ML20134G123
| ML20134G123 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 02/04/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20134G109 | List: |
| References | |
| 50-254-96-17, 50-265-96-17, NUDOCS 9702100289 | |
| Download: ML20134G123 (30) | |
See also: IR 05000254/1996017
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U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos: 50-254, 50-265
Report No: 50-254/96017(DRP), 50-265/96017(DRP)
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Licensee: Commonwealth Edison Company (Comed)
Facility: Quad Cities Nuclear Power Station, Units 1 and 2
Location: 22710 206th Avenue North
Cordova, IL 61242
Dates: October 27 - December 6, 1996
, Inspectors: C. Miller, Senior Resident Inspector
K. Walton, Resident Inspector
L. Collins, Resident Inspector
R. Ganser, Illinois Department of Nuclear Safety
Approved by: Patrick Hiland. Chief
Reactor Projects Branch 1
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9702100289 970204
PDR ADOCK 05000254
G PDR
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! EXECUTIVE SUMMARY i
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. Quad Cities Nuclear Power Station, Units 1 & 2
j NRC Inspection Report 50-254/96017(DRP), 50-265/96017(DRP)
! This inspection included aspects of licensee operations, engineering,
L maintenance, and plant support. The report covers a 6-week period of resident
l inspection.
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Doerations
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- . The inspectors determined that winterizing preparations had improved
j. over last year. However, certain equipment, including the auxiliary
, boiler, were not ready for the onset of cold weather. This was a repeat
finding from last year. In addition, the inspectors determined that the
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lack of special precautions or corrective actions for the low
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temperature alarms was a weakness in the annunciator .wponse procedures
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(Section 01.2).
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i . The shift engineer took a conservative approach in the conduct of I
switchyard work to repair the backup battery power supply for switchyard '
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breakers (Section 01.4).
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. The inspectors concluded that Operations and Engineering had failed
! fully to evaluate the effect a degraded check valve would have had on
! the low pressure coolant injection system during an accident. l'
Operations had not initially characterized the degraded check valve as a
- . significant operator workaround (Section 01.5).
l . The inspectors concluded that the work effort on the circulating water
traveling screens was necessary, but not well coordinated from a risk
. perspective. . As a result, one of the two sup) lies to all safety-related ,
! cooling water was unavailable for over a monti with both units operating i
i at full power (Section 02.1).
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j Maintenance
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i . The preparation, communications, and the general performance of the high
pressure coolant injection (HPCI) surveillance test were acceptable.
- Shift management allowed operators to continue the high pressure coolant
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injection (HPCI) surveillance without documenting problems arising in
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the procedure and without documenting a clarification of a step in the
- procedure. Weaknesses in planning and schedule adherence led to an
l extended surveillance period for HPCI (for an administratively increased ,
. surveillance). (Section M1.1).
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. The licensee identified that incorrect bolt material was installed in
the 1C and 2C residual heat removal service water (RHRSW) pumps due to
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inadequate control of vendor processes. A violation was issued for
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failure to ensure correct materials were used in safety-related
- equipment. The use of the incorrect bolt material resulted in a non-
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cited violation for the 2C RHRSW pump being inoperable in excess of
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Technical Specification (TS) limits. The licensee's failure to report a
condition prohibited by TS resulted in a violation of 10 CFR 50.73.
Other examples involving inaaequate control of vendor processes and
materials were also identified by the licensee (Section M2.1).
. During overhaul and modification of the 2D RHRSW pump. the licensee
identified and corrected a number of problems including deficiencies in
vendor supplied parts. Final test results indicated that the overhaul
effort was successful (Section M2.2).
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Various material . equipment deficiencies resulted in increased personnel
radiation exposure and impacted plant operations (Section M2.3).
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Enaineerina
. The licensee identified that the control room emergency ventilation
system was inoperable. Post modification and surveillance testing
! failed to ensure the system met requirements specified in the updated
final safety analysis report (UFSAR). The licensee had not performed a
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required 10 CFR 50.59 evaluation. These three issues were being
considered Apparent Violations (Section E2.1).
. The inspectors identified a violation for failure to incorporate
Technical Specification requirements into station surveillance
procedures (Section E3.1).
l . The inspectors identified weaknesses in the licensee's approach for
determining control room operability for post accident conditions
(Section E3.2). l
Plant Sucoort i
. The inspectors noted additional radiation exposures were received in an >
effort either to repair deficient material condition issues or to
continue operating the unit with the deficient material condition
(Section R1.1).
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Reoort Details i
Summary of Plant Status
! Unit 1 operated at or near full power throughout the inspection aeriod,
with the except M of the first full week in November. On Novem)er 1.
load was dropped to approximately 500 MWe to repair the level control
valve for the "B" steam packing exhauster. The load was further dropped
to approximately 340 MWe due to a seal leak on the 1A reactor feedwater
pump. The unit was returned to full power on November 7 and continued 1
to operate at or near full power through the remainder of the inspection !
period.
Unit 2 started the period by increasing to full power following repairs l
l to the main turbine bypass valve control system. Problems with the
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moisture separator drain tank level ~ control valves, followed by J
continued main turbine bypass valve control system problems, caused the
unit to be taken off-line on October 27. The unit was brought back on-
line on October 30. and held at 200 MWe for testing of the main turbine
control systems. On November 1, the unit was taken to full power. On !
December 2, operators reduced Unit 2 power to 200 MWe to repair a l
packing leak on a reactor water cleanup valve. The unit operated at or
near full power the remainder of the inspection period.
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I. Operations
l 01 Conduct of Operations
l 01.1 General Comments (71707)
l Using Inspection Procedure 71707, the inspectors conducted frequent
i reviews of ongoing plant operations.
l During the inspection period, several events occurred which required
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prompt notification of the NRC pursuant to 10 CFR 50.72. The events and
dates are listed below.
October 27 Operators reduced Unit 1 power due to reactor feed pump
ventilation fan return damper failing closed.
October 27 Operators tripped Unit 2 main turbine due to problems with
moisture separator drain tank level control valves. Foreign
material caused two valves to stick open.
October 28 Emergency Notification System (ENS) call. Safety train of
control room ventilation system declared inoperable due to
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Topical headings such as 01, M8, etc., are used in accordance with the
i NRC standardized reactor inspection report outline. Individual reports are
i not expected to address all outline topics.
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inability to maintain sufficient positive pressure in the
control room.
November 1 Operators reduced Unit 1 power due to problems with "B" !
gland steam condenser level control valve air operator.
November 24 Control room emergency filtration system declared inoperable
since operators were not assured that-a surveillance test :
was performed correctly. Subsequent testing verified system !
operability.
November 26 Operators declared the shared standby diesel generator r
inoperable to Unit 2 due to a relay problem.
December 2 Operators reduced Unit 2 power to less than 15 percent power !
due to problems with reactor water cleanup isolation valve ,
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01.2 Winterizino Checklist (71714)
a. Insoection Scoce l
The inspectors observed performance of scheduled cold weather !
preparation activities including use of Quad Cities Operating Procedure
(OCOP) 0010-01, " Winterizing Checklist." '
b. ' Observations and Findinos l
The inspectors reviewed the licensee's progress of completing the !
checklist throughout the period and found that a majority of items were :
completed prior to the expected date of October 30. A notable exception :
to the licensee's expectations was that the heating boilers were not i
available for use by the first cold spell of the season or by l
October 30.
The inspectors identified several periods when supply air low I
temperature annunciators (panel 912-5, B1 through B5) were lit in the l
control room for the reactor building, the turbine building, and the '
radwaste building. The annunciator response procedures for these alarms
guided the operators to check for valid indication and take corrective
action as necessary. There were no specific actions identified in the
procedures.
