ML20197B264
| ML20197B264 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 12/16/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20197B025 | List: |
| References | |
| 50-254-97-14, 50-265-97-14, NUDOCS 9712230331 | |
| Download: ML20197B264 (42) | |
See also: IR 05000254/1997014
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U. S. NUCLEAR REGULATORY COMMISSION
REGION lli
Docket Nos:
50-254, 50-265
License Nos:
Report No:
50-254/97014(DRP); 50-265/97014(DRP)
Licensee:
Commonwealth Edison Company (Comed)
Facility:
Quad Cities Nuclear Power Ctation, Units 1 and 2
Location:
22710 206th Avenue North
Cordova, IL 61242
Dates:
July 29 - September 22,1997
Inspectors:
W. Kropp, Branch Chief, Reactor Pirjects Branch 1
C. Miller, Senior Resident inspector
K. Walton, Resident inspector
L. Oollins, Resident inspector
C. Lipa, Senior Resident inspector-
Duane Amold Energy Center
R. Gansar, Illinois Depcriment of Nuclear Safety
Approved by:
Mark Ring, Chief
Reactor Projects Branch 1
9712230331 971216
POR
ADOCK 05000254
Q
pm
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EXECUTIVE SUMMARY
Quad Cities Nuclear Power Station, Units 1 and 2
NRC inspection Report No. 50254/g7014(DRP); 50 265/g7014(DRP)
This inspection included aspects of licensee operations, engineering, maintenance, and plant
support. The report covers an 8-week period of resident inspection.
Operations
The licensee identified that on several occasions, operators did not notify chemistry
personnel of the need to perform more frequent sampling of the condenser offgas
system. Similarly, operators failed to test five control rods on Unit 2 prior to raising power
above 40 percent (Sections 01.1,08.7 and M3.2).
The inspectors identified some weaknotses in the licensee's method of counting
50.54(f) indicators (Sections 07.1 and E7.1).
Maintenance
The inspedors found that poor maintenance work practices, including a violation of plant
procedures, prevented conrection of materhl condition problems with an LPCI check
valve. Eventually a leak developed, and repairs resulted in approximately 1 person-rom
additional dose, as well as operational challenges to the plant during a time of operation
with a failed fuel bundle. Poor configuration control and weak understanding of the
design requirements prevented proper alignment of drain valves and prevented
operations personnel from resolving the problem in a timely manner before equipment
had degraded (Section M1.1).
The inspectors' review of the cortpleted surveillance packages verified that the
surveillance results were in compliance with the applicable TS requirements and UFSAR,
but identified that inadequate operations personna' and supervisory review of engineering
surveillance packages had the potential to affect component operability decisions
(Section M1.2).
Maintenance activities resulted in operational disturbances and potentially hazaidous
personnel conditions. Maintenance supervision were hesitant to enter a near miss
situation into the corrective action process. Eventually corrective action processes
worked to the point of identifying hazardous conditions, but failed to come to effective
problem resolution (Section M1.3).
Maintenance activities on the Unit 1 gland steam condenser (GSC) level control valves
(LCVs) were conducted poorly. Problems viith parts support, work package preparation,
planning, troubleshooting guides, work history, and work documentation led to cycling
Unit 1 power levels, increased operator burden, and over 3 person-rem additional
radiation exposure (Section M1.4).
Tne inspectors identified so"eral concems regarding test control during the performance
of the Unit 2 250 Vdc battery modified performance test. The recorded test acceptance
criteria was incorrect and the licensee could not determine where the information was
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obtained. Also, several potential preconditioning issues were identified which could have
affeded test results. The inspectors concluded that the battery test results were
acceptable despite the identified test control weaknesses (Section M3.1).
Even though most surveillances were completed within the critical date, the inspectors
noted a continued adverse trend of missed surveillances. The inspectors concluded that
_ there were multiple reasons for the missed surveillances, Some of these reasons
included defective procedures and/or poor scheduling of surveillances or human error
(Section M3.2).
The inspectors concluded that some TS surveillance requirements and acceptara
criteria were not adequately incorporated into stetion surveillance procedures. The
problems identified were whh a small fraction of the total surveillance population, but the
reviews were conducted on a sampling basis. This could indicate that further -
surveillance adequacy issues remain (Section M3.3).
Enoineenna
The inspectors identified a lack of attention to detail in the design varification process of
calculations for the 250 voit battery (Section E1.1).
Poor communications between engineering. operations, and maintenance personnel were
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evident in backlog reduction efforts (Section E1.2).
The licensee and inspectors identified weaknesses in some safety evaluations
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(Section E1.3).
The inspectots identified that the licensee had not considered the instrument accuracy
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and sensing location in safe shutdown makeup pump system design basis calculations
prior to incorporating the safe shutdown maneup system into the plant TSs. The licensee
did not provide calculations and validate through testing that the surveillance test
acceptance criteria bounded design basis flow and pressure requirements. This resulted
in a violation (Section E1.4).
The inspectors identified various equipment important to safety in an operab,e but
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degraded condition. There were no plans for how and when the equipment would be
removed from the operable but degraded status (Section E2.1).
The inspectors found some discrepancies in the reporting of engineering indicators used
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to support a 10 CFR 50.54(f) request for information (Section E7.1).
The inspectors identified that a licensee commitment made in licensee ovent report (LER)
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50-254/94002 to install a "B" control room emergency ventilation (CREV) hot gas bypass
system had not been met, in August igg 7, the inspectors reviewed tne LER, spoke with
engineering staff, and determined that the system had not been installed and that design
work on the modification had essentially been stopped (Section E8.3).
P! ant Suppgd
An error made by a chemistry technician resulted in a missed TS required surveillance
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(Section R8.1),
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Poor initial troubleshooting efforts and other maintenance problems, such as improper
.govemor installation, prevented the completion of fire pump work within the administrative
LCO time limits. Later troubleshooting resulted in discovery of a long standing problem
.:.with the fire pump. _ Justification forjumpering out fire pump alarms was poor, and '
operator compensatory actions were not adequately spelled out (Section F1,1).
3e inspectors noted an overall lack of sensitivity to fire protection issues. - A number of
equipment problems resulted in administrative Lco time limits being exceeded. Some
equipment was inoperable in excess of 3 years, with planned modifcations to repair the
problems recently canceled or changed. The inspectors noted a lack of rigor in assuring
the required fire watches were established, and a violation was cited. Problem
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identification forms were not effective in focusing management attention on the fire
protection problems. This all occurred in an environment where the licensee was aware
of a relatively high fire risk at the ststion (Section F1.3).
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Report Detalla
Summary of Plard Status
Unit 1 was at full power at the beginning of the inspection period. Fouling of the main
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condenser required the licensee to reduce power daily during off-peak hours to reverse
flow through the main condenser. On September 11 operators reduced power to -
450 MWe to troubleshoot and repair the "B" turbine gland seal condenser level control
valve. On September 16,1997, operators reduced Unit 1 power to about 14 percent to
facilitate a drywell entry to restore the oil level on the 1 A reactor recirculation pump.
Power was held at 400 MWe while repairs were petformed on the 1B gland steam
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condenser level con'tol valve. Again, on September 21, operators reduced power to
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450 MWe to troubleshoot and repair the *B' turbine gland seal condenser level control
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valve. The licensee retumed the unit to full power operations at the end of the inspection
period.'
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Unit 2 was operating at full power at the beginning of the period. A load reduction was'
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conducted on August 6,1997, for drywell entry to identify and isolate a packing leak to the
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drywell equipment drain sump from a core spray testable check valve. Another load drop
was conducted on August 13,1997, while the licensee performed a temporary repair on
the 2A moisture separator drain tank vent fiange. Power increases were rate-limited to
prevent further degradation of a leaking fuel assembly. Hydrogen water chemistry was -
being tripped daily due to offgas oxygen control and offgas hydrogen sampling problems.
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Conduct of Operations
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01.1
Offgas Monitorina Samolina Less Freauent than Reauired by TSs
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Inspection Scope (71707)
The inspectors reviewed operator logs, problem identification forms, and spoke to
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operators
b.
Observations and Findinas
With the Unit 2 oflgas explosive meter inoperable, operators requested that the chemistry -
department obtain grab samples of the ofigas system once every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> as required by -
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TS Table 3.2.H-i TS allowed relaxing the frequency to once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> if reactor power
and offgas recombiner temperature were constant. However, at 10:15 p.m. on
September 4, during flow reversal of the main circulating water system, the hydrogen
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addition system tripped which resulted in a small decrease in recombiner te,mperature.
This condition required a retum to once per 4-hour sampling requirements of the offgas
sptem. Again on September 5 at 8:00 p.m. and at 11:40 p.m., the hydrogen addition
rate changed, requiring more frequent sampling of the offgas system. Operators did not
infoam chemistry of the need to it. crease the offgas system sampling frequency from once
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per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to once per 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The licensee documented this condition on problem
information form (PIF) Q1ggi-03415.
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This was a Violation (50-254/970141a; 50-265/970141a) of TS Table 3.2.H-1.- The -
- licensee attributed this problem to procedural deficiencies since the system outage report
- does r ot address incrossed frequency of testing on decreased recombiner temperatures.
c.
Conclusions
Operations, along with other departments, failed to meet TS surveillance requirements.
other missed or inadequate surveillances were discussod in Sections M3.2 and M3.3 of
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this report.
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02
. Operational Status of Facilities end Equipment
02.1
Safe Shutdown Makeuo Pumo System Walkdowiis
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Inspection Scoce (IP 37551. 62707. 61726. 71707) .
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The inspectors used Inspection Procedure 71707 to walk down accessible portions of the
safe shutdown makeup syste.n (SSMP). The inspectort reviewed past and recently
completed surveillance tests, QCOS 2900-01, " Quarterly Gafe Shutdown Makeup Pump
Flow Rate Test " maintenance work packages, and correspondence with the
architect / engineering firm for the system,
b.
Observations and Findinas
Review of Surveillance Test Data
.TS ex4ptance criteria were met according to the surveillance test. The acceptance
criteria for this pump were in question due a design basis issue being evaluated by
engineering (Section E1,4) Pump inservice test (IST) vibration readings had been
running near the " alert" level for the past 3 years. The system e'igineer believed the
cause of the vibration was pump misalignment. During recent maintenance activity, a
condition concoming shaft tolerances was identified that could also have been a
contributor to the higher vibrations. The liceasee deferred corrective maintenance to
address alignment and shaft dimensions to a future date.
Review of System Maintenance History
The general condition of the SSMP system was good, with the exception of pump
performance. Earlier Sargeant and Lundy (S&L) engineering data showed that the
SSMP was designed to supply 400 gpm at 1250 psig discharge pressure. Tests
conducted shortly after the system was installed in the mid-1980s showed that the pump
could perform at this level. Records showed that in 1987 the pump seized. Following
seizure, some of the intomal bushings were undercut.- Subsequently, it appeared that the
SSMP pump discharge pressures were typically lower than 1250 psig. Pressure readines
ranged from 1220 - 1240 psig, with several results well below 1200 psig.
Correspondence from S & L to the licensee stated the licensee should check the
accuracy of the installed instrumentation and inspect the pump intemals for the cause of -
the loss in performance. The licensee's records indicated that the instrumentation was -
checked and found to be accurate. However, there were no records to indicate that
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pump intamals were over inspected. The licensee's corrective maintmnoe program :
was weak in that the limitations of the SSMP were not assessed. Subsequently, the
licensee did not aggressively pursue the reduced pressure output of the pump which was
very close to the limit of soceptance. This condstion was documented on Section E1.4 of
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Review of Work Packanes For Recent Maintenance Outane
The pro- and post-job briefing sheets in the reviewed work packages were of several
different revisions. The earlier revisions did not contain control measures to assess
rework afforded in the current work package revisions. Accurate identification of
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maintenance rework had been an ongoing problem at the station for some time.
- Consequently, the licensee had not offectively implemented the necessary controls, to
identify and assest rework conditions into the pre-job briefing. The inspectors assessed
this as an administrative weakness which was acknowledged by the licensee. There
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were no negative consequences to the plant in the cases noted.
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Conclusions
The general material condition of the SSMP system was good with the except!on of pump
performance. Past conduct of maintenance monitoring was insufficient, as evidenced by
the poor monitoring of maintenance history and limited action to correct degraded
SSMP output pressure. There was no evidence that the vendor recommendations to
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inspect the pump intemals were accomplished. In general, the licensee had given the
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SSMP system relatively low prionty in addressing design and equipment issues.
