ML14178A088
| ML14178A088 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 03/05/1991 |
| From: | Christensen H, Garner L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML14178A086 | List: |
| References | |
| 50-261-91-01, 50-261-91-1, NUDOCS 9103250215 | |
| Download: ML14178A088 (28) | |
See also: IR 05000261/1991001
Text
1 pkREGU4
UNITED STATES
o
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
ReMp
No.: 50-261/91-01
Licensee:
Carolina Power and Light Company
P. 0. Box 1551
Raleigh, NC 27602
Docket No.:
50-261
License No.: DPR-23
Facility Name: H. B. Robinson
Inspection Conducted: January 11 -
February 15, 1991
Lead Inspector: 2"o -/
L. W. Garne 1, Senior Resident I pector
Date Sygned
Other Inspectors: R. E. Carroll
M. M. Glasman
K. R Jury
Approved by:
da 0iUrust3
1
,H.
0. [Christensen, Chief
D e Gigned
Reactor Projects Branch 1
Division of Reactor Projects
SUMMARY
Scope:
This routine, announced inspection was conducted in the areas of operational
safety verification, installation and testing of modifications, surveillance
observation, maintenance observation, onsite review committee, and followup.
Results:
A violation with two examples was identified for failure to accomplish
activities affecting quality in accordance with procedures or drawings.
The
first example involved maintenance technicians' failure to perform modification
acceptance testing as documented, which resulted in the improper declaration of
modification operability (paragraph
3).
The second example involved an
incorrect size fuse being installed in the A SI pump control circuit other than
that shown on the applicable drawing (paragraph 5).
A violation was identified for inadequate modification acceptance tests being
specified for component functional verification (paragraph 3).
9103250215 910305
ADOCK 05000261
2
A violation was identified involving an inadequate procedure change to test
the main steam line isolation function.
This indicated a weakness in the
preparation and technical review process associated with logic testing
procedures (paragraph 4).
A non-cited violation was identified for failure of a worker to be dressed in
accordance with radiation work permit requirements (paragraph 2).
ASME Code relief was granted to operate cycle 14 with engineered repairs to
service water containment penetrations
and
piping inside containment
(paragraph 2).
Preliminary closeout inspections of the containment indicated that the cleanup
was not being performed in a thorough, systematic manner (paragraph 2).
Two service water system spills in containment and the auxiliary building
were apparently caused by unanticipated valve seat movement (paragraph 2).
The recovery evolution for an unlatched control rod was well planned and
executed (paragraph 2).
Two drawing discrepancies were identified.
drawing incorrectly identified the source of power to the reactor trip breaker
circuit.
A safeguards logic diagram did not indicate that an automatic
containment spray initiation signal would also initiate a safety injection
signal (paragraph 2).
A green liquescent substance originating from Machine Tool wiring was
discovered on contactors inside class 1E motor control centers.
This was
identified as the probable cause of two valves failing to operate properly
(paragraph 5).
The licensee is developing a fuse schedule as part of the development of an
overall fuse control program (paragraph 5).
A commitment was not met to develop a Plant Specific Technical Guideline by
September 28, 1990, in that the basis for some setpoints were not established
(paragraph 7).
REPORT DETAILS
Persons Contacted
- R. Barnett, Manager, Outages and Modifications
C. Baucom, Shift Outage Manager, Outages and Modifications
- D. Bauer, Regulatory Compliance Coordinator, Regulatory Compliance
J. Benjamin, Shift Outage Manager, Outages and Modifications
C. Bethea, Manager, Training
- W. Biggs, Manager, Nuclear Engineering Department Site Unit
- S. Billings, Technical Aide, Regulatory Compliance
- R. Chambers, Manager, Operations
T. Cleary, Manager - Balance of Plant Systems and Reactor Engineering,
Technical Support
- D. Crook, Senior Specialist, Regulatory Compliance
- J.
Curley, Manager, Environmental and Radiation Control
- C. Dietz, Manager, Robinson Nuclear Project
- D. Dixon, Manager, Control and Administration
J. Eaddy, Manager, Environmental and Radiation Support
F. Eckert, Manager, Planning and Scheduling, Outages and Modifications
S. Farmer, Manager - Engineering Programs, Technical Support
R. Femal, Shift Supervisor, Operations
B. Harward, Manager - Mechanical Systems, Technical Support
- J.
Kloosterman, Manager, Regulatory Compliance
D. Knight, Shift Supervisor, Operations
- D. Labelle, Project Engineer, Nuclear Assessment
E. Lee, Shift Outage Manager, Outages and Modifications
- A. McCauley, Manager - Electrical Systems, Technical Support
R. Moore, Shift Supervisor, Operations
D. Nelson, Shift Outage Manager, Outages and Modifications
- M. Page, Manager, Technical Support
D. Seagle, Shift Supervisor, Operations
- J. Sheppard, Plant General Manager
- R. Smith, Manager, Maintenance
- D. Stadler, Onsite Licensing Engineer, Nuclear Licensing
R. Steele, Shift Supervisor, Operations
- D. Stepps, Senior Engineer, Nuclear Engineering Department Site Unit
- G. Walters, Operating Event Followup Coordinator, Regulatory Compliance
D. Winters, Shift Supervisor, Operations
H. Young, Manager, Quality Control
Other licensee employees contacted included technicians, operators,
mechanics, security force members, and office personnel.
- Attended exit interview on February 25, 1991.
2
H. Christensen, Section Chief, Division of Reactor Projects, Region II
was on site January 22-24, 1991, to meet with the resident inspectors and
plant management.
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2. Operational Safety Verification (71707)
The inspectors evaluated licensee activities to confirm that the facility
was being operated safely and in conformance with regulatory
requirements.
These activities were confirmed by direct observation,
facility tours, interviews and discussions with licensee personnel and
management, verification of safety system status, and review of facility
records.
To verify equipment operability and compliance with TS,
the inspectors
reviewed Operations' records, data sheets, instrument traces, and records
of equipment malfunctions.
Through work observations and discussions
with Operations Staff members,
the inspectors verified the staff was
knowledgeable of plant conditions, cognizant of in-progress surveillance
and maintenance activities, and aware of inoperable equipment status.
The inspectors reviewed component status and safety-related parameters to
verify conformance with TS.
The inspectors observed that proper control
room staffing existed, access to the control room was controlled, and
Operations personnel carried out their assigned duties in an effective
manner.
Plant tours and perimeter walkdowns were conducted to verify equipment
operability, assess the general condition of plant equipment,
and to
verify that radiological controls, fire protection controls, physical
protection controls,
and equipment tagging procedures were properly
implemented.
Unlatched Control Rod
On January 29,
1991,
during performance of EST-048,
Control Rod Drop
Test,
RCCA C-07 exhibited an abnormal rod drop trace and time.
The
initial belief was that some equipment malfunction, such as a loose
monitoring lead connection, had caused the abnormal indications.
Repeat
testing on the next day produced similar results (i.e., the trace was not
a smooth curve and the rod took approximately one second longer to fall
than anticipated).
On January 31, 1991, the inspectors witnessed SP-1012,
Control Rod Drive Mechanism C-07 Testing, which verified that the C-07
drive shaft was uncoupled from its RCCA.
This was based upon the rod
lift,
moveable gripper and stationary gripper coil current traces, as
well as sound traces which demonstrated that the C-07 drive shaft
reached its maximum and minimum position three steps before three other
3
rods reached their respective maximum and minimum positions.
The C-07
lift
coil current also revealed that the lift
coil consistently moved its
drive shaft one step quicker (by approximately 20 milliseconds) than
other lift
coils raised their drive shafts one step (i.e., the C-07 lift
coil only had to move the weight of a drive shaft, not a drive shaft and
an RCCA).
