ML20135B522
| ML20135B522 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 02/20/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20135B500 | List: |
| References | |
| 50-254-96-20, 50-265-96-20, NUDOCS 9703030080 | |
| Download: ML20135B522 (30) | |
See also: IR 05000254/1996020
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c. U. S. NUCLEAR REGULATORY COMMISSION
REGION lli
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j Docket Nos: 50-254, 50-265
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Report No: 50-254/96020(DRP), 50-265/96020(DRP)
Licensee: Commonwealth Edison Company (Comed)
Facility: Quad Cities Nuclear Power Station, Units 1 and 2
Location: 22710 206th Avenue North i
Cordova, IL 61242
Dates: December 7,1996 - January 27,1997
Inspectors: C. Miller, Senior Resident inspector
K. Walton, Resident inspector
L. Collins, Resident inspector
R. Ganser, Illinois Department of Nuclear Safety
Approved by: Patrick L. Hiland, Chief
Reactor Projects Branch 1
9703030000 970220
PDR A90CK 05000254
G PDR
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c. EXECUTIVE SUMMARY
Ouad Cities Nuclear Power Station, Units 1 & 2
This inspection included aspects of licensee operations, surveillance, engineering,
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maintenance, and plant support. The report covers a 7-week period of resident inspec: ion.
Ooerations
, e Control room modifications were well planned and controlled (Section O2.1).
e Some decline in control room operator performance was noted. During the
inspection period, c,..erators mispositioned a control rod during control rod
exercising and misaligned one train of the standby gas treatment system rendering
it inoperable. These human performance errors were violations of station
. prccedures and Technical Specifications (TS) (Section 04.1).
e Management oversight was not adequate to ensure consistent quality operability l
evaluations for important systems (Section 07.1).
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Surveillance
e The inspectors identified that the control room emergency ventilation system was
not adequately tested in accordance with the TS surveillance requirement. This
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was a missed surveillance test and a TS violation (Section M1.1).
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e Poor planning resulted in an inadequate review of TS requirements prior to changing
surveillance procedures to accommodata a new shift rotation. Failure to adequately
perform the review resulted in a surveillance interval being exceeded .
(Section 03.1). l
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e The inspectors observed some operator knowledge and procedural weaknesses
j during performance of a control room emergency ventilation system surveillance
(Section M1.2).
. Maintenance
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e Efforts to improve maintenance and testing of standby liquid relief valves produced
some positive results. The licensee improved craftsman knowledge and skilllevel
and made efforts to provide input to the overall training process for mechanical
i maintenance. However, the inspectors observed limited supervisory oversight
during this work activity which was a repeat observation (Section M1.3).
e Material condition deficiencies continued to burden the station. Emergent work
- affected the planned work schedule and increased radiation dose for plant workers
- (Section M2.1).
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. Enoineerina
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- The inspectors identified weaknesses in the licensee's operability evaluation of the
shared emergency diesel generator (EDG) start failure and problems with the
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methodology for determining diesel generator reliability data (Section E1.1).
e The inspectors concluded that an initial operability assessment for the safe
shutdown makeup system was weak, because the assessment failed to verify the
ability to take manual actions (Section E1.2).
e Identification of a design discrepancies in the emergency core cooling system
(ECCS) suction strainers was good. Also, training provided to the operators on
, potential ECCS pump cavitation was timely and effective. The inspectors identified
4 potential problems with credit taken by the licensee for containment over pressure
, in the associated safety evaluation, since values used were not included in the
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licensing basis (Section E2.2).
! Plant Suooort
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- The inspectors identified the flow switch and pressure indicator for the service
water effluent radiation monitor did not have a scheduled calibration frequency
(Section R2.1).
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- Report Details
Summary of Plant Status
Unit 1 operated at or near full power during most of the inspection period. Minor
power reductions were conducted to perform routine activities such as turbine
weekly tests, control rod maneuvers, backwash of condensate demineralizers, and
scram time testing. A larger power reduction occurred in late December due to l
pump suction relief valve leakage on the 1C reactor feedwater pump. The valve
was repaired and the unit was retumed to full power the following day.
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Unit 2 operated at or near full power during most of the inspection period. The unit !
operated at about 660 MWe for several days late in the inspection period to repair a
leaking feedwater heater vent line.
I. Operations
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01 Conduct of Operations' !
01.1 General Comments (71707)
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Using Inspection Procedure 71707, the inspectors conducted frequent reviews of
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ongoing plant operations.
During the inspection period, several events occurred which required prompt
notification of the NRC pursuant to 10 CFR 50.72. The events and dates are listed
below.
December 13 A notification was made due to a control room
ventilation surveillance test not being performed
properly.
December 23 A notification was made regarding emergency core
cooling system (ECCS) suction strainers differential
pressure found to not be in accordance with design
requirements.
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' Topical headings such as o1, M8, etc., are used in acco dance with the NRC standardized reactor inspection
report outline. Individual reports are not expected to addiess all outline topics.
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- January 27 A notification was made that the emergency notification l
system (ENS) and commercial communications were lost due I
to a tripped circuit breaker.
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January 27 A notification was made regarding the identification of drywell
piping design inadequacies related to Generic Letter (GL) 96-06.
O2 Operational Status of Facilities and Equipment
O2.1 Control Room Modifications
a. Insoection Scooe (71707)
The inspectors reviewed the licensee's installation of a control room modification
designed to improve information display and readability for operators and
supervisors, and to provide other control room improvements,
b. Observations and Findinas
The inspectors reviewed plans for the installation, and noted that the licensee had
planned the change well. The modification was first installed in the simulator,
which allowed the operators to train on accident scenarios under the new
configuration. Improvements were made in the control room in three phases in
order to minimize disturbances. In one instance inspectors noted increased noise
levels resulting from the work during a surveillance activity. Shift management
stopped the work until the surveillance activities were complete. The inspectors
noted that under the new configuration, Quad Cities general abnormal procedures
(OGA) flowcharts for accident scenarios would be placed over the sequence of
event monitors. The inspectors discussed the apparent discrepancy with operations
supervisors and the licensee agreed to further evaluate the effect this would have
on operators in accident scenarios. In general, the inspectors noted that the
improvements were beneficial to the operators in terms of improved horizontal
workspace, procedure and drawing storage, information presentation, supervisor
oversight capability, and personnel traffic control.
c. Conclusions
The inspectors noted the control room modifications were an overell benefit to the
operators, and the installation of the modification was well planned and controlled.
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- 03 Operations Procedures and Documentation
03.1 Technical Soecification Surveillances Not Performed Within Reauired Time Period
a. Insoection Scope (71707)
The inspectors reviewed a licensee identified problem regarding Technical
Specification (TS) surveillance intervals being exceeded.
b. Observations and Findinas
The nuclear station operators (NSOs) and equipment operators (EOs) switched from l
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an 8-hour to a 12-hour shift rotation on January 6. Both the NSOs and EOs
performed surveillances that were required shiftly, which was defined by TS as
once every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Several days into the new rotation, the licensee noted a
potential problem with meeting the surveillance interval if operators did not perform i
the surveillances immediately after shift change. '
Since the surveillance procedures did not require the operators to document the
time the surveillance readings were taken, the licensee had difficulty establishing
whether or not the surveillance interval had been exceeded. A poll of operators on
shift during the four days in question found at least one situation where
approximately 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> between surveillances occurred. Based on this one
instance and the uncertainty surrounding the other days, the licensee planned to
submit a licensee event report (LER) documenting the failure to pcrform the
surveillances within the required time period.