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Quality Assurance in Operationa
07.1
Review of 50.54f Performance Indicators
a.
Inspection Scope
The inspectors reviewed several of the licensee's performance indicators which were
implemented in response to a 10 CFR 50.54f letter from the NRC to Comed. The
indicators included operator workarourids, human performance LERs, and failed TS pump
and valve surveillances.
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b.
Observatioits and Findinas
Ooerator Workarounds
The inspectors reviewed the performance indicator charts for the months of May and
June and noted that the workdown curve had changed. On August 1,1997, the
inspectors obtained a list of scheduled work dates for all the open operator workarounds
(OWA) and compared the OWA list with the workdown curve. The inspectors found that
the workdown curve projected by the work control schedule did not match the work.!own
curve published on the indicator chart and also did not match the workdown curve
projected by the Operations department.
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The inspectors were concemed that the indicator goal of less than 10 percent deviation
from the workdown curve did not appropriately measure progress in reducing the
numbers of operator workarcunds since the workdown curve was changed every month,
1 For example, in May the projected number of OWAs for the end of June appeared to be
' 31. ' :==, the actus: number of OWAs at the end of June was 37, and the goal for
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June was changed to 34. Thomfore, the licensee concluded that the goal was met since
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37 was within 10 percent of 34. (Note that the temporary alteration workdown curve also
changed from month to month). In the future, the licensee no longer planned to change
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the workdown curve monthly.
Human _Pefformancatilcanie1 Event Renoria
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The inspectors questioned the licensee about the goal for the number of human
performance LERs. The goal established was less than or equal to two LERs per month.
The inspectors noted that the numbers of human performance LERs from the licensee's
graph for 1994,1995, and 1996 were, respectively,12, 8, and 17. Therefore,2 humin
performance LERs per month could lead to a total of 24, which would indicate a serious -
decline from past performance. The licensee stated during the August 5,1997,
perfonnance indicator meeting with NRC management that the rate of two LERs per
month was used as a threshold for involving licensee corporate management and not
intended to represent an acceptable level of errors.
Failed TG Pumo and Valve Surveillances
While reviewing the data for this serveillance, the inspectors questioned the high number
of monthly surveillances shown on the indicator chart. It appeared that over
3500 surveillances, were posformed in the month of June. The IST coordinator explained
that control rod drive surveillances and scram time testing of control rods exercised up to
14 valves per control rod (177 total) which were individually counted ir. the total number of
tests. Additionalty, one physical performance of a procedure could account for numerous
component tests (for examp;e; leakage test, valve time test.)
The inspectors reviewed PIFs against the data collected fc.- this indicator and found no
discrepancies. All documented failed surveillances were counted appropriately. It should
be noted that the total number of tests are tracked differently than the total number of
failures. The failures were counted on a per component basis rather than the total -
number of test failures. Since the indicator was being tracked for 6 months prior to
establishing a goal and no rate of failure was calculated, the inspectors concluded that
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there was no impact in counting the failures differently than the total number of tests.
However, if in the future a failure rate was used as a goal, the counting methods would
need to be reevaluated,
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Conclusions
Even though the workdown curves did not accurately reflect the projected rate of reducing
OWAs, the inspectors had noted that the overall number of OWAs had decreased over
the past several months.- The inspectors concluded human performance LERs and failed
TS pumps and valve surveillance indicators were adequately counted.
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Miseellaneous Operations leaues (92700)'
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. 08.1 - (Closed) LER 50-254/94010 00: 50 254/94010-01: Unplanned Scram of Control Rod
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During Surveillance. The surveitance generated a half-scram condition to the reactor -
protection system on Unit 2. Since a half-scram did not satisfy the logic required to
produce control rod motion, control rods on the unit were not expected to move.
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However, Rod D 11 fully inserted. The licensee attributed this event to aged diaphragms
in the 117 scram solenoid pilot valve (SSPV). The inspectors cited the licensee
(Violation 50 254/94017-03; 50-265/94017-03) for ineffective corrective actions for repeat
SSPV problems. The licensee subsequently replaced all SSPV diaphragms on both
units. The inspectors have noted better control rod system posformance. This item is
closed.
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08.2 (Closed) LER 50-254/96001-00: "B" Control Room Emergency Ventilation System
(CREVS) inoperable Due to inoperable Relay. An operator identified the "B" CREV8 fan
was spinning backwards irdcating the fan dampers were open. How long this condition
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existed was unknown. Operators started the system to verify the system was capable of
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meeting its design function. The licensee attributed this condition to a failed relay. No
root cause of the failed relay was identified. The licensee had no plans to periodically
replace the contacts. The inspectors reviewed the licensee's corrective actions. This
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LER is closed.
08.3 (Closed) Inspector Followuo item (IFI) 50-254/96002-03: 50-265/96002-03: Buildup of
Debris on Trash Rock Resulted in Low Water Level inside intake Structure. The low
intake water level condition resulted in the fire pumps becoming inoperable on
January 23,1996. Operators reduced power until the trash rack was cleaned and intake
water level retumed to normal levels inside the crib house. The inspectors were
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concemed that maintenance requests for the system were given a low priority, operators
were not prepared to respond to the event in a timely manner, there was no method to
determine water level inside the crib house and operators did not know what water level
would render pumps incapable of providing flow due to cavitation.
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The licensee responded by revir.ing Quad Cities Operating Procedure (QCOP) 4400-04,
" Traversing Trash Rake," to include a frequency of trash raking and included the minimum
water levels in the bays to ensure various pumps would remain operable. Engineering
confirmed that safety-related pumps would pass the required design flow should the river
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level drop to the Updated Final Safety Analysis Report (UFSAR) specified minimum level
of 561 feet above sea level. However, for inservice testing purposes, the pumps would
be declared inoperable should crib house uter level drop below the level specified la
QCOP 4400-04. In addition, the procedure required operators measure the water level
inside the crib house if the trash rack was dirty and the trash rake was not operable. The
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method for measuring water level was to drop a weighted line until the water surface was
contacted then measure the length of the line. The licenses changed Quad Cities
General Procedure (QCGP) 3-2, " Control of Planned Reactivity Changes," to start TS
required shutdowns in a more timely manner.
Operators continued to monitor trash rack conditions shiftly on rounds. The inspectors
observed trash raking activities during the inspection period and noted the equipment
worked satisfactorily. However, the inspectors noted the depth of water at the north end
of the intake structure was less than 5 feet. The licensee plotted the depth of the water in
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frord of the intake structure yearty end noted the sitt buildup had increased. The licensee t
planned to have the area dredged in the future.- The inspectors noted the sin buildup
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would not inhibit the proper operation of the safety-related pumps should river water level:
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- drop to the minimum UFSAR design water level of 561 feet above sea level.
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The inspectors reviewed the licensee's root cause evaluation, corrective actions, and
procedure changes. This Rom is closed.
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08.4 (Closed) LER 50-254/96006-00: TS 3.0.A Incorrectly invoked. During shutdown of Unit -
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1, operators incorrectly entered into TS 3.0.A to perform a local leak rate test (LLRT).
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The LLRT vented the >rimary containment into secondary containment with the reactor at
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power. The inspectors cited a Violation (50-254/96002-02; 50-265/96002-02) for this -
issue.
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The !!censee attributed this event to an inadequate safety evaluation of the LLRT
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procedure and misinterpretation of the intent and application of TS 3.0.A. The inspectors
reviewed the completed corrective actions listed in the LER. This item is closed.
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' 08.5 (Closed) LER 50-254/97001-00: Missed Operations Surveillances. On January 17,1997,
the licensee identified that two TS required surveillances were missed by control room
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operators. Control room operators changed from 8-hour shifts to 12-hour shifts, but
control room logs were not modified to reflect the shift change. The licensee attributed
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this event to not adequately assessing the change to 12-hour shifts.
The two missed TS required surveillances excesoed the 12-hour limit plus the 25 percent
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alluwed grace period. This was a Non-cited Violation (50 254/96020-01;
50 265/96020-01). The licensee implemented administrative controls to ensure the daily
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surveillances were not missed. This LER is closed.
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08.6 (Closed) LER 50 254/97006-00: Inadequate operations Surveillance. The inspectors
identified that the licenses failed to incorporate four residual heat removal service water
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(RHRSW) valves, which were not locked or otherwise secured in position, in a
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surveillance procedure. The licensee determined the surveillance deficiency was due to
an inadequate procedure development and review due to human error. The inspectors
determined this was a Violation (50-254/97011-03; 50-265/97011-03) of TS 4.8.A. The
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inspectors re, viewed the licensee's corrective actions. This LER is closed.
08.7- (Closed) LER 50-265/97006-00. Missed Control Rod Surveillance. On June 29,1997,
the licensee identified four control rod drives (CRDs) had not been adequately tested prior
to their retum to service. Similarly, on July 16,1997, a fifth CRD was identified by the
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licensee as not having been adequately tested. The licensee declared the CRDs
inoperable, inserted the rods, and satisfactorily tested the CRDs, The licensee attributed -
the missed post-maintenance tests to an ineffective tracking process and human error.
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- TS 4.3.D.1 required all CRD testing be completed prior to operating the reactor above 40
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- percent power. At the time of discovery, Unit 2 was operating above 40 percent power.
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The failure to test the five CRDs prior to increasing power on Unit 2 above 40 percent
power was a Violation (50-254/97014-01b,50-265/97014-01b) of TS 4.3.D.1. This LER
is closed.
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- 08.8 (Closed) LER 50 265/97009-00. Control Room Operators Misread Abnormal Offgas
Rad 6ation Readings. This item was discussed in inspection Report No.50-254/97011;
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50-265/97011. The Irispectors vertfled the control room operator logs had been changed
as stated in the LER. This LER is closed.
IL McIntonance
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Conduct of Maintenance-
M1.1 Maintenance Activities
a.
Inspection Scope (61726. 62707)
The inspectors reviewed and/or observed the following work requests (WR) activities and
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assessed the workers performance and compliance with plant requirements:
Unit 1 Emergency Diesel Generator Monthly Load Test
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Repair of 2A low pressure coolant injection (LPCI) air
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operatsd check valve.
Install / Remove Jumper in Unit 2 Rod Control System
.-
Replace Unit 2 Main Steam Line Square Root Converters
+
b.
Observations and Findinas
!
On August 6,1997, Unit 2 reactor power was reduced in order to troubleshoot and repair
a valve packing leak in the drywell. The inspectors reviewed maintenance records and
design information involving valve repacking activities to determine the appropriateness
of the activity and the rotationship to later packing failure. The inspectors' review
determined that about 1 person-rom of exposure resulted from the downpower and repair
activities for the 2A LPCI air operated check valve. The inspectors leamed that the valve
had previously been mpacked in March 1997, Work Request 96003387401 was
performed in March 1997 and included inspection and repair activities on
LPCI Check Valve 2-100168a. After reviewing Work Request 96003387401, the
'
Inspectors discovered that the instructions in the maintenance request were not property
f
followed, and that the design of the packing leak off line for the valve was not understood
by plant personnel.
,
'
Work Request 90003387401 was written to allow for packing replacement. The
supervisor involved changed the scope of the request to add packing rings vice replace
packing, without properly changing the procedure. The work request referred workers to
Attachment D of mechanical maintenance procedure Quad Cities Mechanical
Maintenance (QCMM) 1515-07, Revision 7, " General Valve Packing Procedure." The job
supervisor, when interviewed, indicated that although the package required changing out
i
- the inner und outer packing, he did not think that was necessary for the scope of the job.
instead of following or properly changing the procedure, the supervisor elected to only
,
,
add rings to the outer packing, reasoning that there was no indication of packing leakage.
l
However, the inspectors noted that the outer packing was being replaced because ti. ore
was no adjustment left for tightening packing due to previous tightening efforts - an
indication of packing leakage. By adding rings to the outer packing, the supervisor was
'
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also potentially adversely affect.ng the two stage packing with leak-off line arrangement.
TS 6.8.A required applicable procedurcs recommended in Appendix A of Regulatory
Guide 1,33, Revision 2, February 1978, be impleinented. This regulatory guide included
i
administrative procedures dealing with procedure adherence and maintenance
procedures dealing with safety-related equipment. Failure to follow procedure OCMM
1515-07 was a Violation (50-265/97014 02) of TS 6.8.A.
