ML20140G138
| ML20140G138 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 04/25/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20140G094 | List: |
| References | |
| 50-254-97-02, 50-254-97-2, 50-265-97-02, 50-265-97-2, NUDOCS 9705060401 | |
| Download: ML20140G138 (24) | |
See also: IR 05000254/1997002
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!,,' U. S. NUCLEAR REGULATORY COMMISSION i
REGION 111
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Docket Nos: 50-254, 50-265
Report No: 50-254/97002(D RP), 50-265/97002(DRP)
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Licensee: Commonwealth Edison Company (Comed)
Facility: Quad Cities Nuclear Power Station, Units 1 and 2
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Location: 22710 206th Avenue North
Cordova, IL 61242
Dates: January 28 - March 17,1997
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inspectors: C. Miller, Senior Resident inspector
K. Walton, Resident Inspector
L. Collins, Resident inspector
R. Ganser, Illinois Department of Nuclear Safety
Approved by: Wayne J Kropp, Chief
Reactor Projects Branch 1
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9705060401 970425-
PDR ADOCK 05000254
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.. EXECUTIVE SUMMARY
Quad Cities Nuclear Power Station, Units 1 & 2
NRC Inspection Report 50-254/97002(DRP), 50-265/97002(DRP)
This inspection included aspects of licensee operations, surveillance, engineering,
maintenance, Md plant support. The report covers a 7-week period of resident inspection.
Ooerations
The decision to declare the automatic depressurization system (ADS) valves inoperable due
to seat leakage was appropriate. Unit 2 shutdown activities were in accordance with
licensee procedures and were well executed (Section 01.2).
Control measures taken by operations to improve the working environment in the control
room were effective. The licensee's effort to provide more stringent control of room
access, incoming phone calls, and general noise level was evident (Section 01.3).
Initial operator response to the failure of the reactor protection system (RPS) relay was
appropriate. Subsequent reset of the B trip system was contrary to procedures and was
not in compliance with the Technical Specification (TS). The decision to shut down Unit 1
to perform a root cause analysis of the failure was appropriate and reflected conservative
decision making. (Section 01.4).
The inspectors reviewed open operability assessments and found allitems to be adequately
tracked by the licensee. However, the inspectors identified one degraded equipment
operability issue that was not on the licensee's list of open operability issues (Section
01.5).
The operator failure to properly maintain turbine building negative pressure in accordance
with the annunciator response procedures could have resulted in the spread of
contarnination within and outside the turbine building. This failure was a procedural
violation. Other operational problems noted during the inspection included a weak
response to a degraded drywell equipment drain sump isolation valve and additional
ventilation problems related to control of a modification (Section O2.1).
Maintenance
The inspectors noted problems identified by workers in the field resulted in additional time
spent in TS limiting condition for operations (LCO), some additional radiation exposure to
workers, or affected equipment used to support reactor operations. Some of these events
were the result of poor quality work packages (Section M1.1).
Both the inspectors and the licensee identified instrumentation used by operators to
determine equipment operability and for equipment trending that were not included in a
! calibration program (Section M2.1).
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.. The inspectors had concerns with the licensee's implementation of the maintenance rule,
specifically the identification of maintenance preventable functional failure (MPFF) events
and the failure to promptly evaluate the Unit 2 containment atmosphere monitoring (CAM) ,
system status as (a)(1) under the maintenance rule. Longstanding issues regarding ,
repetitive regulator failures and water intrusion in the CAM system had not been resolved
(Section M2.2).
Surveillance
During a Unit 2 surveillance on the high pressure coolant injection (HPCI) system, operators
quickly assessed that injection was not required and secured HPCI after an unexpected
auto-initiation. However, operators had an opportunity to identify that scheduled activities
were incompatible with existing plant conditions (Section 04.1).
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Enaineerina
The inspectors identified a vulnerability in the licensee's method of identifying and
reporting of 10 CFR Part 21 issues. However, the inspectors did not identify any instances
where 10 CFR Part 21 notifications were not made when required
(Section E7.1).
Plant Suooort
The inspectors identified that some radiation protection technicians (RPTs) lacked good
command and control of radiological aspects of the assigned work. This resulted in some
increase in dose to workers and the potential to spread contamination into clean areas
(Section R1.1).
The inspectors concluded that the high radiation sampling system (HRSS) drill was
successful and that personnel performance was good (Section R4.1).
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.- Report Details
Summarv of Plent Status
Unit 1 operated at or near full power throughout most of the inspection period.
Between February 14 and February 19 Unit 1 power was reduced for j
l troubleshooting the 1B feedwater regulating valve. Power was again reduced on l
l February 25 to swap the reactor protection system power bus to the preferred l
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source. On March 11 the unit was shut down to repair a failed reactor protection l
system relay. Restart of Unit 1 began on March 16, and the generator was on-line
March 17.
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Unit 2 operated at or near full power throughout the inspection period. Power was
reduced on February 25 for testing of the feedwater flow system instrumentation.
On February 28 the unit was shut down one-half day earlier than scheduled for
refuel outage O2R14 due to TS requirements related to surveillance testing of I
automatic depressurization system valves. Unit 2 remained shut down for a
planned 60-day refuel outage, Q2R14. Major activities planned during Q2R14
included inspection of the reactor vessel beltline welds and bottom head drain clean
out, main turbine disassembly and inspection, overhaul 2A core spray pump, 2B
residual heat removal (RHR) heat exchanger inspection and repair, scram solenoid
pilot valve diaphragm replacement, replacement of emergency core cooling system
(ECCS) suction strainers; safety-related breaker and cable replacement, and Generic
Letter 96-06 piping relief valve modifications. The Unit 2 startup was scheduled for
the end of April,
l. Operations
01 Conduct of Operations *
01.1 General Comments (71707)
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.
