ML16342B927
| ML16342B927 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 10/30/1992 |
| From: | Royack M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341G757 | List: |
| References | |
| 50-275-92-27, 50-323-92-27, NUDOCS 9211180221 | |
| Download: ML16342B927 (38) | |
See also: IR 05000275/1992027
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report No.:
Docket No.:
License Nos.:
Licensee:
Facility Name:
Inspected at:
Inspection Conducted:
Inspectors:
'0-275/92-27
and 50-232/92-27
50-275
and 50-323
Pacific Gas
and Electric Company
,Nuclear
Power Generation,
B14A
77 Beale Street,
Room 1451
P. 0.
Box 770000
San francisco, California 94177
Diablo Canyon Units
1 and 2,
Diablo Canyon Site,
San Luis Obispo
County, California
September
14 through October 8,
1992
C. Clark, Reactor
Inspector
C. Myers, Reactor
spector
Approved by:
~Sugar:
oyac
,
sng
ie
,
Engineering
ection
l< 3'2-
a e
cygne
ns ection from Se tember
14 throu
h October
8
1992
Re ort Nos'.
50-275 92-27
and 50-323 92-27
I
d:A
ii
i ii i ii
i iiii iiigi
U
1 Inservice Inspection (ISI), Inservice Testing
(IST) and the
Erosion/Corrosion
Monitoring Program.
Inspection procedures
Nos.
49001,
73753,
73755,=- and 73756 were used
as guidance for this inspection.
General
Co cl s'ons
and
S ec fic findin s
~i
The licensee is developing
an Erosion/Corrosion Monitoring Program consistent
with their commitments to the recommendations
Program strengths
were found in the areas of continuity and engineering
~
~
~
~
~
~
~
~
~
~
~
involvement, experience
and management
support.
Program weaknesses
were
identified in the areas of inspection
personnel
qualification, post-mortem
component inspection, grid area
scanning
inspection technique
and guality
Assurance
involvement.
9211180221
921030
ADOCK 05000275
Q
service
Ins ection:
Except for two hydro tests
the observed Unit I Inservice Inspection activities.
met pr'ogra'm requirements.
serv'ce Testi
The Inservice Testing
(IST) procedures
which were reviewed appeared
to provide
minimum guidance
and instructions to personnel
performing IST Surveillances.
The licensee
appeared to depend
on the 'skill of the craft" of personnel
performing tests
and evaluating
IST data to ensure that all program
commitments
were met.
S
'f cant Safet
atters:
None.
mmar
of
tions
One violation was cited for a'failure to maintain the required
annual vision
test certification for an ISI examiner
(Section 3.3).
A second violation was
cited for a failure to measure
IST vibration data at the location required
by
ASME Code
and to issue
an Action Request
when the nonconformance
was
identified (Section 4.2).
P
0 en Item Summar
During this inspection,
there were no new open items identified.
e
1.0
Persons
Contacted
~TIGRIS
Paci ic Gas
and Electric
Com an
2.0
- S. Banton, Director, Plant Engineering
- H. Burgess,
Director, System Engineering
- L. Cossette,
Plant Engineering,
Senior Engineer
<<H. Coward,
System Engineering
<<W. Crockett,
Hanager,
Support Services
- D. Gonzalez,
Director, System Engineering
- L. Goyette,
Nuclear Engineering
and Construction Services
(NECS),
Onsite Plant Engineering
Group
(OPEG)
- T. Grebel,
Regulatory Compliance Supervisor
- C. Hartz, equality Assurance
Engineer
- D. Hoon, Regulatory Compliance Engineer,
- C. Pendleton,
System Engineering Senior Engineer
<<J. Shoulder,.
NECS/OPEG
- R. Taylor, guality Assurance
- R. Thierry, Regulatory Compliance Senior Engineer
<<J. Townsend,'ice
President
and Plant Hanager,
Diablo Canyon Operations
- A. Young, guality Assurance,
Senior Supervisor
The inspectors
also held discussions
with other licensee
and contractor
personnel
during the course of the inspection.
<<Denotes
those individuals attending the exit meetings of
September
18,
1992, October 2, 1992,
and/or participating in the
telephone exit on October 13,
1992.
ns ection of Erosion Corrosion Nonitorin
Pro rams
49001
2.1
Introduction
2.2
The purpose of this inspection
was to evaluate
the licensee's
long term
erosion/corrosion
(E/C) monitoring program to determine
(1) if the
program was being conducted
in accordance
with NRC guidelines established
"Erosion/Corrosion-Induced
Pipe Wall
Thinning," (2) if the program was being conducted in accordance
with
licensee
commitments
and procedures,
(3) if management
control problems
or generic weaknesses
existed,
and (4) if guality Assurance
(gA) or
independent
reviews of the program have been conducted.
Erosion/Corrosion monitoring is generally conducted
on non-safety related
carbon steel piping.
No specific regulatory requirements
apply to the
content of the licensee's
program.
ro ram De cri tion
The licensee
had initiated
a program for long term monitoring for pipe
wall thinning due to erosion/corrosion
in 1987 during the first Unit 2
refueling outage
(2R1).
