ML20207T856
| ML20207T856 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 03/02/1987 |
| From: | Fredrickson P, Garner L, Ruland W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20207T814 | List: |
| References | |
| TASK-2.K.3.18, TASK-TM 50-324-87-02, 50-324-87-2, 50-325-87-02, 50-325-87-2, NUDOCS 8703240387 | |
| Download: ML20207T856 (22) | |
See also: IR 05000324/1987002
Text
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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101 MARIETTA STREET.N.W.
ATLANTA. GEORGI A 30323
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Report Nos. 50-325/87-02 and 50-324/87-02
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: January 1 - 31, 1987
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Inspectors:
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Approved By:
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P. E. Fredrickson, Section Chief
Date S'igned
Division of Reactor Projects
SUMMARY
Scope:
This routine safety inspection involved the areas of followup on
,
previous enforcement matters, maintenance observation, surveillance observa-
tion, operational safety verification, onsite followup of events, ESF System
walkdown, onsite Licensee Event Reports (LER) review, in office LER review,
followup on inspector identified and unresolved items, cold weather prepara-
tions, Unit 2 drywell closeout and containment integrity, TMI action items,
Unit 2 hydrogen water chemistry test, and reportability for HPCI valve failure.
Results: Three violations were identified: inadequate procedure for responding
to a control room high chlorine alarm, failure to have Control Rod Drive pipes
supported in accordance with piping specifications, and failure to follow
procedures for installation of motor-operated valve anti-rotation devices.
8703240387 870303
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REPORT DETAILS
1.
Licensee Employees Contacted
P. Howe, Vice President - Brunswick Nuclear Project
C. Dietz, General Manager - Brunswick Nuclear Project
T. Wyllie, Manager - Engineering and Construction
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
K. Enzor, Director - Regulatory Compliance
R. Groover, Manager - Project Construction
A. Hegler, Superintendent - Operations
W. Hogle, Engineering Supervisor
B. Wilson, Engineering Supervisor
B. Parks, Engineering Supervisor
T. Parlier, Principal Engineer
R. Creech, I&C/ Electrical Maintenance Supervisor (Unit 2)
R. Warden, I&C/ Electrical Maintenance Supervisor (Unit 1)
W. Dorman, Supervisor - QA
W. Hatcher, Supervisor - Security
R. Kitchen, Mechanical Maintenance Supervisor (Unit 2)
C. Treubel, Mechanical Maintenance Supervisor (Unit 1)
R. Poulk, Senior NRC Regulatory Specialist
D. Novotny, Senior Regulatory Specialist
W. Murray, Senior Engineer - Nuclear Licensing Unit
Other licensee employees contacted included construction craftsmen,
engineers, technicians, operators, of fice personnel, and security force
members.
United Engineers & Constructors
J. May,79-01B Project Engineer, BESU
2.
Exit Interview (30703)
The inspection scope and findings were summarized on February 6, 1987,
with the general manager, vice president and manager engineering and
construction. Three violations (see paragraphs 6 and 7) were discussed in
detail. The licensee acknowledged the findings without exception.
The
licensee did not identify as proprietary any of the materials provided to
or reviewed by the inspectors during the inspection.
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3.
Followup on Previous Enforcement Matters (92702)
(OPEN)
Violation (324/86-12-01), Inadequate Acceptance Test 'in Valve
Operator Plant Modifications, response dated May 22, 1986. The inspector
reviewed documentation of training on this issue and verified that the
manual revision commitment in the response has been met.
However, a
related problem sas identified by the licensee during a review of the
results of 2MST "CI39R, High Pressure Coolant Injection (HPCI) Initiation
Response Time Tes'
run on January 16, 1987. The test had been completed
satisfactorily,
b ever, a member of the maintenance staff questioned
whether the respon;e time of 2-E41-V8, HPCI turbine stop valve, was
correct.
The licensee assigned BESU an action item to research the
problem.
Plant modification 2-83-240, HPCI Turbine Stop Valve Limit Switch Replace-
ment (E41-C002-LS4), failed to adequately specify a test for the HPCI
system.
The limit switch provides the permissive to open the HPCI
injection valve, directly affecting the response time of the system. The
acceptance test only verified that V8 opened and closed and that the limit
switch functioned correctly. The affect on HPCI system response time was
not addressed. While the acceptance test was inadequate, the response
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time was satisfactory based on the performance of the 2MST-HPCI39R on
January 16, 1987.
However, the modification had been declared operable
per memorandum dated March 28, 1986.
No notice of violation is being issued since the date of modification
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operability predates the issuance of the violation and subsequent
response. This violation remains open pending review of the licensee's
Operating Experience Report (OER) and further corrective action in this
area.
One licensee identified violation and no deviations were identified.
4.
Maintenance Observation (62703)
,
The inspectors observed maintenance activities and reviewed records to
verify that work was conducted in accordance with approved procedures,
Technical Specifications, and applicable industry codes and standards. The
inspectors also verified that:
redundant components were operable;
administrative controls were followed; tagouts were adequate; personnel
were qualified; correct replacement parts were used; radiological controls
were proper; fire protection was adequate; quality control hold points
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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.
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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:
86-BUGG1
Conduit Changeout on Diesel Generator (DG) No.1 Lubrica-
tion Temperature Switch.
87-AABK1
Reference Leg Fill for Unit 2 Reactor Water Level Instru-
ment B21-LTM-N0170-1.
MI-10-6G
Plant Batteries, Rev. 12, performed on battery 1A-1,
86-BSDF1
MI-10-500G
Annual Lubrication Change Schedule.
