ML20005E626
| ML20005E626 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 12/29/1989 |
| From: | Dance H, Levis W, David Nelson, Ruland W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20005E624 | List: |
| References | |
| 50-324-89-40, 50-325-89-40, NUDOCS 9001100012 | |
| Download: ML20005E626 (17) | |
See also: IR 05000324/1989040
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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REGION 11
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101 MARIETTA STREET.N.W.
ATLANTA, GEORGI A 30323
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Report Nos.: 50-325/89-40 and 50-324/89-40
Licensee: _ 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
Inspection Conducted:. November. 1-30, 1989
Inspectors:
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W. ' H. Ruland '
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D. J. Nelso
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Approved by:
A
H'. C. Datce, Section\\ Chief
Date Signed
Division of Reactor Projects
SUMMARY
Scope:
This routine safety inspection by the resident inspector involved the areas of
maintenance
observation,
surveillance
observation,
operational
safety
verification, onsite Licensee Event Reports (LER) review, follow-up on
information notice, action on previous inspection findings, and fire protection
sprinkler potential inadvertent actuation.
Results:
In the areas reviewed, one-violation was identified when a design deficiency in
the Standby Gas Treatment System rendered the secondary containment isolation
dampers inoperable without the operator's knowledge.
The licensee's previous
actions relating to this item were judged insufficient (paragraph 5).
Several minor deficiencies were found in maintenance and surveillance
procedures.
The licensee's current schedule for procedure upgrades should
continue to correct these problems (paragraph 2).
9001100o12 e91229
ADOCK 05000324
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(The Reactor: Water Clean-up' bottom head' drain clean-out task was well conceived
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and executed (paragraph 3a).
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!An inform' tion inotice.1 reviewed by -the. inspectors had beene properly-
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'dispositioned (paragraph 6)..
The diesel generator' reliability study h'd' recommended certain. actions that the
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licensee implemented.- The. affect on DG reliability was1 uncertain-(paragraph 7b).
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REPORT DETAILS
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1.
Persons Contacted
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Licensee Employees
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K. Altman, Manager - Engineering Projects
F 'Blackmon, Manager - Operations
- S. Callis, On-Site. Licensing Engineer
T. Cantebury, Manager - Unit 1 Mechanical Maintenance
- G. Cheatham, Manager - Environmental & Radiation Control
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M. Ciemnicki, Security
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R. Creech, Manager.- Unit 2 I&C Maintenance
W. Dorman, Manager - QA
K. Enzor, Manager - Regulatory Compliance
- J. Harness, General Manager - Brunswick Nuclear Project
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W. Hatcher, Supervisor - Security
- A. Hegler, Supervisor - Radwaste/ Fire Protection
- R. Helme,. Manager - Technical Support
- J. Holder, Manager - Outage Management & Modifications (OM&M)
- M. Jones, Manager - On-Site Nuclear Safety - BSEP
R. Kitchen, Manager - Unit 2 Mechanical Maintenance
D. Moore, Manager - On-Site NED Staff
F
J. O'Sullivan, Manager - Training
- R. Poulk, Supervisor - Regulatory Programs
W. Simpson, Manager - Administration and Control
S. Smith, Manager - Unit 1 I&C Maintenance
R. Starkey, Project Manager - Brunswick Nuclear Project
- R. Warden, Manager - Maintenance
B. Wilson, Manager - Nuclear Systems Engineering
Other licensee employees contacted included construction craftsmen,
engineers, technicians, operators, office personnel, and security force
members.
- Attended the exit interview
Note: Acronyms and abbreviations used in the report are listed in the
last paragraph of this report.
-2.
Maintenance Observation (627C3)
The inspectors observed maintenance activities, interviewed personnel, and
reviewed records to verify that work was conducted in accordance with
approved procedures, Technical Specifications, and applicable industry
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codes and standards. The inspectors also verified that:
redundant
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components were operable; administrative controls were followed; tagouts
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were adequate; personnel were qualified; correct replacement parts were
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used; radiological controls were proper; fire protection was adequate;
quality control hold. points were adequate and observed; adequate
post-maintenance testing was performed; and independent verification
requirements were implemented. The inspectors independently verified that
selected equipment was properly returned to 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:
89AMEE1
No. 3 Diesel Generator 18 Month Outage.
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89AMEF1
No. 4 Diesel Generator 18 Month Outage.