To analytically predict locations most
.susceptible
to pipe wall thinning, the licensee
used the
CHEC/CHECHATE
computer codes
developed
by the Electric Power Research
Institute.
The
licensee
has repeatedly
inspected
areas identified by their analysis
as
being susceptible
to E/C to obtain actual, wear rates.
According to the
licensee,
E/C wear. measurements
had been obtained during'our
outage~
in
each Unit.
From the examination data,
the licensee
had established
actual
wear rates for replacement
projections
and for feedback into their
analytical
program.
The licensee, identified that their program was documented
and implemented
'hrough
the following procedures.
~
Nuclear Plant Administrative Procedure
NPAP-D-300, "Honitoring of
Erosion/Corrosion
Induced
Pipe Wall Thinning," Revision 0, dated
Harch 2,
1990.
~
Hechanical
and Nuclear Engineering
Department Instruction I-66,
"Pipe Mall Thickness
Heasurements
for the Erosion/Corrosion
Program," Revision 6, dated August 26,
1991.
Hechanical
and Nuclear Engineering
Department Instruction I-67,
"Acceptance Criteria for Piping Erosion/Corrosion,"
Revision
1,
dated
December
1,
1991.
~
Nondestructive
Examination
Hanual
Procedure
N-UT-ll, "UT Thickness
Heasurement
Using
A Digital Thickness
Gage," Revision
1, dated
Harch 15,
1991.
The licensee
also identified that new procedures
were being developed to
formalize and consolidate the E/C program requirements.
The licensee
had
scheduled
the new procedures
to be implemented
by Harch 1,
1993.
The
inspector reviewed the following draft procedures
for information.
~
Inter-Departmental
Administrative Procedure
IDAP-XXX,
"Erosion/Corrosion
Program Interfaces
and Responsibilities"
~
Department
Level Administrative Procedure
DLAP-XXX,
"Erosion/Corrosion
Program Technical
Requirements"
The inspector
reviewed the licensee's
program documents
and implementing
procedures
and found them to conform with the licensee's
commitments
submitted in their July 19,
1989,
response
to GL 89-08,
"Erosion/Corrosion-Induced
Pipe Wall Thinning."
2.3
ro ram lm lementa io
The inspector
reviewed the method which the licensee
was employing to
determine
E/C wear rates,
the pipe
and components
to be inspected,
the
documentation
and calculations that supported
the analysis,
inspection
data feedback to the analysis
group
and actions taken for degraded
conditions.
Items noted
by the inspector during this inspection
are detailed below.
2.3.1
nal sis
ro ram
The inspector determined that the licensee
used the
CHEC and
CHECNTE computer
codes
developed
by the Electric Power Research
Institute
(EPRI) to identify and prioritize susceptible
locations
for erosion/corrosion
weat
.
The
CHEC code
was applied for ana1ysis
of single phase fluid systems,
and the CHECNTE code
was used for
two phase fluid systems.
The licensee
used these
programs
along
with other industry information and experience
to identify and rank
suspect
locations in piping systems for inspection.
The inspector determined that only the initial'CHEC/CHECNTE
predictions=without inspection data feedback
were used
by the
licensee in their program.
The licensee referred to this initial
calculation
as the
Pass I CHECNTE calculation.
The licensee
used
the
Pass
I results to identify and rank the susceptible
wear areas
for inspection.
Subsequent
inspection data
was input to the
program by the licensee
in their Pass
2 CHECNTE calculation,
but
these results
have not been
used to date.
Instead of using the
Pass
2 CHECNTE calculation the licensee
used
an in-house calculation to quantitatively predict remaining
pipe
wall thickness
and acceptable
remaining time in service.
The
inspector
found that all acceptance criteria identified in licensee
procedure
I-67 were based
on the use of data from this in-house
calculation.
Although the cosputer
codes also predicted
E/C wear
rates,
the licensee
had developed their in-house calculation
due to
the poor correlation of the computer
code predictions with
inspection results.
According to the licensee,
their ana1ysis
technique
represented
an improvement in accuracy
over the
CHECNTE
code.
The inspector considered 'the licensee
technique to be adequate
but
emphasized
the need to incorporate conservative
margins in their
acceptance
criteria commensurate
with the degree of uncertainty in
their ana'lysis at the time.
The licensee
acknowledged
the
inspector's
concern.
The inspector determined that the licensee's
program incorporated
measures
for self improvement. of the correlation with .the computer
codes.
For example, metallurgical evaluation of pipe materia)
composition for areas
found with unexpectedly
low wear was being
conducted
during the outage
inspections
in an attempt to identify if
slight amounts of chromium were present
which would affect their
modeling input data.
The inspector determined that the, licensee
was actively involved in
the
CHEC/CHECMATE user's
group
(CHUG) and
had
been
a lead user for
-qualification of the computer codes.
The inspector determined that
current industry experience
was clearly reflected in the licensee's
activities in developing their program.
