ML20214A385
| ML20214A385 | |
| Person / Time | |
|---|---|
| Site: | McGuire, Mcguire  |
| Issue date: | 04/30/1987 |
| From: | Guenther S, William Orders, Peebles T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20214A372 | List: |
| References | |
| 50-369-87-12, 50-370-87-12, NUDOCS 8705190432 | |
| Download: ML20214A385 (8) | |
See also: IR 05000369/1987012
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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101 MARIETTA STREET.N.W.
ATLANTA, GEORGI A 30323
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-Report Nos.:
50-369/87-12 and 50-370/87-12
Licensee:
Duke Power Company
422 South Church Street-
Charlotte, NC 28242
Docket Nos.:
50-369 and 50-370
License Nos.:
Facility Name: McGuire 1 and 2
Inspection Conduct :
Ma
, 1987 - April 24, 1987
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Inspectors:
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W. Orders,
r' esident Inspec or
Tate Signed
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5 Tiuenther, Resident Inspefor
Date $igned
Approved by:
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Y[30/87
T. A. Peebles, Se'ction Chief
Date Signed
Division of Reactor Projects
SUMMARY
Scope:
This routine unannounced inspection involved the areas of operations
safety verification, surveillance testing, and maintenance activities.
Results:
Of the areas inspected, one violation was
identified:
Failure to
follow procedure pertaining to Auxiliary Feedwater operational readiness valve
line-up.
8705190432 870430
{DR
ADOCK 05000369
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REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- T. McConnell, Plant Manager
- B. Travis, Superintendent of Operations
D. Rains, Superintendent of Maintenance
- B. Hamilton, Superintendent of Technical Services
- N. McCraw, Compliance Engineer
- M. Sample, Superintendent of Integrated Scheduling
- N. Atherton, Compliance
Other licensee employees contacted included construction craftsmen,
technicians, operators, mechanics,
security force members, and office
personnel.
- Attended exit interview
2. Exit Interview
The inspection scope and findings were summarized on April 24, 1987 with
those persons indicated in paragraph 1 above. One violation concerning
failure to follow procedure pertaining to the operation of auxiliary
feedwater was discussed.
The licensee did not identify as proprietary any
of the information reviewed by the inspectors during the course of their
inspection.
3.
Unresolved Items
An unresolved item (UNR) is a matter about which rr. ore information is
required to determine whether it is acceptable or may involve a violation
or deviation.
No unresolved items were identified during this report.
4.
Plant Operations
The inspection staff reviewed plant operations during the report period,
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to verify conformance with applicable regulatory requirements.
Control
room logs, shift supervisors' logs, shift turnover records and equipment
removal and restoration records were routinely perused.
Interviews were
conducted with plant operations, maintenance, chemistry, health physics,
and performance personnel.
Activities within the control room were monitored during shifts and at
shift changes. Actions and/or activities observed were conducted as
prescribed in applicable station administrative directives.
The
complement of licensed personnel on each shift met or exceeded the minimum
required by Technical Specifications.
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Plant tours taken during the reporting period included, but were not
limited to, the turbine buildings, auxiliary building, units 1 and 2
electrical equipment rooms, units 1 and 2 cable spreading rooms, and the
station yard zone inside the protected area.
During the plant tours, ongoing activities, housekeeping, security,
equipment status and radiation control practices were observed.
Unit 1 Operations
Unit 1 operated at 100 percent power from the beginning of the report
period until 10:15 a.m.
on April 14, 1987 when the unit experienced a
Instrumentation and Electrical (IAE) personnel had just
completed IP/1/A/3008/10, the " Turbine Auto Stop Oil Pressure Calibration"
procedure, and had Operations perform a functi_onal verification of the
pressure switches.
This involved depressing an auto-stop oil (AS0) test
switch on the digital electro hydraulic (DEH) control panel in the control
room for each pressure switch that had undergone calibration.
This
actuates a 3-way valve which isolates the pressure switch from the ASO
header and vents the switch to a drain tank to simulate a loss of ASO
pressure.