89AXJZ1
Unit 2 RWCU Square Root Converter Trouble: hooting / Repair.
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89AZQA1
Vacuum Relief Repairs X18F.
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89N01371
2-E41-F001 Electrical Inspection.
890NB451
CAD Vaporizer Route.
Cleaning the Reactor Pressure Vessel Bottom Head Drain Line
The inspector reviewed plans and implementation of the repair of the Unit 2
reactor vessel RWCU bottom head drain line. The work was conducted in
accordance with Special Procedure (SP)89-041, Cleaning the Reactor
Pressure Vessel Bottom Head Drain Line. This line has been clogged since
early in plant life and prevents bottom head-to-recirculation loop
temperature equalizing in the event of a recirc pump trip.
The licensee
cleared the line using a water jet inserted through a modified tee
connection. The tee was subsequently replaced with use of a freeze seal
to prevent draining of the reactor vessel.
This project was well
conceived and implemented although its success has yet to be proven.
The
use of remote radiation monitors during the water jetting evolution
resulted in significant exposure savings.
However, the inspector noted
that the use of a liquid nitrogen freeze seal instead of a liquid
nitrogen / antifreeze mixture was not clearly specified in the SP, although
authorized on the ' freeze seal WR/J0.
The SP referenced Outage
Management / Modification Work Procedure WP-120, Freeze Seals, which limits
the freeze seal temperature on carbon steel to -40 degrees F due to
brittle fracture concerns.
The temperature is controlled by mixing the
liquid nitrogen with antifreeze. Using liquid nitrogen alone results in a
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temperature of -320 degrees F.
The licensee justified the use of liquid
nitrogen without temperature control based on research conducted by
Battelle Laboratories which concluded that low temperature freeze seals
could be used safely on carbon steel. The inspector reviewed the Battelle
report. Based on the inspector's review, no problem was noted with the
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licensee's use of the nitrogen freeze seal.
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The inspectors observed various maintenance tasks on DGs 3 and 4.
The
inspectors found that the vast majority of the work was performed
sati sf actorily. However, the DG-3 outage was scheduled for the full seven
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day LCO. This left little margin for error and could encourage needless
haste in returning the DG to service. The DG LC0 started on November 8,
1989 at 2:40 a.m. and was cancelled on November 15 at 3:47 a.m.
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exceeded the time: allotted to restore the DG to OPERABLE STATUS per TS
ACTION statement 3.8.1.1.b.3 of seven days by 67 minutes. The plant had
12. hours to be in HOT SHUTDOWN. The licensee had a service water pressure
switch failure at the end of the LCO time that only received a detailed
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engineering operability resiew after the DG was declared operable. That
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determination showed ' that the DG operability was not affected by the
pressure switch failure.
Plant management has indicated that, where
possible, future DG outages will provide extra time to resolve unforeseen
problems.
Violations and deviations were not identified.
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3.
Surveillance Observation (61726)
The inspectors observed surveillance testing required by Technical
Specifications.
Through observation, interviews, and record review, the
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inspectors verified that:
tests conformed to Technical Specification
requirements; administrative controls' were followed; personnel were
qualified; instrumentation 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:
IMST-CAC21R
CAC Drywell Suppression Pool Vacuum Breaker Channel
Calibration.
IMST-RCIC24Q
RCIC Steam Leak Detection Channel Calibration.
IMST-RHR27Q
RHR RSDP Head Spray Flow Channel Calibration.
DG-3 Trip Bypass Logic Test.
PT-90.1
Core Spray /Feedwater Visual Examination
101-3.1-
Control Operator Daily Surveillance Report
a.
Procedural Discrepancies
While observing the performance of 1MST-CAC21R, the inspector noted
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that the technician was having difficulty in properly adjusting the
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magnets on the vacuum breaker to obtain the necessary opening force.
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The drywell was closed and the drywell purge fans were running,
creating a slight differential pressure (D/P) across the valve. The
licensee secured the fans and the -technician completed the
surveillance test without any further trouble after the inspector
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asked how the purge fans affected the test.
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The above test conditions were atypical. Usually the vacuum breakers
are tested during an outage when both the drywell and torus are open.
Under these conditions no D/P would exist across the valve. However,
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with the slight D/P across the valve, the valve setting < may be
slightly off.
