ML16342C051
| ML16342C051 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 03/16/1994 |
| From: | Vandenburgh C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16342A444 | List: |
| References | |
| 50-275-94-08, 50-275-94-8, 50-323-94-08, 50-323-94-8, GL-89-13, NUDOCS 9403250013 | |
| Download: ML16342C051 (12) | |
See also: IR 05000275/1994008
Text
Inspection Report:
Operating License:
Licensee:
Facility Name:
Inspection at:
~
~
.S.
NUCLEAR REGULATORY COMMIS
N
REGION
V
50-275/94-08;
50-323/94-08
and
Pacific Gas
and Electric Company
Nuclear
Power Generation,
814A
77 Beale Street,
Room
1451
P. 0.
Box 770000
San Francisco,
California 94177
Diablo Canyon Units
1 and
2
PGLE Corporate Offices
333 Market Street
San Francisco,
California 94177
Inspection
Conducted:
February
28,
March
1 and 8,
1994
Inspector:
Approved by:
e
o
Smmr
P. Narbut,
Regional
Team Leader
C. 1. ~I%
9
~g
Acting Deputy Director
Division of Reactor Safety
h Pro)ects
t
n
- - Routine,
announced
regional
inspection of
PG%E's activities performed in response
to Generic Letter 89-13, "Service
Mater System
Problems Affecting Safety-Related
Fquipment," issued
on July,18,
1989.
The inspection followed up the unresolved
items identified in NRC
Inspection
Report 50-275,
50-323/93-36.
Temporary Instruction (TI) 2515/llB
and Inspection
Procedure
40500 were used
as guidance during this inspection.
m
S
H It:
None
s
U
s
d
Three apparent violations were identified involving:
The failure to implement adequate
design control measures
to assure
that
the specifications
and procedures
associated
with the Component
Cooling
Mater Heat Exchangers
maintained
the system design basis for maximum
system temperature
(Sect'ion 2).
The failure to provide complete
and accurate
information to the
NRC
regarding
the results of the testing of these
heat exchangers
(Section
3.2).
The failure to identify the cause
and take timely corrective action for
the failure of the
CCM Heat Exchanger
1-2 to meet the test
acceptance
criteria for heat
exchanger
capacity
on February
2,
1991 (Section 3.6).
q+O32500
O5Oopp75
Oi3 94O3i7
ADOC 'DR
Q
Summar
of Ins ection Findin s:
~
Apparent Violation 50-275/94-08-01
was opened.
~
Apparent Violation 50-275/94-08-02
was opened.
Apparent Violation 50-275/94-08-03
was opened.
Followup Item 50-275/94-08-04
was opened.
~
Followup Item 50-275/93-36-01
was closed.
~
Unresolved
Item 50-275/93-36-02
was closed.
~
Unresolved
Item 50-275/93-36-03
was closed.
~
Unresolved
Item 50-275/93-36-04
was closed.
~
Followup Item 50-275/93-36-05
was closed.
~
Unresolved
Item 50-275/93-36-06
was closed.
Unresolved
Item 50-275/93-36-07
was closed.
I
Followup Item 50-275/93-36-08
was closed.
Attachments:
~
Persons
Contacted
and Exit Meeting
DETAILS
1.
BACKGROUND
The
NRC issued
System
Problems Affecting
Safety-Related
Equipment,"
on July 18,
1989.
The generic letter described
recurring industry problems with the service water systems
at nuclear
power
plants.
Service water systems
are important to plant safety
as the ultimate
heat sink following a design basis event.
The generic letter recommended
certain actions to be taken
by licensees
and required that each licensee
advise the
NRC of the programs to be implemented
in response
to the generic
letter recommendations.
PG&E Letter No. DCL-90-027, dated January
26,
1990,
provided
PG&E's response
to the generic letter and committed to perform
certain actions.
PG&E Letter No. DCL-91-286, dated
November 25,
1991,
provided
a supplemental
response
to the generic letter and reported the
completion of the initial program actions.