The licensee found a deteriorated jacket water gasket while performing
maintenance on DG 3.
The gasket was located between the engine block and
a cylinder head. The gasket sealed the internal Jacket water passage from
the block to the cylinder head.
The gasket had allowed jacket water to
leak out onto the top exterior of the engine. No damage was done to the
engine.
The licensee has sent the gasket to the Harris Energy and Environ-
mental Center for examination. The licensee plans to replace the gaskets
(one per cylinder) during normal diesel outages once the new 7 day LC0 TS
is approved. The inspector will followup on the licensee's final resolu-
tion of this issue. This is an Inspector Followup Item: DG Jacket Water
Gasket Deterioration (325/87-02-03 and 325/87-02-03).
No violations or deviations were identified.
5.
Surveillance Observation (61726)
The inspectors observed surveillance testing required by Technical
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Specifications.
Through observation and record review, the inspectors
verified that:
tests conformed to Technical Specification requirements;
administrative controls were followed; personnel were qualified; instru-
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mentation was calibrated; and data was accurate and complete.
The
inspectors independently verified selected test results and proper return
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to service of equipment.
The inspectors witnessed / reviewed portions of the following test
activities:
IMST-HPCI39R
HPCI Initiation Response Time Test.
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2MST-ADS 23R
Automatic Depressurization System (ADS) Safety Relief
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Valve Primary Position Channel Calibration.
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Control Rod Drive (CRD) Accumulator Leak Detection Channel
Functional and Low Pressure Channel Calibration.
HPCI Steam Line Break High Differential Pressure Trip Unit
Channel Calibration.
HPCI Initiation Response Time Test.
PT-12.3.1
Emergency DG Inspection.
While observing PT-12.3.1 on DG No.1, the inspector observed that the
fuel pump to injector lines had been removed with no action taken to
prevent trash from falling into the fuel pump discharge opening.
The
cross connect between the left and right fuel return lines was found with
two adjacent support clamps missing. The inspector found one fuel return
line flexible hose abraded from contact with a support member edge. No
condition found by the inspector rendered the DG inoperable. These items
were called to the attention of the maintenance manager.
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 and clearance 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 parameters were within Technical Specification
limits. The inspectors observed shift turnovers 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 identi-
fled 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.
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The inspectors verified that the licensee's health physics policies /
procedures were followed. This included a review of area surveys, radia-
tion 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 identifica-
tion 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.
The following items were observed in the main control room:
a.
On December 31, 1986, the inspector observed licensed personnel's
response to notification of inoperable Technical Specification (TS)
equipment from the time of notification through completion of the
required action statement. The Limiting Condition of Operation (LCO)
involved less than the required number of chlorine detection system
monitors being available, as required by TS 3.3.5.5.
Action state-
ment "b" of TS 3.3.5.5, requires, with both chlorine detectors of
either subsystem inoperable, within one hour isolate the control room
and operate in the recirculation mode. The licensed operator, whom
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was notified that both the Unit 1 and 2 control room monitors
1-X-AT-2977 and 2-X-AT-2977 were inoperable due to electrolyte not
wetting the sensor, knew immediately that they were in a TS LC0
condition.
The inspector noted the following areas of concern:
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The notified individual failed to note the time of notification.
He estimated a time of 9:35 a.m.
When the one hour action
statement was completed at 10:37 a.m., he re-evaluated his time
of initial notification as 9:40 a.m.
The inspector cbserved the
individual on the phone between 9:38 a.m. and 9:40 a.m.
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The action statement phrase, " operate in recirculation mode",
caused some confusion.
The operators had been trained that
recirculation mode meant running the Control Building Emergency
Air Filtration (CBEAF) trains with a makeup of 1000 SCFM from
the outside. In the event of a real chlorine release this would
not be desirable. Shift personnel finally decided that recircu-
lation mode meant running the normal air conditioning system
without any outside makeup.
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The operator followed the instructions provided in annunciation
procedure APP-UA-28, 5-1, Control Room Intake Air Hi Chlorine,
Revision 7, dated May 22, 1986. By following this procedure, the
operator was unsuccessful in closing the normal makeup air
damper (2L-D-CB). One of the chlorine monitor test buttons was
depressed and left engaged to keep the damper closed until a
fuse could be pulled to de-energize the damper in the close
position.
The annunciator procedures app-UA-28,
5-1,
on both Unit 1
(Revision 8) and 2 (Revision 7) were inadequate.
New chlorine
monitors were installed per plant modification 86-072. The system
had been returned to service at 9:30 a.m. , on December 24, 1986.
The new monitors incorporated an automatic reset of the high
chlorine alarm when the condition cleared.
Hence, the momentary
lifting and retermination of a lead in the logic without resetting
the monitor as provided in the annunciator procedure, would not keep
the makeup damper closed.
The need to change the APP was not
identified by the modification package. TS 6.8.1.a. requires written
procedures be established for procedures in Appendix A of Regulatory
Guide 1.33, November 1972. The regulatory guide requires procedures
for correcting abnormal, offnormal or alarm conditions.
Failure to
adequately establish APP-UA-28, 5-1, is a violation of TS 6.8.1.a:
Failure to Adequately Establish Chlorine Monitor Annunciator
Procedure (324/87-02-02 and 325/87-02-02).
The licensee identified the problem with the monitors as a vacuum
being created in the electrolyte reservoir, thereby inhibiting flow
onto the sensor. The licensee drilled holes in the plastic reservoir
cap to correct the problem.
The licensee will issue an OER to resolve the issues found during
this event.