For example,
recent
international
experience
indicating E/C passivation
due to copper
deposition in the porous oxide layer (magnetite)
formed on the pipe
surface
was being investigated
by the 'licensee
by analyzing the
oxide layer of unexpectedly
low wear areas'.
Based
on review of the licensee's
analysis
and inspection results,
the inspector concluded that the licensee's
program adequately
identified E/C wear areas
and initiated actions to preclude
excessive
thinning of those area.
The inspector
observed that the
program was established
to define
and expand inspection locations
for future outages
and schedule
repairs or replacement.
Selection
Cr ter
a
I
-The inspector
reviewed the licensee's
system selection criteria for
determining which systems
would be included in their E/C program.
The inspector
observed that the licensee
had established
a line
se1ection criteria which followed the guidelines contained in NRC
Bulletin 87-01, "Thinning of Pipe Walls in Nuclear Power Plants,"
and
The inspector
reviewed system parameters
for four
included systems
and four excluded
systems
and concluded that th'
selection criteria had been properly applied.
at
In ut
The licensee recently
had all computer
code axleling and data input
performed
by a contractor
including independent
review.
According
to the licensee,
a scheduled
review of the contractor report for
accuracy
and errors
had not yet been performed.
The licensee
planned to perform their own
CHECKMATE analysis
beginning with the
Unit I Fifth Refueling outage
(IR5) data.
The inspector reviewed the licensee's
in-house calculation
No.
92120-C-Ol, Revision 0.
The inspector determined
the data
was
accurate
and independently
reviewed.
The inspector reviewed the heat balance
inputs
and modeling of
selected
systems to verify that the correct data
had
been input for
the ranking of the lines.
The inspector concluded that the, licensee
had utilized appropriate
sources of input data
and had accurately
input the data 'for analysis.
The licensee identified suspect
wear areas for inspection during
outages
based
on the priorities determined
by the
E/C program prior
to the outage.
An outage report documenting the inspection results
5
and recommendations
for future repairs or replacements
was prepared
after each outage.
The inspector reviewed the outage inspection=plan for Refueling
Outage
1RS which was currently in progress.
The scope of the
licensee's
inspection effort included
167 locations which has
expanded
from the initial 60 locations at the beginning of their
program.
The inspector
observed that the number:of licensee's
inspections
to exceed the average
number of inspection locations of
other facilities.
The inspector
observed that the licensee
had completed all analyses
of all high energy large bore piping systems with the exception of
the Gland Steam
System which was to be completed
by December
31,
1992.
The inspector
observed ultrasonic
(UT) inspection in progress.
The
inspector noted that the licensee utilized a china marker to lay out
the grid pattern
and identify inspection points.
The inspector
was
'concerned
that the marks did not appear to be permanent to ensure
repeatable
measurement
points for future inspections.
According to
the licensee,
they had experienced
acceptable
longevity using the
china 'markers after changing
from using high temperature
paint dots.
The inspector
observed that the licensee utilized an inspection grid
pattern which differed from the Nuclear Utility Management
and
Reso'urce
Council
(NUHARC) recommendations
contained in Appendix'
to
'UREG-1344.
The licensee
used
a grid with uniformly spaced
inspection points.
The licensee
considered their grid technique to
result in equivalent inspection coverage.
Probleas with this
licensee's
inspection technique is further discussed
in Section
2.3.6.5.
The inspector concluded that the scope of the licensee's
inspections
was adequate.
s ector
a i
cat'ons
The inspector reviewed licensee
procedure
N-UT-11 and
had
discussions
with two inspectors
performing
UT inspections to
determine their understanding of the
E/C program,
the proper
use of
the
UT instruments
and the importance of accurate grid locations for
future inspections.
The inspector found that the latest revision of
the procedure
was in use
and that the personnel
had been certified.
The inspector
observed that the licensee utilized Nuclear
Engineering
and Construction Services
(NECS) personnel
to layout the
grid patterns
and to perform the
UT inspection.
The certification
of these
personnel
was limited to the use of a digital thickness
gage.
The inspector
reviewed the certification standard for
qualifying personnel
conducting nondestructive
examinations
(NDE),
American Society for Nondestructive Testing
(ASNT), Recommended
2.3.6
2.3.6.1
Practice
No.
SNT-.,TC-1A, "Personnel
gualification and Certification
in Nondestructive Testing,"
and concluded that
a limited
certification was provided for within the standard.
The inspector=
noted that the limited certification required only abbreviated
inspection training consisting of
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> instruction
and
a
demonstration of mastery of the proper
UT inspection skill.
The
licensee justified their certification of inspection
personnel
under
ASNT-SNT-TC-lA on the basis that only minimal inspector skill was
required to accurately obtain the SNT-TC-lA data with the digital
thickness
gage.
The inspector considered
the inspection personnel certification and
training to be
a weakness
in the licensee's
program,
based
on the
observations
of work discussed
in the following section.
Observation
o
Work in Pro ress
The inspector
observed
several deficiencies in the performance of UT
inspectors while observing work in progress.
Grid Point Measurements
The inspection data
was not being obtained at the proper grid point
locations.
According to the licensee's
procedure,
the data
was to
be obtained at
a location immediately adjacent
and downstream of the
marked grid intersection.