NRC Inspection
Reports
50-275,
50-323/93-36
examined the licensee's
actions
taken in response
The inspection report identified
a
number of unresolved
and followup items regarding the adequacy of the
licensee's
actions taken in response
to the generic letter,
and requested
that
the licensee
address
the items in a written response
to the
NRC.
The licensee
provided
a response
to the inspection report in
PG&E Letter No. DCL-94-037,
dated
February
15,
1994.
The response
addressed
each of the inspection
items
and stated that there were instances
in 1987
and
1990 when the Auxiliary
Saltwater
System
(ASW) may not have 'been operable.
The response
stated that
a
supplemental
response
would be provided when the results of the past
operability study were completed.
The results of that past operability study
were documented
in Licensee
Event Report
(LER) 1-93-012-01,
"Auxiliary
Saltwater
System Outside Design Basis
Due to Fouling," dated
March 8,
1994.
2.
ASW OPERABILITY AND DESIGN BASIS
NRC Inspection
Report 50-275/93-36;
50-323/93-36,
dated January
12,
1994,
found that the licensee's
heat
exchanger. test results
showed that one
ASW heat
exchanger did not meet the acceptance
standards
for minimum heat transfer
.
capacity established
by the system design requirements.
This raised
a concern
regarding the operability of the
ASW system which the licensee
subsequently
determined .to be temporarily acceptable
due to the cold winter sea
temperatures.
Additionally, the test data
appeared
to contradict the
licensee's
statements
to the
NRC in their November 25,
1991, letter to the
NRC
regarding the acceptability of the test results.
In addition, the inspector
found that the licensee
had not assured
that the
ASW system maintenance
and surveillance controls were sufficient to assure
system operability;
Specifically, the,licensee
had high differential pressure
limits on the heat exchangers
which allowed macrofouling to a degree that
would apparently
exceed
the manufacturer's
.tube plugging limit and
significantly reduce the heat
removal capacity.'his
concern also affected
the operability of the
ASW system which the licensee
subsequently
determined
to be temporarily acceptable
due to the cold winter sea temperatures.
In general,
the previous inspection
concluded that the licensee
had not
developed
a good engineering
understanding
of the effects of microfouling,
macrofouling,
and heat
exchanger differential pressure
and
had not implemented
adequate
operational
controls to ensure
system operability.
This was
considered
a significant failing due to the high safety significance of the
system
and the number of opportunities the licensee
had to address
the issues.
NRC concerns
regarding
system operability due to differential pressure
had
also
been previously raised in
NRC Inspection
Report 50-275/88-11.
The
licensee
responded
to those
concerns with assurances
that the differential
pressures
were acceptable.
Generic Letter 89-13 again focused attention
on
the issue of heat
exchanger
performance.
The failed heat exchanger
capacity
test in 1991 should
have initiated additional analysis
and understanding,
but
did not.
Finally,
a gA surveillance in May 1993 raised
the
same
heat
exchanger
performance
issues,
but did not result in an adequate
technical
response
from the engineering organization.
In response
to these
concerns,
during the period from December
1993 to March
1994, the licensee
performed extensive calculations to assess
the operability
of the Auxiliary Saltwater
(ASW) system during the periods of high
microfouling and high macrofouling of the Component Cooling Water
(CCW) heat
exchangers.
The results of those calculations
were presented
in
PG&E Letter
No. DCL-94-037, "Auxiliary Saltwater Operability," dated
February
15,
1994;
and Licensee
Event Report
(LER) 1-93-012-01,
"Auxiliary Saltwater
System
Outside Design Basis
Due to Fouling," dated
March 8,
1994.
The letter
concluded that the
ASW system
was operable
and capable of meeting its design
basis for future operation.
The
LER also concluded that the
ASW system
had
been operable,
but not within its design basis for past operating periods.
