ML20034G034
| ML20034G034 | |
| Person / Time | |
|---|---|
| Site: | Summer  |
| Issue date: | 02/22/1993 |
| From: | Cantrell F, Haag R, Keller L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20034G026 | List: |
| References | |
| 50-395-93-03, 50-395-93-3, NUDOCS 9303080083 | |
| Download: ML20034G034 (14) | |
See also: IR 05000395/1993003
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UNITED STATES
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NUCLEAR REGULATORY COMMisslON
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REGION 11
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101 MARIETTA STREET, N.W.
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ATLANTA, GEORGI A 30323
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Report No.:
50-395/93-03
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Licensee:
South Carolina Electric & Gas Company
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Columbia, SC 29218
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Docket No.: 50-395
License No.: NPF-12
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facility Name: Virgil C. Summer Nuclear Station
Inspection Conducted: January 9 - February 7, 1993
Inspectors:
T. M. b@
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R. C. Haag, Senior Resident Inspector
Date Signed
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M Y.lb[N
2/22h3
L. A. Keller, Resident 0 Inspector
Date Signed
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Accompanying Personnel: Tom Farnholtz
Mike Morgan
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Approved by:
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Flo d S. Cantrell,Thfef',
Date Signe'd
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Reactor Projects Section IB
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Division of Reactor Projects
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SUMMARY
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Scope:
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This routine inspection was conducted by the resident inspectors onsite in the
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areas of monthly surveillance observations, monthly maintenance observations,
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operational safety verification, preparations for refueling and onsite follow-
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up of events at operating power reactors.
Selected tours were conducted on
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backshift or weekends. These tours were conducted on six occasions.
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Results:
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A violation was identified involving the failure to establish a written
procedure for a test activity where a jumper was used for connecting test
equipment to safety-related plant equipment (paragraph 3). . A non-cited
violation was identified for a mispositioned switch on the local control panel
for "A" train containment hydrogen analyzer (paragraph 3). The electricians
performing a PM test on a SW booster pump breaker did not appear to have a
good understanding of the testing details specified in the procedure
(paragraph 4).
Information regarding chill water chiller performance was not
9303080083 930225
ADOCK 05000395
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being completely forwarded from operations to engineering as required by a
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nonconformance notice disposition-(paragraph 5).
For the reactor trip that
resulted from a load rejection of the main generator, effective operator
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response and management involvement minimized the challenges to the plant and
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aided in the successful event response (paragraph 7).
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REPORT DETAILS
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1.
Persons Contacted
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Licensee Employees
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F. Bacon, Manager, Chemistry
W. Baehr, Manager, Health Physics
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K. Beale, Supervisor, Emergency Services
- C. Bowman, Manager, Maintenance Services
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- M. Browne, Manager, Design Engineering
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- B. Christiansen, Manager, Technical Services
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- M. Fowlkes, Manager, Nuclear Licensing & Operating Experience
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S. Furstenberg, Associate Manager, Operations-
W. Higgins, Supervisor, Regulatory Compliance
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- A. Koon, Nuclear Operations Project Coordinator
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- D. Lavigne, General Manager, Nuclear Safety
- T. McAlister, Supervisor, Quality Assurance
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- K. Nettles, General Manager, Station Support
H. O'Quinn, Manager, Nuclear Protection Services
M. Quinton, General Manager, Engineering Services
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- J. Skolds, Vice President, Nuclear Operations
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- G. Taylor, General Manager, Nuclear Plant Operations
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- R. Waselus, Manager, System and Performance Engineering
- B. Williams, Manager, Operations
- R. White, Nuclear Coordinator, South Carolina Public Service
Authority
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Other licensee employees contacted included engineers, technicians,
operators, mechanics, security force members, and office personnel.
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- Attended exit interview
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Acronyms and initialisms used throughout this report are listed in the
last paragraph.
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2.
