ML20205E159
| ML20205E159 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 07/22/1986 |
| From: | Blough A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20205E123 | List: |
| References | |
| TASK-1.A.1.3, TASK-TM 50-219-86-12, IEB-79-02, IEB-79-14, IEB-79-2, NUDOCS 8608180257 | |
| Download: ML20205E159 (32) | |
See also: IR 05000219/1986012
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U. S. Nuclear Regulatory Commission
Region I
Report No. 50/219/86-12
Docket No. 50-219
License No. DPR-16 Priority --
Category C
Licensee: GPU Nuclear Corporation
100 Interpace Parkway
Parsippany, New Jersey
Facility Name: Oyster Creek Nuclear Generating Station
Inspection at: Forked River and Parsippany, New Jersey
Inspection Conducted: April 14 - June 1,1986
Participating Inspectors: W. H. Bateman, Senior Resident Inspector
J. F. Wechselberger, Resident Inspector
W. H. Baunack, Project Engineer
Approved by:
,
7 - 2.7 M
A. R.(flough, Chief Date
Reactor Projects Section IA
Inspection Summary:
Routine Inspections were conducted by the resident inspectors and a Region
based inspector (393 hours0.00455 days <br />0.109 hours <br />6.498016e-4 weeks <br />1.495365e-4 months <br />) of activities in progress including outage
management, maintenance, modifications, QC inspection activity, radiation
control, physical security, housekeeping, defueling, fuel sipping, chemical
decontamination of recirculation piping, and fire protection. The inspectors
, also reviewed licensee action on previous inspection findings, followed up
Licensee Event Reports, and made routine tours of the facility. In addition,
the inspectors visited the GPUN corporate offices to review the technical data
associated with the licensee's inspection activities in 1979 and 1980 associated
with NRC Bulletin 79-02. The inspectors also reviewed licensee control of
overtime hours and followed up on various operational problems such as inadver-
tent scram signals caused by IRM spiking and inadvertent starts of the Standby
Gas Treatment System.
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8608190257 860008
l PDR ADOCK 05000219
G PDR
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Results:
Four violations were identified. Three were associated with a seismic upgrading
of portions of the Spent Fuel Pool Cooling system as discussed in paragraphs
1.A, B, and C. The fourth involved failure of the licensee to recognize that
three safety related snubbers in the Isolation Condenser system were inoperable,
thereby, placing the plant in violation of Technical Specification Limiting
Conditions for Operation as discussed in paragraph 2. Review of certain techni-
cal data at Parsippany regarding previous anchor bolt inspections disclosed
that the data had not been adequately reviewed by the licensee prior to taking
credit for it meeting the requirements of Bulletin 79-02. Review of Licensee
Event Reports (LERs) determined a problem exists regarding significant time
delays in submitting supplemental LERs and implementing corrective actions.
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DETAILS
1. Spent Fuel Pool Cooling (SFPC) System Seismic Upgrade - LER 83-26
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Licensee Event Report.(LER) 83-26 stated the effects of the weight of
lead shielding used on the SFPC heat exchangers would overstress the
heat exchangers' foundation bolts during a seismic event. It also
reported that the original portions of the SFPC piping were supported
by dead weight hangers only and, therefore, the affected piping may not
be Seismic Class 1 as stated in the Final Description and Safety Analysis
Report (FDSAR). The licensee submitted a preliminary report of this
issue on 12/20/83. This report stated the corrective actions, in part,
would involve seismically upgrading the spent fuel pool outlet and return
piping prior to plant startup from the 10R outage. LER 83-26 was formally
updated on 2/7/84 and stated the upgrading of the piping would be delayed
until prior to the 11R outage core offload. By letter dated 5/20/86 the >
licensee issued Revision 1 to LER 83-26 to, in part, refine their commit- <
ment to seismically upgrade the piping and heat exchangers prior to 11R ,
core offload. This refinement involved upgrading the pipe supports but
not the heat exchanger supports. The rationale presented for not upgrad-
ing the heat exchanger supports was based on ALARA concerns and the
planned replacement of the SFPC heat exchangers during 11R.
A review of-the licensee correspondence indicates that the licensee
changed their original corrective action commitment twice, i.e., once to
delay it and once to modify it and delay a portion of it. Because Plant ,
Operations would not permit a major portion of the work involved with
installing seismic supports to be done during plant operation, the bulk
of it had to be done after plant shutdown prior to core offload. This
seismic upgrade became an extremely important job during this report
period because it was a NRC commitment that had been delayed once and
modified once and, if not completed in a timely fashion, could delay core
offload. Upon completion of the work associated with the modified seismic
upgrade, the NRC inspector inspected a sample of the upgraded supports.
These inspection activities identified three violations as follows:
A. Hanger mark number BP-435A as detailed on GPUN drawing FP-008, Rev. 2,
was found to be partially disassembled in that the U-bolt was not t
installed in position. A review of work' package A15A-38685, Rev. O, i
Spent Fuel Pool. Cooling System - Mechanical System Upgrade, indicated
this support had been final inspected and accepted by QC, Further ,
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investigation into the discrepancy disclosed that craft personnel
partially disassembled BP-435A after QC inspection to facilitate
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adjusting the piping in a restraint further downstream. This rework -
was not authorized or controlled. After subsequent questioning of .
- involved Maintenance, Construction, and Facilities (MCF) personnel,
! the inspector determined that, as long as a work package remains in
! MCF, there are no procedural provisions to authorize and control
rework. Had the system been turned over to Startup and Test or Plant
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Operations, the work would have been controlled by the "Short Form"
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The failure of MCF and the Work Management System to proceduralize
control of rework prior to turnover resulted in the partial dis-
assembly of a newly installed seismic support after QC inspection
and acceptance. This action invalidated the QC inspection. This is
contrary to Criterion V of 10 CFR 50 Appendix B, and the Oyster Creek
Operations quality assurance plan (QAP) section 3 which requires, in
part, that activities affecting quality be prescribed by procedures.
This is a violation (219/86-12-01).
Subsequent to identification of this problem, MCF management issued a
memorandum to all involved contractors stressing the policy that
rework must be authorized. At the end of the report period, changes
were being initiated to controlling procedures to make this a policy
of the MCF Work Management System.
B. The inspector observed two seismic important to safety restraints
each welded to a different existing floor penetration. GPUN drawings
FP-001 and FP-002 detail the installations. Based on the assumption
that the floor penetrations were not considered seismic, the inspec-
tor questioned the licensee's rationale for attaching a seismic
restraint to a non-seismic member to transfer the loading to the
building structure. Discussions with Technical Functions personnel
responsible for the design confirmed the floor penetrations were
not seismic and that the design was subcontracted to Associated
Technologies, Incorporated (ATI). An explanation as to why the
restraints were attached to the floor penetrations was not given.
Since ATI used the floor penetrations as a piece of supplementary
steel to transfer loads to the building structure, it is evident they
were not aware that they could not do this. ATI's lack of awareness
can be attributed to lack of appropriate technical information in the
contractual document procuring ATI's services. The failure of GPUN
to assure ATI properly performed the subcontracted design work is
contrary to the requirements of Criterion IV of 10 CFR 50 Appendix B
and QAP section 6.4. This is a violation. (219/86-12-02)
It should be noted that neither GPUN nor ATI performed any calcu-
- lations to demonstrate the floor penetrations were capable of
l transferring the imposed loads. The seismic calculations ended
with the restraint design, i.e., upstream of the attachment weld to
the floor penetration. Before the end of the report period, Tech
l Functions personnel stated the design standards would be clarified
to address proper design of seismic supports, once completed the
design standards would be made available to all contractors doing
design work for GPUN involving Oyster Creek, and calculations would
be performed to justify the use of the floor penetrations as seismic
members.
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C. Since the two seismic supports discussed in paragraph 1.8 above were
i welded to the floor penetrations, the inspector reviewed the welding
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documentation associated with these welds and determined that the
type of material the penetrations were made from was not known by
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either Tech Functions, Special Processes'and Programs (SPP), or QC.
The GPUN Welding Manual (Procedure 6150-QAP-7220.01, Rev. 0-00)
states in paragraph 4.2.4 that engineering documents and Weld Package
Information Requests (WPIRs) must specify base material specification
and grade for new and existing material. A review of the engineering
documents and WPIRs disclosed that the existing material (floor
penetrations) was never addressed. The inspector questioned SPP as
to how they issued a weld package, specified a Welding Procedure
Specifications, and issued filler metal without knowing the types of
materials that were being joined. Representatives of SPP stated that
this specific instance was an oversight and that normally they request
base material information from Tech Functions if Tech Functions fails
to specify the information, as happened in this case.