The licensee
determined that the ability of the
ASW system to meet its design
basis
was assured
subsequent
to the initiation of continuous chlorination of
the system in September
and November
1992 for Units
1 and
2 respectively.
During this inspection,
the inspector reviewed Calculation
No. M-963, Revision
0, File 140.061,
dated
March 7,
1994, which demonstrated
the
ASW system's
past
operability.
The calculation
was very complex, in that several
sets of cases
and assumptions
were used
by Westinghouse
and the licensee's
technical staff
to support their conclusions.. Westinghouse
used five cases
and the licensee
used five cases
with a variety of subsets.
The cases all had variances
and
did not correlate
on
a one-for-one basis.
Nonetheless,
the licensee
was able
to demonstrate
the basis of their conclusions
using the calculations.
However, the inspector noted that the licensee's
determination of operability
was based
on the following four facts:
First, the calculations
depended
on the
1991 heat
exchanger
capacity test
results for the tests
done in response
As
discussed
in Inspection
Report 50-275,
50-323/93-36,
those tests .were not
well controlled
and the microfouling and macrofouling conditions were not
known and
had to be later inferred by the licensee.
The licensee
has
committed to perform additional tests to confirm the performance
inferred
by the tests.
Second,
the licensee
appeared
to essentially
remove the margin in the
calculations.
For example,
the licensee
took advantage
of a two percent
tube plugging allowance provided by the manufacturer to increase
the
baseline
heat
removal capacity
by two percent.
Likewise, the
calculations
used actual.'ocean
temperatur'es,
rather than higher design
basis
ocean temperatures.
Similarly, actual
versus
design values
were
used for containment initial temperature,
reactor power, water
temperature
in the Refueling Water Storage
Tank,
and other parameters.
This technical
approach
appeared
credible to the inspector for assessing
past conditions,
but left little of the conservative
margin usually
preserved for calculational
uncertainties
in predictions of performance.
Third, the licensee
took credit for operator actions
which they
considered
credible at the time, but which were not in all cases
part of
the Emergency Operating
Procedures
(EOPs).
Nevertheless,
the licensee's
assumptions
appeared
credible to the inspector.
Fourth, the study was performed using the licensing basis
model for mass
and energy release
which did not predict
as severe
conditions
as the
newer mass
and energy release
models.
The licensee
made
an approximate
correction for this difference.
The calculations
concluded that no Final Safety Analysis Report
(FSAR) design
bases
would have
been
exceeded
during the injection phase of an accident.
However, the calculation
showed that later in the accident
scenario during the
recirculation phase,
the Component Cooling Water
(CCW) temperature
would have
exceeded
the
FSAR design basis
peak temperature
of 132 degrees
Fahrenheit
and
would have exceeded
120 degrees for longer than the
20 minutes allowed by the
FSAR design basis
under the worst case conditions identified by the licensee
to have actuall'y occurred in the past.
The calculation
showed
a range of
results with temperatures
up to a peak of about
139 degrees
and times
above
120 degrees
of about
33 minutes.
Tiie licensee
evaluated
the
Emergency
Core
Cooling System
(ECCS)
components
affected
by the increased
CCW temperature
and, after contact with Westinghouse
and individual vendors,
concluded
that'one
of the components
would have
been adversely affected with the exception
of the Centrifugal
Charging
Pumps
(CCPs),
which would have experienced
bearing
failures.
However, the licensee
noted that the
CCPs were not required during
the recirculation
phase
and would have
been
secured
by the operators
in
response
to high bearing temperature
alarms.
The licensee
also concluded that
the Post Accident Sampling
System
(PASS) would have
been inoperable
due to the
elevated
CCW temperatures.
However, alternate
means of core
damage
assessment
would have remained available.