February 21 A notification was made that the Train B control room ventilation
refrigerant compressor unit was inoperable due to high temperatures
in the old computer room.
February 27 A notification was made that the Unit 2 HPCI automatically actuated !
during a surveillance test. l
- Topical headings such as 01, M8, etc., are used in accordance with the
NRC standardized reactor inspection report outline. Individual reports are
not expected to address all outline topics. l
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.- February 28 A notification was made that four Unit 2 ADS relief valve closure
times did not meet acceptance criteria. Operators declared ADS
inoperable and commenced shutting down Unit 2. Licensee
commenced refuel outage, 02R14.
March 11 Operators shut down Unit 1 to repair a faulty reactor protective
system relay.
March 16 Operators initiated Unit 1 reactor startup.
March 17 Unit 1 turbine generator returned to service.
01.2 Unit 2 Shut Down Due to inocerable Automatic Deoressurization System (ADS)
Valves
a. Insoection Scoce (93702)
The inspectors reviewed licensee surveillance procedures, and observed Unit 2
shutdown activities.
b. Observations and Findinos
On February 28 at 4:20 p.m. central standard time, operators shut down the Unit 2
reactor due to four of five ADS valves having closing times in excess of the
acceptance criteria. With the valves inoperable, Technical Specifications (TSs)
required the reactor to be in hot shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in cold shutdown
within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
During the shutdown engineering determined that the closing times for the ADS
valves had met the acceptance criteria. However, two of the four ADS valves
exhibited minor seat leakage after testing. Operations continued the reactor
shutdown. The licensee planned to remove and test the two ADS valves exhibiting
seat leakage. The licensee also planned to evaluate whether timing the valves in
the closed direction was required,
c. Conclusions
The decision to declare the ADS valves inoperable due excessive closing times, and
continue the shutdown due to seat leakage, was conservative. Unit 2 shutdown
activities were in accordance with licensee procedures and were well executed.
01.3 Control Room insoections and Plent Area Walkdowns
a. Insoection Scuoe (71707)
l The inspectors performed routine inspections in the control room and throughout
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.- b. Observations and Findinos
During the inspection period the licensee completed control room layout
modifications designed to optimize the operators' ability to monitor the control
panels. Prior to the commencement of the Unit 2 refuel outage, the licenseo moved
work control activities previously conducted in the control room to the adjacent
communications center. This action eliminated most of the excess personnel traffic
to the control room.
While inspecting the Unit 1 feedwater regulating valve area, the inspectors identified
that the 1B feedwater regulating valve inlet isolation motor-operated valve (MOV)
had developed a packing leak. The inspectors reported the leak to the unit
supervisor who verified that the leakage exceeded the licensee's limits and
subsequently wrote an action request (AR) to correct the condition. The inspectors
also identified foreign material on top of the Unit 2 safety-related 4 kilovolt (kV)
switchgear and notified the lead unit planner who initiated the necessary corrective
action.
C. Conclusions
Control measures taken by operations to improve the working environment in the
control room have been effective. The licensee's effort to provide more stringent
control of room access, incoming phone calls, and general noise level was evident.
Routine operator plant tours did not identify a packing leak on the 1B feedwater
MOV or foreign material on safety-related switchgear.
01.4 Unit 1 Reactor Protection System Relav Problem
a. Insoection Scooe (93702)
The inspectors performed a follow up inspection of the failure of the 1-590-108D
reactor protection system (RPS) relay. The inspectors reviewed the TSs and the
operator logs, attended several root cause team meetings, and observed
maintenance troubleshooting efforts,
b. Observations and Findinas
On March 7 at 10:47 a.m. the 1-590-108D RPS relay deenergized unexpectedly l
causing a partial trip of the B RPS trip system: In accordance with Quad Cities
Operating Abnormal Procedure (OCOA) 500-1, " Partial Scram Actuation" operators !
inserted a full trip of the B trip system. No indications of a valid reactor trip signal
were present. At 12:35 p.m. operators reset the B trip system for troubleshooting
in order to determine the cause of the failure. Fourteen minutes later, after the
cause could not be determined, operators again tripped the B trip system.
The RPS consisted of two trip systems, designated A and B. Each trip system
consisted of two redundant trip logic channels (A1, A2, B1, B2). An automatic reactor trip required that both trip systems actuate, in a one out of two twice logic.
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.- Every monitored reactor trip parameter provided input to each of the four trip logic
channels. Any reactor trip input to the B1 trip logic would normally cause two
relays to deenergize, 1-590-108B and 1-590-108D. The failure of the 1-590-108D ,
relay rendered the B1 trip logic and associated instrument channels inoperable. ]
Quad Cities Operating Abnormal Procedure (QCOA) 500-1, " Partial Scram
Actuation" instructed operators to trip the system affected, notify the shift
engineer, and initiate corrective actions to determine the cause of the failure. A
caution was included in the procedure and stated, "Do NOT reset a " half scram"
until the cause is known AND permission to reset the scram has been given by the
shift engineer." The discussion section of the procedure stated, "During a partial
scram actuation, operator response should be focused on plant safety requirements
and NOT on investigating the RPS system."
