IR 05000313/1992026
| ML20035A957 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 03/16/1993 |
| From: | Collins S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20035A955 | List: |
| References | |
| 50-313-92-26, 50-368-92-26, NUDOCS 9303300282 | |
| Download: ML20035A957 (33) | |
Text
{{#Wiki_filter:, . . ~ , APPENDIX U.S.' NUCLEAR REGULATORY COMMISSION
REGION IV
NRC Inspection Report: 50-313/92-26 50-368/92-26 Operating Licenses: DRP-51 NPF-6 Licensoe Name: Entergy' Operations, Inc.
Route 3, Box 137G Russellville, Arkansas 72801 Fr:ility Name: Arkansas Nuclear One, Units 1 and 2 Inspection At: Arkansas Nuclear One, Russellville, Arkansas inspection Conducted: November 2-6 and 16-20, 1992 Inspectors: 1. Barnes, Technical Assistant Division of Reactor Safety W. McNeill, Reactor Inspector, Engineering Section Division of Reactor Safety Dr. B. Nicholas, Senior Radiation Specialist
Division of Radiation Safety and Safeguards
i Dr. D. Powers, Chief, Maintenance Section l Division of Reactor Safety ' W. Walker, Resident Inspector, Cooper. Nuclear Station , Division of Reactor Projects ! Accompanied by: Dr. C. Dodd, Consultant, Oak Ridge National Laboratory ,
Approved: M' D6 km O 3-/bM Samuel J. Col ins, DirectBr () Date ) ~ Division of seactor Safety Inspection Summary Inspection Conducted November 2-6 and 16-20, 1992 (Report 50-313/92-26) Areas Inspected: No inspection of Unit I activities was performed.
Results: Not applicable.
I -! 9303300282 930316 ' PDR ADOCK 0500
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i-2- ] Inspection Conducted November 2-6 and 16-20. 1992 (Report 50-368/92-26) Areas Inspected: Routine, announced inspection to determine the material f condition of Unit 2 steam generator tubing, and to assess the effectiveness of ! licensee programs in detection and analysis of degraded tubing, repair.of defects, and correction of conditions contributing to tube degradation.
[ i Results: , ! The Unit 2 design is unique to the facility and utilizes two vertical
., U-tube recirculating steam generators, each containing 8411 high- !
temperature mill annealed Inconel 600 tubes. The reported mechanical ! properties for the tubing suggested that actual annealing temperatures
used were variable (Section 2.2).
The highest incidence of repairable defects has occurred at.the tube i
expansion transition area on the hot-leg side, with Steam Generator A exhibiting a significantly greater number than Steam Generator B.
The
difference between the two steam generators appeared to be related to i the significantly greater amount of sludge that has been deposited in ! Steam Generator A (Section 2.4).
l Bobbin coil examinations were performed on the minimum 3 percent sample
required by the Technical Specifications through Refueling Outage 2R7 in
1989. Augmented sampling required by the Technical Specifications was l performed during Refueling Outage 2R8 in 1991, as a result of' identified ! defects at eggcrate support locations in Steam Generator B (Section 4.1).
Response to the issue contained in Information Notice 90-49 (i.e., !
identified circumferential cracking at the tube expansion transition l area, whicn was generally only detectable using specialized probes such -! - as the motorized rotating pancake coil) was deferred.by the licensee until concerns abnt time in reduced inventory could be eliminated by , acquisition of nozzle dams (Section 4.2.2).
, f Following a tube leak in March 1992 and confirmation that it_ was caused l
by a circumferential crack in the tube expansion transition area, the ! licensee has performed extensive motorized rotating pancake coil
examinations at this location in both steam generators (Section 4.1).
l I The licensee upgraded eddy current program requirements for Refueling i
Outage 2R9 (Fall 1992) with respect to content of data analysis ! guidelines and adoption of formalized training and testing of data l analysts (Section 4.2.1).
j ! Defects were present and not detected Juring the Spring 1992 outage .
which was attributed, in part, to motorized rotating pancake coil noise (Section 4.3).
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The contractor did not comply with procedural' requirements for control f
of tools and equipment during replacement of the Steam Generator A i feedwater distribution box and thermal sleeve. This was identified as a
noncited violation (Section 3.1).
! The Spring 1992 program for laboratory examination of pulled tubes
-! containing defect indications was considered outstanding with respect to acope and technology used (Section 5.3).
