Information Notice 1997-88, Experiences During Recent Steam Generator Inspections
| ML013100306 | |
| Person / Time | |
|---|---|
| Site: | Mcguire, Harris, Sequoyah, Arkansas Nuclear, Braidwood, Prairie Island, Crystal River, Diablo Canyon, Farley, San Onofre, Maine Yankee, Zion  |
| Issue date: | 12/16/1997 |
| From: | Roe J Office of Nuclear Reactor Regulation |
| To: | |
| References | |
| +sunsimjr=200611, -RFPFR, FOIA/PA-2001-0256, GL-95-005 IN-97-088 | |
| Download: ML013100306 (5) | |
I'JRC Information Notice 97-88: Expe...Recent Steam Generator Inspections
http://www.nrc.gov/NRC/GENACT/GC/IN/1997/in97088.html
UNITED STATES
NUCLEAR REGULATORY COMMISSION
OFFICE OF NUCLEAR REACTOR REGULATION
WASHINGTON, D.C. 20555-0001 December 16, 1997 NRC INFORMATION NOTICE EXPERIENCES DURING RECENT STEAM
97-88:
GENERATOR INSPECTIONS
Addressees
All holders of operating licenses for pressurized-water reactors (PWRs) except those who have
permanently ceased operations and have certified that fuel has been permanently removed from the
reactor.
Purpose
The U.S. Nuclear Regulatory Commission (NRC) is issuing this information notice to inform addressees
about findings from recent inspections of steam generator tubes and secondary-side internal components.
It is expected that recipients will review the information for applicability to their facilities and consider
actions, as appropriate, to avoid similar problems. However, suggestions contained in this information
notice are not NRC requirements; therefore, no specific action or written response is required.
Description of Circumstances
Recent inspections of steam generator tubes and secondary-side internal components have identified a
number of concerns related to the degradation of these components. The relevant findings associated
with these concerns are discussed below.
Degradation of Secondary-Side Internal Components
In May 1997, the licensee for the Shearon Harris Nuclear Power Plant found that four perforated, carbon
steel ribs in a steam generator had been extensively damaged. The ribs are welded to the feedwater
impingement plate which shields the steam generator tubes from direct impact of the feedwater flow.
The licensee concluded that the high flow velocities of the feedwater had eroded the ligaments between
the perforations on the ribs.
During the spring 1997 refueling outage, Southern California Edison Company, the licensee for the San
Onofre Nuclear Generating Station, Unit 3 (SONGS-3), discovered degradation of the steam generator
tube eggcrate supports. The damage was confined to the periphery of the supports. The damage existed
in both steam generators on both the hot-leg and cold-leg sides. but was more extensive on the hot-leg
side. The licensee concluded that excessive deposits on the steam generator tubes and supports were
responsible for changes in flow velocities and water chemistry on the secondary side of the steam
generator. The erosion/corrosion damage mechanism resulting from these changes subsequently
damaged the eggcrate supports. The deposits were removed by chemical cleaning during the outage.
With nominal secondary-side properties restored, further erosion/corrosion is not expected because of
better control of secondary-side chemistry conditions.
Eddy current inspection of steam generator tubes gathers limited information on secondary-side
conditions that could challenge the structural and leakage integrity of tubes. The erosion of
secondary-side steam generator components could potentially lead to loose parts. In addition, erosion of
the eggcrate supports as observed at SONGS-3 could reduce the lateral restraint of the tubes and could
increase the potential for flow-induced vibration of the tubes. Because of these experiences, other
utilities have visually inspected the secondary side of steam generators to assess the integrity of inte
components. Such inspections could promote early detection and mitigation of secondary-side
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component degradation.
