ML030090566
| ML030090566 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 01/09/2003 |
| From: | Chamberlain D Division of Reactor Safety IV |
| To: | Terry C TXU Energy |
| References | |
| IR-02-009 | |
| Download: ML030090566 (23) | |
See also: IR 05000445/2002009
Text
January 9, 2003
C. L. Terry, Senior Vice President
and Principal Nuclear Officer
TXU Energy
ATTN: Regulatory Affairs
Comanche Peak Steam Electric Station
P.O. Box 1002
Glen Rose, Texas 76043
SUBJECT:
COMANCHE PEAK STEAM ELECTRIC STATION - SPECIAL TEAM
INSPECTION REPORT 50-445/02-09
Dear Mr. Terry:
On November 1, 2002, the NRC completed a special team inspection at your Comanche Peak
Steam Electric Station, Unit 1. The enclosed report documents the inspection findings, which
were discussed during a public exit meeting on December 10, 2002, with you and other
members of your staff.
This inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
Within these areas, the inspection consisted of selected examination of procedures and
representative records, observations of activities, and interviews with personnel.
The report discusses an apparent violation that involves the failure to identify and correct an
indicated flaw in a steam generator tube during Refueling Outage 1RF08 that resulted in a
steam generator tube leak. Based on the results of this inspection, the significance of this
issue is pending the determination of its safety significance using the Significance
Determination Process described in NRC Inspection Manual Chapter 0609. Since your staff
removed the leaking tube from service, it does not present an immediate safety concern.
Since the NRC has not made a final determination in this matter, no Notice of Violation is being
issued for the finding at this time. In addition, please be advised that the number and
characterization of the apparent violation described in the enclosed report may change as a
result of further NRC review.
The report also discusses a noncited violation of very low significance for two examples of
failure to identify significant steam generator tube flaw indications during Refueling
Outage 1RF09.
TXU Energy
-2-
These were evaluated under the risk significance determination process as having very low
safety significance (Green). The NRC has also determined that a violation was associated with
these issues. Because the issue had very low risk significance, and because you entered the
issue in your corrective action program and removed the tubes from service, the violation is
being treated as a noncited violation, consistent with Section VI.A of the Enforcement Policy.
The noncited violation is described in the subject inspection report. If you contest the violation
or significance of the noncited violation, you should provide a response within 30 days of the
date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory
Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to the
Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 611 Ryan Plaza
Drive, Suite 400, Arlington, Texas 76011; the Director, Office of Enforcement, U.S. Nuclear
Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the
Comanche Peak facility.
In accordance with 10 CFR 2.790 of the NRCs "Rules of Practice," a copy of this letter and its
enclosure will be made available electronically for public inspection in the NRC
Public Document Room or from the Publicly Available Records (PARS) component of NRCs
document system (ADAMS). ADAMS is accessible from the NRC Web site at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/ by DAP
Dwight D. Chamberlain, Director
Division of Reactor Safety
Docket: 50-445
License: NPF-87
Enclosure:
NRC Inspection Report
50-445/02-09
cc w/enclosure:
Roger D. Walker
Regulatory Affairs Manager
TXU Generation Company LP
P.O. Box 1002
Glen Rose, Texas 76043
George L. Edgar, Esq.
1800 M. Street, NW
Washington, D.C. 20036-5869
TXU Energy
-3-
G. R. Bynog, Program Manager/
Chief Inspector
Texas Department of Licensing & Regulation
Boiler Division
P.O. Box 12157, Capitol Station
County Judge
P.O. Box 851
Glen Rose, Texas 76043
Chief, Bureau of Radiation Control
Texas Department of Health
1100 West 49th Street
Environmental and Natural
Resources Policy Director
Office of the Governor
P.O. Box 12428
Brian Almon
Public Utility Commission
William B. Travis Building
P.O. Box 13326
1701 North Congress Avenue
Susan M. Jablonski
Office of Permitting, Remediation and Registration
Texas Commission on Environmental Quality
MC-122
P.O. Box 13087
Austin, TX 78711-3087
TXU Energy
-4-
Electronic distribution by RIV:
Regional Administrator (EWM)
DRP Director (ATH)
DRS Director (DDC)
Senior Resident Inspector (DBA)
Branch Chief, DRP/A (WDJ)
Senior Project Engineer, DRP/A (CJP)
Staff Chief, DRP/TSS (PHH)
RITS Coordinator (NBH)
Scott Morris (SAM1)
CP Site Secretary (LCA)
DAPowers (DAP)
SRI:EMB
C:EMB
C:PBA
D:DRS
WCSifre/lmb
EMurphy
CSMarschall
WDJohnson
DDChamberlain
/RA/
/RA/
/RA/
/RA/
/RA/ by DAP
12/19/02
12/19/02
12/30/02
12/30/02
01/09/03
OFFICIAL RECORD COPY
T=Telephone E=E-mail F=Fax
ENCLOSURE
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket:
50-445
License:
Report No.:
50-445/02-09
Licensee:
TXU Energy
Facility:
Comanche Peak Steam Electric Station, Unit 1
Location:
Glen Rose, Texas
Dates:
October 7 through November 1, 2002, onsite
Team Leader
W. C. Sifre, Senior Reactor Inspector
Engineering and Maintenance Branch
Inspector:
E. Murphy, Senior Materials Engineer
Materials and Engineering Branch
Office of Nuclear Reactor Regulation
Accompanying
Personnel:
C. Dodd, Consultant
Approved By:
Charles S. Marschall, Chief
Engineering and Maintenance Branch
Division of Reactor Safety
-2-
SUMMARY OF FINDINGS
IR 05000445-02-09; TXU Energy; on 10/07-11/01/2002; Comanche Peak Steam Electric
Station; Unit 1, Special Inspection.
