ML14191B125
| ML14191B125 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 06/08/1989 |
| From: | Dance H, Garner L, Jury K NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML14191B123 | List: |
| References | |
| 50-261-89-09, NUDOCS 8907100036 | |
| Download: ML14191B125 (16) | |
See also: IR 05000261/1989009
Text
9REG,
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report No.:
50-261/89-09
Licensee:
Carolina Power and Light Company
P. 0. Box 1551
Raleigh, NC 27602
Docket Np.:
50-261
License No.: DPR-23
Facility Name: H. B. Robinson
Inspection Conducted: April 18 -
May 10, 1989
Inspectors:
L. W. Garner, enior Resid
In ector
Date Signed
K. R Jury,Zsident In pectotfDtSg~
Approved by:
/
K. C. Dance, Section Chief
Ddte"Signed
Division of Reactor Projects
SUMMARY
Scope:
This routine, announced inspection was conducted in the areas of operational
safety verification, surveillance observation, maintenance observation, onsite
followup of events, and onsite review committee activities.
Results:
Two violations were identified:
(1) failure to incorporate residual heat
removal design basis leakage into specifications, drawings, and procedures
following a change to the source term, paragraph 5.a; and (2) an inadequate
technical review resulted in End Path Procedure EPP-10 not containing a
precaution concerning potential safety injection pump runout with one pump
injecting into two reactor coolant hot leg loops, paragraph 2.b.
A weakness in Fuel Handling Procedure FHP-003 was observed in that an acceptance
criteria was not provided on a detachable data sheet, paragraph 2.a.
An operational weakness was observed in that an instrument channel associated
with the reactor protection system was assumed to be operable without conducting
an investigation into the reason for momentary bistable actuations, paragraph 2.c.
90C7100036. 8906.24.
ADOC 000026.1
FDC
2
Determination that EDG fuel injectors require rebuilding during the next
refueling outage is considered an example of a good predictive maintenance
program, paragraph 3.
Retrieval activities associated with a fuel assembly dropped in the spent fuel
pool was well planned, paragraph 5.b.
REPORT DETAILS
1. Licensee Employees Contacted
R. Barnett, Mainte nance Supervisor, Electrical
R. Chambers, Engineering Supervisor, Performance
D. Crocker, Supervisor, Radiation Control
- ~D.
Crook, Senior Specialist, Regulatory Compliance
- J. Curley, Director, Regulatory Compliance
C. Dietz, Manager, Robinson Nuclear Project
R. Femal, Shift Foreman, Operations
W. Flanagan, Manager, Design Engineering
- W.
Gainey, Supervisor, Operations Support
- E. Harris, Director, Onsite Nuclear Safety
D. Knight, Shift Foreman, Operations
D. McCaskill, Shift Foreman, Operations
R. Moore, Shift Foreman, Operations
- R. Morgan, Plant General Manager
D. Myers, Shift Foreman, Operations
M. Page, Acting Manager, Technical Support
- D. Quick, Manager, Maintenance
D. Seagle, Shift Foreman, Operations
J. Sheppard,,Manager, Operations
- R. Smith, Manager, Environmental & Radiation Control
R. Steele, Acting Supervisor, Operations
- H. Young, Director, Quality A-ssurance/Quality Control
Other licensee employees contacted included technicians,
operators,
mechanics, security force members, and office personnel.
- Attended exit interview on May 17, 1989.
Acronyms and initialisms used throughout this report are listed in the
last paragraph.
2. Operational Safety Verification (71707)
The inspectors observed licensee activities to confirm that the facility
was being operated safely and in conformance with regulatory requirements,
and that the
licensee management control
system was effectively
discharging its responsibilities for continued safe operation.
These
activities were confirmed by direct observations, tours of the facility,
interviews and discussions with licensee management
and personnel,
independent verifications of* safety system status and limiting conditions
for operation, and reviews of facility records.
Periodically, the inspectors reviewed shif t logs, operations records, data
sheets, instrument traces, and records of equipment malfunctions to verify
operability of. safety-related equipment .and compliance with TS.
