ML20056E865
| ML20056E865 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 08/04/1993 |
| From: | Belisle G, Taylor D, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20056E835 | List: |
| References | |
| 50-338-93-19, 50-339-93-19, NUDOCS 9308250246 | |
| Download: ML20056E865 (11) | |
See also: IR 05000338/1993019
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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REGION 11
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101 MARIETTA STREET. N.W., SUITE 2930
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ATLANTA GEORGIA 33323-0199
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Report Nos.: 50-338/93-19 and 50-339/93-19
Licensee:
Virginia Electric & Power Company
5000 Dominion Boulevard
Glen Allen, VA 23060
Docket Nos.: 50-338 and 50-339
Facility Name: North Anna 1 and 2
Inspection Conducted: June 20 - July 17, 1993
Inspectors:
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J. YorR; Actirig/Sgt)ior Resident inspector
Date' Signed
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D. R. T&ylor,'Rfs) dent Inspector
Dits/ Signed
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Approved by:
G. A. Belisle, Sec'tivn Chief
Dits' Signed
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Division of Reactor Projects
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SUMMARY
Scope:
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This routine inspection by the resident inspectors involved the following
areas: plant status, operational safety verification, maintenance
observation, and surveillance observation.
Inspections of licensee backshift
activities were conducted on the following days: June 26, 27, July 10, and
11.
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Results:
In the operations area:
Poor communications on the part of an operating crew resulted in a deviation
report being initiated for non-operable charging pumps.
It was later
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determined that one charging pump was always operable. However, several
weaknesses were identified including operator communications, log taking, and
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documenting work and post-maintenance testing completion (para 3.a).
A violation was identified where an emergency diesel generator muffler bypass
valve was found only partially open. A similar violation was issued on
March 20, 1992, for which the corrective action should have prevented the most
recent violation (para 3.b).
9308250246 930805
ADOCK 05000339
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AFW pump discharge header pressure control valves were found incorrectly set.
The condition was discovered by an alert Shift Technical Advisor during a
system walkdown. The as-found position did not render the auxiliary feedwater
pumps inoperable (para 3.d).
In the engineering / technical support area:
The licensee's response to NRC Bulletin No. 93-02, Debris Plugging of
Emergency Core Cooling Suction Strainers, appeared to be thorough and did not
indicate problems with the potential for debris plugging (para 3.c).
In the maintenance / surveillance area:
Troubleshooting of rod control system problems was well controlled. Thorough
briefings, clear direction and good communication were noted ipara 4).
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REPORT DETAILS
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1.
Persons Contacted
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Licensee Employees
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L. Edmonds, Superintendent, Nuclear Training
- R. Enfinger, Assistant Station Manager, Operations and Maintenance
J. Hayes, Superintendent of Operations
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D. Heacock, Superintendent, Station Engineering
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- G. Kane, Station Manager
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- P. Kemp, Supervisor, Licensing.
W. Matthews, Superintendent, Maintenance
J. O'Hanlon, Vice President, Nuclear Operations
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D. Roberts, Supervisor, Station Nuclear Safety
- R. Saunders, Assistant Vice President, Nuclear Operations (By telephone)
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D. Schappell, Superintendent, Site Services
R. Shears, Superintendent, Outage and Planning
- J. Smith, Manager, Quality Assurance
A. Stafford, Superintendent, Radiological Protection
- J. Stall, Assistant Station Manager, Nuclear Safety and Licensing
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Other licensee employees contacted included engineers, technicians,
operators, mechanics, security force members, and office personnel.
NRC Resident Inspectors
J. York, Acting Senior Resident Inspector
D. Taylor, Resident Inspector
- Attended exit interview
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Acronyms and initialisms used throughout this report are listed in the
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last paragraph.
2.
Plant Status
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Unit 1 operated at or near 100% power the entire inspection period.
Unit 2 began the inspection period at 100% power. On July 12, the unit
began a coastdown for a scheduled September 4 refueling outage. At the
end of the inspection period, the unit was at 96.5% power.
3.
