ML20149K165
| ML20149K165 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 07/07/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20149K149 | List: |
| References | |
| 50-254-97-06, 50-254-97-6, 50-265-97-06, 50-265-97-6, NUDOCS 9707300027 | |
| Download: ML20149K165 (30) | |
See also: IR 05000254/1997006
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U. S. NUCLEAR REGULATORY COMMISSION
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REGION ll1
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Docket Nos:
.50-254,.50-265'
License Nos:
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Report No:
50-254/97006(DR P), 50-265/97006(D RP) -
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Licensee:
Commonwealth Edison Company (Comed)
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Facility:
Quad Cities Nuclear Power Station, Units 1 and 2
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Location:
22710 206th Avenue North
Cordova, IL 61242
Dates:
March 18 - May 5,1997
Inspectors:
C. Miller, Senior Resident inspector
K, Walton, Resident inspector
- L. Collins, Resident inspector
R. Ganser, Illinois Department of Nuclear Safety
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Approved by:
Wayne J. Kropp, Chief
Reactor Projects Branch 1
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9707300027 970707
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ADOCK 05000254
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EXECUTIVE SUMMARY
This inspection included aspects of licensee operations, engineering, maintenance, and
plant support. The report covers a 7-week period of resident inspection,
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Ooerations
Operators performed complex tasks, such as response to transients, unit startups and unit
shutdowns, well. However, several operator performance errors occurred during simple
tasks. Previous inspection reports also have discussed operator performance issues
(Sections 01.2 and 01.3).
Unit 2 fuel off-load activities were discontinued during the Unit 1 shutdown evolution to
reduce the potential for distraction. Overview personnelincluding site quality verification
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(SOV), operations, engineering and station management were present during startups and
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shutdowns (Section 01.2).
Operators appropriately responded to a loss of power on a reactor protection system (RPS)
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bus. Operators restored power to the RPS bus and reestablished shutdown cooling.
(Section 01.4).
Two violations were identified regarding document control. in one violation, operators
were using the wrong revision of a procedure which was obtained from a controlled set of
procedures. The second violation was issued regarding records where a master retention
schedule which lists required quality records and retention periods was'not maintained up-
to-date (Section 01.3 and 07.2).
Maintenance
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The inspectors observed lapses in worker attention to foreign material exclusion (FME) and
. personnelindustrial safety procedures. Radiation protection department monitoring and
control rod drive hydraulic control unit (CRD/HCU) overhaul work indicated the licensee's
continued emphasis on "as low as reasonably achievable"(ALARA) radiation dose
exposure principles (Section M1.1).
Longstanding problems with standby liquid control (SBLC) flow meters used to verify pump
operability led to a failed surveillance, entry into a limiting condition for operation (LCO),
and preparations for a unit shutdown. The adequacy of IST instrumentation is an
unresolved item (Section M2.4).
Enaineerina
The licensee's decision to expand invesselinspection activities based on information from
another nuclear facility, was both warranted and proactive (Section E1.1).
The NRC previously identified that engineering did not adequately trend or analyze room
cooler differential pressure for a period of time (see Deviation 50-254,265/96015-01).
The failure to analyze the degraded condition of the Unit 2 "B" core spray room cooler
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resulted in the licensee operating the facility for an extended period 'of time with a
potentially inoperable train of core spray (Section E2.1).
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The licensee identified on three separate occasions, broken auxiliary contact assemblies on
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4 kilovolt (kV) breakers which were planned to be installed in the facility. The licensee's
initial review of the importance of the issue was narrow in scope. However, subsequent
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breaker inspection, evaluation of the condition, and resultant shut down~of Unit 1 were
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appropriate (Section E2.3).
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Plant Sucoort '
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The first time efforts to decontaminate the Unit 2 torus suction header were partially
successful (Section R1.1).
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An incomplete understanding of the fire hazards analysis resulted in an untimely
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notification to the NRC (Section F4.1).
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Report Details
Summarv of Plant Status
Unit 1 started the period with operators decreasing load from full power to about
80 percent of full power operation due to equipment problems. During the period,
operators shut down and started up Unit 1 twice due to various equipment problems (see
chronology below) .
Unit 2 was shut down for refuel outage O2R14 on February 28,1997, and remained shut
down thr' ghout the period.
l. Ooerations
01
Conduct of Operations
01.1 General Colpments (71707)
Using inspection Procedure 71707, the inspectors conducted frequent reviews of
ongoing plant operations.
During the inspection period, several events occurred which required prompt
notification of the NRC pursuant to 10 CFR 50.72. The events and dates are listed
below.
March 19
A notification was made due to Unit 1 high pressure coolant injection
(HPCI) system being inoperable for about 75 minutes. Workers
identified a HPCI component power supply cable as degraded. The
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licensee later determined the cable was not connected.
March 21
A notification was made due to the Unit 2 "B" core spray room cooler
being inoperable due to fouling in parallel with the Unit 2 "A" core '
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spray system being inoperable due to emergency diesel generator
unavailability.
March 22
Operators shut down Unit 1 reactor due to unanticipated turbine
equipment problems requiring a longer repair time.
March 27
A notification was made due to nonconformance with a fire hazards
design requirement first identified on February 27,1996
(See Section E4.1).
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March 29
Operators startup and synchronize Unit 1 to the grid.
March 31
A notification was made due to an inadvertent start of the Unit 1
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April 3
A notification was made due to the Unit 1 high pressure coolant
injection system being declared inoperable. Subsequent
troubleshooting identified the reason for the turning gear motor
failure.
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April 7-
A notification was made due to a failure of a single train safety
system. Operators received freon alarms indicating the refrigerant
compressor unit of Train B of control room ventilation had a leak.
The leak was later repaired.
April 7
A notification was made due to flow from both Unit 1 standby liquid
control pumps being less than the inservice inspection required flow
rates. Operations commenced shutdown of Unit 1 until the test
could be repeated with properly calibrated gauges.
April 9
Operators notified the NRC that Unit 1 was shutting down due to
concerns identified with cracked auxiliary switches in 4 kV breakers.
April 18
A notification was made due to loss of Unit 1 "B" reacter petection
systern bus. Unit 1 lost shutdown cooling for several hours due to
primary containment isolation system closing the suction valve to the
operating residual heat removal pump. Various other system
isolations occurred. (See Section 01.4).
May 1
A notification was made due to Unit 1 HPCI being declared inoperable
since a code required inspection of a valve was missed.
01.2 Control Room Observations
a.
Insnection Scone (71707)
Yhe inspectors reviewed the sequence of events recorder, operator logs, and spoke
to operators concerning the feedwater heater transient. The inspectors observed
two shutdowns and two subsequent startups associated with Unit 1.
b.
Observations and Findinas
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On March 19 during Unit 1 power ascension, control room operatois received
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annunciators indicating problems with the moisture separator drain tank (MSDT)
flows to the high pressure feedwater heaters. As required by annunciator response
procedures, operators quickly reduced reactor power from about 98 percent to
about 80 percent power. To effect feedwater heater repairs, the licensee removed
the turbine from service with the reactor critical. However, af ter removing the
turbine from service, the operators noted a second electrohydraulic control (EHC)
pump started unexpectedly. This required operators to shut down the reactor on
March 22 and perform additional repairs on the EHC system.