Technical Specification 3.1.A required that the RPS instrumentation channels shown
in Table 3.1.A-1 be operable. The action statement required that with the number
of channels less than the minimum required that the inoperable channel and/or that
trip system be placed in the tripped condition within one hour. Note (a) to table
3.1.A-1 stated that a channel may be placed in an inoperable status for up to two
hours for required surveillance without placing the trip system in the tripped
condition provided at least one operable channel in the same trip system is
monitoring that parameter. The inspectors concluded that the maintenance
troubleshooting effort to determine the cause of the relay failure did not constitute a
required surveillance and that note (a) was not applicable in this situation.
Since the number of RPS instrumentation channels was reduced below the minimum
required for some trip functions as a result of the relay failure, the licensee was
required to take the specified action within one hour. The inspectors found that
initial operator actions were in accordance with the requirement but the subsequent
reset of the B RPS trip system was not in compliance with Technical Specification 3.1.A. This was considered a Violation (VIO) (50-254/265-97002-01).
c. Conclusion
The inspectors found that initial operator actions were in accordance with the TS
requirements but that the subsequent reset of the B RPS system with the relay
inoperable was not in compliance with the TS. The inspectors concluded that the
maintenance troubleshooting effort to determine the cause of the relay failura did
not constitute a required surveillance and that note (a) was not applicable in this
situation.
01.5 Review of Ooerability Assessments
a. Insocction Scooe (71707)
The inspectors reviewed the operability assessments performed within the last two
years to determine which issues remained open.
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.- b. Observations and Findinas
The inspectors found that all remaining open operability assessments were being
tracked by the licensee and were planned for resolution prior to Unit 2 startup.
However, the inspectors identified one degraded system that was not on the list of
open operability assessments. ,
In November 1996 the 2D RHR system discharge check valve failed to close after
the pump was stopped which caused the low pressure coolant injection (LPCI)
system to be inoperable for a short period of time. The inspectors found that PlF
96-3196 for this issue received an " issue screening" which was the first part of the
operability determination process. The degraded check valve was determined to be
operable with no further concerns and was not required to receive the second part
of the review which was the operability determination. The inspectors agreed that
the check valve and the system remained operable but concluded that concerns did
exist since compensatory measures in the form of response instructions to
operators were implemented to ensure system operability. The inspectors found the
degraded check valve was scheduled for replacement during the current outage, and
that the item was sufficiently tracked via the licensee's administrative tracking
system.
The inspectors reviewed a sample of other issue screenings performed in the last
year that did not have associated operability determinations and found no other ;
open issues.
c. Conclusion
The inspectors reviewed open operability assessments and found allitems to be
adequately tracked by the licensee. However, the inspectors identified one
degraded equipment operability issue that was not on the licensee's list of open :
operability issues. l
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O2 Operational Status of Facilities and Equipment !
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02.1 Review of Ooerator Resoonse to Abnormal Conditions l
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a. Insoection Scone (71707)
The inspectors reviewed the operators' response to various plant equipment
problems and abnormal conditions. The irrspectors also reviewed operations and
maintenance priorities for degraded control room equipment.
b. Observations and Findinas
1. Low Priority Given to an Operator Workaround
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The inspectors noted operators having continual problems with the Unit 2
drywell equipment drain sump (DWEDS) outboard isolation valve. This valve
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was one of two containment isolation valves for the DWEDS line which must
be able to close to prevent release of radioactive material outside primary
containment. Operators had trouble opening the valve on numerous
occasions during the pumping of the DWEDS every four hours. On several
occasions operators were required to crawl on top of the torus and hit the
valve with a wrench to ensure the valve would open.
The inspectors found that no operability determination had been performed,
nor had a problem identification form (PIF) been generated. The licensee had
documented the deficiency with an action request. The control room
operators informed the inspectors that the action request was Priority B1
which indicated that work would be started within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and continue
around the clock. The inspectors questioned why no work was in progress
and was subsequently told that the priority was B2. The action request was
written on January 16. The inspectors raised the issue on January 30 and
no work had been performed. The inspectors found that the electronic work
control system (EWCS) action request screen indicated B1 priority in one
place and B2 in another. However, neither priority was being met.
Further investigation revealed that engineering did not have a proposed
solution to determine the cause of the valve sticking, and maintenance did
not have any active work in progress or plan to fix the condition. On
January 31, following the inspectors questioning of operability, operations
supervision documented the problem with PlF 97-281 and forwarded the
operability evaluation to engineering for completion. The initial operability
determination that the valve was operable for closure was acceptable.
Engineering later determined through testing and evaluation that thermal
binding was occurring in the valve in the open direction, but the same
mechanism would not apply in the closed direction. Engineering '
recommended a two hour cycling of the valve to prevent thermal binding,
and included the valve in the Unit 2 outage scope. The inspectors concluded
that the resolution of the problem was adequate, but noted that operations
response to a degraded equipment condition was weak.