The inspection was conducted by a team of three inspectors, one regional inspector, one
headquarters inspector, and one contractor. The inspection identified three findings. Two of
the findings are characterized as a noncited green violation and one is characterized as an
apparent violation of NRC regulatory requirements. The significance of this apparent violation
has yet to be determined; therefore, the finding remains unresolved. The risk significance of
the apparent violation remains unresolved. The significance of issues is indicated by their color
(green, white, yellow, red) and will be determined using the Significance Determination Process
described in NRC Inspection Manual Chapter 0609. The NRCs program for overseeing the
safe operation of commercial nuclear power reactors is described in NUREG 1649, "Reactor
Oversight Process," Revision 3, dated July 2000.
A.
Inspector-Identified Findings
Cornerstone: Barrier Integrity
TBD. A failure to identify and correct a clearly detectable steam generator tube flaw indication
during eddy current examinations in the 2001 refueling outage (1RF08) resulted in the tube
remaining in service until it leaked in September of 2002. This is an apparent violation of
10 CFR Part 50, Appendix B, Criterion XVI.
The risk significance of the finding is unresolved pending completion of a significance
determination. This finding is greater than minor because it degraded the ability to meet the
cornerstone objective with reactor coolant system leakage. The finding had potential for
greater than very low safety significance because the tube failed the in situ testing, indicating
that it would not have met the design basis requirements for withstanding analyzed
transients. (Section 02.01)
GREEN. Inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B,
Criterion XVI for two examples of failure to perform adequate steam generator eddy-current
examination in the 2002 refueling outage (1RF09). The inadequate examinations resulted in
analyst failure to properly characterize two steam generator tube flaws until the licensee took
corrective actions in response to questions from the NRC inspectors.
This finding is greater than minor because it degraded the ability to meet the cornerstone
objective of reactor coolant system pressure boundary. The failure to identify the flaws could
have resulted in flawed tubes that might have developed leaks if left in service. The
significance of this finding is very low because the in situ tests demonstrated that the tubes
would have met the design basis requirements for withstanding analyzed transients, and prior
to returning the plant to operation the licensee removed the flawed tubes from service
(Section 02.02).
Report Details
SPECIAL INSPECTION ACTIVITIES
01
Inspection Scope
The team conducted a special inspection in response to a primary-to-secondary leak
that began on September 26, 2002, and the resultant shutdown on September 28, 2002.
The team also reviewed the associated steam generator inspections. The team used
Inspection Procedure 93812, Special Inspection Procedure, to evaluate the
effectiveness of the examination methods used to examine the degraded tube during
the previous outage, and determine whether licensee evaluators missed an opportunity
to identify the degraded tube during the previous outage. The team also evaluated the
effectiveness of the examination methods used during the current outage as it related to
detecting flaws similar to that in the leaking tube. The team assessed the effectiveness
of this approach in precluding the recurrence of this type of event. During the
inspection, the team developed a complete sequence of events related to the primary-
to-secondary leak first identified on September 26, 2002. The team also reviewed the
licensee personnels root cause evaluation for completeness and accuracy, and
Independently verified key assumptions and facts of that evaluation.
In addition, the team evaluated the corrective actions and ensured that the extent of
condition was evaluated.
The team reviewed procedures, logs, and corrective action documents. The team also
reviewed the steam generator eddy current data, and interviewed key personnel,
including eddy current analysts.
02
Special Inspection Areas
02.01 Overview of Shutdown and Sequence of Events
a.
Inspection Scope
The inspectors reviewed the licensees response to the steam generator tube leak and
verified that appropriate actions were taken.
b.
Findings
On September 26, 2002, Comanche Peak, Unit 1, was at 99 percent reactor power,
coasting down with the refueling outage scheduled to begin on October 5. At 5:41 a.m.
the Unit 1 control room received a condenser off-gas alarm, Condenser Off-Gas-182,
with a reading of 4.92E-6 uCi/mL. The alarm setpoint was 4.86E-6 uCi/mL and the
licensee determined by review of the data that the parameter had been running close to
the setpoint for the previous 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Operators notified the chemistry technicians. At
12:43 p.m. the Condenser Off-Gas 182 alarm actuated with a reading of 6.07E-6 uCi/mL
and the No. 2 steam generator main steam line N-16 monitor went into alarm. A
correlation curve reflecting the theoretical equation for the condenser off-gas monitor
was created by chemistry and distributed to the control room. The condenser off-gas
alarm setpoints were adjusted to reflect 30 gallons per day (gpd) and 40 gpd,
-2-
respectively. At 30 gpd, the plant would enter Action Level 1 in accordance with
Procedure ABN-106 and administrative limits. At 40 gpd, maintained for greater than
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, management decided the plant should shut down in a controlled manner. At
10:24 p.m., the N-16 alarm cleared and the reading continued to trend downward.
