the
next monthly inspection period.
f.
Control of Scheduled Work
The inspectors noted that the operations shift manager had
rejected work.orders (WO) on March 30, 1995, for concurrence of
work scheduled for the following Monday (April 3, 1995).
One work
order was for lubrication of the Unit #1 turbine driven emergency
feedwater pump (WO 9501518-01, PM Lube: Ul TDEFWP And Turbine) and
two others (WO 95026645-01, PM: 16 CYL Diesel Engine, and WO 95026646-01, PM: 12 Cyl Diesel Engine) involved preventive
maintenance that required taking the standby shutdown facility
(SSF) diesel generator out of service.
The SSF generator is the
power supply for the auxiliary service water pumps.
Although simultaneous removal of the equipment was allowed by TS,
the shift manager's decision was based on his awareness of a
Probabilistic Risk Assessment (PRA) that concluded the proposed
configuration would put the plant in a high risk situation by the
II
6
elimination of two sources of emergency feedwater to the Unit 1
steam generators at the same time. The shift manager's decision
was conservative since the PRA program had not been implemented at
that time.
Within the areas reviewed, one violation was identified.
3.
Maintenance and Surveillance Testing (62703 and 61726)
a.
Maintenance activities were observed and/or reviewed during the
reporting period to verify that work was performed by qualified
personnel and that approved procedures adequately described work
that was not within the skill of the craft. Activities,
procedures, and work orders (WO) were examined to verify that
proper authorization and clearance to begin work were given,
cleanliness was maintained, exposure was controlled, equipment was
properly returned to service, and limiting conditions for
operation were met.
Maintenance activities observed or reviewed in whole or in part
are as follows:
(1) Calibrate Reactor Protection System (RPS) Feedwater Pump
(FDWP) Discharge Pressure Switches, Work Order 95005657
The inspectors witnessed calibration of the Unit 2 RPS FDWP
Discharge Pressure Switches. The activity was performed in
accordance with IP/0/A/0305/009, RPS Channel A Main
Feedwater Pumps and Main Turbine Trips Calibration. The
calibration was on an increased schedule, biweekly, due to
drifts in the setpoints associated with the Static-O-Ring
pressure switches.
The unit pressure switches were replaced with a different
model of the Static-0-Ring switch. However, the new
switches have not performed well and the licensee is
evaluating their replacement.
The inspector determined the calibration activity was
performed to acceptable standards.
(2) Perform Preventive Maintenance On Condenser Circulating
Water (CCW) Pump Motor IC, Work Order 95027249
On April 17, 1995, the inspectors observed activities during
the performance of preventive maintenance on the IC CCW
pump. The work instructions involved implementation of
maintenance procedures MP/O/A/1840/040, Pumps-Motors
Miscellaneous Components, and MP/O/B/1300/037, Motor-CCW
Lubrication and Inspection. In addition, electrical tag
outs OPS-95-0693-1, 1C CCW Pump Breaker, and OPS-95-0693-6,
7
1C CCW Pump Motor Heater Breaker, were reviewed as part of
the work package.
The inspectors noted that the completed steps in procedure
MP/0/B/1300/037, had not been initialed. The procedure was
required to be in use and the steps were to be initialed as
they were accomplished. The inspectors questioned the
craftsmen and were informed that the missed initials were an
oversight. As a result, the completed steps were then
initialed by the craftsmen.
The licensee performed an investigation of the event and
took appropriate corrective actions, which included
counselling the individuals involved.
In addition,
expectations for verbatim procedure compliance were stressed
in maintenance team meetings. -The inspectors consider the
corrective actions to be appropriate for the circumstances.
The CCW pump motors are not presently classified as safety
related, but the licensee has committed to a future upgrade
of the pump motors to a safety-related classification and to
perform maintenance activities per safety-related
procedures.