The inspector will review the OER as part of the
violation followup.
b.
On January 6, 1987, the inspector observed on Unit 2, that the B Loop
of Residual Heat Removal (RHR) was in an abnormal configuration.
Discussion with the control operator, who was reviewing the system
alignment, revealed that the RHR pump shutdown cooling suction valves
E11-F006B and 0 had been lef t closed.
The operator had initialed
step 5.4.B.28 of OP-17, Residual Heat Removal System Operating
Procedure, indicating that he had opened these valves. The failure
to complete the step correctly is considered a licensee identified
violation per 10 CFR 2,
Appendix C,
in that it would have been
identified had the inspector not asked.
Corrective actions were
discussed with the operations manager.
c.
On January 12, 1987, the inspector observed no indication on the Unit
1 "J" drywell to torus vacuum breaker. The operator replaced a burnt
out lamp.
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d.
On January 18, 1987, at 4:10 p.m., the inspector observed that Unit 2
had entered an LC0 per TS 3.3.2.
The shift foreman, while reviewing
procedures for changing conditions from startup to power operation,
discovered that reactor pressure was above 500 psig with the -low-
condenser vacuum switches B21-PTM-N056A,
B,
C and D bypassed.
Footnote f of TS table 3.3.2-1, requires the channels to be operable
with reactor steam pressure greater than or equal to 500 psig.
Reactor pressure was reduced to below 500 psig at 5:02 p.m.
The subject was brought to the attention of the operations super-
intendent and general plant manager on January 20, 1987.
The
licensee then initiated a review into the circumstances surrounding
the LCO.
On January 17, 1987, at 11:58 p.m.,
in accordance with
Gp-05, Unit Shutdown, the bypass switches were placed to BYPASS when
reactor pressure was less than 500 psig. At 11:50 p.m., the inboard
Main Steamline Isolation Valves (MSIV) had been closed to maintain
reactor pressure.
At 1:00 a.m.,
on January 18, a clearance,
No. 2-0087, was hung on the inboard MSIV to allow the turbine
gen 2rator exciter to be uncoupled from the generator. Between 2:15
and 2:45 a.m. , on January 18, the shift which bypassed the low
condenser switches allowed reactor pressure to go above 500 psig.
Pressure remained above 500 until the time of discovery at 4:10 p.m.,
by the next shift.
With the switches bypassed, all four channels were inoperable. Per
TS action statement 3.3.2.c, one channel had to be tripped in one
hour and take the action in table 3.3.2.1.
The action No. 21,
required by table 3.3.2.1, is to be in at least startup with the
MSIVs closed within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or be in at least hot shutdown within 6
hours and in cold shutdown within the next 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
From the information presented to the inspector, it appears
fortuitous that the action statement associated with TS 3.3.2 was
met.
According to the licensee, because the inboard MSIVs were
closed prior to exceeding the 500 psig, the intent of action No. 21
{
was met; the unit was in startup with the reactor isolated from the
condenser by the main steamlines being closed. The inspector agrees
with the licensee that this was indeed the situation.
However, the
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inspector notes that the action statement does not specifically
indicate whether closure of one or both MSIVs are required in each
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line.
Failure to close both valves in each line in this particular
case resulted in no safety hazard.
However, this same action
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statement also applies to inoperable main steam radiation monitor
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channels. In that case, it would be advantageous to have both valves
closed, thereby reducing the potential of leakage through the main
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steam 11nes. During the exit, the plant manager agreed to provide the
operators additional guidance concerning shutting the MSIVs in
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compliance with TS.
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The licensee plans to revise GP-05 to include a caution note not to
exceed 500 psig with the low condenser vacuum switches bypassed.
This is an Inspector Followup Item: Add Caution Note to GP-05 and
Review Instructions Regarding MSIV Closure (324/87-02-04).
e.
On January 26, 1987, the inspector observed no indication on the
Unit 1 "C" drywell to torus vacuum breaker. The operator replaced a
burnt out lamp.
During a Unit 2 drywell inspection on January 7,
1987, the inspector
observed a loose pipe clamp nut on snubber 2E11-875S318 and a missing and
some loose pipe clamps on the CRD lines. The licensee issued work request
87-AASE1 to tighten the snubber pipe clamp.
Field inspection by the
,
licensee revealed 5 of 1216 pipe clamps inspected were missing. Another
114 were either loose or bent such that the tolerance between the clamps
and CRD lines exceeded the allowable tolerance. The allowable tolerance
is 1/8" as specified in piping specification BSEP 248-107, section 20.1.
The licensee corrected the problems prior to startup.
An engineering evaluation (EER 87-0051) identified the as-found condition
of the insert lines to meet both short term and long term ASME code
criteria.
One configuration on the withdrawal lines was found to meet
only the short term criteria. Meeting the short term criteria means that
the calculated stresses do not exceed that required to make the material
fail, but, all the conservatism required by the ASME code is not met.
Hence, none of the as-found conditions were severe enough that failure of
a line would have occurred in the event of a seismic event. The safety
significance of postulated CRD line breaks is discussed in FSAR paragraphs
4.6.2.2.2, 4.6.2.2.3 and 4.6.2.2.4.
In summary, the control rod is
anticipated to either stay in place or insert into the core.
A break in the CR0 lines would result in leakage of the reactor coolant
into the drywell .
Paragraph 4.6.2.2.3 of the FSAR states that in an
experiment to simulate the failure of the withdrawal line, a leakage rate
of 80 gpm had been measured with reactor pressure at 100 psi. These lines
are considered to be safety related lines. Failure to have the CR0 lines
supported in accordance with section 20.1 of procedure BSEP 248-107 is
a condition adverse to quality.
