ML20134M988
| ML20134M988 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 08/20/1985 |
| From: | Wright G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20134M971 | List: |
| References | |
| TASK-2.B.3, TASK-2.F.2, TASK-TM 50-254-85-17, 50-265-85-19, NUDOCS 8509040367 | |
| Download: ML20134M988 (15) | |
See also: IR 05000601/2007031
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U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Reports No. 50-254/85017(DRP);50-265/019(DRP)
Docket Nos. 50-254; 50-265 Licenses No. DPR-29; DPR-30
Licensee: Comonwealth Edison Company
Post Office Box 767
Chicago, IL 60690
Facility Name: Quad Cities Nuclear Power Station, Units 1 and 2
Inspection Conducted: June 1 through July 31, 1985
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Inspectors: A. L. Madison
A. D. Morrongfello
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Approved By:, . t h
Reactor Projects Section 2C
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Inspection Summary:
Inspection on June 1 through July 31, 1985 (Reports No. 50-254/85017(DRP);
50-265/85019(DRP))
Areas Inspected: Routine, unannounced inspection by the resident inspectors
of actions on previous inspections findings; operations; radiological
controls; maintenance / modifications; surveillance; bousekeeping procedures;
fire protection; emergency preparedness; security; quality assurance; quality
control; administration; routine reports; LER review; TMI items; Review and
Audits including Site Review Committee; Receipt, storage and handling of
Equipment Program; Spent Fuel Pool Activities; and independent inspection.
The inspection involved a total of 391 inspector-hours onsite by two NRC
inspectors, including 80 inspector-hours onsite during off-shifts.
Results: Two violations were identified. The first involved inadequate
shift turnover and the second lack of proper protective covers for safety
related items in storage. Additionally, an item of concern relating to safety
system challenges was identified in the maintenance area. Overall, the
- licensee's performance has remained steady.
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8509040367 85082124
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DETAILS
1. Persons Contacted
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- N. Kalivianakis, Superintendent
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- D. Bax, Assistant Superintendent for Maintenance
T. Lihou, Technical Staff Supervisor
- R. Roby, Senior Operating Engineer
- N. Griser, Senior Quality- Assurance Specialist
The inspectors also interviewed several other licensee employees,
including shift engineers and foremen, reactor operators, technical
staff personnel, and quality control personnel.
- Denotes those present at the exit interview on July 31, 1985.
- 2. Routine Inspection
The resident inspectors, through direct observation, dis'cussions with
licensee personnel, and review of applicable records and logs, examined
the areas stated in the inspection summary and accomplished the following
inspection modules.
37700 Design Changes and Modifications
38702 Receipt, Storage and Handling of
Equipment Program
40700 Review and Audits, including State
Review Committee
42700 Plant Procedures
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61726 Monthly maintenance observations
62703 Monthly maintenance observations
71707 Operational safety verification
, 71710 ESF system walkdown
- 86700 Spent Fuel Pool Activities
90713 Review of periodic and special
reports
j 92700 Onsite review of LERs
92701 TMI Action Items
92706 Independent inspection
93702 Onsite followup of events
The inspectors verified that activities were accomplished in a timely
manner using approved procedures and drawings and were inspected / reviewed
as applicable; procedures, procedure revisions and routine reports were
in accordance with Technical Specifications, regulatory guides, and
industry codes or standards; approvals were obtained prior to initiating
any work; activities were accomplished by qualified. personnel; the
limiting conditions for operation were met during normal operation and
while components or systems were removed from service; functional testing
and/or. calibrations were performed prior to returning components or
systems to service; independent verification of equipment lineup and
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review of test results were accomplished; quality control records and
logs were properly maintained and reviewed; parts, materials, and
equipment were properly certified, calibrated, stored, and or maintained
as applicable; and adverse plant conditiens including equipment
malfunctions, potential fire hazards, radiological hazards, fluid leaks,
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excessive vibrations, and personnel errors were addressed in a timely
manner with sufficient and proper corrective actions and reviewed by
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appropriate management personnel.