(3) 3C Low Pressure Injection (LPI) Pump Vent Line Replacement,
Due to minor leaks in the weld area, the vent line for the
3C LPI Pump was replaced. The inspectors verified that the
replacement flexible hose (stainless steel), welding rods,
and work procedures were of the appropriate Quality
Assurance classification. The inspectors concluded that
procedural compliance for this activity was good. All
activities observed were satisfactory.
(4) Replace Capacitor Coupled Voltage Transformers (CCVTs) on
230KV Red Bus, Work Order 94062794
The CCVTs were replaced on the 230KV switchyard red bus per
NSM-52950. The inspectors verified that appropriate
precautions were taken to prevent an inadvertent red bus
lockout. The inspectors verified that procedures were in
place and were being followed. All activities observed were
satisfactory.
(5) Repair Seat Leak on Low Pressure Service Water (LPSW) Valve
304, Work Order 95031118
The inspectors reviewed the work request and observed work
activities in progress associated with this corrective
maintenance activity. The activity consisted of replacing
the old globe valve installed in the system with a new globe
8
valve. The inspectors verified that procedures were in
place and were being followed. The inspectors noted that
the maintenance activity was well coordinated between
operations and maintenance personnel and that the valve
replacement was accomplished in an efficient and expedient
manner. No discrepancies were noted.
b.
The inspectors observed surveillance activities to ensure they
were conducted with approved procedures and in accordance with
site directives. The inspectors reviewed surveillance
performance, as well as system alignments and restorations. The
inspectors assessed the licensee's disposition of any
discrepancies which were identified during the surveillance.
Surveillance activities observed or reviewed in whole or in part
are as follows:
(1) Unit 3 Control Rod Movement, PT/3/A/600/15
The inspector witnessed the monthly performance test of the
Unit 3 control rods.
All equipment operated as expected.
Operator communication and procedural compliance were good.
(2) Control of Control Rod Drive Trip Time Testing,
PT/O/A/0300/01
The inspectors monitored this surveillance activity
conducted on April 27, 1995, during the Unit 1 shutdown to
perform control rod drive trip time testing. The test was
performed when reactor power was below 2 percent with all
control rods fully withdrawn. The test consisted of
manually tripping the control rods and determining rod drop
times using the operator aid computer and the events
recorder. The inspectors monitored the test in progress and
reviewed the test results.
The test identified that five
control rods exceeded the Technical Specification required
trip time of 1.66 seconds or less.
The slowest rod dropped
in 2.084 seconds as recorded on the events recorder. Based
on the test results, the licensee initiated a reactor
cooldown to cold shutdown to commence a control rod drive
mechanism refurbishment outage.
Within the areas reviewed, licensee activities were satisfactory.
4.
Onsite Engineering (37551 and 40500)
During the inspection period, the inspectors assessed the effectiveness
of the onsite design and engineering processes by reviewing engineering
evaluations, operability determinations, modification packages and other
areas involving the Engineering Department.
- I
9
a.
Oconee Emergency Power Upgrade Project
Keowee Hydro Station was designed, constructed, and maintained -to
hydroelectric standards. The hydro station was not originally
under the Nuclear Generation Department management and
documentation and programmatic controls have not been consistent
with nuclear industry standards. Over the years several events
and internal/external assessments resulted in a growing list of
commitment items. These included the May 15, 1992, Self-Initiated
Technical Audit (SITA), October 1992 Loss of Offsite Power Event,
Electrical Distribution System Functional Inspection, and the
Design Basis Document (DBD) review program. In order to manage
the list of commitment items, the licensee initiated the Oconee
Emergency Power Upgrade Project. On September 29, 1994, the
licensee presented their plans for this project to NRC Region II
management.
The upgrade project provides for the engineering analyses,
procedure upgrades, maintenance program development, and
configuration documentation/upgrade for the Keowee Hydro Station
and the Emergency Power Path of Oconee Nuclear Station. The
licensee stated that this project will fully incorporate Keowee
into the Oconee nuclear maintenance program and satisfy all open
commitment items. The project is scheduled for completion no
later than January 1996.
b.