When the pushbutton was released the 3-way valve repositioned
to refill and pressurize the switch and line thereby causing a momentary
drop in sensed pressure sufficient to actuate a second pressure switch and
satisfy the two out-of-three reactor trip logic.
The licensee was able to
duplicate the situation during post-trip testing and has initiated action
to revise the surveillance procedure to prevent recurrence.
The licensee also determined that the procedure had never been performed
on a unit at power before, but there was no reason to suspect that an A50
hydraulic transient sufficient to cause a reactor trip might occur.
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All systems appeared to function normally during the trip.
Unit restart
was delayed for a period of time, however, until periodic maintenance on
the "B" train of control room ventilation and chill water could be
completed to clear the made change restrictions of Technical Specification 3.0.4.
A reactor startup began at about 11:00 a.m. the following morning,
with the unit entering mode 1 at 1:31 p.m. that afternoon.
The unit
completed the report period at full power.
A potential concern regarding the estimated critical position (ECP)
calculation came to light during the above reactor startup.
The ECP had
been calculated for a reactor startup time approximately one hour earlier
than the actual time of criticality.
Criticality was anticipated at 82
steps on control bank D, with a " window" of plus or minus 500 PCM (percent
milli-rho).
Criticality was actually achieved at Step 84 on control bank
C, which placed it above the rod insertion limit required by the Technical
Specifications, but below the ECP window.
Since the reactor had tripped
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from a 100 percent equilibrium xenon condition approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
earlier, the rapid decay of xenon (from the post-trip peak) during the
hour-long startup delay accounted for a significant portion of the error
in the ECP.
The licensee's startup procedures currently authorize an ECP
to be used for up to four hours after the estimated critical time, but the
possibility of shortening that time for fast recovery startups is being
evaluated.
The licensee's reactor group is also evaluating the other
sources of error contributing to the poor estimate of April 16.
These
issues will be tracked as an Inspectoc Followup Item (369,370/87-12-01).
A Notification of Unusual Event (N0UE) affecting both units was declared
at 7:20 a.m.
on April 16, when it was discovered that the plant's
meteorological instrumentation was inoperable.
Selected instrumentation
had been declared inoperable for maintenance on April 14.
The 7-day
technical specification limiting condition for operation action statement
did not expire until April 21.
Since this equipment was already
inoperable the operators did not immediately recognize the fact that the
operating instruments had also ceased to function during a severe
electrical storm at about 3:00 p.m. on April 15.
The licensee replaced
the damaged meteorological instruments and terminated the NOUE at
7:04 p.m. on April 16.
Unit 2 Operations
Unit 2 operated at essentially full power for the entire reporting period.
It was unaffected by the Unit 1 trip of April 15, but was subject to the
NOUE of April 16 as discussed above.
5.
Surveillance Testing
Selected surveillance tests were analyzed and/or witnessed by the
inspector to ascertain procedural and performance adequacy and conformance
with applicable Technical Specifications.
Selected tests were witnessed to ascertain that current written approved
procedures were available and in use, that test equipment in use was
calibrated, that test prerequisites were met, that system restoration was
completed and test results were adequate.
Detailed below are selected tests which were either reviewed and/or
witnessed:
PT/1/A/4601/04
RPS Channel 4
PT/0/A/4600/14C
Source Range N-31,N-32
PT/1/A/4601/01
RPS Channel 2
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PT/1/A/4208/03A
NS HX Test
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PT/1/A/4403/01B
RN Train B
PT/1/A/4206/01A
NI Train A
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PT/1/A/4451/018
YC Train B
TT/0/A/9100/187
DG Halon
PT/1/A/4450/06A
VX Train A
PT/1/A/4250/04G
PT/1/A/4403/07
RN Train A
PT/2/A/4252/01B
CA Train B
PT/2/A/4252/01A
CA Train A
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PT/2/A/4208/01A
NS Train A
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PT/2/A/4208/01B
NS Train B
PT/2/A/4209/01A
NV Train A
PT/2/A/4206/01B
NI Train B
PT/2/A/4252/01
CA Turbine Driven
6.