The inspector
observed that all couplant
gel marks were upstream of the grid marks.
The inspector identified
. his observations
to the supervisor
who also observed
the error and
immediately corrected the personnel.
All measurements
were
subsequently
repeated for the component
using the correct grid point
locations.
The inspector observed other component
inspections
and
'found the data points to be appropriately located.
2.3.6.2
.
Cou lant
Ge
A lication
The'couplant
gel
was not being applied properly.
According to the
supervisor,
the personnel
had been trained to apply the couplant gel
to the component at the inspection location and work the gel into
the surface
by hand prior to positioning the
UT probe at the area.
The inspector observed
the personnel
dip the
UT probe into a supply
of gel
and position the
UT probe
and gel
on the component surface.
The supervisor corrected
the individuals on the proper technique for
applying the couplant gel.
The inspector reviewed licensee
Nondestructive
Examination Report
. 420DC-89.380,-
"Diablo Canyon
Power Plant the Effect of Scale
.and
Ultrasonic Thickness
Measurements,"
issued .May 16,
1989.
This
report identified that couplant application technique
can have
a
substantial
effect on the accuracy of the measured
thickness.
2.3.6.3
2.3.6.4.
ibr t'o
lock Cont ol
The calibration block- used for field calibration of the
UT thickness,
gage.did
not contain
a unique identification nor was it under the
'ontrol
of the licensee's
measuring
and test equipment
(H&TE)
program to assure
appropriate
accuracy
and traceability.
easurin
Instrument Control
2.3.6.5
The UT thickness
'gage
was not under the control of the licensee's
NOTTE program.
The field calibration which was performed consisted
of only a single point calibration'sing
the calibration block.
ns ection Techni
ue
2.3.6.6
The inspection technique
measured
data at only discrete points
and
did not incorporate
any scan of the area
between points to assure
that localized minimum wall areas
were detected.
NUHARC inspection
guidance
recommends
several
scanning
methods for various grid types.
The inspector
found this to be
a weakness
in the licensee's
inspection
program.
During the inspection, this weakness
bec'arne self-evident
when the
licensee
found a section of removed piping from the
NSR high-
pressure
drain line which had extensive localized wall thinning in
areas
between the inspection points.
While the pipe wall was
expected to have
a remaining thickness
in excess of the minimum
- allowable thickness of .154 inches,
the actua1
minimum wall
thickness
was found to be .024 inches in localized areas
which were
not identified by UT inspection.
The licensee
acknowledged the inspector's
concern
and identified
that selective
scanning
was occasionally
performed in areas of
particular interest.
The licensee
indicated that the adequacy of
their routine inspection technique
would be reviewed
as part of
their investigation of the unexpected
wear results
for', the replaced
pipe.
Mork Order Control
The inspection activity was not specifically conducted
under the
authority of a work order.
The inspector
found that
an outstanding
work order only directed the preparation
and restoration of the
component for the inspection.
The work order did not specifically
identify performance of the inspection activity through the
implementing procedure
I-66.
The inspector found this to be 'a
weakness
in the implementation of the
E/C program using established
plant procedures.
onclusion
The inspector
concluded that the control of .inspection
instruments,
inspector qualification and the poor correlation of measured
wear
with analytic predictions
were weaknesses
in the licensee's
program.
The licensee
acknowledged
the inspector's
concerns
and indicated
that they are continuing to follow industry initiatives to improve
the accuracy of the
UT technique for the measurements
of E/C wear.
aterial
Re airs
and
Re lacements
The inspector reviewed several
corrective actions initiated by the
licensee
as
a result of identified E/C wear,
The inspector
concluded that the licensee
had replaced
large portions of the
extraction
steam lines with more'esistant
material.
The inspector
concluded that the corrective actions
were performed in accordance
with established
plant procedure.
The inspector
observed that
UT inspection of degraded
components
was
not routinely performed prior to their scheduled
replacement..
Furthermore after removal of the degraded
component,
no confirmatory
inspection
was routinely performed
.
According to the licensee,
a
removed
component
would be saved for inspection only if it was of
particular interest.
The inspector pointed out the opportunity
provided by post-mortem examination of degraded
components
to
confirm the accuracy of the
UT inspection technique,
as well as to
validate the licensee's
analytic predictions of E/C wear rates.
The inspector considered this lack of feedback of post-mortem
inspection data to be
a weakness
in the licensee's
program.
The
.
licensee
acknowledged
the inspector's
concern
and indicated that
they are following the industry actions
underway to address
measurement
accuracy
and would incorporate
improvements
which were
identified.
The licensee identified the following areas
as high wear areas
based
on their E/C program predictions
and actual plant inspections:
(FWHTR) drain lines
2. extraction
steam lines
3. main steam reheater
(HSR) drain tank pump discharge line
4. feedwater
regulating valve bypass line
5.
NSR low pressure
scavenging
steam line
Additional areas of concern which have lower actual
wear rates
included:
(SG)
blowdown line
2. main feedwater lines
3. main condensate
lines
9
'I
The inspector
concluded that the licensee's,
program .incorporated
adequate
corrective actions for components with identified E/C pipe
wall thinning.
