United States Nuclear Regulatory Commission - Protecting People and the Environment

Information Notice No. 97-49: B&W Once-Through Steam Generator Tube Inspection Findings

                                 UNITED STATES
                         NUCLEAR REGULATORY COMMISSION
                     OFFICE OF NUCLEAR REACTOR REGULATION
                         WASHINGTON, D.C.  20555-0001

                                 July 10, 1997


NRC INFORMATION NOTICE 97-49:  B&W ONCE-THROUGH STEAM GENERATOR TUBE          
                               INSPECTION FINDINGS


Addressees

All holders of operating licenses or construction permits for nuclear power
reactors.

Purpose

The U.S. Nuclear Regulatory Commission (NRC) is issuing this information notice
to present the findings from the examination of tubes in Babcock and Wilcox (B&W)
once-through steam generators (OTSGs).  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

Licensees using B&W OTSGs have historically observed very little service-induced
degradation in steam generator tubes.  During the last few years, however, more
degradation has been observed and this degradation has been seen at a variety of
locations, such as dented (dinged) areas, the expansion transition region, the
freespan region, the sludge pile region, and the sleeve joints.  Pertinent
inspection findings from steam generator tubes at several plants with OTSGs are
discussed.

Degradation at Dented Locations

Indications of degradation associated with dented (dinged) areas have been found
at several plants--Arkansas Nuclear One, Unit 1 (ANO-1), Oconee Unit 1, and
Crystal River Unit 3.  These indications have been axial, circumferential, or
volumetric in nature.  At ANO-1 (in 1993), two volumetric indications with
circumferentially oriented cracklike indications were found at dents on the
secondary face of the upper tubesheet (UTS).  These indications were initially
found with a bobbin coil probe and were confirmed to be present with a rotating
pancake coil eddy current inspection probe.  At ANO-1 (in 1996), two axially
oriented eddy current indications associated with dented areas in the tube's
freespan region were observed.  Similar to the 1993 indications, these
indications were also initially found with a bobbin coil probe.  Rotating pancake
coil probe inspection of one of these indications confirmed that the indication
initiated from the outside diameter of the tube and that the indication was
offset relative to the tube axis by approximately 35 degrees.  At Oconee Unit 1
(in 1995), a volumetric and a circumferential indication were detected at dents
located at the 15th tube 


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support plate.  At Crystal River Unit 3 (in 1996), a volumetric eddy current
indication was found at a dented area.  This indication was detected with the
bobbin coil and confirmed with a pancake and plus-point coil.

Degradation at the Expansion Transition Region

The expansion transition region of the tubes in B&W OTSGs were heat treated to
reduce residual stresses from tube fabrication and installation, and to increase
resistance to primary water stress corrosion cracking (PWSCC).  This heat
treatment resulted from a full furnace stress relief of the entire tube bundle. 
During the manufacturing process, however, several tubes were re-rolled into the
tubesheet following the full furnace stress relief to temporarily seal the tube
during the shop hydrostatic tests.  As a result, a limited population of tubes
was not stress relieved at the expansion transition region (i.e., fewer than 200
tubes are known to have not been stress relieved).  Axial indications associated
with the expansion transitions of both stress-relieved and nonstress-relieved
transitions were recently noted in several B&W units (Davis-Besse, Crystal River
3, ANO-1, and Oconee 3).  The inspection findings at these plants are discussed
below.

At Davis-Besse (in the spring of 1996), an axially oriented indication was
detected during the examination of what was believed to be a nonstress-relieved
roll transition.  This indication was in the roll transition in the UTS (i.e.,
the hot leg).  Subsequent review of shop records showed that the expansion
transition had not been re-rolled and was, therefore, stress relieved.  The
licensee removed the roll transition portion of this tube for destructive
examination.  The destructive examination showed that the indication was caused
by PWSCC.  To ascertain whether the tube had been stress relieved, the licensee
performed additional analyses and testing.  As a result of this testing, the
licensee concluded that the roll transition was not stress relieved (i.e., it had
been re-rolled following the full bundle stress relief process).

At Crystal River 3 (in the spring of 1996), a single axial indication was
detected in the roll transition in a tube that had been re-rolled following the
full bundle stress relief (i.e., a nonstress-relieved transition), and a multiple
axial indication was detected in the tube end, above the shop re-roll in the same
tube.  These indications were located in the roll transition in the UTS
(i.e., the hot leg).  The eddy current data clearly indicated that the tube had
been rolled multiple times.  The licensee attributed the indication to PWSCC.  