A review of the Structural Weld Record Sheet associated with these
welds indicated that QC had signed for acceptance of the base
materials used in the weld. This signoff indicated, in part, that
material traceability requirements had been met for the materials
joined. Because the existing base material was not known, one would
question the intent of the QC signature. The inspector concluded
there was a failure of (1) Tech Functions to supply existing base
material information as required by procedures, (2) SPP to question
Tech Functions regarding the base material prior to issuing the weld
package, and (3) QC to recognize that the base material of the pene-
trations to which the seismic supports were welded was not defined.
These failures are contrary to the requirements of Criteria IX and X
of 10 CFR 50 Appendix B and QAP, sections 6.4 and 6.12. This is a
violation (219/86-12-03).
At the end of the report period, the licensee did not know the ma-
terial type. A search of old drawings was performed in an attempt
to identify original material requirements. The results indicated
the floor penetrations should have been galvanized A36 steel. How-
ever, an inspection of these penetrations led to the conclusion they
were not made of A36 'as required by the original construction drawing.
The licensee plans to take a sample of the material and have it
analyzed.
Further, in reviewing the Structural Weld Record Sheet (SWRS) with
SPP and QC, it became obvious the instructions for use of this
document are confusing. The SWRS is Exhibit 6 in the GPUN Welding
Manual. The specific areas that require clarification are as
follows:
(1) QC acceptance of material traceability on the SWRS when one
line on the sheet may represent several different welds;
(2) The often time inadequate space on the SWRS used to record
the required information;
(3) The use of a SWRS Attachment sheet;
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(4) The requirements to list material traceability when welds
are not listed individually on the SWRS; and
(5) Proper method of QC signoff on SWRS when welds are not
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listed individually, including requirement to list Plant
Inspection Report (PIR) number.
In addition to clarifications of the SWRS, the GPUN Welding Manual
should be modified to specifically address attachment welds to
existing plant steel. The licensee agreed to review the manual with
respect to the above aspects.
Licensee action on the above items will be verified in a subsequent
inspection (219/86-12-04).
Other than the problems discussed in the above three violations, the
completed work was found to meet drawing and construction installation
requirements.
2. Inspection of Piping and Pipe Supports
During this report period, insulation was removed from portions of several
safety related piping systems to facilitate various inspections of pipe
welds and pipe supports. As discussed in previous NRC Inspection Reports,
the licensee had performed a substantial reinspection of pipe supports in
response to a NRC inspection to close NRC Bulletin 79-14. However, this
inspection activity did not include removing insulation to verify correct
installation of the support to the piping. In a meeting held April 1,
1986 at the NRC Regional Office, the licensee stated, with the exception
of several recirculation system supports, all supports had been reinspected
and the results of the inspections were being analyzed. No additional
inspections to meet requirements of Bulletin 79-14 were planned beyond the
several recirculation system supports.
The NRC inspectors walked down those portions of the Isolation Condenser
system piping from which insulation had been removed. During this
walkdown the inspectors observed that the pipe clamps that form a part of
the overall snubber assembly of two snubbers were not welded to the
piping. The particular snubbers and their design drawings are as follows:
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633-R1 or NE-1-S4 as shown on Bergen-Paterson Dwg. #173
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633-R4 or NE-1-S5 as shown on Bergen-Paterson Dwg. #176.
These snubbers are shown on piping isometric drawing JCP-19433, Rev. 3,
Sheet 2 and are located on the steam lines to the 'A' isolation condenser.
The drawing for snubber 633-R1 requires that two 3/8" x 1 1/2" x 3" long
stainless steel lugs be fillet welded to the pipe along the 3" side of the
lugs (the 3" long side follows the circumference of the pire) and that the
pipe clamps be butted up against the other 3" side of the lugs and a
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fillet weld used to connect the lugs to the pipe clamp. This arrangement
prevents movement of the pipe clamp relative to the pipe and permits
transfer of loads to the snubber as designed. The 633-R1 snubber drawing
indicated lug placement on opposite sides of the clamp 180 degrees apart.
In the case of this snubber, tne gap between the lugs was approximately
1/4" greater than the width of the pipe clamp. This gap existed totally
on one side of the clamp, i.e., the other side of the clamp was in bearing
with the other lug. This 1/4" gap precluded making a fillet weld between
the one lug and the clamp. In fact, neither lug was welded to the clamp.
The drawing for snubber 633-R4 requires that the same size and type lugs
be attached in the same way, but on the same side of the clamp. In the
case of this snubber, it was obvious that welds had at one time existed
between the lugs and the pipe clamp but that these welds had been ground
out and not subsequently rewelded.
The fact that these two snubbers' pipe clamps were not welded to the lugs
rendered them inoperable. Both of these snubbers are required by Tech
Specs to be operable. In particular, the Technical Specification Limiting
Conditions for Operation 3.5.A.8 states:
a. All safety related snubbers are required to be operable whenever
tne systems they protect are required to be operable except as
noted in 3.5.A.8.b and c below.
b. With one or more snubbers inoperable, within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> replace or
restore the inoperable snubber (s) to operable status.
c. If the requirements of 3.5.A.8.a and 3.5.A.8.b cannot be met,
declare the protected system inoperable and follow the
appropriate action statement for that system.
The action statement Tech Spec 3.8.C for the Isolation Condenser system
states that if one isolation condenser becomes inoperable during the run
mode, the reactor may remain in operation for a period not to exceed 7
days; then the reactor shall be placed in the cold shutdown condition.
Subsequent to this finding, the Itcensee commenced an investigation to
determine why the snubbers were not welded. Although the investigation
was not completed prior to the end of this report period, it was deter-
mined that a discrepancy list generated in August 1984 during Isolation
Condenser system piping repairs of cracks caused by IGSCC identified
missing welds on three snubbers. Two of the three snubbers were those
discussed above. The third was inspected by the licensee during this
investigation and it was also found to be missing the welds between the
lugs and the pipe clamp.
The failure of the licensee to realize that three Tech Spec required
snubbers were inoperable resulted in operation of the plant in violation
of Technical Specification Limiting Conditions for Operation for a period
of at least the entire Cycle 10 operating period. This is a violation
(219/86-12-05).
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3. On-Site Review of LERs
The following LERs were reviewed to deternine if reporting requirements
were met, the report was adequate in assessing the event, the cause
appeared accurate, corrective actions appeared appropriate, generic
applicability was considered, the licensee review and evaluation were
complete and accurate, and the LER form was properly completed.
(Closed) 83-04: Failure of CR0 Feed Pump Breaker to Operate as Designed
During a preventive maintenance (PM) bench test of a CR0 feed pump circuit
breaker, it was determined that the undervoltage tripping function of the
breaker was not functioning properly. The malfunction was attributed to
binding and friction of the trip shaft bearings due to oxidized lubricant.
The inspector reviewed documentation which verified all similar breakers
in safety related applications have been disassembled and inspected. Also,
the PM frequencies have been revised to require 12 month inspections and a
new PM checksheet has been developed.
(Closed) 83-07 and 83-07/03X-1; SGTS II Declared Inoperable and Removed
from Service for HEPA Filter Replacement
Standby Gas Treatment System (SGTS) II was declared inoperable du*ing
surveillance testing due to a high differential pressure across its HEPA
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filters. The HEPA filters and pre-filters were replaced and satisfac-
torily tested.
Subsequent licensee evaluation (83-07/03X-1) showed that apparent high
filter differential pressure resulted from (1) corrective maintenance on
the flow sensing pitot tube and no post maintenance testing to verify flow
curves, and (2) use of a noncontrolled outdated flow curve by operations
personnel.
The inspector reviewed documentation which verified flow calibration
curves have been revised in appropriate procedures; the LER was made
required reading for Maintenance and Construction, Plant Materfel, and
Plant Operations personnel; that appropriate personnel have been made
aware of the requirement to calibrate flow instruments following repair of
sensing elements; and that a memorandum was issued to all Operations
personnel regarding outdated operational aids.
(0 pen) 83-24: Limitorque Motor-Operated Valves Torque Switch Setpoints
The licensee reported that during a review of torque switch setpoints of
the Limitorque motor operated valves at Oyster Creek, it was discovered
that the setpoints on many motor operated valves had been set lower than
the manufacturer's data. Further investigation of isolation valves
revealed that the torque switch setpoints set during pre-operational
testing were found to be lower than the manufacturer's data. In some
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cases, these setpoints were later changed to values lower than pre-opera-
tional testing in the course of plant operation as determined through
maintenance and surveillance testing.