Specific
2
items reviewed include control room logs, operating orders, jumper logs,
and equipment tagout records. Through periodic observations of work in
progress and discussions with operations' staff members, the inspectors
verified that the staff was knowledgeable of plant conditions; responding
properly to alarm conditions; adhering to procedures and applicable
administrative controls; and was aware of equipment out of service,
surveillance testing,
and maintenance activities in progress.
The
inspectors routinely observed shift changes to verify that continuity of
system status was maintained and that proper control room staffing
existed. The inspectors also observed that access to the control room was
controlled and operations'
personnel were carrying out their assigned
duties in an attentive and professional manner.
The control room was
observed to be free of unnecessary distractions. The inspectors performed
channel checks and reviewed component status and safety-related parameters
to verify conformance with TS.
During this reporting interval, the inspectors verified compliance with
selected LCOs. This verification was accomplished by direct observation
of monitoring instrumentation, valve positions, switch positions, and
review of completed logs and records.
Plant tours were routinely conducted to verify the operability of standby
equipment, assess.the general condition of plant equipment, and to verify
that radiological controls, fire protection controls and equipment tag out
procedures were being properly implemented.
These tours verified the
following:
the absence of unusual fluid leaks; the lack of visual
degradation of pipe, conduit, and seismic supports; the proper positions
and indications of valves and circuit breakers; the lack of conditions
-which could invalidate
EQ;
the operability and calibration of
safety-related instrumentation; and the operability of fire suppression
and fire fighting equipment and emergency lighting equipment.
The
inspectors also verified that housekeeping was adequate and areas were
free of unnecessary fire hazards and combustible materials.
In the course of the monthly activities, the inspectors included a review
of the licensee's physical security and radiological control programs.
The inspectors verified by general observation and perimeter walkdowns
that measures taken to assure the physical protection of the facility met
current requirements. The inspectors verified station personnel adhered
to radiological controls.
a. Procedure Data Sheet Does Not Provide Acceptance Criteria
During movement of spent fuel into the DSC on April 25, 1989, a
procedure weakness was noted by the inspectors.
Step 8.2.3 of
FHP-003,
revision 5, Fuel Assembly Movement in the Spent Fuel Pit,
requires hourly monitoring and recording of relative humidity on
attachment 9.2.
Neither step 8.2.3, nor attachment 9.2, provides
an acceptance criteria and actions to be taken if
the humidity
3
acceptance criteria is exceeded.
This information is provided in
section 6.0, Precautions and Limitations.
Paragraph 6.16 of this.
section states that relative humidity shall not exceed 70% during
movement of new or spent fuel.
The 70% limitation is contained in
the basis of TS, and hourly monitoring is required per TS 4.12.3.
The inspectors observed that: attachment 9.2 had been detached from
FHP-003 and that section 6.0 was not located in the spent fuel pool
area.
Subsequent to fuel movement, the inspectors inquired of an
operator, the reasoning and basis for recording the humidity
measurements. The operator completing the procedure was aware of the
70% limitation. Not providing an acceptance criteria on a data sheet
which may be removed from the document containing the acceptance
criteria constitutes a weakness in the procedure system.
b. Emergency Procedure Did Not Address SI Pump Runout
On April 4, 1989, the inspectors observed that EPP-10, Transfer to
Hot Leg Recirculation, revision 2, step 3 required both hot leg
injection valves, SI-866A and B, be opened.
Opening SI-866A and B
allows flow into the C and B RC hot leg loops, respectively.
Step
4.6 required two SI pumps be started as available. OST-154, revision
11, Safety Injection System High Head Check Valve Test, contains the
following precautions and limitations:
(1) Do not allow one SI pump to runout beyond 600 gpm or below 500
psig discharge pressure.
(2) At any time that only one SI pump is operating, one of the two
injection headers (cold leg or hot leg) must be isolated to
avoid possible pump runout.
(3) When running flow tests on the SI pumps (discharging to the
system during refueling operations) use only one hot leg path
when operating a single pump.
Two hot leg paths may be used if
two or more SI pumps are operating.
It appears that these statements are based upon a Westinghouse report
entitled Safety Injection System Test Evaluation, issued June 1974.
The report indicates that testing of one SI pump with both hot leg
valves open was "omitted since pump runout flow exceeded allowable
limit".