The inspectors questioned operators as to the special precautions being
taken during the time when low intake temperature alarms were
annunciated. The operators indicated that only normal rounds were being
performed and that maintenance actions to repair the boilers were
underway. The inspectors noted that the potential for colder than
normal equipment temperatures existed during this time, especially in
the vicinity of su)
conditions during )uilding
ply air inspections.
duct outlets, but found no unacceptable
c. Conclusions
The inspectors determined that use of the winterization checklist had
improved from the previous year. P vever, the licensee still failed to
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) lace the auxiliary boiler and other items on the cNcklist in service
l Jefore the arrival of cold weather. This was a repeat problem from
l 1995. In addition, the inspectors determined that the lack of special
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precautions or corrective actions for the low temperature alarms was a
weakness in the annunciator response procedures.
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01.3 Conservative Ooerations Control of Work Activities
l The inspectors attended a meeting conducted by the shift engineer to
l address switchyard work that had the potential to remove backup battery
l power for the switchyard breaker trip circuits. The shift engineer
directed that the engineers )erform a 10 CFR 50.59 safety evCuation to
address a design condition tlat would be controlled by temporary I
alteration. The meeting was concise, and resulted in o. i parties
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knowing their roles and actions. There was good inter-departmental
communication. Shift management's conservative approach was
demonstrated in the pursuit of a safe and effective corrective action
for a problem that could have adversely affected the units.
01.4 Unit 2 Low Pressure Coolant Iniection (LPCI) System Inocerable Due to
Loss of Discharge Header Pressure
a. Insoection Scone (71707)
The inspectors responded to a licensee report on November 12 in which
the LPCI system was declared inoperable after losing keep fill pressure
on the common discharge header from the residual heat removal (RHR)
pumps. The inspectors interviewed licensed operators and the system
engineer, and reviewed the system configuration and previously completed
surveillance tests.
b. Observations and Findings
The licensee had started the "2D" RHR pump in order to verify proper
breaker operation after maintenance. After stopping the pump, the
discharge check valve (2-1001-67D) failed to fully reseat. This failure
allowed water in the discharge header to drain back to the torus through
the normally open pump suction valve. Since the discharge header was
common to all four RHR pum)s the entire LPCI system was affected.
Under normal conditions, t1e keep fill system maintained pressure in the
discharge header for both LPCI and the core spray system. However, the
keep fill system could not maintain the discharge header pressure with
the discharge check valve stuck open.
The licensee entered a 7-day shutdown limiting condition for o)eration
(LCO) according to Technical Specification (TS) 3.5.A.2 when t1e Unit 2
LPCI system was declared inoperable. Operators shut the suction valve
for the "20" RHR pump which allowed the keep fill system to repressurize
the discharge header. Operators then filled and vented the system in
l accordance with the operating procedure. The "2C" RHR pump was started
l to reseat the discharge check valve on the "2D" pump. Once the "2C" RHR
l pump stopped, header pressure remained constant: and operators
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determined-that the "20" pump discharge check had reseated. The LPCI
system was then determined to be operable and the LCO was exited.
Operators generated problem identification form (PIF) 96-3196 that
referenced a 3revious similar event and mentioned a caution card on the-
control switc 1 for the "2D" RHR pump. The inspectors found that the
caution card on the control panel was dated July 3,1996, and referenced
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an action request from May 21, 1996. The inspectors reviewed the
previous event and found it was similar to the current event, except the-
unit was in cold shutdown. The system engineer told the inspectors that
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this check valve had been replaced during the 1995 Unit 2 refueling
outage and that he had been aware of the leak since May 1996 when the
RHR system was operating in the shutdown cooling mode.
i The inspectors viewed the degraded condition of the check valve as a
{ significant operator work around since failure of the valve to seat
could affect the LPCI function during an accident. However, the
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inspectors found that this work around was not documented on the
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operator work around list and that no specific information or
, instructions had been given to operators regarding this potential
failure mode. Although the caution card existed on the control switch
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for the pump, inspectors determined that some control room operators did
not recognize the impact of the condition on accident response, and some-
l were not even aware of the degraded condition. )
! The licensee agreed that the degraded check valve met the criteria for !
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an operator work around. At the end of the inspection period, the i
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licensee had ordered a new valve and was evaluating whether to perform
the maintenance on-line or during the upcoming refueling outage. In
, addition. Operations issued a standing order with special instructions
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to operators regarding this valve.
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c. Conclusion
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l The inspectors concluded that Operations and Engineering had failed to
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fully evaluate the impact the degraded check valve would have had on
LPCI during accident. Even after the second instance of a check valve
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failing to reseat, the licensee was slow to consider this a significant
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operator work around. The inspectors found the licensee's plans for
future replacement of the valve and the issuance of the standing order
to operators to be acceptable cc' *ective actions and compensatory
measures for this degraded condim in,
j 02 Operational Status of Facilities and Equipment
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02.1 Circulating Water Bay Conditions
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a. Inspection Scope (71707)
! The inspectors observed maintenance activities on the Unit 1 circulating
j water bay to assess the licensee's evaluation of risk significant
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b. Observations and Findinas
Poor Risk Persoective and Prioritization
The inspectors observed maintenance activities associated with repairs
on the 1A circulating water pump and motor, and the 1A and 18 traveling
screens. Repairs to the traveling screens required the 1A circulating
water bay to be dewatered. This was accomplished by placing stop logs
upstream of the 1A and 1B traveling screens and at the Unit 1 water
supply to the safety-related cooling water bay at the crib house, and
Jumping the water out of the 1A bay. The safety-related cooling water
Jay was the suction source for all trains of emergency diesel generator
cooling water (EDGCW), residual heat removal service water (RHRSW) for
both units, and one of two diesel fire pumps for both units.
The inspectors determined that the repairs to the circulating water
system were necessary and appeared to be aimed at correcting long
standing problems identified with the traveling screens. However, the
limited risk considerations given to this work were troubling.
Dewatering the 1A bay left only one supply of water to the safety-
related water bay (through the PE and 2F traveling screens and the fixed
screen from the 2C circulating water bay). Normally there were two
sources of water to this safety-related water bay, from the ultimate
heat sink (VHS) through the 1A and the 2C circulating water bays. The
second supply to the safety-related water bay was unavailable since
October 28, 1996.
The inspectors asked what processes were used to evaluate the risk
3riorities of )erfcrming work which required circulating water bay 1A to
]e drained witi both units at 100 percent power instead of with one or
both units shut down. The licensee indicated that the risk priorities
of various plant conditions were not considered, and that the work was
always scheduled for on-line maintenance. The inspectors found that the
work requests had been generated in 1995, and since that time both units
had been shut down simultaneously for several months. Additionally, the
inspectors found that the process described in Quad Cities
Administrative Procedure (0 CAP) 2200-07 "Probabilistic Risk Assessment
of On-Line Maintenance Activities" was used, but was not detailed enough
to model items such as the circulating water bay supply to RHRSW in the
station probabilistic risk assessment driven operational safety
predictor program.
The inspectors had previously identified opportunities for better
planning of on-line shared diesel generator work that could have been
performed during the sam dual unit outage period (see Inspection Report
(IR) 50-254/265-96014). Licensee management indicated the potential
weaknesses in scheduling risk significant work would be evaluated.
Lead Unit Planners reviewed the risk significance of circulating water
bay dewatering efforts. However, only the risk effects of making a
circulating water and service water pump inoperable were considered.
The loss of redundancy to the RHRSW water supply from the UHS was not
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modeled in the operational safety predictor or considered by planners or
operations supervision. Since the work was not considered risk
significant, planners scheduled the work only on day shift for about the
first 2 weeks of the job. Later, a limited sized evening shift crew was
added. At times, all crews were pulled away to work on other emergent
work for 1 to 2 day periods.