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ii. A Modification Packaae Resulted in Ventilation Problems l
The inspectors questioned the unit supervisor as to whether or not the
proper negative pressure was assured in the laundry tool 6 contamination
(LTD) buildings following restoration of the ventilation. The unit supervisor
investigated and determined that a discharge damper was closed when the ,
damper should have been open. This condition prevented the proper )
negative pressure in the building. The inspectors found that the problems
resulted from an inadequate procedure that did not identify the existence of
the discharge dampers. This was due to the fact that the design
! modification that installed the ventilation system had not been closed or
authorized by operations before the building had been put into service. This
l was considered an Unresolved item (50-254/265-97002-02) pending further
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,- review of the modification work package and licensee procedures for j
authorizing modifications. '
iii. Failure to Control Turbine Buildina Neoative Pressure
- The inspectors found several instances throughout the period where
operators were not responsive to ventilation annunciators which had alarmed l
in the control room. in one case, operators took no corrective action for a ;
l- service building ventilation annunciator because the annunciator appeared to ]
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be a phenomena associated with the infrequently run train B control room '
ventilation. In another case, inspectors identified that operators were not I
taking corrective action for a turbine building low differential pressure l
annunciator. The inspectors discussed these observations with station
management who agreed that better sensitivity to annunciators was j
required. However, on March 7, inspectors found that the turbine building
low pressure annunciator was again lit, turbine building pressure was
positive, and operators were not trying to establish a negative pressure in the ,
building. The unit supervisor indicated initially that this condition was j
acceptable because a turbine building door was open. The inspectors i
pointed out that having a turbine building door open and positive pressure in
the turbine building could result in an unmonitored release of radioactive l
airborne material. The unit supervisor then took action to make turbine
building pressure negative.
Annunciator procedure OCAN 912-5,C.2, " Turbine Building 1 Low DP,"
required operators to start another exhaust fan and check for open doors.
Since all additional exhaust fans were out of service, operators could not
take the specified action but allowed the turbine building door to be opened
anyway. This was a Violation (VIO) (50-254/265-97002-03) of the
implementing annunciator procedure,
c. Conclusion
Operators failure to properly maintain turbine building negative pressure in
accordance with the annunciator response procedures which could have resulted in
the spread of contamination within and outside the turbine building. This was a
violation. Other operational problems included a weak response to degraded
equipment and additional ventilation problems related to inadequate control of a j
modification. j
O2.3 Fire Pumo Inocerable In Excess of Administrative Limitino Condition for Ooeration
The inspectors noted that the licensee had entered a 7-day administrative limiting l
condition for operation (LCO) for the % diesel generator fire pump. The LCO was !
entered for repairs to components affecting the 1C circulating water bay, with the ;
work initially planned for more than 20 days. The inspectors questioned operations j
and maintenance supervision to determine the scope of the work and the level of ;
effort being expended to complete the work expeditiously. The inspectors found
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weekends. After discussing the inspectors' concerns with prioritization of this {
work, the licensee increased the effort and focus on the work. i
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A recent licensee submittal regarding an individual plant examination for external I
events (IPEEE) revealed that the risk for core damage from external events could be
as high as SE-3, with fire being the highest contributor. Although the licensee was
adding a modification to improve the risk posture, reactor operation continued with l
an inoperable fire pump for a period exceeding the LCO limit before the modification
was installed. This action reduced the reliability of the fire . system even though
other actions had been taken to minimize this risk. The inspectors verified that the
requirements of the LCO action statement were met, but concluded that the
licensee's work prioritization did not adequately consider plant risk.
02.4 Insoection Results of Emeraency Diesel Generator System (71707)
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The inspectors reviewed licensee procedures to ensure compliance with design I
basis, TSs, and Sections 8.3.1.6 and 9.5 of the updated final safety analysis report
(UFSAR). The inspectors reviewed chemistry logs, inservice testing commitments,
and surveillance requirements. The inspectors walked down mechanical portions of
the emergency diesel generator (EDG) systems. The inspectors concluded, that for
the areas reviewed, the licensee's EDG program met TS requirements. However,
the inspectors identified weaknesses in the licensee's calibration program and
program for trending power system indicator performance. (See Section M2.1).
02.5 Failure to Control Reouired Comnensatorv Measures to Ensure System Ooerability
a. Insoection Scooe
The inspectors reviewed the operability determination for the low pressure ECCS
with the associated room coolers out of service.
b. Observations and Findinas
The inspectors noted that all of the room coolers for the Unit 2 ECCS were taken
out of service after Unit 2 reached cold shutdown conditions on March 1. Although
the reactor was in cold shutdown, TS 3.5.B required two low pressure emergency
core cooling subsystems to be operable unless the reactor vessel head was
removed, the cavity flooded, the spent fuel pool gates removed, and water level
maintained within the limits of TSs 3.10.G and 3.10.H. Since the vessel head was
not yet removed or the cavity flooded, the inspectors questioned the operability of
the required systems with the room coolers out of service.
The inspectors reviewed the licensee's written operability assessment from PIF 95-
1976 and found that it was adequate, but noted that several compensatory
measures included with the justification had not been incorporated into procedures.
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The inspectors concluded that the required ECCS systems remained operable with
the room coolers out of service and that no TS violation had occurred. The
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. inspectors reviewed UFSAR Sections 6.3.2.1 and 6.3.2.2 which described room !
cooler operation as needed to maintain the room temperatures below the !
qualification temperature of the components that are required for safe shutdown of i
the plant. The UFSAR did not contain any information regarding ECCS or room
cooler requirements during shutdown conditions.
The compensatory measures included monitoring residual heat removal room
temperatures, maintaining additional pumps available if a room cooler was out of .
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i shutdown. The inspectors found that none of these compensatory measures were ,
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c. Conclusion
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The licensee failed to ensure that the proper compensatory measures were in place l
to control ECCS system operability without room coolers during shutdown
conditions. The inspectors did not identify any situatinns in which the room coolers
were removed from service prior to achieving cold shutdown conditions. However, '
lack of procedural controls to ensure operability during all operational modes was
considered a weakness in the operability determination process. ,
04 Operator Knowledge and Performance
04.1 Hiah Pressure Coolant Iniection Initiation Durina Testina
a. Insoection Scoce (71707)
The inspectors reviewed operator response to an inadvertent start of Unit 2 high
pressure coolant injection (HPCI) pump during surveillance testing. The inspectors
reviewed the emergency notification system (ENS) report, the set,uence of event
recorder, the UFSAR Sections 15.1 and 15.5. The inspectors spoke to operators
and members of the investigative team assembled to review this event. !
b. Observations and Findinas !