I
Pro ram Mana ement
ualit
ssu
a ce Overview
,The inspector
reviewed the management
of the licensee's
program
and
had the following observations.
Pro ram Res onsibil t
The inspector
observed that the responsibilities for administering
the licensee's
program were identified in licensee
procedure
D-300.
The inspector
reviewed the licensee
procedure
and concluded that the
'program responsibilities
were adequately
defined.
ualit
Assurance
The inspector
observed that the guality Assurance
department
had not
been significantly involved in the development of the licensee's
program.
There
had been
no audits of the program nor specific
surveillances of the inspection activities to assess
the adequacy of
the program or the quality of its implementation.
The inspector
considered this to be
a weakness
in the licensee's
program.
The licensee
acknowledged
the inspector's
concern
and identified
that
an audit of the
E/C program was planned for the
1R5 outage
as
part of the guality Assurance
department
outage
management
inspection.
The inspector reviewed the audit plan for the
inspection
and found it comprehensive.
The inspector concluded that
,the lack of gA involvement had been
a weakness in the program which
the licensee
appears to be addressing
during the current outage.'
Lon
Term Strate
The inspector
observed that the licensee's
program did not currently
include
a long term strategy for reducing general
E/C wear rates
as
recommended
by the
EPRI guidelines.
The licensee's,
program was
designed for long term monitoring for E/C wear and component
repair/replacement
with more resistant material
as required.
The licensee
considered
that the relatively high rates of E/C wear
which they have experienced
in several
systems
was the direct
consequence
of plant operation at relatively low Ph (8.7-9.0) with
an aneonia
based
secondary
chemistry.
The licensee
indicated that
a
change in secondary
chemistry to increase
the
Ph was being
considered
by an engineering task force as
a possible plant
betterment
for long term corrective action.
The inspector concluded that the licensee
was still 'developing their
long term strategy for reducing
E/C wear.
10
ummar
of
C
o ram Stren t
s
d Weaknesses
2.4.1
The inspector identified specific strengths
and weaknesses
in the
implementation of the licensee's
E/C program.
~Stren ths
2.4.1.1
Co tinuit
and
n ineerin
o vement
The
NECS engineering
personnel
developing
and supervising the
program were involved in the program since its inception.
The
personnel
have
a good working knowledge of the program
and its
limitations and have developed
the program with a defense-in-depth
philosophy.
The, personnel
have
a keen
awareness
of the cause
and
effects of E/C, particularly in the areas of localized effects which
are not modeled
by the computer codes,
such
as throttling
cavitation.
2.4.1.2
erience
2.4.2.3
'.4.2
Actual plant problems
and experience with E/C have
been incorporated
into the
E/C program
and are
a cornerstone
in the licensee's
program.
ana
ement
Su
ort
Management attention
and support of the
E/C program
and its
development
have
been evident in the high level
awareness
of the
program
and involvement in industry initiatives.
Weak esses
2.4.2. 1
Ins ection Personnel
ualif cation
2.4.2.2
Plant inspection
personnel
were not utilized to obtain inspection
data.
Abbreviated inspection training for NECS personnel
established
minimal qualification and experience.
ost-mortem
Com onent Ins ect'on
Components
were not routinely inspected after repair or replacement
to verify measurement
accuracy or predicted
wear rates.
2.4.2.3
Grid Area Scanni
Ins ection Techni
ue
UT inspection technique did not incorporate routine scanning of the
grid area
between discrete intersection points to assure
minimum
wall thickness location were identified.
2.4.2.4.
ual it
ssui ance
Involve
t
guality Assurance
involvement in the developmerit
and implementation
of the
E/C program
had
been peripheral.
2.4.2.5
Calibration Block Control
The calibration block used for field calibration of the
UT thickness
gauge did not contain
a unique identification with tr aceability to
its material or verification of its dimensional configuration.
'hile there is no specific regulatory requirements
applicable to E/C
calibration blocks, industry practice is to normally have
traceability of calibration blocks to associated
documents/records.
2.4.2.6
UT Instrument Calibratio
Control
The
UT thickness
was not under the control of the licensee's
M&TE program
and did not appear to receive
any periodical
calibration/linearity checks.
While there is no specific regulatory
requirement applicable to UT instruments
used for E/C work, industry
practice is to have measurement
equipment cal,ibration/linearity
periodically checked.
2.4.2.
i~it
k
t
The work orders
issued for E/C inspections
only directed the
preparation
and restoration of the components'or
the inspections.
The work orders did not specifically identify performance of the
inspection activities.
While there is no specific regulatory
requirement applicable to the procedural
control of E/C inspection
activities, the industry normally standardizes
the processes
at
a
facility for continuity of inspection/work activities.
2.5
Conclusion
The inspector concluded that the licensee
was developing
a comprehensive
program for long term monitoring of E/C in accordance
with thei,r
commitments to GL 89-08.
The program applied generally to non-safety
related
carbon steel
piping.