After discovery, the licensee changed the governing procedures to require the
surveil;ances to be performed within the first three hours of the shift and to
document completion times.
The licensee determined that shiftly channel check surveillance requirements
required by TS 4.2 pertaining to reactor pressure and water level exceeded the
surveillance interval by more than the 25 percent extension allowed by TS 4.0.B. l
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The inspectors concluded that a violation of TSs occurred. However,, this licensee
identified and corrected violation is being treated as a Non-Cited Violation
(50 254/265-96020-01), consistent with Section Vll.B.1 of the Enforcement Policy.
c. Conclusions j
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The licensee failed to adequately perform a review of all TS requirements prior to i
changing to the new shift rotation and surveillance procedures.
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f. 04 Operator Knowledge and Performance
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i 04.1 Declinina Ooerator Performance
a. Insoection Scoce (71707)
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i The inspectors reviewed recent control room operator errors which resulted in one
i train of a safety system being made inoperable for approximately , hours and a
- control rod mispositioning event. The inspectors reviewed procedures and spoke
j with control room operators.
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l b. Observations and Findinas-
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l Upon initial entry into the control room approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after turnover, a
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Unit 2 NSO questioned why the annunciator " Standby Gas Treatment Trouble" was
lit. Subsequently, the control switch for the "B" train of standby gas treatment
was found in the "off" position. Since the train would not automatically start with
p the control switch in off, the train was inoperable, in addition, both units were in a
- 7-day limiting condition for operation (LCO) as required by TS 3.7.P.1. The control
, switch was retumed to its " primary" position, restoring operability, and an 1
j investigation was initiated.
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i One month later, during control rod exercising in accordance with Quad Cities
j- Operating Surveillance (OCOS) 0300-01, "CRD [ control rod drivel Exercise," a NSO
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inadvertently used the " rod out notch override" switch instead of the " single notch
l withdraw" button. As a result, the control rod being tested was withdrawn one
- notch further than anticipated. Subsequently, the rod was inserted to the correct
! position and a problem identification form (PlF) was initiated to document the error i
{ and the licensee's investigation.
! The inspectors reviewed the licensee's investigation into the two events and
j identified three examples of failure to properly implement station procedures:
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I (1) On December 16,1997, the standby gas treatment (SBGT) system Train B
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control switch was put in the off position at 2139 during the performance of OCOP
7500-2, " Standby Gas Treatment System Shutdown." An NSO failed to perform ;
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steps G.3.A.6 and G.3.A.7 of OCOP 7500-2, which would have placed the Train B l
{ control switch to " primary" and failed to verify that all the SBGT system
- annunciators were cleared. This is an example of a Violation (50-254/265 96020-
) 02a).
' (2) On December 16,1996, the Unit 2 reactor building ventilation isolation
function was being tested, and the Unit 2 operators were performing QCOP
! 7500-2. However, Unit 1 operators were generally assigned responsibility for the .
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common panels which included the reactor building ventilation system and SBGT
system controls. Operating Department Memo 96-2 directed the Unit 1 NSO to
j walk down the common panels once per hour. Since the condition of the SBGT
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_ system was not discovered for approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, these required checks were i
not adequately performed.
Additionally, this condition existed through shift turnover. The oncoming shift of
NSOs were required to walk down the control room panels in accordance with i
Quad Cities Administrative Procedure (OCAP) 0210-4, " Shift Turnover Panel Check
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for Common Panels," Section D.3.d. The procedural requirement was checked
complete by the Unit 1 oncoming NSO indicating that SBGT Train B was in
" primary" and Train A was in " standby"; however, Train B was actually in the "off"
position. The oncoming Unit 1 operators logged the annunciator as being lit in the
Unit 1 log book, but did not understand the cause of the alarm or recognize that the
train was inoperable. This is another example of a Violation (50-254/265-96020-
02b).
(3) On January 18,1997, the NSO performing CRD exercising failed to properly
implement step 4 of QCOS 0300-1, when the " rod out notch override" switch was
used instead of the " single notch withdraw" button while exercising a control rod.
Step 4 of OCOS 0300-1 required when exercising control rods that were not fully
withdrawn, i.e., position 48, that the operator use the " single notch withdraw"
. button instead of the " rod out notch override" switch. The control rod was to be
inserted to position 24 and withdrawn back to position 26, but instead was
withdrawn to position 28. This is another example of a Violation (50-254/265-
96020-02c).
The licensee considered the causes of these events to be poor procedure
adherence, lack of a questioning attitude, and insufficient degree of attention
applied. Corrective actions included counseling the individuals involved and a
review with all operating crews of operating standards and expectations.
The lack of attention to detail appeared to be more than an isolated case since three
separate operators responsible for checking the status of the SBGT system failed to
note the inoperable Train B. Additionally, corrective actions for the event were not
sufficient to prevent a similar operator error (involving one of the same individua!s)
approximately 1 month later when the control rod was mispositioned.
The operations department performance trending program identified an increased
human error rate for control room operators during the month of December. A PIF
was initiated to further investigate the declining performance trend.
c. Conclusions
This series of operator errors indicated a lack of attention to plant configuration.
The inspectors noted that control room operator performance was relatively good
over the past year, but these events marked a declining trend in the area of control .
room operator performance.
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07 Quality Assurance in Operations
07.1 Problematic Onerability Evaluations
a. Insoection Scoce (71707)
The inspectors reviewed several issues which involved operability evaluations for
degraded equipment or which involved return to service of equipment which had
been in a TS limiting condition for operation (LCO) for degraded conditions.
b. Observations and Findinos
The inspectors' review indicated that, in some cases, operations and station
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management were not ensuring quality root cause evaluations and compensatory
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actions were being performed prior to declaring equipment operable. Three
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examples are discussed below:
(1) in one instance documented in Section E1 of this report, the shared emergency
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diesel generator (EDG) was declared operable before a complete root cause analysis
(all possible failures) had been reviewed, before root cause and corrective actinn for
the suspected component failures had been identified and implemented, before a
schedule had been established for analysis of the suspected component failure to
ensure the accuracy of the initial root cause effort, or before the need for increased
testing frequency or component change-out requirements had been established.
The inspectors noted the need for a hurried effort and limited review could have
been a factor since the EDG was in a 7-day LCO which would have required both
units to shut down. However, since the shared EDG was the component with the
single largest effect on core damage frequency, and diesel generator failures had
been problematic in the past, the inspectors considered the lack of station
management and operations management oversight of the shared EDG operability
call a weakness.