The calculations
also
showed that, in approximate
terms:
(1)
a clean
heat
exchanger
had about
20 percent margin,
(2)
a heat exchanger
microfouled to the
usual
amoun't currently encountered
with continuous chlorination
and
macrofouled to 140 inches of differential pressure
would have
no margin,
and
(3)
a heat exchanger with the current typical
amounts of microfouling and
macrofouling would be somewhere
in
between.'lthough
the licensee's
evaluation demonstrated
the operability of the
ASW
system under past actual
operating conditions,
the licensee
concluded in
Letter No. DCL-94-037, "Auxiliary Saltwater Operability," dated
February
15,
1994;
and Licensee
Event Report
(LER) 1-93-012-01,
"Auxiliary Saltwater
System
Outside
Design Basis
Due to Fouling," dated
March 8,
1994, that the
ASW system
was not within its design basis for past operating periods.
The licensee's
failure to assure that the design basis
as specified in the Final Safety
Analysis Report
(FSAR) was correctly translated
into instructions
and
specifications
for the operation
and maintenance
of the
ASW system
and the
heat exchangers,
was considered
an apparent violation (Apparent Violation 50-
275/94-08-01).
3.
OPEN
ITENS INSPECTION
The inspection
examined the unresolved
items
and followup items identified in
Inspection
Report 50-275/93-36;
50-323/93-36 to determine their disposition.
3. 1
Closed
Followu
Item 50-275 93-36-01
Review of Desi
n Basis
This item concerned
the perception that the licensee
had adopted
a revised
design basis
which had not been reviewed
by NRR.
The licensee's
response,
PG&E Letter DCL-94-037, dated
February
15,
1994, clarified that the design
basis
had not changed
from that which was described
in the Final Safety
Analysis Report
(FSAR).
The families of acceptance
curves in WCAP-12526,
Revision
1, "Auxiliary Salt Water and Component
Cooling Water Flow and
Temperature
Study for Diablo Canyon. Units
1 and 2," dated
June
1992,
were
derived utilizing the proper design basis.
3.2
Closed
Unresolved
Item 50-275 93-36-02
Failure to Provide
Com lete
and
Accurate Information
Re ardin
a Heat
Exchan er
Ca acit
Test
This unresolved
item involved the adequacy of the results of a heat exchanger
capacity test which had
been
performed
on the
Component
Cooling Water heat
exchangers.
The licensee
had reported to the
NRC that the heat
exchan'gers
met
their design, heat
removal capacity
'however,
the test data
showed, that one of
the four heat exchangers
did not meet this capacity.
Generic Letter 89-13 requested
that licensees
conduct
a test program to verify
the heat transfer capability of all safety-related
heat exchangers.
In
Letter DCL-90-027, dated January
26,
1990, the licensee
explained that they
would perform
a one-time heat exchanger
performance test to confirm the
baseline
heat transfer capability of the heat exchangers.
In
PG&E Letter DCL-
91-286,
dated
November 25,
1991, the licensee
reported that they had performed
the heat exchanger
capacity test
and stated that "...the computer
model
predicted that the heat exchanger
would remove the design basis
heat load at
design conditions."
The inspector
reviewed the results of the one-time heat
exchanger test.
The
test methods
and results
were described
in Field Test Report 420DC-91. 1156,
"Diablo Canyon
Power Plant
CCW Heat Exchanger
Performance
Tests Units
1
and 2," dated
November 22,
1991.
The test report
showed that the computer
prediction for Unit
1 Component
Cooling Water Heat Exchanger
1-2 did not
predict that the heat
exchanger
would remove the design basis
heat load.
Rather,
the test results
showed the heat
exchanger
capacity to be at 98.7
percent of design.
The licensee
subsequently
concluded
and reported in
PG&E Letter No. DCL-94-
037, dated
February
15,
1994, that the test results for the heat exchanger
did
not meet the projected
design basis
heat transfer requirements
using the
computer program chosen at the time.
The licensee
concluded that the heat
exchanger
was fouled by an abnormal
amount of microfouling at the time of the
test.
The licensee
also concluded that if a different, more commonly used,
computer
code
had
been
used then the calculated test results
would have
been
101 percent of the design basis
requirements
vice 98.7 percent.