EPP-10 authorizes operation with only one SI pump without
precautions for potential runout. One reason for EPP-10 revision in
September 1988, was to address that use of one SI pump is an allowed
configuration in some cases.
An inadequate technical review of this
revision was the major contributor in failing to incorporate this
precaution into the procedure.
Failure to address potential runout
with only one SI pump operating is a violation: EPP-10 Inadequately
Addresses Potential Pump Runout With Only One SI Pump Injecting Into
Two Hot Legs, 89-09-01.
4
The inspectors reviewed the applicability of the one SI pump
precaution to injection into three cold legs.
This configuration
would be the expected alignment during a design 'basis LOCA. In 1988,
Westinghouse performed a calculation which demonstrated that this
operating mode would be acceptable; however, the 1974 flow test did
not conduct testing which demonstrated this flow configuration was
acceptable. The inspectors' review of the 1974 flow test results for
other pump combinations into the cold legs, indicates one SI pump
injection into three cold legs may result in operation approaching
runout conditions.
In the exit interview, the licensee indicated that they believe that
runout would not occur for neither the three cold leg injection
pathway nor for the dual hot leg pathway.
However, they did agree
that existing available information supports that a limitation should
be placed on one SI pump injection into the dual hot leg, pathway.
Additional review is required to determine what testing, if any,
should be performed to support operation of the system in the current
configuration. This is an URI: Determine If One SI Pump Injection
Into Three Cold Legs Should Be Demonstrated, 89-09-02.
c. Instrument Evaluations To Determine Operability Needs Enhancement
An operational weakness was observed, in that, an instrument channel
associated with the reactor protection system was assumed to be
operable without conducting an investigation into the reason for
momentary bistable actuations.
The cause was assumed to be known
because of a recent similar problem with a redundant instrument-loop.
Investigation later determined that the instrument was operable. The
details of this issue are discussed below:
On May 3, 1989, the inspectors were informed that RC loop C low flow
instrument
FT-436
appeared to be operating ' erratically.
The
instrument was spiking low 12 to 15 times per shift, thereby causing
momentary low flow bistable actuations.
This condition had begun
approximately three days earlier, after the redundant transmitter
FT-435 had experienced a similar problem.
The FT-435 problem had
been corrected by venting. the transmitter.
The inspectors were
informed that part of the air bubble which had been in FT-435 had
apparently moved into the FT-436 portion of the common high pressure
line. When corrective actions were addressed, the licensee indicated
that they believed that the bubble would dissolve. When asked if the
spiking frequency was decreasing, the licensee indicated that they
believed that it was; however, the number of occurrences had not been
recorded nor trended.. Furthermore, the inspectors were informed that
no troubleshooting had been performed because the spiking was in the
conservative direction and was similar to the FT-435 problem.
The
'inspectors pointed out that there were no alarms or other installed
means by which it could be determined if spiking was occurring in the
5
non-conservative direction.
In addition, spiking of this nature
could be the result of an electrical problem with the instrument
loop.
Comparison of the RTGB indicator with the other two redundant
instruments revealed that FT-436 was varying only slightly from the
other two channels. The inspectors questioned if the instrument's
response time would meet that assumed in transient analysis, and what
the basis was for not declaring the instrument out of. service (i.e.,
tripping the channel to maintain the degree of redundancy specified
by TS 3.5.1.3 and TS Table 3.5-2).
Since the observed spiking was in
the conservative direction (the channel trips), OMM-001, Operations
Conduct of Operations, revisons 19, section 5.14.2.1 was considered
to apply. This section in part addresses channels deviating by a
known
constant amount.
If
this constant deviation is in a
conservative direction, an appropriate trip need not be inserted.
The inspectors do not believe that this section applies to erratic or
spiking instrumentation.
Since the ability of the instrument to
respond within the time assumed had not been addressed,
the
inspectors, after consultation with NRC
Region II
management,
informed the licensee that the channel should be considered
The licensee promptly declared the channel inoperable
and took the action required by TS.
On May 4, plant management
discussed the matter with the inspectors, contending that the spiking
could only occur in the conservative direction and that the
instrument tracked the other channels; therefore, they considered the
instrument was operable.
Furthermore,
since troubleshooting was
hampered by having the channel tripped, the licensee stated their
intent to return FT-436 to service.
