ML20149G899
| ML20149G899 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 07/11/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20149G866 | List: |
| References | |
| 50-254-97-08, 50-254-97-8, 50-265-97-08, 50-265-97-8, NUDOCS 9707240118 | |
| Download: ML20149G899 (23) | |
See also: IR 05000254/1997008
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U. S. NUCLEAR REGULATORY COMMISSION
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REGION lit
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Docket Nos:
50-254, 50-265
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License Nos:
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Report No:
50-254/97008(DRP), 50-265/97008(DRP)
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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 '
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Cordova, IL 61242
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Dates:
May 6 through June 16,1997
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inspectors:
L. Collins, Resident inspector
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K. Walton, Resident Inspector
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R. Ganser, Illinois Department of Nuclear Safety
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Approved by:
Wayne Kropp, Chief
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Reactor Projects Branch 1
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9707240118 970711
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ADOCK 05000254
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EXECUTIVE SUMMARY
Ouad Cities Nuclear Power Station, Units 1 & 2
NRC Inspection Report 50-254/97008(DRP), 50-265/97008(DRP)
This inspection included aspects of licensee operations, engineering, maintenance, and
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plant support. The report covers a 6-week period of resident inspection.
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Ooerations
Major activities such as tno Unit 2 refueling and startup were performed in a controlled
manner and essentially error free. Less significant evolutions were not always planned as
carefully and occasionally resulted in unexpected events or challenges to operatora.
Operators inappropriately used the discrete component operation process to perform
alternate system lineups for the fuel pool cooling system, drywell floor drain system, and
the feedwater system during unit shutdowns.
Maintenance and Surveillance
ihe inspectors identified, through a sampling of emergency diesel generator (EDG)
surveillance procedures, where the EDG surveillance program did not meet either the
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Technical Specification (TS) and/or the design basis documents. There was also one
example where the test methodology was not adequate to determine the sealing capability
of a check valve in the starting air system for the EDG.
Maintenance workers performed tasks safely and according to procedures. The successful
repair of the reactor core isolation cooling (RCIC) system steam supply valve was well
planned.
The inspectors reviewed and observed severallogic functional tests on Unit 2. The tests
were satisfactorily performed. The inspectors observed minor deficiencies including one
pretest brief where the test director was unprepared and a maintenance error in which a
jumper was placed in the wrong location.
Ennineerinn
The inspectors identified an inadequacy with an abnormal operating procedure for the high
pressure coolant injection (HPCI) system. TF ) procedure did not include a reference for
manually engaging the turning gear if necessary after an HPCI turbine trip.
Plant Suooort
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As low as reasonably achievable (ALARA) initiatives during the Unit 2 refuel outage helped
to reduce overall station dose to date. Radiation protection tracking and trending of dose
was improved over previous refuel outages and allowed the mid-year rev sion to the dose
goal. The 1997 station dose goal was revised from 1260 rem to 720 rem.
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The failure to take appropriate corrective action in response to identified zebra mussel
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growth in 1995 resulted in both firo pumps becoming inoperable in 1996 due to clogged
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suction strainers,
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Report Details
Summarv of Plant Status
Unit 1 entered the inspection period at full power. On May 16 a load drop was performed
to repair a leak on the RCIC system steam supply valve. Following repairs to the RCIC
valve, load was increased to full power and remained at or near full power throughout the
inspection period.
Unit 2 was shut down for refueling outage O2R14 on February 28,1997. The reactor
was restarted on June 8 and was shut down on June 10 to repair a degraded seal
condition on the 2B recirculation system rump. The unit remained shut down at the end
of the inspection period.
I. Operations
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Conduct of Operations
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01.1 Qbservation of Sinnificant Operations Evolutions
a.
Insoection Scone (71707)
During the period the inspectors observed major refueling outage activities for
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Unit 2. The inspectors watched reactor refueling operations from the control room
and refueling bridge, toured the drywell prior to final closcout, and observed startup
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activities including reactor criticality, power increase, and shutdown to repair the
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2B recirculation pump seal.
b.
Observations and Findinos
Refueling began May 7 in accordance with Quad Cities Fuel Handling
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Procedure 0100-01, " Master Refueling Procedure." The inspectors verified that
operators were in constant communication, recorded temperatures on an hourly
basis, and performed required checks of source range monitor (SRM) response.
Operators on the refueling bridge used three independent checks versus the
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required two when loading fuel assemblies into the reactor.
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The inspectors conducted a drywellinspection near the end of the Unit 2 refueling
outage. Drywell general material condition and housekeeping was good, notably
better than at the end of previous outages. The inspectors identified a large
amount of test wiring, previously used to transmit test data from main steam relief
valves. The licensee subsequently removed this wiring. A small amount of work
remained to be completed prior to final closeout inspections by the licensee.
During Unit 2 reactor vesselleak testing prior to startup and during startup
activities, the inspectors attended several " heightened level of awareness"
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briefings. The briefings were well coordinated and included all participating
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departments. Procedures were discussed and task responsibilities assigned. The
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inspectors observed full participation from operators and noted clear communication
with respect to potential problems, abort criteria, and expected results.
Unit 2 startup' activities were carefully conducted and essentially error free. Noted
anomalies included a single control rod drift into the core from the fully withdrawn
position and the abnormal response of the 2B recirculation pump seal pressures.