Limitations in the accuracy of the
predictive state of the art were recognized.
Weaknesses
in the
implementation of the program through established
plant procedures
indicated
a lack of lateral integration of the E/C program into the plant
as it transitions
from an engineering project to'n established
long term-
plant program.
No violations or deviations
from regulatory requirements
were identified.
3.0
Inserv'ce
Ins ection - Observat'on of Work and Work Act'v'ties
73753
3.1
The inspector
reviewed
samples of Unit I Inservice Inspection (ISI) work
activities in progress
to- ascertain that repair and replacement
of
-components, were being performed in accordance
with applicable
12
requirements.
Examination personnel
observed during this review appeared
to'be knowledgeable
.and performed the examinations
in an acceptable
manner.
The licensee
was conducting the Unit
1 fifth refueling outage
.
(IR5).
3. 1. 1.
-
Ultrasonic examinations of the transition pipes at each feedwater
nozzle of the Unit
identified that the short
piece of pipe should
be replaced.
The licensee
issued
Design
Change
Package
(DCP)
No. P-47662 to accomplish this work for all four steam
generators.
The transition pipes (approximately
2 inches long) were
sections of the original-16 inch outside diameter piping left
attached to the feedwater nozzles after nozzle weld repair in 1977.
Unit 2 steam generators
did not have these
two inch pieces of
transition pipes installed.
Additional
NRC followup of this problem
is documented
in Inspection
Report
No. 50-275/92-31.
3.1.2
Ultrasonic examinations of the nozzles
on the four Unit
1 emergency
core cooling system accumulator
tanks identified nozzle cracking in
tank 1-4, nozzles
C-B, C-1B,
and the skirt coupling off
nozzle
G, which were all replaced
in accordance
with instructi.ons
issued in DCP No. N-47241.
The licensee
issued instructions to
perform eddy current examination of all nozzles in the four tanks
(from inside -the tanks).
Licensee
acceptance criteria required the
replacement
of any 2 inch and smaller accumulator nozzle or skirt
couplings that showed indications of Inter-Granular Stress
Corrosion
Cracking (IGSCC).'s of October 20,
1992,
no additional nozzles or
skirt couplings were replaced
in Unit
1 tanks.
The Unit 2
nozzles
and skirt couplings were inspected,
repaired
and/or replaced during the last refueling outage
(2R4).
3.2
The inspector
reviewed the current ISI plan and schedule:-to
determine if
changes to the ISI plan had been properly documented
and approved.
No
concerns
were identified.
l
3.3
The inspector
reviewed the qualifications
and certifications of the
inspection
personnel
involved in work activities in progress.
No
concerns
were identified.
The inspector also reviewed the qualifications
and certifications of a sample of contractor
and maintenance
examination
personnel
who had performed ISI activities during this outage.
The
inspector identified the following failure to maintain required personnel
qualifications.
~
On September
4,
1992,
a licensee
Level II visual examiner from the
maintenance
department
observed.two
System
14,
Code Class III,
hydrostatic pressure tests
and completed
two data sheets
(Attachments
B, Report of Section XI System Pressure
Test
2-1).
However,
as of October
1,
1992, this examiner did not'ave
a
current Vision Test Certification in the licensee's
qual,ifications
and certification files.
13
On October 5,
1992, the licensee
provided information to the
NRC that
identified that
as of October
1,
1992, the subject
examiner Vision Test
Certification had expired January
4,
1992.
The licensee
issued Action
Request
(AR) number A-279236 to identify this non conformance
and to
identify that the subject
examiner
had successfully
renewed his Vision
Test Certification on October 2,
1992.
Licensee
Procedure
No. 2. 1, "gualification and Certification of
Personnel,"
Revision No. 6, states
in part that:
~
Section l. 1, "This procedure establishes
criteria for qualification
and certification of PG&E personnel
whose jobs require appropriate
knowledge of the technical principles applicable to the
,nondestructive
examinations
they perform.
This procedure
meets the
requirements
of the following Codes:
1. 1. 1 American Society for
Nondestructive
Tested
Recommended
Practice
SNT-TC-1A, 1980,
Edition...ASME Boiler and Pressure
Vessel
Code,Section XI, 1977
Edition through
Summer
1978 addenda..."
~
Section
7. 1. 1,
"The visual activity and color vision (physical)
examination shall
be performed annually..."
Under paragraph
8. 1. 1 Physical,
Paragraph
8.1.1(4) of Recommended
Practice
No. SNT-TC-1A states
in part that "The examination
should
be
administered
on an annual
basis.
Subartice
IWA-2300(e) of the subject edition and
addenda of the
ASME Code
states
in part that "Nondestructive examination
personnel
for all methods
shall
be examined...personnel
vision examinations shall
be conducted
.
annually."
=
'he
failure of the Level II visual examiner,
who performed the September
4,
1992,
System
14 hydrostatic pressure tests,
to have
a current
annual
vision examination is considered
an apparent violation (50-275/92-27-01).
A similar violation (50-323/83-04-01)
was issued
nine years earlier in
Inspection -Reports 50-275/83-05
and 50-323/83-04.