Troubleshooting would then be
performed to determine, if possible, the exact nature of the problem
and occurrence trending would be performed. In addition, the licensee
indicated that if the spiking occurrence frequency was not decreasing,
the unit would be reduced below P-8,
the one
RCP trip bypass
permissive setpoint, and the instrument loop would be vented during
the subsequent weekend. After consulting with Region II management,
the inspectors informed the licensee that the NRC did not object to
this course of action. Subsequently, FT-436 was returned to service.
The instrument was not vented since it was spiking only three or four
times during most days. Occasionally, FT-436 would spike as many as
ten times per day. The licensee has also determined from instrument
data that there was no information which indicated that the FT-436
response time to changes in flow was adversely affected.
If the
transmitter is still spiking by the end of May, the licensee plans to
vent the instrument lines when power is decreased for turbine valve
testing.
During the exit interview, the inspectors discussed with plant
management the need to conduct a proper investigation when an
instrument loop is not functioning correctly.
In particular, a
determination needs to be made as to whether an. observed abnormal
behavior indicates an instrument loop may or may not perform its
6
function as described in transient analysis.
In the case discussed
above, the licensee, having assumed the problem was due to air in the
instrument loop, failed to evaluate if this would adversely effect
the 0.2 second instrument loop response time.
The licensee stated
that they believed that the guideline of OMM-001 had applied to
FT-436;
however,
the licensee did agree to review their current
practices in this area.
This review includes contacting other
utilities to determine what actions are typically taken to address
this type of situation. This is an IFI:
Review Actions To Be Taken
When An Instrument Loop Exhibits Random Erratic Behavior, 89-09-03.
One violation was identified within the areas inspected.
3. Monthly Surveillance Observation (61726)
The inspectors observed certain surveillance activities of safety- related
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
LCOs were met; the tests were completed at the required frequency; the
tests conformed to TS requirements; the required administrative approvals
and tagouts were obtained prior to initiating the tests; the testing was
accomplished by qualified personnel in accordance with an approved test
procedure; and the required test instrumentation was properly calibrated.
Upon completion of the testing, the inspectors observed that the recorded
test data was accurate,
complete,
met TS requirements,
and test
discrepancies were properly rectified.
The inspectors independently
verified that the systems were properly returned to service. Specifically,
the inspectors witnessed/reviewed portions of the following test
activities:
OST-010 (revision 9)
Power Range Calorimetric During Power Operation
OST-401 (revision 22)
Emergency Diesels
RST-001 (revision 33)
Radiation Monitor Source Checks
EST-058 (revision 4)
SI-890A and 890B Check Valve Test
The inspectors discussed with the cognizant engineer the A EDG OST-401
test data taken on May 1, 1989.
The engineer indicated that trends on
some cylinder exhaust temperatures indicate deterioration in fuel injector
performance. This does not effect operability of the EDG, and plans are in
progress to have these injectors rebuilt during the next outage.
The
inspectors consider this as an example of good predictive maintenance.
No violations or deviations were identified within the areas inspected.
4. Monthly Maintenance Observation (62703)
The inspectors observed several maintenance activities of safety-related
systems and components to ascertain that these activities were conducted
in accordance with approved procedures, TS, and appropriate industry codes
7
and standards.
The inspectors determined that these activities did not
violate LCOs, and that redundant components were operable. The inspectors
also determined that activities were accomplished by qualified personnel
using approved procedures; QC hold points were established where required;
required administrative approvals and tagouts were obtained prior to work
initiation; proper radiological controls were adhered to; and the effected
equipment was properly tested before being returned to service.
In
particular, the inspectors observed/reviewed the following maintenance
activities:
MST-901 (revision 19)
Radiation Monitoring System
OWP-004 (revision 6)
WR/JO 89-AEPM1
Repair SI-890B Bonnet to Body Leak
On May 2, 1989, while observing maintenance activities on SI-890B, the B
CV spray pump discharge check valve, the inspectors observed that the only
post-maintenance testing specified on WR/JO 89-AEPM1 was an examination
for external leakage from the valve while at operating conditions.