Operators promptly noted the problems and took appropriate actions. The Unit 2
reactor was subsequently shut down on June 10 to replace the recirculation pump
seal.
On several occasions operators encountered an unexpected plant response during
fairly standard evolutions. Twice a control rod drive pump tripped after starting,
and once during a teactor protection system (RPS) power supply swap for Unit 2 a '
- full reactor trip occurred. in all of these cases, plant configuration was different
than expected and operator actions resulted in an unanticipated response. The
control rod drive (CRD) pumps tripped on low suction pressure and the reactor trip
occurred because the RPS shortin0 links were installed during the power supply
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swap. Management attributed the problems to a breakdown in scheduling and
planning during the outage and took actions to ensure that all operations' activities
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were carefully reviewed prior to execution. The inspectors noted that no further
anomalies of this type occurred.
c.
Conclusions
Major activities such as refueling and startup 'ontinued to be carefully planned and
controlled. Operator performance during thex avolutions was essentially error free.
Problems with schedule control resulted in an unegected plant response on a few
occasions. No adverse consequences resulted, and corrective actions were taken
to prevent further events.
01.2 Both Standbv Gas Treatment Trains Inonerable Durino Testina
a.
Insnection Scone (71707. 93702)
The inspectors reviewed the shift engineer's logbook and spoke with operations
personnel concerning the standby gas treatment (SBGT) system inoperability,
b.
Observations and Findinas
During the performance of Guad Cities Operating Surveillance Procedure 1600 13
" Refueling Outage PCI [ Primary Containment isolation] Groups 2 and 3 Isolation
Test," on May 4,1997, operators inadvertently rendered both SBGT trains
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inoperable. On May 5 the shift engineer determined that the condition was
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reportable in accordance with 10 CFR 50.72 and initiated Problem Information Form
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(PIF) 97-2156.
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The SBGT system consisted of an A train and a B train, with the A train control
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switch normally in standby and the B train control switch in primary. The SBGT
system logic automaticaliy starts the primary train when en initiation signal is
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received, if the primary train failed, the standby train would start after a 25 second
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time delay. To test this function, the B train was taken to the off position and the
A train was placed in standby. An initiation signal was simulated, but the A train
f ailed to start after the 25 second delay.
Earlier in the test a rnaintenance error caused a fuse to blow. Test personnel
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recognized the error and proceeded to replace the blown fuse, but inadvertently
reinstalled the bad fuse. This blown fuse in the logic would have prevented the
A train from automatically starting when in standby. The error in reinstal!ing the
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bad fuse was not recognized ui.*il the test continued and the A train did not start.
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The blown fuse was replaced. During this time the operators recognized that Unit 1
was in a limiting condition for operation (LCO) in accordance with TS 3.7.P.2, but
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did not recognize that the event was reportable under 10 CFR 50.72(b)(2)(iii) as the
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occurrence of any event or condition that alone could have prevented the fulfillment
of the safety function of structures or systems that are needed to control the
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release of radioactive material. This condition existed from 8:35 p.m. to 9:15 p.m.
central standard time on May 4,1997. During this period both trains were capable
of manual start but not automatic start.
The next day the inspectors questioned the day shift engineer about the event and
required reporting and found that the shif t engineer was already reviewing the
circumstances surrounding the event. The shift engineer concluded that the event
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was reportable and an emergency notification system (ENS) call was made on
May 5,1997. Failure to report this condition within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of discovery was a
vio!ation of 10 CFR 50.72. This licensee-identified and corrected violation is being
treated as a Non-cited Violation (50-254/265-97008-01) consistent with
Section Vill.B.I of the NRC Enforcement Policy. The inspectors reviewed the
licensee's corrective actions, which included a review of this event and reportability
requirements with licensed reactor operators.
c.
Conclusions
The inspectors concluded that the safety significance of this event was low since
either train could have been manually started. However, the failure to recognize a
reportable event was a concern. The licensee's corrective actions addressed the
inspectors' concern with accurately identifying reportable occurrences.
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Operations Procedures and Documentation
03.1 Use of Discrete Comoonent Ooerations
a.
Insoection Scone (71707)
The inspectors reviewed the use of discrete component operations (DCOs) and a
set of completed DCOs from April 1997. The inspectors discussed the use of
DCOs with management.
b.
Observations and Findinns
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Quad Cities Administrative Procedure 0230-06, " Discrete Component Operation,"
provided guidance for the operation of individual components where other
procedural guidance did not exist. A DCO was defined as a set of actions
necessary to operate a system component. The use of a DCO was not limited to
one component, since more than one component may require operation to support
the activity. The DCO process required that a request form be filled out with
appropriate action steps approved by the unit supervisor. The procedure stated
that a DCO was utilized when a component required operation for testing, such as
troubleshooting or post maintenance test verification (PMTV), or as part of a
maintenance activity such as an uncoupled pump run or, in other situations, at the
unit supervisor's discretion. The DCO was approved by two individuals, a reactor
operator or knowledgeable management person, and the unit supervisor.