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Poor Understanding and Control of Licensing Basis
The inspectors were concerned that the licensee modified an UHS flowpath
of water to safety-related cooling components without performing an
evaluation for the modification. Technical Specification recuirement
3.8.A specified that during plant operation at power, two incependent
subsystems of RHRSW be available with an operable flow path capable of
taking suction from the UHS. On November 24 the inspectors questioned
the licensee about the operability of the RHRSW subsystems when only one l
path from the UHS to the safety-related water bay was available, and it '
was common to all trains. Operations management indicated that the
safety-related water bay was considered part of the UHS, and there was i
no restriction to operations with only one pathway. l
The inspectors determined that the updated final safety analysis report
(UFSAR) descriation of the UHS and of RHRSW was not detailed enough to i
determine the )oundary of the UHS and what flow requirements were needed i
for intake into the safety-related water bay. The inspectors pointed
out that the licensee had used stop logs to modify the safety-related
water bay without evaluating the potential impact. For example, the
licensee had not initially considered if the flow capacity of the single I
fixed screen was sufficient, and had not considered the risk impact of
the loss of the redundant water supply. The inspectors also questioned :
the ability of the stop logs to maintain an acceptable water level at j
all times during a seismic event. The licensee was evaluating the '
design requirements for the UHS at the close of the period. The
inspector's planned assessment of the licensee's evaluation of the
design requirements of the VHS and review of scheduling of risk
significant activities is considered an Unresolved Item (50 254/265- ,
96017-01). I
c. Conclusions
The inspectors concluded that the work effort on the circulating water
traveling screens was necessary, but was not well coordinated from a
risk perspective. As a result, one of two supplies to all safety-
related cooling water was unavailable for over a month with both units
operating at full power. In addition, the design basis for the sup) lies
to safety-related cooling water were not well known or considered w1en
stop logs isolated one of the pathways for safety-related cooling water
from the UHS.
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- 08 Hiscellaneous Operations Issues (92700)
08.1 (Closed) Unresolved Item (50-254/265-94004-23): Reactor Vessel
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Temperatures Not Recorded During Cooldown. The Diagnostic Evaluation
Team (DET) noted that the licensee previously identified operators
failed to verify reactor vessel temperature limits during unit cooldown
1 as required by TS 3.6. This was addressed-in licensee event report t
(LER) 50-254-92011 and LER 50-265-92010. These LERs were previously
reviewed and closed. The inspectors noted the licensee adequately
l verified temperature limits during unit heat ups and cool downs. .
! The DET also identified the licensee had no procedural requirements to
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log or monitor inoperability of instruments to ensure compliance with TS
l during surveillance testing. The licensee subsequently established
procedural controls in this area. The inspectors noted the licensee
. continued to implement these administrative controls while complying
i- with TS LCOs for ecuipment unavailability during surveillance testing.
This item 1.s closec .
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08.2 (Closed) Licensee Event ReDort (LER) 50-254/94011: Control Rod L-11
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Failed to Scram During Rod Time Testing. A maintenance activity during
i the Unit 11994 refueling outage installed a pipe plug into a solenoid
3 valve exhaust port during maintenance testing but the plug was not
i removed until detected by operators during rod testing. The licensee
! attributed this event to maintenance workers failing to adhere to
i procedures. The licensee trained maintenance personnel on temporary
- alterations and maintenance on hydraulic control units. The licensee
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changed procedures and performed rod testing during the primary plant
i hydrostatic test in lieu of testing rods during startup from a refuel
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outage. The inspectors reviewed the changed procedures.and verified
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compliance with TS. Maintenance craft procedure adherence has been
i enhanced by the station requirement to sign each line item of a
1 procedure. Some sequencing and procedure adherence problems have
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continued, to a lesser extent, and will be addressed on an individual
basis. This event resulted in a Level III Violation and Civil Penalty.
See inspection reports 50-254/94017 and 94027 for additional
information. This item is closed.
l 08.3 IC.losed) Violation 50-254/265-94017-01: Violation of Procedure
i Adherence, Test Control, and Corrective Actions Associated with Failure
] of a Control Rod to Scram During Testing. This violation was the same
event described in Section 08.2 above. Corrective actions for the
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procedural adherence violation were described above. Licensee actions
for test control and corrective action violations included counseling of
appropriate nuclear engineering personnel. The licensee hired an
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experienced nuclear engineer to provide oversight of nuclear engineering
issues. Corrective actions taken by the licensee to address delayed
i start of rod motion included replacement of scram solenoid pilot valve
diaphragms with models less prone to the phenomena. The licensee also
- reinforced the use of the nuclear tracking system to ensure documented
problems were tracked to resolution. The-inspectors reviewed the
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licensee's corrective actions. This item is closed.
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II. Maintenance
M1 Conduct of Maintenance (62707)
M1.1 High Pressure Coolant Iniection (HPCI) System Surveillance Test
a. Insoection Scone
The inspectors observed performance of scheduled activities including a
monthly surveillance test run of Unit 2 HPCI system Quad Cities
Operating Surve111ance (0C05) 2300-5, " Quarterly HPCI Pump Operability
Test."
b. Observations and Findings
0)erations stopped at one point to make a )rocedure field change when
tie normal pressure indication listed in tie procedure was not available
due to maintenance. However, the inspectors identified one instance
where operators could not properiy verify the requirements of the
procedure. Step H.31.b. required operators to verify turbine speed
increased to approximately 3900 rpm. When the turbine speed reached
only 3100 rpm, operators appro)rlately notified the system engineer.
The system engineer informed t1e operating crew that this was acceptable
performance for the present system condition, and to continue the test.
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The inspectors identified that the system engineer was not aware of the
origin of the test requirement or why previous crews had not had trouble
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meeting the requirement. The system engineer felt confident that the
3900 rpm requirement was related to the high speed stop setting of the
HPCI motor speed changer circuitry and was not a critical parameter.
The inspectors reviewed the completed procedure and identified that
operators had not documented the inability to meet the 3900 rpm
requirement, and that no procedure change was made, even though the i
actual rpm during the test was about 20 percent lower than required.
The system engineer indicated that the rpm seen could be considered l
approximately equal to that required by the procedure. Based on the
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magnitude of the s)eed difference, the inspectors believed that
documentation of t1e speed difference would clarify the step during
future testing. The surveillance results indicated that all TS l
requirements for rated flow were met. 1
The inspectors noted that the next performance of the surveillance was
scheduled for November 28: however, the test was not performed until
December 7. The licensee had postponed the test due to Thanksgiving
holiday work schedule conflicts. Although this test was only required
to be performed quarterly by TS, the licensee scheduled it monthly
because previous performance problems had reduced confidence in the ,
system. The licensee sought to improve performance through increased !
testing and troubleshooting. ;
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c. Conclusions
The inspectors noted that the preparation, communications, a'nd the
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general performance of the' surveillance test were acceptable. An
opportunity to document 3roblems and clarify the meaning of steps in the
procedure was missed. S11ft management allowed operators to continue
the HPCI surveillance without documenting problems arising in the
procedure and without documenting a clarification for the step for lower
than expected rpm. Weaknesses in planning and schedule adherence led to
an extended surveillance period for HPCI.
M2 Maintenance and Haterial Condition of Facilities and Equipment
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M2.1 Use of Incorrect Bolt Material in RHRSW Low Pressure (LP) Pumos (IP
92700)
a. Insoection ScoDe
The ins)ectors investigated the licensee's use of incorrect bolts in the
RHRSW L) Pumps.
b. Observations and Findinas
Incorrect Bolt Material on 1C and 2C RHRSW LP Pumos
On May 3. 1996, the RHRSW Jump vendor notified Comed (Ref: 073-
61152/503284XX348/XX275) t1at the ) art number for the bolts used in the
RHRSW LP pumps was not current. T1e recommendation from Ingersoll-
Dresser Pump Co. was to change the bolt material from SAE Grade 8 to
A193-75 Class 2 Grade B8. The vendor certified that the recommended
parts had not affected the form, fit, or function of the original parts,
when in fact, the substitution bolts had a lower yield strength limit
than the original Grade 8 material. On May 24, 1996. Comed's Corporate i
Materials Engineering Group, performed an evaluation. M-1996-0454-0. l
agreeing with the vendor's incorrect substitution recommendation (PIF '
96-3039).