In the inspector's opinion, the operability of the
vacuum breakers would not be affected since the Technical'
Specification value for opening is 0.5 psid. The. licensee sets their
valves to open at 0.1 psid. The licensee did state ~, however, that
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- they; would revise their MST to address the situation where some D/P
may exist: .across the valve due to drywell/ purge fan operating
combinations.
During the performance of 2MST-DG21R, DG-2 Loading Test, the
' inspector noted the following procedural problems:
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During the ' performance of - step 7.10.7, the technuian was
instructed to acknowledge alarms. He accomplished'this ~ step by
depressing the silence button on the engine control panel. When
he proceeded-to the next step, he found that relay ANCR was not
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' deenergized as required.
When the technician depressed the
acknowledge button on the generator control panel, he found that
the relay deenergized as required.
Step 7.11.3 required the technician to install a jumper across
points 1 and 52 of the STR relay.
The technician found three
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points labried as point 1.
The licensee stopped tne procedure
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at this point and verified that the points labeled "1" were in
fact the same points electrically.
The li:vnsee stated that they would provide additional clarification
in the procedure to' correct these two deficiencies.
The inspector
also noted that when the diesel start signal was provided in step
7.10.11, the motor driven fuel oil ~ pump started several times. The
inspector-questioned the effect of the repeated start attempts on the
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pump motor.
The licensee will evaluate the need to take some
precautiens to prevent pump start.
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Ouring the performance of the test, the auxiliary operator in the
diesel room attempted to start the motor driven jacket water pump to
support other acceptance testing in progress in the diesel room.
Prior to starting the pump, the inspector informed the A0 that the
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jociet water pump motor was required to be off in accordance with
step 7.7 of the MST. At this point, the lead technician informed the
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control room of the other competing work activities and the other
work was stopped until completion of the MST. No violation occurred
in this case as the A0 did not start the motor. However, the need to
adequately control competing work activities was discussed with
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management maintenance personnel who acknowledged the inspector's
comments.
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While observing the performance of MI-03-6F4 for the Unit 2 RWCU K605
square root converter, the inspector noted that test psints 3 and 4
were not marked on the square root converter.
The procedure
requires, in step XI.D, that the technician install his test leads
sinto these test points. In addition, no diagram was provided in the
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procedure to show where these test . points were located.
The
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inspector questioned the technician on how he determined which test
points to use. The technician was able to show the inspector a copy
of the technical manual which showed-that he was using the correct
points.
The technical manual copy was not provided with the work
package but was retrieved from the plant's maintenance library.
The inspector also reviewed the plant's related surveillance test
2MST-RWCU21R, Revision 6,
and noted that the same discrepancy
regarding the labeling.of test points 3 and 4 existed. The licensee
informed the inspector that they would revise the MI and the MST with
appropriate instructions for the technician,
b.
'The inspector observed the performance of 1MST-RHR27Q,
he RHR RSDP
Head Spray Flow Channel Calibration.
The testing is required by
Technical Specification 4.3.5.2-1(7).
-However, the head spray
feature of the RHR system has been disabled for both units for
several years. For Unit 2, some of the piping has been removed. The
licensee had started the process to request a technical specification
Amendment in- February, 1989, to remove the testing requirement for
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Unit 2. . The priority of that request has since been downgraded and
is.not being pursued at this time.
The test required the use of three technicians. One technician was
required to wear anti-contamination clothing since the transmitter is
located in a contaminated area.
The total dose accumulated during
the job was 15 mrem as read by the pocket dosimeter.
The inspector
noted, also, that brown water was observed coming from the
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transmitter during the venting of the device.
The technician
performing the job stated that it was common to see the brown water.
The inspector concluded that the performance of this surveillance
test for a system that did not function was not in the best interests
of maintaining radiation exposure ALARA.
The inspector urged the
licensee to pursue the technical specification amendment to delete
the testing.
The licensee is also evaluating the need to
periodically flush the head spray piping to prevent the accumulation
of corrosion products.
The inspector also interviewed four groups of workers in the Unit 2
reactor building concerning dose rates in their area. Two groups did
not know the dose rate nor the areas of highest or lowest dose rate.
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One group was-well informed and one group'had an HP present who knew-
the dose rates. -In particular, two individuals were standing by the
North HPCI entrance observing work' across a step off pad. The area's -
dose rate was'about 15 mrem /hr. They were standing within.'3 meters
of hot spot 2RB-23 which was labeled'7000 mrem /hr and 1 meter from a
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high radiation area sign.