(2) In another instance documented in Section E1.2 of this report, operations
management considered degraded safe shutdown makeup system valves operable
because the valves could be manually operated. However, when the inspectors
questioned the ability of the operators to operate the valves under design accident
conditions, the licensee identified that additional equipment would be required to
provide a mechanical advantage.
(3) In a third instance, operator action to secure service building ventilation was
credited in order to consider control room ventilation operable under certain
accident conditions. As documented in Section M1.2 of this report, the inspectors
identified that operators were not trained on how to secure service building .
ventilation and were unable to perform the task without further guidance during a
surveillance test.
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- c. Conclusions
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The inspectors concluded that management oversight was not always adequate to
ensure consistent quality operability evaluations were being performed and -
validated for key systems.
08 Miscellaneous Operations issues
08.1 (Closed) Violation (50-254/265-95004-01): Control Rod Hydraulic Control Unit
(HCU) Returned to Service After Maintenance Without Being Tested. Operations
allowed maintenance workers to adjust valve packing on an HCU without scram
time testing the HCU after work was completed. The licensee subsequently scram
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time tested the control rod successfully. The licensee discussed this event with
operations and maintenance personnel and revised two work control administrative
procedures to ensure post-maintenance test requirements were reviewed by
operations personnel. The inspectors reviewed the licensee's corrective actions.
This item is closed.
08.2 (Closed) LER (50-254/95004): Unit 1 High Pressure Coolant injection (HPCI) Failed
to Operate. Subsequent troubleshooting revealed the motor speed changer (MSC)
gear train failed. The licensee determined an improper setting of a contact block
resulted in excessive plunger travel required to actuate the switch contacts. The
licensee replaced the limit switch and MSC gear train and later tested the system
satisfactorily. The licensee changed the vendor manual to reflect recommendations
for installation and adjustment of the limit switches. The licensee continued to test
the HPCI systems at an increased frequency in an attempt to identify problems
sooner and improve HPCI performance. This item is closed.
11. Maintenance
M1 Conduct of Maintenance
M1.1 Imoroner Testina of Control Room Emeraency Ventilation System (CREVS)
a. Insoection Scoce (62703)
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The inspectors reviewed station surveillance procedures to ensure Section 4.8.D of
the TS requirements was incorporated. The inspector spoke to engineering
personnel about deficiencies identified and reviewed electrical prints associated
with CREVS. The inspectors also reviewed Section 6.4 of the updated final safety
analysis report (UFSAR).
b. Observations and Findinas s.-
As a result of the inspectors' questions, a system engineer identified that the
surveillance test did not properly test the automatic isolation function of CREVS as j
required by TS 4.8.D.5.b.2. Specifically, OCOS 1600-13, " Refueling Outage PCI i
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Groups 2 and 3 Isolation Test," verified the operation of control room annunciator
B-8, " Control Room Vent isolated." However, the annunciator was energized from
a relay different from the relays which closed the control room ventilation dampers.
The licensee declared the system inoperable, notified the NRC, and documented
this concern on PlF 96-3499.
Engineering successfully tested the proper relays in accordance with an interim
procedure and the system was later declared operable. The licensee planned to
incorporate the interim procedure into OCOS 1600-13. Also, the licensee planned
to review portions of the recently upgraded TSs to ensure testing adequately
addressed TS requirements.
Failure to properly test the automatic isolation function of CREVS is a Violation (50- .
254/265-96020-03) of TS 4.8.D.5.b.2.
c. Conclusions
This problem, and another example documented in Inspection Report
50-254/265-96017 were identified by NRC inspectors. As a result of problems
recently identified with the design and testing of CREVS, several opportunities were
available to the licensee to self-identify these discrepancies.
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M1.2 Surveillance Observations
a. Insoection Scone (62703)
The inspectors observed portions of the following surveillance tests:
OCOS 5750-2 Control Room Emergency Filtration System Test
OCOS 1300-1 Reactor Core Isolation Cooling (RCIC) Pump Operability Test
OCOS 2300-5 Quarterly High Pressure Coolant injection (HPCI) Pump
Operability Test
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The inspectors attended pre-job briefings, accompanied operators during the
surveillances, and reviewed the TSs and UFSAR system descriptions.
b. Observations and Findinos
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i. CREVS Ooerability Test (OCOS 5750-2) '
The inspectors attended the briefing for the monthly CREVS surveillance and
noted that neither the NSO or the EO involved with the test were familiar
with newly added procedure steps to secure service building ventilation.
The inspectors were concerned that the new requirement to secure service -
building ventilation, which was not only required during the surveillance, but
also during a loss of cooling accident (LOCA), had not been communicated
to the operators. Securing service building ventilation was an important step
to ensure that control room positive pressure was maintained and to
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j minimize in-leakage to the control room emergency zone during an accident.
Failure to perform these actions in a timely manner during an accident could
{ increase the dose to operators.
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5 The NSO involved in the test activity questioned the unit supervisor and shift
) engineer about the new procedural requirement. (The unit supervisor and
j shift supervisor were aware of the new steps and of some existing guidance
- on how to complete the step.) The procedure was in the revision process to
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add specific instructions to secure service building ventilation. Prior to
actual test performance, the operators made a procedure field change (PFC)
- to the affected procedure to add the detailed steps for securing service
j building ventilation.
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j As noted above, the surveillance procedure was in the revision process at-
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the time the surveillance was scheduled to be performed. At the end of the
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inspection period, the procedure had been revised, but all the operators had
- not yet been trained on the new requirements.
The CREV system included a refrigeration condensing unit (RCU) which
, provided cooling to the entire control room emergency zone and operated
j based on control room return air temperature. The RCU itself could be
i cooled b) either plant service water (non-safety related) or " safety related"
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residual heat removal service water (RHRSW). The UFSAR stated that plant
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service water was the normal supply and that on loss of plant service water
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the condenser could be cooled by RHRSW. The inspectors noted that for
}. the design basis LOCA analysis, offsite power was assumed to be ,
unavailable; therefore, plant service water would be unavailable. The i
i surveillance procedure called for flushing the RCU with RHRSW but provided
- the option to either run the test with RHRSW or plant service water.
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I During the observed surveillance, operators chose to run the test with plant
j service water and indicated to the inspectors that the test was normally run
that way. The inspectors asked the cognizant system engineer if the
{. surveillance test was ever run with the equipment cooled by RHRSW. The
- test had been operated with RHRSW three times in the last 2 years, with the
longest interval between runs of 14 months. Technical Specification
i 4.8.D.1 required operators to verify once every 18 months that the RCU
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was capable of removing the required heat load. Test procedure OCOS j
5750-2 was inadequate in that it allowed the test performers to select at l
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random which service water system to use. Failure to incorporate adequate
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guidance into the test procedure is another example of Violation 50-
3 254/265-96017-06, of 10 CFR Part 50, Appendix B, Criterion XI, " Test
, ' Control." That violation was recently issued in Inspection Report 50-
254:265-96017, dated February 4,1997. At the close of this inspection ,.-
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j period, the licensee had not yet responded to the initial violation and was
- revising applicable test procedures to ensure that the RCU was tested every
j 18 months with both RHRSW and plant service water. The inspectors will
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l *,. review the licensee's response to the initial violation and no additional :
- information regarding this example is required.