When
the inspectors questioned if this was all the testing to be performed,
.they were informed that no testing of SI-890B other than that required by
Section XI of the ASME code was required. ASME Section XI requires only a
leak check after a gasket replacement and per a code exemption request
response from the NRC,
disassembly and visual examination of the full
stroke of the check valve is sufficient to comply with Section XI
requirements. These requirements were specified to be performed by the
WR, and it was determined no further testing, such as a partial flow test,
was required. Item 9.,a of Regulatory Guide 1.33, revision 2, as required
by TS 6.5.1.1.1.a,
requires that maintenance which can affect the
performance of safety-related equipment be performed in accordance with
written procedures appropriate to the circumstances. 10 CFR 50, Appendix B,
Criterion V, requires instructions to include appropriate quantitative
or qualitative acceptance criteria for determining that important
activities
have been satisfactorily accomplished.
The inspectors
considered a partial flow test was necessary as a qualitative acceptance
criteria after partial disassembly of the valve.
This item was discussed
with the Plant Manager.
Prior to returning the B CV spray loop to
service, the licensee performed additional testing.
The licensee agreed that additional testing requirements should have been
included on the WR since the valve was almost completely disassembled. A
PLP-026 investigation is to be conducted in order to determine the root
cause for the failure, to include appropriate test requirements, and to
determine what actions, if
any, are required to prevent recurrence.
However, during the exit interview, the licensee stated that a partial
flow test would not be required for a limited work scope such as removal
and replacement of a bonnet with an attached flapper assembly (assuming
the flapper assembly is not disassembled or adjusted).
The inspectors
believe that this type of activity would require partial flow testing.
This belief is based in part on Attachment 1, paragraph 2, of GL 89-04,
8
Guidance on Developing Acceptable Inservice Testing Programs,
issued
April 3, 1989.
This paragraph requires a partial flow test be performed,
if possible, after reassembly. Resolution of what constitutes disassembly
and reassembly of a check valve is considered an URI:
Resolve What
Degree Of Maintenance Activity On Check Valves Warrants A Partial Flow
Test After Reassembly Per GL 89-04, 89-09-04.
No violations or deviations were identified within the areas inspected.
5. Onsite Followup of Events at Operating Power Reactors (93702)
a.
RHR Pit Leakage Design Basis Could Not Be Met During Accident
Conditions
On April 6, 1989, the resident office was notified that a potential
common mode failure of both RHR trains may exist. due to flooding.
The
pump bays are separated by a concrete shield wall
approximately eight feet high at its lowest point.
The RHR pump
motor pedestal is approximately four feet high. As part of the RHR
system design basis document review, the question was raised whether
the wall was intended to serve a flood protection function.
As
constructed, the wall did not provide separation since the two pump
bays were connected at floor level by a six-inch diameter open ended
pipe. During resolution of this issue on April 10, 1989, the PNSC
and NED determined that the system design basis to detect and isolate
a 50 gpm leak into the RHR pit within 30 minutes did not appear to be
obtainable during accident conditions.
Later that evening, it was
confirmed that during the recirculation mode of operation, a passive
failure resulting in a leak could not be isolated, since high
radiation levels would not allow personnel access to certain manual
valves required for isolation. Anticipated radiation fields could be
as large as several thousand Rem/hr.
Potential passive failures
considered included: flange leaks, pipe.cracks, packing leaks, tube
leaks, and pump seal leaks on either the SW, CCW or RHR components in
the RHR pit. Anticipated radiation levels were based upon the source
term associated with TMI Action Item II.B.2, Shielding Modifications
for Vital Area Access.
Manual valves which would be inaccessable
after initiation of the recirculation phase include:
RHR-752A and B,
the RHR pump suction valves; SW-75,
-76,
-77,
and -78,
the RHR room
coolers'
(HVH-8A and B) supply and return valves; and CC-768A and B,
the RHR pump seal coolers' supply valves.
Inherent to the accident
scenario is the assumption that the RHR pit sump pumps would be
unavailable since they are not environmentally qualified and are not
powered from emergency onsite power.
At the time of discovery, the unit was shutdown for removal of a
loose part from C S/G (see Inspection Report 89-08).
Prior to
resuming power operations, procedure changes and temporary modifica
tions were implemented to address the issue until a permanent solution
is identified.
Independence of the pump bays was established by
9
grouting the six inch diameter pipe.