Recovery of the unlatched control rod involved removal of the reactor
vessel head, as found inspection of C-07,
and video camera inspection of
the associated guide tube and RCCA. The inspectors witnessed performance
of SP-1016, Testing And Latching; Inspection And Unlatching Of The RCCA At
Core Location C-07, which confirmed by weighing that the C-07 drive shaft
was not attached to its associated RCCA. Subsequent testing revealed that
the drive shaft could be latched to the RCCA. A visual inspection of the
drive shaft revealed minor scratches and denting at the latching end of
the drive shaft.
Video camera inspection of the RCCA hub revealed only
superficial damage. There was not a condition found which could explain
the failure of the drive shaft to be latched to the RCCA. Video camera
inspection of the guide tube identified that it had been struck at several
locations by the drive shaft during rod drop testing.
The top of one
opening where the RCCA rodlets moves through the guide tube was determined
to be bent inwards.
Based upon the observed damage,
recommended that the guide tube be replaced.
A new drive shaft and guide
tube were installed. The RCCA was inspected by video camera and partially
lifted to verify freedom of movement.
Based upon these results, the
RCCA was determined to be acceptable for continued service.
Prior to reactor vessel head installation, special verifications were
performed of each control rod to ensure by visual inspection and "go,
no-go" gaging that the drive shafts were set inside the RCCA hubs and the
latching buttons were properly engaged.
The inspectors noted that the
recovery evolution was well planned and executed.
Inadverent Removal of Source Assembly
On February 10,
1991, while moving the upper internals package for C-07
recovery evolutions,
the lift
was terminated when the control room
operator observed that source range monitor NI-31 count rate rapidly
decreased from 100 cpm to 20 cpm.
Visual inspection revealed four
rodlets hanging from under the upper internals package.
These rodlets
were determined to be an antimony-beryllium secondary source assembly.
At the time of discovery, the bottom of the upper internals package was
approximately 2 to 3 feet above the reactor vessel flange. The inspectors
witnessed successful performance of SP-1015,
Secondary Source Inspection
And Recovery.
The
SP provided instructions for lifting the upper
internals package sufficiently high enough to allow movement across the
reactor flange area with the 14 foot long source assembly attached and
subsequent removal of the source.
Movement across and positioning the
4
source above the refueling cavity floor was monitored by underwater
cameras.
Once positioned a few inches above the floor, a long rod was
used to reach inside the guide tube and lightly tap the top of the source
assembly.
The source assembly, weighing approximately 27 pounds, fell
uneventfully onto the cavity floor. The source assembly was subsequently
removed to the SFP for disposal.
The inspectors verified that ALARA and
radiation protection considerations were appropriately considered during
this evolution.
Root cause investigation attributed this event to an inadequate technical
review.
The source assembly was installed this RO in a different core
location,
H2,
than that previously utilized.
This particular location
does not have a flow vane installed in the top core plate as previous
locations did.
The flow vane presses down onto the source assembly,
thereby, keeping the assembly in place.
Without a flow vane installed,
the core differential pressure was sufficient to allow the light weight
source assembly to float up and wedge approximately eight inches inside
the upper internals package.
Corrective actions to preclude future
occurrences of positioning core components into undesirable locations are
under development.
As a result of not being able to reload this source into the core, there
is no irradiated source assembly installed in the core.
However, the
NI-31 and NI-32 count rates, approximately 20 cpm due to the presence of
irradiated fuel, are sufficient to allow a safe restart.
ASME Code Relief Request -
SW Piping
On January 6, 1991,
MIC was identified in the six inch diameter, schedule
40, 316L stainless steel weld joints in the SW supply and return piping of
containment fan cooler HVH-4. MIC indications were subsequently observed
in 11 of 16 HVH-4 piping weld joints radiographically examined.
The
affected HVH-4 piping contained a total of 53 weld joints.
One weld
joint was removed and taken to the HE & EC for analysis; the HE & EC
confirmed the presence of wall thinning due to MIC.
The MIC initiation
location was along the base metal/weld metal interface and the weld.
This location was different from the MIC previously observed in the 304L
stainless steel HVH SW return and supply piping, in that, the 304L MIC
had initiated in the weld joint heat affected zone adjacent to the weld.
During
RO 12, all the stainless steel HVH SW supply and return lines
inside the CV were replaced with AL6XN material except for the 316L piping
discussed above and inside the containment penetrations.
The HVH-4 SW
piping traversing under the refueling canal had been replaced in 1985 with
316L material.
All five 316L HVH-4 weld joints radiographically examined
in 1988 showed no MIC indications.
Radiographic examinations of the eight containment penetrations (a supply
and return penetration for each of the 4 containment fan coolers)
identified 4 penetrations with MIC.
The eight containment penetrations
5
had a 316L stainless steel liner installed in 1985 inside the 304L penetra
tion piping. The 304L penetration piping was fillet welded to the liner
and the 304L SW piping to the HVH units was then inserted over a portion
of the liner and fillet welded to the liner. During RO 12, the liners
were cut, the 304L piping from the CV side of the penetrations to the
HVH units was removed and replaced with AL6XN material.
The AL6XN piping
was inserted over the liner and fillet welded to it. This resulted in the
stainless steel liner being in contact with SW and having heat affected
zones acting as a containment boundary.
On January 16, 1991, the licensee requested an ASME code relief to allow
operation with temporary,
non-code,
engineered repairs to the above
described piping due to material availability and the long lead time
required for penetration repair technique development.
The engineered
repair consists of welded sleeves over all the 316L HVH-4 weld joints
which were not code repaired and welded sleeves over the piping of 4
containment penetrations which contained MIC indications.
The relief
request demonstrated that the unit could operate safely with the non-code
repairs.
The licensee committed (in the request) to replace the non-code
repaired 316L HVH-4 piping during RO 14 and submit to the NRC, a plan and
schedule for permanent repair of the containment penetrations by
September 30, 1991.
After review, the NRC granted the relief request on
January 23,
1991.
When the outage was extended as a result of an
unlatched control rod,
the inspectors verified that delivery dates
associated with the AL6XN elbows made it impractical to make permanent
code repairs to the HVH-4 during this RO.
SW Spills Into Containment and Auxiliary Building
On January 8, 1991, at 9:00 p.m.,
"significant leakage" was identified
coming from an open section of HVH-4 piping, and started flooding the first
level of the CV.
This open piping was caused by the removal of a section
of piping for MIC analysis. As operations was attempting to determine the
source of the water, the leak stopped with no apparent actions having been
initiated to terminate it
(i.e., valve manipulation/source isolation).
Upon evaluation, it was determined that approximately 12,000 gallons had
discharged into the CV sump. The SW system and the HVH-4 unit had been
isolated with proper clearances and drained prior to the piping removal.
An investigation and ACR 91-014 were initiated the next day to determine
the source and/or cause of the leak.
The system had no unisolated
potential leakage paths available that could have accounted for this
volume of water. A subsequent SW leak (see below) revealed the probable
flow path for this spill.
On January 17,
1991, during a SW system line-up for a hydrostatic test,
approximately 1600 gallons of SW leaked into the CV and Auxiliary Building
hallway. This leak occurred when the flange joint downstream of butterfly
6
valve V6-33E was separated, allowing the valve seat to shift out of the
valve. This allowed water to flow by the disc and pressurize the piping
downstream.
When the downstream piping associated with butterfly valve
V6-33D was subsequently opened, a leak path was created, allowing the
water to flow onto the Auxiliary Building floor. Additionally, there was
apparently a vent and drain valve open in the CV in preparation for the
hydrostatic test; thus allowing leakage into the CV.
Operations
subsequently isolated the leak and initiated ACR 91-040 to determine root
cause.
The seat movement associated with valve V6-33E evidently was the root
cause of both the January 8 and 17, spills.
In the January 8 spill, the
V6-33E flange joint was partially opened at a time which corresponds to
spill initiation. The licensee believes that the seat moved during this
event allowing water to flow around the disc and out the open section of
piping.