Following plant startup, the inner packing began leaking and eventually resulted in a unit
d-rwrpr;r to isolate the packing leak. The packing leak was routed through a leak-off
line which led to the drywell equipment drain sump. The excessive leakage required
frequer:t pumping and recirculation of tne sump. In addition, the high temperatures
'
caused by the leak eventually led to a required change out of the sump pumps. These
operator problems and the radiation dose received from the rework on this job could have
been avoided had the original maintenance activity been conducted property.
+
Once the leak was discovered, operators could not tell if the leak-off line was supposed to
be open or closed. The leak-off line isolation valve 21001-64c for the 68a check valve
was shown by piping and instrument diagrams (P&lD) to be open but required by
Qusd Cities Operating Mechanical (QOM) 2-0020 02, "U2 Drywell Valve Check List,"
procedure to be closed. The isolation valves had been listed as a discrepancy in the
QOM check list, and left open. Failure to control plant configuration property, and
property evaluate procedure changes led to the increased leakage into the drywell
' *
equipment drain sump. The licensee addressed the discrepancy by initiating
Drawing Change Request 970179 to change the indicated position of the valve to
" closed" on the P&lD. This licensee-identified and corrected violation is being treated as
a Non cited Violation (50-254/97014-03; 50-265/9701443) consistent with
- Section Vll.B,1 of the NRC Enforcement Policy. The inspectors found through
discussions with engineering and maintenance personnel that drywell equipment leak-off
drain lines were initially installed to give early indication of packing leakage. Inability to
maintain packing was cited as the reason for plant decisions to isolate the leak-off
isolation valves, and even cap off the lines in some cases. Poor understanding ofine
design configuration led to a situation where degraded I;acking and an open drain line
caused an excessive amount of drywell packing leakage.
c.
Conclusions
4
The inspectors found that poor maintenance work practices including a violation of plant
procedures prevented correction of material condition problems with a LPCI check valve
and resulted in approximately 1 person-rem additional dose, as well as operational
challenges to the plant during a time of operation with a failed fuel bundle. Poor
configuration control and weak understanding of the design requirements prevented
proper alignment of draic, valves and prevented operations from resolving the problem in
a timely manner before equipment had degraded. A non-cited violation was issued
'
following licensee identification and resolution of the configuration control problem.
,
1
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M1.2 Surveillance Observations
a.
Insoection Scoce
The inspectors reviewed and/or observed the surveillance activ.cas listed below. The
inspectors verified the surveillances were in conformance with the design basis of the
facility and in compliance with TS.
QCOS 0300-01
Control Rod Drive Exercise
QCOS 1000-06
Quarterly Residual Heat Removal (RHR) Pump / Loop Operability
Test
QCOS 6900-01
" Station Battery Weekly Surveillance" for March 11,18, and 24,
1997, for the Unit i Safety-Related 250 Vdc Battery
QCOS 6900-02
" Station Battery Quarteriy Surveillance" Performed on the Unit i
250 Vdc Battery on March 14,1997
QCOS 6900-02
" Station Battery Quarterty Surveillance" performed on the Unit 2
250 Vdc Battery on March 31,1997
QCTS 0240-04
" Unit One (Two) Service Test 250 Vdc Safety Related Battery"
Performed on the Unit i 250 Vdc Battery in May 1996
QCTS 0240-06
" Unit One (Two) Modified Performance Test 250 Vdc Safety
Related Battery" Performed on the Unit 2 250 Vdc Battery on
April 7,1997
b.
03servationt_and Findinas
During this review the inspectors identified concems with the surveillance procedures
pertainog to testing methodology and the accepte. .e criteria used in procedure
Quad Cities TS (QCTS) 0240-06 " Unit One (Two) Modified Performance Test 250 Vdc
Safety Related Battery," Revision 2. These concems are discussed in detailin
Section M3.1 of this report.
The inspectors also identified a concem with the review process of completed
surveillances. Surveillance procedure QCTS 0240-06 did not require a review of the test
results by on-shift operations personnel prior to declaring the 250 Vdc battery operable.
The inspectors were concemed that only one level of review of completed surveillance
packages coeld lead to unacceptable surveillance results not being identified in a timely
manner prior to declaring a component operable. For example, TS surveillance
QCTS 0240-06 perfrvmod on April 7,1997, and discussed in Section M3.1 of this report,
had an incorrect acceptance criteria for the battery capacity. The acceptance criteria was
required to be noted in Step D.8 of the proc 3 dure each time the modified performance
test was performed by engineering. The inspectors identified there was no operations
review of the cumpleted package; therefore, there was a missed opportunity to identify
the incorrect acceptance criteria on April 7. The incorrect acceptance in this casa did not
resultin an inoperable battery,
13
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Conclusions
The inspectors' review of the completed surveillance packages verified that the
surveillance results were in compliance with the applicable TS requirements and UFSAR,
but that inadequate operations and supervisory review of engineering surveillance
packages had the potential to affect component operability decisions.
<
k 1.3 Eg[R100tllEftbLEt9 Meet
a.
Insoecuon scope
The inspectors rev wwod plant response to two events involving maintenance activities
which had a high potential for, but fortunately did not resuh in personnel injury,
b.
Observations and Findings
in one case, on August 13,1997, inspectors observed maintenance personnel
conducting fire system surveillance Quad Cities Mechanical Maintenance Surveillance
(QCMMS) 4100-32, *1/2A-4101 Diesel Driven Fire Pump Annual Capacity Test." Just
prior to opening a fire test header isolation valve, two maintenance supervisors walked
onto a catwalk over the circulating water discharge canal to test the structural integrity of
devices installed to protect plant equipment from damage caused by high pressure water
sprayed during the surveillance. When the valve was opened, high pressure water
trapped in the line discharged into the discharge canal area and struck one supervisor,
pushing him up against a safety railing and knocking his hard hat into the discharge
'
canal. The procedure and maintenance supervision failed to adequately protect
personnel from injury during the surveillance activity. Additionally, this near-miss incident
was net documcnted on a PIF until prompted by the quality and safety assessment
mar ~ dr the following day.
Corre,
e action for the event was also inadequate in that PlF Q1997-3188, written to
address the problem, did not adequately address the safety issue involved. The PlF was
closed to a data point with the understanding that a change to the surveillance procedure,
including an additional caution statement, would be made. However, on September 2
i
when the inspectors reviewed the QCMMS, a correction to the procedure had not been
i
made. in addition, the PlF had identified that the likely cause of the pressure surge when
,
opening the system was water trapped due to valve leakage into the header. But
corrective action to fix the valve leakage had not been taken or initiated as of August 29
'an the inspectors informed plant management. On September 2 the valve work was
not p',rformed and the procedure change had not been implemented, meaning that no
. -
effective corrective action had yet been taken. Following NRC discussions with
management, operators hung caution tags on the valve in question to assure personnel
safety until the issue was resolved.
On September 2,1997, the inspectors observed control room operations and
maintenance staffs respond to an event in which workers cut a live 13.8 kV electric line
by accident using a backhoe. This event was very similar in nature and consequences to
-
another 13.8 kV line cut caused by maintenance on September 9,1996, and documented
,
in Inspection Report No.254/96012; 50-265/96012. Operators properly addressed the
numerou annunciators and equipment changes cau' sed by the high voltage line cut, but
j
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were distracted from routine control room duties during the event.E The inspectors found
that tne workers had made attempts to locate energized lines in the dig area. The
licensee was investigating the cause of the event, using PIF Q1997-03367 as the tracking
mechanism,
c.
Conclusions
The inspectors concluded that maintenance activitievosulted in operational
distutt>ances and F-ME'"i hazardous personnel conditions. Maintenance supervision -
were hesitard to enter a near miss situation into the corrective action process. Eventually
corrective action processes worked to the poird of identifying dangerous conditions, but
failed to come to effective problem resoluti,m.
M1.4 Poor Gland Seal Level Control Valve Maintenance
a.
. inspection Scope
The inspectors reviewed work packages and work in progress to determine the
effectiveness of maintenance in repairing the "1B" gland steam condenser (GSC) level
control valve (LCV.)
b.
Observations and Findinas
4
The gland seal condenser level control valves have been chronic maintenance problems
at Quad Cities in the recent past. The Unit 2 startup from the Q2R14 refueling outage
was troubled by GSC LCV problems. The 1 A GSC LCV had been tagged inoperable
since April 1997.. Maintenance history showed problems with the 1B valve in
November 1996 and then in January 1997, June 19g7, and then August through
September 1997. Radiation dose to workers had been high when failures occurred
because the area of the LCV was a high radiation area during power operations. The
system was designed with redundancy, so when one LCV failed, the o'her may be put
into service. However due to inability to maintain the valves, Quad Cities has been
operating Unit 1 with only one operable LCV. Thus when the 1B valve began to fail in
~ August 1997, operstc. s were forced to go into the heater bay to manually control
.
GSC level. Inability to control level could have resulted in gland steam leaks in the heater
bay on high level, or degraded main condenser vacuum on low level.
Operations normally reduced reactor power in order to lower radiation exposure to
operators and maintenance workers when a GSC LCV problem was experienced.
Although as low as reasonably aciiievable (ALARA) practices were normally followed for
the repairs, the number of repair attempts led to high overall exposures to personnel in -
August and September. Radiation exposures of up to 3.5 person rem were experienced
for all the various heater bay entries involved.
The inspectors noted that the initial work package for repairing the 1B GSC LCV lacked a
troubleshooting plan. Several attempts were made to repair the valve by tuning the -
controller, repairing air leaks, and repairing a valve diaphragm, before a comprehensive
plan was a developed by a team. The inspectors spoke with Me maintenance
i
superintendent who indicated that this effort did not meet hb expectation for a
..
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A
troubleshooting plan. That expedation had been expressed earlier following poor -
maintenance on diesel generator air start motors.
,
The inspectors noted that some of the entries in Work Package 960102229 lacked detail.
Previous attempts to repair the LCV were recorded with insuffderd h! story to determine
the problem with the equiomord. During the repair attempts on the 1B valve,
maintenance and engineering personnel also attempted to repair the 1 A valve. Partly due
to insufficient documerdation of the status of the 1 A valve, there was significant confusion
about the status of the valve, leading personnel to spend effort on the repair when a
retum to service was unlikely.
Parts support ws: =!:o a oroblem. Techniciam found that parts on order to mpair the
1B valve were incorrect. Once the 1B valve intomats were removed, incorrect parts were
also found there. The inspectors were also informed that parts to repair both the
1 A valve and the 1B valve were not available. The inspectors questioned why a critical
balance of plant component with por repair history did not have ample spare parts
available to fix both the 1 A and 1B LCV, especially considering the two active
maintenance requests written against LCVs on Unit 1 and Unit 2.
c.
Conclusions
Maintenance activities on the Unit 1 GSC LCVs were poor. Problems with parts support,
work package preparation, planning, troubleshooting guides, work history, and work -
documentation, icd to cycling Unit 1 power levels, increased operator burden, and
additional radiation dose.
M3
- Maintenance Procedures and Documentation
Qggd Cities Techrical Staff Procedure 0240-06. " Unit One (Two) Modified Performance
l
M3.1
Test 250 Vdc SafeN Related Batterv"
a.
Inspection Scoce (61726)
The inspectors had previously witnessed portions of the Unit 2 modified performance test
for the Unit 2 250 volt direct current (Vdc) safety-related battery conducted in accordance
with QCTS 0240 06 on April 7,1997 (see inspection Report No. 50-254/97006(DRP);
_'
50-265/a7006, Section M2.3). During this inspection, the inspectors further compared the
completed test package to the designed load duty cycle of the battery to verify that the
test requirements conformed to TS 4.9.C, UFSAR 8.3.2.1, and S&L battery calculation,
"PMED 891377-01", Revision 10. The inspectors had specific observations pertaining to
PMED 891377-01 which are discussed in Section E1.1 of this report.
b.
Observations and Findinas
The review of the completed April 7,1997, modc id performance test package
(QCTS 0240-06) identified several issues, some pertaining to methodology and others to
acceptance criteria. The updated TS, issued in the fall of 1996,' allowed the licensee to -
conduct a modified performance test on the 250 Vdc battery in lieu of a separate service
test (based on the battery's design duty cycle) and a performance test (measures battery
capacity). The requiremer,ts for a modified performance test is defined in standard
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Institute of Electronic of Electrical Engineers (IEEE) 4501995, " lEEE Recommended
practice for Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries for
%
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Stationary Applications." The licensee issued procedure QCTS 0240 06,
" Unit one (Two) Modified Performance Test 250 Vdc Safety Related Battery," to define
the testing methodology for the new TS modified performance test.