On September 27, 2002, at 12:19 a.m., the Condenser Off-Gas 182 alarm cleared. At
10:25 a.m., the N-16 alarm returned at an estimated 5.00 gpd. At 10:40 a.m., the
Condenser Off-Gas 182 alarm came in with 9.81E-6 uCi/mL followed by the Condenser
Off-Gas 182 Hi alarm at 10:51 a.m. with a reading of 1.17E-5 uCi/mL. At 1:06 p.m.,
these alarms cleared and peak readings were determined to be 12.8 gpd. These alarms
came in twice more on this day. At 7:54 p.m., the Condenser Off-Gas 182 alarm
reached a peak value of 1.7E-5 uCi/mL and at 10:32 p.m., the Condenser Off-Gas 182
HiHi alarm was greater than the 40 gpd limit at 1.8E-5 uCi/mL. The alarms cleared in
less than an hour so that the shutdown criteria established by licensee management
was not exceeded.
On September 28, 2002, at 1:40 a.m., the Unit 1 control room operators commenced
power reduction in response to the 1-02 steam generator tube leak. The operators
target was to be off-line in 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The Unit 1 control room operators entered
Section 3.0 of Procedure ABN-106. At 3:12 a.m., the Unit 1 control room operators
performed a planned trip of the Unit 1 reactor and entered Mode 3.
Subsequent inspection and testing by the licensee determined the source of the leakage
to be a stress corrosion crack initiating from the outer diameter surface in the u-bend
region of Tube R41C71 of Steam Generator 2. The licensee also determined through
pressure testing that the tube failed to exhibit structural and accident leakage integrity
margins consistent with the plant design and licensing basis.
02.02 Effectiveness of Previous Examinations
c.
Inspection Scope
The team independently reviewed eddy current test data from the previous (1RF08)
inspection in 2001 for the specific tube location where the leakage developed in
September 2002. The team also reviewed the Comanche Peak, Unit 1, Steam
Generator Eddy Current Analysis Guidelines for Refueling Outage 1RF08, Revision 0.
d.
Findings
Introduction. An apparent violation with risk to be determined was identified in that the
licensee failed to identify and correct a degraded steam generator tube during Refueling
Outage 1RF08 and this failure directly resulted in a steam generator tube leak.
Description. The eddy current test techniques employed for Refueling Outages 1RF08
and 1RF09 included bobbin coil inspections of the tube from end-to-tube end and plus-
point coil inspections at special interest locations described in additional detail below.
Data analysis was performed in accordance with the Comanche Peak, Unit 1, steam
generator eddy current analysis guidelines. The guidelines provided for independent
analysis of all data by a primary analyst team and a secondary analyst team. A
-3-
resolution analyst was responsible for resolving differences noted between the primary
and secondary analysis reports. Two independent resolution analysts from the two
analysis teams had to concur before changing an indication of degradation to a
non-reportable status, which would not require further examination. Differences
between the resolution analysts were resolved by the overall lead analyst with the
concurrence of the licensees Level III analyst. In addition, a Level III qualified data
analyst sampled data to ensure that primary, secondary, and resolution analyst
equipment setups were correct and that discrepancy resolutions were performed
properly and the calls were correctly dispositioned.
The primary data analysis was performed by a computerized automatic data screener.
The automatic data screener was a program that had been qualified to the same
standards as the human analysts; i.e., Appendix G of the EPRI Steam Generator
Examination Guidelines and the site-specific performance demonstration. The program
used a rule base established by the licensee that incorporated the indication reporting
criteria in the eddy current analysis guidelines. For each tube, the automatic data
screener listed indications that satisfied the rule base. Each of these indications was
manually dispositioned as part of the primary analysis process.
Freespan indications found by the primary or secondary analysts, and upheld during
data resolution, were designated as freespan differential signals. A history check was
then performed by the resolution analysts to identify a change in the signal response
over time. Those freespan differential signals that satisfied the guideline change criteria
were considered to be potential flaw indications and were assigned an I-code. In the
analysis guidelines for Refueling Outage 1RF08, the change criteria were a change in
the phase angle response greater than 15 degrees, a 0.5 volt change in amplitude, or
no prior indication over the last two cycles. If associated with a ding or dent, the change
criteria was 10 degrees or no prior indication. A ding refers to localized tube wall
deformation at locations between supports. A dent refers to localized wall deformation
at tube support locations. All locations with an I-code were required to be inspected with
a plus-point probe. All tubes with I-codes confirmed by plus-point were required to be
plugged or repaired.
The teams review found that a clearly detectable indication was present at the leak
location during the previous outage (1RF08) inspection in 2001. The flaw indication was
in Tube R41C71 in Steam Generator 2. This indication measured 0.96 volts at 130 kHz
with a phase angle of 93 degrees and 1.79 volts at 300 kHz with a phase angle of 122
degrees. The indication was outside (did not meet) the reporting criteria in the Refueling
Outage 1RF08 analysis guidelines and was not reported by either the primary or
secondary analyst in 2001.
The applicable reporting criteria during Refueling Outage 1RF08 for freespan bobbin
indications in the absence of a dent or ding signal was a phase angle response
corresponding to 0 percent through wall; i.e., a phase angle response of 84 degrees on
the 130 kHz channel and 118 degrees on the 300 kHz channel. The presence of a dent
or ding signal would cause a flaw signal to rotate out of the normal phase angle window.