All the other HVH unit supply SW valves, as well as other SW
system valves, are Allis Chalmers Streamseal resilient seated butterfly
valves.
These valves have quickly changeable seats which are positioned
by the compressive force of the mating flanges.
The phenomenon of the
seat moving, due to water pressure on the upstream side of the seat when
the downstream flange was unbolted,
was unexpected.
The licensee is
performing (through the ACR process) root cause verification, as well as
the scope of and the need for procedural controls to ensure clearance
boundary adequacy in the future.
The inspectors will review the
corrective actions
adequacy
through routine
ACR
monitoring
and
evaluation.
Contamination Protection Practices
On February 10,
1991, the inspectors observed an individual inside the CV
who was not dressed in accordance with the applicable RWP requirements.
The individual was observed wearing a skull cap with her hair exposed;
the applicable RWP,90-637, required a cloth hood.
This condition was
reported to an onshift HP technician inside the CV who had the individual
correct her dress.
In addition, another worker was observed inside the
CV without his gloves taped to his PCs, which is considered a poor work
practice.
This was also reported to an HP technician who had the
individual tape the gloves.
These observations were later discussed with
the E & RC Manager who subsequently sent a memo to the HP Foremen
re-emphasizing the need for HP personnel to set and enforce high standards.
An NCV was issued in IR 90-18 involving failure of a laboratory technician
to dress in accordance with an RWP.
However, there is a dissimilarity
between the 90-18 item and the above RWP violation, in that the laboratory
technician failed to recognize that he needed protective clothing,
whereas,
the RWP violation involved improper dress.
The corrective
actions taken by the E & RC Manager before the end of the inspection
period were deemed appropriate. This violation is not being cited because
0
7
the criteria specified in section V.A of the NRC Enforcement Policy were
satisfied. This item is a NCV: Failure To Follow The Provisions Of A RWP
As Required By PLP-016, 91-01-01.
CV Cleanup
On January 31,
1991, while performing a general area inspection of the
CV,
the inspectors observed debris under two containment fan cooler
units.
The debris included a plastic bottle, two rolls of duct tape,
discarded gloves, a sign, metal tags,
and wads of paper and tape.
The
other two containment fan coolers were not examined.
The inspectors
observed isolated pieces of trash on, under, and behind various pieces of
equipment, panels,
and supports.
Upon exiting the CV, the inspectors
discussed the conditions with an SRO who had made a similar tour earlier
that day. The SRO had also observed the above conditions. These observa
tions were significant, in that, efforts had been in progress for a
minimum of three days to clean up the CV in preparation for restart.
The daily outage schedule for January 30 to January 31,
1991, listed the
final CV walkdown prior to 200 degrees and closeout per PLP-006, Contain
ment Vessel Inspection/Closeout, was to be at 2:00 p.m. on January 31. The
preliminary walkdown by the SRO on that day revealed that the final CV
closeout per PLP-006 was not possible. The resident inspectors also noted
that a partial CV walkdown by the licensee on January 29,
1991,
which
generated a list of 45 items to be addressed prior to CV closeout, had not
identified the debris under the containment fan coolers. The inspectors
discussed their observations with the Plant General Manager concerning
CV cleanliness.
The inspectors were concerned that these observations,
along with those documented in IR 90-05 and 90-12, indicated that the
cleanup inside the CV had not been approached in a thorough and systematic
manner.
Circuit Breaker Identification Aids
On January 18,
1991,
the inspectors observed that outdated circuit
breaker lists were posted inside instrument buss panels 7A and 9A.
The
circuit breaker lists provides information as to the function associated
with each circuit breaker located in a panel.
Subsequent review by both
the inspector and the licensee revealed that the problem also existed in
other instrument buss and power panels.
The method used to maintain
current circuit breaker lists in the panels involved a designated
operations technician receiving a controlled revision to the applicable
procedure containing the list.
He is then responsible for placement of
the revised list inside the panel.
However, in May 1990, the technician,
was inadvertantly deleted from distribution for these revisions.
At the
end of the report period, the current lists had been placed in the panels
and the procedure revision distribution list had been changed to include
the operations technician for distribution of future revisions.
One non-cited violation was identified.
8
3.
Installation And Testing Of Modifications (37828)
Modification M-1016, Electrical Penetration Replacement Testing
During performance of EST-048, Control Rod Drop Test (Refueling Outage),
revision 6, on January 29, 1991, the RPI for RCCA P-6 in control bank B
failed to increase in response to control bank B withdrawal.
However,
the RPI for RCCA D-10 in control bank C did increase in response to
control bank B withdrawal.
Similarly, when control bank C was withdrawn,
RCCA D-10 RPI failed to increase while RCCA P-6 RPI indication increased.
At that time, EST-048 was exited, all control rods were fully inserted,
the reactor trip breakers were opened,
and the rod drive cabinet fuses
were reinstalled.
ACR 91-060 was generated to document and investigate
this anomaly.
Upon investigation, it
was determined that the electrical penetration
through which these RPI cables traverse was changed from Penetration C-2
to E-1 during implementation of modification M-1016, Electrical Penetra
tion Replacement.
The modification had been declared operable on
January 22, 1991. Apparently, during or after modification implementation
the RPI cables for P-6 and D-10 (cable numbers C2078BN and C2079BC,
respectively) were "rolled" or switched. This situation was not detected
during modification implementation,
QC verification, or modification
acceptance testing.
As a result of the modification being declared operable without detection
of the problem,
the adequacy of the acceptance tests specified and
performed was evaluated.
In the case of the RPI cables, the acceptance
test specified was the performance of loop calibration procedure LP-551,
Rod Position Indication System, revision 3. The test was to be performed
in 45 relocated cables. After the rolled leads were corrected, LP-551 was
not performed as expected. Upon further investigation it was determined
that LP-551 had not been performed as required for any of the 45 RPI
cables prior to the modification being declared operable. The maintenance
technicians had initialed the functional test signature blocks as having
been performed, when evidently, the only test performed was a resistance
check of each RPI's cable.
The resistance check could not and did not
identify the rolled leads.
Additionally, the functional tests (LP-251,
Radiation Area Monitors RMS R1-R8) specified for radiation monitors R-2
and R-7 were signed as having been completed. However, this procedure had
been deleted approximately two months earlier and replaced by test
procedure
OST-924,
Radiation Monitoring
System,
neither of which
was performed for the acceptance test. The testing which the technicians
performed cannot be verified.
In addition, there are other examples
within the modification where the testing performed was not the specific
testing specified. The failure of the maintenance technicians to conduct
the functional testing specified in the modification is the first example
of a violation:
Activities Affecting Quality Were Not Performed In
accordance With Procedures And Drawings, 91-01-02.
9
During the review of the testing conducted versus the testing specified
to be performed, it was identified that some functional tests specified in
the modification were not adequate to test the components/cables which
were affected by the penetration replacements. Examples of this included
a specified resistance check as a functional test on approximately 60
temperature elements. The resistance checks performed only verified the
equipment was connected; the tests did not confirm that the resistance
was in fact, at the instrument it should be.
Additionally, LP-551, which
was the functional test specified for the RPIs,
was inadequate to
functionally test individual RPIs.
As such, if the rolled leads were not
identified during performance of a test (EST-048)
unrelated to the modi
fication, these RPI would not have been functionally tested.
There were
additional tests specified in the modification, the adequacy of which were
questionable.
Examples of these questionable tests included PIC-009,
Current/Pressure (I/P) Transducer,
and PIC-401, Valve Positioner, which
were specified as the functional tests for three valves; and OP-202,
Safety Injection and Containment Vessel Spray System,
which only
performs a valve line-up for valve HCV-936.
The failure to adequately
establish tests is a violation: Modification M-1016 Acceptance Tests were
Inadequate, 90-01-03.