- The inspectors identified the following concems with the April 7 modified performance
test and procedure QCTS 0240-06:
Step D.8 of procedure QCTS 0240-06 required the individual performing the test
to determine the minimum acceptable battery capacity from the latest revision of
the direct current (dc) Electrical Load Monitoring System (ELMS) and record the
number in the step. The minimum acceptable battery capacity acceptance criteria
recorded for the April 7 test was 70 percent. This acceptance criteria was not
correct. The minimum acceptable capacity should have been 80 percent or the
margin calculated from the design load profile for the battery, whichever is greater
(Step F.4). In the case of the April 7 modified performance test, based on the
current capacity margin as defined in the design load profile, the minimum
!
capacity acceptance criteria should have been 80 percent. The completed
modified performance test determined that the battery's capacity was 100 percent;
'
therefore, the incorrect acceptance criteria of 70 percent did not adversely impact
the operability of the battery. The licensee could not determine where the
70 percent acceptance criteria was obtained. The failure to have the correct
acceptance criteria for the Unit 2 safety related 250 Vdc battery modified
performance test is considered a Violation (50-254/97014-04; 50 265/97014-04)
of 10 CFR 50, Appendix B, Criteria XI, " Test Control."
l
Section B of proc 4 dure QCTS 0240-06, titled " Discussion," stated the initial
i
e
'
conditions for the modified performance test should be identical to those specified
for a service test. Also, IEEE 450-1995, Ssetion 5.4, had a similar statement.
I
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Procedure QCTS 0240-06 referenced standard IEEE 450-1987 which was
incorrect since it did not address modified performance testing. For the purpose
of this inspection, the inspectors utilized IEEE 450-1995 as t'l* recognized
standard for the modified performance test.
The purpose of a service test was to determine if a battery could provide the
required current within specified voltage parameters during the design load profile.
Standard IEEE 450-1995, Section 6.6, stated that the battery condition for the
service test be in an "as found" condition. For example, battery connections and
'
resistance readings can be checked prior to the test, but no corrective action
would be taken unless there was a possibility of battery damage. The inspectors
identified the following concems in this area:
(1)
On March 31,1997, the licensee performed TS 4.9.C.2. Quad Cities
Operations Surveillance (QCOS) 6900-02, " Station Battery Quarterly
Surveillance." During the surveillance, corrosion was identified at cell
connections 70,73, and 90. Procedure QCOS 6900-02 required the
corrosion to be cleaned by performing procedure Quad Cities Electrical
Preventive Maintenance (QCEPM) 0100-01, " Station Battery Systems -
Preventive Maintenance." The inspectors determined that the corrosion
was cleaned from the affected cells. - The inspectors reviewed the records
i
associated with the recording of the cell resistance (Attachment F of
17
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r
procedure QCEMP 0100-01) and noted that only "as found" resistance '
,
readings were recorded and not also the "as left." The inspectors were
concemed that the battery was not tested on April 7 in the "as found"
condition as recommended by lEEE 4501995.
(2)
The modified performance test procedure QCTS 0240-06, Revision 2, did
not require that all battery connections have the correct resistance. The
inspectors determined that the last time the resistance of the battery
connections were checked was in May 9,1996, approximately 11 months -
prior to the April 7,1997, modified performance test. The resistance was
checked as required by TS 4.9.C.3 using procedure QCEMP 0100-01,
" Station Battery Systems Preventive Maintenance." The TS surveillance
was to be performed every.18 months. The inspectors were concemed
that the "as found" condition of the battely was not being ascertained prior
to performing the modified performance test as recommended by
lEEE 4501995,
A prerequisite, defined in Step D.6, stated that if necessary, locate temporary
e
heaters in the battery room to mainta!n adequate electrolyte temperature. The
procedure did not identify the adequate electrolyte temperature
(note: TS 4.9.C.2c. requires the average electrolyte temperature to be above
-
60'F). Even though heaters were not used prior to the April 7 modified
performance test, the inspectors were concemed that using heaters in the future
would be preconditioning the battery for the portion of the modified performance
test pertaining to the 1 minute peak testing discharge rate (920 amps), increasing
the electrolyte temperature improves the battery's performance and could mask a
degraded battery and coiTipromise the requirement of testing the battery in an "as
found" condition. This concem was discussed with the licensee, and procedure
QCTS 0240-06 will be revised to delete placing heaters in the battery room to
elevate the battery's electrolyte temperature prior to the test.
'
Conclusions
The inspectors identified several concems regarding test control during the performance
of the Unit 2 250 Vdc battery modified performance test. The recorded test acceptance
criteria was incorrect and the licensee could not determine where the information was
obtained. Also, coveral potential preconditioning issues were identified which potentially
could have affected test results. The inspectors concluded that the battery test results
were acceptable despite the identified test control weaknesses.
M3.2 Missed Surveillances
3
a.
inspection Scope (92701,61726)
The inspectors reviewed recent PIFs and LERs associated with missed surveillances.
b.
Observations and Findinas
.The hspectors noted multiple instances of missed surveillances identified by both the
i
licensee and the inspectors over the past year. In the winter of 1997, the inspectors
_
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identified two violations where control room ventilation surveillances were missed. These
were due to inadequate review of existing surveillance procedures to ensure the new
TS upgrade program (TSUP) requirements were included. More recently, the inspectors
identTHHi two non-cited violations (NCVs) for missed surveillances. One of these missed
surveillances was due to operators changing from 8-hour to 12-hour shifts (see Section
08.5). A second NCV cited a deficient localleak rate test identified by an NRC
information notice (see Section E8.9). Both NCVs were attributed to different causes,
in this report, five miswed inservice testing surveillances resulted in a violation
(see Sections MB.3, M8.4 and E8.13). The licensee attributed two of these to defective
procedures. A third missed surveillance was mostly due to a scheduling process
deficiency A failure to test five control rods before Unit 2 power was increased above
40 percent was attributed to post rnalntenance testing process deficiencies and human
erm (see Section 08.7) A missed chemistry surveillance was att-ibuted to human error
(see Section R8.1).
The licensee recently documented two PlFs where non TS required surveillances were
not completed on the scheduled dates due to scheduling deficiencies. A room cooler
inspection was deferred numerous times due to scheduling conflicts (PIF Q1997-3452).
A computer room halon surveil lance exceeded its critical date due to scheduling
deficiencies (PlF Q1997-3447),
c.
Conclusions
Even though most surveillances were completed within the cri ical date, the inspectors
noted a continued adverse trend of missed surveillances. The inspectors concluded that
there were multiple reasons for the missed surveillances. Some of these reasons
included defective procedures and/or poor scheduling of surveillances or human error.
M3.3 Inadeouste Surveillances
a.
insoection Sqqp3 (92701,61726)
The inspectors reviewed LERs, PIFs and surveillance procedures to ensure TS-required
surveillance tests were properly implemented,
b.
Observations and Findinas
- The inspectors noted four instances of inadequate surveillances. A battery surveillance
lacked the correct acceptance criteria (see Section M3.1) Additionally, a
RHRSW surveillance was inadequate to assure equipment operability (see Section E8.5).
A safe shutdown makeup pump surveillance was lacking design basis documentation
(see Section E1.4). An operations monthly surveillance failed to include four
RHRSW valves (see Section 08.6).
c.
Conclusions
rhe inspectors concluded that somo TS surveillance requirements and acceptance
criteria were not adequately implemented into station surveillance procedures. The
problems identified were with a small fraction of the total surveillance population, but the
19
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reviews were conducted on a sampling basis. This could indicate that further
survelilance adequacy issues remain.
MS
Miscellaneous Maintenance issues (92902)
M8.1 LQhaed) LER 50-26: Misinterpreted TS Surveillance
Requirement. As discussed in Inspection Report 50-254/96012; 50-265/96012, the
licensee originally believed that a TS required surveillance was missed; however, upon
further revisw, the licerssee determined that no surveillances were missed. An Unusuel
Event was declared and terminated on September 4,1997, and was subsequently
,
retracted on September 1E 1997. The licensee submitted the LER voluntarily to report
the event. The inspectors agreed with the licensee's determination that no TS
surveillances were missed and had no further concems. This item is closed.
M8.2 [Q!osed)IFl 50-254/97006-05@f.5197006-Q1: Unit 2 250 Vdc Battery Modified
Performance Test Load Profile. Th9 inspectors further reviewed the load profile and
determined that the high pressure coolant injection (HPCI) suction path transfer from the
contaminated condensate storage tank (CCST) to the suppression pool was adequately
modeled. Also, all safe shutdown loads were included in the load profile. Additional
inspections were performed on the 250 Vdc battery system and the results are
documented in section M3.1 of this report. This item is closed.
MB.3 (Closed) LER 50-254/97014-00: Target Rock Mfety Relief Valves (TRSRV) Did Not
Receive As-found Set Point Testing Within 12 Mcnths. The licensee identified that
neither Unit 1 nor Unit 2 TRSRVs that were removed during the most recent unit refuel
outages, had been set pressure tested within 12 months of their removal from the
system. The licensee had since set pressure tested both TRSRVs. Both valves were
outside their 1 percent acceptance band and were adjusted. The licensee evaluated the
as-found condition as a condition not violating any reactor safety limits or fuellimits. The
licensee attributed this event to defective procedures which failed to ensure prompt
testing of tue TRSRVs. Similar procedure deficiencies were identified with the main
steam safety valve (MSSV) testing. The inspectors noted the le.ensee planned to modify
TRSRV and MSSV testing procedures.
The relief valves were required by TS 4.0.E and American Society of Mechanical
Engineers (ASME) Code requirements to be set pressure tested withiri 12 months of
removal from the system. Failure to set point test the valves within the nquired time was
a Violation (50-254/97014-01c; 50-265/97014-01c) of TS 4.0.E. This LER is closed.
Ma.4 [ Closed) LER 50-254/97016-00: Diesel Generator Cooling Water Inservice Testing
Requirements not Completed. Licensee operating surveillance procedure,
QCOS 6800-08, * Quarterly % Diesel Generator Cooling Water (DGCW) to Unit 1 and
Unit 2 ECCS (Emergency Core Cooling System) Room Coolers Flow Test," was intended
to be performed for both units. However, the licensee's scheduling process tested Unit 2
components, but did not schedule the test for Unit 1 components. Afterwards, the
licensee completed the surveillance for Unit 1. The licensee issued two predefine work
requests for the surveillance test.
This surveillance test was required by TS 4.0.E , inservice testing and inspection of
ASME Code Class 1,2, and 3 valves. The failure to complete QCOS 6600-08 for Unit 1
20
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__________ _ _____ _ _____ _ _ - _ -_______ _____ - ______- _ - __ _ __ _ _ - -
for the second quarter 1997 was a Violation '50 254/97014 01d; 50-265/97014 01d) of
TS 4.0.E. This LER is closed.
Ill. Enn'neerina
E1
Conduct of Engineering
hpl.gs1Qttga_Ir,formajion Tran1mittals SO40 Oll-0296 AND 0302
i
E1.1
,
s.
kapt@_qnSoppa f71707. 37501)
The laspectors reviewed Nuclear Design Information Transmittals (NDITs)
SO40-QH-0296, dated February 14,1997, and SO40 OH-0302, dated Mare.h 4,1997, to
verify compliance with TS and UFSAR requirements. Nuclear Design Information
Transmittal SO40-QH-C296 evaluated battery loads based on abnormal operation of the
Units 1 and 2 HPCI emergency oil pumps and the Unit i HPCI tuming gear. Nuclear
Desi- t Information Transmittals SO40-QH-0302 evaluated the effects on the Unit 1
safety-related 250 Vdc battery with Unit 1 at power supplying 250 Vdc busses 1,1A,18,
2A and 28 a!ong with the Unit 2 safety-related 250 Vdc battery undergoing a service test.
Each of thess NDITs had Sargeant and Lundy (S&L) calculations attached to support the
conclusions documented in the NDITs.
b.