Unit 1 was returned to service on March 29. However, on April 5 operators again
were required to reduce Unit 1 reactor power due to problems associated with
feedwater heater level control valves. Maintenance personnel adjusted a feedwater
heater level controller and Unit 1 was returned to full power operation.
On April 9 operations declared 4 kV breakers on safety-supporting electrical busses
as inoperable and shut down Unit 1 (See Section E2.3).
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With Unit 1 shut down on April 18, a loss of power to a reactor protection bus
resulted in a loss of shutdown cooling. This required operators to reset the reactor
protection system and reinitiate shutdown cooling operations (See Section 01.4).
The inspectors noted the control room atmosphere was quiet and controlled during
most evolutions. Communications and coordination efforts were conducted
smoothly with minimal distractions. A reduction in distractions was aided by the
licensee's recently implemented effort to strictly limit control room access, and to a
lesser degree, by reducing the number of phone calls to the control room.
The unit supervisors demonstrated good command and control of evolutions, and
conducted periodic briefings to ensure all operators received current information
concerning unit status. Operator communication with each other and with the unit
supervisor was good. Unit 2 fuel off-load activities were discontinued during the
Unit 1 shutdown evolution to reduce the potential for distraction. Overview
personnel including site quality verification (SOV), operations, engineering, and
station management were present during startups and shutdowns.
During one startup evolution, coordination of the nuclear station operators (NSOs)
was not commensurate with previous startups. This was primarily due to recent
reassignment of persons in key positions within the operating crew. Overall, crew
performance was adequate. All procedures were adhered to, and evolutions were
safely conducted. During a startup, the inspectors observed that operators
demonstrated professional demeanor in the conduct of unit startup evolutions. In
this example, communications, self-checking, and adherence to all procedures and
management expectations was excellent.
c.
Conclusions
Operators continued to be challenged by equipment problems requiring frequen'.
maneuvering of the units. The inspectors noted operators responded appropriately
to transients due to the equipment problems. - Unit 1 shutdowns and subsequer't
startups were well executed.
01.3 Operations Surveillances
a.
insnection Scooe (71707)
The inspectors observed operators performing surveillances and using operating
procedures during routine control room mocitoring. The inspectors discussed with
operators the errors that had occurred during the surveillance tests.
b.
Observations and Findinos
On March 31 prior to performance of a surveillance test, an operator over
rotated the Unit 1 EDG control switch. This resulted in an inadvertent start
of the EDG. The licensee documented this on Problem Information Form
(PlF) 97-1241. The licensee determined methods used by operators to
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operate a pistol-style grip switch were poor and initiated training for
operators (See Section 08.2).
On April 3 the inspectors observed an operator performing Quad Cities
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Operating Surveillance Procedure (OCOS) 2300-01, ."High Pressure Coolant
injection Periodic Test." The operator did not set the proper pump discharge
pressure as required by the surveillance test. An operations supervisor,
performing a peer check of the reactor operator setting discharge pressure,
concurred that the proper discharge pressure was set. However, before
proceeding with the test, a third operator identified and informed both
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operators that the incorrect discharge pressure was established. The proper
discharge pressure was established and the test proceeded.
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Previously, management suggested operating crews implement peer checks
to prevent undetected human errors from occurring. Peer checks were not
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required. The inspectors spoke to management about this issue. This issue
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was not documented on a PIF and the inspectors noted management missed
an opportunity to enforce expectations with the individuals involved.
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On April 9 the inspectors observed an operator realigning the 250 VDC
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system after performance of a battery discharge test. The operator used a
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copy of Guad Cities Operating Procedure (QOP) 6900-16, " Transfer of Bus
18 from MCC [ motor control center) 1 to MCC 2," Revision 8, from a
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controlled procedure book. During the procedure, operators in the plant
performed steps not recognized in the control room copy of the procedure.
The operator identified that the control room copy of.the procedure did not
have the proper revision. The operator stopped the procedure, reconciled
differences between the two revisions, and completed the procedure. This
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condition was documented on PlF 97-1540.
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Revision 9 to the procedure returned both 250 VDC buses 18 and 2A to
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their normal source. However, Revision 8 to the procedure only returned
250 VDC Bus 1B to the normal source. Bus 2A powered important safety-
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related components in Unit 2. However, Unit 2 was shut down at the time
of the event and components powered by Bus 2A were not required by
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Technical Specifications (TSs).
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The licensee acknowledged the failure of two barriers to prevent the use of
incorrect revisions of procedures. The operator did not ensure the proper
revision was in hand prior to performing the procedure and the wrong
procedure revision was included in the control room controlled procedures
book. The failure to maintain the proper revisions of operating procedures in
control room controlled procedure books and the failure to ensure the use of
the proper revision of the procedure was considered a Violation (50-
254:265/97006-01) of 10 CFR Part 50, Appendix B, Criterion VI,
" Document Control."
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On April 15 the inspectors observed control room operators during the
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performance of Quad Cities Operating Surveillance Procedure (OOS)
6500-03 "4 kV Bus 14-1 Undervoltage Functional Test." The surveillance
test was required to demonstrate the undervoltage relay operation and load'
shedding upon loss of voltage to Bus 14-1 and to verify that the Unit 1
diesel generator started and loaded in the required time. Bus 14-1 was a
safety-related 4 kV bus that supplied power to emergency core cooling
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pumps.
The procedure allowed for the prerequisite steps to be performed in any
logical order. Several of the prerequisite steps were performed by control
room operators on the night shift. The day shift operators continued the
procedure. Step C.1.t stated, Verify "At 901-8 Panel, BUSSES 14-1 and
24-1 TIE ACB is closed." The step was initialed as completed but the
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breaker remained in the open condition. One of the load shedding functions
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to be tested included the tie breaker between the Unit 1 Bus 14-1 and the
Unit 2 Bus 24-1. However, the test required that the tie breaker be closed
to verify that it opened properly during the undervoltage test. Immediately
after the undervoltage signal was introduced, the control room operator was
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required to verify that; the Unit 1 diesel generator automatically started,
Annunciator E3,4 kV Busses 13-1/14-1 low voltage alarmed, and the Bus
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14-1 and 24-1 tie breaker tripped. The operator could not verify that the tie
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breaker had tripped since it was already open. The failure to properly
implement the test procedure was a Violation (50 254:265/97006-02) of
TS 6.8. A.
Immediately af ter the discovery of the discrepancy, the operators generated
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PIF 97-1779 to document the error. The engineering staff wrote interim
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procedure 97-0057 to perform a modified version of the test to verify that
the tie breaker tripped on an undervoltage condition on Bus 14-1.
The cause was considered to be a procedural adherence failure.
Management recently emphasized the use of " peer check" for operators to
prevent such errors. In this case, peer check could have prevented the error
from occurring, but was not used. Another barrier to prevent such errors,
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the test briefing, failed to identify that the required test configuration did not
match the plant configuration.
c.
Conclusion
During this inspection period, the inspectors were concerned with operator errors,
and the effectiveness of the operator peer checks to prevent these errors. The
inspectors concluded that these errors were similar to those previously documented
in Inspection Report 50-254:265/96020 indicating a continuation of operator
performance errors.
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01.4 Loss of 1B Reactor Protection System Bus Causes Loss of Shutdown Coolina (PlF
97-1851)
a.
insoection Scooe (93702. 71707)
On April 18, the 182 electrical protection assembly (EPA) for RPS Bus 18 tripped
unexpectedly causing a loss of power to the 1B RPS bus. The loss of power
resulted in a loss of shutdown cooling and a partial primary containment isolation.