At ANO-1 (in the fall of 1996), 24 axially oriented and volumetric indications
were detected in stress-relieved roll transitions in the UTS (i.e., the hot leg). 
The licensee attributed the axial indications to inside diameter-initiated stress
corrosion cracking (i.e., PWSCC).  The volumetric indications had been initiated
on the outside diameter, pointing perhaps to  .                                                                IN 97-49
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intergranular attack (IGA) or to closely spaced cracks.  To further characterize
the nature and cause for the upper roll transition indications (and other
indications), the licensee for ANO-1 removed several tube sections for
destructive examination.  The destructive examination findings from the one roll
transition indication that was removed confirmed that the indication was
attributable to PWSCC.  This transition had been stress relieved.

At Oconee Unit 3 (in the fall of 1996), 19 tubes were identified by eddy current
testing as having PWSCC at the roll transition region in the UTS.  Of the 19
indications, 15 were axial indications in the roll transition region, 3 were
axial indications in the rolled area , and 1 was a volumetric indication at the
roll transition region.  One tube was removed for laboratory analysis of the
indication at the upper roll transition region.  The laboratory destructive
examination findings were not available at the time this notice was prepared.

Degradation at Freespan Locations

Axially oriented degradation in the freespan region has been observed in several
B&W OTSGs (Oconee 1, Oconee 2, Oconee 3, and ANO-1).  Freespan degradation is
degradation observed above the sludge pile region and not located at any support
structure (e.g., tube support plates).  A freespan axial indication was first
identified at Oconee 1 in May 1994.  This indication was identified with a bobbin
coil and confirmed to be present with a rotating pancake coil probe.  This tube
along with six others were removed for destructive examination.  The destructive
examination confirmed the presence of freespan axially oriented IGA in all seven
tubes.  The tube with the indication detected with a bobbin coil was the most
significant with a through-wall depth of 47 percent and a burst pressure of 
7400 pounds per square inch (psi), well above the structural criteria specified
in Regulatory Guide 1.121.  The IGA in the remaining tubes ranged from 5 percent
to 28 percent through-wall.

Subsequent bobbin coil inspections at Oconee Units 1, 2, and 3 identified
additional tubes with freespan axial indications.  For example, 9 tubes with
indications were detected at Oconee 2 in October 1994, 22 tubes with indications
were detected at Oconee 3 in June 1995, 40 tubes with indications were detected
at Oconee 1 in November 1995, and 173 tubes with indications were detected at
Oconee 2 in April 1996.  During the Oconee 2 inspection outage in April 1996,
four tubes were removed for destructive examination.  The selection criteria for
these tubes included small and large indications, the number of indications per
tube, and a sampling across the tube bundle.  The burst pressures for these tubes
ranged from 5700 psi to 11000 psi.  In November 1996, the most recent steam
generator inspection outage at an Oconee unit, 67 tubes with confirmed bobbin
coil indications were identified at Oconee 3.  An assessment performed by the
licensee, based on previous tube pull analysis, indicated that these tubes had
adequate structural integrity.  All tubes with axially oriented freespan IGA,
which were confirmed to be present with a rotating pancake coil probe, were
removed from service upon detection.  During the Oconee 3 outage in November
1996, three tubes with IGA were removed for destructive examination.  The
laboratory destructive examination findings were not available at the time this
notice was prepared.

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The root cause analysis from the Oconee 1 tube pull analysis did not identify any
unique feature to this degradation mechanism that would indicate that the problem
was limited to the Oconee Units.  That is, the base material properties met
specific values, no high residual stresses were measured, and no detrimental
environmental or chemical species were identified.  These results indicate that
all B&W OTSGs are potentially susceptible to this mechanism.  In
September/October 1996, the licensee for ANO-1 detected freespan axial
indications similar to those observed at the three Oconee units.  Approximately
13 tubes with freespan axial indications were identified and plugged at ANO-1
during this outage.  These indications were initially detected with a bobbin coil
probe.  In-situ pressure testing of two of the more severe indications (as
identified by nondestructive examination) indicated burst pressures for these
freespan axial indications in excess of 4550 and 5750 psi.  No leakage was
observed from either of these two indications during the in-situ test.  Each of
the Oconee units and ANO-1 inspected 100 percent of the inservice tubes with a
bobbin coil during their last inspection outage.