Observations and Findinas (b1726)
Calculation PMhD 891377-01, Revision 10, dated March 4,1997, identified a change to
the most limiting load profile on the Unit 1 & 2 *250 Vdc Safety Related Batteries' as a
main steam line break outside containment. Previously, an intermediate loss of coolant
accident was considered the most limiting case. The inspectors reviewed supporting
documentation within calculation PMED 891377-01 and identified the following conc.ims:
The battery Flzing calculations, dated Fcruary 13,1997, that were included in
e
NDIT SO40-QH-0296 utilized 65T. as tha lowest expected electrolyte
temperature. The correction factor of 1.08 for this electrolyte temperature was
used in uetermining the number of positive plates required for the battery to meet
the design load profile. However, updated TS 4.9.C, issued in the fall of 1996,
identified the lowest electrolyte temperature as 60', which required a temperature
correction factor of 1.11, Thereforo, by using the 1.08 factor versus 1.11, the
sizing calculations were non conservative. The use of the incorrect temperature
did not reduce the battery capacity margin a significant amount, and the
safety-related 250 Vdc batteries remained operable. The use of the wrong lowest
expected electrolyte iemperature as a design input to o battery sizing calculation
was si Violation (SJ-254/97014-052; 50 205/97014-05a) of 10 CFR 50,
Appendix B, Criterion lil, " Design Control."
The worst case 250 Vdc battery load profile was based on assumptions in
e
calculation PMED 891377-01, Revision 10. One of the assumptions used in the
calculation was the failure of the unit emergency diesel generator (EDG).
However, in 1993 the de turbine emergency oil pump (EOP) was removed as a
load from the safety-related 250 Vdc battery and placed on a nonsafety-related
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banery. Calculation PMED Sg137741 was revised to remove the de turbine EOP
from the battery load pronie. However, the review and design vert 6 cation of the
ravised Ma%, and other subsequent revisions, failed to idenufy that with the
'
unovel of the dc turbine EOP the failure of the M (swing) EDG would result in
the worst case pronie. The assumed failure of the M EDO would resuM !n the
I
unintermptible power supply (UPS), a 7G amp load, being powered from the
j
C:Fi::f 250 Vdc battery. The failure to idenufy a change in a design basis
assumption in 19g3 due U a mod 46 cation was another example of a
'
Vleistion (50-254/97g1445b; 50-285/97014 05b) to 10 CFR 50, Appendix B,
-i
'
CrNorton lil, * Design Control.'
The inspectors noted that station engineering persegnol did not have a thorough
c
understanding of the design basis of the aatety-related 250 Vdc battery system.
l
'
Questions regarding the loart proRio and the test soceptance critoria were initially posed
'
to the engineering staff in April, shortly after the test was performed. However, complete
answers were not provided to the inspectors until August. Battery sir.ing and load pronle
coloulations were performed by S&L and M appeared to the inspectors that transmitted
i'
data and results required for the testing did not recolve an in-depth site engineering
review prior to use.
t
'
c.
Conclosigns
Errors in 84L calculation PMED 8g1377-01 were indicative of a lack of attention to detail
in the design verification process of calculationc. Other minor problems were identified
with the calculation and the NDITs (that is; wrong calculation referenced, clarity, etc.) that
also substantiate the need for management attention in engmeeting activities. The
<
licensee has recently established a engineering assurance group (EAG) in April igg 7.
,
Part of the EAG's responsibilities would be to perform a sample review, as an overview
function, of calculations. Due to the EAG's recent establishment, the effectiveness of the
'
EAG could not be determined.
,
.
The inspectors considered the change to the limiting load profile of the 250 Vdc battery
system to be important design basis information and expected that station engineering
personnel would have detailed knowledge of the design basis.
But in addition to lack of attention to detailla the design verification process, the
inspectors were concemed that station engineering personnel did not have a thorough
understanding of the design basis for the safety related 250 Vdc battery system. This
was evident by the initial inability to answer questions regarding the limiting load profile
for t'i s 250 Vdc battery system and the length of time to provide answers to those
- questbns.
E1.2 Poor Comrpunication in Backlog ReductienEfforts
i
s.
Inspection.8 cope (71707)
The inspectors reviewed a list of engineering requests which had been canceled by
engineering, to determine impact en other departments.
.
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2
22
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.-2.
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c,-
..
b.
Observations and Findinas
During the review, the inspectors leamed from a supervisor in another department that an
engineering request he was counting on for cathodic protection system improvements
had been canceled without his knowledge. The inspectors spoke with plant management
representatives who later indicated that the engineering requests had been cav.eled
inappropriately and without proper review by Operations. Some of the engir eering
requests which had not been reviewed by Operations for cancellation included HPCI push
button start modification work,1 A air ejector booster modification, heat tracing for diesel
fire pump lines, and hot short protection valve bgic modification.
The inspectors learned of another backlog reduction effort which involved engineering
requests, action requests, nuclear work requests, PlFs and other items with high backlog
numbers. A team was formed this period to reduce these backlog numbers with such
intended methods as the screening team voting on canceling old nuclear work requests
and engineering requests, and deleting nuclear work requests from the maintenance
backlog when there was an engineering action associated with the request. After further
managiment review, the licences decided not to delete work requests from backlog
numbers simply because a supporting engineering request was needed.
c.
ConclusioD.1
The inspectors found that station management was not fully aware of the nature of the
backlog reduction screening efforts being attempted, and that Operations did not have
sufficient understanding of the process to ensure that required items were being properly
tracked and not inappropriately canceled. Poor communications between engineering,
operations, and maintenance personnel was evident in both backlog reduction efforts.
E1.3 quality of Enalneerina Safety Evaluations
a.
Agapection Scong (37551)
The inspectors reviewed various safety evaluations and screenings associated with
maintenance and surveillance activities. The inspectors also reviewed vnrious PlFs and
temporary alterations.
b.
Observations and Findinal
Control Rod Drive P-4
The inspectors observoo Unit 2 opteators perform weekly control rod surveillance tests.
However, a poor electrical contact in the control rod logic circuit inhibited operators from
moving control rod P-4. In order to complete the surveillance test, operators reques%l
maintenance personnel to install a jumper around the poor electrical contact. Since
late July, maintenance personnel controlled the installation and removal of the jumper
with a work package and Quad Cities Instrument Procedure (QCIP) 100-13, Ma'.ntenance
Alteration Procedure." Maintenancs questioned whether the practice of installing and
removing the jumper weekly bypassed the more cumbersome temporary alteration
process. The licensee documented t.ie issue on a PIF Q1997 3290.
23
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The inspac. tors noted this practice did not inhibit control rods from scramming but resalted
in periodicalty blowing of a % amp power supply fuse. The inspectors also noted this
condition was not listed on the operator work around list. However, the licensee planned
to correct the deficient condition during the upcoming planned maintenance outage, in
response to the PlF, operations changed QCOP 0300-01 to sequence and control
installing and removing the jumper. Subsequently, operators imerted Rod P-4 and took
the rod out of service to avoid the need of installing and removing the jumper from the rod
control system.
The inspectors consider the addition of a jumper to the rod control system to be a change
to the facility as oescribed in the UFSAR and required 10 CFR 50.59 screening to
determine if the addition of the jumper constituted an unreviewed safety question. The
licensee did not perform a 50.59 screening of the addition of the jumper until the
QCOP 0300-01 was changed. This licensee identified and corrected violation is being
treattd as a Non-cited Violation (50 254/97014 06; 50-265/1#7014-06) consistent wit i
Section Vll.B.1 of the NRC Enforcement Policy.
Jumoerina Out Alarms for Fire Diesel Pumos
The inspectors reviewed Temporary Alteration Package 97127 written on August 16,
1997, to jumper out the remote alarm capability on the % A and M B diesel driven fire
pumps. The Inspectors identified the 10 CFR 50.59 screening criteria used to ensure an
unreviewed safuy question was not involved mentioned the design requirements of the
remote alarms but did not Odequately justifv their removal. The UFSAR Section 9.5.1.2.0
indicated that standards of tile National Fn Protection Association (NFPA) corte were
followed for fire pump installation. The !.FPA code required both local and remote
annunciation of low oil pressura, high Acket water temperature, failure to start and
overspeed conditions. Temporary A'ioration 97127 failed to discuss these requirements
and why tha removal of the alarm fun:tions did not constitute an unreviewed safety
question. After the inspectors spoke to licensee management, engineers performed a
more thorough review which indicated that an unreviewed safety question was not
involved. Engineering management reviewed this event with engineering personnel.
Ucensee Findinas and Response
The licensee acknowledged weaknesses in adhering to the safety evaluation processes.
Tne licensee identified a wer safety evaluation on a problem associated with the
Unit 2 "C" reactor feed pump. I'his, and other insoector and licensee identified problems
associated with the safety evaluation process, resulted in the Engineering Assurance
Group documenting the process weaknesses on PlF Q1997 3530. The EAG noted some
safety evaluations lacked sufficient information to become quality products. As an interim
musure, engineering required a third party review of all 50.59 reviews in an attempt to
impmvec quality. The licensee was assembling a root cause evaluation team to determine
appropriate corrective actions,
c.
Conclusions
The inspectors concluded engineering processes used to ensure equipment was in
compliance with design requirements were not followed on some occasions. Specifically,
there was no design review for adding a jumper to allow movement of Rod P-4. In
24
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addition, t a Wcial des 1 n review for the fra diesel pump temporary alteration was
9
inadequne. the inspectors concluded engineering and management displayed a poor
understanmg of design change requiremems. Engineering planned third party reviews
as an interim corrective action.
E1.4
Failure to Assure Deslen Basis Recutrements of Safe Shutdown Makeuo Pumo System
a.
Inspection Scone
The inspectors reviewed surveillance test, QCOS 2900-01, Revision 12, "Quarterty Safe
Shutdown Makeup Flow Rate Test,' to assure the test acceptance criteria met
TS requirements and were within the design basi.i of the plant.
The SSMP system was designed as a backup for the reactor core isolation coo'ing
(RCIC) system as part of 10 CFR 50, Appendix R, Section lil.G, " Fire Protection and
Safe Shutdown Capability."
b.
Observations and Findinas
Quad Cities Operational Surveillance 2900-01 acceptance criteria required the
SSMP supply a minimum of 400 gpm, at a minimum pump discharge pressure of
1219.5 psig. This surveillance test was based on original 8 & L calculations which
indicated that with 1219.5 psig at the discharge of the pump and a design flow late of
400 gpm, the system would supply water to the reactor core at the required pressure of
1120 psig. When asked by the inspectors, the licensee could find no documentation that
the tolerances of the installed instrumentation were included into the acceptance criteria
for the pump discharge flow and pressure,
in late July 1996 the system engineer had generated an engineering request,
Engineering Request (ER) 9604270, to address the concem that the discharge pressure
of the safe shutdown makeup pump had degraded and might not be adequate, and
requested a design basis calculation to reconcile instrument accuracy, sensing location,
and plant conditions assumed in the design basis, in September 1996 the SSMP system
was included into the TSs without resolution to ER 9604270. An adequate design basis
calculation was not performed to substantiate the system test acceptance criterta by
taking into r'onsideration instrument accuracy and sensing location. Consequently, the
licensee did not assure the SSMP systera met the TS requirements for system
operability. This was a Violation (50-254/97014-07; 50-265/97014-07) of 10 CFR 50,
Appendix B, Criteria XI, " Test Control' and TS 4.8.J.2.
Following the inspector's identification of this issue, the licensee ran an additional
surveillance test using high accuracy instrumentation. Th!s test verified that the installed
instruraentation was within the tolerance ranges of the high accuracy instruments. The
licensee 6etermined that the acceptance criteria for Unit 1 could not be assured using
only the installed instrumentation. The licensee then declared the SSMP system
inoperable to Unit 1, pl. icing the unit in a 67-day limiting condition for operation (LCO),
while design basis calcelations were verified. The SSMP system to Unit 2 was not
declared inoperable because, due to fewer line losses, the licensd hau a high degree on
confidence that the design basis was met.
25
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c.
canaluelens
.
The licensee failed to act on a system engineer's identification of the unresolved design
basis issues conooming the SSMP system. Consequently, the licensee did not provide
4
i
calculations and validate throug'i testir.g that the TS test acceptance ortteria were met for
SSMP flow and pressure.
E2
Engineering Support of Foollaties and Equipment
.
E2.1
Ooerable but Dearaded Eauloment Lists
a.
Innoodion Sonne (37551)
The inspe::lors reviewed the' licensee's *Open Operability Determinations Log," a Quality
'
and Safety Assessment (QSA) audM and PlFs.
b.
Observations aridfindinns
Due to fouling, icom coolers for the Unit 2 'A' Core Spray Room and "B' Residual H6at
= Removal Room were classified by engineering as " operable but degraded." However, the
inspectors identified that this equipment, and other degraded safety-related equipnient
,
were not included in the "Open Operability Determinations Log" maintained by operations.