EPP-9, Transfer to Cold Leg
Recirculation, was revised to:
(1) secure SW to the RHR room coolers
by closing SW-75,
-76,
-77 and -78; (2) isolate the RHR pump suction
lines from one another by closing either RHR-752A or B; and (3)
install a temporary RHR pit level measuring system.
Temporary
modification 89-709 supplied two level devices to be installed by
operators.
Each device, one for each bay, consists of a float, a
cable and counterweight.
The float is to be lowered into the
RHR pump bay,
the cable suspended over a pulley system and the
counterweight hung adjacent to a level scale painted on a wall
outside the RHR pit.
The above mentioned items are to be completed
immediately prior to initiating RHR recirculation. A revision to the
EPP-Foldouts was made to require hourly monitoring of the temporary
level system. A new procedure, EPP-24, Isolation of Leakage in the
RHR Pump Pit, was issued on April 13, 1989.
This procedure provides
instructions on the use of the level system to determine which bay
contains the leak and the steps required to isolate the leak while
still maintaining one RHR pump operating.
The licensee described
this event in LER 89-008.
The acceptability of continued operation until the next refueling
outage based on the above described actions is documented in JCO
89-05. The inspectors reviewed the JCO and associated engineering
evaluations.
Two specific items addressed in the JCO were the
leakage from the CCW and SW systems.
The RHR pump vendor indicated
that the
pump seals could operate indefinitely at the
temperatures anticipated during the recirculation phase of an
accident. However, it
was considered prudent to have the RHR pump
seal coolers in service; therefore, it
was decided to continue to
supply CCW to the seal coolers during the recirculation phase of an
accident. This was based in part on the determination that leakage
from the CCW lines supplying the
RHR pump seal coolers was a
relatively small contributor to core melt frequency for the assumed
event.
The acceptability of removing the
RHR room coolers from
service by securing service water to HVH-8A and B is documented in EE 88-080.
EE 88-080 was developed to support JCO 88-002, approved
July 1, 1988.
JCO 88-002 addressed operation of the RHR pumps under
post LOCA conditions without HVH-8A and B in service.
HVH-8A and B
were assumed to fail since no
EQ package had been developed to
address the effect of radiation on the fan motors (see Inspection
Report 88-16). JCO 88-002 and EE 88-080 had been previously reviewed
by the inspectors.
The acceptability of these evaluations to the
current issue was confirmed.
The inspectors witnessed shift training on the revised EPP-9 and
newly issued EPP-24.
This training included a field walkdown to
identify the location of manual
valves which would require
manipulation. Additionally, the inspectors witnessed simulation of
the revised section'of EPP-9.
Problems encountered during the
simulation were adequately addressed by the licensee.
These actions
were completed prior to unit restart on April 15, 1989.
10
The UFSAR does not address the design basis statement that an
operator can detect and isolate a 50 gpm leak within 30 minutes.
UFSAR Chapter 6, section 6.3.2.5.5, Recirculation Loop Leakage, does
state that valving is provided to permit the operator to individually
isolate each RHR pump. Manually operated valves RHR-752A and B are
the valves required for isolation of RHR pumps A and B, respectively.
As described in the preceding paragraphs,
these valves are not
accessible due to postulated radiation levels after initiation of
recirculation.
Hence,
the existing RHR configuration does not
reflect the design as described in the UFSAR; however, it appears
that the RHR pit was considered accessible when the plant was
licensed.
Statements contained in analysis WCAP-12070 indicate that
this area is accessible for maintenance on a RHR pump when the other
pump is operating in the recirculation mode.
This analysis was
issued in December
1988 as a compilation of original design
information. This compilation is based upon both documentation and
personal recollections.
The licensee believes that the source term
used in the original plant shielding analysis would support the
statements contained in WCAP-12070.
As discussed previously, the
radiation levels now anticipated are based upon analysis performed to
comply with TMI item II.B.2.
The licensee's review of these.later
calculations indicated that there is a large amount of conservatism
in this analysis.
Thus,
they believe if
this analysis were
reperformed, the areas required for leakage isolation may be
accessible.
Statements provided in WCAP-12070 are the only documented basis
identified to date which indicate that a 50 gpm leak into the RHR pit
must be isolable.