Further, additional observations were made in the following areas:
' Action on Previous Inspection Findings
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a.
] (Closed) Open Item 254/85007-01 and 265/85007-02: Install 48V
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Battery Seismic - side Spacing. Problems. This item was used to
track completion of modifications to the station 48V batteries to
, correct side spacing problems. It was determined by the licensee
I that adjustments could be made to the existing battery supports and,
therefore, no modifications were required. Proper adjustments were
i made. No further actions are required.
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(Closed) Open Item 265/85004-01: No Procedures For Dropped or
Otherwise Damaged Fuel Bundle. This item addressed concerns with
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the adequacy of the licensee's refueling procedures and identified
the following weaknesses:
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(1) No procedures for the refueling crew in the event of a dropped
or otherwise damaged fuel bundle.
(2) No requirements to ensure adequate radiation monitoring during
fuel movement.
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(3) No guidance given in the event of a loss of water level during
refueling operations.
! The licensee initiated changes to appropriate procedures to address
l these weaknesses prior to refueling operations on Unit 2. The
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inspectors reviewed these changes and found them adequate. No
further actions are required.
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(Closed) Open Item 254/85012-02 and 265/85013-02: Station Battery
Surveillance and Maintenance Procedure Changes. This item was used
to track procedure changes to address the following two concerns:
(1) No post-maintenance testing following cell jumpering or
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replacement.
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(2) No requirement for float charge as part of initial conditions
'for weekly and quarterly surveillances.
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Changes to appropriate procedures have been accomplished and
reviewed by the inspectors. No further actions are required.
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No violations or deviations were identified.
b. Operations
Unit I was in operation at the beginning of the report period. On
June 8, 1985, a Residual Heat Removal Services Water (RHRSW) pump
was found to have a broken seal cooling water line. This placed the
Unit in a 30 day Limiting Condition for Operation (LCO). During
testing of equipment required by the LCO, it was discovered that the
Torus Spray Valve would not open. Since the requirements of the LCO
could not be met, an Unusual Event was declared and a shutdown was
initiated. Subsequently, the RHRSW pump and valve were repaired and
returned to service and the Unusual Event and the shutdown were
terminated.
On June 17, 1985, a vent line on 1 C RHRSW pump ruptured, spraying
water on 1 B RHRSW pump and the 1/2 Diesel Generator service water
(DGSW) pump. This placed Unit 1 in an Unusual Event and an orderly
shutdown was initiated. Several hours later the leak was stopped
and the 1 B RHRSW pump and 1/2 DGSW pump were returned to service.
The Unusual Event and the shutdown were then terminated.
On July 11, during panel checks for shift turnover on Unit 1, it
was found that the High Pressure Coolant Injection (HPCI) controller
had been left in the manual position instead of automatic following
testing. This was the second shift change to occur following
completion of testing. The controller was set to 100% so HPCI would
have injected adequate cooling water upon an initiation signal.
However, QAP 300-7: " Shift Change Nuclear Station Operators",
requires that both the offgoing and oncoming operators check the
control room panels pursuant to QOS 005-2: " Normal Control Room
Inspection and Shift Turnover Panel Check". QGS 005-2 requires the
HPCI flow controller to be in automatic.
The initiating cause was an inadequate test procedure which did not
require the controller to be returned to automatic. Personnel error
on the part of the offgoing and oncoming operators in not performing -
an adequate shift turnover allowed the controller to remain in that
condition. This is a violation (254/85019-01(DRP)).
On July 25, 1985, the licensee declared an Unusual Event when it was
determined that the room cooler for one RHR corner room uas inoperable.
This made two RHR pumps inoperable and a third was already out of
service for repair purposes. Therefore, with three out of four RHR
pumps inoperable, an orderly shutdown was commenced. Several hours
later the room cooler was repaired and the Unusual Event and Shutdown
were terminated. Unit I remained at full power at the close of the
report period.