On October 25. 1996, during assembly of a sJare RHRSW LP Pump.
Mechanical Maintenance Department (MMD) worcers were torquing the pump ;
casing flange bolts. One bolt broke and several others showed signs of 1
stretching. The licensee stopped the work and began an investigation of
the cause of the failures (PIF 96-3025). The licensee inspected all LP
pump casing bolts and discovered that lower yield strength A193-75 Class
2 Grade 88 bolt material had been installed in the 1C RHRSW LP Pump (PIF i
96-3029) on October 8. 1996, and in the 2C RHRSW LP Pump (PIF 96-3030) !
in July 1996. A torque value of 375 ft/lbs applying to the original
"high yield strength" limit for the SAE Grade 8 bolts, was used to
assemble the pump casings. Consequently, the yield strength limit for
all of the LP pump casing bolts on the 1C and 2C RHRSW LP Pumps was
exceeded during assembly,
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The licensee's corrective actions included validating (through the
vendor) that the high yield strength SAE Grade 8 bolt material or
equivalent was the correct replacement. The torque value was verified
to be correct at 375 ft/lbs lubricated with N5000 Antiseize for the SAE
Grade 8 bolts. Additionally, the vendor recommended a "one-time-use-
only," for the high yield strength SAE Grade 8 bolts. Following
replacement of the incorrect LP pump casing bolts with the correct
bolts, the 1C pump was tested and declared operable on October 27, 1996,
and the 2C pump was declared operable on October 28, 1996. The licensee
was assessing the condition of other RHRSW LP pumps using the correct
SAE Grade 8 bolts which have been torqued more than once. Past practice
allowed reuse of the bolts.
A)pendix B of 10 CFR Part 50, Criterion III, " Design Control." requires
tlat measures shall be established for the selection and review for
suitability of application of parts that are essential to the safety-
related functions of the structures, systems and components. The
licensee's failure to assure that the correct a] plication of bolt
material was used in the safety-related RHRSW L) pumps was a Violation
(50 254/265-96017-02) of 10 CFR Part 50 Appendix B, Criteria III.
The licensee took good corrective actions at the station level following
the discovery of a broken bolt. However, this condition appeared to be
similar to other 2roblems related to the control and issuance of safety-
related parts. W1ile the short term corrective actions were aggressive,
long term actions which included both station and corporate actions,
have not been demonstrated. Based on this lack of comprehensive
corrective action to prevent recurrence, the NRC chose not to exercise
the discretion outlined in Section VII.B.1 of the Enforcement Policy.
2C RHRSW Pumo InoDerable in Excess of TS LCO
Technical Specifications 3.5.B.2 required that with one RHR$W pump
inoperable, continued reactor operation is permissible only during the
succeeding 30 days provided that all other active components of the
containment cooling mode of the RHR system are operable. Technical
Specifications 3.5.B.5 stated that: "If the requirements of 3.5.B
cannot be met, an orderly shutdown shall be initiated, and the reactor
shall be in a cold shutdown condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />." The 1C and 2C
RHRSW pumps were declared inoperable on October 26, 1996, when the
licensee recognized the potential impact of the installation of
incorrect bolt material that was discovered late on October 25, 1996.
It was established that the correct bolt material for use in the LP
pumps was the original SAE GRADE 8 material. The 2C RHRSW Pump was
inoperable from July 12, 1996, when incorrect bolts were installed in
the LP ) ump casing, until October 28, 1996. The 1C RHRSW Pump was
inopera)le from the period following October 8, 1996, when incorrect
bolts were installed in the LP pump casing, until October 27, 1996.
Unit 2 was started on August 15, 1996, and the incorrect bolt condition
, was discovered on October 25, 1996. Unit 2 was operated past the
13
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30 days allowed by TS. This licensee-identified and corrected violation j
l is being treated as a Non-cited Violation 50-254/265 96017 03 consistent l
l with Section VII.B.1 of the NRC Enforcement Policy. I
Failure to ReDort a Condition Prohibited by TS
l
'
The 10 CFR 50.73 Section (a)(2)(B). " License Event Report System,"
required the licensee to report any condition prohibited by the plant's
l TS within 30 days after the discovery of the event. However, the l
licensee failed to report by November 24, 1996, in accordance with j
10 CFR 50.73, operation of Unit 2 in a condition prohibited by plant
TS 3.5.B.2 and 3.5.B.5 following discovery of the incorrect bolts on
October 25, 1996, which is a Violation (50 254/265 96017-04) of i
10 CFR 50.73. '
Other Problems Identified Durino RHRSW LP Pumo Maintenance
On October 26. 1996, due to a separate incorrect recommendation from the i
vendor (PIF 96-3043), a single incorrect bolt was found to have been '
installed on the 2A RHRSW LP Pump. A substitute bolt material, A193
Grade B7, was installed. This material has a yield strength between the
correct SAE Grade 8 material and that of the lower yield A193-75 Class 2
Grade B8 material. This single bolt was replaced.
Another PIF (96-3253) was written to address two spare bearing housings !
for the RHRSW LP Pumps that did not have all of the bolt holes tapped. l
There were dimensional problems with two new LP pump shafts drawn from
stores for future rebuilds (PIF 96-3000). Several other problems
involving inadequate control of vendor supplied materials for LP pumps
are described in section M2.2 below.
During overhaul of the 1C RHRSW Pump in the previous inspection period
(NRC Inspection Re3 ort 50-254/265-96014), the LP pump casing flanges
were found not to 1 ave met a critical dimension and the pump failed the
post maintenance leak test. In response, the licensee's Site Quality
Verification Department has initiated a "stop work" to the vendor in
order to identify the root cause and take effective corrective actions
for the relatively high number of quality control issues from one
vendor. The licensee initiated a 10 CFR Part 21 internal and/or
external report to address the generic and potential industry
implications of the materials issues.
c. Conclusions
The licensee had not assured adequate quality assurance measures for
control of some vendor materials and processes. This resulted in
incorrect bolt material being installed in the 1C and 2C RHRSW LP pumps,
rendering the pumps inoperable. A separate incorrect bolt
recommendation resulted in the installation of one incorrect bolt in the
l
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.
. l
The licensee's response to the broken bolt while rebuilding the spare
pump'in the shop was appropriate. Stopping the job and )erforming
timely inspections of all the other pumps demonstrated tlat MMD workers
were alert to conditions adverse to quality. The licensee's
-identification and timely correction of the incorrect bolt material was
an adequate immediate response. While the short term corrective actions
were aggressive, long term actions which include both station and
corporate actions, have not been demonstrated.
The inspectors will continue to monitor the licensee's performance in
determining the root cause of inadequate quality assurance of materials
and processes supplied by a vendors.
M2.2 Observation of MMD Work Activities for Overhaul of the 20 RHRSW Pumn
a. Insoection Scooe
The inspectors observed the MMD during portions of the overhaul of the
20 RHRSW Pump. This was the seventh of eight pump overhauls to perform
modifications (cutwater modification) to improve the overall pump
performance characteristics and increase reliability.
b. Observations and Findinas
The inspectors noted that spare components and tools were staged in an
orderly fashion. Foreign material exclusion (FME) barriers were
appropriately placed and FME practices were adhered to. Job supervision
was adequate and workers coordinated the tasks with each other. A
number of issues described below were identified during the overhaul
effort.
Erosion of Flance
E2cessive erosion was found at the 2D RHRSW LP pump discharge flange.