In the report the licensee described corrective actions which would be
taken on safety related valves prior to plant startup.
During this inspection the inspector reviewed a GPUN Technical Data Report
which documented the actions taken as required by the corrective actions
described in LER 83-24. The corrective actions described and the actions
taken were as follows:
(1) Completion of the actual design basis investigation -- GPUN obtained
from Limitorque copies of the motor operator bills of materials for
57 valves which were identified as isolation and/or safety related
valves. These bills of material list the differential pressure used
to size the operator and the torque switch setting required to oper-
ate the valve against differential pressure. This data is the origi-
nal baseline data for the Oyster Creek plant.
(2) Determine the appropriate torque switch setpoints -- GPUN used an
independent third party, Torrey Pines Technology, to do torque switch
setpoint calculations.
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(3) Resetting the torque switch setpoints on all applicable valves --
GpVN used Motor Operated Valve Analysis and Test System (M0 VATS) to
reset the torque switches and test and analyze the 57 safety related
valves.
(4) Issue administrative controls to eliminate recurrence of this
incident -- Oyster Creek Nuclear Generating Station Procedure
700.2.010, Motor Operated Valve Removal Installation or Inspection
(Elect) has been revised to specify opening and closing torque switch
settings.
The licensee also stated a followup report would be issued following the
completion of an investigation of this matter. This item remains open
pending receipt of the licensee's followup report.
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( Closed) 83-25: Procedures Did Not Contain Requirement for Verifying
During a review of plant procedures by the licensee, six maintenance and
two surveillance procedures were identified as not adequately addressing
the Technical Specification requirement that each time an instrument line
is returned to service after any condition which could have produced a
pressure or flow disturbance in that line, the open position of the flow
check valve in that line shall be verified.
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These deficiencies were discovered by the licensee during a review of all
Technical Specification surveillance procedures to ensure they reflected
Technical Specification requirements.
All excess flow check valves affected by the deficient procedures were
verified open prior to returning the associated systems to service.
During this inspection the inspector verified corrective action had been
taken to revise procedures as necessary. Procedure 603.3.002, 610.3.010,
and 703.3.001 were changed to include the Technical Specification require-
ment. Procedures 700.3.007, 719.3.006, 710.1.003 and 719.1.001 have been
deleted, and Procedures 700.3.008 and 700.1.004 were determined to not
require a change.
(Closed) 84-01; Diesel Generator Fuel Oil Tank Level Below Technical
Specification Limit
After several test runs of the No. 2 diesel generator, the fuel oil tank
level was noted as being slightly below the Technical Specification limit.
The apparent cause was operator error in not properly following up on an
apparent low level indication. However, a contributing factor is that the
tank capacity is only slightly greater than the Technical Specification
limit, and the tank has been overflowed in the past.
The corrective action to prevent recurrence was to change procedure
636.4.003 to clarify the requirement to refill the diesel fuel oil tank,
and to issue a memo to all operating and supervisory personnel informing
them of the revision to the procedure i istructing them to refill the tank
after each load test or one hour of operation. In addition, Amendment No.
99 has been issued which reduces the Technical Specification required fuel
oil amount. With this Technical Specification change, more operating
flexibility is provided.
.(Closed)84-02: Failure of Several Breakers to Trip Upon De-energization of
Their Undervoltage Trip Device
The licensee reported the failure to trip of three separate breakers
during the performance of undervoltage trip time operability and trip bar
actuation tests. Immediate corrective action was to perform preventive
maintenance on the circuit breakers. The trip shaft bearings were
cleaned, lubricated and measured to have a torque of 20 inch-ounces. The
static time delay units ware readjusted to within specifications and the
breakers tested for operability three times before being returned to
service.
During this inspection, the inspector reviewed documentation which
verified that Preventive Maintenance Procedure 761.2.003 was revised to
include 'lla appropriate recommendations of GE Service Advice 175(CPPD)9.3.
Additional actions taken by the licensee to assure operability of
undervoltage trip devices is provided in the licensee's response to IE
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(Closed) 84-06; Torus Corrosion Pitting and Missing Structural '4 elds
This is a voluntary report submitted by the licensee to discuss the
identification or torus pitting and missing torus structural welds. The
report also identified the repairs performed to restore the torus to the
original as-designed condition.
NRC Region I Inspection 84-07 was devoted entirely to the inspection
activities associated with the torus shell thickness. In addition,
routine inspections reviewed additional aspects of the torus repair.
Based on these efforts, this item is considered closed.
(0 pen) 84-08; Degradation of Neutron Monitoring Instrument Dry Tubes
This report describes the identification by the licensee of cracks found
in the neutron monitoring instrument dry tubes. While performing local
power range monitoring instrumentation replacement work during a refueling
outage, operators visually noticed that the dry tube associated with an
intermediate range monitor (IRM) appeared bent near the upper core grid.
Further investigation revealed that a total of seven IRM and one source
range monitor (SRM) dry tubes were cracked. The cracks were located in
the thin wall tube surrounding the assembly compression spring and not in
a pressure boundary portion of the dry tube. There are a total of 12 dry
tube assemblies, 8 IRMs, and 4 SRMs in the reactor vessel. The corrective
action was to replace all 12 dry tubes.
During this inspection, the inspector reviewed documentation which showed
all 12 instrument dry tubes were replaced during the time period June 3 to
July 19, 1984. All SRM and IRM detectors have been verified operational.
The LER indicated a supplemental report is expected to be submitted. The
expected submission date of this report was October 30, 1984. To date
this report has not been submitted. This LER remains open pending receipt
of this report.
(0 pen) 84-05: Isolation Condenser Piping Leak Near Weld Joint
With the facility shutdown during the performance of a post maintenance
hydro test, leakage was noted from isolation condenser condensate piping.
At the time of the report, plans were being made to determine the cause of
the failure.
The LER indicated a follow-up report would be submitted. The estimated
submission date of this report was identified as June 30, 1984. To date
this report has not been submitted.
The follow-up report is to contain: 1.) the results of an investigation
to determine the safety significance of this event had the plant been in
operation; 2.) the results of an inspection of the entire isolation
condenser system piping; and 3.) a description of the corrective actions
required. This LER remains open pending receipt of the follow-up report.
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(Closed) 84-09; Deg_radation of Secondary Containment
Both doors of the reactor building personnel access airlock were opened
simultaneously by contractor personnel in order to bring a length of pipe
into the building. The length of the time the doors were open is unknown,
but the duration was believed to have been short.
A critique of the incident was held. The individual responsible was
dismissed, a memorandum was addressed to all onsite contractor firms to
reinforce training on this matter, and signs were posted at each personnel
access airlock warning personnel.
(Closed) 84-10; Fuel Pool Gate Movement Above Irradiated Fuel
Technical Specifications require that no objects in excess of the weight
of one fuel assembly (approximately 485 lbs.) be moved over stored
irradiated fuel. During a licensee review of a proposed modification to
the fuel storage rack configuration, a question was raised as to whether
or not the fuel pool gates (approximately 1800 lbs.) are moved over spent
fuel during their removal or replacement. Operations could not specifi-
cally cite any one particular instance of this, but they believe that
movement of the gate over spent fuel may have occurred several times
during past refueling operations. The station procedures used for
movement of thes6 gates refers to the reactor building overhead crane
operating procedure for control of loads over irradiated fuel.
To prevent recurrence, Station Procedure 756.1.004, Fuel Pool Gates
Removal and Installation, has been revised to caution that fuel pool gates
shall at no time be moved over irradiated fuel. Also, a memo was issued to
all Productio.1 Group Maintenance Supervisors and Mechanics informing them
of these requirements.
(Closed) 84-11; S andby Gas Treatment Systems I and II Simultaneously
Goth trains of the Standby Gas Treatment System (SGTS) were inoperable
for nine (9) minutes while performing preventive maintenance on a circuit
breaker. The maintenance required that the circuit breaker for a motor
control center be racked out, which secured power to the emergency exhaust
fan and the inlet, outlet, and orifice valves of SGTS II. This made SGTS
II inoperable. The three (3) valves in the SGTS II failed open due to
the loss of power, which permits recirculation flow through train II
from train I upon initiation of SGTS I. This caused SGTS I to also be
considered inoperable. The event occurred due to Operations management
misunderstanding of the extent of the temporary change associated with a
plant modification involving the SGTS.