The inspector
observed that apparently there were examiners
from at least
two different licensee
departments,
the ISI Department
and the Mechanical
Maintenance
Department,
performing
ASME Code Examinations.
Each
department
maintained qualification and certification records for their
own personnel.
The lack of consolidated
records or a status list of all
examiner records
may have contributed to the failure to maintain
a
current visual certification for the examiner.
As part -of the licensee
corrective actions to address this nonconformance,
the licensee
identified that they would evaluate consolidating all examiner records at.
one location
and establishing
an updated,
consolidated
status list for
all examiners
performing Section
XI examinations.
0
14
3.4
0 c
s ons
4.0
In general,
the inspector
concluded that the licensee
was implementing
a
comprehensive
inservice inspection
program
and that work was adequately,
performed except for the hydrostatic pressure
testing verified by the
examiner with the expired Vision Test Certification.
nservice Testin
of Pum
s and Valves
73756
4.1
The inspector
reviewed
a pump surveillance activity to determine whether
Technical Specification requi} ements
and licensee
commitments for
inservice testing
(IST) were being met.
On October 1,
1992, the
inspector observed
performance of a Unit 2 Technical Specification
surveillance
performed per test procedure
STP P-6B, Revision 24, "Routine
Surveillance Test of Steam-Driven Auxiliary Feedwater
Pump."
Section
1. 1
of procedure
STP P-6B identified that the
pump was required to be tested
in accordance
with the
ASNE Code,
Section
XI and Technical
Specifications.
The inspector identified the following:
ocedure
Weakness
4.2
Step 10.23 of STP P-6B stated
in part,
"Obtain the Following Vibration
Data,"
and provided
a sketch with a single arrow pointing to the top of-
the test point locations, with a table to record both
a horizontal
and
a
vertical vibration measurement
for each of the four test points.
There
were no procedure
instructions specifying where to place the vibration
pickup probe to ensure continuity between data measurement<from
surveillance to surveillance.
Since different locations
may provide
different results, continuity between vibration measurement
locations is
required to ensure
acceptable
data trending
and evaluation.
The
licensee's
IST engineer
stated that additional instructions specifying
. where
and
how to take vibration data were not required in procedure
P-68, since this information was available to surveillance
personnel.
performing the surveillance
through "skill of the craft."
A weakness
observed
in the performance of vibration measurement
is further discussed
in Section 4.2.
est Performance
Weakness
The inspector noted that turbine test points
1 and
2 had blue dots
painted
on the top and side of the bearing housings
and that
pump test
points
3 and
4 did not have
any painted blue dots identifying their
location.
Surveillance
personnel
identified that they, used the procedure
sketch
and skill-of-the-craft to position the pickup probe for pump test
p'oints
3 and 4.
The inspector also noted that surveillance. personnel
could not physically position the probe
on one blue dot for the
horizontal vibration reading at test point 2 and
had actually positioned
the probe
on the
pump side of the blue dot.
The surveillance
personnel
identified that they had received training as
part of the operator training program to take vibration data
on the blue
0
15
dot locations
and in accordance
with the information provided in the
procedure/sketch.
The inspector
noted. that the actions taken
by test personnel
to obtain
the subject vibration data did not appear to meet either the guidance
provided in the procedure or the training.
In response
the licensee
issued
two Action Requests
(ARs).
In AR No. A0279035 the licensee
identified that the blue dots for pump vibration test points 3 and
4 had
been inadvertently painted over.
Action Request
No. A0279061 identified
that the turbine inboard bearing test point 2 horizontal vibration
reading should
have
been taken at the associated
blue dot and not
adjacent
as the inspector
had observed.
It appeared,
after discussions
with the licensee,
that several
surveillances
had been performed prior to
the October
1,
1992, with painted blue dots missing from the
pump
and
an
interference for installation of the vibration pickup probe
on test point
2.
However,
no AR's had
been written identifying the problems.
The licensee
was asked to provide
a copy of the guidance provided to
their surveillance
personnel
for recording
ASIDE Code vibration data.
On
October 6, 1992,
a copy of an instructor lesson guide,
Lesson
NLR9121,
"Vibration Instrument Training," dated
September
12,
1991,
was provided
to the inspector.
Lesson
Guide
NLR9121 was identified as. the only
documented
guidance
issued for taking vibration data.
Section
3 of this
lesson guide,
page
9, states
in part that
"The blue dots are the ones
used
by operations for surveillance testing.
If blue dots are not
present
on
a machine...
an
AR should
be written to resolve the problem."
The inspector reviewed the available surveillance records,
along with
revisions
23 and 24 of surveillance
procedure
STP P-6B and identified the
following:
~
Subsubarticle
IMP-4510 of Division 1 of Section XI of the
ASIDE Code
states
in part that "At least
one displacement= vibration amplitude
{Peak-to-Peak
composite)
shall
be read during each inservice test.
On
a pump coupled to the driver, the measurement
shall
be taken
on
the bearing housing near the coupling."
~
Revision
23 was issued
June
5,
1992.
