ML20203L263
| ML20203L263 | |
| Person / Time | |
|---|---|
| Site: | Big Rock Point File:Consumers Energy icon.png |
| Issue date: | 04/24/1986 |
| From: | Boyd D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20203L251 | List: |
| References | |
| 50-155-86-04, 50-155-86-4, NUDOCS 8605010198 | |
| Download: ML20203L263 (8) | |
See also: IR 05000155/1986004
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Report No. 50-155/86004(DRP)
Docket No. 50-155
License No. DPR-6
Licensee: Consumers Power Company
212 West Michigan Avenue
Jackson, MI 49201
Facility Name: Big Rock Point Nuclear Plant
Inspection At: Charlevoix, MI 49720
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Inspection Conducted: January 24 through April 8,1986
Inspector:
S. Guthrie
Approved By:
D. C.
YM
,
Reactor Projects Section 2D
Date
Inspection Summary
Inspection on January 24 through April 8,1986 (Report No. 50-155/86004(DRP))
Areas Inspected: Routine, unannounced inspection conducted by the Senior
Resident Inspector of Licensee Actions on previous Inspection Findings,
Operational Safety, Maintenance, Licansee Event Report followup, and Licensing
Actions.
Results: Of the five areas inspected, no violations or deviations were
identified. No significant safety items were identified. However, the
question of diesel fire pump dependability in light of its age and difficulties
encountered in obtaining parts and experienced repair service is a source of
increasing concern because of that pump's crucial role in providing low
pressure core spray water as well as water for fire protection purposes.
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8605010198 860424
ADOCK 05000155
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DETAILS
1.
Persons Contacted
- D. Hoffman, Plant Superintendent
G. Petitjean, Planning and Administrative Services Superintendent
G. Withrow, Engineering Maintenance Superintendent
R. Alexander, Technical Engineer
R. Abel, Production and Plant Performance Superintendent
- L. Monshor, Quality Assurance Superintendent
R. Barnhart, Senior Quality Assurance Consultant
P. Donnelly, Senior Review Supervisor, Nuclear Activities Department
D. Swem, Senior Engineer
G. Sonnenberg, Senior Technical Analyst
D. Staton, Shift Supervisor
W. Trubilowicz, Operations Supervisor
- J. Beer, Chemistry / Health Physics Superintendent
E. Evans, Senior Engineer
J. Tilton, General Engineer
D. Kelly, Maintenance Supervisor
D. Ball, Maintenance Supervisor
W. Blosh, Maintenance Engineer
L. Darrah, Shift Supervisor
J. Horan, Shift Supervisor
R. May, Shift Supervisor
R. Scheels, Shift Supervisor
J. Warner, Property Protection Supervisor
T. Fisher, Senior Quality Assurance Consultant
S. Bartosik, General Quality Assurance Consultant
R. Krchmar, General Quality Assurance Analyst
- D. Hice, Technical Engineer (Acting)
- R. Schrader, Engineering, Maintenance Superintendent (Acting)
The inspector also contacted other licensee personnel in the Operations,
Maintenance, Radiation Protection, and Technical departments.
- Denotes those present at exit interview.
2.
Licensee Action on Previous Inspection Findings
a.
Section 10 of Inspection Report No. 85021 describes the licensee's
administrative procedures permitting the Shift Supervisor (SS), as the
only licensed Senior Reactor Operator (SRO) on shift, to be absent
from the control room and, in his abrence, delegating an operator
holding c Reactor Operator (RO) license to assume command of the
control room.
Both of these activities are prohibited by
The staff of NRR, by letter May 2, 1980, accepted the licensee's
proposal to assign " primary management responsibility" for the plant
to the SS and recognizes that certain emergency situations may
require the SS to leave the control room in the interests of plant
safety.
Subsequent to this acceptance by the staff the requirements
of 10 CFR 50.54(m) were imposed by regulation.
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The licensee indicated their intention to submit a change to
technical specifications.
During this review the inspector noted that Administrative Procedures
Volume I, Chapter 4, Section 1.4.a.l.5 states that the SS may leave
the control room during emergency situations other than site or
general emergency "provided the Shift Technical Advisor / Shift Engineer
remains in the control room during his absence." The Shift Technical
Advisor / Shift Engineer positions is no longer staffed at Big Rock as
the licensee fulfills that positions requirements with an On-call
Technical Advisor (OTA).