The time criterion is based upon the calculated
time available to isolate a 50 gpm leak prior to RHR motor damage.
The volume in each pump bay (below the RHR motor pedestal) is 200
cubic feet; thus a 50 gpm leak must be isolated within 30 minutes.
The assumption in the calculation was that the two RHR pump bays were
separated. This was not the as-found configuration since the pump
bay sumps were connected by a six-inch diameter pipe. The connection
had probably existed since plant construction.
In a response to NUREG 0737 Item II.B.2, dated December 31, 1980,
the licensee stated:
"This response to NUREG 0737 Item II.B.2
together with the CP&L responses to NUREG 0578 dated December 31,
1979, and supplemented March 31,
1980,
constitutes CP&L's complete
response on this item.
CP&L considers this item to be.complete."
Neither this response nor its referenced documents address the RHR
leakage detection and isolation design criteria.
Hence, during.
implementation of II.B.2 adequate design controls were
not
established to assure design basis were properly incorporated into
design documents and plant procedures.
In summary, the licensee's design basis document review determined
that available information indicates inaccessibility to areas
required to isolate a 50 gpm leak into the RHR pit during the
11
recirculation phase of an accident.
No credit is taken for the RHR
pit sump pumps since they are not powered from emergency onsite power
sources. Futhermore, even if power was available, the installed sump
pumps and associated control circuits cannot be assured to remain
functional since the EQ of these items have not been demonstrated.
Under the above described conditions, a 50 gpm leak or less would
eventually result in sufficient flooding to damage both RHR pump
motors. The loss of both RHR trains during the recirculation phase
would result in the loss of all ECCS capability.
The licensee has
initiated compensating action in hardware and administrative controls
until a long term fix has been approved and implemented during the
next refueling outage. The failure to assure that design basis are
correctly .translated into specifications, drawings, and procedures is
a violation of 10 CFR 50 Appendix B Criterion III: Design Control
Measures Were Not Adequately Established To Assure That The 50 Gpm
Leak Isolation Capability Design Basis Was Correctly Translated Into
Specifications,
Drawings,
and Procedures
For The
RHR System,
89-09-05.
b. Spent Fuel Assembly Disengaged From Grapple During DSC Loading
On April 26, 1989, at approximately 12:35 a.m., a spent fuel assembly
became uncoupled from the fuel handling tool and fell against the
spent fuel pool wall.
Personnel working in the spent fuel pool area
immediately evacuated the area.
Air samples and radiation monitors
showed no increase over normal background levels.
At the time of
occurrence,
a spent fuel assembly was being loaded into a DSC in
preparation for onsite storage in the ISFS facility.
Five fuel
assemblies
had been successfully loaded into the DSC when the
operator experienced difficulty in positioning the sixth.
After
several attempts, the assembly caught on the top DSC grid-work while
being lowered. The grapple cable slackened, the assembly separated
from the tool,
and fell against the spent fuel pool wall.
The
inspectors estimated that the assembly formed a 40 degree angle with
the wall and incurred a 25 degree torsional twist.
The licensee
prepared a special procedure and successfully retrieved the assembly
on April 26.
The assembly was positioned in the fuel elevator for
inspection; no damage was observed. The assembly has been returned
to the spent fuel pool storage location.
The inspectors reviewed the special procedure, attended the PNSC
which approved the special procedure,
and attended the pre-job
briefing.
The inspectors determined that the retrieval activity was
well
planned and contained sufficient safety precautions
and
contingency plans.
Visual inspection of the top nozzle blocks of the assemblies which.
were contained in -the DSC at the time of the event revealed no
assembly damage had occurred.
As a result of the fuel assembly
falling onto the DSC, the DSC was unloaded and removed from the spent
12
fuel pool for repair of minor damage to the grid-work. After repair,
the DSC was returned to the spent fuel pool and successfully loaded
with seven spent fuel assemblies on April 28 without any further
difficulties.
The assembly which fell against the wall will remain
in the spent fuel pool until its final disposition is decided.
Investigation into the event revealed that the most probable cause
was that the tool had been engaged on the leaf springs instead of in
the top nozzle block.
Measurements of the tool revealed no
dimensional reason for the failure to properly engage the assembly.