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With Unit 2 at about 91% power, instrument technicians performing a Quad Cities l
Instrument Preventive Maintenance test (OCIPM), QCIPM 100-10 " Refuel Outage
ECCS Instrumentation Check Prior to ECCS Logic Test," initiated HPCI causing ,
about 50 gallons of cold water to be injected into the feedwater system. Injection i
of a sufficient amount of cold water into an operating reactor would have resulted in ;
addition of positive reactivity to the reactor core. Operators received annunciators l
indicating a start of the Unit 2 HPCI pump. Operators did not expect the pump to :
start as a result of testing, and secured the pump after determining that plant !
conditions did not warrant use of HPCI. The operators did not detect any changes l
in power or reactor vessel water level as a result of this event. The licensee ,
documented this condition on PlF 97-0549 and formed a multi-disciplined team to !
investigate the causes of this event. The investigative team determined that the i
root cause of this event was an inadequate procedure. The procedure was written ;
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. to be performed during refueling or shutdown mode and not during power
operations.
The team identified that the surveillance procedure was not appropriate for the plant
conditions and multiple barriers designed to prevent this type of event had failed.
An independent review of the procedure by various personnel (maintenance
scheduler, foreman, and unit supervisor) failed to prevent the event from occurring.
All personnel relied on comparing the OCIPM procedure to an existing procedure
performed during power operations instead of reviewing the electrical drawings. A
review of electrical drawings would have determined that the OCIPM procedure
would initiate HPCI. Planned corrective actions for this event included revising
OCIPM 100-10 prerequisites, reviewing a sampling of procedures to ensure that
assumptions made in 50.59 evaluations were included in procedure prerequisites,
and more clearly explaining management expectations for first line supervision
responsibilities.
The inspectors concluded that the immediate operator actions to secure HPCI were
appropriate. The inspectors also concluded that the HPCI system performed as
expected under the circumstances. However, the inspectors considered
performance of OCIPM 100-10, " Refuel Outage ECCS Instrumentation Check Prior
to ECCS Logic Test," during power operations to be a Violation (50-265-97002-04)
of 10 CFR 50 Appendix B, Criterion V. Instructions, Procedures and Drawings.
A 10 CFR 50.59 safety evaluation written for the procedure required OCIPM
100-10 be performed with the unit shutdown, and the procedure was not
appropriate for performance with the reactor at power.
c. Conclusions
The inspectors noted operators quickly assessed that HPCI was not required and
appropriately secured HPCI. Additione!!y, operators had previously identified that
scheduled activities were incompatible with existing plant conditions. As a rer, ult,
several days prior to this event, the licensee documented an adverse trend in
scheduling activities on trend PlF 97-0486. The weaknesses identified in
scheduling activities is an Inspector Followup Item (IFI) (50-254/265-97002-05).
08 Miscellaneous Operations issues (92700)
08.1 Review of Institute of Nuclear Power Ooerations Assessment
The inspectors reviewed the 1996 Institute of Nuclear Power (INPO) evaluation of
Quad cities to determine if there were any safety issues which were previously
unknown to the NRC. The report documented findings of similar programmatic
problems to those previously identified by the NRC and the licensee.
08.2 (Closed) Violation (50-254/265-96002-02): Primary Containment Violation. The
l inspectors identified that the licensee opened a manually operated valve during a
l local leak rate test. This allowed the torus to communicate with the reactor building
basement with Unit 1 operating at full power. The licensee attributed this event to
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. a lack of knowledge of Generic Letter (GL) 87-09 with respect to application of TS 3.0.A. A policy statement was developed by the operations manager. Current
license holders received training on various additional GL requirements. This item is
closed.
II. Maintenance
M1 Conduct of Maintenance
M 1.1 Maintenance Observations
a. Insoection Scope (62707. 71707)
The inspectors observed work in the field and walked down the hydraulic control
units (HCU) to assess the quality of maintenance activities.
b. Observations and Findinas
1. Walkdown of HCUs
The inspectors identified a nitrogen supply tank for Unit 2 HCU 14-39 that
was not properly mounted. Specifically, the tank upper mechanical joint
connection bolt was backed off one-half inch. Operations documented the
condition on a PIF 97-0384 and declared the HCU inoperable until
maintenance repaired the joint. The HCU was worked during the previous
outage. However, the licensee was not certain if the nitrogen supply tank
mechanical joint was loosened during that activity. All other nitrogen supply
tank joints were inspected satisf actorily. The inspectors determined that the
licensee's actions were appropriate.
ii. Field Observations
During maintenance inspection activities, the inspectors observed the
following:
e Engineering specified a local leak rate test (LLRT) procedure for post-
maintenance testing of the Unit 1 A loop of containment spray.