This is a violation of 10 CFR 50,
Appendix B, Criterion V, which requires activities affecting quality be
accomplished in accordance with procedures: Failure to Have CRD Supports
Installed Per Specification (324/87-02-01).
One violation and no deviations were identified.
7.
Onsite Followup of Events (93702)
On January 5,
1987 at 4:12 p.m.,
Unit 2 reactor experienced a turbine
control valve (TCV) fast closure scram from 100*. of full power.
The
initiating event was a malfunction of the main generator auto voltage
regulator.
While attempting to raise the voltage as required by
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procedures, the auto voltage regulator became erratic. Voltage oscillated
up and down randomly in large swings.
On one spike down, the loss of
excitation relay actuated causing the generator field breaker to open and
a load reject signal to be generated.
The TCVs fast closed on the load
reject signal. The loss of excitation relay actuation also initiated a
primary generator lockout. The resultant trip of the generator caused a
power drain on the system and a 60% to 70*.' of nominal voltage degraded
voltage condition. This condition existed for approximately five seconds.
The following sequence of events describes the plant response of major
systems and operator actions required to place the plant in a stable
condition.
TIME:SEC.
EVENT
COMMENT
1612:45
Reactor Scram.
1612:46
Group 1 (MSIV Closure).
Degraded voltage on E Bus
probably allowed leak
detection logic to
momentarily de-energize.
DGs start.
Per design, DG start on
primary generator lockout.
Recirculation Pumps
Probably on high reactor
trip.
pressure.
HPCI/ Reactor Core
Momentary Low Level No. 2
Isolation Cooling
starts systems but clears
(RCIC) Turbines Start,
before injection valves'
other permissives are met.
1613:04
(SRV) F, J, K, G, H open.
1616
HPCI/RCIC Turbines trip.
Reactor Vessel level
increases to 208" because of
SRV lift swell and
feedwater injection while
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feed pumps coast down.
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Manual SRV A lift.
Per Emergency Operating
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Procedure (EOP).
1618
Manual SRV E lift.
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1619
HPCI manually started
HPCI F006 (inboard injection
to feed vessel.
isolation valve) is manually
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opened,
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Standby Gas Treatment
Per E0P and Operations
System manually started.
Procedures OP-19.
1620
RHR Loop B placed in
Torus Cooling Mode.
1621
RCIC manually started
to feed vessel.
1623
Manual SRV J lift.
1625
HPCI flow to vessel
HPCI F006 valve is closed,
secured.
Placed in
full flow test mode
for pressure control.
RCIC remains in
injection mode.
1632
Vessel level at 181".
Normal value is 187".
1637
Open inboard MSIV
Per E0P.
To equalize around
and steam line drains
reopened and main condenser
used as heat sink.
1642
Reactor low level No. 1
HPCI, RCIC and main steam
reached (162.5").
line drain steam flow
exceeds RCIC and CR0 A pump
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ability to add water.
Manual opening of HPCI
Attempting to use HPCI to
F006 fails. Overload
supplement RCIC flow to
alarm comes in.
vessel.
Valve fails to move
off seat.
1653
Second attempt to open
Breaker reset.
Next attempt
HPCI F006 fails,
results in overload alarm
again.
Valve never moves.
Vessel level at 144".
1655
Close steam drains and
To conserve inventory,
inboard MSIVs.
Start CR0 Pump B.
Both CRD pumps running.
1658
Vessel level at 137".
Pressure at 853 psig.
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1700
Torus temperature is
95 degrees F.
1705
Second Loop of RHR, A,
placed in Torus cooling
mode.
1706
Vessel level at 132".
1708
Manual SRV F lift.
1710
Torus temperature is
97 degrees F.
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1713
Manual SRV D lift.
1716
Manual SRV G lift.
1721
Manual SRV C lift.
1745
RCIC trips on high
RCIC and 2 CR0 pumps over-
level,
fill level.
Exact time not
known.
Estimate from vessel
level chart.
1811
RCIC manually started
RCIC F022 valve (full flow
and placed in full
test line isolation), is
flow test mode,
manually opened.
First time
valve is actuated during
1815
Unsuccessful attempt to
RCIC F022 valve gave full
switch RCIC from full
close indication but pump
flow test mode to
discharge pressure would not
injection into vessel,
exceed 350 psig.
Vessel level decreasing.
RCIC using steam but not
adding water.
Both CR0
pumps could not make up
inventory loss.
Redundant RCIC full
If level had continued to
flow test line isolation
decrease to low level No. 2
valve, HPCI F011, is
(112"), the HPCI F011 valve
manually closed,
would have received an
automatic low level close
signal.
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1817
RCIC injection into
vessel.
2018
Open MSIVs.
2050
Started 2A Reactor
Cooldown continued.
Cold
Feedpump.
shutdown reached on January
6 at 1950 hours0.0226 days <br />0.542 hours <br />0.00322 weeks <br />7.41975e-4 months <br /> without any
major problems.
Excluding HpCI and RCIC, all other major components functioned as
designed. These items are discussed in greater detail below. The voltage
regulator was found to have dirty contacts.
Because the regulator had
been erratic, the licensee was in the process of writing a special
procedure to clean the contacts while on line.
During the event, the RHR Service Water (RHRSW) pump 20 was found tripped.
It was restarted without difficulty.
The permissive suction pressure
switch was calibrated.
No problem could be found.