Operational Safety Verification (71707)
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The inspectors conducted frequent visits to the control room to verify
proper staffing, operator attentiveness and adherence to approved
procedures. The inspectors attended plant status meetings and reviewed
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operator logs on a daily basis to verify operational safety and
compliance with TS and to maintain awareness of the overall operation of
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the facility.
Instrumentation and ECCS lineups were periodically
reviewed from control room indications to assess operability.
Frequent
plant tours were conducted to observe equipment status, fire protection
programs, radiological work practices, plant security programs and
housekeeping. Deviation Reports were reviewed to assure that potential
safety concerns were properly addressed and reported.
Selected reports
were followed to ensure that appropriate management attention and
corrective action was applied.
a.
Lharging Pump Operability
Unit 2 has three charging pumps. The A pump is powered from the H
emergency bus, the B pump from the J emergency bus, and the C pump
(a swing pump) can be powered from the H or J emergency busses.
TSs require two pumps be available with one powered from the J bus
and one powered from the H bus. A 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement is
entered with only one pump available. Normally all three pumps
are available with control switches in auto with the C pump power
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being supplied from the H bus. Upon the receipt of an ECCS
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signal, all three pumps get a start signal but only two pumps will
remain running. The two pumps that run depend on the initial pump
running configuration and will be powered from different emergency
buses. With the C pump control switch in pull-to-lock, the pump
interlock logic is designed such that both the A and C pumps are
rendered inoperable when the C pump normal supply breaker is
racked into its breaker cubicle.
The inspectors reviewed DR 93-1023, which stated that, "in process
of restoring 2-CH-P-1B to service after maintenance an approximate
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three minute period occurred during which no charging pumps were
operabl e."
The DR was initiated because it was not clear to the
STA whether all post maintenance testing had been successfully
completed and the B pump declared operable prior to returning the
C pump to its normal lineup.
When securing the B pump for
maintenance or bringing the pump back from maintenance the
procedure requires a short period of time where the C pump is in
pull-to-lock with its normal supply breaker racked in. This
condition exists while switching the C charging pump from its
normal to alternate power supply and subsequently switching it
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back. This automatically renders both the A and C pumps
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The inspectors discussed this situation with licensee management
and learned that immediately after the DR was written a SNSOC
meeting was held to determine B pump operability. SNSOC
determined that PMT requirements had been completed and the pump
was operable prior to the A and C pumps being made inoperable for
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the three minute period. To independently verify SNSOC's
conclusi,ns, the inspectors obtained copies and reviewed all the
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maintenaace work packages for work performed during the B charging
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pump maintenance window.
In parallel with this, the licensee,
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with help from CNS, continued their investigation.
Further, the
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licensee called in all personnel involved with the event for an
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information gathering meeting.
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The inspectors attended that meeting which was held on June 25.
Through discussions with the persons involved and independent
review of post maintenance test data, the inspectors concluded
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that the B charging pump was operable when the A and C pumps were
made inoperable. However, the inspectors noted the following
weaknesses:
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The STA brought up the concern for rendering all charging
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pumps inoperable to the unit SRO prior to the evolution that
rendered A and C pumps inoperable. The SRO did not stop the
evolution or explain to the STA why he felt the B pump was
operable at that time. The STA felt the B pump was not
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operable because a periodic surveillance test was being run
on the B pump. A review of the PMT data sheets indicated
the surveillance was not a PMT requirement for the work
done. The surveillance was being performed because of
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normal TS requirements.
Although all PMT was completed, documentation had not been
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completed.
For example WO 163207, to install a springpack
in MOV 22878, had not been signed off as being performed or
accepted by the craft. Six other work orders had not been
signed by operations for equipment returned to service. The
SR0 was aware of the W0s and status.
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A review of the SR0 and R0 logs did not indicate when the B
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pump was declared operable. The logs did not clearly
indicate when action statements were entered and cleared.
The CNS audit review identified that OPAP-0004, Logs and
Operations Records, states that the SRO and R0 should log
entering or leaving TS action statements. For this case,
the R0 assumed the B charging pump operable based on the
fact that it was running.