However, the LLRT procedure was written for the unit in a shutdown
mode instead of an operating mode. A change to the procedure was
required before testing could continue. Testing was delayed while in
a TS LCO until the procedure was changed.
e As part of a modification to the reactor building fire main, a blank I
flange was removed and a new valve was to be installed. However,
the new valve would not fit onto the strainer housing since the
strainer was one-half inch too long. The interference between the
existing strainer and the new valve was not recognized by the work
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package. The package was changed to trim the strainer. This also l
l delayed work in a TS LCO.
e A work package for welding on a Unit 1 reactor water clean up
(RWCU) valve 1-1201-133 specified an incorrect weld. The work
package was changed to specify the proper welding procedure. This j
,
resulted in additional time spent with' Unit 1 RWCU out of service.
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c. Conclusions
The inspectors noted that work package deficiencies resulted in additional time )
spent in TS LCOs, or affected aquipment used to support reactor operations. '
M2 Maintenance and Material Condition of Facilities and Equipment
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M2.1 Instrument Calibration Proaram Weaknesses
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a. Insoection Scoce (61726)
The inspectors reviewed portions of the licensee's instrument calibration program,
operations surveillance procedures, and a site quality verification (SQV) corrective
action record (CAR). The inspectors reviewed codes and standards committed to
by the hcensee.
b. Observations and Findinas
The inspectors identified process radiation monitoring support equipment
instrumentation that was not included in a calibration program (Inspection Report
50-254/265-96020, Section R2.1). The inspectors also identified indicators
monitored by operators during monthly surveillance testing of the emergency diesel
generators that were not included in a calibration program. The licenses planned to
calibrate both local and remote power system meters when calibrating other power
system components. However, the licensee stated that local indicators logged
during EDG surveillance testing were not required to be calibrated by Quad Cities
instrument Procedure (OlP) 100-11, " Calibration of instruments used by Operations
in Performing Surveillance Requirements," since the indicators were used for
trending purposes and were not used in determining equipment operability. 4
SOV documented a level 1 corrective action request (CAR) on CAR 04-97-004 that
the control room narrow range reactor pressure indicator, control room emergency
diesel generator frequency and voltage indicators, and secondary containrnent
differential pressure indicators were used by operators to determine equipment
operability, but were not included in a calibration program. ,
The licensee also found the Unit 1 EDG frequency meter was out of calibration and
documented the discrepancy on an out of tolerance report as required by procedure.
However, the inspectors noted out of tolerance reports were neither tracked nor
trended. As a result, adverse trends for electrical power instrument calibrations
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, may not be adequately identified. The licensee planned to document future power
system meter discrepancies on PlFs.
c. Conclusion
Both the inspectors and licensee-identified indicators used by operators to determine
equipment operability and also used for equipment trending that was not included in
a calibration program. The inspectors considered resolution of the instrument
calibration program to be an inspector Followup item (50-254/265-97002 06)
pending review of licensee's corrective action system results.
M2.2 Containment Atmosohere Monitorina Svstem Maintenance
a. Insoection Scoce (62707)
The inspectors observed corrective maintenance activities, reviewed maintenance
history on the 1B containment atmosphere monitor (CAM), and reviewed the
UFSAR Section 6.2.5.2.
b. Observations and Findinas
The CAM system was designed to be used post-accident to monitor hydrogen and
oxygen levels in containment. The 1B CAM system was declared inoperable on
January 24,1997, after the oxygen analyzer failed the weekly surveillance test.
The licensee entered TS LCO 3.2.F which required the system to be restored or the
reactor shut down in 30 days.
During the troubleshooting effort, maintenance workers encountered numerous
problems with the system not related to the observed failure mode. Work continued l
without resolving the problems until day 18 of the LCO before a root cause j
investigation team was assembled. At this point, the maintenance supervisor had I
contacted the vendor who was on site assisting the maintenance workers. On day
19 of the LCO the problems were corrected and the system restored to an operable
status. The inspectors concluded that assembly of the team was slow and had little
impact on the final outcome of this maintenance activity. l
The cause of the failure was determined to be a bad oxygen analyzer cellin
combination with a failed regulator. The maintenance team also found at least four
other degraded parts, including other regulators in the system. The licensee sent
the failed regulators and oxygen analyzer cell off site for failure analysis. At the
conclusion of the inspection period, the licensee did not have the results of those
analyses. ;
After reviewing the maintenance history for the 1B CAM system, the inspectors !
found that multiple regulator problems had occurred in the past. After each failure
event regulators were replaced, however no root cause for repeat failures was
performed. Furthermore, in the maintenance history, the inspectore found several
failures attributed to water intrusion in the system. A design change to eliminate
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. this longstanding problem was planned for 1998 and compensatory measures to ;
periodically drain water from the system were recently established. l
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The inspectors reviewed the CAM system monitoring for the maintenance rule ,
(10 CFR 50.65). During the most recent assessment in December 1996, the l
licensee exceeded the reliability criteria of no more than two failed surveillances per l
refuel cycle on the Unit 2 CAM system. Train A experienced two failed
surveillances and Train B experienced one failed surveillance. At that time, the
system was reclassified as potential (a) (1). However, the system engineer
recommended that the classification remain (a) (2) and submitted a reliability criteria
change to the site maintenance rule coordinator to allow no more than three failed
surveillances per refuel cycle. The rationale for the criteria change was that the
refuel cycle had changed from about 18 months to 22 months, no more than two
failed surveillances per train occurred, and none of the three failed surveillances in
question were categorized as maintenance preventable functional failures (MPFF).
At the end of the inspection period, the criteria had not been revised and no action
had been taken to reclassify the system as (a) (1).