The inspectors reviewed the following examples of the DCO process:
Operators used a DCO to align the Unit 2 drywell floor drain sump (DWFDS)
discharge to the floor drain collector tank rather than the normal lir.eup to
the waste collector tank, As a result of drywell activities during the cutage,
the DWFDS water was not suitable for reprocessing, and operators needed
to route the water to the floor drain collector tank. No procedure existed for
changing the lineup, and the DCO was generated on April 3,1997. This
path was used until the system was realigned to the normal configuration on
May 5,1997
Operators used a DCO during the refueling outage on Unit 2 to alter the fuel
pool cooling pump discharge valve lineup in order to throttle flow to the
reactor cavity while r0 tinuing to discharge to the fuel pool. A procedure
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existed (Quad Cities operating Procedure [QCOP] 1900-20) and could have
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been utilized with only minor changes to perform the required evolution.
Another DCO was used to control reactor water level for Unit 1 during a
shutdown when the reactor water cleanup system was not available to
reject water. This DCO directed operators to isolate leakage past the
feedwater low flow valve while the reactor water cleanup (RWCU) system
was shut down and to open the valves as necessary to add water to the
reactor vessel.
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In all three examples discussed above, operators used DCOs to perform infrequent
but necessary tasks. Each case involved an attemate system lineup and was not a
" component" operation. No adverse consequences resulted; however, the use of
D,COs rather than reviewed and approved procedures for operational activities was
a concern.
The inspectors questioned operations management about the use of DCOs. A third
party review of the use of DCOs had previously identified issues regarding potential
improper use and lack of reviaw. As a result the licensee had begun a monthly
review of DCOs and had discovered issues that were similar to the inspectors'
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findings. The licensee was aware of the examples discussed above and was
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pursuing corrective action. At the end of the inspection period, operations'
management had relayed examples of inappropr'iate use of the DCO process to all
of the operating crews and had included the appropriate rnethods for controlling the
activities (i.e., procedure field change, out of service, etc.).
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Conclusions
The inspectors found that on several occasions DCOs were used improperly. The
use of DCOs instead of reviewed and approved procedures for operational activities
could result in unexpected challenges or plant response. However, the problems
were previously identified, and the licensee had initiated corrective action.
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Operator Training and Qualification (IP 71707)
05.1 Onerator Trainina Observations
a.
Insoection Scone
The inspectors observed all or portions of the folluwing training activities:
-Two classroom sessions of initial licensed training (ILT), including the oxygen
sampling and containment emergency venting systems
Licensed operator requalification (LOR) classroom session on safe shutdown
makeup system
Two simulator sessions including " anticipated transient without scram"
(ATWS) and " recirculation pump run-up," and A post scenario critique
following the simulator session for ATWS.
b.
Observations and Findinas
The ILT class was fast paced and concentrated. The instructor was clear and
precise and closely followed the lesson plan. The inspectors noted that information
concerning containment emergency venting, in the event of a loss of coolant
accident, included clear instruction on the requirement for timely notification of
outside agencies.
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During simulator training, in one scenario, the shift technical advisor (STA) was
. located in the simulator control room at the start of the scenario. When in the
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plant, the STA is generally stationed outside the control room. The inspectors
questioned whether it would have been more realistic for the STA function to
remain outside the simulator control roorn until the scenario warranted STA
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participation. The person in the role of the STA stated that the normal practice was
for the STA to remain outside the simulator control room until required to enter by
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the simulated training event, and that this was an exception to what was the
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normal practice. The post scenario critique, following the simulator sessions, was
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interactive and constructive.
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Conclusions
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In the areas observed instructors were well prepared and trainees were interactive
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in the training effort. Operations management demonstrated an active interest in
assessing and improvin0 the ;evel of training effectiveness.
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Miscellaneous Operations issues (92700)
08.1 (Closed) Licensee Event Report (LER) (50-254/93014): Intermediate Range
Monitor 11 and Average Power Range Monitor 3 Both Bypassed Without % Scram
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Being inserted. The LER stated that the cause was the f ailure to perform a self
check. The inspectors verified that all corrective actions were completed and noted
an increased use of self check and decreased number of errors since this event
occurred. This item is closed.
08.2 (Closed) Unresolved item (50-254:265/94016-03): Reactor Vessel Draining
Evolution. Quad Cities Administrative Procedure 260-3, Revision 2, " Screening for
Potential to Drain the Vessel," considered that a motor operated valve (MOV)
closcable from the control room provided sufficient isolation to prevent inadvertent-
drain down of the reactor vessel. The inspectors verified that the licensee has
since revised the procedure (Revision 5) which credits automatic isolation on low
reactor water level to prevent drain down. This item is closed.
08.3 (Closed) Violation (50-254:265/96004-01a&b): Out of Service Errors Render the %
EDG Inoperable t nd 6: ult in an Engineered Safety Features System Actuation.
The licensee couaseled individuals involved in these events and added information
to diesel generator procedures to describe the impact of removing certain fuses.
The inspectors noted a decline in out of service errors since these events occurred
in 1996. This item 6 closed.
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08.4 (Closed) Licensee Event Reoort (50-265/97009): Both Trains of SBGT Inoperable
Due to Fuse Replacement Error. See Section 01.2. This LER is closed.
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II. Maintenance
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Conduct of Maintenance
M 1.1 Surveillance Observations
a.
Insoection Scong
The inspectors observed / reviewed all or portions of the following surveillances.