-4-
In the presence of a detectable ding signal, the applicable reporting criterion was a
phase angle response of at least 155 degrees on the 130 kHz channel. In the presence
of a detectable dent signal, a distortion of the signal on the 550/130 kHz mix channel
was reportable.
Dings and dents are reportable if they equal or exceed 2 volts on 550 kHz channel for
dings or the 300/130 kHz mix channel for dents. Although dings and dents are not
themselves reportable at less than 2 volts, the flaw indication reporting criteria are
subject to the wider phase angle reporting window for dent/ding locations if dings or
dents are detectable, irrespective of whether the ding or dent exceeds 2 volts.
No ding signal was reported at the flaw location during Refueling Outage 1RF08 by the
primary or secondary analysts. The 0 percent through-wall phase angle criteria was
applied to the 130 and 300 kHz signal. This indicated that the analysts did not see
evidence of a ding signal, irrespective of voltage. The team agreed that there is no
clear evidence of a ding in the Refueling Outage 1RF08 signal response. However, the
team observed a large amount of horizontal noise (about 1.75 volts at 550 kHz)
attributable to probe wobble, which could easily mask a 2 volt ding signal.
The team found that the analysis guidelines provided discretion that may be exercised
by the human analysts when interpreting the signals. Paragraph 1.3 of the TXU eddy
current guidelines stated:
The guidance on signal interpretation is not intended to restrict the
analysts. Conditions encountered which are not clearly addressed in the
guidelines shall be brought to the attention of the lead analyst and the
TXU Eddy Current Level III for concurrence and inclusion into the
guidelines. No deviation from the current guidelines is permitted.
Paragraph 6.4.3 of the guidelines stated, in part,
However, signals may be observed that act like flaws yet cannot be
quantified due to signal distortion . . . In such a case, one of the
appropriate I-codes may be used to characterize the indication.
The team concluded that an experienced analyst should recognize that the large wobble
signal could mask a dent that could distort or rotate an indication outside the reportable
phase angle response criteria. In such a case, the guidelines enabled the analyst to
bring the indication to the attention of the lead analyst and the TXU Level III analyst and
for assigning an I-code. The team determined that the analyst should have recognized
the large wobble signal and should have assigned an I-code.
The team concluded that the following factors contributed to the failure to detect the flaw
indication during Refueling Outage 1RF08:
1.
The probe wobble signal masked a ding signal at the flaw location.
-5-
2.
Non-conservative reporting criteria were applied to the flaw signal. As a result,
the ding signal was not identified.
3.
The primary analysis was strictly rule based (being computerized) and, thus, had
no opportunity to exercise discretion in calling the indication.
4.
The secondary analyst failed to report the indication, which was readily apparent.
It appeared that the analyst dismissed the indication based on strict application
of the guideline reporting criteria for non-dinged locations and failed to recognize
that the large wobble signal could potentially mask dings, which could rotate the
indication outside the reportable phase angle response criteria.
The direct consequence of failure to detect the flaw in Tube R41C71 during Refueling
Outage 1RF08 was that the tube was not removed from service and, therefore,
subsequently degraded to the point that it leaked and no longer satisfied the applicable
tube integrity performance criteria. This occurred because the examination methods
used during Refueling Outage 1RF08, including the analysis guidelines, were not
effective for ensuring that tubes would maintain their integrity until the next scheduled
inspection. The team also concluded that the guideline phase angle reporting criteria
were inappropriate in the u-bend region where the high potential existed for large probe
wobble signals, which may mask the presence of dents or dings.
Analysis. The finding is greater than minor because it adversely affected the reactor
safety barrier integrity cornerstone and degraded the ability to meet the cornerstone
objective of controlling reactor coolant system leakage. The finding also was
determined to have potential safety significance greater than very low significance
because it resulted in a steam generator tube leak and the tube failed in situ testing,
indicating that it would not have met the design basis requirements for withstanding
analyzed transients. The final risk determination is pending evaluation using the
Significance Determination Process described in NRC Inspection Manual Chapter 0609.
Enforcement. The team concluded that for the reasons stated above, the licensee
clearly missed an opportunity to have identified the indication during the previous
inspection. The failure to identify and correct the degraded tube during Refueling
Outage 1RFO8 is an apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI
(APV 50-445/0209-01). The licensee has documented this issue in Smart
Form SMF-2002-003142-00. The risk significance of this apparent violation remains
under review by the NRC.
02.03 Effectiveness of Current Examinations
a.
Inspection Scope
The team reviewed the scope of the licensees Refueling Outage 1RF09 inspection
program and the results obtained. Primary attention was directed to the effectiveness of
the licensees inspection program for detecting freespan cracks such as the one in
Tube R41C71 that was missed during the previous inspection during Refueling
-6-
Outage 1RF08. The team also reviewed the Comanche Peak, Unit 1, Steam Generator
Eddy Current Analysis Guidelines for Refueling Outage 1RF09, Revision 4.
b.
Findings
Introduction. A Green noncited violation of 10 CFR Part 50 Appendix B, Criterion XVI,
was identified for two examples of failure to identify steam generator tube flaw
indications.