This included instalianon of jumpers to remove the alarm functions for both fire diesel
pumps, leakags past the seat for the UnN 2 38 power operated relief valve, a potential
1
condition for the UnN 2 omorgency core cooling system suction strainers to be made of
'
,
improper material, and others. The inspectors spoke to licensee management of these
concoms. The licensee identified that two separate lists of operable, but degraded
'
equip.,iont existed, but were not consistent.
'
The QSA group audited both lists maintained by engineering and operations and
identified the following:
'
three issues on the engineering list were not evaluated for operability corums
seven items on the engineering list which had been reviewed via the PIF proc 6,ss
+
<
had not been evaluated via the operability determination procedure
.
four Mems on the operations list were not on the engineering list
.
eight issues on the operations list newed to be resolved prior to startup from the
+
upcoming planned maintenance outage (Q2P01). Only two of the eight items
were included in the scope of Q2P01.
In Generic Letter g1 18, " Resolution of Degraded and Nonconforreting Conditions," the
NRC lasued guidance on how degraded or nonconforming cond;tions shodd be resolved
commensurate with the safety significance of the issue. The inspectors noted in some
-
instances above, the licensee had not fully evaluated the nature of the degraded
l
condition, and what action wouk' be needed to resolve the condition in a time
,
commensurate with the safety significance.
o
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,
c.
Conduaiana
Lists of important equipment considered operable but degraded were not servlinised well
tr/ either engineering or operations. In some cases, there were no plar,s on when or now
to remove equipmerd from a degraded status. The inspectors concluded the iioensee
displayed a lack of riger in ensuring importard equipment wculd be brought back into
compliance with design requirements within a timely manner.
E2.2
facility Adherence to the Um
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 inspedors reviewed the
following sections of the UF8AR:
'
IR Section
UFSAR Section
Apolicability
M1.2
8.3.2.1
250 Volt Station Battery
-
-08.3
2.4.4,g.2.5
For the sections reviewed, the inspedors did not identify any discrepancies between plant
configuration and design basis as described in the UFSAR.
E7
Quality Assurance in Engineering Activitica
E7.1
Review of 50.54m Performance Indicator Accountina
a.
Inspection Scope (40500)
By letter dated January 27,1997, the NRC required the licensee to provide additional
information pursuant to 50.54(f) for plans to measure performance improvement at each
Comed nucisar site. - In a response dated March 28,1997, Comed committed to track
each nuciosi station's performance using standard industry indicators on a monthly basis.
The inspectors reviewed three performance indicators reported by the licensee to
corporate. The inspedors reviewed how the licensee complied with the counting
guideline provided by corporate in the desktop instruction manual for three performance
I
inoicators. These performance indicators included temporary alterations, engineering
'
requests (ERs), and ERs overdue,
b.
Observations and Findings
'
l
The inspectors determined the temporary alterations counted at the station and reported
l
to corporate were different. However, the instruction manual allowed for not counting the
following as temporary alterations: ventilation dampers wired open, installation of
- furmanMe clamps, or installation of recorders. After reconciling the reported list with the
-
instructions, the inspedors believed the number of temporary alterations reported offsite
I
- were accurate.
.
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{
The Lg: As determined the method for counting ERs and ERs overdue was not in
!
eewf': .ee with the desktop instruction manual. Spoolfically, ERs counted at the site and
!
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reported to corpwate did not include parts evaluations and requests for design changes.
!
Similarly, the station only counted 2 of the 19 types of ERs for the ER overdue count.
i
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The instruction manual required all Priority A and 8 ERs, regardless of ER type, be
.
1
counted.
i
The licensee acknowledged the weakness and admittsd the counting process was still
not consistent between sites. The various sites met to develop a more standardized
,
method of reporting the ER numbers,
i
Section E1.2 of this report documents problems identified by the inspectors where
ER bacidog reduction efforts were not well reviewed, understood or communicated
2
throughout the station.
,
,
- i
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c.
Conclusions
l
"
i
The inspectors concluded some temporary alterations at the site were not included in the
j
count of performance indicatosi. However, the temporary alteration indicator was in
'
compliance with the instructions. The inspectors determined ERs and ERs overdue were
l
not counted in compliance with the !nstructions. The inspectors noted the licensee was
j
attempting to reconcile differences in their counting methodologies to ensure that all sites
were counting the performance indicators consistently. This would allow a better
comparison of performance between Comed sites. The inspectors noted that some
>
efforts to reduce the ER backlog were not reviewed or understood throughout the station.
i
E4
Miscellaneous Engineering issues (92902)
,
' E8.1
(Closed) Unresolved item (URI) 60-254/922&911Q-291/91201-02: This URI had four
'
concams. Concem 2 was no (4ssessment of the effect of higher flows on Unit 1 and Unit
% DGCW pumps and was closed in Inspection Report No. 50 254/92025(DRP);
,
50 265/92025. Concom 3 was the % DGCW pump had not demonstrated meeting the
demands of the M DG Heat Exchanger (HX) and the Unit 1 Emergency Core Cooling
Oystem (ECCS) pump room coolers; and wcs closed in Inspection Report
i
No.50 245/95004(DRP); 50-265/95004(DRP).
l
Concem 4 was an operability question with the Unit 2 DGCW due to unsuccessful flow
'
.
balancing in that most distributions to the individual Unit 2 ECCS room coolers were
L
unknown. The licensee installed flow instrumentation for each of the Unit 2 ECCS room
coolers by Design Change Package (DCP) 9540. The DCP was declared operable on
May 29,1997. The flows were continuously observable and appropriately trended
.
against conservative criteria. Concem 4 is closed.
.
Concem 1 was the Unit 1 DGCW flow was unbalanced and distributions to individual Unit
1 ECCS room coolers were unknown. The differential pressure (D/P) across each Unit 1
ECCS room cooler was well trended by QCOS 5750-9 except during a 7 month period
'
due to an improper engineering tumover (This was considered a Deviation in inspection
Report No.50 254/96010(DRP); 50 265/96010(DRP)). If adverse D/P was detected, the
'
licensee was required to document the condition on a PIF. The licensee would then
inessure flow with a Controlotron Ultrasonic Flowmeter. Any adverse flow detected
i
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>
required an evaluation and the room cooler cleaned if necessary. The licensee was
'
planning on revising QCOS 5750 9 to measure Controlotron flow monthly for t'l Unit 1
ECCS room coolers. Some scaffolding had been installed to facilitate Controlotron
'
measurements. Signi6 card portions of DCP 95 57 had been written to instaN permanent
flow instrumentation for the Unit 1 ECC8 room ooolers and was scheduled for
'
implementation during the UnN 1 Refueling Outage Q1R15 in September of 1998.
!
Concem 1 is closed. This URIis closed.
!
y
E8.2
(Closed) IFl 80 254/93003-01: 50 265/93003-01: The M Diesel Generator Cooling Water
.l
t
Pump Transfer Starter Panel 2251 1H Components Were Not in Preventative
j
Maintenance Progmm. The inspectors vert 6ed the licensee wrote and tracked a
preventive maintenance hem (PM ID 104293) for components on DGCW pump starter
panel 2251 10-0. The electrical maintenance prede6ne coordinator ensured the hem was
!
performed on a 3-year frequency as prescribed by Quad CHies Electrical Maintenance
!
Surveillance (QCEMS) 0250-06, * Exhaust Fan and Room Cool 6r Motor Environmental
!
Quellfloation Surveillance," Revision 7. The panel was specifically delineated in
!
q
Attachmerd F of the procedure, This item is closed.
l
E8.3 (Closed) LER 50 254/94002-00: *B" Control Room Emergency Ventilation (CREV) failure.
,
This LER documented the inoperabilty of the "B" CREV system due to the failure of a
!
4
compressor motor contactor on January 4,1994. The failure of the contactor was
1
'
attributed to cumulative cycling. One cause of the cycling of the contactor was a resuN of
i
the compressor being sized such that it will handle the heat load under extreme
l
conditions. Under normal operating conditions, the compressor frequently cycles as
opposed to running continuously with its load being modulated. A previous cause of
cycling the contactor was the control of cooling water to the condenser which frequently
caused trips / restarts of the compressor resulting in additional cyales of the contactor.
Corrective actions in response to the event included contactor replacement and changes
to operating procedures to bettes control cooling water flow to the condenser. Planned
corrective actions documented in the LER included the insteilation of a hot gas bypass
3
system for the compressor to reduce cycling by inducing a larger heet load on the
'
- compressor to better match its capacity. In the cover letter transmitting the LER to the
NRC, dated January 29,1994, the licensee committod to the NRC to install the
!
l.
- B" CREV hot gas bypass system. In August 1997 the inspectors reviewed the LER,
l
spoke with engineering staff and determined that the system had not been installed and
!
that design work on the modification had essentially been stopped. The failure to
accomplish this actiot, was a Deviation (50-254/97014-08). This LER is closed.
,
'
E8.4
(Closed) URI 50-254/94004-17: 50-265/9400417: Inoperable Heat Trace Line from Unit
1 Standby Liquid Control (SBLC) Tank to One of the Pumps. The NRC's Diagnostic
.
!
Evaluation Team (DET) identified this condition in September 1993. By November 1993
the licensee had replaced the entire heat tracing system for the SBLC systems for both
units. The replacement systems were improved and have had greater reliability. The
>
minimum low temperature alarm setpoints for both the piping and tanks were increased
!
from 78 to 83* F. The inspectors verified during a walkdown that the new system was in
good material condition with the new controllers indicating 95 ?F. which was their nominal
setpoint. This item is closed.
,
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E8.5
(Closed) URI 50-254/94028-02: 50 265/94028-02: Inadequate Residual Heat Removal
l
Service Water (RHRSW) Surveillance. The inspectors observed that surveillance testing
for the RHRSW room cubicle cooler did not contain limits for acceptable differential
pressure across the cooler. The licensee revised the procedure and established criteria
but concluded that differential pressure measurements alone could not establish
operability of the cooler. The licensee relied on periodic cleaning of the coolers and
differential pressure measurements to assess operability. If differential pressure criteria
,
were not met, engineers measured flow with a portable ultrasonic flowmeter since no flow
,
gauges were installed. Similarly, other required ECCS room coolers did not have
instatied flow gauges. The NRC issued a violation in Inspection Report
No.50 54/97006(DRP); 50 265/97006(DRP) since appropriate corrective action was not
taken in a timely manner to measure flow through the core spray room coolers after
differential pressure measurements exceeded the survelliance procedure acceptance
criteria. This item is closed.
E8.6 (Closed) IFl 50-25E9.5005-03: 50-265/95005-03: Long Term Use of Temporary Sealant
Repair. The inspectors verified that a permanent repair to the leaking 2A recirculation
pump flange was completed during refueling outage Q2R14. This item is closed.
E8.7 (Closed) IFl 50-254/96002-12: 50-265/96002 12: The UFSAR Needed to be Updated to
Reflect the Frequency of a Full Core Off-load and Previous Licensing Commitments. The
licensee revised procedures and updated the UFSAR. Allissues were addressed in the
most recent UFSAR revision annotated Revision 3, December 1995 except for the
clarification conceming storage of other than GE 8x8R fuel. On February 19,1997, a new
nuclear tracking system (NTS) l tem svas opened by the licensee to track this issue. On
September 9,1997, the licensee closed this NTS item. All General Electric fuel critically
analyzes use of one of two methods described in UFSAR section 9.1.2.3. For the
ATRIUM-9B Siemens fuel the licensee will use an analysis as submitted to the
Quad Cities Regulatory Assurance staff on April 23,1997, for incorporation into the
UFSAR. This item is closed.
E8.8 (C.lgytp)_1FI 50-254/9QM2-13: 50-265/96002-13: Problems With Safety-related
.
Control Room Emergency Ventilation (CREV) System. Early in 199C the inspectors noted
numerous equipment problems with the CREV system leading to high unavailability of the
system. The licensee determined the high system unavailability was due to poor work
pisnning and scheduling, several design deficiencies, and a lack of a preventative
mainter,ance program. Subsequent to inspection Report No. 30-254/96002(DRP);
50 265/96002(DRP), in Inspection Report No. 50-254/96017(DRP); 50-265/96017(DRP),
the inspectors documented more design and testing deficiencies with the system. The
NRC lasued two Severity Level IV violations after conducting an enforcement conference
with the licensee. The licenses completed work to restore the system to its original
design basis. The inspectors noted a decreased number of equipment problems since
these efforts were completed. This followup item is closed.