OCIPM 0756-03
Local Power Range Monitor (LPRM) Calibration
QCIS 0200-28
Calibratiori ATWS High Pressure and Low Level Instruments
QCCP 0600-07
Determination of Sodium Pentaborate Concentration in
Standby Liquid Control System
OTS 0170-07
Functional Test of the Second Level Undervoltage (Bus 23-1)
~QCTS 0300-07
Functional Testing of the ATWS Recirculation Pump Trip and
Alternate Rod insertion (ARI) Logic
QCTS 0300-04
High Pressure Coolant injection Logic Functional Test
QCTS 0920-15
Strongest Control Rod Withdraw Subcritical Check
OCIS 0500-03
Instrument RPS Scram Response Time Test
OCTS 0300-07
(IP 97-0076), ATWS Recirculation Pump Test and ARI Logic
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QCTS 300-03
RCIC Logic Functional Test
OCTS 0310-03
Unit 2 Emergency Core Spray System Simulated Automatic
Actuation and Diesel Generator Auto-Start Surveillance
b.
Observations and Findinas
During a pretest brief the inspectors noted, in one case, the test director did not
appear to be fully knowledgeable of the details of the test. However, questions
generated during the brief were answered by the test director prior to commencing
with the test.
At one point during Quad Cities Technical Surveillance (OCTS) 300-03, RCIC Logic
Functional Test, the inspectors observed that test technicians were confused about
the location of a push button. Subsequently, the test was stopped until the correct
switch location was identified. The test was again stopped when a jumper was
placed on a wrong relay causing a ground condition and concurrent alarms in the
control room. Problem identification Form 97-2277 was written to address this
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problem. The licensee found that there was conflicting labeling on a relay resulting -
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from past relay swaps without subsequent removal of old labeling. The evolution
had been successfully performed in the previous fuel cycle with no known
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problems. The electrical drawing had been changed to reflect the new
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configuration, so when the test director walked down the test, he observed the
correct labeling on the correct relay. There were no panellayout drawings to show
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precise locations of relays in this panel. The test director performed a thorough
walkdown to ensure that there were no other labeling problems. Following this, the
test was successfully completed without further incident.
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The inspectors observed key portions of the emergency core cooling system (ECCS)
logic functional test, QCTS 0310-03. Operators conducted a final briefing prior to
initiation of the test. ' Contingencies were reviewed for critical steps so that
operators were certain of what action to take if the expected automatic action did
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not occu'r. Command and control was good. Each operator was given an assigned
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task and was thoroughly familiar with the actions required. The test was
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completed satisfactorily.
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C.onclusions
The inspectors reviewed and observed severallogic functional tests on Unit 2. The
tests were satisfactorily performed. The inspectors observed minor deficiencies
including one protest brief where the test director was unprepared and a
maintenance error in which a jumper was placed in the wrong location.
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M1.2 Maintenance Observations
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a.
insoection Scone
The inspectors observed the following maintenance activities:
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Post maintenance testing of the Unit 2 reactor protection system
uninterruptible power supply,
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Overhaul of the 2A CRD pump in maintenance shop,
Licensee's activities concerning a RCIC steam valve leak,
Emergency Diesel Generator Air Start Motor Replacement,
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Modify and Install Bus 24-1 Cubicle 8 for New Breakers, and
Replace Merlin Gerin Breaker Auxiliary Switches.
b.
Observations and Findinos
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The inspector observed electrical maintenance technicians perform post
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maintenance testing on the Unit 2 RPS uninterruptible power supply (UPS) following
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a periodic maintenance inspection. Workers performed voltage measurements to
ensure UPS setup was in accordance with the procedure. The inspectors observed
that workers observed proper safety precautions, communicated effectively, and
carefully followed procedures.
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Work observed on the 2A CRD pump consisted of mechanical maintenance
department (MMD) personnel and a vendor representative in the process of
measuring and stacking the rotating segments of the multi stage pump onto the
shaft. This procedure required numerous trial setups. Workers carefully recorded
measurements and safely handled the sections of the pump assembly. No
discrepancies were observed in this activity.
The-Unit 1 RCIC system outboard steam supply valve, 1-1301-17, had developed a
steam leak around the seal ring. The licensee had bcen monitoring the steam leak
and, based on its progression, developed a plan to repair the valve during reduced
oower operations to limit radiation exposure to personnel. Through a good planning
effort and effective teamwork, the licensee successfully completed the repair work
with dose exposure levels below those projected.
c.
Conclusions
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Maintenance workers performed tasks safely and according to plant procedures.
The licensee effectively monitored the RCIC steam supply valve leakage. This
resulted in a timely and well planned repair effort. The licensee's effort to plan and
effect repairs resulted in successful repair of the valve leak with minimum dose
exposure to workers.
M3
Maintenance Procedures and Documentation
M3.1 Emeraency Diesel Generator Surveillance Procedures
a.
Insoection Scone (61726)
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The inspectors reviewed the below listed EDG surveillance procedures to determine
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if the requirements of Sections 8.3, 9.5.4, 9.5.5, and 9.5.6 of the Updated Final
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Safety Analysis Report (UFSAR) and the applicable portions of 3/4.9.A of the TS
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were properly addressed. The inspectors also reviewed the surveillance procedures
to verify that the applicable TS bases were addressed.