A report was made to the NRC via the emergency notification system (ENS). The
inspectors observed the restoration of shutdown cooling and followed up on the
root cause investigation and initial operator response to the event. The inspectors
reviewed the Unit 1 logbook and spoke with operators to understand the sequence
of events,
b.
Observations and Findinas
The loss of power to the RPS Bus 18 occurred at 7:27 a.m. central standard time,
when the 182 EPA deenergized unexpectedly. Two EPAs in series are designed to
protect the RPS bus from an undervoltage, over voltage, or under frequency
condition. The loss of the B RPS bus caused some valves in the primary
containment isolation system to close. As a res alt, the reactor water cleanup
(RWCU) system, which was controlling reactor watcr level, and the residual heat
removal (RHR) system, which was removing decay heat. isolated.
Prior to the event, shutdown cooling was in service and the initial reactor water
temperature was recorded as 150 degrees Fahrenheit. Operators responded to the
event and entered Quad Cities Operating Abnormal Procedure (QCOA) 1000-2,
" Loss of Shutdown Cooling," and Quad Cities Operating Abnormal Procedure (OOA)
7000-1,"120 VAC Reactor Protection Bus Failure." Per OOA 7000-1, an operator
was dispatched to the RPS bus to determine the cause of the bus deenergizing. No
obvious reason for the condition was identified. Electricians were called to assist in
checking the status of the 1B bus prior to reenergizing per QOP 70001, " Reactor
Protection System MG Sets." i9o problems were identified and the 1B RPS bus
was reenergized at 8:55 a.m. At 8:58 a.m. operators restored the RWCU system
and at 9:17 a.m. RHR shutdown cooling (SDC) was placed in operation. The
highest recorded reactor water temperature was 175.5 degrees Fahrenheit, an
increase of about 25 degrees Fahrenheit during the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and
50 minute period that SDC was off.
Based on discussions with operators, the inspectors found the first 70-80 minutes
were used for troubleshooting the 182 EPA and the 1B RPS bus to determine the
cause of the EPA trip and that the actual time spent to restore power and return
RWCU and SDC to service was approximately 30-40 minutes.
Operators considered a band of 130 to 180 degrees Fahrenheit as an administrative
limit for reactor water temperature during normal shutdown cooling operations.
The inspectors did not find any procedures that referenced these administrative
temperature limits. A review of Unit 1 plant data and log books showed that
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operators generally maintained temperature around 150 degrees Fahrenheit, but the
temperature fluctuated between 140 and 170 degrees Fahrenheit. The inspecto s
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questioned operations management about the wide temperature band and
concluded that the_130 to 180 degree temperature band was a widely understood
but informal operating range. At the end of the inspection period, operators were
reviewing past practices and procedural guidance for maintaining a temperature
band while in shutdown cooling and planned to enhance existing controls.
The failed breaker was last calibrated on April 12,1997, with satisfactory results.
Testing after the failure revealed that the breaker was tripping prematurely and
could not be reset. The breaker was replaced. The licensee reviewed five years of
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data on the EPAs and found one spurious trip of the 182 EPA had occurred in
1996. The licensee planned to upgrade the remaining EPAs with new breakers and
upgraded circuit boards. The failed breaker was sent off site to the materials
engineering group (MEG) for additional failure analysis.
c.
C_qn, clusion
The inspectors reviewed the initial operator response to the loss of shutdown
cooling event and concluded that operators followed the appropriate procedures to
restore power to the RPS bus and restore RWCU and RHR SDC. However, the
control of the limit for reactor water temperature during normal shutdown cooling
operations was not procedural defined and sometimes varied from shift to shift.
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Quality Assurance in Operations
07.1 Premature Event Screenino Committee Event Closures
The inspectors attended an event screening committee (ESC) meeting. The ESC
evaluated the quality of corrective actions and disposition of events. The licensee
has recently been using the ESC to disposition and close PIFs at an early stage to
help reduce the number of open PIFs. The inspectors found that PIF 97-1295
which involved plant oversight review committee (PORC) members not being
qualified for their function (specifically, the chairman) was closed with no corrective
action taken. The items covered during the PORC were not reboarded because the
licensee said that the function of the chairman was not critical enough to invalidate
the results in addition, no action to ensure a repeat of the failure to operate with
qualified members was called for and no action was initiated to review past
meetings for qualified members was initiated. Although PORC is not required at
Quad Cities, management has relied upon PORC as tte key organization to review
the quality cnd effectiveness of plant decisions. The inspectors concluded that ESC
decisions to close the PlF were not based on good corrective actions commensurate
with the importance of the function of PORC.
Another PIF (971243) was closed which dealt with a potential degraded condition
of fan noise on the shared EDG ventilation fan. The ESC committee closed the PIF
with the understanding that the problem occurred once and had not repeated, and
that an action request for the fan would be worked in September 1997. The nature
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of the root cause analysis, the effect of the fan's failure on EDG operability, and the
effect of the operable but potential degraded condition on the Unit 2 startup were
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not discussed. The inspectors concluded that the decisions made by the ESC about
the EDG PlF were not based on the criticalimportance of the shared EDG.
07.2 Quality Records Manaaement
a.
Insoection Scooe (39701)
The inspectors reviewed the licensee's process for identifying quality records and
specifying the required retention period in accordance with 10 CFR Part 50,
Appendix B, Criterion XVil and the Site Quality Assurance Manual. The inspectors
questioned operations, site quality verification, and office support personnel to
determine how completed procedures were documented as quality records.
b.
Observations and Findinas
The Site Quality Assurance Manual stated that the quality records program included
those record types, controls, and provisions for storage and preservation contained
in Nuclear Quality Assurance (NOA) -1, Supplement 17S-1 and that records were
administered through a system which included an index of record type, retention
period, and storage location.
The Quality Assurance Program Requirements for Nuclear Facilities outlined in
NOA 1, Supplement 17S-1, covered receipt control of records. This supplement
states that as a minimum the receipt control system shallinclude a method for
designating the required records. The receipt control section also stated that each
receipt control system shall be structured to permit a current and accurate
assessment of the status of records during the receiving process.
The inspectors reviewed UFSAR Section 13.7 covering records. The UFSAR stated
that control room record retention period was specified on the Commonwealth
Edison Record Retention Schedule forms for each record.
The inspectors reviewed the master retention schedule which was the document
intended to ipecify retention requirements for various plant procedures. The
retention schedule did not specify whether the records were considered to be
quality documents. Additionally, the retention schedule was not up to date. The
inspectors identified that outdated procedures were listed and that some currently
required surveillances were not listed. Also, new required surveillances since the
implementation of the upgraded TS in September 1996 had not been added to the
master retention schedule to designate the required retention period. The station
procedure, Quad Cities Administrative Procedure (OCAP) 1200-1, " Station
Records," stated that the responsible department records custodian shall update the
master retention schedule when a new record is created. The custodian was
responsible for determining if the record was a quality document. The inspectors
found that the procedure was recently implemented and that the department
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records custodian was not following the procedure. The operations department
records custodian told the inspectors that the custodians did not regularly review
new procedures to determine if the procedures created quality records.