These individuals were unaware of the
areas dose rates.
The licensee was made -aware of this lack of.-
awareness.
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Violations and deviations were not identified.
- 4.
Operational Safety Verification (71707)
The inspectors verified that Unit 1 and Unit 2 were operated in compliance
with technical specifications and other 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 operator,
shfft supervisor, clearance, STA, daily and standing instructions, 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 verify
operability and that operating parameters were within
technical
specification limits.
The inspectors observed shif t turnovers to verify
that continuity of system status was maintained. The inspectors verified
the-status of selected control room annunciators.
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Operability of a selected Engineered Safety Feature division was verified
weekly by insuring that: each accessible valve in the flow path was in
its correct position; each power supply and breaker was closed for
components that must activate upon initiation signal;
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
inspectorr
verified
that
the
licensee's
health
physics
policies / procedures were followed.
This included observation of HP
practices and 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
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protected area; vehicles were properly authorized, searched and escorted
within the PA;' persons within the PA displayed photo identiiication
badges; personnel in vital areas were authorized; effective compensatory.
measures were employed when: required; and security's response to alarms
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was adequate.
.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.
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Unit 1 entered a forced outage on November 16, 1989 due to the failure of
Suppression Pool-to-Drywell Vacuum Breaker X18F, discovered during
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surveillance testing.
Repairs were made and the unit restarted on
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November 19.
While the unit was shutdown the inspector conducted tours of the drywell,
torus, and reactor building ,66-foot level penetration room.
In the
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drywell, specific attention was paid to the safety relief valves' acoustic
. monitors which had been discovered damaged in the past. No. discrepancies
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were noted.
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On the. 38-foot level of the drywell the inspector found a Simpson
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multimeter that had mistakenly been left in the drywell during an outage
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in June, 1989. The multimeter remaining in the drywell-during operation
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is not safety significant since it was unlikely to block a ECCS suction.
However, it is reasonable to expect that all tools and equipment remaining
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in the drywell after an outage would be discovered and removed during the
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licensee's drywell closeout inspection. The multimeter was reported lost
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during the June outage and was assumed to have been e inadvertently
discarded.
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The housekeeping in the reactor building 66-foot level penetration room
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was. poor compared to other reactor building areas.
This is a high
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radiation area that was formerly a neutron radiation area that is normally
locked.
No other discrepancies were noted.
The inspectors interviewed General
Electric and licensee project
' management personnel concerning the Unit 2 recirculation pipe replacement
work. The inspector found personnel well informed of current job schedule
and scope and were present during backshift time on occasion. Actual job
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status and detailed inspection efforts are included in inspection reports
89-33 and 89-43.
Subsequent to Unit I restart, on November 20 the inspector discovered
normally closed RWCU valve G31-F034, Reject to Condenser, open by
indication on the motor control center. This was also indicated on the
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control board.
The reject flow control valve, G31-FCV-F033, was shut,
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therefore, reject flow was secured.
Once reject to the condenser is
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secured during startup, F034 should be returned to its normal position.
The on-duty Control Operatoristated that he also had noted the valve was
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open and recalled other startups when the same condition had occurred.
The. Senior Control Operator directed that the valve be shut.
Reviewing
the startup procedJre, GP-2,. Approach to Criticality and Pressurization,
revealed that no direction is given to shut F034 once reject flow has been
terminated .as the means for level contro'l .
The' operators initiated a
procedure revision request in accordance with 01-28, Preparation and
review of Operations Procedures, to add steps to GP-2 to ensure that F034
is shut when appropriate during ' the startup.
Further review by the
licensee concluded that F034 should ?have been shut af ter placing the
second~ RWCU filter /demineralizer in service in accordance with Operating
Procedure (0P)-14. OP-14 contains a specific step to shut.the valve. Non
Conformance Report (NCR) S89-120 was initiated to investigate this
discrepancy. The.NCR was still outstanding at the close of the inspection
period.
Further inspection will be conducted pending completion of the
NCR.
The - NRC does not consider this specific problem to be safe ty
significant, however, the inspector is concerned with recurring examples
of. valves out of position.
Violations and deviations were not identified.
5.
Onsite Review of Licensee Event Reports (92700)
The -~ below listed .LERs were reviewed to verify that the information
provided met? NRC reporting requirements.
The verification included
adequacy of event description and corrective action taken or planned,
existence' of. potential
generic problems and the relative safety
significance of the event.