The inspectors noted that the licensee's investigation into this
event was thorough. The overall conclusion by the CNS audit team
was that command and control was weak. Recent events and NRC
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inspection activities had also identified this as a concern.
b.
Operability of Unit 1 EDG IH
The inspectors reviewed DR 93-1024 documenting the 1H EDG muffler
bypass valve being found in a locked and throttled position. The
valve is required to be locked open during EDG emergency standby
operations and being throttled potentially renders the IH EDG
inoperable. This condition was reported to the NRC on
June 24, 1993, in accordance with 10 CFR 50.72(b)(2).
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The inspectors reviewed requirements for the muffler and muffler
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bypass valve. The EDG muffler bypass valve and piping were added
to each EDG per DCP 79-S14. The DCP was implemented because the
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EDGs' mufflers were not seismically supported nor missile
protected as required by UFSAR section 3.2.
Prior to implementing
the DCP, the total loss of a muffler during a tornado would not
have affected the diesel engine's performance; however, it was
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considered at that time that a direct hit by a tornado missile
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could constrict the diesel exhaust path thus potentially stop the
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diesel because of high back pressure. The DCP added a protected
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muffler bypass path which can.be isolated. The muffler bypass
path is routinely isolated by a valve during surveillance tests to
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reduce the noise level. The valve is required to be returned to
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full open following the tests. The IH EDG muffler bypass valve is
located in a tornado missile protected area above the IH EDG room.
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The valve is positioned by a chain operator located in the EDG
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room. On June 24 the muffler bypass valve was found one complete
chain revolution from full open (approximately 29% open).
The inspectors reviewed EDG operability with the bypass valve
approximately 29% open, and the muffler totally closed due to
tornado missile damage. The licensee contracted an engineering
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firm to calculate EDG loading given the above described
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conditions. The results of the calculation concluded that the EDG
would not have been capable of achieving required load. The load
requirements for this calculation assumes a loss of offsite power,
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a single failure (failure of the other EDG, IJ), and no operator
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action. The required load for the EDG for this scenario is 2314
KW. The calculated achievable load was approximately
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1700 KW.
The licensee performed several other calculations for the
evaluation of this postulated event. One calculation involved the
probability of a tornado producing a missile hit on the exposed
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part of the exhaust system. The calculations showed the
probability for this occurring would be less than 10 to the minus
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Standard ANSI /ANS 51.1-1983, Nuclear Safety Criteria for the
Design of Stationary Pressurizer Water Reactor Plants, section
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3.2.3 states that events with an occurrence frequency of less than
10 to the minus 6 need not be considered for design.
Further
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engineering evaluation and calculations revealed that a side, end,
or vertical impact by a tornado missile would develop sufficient
loads and deformations in the exhaust system that the rubber
expansion joint would separate and would not restrict the exhaust
fl ow. Therefore the EDG was not inoperable.
The licensee HPES group reviewed the incident and determined the
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most likely cause for this event was that an operator failed to
position the valve to the full open position when performing
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1-0P-6.5A,1H and IJ EDG Post Operational Check. A review of
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previous enforcement history by the inspectors identified a
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similar violation in NRC Inspection Report No. 50-338,339/92-03.
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The inspectors reviewed corrective actions for this similar
violation (50-338/92-03-01) which should have prevented this
condition from recurring. This violation, the IJ EDG muffler-
bypass valve was closed when required to be open, occurred on
January 5, 1992. The licensee responded to the violation as
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follows:
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The section on the chain for the EDG exhaust muffler bypass
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valve operators where it locks to the stanchion has been
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painted and labels have been installed in the EDG room
indicating that the muffler bypass is open when the padlock
is secured through the painted (red) chain links.
The governing procedure for the evolution, 1-0P-6.5A, has
been revised to require independent verification following
valve repositioning.