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OCOS 6600-01
" Diesel Generator Monthly Load Test," Revision 15
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OCOS 6600-02
" Diesel Generator Air Compressor Operability,"
Revision 9
OCOS 6600-03
" Diesel Fuel Oil Pump Monthly Operability," Revision 2
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OCOS 6600-05
" Quarterly Diesel Generator Fuel Oil Transfer Pump
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Flow Rate Test," Revision 6
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OTS 0310-06
" Emergency Diesel Generator Protective Trip Auto-Start
Bypass Surveillance," Revision 3
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Interim Procedure
"DG [ diesel generator] Trip & Alarm Switches Cal.,
97-0080
Protective Trip Bypass & Functional Test"
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The inspectors also reviewed procedure OCOS 6600-02, along with drawing M-25,
and interim Procedure 97-0080, along with drawing 4E-1350A (sheets 1 and 2), to
determine if the testing methodology described in the procedures was acceptable.
b.
Observations and Findinas
The inspectors' review of the above procedures, applicable portions of the TS, and
the UFSAR identified the following:
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QCOS 6600-01, " Diesel Generator Monthly Load Test"
Step G.1 (performance acceptance criteria) states that the generator volta 0e was
3900 to 4580 volts. The TS requirement for voltage, as stated in 4.9.A.2.c. was
4160 volts plus or minus 420 volts (3740-4580 volts). The voltage acceptance
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criteria in surveillance procedure QCOS 6600-01 was more than the TS
requirements (3900 versus 3740). Discussion with the system engir.mr
determined that the acceptance criteria was administratively controlled to
3900 volts to ensure the EDG would maintain voltage above degreded voltage
criteria in TS 3.2.B-1.6.b (3845 volts-Unit 1 and 3833 volts-Unit 2).
Section 8.3.1.8 of the UFSAR, Analysis of Station Voltages, states that the
minimum running voltage for the 4160 kV bus would be 3840 volts. The UFSAR
further states that upon an undervoltage condition where the undervoltage relays
actuate, the incoming line breakers trip, load shedding of the 4160 kV busses
initiate, and the associated EDG starts and the EDG output breaker closes when the
voltage and frequency from the EDG become satisfactory. At present the TS
requirements for EDG voltage differs from the UFSAR analysis for degraded voltage.
Even though the licensee is administratively controlling the minimum voltage during
the monthly surveillance in OCOS 6600-01, Revision 15, a TS amendment would
be necessary to establish acceptance criteria that would be in agreement with the
design basis. This issue is an Inspector Followup Item (50-254/265-97008-02)
pending submittal of a TS amendment to revise the EDG voltage acceptance criteria
to agree with the design basis.
Technical Specification basis 3/4.9, page B3/4.9-3, states that the periodic
surveillance requirements also verify that without the aid of the refill compressor,
sufficient air start capacity for each EDG is available. The basis further states that
with either pair of air receiver tanks at minimum specified pressure, there is
sufficient air in the tanks to start the EDG. Procedure OCOS 6600-01, Revision 15,
does not : quire that the air compressors be off and the air tanks at minimum
specified ptussure (230 psig). This is considered an Unresolved item
(50 254/265-97008-03) pending further discussion with the NRR technical staff.
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QCOS 6600-02, " Diesel Generator Air Compressor Operability"
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Each EDG has two banks of starting air with each bank consisting of a pair of air
receiving tanks (A'and B or C and D) and associated valves, and one starting air
compressor. One of the purposes of QCOS 6600-02, Revision 9, is to verify that
the check valves on the discharge header for each pair of air receiver tanks will
close and seal as required by the licensee's IST program. The test methodology to
verify the discharge check valve for air banks A and B will close and seal consisted
)
of the following:
1)
Isolate the C and D air receiver tanks.
2)
Close the discharge valve for the air compressor associated with banks
A and B and placing the air compressor control switch in pull-to-lock (PTL).
3)
Bleed down banks A and B to 225 to 230 psig and record the final pressure.
i
4)
Unisolate the C and D air receiver tanks.
- 5)
Af ter five minutes record the pressure for air receiver tanks A and B.
6)
Calculate the change in air receiver pressure in tank A and tank B from the
start of the test to the air pressure after five minutes, if the air pressure has
'
increased 15 psig or more, than the check valve on the discharge header for
tanks A and B had not sealed properly.
The inspectors had a concern with the above testing methodology. The air receiver
pressure would be maintained from 230 to 250 psig with the TS minimum air
pressure requirements being 230 psig. Therefore, if:
.
the air pressure in air receiver tanks C and' D during the start of the
surveillance test for the check valve for air receiver tanks A and B was the
minimum 230 psig, and
i
.the pressure in air receiver tanks A and B at the start of the test (Step 2)
was 225 psig,
the acceptance criteria'of less than 15 psig would be met even though the
discharge check valve for tanks A and B could be improperly sealed. The
inspectors consider OCOS 6600-02, Revision 9, not appropriate to ensure that the
check valves on the EDG air receiver tanks sealin the closed direction. This failure
to have an appropriate procedure is considered a Violation (50-254/265-97008-04)
of 10 CFR Part 50, Appendix B, Criterion V.
14
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4
Interim Procedure 97 0080, "DG Trip & Alarm Switches Cal., Protective Trip
'
'-
- .