Deficiencies in Inservice Inspections
Qualification of Eddy Current Depth Sizing Techniques
Attempts to qualify eddy current techniques for estimating the depth of intergranular attack (IGA) and
stress-corrosion cracking (SCC) in steam generator tubes have had limited success. Entergy, the licensee
for Arkansas Nuclear One, Unit 1 (ANO-1), developed a technique to estimate the depth of volumetric
IGA in once-through steam generator (OTSG) tubes. The technique was qualified using data primarily
from Crystal River Nuclear Plant, Unit 3 (CR-3) tube specimens and supplemented with data from
ANO- 1 tube specimens. The licensee applied the technique to IGA indications in the upper tubesheet
crevice. Destructive examination of several tubes revealed that the technique underestimated the depth
of the indications by as much as 50 percent of through-wall depth. The tube specimen data obtained
from CR-3 contained indications from the lower regions of the tube bundle above the lower tubesheet.
The environment in that region differs considerably from the environment in the upper tubesheet crevice.
Because of the differences in the environments in which the IGA degradation developed and the
licensee's reliance on data obtained from CR-3, the resulting sizing technique developed in the
qualification process yielded nonconservative depth estimates when applied to the degradation in the
ANO-1 OTSGs.
Entergy's experience illustrates some of the potential difficulties in qualifying and applying eddy current
depth-sizing techniques. Because eddy current inspection methods are sensitive to a number of variables, the qualification process should consider all of these variables. Although Entergy assumed that the IGA
indications from ANO-1 and CR-3 were of similar morphology, other factors, such as the conductivity
of the degradation, were not considered in the development of the sizing technique. Also, because the
tube specimens were obtained over a period of many years, it may have been appropriate to address
changes in the degradation that may have occurred over time. Validation of developed depth-sizing
techniques through sizing and subsequent destructive examination could address each of these factors.
Inaccuracies in the Location of Indications
In June 1997, Duke Power shut down William B. McGuire Nuclear Station, Unit 2, because of an
increasing primary-to-secondary leak. A steam generator tube was leaking approximately 13.2 cm [5.2 inches] above the second cold-leg tube support plate. During the preceding refueling outage, the general
bobbin coil probe inspection identified an indication in this same area. At that time, in accordance with
procedure, the licensee inspected the area with a rotating pancake coil (RPC) probe from 12.7 cm [5 inches] below to 2.5 cm [1 inch] above the location at which the bobbin coil probe detected an
indication. The RPC probe inspection did not confirm the indication and the tube was returned to
service. After the primary-to-secondary leak occurred and was located, the licensee reexamined the
inspection data from the previous refueling outage and concluded that the RPC data were actually not
acquired over the area of interest. Although the area containing the degradation should have been, and
appeared to have been, inspected with the RPC probe, the measurement from the second support plate to
the indication location was inaccurate which resulted in the indication not being inspected.
Several licensees have provisions in their eddy current inspection program that reduce the possibility of
leaving a defective tube in service as was done at McGuire Unit 2. Instead of attempting to position a
rotating probe at a particular location relative to a support, data are collected between two support
locations that bound the section of tubing containing the indication which should guarantee that the area
of interest is inspected. Other methods that minimize probe positioning inaccuracies include: (1) using
axial encoders during data acquisition, (2) establishing consistent settings in the data analysis software, and (3) using sharp reflectors sufficiently spaced in the calibration standard to more accurately calibrate
the probe translation speed.
Potential Inability to Detect Cracks at Locations with Dents Less Than 5 Volts
To better detect cracks at dented locations, the Electric Power Research Institute (EPRI) recommends the
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use of supplemental eddy current probes (e.g., Cecco or RPC) on dents greater than 5 volts. At Sequoyah
Nuclear Plant, Unit 1; Diablo Canyon Nuclear Power Plant, Unit 1; and Maine Yankee Atomic Power
Station, inspection of dents less than 5 volts with RPC probes have detected crack indications that were
not detected with the bobbin coil probe. The dents were at tube support plate intersections. The
indications initiated from both the inside and outside diameter of the tube and were both circumferential
and axial in nature. Apparently, eddy current signal distortion from the dents hindered detection with the
bobbin coil probe.
These inspection findings call into question the adequacy of the 5-volt threshold recommended by EPRI.
The licensee for Sequoyah Unit 1 has surveillance requirements in the plant's technical specifications
which require an RPC inspection of dents less than 5 volts. Such requirements may improve the ability
to detect cracks in tubes with dents less than 5 volts.
