ML20203N156
| ML20203N156 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 09/12/1986 |
| From: | Fredrickson P, Garner L, Ruland W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20203N119 | List: |
| References | |
| 50-324-86-18, 50-325-86-17, NUDOCS 8609230172 | |
| Download: ML20203N156 (14) | |
See also: IR 05000324/1986018
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UNITES STATES
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NUCLEAR REGULATORY COMMISSION
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REGION 11
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101 MARIETTA STREET, N.W.'
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ATLANTA, GEORGI A 30323
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Report-Nos.: 50-325/86-17 and 50-324/86-18
l.icensee: Carolina Power and Light Company
P. O. Box 1551
Raleigh, NC" 27602
Docket Nos.: 50-325 and 50-324
License Nos.: DPR-71 and DPR-62
Facility Name: Brunswick 1 and 2
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Inspection Co(ducted:
Ju 7
-31, 1986
Inspectors:[
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Approved by:
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P. E. Fredrickson, Section Chief
ate Signed
Division of Reactor Projects
SUMMARY
Scope: This routine resident inspector safety inspection examined the areas of
maintenance engineered safety features observation, surveillance observation,
operational safety verification, onsite follow-up of events, survey of licensee's
response to selected safety issues, ESF system walkdown, and TIP tube reversal.
Results:
Two violations were identified:
failure to follow procedures
concerning smoking and failure to follow procedure concerning rigging scaffolding
to a snubber extension.
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REPORT DETAILS
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1.
Licensee Employees Contacted
P. Howe, Vice President - Brunswick Nuclear Project
C. Dietz, General Manager - Brunswick Nuclear Project
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T. Wyllie, Manager - Engineering and Construction
J. Holder, Manager - Outages
E. Bishop, Manager - Operations
L. Jones, Director - Quality Assurance (QA)/ Quality Control (QC)
R. Helme, Director - Onsite Nuclear Safety - BSEP
J. Chase, Assistant to General Manager
J. O'Sullivan, Manager - Maintenance
G. Cheatham, Manager - Environmental & Radiation Control
E. Enzor, Director - Regulatory Compliance
B. Hinkley, Manager - Technical Support
R. Groover, Manager - Project Construction
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A. Hegler, Superintendent - Operations
W. Hogle, Engineering Supervisor
B. Wilson, Engineering Supervisor
R. Creech, I&C/ Electrical Maintenance Supervisor (Unit 2)
R. Warden, I&C/ Electrical Maintenance Supervisor (Unit 1)
W. Dorman, Supervisor - Quality Assurance (QA)
W. Hatcher, Supervisor - Security
R. Kitchen, Mechanical Maintenance Supervisor (Unit 2)
C. Troubel, Mechanical Maintenance Supervisor (Unit 1)
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R. Poulk, Senior NRC Regulatory Specialist
D. Novotny, Senior Regulatory Specialist
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W. Murray, Senior Engineer - Nuclear Licensing Unit
W. Ziegler, Principal Engineer - Corporate Nuclear Fuels Section,
Operations Support
Other licensee employees contacted included construction craftsmen,
engineers, technicians, operators, office personnel, and security force
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members.
2.
Exit Interview (30703)
The inspection scope and findings were summarized on August 4,1986, with
the vice president and general manager.
The two violations, failure to
follow procedure regarding smoking and failure to follow procedure regarding
rigging scaffolding to a snubber attachment (parafcaph 6), were discussed in
detail. Also discussed was management tours of the vital areas (paragraph
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6). One Unresolved Item *, TIP Tubing Reversal (paragraph 10), was discussed
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with the general manager during a special meeting on July 25, 1986.
The
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- Unresolved items are matters about which more information is required to
determine whether they are acceptable or may involve violations or deviations.
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licensee acknowledged the findings without exception. The licensee did not
identify as proprietary any of the materials provided to or reviewed by the
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inspectors during the inspection.
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3.
Followup on Previous Enforcement Matters (92702)
Not inspected.
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4.
Maintenance Observation (62703)
The inspectors observed maintenance activit.ies and reviewed records to
verify that work was conducted in accordance with approved procedures,
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Technical Specifications, and applicable industry codes and standards. The
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inspectors also verified that:
redundant components were operable;
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administrative controls were followed; tagouts were adequate; personnel were
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qualified; correct replacement parts were used; radiological controls were
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proper; fire protection was adequate; quality control hold points were
adequate and observed; adequate post-maintenance testing was performed; and
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independent verification requirements were implemented.