The inspectors identified several surveillances and other quality records that were
not listed or were listed incorrectly on the master retention schedule including:
OCAP 0230-07, " Operability Determination"
OCCP 1200-2, " Post LOCA Hydrogen and Oxygen Monitoring System"
OCIS 2400-1, "Drywell Radiation Monitor Calibration and Functional Test"
OCOS 1600-4, " Weekly Primary Containment Oxygen Concentration"
The licensee told the inspectors that these records were properly retained even
though they were not listed on the retention schedule. The licensee was in the
process of upgrading the records management program, including the master
retention schedule, but no completion date for the project was available. The
inspectors concluded that records were not accurately identified as quality records,
and that the station was not controlling quality records in accordance with the
station procedure, the quality assurance manual and 10 CFR Part 50, Appendix B.
The failure to identify quality records and to establish retention requirements was
considered a Violation (50-254:265/97006-03) of 10 CFR Part 50, Appendix B,
Criterion XVil, " Quality Assurance Records."
c.
Conclusion
Over time, the licensee failed to ensure that the master retention schedule was
updated to include newly created quality records. The inspectors identified that
some TS required surveillances were not listed on the retention schedule and were
not designated as quality records. This was considered to be a violation of 10 CFR Part 50 Appendix B, Criterion XVil, " Quality Assurance Records."
08
Miscellaneous Operations issues (92700)
08.1 (Closed) Insoector Follow-uo item (50-254:265/96006-04): Inattentive Test
Director. The inspectors observed a test director in the control room in an
inattentive state and brought this to the attention of the shift engineer. The
licensee conducted an investigation. The individual was disciplined. The inspectors
reviewed the investigation results and consider the item closed.
08.2 (Closed) Licensee Event Reoort (LER) (50-254:265/97007): Unit 1 EDG Mar! Due
to Personnel Error. A r.oet room operator over-rotated a pistol grip stya EC'G
control switch. As a r69 ult, the Unit 1 EDG inadvertently started. The operator
was counseled and an operations supervisor provided direction to operators on
proper operation of pistol grip switches. The inspectors considered this a violation
of adherence to the surveillance procedure OCOS 6600-01, "EDG Monthly Load
Test," since the switch was to be moved to the stop position instead of the start
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position. This licensee-identified and corrected violation is being treated as a
Non-Cited Violation (50-254:265/97006 04), consistent with Section Vll.8.1 of the
NRC Enforcement Policy. This LER is closed.
08.3 (Closed) Violation 50-254:265/95005-02: Failure to Maintain the RHR Room
Watertight Door Closed in Accordance with TSs. As corrective action the licensee
developed procedure OCAP O250-06, " Control of In-Plant Watertight Submarine
Doors." This procedure provided adequate guidance for control of the watertight
doors. Several PlFs have been generated since the violation was written. Problem
Identification Form 95-2542 was written to address a worker leaving a door open
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long enough to retrieve a tool. The worker was unaware that the procedure did not
allow this practice. The licensee coached the individual on the correct use of the
procedure. Problem Identification Form 961780 was written to address an
incident where a door was found latched but not dogged. The licensee did not
determine the person responsible; however, narrowed it down to a specific work
group. As follow-up action, the licensee addressed the issue through tailgate
meetings. The licensee's vigilance and attention to maintaining the integrity of
watertight doors has been increased since June 1995 when the initiating violation
was identified. This item is closed.
08.4 (Closed) Licensee Event Reoort 50-265/95007: Unit 2 HPCI Turning Gear Motor
Failed to Start as the Turbine Coasted to a Stop. Following this event, the licensee
suspected a failure of the turning gear to properly reset. The licensee performed a
series of tests on an accelerated schedule; however, they were unable to reproduce
the failure. One of the accelerated tests resulted in a turning gear engagement
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failure due to gear abutment; however, the license"3 procedures addressed this
condition. There were two turning gear related wcurrences on the Unit 1 HPCI
since this LER. The licensee has shown that neither of these was related to the
event on the Unit 2 HPCI. This item is closed based on adequate follow-up action
by the licensee.
11. Maintenance
M1
Conduct of Maintenance (62707)
M 1.1 Observation of Maintenance Activities Durina Refuel Outaae 02R14
a.
Insoection Scone
Maintenance activities observed during this inspection period included: movement
of emergency core cooling system (ECCS) suction strainers to the Unit 2 torus,
Unit 2 turbine overhaul work, turbine stop valve HO 2-5699-MSV1 actuator rebuild,
electrical maintenance department (EMD) switch replacement work on the 2202-20
panel for hydraulic control unit (HCU) banks three and four, CRD HCU overhaul
work, snubber testing, preparation for chemical decontamination of the Unit 2
recirculation system, tube lance on the 18 control room heating ventilation and air
conditioning (HVAC) heat exchanger, electrical maintenance department (EMD)
inspection of 4 kV breaker auxiliary contact assemblies, penetration sealing and
13
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duct repair of the control room emergency ventilation system, and planned -
inspection and maintenance of the 2B recirculation system motor generator (MG)~
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set slip rings and commutator.
b.
Observations and Findinos
When workers attempted to lower the first of the new type ECCS suction
.
4
. strainers through the floor opening into the Unit 2 torus, there was
i
insufficient clearance due to interference from a section of structural steel.
Lack of adequate planning and pre-measurement caused some lost time and
j
unnecessary radiation exposure during this first attempt. All other aspects
of this effort observed by the inspectors were satisfactory.
The inspectors observed contract workers perform overhaul work on a
'e
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Unit 2 turbine stop valve actuator HO 2-5699-MSV1, in accordance with
j.
work package WR 960076977. Work procedures were conducted
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adequately, with the exception that foreign material exclusion (FME) controls
i
were somewhat lax. The inspectors observed that there were items in a
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zone 2-work area that were not logged in on the FME log sheet, specifically
some tape and gloves. The inspectors brought this to the attention of the
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workers, who did not appear to have a clear understanding of the FME
i
requirements. The workers removed the non-controlled items from the FME
5
zone. The workers discussed the procedures with the immediate supervisor
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to understand the FME requirements. The work package was current and
'
workers adequately documented the work steps when completed.
!
Overhaul work on CRD/HCUs was well coordinated. Radiation protection
e
!
personnel were assigned full time to this job to coordinate work movement
and to assure radiation exposure to workers was maintained ALARA. The
- total radiation exposure for the entire effort was approximately 55 percent of
the amount allotted. This dose savings was due to job planning and worker
diligence in minimizing dose, and by workers consistently remaining in the
lowest possible dose areas throughout the entire job.
e
The inspectors observed three scaffolding workers standing on high scaffold
elevations in the Unit 1 turbine building who were wearing fall protection
harnesses but were not hooked up to an anchor point. The inspectors
questioned the acting foreman about the safety requirement for fall
protection. The foreman reminded the workers of the safety requirement.
Later in the shift the tr.spectors verified that all of the workers were correctly
adhering to the safety procedure. The inspectors discussed these
observations with site safety engineers the following day.
The inspectors observed EMD workers following a procedure in preparation
for chemical decontamination of the Unit 2 reactor recirculation system. The
project manager for the decontamination crew accompanied the EMD
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workers and was closely involved in the activity. The inspectors observed
that the projact manager and the workers observed good self-checking and
second party verification (peer checking) techniques.
c.
Conclusions
in general, plant workers were attentive to radiation and personnel safety
requirements, with only minor exceptions. Workers used approved procedures to
perform work and contributed constructive suggestions to help minimize radiation
l
exposure. Work areas were kept orderly and free of clutter. Job coordination in
!
. busy work areas was good.