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ii Unit 2 RCIC Pumo Operability Test (OCOS 1300-1) -
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During the perfwhance of OCOS 1300-1, the inspectors observed that the l
equipment operator (EO) was knowledgeable and provided good on-the-job i
training to two trainees. In addition, the inspectors noted that the radiation j
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protection briefing and coverage during the potentially high dose job to be :
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thorough and effective with respect to the ALARA [as low as reasonably
- achievable] program. )
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3 The inspectors noted that both Unit 1 and Unit 2 RCIC rooms had .
scaffolding that had been in place for several months. The system engineer
- indicated the scaffolding had been erected to support valve operation test
- and evaluation system (VOTES) testing of valves. However, the testing had
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not occurred and was not scheduled. The system engineer told the
inspectors that the scaffolding was built to seismic standards and was.
j perbdically checked. The inspectors did not find any deficiencies with the
i scaffolds, but noted that it was a housekeeping issue that could hinder
operator performance.
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)j iii , Unit 1 HPCI Operability Test (OCOS 2300-5)
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l The inspectors attended the shift briefing and observed the performance of
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the test from the control room. The test had been scheduled for the
afternoon shift and coincided with ongoing control room modification work.
l The inspectors noted that the control room was crowded and noisy due to
. the modification work. The shift' engineer cleared the control room of all
construction personnel throughout the duration of the HPCI surveillance.
- . The inspectors considered this action appropriate since the HPCI surveillance
! required full operator attention and communication and the construction
j work could have been distracting.
Operator performance during the surveillance was good. Communications
were clear and the operators demonstrated good knowledge of the HPCI
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system and the surveillance procedure. All TS requirements were met.
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c. Conclusions
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l The inspectors noted some knowledge and procedural we'aknesses during the
- performance of the CREV system surveillance. Operator knowledge of the new
{ requirement to shut down service building ventilation during CREV system operation
t was weak due to the failure of the operations department to promptly update the . :
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procedure and train the operators on the current system status. Operators l
j - performance with respect to procedure adherence and communications during the
j surveillances observed was good. i
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The inspectors concluded that the CREV system surveillance procedure did not
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adequately control the testing configuration of the RCU to ensure that the system
would always be tested in accordance with TS 4.8.D.1. Failure to provide
adequate test instructions, was another example of an earlier violation of 10 CFR
50, Appendix B, Criterion XI, " Test Control."
M1.3 Observation of Standby Licuid Control System Relief Valve Rebuild
l a. Insoection Scoce (62703)
The inspectors observed mechanical maintenance department (MMD) personnel
overhaul and bench test the standby liquid control (SBLC) system relief valves. The
inspectors also interviewed the SBLC system engineer to assess overall system
performance,
b. Observations and Findinas
The licensee planned to remove and bench test the SBLC relief valves at each refuel
. outage. The relief valves had historically experienced inconsistent lift-set pressure
, test results. The inconsistencies were thought to have been caused by the lack of
precise test controls and weak work practices during valve overhaul. The licensee's
response was to change the method of overhaul and testing for these valves. The
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i licensee brought a vendor representative onsite who gave instructions to coach and
assist MMD craftsmen on the correct overhaul and bench testing techniques. The
vendor provided input to upgrade the station procedures and current technical
information for MMD training.
The licensee had previously identified that the station procedure for this task was
obsolete and no longer met the station standards. The vendor provided a current
work instruction and expertise to guide the work activity.
The inspectors noted that MMD supervisors monitored the work activity
infrequently. Numerous work activities in progress limited the supervisor's ability to
> devote time and attention to any single job. This weakness did not manifest itself
< in any identifiable problems with this particular work activity. However, as
documented in Inspection Report 50-254;265-96014, dated December 20,1996,
Section M1.1.b.ii, the lack of supervisory oversight was previously observed for
maintenance on important equipment.
The inspectors observed lift-set pressure testing on one of the valves, and verified
the calibration of the tect gauge was current. The test procedure required two
consecutive tests within specifications. The consistency of the successive tests
was good. Of the six SBLC system relief valves designated for overhaul and lift-set
testing, two of the valves were rejected. On one valve, the bonnet could not be
machined sufficiently to house the larger spring assembly which was to be installed
in all of the rebuilt valves. This valve, and one other exhibited problems with
insufficient clearance between the disc assembly and the internal orifice. The
licensee generated a PIF to address the cause of the wrong clearances. Spare parts
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for the remaining valves were correct. Four valves were successfully overhauled,
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lift-set pressure tested and placed into storage for future installation. The MMD
. developed a tracking method to keep accurate updated maintenance records of 4
each valve.
c. Conclusions
4
The licensee's effort to improve maintenance and testing of SBLC relief valves .
produced positive results as evidenced by consistent test results. The licensee !
, improved craftsman knowledge and skilllevel for this job and made efforts to
provide input to the overall training process for mechanical maintenance. However,
limited supervisor oversight was an observed weakness, which was a repeat
observation.
M2 Maintenance and Material Condition of Facilities and Equipment
i M2.1 Continued Hiah Number of Material Condition Deficiencies
a. Insoection Scoce (40500)
The inspectors reviewed some of the material condition issues which affected
j station performance. l
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b. Observations and Findinos
- The shared (1/2) EDG experienced a failure to stop and a failure to start.
- The stop failure was attributed to a failed governor solenoid and the failure i
to start was an air start motor problem. Both failed components were repeat
problems with the EDG system (Section E1.1).
i
- The safe shutdown makeup (SSM) motor-operated valves were found to
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have undersized motors (Section E1.2).
- The 1 A reactor feed pump (RFP) was out of service for the entire inspection ,
period awaiting rotating element and seal replacement.
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- The 2C RFP was returned to service following seal replacement.
- The 2A control rod drive (CRD) pump developed a sealleak. Tne pump
remained in service for limited use only.
- The 2A and 1B containment atmospheric monitoring (CAM) systems were
inoperable at different times which required entry into 30-day shutdown
LCOs. The 18 CAM system remained out-of-service (OOS) at the end of the
inspection period.
- The 2B stator water cooling pump failed to produce the required flow during
testing and was determined to have high motor vibes. The low flow
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1 condition was later attributed to a discharge check valve problem, and
additional operator action was required to use the 2B pump.
- Unit 1 reactor water cleanup (RWCU) system problems, including
demineralizer bypass valve leakage and 1 A RWCU pump problems resulted in ,
RWCU system being shut down for several days. Reactor water chlorides l
increased to an administrative limit for action but did not reach any TS 1
limits. I
e The 1B RHRSW pump developed an outboard sealleak. The pump was
scheduled for repair in February 1997.
e Hydrogen pumps supplying both units tripped off several times. On several
occasions hydrogen addition to the reactor was reduced to conserve the
hydrogen supply.
e The 1 A .urbine building closed cooling water heat exchanger was inspected
and found to be severely degraded. At the end of the inspection period,
tube replacement was in progress.
e Unit 2 dropped load due to 2C1 feedwater heater operating vent line leak. A
section of piping was replaced.
c. Conclusions
The inspectors noted that a high number of material condition deficiencies
continued to burden the station. Emergent work adversely affected the
maintenance schedule and contributed to increased dose for plant workers.