The cause of the
initial pump trip was attributed to low suction pressure. Apparently when
the 2A RHRSW pump was started with two service water pumps supplying
the conventional service water header, the header pressure decreased
momentarily causing the 2D RHRSW pump to trip.
Other problems encountered involved SRV sonic detector indications and
some computer points which did not print.
These items were corrected
prior to startup on January 13, 1987,
2-E51-F022, RCIC Return to Condensate Storage Tank (CST), Anti-Rotation
Device
The F022 valve failed to fully close due to failure of the valve's anti-
rotation device.
During normal operation, the motor operator stem nut
turns, moving the valve stem up or down.
The stem clamp, normally
attached to the valve stem through a key and set screw arrangement, rides
up and down a groove inside the valve yoke, preventing stem rotation.
If
the stem clamp disengages from the yoke guide, the valve stem would turn
with the stem nut and not open or shut the valve.
Once the actuator
turned the limit switches the required number of turns, the valve would
indicate the required position and stop.
The F022 valve failed because the set screw had not been engaged to the
valve stem.
The valve stem set screw hole had been drilled in the wrong
location, not allowing the set screw to engage the valve stem.
This let
the stem clamp drop down, freeing the stem clamp key, disengaging the stem
clamp from the yoke. When the valve was operated, the motor-operator
turned the required number of turns, the closed limit switch then opened,
stopping the motor. However, since the stem was rotating, the valve was
not shut.
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The licensee found five other valves with anti-rotation device stem clamp
problems during subsequent inspections as follows:
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Valve
Problem
2-E11-F0248, RHR Suppression Pool
Valve Stem Not Drilled.
Return Valve.
2-E11-F045, RCIC Steam Admission Valve.
Missing Key.
1-E41-F012, HPCI Minimum Flow Valve.
Missing Key.
Two Unit 2 non-safety Reactor Water Cleanup (RWCU) valves also had
problems.
The licensee has inspected all but seven Unit 1 valves that have anti-
rotation devices as of the exit interview. The licensee has committed to
report the complete inspection results in a supplement to LER 2-87-01.
The inspectors will followup on the inspection as part of the LER
clowout.
When the licensee had discovered the F022 problem, they embarked on an
ihspection program.
Special Procedure SP-87-002, Inspection of Anchor-
04,rling Anti-rotation Devices for Unit 1 and 2, was written to conduct
the inspection.
The licensee started inspecting Unit 2 valves per the
pricedure first and performed a visual inspection of the Unit 1 valves for
dislodged stem clamps. No problems were noted during the visual inspec-
tien. However, the E41-F012 valve was found with a missing key when the
SP-37-002 inspection was performed. The stem clamp had rotated with the
set screw catching in the stem keyway. While the valve would continue to
function like that, for how long is unknown. Thus, the ability of the
miniaum flow valve to maintain a flowpath for the HPCI system was in
jeopt rdy.
The tissing key for the 2-E51-F045 valve could have compromised the
operaatlity of the RCIC system.
The F045 must open in the event of a
demand for RCIC in order to supply steam to the turbine. The set screw
was pieventing rotation of the valve stem rather than the key / keyway fit.
While the RCIC was not rendered inoperable at that time, valve failure
could have occurred in the future.
Two licensee procedures currently govern the installation of the anti-
rotation devices:
Anchor (Pressure Seal) Globe Valves Maintenance
Instruction MI-16-503J, and Anchor (Bolted Bonnet) Globe Valves Mainte-
nance Instruction MI-16-5030.
For example, MI-16-503J, Rev. 6
step
!!.D.18 of the reassembly procedure, requires that the mechanic " Replace
the -key (s) and lif t the stem clamp in place." Contrary to this require-
ment, valves 2-E51-F045 and 1-E41-F012 were found without keys.
Step
!!.D.17, requires the mechanic to drill small indentations in the valve
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14
stem per attachment 1 in the procedure.
Contrary to this requirement,
valve 2-E51-F022 was found with the stem indentation incorrectly drilled.
Based on the location of the set screw, the indentation could not be lined
up to the screw. The above failure to follow procedure is a violation:
Failure to Follow Maintenance Procedures When Installing Motor-Operated
Valve Anti-Rotation Devices (325/87-02-05 and 324/87-02-05).
2-E41-F006, HPCI Injection Valve, Motor Failure
As described above, the F006 motor failed when the operator attempted to
manually inject HPCI. The licensee found a hole burned through the motor
armature and extensive heat damage.
The DC motor was manufactured by
Peerless for Limitorque in August,1985, per the date code in the serial
number. The inspector verified that environmentally qualified insulation
had been used in the motor.
The verification was accomplished through
examinations of motor procurement documents, motor and insulation inspec-
tion, and discussions with licensee employees and a vendor program branch
inspector.
The inspector also verified that a recent Part 21 issued by
Limitorque on December 19, 1986, concerning lead wire insulation, did not
apply to the F006 motor. The part 21 referred to a Kapton over Nomex
insulation while the F006 valve had a woven fiberglass over Nomex.
One violation and no deviations were identified.
8
Engineered Safety Features (ESF) System Walkdown (71710)
The inspectors performed a walkdown of the Unit 1 and 2 HPCI systems. The
walkdown included inspection of the turbine pump skids, portions of the
steam lines and injection lines.
Major valves and instruments were
verified to be in service as required by operating procedure, OP-19, High
Pressure Coolant Injection System, Revision 7 and 52 for Units 1 and 2,
respectively.
No violations or deviations were identified.
9.
Onsite Review of Licensee Event Reports (92700)
The listed Licensee Event Reports (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, licensee conditions and commitn.ents.
The
following reports are considered closed.