Indications Identified in Welded Tubesheet Sleeves
In the 1995 refueling outages at Zion Nuclear Plant, Units 1 and 2, eddy current inspections of welded
tubesheet sleeves identified a number of indications that were not detected by visual or ultrasonic
inspection methods. The sleeved tubes containing eddy current indications were returned to service on
the basis that the visual and ultrasonic inspections did not confirm the indications. This was documented
in a nonconformance report, however, a formal safety evaluation to assess the significance of the eddy
current indications was not performed. In January 1996, inspections of welded sleeves at the Prairie
Island Nuclear Plant, Unit 1, found 61 indications similar to those found at Zion. Metallurgical
evaluations of sleeve/tube assemblies removed from Prairie Island revealed that the indications were the
result of weld conditions caused by improper surface preparation during the sleeve installation process.
Subsequent inspections of sleeve welds at other plants with welded tubesheet sleeves showed similar
indications.
The initial sleeve weld acceptance criteria are based primarily on an ultrasonic test examination to
demonstrate an adequate sleeve weld joint. Although indications were detectable using eddy current
methods, this testing was performed only to provide a baseline for future examinations. The experience
with welded sleeves indicates a combination of visual, ultrasonic, and eddy current techniques may be
needed to provide comprehensive coverage of areas susceptible to defects. Although the alternative
inspection techniques did not identify the presence of the eddy current indications at Zion, the
significance of the indications detected by eddy current was indeterminate because the nature of the
degradation and the sensitivity of visual and ultrasonic inspection techniques to the indications was
unknown.
The experience with welded CE sleeves highlights the importance of adequately qualifying the
capabilities of each inservice inspection technique and addressing the root cause of new modes of steam
generator tube degradation. Because the capabilities of the ultrasonic and visual inspection techniques to
detect the weld zone defects had not been assessed, negative inspection results (i.e., lack of
confirmation) should not have been considered sufficient evidence to conclude that the sleeved tubes
with the eddy current indications were acceptable per the plugging limits specified in the technical
specifications.
High Voltage Growth of Outer-Diameter Stress Corrosion Crack (ODSCC) Indications
The Joseph M. Farley Nuclear Plant, Unit 1, applies a voltage-based steam generator tube repair criteria
to ODSCC indications conforming to the guidance in NRC Generic Letter (GL) 95-05, "Voltage-Based
Repair Criteria for Westinghouse Steam Generator Tubes Affected by Outside-Diameter
Stress-Corrosion Cracking." During a routine tube inspection in April 1997 at Farley Unit 1, data
analysts identified a bobbin coil indication with a voltage amplitude of approximately 14 volts. The
voltage of the indication was 1.46 volts at the previous inspection and was not anticipated based on an
operational assessment completed during the prior refueling outage. The operational assessment also did
not predict the distribution of higher voltage indications identified during the subsequent inspection.
Because the operational assessment underestimated the magnitude and number of higher voltage
indications, the calculated end-of-cycle (EOC) conditional tube burst probability was lower than would
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be calculated using the actual inspection results.
Commonwealth Edison (Corn Ed) similarly identified a number of higher voltage ODSCC indications in
an inspection at Braidwood Station, Unit 1, that were not anticipated based on the licensee's previously
completed operational assessment. Consequently, the EOC main steam line break (MSLB) tube leakage
predicted as part of the assessment (26.5 liters per minute (1pm) [6.99 gpm]) was lower than the leak rate
predicted using actual EOC inspection results (45.5 1pm [11.5 gpm]). At a meeting with the NRC on
July 23, 1997, Com Ed presented its conclusion that the voltage growth of ODSCC indications is
dependent on the initial voltage of the indications. GL 95-05 recommended a methodology for
projecting the distribution of indications (i.e., the number and voltage) which assumed that the growth
rate for indications left in service was independent of the initial indication voltage. The use of this
assumption was contingent upon the licensee having demonstrated that the methodology predicted
distributions of indications which were conservative when compared to operating experience. Using
voltage-dependent growth rates, Com Ed was able to improve the accuracy of the EOC MSLB tube
leakage estimation.