The licensee
stated
in the February
1994 letter that they believed that their statement
regarding test results in the November
1991 letter was accurate
and complete
based
on guidance in the generic letter and based
on the inaccuracies
of the
testing methodology.
The inspector reviewed the guidance in the generic letter with the licensee
and found only general
discussions
that indicated that the level of detail
provided
by licensee's
should
be sufficient to demonstrate
the adequacy of
their actions.
Therefore,
the inspector
concluded that the licensee failed to
provide complete
and accurate
information to the
NRC in regards to the
CCW 1-2
heat exchanger's ability to meet the design basis
heat load.
This failure is
considered
an apparent violation (Apparent Violation 50-275/94-08-02).
3.3
Closed
Unresolved
Item 50-275 93-36-03
Differential Pressure
imits
for the
CCW Heat
Exchan ers
.
This item involved the adequacy of the 140-inch differential pressure limit
used
by the licensee
as
an operational limit for macrofouling
and heat
exchanger operability.
The inspector
was concerned that the licensee's
basis
for this operating limit was essentially
engineering
judgement,
rather than
analysis or some other technical
basis.
The inspector's
review developed
a
technical
basis for a substantially lesser
amount of differential pressure
based
on the manufacturer's
tube plugging limit.
The licensee
subsequently
performed calculations of the effects of tube
blocking on heat exchanger differential pressure utilizing the current
expected
amounts of heat exchanger microfouling (i.e., slime).
These
calculations reflected the use of continuous chlorination which the licensee
demonstrated
had reduced the amount of microfouling.
The licensee
then
used
the reduced
amount of microfouling to increase
the allowed amount of
macrofouling.
The licensee
concluded that the operational limit of 140 inches
was
appropriate.
However, to achieve this conclusion the licensee
performed flow
testing in February
1994
and then projected the results to include the more
difficult conditions of low tide, cross-train flow configuration,
and
an ocean
temperature
of 64 degrees.
The results of that calculation (Calculation
No.
M-962, Revision 0)
showed that
a differential pressure of up to 134 inches
(not 140 inches)
could be tolerated
and provided the necessary
amount of flow
for design basis cooling.
This calculation
was based
on the limited 1991 heat
capacity test results
and
showed that the
134 inch differential pressure
was
achieved with a total blockage of about
250 tubes.
The licensee
then used
a
qualitative assessment
to judge that
a value of 140 inches would be
an
appropriate limit.
This assessment
was based
on the opinion that the blocked
tubes
would not be totally bl,ocked but would allow some flow and cooling to
occur.
The inspector concurred with the licensee's
observation that the heat
exchanger
tubes
do not generally
become fully blocked
by the mussels
and
barnacles typically found in the heat exchangers.
The licensee
attempted to correlate
these calculational results with results
from biomass
surveys
which had sometimes
been
done during heat exchanger
cleanings.
However, the data did not correlate well and
showed
a wide
variance
in the number of marine creatures
removed at any given differential
pressure.
It was the opinion of the licensee's
marine biologist that, the
calculated
number of blocked tubes
(about 250) roughly'greed with the usual
condition at
130 inches of differential pressure.
The inspector
concluded that the licensee calculations
demonstrated
that the
differential pressure limit of 140 inches
was sufficient to provide design
basis cooling if the amount of microfouling assumed
and the heat
exchanger
capacity
assumed
were correct.
However, the inspector noted that the
calculations
did not demonstrate
that any significant margin existed in the
140 inch limit.
The licensee
stated
in
PG&E Letter No. DCL-94-037, dated
February
15,
1994,
that they recognized
the limitations of the calculational
model.
The letter
also stated that additional functional tests of the heat exchangers
would be
performed during the
1994 refueling outages
and that
PG&E would reassess
the
140 inch limit based
on the test results.