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Opening the muffler bypass valve from full closed takes
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approximately 1-1/2 full revolutions of the chain. The painted
(red) chain link pass the stanchion at approximately 1/2
revolution and again when full open at 1-1/2 revolutions. When
the valve was discovered throttled on June 24, the valve chain was
1/2 revolution from having the valve full closed. The muffler
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bypass valve local position indication can be seen from the
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ventilation penthouse on the EDG roof building.
The inspectors
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examined the local indication and noted that the valve position
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was 29% from full closed. The inspectors also verified other EDG
muffler bypass valve positions and these were all full open.
Further, the inspectors reviewed 1-0P-6.5A and it clearly
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specifies that it takes approximately 1-1/2 revolutions of the
chain to fully open the valve.
Failure to position the EDG muffler bypass valve in accordance
with 1-0P-6.5A is identified as similar violation 50-338/93-19-01.
c.
NRC Bulletin No. 93-02-Debris Plugging of ECC Suction Strainers
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This bulletin notifies licensees of an additional potential
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contributor (mineral wool insulating material) for blocking the
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containment sumps during the recirculation phase of a LOCA. The
licensee responded that in accordance with existing programmatic
controls, temporary fibrous material is not left in containment
during plant operation.
The inspectors reviewed operating procedure 1-0P-1B, Containment
Checklist, Rev.13, dated April 23, 1993.
Beside verifying that
the ventilation systems are properly operating, this procedure is
used to verify that no loose debris, which could cause sump
restriction during LOCA conditions, is left in containment. The
procedure requires a visual containment inspection to be conducted
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at the end of an outage and a final walkdown is performed by an
SRO. The procedure instructs that it is necessary to remove any
rags, trash, clothing, and any other material that could cause a
problem in the sump. This procedure is very detailed and requires
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an individual cleanliness sign off for each containment level.
A thorough evaluation was conducted by engineering on material
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permanently installed in containment. The evaluation considered
coatings, insulation, fire stop damming materials, and ventilation
filters. None were considered potential problems for plugging of
ECC suction strainers.
d.
AFW Pump Operation
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On June 22, the inspectors were informed by the licensee that AFW
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discharge header pressure control valves 2-FW-PCV-259A and B were
controlling at about 750 psig instead of 900 psig. The valves are
designed to maintain 900 psig at the discharge of the motor driven
AFW pumps. This back pressure prevents pump runout when steam
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generator pressure is far below normal such as in a steam line
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break event, which would significantly reduce steam pressure.
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During normal pump operation (with S/G pressure > 900 psig), the
valves are full open. The condition was discovered by an alert
STA during a system walkdown. The STA noted header pressure below
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800 psig with the valves still open.
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The inspectors observed I&C technicians obtain as-found settings
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for these Unit 2 valves and verified the as-left setpoints were
properly set to modulate at 900 psig. The Unit 1 valves were
checked and found to be set correctly.
Based on the as-found setpoints of the Unit 2 valves, the
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operability of the AFW pumps was questioned by the inspectors.
The licensee conservatively estimated the AFW pumps would develop
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a flow of 750 gpm based on the as-found setpoints of the pressure
control valves.
The pump head curves provided with the AFW pumps
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only went to 700 gpm. Based on the estimated flow, it could not
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be determined by the pump curves whether adequate NPSH would be
available to keep the pump from experiencing severe cavitation.
The vendor was contacted for additional information.
Based on a
curve developed for a- similar pump (same pump model utilizing same
impeller patterns) where more extensive (higher flow) NPSH testing
was performed, the vendor indicated that at 40 feet of available
NPSH, the pumps can discharge 750 gpm without significant
cavitation. The licensee demonstrated that, using an initial
minimum condensate storage tank level, it would take approximately
30 minutes for the available NPSH to decrease to less than 40
feet. Per the E0Ps, the operators would throttle the AFW pump
flow within 30 minutes of the onset of a design basis steam line
break. The inspectors independently reviewed the head curves
provided by the vendor and the licensee's conclusions. The
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inspectors concurred that the pumps would have operated if called
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upon during a design based steam line break.
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At the end of the inspection period, the inspectors were
continuing to look at the procedures and requirements for the
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incorrectly set pressure control valves.