The findings discussed above identify instances where the methodology discussed in GL 95-05 was
shown to be nonconservative with respect to operating experience. Braidwood 1 is unique in that it has a
voltage-based criteria value greater than other licensees which permits higher-voltage indications to
remain in service. However, the nonconservatism identified by Com Ed may have implications for other
licensees using voltage-based repair criteria. Licensees utilizing the methodology may wish to address
the implications of this issue in future operational assessments.
Continued Degradation Growth in Plugged Tubes
Eddy current inspection of tubes recently removed from the retired McGuire, Unit 1 steam generators
found that the bobbin coil voltage for indications had increased even after the tubes were plugged. Of the
12 crack-like indications examined, 10 had apparently initiated from the outside diameter (OD) of the
tube and 2 from the inside diameter. The inspections revealed increases in the bobbin coil voltages
ranging from 0.3 to 6.1 volts since the tubes had been plugged. Increases in RPC voltage were also
noted. Because the results are preliminary and are based entirely on nondestructive inspection data, it is
not certain whether the indications had grown after the tubes were plugged, however, these results
suggest that the indications did change in some way after the tubes were plugged.
During the spring 1997 refueling outage at Braidwood 1, Com Ed found that 49 of 85 "locked" tubes
(also plugged) had circumferential cracks at the tubesheet expansion transition area. The tubes had been
locked by expanding them above and below certain tube support plate intersections in support of the use
of voltage-based repair criteria. Inspections of the tube expansion-transitions completed before the
plugging verified that no indications were present in the tubes.
The inspection findings discussed above suggest that steam generator tubes remain susceptible to stress
corrosion cracking (SCC) even after they have been plugged. Although the susceptibility to SCC of
plugged tubes should be less than that for tubes remaining in service, many of the factors associated with
the development of SCC remain unchanged (e.g., material susceptibility). The consequences of
continued degradation of plugged tubes include the potential for complete severance of the tube and the
potential for creation of loose parts, both of which could damage inservice tubes. Some utilities have
installed tube stabilizers in tubes with outside-diameter-initiated circumferential defects before plugging
them, which may lessen the potential to damage inservice tubes.
Discussion
As PWRs continue to age, new modes of steam generator degradation continue to appear. Historically, verification of tube integrity has focused on degradation which directly affected the tubes. However, the
recent findings at Shearon Harris and San Onofre illustrate the importance of considering the impact of
other modes of degradation on the integrity of steam generator tubes. Although inspection practices
generally focus on locations in steam generator tubes where degradation has previously been identified, the examples presented here demonstrate that degradation taking place elsewhere in steam generators
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NRC Information Notice 97-88: Expe...Recent Steam Generator Inspections
http://www.nrc.gov/NRC/GENACT/GC/IN/1997/in97088.htm1 could potentially challenge the integrity of the tubes.
Because of improved inspection capability, specifically improvements in probes and data analysis
software, earlier detection and perhaps more accurate sizing of tube degradation is possible. However, problems with tube inspections continue to occur. As discussed, these problems may arise from
inadequate qualification of data analysis procedures or from errors associated with the acquisition of
inspection data. It remains important for licensees to assess the significance of indications with respect
to the qualification of the inspection techniques and the manner in which the indications were detected.
Such practice is consistent with regulatory requirements in Criteria IX and XVI of Appendix B to 10
CFR Part 50. The conclusions from these assessments may dictate revisions to inspection procedures
and repair of tubes.
This information notice requires no specific action or written response. If you have any questions about
the information in this notice, please contact one of the technical contacts listed below or the appropriate
Office of Nuclear Reactor Regulation (NRR) project manager.
signed by
Jack W. Roe, Acting Director
Division of Reactor Program Management
Office of Nuclear Reactor Regulation
Technical
Phillip J. Rush, NRR
contacts:
301-415-2790
E-mail: pjrl@nrc.gov
Eric J. Benner, NRR
301-415-1171 E-mail: ejb lnrc.gov
(NUDOCS Accession Number 9712120012)
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