Review of SITA Items
During the inspection period, the inspectors confirmed that all
NRC open items related to Oconee emergency power were addressed by
the Emergency Power Upgrade Project. Additionally, the inspectors
reviewed the status of the May 15, 1992, SITA. The inspectors
noted that there were 86 SITA items (findings, followups, and
document discrepancies) that required a written response with
proposed corrective action to Duke's Quality Verification group in
Charlotte. Thirty of these SITA items remained to be completed by
Oconee. The inspectors reviewed the 30 open SITA items to
determine if they were being appropriately dispositioned. The
inspectors verified that all 30 open items were included in either
the Emergency Power Upgrade Program or the Problem Investigation
Process. A detailed review of several of the SITA items was
conducted to determine the adequacy of the licensee's response.
The results of this review were as follows:
(1) SITA item 3.1.4-1, "The Keowee Station has not been Analyzed
for Flooding" (Emergency Power Upgrade Project Item #26)
The SITA auditors identified a finding where the Keowee
units could be incapacitated due to internal flooding. The
source of flooding was listed as a break in the service
water line, a fire hose or the drinking water system. The
recommended corrective action from the audit team was to
10
assess the effect of flooding on the Keowee units. Oconee's
response to this finding was that no flood analysis for the
Keowee units was necessary. The basis for this position was
that, according to the Oconee licensing basis, the flood
does not occur simultaneously with nor subsequent to any
other accident condition. Therefore if internal flooding
rendered both Keowee units inoperable, the appropriate
Technical Specification would be entered. The inspectors
confirmed that the Oconee licensing basis does not postulate
any mechanical passive failures coincident with, or
subsequent to, a loss of offsite power (LOOP).
The
inspectors concluded that the licensee's position on this
item was acceptable.
(2) SITA item 3.8-1, "Problems Associated with the Integrated
Systems Analysis (ISA) Report 81-04" (Emergency power
upgrade project Item #30)
This finding was due to perceived problems.associated with
ISA Report 81-04. This report assessed the ability of the
station to perform ten basic shutdown functions following a
seismic event. The finding stated that basic assumptions in
this report that certain initiating events were outside the
licensing basis were incorrect. The Oconee site response
was that this ISA Report does not represent a licensing or
design basis document. Accordingly, the inspectors verified
that ISA Report 81-04 was not intended to be used as a
reference by licensee personnel.
Within the areas reviewed, licensee activities were satisfactory.
5.
Plant Support (71750 and 40500)
a.
Fire Protection
During the course of normal tours, the inspectors routinely
examined facets of the licensee's fire protection plan. The
inspectors reviewed transient fire loads, flammable materials
storage, housekeeping, control of hazardous chemicals, ignition
source/fire risk reduction efforts, and fire barriers.
b.
During this inspection, the inspectors toured the protected area
and noted that the perimeter fence was intact and not compromised
by erosion or disrepair. Isolation zones were maintained and were
clear of objects which could shield or conceal an individual.
The inspectors observed that personnel and packages entering the
protected area were searched either by special purpose detectors
or by a physical patdown for firearms, explosives, and contraband.
The processing and escorting of visitors was observed.
11
c.
Radiological Protection Program
Radiation protection control activities were observed to verify
that these activities were in conformance with the facility
policies and procedures, and in compliance with regulatory
requirements. These observations included:
-
Entry to and exit from contaminated areas, including stepoff
pad conditions and disposal of contaminated clothing
-
Area postings and controls
-
Work activity within radiation, high radiation, and
contaminated areas
-
Radiation Control Area (RCA) exiting practices
-
Proper wearing of personnel monitoring equipment, protective
clothing, and respirator equipment
d.
Licensee Self-Assessment
On April 19, 1995, the inspectors attended the licensee's
Corrective Action Continuous Improvement Team (CACIT) meeting. The
meeting addressed the program status and implementation of
corrective actions, performance goals, trend reviews, and
effectiveness. Site senior management participated in the meeting
and informed the committee that the number of overdue items were
expected to be reduced to zero within the near future.