There are two concerns associated with these violations.
The first
relates to the inadequate acceptance tests, in that there appeared to be
inadequate reviews performed on the tests' adequacy during the modifica
tion review and approval process.
Modification acceptance testing
adequacy has
been a previous identified concern and this problem
underscores the need for additional efforts in this area.
The second
concern relates to the oversight provided during component/cable functional
testing, in that, the modification was declared operable without the
functional tests specified being performed.
This testing was performed
over a period of several weeks, thus allowing numerous occasions for the
identification of the tests not being performed as specified.
More
interactive oversight may be warranted during modification development,
implementation, and testing.
Two violations were identified.
4. Monthly Surveillance Observation (61726)
The inspectors observed certain safety-related surveillance activities on
systems and components to ascertain that these activities were conducted
in accordance with license requirements.
For the surveillance test
procedures listed below, the inspectors determined that precautions and
LC~s were adhered to, the required administrative approvals and tagouts
were obtained prior to test initiation, testing was accomplished by
qualified personnel in accordance with an approved test procedure, test
instrumentation was properly calibrated, the tests were completed at the
required frequency,
and that the tests conformed to TS requirements.
10
Upon test completion, the inspectors verified the recorded test data was
complete,
accurate,
and met TS requirements; test discrepancies were
properly documented and rectified; and that the systems were properly
returned to service.
Specifically, the inspectors witnessed/reviewed
portions of the following test activities:
EST-004
Isolation Valve Seal Water
EST-006
Containment Spray Nozzles
EST-049
Rod Drive Mechanism Operation Testing
(Refueling Outage)
EST-058
SI-890A And 890B Check Valve Test
OST-163
Safety Injection Test And Emergency
Diesel Generator Auto Start On Loss Of
Power And
Safety
Injection And
Emergency Diesel Trips Defeat
OST-351
Containment Spray System
RHR Pump Flow Test
RHR Pump Flow Test
Service Water Flow Test
Control Rod Drive Mechanism C-07
Testing
OST-351
On January 17, 1991, the inspectors witnessed the performance of OST-351,
Containment Spray System, revision 9.
The test was terminated when
certain relays were not energized as required by OST steps 7.2.13 through
7.2.16.
A review of Safeguards System drawings CP-380-5379-3233,
3235,
and
CWD B-190628 sheets 141,
144,
and 147,
indicated that the relays
should not have been energized. A previously performed step, 7.2.9, had
returned the bistables, which were tripped to cause a containment spray
initiation, to their normal position.
This action reset the indication
signal and removed the power from the relay coils which were to be
verified as energized in steps 7.2.13 through 7.2.16.
It was also
observed that steps 7.2.13, 7.2.14, and 7.2.15 referred to the relays as
KA,
and MA, where as the CWD sheets 141,
144, and
147 referred to these relays as SX1, SX2, and SX2 on panels AA, KA, and
MA, respectively. Review of OST-351, revisions 6 and 7, completed May 28,
1987,
and November 15, 1988, respectively, as well as revision 8 (never
performed) revealed these earlier revisions also contained the step to
reset the bistables to normal prior to performing the relay verification
steps.
Thus, on at least two prior occasions, the procedure steps were
improperly signed as having been satisfactorily completed.
Apparently,
personnel preparing the procedure knew that the steps were to be performed
in response to the containment spray initiation signal and not in the
sequence specified in the procedure (i.e., after the initiation signal
was reset.
Personnel implementing the procedure had performed the steps
as intended, not as written. The fact that on January 17, 1991, I & C
technicians did not sign OST-351 steps 7.2.13 through 7.2.16 as being
satisfactorily completed,
indicated that in the Maintenance unit an
evolving awareness of what constitutes procedure adherence is occurring.
At the same time, however, a licensed operator signed that "both contain
ment spray pumps START"
and selected valves "have OPENED"
and "have
CLOSED" after the containment spray initiation signal was reset.
Since
the steps did not require verification that the pumps remain running or
the valves remain opened or closed; the operator had actually acknowledged
that the actions occurred as a result of the initiation signal reset
verses the initiation signal.
The failure by the operator to recognize
that changes of state of equipment during testing should be attributed to
the step immediately preceding the change of state, unless otherwise
specified, was identified as a weakness in procedure adherence. This was
discussed with the Operations Manager.
On January 18, 1991, OST-351 revision 10, was issued to correct the above
problem (i.e., the actions which occur as a result of the initiation
signal are to be verified prior to resetting the initiation signal).
Revision 10 incorporated additional steps to correct another deficiency
(i.e., the B train MSIV closing solenoid circuits were not being completely
tested).
To address this oversight, revision 10 included steps to verify
that relays SX2, SX1 and SX1 on respective panels JB, FB, and DB energize.
However, with the RTGB control switch in the shut position (the condition
it
would most likely be in due to these steps routinely being performed
when the MSIVs are under clearance) these relays are already energized
and remain energized.
This was recognized by the onshift personnel
preparing to perform the new revision.
Revision 10 was satisfactorily
performed on January 19,
1991, with the notation that relays on panels
JB, FB, and DB are always energized with the control switches in the shut
position. Abnormal Condition Report ACR 91-035 was issued to address the
adequacy of OST-351 to test the MSIV isolation logic.
Revision 11 was
issued and was successfully performed on January 26, 1991, to completely
test the MSIV logic.
The failure to provide adequate steps in revision
10 to test the MSIV logic indicated a weakness in the preparation and
technical review process involved with logic test procedures. Discussion
with the revision 10 procedure preparer revealed that he had only received
on-the-job training involving preparation of, or changes to logic test
12
procedures.
The inadequacy of OST-351 revision 10 to completely test the
MSIV closure logic is a violation:
OST-351, Revision 10 Was Inadequate
In That It Did Not Completely Test The MSIV Logic, 91-01-04.
Another example of a recently issued inadequate procedure change was
temporary change no. 4092 issued to SPP-011, Removal And Restoration Of
SI Actuation.
The temporary change dated January 17,1991, incorporated
steps for a continuity check to be used to verify proper wiring restora
tion.
The steps would not work as written because an indicating light
circuit was in parallel to the circuit being verified.
Another temporary
change dated January 26,
1991,
to SPP-011 was issued and successfully
performed to verify continuity of the restored wiring.
Revision 5 to
SPP-011 was issued on February 16,
1991, to permanently incorporate this
change into the procedure.
Service Water System Flow Test
On January 29,
1991,
a SW system flow test was conducted per SP-1010,
Service Water Flow Test.
The SW system had undergone extensive
repairs/refurbishment and this test was performed to confirm adequate
system performance. The system mode tested was an accident configuration
(i.e.,
two SW pumps running, turbine building SW loads isolated, and
approximately 10,000 gpm circulated through the CCW HXs).
The test
verified that the minimum required SW flow of 564 gpm to each EDG HX
was satisfied.
The flows to the EDG HXs were acceptable and exceeded the
required 564 gpm with and/or without the SWBPs operating (with the SWBPs
operating, the EDG HXs receive less flow).
The KYPIPE computer program
was used to model system configurations and expected resultant flows and
pressures.
The KYPIPE predictied flows and pressures corresponded
similarly with those measured during the test.
Drawing Deficiencies
During review of the OST-351 deficiencies discussed above, the licensee
and the inspectors together identified that logic drawing CP-300
5379-2759,
revision 15,
did not show that a high high containment
pressure containment spray initiation signal would initiate an SI signal
if
RCS coolant temperature is above the low TAVG setpoint.
Safeguard
drawings CP-380-
5379-3232,
3233 and 3235 show that the automatic
containment spray initiation relays AS1 and AS2 energize relays SL1 and
SL2 which energize the safety injection initiation relays SIA1 and SIA2.
This is apparently a backup to the high containment pressure SI
initiation signal.