M8 Miscellaneous Maintenance issues
M8.1 (Closed) LER (50-265-95001 and Rev.11: Valve Seat Leakage Exceeded Local
Leak Rate Test (LLRT) Limits. During the Unit 2 refueling outage, the licensee
identified nine valves which had exceeded their LLRT leak rate limits. The licensee
machined the interior of two leaky outboard main steam isolation valves and !
replaced the seat liner. The remaining valves were repaired or replaced and
retested satisfactorily. The inspectors reviewed the post-maintenance LLRT results.
This item is closed.
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M8.2 (Closed) Violation (50-254/265-95005-01): Maintenance Personnel Failed to :
Adhere to Procedural Requirements. Workers, attempting to remove a CRD, failed I
to lock the carriage and winch cart together. This resulted in the control rod drive
and the cart being damaged. Workers failed to complete a work activity screening
sheet prior to working on the Unit 2 HPCI system as required by the procedure. .
Maintenance personnel were instructed on the use of work activity screening
sheets when working on nuclear safety related equipment. Maintenance personnel
were also briefed on department training requirements to ensure personnel
possessed the knowledge and skill required to perform as signed tasks. The licensee
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changed CRD handling procedures and trained maintenance personnel on CRD
handling equipment. The inspectors attended a hands-on training session and
viewed a subsequent CRD installation. This item is closed.
M8.3 (Closed) Insoector Follow-uo item (50-254/265-95009-01): Shared EDG Failed to
Start Due to Failed Relay. The shared EDG started and ran for about 15 seconds
during a surveillance test before stopping. Monitoring equipment identified a failed
Time Delay (TD)-1 relay. Subsequent analysis of the failed relay determined the
relay had a manufacturing defect which was not detected during bench testing prior
to installation. The licensee revised Quad Cities Electrical Preventive Maintenance
(OCEPM) procedure 0700-18, " Calibration of Diesel Generator Time Delay Relays,"
to check TD relays for full needle travel prior to installation into the circuits. The
licensee sent a notification to owners of this style of EDG to make those owners
aware of the relay failure. The inspectors reviewed the licensees corrective actions.
This item is closed.
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111. Enaineerina
E1 Conduct of Engineering
E1.1 Problems With Shared EDG
a. Insoection Scone (71707)
The inspectors spoke to licensee personnel and observed maintenance activities
associated with the shared emergency diesel generator. The inspectors reviewed
the licensee's root cause evaluations and subsequent corrective actions.
I
b. Observations and Findinas
b.1 Shared EDG Failed to Stoo
.
Operations declared the shared EDG inoperable after the EDG failed to stop
- at the conclusion of routine testing. An engineering investigative team
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developed a plan to determine the causes for the EDG not stopping on
command. The team produced a root cause evaluation, that determined
three likely causes for the failure to shut down. Engineering determined the
most probable cause was a binding shutdown solenoid in the govemor and ,
replaced the solenoid. During the subsequent operability test, the shared l
EDG failed to start.
b.2 Poor Root Cause Followuo for the Shared Emeraency Diesel Generator l
Failure to Starl . I
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After repairing the shutdown solenoid, the shared EDG failed to start during
a post-maintenance operability test. Engineering reassembled the
investigative team and started a second root cause analysis. Engineering
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1 deduced that a component in the air start system caused the failure to start,
based on system engineer observations of the diesel during the attempted
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start and further component inspection and testing. Maintenance tested and
inspected components in the air start system. The licensee identified one of
the two air start motors was difficult to turn by hand, replaced both air start
motors, and intended to send the faulted air start motor out for further
analysis. The licensee also inspected air start motors for both unit EDGs and
found the motors turned satisfactorily.
In the interim, engineering determined that the problem was corrected, and
operations declared the EDG operable on January 18. However, the
inspectors identified that the air start motors still had not been sent for
analysis by January 22 and questioned plant management about the
confidence of the operability call since the primary component believed to be
at fault had not yet been evaluated. In addition, other potential failure
modes for the conditions noted had not been evaluated. The inspectors
noted for both EDG failures, the licensee had identified a "likely" component
failure and replaced it, but had not identified the root cause for the failures
of the components. The inspector's review of records back to 1992
revealed that the shutdown solenoid or the air start motors had been the
cause of EDG failures on at least five occasions. Yet, the licensee's
followup actions for these events did not reference a plan to correct the root
cause or address component replacement frequency or increased surveillance
frequency.
The licensee referenced a proposed modification to replace the governor
shutdown solenoids, but could not specify an implementation date when
asked by the inspectors. The licensee agreed that a higher priority should
have been placed on air start motor testing and sent the motors off site for
evaluation on January 22. Engineers also documented further reasoning to
support the validity of the initial operability call.
b.3 Poor Comoonent Trendina
The inspectors noted that the system engineers did not classify the failure of
the shared EDG to start as a valid test failure. The reason given was that
during the surveillance test, one half of the starting air tanks were valved
out to satisfy in-service testing requirements. Since the EDG started on the
second try fifteen minutes later (and so theoretically would have started with
both air banks valved in on the second try), the engineers concluded that the
start should not be counted as a " valid" test failure. The inspectors noted
that this action could precondition the EDG for the purposes of reliability
testing, since the air start, governor, and fuel systems had been exercised
on the first start attempt. Licensee engineers informed the inspectors that
the station followed, but was not committed to the requirements of
Regulatory Guide (RG) 1.9, Revision 3, " SELECTION, DESIGN,
QUALIFICATION AND TESTING OF EMERGENCY DIESEL GENERATOR
UNITS USED AS CLASS 1E ONSITE ELECTRIC POWER SYSTEMS AT
NUCLEAR POWER PLANTS," for determining reliability of the EDG.
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1 The inspectors determined that the licensees's conclusion that the failed
EDG start was not a " valid failure" was inconsistent with the guidance
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contained in RG 1.9 in three areas.
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1) Section 2.1 under " start failure definitions" stated: "Any condition identified
in the course of maintenance inspections (with the emergency diesel
generator in the standby mode) that would have definitely resulted in a start
failure if a demand had occurred should be counted as a valid start failure."
The failure mode identified by the licensee during maintenance
troubleshooting did result in a start failure.
2) Section 2.1 under " exceptions" stated: " Unsuccessful attempts to start or
load-run should not be counted as valid demands of failures when they can
be definitely attributed to the following: ... A failure to start because a
portion of the starting system was disabled for test purposes if followed by
a successful start with the starting system."
System engineers referred to this as the reason the start failure was not
,
valid. However, the inspectors noted that the licensee's investigation
pointed out that the alignment of the air start system with only one set of air
banks was not the reason for the failure to start since air pressure in the
tanks did not go below normal required pressure.
- 3) Section 2.1 also stated
- "the successful test that is performed to declare
the emergency diesel generator operable should be counted as a demand."