On April 20, 1995, the inspectors attended a Plant Operations
Review Committee (PORC) meeting. The principal topic of the
meeting was the slow rod drop times during the April 14, 1995,
Unit 2 trip, and the implications for Unit 1. As discussed in
paragraph 2.e above, the licensee decided to shut down Unit 1 in
order to measure the control rod drop times.
The inspectors
concluded that the PORC encouraged an open discussion of the
issues involved, with a proper focus on safety.
Within the areas reviewed, licensee activities were satisfactory.
6.
Inspection of Open Items (92901, 92902 and 92903)
The following open items were reviewed using licensee reports,
inspection record review, and discussions with licensee personnel, as
appropriate:
a.
(Closed) Unresolved Item 50-270/95-03-03, Valve Configuration
This issue involved a mispositioned Unit 2 valve in the CCW system
(2CCW-110) that was discovered on March 23, 1995. The valve had
been closed for a hydrostatic leak test and was not reopened at
12
the completion of the test on November 4, 1994.
The licensee had
relied on a system realignment to return the valve to the required
open position.
However, the system realignment had been performed
prior to completion of the hydrostatic test and the valve was not
returned to its open position. This event was described as
similar to an event discovered on August 15, 1994, when the
licensee had found comparable valves misaligned in the CCW System
on Units 1 and 3. The licensee had relied on a system realignment
after a hydrostatic test to restore the valves to their required
position. Again, the system had already been realigned prior to
completion of the testing activities.
Corrective actions taken by the licensee as a result of the valve
configuration problems identified on August 15, 1994, were
implemented on March 14, 1995. This included change 26 to
MP/0/A/1720/010, System/Component Hydrostatic Test Controlling
Procedure, to require a listing of each component to ensure proper
system realignment after completion of hydrostatic testing. Since
the licensee identified the second occurrence and it was prior to
implementation of actions designed to prevent recurrence of the
previous event, associated corrective actions were determined by
the inspectors to be acceptable. This item is closed.
b.
(Closed) Unresolved Item 269,270,287/94-16-03, Engineered
Safeguards Wiring Discrepancies
This item involved a design deficiency associated with the
Engineered Safeguards cabinets. During post-modification testing
conducted on Unit 1 during a scheduled refueling outage, the
licensee identified that the manual control relays inside the
engineered safeguards (ES) unit control modules were connected to
the instrument ground system. The electrical circuit for manual
control after an ES actuation are dependent on the instrument
ground system, through the station ground system and the KRA
regulated power panelboard neutral conductor, to the 120 volt
vital power inverters neutral conductor. The instrument ground
system, station ground system, and regulated power supply system
are not considered safety-related. The electrical circuit relied
on a common electrical cable in several locations to maintain an
electrical circuit for manual control of ES components following
an ES actuation.
The licensee modified the Unit 1 circuitry during the refueling
outage and performed an operability evaluation on the Unit 2 and 3
ES systems. The operability evaluation determined that the ES
systems were operable based on the fact that the grounding systems
were passive and no credible single failure could be postulated
for any design basis events. The inspectors verified that the
Unit 2 and 3 ES systems were subsequently modified to correct the
design deficiency. Unit 2 was corrected by Minor Modification
6710 and Unit 3 was corrected by Minor Modification 6711. Based
on these actions, this item is closed.
7.
Exit Interview
13
The inspection scope and findings were summarized on May 8, 1995, with
those persons indicated in paragraph 1 above. The inspectors described
the areas inspected and discussed in detail the inspection findings.
The licensee did not identify as proprietary any of the material
provided to or reviewed by the inspectors during this inspection.
Item Number
Status
Description and Reference
Violation 269,270,
Open
Inadequate Corrective Action
287/95-06-01
for Control of Keowee Operating
Limits (paragraph 2.d).
Unresolved Item
Closed
Valve Configuration (paragraph
270/95-03-03
6.a).
Unresolved Item
Closed
Engineered Safeguards Wiring
269,270,287/94-16-03
Discrepancies (paragraph 6.b).
0II
0