3.4
Closed
Unresolved
Item 50-275 93-36-04
Routine Ins ection
and
Maintenance of the
ASW S stem
Pi in
This item concerned
the licensee's
apparent failure to develop
and implement
a
routine inspection
program for ASW piping as committed in
PG&E Letter DCL-90-
027, dated January
26,
1990,
and
as stated
as complete in
PG&E Letter DCL-91-
286, dated
November 25,
1991.
recommended that
a routine inspection
and maintenance
program for the service water system piping and components
be established
so
that corrosion,
erosion,
coating failure, silting, and biofouling would not
degrade
the performance of the system.
In
PG&E Letter DCL-90-027, dated
January
26,
1990, the licensee
stated that they would develop
a program
and
that procedures
for a routine piping inspection
and maintenance
program for
the
ASW system would be established
by the
1991 fourth refueling outages of
Units
1 and'.
In
PG&E Letter DCL-91-286, dated
November 25,
1991, the
licensee
stated that they had established
a routine piping inspection
and
maintenance
program.
The inspector
had previously concluded that the inspection
program
had not
been
implemented
as stated
based
on the apparent fact that the procedure for
inspection
had not been
issued
and the frequency of inspection
had not been
selected.
During this inspection,
the licensee
stated that they considered
that the inspection
program
had
been
implemented
based
on two open action
items which documented their decision
on frequency of the inspection
and the
intent to issue
a permanent plant procedure
based
on their temporary
procedure.
Specifically,. the licensee
had previously provided the inspector
a
copy of open Action Request
(AR) No. A0221696,
dated
March 6,
1991, which
requested
that the temporary inspection
procedure
be made
a permanent plant
procedure
and that
a regular inspection
frequency
be established.
Additionally, the licensee
provided
AR A0245348, dated
September
30,
1991,
which had not been presented
during the previous inspection.
This action
request
was directed to the system engineer
from the design engineer
and
requested
that
a frequency
be established
for the internal piping inspections.
An electronic response,
dated
November 22,
1991, stated that the frequency
would be every fourth, refueling outage,
with the option to change the
frequency
based
on experience.
Based
on the above,
the inspector considered
that the licensee
had
satisfactorily demonstrated
that they 'had determined
the frequency of the
inspection
and
had
an internal action item to prepare
a permanent plant
procedure to perform the inspection.
Therefore,
the inspector considered
that
the licensee's
statement
to the
NRC in letter DCL-91-286, dated
November 25,
1991, that
"The procedures
and inspections for this program have
been
established
and were performed during the Units
1 and
2 fourth refueling
outages,
and frequencies
of performance
were established
or confirmed in
response
to the observations
during these
outages."
was sufficiently complete
and accurate.
This unresolved
item is considered
closed.
3.5
Closed
Followu
Item 50- 75 93-36-05
Confirmation of the Licensin
Basis of the
ASW S stem
This item concerned
an assessment
of the need for the licensee to reperform
a
review of the adequacy of their design
bases for the
ASW system which had been
performed for Generic Letter 89-13.
The question
arose
from the
inspector's'uestions
regarding the adequacy of the licensee's
understanding
of their
macrofouling
and microfouling limits and also from the licensee's
quality
assurance
audit findings regarding
pump runout conditions.
In PG&E Letter No. DCL-94-037, dated February
15,
1994, the licensee
stated
that additional testing of the
CCW heat exchangers
would be done in 1994 to
assure that the heat exchangers
met their design basis.
Additionally, the
letter stated that
a team (consisting of operations,
quality services,
maintenance,
and engineering)
would thoroughly and critically
review the
ASW,
CCW,
and interfacing systems
by the end of 1994.
The letter
also stated that the design basis, document
would be revised appropriately.
'ased
on the licensee's
committed actions, this item is considered
closed.
3.6
Closed
Unresolved
Item 50-275 93-36-06
Failure to take Timel
Action
This item concerned
the licensee's
slow resolution of problems
adverse to
quality.