The inspectors
independently verified that selected equipment was properly returned to
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service.
Outstanding work requests were reviewed to ensure that the
licensee gave priority to safety-related maintenance.
The inspectors observed / reviewed portions of ' the following maintenance
activities:
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86-BDAG1
2-G31-F001 Failed to Close on Group 2 Signal.
86-BDGB1
Reactor Manual Control System Inadvertent Rod
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Movements.
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86-BFFC1
Nuclear Service Water Low Pressure Annunciator
Transmitter Calibration.
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86-BFQA1
Work on G16-F003 Valve.
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MI-03-03A
General
Pressure / Vacuum
Switches
Instrument
Calibration.
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MI-03-4U12
Texas Instrument TIGRAPH 200 Recorder Calibration.
MI-03-38A5
General
Electric
Power
Supply
Type
570-06
Calibration.
No violations or deviations were identified.
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5.
Survei'.ance Observation (61726)
The inspectors observed surveillance testing required by Technical
Specifications.
Through observation and record review, the inspectors
verified that:
terts conformed to Technical Specification requirements;
administrative controls were followed; personnel were qualified; instrumen-
tation was calibrated; and data was accurate and complete. The inspectors
independently verified selected test results and proper return to service of
equipment.
The inspectors witnessed / reviewed portions of the following test activities:
E&RC-0358
Weekly Check of the Area Radiation Monitors High
and Low Setpoint Alarms.
E&RC-1221
Sampling and Analysis Procedure for Routine Steam
Jet Air Ejector Off-Gas Analysis.
E&RC-1222
Operat. ion of Gas Chromatograph.
E&RC-2016
Sampling and Analysis of Drywell Purges.
1 MST-PCIS25M
PCIS High Main Steam Line Flow Trip Unit Channel Al
Calibration.
01-03.1
Periodic
Testing
and Control Operator Daily
Surveillance Report - Unit 1.
01-03.2
Periodic
Testing
and Control Operator Daily
Surveillance Report - Unit 2.
PT-01.11
Core Performance Parameter Check.
No violations or deviations were identified.
6.
Operational Safety Verification (71707)
The inspectors verified conformance with regulatory requirements by direct
observations of activities, facility tours, discussions with personnel,
reviewing of records and independent verification of safety system status.
The inspectors verified that control room manning requirements of 10 CFR 50.54 and the Technical Specifications were met.
Control room, shift
supervisor, clearance and jumper / bypass logs were reviewed to obtain
information concerning operating trends and out of service safety systems to
ensure that there were no conflicts with Technical Specifications Limiting
Conditions for Operations.
Direct observations were conducted of control
room panels, instrumentation and recorder traces important to safety to
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verify operability and that parameters were within Technical Specification
-limits.
The inspectors reviewed shift turnover sheets to verify that
continuity of system status was maintained.
The inspectors verified the
status of selected control room annunciators.
Operability of a selected Engineered Safety Feature (ESF) train was verified
by insuring that: each accessible valve in the flow path was in its correct
position; each power supply and breaker, including control room fuses, were
aligned for components that must activate upon initiation signal; removal of
power from those ESF motor-operated valves, so identified by Technical
Specifications, was completed; there was no leakage of major components;
there was proper lubrication and cooling water available; and a condition
did not exist which might prevent fulfillment of the system's functional
requirements.
Instrumentation essential to system actuation or performance
was verified operable by observing on-scale indication and proper instrument
valve lineup, if accessible.
The inspectors verified that the licensee's health physics policies /
procedures were followed. This included a review of area surveys, radiation
work permits, posting, and instrument calibration.
The inspectors verified that: the security organization was properly manned
and security personnel were capable of performing their assigned functions;
persons and packages were checked prior to entry into the protected area
(PA); vehicles were properly authorized, searched and escorted within the
PA; persons within the PA displayed photo identification badges; personnel
in vital areas were authorized; and effective compensatory measures were
employed when required.
The inspectors also observed plant housekeeping controls, verified position
of certain containment isolation valves, checked a clearance, and verified
the operability of onsite and offsite emergency power sources.
a.
Open Control Room Airlock Doors
On July 8,1986, at about 7:15 a.m. , the inspector observed that both
doors of an airlock leading into the back of the control room were
open. The inner door had been removed for modification and the outer
door had been wired opened.