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M2
Condition of Facilities and Equipment
l
M2.1 Miscellaneous Material Condition issues (71707)
l
The inspectors noted continued equipment problems affected reactor operations,
and resulted in two forced shutdowns for Unit 1 during the period. Listed below
are material condition issues that affected Unit 1 operations:
Breakers installed in safety-related electrical switchgear were identified as having
- auxiliary contact switches prone to cracking. This resulted in operations declaring
the breakers inoperable and required shutdown of Unit 1 (See
Section E2.3).
Repairs were made to an inoperable intermediate range monitor (IRM) -15. During
startup of Unit 1, IRM-15 acted erratically. Operators declared the IRM inoperable
again. The licensee subsequently replaced the IRM detector and declared IRM 15
operable. IRM-15 operated properly during subsequent startup of Unit 1.
During the shutdown of Unit 1, a valve on a hydraulic control unit exhibited leakage
from a body to bonnet joint. The valve was cut out and replaced. A laboratory
later determined the valve was missing a body to bonnet gasket due to
maintenance performed a year previously.
Refuel bridge locked up twice due to problems with an electrical cable. The
licensee later identified the cable was improperly manufactured. The cable was
replaced and Unit 2 reactor defueling continued.
The normal drain valves from the moisture separator drain tanks to the high
pressure feedwater heaters on Unit 1 were degraded and resulted in a plant
transient. The licensee shut down Unit 1 to effect repairs to the system. The
licensee historically has had problems operating the feedwater heating system. The
licensee's investigation identified the valves were undersized by industry standards,
air leaks existed on valve actuators, and the system had been prone to fouling by
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material from inside the system. Engineering determined the system was not
l -
periodically tested, there were no existing preventive maintenance items for the
3
system, and existing predictive maintenance activities were not adequate to trend
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valvo performance. The licensee identified these issues and others, and panned to
implement corrective actions.
During the shutdown of Unit 1, operators noted increased flow through the turbine
electrohydraulic control system. Engineers noted excessive seat leakage through
spool valves in both intercept and stop valves manifolds. Spool valves in ten
actuators were replaced.
i
c.
Conclusion
in each of the above cases, the inspectors reviewed the licensee's investigations
(when performed) and corrective actions. The inspectors noted initial work on the
IRM did not correct the condition. The inspectors noted work performed on the
HCU introduced a problem which was not identified during post maintenance
testing. The inspectors deemed the licensee's corrective actions appropriate to the
circumstances.
M2.3 250 Volts Direct Current Batterv Testina
a.
Insnection Scone
The inspectors observed portions of the Unit 2 modified performance test for the
250 volts direct current (VDC) safety-related battery (Quad Cities Technical Staff
Procedure [OCTS] 0240-06). The inspectors reviewed the load duty cycle of the
battery, the TS requirements for testing, and the UFSAR.
b.
Q_bservations and Findinos (61726)
The modified performance discharge test was allowed by TS 4.9.C.5 to satisfy
both the service test and the performance test. The modified performance
discharge test was perforrned once every 60 months and was used to verify the
battery's ability to meet the critical period of the load duty cycle and to measure
the battery's capacity. The UFSAR (Section 8.3.2.1) stated that the battery was
sized to start and carry the normal direct current (DC) loads required for safe
shutdown on one unit, and the operational loads required to limit the consequences
of a design basis event on the other unit, for a period of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> following loss of
all alternating current (AC) sources. The 250 VDC battery systems are cross-tied
such that each unit's battery feeds the high pressure coolant injection system
(HPCI) system for that unit and the reactor core isolation cooling system (RCIC)
system on the opposite unit in addition to several other DC loads.
The licensee had recently updated the electricalload profile and determined that the
most severe transient on the 250 VDC battery had changed from an intermediate
loss of coolant accident to a steam line break outside of containment. The
inspectors observed portions of the test and verified that the load applied to the
battery conformed to the licensee's documented load profile for the steam line
break scenario. The inspectors reviewed the completed procedure and verified that
16
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the calculated battery capacity of 100.7 percent was greater than the minimum
.
acceptable battery capacity and that the TS requirement was satisfied.
The inspectors reviewed in detail the electricalload profile for the steam line break
t.
)
scenario and asked the system engineer to clarify several of the assumptions made
. in the calculation. The load profile based on Unit 1 assumed that Unit 1 HPCI and
j
Unit 2 RCIC were in the test configuration when the steam line break and loss of
offsite power occurred. The inspectors questioned why this configuration was
more limiting than the HPCI system starting at the initiation of the accident since
'
the operation of the injection valve, the auxiliary oil pump, and the steam supply
- -
valve were significant loads on the battery. The inspectors also questioned the
1
system engineer if the HPCI suction path transfer from the contaminated
condensate storage tank (CCST) to the suppression pool and any cycling of HPCI
,
1
4
. on and off was considered in the load profile. Additionally, the inspectors asked
1
the system engineer to identify which Unit 2 safe shutdown loads were included in
^
the load profile. This issue is an Inspector Follow up item (50-254:265/97006-05).
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c.
Conclusions
The modified performance discharge test for the 250 VDC battery was performed
j
successfully and appeared to meet TS requirements. The inspectors had some
follow-up questions concerning assumptions made in identifying the limiting
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electricalload profile for the 250 VDC battery system.
M2.4 Standby Liauid Control System Testina
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a.
Inspection Scooe(93702. 61726)
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The inspectors observed portions of OCTS 0340-01, " Standby Liqu'd Control
j.
System Outage Surveillance" performed on Unit 2. The inspectors attended a pre-
job briefing and observed operators in the field. The inspectors also followed up on
an NRC ENS notification on April 7,1997, when the SBLC system on Unit 1 was
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' declared inoperable due to low system flow during quarterly surveillance testing.
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b.
Observations and Findinas
,
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The outage surveillance tested portions of the SBLC system that could not be
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routinely tested during reactor operations. The inspectors attended the pre-job
'
briefing and noted good communication among operators. One equipment operator
i
specifically asked for an additional operator to assist in " peer check." The
inspectors observed the portion of the test designed to verify the pump suction
lines from the storage tank were not plugged. The test results were satisfactory.
i
The. inspectors reviewed the test requirements against the TSs and noted that the
test was designed to satisfy surveillance requirements for SBLC system specified in
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TS 4.4.A.4 and for isolation actuation specified in TS 4.2.A. The initiation of SBLC
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causes the isolation of the RWCU. The inspectors verified that the procedure
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tested the isolation function. However, this portion of the test was not identified
under the performance acceptance criteria section or under the discussion section
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which listed the TS requirements which were satisfied by the procedure. The
licensee recently performed an audit of TS surveillance requirements and had also
noticed the deficiency and planned to fix the procedure.
On April 7,1997, operators declared Unit 1 SBLC system inoperable when the
j
measured flow for each of the pumps was in the required action range of the
inservice test (IST) program criteria. The TS flow requirement of 40 gpm was
satisfied. The IST program baseline for the Unit 1 pumps was established at
'
44 gpm with the required action range either greater than 48.4 gpm or less than
40.9 gpm. The measured flow for each pump during the surveillance was 40 gpm.