The inspectors also identified two other drawing discrepancies.
Reactor
Protection System drawing CP-380 5379-3244 revision 12,
showed the
reactor trip contacts in the reactor trip trains A and B being powered
from 125 VDC panel A circuit 10 and panel B circuit 9, respectively.
13
However, drawing CP-380 5379-3243 and 3252 show that the trip contacts
are powered from panel A circuit 18 and panel B circuit 18 via train A
and B terminal strips 5T7.
The licensee has agreed that drawing 3244 is
in error and will revise it. Residual Heat Removal System Flow Diagram
5379-1484 revision 19, did not show that the piping to valve RHR-744A,
the SI Cold Injection Valve, is reduced from 12 to 10 inches. A 12 X 10
inch reducer is shown upstream of the RHR-744B valve.
The licensee is
reviewing this drawing to determine if it should be clarified.
One violation was identified.
5. Monthly Maintenance Observation (62703)
The inspectors observed safety-related maintenance activities on systems
and components to ascertain that these activities were conducted in
accordance with TS,
approved procedures,
and appropriate industry codes
and standards.
The inspectors determined that these activities did not
violate LCOs and that required redundant components were operable. The
inspectors verified that required administrative, material,
testing,
radiological,
and fire prevention controls were adhered to.
In
particular, the inspectors observed/reviewed the following maintenance
activities:
Removing Green Oily Resin And
Replacing Power Wiring In MCCs 5,6,
9, & 10
Secondary Source Inspection And
Recovery
Testing And Latching, Inspection And
Unlatching Of The RCCA At Core
Location C-07
SPP-011
Removal And Restoration Of SI
Actuation
WR/JO 91-ACDK1
Reactor Head Stud Cleaning
Machine Tool Wire
On January 4, 1991,
the B main feedwater stop valve V2-6B,
failed to
close.
Upon investigation poor continuity readings were measured on one
phase of the MCC closing contactor and a clear covering, like nail polish,
was popped off the contact surface.
The valve subsequently cycled
properly. A similar incident involving the need to clean an unidentified
substance from contactors associated with V2-35B, radiation monitor sample
for HVH-2 return isolation valve, had occurred during the preceding week.
14
In neither instance was the removed material retrieved for analysis.
Inspections revealed a green liquid gel in the contactor housings,
but
not on the contact surfaces.
Examination of other 208 and 480V MCCs
revealed that most compartments exhibited green liquid migration out of
the power conducting internal wiring of the MCCs.
Initial evaluation revealed that the green liquid appeared to be a
vegetable oil plasticizer used in the PVC covered wire. The wire was black
in color and marked as machine tool wire -
105 degrees C.
Subsequent
analysis indicated that the green liquescent material is a conductor when
in a liquid/gel form but may be a conductor or insulator when dried;
dependent upon the amount of copper oxide salts dissolved in the material.
The liquid may range in color from light green (almost clear in thin
films) to dark green, also depending on the amount of dissolved copper
oxide salts.
The licensee determined that the above mentioned valve
failures were most likely due to the plasticizer migrating onto one or
more of the contactor contacts.
The licensee's inspection of Class
1E MCC
compartments revealed the
presence of the green material in most compartments.
The only use
identified for machine tool wire was to connect the breaker to the
The effected MCC compartments are size 1 compartments
manufactured by Westinghouse around 1962.
The wire is commercial grade
AWG #12 wire supplied under industry standards in effect at that time.
Westinghouse obtained wiring from several different vendors during the
early 1960s.
Records review to date has not identified the manufacturer
or manufacturers of the machine tool wire. In the late 1960s, Westinghouse
discontinued use of this wire and began use of wire with a different
insulating material.
The licensee developed and implemented SP-1005 to replace the machine
tool wire with surprenant wire and cable type CL-1251 XLPE 600V wire and
to clean the contactors in 111 compartments of MCCs 5, 6, 9, and 10.
Since the green material was also observed in non-safety related MCCs,
plans were being developed to replace the machine tool wire and clean
these affected compartments during RO 14.
The inspectors verified via
examination of all compartments on MCC 6 and 9, that the wire was not used
in other applications.
The inspectors also looked inside reactor protec
tion and safeguard cabinets and instrument buss and power panels. Again,
no other use of the wire was discovered.
Fuse Control
On January 16,
1991,
while witnessing performance of OST-163,
the
inspectors observed that the installed A SI pump control power fuse was a
Bussman Type F61C 30 AS fuse. The similar fuse associated with C SI pump
was a Bussman F61C 10 AS fuse.
Control wiring diagram B-190628 sheets
237, revision 14, and 239, revision 12, required 10 ampere fuses to be
15
installed in the A and C SI pump 125 VDC control circuits respectively.
The licensee verified that the fuse installed in the A SI pump circuit
was a 30 ampere fuse. Since there were no replacement 10 ampere fuses in
stock, the fuse from the C SI pump circuit was placed in the A SI pump
circuit.
The C SI
pump has been offsite for casing repairs since
mid-1989.
Procedure OST-163 was subsequently successfully performed,
thus ensuring the circuit would perform correctly with the lower ampere
fuse installed.
The inspectors verified that the correct fuse size was
installed in six other randomly chosen emergency buss El and E2 breaker
control circuits. Other discrepancies were not identified. The licensee
has subsequently verified that other fuses installed in El and E2 breaker
control circuits are in accordance with the CWDs.
Failure to have the
size fuse specified on the CWD installed is a second example of violation
91-01-02.
The inspectors also noted that numerous CWDs did not specify fuse sizes.
Furthermore,
few safety-related CWDs specify a specific kind or type of
fuse.
A fuse schedule which provides sizes, acceptable types,
and
manufacturers for fuse applications did not exist. The licensee has been
controlling fuses by replacement-in-kind or by engineering evaluations if
a replacement-in-kind fuse was unavailable.
However, design information
involving what fuse attributes are taken credit for in circuit protection
or coordination are not always available.
Some circuits such as those
associated with Appendix R coordination
have design calculations
available.
The licensee was developing a fuse control program to address
these issues. The present status of the licensee's effort include:
o
Design guide for fuse selection criteria was in draft
o
Identification of calculations which need to be performed to support
coordination and/or protection should be completed by Spring 1991.
Scheduling of presently identified calculations was in progress
o
A fuse schedule which will provide acceptable size, types,
and
manufacturers for each application was being planned.
An initial
fuse schedule with known, verified information for most DC fuses and
some AC fuses was planned to be issued this fall
The above three items are considered an IFI: Review Fuse Control Program
Development And Implementation, 91-01-05.
DC Fuses
Concerns were raised at the Harris Nuclear Plant involving possible
misapplication of fuses in DC circuits.
The concerns involve applying
voltage and interrupting current ratings of either AC fuses to DC
circuits or
DC fuses to higher than specified DC voltages without
16
consulting the manufacturer.
On January 25 and 26,
1991,
a licensee
field walkdown identified the manufacturer and type of approximately 350
fuses installed in primary 125 VDC circuits.
Engineering calculations were performed to identify the maximum fault
current available for each fuse type at the pertinent sections of the 125
VDC distribution system.
The fuse types, ratings,
and maximum fault
currents were submitted to the manufacturers for evaluation. As a result
of this process, eleven circuits were identified for which the existing
fuses were replaced. The functions associated with these circuits are:
o
Batteries A and B DC MCCs undervoltage monitoring (2 circuits)
"
PZR safety valve flow monitoring (2 circuits)
o
Condensate pump B and Feedwater pumps A and B ERFIS status (3
circuits)
o
HVH-1,2,3, and 4 vibration and flow monitoring (4 circuits)
The HVH vibration and flow monitoring circuits had 32 V fuses installed
in 125 VDC applications.
The other fuses contained in the above circuits
were suspect per the vendor as a result of the concerns raised at the
Harris Nuclear Plant.