The inspectors noted that the test which identified the EDG would not start
was performed for such purposes. The test was a valid demand, the failure
,
mode was no'. due to the test configuration, and the failure mode resulted in
a failure to m: . Therefore, the inspectors concluded that the licensee was
not following tne intent of RG 1.9.
In general, the licensee was counting surveillance testing of the EDGs as valid start
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successes if the surveillance passed, but not as valid start failures if the
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surveillance did not pass on the first try. This did not a,apear to be a valid
statistical approach to determine EDG reliability. The inspectors noted that
information on EDG reliability was provided to the NRC in past meetings (e.g.,
management meeting in Rill 12/11/95) as a basis for safety system reliability.
Resolution of the reliability testing and start failure root cause and corrective action
is an inspector Followup Item (50-254/265-96020-04), pending the inspectors
review of the licensee's assessment of this issue.
c. Conclusions .
The inspectors determined the licensee's root cause evaluation approach for the
problems with the shared EDG had improved somewhat from similar EDG root
cause efforts in 1995, but still did not sve at resolution of root cause and
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1 ' effective followup action in a time commensurate with the safety significance of
the system. In addition, the inspectors identified that reliability testing statistics for
the EDGs might be flawed and did not appear to be in accordance with RG 1.9.
E1.2 Weak Operability Evaluation for the Denraded Safe Shutdown Makeuo (SSM)
System Valves
a. insoection Scope (71707)
The inspectors reviewed the operability assessment, corrective action documents,
and caution cards for the SSM system. The inspectors also spoke'with the system
engineer, operators, valve engineers and the shift operations supervisor about the
system operation.
b. Observations and Findinas
While conducting a plant tour, the inspectors noted that caution cards attached to
SSM valve control switches stated that the valve motor operators were undersized,
and that the valves might not close under all conMons. The SSM system provided
water from a storage tank to the reactor during censin Appendix R fire scenarios if
the feedwater and RCIC systems were unavailable. The motor driven pump injected
water to either the Unit 1 or Unit 2 reactor. Although the system was not credited
in any accident analyses described in Chapter 15 of the UFSAR, it was included in
the station's individual plant examination and was an important system in terms of
overall risk.
The inspectors reviewed the licensee's corrective action document and spake with
the cognizant system engineer. The licensee identified that the original valve data
usod for motor sizing was incorrect and undersized motors were installed for three
SSM valves. A recent calculation showed a required torque of 106 ft-lbs [ foot-
pounds) to close the valves under design condition, while the motor operators were
sized to produce 42 ft-lbs. The affected valves were the two SS*' discharge valves
(one to each unit) and the SSM recirculation valve. System opc.ating procedures
required the recirculation valve to initially be opened and closed after the injection
valve to the proper unit was opened.
The operability evaluation determined that the system was operable but degraded.
The evaluation took credit for local, manual operation of the valves. As
compensatory measures, the licensee placed caution cards on the controls,
submitted a procedure change request to include the caution in the procedures, and
verified the ability to cycle the valves under static conditions. Engineering
- performed a safety evaluation screening and planned to evaluate long term
corrective actions.
The inspectors questioned the validity of the static test for manually operating the
valves, since the torque required under static conditions was different from that
required under the design basis fire scenario. Subsequently, the licensee simulated
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!' a test and identified that the valves would be difficult to close without an additional
' mechanical advantage. Valve wrenches were then staged in the SSM room.
The operability evaluation did not consider the time constraints on operators during
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fire to place the SSM system in service. The Quad Cities Appendix R analysis ,
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j concluded *. hat the SSM system must be injecting into the reactor within 35
l minutes after reactor shutdown. The procedures specified local operation but were
quite complex, and the inspectors questioned whether there was sufficient time to
obtain a valve wrench to manually close the recirculation valve. The inspectors
noted that in the current condition with the valve wrenches staged locally, the time
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l to initiate the system had not increased relative to the initiation time with fully
qualified ve.lve operators.
The inspectors noted that this SSM problem was added to the operator work l
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around list. However, the inspectors identified that a lead unit planner, responsible
fer prioritizing and planing work, was not aware of the most recent problem with l
l the SSM. In addition, no action request (AR) or engineering request (ER) was
! written to resolve the degraded condition. ;
l
The operability assessment process required corrective actions be tracked by the l
l station's nuclear tracking system (NTS). The licensee issued an NTS item to
l develop a long term corrective action plan by March 1,1997. In addition, the
licensee performed a 50.59 screening evaluation since the system was to remain in
a degraded condition for an extended period of time.
Several weeks after the inspector initially questioned the licensee about the
l degraded condition of the valves, an operating crew wrote ARs for the three valves. )
l The work planning group prioritized the work as emergent work to be worked
within 5 weeks. The inspectors noted that the AR process had been bypassed and ,
that the degraded equipment was not tracked in either engineering or maintenance ;
backlogs. The licensee planned to review the various processes for initiating ARs, l
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ERs, and the general PIF procedure to improve the process. Pending the inspectors'
l review of the licensee's assessment of needed improvements in this area, this is an
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l Inspector Followup Item (50-254/265-96020-05).
c. Conclusions
l
The licensee's approach to the condition of the valves was not consistent with the
l importance of the system. Poor assumptions in the initial operability assessment,
l and failure to appropriately apply the proper administrative procedures to resolve
known deficiencies showed a lack of sensitivity to significant operator ;
workarounds. !
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j . E2 Engineering Support of Facilities and Equipment
E2.1 Facility Adherence to the UFSAR
l
I 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 die UFSAR:
IR Section UFSAR Section Acolicability
E2.2 6.2 and 6.3 ECCS Suction Strainer Design
R2.1 11.5.2.7 Process Liquid Radiation Monitors
E1.2 5.4.6.5 SSM System
M1.2 6.4 CREV System
! E2.2 Desian Discrecancy with Emeraency Core Coolina System (ECCS) Suction Strainers
a. insoection Scoce (92700)
The inspectors attended plant onsite review committee meetings and spoke with
design engineering personnel and operators concerning ECCS suction strainers. The
inspectors reviewed the licensee's operability evaluation,10 CFR 50.59 safety
l evaluation, supporting calculations, and Sections 6.2 and 6.3 of the UFSAR.
b. Observations and Findinas
Licensee's Evaluations
On December 20 a contract engineering firm, reviewing an upcoming modification
to replace the ECCS suction strainers, identified that the ECCS suction strainers
were not built in accordance with design as described in the UFSAR. Specifically,
l the UFSAR assumed a maximum of 1-foot differential pressure (d/p) across the
,
strainer at 10,000 gallons per minute (gpm) (rated) flow. However, the analytical
model of the installed suction strainer had a 5.8 foot d/p at rated flow. The higher
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d/p could affect the net positive suction head (NPSH) of ECCS equipment in post-
accident conditions.
Section 6.2.2.3 of the UFSAR assumed one of the four suction strainers would be
fully plugged during a large break loss of coolant accident (LOCA). During the
LOCA, all low pressure injection pumps (about 30,000 gpm injection) would draw
suction through the remaining three strainers. The difference in the head loss of
l the installed versus designed strainer was documented on PlF 96-3571.