Onsite inspections were performed and
concluded that necessary corrective actions have been taken in accordance
with existing requirements, license -conditions and commitments unless
otherwise noted.
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a.
(CLOSED)
LER .1-89-18, Exceeded Technical Specification 3.6.5.2,
Required Action As Result of Unrecognized Design Logic Interface with
the Standby Gas Treatment System.
This LER documents design
deficiencies found in the isolation logic to the secondary
containment isolation dampers and the resultant violation of
Technical Specification 3.6.5.2.
The licensee determined that
deenergizing the starter circuitry of the SBGT train will cause
selected isolation logic for the dampers to be inoperable.
The
Reactor Building supply and exhaust dampers receive a secondary
containment isolation signal from the following parameters:
High Drywell Pressure
Low Reactor Vessel Level
Reactor Building Exhaust High Radiation
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The CRMX relay, which is actuated from the high drywell pressure and
low reactor vessel level conditionsi and inputs to the Reactor
Building supply and' exhaust damper isolation logic, receives its
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power from the SBGT_ starter circuitry. Division I (CRMX A) receives
its power from'SBGT starter A and Division II (CRMX B) receives its
power ' from SBGT . B.
Therefore, if the SBGT starter circuitry is
deenergized,. its associated division of logic for the Reactor
Building dampers is inoperable for the high drywell pressure and low-
vessel level signals. An isolation-signal from either division will
shut all four dampers.
.The TS ACTION statement for the SBGT system. requires that a single
train be restored ' to operable status within 7 days.
The ACTION
statement ' for the secondary containment- isolation dampers requires
that the dampers be restored to operable status or isolated within
eight hou r s'.
If the SBGT train is taken out of service with its
starter circuit deenergized for the duration of the SBGT ACTION
statement, the ACTION statement for the secondary containment
isolation dampers would be exceeded since some of its isolation logic
is inoperable.
This has happened in the past and most recently
occurred on Unit 1 from July 11 to July 14, 1989, when SBGT 1B train
was removed from service with its starter circuitry deenergized as
required by Equipment Clearance.1-1065. This time period exceeded
the time specified in TS 3.6.5.2 for the secondary containment
isolation dampers and is listed as a Violation:
Inoperable SCIDs Due
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- to Unrecognized Design Logic Interface with SBGT, (325/89-40-01).
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The deficiency regarding *the isolation logic was initially discovered
during 'the modification review for another design deficiency
associated with the SBGT damper indicating lights in the control
room. This modification for the indicating lights was initiated as
-part of the corrective action for Violation 325/88-45-01.
At the
time of discovery, the operations reviewers informed the modification
engineer of the concern.
The modification engineer discussed the
concern with the Unit 1 operations engineer who incorrectly concluded
that the seven day LCO for SBGT would cover the damper logic concern.
The operations person who questioned the logic initially did so again
in the- August 1989 time frame when the SBGT 1A train was to be
removed frot, service for maintenance.
The review by other licensed
operators on his shift and subsequent Regulatory Compliance group
review showed that this condition would render the secondary
containment isolation dampers inoperable and put them in an eight
hour Technical Specification ACTION Statement.
The safety significance of this event is minimal since the design
deficiency does not affect the isolation due to high radiation sensed
in the Reactor Building exhaust.
The purpose of
secondary
containment, which includes SCIDs, is to minimize the ground level
release of airborne radioactive material and to provide a means for
filtered and controlled elevated release of Reactor Building
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atmosphere should an accident occur, so that releases. to the
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environment 'will be , kept to the minimum practical and within '
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-10 CFR-100 limits. The isolation of the. SCIDs for vessel low level-
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and high drywell pressure appear to be anticipatory signals and would
not affect the ability of the secondary containment to perform its
design function.
A violation is warranted in this case,=however, for two reasons. The
licensee had the . opportunity to note and correct the problem eight.
months before the problem;was properly characterized,
In addition,
the licensee's corrective action, once the problem was identified, .
was neither far-reaching ' or extensive.
Their corrective ~ action
included training for the operations, technical. support and' NED
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-organizations. ' Caution tags were hung on the SBGT breakers warning .
operators of the ~ condition and a PID:was initiated -to correct the
design problem.
No date was provided in the LER for. when the-
-deficient design condition would be corrected. The licensee also did'
not look any further to determine if other design problems existed in
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the secondary containment area. LERs 1-88-032 and 1-88-034 - describe
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other design problems with the SBGT and the SCIDs indicating that the-
design should be further challenged.
b.