Maintenance Observations
Routine maintenance activities were reviewed and/or witnessed by the
resident inspection staff to ascertain procedural and performance adequacy
and conformance with applicable Technical Specifications.
The selected activities witnessed were examined to ascertain that, where
applicable, current written approved procedures were available and in use,
that prerequisites were met, that equipment restoration was completed and
maintenance results were adequate.
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a.
Halon System Maintenance
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Each McGuire unit is equipped with two emergency diesel generators
(EDGs) to supply standby power for safe unit shutdown in the event of
These EDGs are protected by a halon fire
suppression system consisting of two eight-cylinder banks (main and
reserve) for each unit.
Either bank can be selected for standby
operation by means of a local selector switch.
The selected bank is
actuated by either an automatic signal from the fire protection
system or by a manual pull lever on that bank's pilot cylinder.
The
automatic actuation signal opens a solenoid pilot valve which admits
nitrogen from a small pilot control cylinder to the pilot cylinder's
manual pneumatic actuator.
This actuates the pilot cylinder which
then supplies the additional gas pressure needed to actuate the
remaining seven slave cylinders in the bank.
While performing a performance test on February 18, 1987, Operations
personnel discovered that the manual pneumatic actuator on the Unit 2
main bank pilot cylinder did not operate properly.
The reserve bank
functioned properly and was placed in service, and a work request was
initiated to repair the defective actuator.
On March 11, 1987,
Maintenance personnel performed the " Diesel Generator Halon Cylinder
Pressure and Weight Test", MP/0/A/7400/49 on the Unit 2 main and
reserve banks.
This involved removing the manual pneumatic actuator
and its flexible connection tubing from the pilot cylinder so that
the cylinder could be weighed.
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On March 17, 1987, Instrument and Electrical personnel began work on
the Unit 2 main bank actuator and discovered that the reason for its
" failure" on February 18 was that the actuator had been incorrectly
installed.
The flexible tubing which connects the "A" and "B" ports
of the manual pneumatic actuator assembly to the actuation and slave
pilot manifolds were found reversed.
The same condition was found to
exist on the Unit 2 reserve bank pilot cylinder suggesting that those
connections had probably been reversed during the performance of
MP/0/A/7400/49 on March 11.
The Unit 1 EDG halon fire suppression system was also inspected.
The
main bank, which happened to be in service at the time, was found to
have the same problem as the Unit 2 system.
The reserve bank,
however, was properly connected and was placed in service.
When the nature of the deficiency was understood, the licensee took
prompt action to restore the degradcd halon systems to their design
configuration and to correct the cause of the maintenance error to
prevent recurrence.
Furthermore, on April 11, 1987, the licensee
conducted a special test of the EDG halon system to determine whether
the incorrectly configured manual pneumatic actuator assemblies had
rendered the systems inoperable.
The Unit 1 reserve bank was placed
in the as-found (incorrect) condition and actuated in both the
automatic and manual modes.
Five of the eight cylinders actuated in
the automatic mode and only one cylinder (the pilot) actuated in the
manual mode.
These results indicate a definite degradation in system
performance while incorrectly configured, however, the licensee's
design organization is continuing to evaluate the results to
determine whether minimum required fire suppression capability
(operability) was maintained.
The failure of MP/0/A/7400/49 to ensure the proper reassembly of EDG
halon system pilot cylinder actuator assemblies on three occasions
clearly illustrates an inadequacy in that MP and, as such,
constitutes a violation of Technical Specification 6.8.1.
As
permitted by Appendix C to 10 CFR 2, however, no Notice of Violation
is proposed and the incident is classified as a Licensee Identified
Violation (LIV 369,370/87-12-02).
b.