The licensee
had identified that
CCW heat exchanger
1-2 failed to
meet its test
acceptance
criteria in a test conducted
on February 2, 1991.,
The test failure was documented
in Field Test Report 420DC-91.1156,
"Diablo
Canyon
Power Plant
CCW Heat Exchanger
Performance
Tests Units
1 and 2," dated
November 22,
1991.
The test failure was also identified during
a guality
Assurance
(gA) surveillance
and documented
on Action Request
No. A03066715,
dated
Nay 10,
1993.
The effect of the test failure on
ASW system operability
was not resolved until after the issues
were identified by the
NRC inspector
in
NRC Inspection
Report 50-275/93-36;
50-323/93-36.
As previously discussed
in Section 2.0 of this report, the licensee
concluded
that the
ASW system
had been operable,
but outside its design basis for-
periods prior to September
1992 when continuous chlorination of the system
was
initiated.
These conclusions
were provided to the
NRC in a
report
made
on December 30,
1993.
The licensee
also documented their
conclusions
in
PG&E Letter DCL-94-049, dated
March 8, 1994,'hich provided
Licensee
Event Report 1-93-012-01,
"Auxiliary Saltwater
System Outside Design
Basis
Due to Fouling."
The report concluded that on August 23,
1990,
and
perhaps
dates prior to and subsequent
to that 'date,
the
CCW heat
exchangers
for both units
may have
had sufficient fouling to have precluded
the systems
from meeting their design bases.
10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," states
that
conditions
adverse
to quality are promptly identified and corrected.
The
-8-
criterion further states that, in the case of significant conditions
adverse
to quality, the cause of the condition should
be determined.
The failure of the
ASW system to have met its design basis is considered
a
significant condition adverse
to quality.
Subsequent
to the
CCM heat
exchanger
1-2 capacity test failure on February I, 1991, the licensee failed
to promptly identify, correct, or fully determine
the cause of the test
failure.
The determination
was
made in February
1994 in response
to
Inspection
Report 50-275/93-36;
50-323/93-36.
The failure to identify the cause
and implement timely corrective actions for
this condition adverse
to quality is considered
an apparent violation
(Apparent Violation 50-275/94-03).
3.7
Closed
Unresolved
Item 50-275 93-36-07
Use of a
Com uter Code that
had
not been Validated
This item concerned
the licensee's
use of a computer
code which had not been
validated for accuracy.
The code
was used to calculate
the heat exchanger
capacity for the
CCW heat exchanger
capacity tests
done in response
During this inspection,
the licensee
demonstrated
that the
results of the code
used
were conservative
compared to the code generally
utilized by the industry to analyze'eat
exchanger capacity.
Additionally,
the licensee
demonstrated
that the
NRC had indicated,
Supplement I, "guestions
and Answers," that 'it was willing to accept off-th'-
shelf software.
3.8
Closed
Followu
Item 50-275 93-36-08
Scalin
of Heat
Exchan er Tubes
This item concerned
scaling
on the inner diameter of the
CCW heat exchanger
tubes.
The scaling
was located only at the outlet end of the heat
exchanger
in the tube sheet
area.
The system engineer
had stated that the cause of the
scaling
was deposits
from seawater
caused
by the impressed
voltage system for
cathodic protection of the
ASM piping.
The system engineer
had further stated
that the scaling
was deposited for a short length
and would not affect the
available heat transfer
area or tube fouling factor.
The inspector
was
concerned that the scaling could cause
the tubes to plug at the outlet end,
which would not be detected
by the periodic cleaning
and inspection of the
inlet end.
The system engineer
had indicated that such tube
end plugging had
not been
seen
and that only a small
amount of scaling
had been
seen.
The
inspector
noted that the system engineer
interviewed at the time of the
December
1993 inspection
was
new and was not the engineer
who had performed
the inspections of the heat exchangers.