Unit 2 was shut down for a maintenance and refueling outage at the
beginning of the report period. On June 5, 1985, the unit returned
to power and, except for minor reductions for testing and load
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dispatcher requirements, remained at power throughout the remainder
of the report period. The smooth startup and relatively trouble
free operation of Unit 2 are evidence of an effective maintenance
program.
-During plant tours of Units 1 and 2, the inspectors walked down the
accessible portions of the Standby Liquid Control Systems, the
Standby Gas Treatment Systems, and the Reactor Core Isolation
Cooling Systems and performed the applicable portions of Inspection
Procedure 71710 "ESF System Walkdovn".
No other violations or deviations were identified.
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c. Radiological Controls
On July 24, 1985, the licensee confirmed that a pipe used to transfer
processed water from the liquid radwaste treatment facility to the
Condensate Storage Tanks (CST) had developed a leak. The pipe is
five feet below ground and covered by the radwaste concrete floor.
Discovery was made due to water seepage through the floor. The
licensee has isolated the pipe and intends to replace it with above
ground piping.
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Initial on-site sampling and observations by the licensee indicate
that no off-site releases have occurred. The concentration of
activity in the CST based on a gamma isotoxic analysis is below the
maximum permissible concentration for unrestricted release. The
licensee and Region III are continuing to investigate this matter.
Final resolution will be tracked as an Open' Item (254/85017-02(DRP)
and 265/85019-01(DRP)).
No violations or deviations were identified.
d. Maintenance
The following activities were observed / reviewed:
(1) Observed repair work and installation of IB Turbine oil cooler.
(2) Observed mechanical repair work on 2A Recircult:fon Motor
Generator.
(3) Observed mechanical repair work on 1A Diesel fire pump.
(4) Observed electrical repair work on IB Service Water motor.
(5) . Reviewed replacement of IB Residual Heat Removal Pump.
(6) Reviewed repairs to Unit 2 Scram Discharge Volume
Instrumentation.
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On July 29, 1985, Unit 2A Fuel Pool monitor tripped spuriously
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causing an automatic initiation of Standby Gas Treatment. All
systems responded as required. This is not a significant safety
issue. However, a large number of spurious trips have occurred in
the recent past as documented in LER 85005, 85012, and 85014 for
Unit 1, and this has resulted in excessive challenges to plant
safety systems. Also normal corrective maintenance does not appear
effective in preventing these spurious actuations. This is an item
of concern and will be tracked as an Unresolved Item (254/85017-03
The licensee has been requested to respond in writing identifying
what actions are intended to eliminate any further spurious
actuations and the schedule for completion of these actions.
i No violations or deviations were identified.
e. Surveillance
The following activities were observed / reviewed:
, (1) Observed High Pressure Coolant Injection overspeed test for
Unit 2.
(2) Observed hot scram timing for Unit 2.
(3) Observed Unit 1 Power Operation Fcnctional Test (QIS - 60).
(4) Observed Unit 2 Reactor High Pressure Automatic Blowdown
l Calibration.
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(5) Observed Unit 2 Main Steam line Radiation Scram and Isolation
testing (QIS - 31).
(6) Observed magnetic particle testing of lift piers for turbine
strongback.
(7) Observed Unit 2 Vessel level instrument calibration checks.
(8) Observed Unit 1 Local Power Range Monitor calibration and
associated Transverse Incore Probe operations.
(9) Reviewed Operability testing of Unit 2 Reactor Core Isolation
Cooling system.