EB.9
(Closed) LER 50-254/96008-00: TS Pressure not Achieved During a Local Leak Rate
Test (LLRT). In response to NRC Information Notica 9613, " Potentia! Containment Leak
Paths Through Hydmgen Analyzers," the licensee identified the containment atmospheric
monitodng inlet piping was not pressurized to 48 pounds per square inch as required by
TS 4.7.A. The licensee determined the cause of the event to be a deficient procedure.
The licensee corrected the procedure.
30
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The inspectors determined this was a non-cited violation (50-254/9600815;
50-265/96008 15). The inspectors reviewed the licensees corrective actions. This
LER :s closed.
E8.10 (Closed) Violation 50-265/96010-01: Incorrect Replacement Torus Suction Valve Weight
Used in Safety Evaluation Review. In July 1996 NRC inspectoia were concemed that the
licensee's design review process had failed to identify the consultant's use of the
incorrect valve weight even though no major hazard had been caused. The licensee
conducted an investigation to determine the root cause and any other related conditions.
l
in response to the viol? tion the licensee stated that: (1) even though the documentation
from the consultant indicated to the licensee that the new weight had not been property
taken into consideration, it had been by the actual analysis methodology; (2) some of the
licensee staff had beer, made aware by phone that the correct weight was taken into
consideration but no documentation of the phone call's discussion could be found; (3) the
desl(,n review requirements of Nuclear Engineering Procedure (NEP) 12 03,
- Nuclear Design I". formation Transmittals (NDITs)," Revision 0, will be more assidcously
enforced in the future; and (4) an engineering department training sess;on to
reemphasize the NDIT design review requirements of NEP 12-03 was held during the
depsrtmental meeting on October 1,1996. The inspectors reviewed the licensee's
followup investigation, and immediate and long-term corrective acitons and found them to
be thorough and acequate. This violation is closed.
E8.11 [Ocen) IFl 50-254/96011-06: 50 265/96011-06: Evaluation of Pipe Whip Impingement
Plate Alteration. While resolving improperlyinstalled concrete expansion anchors
(CEAs), the licensee identified a questionable mounting support for high energy line break
impingement plate 2.JIHP 3. The inspectors reviewed Calculation No. 5061-00 EP 82,
Revision 4, which evaluated this support configuration. After noting that a safety factor of
2.0 was used to qualify the existing CEAs, the inspectors asked the licensee why the
standard safety factor of 4.0 was not used. This was subsequently provided in.
Calculation No. QDC-0000 S 0210, Revision O. After reviewing this information and
discussing it in detail with the licensee, the NRC disagreed with the licensee's technical
arguments justifying their use of the safety factor of 2.0.
The NRC determined that additional analyses and/or anchor bolt capacity upgrades would
be required for high energy pipe whip restraints, in order to meet the CEA manufacturers'
recommended capacities. The NRC staff considered the criteria for CEAs given in
NRC Bulletin 79 02 and in Revision 2 of the Generic Implementation Procedure
developed by the Selcmic Qualification Utility Group for Unresolved Safety Issue A-46 to
be acceptable. Pending a review of the licensee's schedule to complete the additional
analyses or upgrade the anchorage capacity, this item will remain open.
EB.12 LGpsed) LER 50-254/96022 00: "B" CREV System Unable to Maintain 1/8" D/P. The
inspectors verified work was completed to restore the system to its design basis as
described in the UFSAR. Testing conducted on April 22,1997, verified the system could
maintain 1/8" D/P in the control room emergency zone. The inspectors verified that the
licensee submitted to the NRC a revised control room habitability study as committed to
in the corrective actions described in the LER. This LER is closed.
E8.13 (Closed) LER 50 254/97003-00: Missed Visual Examination of High Pressure Coolant
Injection Check Valve. On April 29,1997, the licensee identified a failure to visually
31
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examine the Unit 1230145 check valve. As required by the ASME Code for Class 1,2,
and 3 components, the licensee was required to perform a visual examination following
replacement of the valve. The licensee declared the system inoperable until a qualified
inspector examined the valve in accordance with code requirements. The licensee
attributed the missed visual examination to inadequate procedures.
TS 4.0.E required inservice inspection and testing of ASME Code Class 1,2, and 3
components after rt...acement. Failure to perform the required ASME Code visual
inspection constitutes a Violttlon (50 254/97014-01e; 50-265 97014-01e) of TS 4.0.E.
This LER is closed.
IV. Plant Support
R8
Miscellaneous Radiation Protection and Chemistry lasues
R8.1
LQlosed) LER 50-265/97010-00: Missed Chemistry Surveillance. With the Unit 2 *B"
offgas hydrogen analyzer inoperable TS Table 3.2.H 1 required a grab sample of an 8-
hour frequency. On August 19,1997, chemistry technicians missed taking an 8-hour grab
sample from the Unit 2 offgas system. This event was due to a human error. The
licensee counseled the individual. The failure to take the TS required grab sample from
the offgas system was cunsidered a Violation (50-254/97014-01f; 50 265/97014-01f) of
TS 3.2.H. This LER is closed.
F1
Control of Fire Protection Activities
.
The inspectors reviewed several activities related to fire protection and safe shutdown
components, and the related operational maintenance, and engineering activities involved
with supporting these components. Problems with inoperable fire pumps, inoperable safe
shutdown paths, inoperable sprinkler systems, poor tracking of actions needed to track
degraded components, and poor engineering reviews all led to an overall weak
performance in fire protection activities. Some response to safe shutdown p:tblems
discovered by the licensee were considered good.
F1.1
Problems Associated with the "A" Fire Diesel Pumo
a.
Inspection Scooe
The inspectors observed maintenance, testing and troubleshooting activities associated
with the % A diesel fire pump.
b.
Observations and Findinal
After performing annual maintenance to the % A fire diesel pump, the licensee tested the
pump in accordance with QCMMS 4100-32, *% A Diesel Driven Fire Pump Annual
Capacity Test." Having been informed by an insurance representative that alarm testing
for the diesel driven fire pumps was inadequate at Quad Cities because initiation of the
alarm at the sensor was not performed, the licensee corrected the procedure to include
initiation at the sensor (for low oil pressure and high Jacket water temperature). When
testing the alarms with initiation at the sensor, it was discovered that the alarm circuitry
32
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- caused the M A diesel to trip on overspeed. A review of the troubleshooting and repair-
offorts is discussed below. A near miss personnel safety issue occurred during the
testing and is documer6d in sodion M1.3.
Troubleshootina Efforts
Troubleshooting activihes were initially poor. Some of the problems included:
A troublemhooting plan which was expected by the maintenance supenntendent,
was not used. A roct cause evaluation process was not used for several days of
the activity.
The inspectors noted that maintenance history indicated a number of similar
+
failures on both the M A and M B fire pumps since 1993. The root cause for
'
these failures had not been determined in many cases, and trending of the -
problem was not readily available. Maintenance rule evaluations were not
adequate to justify that the failures were not to be considered maintenance rule
j
functional failurer. Resolution of this asp"d is being reviewed in the maintenance
rule inspection (see inspection Report No. 50 254/97017(DRP);-
50 265/97017(DRP)),
!
When initial troubleshooting led technicians to replace the electronk govemor
+
(speed switch), the switch was not adjusted property during instaliation. This
caused the diesel engine to overcrank during subsequent testir g.
Continuity of the repair technicians assigned to the fire pump repair effort was not
]
maintained throughout the troubleshooting process.
i
,
i
The vendor representative brought in to assist in troubleshooting was not certified
+
by the vendor to be qualified for the fire pump diesel engine.
Troubleshootirg activities continued for several days and resulted in the fire pump
i
- exceeding the 7-day administrative LCO time limit. The licensee documented this
condition on a PlF (97-3214).
After 3 days, the license put together a team and a comprehensive troubleshooting plan
to evaluate the root cause of the engine tripping. Possible failure modes were
systematically eliminated. The licensee determined that the cause of the problem was
poor instal!ation of a design modification in 1993 which replaced the mechanical govemor
with an electronic govemor. During installation, wires carrying relatively large alarm bell
currents were routed near wiring transmitting the sensitive electronic govemor speed
signal. The inductive current related to the clearing of the alarm circuit had apparently
caused the r.eart>y unshielded speed sensor circuit to sense overspeed conditions,
causing an overspeed trip. The licensee corrected the trippinn problem by jumpering out
'
the associated alarms.
The inspectors found that the licensee performed a poor review of the desig.1 basis
'
justification for jumpering the alarms (Section E1.3), and. Operations did not property
address operator action required for conditions when the diesel fire pump alarms were
inoperable. Operations had included actions for operators to attend the fire pumps during
.
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weekly surveillance operation, but had failed to adequately address actions needed
during emergency fire pump operation and during some auto stPrt conditions. Following
discussions with Operations management, the inspectors verified that the licensee
addressed these concoms with updated surveillance (QCOS 4100 series) and operating
(QCOP 4100 series) procedures .
c.
Conclusion
The inspectors found that poor initial troubleshooting efforts and other maintenance
problems such as improper govemor installation delayed the completion of fire pump
work within the administrative LCO time limits. Later troubleshooting resulted in
discovery of a long standing problem with the fire pump. Justification forjumpering out
fire pump alarms was poor, and operator compensatory actions were not adequately
spelled out.
F1.2
Safe Shutdown Paths Inoperable
a.
Inspection Scop _t
The inspectors reviewed licensee actions upon discovery that 9 of 16 safe shutdown
paths were inoperable,
b.
Observations and Findinas
On August 26,1997, the licensee discovered that proccdures written to support taking
the units to cold shutdown conditions in the event of a fire did not support the
requirements of the fire protection report. This condition rendered 9 of 16 safe shutdown
paths inoperable because tripping of non safe shutdown path loads would not have been
accomplished. The liceasee estimated that the instantaneous fire risk associated with
having nine safe shutdown paths and % A pump inoperable during dual unit operation
would have been approximately 2.7E-03 per reactor year. The licenses took quick action
to correct the procedure discrepancies, began an investigation of the cause of the
discrepancies, and reported the condition on LER 50-254/97021. Previous procedure
problems had been identified in earlier LER reviews, and will be looked at as part of the
review of this LER. Review of this item will be accomplished following the licensee's
review, and tracked as part of followup to the LER.
c.
Conclusions
The inspectors noted that the already relatively high risk associated with fires at
Quad Cities was made even higher by procedure discrepancies in 9 of 1S safe shutdown
paths. Licensee action upon discovery was good, but previous corrective actions for
other LERs and subsequent corrective actions must still be evaluated.
34
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F1.3
Poor Corrective Action for Fire Protection Problems
f
a.
Insoection Scope
1
The inspectors observed licensee corrective action for several fire protection issues,
j
including management meetings, action plans for equipment repair, and observation of
compensatory actions in place.
i
b.
Observations and Findinos
The inspectors found operators and managernent to be insensitive to inoperable
fire-related protection equipment problems. Some of this insensitivity appeared to be in
part to a history of equ'pment exceeding administrative LCO times at Quad Cities.
Fire Pumo Dearadation Corrective Action
Since June 27,1994, fire impairment FM-94-152 had been inoperable due to hydraulic
concems with the wet pipe suppression system in the Unit i heater bay. This system has
a 14-day limiting condition for operation action statement which was controlled
administratively (fire protection requirements were removed from Quad Cities TS). On
January 13,1995, fire impairment FM94152 was transferred to FM-95-23. Two other
impairments wero addr.6 on January 1.' "o95, due to hydraulic concems with wet pipe
systems in the Unit 2 heater bay and b .41 Southeast Residual Heat Removal comer
room. Although the LCO time was 14 days, these impairments we~ in effect for over 3
years in some cases without resolution, using fire watches as compensatory actions.
Quad Cities Administrative Procedure (QCAP) 1500-1 * Administrative Requirements for
Fire Protection," only required a non-reportable PIF to be generated when the 14 day LCO
time limit was exceeded.
The hydraulic concems were due to degraded performance of the stations' two diesel
driven fire pumps. The licensee had informed the inspectors on several previous
occasions that a modification was planned and approved to correct these problems with
degraded fire pump performance and to correct problems with zebra mussel blockage of
the fire pump suctions. (Modification number DCP 9600045 was approved for work on
September 24,1996.) The inspectors were informed during this inspection period that
the approved modification had been put on hold due to funding concems. Although
knowing about the funding concems since June 1997, the licensee had no plans in place
for improving fire pump performance and/or correcting the hydraulic impairments. The
inspectors also found that during the recent % A and B fire pump testing, additional
degradation of fire pump flow was noted. In total, a degradation of about 6 percent was
noted since the fire pumps were rebuilt in the 1993 time frame. While this only
exacerbated the original hydraulic impairment problems and did not cause any additional
systems to be inoperable, it did point to the continuing need for effective corrective action
for fire pump problems.