In accordance with the security plan, a
security guard was posted at the vital entrance, the inner door. The
passageway leads to a metal office building which had been added to the
radwaste roof after original construction.
Onshift responsible
personnel were unaware of the condition and ifad not authorized opening
of the outer door. At the time work was authorized, verbal instruc-
tions had been issued to keep the outer door closed. The outer door is
clearly marked as " Fire Door / Keep Closed." However, at the time, the
outer door was posted as being an inoperable fire door and was being
monitored by a roving fire watch.
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Final Safety Analysis Report, amendment No. 4, dated June 2,1986,
cescribes .the leak tightness and toxic gas protections of the control
room.
Section 6.4.2.4, Interaction with Other Zones and Pressure-
Cuntaining Equipment, states:
The following provisions were taken into consideration in the
Control Room Area Ventilation System design to assure that there
are no toxic or radioactive gases and other hazardous material
that would transfer into the Control Room:
(a) The Control Room envelope is maintained at static pressures
slightly higher than atmospheric to prevent infiltration from
the outside.
(b) Doors and other openings into the Control Room are
conspicuously marked to assure that they will normally remain
closed.
This administrative control will assure that the
Control Room normally remains closed. The doors are equipped
with reclosers.
Section 6.4.4.2 states:
Infusion of chlorine contaminated air will be inhibited by:
1)
Quick-acting dampers having a maximum travel time . of
five seconds or less.
Total
isolation time (time
between 5 ppm chlorine signal at the control room
chlorine detector and completed damper travel) require-
ment is less than or equal to 10 seconds.
2)
Tightly fitting and weather-stripped doors, and
3)
By having all cable conduits to the Control Room potted
or sealed.
In addition, Technical Specification 3.7.2 requires two control
room emergency filtration systems be operable or the unit must be
in at least hot shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in cold shutdown
within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. One of the conditions of operability is
the successful completion of surveillance requirement 4.7.2.d.4,
which requires every 18 months a verification that the system
maintains the control room at a positive pressure relative to the
outside atmosphere during system operation.
The licensee is investigating the event.
The licensee reports
that the outer door was opened between 6 and 7 p.m. on the
preceding day (July 7,1986), was closed about midnight and then
re-opened some time prior to the inspector's discovery. Hence, it
appears that the 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to be in hot shutdown was not exceeded.
Also, af ter the fact, the licensee performed a test with both the
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doors open and showed that with the emergency filtration system
operating, smoke would blow out the passageway away from the
control room.
The tank car siding chlorine monitors, not assumed
operable for the FSAR analysis, were also operable during this
time.
The licensee interviewed personnel involved. Because of the heat
and poor ventilation in the area, an individual apparently
attempted to find out why the outer door could not be opened. In
discussions with a non-licensed operations department staff
member, the individual thought that he had gotten permission to
leave the door open. However, the operations person, after seeing
that the fire door was already under fire watch, apparently
indicated that he saw no reason why it should not be opened. The
operations person believed that this was only for a short duration
to allow some air flow and did not intend to give the impression
that it could remain open.
This miscommunications led to the
first instance of wiring the door open. The circumstances around
the second instance is still being reviewed.
During the review, the licensee determined that the on-duty senior
auxiliary operator, a licensed individual, and a shift technical
advisor made one or more entrances or exits through the passageway
while both doors were open.
Neither apparently recognized that
the condition could adversely impact the control room habitability
as described in Technical Specifications and the FSAR.
The
inspectors have concluded that no violations ;of the control room
boundary occurred. The guard who was posted on the door, could
have shut the door in the event of an accidental chlorine release
maintaining the boundary.
The inspector plans to review the
licensee's determinations concerning the breakdown in work
controls and actions to prevent recurrence when the experience
report is completed.
This is an Inspector Followup Item, Review
of Unauthorized Control
Room Pressure Boundary Extensions
(325/86-17-03 and 324/86-18-03).
b.
Scaffolding Attached to Seismic Support
On July 11, 1986, the inspector ooserved scaffolding attached to the
Unit 1 Reactor Core Isolation Cooling (RCIC) System discharge line
seismic support. A 4 by 4 was resting on and wired to the snubber,
E51-41SS89, attachment rod and paddle assembly.
The scaffolding had
been erected on July 8,
1986, by a craft <farker of the mechanical
construction group.