During this inspection,
the inspector determined
by a review of past
heat
exchanger
records
from April 1992, that heat
exchanger
scaling
had proceeded
to such
an extent in
CCW Heat exchanger
2-1 that
7 of the
20 tubes
examined
by
a video camera,
had
become completely blocked at the outlet end,
and
3
additional
tubes
were partially blocked.
This heat exchanger
had not had the
normal
outage
maintenance
of tube scraping
performed during the previous
refueling outage
due to an outage
management
decision according to the
licensee.
The lack of tube scraping in the previous outage
was attributed
as
the cause of the observed
tube blockage.
The inspector
noted that the licensee's
response
to the December inspection
provided in
PG&E Letter DCL-94-037, dated
February
15,
1994,
stated that the
licensee
considered
that there
was
a low potential for tube plugging
and that
tube plugging would be detected
by heat exchanger differential pressure.
The
inspector noted that this statement
appeared
to contradict the inspection
data
for CCW Heat Exchanger
2-1.
In explanation,
the licensee
stated that the
statement
regarding the low probability of tube plugging was made reflecting
the revised maintenance
policy which required tube scrapping
each outage.
The February
1994 response
also stated that the licensee
would change their
monthly surveillance
procedure to add trending of the differential pressure
across
the heat exchanger.
The inspector noted that differential pressure
trending would not provide data
on the rate
and degree of scale buildup.
It
appeared
to the inspector that the licensee
had
assumed,
rather than
demonstrated,
that scraping
once
an outage would prevent tube blockage.
Factors
such
as the level of voltage
used for cathodic protection were not
assessed
for their affect on the rate of scale buildup.
At the exit
interview, the licensee
committed to trend the rate of scale buildup in the
CCW heat exchangers
and to assess
the adequacy of the impressed
voltage.
4.
INSTRUMENT LINE SILTING
During testing
conducted
in February .1994 the licensee
found that silting of
the differential pressure
instrument lines
had occurred.
The silting caused
errors in the indicated differential pressure
across
the heat exchanger
estimated
by the licensee to be
up to 25 inches.
The licensee
stated that
they would establish
a regular cleaning maintenance
task to preclude
repetition.
The licensee
had not assessed
the significance of the silting.
This is
a followup item (Followup Item 50-275/94-08-04).
-10-
ATTACHMENT
PERSONS
CONTACTEO
Pacific
Gas
and Electric
Com an
+*W.
M.
J.
+*T
- M.
K.
C.
G.
R.
J.
J.
H. Fujimoto, Vice President,
Nuclear Technical
Services
J.
Angus,
Manager,
Technical
and Support Services
A. Sexton,'anager,
Nuclear Regulatory Services
L. Grebel, Supervisor,
Regulatory Compliance Supervisor
E.
Leppke, Assistant
Manager,
Technical
and Support Services
S. Smith, Mechanical
Engineer,
Nuclear Engineering Services
P.
Rhodes,
Senior Engineer
L. Starnes,
Mechanical
Engineer,
Technical
and Ecological Services
B. Clark, Director of Nuclear Engineering Services
Kelly, Mechanical
Group Leader,
Nuclear Engineering Services
R. del
Mazo, Director of Mechanical
Engineering
Contractor for Pacific
Gas
and Electric
Com an
R. J. Bell, Director of Engineering,
Heat Exchanger
Systems,
Inc.
F. L. Steinert,
Senior Scientist,
Aquatic Systems
Inc.
- Denotes those attending the exit interview on March 1,
1994.
+*Denotes those attending the exit interview on March 8,
1994.
EXIT MEETING
An exit meeting
was conducted
on March
1 and March 8,
1994, with the
.
licensee
representatives
identified above.
The inspector summarized'he
scope
and findings of the inspection
as described
in this report.
The
licensee
did not identify as proprietary
any of the materials
reviewed
by
or discussed
with the inspectors
during this inspection with the
exception of some of the Westinghouse
calculations
which were marked
as
"Proprietary Class 2."