Plant Status
The plant operated at 100 percent power until January 12, 1993, when a
reactor trip occurred due to the unexpected opening of the main
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transformer output breaker. The reactor was made critical on January 14,
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1993.
Full 100 percent power operation did not occur until January 21,
1993, due to problems with the main feedwater pumps. On January 28,
1993, power was reduced to 85 percent for approximately one day for
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vibration repairs on "A" main feedwater pump and calibration of a
condensate flow control valve. On February 3, 1993, power was reduced to-
. 90 percent for additional vibration repairs on
"A" main feedwater pump.
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On February 4, 1993, power was returned to.100 percent and remained at
that level through the remainder of the inspection period.
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Other inspections or meetings:
During the week of January 11, 1993, a regional inspection in the
area of emergency preparedness was performed (NRC Inspection Report
No. 395/93-02).
Floyd Cantrell, Section Chief, DRP, was onsite January 13-15, 1993,
to review resident inspector activities, tour the plant and meet
with licensee management.
During the week of January 25, 1993, a regional inspection in the
area of motor operated valve testing was performed (NRC Inspection
Report No. 395/93-04).
On January 29, 1993, a meeting with licensee management personnel
and NRC personnel was conducted in the Region 11 office to discuss
the upcoming refueling outage, which is scheduled to start on
March 5, 1993.
During the week of January 25, 1993, Mr. Motohisa Mizuno, of the
Japan Ministry of International Trade and Industry, was onsite to
observe activities of the resident inspectors and to tour the plant.
3.
Monthly Surveillance Observation (61726)
The inspectors observed surveillance activities of safety-related
systems and components listed below to ascertain that these activities
were conducted in accordance with license requirements. The inspectors
verified that required administrative approvals were obtained prior to
initiating the test, testing was accomplished by qualified personnel in
accordance with an approved test procedure, test instrumentation was
calibrated, and limiting conditions for operation were met. Upon
completion of the test, the inspectors verified that test results
conformed with technical specifications and procedure requirements, any
deficiencies identified during the testing were properly reviewed and
resolved and the systems were properly returned to service.
Specifically, the inspectors witnessed / reviewed portions of the
following test activities:
Visual instection and functional testing of reactor building spray
system snubbers (STP 803.002 and STP 803.003). These procedures are
performed to satisfy the requirements of TS 4.7.7.
All activities
observed were satisfactory.
Monthly analog channel operational test for main steam line
radiation monitor RMG 19A (STP 360.010).
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Sampling the spent (uel pool ventilation system charcoal absorber
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material (STP 455.001). The charcoal material was withdrawn from
the filter housing to allow filling three previously used test
canisters and for the sample to be analyzed.
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Growl test and silent actuation test of the early warning siren
system (EPP 022).
These tests were performed at the control room
actuation panel and the TSC early warning system control station
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after a modification was completed to perform continuous testing of
the activation transmitters.
In July, 1992, the licensee discovered
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that a failed power supply had rendered the control room and the TSC
activation transmitters inoperable.
Based on the frequency of
personnel monitoring the system, the licensee estimated that this
condition existed for less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The newly installed
testing system will monitor each of the four activation stations and
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will provide an alarm in the control room within 60 minutes, if any
station is inoperable.
Local leak rate test of penetration XRP 0101 for the reactor
building purge ventilation system (STP 215.002A). The exhaust
penetration which contained valves XVB 2A and 2B was included in the
test.
Monthly test of "A" containment hydrogen analyzer (STP 302.006).
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During the initial portion of the test, the 1&C technicians
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discovered that the "as-found" position of the functional selector
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switch on the local control panel was incorrect. The switch has
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three positions:
sample, zero and span. The zero and span
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positions are used for calibration of the analyzer, while the sample
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position is required for monitoring containment hydrogen
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concentration.
The "as-found" condition of the switch was in the
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span position.
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The hydrogen analyzers are normally maintained in the standby mode.