Fire Suppression System Maintenance
The McGuire Nuclear Station fire suppression water system (RF)
consists of three motor-driven fire suppression pumps (A, B and C)
capable of taking suction from Lake Norman and transferring water
through an associated distribution system.
The A and B pumps are
located in pits at the intake structure and are cooled by
thermostatically controlled air handling units (AHUs) mounted in
removable pit covers.
Two pumps (A and C or B and C) are required to
be operable to satisfy Technical Specification requirements.
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On February 21, 1987, the motor on the B fire pump failed,
necessitating its removal and shipment to the vendor for repair.
The
associated AHU was removed to permit the pump motor to be removed
from its pit and its electrical leads were individually taped and
tied out of the way.
On April 6, while reinstalling the B RF pump motor and its associated
AHU, an Instrument and Electrical (IAE) technician experienced a
"near miss" when, while pulling the AHU electrical leads through
their conduit, the insulating tape abraded and an electrical flash
occurred.
The licensee's investigation of the incident is on going, however, it
has been concluded that power to the AHU was never isolated by
opening the associated circuit breaker as required by the licensee's
Station Directive (No. 3.1.19), " Safety Tags, Lock-Outs , and
Delineation Tags".
The licensee is attempting to determine whether
this incident represents an isolated instance of procedural
noncompliance or a more serious deficiency in the tagging program.
The Institute of Nuclear Power Operations (INP0) also reviewed the
incident during its recent evaluation of the McGuire facility and,
according to licensee management, intends to include it as a finding
in the Operations area.
Although this incident represents a
violation of the station's tagout procedure and, therefore, Technical Specification 6.8.1, no Notice of Violation is proposed at this time
pursuant to the memorandum of understanding between the NRC and INP0.
This item will, however, be carried as an Inspector Followup Item
(IFI-369,370/87-12-03).
7.
Auxiliary Feedwater (CA) System Walkdown
Accessible portions of the Unit 1 CA System were walked down during the
inspection period to verify proper standby alignment in accordance with
OP/1/A/6250/02, " Auxiliary Feedwater System".
Some material deficiencies
were detected (missing valve handle, loose packing gland retainer, missing
vent pipe cap) and reported to the licensee for correction.
Subsequent
inspection revealed that the identified deficiencies had been remedied.
On April 8,1987, the inspector identified two valves on Enclosure 4.5,
the valve checklist, of OP/1/A/6250/02 that were in other than their
specified positions.
Valves ICA-153 and 1CA-154 isolate CA storage tank
overflow to the Unit 1 and Unit 2 condensate storage tanks, respectively.
In a normal standby configuration, both the makeup to and the overflow
from the CA storage tank are aligned to Unit 1 (i.e. , ICA-153 is open and
1CA-154 is closed).
Upon finding the apparent misalignment the inspector consulted the
Operations Shift Supervisor to obtain verification that the valves were,
indeed, out of their normal positions and to determine whether the out of
normal operating condition was justified.
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OP/0/A/6100/09, " Removal and Restoration (R&R) of Station Equipment", is
normally used to provide the o)erators with an up to date status of all
out of normal operating conditions by maintaining an R&R checklist in the
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control room until the equipment is returned to normal service.
The
on-duty SS was unable to find an active R&R checklist to document the out
of normal CA alignment and referred the problem to another Operations
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staff member for resolution.
Further discussions with the Operations staff on April 9 confirmed that no
R&R checklist had been completed to cover the deviation from the normal CA
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alignment.
They speculated that the CA storage tank makeup and overflow
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had been transferred from Unit 1 to Unit 2 on February 17 when a leaking
plant heating converter caused the Unit 1 secondary system sodium
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concentration to go out of specification (as documented in NRC Inspection
Report 369,370/87-05),
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Although the actual alignment of the CA storage tank to.either Unit 1 or 2
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is of minimal significance, the fact that the Operations Staff failed to
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maintain an accurate status of an out of normal operating condition as
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required by the R&R procedure is evaluated as an apparent violation of
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Technical Specification 6.8.1 (369/87-12-04).
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