Engineering evaluation EE 91-030 indicated that the inspection, while
not a complete inspection, did represent the majority of DC fuses
installed.
Based upon the limited number of problems identified, EE 91-030 concluded that additional fuse inspections, necessary to complete
a DC fuse list, could be performed as plant conditions permit and are not
required prior to startup from RO 13.
The licensee presently plans to complete inspection of the installed DC
fuses by the end of RO 14.
This information will be incorporated into
the fuse schedule being developed as one element of the fuse control
program discussed above.
MCC Inspection
During Class 1E MCCs 6 and 9 compartment inspection, the inspectors
observed various abnormal conditions.
These included: V-749B compartment
thermal overload reset button was missing and control power transformer
was bolted on the same side, thereby allowing the transformer to move on
its attachment bracket; SI-845B compartment bucket top latching mechanism
was open; V6-33C,
V6-33D,
V6-33F,
V6-35B,
V6-35D,
V2-16C
and V-749B
compartments had one or both bucket bottom alignment/attachment screws
not engaged; and V2-20A control power circuit contained a Bussman BAF 3
fuse.
The inspectors observed that V2-20B compartment contained a
17
Bussman BAF 1 fuse.
The licensee was informed of these conditions. The
licensee determined that either the 1 or 3 ampere fuse size was
acceptable for the application; however, for consistency, the fuses will
be changed so that the same size will be used for similar applications.
A second example of a violation was identified.
6. Onsite Review Committee (40500)
The inspectors evaluated certain activities of the PNSC to determine
whether the onsite review functions were conducted in accordance with TS
and other regulatory requirements.
In particular, the inspectors
attended
PNSC meetings on January 30 and February 7, 1991, involving
plant status review prior to exceeding 200 degrees and a procedure change
to allow head lift
under existing plant equipment conditions,
respectively. It was ascertained that provisions of the TS dealing with
membership, review process, frequency, and qualifications were satisfied.
No violations or deviations were identified.
7. Followup (92709, 92701, 92702)
(Closed) LER 88-07, HVH-2 Breaker Failed To Close On Safeguard Sequence
During Performance Of Special Test.
On February 12,
1988, during
performance of a special test while in cold shutdown, containment fan
cooler HVH-2 failed to start during the safeguards sequence.
Licensee
investigation revealed that the breaker, a Westinghouse model DB-50, did
not close because of a faulty alarm switch located in the closing circuit
of the breaker.
Apparently, oxidation buildup on the alarm switch
contacts was the root cause of the breaker not closing.
The licensee
subsequently checked alarm switches on other emergency switchgear supply
breakers, and found 11 additional switches that had intermittently high
contact resistance readings.
These switches were replaced.
Interviews
with the Manager-Electrical Systems (Technical Support) indicated that
the preventative maintenance procedure for DB-50 breakers,
revision 5, Circuit Breaker Inspection and Testing, requires the alarm
switches to be replaced every fifth refueling outage.
Furthermore, the
inspector was informed that alarm switches which had not been replaced
todate will be replaced during the next refueling outage, and PM-402 will
be revised accordingly.
In addition, the licensee contacted the vendor
regarding testing the alarm switches.
The vendor indicated that there
was not a criteria for such a test, and alarm switch failures were not a
widespread problem. A successfully cycling of the breaker, as is done
during maintenance and surveillance testing of associated equipment, is
the best functional test of the alarm switches. This item is closed.
(Closed)
LER 88-08, Operation In Violation Of Technical Specifications
Due To Analytic Input Error. This issue involved an error in fuel cycle
12 analytic factor decks used to process in-core detector measurements
18
and to monitor compliance with TS
thermal-peaking limits.
ANF
Corporation notified the licensee (NFS)
of the error (assignment of
incorrect isotopic data to a reinsert assembly) on March 24, 1988. Flux
map reevaluations using corrected analytic factor decks indicated that
allowable power level while operating with a 5 percent delta flux target
band should have been 99.98 percent instead of the 100.22 percent
originally calculated.
To ensure peaking factor conformance,
TS 3.10.2.2.2 requires the use of the APDMS when power levels exceed the
allowable power level.
Consequently,
subsequent review identified
operations during June 29 through August 12,
1987, as being nonconserva
tive (i.e., delta flux target band greater than 3 percent and APDMS was
not in use).
However,
because of inherent conservatism in ANF's power
distribution control methodology (PDC-II), subsequent analysis was able to
demonstrate that the plant did not operate in an unsafe condition.
The
inspector considers the
additional in-core deck checkout reviews now
being conducted by NFS,
as well as those actions taken by ANF to
strengthen related internal performance and activities to be appropriate.
Somewhat related, the inspector notes that IR 90-23 addressed an ANF LOCA
computer code error which was reported by the licensee on October 23,
1990.
Consequently, generic ANF concerns will be addressed during the
followup of this more recent event under URI 90-23-01.
LER 88-08 is
considered closed.
(Closed)
LER 88-19, Inoperable Containment Fan Coolers Due to Biological
Fouling.
On September 5, 1988,
the licensee notified the NRC of a
four-hour non-emergency event due to inoperable containment fan coolers.
The licensee found that a significant amount of biological fouling had
taken place in the cooling coil tubes.
The fouling resulted in the tube
inner diameter being reduced and caused the heat removal capability of
the coolers to be reduced under Design Basis Accident conditions.
The
licensee also found that the four fan motor coolers were also fouled in a
similar manner.
Immediate corrective actions included cleaning out the
heat exchangers, inspection of the tubes, and hydrostatic testing of the
tubes.
An assessment of the event and a root-cause evaluation determined
that due to lack of a performance monitoring program and lack of flow
(during the long steam generator outage in 1984) the tubes became fouled.
To prevent recurrence, the licensee implemented plant modification M-968
which installed RTDs and differential pressure instruments as performance
monitoring instrumentation on HVH-4.
The instrumentation allows HVH-4
performance to be monitored, thereby providing detection capability for
potential degradation of equipment due to biofouling.
A side-stream
monitor was also installed to allow for close monitoring and observation
of biological growth inside piping and coolers.
Additionally, a
chlorination process was installed to treat the entire service water
system to help prevent biofouling.
Instrumentation similar to that
installed on HVH-4 were installed on HVH-1,
2, and 3, during RO 13.
Inspections of two
HVH units,
performed during RO
13, revealed no
19
evidence of biofouling.
Based on over two years of successful operation
the licensee's long-term corrective actions have proven effective in
preventing biofouling of the HVH units and associated motor coolers.
This item is closed.
(Closed)
LER 88-26,
Inadvertent Safeguards Actuation.
On November 14,
1988, the plant was in cold shutdown for refueling when a safeguards
actuation was received from an inadvertent SI signal.
The licensee's
investigation revealed that the pressurizer SI block permissive was
removed when licensee staff de-energized two of three reactor protection
channels as part of a plant modification.
This safeguard actuation did
not result in an actual injection into the reactor coolant system; the
breakers to the safety injection pumps were open and the discharge valves
were closed and de-energized.
Remaining safeguards equipment functioned
as designed.
The licensee's root cause investigation indicated that
there were inadequate procedural precautions to ensure that safeguards be
de-energized prior to removing two of three reactor protection channels.
In addition, the licensee indicated that there was some miscommunication
between the operations coordinator and the clearance center operators, in
that, only a partial breaker lineup was required, yet a full breaker
lineup was initiated resulting in the inadvertent Safeguards actuation.
The intended partial breaker lineup would have prevented the inadvertent
SI signal.
Corrective actions included discussions between licensee
staff, revisions to applicable procedures, and the placement of operator
aids in the control room and on the DC breakers which supply the
Safeguards System.