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To sample the containment atmosphere, several valves must be opened
and a control room switch must be moved from the standby to analyze
position. The licensee stated that the mispositioned switch would
have been easily detected if the analyzer had been put into
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operation. This was based on the analyzer trouble annunciator
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coming into alarm when the control room switch was placed in the
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analyze position.
After reviewing the hydrogen analyzer technical
manual, the inspector agreed that an alarm would be received if the
functional selectnr switch is in the span position. The licensee
believes the mispositioned switch resulted from the previous monthly
test when the switch was not repositioned to " sample" as required by
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the STP.
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Step 7.12.3 of the STP clearly states to place the functional
selector switch in the sample position, while step 7.12.6 states to
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verify that the analyzer trouble alarm is clear. Also, step 7.13
requires that a sacond technician verify all restoration steps of
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section 7.12 wer
arformed properly.
Each of these three steps
provided separate opportunities to ensure the functional selector
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switch is properly positioned. The licensee noted that the trouble
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alarm in the control room could have been clear when performing step
7.12.6, if an additional task of step 7.12.3 was also not performed.
Based on the above information, the inspector concluded that the
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exact cause of the mispositioned switch could not be determined;
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however, it is clear that several steps / actions required by the STP
were not performed to allow mispositioning of the switch.
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Section 6.8.1 of TS requires that written procedures be established,
implemented and maintained for surveillance and testing activities
of safety-related equipment. The failure to return the functional
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selector switch to the sample position is identified as a non-cited
violation (NCV 93-03-01). This violation will not be subject to
enforcement action because the licensee's efforts in identifying and
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correcting the violation meet the criteria specified in Section
VII.B. of the Enforcement Policy.
The licensee initiated a root
cause evaluation of this event to determine if improvements are
warranted. The inspectors will followup on the licensee's
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evaluation and any resulting actions.
Quarterly operation stroke test of the steam generator blowdown
isolation valves XVG 503A, B, and C (STP 136.001).
Testing electrical switchgear protective relays (EMP 190 series).
Electricians from the relay department of SCE&G's transmission and
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distribution division were performing the tests and calibrations.
Approximately 105 relays were tested or plan to be tested prior to
the upcoming refueling outage. The licensee's operability
interpretation No. 87-3.8.1-1 allows testing / calibration of relays
for associated equipment that is in service providad there are at
least three relays in the scheme and only one relay is tested at a
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time.
For some protective schemes,
i.e., the EDG's, safety bus
under-voltage protection, etc., the relays can not be tested while
the equipment is in service.
While observing the testing of some BOP relays, the inspector noted
that electrical jumpers were connected from the test equipment to
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the adjacent 480 volt switchgear. The electrician informed the
inspector that the jumpers were used to obtain a source of 120 VDC
power to operate the relay while it was tested.
The relays were
solid state differential current sensing devices which require 120
VDC current for operation. The test equipment is placed on a cart
and taken out to the switchgear for the relay testing. The
inspector also learned that similar relays in safety-related buses
1DB1 and IDB2 were tested with jumpers used to obtain the 120 VDC
current.
The PM task sheets and the testing procedure, EMP 190.010,
associated with 1DB1 and 1DB2 relays were reviewed. The practice of
using jumpers between the test equipent and the switchgear is not
mentioned. The EMP only describes testing of the relays with no
instructions provided for interaction between the switchgear and the
relay during the test.
After questioning the licensee on the use of jumpers, an additional
piece of test equipment that would generate a 120 VDC power supply
was used for testing the remaining differential current relays. The
inspector reviewed the specific application of the jumpers in buses
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IDB1 and 1082 and determined that a short or problem with the
jumpers could have resulted in the differential current relays or
the local / remote control switch not being able to operate.
The
licensee noted that if a short were to occur, the electricians
should have been able to recognize the problem and inform the
operator.
The licensee stated that relay testing could be improved
by use of test equipment to obtain the 120 VDC current.
However,
they believe that the use of jumpers to connect test equipment to
safety-related equipment can be performed using " skill of the craft"
knowledge and does not require procedural instructions.