Poor Heater Bay S.prinkler Corrective Actions
On September 8 the inspectors questioned the unit supervisor for Unit 1 about a log entry
mgarding an inoperable sprinkler in the Unit 1 heater bay. The unit supervisor informed
the inspectors that on September 6 a sprinkler head in the heater bay wet pipe system
35
began flooding the heater bay, requiring operators to isolate the entire wet pipe system
for half of the heater bay. When asked about compensatory actions for the isolation of
the wet pipe systern, the unit supervisorindicated that the system was the same system
already in a hng term impairment (since June 1994) and no additional corrective action
other than the fire watches for the original impairment were required.
The inspectors were concemed because the originalimpairment required fire watches
due to a degraded flow condition (about 5 gpm degradation from required flow.) The
problem resolution on September 6 caused the suppression system to have zero flow.
No effective plan for short term maintenance corrective action had been identifieri until
after September 10 following inspectors discussions of the problem with senior station
management. The original plan developed then focused on waiting until hydrogen
injection was scheduled to be tumed off on September 17 (for dose minimization
concems), or 12 days into the period of the isolated wet pipe system. The inspectors
asked station management why the priority was so low that either hydrogen injection
could not be tumed down earlier or reactor power could not be reduced to minimize dose
and complete the work earlier. In the discussion, inspectors pointed out that hydrogen
injection was being tumed off daily on Unit 2 due /o equipment problems. Eventually the
licensee corrected the problem on about September 15, after reducing reactor power to
repair another component.
During the time the wet pipe was isolated, the inspectors observed the fire watches in
place as compensatory meosure. The inspectors noticed on September 9 that cameras
in place for fire watches to monitor were not functioning, and had been noted as needing
repairs for several days. The inspectors notified the operations manager, who later called
for an investigation. The licensee found that several cameras were not providing the
picture adequately for the required fire watches, and documented this on
PlFs Q1997-03450,03437, and 03445. The condidons were corrected and fire watches
were briefed on the proper cameras to watch and what to do in the event of inoperable
cameras. Quad Cities Administrative Procedure 1500-01, Revision 6 dated February 17,
1997, Step D.2.c.2.(b) required a roving (15 mincte) fire watch be estab%hed if a water
suppression system which protects a safe shutdown system is inoperable and the
affected unit is not in a safe shutdown condition. Since the cameras which were
supporting ths hourty fire watch rounds were not fully operable, the NRC and licensee
considered this a case of missed fire watch rounds, a violation of station proc 6dures and
l
ls a Violation (50 254/97014-09; 50-265/97014 09) of TS 6.BA. Generation of a PlF was
l
the only requirement in the QCAP 1500-1 procedure for a missed fire watch and for most
missed fire protection LCOs. The PlF process appeared to be a weak vehicle to focus
station attention on risk important equ;pment and processes. The PlFs reviewed by the
inspectors were given the lowest level in significance and did not generate a higher level
review, even when LCOs were missed by long periods or when multiple systems were
inooerable.
The inspectors found that, in general, fire protection issues received relatively low priority
at Quad Cities, even when exceeding LCO times were involved. Even significant fire
protection LCOs (such as loss of water to the heater bay suppression system) did not
(
receive any significant plan of the day attention or management discussion during
l
meetings observed by the inspectors, compared to balance of plant equipment which
affected generation capability (such as gland seal level control valves.)
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c.
Conclusion
The inspectors noted an overalllack of sensitivity to fire protection issues. A number of
equipmont problems resulted in administrative LCO time limits being exceeded. Some
equipment was inoperable in excess of 3 years, with planned modifications to repair the
problems recently canceled or changed. This led str'. ion personnel to be less than
aggressive in addressing new fire protection probier.is. Fire watches were the required
compensatory actions for some of these impairments. The inspectors noted a lack of
rigor in ussuring the required fire watches were met, and a violation was cited. Problem
identification forms were not effective in focusing management attention on the fire
protection problems. This all occurred in an environment where the licensee was aware
of a relatively high fire risk at the station.
V. Manaoement Meetinas
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at the
conclusion of the inspection on September 19,1997. The licensee acknowledged the findings
presented. The inspectors asked the licdases whether any materials examined during the
inspection should be considered proprietary. No proprietary information was identirsed.
.
37
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PARTIAL UST OF PERSONS CONTACTED
!
Lh190199
W. Pearce, She Vice President
'
R. Fairbank. Engineering Manager
F. Famulari, Quality and Safety Assessment
C. Norton, operations Supervisor
C. Peterson, Regulatory Affairs Manager
G. Powell, Radiation Protection Supervisor
M. Weyland, Maintenance Manager
,
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INSPECTION PROCEDURES USED
iP 37551:
Onsite. Engineering
IP 40500:
Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing
Problems
IP 6' 726:
Surveillance Observations
IP 62707:
Maintenance Observations
l
IP 71707:
Plant Operations
IP 92700:
Onsite Followup of Written Reports of Nontouthe Events at Power Reactor
l
Facliities
IP 92701:
Followup Planned Non-Routine Activities
IP 92902:
Followup Engineering
ITEMS OPENED, CLOSED, AND DISCUSSED
Opene.d
50 254/97014 01a; 50-265/97014 01a
surveillance requirements not met during
50-254/97014-01b; 50-265/97014 01b
rnactor modes
50-254/97014-01c; 50 265/97014-01c
50-254/97014-01d; 50 265/97014 01d
50 254/97014 01e; 50 265/97014-01e
50-254/97014-01f; 50 265/97014 01f
50-265/97014 02
failure to follow procedure QCMM 1515-07
50-254/97014-03; 50 265/97014-03
NCV discrepancy in QOM check list
50-254/97014-04; 50-265/97014 04
errors in OCTS 0240-06 resulted in
performance test not being performed
per TS 4.9.5
50 254/97014-05a; 50 265/97014-05a
design basis information not correctly
50-254/97014 05b; 50-265/97014 05b
translated
50-254/97014 06; 50-265/97014-06
NCV 50.59 screening of the addition of the jumper
not performed until QCOP 0300-01 was
changed
50-254/07014-07; 50-265/97014 07
no demonstration that SSMP would perform
in accordance with requirements of
TS 4.8.J.2
50-254/97014 08
DEV hot gas bypass system not installed
50-254/97014-09; 50-265/97014-09
poor heater bay sorinkler corrective actions
Closed
50-254/94010-00
LER
unplanned scram of control rod during
surveillance
50-254/04010-01
LER
unplanned scram of control rod during
surveillance
50-254/96001 00
LER
the *B' CRVS inoperable due to inoperable
relay
50 254/96002-03; 50-265/96002 03
IFl
buildup of debris on trash rack resulted in
low water level inside intake structure
50-254/96006-00
LER
the TS 3.0.A incorrectly 8nvoked
39
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50-254/97001 00
LER
missed operations surveillances
50 254/97008-00
LER
inadequate operations surveillance
50-265/97008-00
LER
missed control rod surveillance
50-265/97009-00
LER
control room operators misread abnormal
offgas radiation readings
50-254/96018-00
LER
misinterpreted TS surveillance requirement
50 254/96018-01
LER
misinterpreted TS surveillance requirement
50 254/97000-05; 50-265/97006-05
IFl
The HPCI suction path transfer from the
CCST to the suppression pool and any
cycling of HPCI on and off considered in the
load profile and modified performance test of
u. ' t 2 250 Vdc battery
50-254/97014 00
LER
the TRSRV did not receive as found set
point testing within 12 mo'1ths
50-254/97016-00
LER
diesel generator cooling water inservice
testing requirements not completed
50-254/92201 02; 50-265/92201 02
no assessment of effect of higher flows on
Unit 1 and Unit % DGCW pumps
50-254/93003 01; 50-265/93003-01
IFl
the % DGCWP transfer starter
panel 2251 10-0 components were not in
preventative maintenance program
50 254/94002-00
LER
this LER documented the inoperability of the
- B' CREV system due to the failure of a
compressor motor contractor on January 4,
1994
50 254/94004 17; 50-265/94004 17
inoperable heat trace line from Unit i SBLC
tank to one of the pumps
50-254/94028-02;50 265/94028-02
inadequate RHRSW surveillance
50 254/95005-03; 50-265-95005-03
IFl
long term use of temporary sealant repair
50 254/96002 12;50 265/06002 12
IFl
the UFSAR needed to be updated to reflect
the frequency of a full core off load and
previous licensing commitments
50 254/96002-13; 50-265/96002 13
IFl
problems with safety-related CREV system
50-254/96008-00
LER
Technical Specification pressure not
achieved during a LLRT
50-265/96010-01
incorrect replacement torus suction valve
weight used in safety evaluation review
50-254/96022 00
LER
the "B" CREV system unable to maintain
1/8" D/P
50-254/97003-00
LER
missed visual examination of HPCI check
valve
50 265/97010-00
LER
missed chemistry surveillance
50-254/97014 03; 50-265/97014-03
NCV discrepancy in the QOM check list
50-254/97014-06; 50-265/97014-06
NCV 50.59 screening of the addition of the jumper
not performed until QCOP 0300-01 was
changed
Discussed
50-254/96011-06; 50-265/96011 06
IFl
evaluation of pipe whip impingement plate
alteration
40
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LIST OF ACRONYMS AND INITIALISMS USED
As Low As ReasonsHy Achievable
ANSI
American National Standards Institute
American Suclety of Mechanical Engineers
CCST
Contaminated Coodcasate Storage Tank
Concrete Expansion Anchors
CFR
Code of Federcl Regulations
Comed
Commonwealth Ecson Company
Control Rod Drive
Control Room Emergency Ventilation
d:
direct current
Design Change f ackage
DET
Diagnostic Evaluation Team
DEV
Deviation
DGCW
Diessi Generator Cooling Water
D/P
Differential Pressure
EAG
Engineering Assurance Group
EmergeE:y Core Cooling System
ELMS
Electrical Load M tnitoring System
Emergency Notifi:ation System
Emergency Oil Pump
ER
Engineering Request
GL
Generic Letter
GSC
Gland Steam Condenser
High Pressure Coolant injection System
Heat Exchanger
IDNS
lilinois Department af Nuclear Safd *
IEEE
Institute of Electronics of Electricai .ngineers
IFl
Inspector Followup item
Inservice Test
kV
Kilovolt
LCO
Limiting Condition for Operation
Level Control Valve
iFR
Licensee Event Peport
t
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Loca! Leak Rate Test
Low Pre 3sure Coolant injection
Main Steam Lafety Valve
Non-cited Violation
NDIT
Nuclear Design Information Transmittal
NEP
Nuclear Engineering Procedure
National Fire Protection Association
NTS
Nuclear Tracking System
Operator Workarounds
P&lD
Piping and Instrument Diagrams
,
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Public Document Room
Pmblem Identification Form
QCAP
Quad Cities Admin;strative Procedure
QCEMS
Quad Cities Electrical Maintenance Surveillance
41
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QCEPM
Quad Cities Electrical Preventive Maintenance
QCGP
Quad Cities General Procedure
QCIP
Quad Cities Instrument Procedure
OCMM
Quad Cities Mechanical Maintenance
QCMMS
Quad Cities Mechanical Maintenance Surveillance
QCOA
Quad Cities Operating Abnormal Procedure
QCOP
Quad Cities Operating Procedure
QCOS
Quad Cities Operating Survelilance Procedure
QCTS
Quad Cities Technical Staff Procedure
QGA
Quad Cities General Abnormal Procedure
'
QOM
Quad Cities Operations Manual
Quality and Safety Assessment
Reactor Core Isolation Cooling System
Regulatory Guide
'
Residual heat Removal Service Water
S&L
Sargent and Lundy
SBLC
Safe Shutdown Makeup Pump
Scram Solenoid Pilot Valve
TRSRV
Target Rock Safety Relief Valve
TS
Technical Specification
TSUP
Technical Specification Upgrade Program
Updated Final Safety Analysis Report
Uninterruptible Power Supply
Unresolved Itern
Vdc
Volt direct current
Work Requests
42
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