No violations or deviations were identified.
f. Procedures Reviewed
The following procedures were reviewed:
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QIS 34-1 Rev. 7 Reactor Building Ventilation Monitoring
Calibration
QIS 34-2 Rev. 6 Reactor Building Ventilation Monitoring
Functional Test
QOA 4100-2 Rev. 2 Fire Protection System Failure
90A 1700-5 Rev. 3 Main Steam Line High Radiation
Q0A 5450-6 Rev. 6 Off-Gas Recombination at a Location Other Than
the Recombiner
QOP 020-1 Rev. 3 (1 9ning a Penetration in Secondary Containment
QMP 100-12 Rev. 5 Electrical Maintenance of Safety-Related and
Non-Safety-Related Motor Operated Valves
QMP 100-2 Rev. 4 Control and Handling of Welding Electrodes and
Bare Wire
QMP 300-5 Rev. 6 Steam Separator Removal
QRP 1210-2 Rev. 2 Film /TLD Badge Issuance and Completion of
Occupational External Radiation Exposure
History Form (NRC)
QIS 27-1 Rev. 6 HPCI Turbine Area High Temperature Isolation
Calibration
QIS 45-1 Rev. 2 Primary Containment CAM Radiation Monitor
Source Calibration Check
QMS 200-S3 Rev. 5 Diesel Inspection - Monthly
QMS 7500-1 Rev. 4 Standby Gas Treatment Automatic Start
QOS 005-2 Rev. 8 Normal Control Room Inspection and Shift
Turnover Panel Check
QOS 500-1 Rev. 6 Mode Switch in Shutdown; Scram Instrumentation
Functional Test
QRP 1170-1 Rev. 1 Administrative Controls for Health Physics
Instrumentation
QRP 1610-S4 Rev. 5 Access Control Point Checklist
QOP 1900-19 Rev. 1 Discharging Fuel Pool Cooling into the RHR
Injection Loop
QOP 201-4 Rev. 1 Draining Reactor Cavity to the Suppression
Chamber
QTP 500-6 Rev. 3 Guidelines for Development of Tests for
Modifications
QTP 500-11 Rev. 23 Safety-Related, Code-Related, and Engineering
Assisted Modifications
QTP 500-12 Rev. 19 Non Safety-Related, Non Code-Related Non
Engineering Assisted Modifications
QDM-11 Rev. 12 Drawing and VETI Control for Work Requests,
Procedures, and Plant Modifications
QDM-11-T1 Rev. 3 Central File Document Update Notice
QDM-14 Rev. 1 Processing of Controlled Vendor Equipment
Technical Information (VETI) Document
QOP 6900-1 Rev. 5 250 VDC Electrical System
QOP 6900-2 Rev. 5 125 VDC Electrical
QOP 6900-3 Rev. 6 48/24 VDC Electrical System
QOS 6900-1 Rev. 10 Station Battery Weekly Surveillance
QOS 6900-2 Rev. 8 Station Battery Quarterly Surveillance
QOS 6900-4 Rev. 2 Station Battery Monthly Surveillance
QOS 6900-S1 Rev. 11 Station Batteries (Weekly)
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QOS 6900-S2 Rev. 10 250 VDC Station and Computer UPS Batteries
(Quarterly)
QOS 6900-S3 Rev. 8 125 VDC Station Batteries (Quarterly)
QOS 6900-S4 Rev. 9 24/84 VEC Station Batteries (Quarterly)
QOS 6900-S6 Rev. 3 Station Batteries (Monthly)
g. Review of Routine and Special Reports
(1) The inspectors reviewed the monthly performance report for
Units 1 and 2 for the months of May and June, 1985.
(2) The inspectors reviewed a special report detailing the actions
connected with finding that the recombiner for Unit I was not
put on the line prior to reactor. pressure reaching 900 psig as
required by the Technical Specifications.
On May 17, 1985, Unit I was in the STARTUP mode at less than 1 percent
thermal power. Control rods were being pulled and Reactor pressure
was increasing. During this time, difficulty was experienced with
condenser vacuum. This difficulty led to the belief that a possible
vacuum leak had developed, and therefore, efforts were concentrated
on locating the leak. Because of this preoccupancy with the potential
vacuum leak, a Recombiner was not put on-line when Reactor pressure
reached 700 psig as required by the Normal Startup Procedure. A
Recombiner is required to be in ope. ration whenever Reactor pressure is
above 900 psig in accordance with Technical Specification 3.8.A.5.a.