Procedure WP-18, Temporary Construction Loads,
states that " Rigging from pipe hanger struts, spring cans, snubbers or
snubber parts shall not be allowed." The scaf folding had been rigged
on the snubber attachment, a snubber part, and thus was prohibited by
WP-18.
10 CFR 50, Appendix 8,
Criterion V,
requires activities
af fecting quality shall be accomplished by procedures.
Failure to
follow WP-18 in the rigging of scaffolding is a violation:
Rigging
Scaffolding to RCIC Snubber Attachment (325/86-17-01).
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c.
CAC-V10 Open During Walkdown
On July 17, 1986, while performing a walkdown of the Unit 2 main
control bcard, the inspector found CAC-V10, Outboard Drywell Purge
Exhaust Valve, open.
In accordance with procedure OP-24, Containment
Atmosphere Control System, Revision 67, the valve is normally closed
per valve check list page 107, and is specified to be closed after
primary containment inerting per step 7.1.B 9.
The on-duty operator
indicated that it had been closed during turnover, about 30 minutes
earlier. He cycled the valve and left it in the closed position. He
further commented that the valve had been slow to open during his last
use of the valve. However, no difficulty had been observed in closing
the valve. CAC-V10 receives a close signal during a Group 6 isolation.
CAC-V9, Drywell purge exhaust isolation valve, was closed when CAC-V10
was found open, maintaining the containment.
The licensee initiated
work request 86-BEAHl. Further review revealed that this condition had
been reported earlier on work request 86-BAEF1, dated June 18, 1986.
Apparently, an operator had given the valve an open signal and the
valve had stayed closed.
Then, at some later time, the valve opened.
The inspector verified that the valve logic would allow the valve to
perform in this fashion.
Instructions have now been issued to
operators to log the opening of the valve and any problems encountered.
The inspector has no further questions at this time.
d.
Smoking In Diesel Generator Building
The inspector found eight smoked cigarette butts in two ventilation
ducts in the diesel generator building. The ventilation ducts connect
the emergency switch gear rooms with the diesel generator fan room.
The rooms are separated by a concrete wall with the exception of the
ducts.
Both rooms are frequently patrolled by Technical Specification
required fire watches.
The inspector did not find anyone smoking
cigarettes in the diesel building.
However, the inspector believes
that evidence of smoking is sufficient reason to warrant further
management attention.
Fire Protection Procedure FPP-014, Rev. 2, Control of Combustible,
Transient Fire Loads and Ignition Sources, attachment 3,
lists the
Diesel Generator Building as a no smoking area.
The cigarette butts
found in the ventilation duct indicate that smoking had occurred in the
building.
This failure to follow procedure FPP-014 is a violation:
Cigarette Smoking in the Diesel Generator Building (375/86-17-02 and
324/86-18-02).
e.
Management Entry Into Vital Areas
The inspector reviewed security access logs to verify that plant
management toured the vital areas on a regular basis.
The inspector
reviewed the personnel transactions of management as recorded by the
Brunswick Security System from June 26 to July 28, and also on July 29,
1986.
The vice president and several managers, and most of the
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principal managers had made several tours during the above period. A
few managers had not conducted tours of the plant during this period.
The operations superintendent, whose office is in the control room, had
not entered either the reactor building, the service water building, or
the diesel generator building during the period.
Howeve'r, the
operations superintendent had been off-site about ten days during the
above period.
The inspector discussed the issue with senior plant
management.
Management visits to the plant will continue to be
monitored by the inspectors.
Two violations and no deviations were identified.
7.
Onsite Follow-up of Events (93702)
On July 11, 1986, at 3:03 a.m. Unit 2 was manually scrammed from 17% of full
power while conducting a normal reactor shutdown to repair a reactor water
cleanup (RWCU) valve. The licensee decided to scram the unit earlier than
anticipated because of problems with the reactor manual control system
(RMCS). After the scram, the licensee found that the inboard drywell floor
drain primary containment isolation valve, G16-F003, had failed to close on
a group 2 isolation signal and Source Range Monitor (SRM) C had failed
downscale. Excluding these items, all systems responded as expected and the
condensate /feedwater systems and main condenser were used for level and
pressure control.
Unit 2 was being shutdown to repair the inboard RWCU suction primary
containment isolation valve, G31-F001.