- Bypass & Functional Test"
The inspectors reviewed drawing 4E-1350A, sheets 1 and 2, and Interim Procedure
97-0080 to determine if the testing methodology for ensuring that the protective
-
,
high crankcase pressure trip was bypassed on auto starts of the EDG, as required
by TS (4.9.A.8.g). The inspectors determined that the testing methodology
adequately verified that all the necessary contacts required to change state for
l
bypassing the high crankcase pressure trip were tested.
c.
Conclusions
The inspectors identified, through a sampling of EDG surveillance procedures,
several examples where the EDG surveillance program did not meet either the TS
'
'and/or the design basis documents. There was also one example where the test
'
methodology was not adequate to determine the sealing capability of a check valve
.
in the starting air system for the EDG
,
M8
Miscellaneous Maintenance issues (92902)
1
-
'
M8.1 (Closed) Licensee Event Reoort (LER) 50-254/97010: "B" Control Room Ventilation
System (CRVS) Inoperable Due to Freon Leak. On April 7,1997, the licensee
identified a Freon leak from B" CRVS and declared the system inoperable. The
licensee determined the failure occurred due to vibration-induced fatigue and
'
replaced the damaged pipe. The licensee planned to assess the compressor /
i
condenser skid for vibration. The inspectors reviewed the licensee's corrective
actions and consider this LER to be closed.
Ill. Enoineerinn
E2
Engineering Support of Facilities and Equipment
E2.1
Inadeauate Hiah Pressure Coolant Iniection System Procedure
The inspectors identified a problem concerning procedure QCOA 2300-04, HPCI
Auto Trip. The high pressure coolant injection (HPCl) system control circuitry was
designed to automatically start and engage the HPCI turning gear on a coast down
following a trip of the HPCI turbine. There was a design flaw in the tuming gear
engagement mechanism whereby an engagement failure could occur in the rare
occurrence of engagement gear abutment. According to the system engineer, the
vendor has acknowledged this problem and has developed a modification to fix the
problem. The licensee has not installed this modification in the HPCI system for
either unit. The licensee developed procedure OCOA 2300-08, Tuming Gear Failure
to Start on a Coast Down, Revision 4, dated November 4,1996, to ensure
engagement of the tuming gear. The procedure for " normal" HPCI shutdown under
routine test conditions, QCOP 2300-04, HPCI System Shutdown, directs operators
to use procedure OCOA 2300-08, should the turning gear fail to engage. However,
the inspectors found that procedure QCOA 2300-04, HPCI Auto Trip, Revision 6,
15
.=
.
dated April 10,1997, did not direct the operators to enter procedure
.
OCOA 2300-08. The failure of the tuming gear to engage upon HPCI shutdown
could result in damage to the HPCI turbine, rendering it unable to perform its design
function on a subsequent initiation during accident conditions. This inadequate
procedure was another example of a violation of 10 CFR Part 50, Appendix B,
Criterion V. The licensee's raponse to this deficiency was to revise
OCOA 2300-04, HPCI Auto Trip, and reference procedure OCOA 2300-08 in the
event of a failure of the HPCI turning gear to engage following an automatic trip.
The inspectors verified that procedure Revision 7, dated May 29,1997, was
issued. The licensee did not, however, require operator training on procedure
OCOA 2300-04, Revision 7. Following the inspectors's questions about operator
training, the licensee initiated training by placing the procedure change in the
required reading binder.
The inspectors were concerned that previous problems with the HPCI turning gear
engagement, particularly on Unit 2 (LERs 25497008,26595007, and
PlF 96-1642), posed a real failure mode of HPCI upon restart when needed during
an accident situation and that the procedure used under accident circumstances did
not providc adequate instructions to cope with potential problem. Additionally, the
f ailure to provide training to operators on this potent; ally safety significant issue
~
was a weakness in the procedure revision process which did not identify the
training as required.
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
li
A_pf cability
M3.1
8.3.1.6, 8.3.1.8
EDG,4 Kilovolt Station Voltages
E 2.1
7.8
Anticipated Transient Without
E8
Miscellaneous Engineering issues (92902)
E8.1
[ Closed) Licensee Event Reoort (50-265/95005): Automatic Scram During Electro-
hydraulic Control (EHC) System Testing. The recently installed steam line
resonance compensator (SLRC) circuit board time constant was set assuming a
standard steam line length provided by General Electric. The steam lines were
i
shorter at Quad Cities. The licensee recalibrated the SLRC, and the test was
satisfactorily performed. The same modification was performed on Unit 2 and
testing conducted in August 1996 during startup. Lessons learned from the Unit 1
transient prevented a similar event from occurring on Unit 2. This item is closed.
16
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E8.2 (Closed) Inspector Followun item (50-254:265/96004-07): Offgas Test Timor
Drawing Discrepancy. The inspectors noted that indicating lights for the timer were
not specified on the electrical schematic. The licensee confirmed that the lights
1
were originally installed in the plant but were not on the electrical drawings. A
50.59 screening concluded that no unreviewed safety question existed. The
inspectors confirmed that the drawings were updated to show the indicating lights.
This item is closed.
E8.3 (Closed) Violation 50-254:265/96017-02: Residual Heat Removal Service Water
Pump Bolt incorrect Strength, in October 1996 the licensee discovered the use of
inferior bolt materialin the 1C and 2C RHRSW pump casings while performing
maintenance on a spare RHRSW pump casing in the shop. The licensee declared
the affectbd pumps inoperable, changed the incorrect bolt material to meet design
requirements, and conducted an investigation to determine the root cause and any
other related conditions. The inspectors reviewed the licensee's immediate
corrective action and followup investigation and found them to be thorough and
adequate. This violation is closed.