Hofever, Technical Specification 3.8.A.S.b allows the Recombiner to
be made inoperable for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. In this case, Reactor pressure
reached 900 psig at approximately 3 a.m. on May 17, but the 1A
Recombiner was not put on-line until approximately 8 a.m. on May 17
when Unit I was operating at 458 MWt. No equipment failures were
involved, therefore, no action was required to prevent a recurrence
of equipment failures, and the 1A Recombiner was put on-line using
normal procedure.
The immediate corrective action upon discovery was to put the 1A
Recombiner on-line. Because the Shift Engineer has the ultimate
responsibility of seeing that plant operation is in compliance with
the plant's operating license and operating procedures, a discussion
with all Shift Engineers regarding this deviation was conducted by
Station management. This was the first time that Recombiner
operation was inadvertently overlooked since the new Technical
Specification requirement to have a Recombiner in operation when
Reactor pressure exceeds 900 psig took effect in December 1984.
Also, the Deviation Report was included in the Required Reading book
for all NS0's and SCRE's.
Because this error was identified by the licensee and prompt,
effective corrective actions were taken and because of the relative
safety significance of this event, no violation was issued.
No violations or deviations were identified.
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-h. LER Review
(1) (Closed) LER 85002, Revision 0: Unit 1 #4 Tip Ball Valve
On May 9,1985, while performing TIP system power operated
Valve Stroke Testing, #3 TIP Ball Valve failed to close
following testing. The unit was shut down and did not require
Secondary Containment at the time. The cause of the stuck ball
valve was a loss of lubrication. The valve was cleaned and
lubricated and returned to service on May 11, 1985. No further
actions are required.
(2) (Closed) LER 85003, Revision 0: Unit 1 Group II Isolation and
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'A' Standby Gas Treatment Failure To Start On May 17, 1985,
while Unit 1 was in the RUN mode and Unit 2 was in COLD SHUTDOWN,
Unit 2 received an unexpected Group II isolation signal. This
signal occurred when the test for a modification tripped Group
II Channel B. Group II Channel A was previously tripped due to
the removal of the 2A Drywell radiation monitor for maintenance.
Upon receipt of the Group II isolation signal, the 'B' Standby
Gas Treatment System (SBGTS) (BH) auto-started. The 'A' SBGTS,
which was selected as primary, failed to start. When the 'B'
SBGTS started it was immediately noticed that the heater did
not energize. An Operator was sent to investigate and he
discovered that the breaker for the heater was tripped.
The breaker was reset and the normal differential temperature
across the heater was established. Repeated attempts were
performed to duplicate the 'A' SBGTS failure to start, but in
every case the 'A' SBGTS properly served its function. After
further investigation, it was postulated that the cause of the
'A' SBGTS failure to start was a degradation of the auto-start
relay 595-133. The similar relay on 'B' SBGTS caused an
identical failure of 'B' to start on June 5,1985. The relay
failure was intermittent in nature, causing a failure to start
in 1 out of 3 cases.
The breaker trip appears to have been caused by a faulty breaker
which was replaced after it totally failed on June 12,.1985.
.The personnel error and communication problem involved in testing
Channel B while a Trip signal was present on Channel A was
discussed with the licensee (See Report 254/85012 and 265/85013)
and adequate corrective actions were taken. As such, no further
actions are required.
(3) (Closed) LER 85004, Revision 0: Unit 1 Loss of Essential
Service System Bus.
On May 23, 1985, the Essential Service System (ESS) Uninter-
ruptible Power Supply (UPS) failed causing a half scram and an
auto-start of the 'B' Standby Gas Treatment System. The ESS
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Bus transferred to its AC backup. This event occurred again at
10:08 a.m. on June 12, 1985, when the UPS was repaired and the
feed was transferred from its reserve feed to the normal feed.