During surveillance testing, the
valve had been observed to bind and trip its breaker on 300% overload. In
accordance with Technical Specification 3.6.3.a,
the outboard isolation
valve was closed, thereby removing RWCU from service. The valve was found
to have the actuator bearing house cover cracked with some internal damage
to the actuator. The licensee believes the valve may have had a hairline
crack in the cover which had not been detected when the valve was repaired
during the last outage. The valve had been damaged when it was actuated with
the torque switch installed backwards during a post modification test.
The
licensee inspected the valve disc and seat for damage. None was found. The
actuator was repaired and the valve successfully timed and leak checked.
The RMCS malfunction involved the random insertion or withdrawal of a
control rod one notch when a rod was selected prior to the operator turning
the rod control switch. This was attributed to a loose wire in the RMCS
which would cause the RMCS electronic timer to reset af ter a rod movement
was complete and the rod deselected but before *the subsequent rod is
selected. When a different rod is selected, it can move one notch on its
own prior to a command from the operator.
The wire was properly secured.
The investigation revealed that this phenomenon can also occur if an
operator attempts to select a rod while the electronic timer is running. In
this case, the operator's action sets up a " relay race" between final rod
movement and deselection and selection of the next rod while the timer is
running; e.g., if a rod can be selected (rod movement complete, deselection
of a rod is complete and the timer is still running), the timer will reset
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and the newly selected rod will move one notch. The interval during which
this can occur is from final rod mavement (settle function complete) to the
end of the timer sequence, 0.5 seconds.
Administrative controls now
-instruct the operators to verify the timer has stopped prior to . selecting
the next rod.
The licensee is evaluating a modification to prevent the
" relay race". The problem with the RMCS did not effect the Rod Sequence
Control System (RSCS), that is, at no time was a rod pattern outside the
notch constraint pattern when RSCS was controlling.
G16-F003, which had failed to close on the group 2 isolation signal and from
the control board manual switch after the scram, functioned correctly during
trouble shooting.
The licensee suspects that some blockage in the air
solenoid may have caused the malfunction and the blockage subsequently
cleared. The licensee did not disassemble the solenoid because no rebuild
kit was found in stock.
The licensee instituted a program to weekly cycle
this valve and three similar ones until the affected solenoid is rebuilt and
examination of the solenoid internals can be performed. On July 31, 1986,
while performing the surveillance, G16-F003 would not shut. The licensee
closed the other isolation valve per Technical Specification 3.6.3.a.
Instrument and control technicians datermined that the solenoid was
sticking. Discussions between maintenance and engineering revealed that a
rebuild kit was available and had been all along.
The solenoid was
subsequently repaired and returned to service.
Apparently maintenance
planners had attempted to locate parts for the old style solenoid which had
been removed during the last outage. The inspector plans to review the
licensee's experience report concerning failure determination and part mixup
when it is issued.
No violations or deviations were found.
8.
Survey of Licensee's Response to Selected Safety Issues (TI 2515/77)
The subject Temporary Instruction (TI) involved surveying the actions that
the licensee is taking to address two safety issues:
reliability of the
High Pressure Coolant Injection / Reactor Core Isolation Cooling (HPCI/RCIC)
Systems and biofouling of cooling water heat exchangers.
Actions taken through the end of this report period associated with
HPCI/RCIC reliability include incorporation of information frum vendors,
General Electric and Institute of Nuclear Power Operations (INPO), as
applicable, into their preventive maintenance, calibration and testing
programs.
In addition, the licensee established in early 1986 an inter-
disciplinary task force to seek additional improvements to increase systems
reliability.
The areas and goals being studied include:
adequacy and
frequency of test program, development of methodologies for validating a
reliability monitoring program and establishment of an effective reliability
monitoring and predictive maintenance program.
Completion is expected in
1987.
The following NUREG-0737 items regarding HPCI and RCIC have been
closed:
II.K.3.13, II.K.3.15, II.K.3.22 and II.K.3.24.
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The only systems considered susceptible to biofouling are those -involving
water drawn from the Cape Fear River and marshes. Systems such as the fire
protection system using the county water system or deep wells are not
considered susceptible to biofoulin0
An event involving significant
degradation of the Residual Heat Removal (RHR) heat exchangers (Hx) was
described in Information Notice (IEN) No. 81-21, Potential Loss of Direct
Access to Ultimate Heat Sink.
The event was attributed to failure to
maintain the chlorination system operational during periods of anticipated
marine organism growth.
Since that time, the chlorination system has been
upgraded
and chlorination
is
provided continuously.