To prevent recurrence, a plant modification has been made which makes
each SGTS train electrically independent. The air operated valves for
each train fail close on loss of electrical power to the respective
fans. Also, a re-evaluation of the method used to inform personnel of
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the status of plant modifications was conducted. The evaluation con-
cluded existing procedures and the use of " Nite Orders" are sufficient
to insure that plant personnel are informed and trained on system /
equipment modifications.
(Closed) 84-12; Both Emergency Diesel Generators Simultaneously
During a scheduled load test on Emergency Diesel Generator No.1 (EDG-1),
a diesel fuel oil day tank low level alarm was received in the Control
Room. Subsequent investigation revealed that the diesel fuel oil transfer
pump control switch for EDG-1 was in the Off position. In the Off
position, fuel oil is not automatically transferred to the diesel day tank
from the main fuel storage tank. This resulted in EDG-1 being considered
inoperable. Since EDG-2 was out of service for governor repairs, both
emergency diesel generators were simultaneously inoperable.
To prevent recurrence, plant tour sheets were revised to incorporate a
check of the transfer pump control switch position.
(Closed) 84-25; Inadvertent Initiation of Core Spray System During Reactor
Low-Low Sensor Calibration
During a calibration of reactor water level sensors for Core Spray
System II, Core Spray System I was inadvertently initiated and injected
torus water into the vessel for approximately 20 seconds. The cause of
the occurrence is attributed to personnel error. Personnel were perform-
ing sections of the procedure out of the as-written sequence, accidentally
omitted a key step, and erroneously performed a step on the wrong instru-
ment. Another cause of the event was the amount of temporary changes to
the procedure being used. The procedure was changed extensively,
primarily to delete steps not needed for the low-low sensor calibration.
A critique was held immediately following the event and certain corrective
actions were specified.
During NRC Inspection 50-219/85-11, it was noted that no corrective
actions had been initiated until the time of the inspection (March 28,
1985, four months after the event). Durir.g this inspection, the inspec-
tor verified corrective actions had been made which consisted of changes
to Station Procedure 116, Surveillance Test Program. This change was to
reflect that procedures will be performed in the as-written sequence and
that the person responsible for performing the test sign that the proce-
dure has been completed in its entirety. Also, this LER was made required
reading for Control Room Operators.
(Closed) 84-29; Cask Lift with Unadjusted Crane Vertical Limit Switches
While performing an initial training lift and movement of a spent fuel
shipping cask above the top of the Cask Drop Protection System (CDPS),
the two crane vertical limit switches were not properly adjusted and
were manually overridden. Technical Specifications require vertical
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limit switches to be operable during cask movement above-the top of the
CDPS to limit the height of the cask to no more than 6 inches above the
CDPS.
The causes of the event were determined to be lack of detail in the cask
handling procedure, inadequate supervision of craft personnel, and
inadequate instruction of personnel on Technical Specification
requirements relative to cask handling.
After it was noticed that the limit switches were not set, the cask was
removed from above the CDPS and lowered to the refueling floor on a safe
load path.
A critique was held to discuss all noted deficiencies. Corrective actions
were initiated and completed prior to further cask movement. These
corrective actions included instructions to personnel, procedure changes
and the proper setting of the limit switches. These corrective actions
were verified at the time of the occurrence.
(0 pen) 84-31; Failure of Main Steam Drain Valves to Operate
During performance of the Main Steam Isolation Valve (MSIV) closure and
In-Service Test (IST), three of four Main Steam Drain Valves (106,107,
110) failed to operate when given appropriate signals. The valves
partially opened and would not reclose. Two valves were closed by
bypassing their control circuits (106, 107) and the third valve (110)
was manually closed. These valves were deactivated and secured in their
isolated position as required by TS 3.5.A.3.
The apparent cause of this occurrence was the opening of the torque
switches, interrupting operation of the valves. The cause of the torque
switches opening is unknown at this time.
The immediate corrective actions were to close, deactivate, and tag out
of service all three valves, as required by the TS.
This LER was reviewed during inspection 85-11. At that time, the LER
remained open pending the completion of a licensee investigation to
determine the cause of the event and the submittal of a follow-up report.
It is expected that the licensee will complete his investigation of the
valve failures during this outage. This item remains open pending receipt
of the licensee follow-up report.
(Closed) 85-02: Two Inoperable Containment Isolation Valves in a Single
Penetration
During a planned shutdown, Reactor Water Cleanup System isolation valve
V-16-1 was required to be taken off its backseat. An electrician was
dispatched to the motor control center supplying the valve to engage the
closing contactor. To prevent full closure of the valve due to a seal-in
closing signal, the electrician manually tripped the breaker. The breaker
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15
trip caused the cleanup recirculation pump to trip, which in turn caused a
cleanup system isolation on low flow. A second isolation valve V-16-14
failed to fully close on the system isolation signal, resulting in two
inoperable isolation valves in a single penetration. The second valve
failed to close due to its lantern ring being damaged which caused the
stem to bind.
A violation was issued in NRC Inspection Report 85-23 for making the
automatic isolation function of a containment isolation valve inoperable
when it was required to be operable. NRC staff follow-up on licensee
corrective action for this violation will be reviewed in a future
inspection.
During this inspection, it was verified that the corrective action
specified in the LER was taken. This corrective action consisted of
placing a sign at the breaker for valve V-16-1 that indicated opening the
breaker caused a clean-up system recirculation pump trip, and revising
Standing Order No.33, Backseating/Unbackseating of Valves, to provide
instructions for the proper unbackseating of valve V-16-1.
(Closed) 85-03; Design Deficiency in Core Spray Pump Logic
On January 29, 1985, a design deficiency was discovered in the Core Spray
system booster pump failure logic. Discharge pressure of the booster
pumps is utilized to detect a booster pump failure which will trip the
failed pump and provide a start signal to the backup booster pump. Two
events were identified which can cause this instrument to misinterpret
Core Spray system status and result in the system not performing according
to its original design intent - the detection of loss of flow from the
Core Spray booster pump. The cause of this occurrence was a deficiency
in the original plant design.
Corrective action consisted of performing a modification to replace the
pressure switches on the booster pump discharge with differential pressure
switches. The differential pressure switches will sense differential
pressure across the booster pump. This modification allows the pump
failure logic to perform as originally designed under all postulated
conditions.
The modification was verified to have been installed prior to the startup
from the plant shutdown which commenced on February 2, 1985.
{C.losed)85-04: Violation of APLHGR Limit
On Janttry 10, 1985, it was noted that the Power Shape Monitor System
(PSMS) calculated TIP traces were under-calculating the reactor axial
neutron flux profile when compared to measured TIP traces and PSMS model
performance was beyond established acceptance criteria. An investigation
commenced immediately to confirm the observation and determine the cause
of the different flux values. The reactor rod pattern was adjusted on
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January 15, 1985 in an attempt to reduce the high flux peaks. On January
24, 1985, a complete set of TIP traces were taken to determine if the
adjustment reduced the peaks and improved model performance. Upon review
of this TIP set, it was noted that flux peaks remained high and PSMS model
performance was still outside the established acceptance criteria. At
this time, it was suspected that the APLHGR Technical Specification limit
was violated.
Once it was determined that the Technical Specification limits on APLHGR
had been exceeded, core thermal power was reduced and the control rod
pattern was reconfigured to reduce power peaking. The flattening of the
power distribution was sufficient to eliminate the Technical Specification
violation.
The causes of the violation were that the bottom flux peaks which existed
at the facility during the month of January were beyond the limits of the
PSMS Cycle 10 model and resulted in the under calculation of the peaks,
'
and the PSMS software did not permit the LPRM feedback option to function,
even though the option was turned on.
The corrective actions consisted of improved procedural control which
would more frequently evaluate the PSMS nodal model accuracy and
performance; specification of immediate corrective action when PSMS
performance is outside acceptance criteria; and strict adherence to
operational guidelines during core operations will reduce measured TIP
peaks and reduce average relative axial power shape; and more frequent
performance of individual TIP traces during power maneuvering.
Discussions with Core Group personnel verified that all corrective action
has been incorporated into various facility procedures. The corrective
actions were incorporated into procedures over a period of time to
coincide with major procedure revisions. Core group personnel stated all
procedure changes required as a result of this LER have been made.
(0 pen) 85-06: Reactor Scram Due to Low Water Lovel
,
On February 24, 1985 an automatic reactor scram occurred due to low
reactor water level during a plant startup. The reactor was operating at
a power level of 400 MWt with level and pressure being controlled
automatically. A planned drywell inspection for steam leaks required
reactor power to be less than 10% with steam flow minimized. In
preparation, rods were inserted to decrease power. The rod movement
caused a level, power, and pressure transient which ultimately led to an
automatic scram on low level despite operator attempts to stabilize the
transient. All plant systems responded as expected and control room
operators brought the plant to a shutdown condition.