The cause of the erosion was determined to be a weld dam used to
initially construct the pipe. The weld dam allowed excess turbulence at
the discharge flange, resulting in accelerated erosion. The repair i
consisted of building up the eroded area inside the pipe and machining j
the added material to form a smooth surface (ER 9606131). The pump 1
engineer stated that the condition had not been detected during
ultrasonic testing. The eroded condition had been noted on one or more
of the other RHRSW pumps during overhaul, but was not as advanced as on
the 2D pump.
Bearina Housina i
One of the bearing housings for the 2D RHRSW high pressure (HP) pump was
dimensionally incorrect (PIF 96-3203). These housings, although
supplied as new, had a thick paint-like coating on the inner surface.
Some of this coating had flaked off and was lose in places, such that it i
posed a potential for introducing foreign material into the bearings
'
during operation. The licensee replaced the faulty housings. !
15 !
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Rework
Maintenance workers initially positioned the 2D RHRSW HP pump seal ,
housings 180 degrees out of the correct orientation. This was :
attributed to a performance error on the part of the MMD worker who '
!
failed to check the proper orientation prior to assembly. Following the
licensee's evaluation of the PIF, an additional work instruction was
added to the work package, specifying the orientation of the seal
housings to minimize the potential for recurrence. The licensee
j initially. indicated that the orientation of the seal-housing was within
the skill of the craft.
,
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The second issue arose during post maintenance testing (PMT) of the pump
when minor leakage occurred at the HP Jump outboard seal. Engineering
recommended that the HP' pump be re-worced. The cause of the leak was
found to be an improperly seated "0" ring in the pump seal assembly.
- The licensee determined that this was due to im)recise dimensional
specifications on the threaded portion of the slaft as it was delivered
by the vendor. Maintenance Engineering recommended dimensional
l adjustments to the shaft assembly to eliminate the potential for the
.
interference between the "0" ring and the threaded portion of the pump
! shaft. Resultant changes were implemented into the work instructions
for future reference.
c. Conclusions
l
Weaknesses were identified in quality assurance of vendor supplied
components. The licensee's work procedure was inadequate for the skill
level of the workers as indicated by the incorrect installation of the
2D RHRSW HP Pump seal housings. In spite of a number of problems which
the licensee resolved, the work was successfully completed and the pump
was returned to service within the original schedule. Test data
,
indicated that the pump performance had improved significantly over the
!
prior-to-overhaul condition. The efficiency of the overhaul process was
improved, in part, due to using many of the same 3ersonnel for each
overhaul job. The knowledge and skill level of t1e alignment and
vibration team has increased with the experience on the RHRSW pumps.
Some lessons learned from previous RHRSW pump overhaul efforts were
effectively implemented.
M2.3 Material Condition of the Facility
a. Insoection Scone (71707. 62707)
The inspectors reviewed operator logs, PIFs, interviewed operations and
,
maintenance personnel, and observed activities in progress.
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b. Observations and Findinas
Reactor Water Clean UD (RWCU) System Problems - Unit 1
Maintenance personnel, troubleshooting a pump low flow candition,
discovered an installed orifice in the discharge nozzle of the 1A RWCU i
Jump. A modification performed in 1986 (M04-1-85-065) was supposed to
lave removed the orifice. In the work package impleme iting M04-1-85-
065, workers documented the orifice could not be located. and
l reassembled the discharge piping without removing the arifice. As
I corrective actions, the licensee removed the orifice from the 1A RWCU
pump, and wrote a work request to remove the orifice from the 2B RWCU
j pump.
l
After removing the orifice from the 1A RWCU pump, old weld deficiencies
on the pump delayed the return to service. Concurrent with work
performed on the 1A pump, the IB RWCU pump was removed from service due
to high vibrations.
Delay in olanned maintenance of the 1A pump coupled with an emergent
material condition concern with the 1B pump resulted in operating Unit 1
without a functioning RWCU system. The licensee classified this as a
maintenance rule functional failure. Workers repaired the 1B RWCU pump
within 3 days and returned the RWCU system to service.
, Removing the RWCU system from service was not desirable since some
chemistry parameters can be adversely affected. The length of time the
'
RWCU system was removed from service did not result in any chemistry
parameters exceeding TS limits.
.
RWCU System Problems - Unit 2
In late October, operators detected a packing leak on the Unit 2 RWCU
containment outboard isolation valve (2-1201-5). Subsequent cycling of
the valve and tightening of valve packing reduced the leakage to
acceptable levels. However, on December 1, operators noted steam
emitting from the 2-1201-5 valve packing.
Seat leakage of the RWCU containment inboard isolation valve (2-1201-2)
coupled with the Jacking leak on 2-1201-5 resulted in a degraded
condition of the RWCU system. In order to perform repairs at power,
operators reduced Unit 2 power and removed RWCU from service. The valve
packing leak was temporarily corrected and Unit 2 returned to full power
operations. Action requests were written to address both material
condition issues for the upcoming outage. The RWCU system was out of
service for about 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br /> and TS li. dts of chemistry parameters were
not exceeding .
l Gland Seal Condenser Level Control Valve (LCV) Problems
On November 1, operators received control room alarms indicating a
failure of the "B" gland steam condenser LCV (1-5404B). The operators
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reduced Unit 1 power and placed the "A" (1-5404A) LCV in service.
Workers replaced a ri) ped diaphragm in the "B" LCV air operator and
identified that both _CV controllers had 3roblems maintaining the proper
level in the condenser. Also, the drain leader from the "A" gland seal
condenser was found to have been plugged.
Workers repaired the controller and returned the "B" LCV to service.
The "A" LCV remained out of service until an inspection of the drain
header could be performed. However, on November 27, o]erators received
control room alarms indicating additional problems wit 1 the "B" LCV.
Workers identified the "B" LCV air operator had broken hold down bolts.
4
This resulted in the air operator being displaced from the valve yoke
, and caused the LCV to close. Workers replaced the broken bolts. ,
,
The failures of the Unit 1 gland steam condenser LCVs although not
safety significant, required operators attention to be diverted from
,
monitoring the unit. This condition had the potential to spread
contamination from the main turbine seals. On several occasions,
operators were re
condenser level. quired to take manual control of the gland seal
The local control station was in the feedwater heater
bay: an area of elevated radiation dose.
Foreion Material Found in Feedwater Heater System - Unit 2
l
~ On November 26, control room operators received feedwater heater drain l
le/e1 alarms indicating problems with the system LCVs during an increase
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in Unit 2 power. Operators discovered two air operated valves (A02- i
3508C and A02-3509A) were stuck open. Operators removed Unit 2 main
turbine from service to allow inspection of all six feedwater heater
drain LCVs.
The inspection identified that foreign material caused the two valves to
stick open. Foreign material was found in a third LCV. The foreign
i
material was believed to have originated from decaying grid work inside
moisture separator drain tanks upstream of the LCVs.
To effect repairs, the licensee was required to remove the unit from
operation affecting operational performance of the unit and some
increased dose to the workers.
4
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c. Conclusions
During the inspection period, the licensee experienced numerous
equipment performance problems. The licensee was still evaluating the
causes of the above equipment failures.
'
The equipment mentioned above was not classified as safety-related.
However, poor equipment performance necessitated operator intervention
prior to further equipment degradation. Additionally, the degraded
i
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equipment performance caused increased personnel radiation exposure to
repair and/or restore the affected equipment, re-directed maintenance
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! resources, delayed the start of scheduled maintenance activities. and
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impacted the operation of the units.
M8 Miscellaneous Maintenance Issues (92902)
M8.1 (Closed) Violation (50-254/265-96011-04): Three Examples of Workers Not
Properly Executing Work. The inspectors reviewed the licensee's
corrective actions for the personnel errors leading to this violation.
.
This item is closed.