Once the pumps were declared inoperable, operators entered the action statement
for TS 3.4.A.1 which required at least one pump be restored in 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or the unit
to bo in hot shutdown in the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
1
The licensee immediately suspected the flow meter which was in-line to the test
'
tank since there were past problems associated with the meter. Under work
request 970040020-01, instrument maintenance mechanics adjusted the zero
reference for the flow meter. The flow test for the pumps was then successfully
performed. The inspectors reviewed the calibration history for the flowmeters and
found that the meters were sent offsite for calibration once a year. The inspectors
reviewed the calibration data and found that the flow meter was often found to be
out of tolerance during the as-found testing. The system engineer was aware of -
the problems with this particular type of flow meter and had identified a new style
flowmeter to use. However, the modification packago initiated in 1995 had not yet
been approved. The inspectors found that the margin between the established
baseline flow rate of the pump and the IST and TS limits was small which increased
the importance of accurate flow rate measurements. Additionally IST limits were
calculated down to the tenth of a gpm (e.g.,40.9) and the installed gauge was in
increments of 2 gpm. The inspectors reviewed several completed surveillances and
found the operators were recording the flow in whole numbers and not attempting
to read the gauge to meet the IST criteria. In this event, longstanding problems
with the flow meter caused entry into an LCO and required operators to begin a
reactor shutdown.
The vendor manual for the meter stated that a check and adjustment of the
indicator should be performed at an interval established by the customer and that
indicator response should be checked every six months. The inspectors asked
instrument maintenance staff if these checks were performed and found that
adjustment of the indicator was performed during the annualinstallation of the flow
meter and that indicator response was checked during performance of the flow
test.
c.
Conclusion
Longstanding problems with the SBLC flowmeters used to verify SBLC pump
operability led to a failed surveillance, entry into a limiting condition for operation,
and preparations for a unit shutdown. The installed gauge did not allow the
operator to read the flow measurement with the precision required by the IST
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limits. Accurate flow measurement was particularly important in the SBLC system
since little margin existed between the required flow and reference flow of the
pumps. This issue is an unresolved item pendinp NRC review of IST
instrumentation requirements. (URI 50 256:264/97006-06)
4
Ill. Enaineerino
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Conduct of Engineering
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E1.1
Exoansion of Invessel Insoection Activities
4
Based on information received from another nuclear station, the licensee decided to
,
expand the scope of interior reactor vessel weld inspections to include core shroud
'
vertical welds. The vertical weld inspections added about three days to the outage
schedule. The licensee performed both visual and ultrasonic inspections of four of
,
4
the six welds. (The other two welds were considered inaccessible.) These
inspections did not identify any rejectable indications on the welds. The inspectors
considered the addition of this inspection activity to be both warranted and
proactive.
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E2
' Engineering Support of Facility and Equipment
i
E2.1
Inocerable Core Sorav Room Cooler Due to Foulina
1
a.
Insoection Scooe (71707. 37551)
The inspectors spoke to system engineering, reviewed room cooler trend charts,
and reviewed the licensees response to Deviation 50-254:265/96015-01. The
,
inspectors reviewed Section 3.11.4, 6.3.2.1, and 9.5.5 of the UFSAR and an NRR
safety evaluation related to comer rcom cooler heat removal capability.
s
b.
Observations and Findinas
- !
On March 21,1997, with Unit 2 in a refueling outage, the licensee opened and
inspected the "B" core spray room cooler. The licensee found 10 of 18 tubes that
were completely plugged with erosion and corrosion products. Six additional tubes
were significantly plugged. Operations declared the room cooler incperable.
System engineering reviewed room cooler monthly differential p. essure
'
measurements, and concluded the condition existed since abotit June of 1996. In
addition, the shared emergency diesal annerator was inoperable a total of about
]
nine days resulting in the "A" core spray pump room cooler not having an
2
emergency source of elec%ical power.
4
The licensee attributed the blockage of the room cooler to a previous attempt to
hydrolaze upstream service water piping during the refuel outage in Spring of 1995.
This resulted in loosening debris, and later, required disassembly of the room cooler
to remove erosion and corrosion products. The room cooler was placed back in
service.
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In October 1996,in NRC Inspection Report 50-254;265/96015, the inspectors
identified that the licensee had not implemented a 1992 LER commitment te trend
and analyze residual heat removal room cooler differential pressure. Data recorded
by QCOS 5750-09, "ECCS Room and DGCWP [diesei generator cooling water
pump] Cubicle Cooler Monthly Surveillance Test," was not evaluated by the
cognizant system engineer. In 1994, the licensee had removed the acceptance
criteria for the cooler flow surveillance from the procedure, relying on engineering to
trend and analyze the data. In response to the deviation, the licensee evaluated
ECCS room cooler d/p in October 1996. At that time, system engineering identified
2 "B" core spray room cooler had exceeded the maximum criteria .in June 1996.
The room cooler d/p periodically exceeded the maximum criteria and showed an
increasing d/p trend during the operating cycle. System engineering noted this
condition and commented the cooler would be cleaned during the upcoming outage.
This condition was not documented on a PlF and the condition was not evaluated
for operability. In addition, there were no attempts to clean and inspect the room
cooler during plant operation.
The licensee attributed this event to inadequate flushing of the 2 "B" core spray
room cooler after hydotazing, and a personnel error by the system engineer for not
trending and analyzing the room cooler performance. Engineering could not
determine the heat removal capebilities of the degraded "B" core spray room
cooler.
The inspectors noted the shared EDG was inoperable with both units at power from
October 21 to October 27,1996, and from January 15 to January 18,1997. The
shared EDG provided emergency power to Unit 2 "A" core spray equipment. The
emergency source of power to the Unit 2 "A" core spray room cooler was
unavailable and the Unit 2 "B" core spray room cooler was inoperable since
June 1996. The inspectors consider this to have been potentiaHy significant as
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TS 3.5.A.1 required both core spray systems to be operable with Unit 2 in
operation.
During the outage, the licensee also opened and inspected all the other ECCS roorn
coolers except the 2 "B" RHR room cooler. (The 2 "B" RHR room cooler was
planned to be inspected later in the outage.) Flow through the Unit 2 HPCI room
cooler was previously determined to be degraded but not inoperable. The licensee
found pieces of zebra mussel shells plugging scme of the room cooler tubes. In all
cases, the room coolers were cleaned prior to beng returned to service.
c.
Conclusions
The NRC previously identified that engineering did not adequately trend or analyze
room cooler differential pressure for a period of time (see Deviation
50-254:265/96015-01). The system engineer had an opportunity to document,
and evaluate the degraded condition upon responding to the deviation in
October 1996. Missed opportunities to identify, document and analyze the
degraded condition of the core spray room cooler resulted in the licensee operating
a train of core spray for an extended period of time with a cooler in a degraded
20
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condition without evaluating its effect on operations. Failure to take timely
corrective action for a condition adverse to quality was a violation of 10 CFR,
Appendix B, Criterion XVI " Corrective Action" (VIO 50 254:265/96006-07).
E2.2 Facility Adherence to the UFSAR
While performing the inspections discussed in this report, the inspectors reviewed
the applicable portions of the UFSAR that related to the areas inspected. The
inspectors reviewed plant practices, procedures and/or parameters to that described
in the UFSAR and documented the findings in this inspection report. The inspectors
reviewed the following sections of the UFSAR:
IR Section
UFSAR Section
Aoolicability
07.2
13.7
Reccrds
M2.3
8. 3. 2.1
250 VDC System
E2.1
3.11.4, 6.3.2.1, 9.5.5
CS room cooler
For the sections reviewed, no issues with plant configuration or UFSAR accuracy
were identified.