(CLOSED) LER 2-89-008; Auto Initiation' Without Injection of Low
Pressure-Coolant Injection Core Spray and Residual Heat Removal Pumps
'
Due -to LOCA - Signal During Surveillance Testing.
LER 1-89-017;
Spurious -Isolation of High Pressure Coolant Injection Channel A
Caused by Suspected Failure of Rosemount 510 DU Trip' Unit. These two
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LERs ' report ESF actuations caused by suspected failure of Rosemount
'
510'DU trip units. Similar failures .have occurred' at other nuclear
power plants. The licensee has established contact with Rosemount
4
and another licensee to-coordinate final corrective actions.
In the
meantime, the licensee periodically checks the output voltage of
inservice 510 DU trip units in order to reveal failed or failing
a
units prior to ESF actuations occurring.
-
One violation and ro deviations were identified
6.
Followup on Information Notice (92701)
The inspector reviewed licensee actions taken with respect to Information Notice 89-66, Qualification Life of Solenoid Valves. The notice described
problems with ASCO model 8323 solenoid valves exceeding their qualified
life if single versus double coil heat wire data was used in the qualified
life calculation.
The inspector determined that the licensee's Onsite
Nuclear Safety (0NS) organization had reviewed and followed up on the
notice and that the licensee's technical support organization had updated
their EQ files prior to the issuance of the notice based on information
.
provided to them from the Nuclear Utility Group on Equipment
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Qualification.
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The inspector reviewed licensee actions taken with respect'to Information Notice 89-51,. Potential Loss of Required Shutdown Margin During Refueling
Operations.
This notice. resulted ..from ' a 10 CFR Part 21 report from-
another licensee concerning . fuel reloads at a. Pressurized Water Reactor
being placed 'in intermediate configurations such that shutdown margin-
calculations were no longer applicable.
Subsequent to issuance of the
!
notice additional information has become available to the NRC. suggesting-
1
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that j some conservative assumptions used in shutdown margin calculations
were inappropriate.
Since' Brunswick Unit 2 is currently in a refueling
outage, the inspector informed the licensee of the new information. The
licensee'.s ONS organization reevaluated the Information Notice and
concluded that the concerns are not directly applicable-to Brunswick since
>
fuel reloads are not.placed in intermediate-positions.
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Violations and deviations were not identified.
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7.
Fir'e' Protection. Sprinkler Potential Inadvertent Actuation (93702)
g-
The inspectors asked the licensee whether their environmentally qualified
equipment was qualified for an inadvertent actuation of the reactor
1
bufiding fire sprinklers.
Another licensee found, on November 3,1989,
that their sprinklers would actuate during a High Energy Line Break
j
(HELD), possibly defeating the steam leak detection system.
The
i
inspectors followed this issue to determine if the licensee's actions were
I
appropriate. The licensee had taken no compensatory action regarding .the
sprinklers on November 28, when first asked by the inspectors.
By the
i
last -day of the inspection period, the licensee had isolated = the
sprinklers . in Unit -1 south RHR room and stationed a - fire watch. The
inspectors also found that the licensee had evaluated this -issue in EER
89-0282, Evaluate Proper Temperature for Sprinklers in the - Reactor
Building. This EER was started in response to the spray down event of the
1A Core Spray pump motor (see report 89-12).
That EER, approved on
November 10, had no EQ review, yet recommended that the sprinkler heads be
changed from 165 degrees F to 350 degrees in the RHR rooms, for example.
!
This issue is an Unresolved Item since the inspector and licensee actions
continued in the next inspection period:
Fire Protection Sprinkler
Actuation During HELB May Af feet EQ Components (325,324/89-40-02).
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8.
Action on Previous Inspection Findings (92701) (92702)
'
a.
(CLOSED) Unresolved Item 325/87"13-03, PT-4.1.8, Off gas Automatic
Isolation Operability Check Procedure Inadequate.
The inspector
reviewed OER-87-027 dated June
9,
1987, which described the
<
circumstances of the procedural deficiencies and the resultant
"
corrective actions.
The inspector verified that PT-4.1.8 had been
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updated to incorporate the required unit specific actions to prevent
recurrence of the specific problems noted. In addition, the licensee
revised their technical reviewer evaluation worksheet contained in
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Vol. '1, Bk. I to ensure that individual unit mechanical or. electrical
designations in common unit procedures are properly identified. The
-inspector had no further questions ~.
b.