The inspectors reviewed the licensee's list of maintenance rule functional failures
(MRFF) for July 1993 through December 1996. Seventeen MRFFs were
documented for both Unit 1 and Unit 2 CAM systems. Two of the seventeen
failures were identified as MPFFs. The inspectors identified several other failures on
the list which appeared to be maintenance preventable and disagreed with the
licensee's application of the MPFF definition. The cause of 3 of the 17 failures was
unknown and yet the events were not categorized as MPFF. Two additional failures
were attributed to aging power supplies and were also not coded as MPFF. The
inspectors found that the licensee's root cause investigations into past failures were
not detailed enough to identify events as MPFFs.
The inspectors concluded that the root cause of repetitive CAM system problems
and failures had not been identified, but that repetitive regulator problems and water
intrusion were longstanding issues that had not been resolved. Additionally, the
inspectors identified problams with the licensee's implementation of the
maintenance rule for this system, specifically the identification of failures as
maintenance preventable and the failure to promptly reclassify the Unit 2 CAM
system to an (a) (1) status. The inspectors planned to follow up on the licensee's
root cause assessment of the most recent failures and the classification of the
Unit 2 CAM system under the maintenance rule and consider this to be an
Unresolved item (50-254/265-97002-07).
c. Conclusion
The inspectors had concerns with the licensee's implementation of the maintenance
rule, specifically the identification of MPFF events and the failure to promptly
evaluate the Unit 2 CAM system status as (a)(1).
The inspectors also concluded that long-standing issues regarding repetitive
regulator failures and water intrusion in the CAM system had not been resolved and
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. although the immediate problems were corrected and the system declared operable,
the root causes of the system failure had yet to be fully addressed. In addition, an
- excessive amount of LCO time was used before additional maintenance resources
were applied to repairs.
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M2.3 Miscellaneous Material Condition issues (71707)
The inspectors noted that continued equipment problems affected reactor
operations and resulted in an early shutdown for refueling for Unit 2 and a forced
shutdown for Unit 1. Below are severalitems identified by the licensee and the
inspectors that affected plant operations:
- s
The inspectors noticed that a number of valves on the Unit 2 control rod drive HCUs
had rusty flange bolts. The deteriorating condition of these valves was not included
- in a problem tracking system, such as an action request.
- Two Unit 2 intermediate range monitor (IRM) systems were failed prior to the unit
'
shutdown. A third IRM failed during the shutdown.
- A Unit 1 turbine sealing steam valve developed a leak. Repairs were performed
4
during the forced outage.
The Unit 2 DWEDS containment isolation valve was difficult to open. The cause
was identified as thermal binding.
i
l A Unit 1 RPS relay failed. The licensee made a conservative decision to shut the
unit down to investigate and repair. The relay was replaced during the forced
- outage.
.
M8 Miscellaneous Maintenance issues
M 8.1 (Closed) Violation 50-254/265-95010-02: Solenoid-Operated Valve improperly
Mounted. The inspectors identified a safety-related solenoid-operated valve that
was not mounted in accordance with vendor instructions. The licensee remounted
the solenoid and verified valve operability. The licensee verified proper installation
of similar solenoid-operated valves accessible during power operations. No other
deficiencies were noted. Procurement, maintenance, and engineering personnel
received training on the necessity of maintaining proper orientation of solenoid-
operated valves. This item is closed.
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Engineering and Technical Support (71707, 37551)
E2 Engineering Support of Facilities and Equipment
E 2.2 Facility Adherence to the Uodated Final Safety Analvsis Reoort
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 Acolicability
02.4 8.3.1.6 EDG Systems
O 2.4 9.5 EDG Auxiliary Systems
02.5 6.3.2.1, 6.3.2.2 ECCS Room Coolers
04.1 15.1,15.5 Inadvertent HPCI Actuation
M 2.2 6.2.5.2 CAM System
For the sections reviewed, no issues of plant configuration of UFSAR accuracy were
identified.
E7 Quality Assurance in Engineering Activities
E7.1 Proaram Weaknesses in Evaluation of Part 21 issues
a. Insoection Scope (37551)
The inspectors reviewed the PlF process to determine how the licensee
implemented 10 CFR 21, " Reporting of Defects and Noncompliance."
b. Observations and Findinas
The licensee documented a failure of the shared EDG to start on November 4,
1995, on PlF 95-2795. The PlF was reviewed by the event screening committee
(ESC) the following day and determined not to be a potential Part 21 reportable
event. Subsequent evaluation determined the shared EDG failed to start due to a
defective part. The inspectors determined the licensee evaluated and correctly
concluded that the defective part did not have Part 21 applicability. However, the
inspectors were concerned the licensee's ESC prematurely evaluated Part 21
aspects prior to identifying defective parts as the cause for equipment failure. The
inspectors spoke to the site quality verification manager who acknowledged the
process vulnerability. However, no plans were committed to by the licensee to
permanently address the issue.
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. c. Conclusions
The inspectors identified a vulnerability in the licensee's method of identifying and
reporting of 10 CFR Part 21 issues. However, the inspectors did not identify any
instances where 10 CFR Part 21 notifications were not made when required.
E8 Miscellaneous Engineering issues
E 8.1 (Closed) Licensee Event Reoort (LER) 50-254-93002. Rev.1: Failure of Secondary
Containment Test. The licensee added an additional corrective action for this LER.