The root cause of the event was determined to be operator error in
, introducing a too-rapid decrease in reactor power and the inability of the
'
operators to stabilize plant parameters,
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Corrective action for this event was described as adding a caution to the
drywell access procedure alerting the operators to the sensitivity of
level and pressure to power changes at low power conditions. Also, plant
startup and shutdown procedures will be reviewed for applicability of this
caution.
During this inspection it was determined that following the issuance of
this LER on March 27, 1985 a Licensing Action Item was issued to Plant
Engineering on April 1, 1985 tasking them with implementation of the
corrective actions. Plant Engineering on June 18, 1985 issued a Technical
Functions Work Request asking Technical Functions to implement the
corrective actions. At the time of this inspection, 15 months after the
event, corrective actions consisting of procedure changes had not yet been
made.
(Closed) 85-07; Failure to Sample Tank
On March 20, 1985, during a routine Technical Specification surveillance,
it was discovered by the Plant Chemistry Department that the outside floor
drain sample tank was being used but had not been sampled since March 13,
1985 This was in violation of Technical Specifications which require
this tank to be sampled every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> unless it has been valved out of
service after determining its radioactive content. Upon discovering that
the tank was being used but not sampled, a sample was taken to cenfirm
that the tank did not exceed the applicable Technical Specification
maximum curie limit.
The event resulted from Chemistry not being told when the tank was placed
back in service after it had been isolated.
To prevent recurrence, certain procedure changes were made. The inspector
verified that a precaution / limitation had been inserted into procedures to
ensure that the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Technical Specification sampling is met and that
either the Manager of Radwaste Operations or Chemistry is notified prior to
the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> time limit, if this requirement cannot be met for any reason.
This change was made in Revision 11 to Procedure 351.1, Revision 12 to
Procedure 351.2, and Revision 1 to Procedure 830.4.
(Closed) 85-08: 4160V Emergency Bus Technical Specification Violation
A Plant Engineering review of Technical Specification Amendment 80 found
that existing procedures did not meet the new Technical Specification
requirements and calibration tolerances. Existing calibration
documentation was reviewed for the degraded voltage relays and degraded
voltage relay timers. Although they were found to be within the
acceptable tolerances stated in the existing procedures, the procedures
had not been revised to incorporate the recently issued Technical
Specification requirements. The Amendment was effective on the date of
issuance and did not provide for an implementation period in which to
revise the procedures. Immediate action was taken to temporarily change
the procedures required to ensure compliance with the Technical
Specification Amendment.
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The inspector verified that appropriate procedures have been prepared to
implement the Technical Specification change.
,
(0 pen) 85-09; 480 Volt Bus Overload
As the result of an electrical load study performed for Oyster Creek, it
was determined that 480 Volt Unit Substation 1A2 or 182 may be overloaded
during a loss of coolant accident with offsite power available and
! concurrent loss of one Unit Substation. The cause of this deficiency has
been determined to be a design problem because the impact of plant modi-
fications on bus loadings was not evaluated for this particular set of
conditions. If the Unit Substations are run in the anticipated overload
condition, it will result in decreased transformer life. Corrective
actions are planned to install fans to increase transformer capacity and
install an overcurrent alarm for the buses.
An alarm indicating overcurrent on each of the Unit Substations has been
installed. This alarms in the control room and the alarm response
procedure instructs control room personnel to shed unnecessary loads.
Fans will be added to the transformers for the Unit Substations. These
fans will increase the capacity by 15*4 and bring the anticipated worst
case loading within the rating of all the Unit Substation components. The
fans will be installed during this outage. This item remains open pending
l the installation of the fans.
1
(0 pen) 85-10; IRM Setpoints Exceeded Technical Specification Limits
While reviewing "as found" data on IRM setpoints, it was discovered by
the licensee that some upscale scram and upscale rod block setpoints had
slightly exceeded the allowable Technical Specification limit. The
apparent cause of this occurrence was the inadvertent deletion of the IRM
calibration procedure. Since the deletion of this procedure, the IRM
< drawers have been calibrated during refueling outages using vendor manual
instructions with the "as found" and "as left" setpoints not documented.
An appropriate procedure, 620.3.007, Mean Square Voltage Wide Range
Monitor (IRM) Bench Calibration, which documents "as found" and "as left"
setpoints has been prepared. Also, a modification is being evaluated to
permit testing trip settings during weekly front panel tests. This item
remains open pending the installation of this modification.
- (0 pen)85-11
- Three of Four Isolation Condenser _ Actuation pressure Sensors
! Out of Specification
i
During routine surveillance testing, 3 of 4 isolation automatic actuation
pressure sensors tripped at values slightly greater than specified in the
Technical Specifications. The cause has been attributed to instrument
drift. The immediate corrective action was to reset the trip setpoints
within desired limits. Replacement of these sensors with ones having
better setpoint repeatability is scheduled during the Cycle 11 refueling
outage. This item remains open pending replacement of these sensors.
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(0 pen) 84-26; Emergency Service Water Containment Spray Negative Delta
Pressure
This report describes a condition which has existed for sometime. In
particular, the differential pressure between the Emergency Service Water
(ESW) and Containment Spray (CS) is such that the CS water pressure is
higher than the ESW pressure in the CS heat exchangers. This would,
following a loss of coolant accident, permit radioactive CS water to leak
to the environment if a heat exchanger leak were present. This condition
is also contrary to that described in the Facility Description and Safety
Analysis Report. A Notice of Violation relative to this matter was also
issued on March 14, 1985.
TheLElknotesthecauseofthenegativedifferentialpressureisbelieved
to be a decrease in ESW pump performance and increased pressure drop in
the ESW piping. Subsequent evaluation by the licensee in reference to
Licensing Action Item 84208.01, documented that the negative pressure
differential across heat exchanger tubes is the result of degraded pump
performance and increased resistance due to biological foulir.g.
The licensee performed a safety evaluation to estimate the offsite dose
due to leakage from the CS' System during a loss of coolant accident.. The
evaluation concluded the existing condition will not significantly affect
the safety of the public or plant personnel. However, the evaluation
specifically notes the condition allows the possibility for a lingering
effect of radioactive iodine deposition to the environment after a loss of
system coolant accident. Therefore, the system will be returned to its
original design prior to startup from the 11R refueling outage (that is,
emergency service water at a higher pressure than the Containment Spray
System).
! The LER also indicated a supplemental report would be submitted, with the
expected submission date being June 30, 1985. This LER remains open
pending the receipt of the licensee's supplemental report and verification
of proper differential pressure between the shell and tube side prior to
startup from the 11R refueling outage.
.(Open) 86-04 Reactor Scram on Anticipatory Turbine Trip Caused by Limit
Switch Failure
'
This LER, in addition to reporting the reactor scram, also reports a
Technical Specification violation associated with failure to close and
deactivate a containment isolation valve in the same penetration with an
inoperable containment isolation valve.
During this inspection, the circumstances associated with the licensee's
decision to declare a containment isolation valve operable following its
apparent failure after the reactor scram on March 6, 1986 were reviewed.
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As noted in the LER, "At 0236 Reactor Water Cleanup system containment
isolation valves were opened to attempt a restart of the cleanup system in
order to control water level. A high pressure isolation occurred but
V-16-14 did not fully close as noted by double valve indication. The
torque switch was jumpered out and the valve closed."
Also, the Licensee's Deviation Report prepared in association with the
testing of V-16-14 states, in part, "All valves isolated properly. In
the process of restarting RWCU a second system isolation occurred on high
pressure. This time V-16-14 did not fully isolate (double indication). An
electrician was called and he had to jumper out the torque switch to close
V-16-14."
The Post Trip Review Group recommended prior to restart that discrepancies
with V-16-1 and V-16-14 be corrected.
In order to affect this corrective action, Maintenance and Construction
Short Forms SF34723 and SF34275 were written. SF34275 was written to
perform M0 VATS testing of V-16-14. The Short Form (SF) indicated that
MOVATS current traces obtained for V-16-14 were found to be acceptable.
MOVATS switch signatures were judged not to be required. The malfunction /
cause described on the SF initially was "under sized motor," but it was
subsequently changed to "possible under sized motor" upon further review
by the licensee.