(CLOSED)
IFI - 325/88-01-04 and 324/88-01-04, Review DG Reliability -
Assessment. .The inspector reviewed the results of the DG reliability
study completed on~ March 4,
1988.
The report reviewed 11 diesel
generator failures during 1987 and early 1988 to-establish the root
cause of the failures. The final recommendations of the report are
listed in ~ Appendix F.
The licensee has implemented = several- of the
recommendations including the replacement of the Allen - Bradley-
pneumatic time -delay relays, increased frequency - of - blowdown = of
starting / control : air headers, . upgrading of service- water instrument-
a-tion piping along with the preventive maintenance inspection of
switchboard wires and lugs, to correct the majority of the problems
uncovered by the report. Additional items under consideration by the-
licensee include evaluating the need for new saddle tank level
switches, the installation of a'new or different relay to. replace the
<~
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Allen Bradley pneumatic time delay relays and a better way to time
diesel generator starts for. trending purposes.
Based. on the.
inspectors review, the corrective actions taken by the licensee have
been effective. The inspector was unable to determine quantitatively
the overall improvement in diesel generator availability because the
licensee now calculates availability differently.
The diesels are
now considered unit specific.
Therefore, if a diesel is taken out
for maintenance during its associated unit's outage, its out of
service _ time is not included in the availability calculation.
Formerly, the availability of the diesels was based on the Technical
Specifications that required all four diesels for each unit. In this
case, any diesel down time would affect the availability numbers
unless both units were in an outage,
c.
(CLOSED) Violation- 324/87-40-01; Failure to Calibrate Jet Pump
Instrument in Accordance with Procedure. The inspector reviewed the
licensee's response t'o this violation.
The licensee noted that
although the jet pump instruments were not calibrated in accordance
with the procedure, the error was detected and proper calibrations
performed prior to returning the instrumentation to service.
The
licensee attributes the cause of the violation to personnel error.
Corrective action consisted of counseling for the technician involved
and training for other I&C personnel,
d.
(CLOSED) Violation 325, 324/88-41-01; Exceeding Overtime Limits. The
inspector reviewed the licensee's response to the violation and
resultant
administrative
precedure
revisions.
Administrative
Procedure Volume 1, Book I was revised to require Plant General
Manager approval prior to overtime guidelines being exceeded.
'
Previously, the AP was not in conformance with Generic Letter 82-12,
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Nuclear Power Plant Staff Working Hours, regarding overtine approval.
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Additionally, other unauthorized exceptions ' to the Generic - Letter
were deleted,
e.
(CLOSED)' Violation 325/89-14-01; Failure' to Follow Procedure,
Handling of 1A- Core Spray Pump, Motor. This-violation resulted from
handling the removed 1A Core Spray Pump' motor with a fork lift of;
insufficient noted capacity in ' close proximity to safe shutdown
equipment with the reactor at full power. The inspector reviewed'the
licensee's response to this violation. Thellicensee stated that the
mechanical foreman of the job made a poor, judgement of. the motor's
weight-reasoning that removed motor components lowered the weight to
within the fork lift's capacity. The licensee also. described the
difficulty -in determining. the actual ' weight of the motor after the
t -
fact. The licensee obtained six different weights ranging from 7,700
to 9,200 pounds during six measuremental attempts. (Fork lift rated
capacity was 8,000 pounds). The weight of the motor was concluded to
be approximately 8,450 pounds. 'Nonetheless, the root cause was
determined. to be failure of the foreman to determine the weight of
the motor prior to transport.
Corrective actions consisted. of
revising the rigging scheme for motor return - although the reactor
was in-cold shutdown and no threat to safe shutdown capability could
be made. Additional corrective actions consisted of retraining of
personnel on proper weight handling.
f.
(OPEN) TMI Action Item *II .E.4.2.7
Containment Isolation - High
. Radiation Signal.
This item was previously inspected in reports.
82-08, 85-38 and 86-24. The licensee installed a modification for
both units so that containment purge and isolation valves close on a
high radiation signal as sensed by the stack radiation monitor. The
.setpoint for'the isolation signal -is established in accordance with
the licensee's Offsite Dose Calculation Manual and such that any
release will be well within 10 CFR 100 limits. The NRC approved the
proposed modifications in a March 5,
1987 letter to CP&L.