(CLOSED) LER 1-84-04, Train 8 of Control Building Emergency Air Filtra-
tion (CBEAF) System Started Due to Fire Alarm in Unit 2 Back Panel Area.
The licensee committed to evaluate corrective actions to minimize spurious
actions of the CBEAF systems.
The licensee implemented modification
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No.85-042 ir/ December, 1985, thave the CBEAF isolate only on tnr fira
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detectors witMn the zones .affected by the CBEAF system.
The inQector
rev'ewed the conclusions of the engineering evaluatic and the o$ rability
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checksheet associated with the modification.
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(CLOSED) LER 3-84-05, Train'[A of CBEAF Systems Starterf Due to a Sh eted
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Fire Datector in the Cabladpread Area. The electricilly shorteo fire
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.' detector in tM Unit 2 cab % spread are,s was repaired under work request,
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No. 1-E-84-2184.
The inspector reviewed the licensee's LER closeout B
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package. The, Anspector noted tFat this cetector has been removed 'from'c
those wMeh a;tuate CBEAFJ 'See LEA 1-84-04 above.
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(CLOSED) LER 1-84-06, Inadvertent Securing of Service Air to Condensate
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Flow Control Valves fwsults' tn Loss of Feedwater and Unit 1 Scram. The
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. inspector verifisd..via the training, roster, tiat the licensee conducted
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training of appropriate operations personnel,as committed in the LER. f
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(CLOSED) LER 1-h4-23, UnM 1 and 2 Core 3 pray Loops A Inoper able 11ue +.'o
Support Imbed Plates Being Loose.
A supplement to. the LER was issued
February 12, 1985. Cause of,the problems was attribut2d to.possible w eer
hammer events at some undetermined time.
The /nspectar \\*rtfied that
,*
Procedure Test, PT-7.2.4a and db. Core Spray Syt. tem Operability Test, icop
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A and . Loop B respectively, yhidh are pe1,*!ormed every 92 ' days, requins
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posting of an operator to men! tor sy tp piping for excessive motion or
water harmer.
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(CLOSED) LER 1-84-28, Automatic Actuatior of'C8ti4 Train B b e to Failure
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of Actuation Relay. The inspector reviewed th9 wpLrequestfo.1-E-84-
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5292 which repaired the actuation relay.
(CLOSED)
LER 1-84-32, Spurious Actuations of Control Room Chlorine
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Detectors. New detectors were installed in December, 1986, per modifica -
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tion No.86-072.
The inspector verified operability' of the new rt.onitors
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after installation.
Algae growth in electrolyte is discussed in LER
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1-85-43 write up.
(CLOSED) LER 1-85-18 Inadvertent Primary Containment Groups 3 and 6 Oue '
to Open Power Supply Breakers and Blown Fuse. The inspector verified via
the training roster, dated May 4,1985, that the LER was revieced with
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craftsmen as committed.
(CLOSED)
LER 1-85-21, Spurious Actuations of CBEAF/ Control Building
,
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Heating Ventilating Air Conditioning (CBHVAC) Isolation Due to Fire
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Detectors and Chlorine Monitor.
Modifications have been installed to
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reduce spurious fire detector actuations. See LER 1-84-04 write up.f The
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chlorine monitors were also replaced.
See LER 1-84-32 closecut.
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(CLOSED)
LER M-85-31, Reactor Protection System Trip During Induction
Heat Stress Irrrovement of Recirculation System Piping.
The inspector
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verified that plant modification No.85-022 had been revised as committed.
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(CLOSED) LER I-85-32, Spurious Intermediate Range Monitor (IRM) A Signal
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\\ b U)N p'Causes Reactor , Protection System fxtuation During Refueling Outage. The
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inspector reviewed completed work request 1-E85-2691.
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(CLOSED)
LER 1-85-34, Bumping of Loose Fuse Holder Initiates Group 8
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Primary Containment Isolation System. The loose fuse holder was replaced
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on' July 18, 1985, per work request 1-E-85-2642. The inspector verified
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thate 1-E-85-2642 contained appropriate quality control verification of
'6',
reterminated leads.
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(CLOSED)
LER 1-85-37, ' Reactor Protection System Trip During Refueling
,V
Outage Due to Radiography.
The licensee issued standard operating
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practice, SOP-3.15, Radiography Controls, on August 23, 1985, to prevent
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recurrecce.
The inspector verified that SOP-3.15 adequately addresses
enhanced' controls to reduce the potr 'tial of radiation monitors being
,
-affected by radiography,
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- (CLOSED) LER 1-85-38, Auto Initiation of CBEAF System Due to Defective
Fire Detector.
Cause of the fire detector failure could not be
,
determined.
(CLOSED) LER 1-85-40, Spurious Signals from Fire Detectors Cause CBEAF
Actuations. This LER references the modification committed to in earlier
LERs. See LER 1-84-04 writeup.
I
(CLOSED)
LER 1-85-43, Fungi Growth Results in Inoperable Chlorine
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Detectors.
The licensee implemented plant modification Nos.85-057 and
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86-072 to address the problem.
The inspector verified that the new
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monitors have sight glasses to determine electrolyte level. The inspector
verified that the current revision (Revision 1, dated January 7, 1987), of
procedure OPM-DET001, PM for Wallace and Tiernan 50-125 D1 and 50-125
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Chlorine Detectors requires, per step 7.3.1, the addition of sodium
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benzoate to the electrolyte solution. This is to inhibit algae or fungi
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growth in the electrolyte solution.