The current values obtained on March 6, 1986 and previous values obtained
on November 15, 1985 were noted as follows for V-16-14:
3/06/86 11/15/85
0C* CO** OC C0
Start Current 39.5 A 42.35A 35.6A 36.85A
Avg. Run Current 7.35A 8.4 A 7.2A 8.5 A
May Run Current 7.35A 8.8 A 8.8A 9.8 A
End Current 32.15A 8.8 A 31.9A 8.55A
- 0C -- Valve moving from open to closed
- C0 -- Valve moving from closed to open
The TFWR associated with V-16-14 was written on November 22, 1985, and
described results of some previous testing. The TFWR noted that on
November 15, 1985, the operator was unable to obtain the recommended
minimum thrust values and that any increase in torque switch setting would
result in the motor running continuously after completion of valve travel
because the motor would never generate enough torque to trip the torque
switch. Additionally, the TFWR stated that the motor capability was
marginal. The TFWR also notes the motor pinion and worm shaft gears of
the operator were changed. This increased the capability of the motor but
it is still considered marginal. The TFWR requests Technical Functions to
review the feasibility of increasing the motor, cable, and starter size
for V-16-14.
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Additional information relative to the performance of V-16-14 was obtained
from a review of the valve maintenance history and a memorandum dated
March 17, 1986, from Plant Engineering to Technical Functions which
provided a history of V-16-14 failures. This information is summarized as
follows:
--
The operator currently on the valve was installed during the
1983-1984 outage.
--
February 2,1985, the valve failed to fully close. This was
attributed to mechanical binding causing the torque switch to open.
The cause of the binding was due to a damaged lantern ring.
--
June 12, 1985, V-16-14 failed to open due to a motor overload trip.
Later, when closing the valve the close contactor would not drop out
and an operator present at the motor control center had to trip the
breaker manually. The cause of this failure to trip was attributed
to a loose set screw which allowed the torque switch setpoint to
drift to a higher value. At this higher value, the motor was unable
to trip the torque switch open. It was noted that previous M0 VATS
testing had shown the motor to be marginal and that it would not trip
the torque switch at higher thrust values. LER 85-12 identified the
valve's failure to open following a June 12, 1985 reactor trip. This
was attributed to insufficient torque due to improper gear ratios in
the operator. On June 15, 1985 the motor pinion and worm gears were
changed to increase the motor torque. Tests showed torque increased,
but is was still considered marginal.
Valve thrust data after gear replacement was reviewed and noted to be
as follows:
Recommended Thrust Values
Minimum Normal Maximum
Open 15956 21164 23280
Close 8346 10582 11640
'-
Recorded Thrust Values
Open Close Date
10283 10442 10/03/84
15955 11493 02/13/85
10530 11237 11/15/85
As can be seen, little improvement was noted following the gear
replacement.
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November 10, 1985 a broken stem nut was identified. This failure was
not attributed to the motor or torque switch. Also, the spring pack
lock-nut was found loose. Testing following the repair again showed
the motor was unable to trip the torque switch open at higher
setpoints and thrust values.
--
November 22, 1985, the motor for V-16-14 was replaced with an
identical motor from V-17-57. The motor was replaced due to damaged
wiring incurred while re-installing the motor after troubleshooting
for a ground. Current signatures indicated the same characteristics
'
as the original motor current signatures.
--
March 6, 1986, the failure described in this LER 86-04 occurred.
A follow-up memorandum to the TFWR from Technical Functions dated May 1,
1986, which was not available to the reviewer on March 6, 1986, indicated
that Limitorque, the operator vendor, stated the operator should provide
sufficient torque (thrust) to satisfy its application. They feel that if
the operator is not providing sufficient output, then there must be a
problem in the operator, motor, or its power supply. Additional data
presently available on site shows that a new identical operator tested by
Limitorque is providing approximately twice the thrust the installed
operator is providing. Further evaluation of this new operator is planned
when it is installed on V-16-14. Also, the valve is scheduled for
inspection during this 11R outage.
_
Since the valve had apparently failed to close on March 6,1986, and that
no changes or repairs had been made based only on a MOVATS current trace
which showed the currents were essentially the same as they had been prior
to the failure, the inspectors questioned the licensee on his basis for
declaring V-16-14 operable.
The licensee provided the inspectors the basis by which the valve was
declared operable during a meeting with representatives of Plant
'
Engineering and Operations personnel on June 3, 1986. The licensee's
position is summarized as follows:
The licensee felt, ba2ed on the available data at the time of the trip and
the post trip review, that it was not clear as to whether V-16-14 failed
to open or failed to close. To be conservative they declared the valve
inoperable and decided to obtain a MOVATS current signature of the valve.
The current signature indicated there were no problems. Based on this
data and subsequent satisfactory operation of V-16-14, the valve was
declared operable. The decision not to perform additional troubleshooting
appears to be related to the ambiguity as to what actually happened with
V-16-14 and the understanding by many people at the time just after the
event until after restart, that the valve failed to open, not close. The
licensee stated V-16-14 will be thoroughly inspected and tested prior to
restart from the 11R outage.
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In fact, V-16-14 did fail to close. It's closing torque switch tripped
and left the valve in an intermediate position. This occurred when
V-16-14 was being jogged open and a Reactor Water Cleanup system isolation
signal was received. It is incumbent on Plant Engineering to address this
scenario and determine if a problem exists such that if the torque
required to reverse the valve direction is greater than the setting of the
torque switch, then V-16-14 will always fail to close in this scenario.
Differential pressure across the valve also needs to be included in the
scenario.
The NRC staff will continue to follow this matter.
( '
(0 pen)84-007; Failure to Test a SGTS Train Within Required Time
During a refueling outage, a diesel generator (DG) was declared inoperable
as a result of a monthly surveillance failure. This required testing the
redundant standby gas treatment system (SBGTS) train, since the DGs are
the emergency power source for the SBGTS. The redundant train was not
tested for ten hours dn to a procedure limitation as a result of torus
painting. Technical Specifications require testing the redundant train
within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. This was not accomplished and handling of irradiated fuel
continued on the refueling floor in violation of Technical Specification
requirements.
In response to this, GPUN licensing committed to request a revision of
Technical Specifications by November 15, 1984. Technical Specification
Change Request (TSCR) No. 133, was submitted January 30, 1986 over one
year late. The commitment was made to clarify the fechnical *
Specifications with regard to surveillance requirements and backup power
supply. LER 84-7 stated as part of the corrective action that "a change
to the Technical Specificationis will be investigated to ascertain if the
more restrictive Technical Specifications regarding normal or emergency
power supply requirements in the snutdown or refuel modes.can be eased or
clarified." TSCR 133 requested a change in the time to test a redundant
SBGTS train from two to twalve hours if a SOGTS train is inoperable and
significant painting, fire, or chemical release has taken place in the
reactor building. TSCR 133 did not clarify the Technical Specifications
with regard to normal or emergency power supply requirements. In
addition, no clarification was provided on moving irradiated fuel untti
the SBGTS operability has been determined.
Furthermore, the licensee has traditionally interpreted and so states in
LER 84-07, that Techniccl Specification 3.0.B is more restrictive during
shutdown or refueling with regard to inoperability of power sources than
during normal operations. This refers to the last sentence in 3.0.8,
"This specification is not applicable in cold shutdown or the refuel
mode." which the licensee has intenreted to mean that during these modes
both normal and emergency power supplies are required for a system to be~
operable. During normal operation, 3.0.B allows system to be considered
operable if either the normat or emergency power source is inoperable and
the redundant train is operable. The last sentence in 3.0.B could also
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be taken to apply to only the preceding sentence, which requires the plant
to proceed to cold shutdown if 3.0.B is not satisfied; thus negating the
requirement to proceed to cold shutdown if that is the plant's present
mode of operation. The licensee has applied 3.0.B in cold shutdown and
refueling to require an operable emergency power source. The licensee has
agreed to change the applicable section of the technical specification for
clarification. This LER will remain open pending generation of a Tech-
nical Specification that addresses normal and emergency power supply
requirements during all modes of operation, including shutdown and totally
defueled.
Summary
A total of 29 LERs were reviewed during this inspection. Seventeen of the
29 are considered closed. Four LERs, 84-31, 85-09, 85-10, and 85-11, are
'
expected to have specified corrective actions completed during this
outage, with 84-31 having a follow-up report due.
Report 85-06 remains open pending the completion of the specified '
corrective action. As noted above, corrective action consisting of
procedure changes has not been implemented 15 months after the event.
One LER, 86-04, had only the circumstances associated with declaring a
containment isolation valve V-16-14 operational following a valve failure
reviewed. The NRC wiil continue to follow up this matter.