Description. The Refueling Outage 1RF09 steam generator inspection program
included a full length bobbin coil examination of all tubes in all steam generators. All
locations where I-codes were found by the bobbin coil examinations were subsequently
examined by plus-point probes. For freespan I-codes, the extent of plus-point
inspection was from the nearest support structure (e.g., tube support plate or anti-
vibration support) on one side of the flaw to the nearest support structure on the other
side of the flaw. Additional plus-point inspections were performed for freespan cracks at
the following special interest locations:
All tube spans between adjacent supports containing greater than 5 volt dents or
dings.
A 20 percent sample of u-bend spans between adjacent supports containing
greater than 2 volt dents/dings.
A 20 percent sample of spans between adjacent supports containing bobbin
freespan differential signals, irrespective of whether they were dispositioned as
I-codes based on history review.
A 100 percent sample of spans between adjacent supports containing freespan
differential signals in u-bends.
Revision 4 of the Comanche Peak, Unit 1, steam generator eddy current analysis
guidelines was utilized for the Refueling Outage 1RF09 initial inspection program. As
corrective action to preclude missing flaws, such as Tube R41C71 in Refueling
Outage 1RF08, Revision 4 included the following key changes to the Refueling
Outage 1RF08 inspection.
The phase angle reporting criteria for freespan indications in the absence of
dings/dents was changed to require only that the 130 kHz signal phase angle
response be less than 160 degrees.
A new reporting criterion added that freespan indications in the absence of
dings/dents exhibit a 20 to 200 degree phase angle response at 550 kHz.
The phase angle change criterion for historical review for freespan differential
indications not associated with dings/dents was changed from 15 to 10 degrees.
In addition, wording was clarified that a two cycle look back is required.
-7-
The rule base for the primary analysis auto data screener was updated to reflect the first
two changes above. The third change only affected the resolution process. The team
witnessed application of the auto data screener with the Revision 4 guideline rule base
to Refueling Outages 1RF07 (1999) and 1RF08 (2001) raw bobbin data at the leak
location. In both cases, the auto data screener identified a freespan differential
indication at the location, which eventually leaked prior to Refueling Outage 1RF09.
The licensees inspection program identified 20 single axial indications, including the
leaker, affecting 11 tubes. The single axial indications fell into two different categories.
The first category included 11 single axial indications (including the leaker), affecting
9 tubes, located between the uppermost hot-leg support (H10) and the uppermost
cold-leg support (C10) including the u-bend region. All except 1 of these indications
were associated with a detectable ding or dent. With the exception of the leak
indication, these indications were short and exhibited low voltage responses, indicating
that they had little structural significance.
The second category included 9 single axial indications affecting 2 tubes, R11C42 in
Steam Generator 2 and R7C17 in Steam Generator 3. These indications were not
associated with detectable dings or dents. They appeared to be oriented end-to-end
along a straight line with some axial distance between them.
The team identified the following concerns with the effectiveness of the inspection:
The secondary analyst failed to identify half of the single axial indications
confirmed with the plus-point coil and not involving greater than 5 volt dents or
dings.
Similarly, half of the single axial indications not associated with greater than
5 volt dents had not been detected during the primary analysis of the bobbin
data. In general, these indications exhibited bobbin coil amplitude responses
less than 0.2 volts. The auto data screener is set up to identify only indications
with amplitude responses above 0.2 volts. The secondary human analysis was
not subject to an amplitude reporting criteria. In one case, the auto data
screener did report a freespan differential indication, but it was inexplicably
deleted by the analyst who prepared the primary analysis report.
Eight of the single axial indications were not identified as freespan differential
indications by either the primary or secondary analysts. These were found
fortuitously rather than by programmatic implementation. The single axial
indications were found only because the licensee performed a plus-point
examination to address a freespan differential indication or large voltage dent
found elsewhere in the same span.
Of particular concern to the team was a long single axial indication at 10.7 inches above
the H5 hot-leg support in Tube R11C42 of Steam Generator 2. This indication was
missed by both the primary and secondary analysts. The indication was 1.6 inches in
-8-
length with a maximum voltage response of 0.26 volts. Depth estimates involve
significant uncertainties for low voltage indications such as this. The measured depth at
the location of the maximum voltage response was 64 percent through wall based on
phase angle. The licensee is required to plug tubes with flaw indications greater than
40 percent through wall.
The failure of the licensee analysts to identify this indication is the first example of a
violation of 10 CFR Part 50, Appendix B, Criterion XVI. Based on the licensees
corrective actions (documented in SMF-2002-003142-00), including pressure testing
and removal of the affected tube from service, this violation is being treated as a
noncited violation consistent with Section VI.A of the NRC Enforcement Policy
(NCV 50 445/0209 02).
To address the missed indication and to ensure that no additional indications were
missed, the licensee elected to perform a complete manual re-analysis of the bobbin coil
data.
Training of participating analysts was focused on the bobbin coil signals associated with
the freespan single axial indications found by plus point probes during the initial data
analysis. Particular attention was directed to the long freespan indications found in
Tubes R11C42 and R7C17, including those missed by the secondary analysts.
The licensee prepared Revision 5 of the steam generator eddy current analysis
guidelines to support the review. Revision 5 added the 300 kHz channel to the channels
to be screened for a differential response. It also required complete history reviews
during resolution. These reviews were now required to extend back to the first inservice
inspection for the subject tube.