The OTA is required to be onsite during
certain evolutions and within one hour of being summoned by the SS
and thus it is not reasonable to require an OTA, who does not hold
an SRO license, to be present before the SS is allowed to leave the
control room in the interest of plant safety.
The licensee agreed
to review the procedural requirement.
b.
Section 5.d of Inspection Report No. 85021 described failure of the
diesel fire pump (DFP) to start within the required start time during
performance of weekly Surveillance T7-20, DFP Start Test.
Corrective
maintenance efforts were ultimately unsuccessful, and on February 4,
the DFP was declared inoperable based on excessively long start times.
Technical Specification 11.3.1.4. requires both the Electric Fire Pump
and the DFP to be operable at power, and declaring the DFP inoperable
placed the facility in a Limiting Condition for Operation (LCO)
requiring a shutdown to be initiated with 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
At Big Rock the
DFP performs a core spray function as well as providing water for fire
fighting. On February 4 the licensee initiated a change to
Procedure T7-20 to increase the maximum start time from 20.4 seconds
to 45 seconds, citing as engineering justification the Safety
Evaluation performed by NRR supporting the approval of Amendment
No. 44 to the units Operating License.
This amendment, dated June 9,
1981, revised reactor operating limits based on a new Loss of Coolant
Accident (LOCA) analysis.
Section 2.3 of the Safety Evaluation
concludes that a delay in DFP start time of an additional 25 seconds
(45 seconds total) does not affect the LOCA-based reactor operating
limits.
All DFP starts, including those which had exceeded the former
20.4 second limit, were within the revised 45 second limit, thus
relieving the licensee of the requirements of the technical
specification LCO.
On February 4 the inspector reviewed the problen with the licensee
and expressed a concern that the erratic starting behavior of the DFP
and the inability of maintenance personnel and vendors to positively
identify and correct the cause of the poor performance was a problem
that could not be corrected solely by increasing allowable starting
times no matter how valid the engineering justification.
The licensee
agreed to operate the DFP continuously from February 4 until entering
an upcoming scheduled outage period where DFP operability was no
longer required by technical specification.
The DFP ran continuously
except for daily maintenance trouble shooting sessions until
February 11.
During the outage the licensee brought in manufacturer's
representatives to diagnose and correct the problem.
Diagnosis and
repairs were hampered by the age of the equipment, prompting the
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licensee to consider the DFP engine for total replacement during the
1986 refueling outage.
Unavailability of parts and a shortage of
maintenance personnel experienced with the outdated engine make future
repairs questionable.
Electrical components cleaning, fuel line leak
tightness verification, and valve adjustments produced satisfactory
start time performance and a pump output capacity test was
satisfactorily performed February 15.
Following the DFP's return to
operability the licensee conducted daily performances of T7-20, n '.h
maintenance personnel present, from February 17 to March 3.
All tests
had start times of less than 7 seconds, a figure consistent with the
pump's long term surveillance history.
The inspector will monitor the licensee's activities related to DFP
engine replacement.
3.
Operational Safety Verification
The inspector observed control room operations, reviewed applicable logs
and conducted discussions with control room operators during the inspection
period.
The inspector verified the operability of selected emergency
systems, reviewed tagout records and verified proper return to service of
affected components.
Tours of the containment sphere and turbine building
were conducted to observe plant equipment conditions, including potential
fire hazards, fluid leaks, and excessive vibrations and to verify that
maintenance requests had been initiated for equipment in need of main-
tenance.
The inspector, by observation and direct interview, verified that
the physical security plan was being implemented in accordance with the
station security plan.
The inspector observed plant housekeeping / cleanliness conditions and
verified implementation of radiation protection controls.
During the
inspection period, the inspector walked down the accessible portions of
the Liquid Poison, Emergency Condenser, Reactor Depressurization System
(RDS), Post Incident, Core Spray and Containment Spray systems to verify
operability.
a.
Throughout the report period the licensee experienced problems with
high turbine gland seal steam pressure.
Turbine gland seal steam
normally runs about 2 psig but increased for reasons that remain
unclear to about 8 psig, a pressure at which gland seal steam escapes
from the turbine shaft gland and condenses to become mixed with
lubricating oil at the turbine shaft bearing.
Presently the quantity
of water becoming mixed with oil is minimal and easily removed by a
centrifugal purifier and by evaporation from the warm oil.