E8.4 (Closed) Violation 50-254:265/96017-04: Failure to Make Required Report in
Accordance with 10 CFR 50.73. Subsequent to the licensee's discovery that the
1C and 2C RHRSW pumps were inoperable due to the use of incorrect bolt
material, between July 12,1996, and October 25,1996, Unit 2 was operated for a
period in excess of 30 days with the 2C RHRSW pump inoperable. The licensee
failed to report that Unit 2 had operated beyond the TS allowed 30-day time period
within the required reportability time. The licensee determined that the violation
resulted from failure to follow the normal process for dispositioning PIFs.
Subsequently, the licensee discussed the omission with the event screening
committee (ESC) emphasizing the importance of timely processing of PlFs and
improved tracking of open items. The licensee submitted LER 97-004 to document
the use of improper pump casing bolts and that the 2C RHRSW pump would have
performed its intended function. The inspectors reviewed the licensee's closure
activities and found them to be adequate. This violation is closed.
E8,5 (Closed) Licensee Event Reoort 50-254/97004: Residual Heat Removal Service
Water Pumps in a Degraded Condition Due to inadequate Evaluation of Replacement
Pump Casing Bolts. The licensee concluded that the affected residual heat removal
service water (RHRSW) pumps were not inoperable but degraded due to the use of
incorrect bolts in the low pressure pump casing. A bolt material having a lower
stress limit had been installed in two of the RHRSW pumps. The higher torque
value applying to the high strength material was used to install these bolts.
According to the licensee's data, the rnaximum torque limit for the installed (lower
strength) material was exceeded. However, the licensee's analysis of the removed
pump casing bolts provided conclusive evidence that bolt deformation had not
occurred and that the pumps would have performed their intended function in
accident conditions. The licensee promptly replaced the bolts in the affected
pumps upon discovery of the condition. There was also a typographical error in
section B of the LER,2nd paragraph, in which the 1C and 2C pumps were
incorrectly swapped in the text. This LER is closed.
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IV. Plant Sucoort
R1
Radiological Protection and Chemistry Controls
,
R 1,1
Revised Annual Dose Gdal
$
a.
Insnection Scone
The inspectors reviewed the licensee's data for accumulated radiation dose for the
Unit 2 refueling outage and discussed the revised 1997 annual dose estimate with
1
the station ALARA coordinator.
1
b.
_Qbservations and Findinas
~
y
The licensee revised the 1997 annual dose goal from 1260 rem to 720 rem. The
.
inspectors reviewed the licensee's data which separated the dose into five
categories - non-outage, refuel outage, contingency, emergent, and forced outage.
.
As of June 1 all five categories showed an underage when compared to the
estimate. The largest dose savings was in the area of, refuel outage. Dose savings
in the refuel outage were attributed to several factors including increased work
3
'
efficiency and good planning in the recirculation pump motor replacement and valve
work, and overall improved worker ALARA awareness. In some cases. however,
,
the dose savings was also attributed to the fact that estimates were based on
power operation of Unit 1 but the work was performed while the unit was shut
'
down, thereby reducing the dose rates in the work area.
.
4
The inspectors noted that the revision of the dose goal was based on detailed
'
tracking and trending and concluded that ALARA initiatives at the station were
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effective in reducing overall dose during the refueling outage.
'
.
}
c.
Conclusions
1
As low as reasonably achievable initiatives during the Unit 2 refuel outage helped to
,
reduce overall station dose to date. Radiation protection tracking and trending of
,
I
. dose was improved over previous refuel outages and allowed the mid-year revision
to the dose goal. The 1997 station dose goal was revised from 1260 rem to
720 rem,
.
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F8
M!scellaneous Fire Protection Issues (92904)
t
,
F8.1
(Closed) Licensee Event Reoort (50-265/93020): Continuous Fire Watch Missed for
t
the Hydrogen Seal Oil and Turbine Seal Oil Tank Deluge System. Fire protection
valves were disabled for greater than one hour and no compensatory fire watch
was established. Corrective actions included training and procedure changes. The
inspectors verified the actions were completed. This item is closed.
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F8.2 (Closed) Unresolved item (50-254:265/96011-03) and Licensee Event Reoort
50-254/96013: Zebra Mussel Fouling of Intake Structure. During the previous year
'
the licensee identified zebra mussel growth in the intake structure and documented
the condition on PIF 95-0915. The corrective actions for this PlF addressed
cleaning and repairing the intake screens, in August 1996 the licensee identified
both fire diesel pump suction strainers were fouled. Similarly, the walls of the
'
intake structure adjacent to the "B" diesel pump suction piping were about
100 percent covered with zebra mussel growth. The licensee inspected safety-
related pump suction piping and identified less than 20 percent coverage of the
interior piping. Zebra mussel growth was cleaned from component piping, strainers
and intake structure walls.
However, the licensee considered both fire pumps to be inoperable from May 6,
1996, when river water temperature increased to above 55 degrees F (the
temperature where zebra mussels are known to spawn). Both units were shut
down after May 10,1996. The inspectors considered the licensee's corrective
actions to monitor zebra mussel growth and its affects on fire pump operability to
be inadequate to detect the degraded condition of the fire protection system. The
inspectors consider this to be a Violation (50-254/265-97008-05) of 10 CFR Part 50, Appendix B, Criteria XVI, Corrective Action. This item is closed.