After
additional review, the inspector concluded that the practice of
connecting test equipment to safety-related switchgear is an
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activity required to be covered by written procedures.
This
conclusion is based on:
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The task authorized by operation was for relay testing, which
they believed only involved removing the relay, testing and
reinstalling the relay back into the cubical.
They were not
aware of jumpers being used in the switchgear, nor were any
other station personnel, until the inspector questioned the
practice.
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Since the task was not proceduralized, the reviews associated
with an approved procedure were not performed.
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Since the details of the task were not specified in a
procedure, the consistent use of jumpers, i.e., jumper location
in the switchgear, was not specified nor controlled.
TS 6.8.1 requires that written procedures be established for
surveillance and test activities of safety-related equipment.
In
addition, the Operational Quality Assurance Plan states that written
test procedures shall include test methods and any special test
equipment or calibrations required to conduct the test.
The failure
to establish written procedures to control jumpers used to connect
test equipment to safety-related equipment during testing activities
is identified as violation
395/93-03-02.
Quarterly testing of "A" charging / safety injection pump XPP 43A and
associated valves (STP 105.001).
Quarterly operational stroke test of the feedwater system valve as
required by Section XI of the ASME code (STP 148.001).
A portion of the relay testing which involved connecting test equipment
to safety-related switchgear was completed without a written procedure.
A mispositioned switch was identified on a local control panel for the
containment hydrogen analyzer even though the STP provides three
opportunities to ensure the switch is correctly positioned.
The
remaining tests observed were performed in accordance with applicable
procedures and demonstrated acceptable results.
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4.
Monthly Maintenance Observation (62703)
Station maintenance activities for the safety-related systems and
components listed below were observed to ascertain that they were
conducted in accordance with approved procedures, regulatory guides,
and industry codes or standards and in conformance with TS.
The following items were considered during this review:
that limiting
conditions for operation were met while components or systems were
removed from service, approvals were obtained prior to initiating the
work, activities were accomplished using approved procedures and were
inspected as applicable, functional testing and/or calibrations were
performed prior to returning components or systems to service,
activities were accomplished by qualified personnel, parts and
materials used were properly certified, and radiological and fire
prevention controls were implemented. Work requests were reviewed to
determine the status of outstanding jobs and to ensure that priority
was assigned to safety-related equipment maintenance that may affect
system performance.
The following maintenance activities were
observed:
Steam dump valve IFV02106 diagnostic testing and current to pressure
converter calibration (PMTS 0161501). The current to pressure
converter (IFY2096-MB) was calibrated in accordance with ICP 365.008
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and the valve diagnostic testing was done in accordance with ICP
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240.159.
No discrepancies were noted.
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Preventive maintenance to change the lubricating oil in "B"
booster pump bearings (PMTS P016338).
Replacement of the inboard bearing on "A" SW booster pump
XPP 45A (MRW 9204475). A previous oil sample for the bearing
indicated higher than normal wear particles (alloy steel and brass).
The chemistry report recommended that the bearing be inspected.
Based on satisfactory vibration readings, the pump remained operable
during the time period prior to the bearing inspection. While
inspection of the old bearing did not indicate any obvious problem,
maintenance personnel decided to replace the bearing.
Considering
the length of time from initiation of the chemistry report until
maintenance was performed (approximately 21 days), the inspector
found that timely corrective action was taken to resolve this
condition.
Inspection of SW pipe wall thickness using ultrasonic testing
methods (MWR 9200062). As part of the licensee's SW corrosion
monitoring and control program, ultrasonic inspections will be
performed at 58 locations either prior to or during the upcoming
refueling outage.
Installation of motion detectors near the entrance of the reactor
building personnel airlock (MWR 9350001). During the last refueling
outage (1991), the inspector identified a potential pathway for
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entry into the airlock that could be partially blocked from the
sight of the security officer at the access point. At that time the
licensee stationed an additional security officer at the airlock who
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maintained an uncbstructed view of airlock entries. Tne inspector
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observed the functional testing of the detector and noted that the
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pathway previously questioned is now monitored by the detector.