(CLOSED) LER 1-85-44, Faulty Turbine Stop Valve Servo Valve contributes
to Group 1 Primary Containment Isolation System Actuation During Refueling
,
Outage.
The inspector reviewed the work request No. 1-E-85-3576, which
replaced the servo valve.
(CLOSED)
LER 1-85-48, Spurious Fire Alarms from Computer Room Air
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Conditioner Condensate Dripping on Detectors Results in CBEAF Actuations.
This LER references the modification committed to in earlier LERs.
See
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LER 1-84-04 writeup.
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(CLOSED) LER 1-85-50, Chlorine Detector Spurious Actuations Cause CBHVAC
Isolations. Corrective actions include those inspected as part of LER
1-85-43 closeout. See LER 1-85-43.
In addition, the licensee committed
to perform increased surveillance on the monitors. The inspector verified
that PT-46.3P contained the appropriate checks as committed. The PT'has
been replaced by OMST-CLDET11M. The inspector reviewed Revision 4, dated
January,5,1987, of OMST-CLDET11M.
(CLOS D)
LER 1-85-57, Automatic Isolation of CBHVAC Due to Spurious
Chlorine Detector Alarm.
See LER 1-85-50 closeout writeup.
(CLOSED)
LER 1-85-60,
Failure to perform Required Explosive Gas
Monitoring System Sampling When Plant Condition Changed. The inspector
verified that current revisions of operating procedures GP-02, Approach to
Criticality and Pressurization of the Reactor, Revision 12, and OP-30,
Condenser Air Removal and Off Gas Recombiner System, (Rev.12 for Unit 1
and Rev. 36 for Unit 2), contain reference to Technical Specification (TS)
Table 4.3.5.9-1 requirement if any hydrogen analyzers are inoperable. The
inspector also verified that LER 1-85-60 discussion was included in real
time training package No. 86-1-3.
(CLOSED)
LER 1-85-61, Low Pressure Coolant Injection (LPCI) and Core
Spray Declared Inoperable. The licensee committed to return the failed
transmitter for
failure analysis.
The
inspector
reviewed
the
manufacturer's (Rosemont) analysis.
Rosemont concluded that the failed
component, designated IC-1, on the amplifier board had resulted in an
abnormal zero and full scale shift.
Based on their projected lifetime,
they considered tne failure as random.
(CLOSED) LER 1-86-12, Personnel Error Results in CBHVAC Isolation Due to
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Chlorine Leak. The licensee committed to review the event with operations
personnel. The inspector reviewed the plant memorandum from the opera-
tions manager to the operations supervisors concerning this event and
procedural ccepliance.
The inspector verified, via training roster
memorandums,'that appropriate licensed and non-licensed personnel reviewed
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s
procedural compliance policy.
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No violations or deviations were identified.
10. In Office 'LER Review (90712)
The 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.
(CLOSED)
LER 1-85-63, s9rimary Containment Group 3 Isolation; Isolation
Signal Is Attributed to a, System Leak Condition.
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(CLOSED) LER 1-86-03, Automatic Isolation - Common CBWVAC System; Due to
Chlorine Detection Alarm.
(CLOSED)
LER 1-86-04, Automatic Starting of CBEAF System Train 2A;
Cause-Spurious Actuation of a Fire Detector in Unit 2 Electronic Equipment
Room and Actuation of a Fire Detector at Unit 1 Control Room.
(CLOSED)
LER 1-86-05, CBHVAC System Auto Isolated / Train 2A of CBEAF
System Auto Started Due to High Radiation Trip Signal from Common Control
Room Area Radiation Monitor Trip Module.
(CLOSED) LER 1-86-06, Automatic Isolations of Units 1 and 2 CBHVAC System
'
occurred Due to Actuations of Chlorination System Storage Area Chlorine
Detector; Cause-Chlorine Gas in Vicinity of the Detector.
(CLOSED)
LER 1-86-07, Units 1 and 2 CBEAF System Train 2A Automatically
Started Due to a Control Building Fire Alarm; Cause-Actuation of Fire
Detector in the Units' Common Control Room Kitchen Due to Cooking Fumes.
(CLOSED)
LER 1-86-08, Automatic Closure of Reactor Water Cleanup (RWCU)
System Inlet Primary Containment Outboard Isolation Valve,1-G31-F004, Due
to Erroneous RWCU System Area High Temperature Signal.
(CLOSED)
Information LER 2-86-19, Misconfiguration of Traversing Incore
Probe (TIP) System Due Misidentification of the Tubing. See followup on
Unresolved Item 324/86-18-04, this report.
No violations or deviations were identified.
11.
Followup on Unresolved Items (92701)
(CLOSED)
Unresolved Item (324/86-18-04), TIP Tube Reversal.
Event
information also included in LER 2-86-19. This item was last inspected in
report 324/86-22. The licensee confirmed that the TIP tubes were reversed
on a drywell entry on October 16, 1986 as documented in work request
85-AKHLI.
The inspector reviewed the work request which corrected the
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misconfiguration. Based on the licensee's identification of the reversal,
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their prompt corrective action at the time of discovery, their submittal
of an ir.formational LER, that the violation could not have been prevented
!
by corrective action for a previous violation, and that the problem was
,
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corrected, no Notice of Violation is being issued.
(CLOSED) Unresolved Item (325/86-21-01), Licensee's Implementation of TS
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3.0.5.
The inspector reviewed the licensee's position on TS 3.0.5 as
stated in an internal memorandum dated September 3,
1986, serial No.
86-1300.