The UPS failed due to the failure of two transistors in the
Inverter Logic Power Supply. All circuitry was repaired and
the UPS was successfully returned to service at 10:08 a.m. on
June 12, 1985. No further actions are required.
(4) (Closed) LER 85005, Revision 0 and Revision 1: Unit 1A Fuel
Pool Monitor - Various Trips.
As noted in Section d. of this report, concerns related to this
LER and others have been addressed as an Unresolved Item and
the Licensee has been requested to respond in writing.
Therefore, tracking of this issue will be handled in that
manner.
(5) (Closed) LER 85006, Revision 0: Unit 1 Reactor Scram From
Group I Isolation.
On May 30, 1985, while valving in Pressure Transmitter PT
1-5641-2, Instrument Rack 2251-1 began to vibrate. This rack
contains pressure switches which actuate a Group I isolation en
Main Steam Line low pressure. The vibration on Instrument Rack
2251-1 caused these pressure switches to trip initiating a
Group I isolation. The reactor then scrammed from Main Steam
Isolation Valve (MSIV) closure. The MSIVs were reopened and
the Bypass Valves opened to lower Reactor pressure. Reactor
water level decreased rapidly. A Reactor feed pump was started
to replace the lost inventory. A second Reactor scram occurred
at 6:07 p.m. due to low Reactor water level. A minute later,
Reactor water level was restored to normal.
The licensee is investigating possible engineering solutions
to reduce the potential for this event. Also, in the future,
when valving in on this rack, Instrument Maintenance will
pre pressurize the sensing line to prevent vibration. No
further actions are required.
(6) (Closed) LER 85007, Revision 0: Unit 1A Fuel Pool Monitor Trip.
See Item 4.
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(7) (Closed) LER 85008, Revision Oi 1/2 Diesel Generator Cooling
Water Pump and 1B Residual Heat Removal Service Water Pump Out
of Service.
On June 17, 1985, a high level alarm was received from the
IB/1C Residual Heat Removal Service Water (RHR) vault sump.
The IC RHR Service Water Pump was immediately tripped and an
Equipment Attendant was dispatched to investigate. It was
discovered that a broken vent line on the 1C RHR Service Water
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Pump existed and that the vault was partially filled with
water. As a precautionary measure, the 1B RHR Service Water
Pump and the 1/2 Diesel Generator Cooling Water Pump were
declared inoperable because they are locted in the same room.
This action rendered the 1/2 Emergency Diesel Generator
inoperable. Electrical integrity tests were performed on all
the motors and showed all parameters to be normal. The'1C RHR
Service Water Pump was repaired on June 18, 1985. The 1/2
Diesel Generator Cooling Water Pump and the IB RHR Service
Water Pump were also returned to service on June 18, 1985. No
further actions are required.
(8) (Open) LER 85011, Revision 0: Unit 1 Scram and Loss of Unit 2
Auxiliary Power.
On May 7,.1985, Unit l'was in the RUN mode and Unit 2 was in
COLD SHUTDOWN. Contractor personnel working on roof repairs
were attempting to connect a power cord for a drill to an AC
outlet located near the ground below. While lowering the cord
from the roof, a sudden 'A' phase to ground fault occurred.
This fault opened oil circuit breakers, which caused a loss of
normal auxiliary power to Unit 2. Diesel Generator 1/2 auto-
started and closed-in to Bus 23-1 on a Bus 23-1 undervoltage
signal. Unit 2 remained stable.
The electrical transient in the 345 KV switchyard caused a
transient on the Unit l' electrical system. The transient
caused a loss of 'A' Reactor Protection System Bus and a
lock-up of a Feedwater Regulating Valve. The locked-up
Feedwater Regulating Valve resulted in a high Reactor water
level condition which resulted in a Turbine trip, and Reactor
scram. Subsequently, a normal scram recovery was performed and
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all_ electrical systems were returned to normal. All systems
- and equipment functioned-as designed.