The
approval was based on review of information provided in the
licensee's August 26, 1986 and December 1986 submittals to NRC.
,
.The inspector reviewed the correspondence and the plant modifications
that installed the hardware to ensure that the modification was
installed in accordance with NRC requirements and commitments.
In
addition, the inspector reviewed training records and materials,
surveillance tests and operating procedures to veri fy that the
modification was operable as installed and that the appropriate
training was conducted and necessary procedure changes made. As a
result of the review, the inspector had one remaining open issue and
one noted weakness.
The CP&L December 17, 1986 letter to NRC summarized the results of a
conference call between NRC and CP&L conducted on November 13, 1986.
The letter provided additional design information based on NRC
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questions on the-proposed system design presented ~in a August 1986
letter to NRC. In the December 17, 1986 letter the licensee stated-
'that ' the _ safety related ' circuit 'would be separated from the
'
- non safety related circuit by two-means.
In the CAC isolation trip
override circuit the separation was accomplished by means of a
fuse and: fuse block _ which would be purchased Q-list. A,600V:noted
Q-list relay would provide circuit isolation from the Decatur
Building Exhaust Radiation Monitor Circuit.
The inspector found in.
his review of PM 86-005(U-1) and 86-006 (U-2) that the fuse referred
to, FU-C1 was not purchased Q-list but rather purchased as
a-
commercial grade item.
The relay .is used in a 120 Vac control
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circuit.
These apparent discrepancies were- referred to NRR to
^
determine their' acceptability.
The inspector also noted that time respcnse testing was not performed
- during the acceptance testing of- the plant modifications.
At the
time: of the installation the licensee did not think that these
instruments and associated isolation logic would be included in the
plant's Technical Specifications.
Subsequent to the modification
installation, NRC required in a June 3, 1988 letter that the licensee
include the main ~ stack radiation monitor in the plant's Technical
Specification. The licensee submitted the Technical Specification
Amendment request on September 27, 1988.
The NRC approved the
request and issued Amendments 132 and 162 on June 12, 1989.
With
their inclusion into Technical Specification Table 3.3.2-3 an
isolation time of <1 second was required with an 18 month surveillance-
interval to demonstrate that feature required by TS 4.3.2.3.
Once the stack rad monitor was incorporated into TS, the licensee
developed the necessary procedures for surveillance testing.
Procedure 1/2 MST-RGE-31R was developed to demonstrate the time
response requirements of. TS 4.3.2.3 for the stack rad monitor.
The test is scheduled for accomplishment in August 1990.
The time
response of the installed system has therefore never been tested.
The inspector believes that the licensee should have reevaluated the
status of the system once the TS amendment was issued and performed
.the necessary testing for any design requirements that had changed
since initial installation and issuance of the amendment. The item
was discussed with plant management who acknowledged the inspector's
comments
Violations ano deviations were not identified.
9.
Exit Interview (30703)
The inspection scope and findings were summarized on December 1,1989,
with those persons indicated in paragraph 1.
The inspectors described the
areas inspected and discussed in detail the inspection findings listed
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belowLand in the summary. Dissenting comments were'not received from the
f. li cen see , No proprietary information-was identifiedEto the. inspectors.
m
, Item Number
Description / Reference Paragraph
-325/89-40-01
Violation - Inoperable SCIDs Due to Unrecognized
Design Logic Interface With SBGT, (paragraph ~Sa).
325, 324/89-40-02:
URI - Fire Protection Sprinkler Actuation During -
HELB May Affect EQ Components, (paragraph 8),
_13.
Abbreviations and Abbreviations
A0
AuxiliaryL0perator
. Administrative Procedures
BSEP'
Brunswick Steam Electric Plant
Engineered Safety Feature
F
' Degrees Fahrenheit
HP-
Health Physics
I&C-
Instrumentation and Control
IE '
NRC Office of Inspection and Enforcement
,
'IFI
Inspector Followup Item
_'
IPBS
-Integrated Planning, Budgeting _and Scheduling
'LER
-Licensee Event Report
MREM
Millirem
NRC.
Nuclear Regulatory Commission
Protected Area
PNSC
Plant Nuclear Safety Committee
Quality Assurance-
QC-
Quality Control
TS
Technical Specification
VRI
Unresolved Item
V
Volt
Vac
Volts Alternating Current
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