E2.3 Unit 1 Shut Down Due to Dearaded Auxiliary Switches in 4 Kilovolt (kV) Breakers
a.
Insoection Scone (71707,37551)
The inspectors observed licensee inspection of 4 kV breakers and attended
engineering action meetings and plant operations review committee meetings to
evaluate the degraded condition of the breakers. The inspectors monitored
operators during the Unit 1 shutdown.
b.
Observations and Findinas
On February 11,1997, during breaker testing observed by a Quad Cities engineer
at the manufacturer, an auxiliary contact assembly (ACA) on a 4 kV breaker was
found broken. The manufacturer replaced the ACA. On March 5, the licensee
identified a similarly broken ACA on another spare 4 kV breaker. The condition was
documented on PlF 97-0822. On April 1,1997, the licensee identified a third
broken phenolic auxiliary contact assembly (ACA) mounted on a 4 kV breaker prior
to installation in a safety-related bus (PlF 97-1276). The failure resulted in the ACA
physically separating from the support mount. The ACA provided ci itacts for both
local and remote, indication and operation of the breaker. The licensee .nspected
similar spare breakers and identified 12 of 14 breakers with similarly cracked, but
not broken, ACA. The licensee removed and replaced two residual heat removal
service water pump (RHRSWP) breakers in Unit 1 due to finding cracked ACAs. All
of the inservice electrical breakers' ACAs were identified as being intact.
The licensee used Merlin-Gerin breakers in safety-related applications. These
breakers supplied normal power to safety-related busses and power to the
RHRSWPs. Engineering concluded that the breakers installed could not be deemed
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operable based on conditions identified on both installed and spare breakers. The
licensee had not experienced any failures to operate with the installed breakers.
The breakers could be operated locally. However, the licensee declared the
RHRSWP breakers inoperable and commenced shut down of Unit 1 on April 9,
1997, as required by TSs. (Unit 2 was already in a refuel outage when the
deficient condition was identified.)
The licensee tested and implemented a interim repair to the cracked ACAs. The
tests were observed by the inspectors and NRR personnel (see below paragraph).
After the repairs to the ACAs, the affected breakers were considered operable for a
limited number of cycles. The licensee planned to implement random weekly
surveillances to ensure the breaker modification was monitored. The licensee
considered the modification to the breaker as a potential long term repair and
planned to continue testing the modification at an offsite laboratory. The licensee's
long term corrective actions will be tracked by LER 254/97-011.
'
c.
Conclusions
The inspectors noted the licensee had prior opportunities to identify the degraded
ACAs condition and effect repairs prior to April 1. Similarly, the inspectors noted
.
^
the PlF 97-0822 was marked by the events screening committee as not being a
potential Part 21 notification. The inspectors considered the licensee's initial
evaluation of PlF 97-0822 to be narrow in scope. Subsequent engineering
evaluation of the ACAs condition resulted in the licensee viewing the condition on a
wider perspective, including Part 21 aspects. The licensee subsequently decided to
declare the breakers inoperable and shut down Unit 1 due to the unknown status of
the electrical breaker ACAs. The additional surveillances to rnonitor the condition
of the ACAs in the affected breakers was deemed by the inspectors to be an
acceptable interim measure untillong term testing of the repair was completed.
E2.4 Modification to Auxiliarv Switch in Merlin-Gerin (M-G) Circuit Breakers
a.
Scope
On April 14,1997, inspectors from NRC headquarters Office of Nuclear Reactor
Regulation (NRR) met with the licensee's staff at the System Materials Analysis
Department (SMAD) and reviewed the actions taken by the licensee to determine
the root cause of the cracking of auxiliary switches installed in 4.16 kilovolt (kV),
M G circuit breakers at Dresden and Quad Cities. The inspectors also examined
some of the failed breakers from Quad Cities and reviewed the licensee's proposed
interim corrective action and development of permanent corrective action in
consultation with the breaker supplier and the manufacturer. On April 15,1997,
the inspectors observed testing of one of the failed M-G breakers at Dresden 2.
22
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b.
Observations and Firdinas
Root Cause Evaluation
To investigate the cause of the cracks on the switches, SMAD assembled
engineers from Dresden and Quad Cities, representatives from M-G, Square D
Company (M-G's U.S. distributor), and Pacific Breaker Systems (the current
supplier) and modifier of the M-G breakers for General Electric (GE) (Magne-Blast
switchgear). SMAD evaluated numerous possible contributing factors and showed
the inspectors the high-speed videos which captured the motion of the switches
during the opening and closing of the breaker.
SMAD identified two potentially significant factors that distinguished the M-G
breakers at Dresden and Quad Cities from those at other U.S. installations and
abroad: The type of switch wiring connections and the spring discharge feature.
To meet a licensee wiring requirement, the wires to the breaker auxiliary switches
for Quad Cities and Dresden were connected using ring-tongue terminals . screwed
onto the switch terrninals; whereas, all other installations used spado connectors.
In addition, the inspectors pointed out that connecting the wires after the switches
were mounted could subject the switch mounting slots to extra stress during the
tightening of the terminal screws.
The spring discharge safety feature in the Dresden and Quad Cities breakers,
specified by ANSI /IEEE Std C37.04 for U.S. nuclear plants, was unique among all
other installations of the affected type of M-G breakers because those facilities are
the only U.S. nuclear plants with M-G breakers. The spring discharge feature,
actuated by a mechanical rackout interlock for personnel safety, subjects the
breaker to a complete closing and opening cycle in rapid succession every time the
i
breaker is racked out. This feature, with its associated significant increased stress
on the switches (vibration and shock loading), was being considered as a possible
contributing factor to the cracking of the auxiliary switches.
The upper auxiliary switch shaft is the fulcrum for the operating levers which
operate the upper auxiliary switch, the bottom auxiliary switch and the open/close
indicating flag. If the tabs of the mounting slots (which are molded into the
phenolic switch body segments) crack and break off, the mounting T-bolts can
come out of the slots and the switch will break away from its mounting bracket.
However, the switch remained attached to the operating levers by its shaf t and
thus will hang down, typically about 1/4 inch below the mounting bracket. Thus
far, cracks have been found only on the upper switch.
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Failure Effects
Specifically, if the auxiliary switch broke loose as the breaker closed, the breaker
may not have opened electrically (automatic trips, or local or remote hand switches)
unless the upper auxiliary switch changed state. If the auxiliary switch broke loose
'
as the breaker opened, the breaker may not have closed electrically unless the
switch changed state.
Prooosed interim Corrective Action
The licensee's proposed interim corrective action was to replace all upper auxiliary
switches that are broken or have visible pieces missing (but not ones that only have
visible cracks) and then secure all the switches with nylon cable tie (ty-wrap), with
Tygon tubing as chafing gear, as a backup to their regular mounting system. To
test this proposed fix, the licensee cycled a breaker 225 times with the ty-wrap
installed, the rear mounting slot tabs completely broken off and with the nuts
removed from the T-bolts that normally attach the switch to its mounting bracket.
'
No failures occurred during this testing. This interim fix was also being seismically
tested at Wyle Laboratories.