I M8.2 (Closed) Violation (50-254/265-96002-08): Improper Storage of Emergency
Diesel Generator Air Start Motors. The cause of the improper storage of
! the air start motors was that the motors were not effectively coded to
, have planned maintenance (PM) performed on them. This PM would have
i
assured storage in a. moisture-free environment to prevent moisture
. buildup. In response to the NOV. the licensee performed an expanded
1- scope inspection of safety-related spare parts that were coded for PM
! activities to be performed while in stores. Of over 400 items screened,
the licensee identified approximately 35 items which were not coded
i
properly for a PM action. There were no cases in the sample inspected
j in which installation of faulty parts occurred, or failures of safety-
related ecuipment due to s Jare parts PM deficiencies. The licensee
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identifiec and corrected tle PM deficiencies and another administrative
{ weakness whereby the PM code was inappropriately ap)1ied to discontinued
,
or redesignated items. The inspectors determined t1e corrective action
j was adequate. This item is closed.
, 4
III. Enaineerina '
y
i .
I E2 Engineering Support of Facilities and Equipment (IP 37551) '
"
l
E2.1 Control Room Emeraency Ventilation System (CREVS)lnocerable and Outside
- of the Desian Basis as Described in the UFSAR.
.
I
a. Inspection Scone (IP 37551)
The inspectors reviewed the CREVS ino)erability which was reported to
the NRC on October 28, 1996, via the ENS phone line. The inspectors
used the TS, the UFSAR, the licensee's operability assessment, various
regulatory guides, the standard review plan on control room
habitability, and completed surveillance tests in the review. In
addition, the inspectors interviewed system engineers and licensee
management and attended plant on-site review committee (PORC) meetings
on the subject. The inspectors also observed portions of the
maintenance and surveillance activities during repair and restoration of
the system to an operable status.
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b. Observations and Findinas
On October 8, 1996, the licensee initiated PIF 96-2892 to document an
issue found at Dresden for review at Quad Cities. The issue concerned
TS surveillance requirement 4.8.D.5.c which required that once every
18 months, verification that the control room Jositive pressure was
maintained at greater than or equal to 1/8 inc1 water gauge relative to
adjacent areas during system operation at a flow rate less than or equal ,
to 2000 scfm. This particular surveillance requirement was new as of I
September 24, 1996, when new TS for Quad Cities were implemented. At i
the time of implementation, all new TS requirements for surveillance !
-
were required to be current and completed. l
l
After taking differential pressure measurements supplemental to the
measurements of the current surveillance procedure, the licensee
identified that the surveillance procedure was inadequate because the
control room differential pressure with respect to all adjacent areas I
was not measured. Engineers found that the required 1/8 inch positive
pressure in the control room was not met with respect to the cable
<
s3 reading room. The licensee identified eight additional adjacent areas
i
t1at needed to be included in the surveillance. On October 28, 1996,
the CREVS was declared inoperable, reported the condition to the NRC,
and entered the 7-day Limiting Condition for Operation. The inspectors
determined that the system had been inoperable since at least the
implementation of the new TS on September 24, 1996, since the as-found
condition was not in conformance with the TS and the required test had
not been performed prior to November 3, 1996. The inspectors concluded
that this was an Apparent Violation of TS 3.8.D.1, since the system was
inoperable for a period greater than allowed by the 7-day LCO while both
units were in Mode 1.
The licensee identified a discrepancy between the requirements of the TS
surveillance and the UFSAR description. Technical Specification 4.8.D.5.c required verification of the differential pressure between the
control room and adjacent areas, while the UFSAR (Section 6.4) stated
that the control room emeraency zene should be maintained at a 1/8 inch
Jositive pressure. The control room emergency zone was defined in the
JFSAR as the main control room, cable spreading room, auxiliary electric
equipment room, and the train "B" heating, ventilation, and air
conditioning (HVAC) equipment room. Differential pressure measurements
taken between the control room emergency zone and the adjacent areas
revealed that some areas were at a negative pressure and that some
areas, while positive, could not meet 1/8 inch design basis.
The inspectors reviewed the original design modification that installed
the CREVS and determined that testing for Modification M04-1/2-82-02
completed on April 16,1985, had not measured differential pressure
between the control room emergency zone and adjacent areas and therefore
failed to ensure UFSAR Section 6.4.4.1 criteria were met. The
inspectors concluded that both the modification test and subsequent
surveillance tests of the CREVS were inadequate to ensure that the
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.
- . system would perform'its design basis function as described in the
- UFSAR. The inspectors consider this an Apparent Violation of !'
l 10 CFR Part 50, Appendix B, Criterion XI, " Test Control."
The UFSAR stated that the purpose of maintaining Jositive pressure in i
.
the control room emergency zone was to minimize t1e transfer of toxic or !
i
!
radioactive gases into the control room (Section 6.4.2.4). Chapter 15 ,
of the UFSAR described the control- room dose calculation which assumed !
the in-leakage into the control room emergency zone was 259.3 standard
- cubic feet per minute (scfm). !
The licensee sealed the CREVS ductwork and plugged leakage pathways into
the control room eme m ncy zone. A final set of differential pressure
readings concluded that while the control room had been restored to
1/8 inch positive pressure with respect to all adjacent areas, other
sections of the control room emergency zone remained at a negative !
pressure. I
In addition to the repairs, the licensee performed a control room dose
calculation to determine how much in-leakage into the control room
emergency zone would result in failure to meet General Design Criteria (GDC) 19 of 10 CFR Part 50, Appendix A which sets limits for the
radiation dose operators can receive during an accident. Concurrently, ,
the licensee performed a test to measure the in-leakage. The measured' '
in-leakage was 275 plus or minus 99 scfm. an amount greater than that
assumed in the UFSAR.
The licensee performed a new control -room dose calculation (NUS
calculation number 6200.001-M-04) using the measured in-leakage. The
calculation methodology was different from that described in the UFSAR
Section 15.6.5. It used dose conversion factors from International
Committee on Radiation Protection (ICRP) 30. took credit for suppression
pool scrubbing of iodine (Standard Review Plan (SRP) 6.5.5), and used a
different secondary containment effluent leakage rate (4 volumes per
day). The combined effect of these differences resulted in a lower
calculated dose to the thyroid (12.5 rem) for control room personnel
when compared to the UFSAR calculation (29.4 rem).
The licensee used the results of the new control room dose calculation
and the completed control room differential pressure surveillance tesi
as the basis to declare the CREVS operable and exit the LCO on
November 3, 1996. The written operability assessment declared the
system fully operable and not degraded. Corrective actions described in
LER 50-254/96-022, dated November 25, 1996, included a revision of the
control room habitability study and new submittal to the NRC but had not
included plans to restore the plant to the original design basis as
described in the UFSAR.
The inspectors concluded that several discrepancies continued to exist
between the UFSAR and plant conditions after the licensee determined
that the CREVS was operable on November 3. On November 27, 1996, the
licensee informed the inspectors that as of November 26. the licensee
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planned to restore the system to its original design basis, while !
- pursuing an update to the control room habitability study. At the end
- of the inspection period, the licensee developed a schedule for l
3 restoring the CREVS to its design bases, l
i
From November 3, when the CREVS was declared operable, to November 26, 1
4
the licensee did not plan to restore the CREVS to correct the identified l
- UFSAR discrepancies. This de facto change in the facility was subject !
to 50.59 review. Failure to perform this required evaluation was an-
i
,
Apparent Violation of 10 CFR 50.59, " Changes, Tests, and Experiments."
i
c. Conclusion
'
The inspectors concluded that the licensee had failed to ensure that I
- !
i testing associated with the CREVS was adequate to verify that the system - ;
- could perform as described in the UFSAR. The licensee's actions after
identifying this inadequacy appeared to be technically adequate to
ensure operability of the system in that radiation exposure to control !
rcom operators would not have exceeded GDC 19 limits. However, the i
i licensee had not properly im]lemented the procedures re !