To increase confidence in the effectiveness of the analysts, the licensee also inserted
Judas Tube signals into the data stream. A Judas Tube was a tube with known long
single axial indications. The signals from this tube were inserted randomly into the
actual data stream being analyzed. Presumably, the success of the analysts in
detecting the Judas Tube signals from among the actual data under evaluation provided
insight into the ability of the analysts to find similar indications from among the actual
data. Signals for two Judas Tubes were inserted into the data stream. These signals
were the 2002 (1RF09) and 2001 (1RF08) signals for the tube that was missed
(R11C42). The analysts detected the three largest amplitude signals on the tube, which
included the indication that was missed by both the primary and secondary analysts
during the initial data analysis program and that was of particular concern to the team as
previously discussed. The team concluded that the use of the Judas Tube signals had
the additional benefit of heightening the alertness of the data analysts to potential
freespan indications.
-9-
Tube R11C42 was one of two tubes pulled during Refueling Outage 1RF09 for
laboratory testing and examination. Burst testing was completed for this tube at about
the time the review was nearing completion. Preliminary information from the test was
that the burst pressure was 8200 psi. The team concluded that this result provided
further confidence that the analysts were capable of identifying free span cracks well
before they become structurally significant.
Subsequent analysis led to the finding of additional freespan differential indications and
I-codes. Plus-point examination of the I-codes identified six additional tubes with single
axial indications. Three of these tubes were found to contain relatively short single axial
indications at ding locations. The other three tubes contained long single axial
indications or arrays of single axial indications not associated with detectable dents or
dings. One of these tubes, R7C90, was found to contain a 15-inch long array of single
axial indications above the H1 support, and four single axial indications above the
H3 support. Only the largest single axial indication in each of the spans was identified
as a freespan differential indication and designated as an I-code during the third
resolution process. The single axial indications in these spans not identified by the third
analysis were very small amplitude indications (0.1 volts or less), less significant than
some of the single axial indications found in Tube R11C42, which exhibited a high,
8200 psi, burst pressure.
However, the results for the other two tubes with long single axial indications, R7C117
and R4C51 in Steam Generator 3, raised a new issue regarding the effectiveness of the
data resolution process at Comanche Peak. For Tube R7C117, the third analysis
identified a freespan differential indication at 8.6 inches above the H8 support. The
history review confirmed a change in signal and an I-code was assigned. The team
observed, however, that both the primary and secondary analysts had previously
identified a freespan differential indication at this location during the original Refueling
Outage 1RF09 analysis. The resolution process at that time failed to identify a change
in signal relative to 1999 in excess of the specified change criteria and thus, no I-code
was assigned and no plus point probe examination was performed.
Based on a review of the data, the team found that the change in indication since 1999
was clearly observable. The plus-point examination following the third analysis revealed
a relatively large single axial indication with a maximum voltage response of 0.82 volts.
The single axial indication measured over 2.5 inches in length with a depth of 62 percent
through wall at the peak voltage location based on measured phase angle. Amplitude-
based depth measurements ranged as high as 85 percent through wall. This tube was
in-situ pressure tested and successfully sustained three times normal operating
differential pressure (4070 psi) without burst or leakage. The team observed that there
is little basis for confidence that the pressure capacity of this tube was much above
4070 psi or that the tube would have continued to meet the 3 delta P criterion until the
next refueling outage, given the uncertainty of the depth measurements. The licensees
representatives stated their intent to conduct additional testing of the tube and provide
the results to the inspectors when they become available.
-10-
For Tube R4C51, freespan differential indications were identified during the third
analysis at three locations above the H9 support. Each of these was designated during
resolution as an I-code, and plus-point examination revealed single axial indications at
each location. The team observed, however, that freespan differential indications had
been identified at two of these locations by the primary analyst during the original
Refueling Outage 1RF09 analysis. The resolution analyst had overruled one of these
calls as no detectable degradation and had determined that the other had not indicated
a change since 1999 in excess of the change criteria.
The failure of the licensee analysts to identify these indications is a second
example of a violation of 10 CFR Part 50, Appendix B, Criterion XVI. Based
on the licensees corrective actions (documented in SMF-2002-003142-00),
including removal of the affected tube from service, this violation is being treated as
a noncited violation consistent with Section VI.A of the NRC Enforcement Policy
(NCV 50-445/0209-02).
It was the team's opinion that the third analysis was effective in providing confidence
that potentially significant indications were brought to the attention of the resolution
analysts. However, the third analysis raised a new issue with respect to the
effectiveness of the resolution process to ensure that potential freespan indications
stemming from the front line analysis were addressed. In particular, there was concern
regarding the effectiveness of the historical review for changes relative to the change
criteria.
The team discussed the concern with the licensee's representatives. To address the
concern, the licensee elected to perform a new, supplemental history review of all
freespan differential indications from the third analysis.
The licensee prepared guidelines for the supplemental history review, which were
reviewed by the team. These guidelines incorporated a number of improvements, which
the team considered to significantly improve the effectiveness of the analysis in
identifying signals that were potentially changing since the first inservice inspection.
These guidelines called for the historical reviews to be performed by two qualified data
analysts working together as a team. The analysts were to consider all available data,
including the low frequency absolute channel. This reflected a lesson learned from
Tube R7C112 in Steam Generator 3, which showed a clear change in the absolute
signal. Analysts were instructed not only to identify indications with changes exceeding
the specified change criteria, but to identify any indication with a change which, in their
experience and judgement, was beyond that associated with normal eddy current
repeatability. The inspectors considered this change a significant improvement.