Pending
determination of corrective action by turbine specialists, operators
are reducing load in one mwe increments to keep seal steam pressure
under 8 psig.
Power has been reduced from 70 mwe to 66 mwe for this
purpose.
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b.
On February 10 at 10:00 p.m. the licensee attempted to perform
Quarterly Surveillance T90-07, RDS Isolation Valve Test. To perform
the test, RDS-101 valves (bypass manual isolation) must be open and
the piping between the upstream isolation valve and the depressuri-
zation valve pressurized.
Erosion of the pilot valve assembly on
SV-4985 (B train depressurization valve) caused lifting of that valve
and the test was terminated.
RDS valves 101 B and C were reclosed.
The licensee, in anticipation of this situation preventing performance
of the required surveillance, had scheduled an outage period to
perform RDS valve maintenance.
The following morning of February 11 the licensee performed primary
plant leak rate calculations and determined total unidentified leak
rate to be 1.126 gpm.
Technical Specification 4.1.2.(c) requires
the plant be placed in hot shutdown condition within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
Big
Rock Emergency Procedures require that declaration of an Unusual Event
be made when plant shutdown is required by a technical specification
LCO. All Unusual Event notifications were completed, and the reactor
was shutdown within the required period.
Leak rate calculations
performed after shutdown indicated total unidentified leakage of
0.349 gpm.
The licensee suspects leakage through the RDS valves
which were manipulated during the surveillance attempt.
During the outage the licensee replaced depressurization valve top
assemblies on SV-4985, SV-4986, and SV-4987.
Valve RDS 101 B was
also replaced.
The reactor was returned to service February 16.
following startup was 0.192 gpm.
c.
On March 7 the inspector discussed with the licensee an event at the
Lacrosse facility in which heat generated in a silver zeolite sampling
cartridge in use at the offgas sample line caused hydrogen ignition
in the sample line and offgas system piping.
The licensee had
discussed the incident with the Lacrosse licensee and evaluated the
use of silver zeolite cartridges at this facility.
Currently the
silver zeolite cartridges are used for emergency general sampling for
all areas but are capable of sampling at the offgas sample point.
The
licensee had already determined the need for a warning sign at the
offgas sample point.
d.
On March 23 the unit experienced an increase of offgas flow of
6-8.5 CFM with no significant changes in any other plant parameter.
Investigation revealed a hole in a 10 inch steam line piping elbow
downstream of bypass valve CV4014.
This was apparently caused by
erosion from steam impinging on the elbow's interior surface from a
warming line.
The line is normally under vacuum from the main
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condenser but the size of the hole when first discovered was small
enough to be within the capacity of the air ejectors to maintain
vacuum.
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e
During the period of increased offgas flow the licensee observed a
slight increase in radionuclide activity exhausting to atmosphere as
short lived nuclides were rushed through the offgas system's hold up
volume.
This hold up volume, given normal offgas flow rates, provides
sufficient time for short lived radionuclides to decay within the
volume, thus reducing the total activity discharged to the atmosphere
via the stack.
Xenon 138, a short lived nuclide monitored by the
licensee, increased from a typical valve of 400 uci/sec to around
800 uci/sec.
Licensee monitoring of Xenon 133, a long lived nuclide
which does not linger in the hold up volume long enough to decay,
significantly showed no change.
Discharges are limited by 10 CFR 50,
Appendix 1.
On March 24 a temporary patch was affixed to the elbow's exterior.
Following fabrication, on March 31, a patch was welded to the elbow.
During the installation process, declining condenser vacuum required
operator action to increase air ejector flow to prevent a reactor
scram from low vacuum (22 in. hg).
Permanent elbow replacement is
planned for the 1986 refueling outage.
e.
On March 26 the inspector observed portions of hands-on fire training
conducted at the site.
No violations or deviations were identified in this area.
4.
Monthly Maintenance Observation
Station maintenance activities of safety-related systems and components
listed below were observed / reviewed to ascertain that they were conducted
in accordance with approved procedures, regulatory guides, industry codes
or standards, and in conformance with technical specifications.
The following items were considered during this review:
the limiting
conditions for operation were met while components or systems were removed
from service; approvals were obtained prior to initiating the work;
activities were accomplished using approved procedures and were inspected
as applicable; functional testing and/or calibrations were performed prior
to returning components or systems to service; quality control records were
maintained; activities were accomplished by qualified personnel; parts and
materials used were properly certified; radiological controls were
implemented; and fire prevention controls were implemented.