Since
1982,
non-availability of the chlorination system has been limited to less than
two weeks.
Success of the program has been verified during refueling
outages in which inspections of heat exchangers and associated piping has
shown little or no evidence of biofouling.
The licensee has established
procedures and trained operators for coping with significant heat exchanger
performance degradation if it should occur.
The licensee periodically
monitors the RHR Hx baffle plate differential pressure to ensure that
biofouling would be detected in time to prevent recurrence of the IEN 81-21
event.
The inspector concluded .that the licensee's actions taken in response to
these safety issues as well as ongoing actions demonstrate a positive
attitude and sensitivity to the importance of these items.
No violations or deviations were identified.
9.
Engineered Safety Features System Walkdown_(71710)
The inspector performed a complete walkdown of the accessible portions of
the Unit 1 and 2 Core Spray System to verify system operability.
The
inspector verified that: hangers and supports were functional, housekeeping
was adequate, valves and pumps were properly maintained, component labeling
was correct, instrumentation was properly installed and functioning, power
was available to motor-operated valves and that valves were in the correct
position, and that the room coolers were operable.
The inspector verified that all system instrumentation was listed on either
the periodic test scheduling designator report (for non Technical Specifi-
cation instruments) or calibrated using a PT or MST (for Technical
Specification instruments). All system instrumentation required for system
operability was verified installed and calibrated.
The inspector verified that the system checklists'in OP-18, Core Spray (CS)
System Opercting Procedure, Revision 6 for Unit 1 and Revision 24 for
Unit 2 contained the major system valves as indicated by the Core Spray
piping and instrumentation drawings (P&ID), [0-25024, Sh. 1 (Rev. 19),
0-25024, Sh. 2 (Rev.17), D-2524, Sh.1 (Rev. 20), 0-2524, Sh. 2 (Rev.19)].
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The inspector found two drawing discrepancies on the CS P&ID's.
The
isolation valves for the CS leak detection instrumentation (V87, V88) were
shown as open on the Unit 1 P&ID but shown as locked open on the Unit 2
P&ID. The Unit 1 P&ID did not show that pressure switches PS-N008A & B, and
PS-N009A & B supplied the ADS permissive logic. The licensee will correct
the drawings.
The licensee has removed the Unit 1 Division I & II core spray suction
relief valves, F032A & B.
The licensee has removed the valves because they
leaked by and replacements were not readily available.
EER 85-256 allows
continued operation of the system with 1-E21-F032A removed and the suction
valves caution tagged to prevent operation with both the torus and
condensate storage tank suction valves shut. A similar EER was issued for
1-E21-F0328. The relief valve's setpoint was 125 plus or minus 10 psig to
protect the suction piping in case both suction ifnes are isolated and the
discharge line valves leaked by.'The relief valve lines are now capped with
a 150 psig flange that has been operationally leak tested. The EER expires
September 15, 1986.
The inspector has no further questions about the
suction relief valves at this time.
The inspector verified that the
readings of the four core spray sparger high differential pressure switches
were consistent with the system description.
The inspector compared the readings of the four core spray sparker high
differential pressure switches. They read as follows:
1-E21-N004A:
110" with plus or minus 3" swings
1-E21-N004B:
100"
2-E21-N004A:
93"
2-E21-N004B:
156"
The inspector found the 3/4" instrument line to 2-E21-PSH-N007A not clamped
to two unistruts.
The licensee had previously identified a similar
condition during the blanket walkdown of Unit 1.
The blanket walkdown of
Unit 2, scheduled to start during the current operating cycle, most likely
would have identified the missing unistrut clamps. The inspector also found
that the Service Water (SW) valve solenoid valves to the CS room cooler for
both Units were not mounted properly.
The licensee reported to the
inspector the solenoid valves de-energize when core spray initiates, opening
the SW supply to the room coolers. The screws that fastened the solenoid
valve to a mounting bracket on the main valve body were missing on three of
four coolers and only one screw was in place for the remaining solenoid.
The licensee reported that a safety concern did not exist since, on loss of
air, the SW valves would open, supplying water to the room coolers.
The inspector found scaffolding erected near the Unit 1 CS F0048 and F0058
valves and the Unit 2 F004A and F0058 valves.
The scaffolding was
constructed of fire retardant wood. However, no work was being done near
those valves and the Unit 1 outage had been completed 200 days ago. The
licensee issued work requests to remove the scaffolding.