I
Engineering performed short term and long term calculations to determine the NPSH
required for post-accident operation of various combinations of core spray (CS) and
residual heat removal (RHR) pumps. The licensee took credit for post-accident
primary containment over pressure in the calculations. The use of over pressure
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5 was described in UFSAR, Section 6.3.3.2.9, and in an NRC safety evaluation report
(SER) dated August 25,1971.
I The short term calculation used 5.5-pounds per square inch gauge (psig) over l
pressure and concluded there would be adequate NPSH for CS and RHR pumps I
operating at full flew for the first 8 minutes post-accident. After 8 minutes, when l
primary containment pressure started decreasing, the margin to pump cavitation J
l
would be decreased. The CS pumps were more vulnerable to cavitation. However, i
the licensee believed the design flow rate of 4500-gpm would still be met with the
CS pumps cavitating, and that no damage would occur as a result of operating the
CS pumps with some cavitation.
l
The long term calculation took credit for 3.4 psig over pressure and operator action
to throttle back on CS and RHR injection flows. This resulted in CS and RHR
pumps not cavitating and able to deliver the design post-accident flow rates.
Engineering stated these flow rates were sufficient for the required safety function.
Operations declared the system " operable, but degraded," pending further
engineering reviews. Prior to taking the shift, operators received training on the
indications of ECCS pump cavitation. Training consisted of observing a simulator
scenario and review of QCOP 1000-30, " Post Accident RHR Operations" and l
Quad Cities Operating Abnormal (OCOA) 1400-01, "CS System Automatic
Initiation." These procedures were changed to throttle ECCS injection flow to I
assure adequate core cooling. The inspectors reviewed the procedure changes and
spoke to operators after training was provided and concluded that the operators
sufficiently understood the indications of pump cavitation and actions to be
performed.
Insoectors' Review of Licensee's Evaluations
The inspectors noted that the NRC allowed the licensee to use "a few psi [ pounds
per square inch)" over pressure as stated in a safety evaluation report dated
August 25,1971. However, no quantitative values were provided. The values of
over pressure used by the licensee were from a vendor calculation and were based
on an NRC approved methodology. This information, although not documented in
the UFSAR, was design information available to the licensee. The inspectors
questioned the limits on the over pressure amount used in the 50.59 evaluation,
since specific values were not included in the UFSAR. This is considered an
inspector Followup item (50 254/265-96020-06) pending further NRC review
during the next report period.
c. Conclusions
l
Self identification of the discrepancy between the design and se.tual condition of
the suction strainer was good. In addition, the training provided to control room
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operators on ECCS cavitation was timely and effective. Further NRC inspection of
the specific values of over pressure assumed in the licensees 50.59 evaluation were
planned.
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l$ E8 Miscellaneous Engineering issues (92902)
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E8.1 (Closed) Insoector Followuo item 50-254/265-95006-01 and
LER 50-265-95005: Unit 2 Reactor Scram During Electro-Hydraulic Control (EHC)
l System Testing. During EHC system testing, the licensee failed the "A" pressure
l regulator expecting the "B" pressure regulator to properly take control. The
l licensee determined the root cause as the failure to recognize the severity of the
transient produced by the pressure regulator failure test. As a result of a larger
than expected difference between the pressure regulator settings, and an
l improperly set steam line resonance compensator (SLRC), Unit 2 automatically shut
down. The licensee determined the method used to set the SLRC was incorrect.
The licensee implemented a procedure to properly set the SLRC. Similarly, the EHC l
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pressure amplifier circuit procedure was modified to ensure the pressure setpoint
bias was set to 3-psid. The inspectors reviewed the procedure changes and
observed portions of EHC testing. The inspectors noted that changes made to the
EHC testing process were successfully incorporated into Unit 1 EHC testing. This I
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item is closed.
I
E8.3 (Closed) Insnector Followuo item (50-254/265-95009-03) and l
LER (50-254/95008 and Rev.1): Oscillations of Unit 2 High Pressure Coolant
injection (HPCI) Pump. During routine testing of Unit 2 HPCI pump, operators noted
turbine speed and pump flow oscillations. Operators also observed an inlet drain l
l pot high level alarm due to a failed drain valve. As previously documented in l
Inspection Report 50-254/265-95011, Section 6.1, the inspectors reviewed the !
licensee's corrective actions for the failure of the drain pot level switch and
solenoid operated valve failure. The inspectors noted that testing of the limit
switch and testing of Unit 2 HPCI after troubleshooting efforts were completed.
The item remained open pending review of the licensee's root cause and corrective
actions for the flow oscillations.
l The licensee's initial response to the flow oscillations was to make a minor l
l adjustment to the proportional band on the flow controller. However, subsequent
l testing revealed the problem still existed. The inspectors concluded the licensee's
initial root cause evaluation was weak. The licensee assembled a multi-disciplined
i team to determine the root cause of the Unit 2 HPCI flow oscillations. The team
l had Operations test Unit 2 HPCIin multiple configurations. The team determined ,
the position of the test valve was changed during the outage. This produced a 1
lower discharge pressure during high pressure steam testing conditions. Since the
flow controller was not adjusted to the new conditions, flow oscillations occurred.
The team had the test return valve properly positioned and tested the flow
controller response time.
The licensee initiated an increased testing frequency of both units' HPCI pumps in
order to increase confidence with the system performance. in addition, the licensee
l purchased and trained personnel on use of air operated valve (AOV) diagnostic
equipment. This equipment was part of a program to control and document air
pressure settings for a growing selection of AOVs as well as detecting problems
with AOV performance.
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L The impectors determined the initial root cause evaluation of the HPCI flow
oscillotions was weak. However, the licensee's response team and the results
produccd by that team, led the inspectors to conclude the final root cause analysis
was good. This item is closed.
E8.4 (Closed) Insoector Followuo Item (50-254/265-96006-05): Main Steam isolation
Valve (MSIV) Spacer Plates inadvertently Left installed. The licensee performed
a 10 CFR 50.59 safety evaluation to document that the spacer plates would not
introduce any unanalyzed conditions adverse to safety. The licensee's
determination of root cause was that recommendations communicated in the parts
evaluation, to remove the sover plates from the MSIVs, were not adequately ;
processed by Engireering, dequently, these recommendations were not l
implemented into the work packages by work analysts. Problem Identification
Form 96-3018 was written to ensure future configuration control by establishing an l
allinclusive history table of the MSIVs and consolidating related PIFs from 1991 l
through 1996. A NTS item was assigned to ides.tify and control removal of the
1-inch spacer plates during the next overhaul of each actuator. The inspector
concluded that this failure to control design configuration was a violation of 10 CFR
Part 50 Appendix B, Criterion Ill, " Design Control." The licensee's corrective
actions to ensure safety, operability, and configuration control appeared adequate.