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- The auxiliary transformer was examined and damaged insulators
were found on the 'A' phase lines feeding the transformer. The
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i insulators were replaced and the transformer was returned to
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service on May 8, 1985. All systems and equipment functioned
L as designed and no changes were necessary. However, the
Station is considering a modification which may prevent losing
the feed to the RPS MG Set drive motor for similar faults on
the 345 KV system. The' modification involves a time delay
relay which allows the flywheel to.be more effective in
- performing its intended function.
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- This LER will remain open pending resolution of this modification.
(9)- '(Closed) LER 85014, Revision 0 and Revision 1: Unit 1A Fuel
Monitor Trip.
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(10) (Closed) LER 85006, Revision 0 and Revision 1: Unit 2 Main
Steam Isolation Valves Failed Local Leak Rate Testing.
The licensee has submitted a supplemental report detailing the
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amount of leakage and the repairs performed to correct the
sealing surface wear. No further actions are required.
(11) (Closed) LER 85007, Revision 0 and Revision 1: Unit 2 Local
i Leak Rate Tests Exceeded Limits.
The licensee has submitted a supplemental report detailing the
amount of leakage and the repairs performed to correct problems
found. No further actions are required.
(12) (Closed) LER 85008, Revision 0 and Revision 1: Unit 2
Recirculation Pipe Riser Crack.
The licensee has submitted a supplemental report delineating
crack indications found and corrective actions taken. No
further actions are required.
(13) (Closed) LER 85012, Revision 0: Unit 2 Group II Isolation.
On May 20, 1985, the main feed breaker to Bus 24-1 tripped
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during testing by the Operational Analysis Department (OAD).
The Unit 2 Diesel Generator was already running for testing and
it was feeding Bus 24-1. Because the Diesel Generator was then
carrying the full load of Bus 24-1, Diesel Generator load went
y from 700 KW to 2500 KW. Since the unit operator was not aware
3' of the cause of the breaker trip, the Diesel Generator was
tripped. This caused a one/ half Group II isolation. The other
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half of the Group II isolation logic was already satisfied
because the 2A High Drywell Radiation Monitor was removed for
maintenance. This started the Standby Gas Treatment System
(SBGTS).
After it was determined that OAD personnel had tripped the main
feed breaker to Bus 24-1, normal power was restored to the Bus.
The Group II isolation was reset and the SBGTS was secured.
Station Management immediately stopped all OAD work. The
following day it was emphasized to 0AD that all work performed
at the Station must be done under the control of a Work Request.
The Work Request that controlled the wiring verification did
not allow the movement of any relays. The personnel involved
with this incident were cautioned to not operate outside of a
Work Request. This prompt action by Station Management should
prevent future recurrence. Because of this prompt corrective
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action and the relative safety significance of the event, no
violation will be issued.
(14) (Closed) LER 85013, Revision 0: Unit 2 loss of Emergency
- Diesel Generators.
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On May 22, 1985, Unit 2 was in the REFUEL mode. The 1/2 Diesel
Generator was out of service while the Electrical Maintenance
Department was performing QMS 700-5, " Core Spray Logic Functional
Test". In accordance with the test,.the Unit 2 Diesel Generator
started. The Diesel Generator only ran 30 seconds when it
tripped out mechanically on overspeed. A Generating Station
Emergency Plan (GSEP) Unusual Event was declared since Unit 2
had no operable Diesel Generator. The 1/2 Diesel Generator was
immediately returned to service. The Unit 2 Diesel Generator
trip was caused by the governor compensating mechanism being
out of adjustment. It was readjusted and the Diesel Generator
was returned to service on May 24, 1985.
No further actions are required. ,
(15) (Closed) LER 85014, Revision 0: Unit 2 Scram From Surveillance
Procedure.