The inspectors reviewed the additional corrective action. This item is closed.
l >
IV. Plant Support
R1 Radiological Protection and Chemistry Controls
R1.1 Radioloaical Protection Observations
1
a. Insoection Scooe (71750)
The inspectors reviewed maintenance activitfes in the plant requiring support by
radiological protection technicians (RPTs). 1
b. Observations and Findinas
The inspectors observed the following radiological protection concerns:
The reactor building crane malfunctioned preventing workers from lifting the spare
recirculation pump motor. The inspectors observed then notified the RPT of some
workers loitering in radiation areas during the delay. The RPT then directed the
workers into lower radiation areas until the crane was returned to service.
The inspectors also noted a RPT in charge of a job on the refuel floor who was
outside of the work area, but within shouting distance of the workers. The
inspectors questioned the ability of the RPT to control the job from a distance.
The inspectors observed a radiation worker inside a clean area leaning over a
contamination boundary against a pillar in a contaminated area. The inspectors
notified a RPT supervisor who corrected the individual. The inspectors were
concerned that the individual did not respect the contamination boundary and the
radiological deficiency was not detected by the two RPTs on the job. There was no !
spread of contamination into the clean area from this event. I
A shoe contamination event occurred during a walkdown of the area above the .
j Unit 2 drywell equipment hatch. A repeat event occurred the next day, after I
radiation protection personnel were informed and the area had been cleaned.
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The inspectors identified some RPTs lacked good command and control of
radiological aspects of the work assigned. This could have resulted in an increase
in dose to workers and the potential to spread contamination into clean areas.
R4 Staff Knowledge and Performance in Radiological Protection and Chemistry Controls
R4.1 Observations of Simulated Exercise of Hiah Radiation Samolino System
a. Insoection Scoce ( 71750)
The inspectors observed an emergency exercise which involved a simulated use of
the high radiation sampling system (HRSS), ,
b. Observations and Findinos
The inspectors noted that the sampling teams' performance during the drill was
good. While the drill did not involve actually taking samples, allindividuals involved
simulated in detail the actions that would be taken to obtain a reactor water sample
under post-accident conditions. The chemistry technicians and the HRSS chemist
were knowledgeable of the procedures and the equipment. The HRSS building was
adequately equipped with the necessary supplies. The sample was obtained and
processed in the required time,
c. Conclusions
The inspectors concluded that the HRSS drill was successful and that personnel >
performance was good.
V. Manaaement Meetinas l
X1 Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at the i
conclusion of the inspection on March 14,1997. The licensee acknowledged the findings
presented. ,
The inspectors asked the licensee whether any materials examined during the inspection i
should be considered proprietary. No proprietary information was identified. ,
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PARTIAL LIST OF PERSONS CONTACTED
'
Licensee
E. Kraft, Site Vice President
A. Chernick, Regulatory Assurance Supervisor ,
D. Cook, Operations Manager
J. Hoeller, Independent Safety Engineering Supervisor .
J. Hutchinson, Site Engineering Manager !
W. Lipscomb, Work Control Superintendent
M. Wayland, Maintenance Superintendent
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l, INSPECTION PROCEDURES USED
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IP 37551: Onsite Engineering
IP 61726: Surveillance Observations
IP 627070: Maintenance Observation
4
IP 71707: Plant Operations
IP 71750: Plant Support Activities
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
[ 50-254/265-97002-01 VIO Unit 1 RPS relay problem
50-254/265-97002-02 URI inadequate modification closure resulted in
"
ventilation problems
50-254/265-97002-03 VIO failure to control turbine building negative
.
pressure
50-254/265-97002-04 VIO high pressure coolant injection system initiation
during testing
j 50-254/265-97002-05 IFl weaknesses identified in scheduling activities
50-254/265-97002-06 IFl instrument calibration program weaknesses !
1
50/254/265-97002-07 IFl containment atmosphere monitoring system
"
maintenance
j Closed
,
50-254/265 96002-02 VIO primary containment violation
j 50-254/265-95010-02 VIO solenoid-operated valve improperly mounted
j
50-254/265-93002, Rev.1 LER failure of secondary containment test
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LIST OF ACRONYMS USED
l.
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ADS Automatic Depressurization System
AR Action Request
CAM Containment Atmosphere Monitoring *
CAR Corrective Action Record
- Comed Commonwealth Edison Company
DP Differential Pressure
ECCS Emergency Core Cooling System
i EDG Emergency Diesel Generator
- ENS Emergency Notification System
i ESC Event Screening Committee l
1 EWCS Electronic Work Control System
. GL Generic Letter j
j HCU Hydraulic Control Unit ;
4
HPCI High Pressure Coolant injection j
HRSS High Radiation Sampling System l
'
IFl Inspector Followup Item
INPO Institute of Nuclear Power Operations l
- IPEEE Individual Plant Examination for External Events !
8
IRM Intermediate Range Monitors
kV Kilovolt l
LCO Limiting Condition for Operation
LER Licensee Event Report
LLRT Local Leak Rate Test
LPCI Low Pressure Coolant injection
LTD Laundry Tool Decontamination
MOV Motor-Operated Valve
MPFF Maintenance Preventable Functional Failure
MRFF Maintenance Rule Functional Failure
PDR Public Document Room
PIF Problem Identification Form
QCAN Quad Cities Annunciator Procedure
OCIPM . Quad Cities Instrument Preventive Maintenance
OCOA Quad Cities Operating Abnormal Procedure J
OlP Ouad Cities instrument Procedure l
RPS Reactor Protection System j
RPT Radiation Protection Technician l
RWCU Reactor Water Clean Up
SAR Safety Analysis Report l
SOV Site Quality Verification i
TS- Technical Specification J
UFSAR Updated Final Safety Analysis Report !
URI Unresolved item
VIO Violation
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