Information Notice 1997-88, Experiences During Recent Steam Generator Inspections
UNITED STATES
NUCLEAR REGULATORY COMMISSION
OFFICE OF NUCLEAR REACTOR REGULATION
WASHINGTON, D.C. 20555-0001 December 16, 1997 NRC INFORMATION NOTICE 97-88: EXPERIENCES DURING RECENT STEAM
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
PER X, e 97-038 `97124;
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_~ 7-88 ecember 16,1997 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 internal components. Such inspections could promote
early detection and mitigation of secondary-side 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.
~~\,...i9748
-Zcember 16, 1997 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 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.
Vv7-88 D-tecember 16, 1997 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
December 16, 1997 indications, the calculated end-of-cycle (EOC) conditional tube burst probability was lower than
would 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
(Ipm) [6.99 gpm]) was lower than the leak rate predicted using actual EOC inspection results
(45.5 Ipm [11.5 gpm]). At a meeting with the NRC on July 23, 1997, Corn 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, Corn 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 Corn 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, Corn Ed found that 49 of 85 Blocked"
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.
December 16, 1997 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 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.
W. Roe, Acting Director
Zion of Reactor Program Management
Office of Nuclear Reactor Regulation
Technical contacts: Phillip J. Rush, NRR Eric J. Benner, NRR
301-415-2790 301-415-1171 E-mail: pjr1@nrc.gov E-mail: ejbl@nrc.gov
Attachment: List of Recently Is ued NRC Information Notices
14y4 p
KU ,achment
..
IN 97-88 December 16, 1997 LIST OF RECENTLY ISSUED
NRC INFORMATION NOTICES
Information Date of
Notice No. Subject Issuance Issued to
97-87 Second Retrofit to 12/12/97 All industrial radiography
Industrial Nuclear Company licensees
IR 100 Radiography Camera, to Correct Inconsistency In
10 CFR Part 34 Compatibility
97-86 Additional Controls for 12112/97 Registered users of the Model
Transport of the Amersham No. 660 series packages, and
Model No. 660 Series Nuclear Regulatory Commission
Radiographic Exposure Devices industrial radiography licensees
97-85 Effects of Crud Buildup 12/11/97 All holders of OLs for pressurized- and Boron Deposition on water reactors, except those
Power Distribution and licensees who have permanently
Shutdown Margin ceased operations and have
certified that the fuel has been
permanently removed from the
reactor vessel
97-84 Rupture in Extraction 12/11/97 All holders of OLs for nuclear
Steam Piping as a power reactors except those
Result of Flow-Accelerated who have permanently ceased
Corrosion operations and have certified
that fuel has been permanently
removed from the reactor vessel
95-49, Seismic Adequacy of 12110/97 All holders of OLs for nuclear
Sup. 1 Thermo-Lag Panels power reactors
97-83 Recent Events Involving 12/05/97 All holders of OLs for pressurized- Reactor Coolant System water reactors, except those
Inventory Control During licensees who have permanently
Shutdown ceased operations and have
certified that fuel has been
permanently removed from the
reactor vessel
OL = Operating License
CP = Construction Permit
7-88 K Member 16,1997
- 1 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 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 Inthis notice, please contact one of the technical contacts listed
below or the appropriate Office of Nuclear Reactor Regulation (NRR) project manager.
original signed by
Jack W. Roe, Acting Director
Division of Reactor Program Management
Office of Nuclear Reactor Regulation
Technical contacts: Phillip J. Rush, NRR Eric J. Benner, NRR
301-415-2790 301415-1171 E-mail: pjrl@nrc.gov E-mail: ejbl@nrc.gov
Attachment: List of Recently Issued NRC Information Notices
DOCUMENT NAME: 97-88.IN
- SEE PREVIOUS CONCURRENCE
To receive a copy of this document, Indicate In the box C=Copy wlo attachmen losureE wit attachmentlenclosure N=No copy
OFFICE PECB EMCB EMCB (A) C:EMCB
NAME EBenner PRush* CBeardslee* ESullivan*
DATE 11/20/97 109/09/97 09/10/97 /97 OFFICE (A) D:DE l SC:PECB C:PECB D:DRPM l
NAME GLainas* RDennig* SRichards*JRoer"'Z/
DATE 09/19/97 11/21 /97 12/03/97 12/08/97 OFFICIAL RECORD COPY
'7-
- ,6ember , 1997 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 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.
Jack W. Roe, Acting Director
Division of Reactor Program Management
Office of Nuclear Reactor Regulation
Technical contacts: Phillip J. Rush, NRR Eric J. Benner, NRR
301-415-2790 301-415-1171 E-mail: pjrl@nrc.gov E-mail: ejbl@nrc.gov
Attachment: List of Recently Issued NRC Information Notices
DOCUMENT NAME: G:\EJB1\SGINFO.WPD
- SEE PREVIOUS CONCURRENCE
To receive a copy of this document, indicate In the box C=copy wlo attachmenVenclosure E=Copy with attachment/enclosure N = No copy
OFFICE PECB EMCB EMCB l (A)C:EMCB l
NAME EBenner PRush* CBeardslee* ESullivan*
DATE 11/20/97 09/09197 09/10/97 /97 OFFICE (A) D:DE SC:PECB C:PECB DQRPM
NAME GLainas* RDennig* SRichards J
DATE 09/19/97 11/21 /97 01'/5/97 'P 97 pFFICIAL REPORD COPY
11A~ /&i///97
IN 97-xx
November xx, 1997 Page of 6 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 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.
Jack W. Roe, Acting Director
Division of Reactor Program Management
Office of Nuclear Reactor Regulation
Technical contacts: Phillip J. Rush, NRR
301-415-2790
E-mail: pjrl@nrc.gov
Eric J. Benner, NRR
301-415-1171 E-mail: ejbl@nrc.gov
Attachment: List of Recently Issued NRC Information Notices
DOCUMENT NAME: G:\EJB1\SGINFO.WPD
- SEE PREVIOUS CONCURRENCE
To receive a copy of this document indicate in the box C=Copy Wo attachmentlenclosure E=Copy Wth attachment/enclosure NNo copy
OFFICE JPECB l EMCB EMCB (A)C:EMCB
NAME EBenne PRush* CBeardslee* ESullivan*
DATE 11/20/97 09/09197 09/10/97 09/12/97 OFFICE (A) D:DE l SC:PECB A C:PECB l D:DRPM Il
NAME GLainas* RDennig8( SRichards JRoe
DATE 09/19/97 10/497 10/ /97 091 /97 OFFICIAL RECORD COPY
!
IN97-xx
September xx, 1997 Technical contacts: Phillip J. Rush, NRR
301-415-2790
E-mail: pjrl@nrc.gov
Eric J. Benner, NRR
301-415-1171 E-mail: ejbl@nrc.gov
Attachment: List of Recently Issued NRC Information Notices
DOCUMENT NAME: G:\EJB1\SG-INFO.WPD
- SEE PREVIOUS CONCURRENCE
To receive a copy of this document, Indicate In the box C=Copy w/o attachment/enclosure E=Copy with attachment/enclosure N = No copy
OFFICE PECB EMCB f EMCB I1 (A) C:EMCB I ET
NAME EBenner _ __PRush_ _ _ CBeardslee (&~ ESullivan a
DATE 09/ t/97 09107197 109/_ _ _97__ 09/f1/97 OFFICE (A) :DE PECB f (A) C:PECBI D:DRPM
NAME GLa s EGoodwin RDennig JRoe
DATE 997 09/ /97 09/ /97 109/ /97
1A k ,!f OFFICIAL RECORD COPY