On May 31, 1985, the surveillance Q0S 1600-11, " Primary
Containment Isolation (PCI) Simulated Automatic Close
Initiation Test" was performed. In the course of adhering to
the procedure, a full scram was initiated. The cause of the
scram was an inadequacy of the procedure. The procedure called
for resetting the alarms, but did not require the resetting of
a 1/2 scram signal initiated on a previous step. A full scram
was, therefore, initiated. The procedure was modified to
require resetting of the 1/2 scram signal before tripping the
other channel.
No further actions are required.
No violations or deviations were identified.
i. TMI Action Items
(1) (Closed) Item II.B.3 Post-Accident Sampling
NRR has issued a Safety Evaluation Report (SER) dated
July 23, 1985 accepting the licensee's Post-Accident sampling
system. The resident inspectors have verified that the
licensee's program does correspond to their submittal.
No further actions are required.
(2) (0 pen) Item II.F.2 Inadequate Core Cooling Instrumentation.
NRR has issued a SER dated June 5, 1985 accepting the licensee's
submittal to comply with this requirement. Actions associated
with replacement of mechanical level indication equipment has
been accomplished and reviewed by the resident inspectors.
Actions to address reference leg overheating are scheduled to
be completed sometime in 1988 and will be reviewed at that time.
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j. Receipt, Storage and Handling of Equipment Program
The inspectors reviewed the licensee's program for receipt, storage
and handling of equipment in accordance with Inspection Procedure
38702 and found it to be acceptable. However, during a tour of the
station warehouse two safety related check valves were found to be
without protective covers as required by QAP 300-13 (1976): Levels
of Storage and Inspection Criteria and ANSI N45.2.13(1976) Quality
Assurance Requirements for Control of Procurement of Items and
Services for Nuclear Power Plants which refers to ANSI 45.2.2 (1972)
Packaging, Shipping, Receiving, Storage and Handling of Items for
Nuclear Power Plants for additional requirements. This is a
violation (254/85017-04(DRP) and 265/85019-03(DRP)).
When notified, the licensee placed protective covers on the valves.
No other violations or deviations were identified.
k. Design Changes and Modifications (40% complete)
The following modifications were reviewed and found to be in
conformance with the requirements of Technical Specifications and
10 CFR 50.59:
M-4-2-84-20 Indicating-lights for Control Valve Test Switches
M-4-2-84-30 Outer Bellows on Core Spray Penetration X-16B
M-4-2-85-20 Feedwater check valve pivot pin modification
M-4-1-85-1 SBLC swing pump - (This modification is still in
progress)
M-4-2-85-23 Fabricate sleeve for 2ARHR Pump Motor
M-4-2-85-13 Limitorgue Motor Operator - EQ Modifications
No violations or deviations were identified.
4. Regulatory Improvement Program Meeting
On July 16, 1985, a meeting was conducted between Ceco and Region III
management. The purpose of the meeting was to discuss additional aspects
of the licensee's Regulatory Improvement Program (RIP) which were
identified during the June 24, 1985 RIP meeting. This meeting was part
of the continuing series of management meetings aimed at improving
licensee regulatory performance and enhancing communications between the
NRC and Ceco.
5. Open-Items l
Open items are matters which have been discussed with the licensee, which
will be reviewed further by the inspectors, and which involve some action
on the part of the NRC or licensee or both. The open item disclosed
during the inspection is discussed in Paragraph 2c.
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6. Unresolved Items
Unresolved items are matters about which more information is required in
,
order to ascertain whether they are acceptable items, items of
j noncompliance, or deviations. The unresolved item disclosed during the
! inspection is discussed in Paragraph 2d.
j- .
1 7. Exit Interview
4
The inspectors met with licensee representatives (denoted in Paragraph 1)
- throughout the month and at -the conclusion of the inspection on
July 31, 1985, and summarized the scope and findings of the inspection
activities.
4
The inspectors also discussed the likely informational content of the
inspection report with regard to documents or processes reviewed by the
i inspectors during the inspection. The licensee did not identify any such
'
documents / processes as proprietary.
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