Four LERs, 83-24, 84-08, 84-05, and 84-26 have been identified by the
licensee as having supplemental reports due. The expected submission date
for the 83-24 supplemental report was not specified. However, expected
supplemental report submission dates for the other three LERs were
October 30, 1984; June 30, 1984; and June 30, 1985. None of these supple-
mental reports have been submitted. This failure to submit supplemental
reports in a timely manner was discussed with licensee representatives.
1
4. Review of Periodic and Special Reports
Upon receiot, periodic and special reports submitted by the licensee
pursuant totTechnical Specification requirements were reviewed by the
inspectors. This review included the following considerations: the report
includes the information required to be reported to the NRC; planned
corrective actions are adequate for resolution of identified problems; and
the reported information is valid.
The following reports were reviewed:
--
Monthly Operating Reports for March and April 1986
--
Special Report 86-01 dated 4/20/86 regarding failure to restore a
non-functional fire barrier penetration seal to functional status
within 7 days from time of discovery.
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Special Report 86-02 dated 5/13/86 regarding temporary deactivation
of fire detection and automatic halon fire suppression systems
serving the 480V switchgear room while room undergoes Appendix R
modifications. The report stated a continuous fire watch has been
established as required by Tech Specs.
5. Observation of Physical Security
During daily tours, the inspectors verified access controls were in
accordance with the Security Plan, security posts were properly manned,
protected area gates were locked or guarded, and isolation zones were free
of obstructions. The inspectors examined vital area access points to
verify that they were properly locked or guarded and that access control
was in accordance with the Security Plan.
In accordance with the requirements of 10 CFR 73.71, the licensee reported
a moderate and a major loss of physical security during this report
period. The moderate loss of physical security involved a short-lived (1
hour and 16 minutes) situation in which less than the required number of
intrusion detection systems were it, service for a portion of the protected
area fence. This event occurred when portions of the protected area fence
were relocated to include several contractor trailers in the protected
area. Upon realization of the problem, it was immediately corrected and a
search of the protected and vital areas performed. No problems were
identified.
The major loss of physical security occurred when access to a vital area
was obtained by an unauthorized individual. This violation was identified
by a member of the security force as the unauthorized individual was
leaving the vital area. Subsequent investigation determined the
individual was a contractor supervisor who should have had authorization
in order to supervise employees under his direction who were working in
the vital area. An investigation of the infraction was conducted and
corrective action implemented.immediately.
Based on the facts that the licensee self-identified both problems and
took prompt and comprehensive corrective action, the inspectors had no
further concerns regarding either matter.
6. Review of Concrete Anchor Bolt Test Data Associated with NRC Bulletin
79-02
The resident inspectors conducted an inspection at the GPUN Corporate
offices in Parsippany, NJ to review test data regarding installation and
performance of concrete expansion anchor bolts in seismic piping systems.
What precipitated this inspection was the licensee's stated intention to
exclude 157 baseplates and their associated anchor bolts from current
Bulletin 79-02 reinspection efforts based on data gathered during their
initial efforts to address this Bulletin. The licensee's current
reinspection program for pipe support base plates using expansion anchor
bolts is in response to the findings from Inspection 50-219/85-14
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26
conducted May 14-17, 1985 which identified deficiencies in the original
ir.spection effort which commenced in 1979 and finished in 1980.
In 1979 the licensee generated Special Procedure No. 79-31, Rev. 1,
Inspection Test and Installation Procedure for Concrete Expansion Anchor
Bolts in Seismic Piping Systems._ This procedure required pull testing of
anchor bolts to verify that Bulletin 79-02 factors of safety could be met.
It also required that anchor bolt installation data be recorded. The
inspection reviewed a sampling of the data to ensure it was sufficient to
meet Bulletin requirements.
The discrepancies identified during the inspectors' review of anchor bolt
test data for baseplate installations associated with pipe supports in the
Isolation Condenser (211) and Core Spray (212) systems are listed in the
below table. It should be noted that all anchor bolt installations
reviewed were shell type. The support identification is listed in the
left hand column and the anchor bolt test data discrepancies associated
with that support are indicated by a 'X' under numbers 1-10 in a row
across the table. Each number represents a different discrepancy as
defined at the end of the table.
Anchor Test Data Discrepancy Table
Discrepancy Type
Support Number 1 2 3 4 5 6 7 8 9 10
212-BP.368.R10.9.A X
212-BP.368.R2.15A X
212-BP.NZ.2.H12.39.A X X X
212-BP.368.R3.40.A X
212-BP.NZ.2.H30.56.A X X
212-BP.41.1.RI.60A
212-BP.NZ.2.H26.64A X X X X
212-BP.NZ.2.H32.93A X X
212-BP.411.R9.74.A X X X
212-BP-NZ.2.RSA.97A
212-BP.NZ.2.H52.43.A X X X
212-BP-NZ.2.R16A.30A X
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Support Nu:nber 1 2 3 4 5 6 7 8 9 10
212-BP.368.R6.20.A X
212-BP.368-RS.21-A X X
212-BP-368.R9 X
211-BP-634-R9-28-A X
211-BP-632 .R4.48-A X
211-BP-NE-1-H5.51.B X
211-BP-632.RI.55.A X X
211-BP-633-R6.64.A X X
211-BP-NE-1-H10.68.8 X X X
211-BP-633-R1.73.A X X
211-BP.633.R2.70.A X
211-BP.634.R3.16.A X X
211-BP.NE.1.H4.49.B X X
211-BP.634.R2.14.A X
Key To Discrepancy Types
1. Incorre;t plate bolt hole size for anchor size. In most cases the
allowable hole size was greater, but in a few examples, the plate
bolt hole size recorded was smaller than the anchor bolt which was
obviously erroneous data.
2. The distance from the top of shell to the top of the red head does
not meet manufacturer's recommendations.
3. Shell embedment depth does not meet manufacturer's recommendations.
4. Dial indicator measurement of anchor bolt displacement during pull
testing indicates an anomaly.
5. Thread engagement measurement of bolt into shell not provided.
6. Bolt spacing may be less than required for 100% capacity.
7. Test loading insufficient to satisfy Procedure 79-31 requirements.
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8. Insufficient thread engagement, i.e., bolt is threaded into shell
less than one bolt diameter.
9. Edge distance between anchor bolt and concrete may not be sufficient.
10. Disagreement between field data sheets and design drawings.
The number of discrepancies found in anchor bolt data as illustrated above
indicates that the licensee should analyze the data for acceptability.
prior to excluding these installations from future inspection activities.
Generally, the data reviewed indicated that the pull test data was
acceptable with some exceptions. In several cases the pull test indicated
zero displacement for each successive increased load (212-BP.NZ.2.H26.64A;
212-BP.NZ.2.H52.43A; 211-BP.633.R1.73A), and, in one case, the displace-
ment decreased with increased load (212-BP-NZ.2.H30.56.A). These
installations should be re-eyamined. Some other anchor bolts were not
tested to the required loading (Discrepancy No. 7). If additional piping
support analysis reveals that the analyzed loading exceeds the loading the
anchor bolts were tested to, then these anchor bolts will have to be
retested to the new loading. In addition, the manufacturer's ultimate
pull out load versus concrete strength data for the anchor bolts and the
concrete strength for Oyster Creek Nuclear Generating Station were not
available. This data is necessary to determine the factor of safety the
licensee's testing verified. The licensee stated that they would provide
the necessary information to the resident inspectors so that a determina-
tion of the factor of safety could be made and this value then compared to
the Bulletin required factor of safety of five for shell type anchors.
(219/86-12-05)
The licensee stated that they plan to conduct a complete review of the
anchor bolt data from the 1979-80 inspection for the 157 baseplates in
question to ensure the data is meaningful.
7. Surveillance Testing
During the observation of a diesel generator load test surveillance
(Procedure 636.4.003), the inspector noted the copy of Procedure 341,
Standby Diesel Generator Operation, posted in the diesel switchgear room
was outdated. The current procedure revision at the time was Revision 19,
while the posted procedure was Revision 18. The purpose of Procedure 341
is to provide detailed instructions for the operation of the Standby
Diesel Generators. The licensee determined this was an administrative
error and that no adverse operating conditions occurred as a result. The
proper revision was posted in the diesel switchgear room.
8. Presentations
The inspectors attended a briefir.g on Technical Manual review conducted by
the vendor document control section of Technical Functions Engineering
Assurance.