Section
10.23 incorrectly
identified that vibration data for test point 3 should
be taken
on
the
pump casing instead of on the bearing housing position
as
required
by ASHE Code,
Section XI, Subsubarticle
IWP-4510.
~
Revision
24 was issued
September
25,
1992.
The sketch
on page
15 of
the procedure
was corrected to identify that vibration test point 3
should
be on the
pump bearing housing.
~
Licensee Administrative Procedure
NPAP C-12/NPG-7, "Identification
and Resolution of Problems
and Nonconformances,"
Revision 21,
Section 4. 1 states
in part that "Any individual who discovers
a
problem...
or a nonconformance
exists, is responsible for initiating
an Action Request
(AR)."
As of October
1,
1992, the licensee
had
16
not issued
an
AR identifying that'evision
23 of surveillance
procedure
STP P-6B incorrectly identified where vibration data
was
to be measured.
,Since
an
AR was not issued,
there
was
no documented
evaluation of whether vibration trending
and
pump operability might
be affected.
~
A-review of surveillance
records for Unit 2 pump 2-1 identified that
between
June
5,
1992,
when Revision
23 was issued,
and September
25,
1992,
when Revision
24 was issued,
the licensee
performed five
surveillances
per revision 23.
These five surveillances
were
performed June
10,
17, July 8, August
5 and September
3,
1992;
~
Administrative procedure
NPAP C-3,
"Conduct of Plant
and Equipment
Tests",
Section 4.5.2.2,
states
in part that '"AR's shall
be
initiated in any 'of the following circumstances...
2. any deviation
from procedures..."
The licensee
stated that no AR's were issued to
identify that the above five surveillance tests
were not performed
in accordance
with erroneous
Revision
23 procedure instructions.
'I
The failure to issue
an
AR when Revision
23 of procedure
STP P-6B was
recognized to be not in accordance
with ASIDE Section XI, and evaluate
the
= operability effects
on the auxiliary pump is an apparent violation (50-
232/92-27-02).
Unit
1 pump l-l surveillance testing
may have also been effected
by the
incorrect instructions in Revision
23 to procedure
STP-P-6B.
The licensee
acknowledged the inspector's
concerns
and identified they
were reviewing the applicable
pump surveillances
and revising current
surveillance procedures.
4.3
Conclusions
The inspector identified discrepancies
in a surveillance
observed
during
this inspection.
The inspector identified additional discrepancies
in
the records of past performances
of the
same surveillance.
These
discrepancies
included failure to resolve incorrect instructions in a
timely fashion
and failure to obtain vibration measurments
in accordance
with the guidance
provided in the
ASNE Code
and licensee training
instructions.
The inspector concluded that additional
management
attention
was required in this area.
5.0
Observation of Im lementation of Forei
n Material
E elusion
P o ram
During observation of eddy current activities for inspection of Unit
1
Emergency
Core Cooling System Accumulator Tank 1-3 nozzles
on September
29,
1992, the inspector identified the following:
~
There
appeared
to be
a difference of opinion between
personnel
logging material into and out of the tank manway,
on what items
~
I
17
should
be logged into the identified Foreign Haterial Exclusion
{FHE) area.
~
,The bottom'0 inch nozzle
was identified as
a "High Risk"
FHE area
and
had
a canvas
purge balloon inserted in the nozzle behind
a sheet
metal cover.
A licensee
examiner found the top piece of a
cellophane
wrapper
and pull tab from a cigarette
package prior to-
removing the sheet
metal cover from the
10 inch nozzle in the bottom
of the tank.
When this item was passed
out of the tank manway, the
FHE personnel
appeared
uncertain
on how to handle this item.
Licensee
FHE personnel
could not identify how the identified foreign
material got into the subject tank.
Since smoking is not allowed in
containment,
and general
cleanliness
controls for work in the
subject tank should
have prevented entry of this foreign material
into the tank, the licensee
stated that they would issue
an
AR and
investigate this observation.
The inspector did not observe
a loss of FHE control for the nozzles
during the examinations
observed.
In response
to the inspector's
observation of different opinions
between
FHE personnel
on what material
should
have
been logged into and out the
tank manway for the
FHE area,
the licensee identified:
~
They had implemented the first training classes
for their new
program in June
and July of 1992.
~
They were still performing training to implement the program
and
clarify procedure instructions.
~
This concern would be reviewed with FNE personnel
to clarify any
uncertainty.
Conclusions
The inspector concluded that the licensee
was implementing
a new
FHE
program which included
new training for personnel
involved in FHE.
The
inspector considered that
FHE controls for the accumulator
1-3 nozzles
were maintained.
The licensee
stated that they would investigate
the
inspector's
observations.
The inspectors
met with the individuals denoted in Section
1 on
September
18,
1992 and October 2,
1992.
The scope
and findings up to
that time were discussed.
The inspectors identified that additional
information had
been requested,
and this information would be reviewed in
the
NRC Regional Office in order to complete the inspection.
Review of
the additional
information necessary
to complete the inspection
was
concluded
on October 8,
1992,
and
a telephone exit was held with the
licensee
pn October
13,
1992.