The team concluded that this review adequately evaluated each of the freespan
differential signals identified during the third analysis.
Analysis. This finding is greater than minor because it is associated with reactor
coolant system barrier integrity and degraded the ability to meet the cornerstone
objective. The failure to identify the flaws could have resulted in flawed tubes that may
have developed leaks if left in service. The risk significance of this finding is very low
-11-
because the in situ tests demonstrated that the tubes would have met the design basis
requirements for withstanding analyzed transients, and prior to returning the plant to
operation the licensee removed the flawed tubes from service.
Enforcement. The failures of the licensee analysts to identify the significant
indications are a violation of 10 CFR Part 50, Appendix B, Criterion XVI. Based on
the licensees corrective actions (documented in SMF-2002-003142-00) including
removal of the affected tubes from service, this violation is being treated as a
noncited violation consistent with Section VI.A of the NRC Enforcement Policy
(NCV 50-445/0209-02).
02.04 Evaluation of Licensees Root Cause Evaluation
a.
Inspection Scope
The licensee performed root cause evaluations from two standpoints. First was the
assessment of root cause from a crack mechanistic standpoint - why the crack
occurred. Second was a root cause evaluation from a programmatic standpoint - why
wasnt the crack detected and the tube removed from service before the leak occurred
and before the tube integrity performance criteria were no longer satisfied. These
evaluations were in progress while the team was onsite. The team reviewed DRAFT
versions of both evaluations.
b.
Findings
1.
Mechanistic Root Cause
The general root causes of stress corrosion cracking are well documented in
industry literature and include having a material that is susceptible to stress
corrosion cracking, the presence of stress in the material, and an aggressive
environment. Each of these causal factors are known to be present for all PWR
steam generators, particularly those employing Inconel Alloy 600 mill-annealed
tubing as is the case for Comanche Peak Unit 1. The aggressiveness of the
cracking, in terms of time to crack initiation and crack growth rate, can be
aggravated by the presence of residual stress or off-normal stress associated
with dings, dents and scratches, material micro-structure, and secondary water
chemistry.
One potential source of information concerning factors that may have hastened
the onset of freespan cracking at Comanche Peak would be a removed tube
sample containing the section of tubing with the leaking flaw. Because of the
u-bend location of the leaking flaw, the licensee could not remove it for additional
testing. However, sections for two other flawed tubes, i.e., R11C42 and
R25C30, were pulled for laboratory analysis and may provide insights on causes
for the cracking. The pulled tube samples were found by inspection to contain
freespan cracks.
-12-
The license observed that the leaking flaw was located at a ding, which was
apparent on the plus-point scan. Dings and dents are local deformations of the
tube wall which lead to increased local stress levels. Dings are thought to be
incurred during the tube fabrication and installation process. By contrast, dents
occur due to the buildup of magnetite in crevices between the tubing and carbon
steel support plates. Crack initiation at ding and dent locations has been noted
by power reactor licensees.
The licensee had not reached a conclusion about the cause of the leak based on
available information. The licensees representatives stated that they would
provide the inspectors with the final root cause determination based on further
evaluation when it becomes available.
2.
Programmatic Root Cause
The team reviewed a number of licensee draft documents that address the
leaking flaw and why it had been missed in Refueling Outage 1RF08 steam
generator inspections in 2002. These documents included:
A draft document entitled, Anatomy of an Event, reviewed error
precursors, flawed defenses, and latent organizational weaknesses that
could have prevented the missed indication.
A draft document entitled September 2002 Unit 1 Primary to Secondary
Leakage Summary Report.
A note prepared by Steve Swilley (TXU) entitled Comments about
1RF08 Inspection Practices and Application of Ding Technique.
These documents identified the following contributing factors:
The probe wobble signal masked a ding signal at the flaw location.
The unseen ding signal caused the flaw signal to be distorted (rotated)
beyond the phase angle reporting criteria which was applicable to non-
dinged locations. The inspectors considered this criteria non-
conservative for dinged locations.
The primary analysis was rule-based (being computerized). Because the
primary analysis failed to identify the dent, the reporting criteria for non-
dinged locations was applied. Since the dent rotated the flaw beyond this
criteria the analyst did not identify it.
The secondary analyst failed to report the indication.
Although the team agreed with the above contributing factors, the team identified
the following important contributing factors:
-13-
Human error: The secondary analyst failed to report the indication which
was readily apparent. The team determined that the analyst should have
reported the indication. It appears likely the analyst dismissed the
indication based on strict application of the guideline reporting criteria for
non-dinged locations and failed to recognize that the large wobble signal
could potentially mask dings which could rotate the indication outside the
reportable phase angle response criteria.
Procedural inadequacy: The phase angle reporting criteria for freespan
cracks in the absence of dings or dents was inappropriate for two
reasons. One, the reporting criteria for dings and dents was 2 volts.