Testina of the Bus 23 Feeder Breaker at Dresden.
l
On April 15,1997, the inspectors observed the Dresden 2 operating tests of its
Bus 23 M-G feeder breaker (from Bus 23-1). The intent was to demonstrate the
prior operability of this closed breaker, whose local mechanical position indicator
flag was stuck in an intermediate, nearly open position. Control room personnel
opened and closed the breaker successfully several times accompanied by proper
operation of the local and remote indicating lights. However, when the breaker was
opened, the position indicating flag on the breaker would go almost fully closed and
when the breaker was closed, the flag would return to its intermediate, mostly-open
position. When the technicians removed the front cover of the breaker mechanism
enclosure, the inspectors observed that the auxiliary switch was detached from its
mounting bracket and was hanging down about 1/2 inch.
c.
Conclusions
The inspectors concluded that the root cause investigation was proceeding
satisfactorily although not completed. The licensee appeared to be effectively
utilizing its contractors and the contractors were providing adequate support.
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IV Plant Support
R1
Radiological Protection and Chemistry Controls
R 1.1 Torus Suction Header Decon1mination Efforts
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a.
Insoection Scoce (71707)
The inspectors spoka with Radiological Protection and Chemistry Controls (RPC)
staff and reviewed the results of the torus suction header decontamination efforts.
b.
Observations and Findinas
The radiation levels in the torus suction header had historically resulted in the
reactor building basement being treated as a high radiation area. During the recent
Unit 2 refuel outage, the licensee removed the emergency core cooling system
(ECCS) suction strainers and used a robot to clean the torus suction header. This
effort had previously not been used and was considered experimental.
Consequently, equipment problems and schedule slippage resulted in cleaning only
eleven of the sixteen bays. For the areas cleaned, post decontamination surveys
showed doses decreased by up to 50 percent and some areas showed an increase
in dose of up to 20 percent due to redeposition of fine particles.
The licensee intended to incorporate lessons learned from this effort to ensure the
entira torus suction header would be decontaminated during the upcoming Unit 1
refuel octage.
,
c.
Conclusio 13.
The inspectors concluded the torus decontamination efforts were good. However,
first time use of equipment resulted in the torus suction ring header
decontamination efforts not being fully completed.
F4
Fire Protection Staff Knowledge and Performance
F4.1
Delinauent Reoortina of Event
On March 27,1997, the licensee identified a previously corrected condition that
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was not reported in accordance with 10 CFR 50.72 requirements. The licensee's
fire hazards analysis report required protection of low pressure piping frem high
pressure systems. The licensee identified that during a postulated fire, no
procedures were in place to ensure low pressure portions of the reactor water
cleanup piping would be protected from the high pressure recirculation system.
This condition was documented on PlF 97-1132 and LER 50-254/97008. The
licensee attributed this event to an incomplete understanding of the licensee's safe
shutdown analysis. The licensee revised a procedure to correct the condition by
May 28,1996, but did not report the condition until March 27,1997.
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The licensee did not report the condition as being outside the design basis until ten
months later. Failure to report the condition is considered a violation of 10 CFR 50.73. However, this licensee-identified and corrected condition was Non-Cited
Violation (50-254:265/97006-08), consistent with Section Vll.B.1 of the
j.
V. Manaaement Meetinas
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X1
Exit Meeting Summary
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The inspectors presented the inspection results to members of licensee management at the
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conclusion of the inspection on May 2,1997. The licensee acknowledged the findings
presented.
The inspectors asked the licensee whether any materials examined during the inspection
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should be considered proprietary. No proprietary information was identified,
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PARTIAL LIST OF PERSONS CONTACTED
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Licensee
B. Pearce, Station Manager
D. Cook, Operations Manager
F. Famulari, Site Quality Verification Director
J. Hutchinson, Site Engineering Manager
J. Kudalis, Support Services Director
J. Purkis, Work Control Supervisor
B. Svaleson, Radiation Chemistry Superintendent
M. Wayland, Maintenance Superintendent
INSPECTION PROCEDURES USED
IP 37551:
Onsite Engineering
IP 39701:
Records Program
IP 61726:
Surveillance Observations
IP 62706:
Maintenance Rule Inspection Procedure
IP 62707:
Conduct of Maintenance
IP 71707:
Plant Operations
IP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor
Facilities
IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors
ITEMS OPENED, CLOSED, AND DISCUSSED
Ooened
50-254;265/97006-01
failure to maintain the proper revisions of
operating procedures
50-254:265/97006-02
failure to properly implement test procedure
50-254:265-97006-03
failure to identify quality records and to establish
retention requirements
50-254;265/97006-04
NCV Unit 1 EDG start due to personnel error
50-254:265/97006-05
IFl
250 volts direct current battery testing
50-254:265/97006-06
IST instrumentation requirements
50-254;265/97006-07
Core spray room cooler clogged and degraded
50-254:265/97006-08
NCV delinquent reporting of event
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.50 254:265/95005-02
failure to maintain the RHR room watertight door
closed in accordance with TSs
- 50-254:265/96006-04
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inattentive test director
50 254:265/97006-04
NCV Unit 1 EDG start due to personnel error
50-254i265/97006-08
NCV delinquent reporting of event
50-265/95007
LER
Unit 2 HPCI turning gear motor failed to start as
the turbine coasted to a stop
-50-254:265/97007
LER
. Unit 1 EDG start due to personnel error
Discussed '
50 254:265/97002-07
Maintenance Rule issues
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LIST OF ACRONYMS AND INITIALISMS USED
Alternate Current
ACA
' Auxiliary Contact Assembly
As Low As Reasonably Achievable
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ANSI
American National Standards institute
American Society of Mechanical Engineers
Containment .^tmosphere Monitor
CCST-
Contaminated Condensate Storage Tank
CFR
Code of Federal hegulations
Control Rod Drive
d/p
differential pressure
Direct Current
DGCWP
Diesel Generator Cooling Water Pump
Electrical Maintenance Department
Emergency Notification System
Electrical Protection Assembly
,
Event Screening Committee
GL
Generic Letter
Hydraulic Control Unit
High Pressure Coolant Injection System
Heating Ventilation and Air Conditioning
(DNS
tilinois Department of Nuclear Safety
IFl
Inspector Follow-up Item
inservice Test
kV
Kilovolt
LCO
Limiting Condition for Operation
LER
Lice ~nsee Event Report
Loss-of-Coolant Accident
Motor Control Center
MEG
Materials Engineering Group
Motor Generator
Maintenance Preventable Function Failure
Maintenance Rule Functional Failure
Moisture Separator Drain Tank
Non-Cited Violation
Nuclear Quality Assurance
NSO
Nuclear Station Operator
Public Document Room
Problem Identification Form
Plant Oversight Review Committee
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QCAP-
Quad Cities Administrative Procedure
OCCP <
Quad Cities Chemistry Procedure
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' QCIS -
Quad Cities Instrument Surveillance
OCOA
Quad Cities Operating Abnormal Procedure
QCOS
Quad _ Cities Operating Surveillance Procedure
QCTS-
Quad Cities Technical Staff Procedure
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OOA
. Quad Cities Operating Abnormal Procedure
OOP
Quad Cities Operating Procedure -
QOS-
Quad Cities Operating Surveillance Procedure
Reactor Core Isolation Cooling System
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RG'
Regulatory Guide
RHRSWP
Residual Heat Removal Service Water Pump
- RPC
Radiological Protection and Chemistry Controls
RPS-
.SBLC
, SIL .
Service Information Letter
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. SQV
Site Quality Verification
TS-
Technical Specification
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Updated Final Safety Analysis
.VDC
Volts Direct Current
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Violation
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