Degradation in the Sludge Pile Region

At ANO-1 (in the fall of 1996), nine axially oriented indications were observed
above the lower tubesheet.  These indications were in the sludge pile region,
approximately 0.25-inch above the lower secondary face of the tubesheet.  The
indications were found with a bobbin coil and were confirmed with a motorized
rotating pancake coil inspection.  Two tubes were removed for laboratory
examination.  The laboratory destructive examination pointed to these indications
being initiated from the outside diameter of the tube and were a result of
axially oriented IGSCC.  The licensee also observed areas of shallow
intergranular corrosion initiating from the outside diameter of the tube near the
fracture faces.  This corrosion was three-dimensional in nature, similar to IGA
regions; however, many of the affected grains were no longer present, resulting
in the removal of tube material and appearance of shallow wastage.  These "IGA
wastage" regions were relatively shallow (less than 24-percent through-wall) and
in the form of meandering grooves or gullies.  The metallurgical results
suggested to the licensee that the axial cracks originated at the bottom of these
IGA wastage zones.  On the basis of nondestructive examination, these meandering
grooves appeared to be located at or near sharp edges of surface deposits.

Degradation at Sleeved Locations

B&W mechanical sleeves have been installed in all operating B&W OTSG plants in
order to mitigate tube leaks caused by high-cycle fatigue and to repair tubes
with other indications of degradation.  The number of sleeves in service at these
plants varies from a few hundred to approximately one thousand.  These sleeves,
fabricated from either alloy 600 or alloy 690, have three roller-expanded joints
to seal them into the parent tube (one at the top of the sleeve and two at the
bottom of the sleeve).  These joints have not undergone any type of process to
relieve stress.

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Axial, circumferential, and volumetric indications were detected in the joints
of B&W mechanical sleeves at ANO-1 (in 1996) although no tubes were removed to
learn the nature of the degradation.  The indications were found at the joints
of both alloy 600 and alloy 690 sleeves with a plus-point coil.  The licensee
believes that 9 of the 10 indications detected are associated with the parent
tube rather than with the sleeve itself.  The degradation has been observed at
both the upper joint (located within the UTS) and the lower joints (in the tube
freespan region); 8 of the 10 indications were observed at the upper joint.  One
circumferential indication was detected at an alloy 600 sleeve joint at Oconee
Unit 3 (in 1996) with a plus-point coil.  This indication was associated with the
upper of the two lower joints (i.e., the upper lower joint).  The licensee for
Oconee Unit 3 believes that the indication could be the result of a scratch made
during the rolling process; however, this cannot be confirmed, since current
technology does not permit the sleeve to be removed from the steam generator for
destructive examination because of its location.

Discussion

The inspection findings from B&W OTSGs indicate that a number of locations are
susceptible to degradation.  In addition, studies of removed tubes have confirmed
in several instances that the eddy current indications are attributable to such
degradation mechanisms as IGA and stress corrosion cracking.  Frequently these
indications can only be reliably detected with specialized probes such as
rotating probes (e.g., roll transition indications, indications in sleeve
joints).  In addition, the depth of many of these types of indications cannot be
reliably determined.

To effectively manage the degradation mechanisms being observed, a variety of
actions have been taken by licensees.  These actions include inspecting locations
potentially susceptible to degradation with techniques capable of reliably
detecting these forms of degradation (or using the best available technique) and
ensuring that the frequency and scope of inspection are sufficient at identifying
and removing degradation from service to prevent the degradation from progressing
to the point at which tube integrity is impaired.  For example, the sleeve joints
at ANO-1 and Oconee 3 were examined with a plus-point coil, and 100 percent of
the tubes were examined with a bobbin coil at ANO-1 and Oconee Units 1, 2, and
3 during their last outage.  Other actions taken by licensees include removing
tubes from service based upon detection when the degradation cannot be reliably
depth-sized (unless an alternative tube repair criterion has been approved by the
NRC), and assessing significant indications in steam generator tubes to determine
whether adequate structural and leakage integrity was maintained during the
previous cycle.  Specific actions taken by licensees to assess the structural and
leakage integrity of tubes include removing tubes for destructive examination as
was done at ANO-1, Davis-Besse, and Oconee 1, 2, and 3, and performing in situ
pressure testing.

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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 S.H. Weiss for

                                    Marylee M. Slosson, Acting Director
                                    Division of Reactor Program Management
                                    Office of Nuclear Reactor Regulation

Technical contacts:  Kenneth J. Karwoski, NRR
                     301-415-2754
                     E-mail: kjk1@nrc.gov

                     Eric J. Benner, NRR
                     301-415-1171
                     E-mail:  ejb1@nrc.gov
Page Last Reviewed/Updated Tuesday, December 03, 2013