Thus, either an obstruction had caused the improper latching or an
operator error had occurred. The actual root cause is still being
evaluated;
however,
a potential contributor to this event was
determined to be a loss in fuel handling efficiency.
During the
previous two refueling outages,
fuel movements were performed by
contract personnel.
Immediate corrective action consisted of
retraining the operating crews on fuel handling techniques and
manipulations prior to performing additional fuel movements,
including removal of the five assemblies from the damaged DSC. Also,
potentially contributing to this event was bowing of the fuel
assembly. This phenomena can hinder latching an assembly. Bowing is
much more pronounced on older assemblies due to the pattern in which
they were irradiated.
Long term corrective action is being developed as part of the PLP-026
incident review.process. This is an IFI:
Review Corrective Actions
To Be Addressed In PLP-026 Associated With A Dropped Fuel Assembly,
89-09-06.
One violation was identified within the areas inspected.
6. Onsite Review Committee (40700)
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
the April 26,
1989 PNSC concerning the dropped fuel assembly.
It was
ascertained that provisions of the TS dealing with membership and review
process were met.
Previous meeting minutes were reviewed to confirm that
decisions and recommendations were accurately reflected in the minutes.
No violations or deviations were identified within the areas inspected.
7. Exit Interview (30703)
The inspection scope and findings were summarized on May 17, 1989, with
those persons indicated in paragraph 1.
Excluding item 89-09-05, the
inspectors described the areas inspected and discussed in detail the
inspection findings listed below and in the report summary.
The licensee
13
was informed of item 89-09-05 on June 1, 1989.
Licensee's comments.
concerning particular items are discussed in the appropriate paragraph.
Proprietary information is not contained in this report.
Item Number
Description/Reference Paragraph
89-09-01
VIO -
EPP-10 Inadequately Addresses Potential Pump
Runout With Only One SI Pump Injecting Into Two Hot
Legs, paragraph 2.b.
89-09-02
-
Determine If One SI Pump Injection Into Three
Cold Legs Should Be Demonstrated, paragraph 2.b.
89-09-03
IFI -
Review Actions To Be Taken When An Instrument
Loop Exhibits Random Erratic Behavior, paragraph 2.c.
89-09-04
URI -
Resolve What Degree Of Maintenance Activity
On Check Valves Warrants a Partial Flow Test After
Reassembly Per GL 89-04, paragraph 4.
89-09-05
-
Design Control Measures Were Not Adequately
Established To Assure That The 50 GPM Leak Isolation
Capability Design Basis
Was Correctly Translated
Into Specifications, Drawings, and Procedures For The
RHR System, paragraph 5.a.
89-09-06
IFI -
Review Corrective Actions To Be Addressed In
PLP-026 Associated With The Dropped Fuel Assembly,
paragraph 5.b.
8. Acronyms and Initialisms
American Society of Mechanical Engineers
Component Cooling Water
CFR
Code of Federal Regulations
Carolina Power & Light Company
CV
Containment'Vessel
Dry Shielded Canister
EE
Engineering Evacuation
End Path Procedures
Environmental Qualifications
EST
Engineering Surveillance Test
FI
Flow Indicator
FT
Flow Transmitter
Fuel Handling Procedure
GL
Generic Letter
gpm
Gallons Per Minute
14
HVH
Heating Ventilation Handling
IFI
Inspector Followup Item
JCO
Justification For Continued Operation
LCO
Limiting Condition for Operation
Maintenance Surveillance Test
NED
Nuclear Engineering Department
NRC
Nuclear Regulatory Commission
OMM
Operations Management Manual
OST
Operations Surveillance Test
OWP
Operations Work Procedure
PLP
Plant Procedure
PNSC
Plant Nuclear Safety Committee
Quality Control
RC
Reactor Coolant Pump
Rem/hr
Roentgen Equivalent Man/Hour
RST
E&RC Surveillance Test
S/G
Safety Injection
TS
Technical Specification
Updated Final Safety Analysis Report.
- URI
Unresolved Item
Westinghouse Corporation Atomic Power
Work Request
WR/JO
Work Request/Job Order
.Unresolved
items are matters about which more information is required to
determine whether they are acceptable or may involve violations or
deviations.