Wor k requests were reviewed to determine status of outstanding jobs and
to assure that priority is assigned to safety related equipment maintenance
which may affect system performance.
a.
On March 24 the licensee entered a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> LC0 for replacement of
Solenoid Valve SV-9153 on Control Valve CV-4094, Exhaust Ventilation
Downstream Isolation Valve.
Solenoid Replacement was completed within
seven hours.
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b.
On April 1, during the performance of T7-20, DFP Start Test, the
operator observed dripping leakage of fuel oil from a fuel oil filter
on the engine.
Vibration of the filter during operation brought it
in contact with its support bracket, eventually wearing through the
filter housing.
Filter replacement and bracket modification required
entry into a LCO as required by Technical Specification 11.3.1.4.
Repairs were completed with the 24 LCO requirements.
c.
During the inspection period the licensee received notification from
the Consolidated Pipe and Valve Supply Company that officials of the
Golden Gate Forged Flange Company, a supplier of forged flanges sold
to the licensee by Consolidated Pipe, had been charged in Federal
Court with criminal false statements related to falsified test
certifications.
The licensee promptly researched all purchase orders
from the vendor and all records of transfer of materials from the
terminated Midland Plant and informed the inspector that none of the
suspect forged flanges were installed or are in storage at Big Rock.
No violations or deviations were identified in this area.
5.
Licensee Event Reports Followup
Through direct observations, discussions with licensee personnel, and
review of records, the following event reports were reviewed to determine
that reportability requirements were fulfilled, immediate corrective action
was accomplished, and corrective action to prevent recurrence had been
accomplished in accordance with technical specifications.
(Closed) LER 86001 and 86001, Revision 1, Failure to Perform Required
Surveillance Test.
This LER describes the licensee's failure to test fire
detection instruments located in the recirculation pump room during the
1985 refueling outage, as required by Technical Specification 4.3.3.8.1.
The omission was attributed to procedural inadequacy which called for
testing of several detectors with different surveillance frequencies under
a single procedure, thus creating the potential for the oversight.
The
omission was discovered on January 17, 1986 and the test was performed on
February 15, 1986 during the next period permitting recirculation pump room
entry.
The LER was revised by the licensee after determining that wording in the
original submittal gave the incorrect impression that the Senior Resident
Inspector had granted permission to continue plant operations in violation
of a LCO.
In fact, Big Rock technical specifications do not include an
action statement requiring plant shutdown to perform the required
surveillance.
When informed of the situation the inspector concurred with
the licensee's decision not to voluntarily shutdown the plant to perform
the fire detector surveillance.
The inspector based his position on the
detectors successful surveillance history and the recognition that the
threat to plant safety and operational stability resulting from plant
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shutdown and restart exceeded the threat to operational safety posed by
three untested fire detectors.
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The missed surveillance was discussed in Section 5.e of Inspection Report
No. 85021.
(Closed) LER 86002, Exceeding Technical Specifications Unidentified Leak
Rate Limit.
This LER discusses the licensee's action to take the unit from
90% power to cold shutdown as required by Technical Specification 4.1.2.C.
This action was in response to an unidentified leak rate in excess of
1.0 gpm observed during performance of surveillance testing on RDS Valves
on February 11.
The event is described in detail in Section 3.b of this
report.
6.
Licensing Activities
By letter dated March 10 the commission issued Amendment No. 83 to Facility
Operating License No. DRP-6 for Big Rock Point.
The amendment changes
technical specifications to reflect a plant staff reorganization implemented
in 1985.
By letter dated March 20, 1986, the Commission issued an exemption from the
requirements of 10 CFR 50.62(c)(5) to install an automatic recirculating
pump trip to trip the reactor under conditions indicative of an Anticipated
Transient Without Scram (ATWS) event.
The letter references several
engineering evaluations and concludes that the existing installed oversized
safety valve capacity at Big Rock is sufficient to limit primary coolant
system pressure rise within acceptable limits without an automatic pump
trip.
7.
Exit Interview
The inspector met with licensee representatives (denoted in Section 1)
throughout the month and at the conclusion of the inspection period
summarized the scope and findings of the inspection activities. The
licensee acknowledged these findings.
The inspector also discussed the
likely informational content of the inspection report with regard to
documents or processes reviewed by the inspector during the inspection.
The licensee did not identify any such documents or processes as
proprietary.
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