One violation was identified.
4.
Maintenance Observation (62703)
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Station maintenance activities were observed / reviewed to ascertain that
the activities were conducted in accordance with approved procedures,
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regulatory guides and industry codes or standards, and in conformance
with TS requirements.
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Rod Control Troubleshooting
The inspectors reviewed DR 93-1008 which documented a rod control system
problem. On June 21, with the rod control system in auto, rods stepped
in at minimum speed with temperature mismatch less than required for rod
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insertion. This occurred several times between 3:00 p.m. and 4:00 p.m.
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Each time the operator manually withdrew the rods back to 225 steps,
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verified that Tave and Tref were matched, and returned the system to
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auto. At 4:15 p.m., rods stepped in at maximum speed (72 steps per
minute) with temperature matched. The rods stepped in 4 steps before
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the operator took rod control to manual and withdrew rods back to 225
steps. WR 022680 was initiated to correct the malfunction.
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On June 22, the inspectors observed troubleshooting of the rod control
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system. The initial troubleshooting was done per WO 163206 and
consisted of reading input and output voltages to various 7300 process
cards in the process instrumentation cabinets.
Prior to the
troubleshooting, briefings were held and communications with the control
established. Clear direction on the extent of the troubleshooting was
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provided. The troubleshooting identified that card C8-452 (Tave, Tref
mismatch summing amp) had failed.
The card was subsequently replaced,
calibrated and rod control returned to auto. The troubleshooting
evolution was well controlled.
No violations or deviations were identified.
5.
Surveillance Observation (61726)
The inspectors observed / reviewed TS required testing and verified that
it was performed in accordance with procedures, that test
instrumentation was calibrated, that LCOs were met and that any
deficiencies identified were properly reviewed and resolved.
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On July 7, the operators observed part of the performance of periodic
test 2-PT-82H, 2H Emergency Diesel Generator Slow Start Test, Rev.12,
dated January 25, 1993. The test verifies Unit 2 EDG 2H operability and
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is performed at least every 31 days. The inspectors observed part of
the test from the control room and observed part of the post operational
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check activities.
The post operational check verifies the EDG is capable of automatic
operation following shutdown.
Procedure 2-0P-6.5A, 2H and 2J Emergency
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Diesel Generator Post-0perational Check, Rev.14-P1, dated July 2,1993,
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had been amended to instruct the operator to locally verify the position
of the EDG exhaust bypass valve by going to the ventilation penthouse
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and looking at the valve position indicator. This procedure was changed
as a result of the valve position problem discussed in paragraph 3.b of
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this report. The inspectors accompanied an operator and an SRO to
verify the valve position. The inspectors identified no problems during
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the observation of the test.
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No violations or deviations were identified.
6.
Exit (30703)
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The inspection scope and findings were summarized on July 21, 1993, with
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those persons indicated in paragraph 1.
The inspectors described the
areas inspected and discussed in detail the inspection results listed
below. The licensee did not identify as proprietary any of the material
provided to or reviewed by the inspectors during this inspection.
Dissenting comments were not received from the licensee.
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Item Number
Description and Reference
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VIO 50-338/93-19-01
Failure to Follow Procedure for Positioning EDG
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Muffler Bypass Valve
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Acronyms and Initialisms
CFR
Code of Federal Regulations
Corporate Nuclear Safety
Design Change Package
DR-
Deviation Report
Emergency Core Cooling
E0P
Emergency Operating Procedure
GPM
Gallons Per Minute
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HPES
Human Performance Evaluation Section
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Instrumentation and Control
KW
Kilowatts
LCO
Limiting Condition for Operation
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Motor-0perated Valve
Net Positive Suction Head
NRC
Nuclear Regulatory Commission
Post maintenance Testing
Pounds Per Square Inch Gage
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Periodic Test
R0
Reactor Operator
S/G
SNSOC
Station Nuclear Safety and Operating Committee
SR0
Senior Reactor Operator
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TS
Technical Specification
Updated Final Safety Analysis Report
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Work Order
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Work Request
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