No violations or deviations were identified.
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1
10. TIP Tubing Reversal
At about 4:00 p.m. on July 22, 1984, with Unit 2 at 100% power, the licensee
discovered that Traversing Incore Probe (TIP) tubes might have been reversed
on Unit 2.
The licensee reduced power, confirmed the swap through control
red movements and. requested the corporate Incore Analysis Unit to calculate
the effect on thermal limits. Further testing was performed to verify that
no other TIP tubes were reversed. A modification to the process computer
program was made to compensate for the swap. Unit 2 was returned to 100%
power on July 25, 1986.
The licensee discovered the TIP tube swap during a routine review of TIP
traces by the Nuclear Engineering Staff. The TIPS are used to calibrate the
Local Power Range Monitors (LPRM) which are in turn used by the process
computer to calculate margins to thermal limits.
There are four TIP
machines, each with its associated detector. Each machine's detector can be
selected to traverse eight or nine LPRM strings. Position ten is the common
channel such that each machine can traverse the same LPRM location (28-29)
to cross-calibrate the TIP machines. The TIP output is also sent to an X-Y
plotter to draw a trace on graph paper. During a review of the A-10, B-10,
C-10 and D-10 traces (common location) taken during the 00-1 calibration,
the licensee noted that the i 10 trace did not match the A-10, C-10 and D-10
trace low in the core.
The center rod, near the common channel, was
inserted to position 36. Further review showed that the B-8 flux shape did
resemble A-10, C-10 and 0-10.
Reactor power was reduced to 95% within one hour for added assurance that no
Technical Specification thermal limits were being exceeded. The margin to
critical power ratio was approximately 5% before the power reduction. Thus,
after power was reduced, about a 10% margin to thermal limits was available
to compensate for any errors in the LPRM calibrations. The licensee used
control rod motions with TIP traverses to verify that B-8 and B-10 were
swapped.
Power was reduced to about 75% power.
A TIP trace was taken
before and after a rod was moved near a TIP locations.
The Incore Analysis Unit of the corpora e Nuclear Fuel Section conducted
off-line analysis of cycle 7 data to verify that no thermal limits had been
exceeded. The BACKUP code was used.
Since B-8 and B-10 were swapped, the
normalization of the TIP machines and their associated LPRMs were affected.
Since actual local power B-3 was predominantly lower than actual B-10 local
power, the swap forced the normalization process to raise the associated
readings for the TIP 8 machine calibrated LPRMs.
This resulted in
conservative thermal limit calculations for fuel fear TIP B calibrated LPRMs
but non-conservative thermal limit calculations for fuel near TIP A, C, and
D calibrated LPRMs.
However, since the cross-calibration process is a
normalization process, the magnitude of the conservative error in the single
B machine is averaged over machines A,
C and D,
leading to a smaller
non-conservative error.
The licensee reviewed all cycle 7 data and found
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that during high power when thermal limits could be approached, the most
limiting location for thermal limits were being monitored by a TIP B
calibrated LPRM. Since TIP B gave conservative readings, no thermal limits
had been exceeded during cycle 7.
The inspectors reviewed selected licensee P1 printouts and core thermal
limit data (PT 1.11) to verify that the licensee's claims regarding power
history were supported by the data.
On July 23, 1986, Special Procedure SP-86-041 was written and performed to
verify that no other TIP tubes were swapped.
No additional problems were
found.
On July 24, 1986, the licensee modified the process computer program to
compensate for the B-8, B-10 swap.
The changes were made to the Digital
Fast Scan program and to the TIP driver software to swap B-8 and B-10
locations.
The licensee verified that the computer program modifications
are functional.
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On the afternoon of July 25, 1986, the licensee returned Unit 2 to 100%
power. The licensee had, at that- time, presented their cycle 7 thermal
limit review information to the resident inspectors.
The licensee . had
previously agreed in a letter dated July 23, 1986, not to exceed 95% without
Region II concurrence.
Based upon information given to the
residents,
Region II concurred in Unit 2 return to 100% power. However, the licensee
has agreed to review cycle 6 data for compliance with thermal limits and to
further investigate how and when the TIP was reversed. The NRC will review
the licensee's additional information when available for possible enforce-
ment actions.
Pending completion of the licensee's review, this is an
Unresolved Item: TIP Tube Reversal (324/86-18-04).
O