P8
Miscellaneous Emergency Preparedness issues
P8.1
(Closed) Licerisee Event Report 50-254/96007: Shut Down Of Unit 2 Due to High
Winds Damaging Secondary Containment. On May 10,1996, with Unit 2
operating at full power, high wind damaged secondary containment, the station
6
blackout diesel generator electrical cables, and other non-safety-related structures
and equipment. The licensee declared an alert and shut down Unit 2. Unit 1 was
already shut down for a refuel outage. The licensee repaired secondary
containment and other equipment important to operation prior to startup of the unit.
The inspectors reviewed the licensee's corrective actions and consider this item
closed.
V. Manaaement Meetinas
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management on
June 13,1997. The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the inspection
should be considered proprietary. No proprietary information was identified.
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PARTIAL LIST OF PERSONS CONTACTED
Licensee
E: Kraft, Site Vice President
D. Cook, Operations Manager
. F. Famulari, SOV Director
. J. Hutchinson, Site Engineering Manager
L. Pearce,- Plant Manager
C. Peterson, Regulatory Affairs Manager
R. Svaleson, Radiation / Chemistry Superintendent
M. Waylandi Maintenance Superintendent
.
INSPECTION PROCEDURES USED
IP 61726:
Surveillance Observations
IP 71707:
Plant Operations
IP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor
Facilities
IP 92902:
Followup - Engineering
IP 92904:
Followup - Plant Support
IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors
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ITEMS OPENED, CLOSED, AND DISCUSSED
,
Onened
'
50-254/265 97008-01
NCV both SBGT trains inoperable during testing
-
50-254/265-97008-02
IFl
EDG voltage acceptance criteria not in agreement with
design basis
50-254/265-97008-03
TS not in agreement with procedures
50-254/265-97008-04
failure to have appropriate procedures
50-254/265 97008-05
zebra mussel fouling of intake structure
Closed
50-254/93014
LER
intermediate range monitor 11 and average power
range monitor 3 both bypassed without % scram being
inserted
50-265/93020
LER
continuous fire watch missed for the hydrogen seal oil
and turbine seal oil tank deluge system
{
50-265/95005
LER
automatic scram during EHC system testing
50-254/96013
LER
zebra mussel fouling of intake structure
shut down of Unit 2 due to high winds damaging
I
i
50-254/265-97004
LER
RHRSW pumps in a degraded condition due to
inadequate evaluation of replacement pump casing bolts
50-265/97009
LER
both trains of SBGT inoperable due to fuse replacement
eriof
l
50-254/97010
LER
"B" CRVS inoperable due to Freon leak
50-254/265-96004-01 a
out of service errors render the % EDG inoperable and
result in an engineered safety features system actuation
50-254/265-96004-01 b
out of service errors render the % EDG inoperable and
result in an engineered safety features system actuation
50-254/265-96017-02
RHRSW. pump bolt incorrect strength
50-254/265-96017-04
failure to make required report in accordance with 10 CFR 50.73
'!
-265-94016-03
reactor vessel draining evolution
50-254/265-96011-03
zebra mussel fouling of intake structure
50-254/265-96004-07
IFl
offgas test timer drawing discrepancy
Discussed
None
21
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LIST OF ACRONYMS USED
As Low As Reasonably Achievable
r
Alternate Rod insertion
JATWS -
Anticipated Transient Without Scram
,
'CFR
Code of Federal Regulations
Comed
Commonwealth Edison Company
Control Rod Drive
~CRVS
' Control Room Ventilation System
DCO-
- Discrete Component Operations
Diesel Generator
Drywell Floor Drain. Sump
i
Emergency Notification System
J
HPCl ^
Event Screening Committee
High Pressure Coolant injection System
~
IDNS
Illinois Department of Nuclear Safety
j
IFI'
Inspector Followup Item
i
Initial Licensed Training
IM
Instrument Maintenance
-
inservice Test
kV
Kilovolt
LCO
Limiting Condition for Operation
LER
Licensee Event Report
LOR.
Licensed Operator Requalification
'
Local Power Range Monitor
MMD'
Mechanical Maintenance Department
Motor Operated Valve
NSO-
Nuclear Station Operator
PCI
Primary Containment isolation
Public Document Room
PlF
- Problem Identification Form
PMTV
Post Maintenance Test Verification
Pull-to Lock
QCCP
Ouad Cities Chemistry Prucedure
OCIPM
Quad Cities instrumern Prevent Maintenance
OCIS
Quad Cities Instrument Surveillance
OCOA
Quad Cities Abnormal Operating Procedure
OCOP
= Quad Cities Operating Procedure
OCOS
Quad Cities Operating Surveillance Procedure
OCTS
Quad Cities Technical Surveillance
OTS
Quad Cities Technical Surveillance
Reactor Core Isolation Cooling
Residual Heat Removal Service Water
22
,
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. .
'a
Standby Gas Treatmer.t
SLRC
Steam Line Resonance Compensator
Source Range Monitor
}
TS
Technical Specification
-
Updated Final Safety Analysis Report
Uninterruptible Power Supply
,
Unresolved item
Violation
Work Request
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