The
intent of the detectors is to aid the security officer at the
airlock access point to ensure all reactor building entries are
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properly monitored.
Replacement of the socket welded pipe stub attached to SW relief
valve XVR 3144B (MWR 9303024).
A small pinhole leak had been
earlier identified at the toe of the socket weld.
See NRC
Inspection Report No. 50-395/92-23 for a discussion on the initial
leak identification. After the pipe was removed, the inspector
viewed the pipe. The reduced wall thickness was only at a small
localized area which contained the pinhole leak.
Based on
inspection of the pipe, the inspector agreed with the licensee's
assessment thtt the identified leaks in small bore SW piping have
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not severely cegraded the structural integrity of the pipe.
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The following maintenance activities were observed when "A"
charging / safety injection pump XPP 43A was removed from service for
corrective and preventive maintenance:
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Replacement of the zinc vent and drain plugs in lubricating oil
heat exchanger with stainless steel plugs (MWRs 9002172 and
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9002173).
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Repair of minor leaks in the lubricating oil system
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(MWR 9204171).
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Semi annual leakage assessment of the pump's inboard and
outboard mechanical seals (PMTS P0163227).
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Testing "B" SW booster pump breaker XSWlDB1 05A (PMTS P0162815).
The breaker is tested every two years as part of the PM program.
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Procedure EMP 405.002, ITE Air Circuit Breaker Maintenance, was used
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to perform the test. The inspector observed the actual current flow
testing of the breaker.
The current testing was performed due to
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the solid state trip device test that was completed earlier not
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meeting the acceptance criteria.
Portions of the current test, such
as the instantaneous trip test and the short time trip test, also
failed to meet the acceptance criteria.
While observing the test,
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the inspector noted that the electricians did not appear to have a
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good understanding of the testing details in the EMP.
At the completion of the test, an electrical supervisor reviewed the
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results and directed that portions of the test be
re-performed and that a new solid state trip device be obtained for
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possible replacement. On the following day, the inspector learned
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that the breaker was tested satisfactorily and returned to service.
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During conversation with the electrical supervisor, the inspector-
was informed that the breaker met the acceptance criteria when it
was retested.
The initial test failures were attributed to
incorrect tap settings which result from a note in the EMP that was
not recognized and the use of test values that were incorrectly
obtained from a chart in the EMP. The inspector informed the
maintenance manager of the concern that the initial test failure
appeared to result from personnel not adequately performing the
procedure and a lack of knowledge concerning the test details.
In
response the inspector was informed that the maintenance manager
would observe a future breaker test in detail to determine if
procedural improvements are warranted or additional actions are
required. The inspector noted that several days after the XSWIDB1
05A test, a similar breaker test was completed by different
electricians and no problems were encountered.
The inspector will
followup on actions resulting from licensee management field
observations and also will observe future breaker testing.
All the maintenance activities observed were performed by using the
applicable procedures / instructions. However, the electricians that
were testing a SW booster pump breaker did not appear to have a good
working level knowledge of the testing details. This may have
contributed to a missed note and a misread chart in the procedure,
which caused the initial breaker test to fail.
5.
Operational Safety Verification (71707)
a.
Plant Tour and Observations
The inspectors conducted daily inspections in the following areas:
control room staffing, access, and operator behavior; operator
adherence to approved procedures, TS, and limiting conditions for
operations; and review of control room operator logs, operating
orders, plant deviation reports, tagout logs, and tags on components
to verify compliance with approved procedures.
The inspectors conducted weekly inspections for the operability
verification of selected ESF systems by valve alignment, breaker
positions, condition of equipment or component (s), and operai,ility
of instrumentation and support items essential to system actuation
or performance.