That memorandum has been reviewed by the Plant Nuclear Safety
l _
Committee
The inspector also reviewed 01-4, Rev. 24, LCO Evaluation and
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Followup, Attachment G: Equipment Required Operable With Diesel Generator
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The licensee included in Attachment G all the ESF equipment
that has redundant components that need emergency power to perform their
safety .related function.
Based on a review of TS 3.0.5,
the above
documents and discussions with plant personnel, the inspector concludes
that the licensee has adequately addressed the issue.
No violations or deviations were identified.
12. Cold Weather Preparations (71714)
The inspector verified that the licensee had implemented 0/I-43, Freeze
Protection and Cold Weather Bill, Rev. 1,
on January 30, 1987.
The
inspector verified that the freeze protection circuit lights were
energized for the RCIC/HPCI condensate storage tank low level switches.
The inspector noted that the thermometers used to measure ambient
temperatures in the service water and diesel generator buildings were
missing. The shift foreman directed an auxiliary operator to replace the
thermometers.
No violations or deviations were identified.
13. Unit 2 Drywell Closeout and Containment Integrity (71707, 61715)
On January 11, 1987, the inspector conducted a tour of the Unit 2 drywell
prior to operations closeout. The inspector observed that the "L" sonic
detector had two of the four mounting band nut to retaining band tack
welds broken.
One edge of the detector was in contact with the SRV
discharge pipe but the opposite side was approximately 1/8" from the pipe.
The licensee replaced the retaining band with one from stock per work
request 87-ABER1.
The licensee could not determine when or how the
retaining assembly got damaged. The inspector verified that the manual
isolation valves on the RHR and core spray systems were locked open as
required per procedure.
A visual inspection of the inboard primary
containment isolation valves was performed on the following systems:
HPCI, RCIC, RWCU, feedwater and main steam. No problems were noted. The
inspector also examined the outboard MSIVs and fesd.ater stop check valves
in the MSIV pit.
Some scoring was noted on the
"C"
MSIV stem.
This
condition had already been evaluated by maintenance.
Plant engineering
plans to re-inspect this item whenever the MSIV pit is accessible.
No violations or deviations were identified.
14. TMI Action Items (25565)
II.K.3.18.c
Modify Automatic Depressurization System (ADS) Logic -
Feasibility for Increased Diversity for Some Event Sequences.
ADS logic modification was required to eliminate the need for manual
actuation of ADS during some accident sequences. The licensee chose to
implement option two modification that was found acceptable to the NRC
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staff in the safety evaluation issued by NRR on June 3,
1983.
The
licensee committed to the installation of the modifications in a letter
dated March 9, 1984. NRR accepted the licensee's commitment in a letter
dated May 18, 1984. The licensee installed the Plant Modifications (PM)
in PM-84-369, declared operable on October 26, 1985, and PM-84-370,
declared operable on May 20, 1986, for Units 1 and 2, respectively.
TS
amendment 87 for Unit 1, dated July 30, 1985, and amendment 124 for
Unit 2, dated April 30, 1986, were made, incorporating the logic changes.
The inspector verified that the ADS logic change was accomplished in
accordance with the commitments made to the NRC.
The verification
included a review of the plant modification packages, as-built drawing
changes, review of Emergency Operating Procedures level / power control flow
chart which included the requirement to place the ADS logic inhibit
switches to inhibit prior to injecting Stanoby Liquid _ Control during an
Anticipated Transient Without Scram (ATWS).
The inspector reviewed
training documents concerning the modification.
The inspector verified that the new switches were installed in the control
room.
The inspector verified that the surve. lance requirement to verify
the position of the inhibic switches had been implemented in 01-3.1 and
3.2, revisions 2 and 4, for Units 1 and 2, respectively.
This item is
closed for both units.
No violations or deviations were identified.
15. Unit 2 Hydrogen Water Chemistry Test (79502)
The licensee conducted test 2-SP-86-081, Rev. 1: Hydrogen Water Chemistry
Mini-Test to Determine the Feasibility of Using Hydrogen to Minimize
Inter-Granular Stress Corrosion Cracking (IGSCC) at Brunswick.
Report
325, 324/87-01 has further details.
The resident inspectors verified
i
that: Main Steam L_ine (MSL) radiation monitor setpoints were increased
per procedure; radiation surveys were conducted prior to and during the
test; personnel manned H2 and 02 flow control stations continuously; H2
detectors were in place and appeared operable; visiting personnel had
required escorts; H2 trucks maintained required distance from the chlorine
tank car; licensee routinely checked for H2 leaks; reviewed SP-86-096,
E&RC Activities During Hydrogen Water Chemistry Test; installation of
,
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hydrogen and oxygen lines per SP-86-096.
The inspector reviewed the
first two water chemistry data sets to ensure that no unanticipated
affects were found.
l
No violations or deviations were identified.
16.
Reportability of HPCI Valve Failure (93702)
The licensee found that the Unit 1 E41-F002, HPCI inboard steam supply
valve, would not stroke open while returning HPCI to standby after a
surveillance test.
The event occurred at 9:45 a.m. on January 16, 1987
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but the licensee did not report the event via the Emergency Notification
System till 6:08 p.m. on January 17. The. licensee failed to recognize
that the event was reportable under 10 CFR 50.72(b)(2)(iii)(D). Since the
licensee identified the problem, reported it when found, and has issued
NCR S-87-002 to address permanent corrective action, no notice of viola-
tion is being issued.
The F002 valve failure resulted from a faulty
auxiliary contact block.
The inspectors will followup on the contact
failure and the above NCR as part of the LER followup.
One licensee identified violation and no deviations were identified.
_ _ _ _ _ _ _