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29
9. TMI Action Plan Requirements Item I.A.I.3, Shift Manning
The inspector reviewed the licensee's Technical Specifications and
Procedure 106, Conduct of Operations, to determine if overtime
restrictions were incorporated in the documents. In addition, the
recorded working hours for Senior Reactor Operators, Reactor Operators,
Equipment Operators were reviewed for May 1986. In both the Technical
Specifications and Procedure 106, the licensee had incorporated the
overtime restrictions and had appropriately specified the minimum shift
requirements. The licensee has implemented a program to track shift
operators' working hours to insure the overtime restrictions are followed.
The review of the working hour records revealed that one equipment
operator had worked 80 hours9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br /> in a seven day period with prior approval of
department management. This item is closed.
10. Inspector Observations of 11R Outage Activities
A. Defueling
The inspectors observed activities leading up to and including
complete defueling of the reactor core. The activities were
conducted in a controlled fashion using approved procedures. The
assignment of an individual to coordinate refueling floor activities
aided in this generally trouble-free sequence of activities.
Problems were encountered when two of three stud tensioners used to
de-tension the reactor head studs broke down and when minor
breakdowns of the fuel handling bridge occurred. These were
considered minor problems with little impact on the schedule.
Shortly after plant shutdown on 4/12/86, local leak rate testing
(LLRT) of containment isolation valves commenced. The LLRT results
for the MSIVs indicated a minor packing leak on one valve and no seat
leakage past any valve. Historically, at least one MSIV has been
found with seat leakage. The fact that there was no seat leakage
past any MSIV is an Oyster Creek first and precluded having to
rebuild two MSIVs as originally planned for in the 11R schedule. Not
all valves tested passed, however. Containment isolation valves in
the RBCCW, Reactor Water Cleanup, Torus Vent systems, in addition to
l others, failed and will have to be repaired. The licensee is
j required by Appendix J to 10 CFR 50 to submit a final report of their
test results which will document all the valves that failed LLRT.
C. Fuel Sipping
The licensee contracted with GE to perform an inspection of the
fuel bundles just removed from the core to determine which leaked.
The process used by GE is called fuel sipping. The process involves
placing a fuel bundle in a chamber, sealing the chamber, then forc-
ing air bubbles past the fuel elements in the bundle. The air
i
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30
strips away any leaking gases from the surface of the fuel elements
thel flows out the top of the chamber into a radiation detector that
peri.irms an analysis to determine gaseous radioactivity. The
liceisee decided to perform. fuel sipping because of increases in
gastous activity found in reactor coolant samples that commenced in
February 1985. This increase in gaseous activity was considered a
precursor of leaking fuel elements. Of 536 fuel bundles sipped, 47
were determined to be leaking. Additional follow-up as to the cause
of the leaking fuel elements will be performed in a subsequent
inspection (219/86-12-06).
During fuel sipping operations in the early morning hours of 5/29/86,
area radiation monitor alarms (ARMS) sounded on the refueling bridge.
At the time the ARMS alarmed, the bridge was positioned on the south
side of the spent fuel pool directly in front of the spent fuel pcol
gates. The fuel handling grapple was latched on a fuel bundle. The
bridge operator disregarded these alarms because he felt they
resulted from shine from the vessel cavity which was cry. He pro-
ceded to lift the bundle out of the spent fuel storage rack and move
it to the sipping cannister. Unknown to the operator at the time,
the C-5 criticality monitor alarm on the refueling floor started to
alarm both locally ano in the control room. The C-5 criticality
alarm has a similar sound as the bridge ARM and was not noticeable as
a unique alarm. When the alarm was received in the control room, the
GSS followed procedural requirements to investigate the alarm. When
he got to the ARM instrument readout, the reading was normal. He
felt the alarm was spurious based on not getting a phone call from
the bridge operators. Unknown to the bridge operators, personnel
friskers in various plant locations alarmed.
This sequence of events happened a second time, when the next fuel
bundle was moved to the sipping cannister and then two additional
times when the bundles were returned to the spent fuel storage racks.
It was not clear whether the C-5 criticality monitor alarmed more
than once. Out of curiosity, the bridge operators obtained a R0-2A
meter to check the radiation level on the bridge when they lifted the
second fuel bundle out of the spent fuel racks. The reading peaked
at 800 mr/hr. The operators on the bridge communicated the fact they
received radiation alarms on the bridge to the GSS in the control
room after the second fuel bundle was in the sipping cannister. The
GSS did not mentally correlate these alarms with the C-5 criticality
alarm received earlier.
Meanwhile, Radcon personnel were attempting to identify the source of
the radiation that was setting off the alarms. They contacted the
control room but the GSS had not recognized the problems on the
refueling floor because of poor communications with the bridge
operators. The Radcon technician on the refueling floor, when
questioned as to the existence of any radiation problems, stated
there were none. He was mislead to this conclusion based on ,
, reassurances from the bridge operators that the bridge alarms were
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31
normal and his misunderstanding that no fuel was being moved. Radcon
continued their investigation for the balance of the shift. Movement
of the problem fuel bundles commenced about 0300 and fuel sipping for
that shift was completed about 0345.
Upon resumption of fuel sipping on day shift, the problem was finally
identified. Specifically, radiation streaming through the spent fuel
pool gate occurred when the fuel bundles reached the elevation of the
gate as they were lifted out of the spent fuel racks. The streaming
was unimpeded by shielding and, therefore, caused the various alarms
!
to initiate. The amount of time involved with the bundles in this
location was minimal as they were moved away from the south wall to
the north wall as soon as they were lifted out of the spent fuel
racks and were lowered back into the spent fuel racks after
completion of sipping.
The licensee held a critique of this occurrence which a NRC inspector
attended. The critique revealed a series of communication and
procedural problems. The critique was effective in establishing the
problem areas and adequate corrective action was proposed. Based on
the effective critique and the fact that no personnel overexposures
or significant unplanned exposures occurred, the inspectors had no
further concerns regarding this matter.
D. Chemical Decontamination
Removal of radioactive material from inside the Recirculation system
piping was performed by the licensee to lower the radiation levels
inside the drywell. This action is consistent with good ALARA policy
and will result in many man-rem savings during subsequent drywell
work activities. The process used has been used successfully at
other nuclear plants and involves injecting certain chemicals in
solution at elevated temperatures (180-195 F range) into the
Recirculation piping. The chemical reaction results in detachment
of small radioactive particles from the inside wall of pipe. These
particles then go into suspension and are subsequently flushed out
of the Recirculation piping and collected in filter beds when the
chemical solution is removed. Upon completion of the chemical
decontamination, a decontamination factor (DF) of 10.38 was
calculated. This was a high DF that exceeded all expectations.
E. Intake Structure Concrete Inspection
Inspection of intake structure concrete below the water line is being
performed during this outage. The NRC inspectors looked at portions
of the below water concrete surfaces after they were hydrolazed to
remove sea growth and found them to be in generally good condition.
Evaluation of cracks and potential corrosion of subsurface rebar is
,
an important aspect of this inspection. No significant findings had
been reported prior to the end of this report period.
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11. Radiation Protection
During entry to and exit from the RCA, the inspectors verified that proper
warning signs were posted, personnel entering were wearing proper dosi-
metry, personnel and materials leaving were properly monitored for radio-
active contamination, and monitoring instruments were functional and in
calibration. Posted extended Radiation Work Permits (RWPs) and survey
status boards were reviewed to verify that they were current and accurate.
The inspector observed activities in the RCA to verify that personnel
complied with the requirements of applicable RWPs and that workers were
aware of the radiological conditions in the area.
With the increased workload during an outage, it is neccssary for Radcon
to augment their staffing with contractor personnel. The inspectors
observed the performance of contractor personnel to ensure they were
adequately trained and capable of performing their duties. No defici-
encies were identified.
In NRC Inspection "eport 85-35, the licensee was cited because person-
nel leaving the RCA were not properly frisking carry along items. The
inspector observed frisking activities at various times during this
report period and noted several examples of this same problem. These
observations were relayed to Radcon management personnel who stated
they had not seen recurrence of this problem during their routine tours
of the site. They agreed to continue to aggressively pursue informing
all personnel of the requirements for frisking prior to leaving the RCA.
The resident inspectors will continue to routinely review this area and
follow-up on licensee corrective actions for the above noted violations
(which are currently under review by NRC Region I).
12. Exit Interview
A summary of the results of the inspection activities performed during
this report period were made at meetings with senior licensee management
at the end of the inspection. The licensee stated that, of the subjects
discussed at the exit interview, no proprietary information was included.
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