The spent fuel pool cooling system, emergency
diesel generator fuel oil transfer system and the reactor building
instrument air system were included in these inspections.
Plant tours included observation of general plant / equipment
conditions, fire protection and preventative measures, control of
activities in progress, radiation protection controls, physical
security controls, plant housekeeping conditions / cleanliness, and
missile hazards. Reactor coolant system leak rates were reviewed to
ensure that detected or suspected leakage from the system was
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recorded, investigated, and evaluated; and that appropriate actions
were taken if required. Selected tours were conducted on backshifts
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or weekends.
b.
Chill Water (VU) System Reliability
During the earlier portions of the inspection period, the inspector
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noted that several chiller trips in the secured train had occurred.
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With SW temperatures below 65 degrees Fahrenheit only'one train of
VU is operated, while the other train is secured but ready for an
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auto start. On November 6, 1992, disposition No. 29 of NCN 3645 was'
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issued. The intent of this disposition was to summarize all the
actions required by the previous dispositions and consolidate
engineering input for VU system operation.
Step 10 of the
disposition recognized that the chiller in the standby train will be
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operated to support testing of components cooled by that train of
the VU system. A caution statement notes that with chiller SW flow
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preset for a " loaded" condition, operation of chiller in an idle
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Monitoring at the chiller and identification of any trip parameter
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loop may result in a chiller trip due to insufficient loads.
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was also required per the NCN.
Information concerning abnormal
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operations and/or trips was requested to be forwarded to the system
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engineer for trending / evaluation. When questioned by the inspector,
the system engineer stated that he had only received information on
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chiller trips that appeared to have some degree of complexity or
trips that were not fully understood by operations. The inspector
questioned how adequate trending / evaluation of chiller trips could
be performed if all the information was not being provided to
engineering. The manager of system engineering was investigating
the reason why this information was not being forwarded to
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engineering and the action needed to ensure required information on
chiller performance was provided to the system engineer. The
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inspectors will continue to followup on chiller performance and
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improvements on the flow of information from operations to
engineering.
No violations or deviations were identified.
6.
Preparations for Refueling (60705)
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The inspectors reviewed the licensee's preparations for refueling.
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Applicable procedures were reviewed for technical adequacy. The
inspector observed rc:cirt inspection and storage of new fuel
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assemblies in the new fuel storage racks. The inspector also observed
the transfer of new fuel assemblies from the new fuel storage racks
into the spent fuel pool.
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Overall planning and preparations for the refueling outage appeared to
be well organized. Management was actively involved in the
preparations.
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7.
Onsite Follow-up of Events at Operating Power Reactors (93702)
At 8:54 AM, on January 12, 1993, a reactor trip occurred from 100
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percent power.
The trip was caused by the main transformer output oil
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cooled breaker (OCB) opening unexpectedly which separated the main
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generator from the switchyard. The reactor tripped due to a power
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range high flux rate signal.
Based on the design features of the plant
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and sequence of breaker openings (the main generator output breaker did
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not open until 32 seconds after the OCB opened), a fast transfer of
offsite power to the B0P electrical buses did not occur. With power
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not available to the reactor coolant pumps (RCP), the RCS was in
natural circulation flow conditions. At 10:39 AM, BOP power was
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restored via the emergency auxiliary transformers and a RCP was
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restarted at 11:15 AM which restored forced circulation in the RCS.
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The inspectors responded to the control room immediately after the
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reactor trip and observed the operator's response. The additional
operations personnel onsite during the day shift were effectively used
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in providing assistance for the operating shift. Management support
was provided in a manner similar to the TSC organization. The
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inspectors considered management's involvement and direction of the
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event recovery a positive aspect of the overall event response.
The licensee's investigation of the event identified that the OCB
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opening was caused by the spurious actuation of time delay relay 21GX-
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An indication flag and post trip tests and reviews were used to
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determine that 21GX-2 relay had actuated, however, no definite reason
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for the actuation was discovered. The licensee had several theories
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for the cause of the relay actuation, but none were fully proven.