-
regulations for evaluating clanges to the design basis. quired by the
\ !
l
E2.2 Engineerino Review of Post Modification Testino Reveals Deficiencies )
.
, a. Insoection Scoce
- The inspectors reviewed the circumstances surrounding the licensee's
1
f failure to adeguately test equipment after design modification. The l
inspectors reviewed PIFs and licensee reports, interviewed engineers and
]; engineering management, and attended several PORC meetings.
b. Observations and Findings
.
In November 1996, the licensee identified an issue regarding improper
i closure of a review of modifications conducted in 1993. In response to
a violation cited by the NRC in inspection report 50-254/265-93012, the
licensee committed to review a sample of old modifications for !
i appropriate post modification testing. That review of 31 modifications l
- was completed in October 1993 but produced 6 operability concerns and
! numerous other issues. The review questioned whether the operability
concerns were properly closed and if the scope had been expanded.
4
The licensee formed a team to review the issue. Three PIFs (96-3199,
-
96-3612, 96-3229) were generated which identified modifications that had
- testing deficiencies. The licensee wrote and performed tests to address
- the deficiencies. In addition, the licensee expanded the scope of the
1 review of old modifications.
,
The ins)ectors planned to inspect the results of the licensee's review
after t1e completion of the additional scope. This is considered to be
Inspector Followup Item (50 254/265-96017 05(DRS)).
22
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c. Conclusion !
The inspectors noted that the licensee's response to the issue was
prompt and appeared to be comprehensive. The inspectors will review the
licensee's corrective actions to the identified deficiencies upon
completion.
E3 Engineering Procedures and Documentation
E3.1 Technical Soecification Review
a. Insoection Scooe (37551)
The inspectors compared the licensee's surveillance procedures to I
Section 4.8.D of TS to determine if all TS surveillance requirements for 1
the CREVS were implemented into procedures. l
,
b. Observations and Findinos
In answering the inspectors' questions concerning testing Jerformed to
meet the requirements of TS' 4.8.0, the licensee informed t1e inspectors
that a procedure was not in place to meet requirement TS 4.8.D.4. Quad l
Cities Technical Staff procedure (0 CTS) 440-03, " Control Room Emergency
Filtration System (CREFS) Removal of Charcoal Adsorber Test Canister,"
Revision 3, had not adequately addressed the TS. Specifically, TS ;
4.8.D.4 required the licensee to remove a sample of charcoal adsorber :
for testing after CREFS exceeded 720-hours operating time. I
I
However, the licensce had not tracked the o)erating hours of the CREFS
and was not readily able to determine the CREFS operating history. The
licensee documented this condition on PIF 96-3413 and were attempting to 1
determine the operating time of CREFS using operating logs. The i
licensee confirmed the 720-hour operating history was not exceeded.
c. Conclusions
The ins)ectors identified a failure to incorporate TS requirements into
applica)le surveillance procedures which is a Violation (50 254/265-
96017-06) of 10 CFR Part 50, Appendix B, Criterion XI, " Test Control."
E3.2 Control Room Emeroency Ventilation System Ooerability Determination
a. Insoection Scoce (37551)
The inspectors reviewed the licensee's operability evaluation for the
CREVS, including portions of the control room habitability study
calculation. The inspectors also reviewed licensee documentation used
for testing in-leakage into the control room emergency zone, operating
procedures and applicable regulatory guides. The inspectors also
reviewed Section 6.4.1.1 of the UFSAR.
,
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b. Observations and Findinas
Or October 27, engineering determined the existing control room
configuration was unable to meet Section 6.4.1.1 of the UFSAR. This
section required the control room emergency zone be pressurized to at
least +1/8 inch differential pressure (d/p) with respect to adjacent i
areas. Engineering determined the CREVS could not meet the design !
functions and operations declared the CREVS inoperable on October 28.
The inspectors reviewed various documents associated with this issue and
noted weaknesses in the licensees approach for determining operability
of the CREVS.
i. Iodine Scrubbino Methodoloav
The licensee performed an operability evaluation and determined
4
'
the CREVS was operable based on a calculation of thyroid dose to
o)erators and measured control room emergency zone in-leakage.
Tie measured in-leakage was greater than the in-leakage assumed in
the UFSAR. The calculation concluded thyroid doses were below
10 CFR Part 50 Appendix A, Criterion 19 limits. The calculation
adopted new methodologies not previously utilized in the original
control room habitability study referenced in the UFSAR, including
removal of iodine by the torus.
I
Standard Review Plan (SRP) 6.5.5 allowed licensees to utilize
iodine scrubbing by the torus provided specific criteria were met.
Criterion II.3 of SRP 6.5.5, required licensees maintain charcoal
filters to the minimum level in Regulatory Guide (RG) 1.52,
Table 2. Table 2 required laboratory tests for a representative
filter sample meet less than 1 percent penetration. However,
TS 4.7.P.2.b. required the standby gas treatment system (SBGTS)
filter sample meet less than 10 percent penetration. The
inspectors considered the licensee had not met the provisions
allowed by SRP 6.5.5 for the iodine removal methodology. This is
considered an Inspector Followup Item (50 254/265-96017-07)
pending further NRC review.
ii. Station Buildino Ventilation Status Post-Accident
The licensee determined that a positive d/p could not be
maintained in the control room emergency zone without securing
Service Building Ventilation (SBV). The licensee changed OCOP
5750-09, "CREVS Operating Procedure," and OCOS 5750-02, "CREFS
Monthly Test," to ensure SBV was secured to maintain a positive
d/p in the control room emergency zone.
The inspectors questioned whether the licensee could take credit
for conditions established by manual intervention of a nonsafety-
related piece of equipment if it can affect safety-related
equipment during post accident conditions. The inspectors noted
SBV will be lost during a loss of offsite power (LOOP) concurrent
24
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-
.
,
with a loss of coolant accident (LOCA) but not during a LOCA
without LOOP unless secured by manual intervention. The
i
inspectors consider this an Inspector Followup Item (50-254/265-
96017-08) pending further NRC review.
iii. Reactor Power level Assumed in the Control Room Dose Calculation
"
The inspectors noted that the control room dose calculation had
, assumed that the reactor power level at the time of the accident
was 100 percent core thermal power. Both the calculation
.
' described in the UFSAR and the calculation performed for the
o)erability determination used 100 percent core thermal power.
i-
T1e inspectors questioned the licensee if the evaluation should
-
be done under the assumption that the reactor was operating at
-
'
102 percent core thermal )ower, as done in the LOCA analysis. The
licensee responded that t1is particular assumption would be re-
evaluated prior to performing the calculations for submittal to
.
the NRC. The inspectors consider this an Inspector Followup Item
- (50 254/265-96017 09) pending further NRC review.
- c. Conclusions
I The ins)ectors identified the above weaknesses in the licensee's
!
approac1 for determining control room operability in post accident -
- situations. These issues were considered Inspector Followup Items i
"
pending further NRC review.
E8 Hiscellaneous Engineering Issues (92902)
.1
l E8.1 (Closed) Licensee Event Report (LER) (50-265/95006): Motor Control
i Center 29-2 Main Feed Breaker Tripped Due to Inadequate Trip Setting.
- As documented in Inspection Reports 50-254/265-95007 and 95011, the
- events which resulted in generation of LER 50-265/95006 were the subject
j of an NRC enforcement conference held on November 25, 1995. This LER is
l closed.
,
, E8.2 (Closed) Insoection Followuo Item (50-254/265-94004-07): Prioritization
of Work Requests. As documented in IR 50-254/265-94004, the work
. control process was burdened by such a large number of nuclear work
j requests (NWRs) that only high priority corrective maintenance items
.
could be worked. In addition, there was no central focus on
- establishing equipment priorities.
t
As documented in IR 50-254/265-96010, the inspectors reviewed the
licensee s work control process and determined that a revised work
control rocess was in place which utilized both system engineers and
- lead uni planners to prioritize corrective maintenance activities.