The inspector held discussions with operations
personnel,
reviewed OST-163 revision 15,
Safety Injection Test,
and
Emergency Diesel Generator Auto-Start on Loss of Power and Safety
Injection and Emergency Diesel Trips Defeat (Refueling), and viewed the
operator aids.
At the time of the inspection, there were no inadvertent
SI actuations since the one reported in the subject LER. The corrective
actions taken by the licensee were deemed adequate by the inspector.
This item is closed.
(Closed)
LER 89-01, Hydrogen Introduced Into The Instrument Air System.
This event is addressed in this section under the closure of URI 88-38-02.
(Closed)
LER 89-02, Failure OF Fast Response RTD Thermowells.
This item
was not required to be reported per 10 CFR 50.73.
However, a voluntary
LER was filed because the event could be of interest to the industry and
the NRC.
Followup inspection is being tracked as IFI 89-07-02.
Hence,
because the LER is redundant to IFI 89-07-02,
the LER is considered
closed.
(Closed) LER 89-03, Licensee-Identified Violation Of 10 CFR 20.101 Due To
Incomplete Contract Employee Forms NRC-4. The subject item was inspected
and closed in IR 89-28 as IFI 89-FRP-01.
20
(Closed) LER 89-06, Reactor Trip Due To Loss Of Turbine E-H Control Power
Supplies.
Prior to restart from the reactor trip the inspectors verified
that equipment repairs and protective circuitry setting adjustments were
completed as described in the LER.
During RO 13, Modification M-1046,
Replacement of E-H Power Supplies, was installed to replace the original
equipment.
Originally, electronics for the EHC system were powered from
two power supplies.
Each power supply provided -15 VDC, +15 VDC, and +48
VDC.
The modification replaced each unit with three individual power
supplies, one for each voltage requirement.
This new configuration
eliminated the cascading failure mode which initiated the reactor trip.
With installation of M-1046, the corrective actions described in the LER
has been completed. This item is closed.
(Closed)
LER 89-08, Potential Loss Of Residual Heat Removal Capability
Due To Pump Flooding.
Inspection Report 89-09,
dated June 26,
1989,
issued an NOV involving this matter.
Followup of LER 89-08 will be
incorporated into the inspection of the VIO, 89-09-05, hence LER 89-08 is
considered closed.
(Closed)
LER 90-11, Technical Specification Violation Due To Inoperable
Fire Barrier Penetration (Fire Damper).
The licensee was unable to
determine when or how the fire damper was mispositioned. The inspectors
verified that the corrective action specified in the LER had been
completed.
This action was to place a permanent label on the damper
access door to inform personnel that the damper is to remain closed.
The
label reads "STOP Damper 77 is a closed damper -
Do not open 77".
This
should preclude future inadvertent opening. This item is closed.
(Closed)
IFI 88-03-03, Subcooling Margin.
The subject item concerned
failure to establish a basis for deviating from the recommended values in
the WOG ERG when end path procedures were developed. Subsequently, a EOP
inspection identified this as a general concern involving not only this
specific item, but numerous other examples.
This general concern was
identified as IFI 89-16-01.
Followup of IFI 88-03-03 disclosed that a
calculated basis for the deviation was still scheduled to be performed. A
statement was contained in the generic analysis applicability document,
dated October 29, 1990, which indicated the values used were bound by the
generic documents.
However, not having the calculation performed to
support the values used in the procedures and not having this documented
in the setpoint document by September 28,
1990, was a failure to meet a
commitment identified in the Response To NRC Inspection Report No.
50-261/89-16 dated December 8, 1989. The licensee has agreed to submit a
revised response providing a date when this calculation and others which
may not yet be completed, will be completed and incorporated into the
setpoint document part of the PSTG.
Followup will be performed under
IFI 89-16-01, hence the subject item is closed.
(Closed) IFI 88-06-01, Review Inadvertent Shipment Of Contaminated Liquid
To Quadrex.
On February 24, 1988, the licensee made a shipment of two
Sea/Land containers to the Quadrex Recycle Center in Oak Ridge,
21
Although the shipping papers identified the physical form of
the enclosed material as being a solid, approximately nine gallons of
liquid had unknowingly been shipped.
This issue was subsequently
reviewed by a regional radiation specialist and violation 88-28-10 was
identified for failure to indicate proper physical form of material on
shipping papers.
As this was a violation of minor safety/environmental
concern for which adequate corrective actions had been taken, it was both
cited and closed in IR 88-28.
Consequently, IFI 88-06-01 is also
considered closed.
(Closed)
IFI 88-28-05,
Licensee To Develop Methodology To Detect
Biological Growth in HVH 1-4. The licensee has installed a computer-based
fouling monitoring system which monitors the heat transfer resistance and
fluid frictional resistance in a section of tubing which is representative
(size and alloy composition) of the tubing in the HVH units.
If fouling
should occur, both heat transfer resistance and fluid frictional resistance
should rise.
The inspector conducted interviews with the HVAC and SW
system engineers who indicated that the fouling monitor system, while not
calibrated against traceable standards,
does provide an indication of
biofouling. This was validated during RO 13 when the section of tubing
was cleaned and reinstalled.
Original data was then compared to data
obtained after the test section was cleaned.
This data indicated that
there was a slight positive change following cleaning, which indicated
that some fouling had taken place in the two years the test section was
interposed in the SW sidestream. However, visual examination of the test
section revealed fouling was not evident.
In addition to sidestream
monitor,
the licensee has implemented
SW chlorination,
and monthly
performs EST-102,
Performance Testing of HVH-4 Reactor Containment Fan
Cooling Unit.
The licensee considers this test to be representative of
the other three HVH units.
Instrumentation installed during RO 13 on the
HVH-1, 2, and 3 will enable the licensee to perform performance testing on
these HVH units.
The licensee is revising EST-102 to incorporate this
change.
At the time of the inspection, no unsatisfactory results have
been obtained.
In addition, inspection performed of two HVH units
revealed no fouled tubes.
This item is closed.
(Closed)
IFI 88-38-03,
Review Selection Methodology,
Adjustment,
And
Testing Of M-939 Breaker Setpoints.
The subject modification (M-939)
involved the replacement of MCPs in safety-related MCCs 5,6,9, and 10 in
order to correct coordination problems.
As discussed in IR 88-38, the
MCPs being installed under M-939 were experiencing trip setpoint anomalies,
requiring substantial adjustment from their calculated setpoints.
Investigation into the matter determined that unrecognized limitations in
the Westinghouse MCP setpoint application guide and personnel errors
during preparation/review of M-939,
resulted in an inadequate margin
between locked rotor current and the MCP setpoint. Accordingly, more than
20 MCPs required upgrading to a larger size and approximately 120 required
new setpoints. The inspector reviewed the completed modification package,
including the design change notices (DCNs 939-19,
21, 22, and 24) which
22
accomplished said rework, and verified the MCPs were subsequently tested
prior to plant heatup above 200 degrees F. Actions taken with respect to
identified casual factors (addressed in both SCR 89-07 and NCR 89-05)
were also reviewed and found to be appropriate. This item is closed.
(Open)
IFI 89-16-01,
Develop A New PSTG.
During inspection of IFI
88-03-03, the inspectors observed that IFI 89-16-01 had been considered
as satisfactorily completed by the licensee and was listed as closed in
the regulatory action item tracking system.
The inspectors were
concerned about the circumstances surrounding closure of IFI 89-16-01
when prior to this closure, outstanding work had been identified which
was to be incorporated into the setpoint portion of the PSTG.
This item
remains open as described in closeout of IFI 88-03-03.
(Closed) IFI 88-28-01, Establish of EQ Lifetimes Inside CV Based Upon
Actual
Temperature Conditions.
Temperatures
used to calculate EQ
lifetime of equipment in the CV were based on bulk average temperature in
the CV.
There were concerns that this bulk average temperature was not
representative of actual temperatures in the immediate vicinity of EQ
equipment.