As
part of the corrective action, 21GX-2 relay and four additional relays
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were replaced. During the plant startup, problems were encountered
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with leaking seals on the main feedwater pumps and one pump that was
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difficult to rotate.
While these types of problems were not
!
j
unanticipated due to the large transient the secondary plant
i
i
experienced from the load rejection and loss of BOP power, these
!
repairs delayed the plant startup and return to 100 percent power.
'j
.
One aspect of the event which was unexpected involved the power range
high flux rate trip signal initiating the reactor trip.
In the
accident analyses chapter of the FSAR, section 15.2.7 describes a loss
i
of electrical load and/or turbine trip event.
For end of core life
t
conditions, the FSAR states an over temperature delta T signal will
i
trip the reactor.
Based on the high flux rate bistables being tripped
!
on all four of the nuclear instrumentation cabinets and the post trip
I
events printout, the licensee is certain that high flux rate caused the
,
reactor trip. After reviewing the data and having discussions with
Westinghouse, the licensee believes the reactor trip was caused by the
t
following sequence of events:
-
Opening of the OCB removed the majority of the electrical load on
the main generator. This caused the main turbine to increase speed
i
1
- - . , , ,
-
- .
. -
_ _ .
. - - -
-_
-
-
-.
_
.
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.
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-
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11
before the mainsteam stop and throttle valves could close.
The
highest recorded turbine speed was 1863 RPMs.
(Normal 1800 RPMs)
!
-
Since the RCPs were being powered from the main generator via the
unit auxiliary transformer, the RCPs also had an increase in speed.
!
t
-
With an increase in RCP speed, flow through the core had a
corresponding increase. The relatively colder water in the core
!
caused a momentary rapid increase in neutron flux. The large MTC
!
(approximately -34 pcm per degree Fahrenheit) which existed near the
!
end of core life contributed significantly to the increase in
neutron flux.
The inspector reviewed the Westinghouse letter which documented their
,
review of post trip plant parameters and provided the bases for their
,
explanation of the high flux rate trip signal. The licensee plans to
,
review the FSAR accident analyses discussion to determine what
t
additional information is required.
-
,
8.
Exit Interview (30703)
!
The inspection scope and findings were summarized on February 8, 1993,
l
with those persons indicated in paragraph 1.
The inspectors described
!
the areas inspected and discussed the inspection findings.
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]
The licensee disagreed with the proposed Notice of Violation concerning
l
the failure to have an established procedure for testing relays while
l
connecting test equipment to safety components. The licensee did not
identify as proprietary any of the materials provided to or reviewed by
j
the inspectors during the inspection.
j
,
Item Number
Description and Reference
,
395/93-03-01
NCV - Failure to return a hydrogen analyzer
functional selector switch to the sample
_
position (paragraph 3).
l
395/93-03-02
Violation - Failure to establish written
i
i
procedures to control jumpers used to connect
'
test equipment to safety-related equipment
j
during testing activities (paragraph 3).
j
i
9.
Acronyms and Initialisms
.
l
American Society of Mechanical Engineers
!
'
B0P
Balance of Plant
!
'
EMP
Electrical Maintenance Procedure
l
Emergency Plan Procedure
Engineered Safety Feature
j
Final Safety Analysis Report
1
Instrumentation and Control
j
Instrumentation Control Procedure
!
s
!
.
.
9
'
.
12
LER
Licensee Event Reports
MTC
Moderator Temperature Coefficient
MWR
Maintenance Work Request
NCN
'Nonconformance Notice
Non-Cited Violation
Nuclear Reactor Regulation
OCB
Oil Cooled Breaker
Percent Millirho
Preventive Maintenance
PMTS
Preventive Maintenance Task Sheet
Reactor Coolant Pump
Revolutions Per Minute
Radiation Work Permits
SPR
Special Reports
Surveillance Test Procedures
TS
Technical Specifications
VDC
Volts Direct Current