This licensee identified and corrected violation is being treated as a Non-Cited ;
Violation (50 254/265-96020-07), consistent with Section Vil.B.1 of the i
Enforcement Policy. This item is closed. I
IV. Plant Suncort
R2 Status of Radiological Protection and Chemistry (RP&C) Equipment
R2.1 Unit 2 Radioloaical Liauid Effluent Monitor Flow Problems
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a. Insoection Scone (71707) l
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The inspectors spoke to engineering and chemistry personnel and reviewed I
equipment calibration histories. The inspectors reviewed Section 11.5.2.7 of the
UFSAR, Section 12 of the offsite dose calculation manual (ODCM) and the
licensee's corrective actions for identified deficient conditions.
b. Observations and Findinas
During tours of the facility, the inspectors identified an uncharacteristic non-
turbulent flow condition in the Unit 2 liquid effluent radiation monitor flow indicator
(bubbler). Subsequent ve'ification of the eductor flow path indicated the flow
return isolation valve had drifted about one half tum closed. Chemistry technicians
operationally checked the, flow switch to verify proper operation, then returned the
valve to the normal position. The technicians determined that the valve position
moved due to a loose packing nut and system vibration. The technicians tightened
the packing nut and checked other similar valve packing nuts. The licensee
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', documented this item on PIF 97-0035. Operations determined that the radiation
monitors had remained operable during the time in question. The inspectors
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concluded the degraded flow condition was not enough to actuate the low flow I
alarm.
In response to questions asked by the ir*spectors, the system engineer identified the I
eduction system flow switch and pressure indicators were included in the licensee's
instrument calibration program but were not required to be calibrated on a specified
frequency. Previously, the licensee would clean the flow switch and then perform a l
functional test of both the radiation monitor and flow switch each refueling outage. ;
Additionally, the system engineer identified a PlF commitment to clean the flow l
switch every 4 months was not implemented and there was no existing calibration
procedure for the flow switch. The licensee documented these issues on
PlF 97-0048.
The ODCM required calibration and functional tests of the radiation monitor but not
of the flow switch or pressure indicators. However, the radiation monitor required j
proper operation of the flow switch and eduction system pressure indicators to )
ensure proper service water flows through the radiation monitor.
The inspectors asked the licensee what other instrumentation, necessarv to ensure l
operability of safety-related equipment, was not maintained in the calibration
program. The inspectors consider the adequacy of the licensee's calibration
program to be an Unresolved item (50-254/265-96020-08) pending review of the
licensee's response.
c. Conclusions
The inspectors noted a potential weakness with the lack of calibration for
instruments used to verify safety-related equipment operability.
V. Manaaement Meeting
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X1 Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at the -
conclusion of the inspection on January 24,1997. 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.
26
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I$ PARTIAL LIST OF PERSONS CONTACTED
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Licensee ;
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E. Kraft, Site Vice President- !
B. Pearce, Station Manager :
- A. Blamey, Station Support Supervisor i
4
D. Bucknell, Site Quality Verification I
- ~ D. Cook, Operations Manager j
J. Kudalis, Support Services Director ;
i W. Lipscomb, Work Control Superintendent )
- M. Wayland, Maintenance Superintendent l
INSPECTION PROCEDURES USED
f
IP 40500: Effectiveness of Licensee Controls in identifying, Resolving, and Preventing
Problems
IP 62703: Maintenance Observation j
IP 64704: Fire Protection Program !
IP 71707: Plant Operations
IP 73051: Inselvice Inspection - Review of Program
IP 73753: Inservice Inspection
IP 83729: Occupational Exposure During Extended Outages
IP 83750: Occupational Exposure
IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor )
Facilities
IP 92902: Followup - Engineering
IP 92903: Followup - Maintenance
IP 93702: Prompt Onsite Response to Events at Operating Power Reactors
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$ ITEMS OPENED, CLOSED, AND DISCUSSED
Ooened
50-254/265-96020-01 NCV technical specification surveillances not performed
within required time period
50-254/266-96020-02a VIO operator left SBGT "B" train control switch in off and
l did not verify that all annunciators were clear
l 50-254/265-96020-02b VIO operator recorded that the SBGT "B" train control
switch was in the primary position and it was actually
in the off position ,
, 50-254/265-96020-02c VIO operator used the notch override switch instead of the
l single notch withdraw to return the control rod to its
l original position after exercising
l 50-254/265-96020-03 VIO improper testing of CREVS l
50 254/265-96020-04 IFl problems with shared EDG
50-254/265 96020-05 IFl weak operability evaluation for the degreded safe !
shutdown makeup system valves
50-254/265-96020-06 IFl design discrepancy with ECCS suction strainers
50-254/265-96020-07 NCV failure to control design configuration
50-254/265-96020-08 URI Unit 2 radiologicalliquid effluent morntor flow problems
l Closed
50-254/265-95004-01 VIO control rod HCU return to service after maintenance
without being testod ;
l
50-254/95004 LER Unit 1 HPCl failed to operate j
50 265/95001-00 and 01 LER valve seat leakage exceeded LLRT limits
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50-254/265-95005-01 maintenance personnel failed to adhere to procedural
'
requirements
50-254/265-95009-01 IFl shared EDG failed to start due to failed relay ;
50-254/265-95006-01 IFl Unit 2 reactor scram during EHC system testing
50-265/95005 LER Unit 2 reactor scram during EHC system testing
50-254/265-95009-03 IFl oscillations of Unit 2 HPCI pump
50-254/95008-00 and 01 LER oscillations of Unit 2 HPCI pump
50-254/265-96006-05 IFl MSIV spacer plates inadvertently left installed
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[4 LIST OF ACRONYMS AND INITIALISMS USED
i
i ALARA As Low as Reasonably Achievable
'AOV Air-Operated Valve
l AR Action Request
! CAM Containment Atmospheric Monitoring
i CFR Code of Federal Regulations
i CRD Control Rod Drive
! CS Core Spray
CREVS Control Room Emergency Ventilation System
i d/p differential pressure
[ ECCS Emergency Core Cooling System
l EDG Emergency Diesel Generator
EHC Electro-Hydraulic Control System
ENS Emergency Notification System
EO Equipme7t Operator
ER Engineering Request
ft-lbs foot-pounds
GL Generic Letter
gpm gallons per minute
HCU Hydraulic Control Unit
HPCI High Pressure Coolant Injection System
IDNS lilinois Department of Nuclear Safety
IFl Inspector Followup Item
LCO Limiting Condition for Operation
LER Licensee Event Report
LLRT Local Leak Rate Test
LOCA Loss of Cco? ant Accident -
MSC . Motor Speed Changer
MMD Mechanical Maintenance Department
MSIV Main Steam isolation Valve
MWe Mega-watts Electric
NCV Non-Cited Violation
NPSH Net Positive Suction Head
NSO Nuclear Station Operator
NTS Nuclear Tracking System
NUREG Nuclear Regulatory Commission Technical Report Designation
ODCM Offsite Dose Calculation Manual
OOS Out-of-Service
PDR Public Document Room
PFC Procedure Field Change j
PIF Problem identification Form
psi Pounds per Square Inch
psid Pounds per Square Inch Differential I
psig Pounds per Square Inch Gauge
OCAP Ouad Cities Administrative Procedure l
OCEPM Quad Cities Electrical Preventive Maintenance
OCOA Quad Cities Operating Abnormal Procedure
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