Procedure SP-797,
Special Procedure for Monitoring CV
Temperature,
was performed to define the CV temperature profile.
The
actual temperatures inside the pressurizer cubicle were much higher than
the bulk average temperature in the CV.
As a result, the qualification
lifetimes of EQ limit switches and solenoid valves were exceeded.
The
licensee has implemented a satisfactory PM schedule to change these
components. This item is closed.
(Closed) URI 88-28-06, Review LER 88-21 And CV Operability Requirements
After Opening Of CV Purge Exhaust Valves. This item concerned the events
associated with the September 22,
1988 reactor shutdown which was
prompted by leaking CV purge exhaust valves V12-8 and V12-9.
The cause
of the leakage,
subsequent inspection/repair activities, and related
corrective actions were adequately addressed in LER 88-21, which was
closed in IR 90-12.
With regard to operability requirements,
the TS
requires valves V12-8
and V12-9 to be closed whenever containment
integrity is required except when purging for safety-related reasons.
Accordingly,
by design the valves will automatically open/shut upon
initiation/securing containment purge fans. To verify system alignment
control,
the inspector reviewed OP-923,
Containment Integrity,
and
Penetration Pressurization System.
From this review,
it
was
confirmed that whenever containment integrity is required,
requires valves V12-8 and V12-9 to be operable (i.e.,
capable of
automatic closure) and OP-912 requires the valves' associated PPS header
to be in service.
Furthermore, OP-912 specifies that PPS header pressure
must be maintained above 42 psig or hot shut down must be achieved within
8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, followed by cold shutdown within the next 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
To assure
proper air pressurization occurs between the valves once a CV purge is
23
secured, section 8.1 of OP-921,
Containment Air Handling, requires PPS
header pressure to be specifically verified. Consequently, the inspector
had no further concerns. This item is closed.
(Closed)
URI 88-28-08, Followup On Actions To Address Equipment Affected
By An Increased CV Submergence Level.
This item was also the subject of
LER 88-022 and supplement 1 to LER 88-022.
The LER was inspected and
closed in IR 89-26.
During this review, the inspector questioned the
qualification of repairs made to penetration F-011 cables.
These items
are being tracked as URI 89-26-02 and 89-26-03.
Thus, URI 88-28-08 is
redundant to these items, and is considered closed.
(Closed)
URI 88-38-02,
Review Hydrogen Event Report, Associated Root
Cause And Corrective Actions.
This item concerned the intrusion of
flammable concentrations of hydrogen into station and instrument air
systems due to personnel error while conducting a main generator air
tightness test on January 6 -
7, 1989.
Specifically, personnel
performing the test inadvertently cross connected plant air systems to
the hydrogen supply for the main generator's cooling system.
Considering
the potential impact this test had on safety-related systems and the fact
that it
was being accomplished without a written procedure, a violation
was issued accordingly on April 6, 1989
(EA
89-02).
The licensee's
corrective actions (addressed in the May 8, 1989 response to the
violation and
LER 89-01)
included:
(1) revising OP-507,
Generator
Hydrogen System, to provide written instructions for conducting a main
generator air tightness test and to ensure proper clearance on the bulk
hydrogen supply; and (2) revising OMM-005, Clearance and Test Request, to
specifically set the bounds on what actions can be taken within a
clearance boundary, as well as delineating how the introduction of fluids
(gas
or liquid) and
system restoration is to be accomplished by
Operations.
Based on a review of the implemented procedure revisions, as
well as,
the Main Generator Air Test Procedure (Section 8.6 of OP-507)
which was successfully completed in December 1990, corrective actions are
considered appropriate to preclude recurrence of this event.
This item
is closed.
(Closed) VIO 89-03-02, Restoration Lineup Of OST-163 Results In BIT Inlet
Valve Being In A Position Other Than That Established For OST-162.
The
inspectors reviewed the licensee's response dated May 5, 1989, to the
NOV.
The inspector verified that OST-162 and OST-163 was revised prior
to their performance during RO 13 as committed.
The revision involved
combining OST 162 and OST-163 into one procedure designated as OST-163.
This corrective action is considered adequate to preclude repetition.
This item is closed.
No violations or deviations were identified.
24
8. Exit Interview (30703)
The inspection scope and findings were summarized on February 25,
1991,
with those persons indicated in paragraph 1.
The inspectors described
the areas inspected and discussed in detail the inspection findings
listed below and in the summary.
Dissenting comments were not received
from the licensee.
Proprietary information is not contained in this
report.
Item Number
Description/Reference Paragraph
91-01-01
NCV -
Failure To Follow The Provisions
Of A RWP As Required By PLP-016
(paragraph 2)
91-01-02
VIO - Activities Affecting Quality
Were Not Performed In Accordance With
Procedures And Drawings In That
Modification Testing Was Not Performed
AS Specified And An Incorrect Sized
Fuse Was Installed (pragraphs 3 and 5)
9 1-01-03
VIO - Modification M-1016 Acceptance
Tests Were Inadequate (paragraph 3)
91-01-04
VIO -
OST-351 Revision 10 Was
Inadequte In That It Did
Not
Completely Test The MSIV Logic
(paragraph 4)
91-01-05
IFI - Review Fuse Control Program
Development
And
Implementation
(paragraph 5)
9. List of Acronyms and Initialisms
Alternating Current
ACR
Adverse Condition Report
As Low As Reasonably Achievable
ANF
Advanced Nuclear Fuels
ANSI
American National Standards Institute
APDMS
Axial Power Distribution Monitoring System
American Society of Mechanical Engineers
AVG
Average
BIT
Boron Injection Tank
C
Centigrade
Component Cooling
25
Component Cooling Water
CFR
Code of Federal Regulations
Carolina Power & Light
cpm
Counts Per Minute
CV
Containment Vessel
CWD
Control Wire Diagram
Direct Current
DCN
Design Change Notice
Enforcement Action
E & RC
Environmental and Radiation Control
e.g.
For Example
E-H
Electo-hydraulic
Emergency Action Level
EE
Engineering Evalution
EQDP
Environmental Qualification Documentation Package
ERFIS
Emergency Response Facility Information System
EST
Engineering Surveillance Test
F
Fahrenheit
Hand Control Valve
gpm
Gallons Per Minute
HE & EC
Harris Energy and Environmental Center
Health Physics
HVH
Heating Ventilation Handling
Hx
Heat Exchanger
Instrumentation & Control
IFI
Inspector Followup Item
IR
Inspection Report
JCO
Justification For Continued Operation
LCO
Limiting Condition for Operation
LER
Licensee Event Report
Loss Of Coolant Accident
Loop Calibration Procedure
M
Modification
Motor Control Center
Motor Circuit Protector
Microbiologically Induced Corrosion
Non-Conformance Report
Non-cited Violation
Nuclear Fuels Section
NI
Nuclear Instrumentation
NRC
Nuclear Regulatory Commission
OMM
Operations Management Manual
OP
Operations Procedure
PC
Protective Clothing
26
Process Instrument Calibration
PLP
Plant Program
Preventive Maintenance
PNSC
Plant Nuclear Safety Committee
Penetration Pressurization System
Psig
Pounds Per Square Inch -
Gage
PSTG
Plant Specific Technical Guideline
PZR
Pressurizer
Quality Control
RCCA
Rod Control Cluster Assembly
Refueling Outage
Rod Position Indication
Resistence Temperature Detector
Reactor Turbine Generator Board
Radiation Work Permit
Significant Condition Report
Spent Fuel Pool
Safety Injection
Special Procedure
SPP
Special Process Pocedure
Senior Reactor Operator
SWBP
Service Water Booster Pumps
TAVG
Temperature Average
TS
Technical Specification
Unresolved Item
V
Voltage
VAC
Volts Alternating Current
VDC
Volts Direct Current
Violation
WR/JO
Work Request/Job Order