This Inspection Followup Item is closed.
i
E8.3 (Closed) LER (50-254/94017): Banked Position Withdrawal Sequence Rules
J Violated Since October 1991 Due To Training, Procedure, and Work
- Practice Deficiencies In The Nuclear Engineering Group. As discussed in
$ 25
,
-d
'
+
-
-
1
\
IR 50-254/265-94028. Unresolved Item (URI) 50-254/265-94028-01 was
opened following discovery by the licensee that some control rods were
withdrawn in the incorrect sequence during reactor startups since
October 1991. This LER is administratively closed due to tracking it as
URI 94028-01. The URI is still open pending inspector review.
E8.4 (Closed) Unresolved Item 50-254/265-96014-05): Torus Baseplate Bolt
Inconsistencies Identified by the Inspector. The inspectors had
)
identified inconsistencies in the bolting on the torus system saddle'
sup) ort baseplates. The licensee engineers performed additional system
walcdowns and consulted with Duke Engineering and Services to provide an
engineering assessment to determine whether the existing conditions were
acceptable. Duke Engineering and Services Document 1598.00043.014 was i
submitted to the licensee design engineering supervisor on November 4, i
1996. The inspectors reviewed this document and discussed the contents
'
with the engineers. In conclusion the documentation provided by the
licensee verified that the as-found condition had not invalidated the
design basis of the torus bolting. The inspectors verified that all
observed inconsistencies were bounded by the design calculations. This
item is closed.
IV. Plant Sucoort
R1 Radiological Protection and Chemistry Controls
R1.1 Material Condition Isst'es Mfoctina ExDosures
The inspectors revie%ed operator logs, PIFs, and viewed activities in
progress. The inspectors interviewed operators maintenance personnel,
and radiological protection staff.
Due to various material condition concerns (See Section M2.3), the
inspectors noted additlonal radiation exposures were received in an
effort to either repair deficient material condition issues or to
continue operating the unit with the deficient material condition. For
example, operators were required to manually control gland seal
condenser level when both level control valves for Unit 1 were
inoperable. The local control station was in the feedwater heater bay;
an area of elevated radiation dose. This dose plus the dose to workers .I
attempting repairs on the valves may have been avoided with better {
repair efforts to these valves which have a history of problems. Dose
rates in the area of the valves were much lower with the Unit shut down.
The licensee did take efforts to reduce dose once both level control
valves failed by lowering power in order to make the repairs. Operators
were also required to enter the Unit 2 containment at power to manually
isolate a reactor water cleanup valve because the remotely operated
valve had not provided proper isolation when a leak on another valve
occurred.
26
l
1
.
.
V. Manaaement Meetinos
X1 Exit Meeting Summary
The inspectors 3 resented the inspection results to members of licensee
management at t1e conclusion of the inspection on December 6, 1996. The
licensee acknowledged the findings presented. <
!
The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary. No proprietary information was
identified. ]
,
I
l
1
1
1
27
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.- -..,
, *
,
"
t
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i
l PARTIAL LIST OF PERSONS CONTACTED
l
!
Comed
,
B. Pearce Station Manager ,
- F. Famulari, Site OV Director r
4
J. Hutchinson, Engineering Manager -
.
F. Tsakeres, Radiation Chemistry Superintendent :
l M. Wayland.. Maintenance Superintendent
i
1
- INSPECTION PROCEDURES USED l
!
>
IP 40500: Effectiveness of Licensee Controls in Identifying, Resolving, and l
. Preventing Problems . l
IP 62703: Maintenance Observation
j
'
IP 64704: Fire Protection Program
IP 71707: Plant Operations
! IP 71714: Cold Weather Preparations
. IP 73051: Inservice Inspection - Review of Program
IP 73753: Inservice Inspection
-
IP 83729: Occupational Exposure During Extended Outages
i
IP 83750: Occupational Exposure
IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power
Reactor Facilities
IP 92902: Followup - Engineering
. IP 92903: Followup - Maintenance
j IP 93702: Prompt Onsite Response to Events at Operating Power Reactors
!
!
, 2
i
28
-.
.
}
!
ITEMS OPENED, CLOSED. AND DISCUSSED
Opened
50-254/265-96017-01 URI Joor understanding and control of licensing
] asis
50-254/265-96017-02 VIO use of incorrect bolt material in RHRSW LP pumps
50-254/265-96017-03 NCV Unit 2 operated past 30 days allowed by TS
50-254/265-96017-04 VIO failure to report prohibited plant condition
within 30 days
50-254/265-96017-05 IFI engineering review of post modification testing
reveals deficiencies
50-254/265-96017-06 VIO failure to incorporate TS requirements into ;
applicable surveillance procedures
50-254/265-96017-07 IFI iodine scrubbing methodology
50-254/265-96017-08 IFI station building ventilation status post-
accident
50-254/265-96017-09 IFI reactor power level assumed in the control room
dose calculation
_C_l? sed
50-254/265-94004-23 URI reactor vessel temperatures not recorded during
cooldown
50-254-94011 LER control cod L-11 failed to scram during rod time
testing i
50-254/265-94017-01 VIO violation of procedure adherence, test control, !
and corrective actions associated with failure
of a control rod scram during testing
50-254/265-96011-04 VIO three examples of workers not properly executing
work
50-254/265-96002-08 VIO improper storage of EDG air start motors
50-265/95006 LER MCC 29-2 main feed breaker tripped due to
inadequate trip setting
50-254/265-94004-07 IFI 3rioritization of work requests ,
50-254/94017 LER Janked position withdrawal sequence rules !
violated since October 1991 due to training, ;
procedure, and work practice deficiencies in the
nuclear engineering group
50-254/265-96014-05 URI torus baseplate bolt inconsistencies identified
by the inspector
29
_ _ _._ .._ _.._ _ _ _ _.__.__ _ _ _
'
- .
i
.
LIST OF ACRONYMS USED
'
CFR - Code of Federal Regulations
'
CREFS - Control Room Filtration System
CREVS - Control Room Emergency Ventilation System
4 CST - Central Standard Time
d/p -
differential pressure
DET -
Diagnostic Evaluation Team
DRP - Division of Reactor Projects
EA -
Enforcement Action
'
EDGCW - Emergency Diesel Generator Cooling Water
- ENS - Emergency Notification System
- FME -
! GDC - General Design Criteria
! HP - High Pressure
. HPCI - High Pressure Coolant Injection System
-
HVAC - Heating, ventilation, and air conditioning
,
IDNS - Illinois Department of Nuclear Safety
i IR -
Inspection Report
i LC0 -
Limiting Condition for Operation
- LCV - Level Control Valve
LER - Licensee Event Report
i LOCA -
Loss of Cooling Accident
i LOOP - Loss of Offsite Power
,
'
LP - Low Pressure
LPCI -
Low Pressure Coolant Injection
4 MMD - Mechanical Maintenance Department
i MWe - Megawatts Electric
NRR - NRC Office of Nuclear Reactor Regulation
. NWR - Nuclear Work Request
- PDR -
Public Document Room
. PIF - Problem Identification Form
1
' PM - Planned Maintenance
PMT -
Post Maintenance Testing
- PORC -
Plant On-site Review Committee
i
OCOP -
Quad Cities Operating Procedure
QCOS - Quad Cities Operating Surveillance
'
.
OCTS - Quad Cities Technical Staff Procedure
t RG -
Regulatory Guide
!
RHRSW - Residual Heat Removal Service Water
i RPM -
revolutions per minute
2
RWCU - Reactor Water Clean Up
! SBV - Service Building Ventilation
- SCFM -
Standard Cubic Feet per Minute
- SRP - Standard Review Plan
- TS - Technical Specification
i
'
UFSAR - Updated Final Safety Analysis Report
j URI -
Unresolved Item
i
$
) 30
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