Dent and ding signals of less than 2 volts can distort or rotate a flaw
indication beyond the phase angle reporting criteria. Two, a large probe
wobble response capable of masking dent and ding signals up to 2.5
volts is an expected condition in the u-bend region. This procedural
inadequacy directly caused the flaw indication to be missed by the
primary automatic data screening analysis because it was entirely rule
based. The human (secondary) analyst applied this guideline criterion
directly and literally. The Figure 3 analysis flow chart in the Refueling
Outage 1RF09 steam generator eddy current analysis guidelines
provided no specific word of caution about the potential for probe wobble
to distort the flaw indication, rendering the reporting criterion
inappropriate. The team determined that procedure established
unnecessarily conservative criteria for reporting flaws.
02.05 Evaluation of Licensees Corrective Actions
a.
Inspection Scope
The inspectors reviewed the licensees corrective actions in response to the steam
generator tube leak.
b.
Fingings
The corrective actions implemented by the licensee have been previously discussed in
this inspection report and involved three sets of actions as follows:
The first set of actions was taken in direct response to the tube leak, and
included opening up the phase angle window reporting criteria to ensure that all
potential distorted indications would be subject to the resolution process for
determination of whether an I-code should be applied to the indication.
The second set of actions was taken in response to team concerns that (1) many
freespan indications were too low in amplitude to be detected by the primary
analysis automatic data screener and (2) that several freespan indications, found
fortuitously by plus-point examination, had been missed by the secondary
(human) analyst. This second set of actions included an independent third party
review of the raw bobbin coil examination data by human analysts who had
-14-
undergone training to sensitize them to the kinds of signals which had been
missed during the original inspection program.
The third set of actions was taken in response to team concerns regarding the
effectiveness of the data resolution analyses implemented during the original
inspection program and third analysis. In particular, the team was concerned
that the history review analyses were not adequately identifying indications,
which had undergone significant change and warranted an I-code designation.
This third set of actions included analysis history reviews for all freespan
differential signals that had not received an I-code designation during the third
analysis.
The second and third sets of corrective actions were taken by the licensee to resolve
NRC concerns. Although these actions did not reveal any additional tubes failing to
meet the tube integrity performance criteria, one indication was found (in Tube R7C112)
during the third analysis that could have challenged the tube integrity criteria during the
next operating cycle as discussed in detail earlier in this report. Thus, the team found
that the licensees corrective action program in response to the leaking tube and
implemented during the original Refueling Outage 1RF09 inspection program (i.e., the
first set of corrective actions) was initially not adequate to establish the extent of
condition and to support operation during the next operating cycle. In response to staff
concerns, additional corrective actions were taken (i.e., the second and third sets of
corrective actions) which led to the finding of several additional freespan indications
including the significant indication in Tube R7C112.
The team found that the corrective actions listed above established a high confidence
that significant indications, which could potentially challenge the tube integrity
performance criteria early in the next cycle were identified and the subject tubes
plugged or repaired. The inspectors considered these corrective actions acceptable.
The licensee will perform an operational assessment to establish that there is a
sufficient bases to operate to its next scheduled refueling outage. This operational
assessment may need to be revised or updated when the results of the tube pull
examinations become available sometime in early 2003.
The team will review the results from the pulled tube examination and the licensees
operational assessment as follow up actions when the results become available.
04
Exit Meeting Summary
The team leader and NRC management representatives presented the special
inspection results to Mr. C. L. Terry, and other members of licensee management on
December 10, 2003, during a public exit meeting. No proprietary information was
identified.
ATTACHMENT
PARTIAL LIST OF PERSONS CONTACTED
Licensee
S. Lakdawala, Engineering Programs Manager
B. Mays, Smart Team 1 Systems Manager
D. Snow, Senior Nuclear Specialist
M. Sunseri, System Engineering Manager
S. Swilley, Steam Generator Program Manager
C. Terry, Senior Vice President and Principal Nuclear Officer
NRC
D. Allen, Senior Resident Inspector
A. Sanchez, Resident Inspector
ITEMS OPENED AND CLOSED
Opened
50-445/02-09-01
APV
Failure to Identify and Correct a Degraded Steam Generator Tube
during Refueling Outage 1RFO8 (Section 02.01).
Opened and Closed
50-445/02-09-02
Two Examples of Failure to Identify and Correct Steam Generator
Tube Flaws (Section 02.02).
PARTIAL LIST OF DOCUMENTS REVIEWED
Comanche Peak Unit 1 Steam Generator Eddy Current Analysis Guidelines for 1RF08,
Revision 0
Comanche Peak Unit 1 Steam Generator Eddy Current Analysis Guidelines for 1RF09,
Revision 4
Comanche Peak Unit 1 Steam Generator Eddy Current Analysis Guidelines for 1RF09,
Revision 5
Comanche Peak Unit 1 Steam Generator Eddy Current Analysis Guidelines for 1RF09,
Revision 6
Westinghouse Vendor Procedure STD-FP-1996-7928, Field Procedure for In Situ Testing of
3/4" Steam Generator Tubes
-2-
Contractor NDE Procedures:
TX-ISI-008, VT-1 and VT-3 Visual Examination, Revision 5.
TX-ISI-011, Liquid Penetrant Examination for Comanche Peak Steam Electric Station,
Revision 7.
TX-ISI-070, Magnetic Particle Examination, Revision 6.
TX-ISI-214, Ultrasonic Examination Procedure for Welds in Piping Systems and Vessels,
Revision 2.
TX-ISI-301, Ultrasonic Examination of Ferritic Piping Welds, Revision 1.
TX-ISI-302, Ultrasonic Examination of Austenitic Piping Welds, Revision 1.