For the first 3 years of commercial operation, Unit 2 was operated with !
no analytical requirements or monitoring for chloride, sulfate, and oxygen on the secondary side (Section 6.1).
j Since the adoption of Electric Power Research Institute secondary water 'l
chemistry guidelines in March 1983, progressive reductions have occurred
! in sulfate, chloride, and sodium concentrations and cation conductivity in the respective steam generator blowdowns, and in copper and oxygen concentrations in the feedwater system.
Little increase in. tube denting
problems was observed since the initiation of boric acid treatment in ! August 1983 (Section 6.2).
Progressive improvements were made since 1983 in makeup water treatment
technology and secondary water conditioning (Section 6.2).
'j Summary of Inspection Findings: .l A noncited violation was identified (Section 3.1).
. Attachment: , t Attachment - Persons Contacted and Exit Meeting . i i ! .
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. ' . . - . t , _4_ ' DETAILS . 1 STEAM GENERATOR YUBE INTEGRITY REVIEW (73755,79501,.79502) The objectives of this inspection were: (a) to ascertain the material condition of Unit 2 steam generator tubing; and (b) to assess the i effectiveness of licensee programs for detection and analysis of degraded tubing, repair of defects, and correction of conditions contributing to tube-degradation.
2 STEAM GENERATOR MATERIALS AND TUBE DEGRADATION HISTORY 2.1 Steam Generator Description t Arkansas Nuclear One, Unit 2 (AND-2) is a Combustion Engineering (CE) Model 2815 design plant which began commercial operation in March 1980.
The plant design is unique to ANO-2 and utilizes two vertical U-tube recirculating steam generators, each containing 8411 Inconel 600 tubes with nominal outside
diameter and wall thickness, respectively, of 0.75 inches and 0.048 inches.
i The steam generator tubes are supported by nine eggcrate type supports (seven full and two partial), two partial drilled support plates, and five strap supports (known as batwings) for the horizontal run of the tubing.
The
material used for fabrication of the vessel shell and internals (including supports) is carbon steel, The eggcrate type support consists of an array of intersecting 1-and 2-inch wide strips.
2.2 Tubino Material ' The inspectors reviewed the technical requirements for ANO-2 steam generator tubing contained in CE Purchase-Specification P4382(e), " Purchase Specification for Nickel-Chromium-Iron Alloy Tubular Products," dated June 5,
1968, and CE Purchase Order 40-80035 dated December 29, 1970, with Supplement I dated October 4, 1971.
It was noted from this review-that ASME Material Specification SB-163 was utilized for the procurement, with the , invoked ASME Codes being 1968 Edition through Winter 1969 Addenda for ' Section III and 1968 Edition through Winter 1968 for Section II. The tubing was specified to be furnished in a bright annealad condition, with test , requirements including a hydrostatic test at 3150 psig, ultrasonic examination, and eddy current examination.
A liquid penetrant examination was i also specified to be performed on a sample of tubes. Appropriate prohibitions
were imposed on the tubing manufacturer in regard to use during manufacture of sulfur-bearing compounds and low-melting point elements.
i i The inspectors noted that the CE purchase order and purchase specification did not specify the annealing temperature to be used for the ASME SB-163 (Inconel 600) tubes.
The certified material test reports furnished by the tubing manufacturer also did not indicate the actual annealing temperature used. A response document to the purchase order from the tubing manufacturer did, however, indicate that the final anneal would be performed at a
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i >.: -5- ! i temperature above 1800oF. The inspectors questioned the licensee on this.
! subject, in that it was noted.that ABB Combustion Engineering (ABB-CE) had cited the use of a specific annealing temperature in its report pertaining to examination of. tubes pulled during the Spring 1992 outage (i.e., ~2F92). _ The licensee determined from ABB-CE that the referenced specific -annealing ] temperature (considered proprietary by ABB-CE) was'obtained during ! > conversations with the tubing manufacturer.
This temperature was apparently ! selected to be a balance between a minimum temperature. to obtain acceptable. ! grain size and a maximum temperature to ensure necessary strength properties.
! I It was noted during review of the report for the 2F92 pulled tubes, that-it - I was inferred that the high-temperature anneal used Eshould have reduced the .j susceptibility of the tubing to primary water stress corrosion cracking. This i was because of solution of a significant amount of carbides and enlargement of-l grain size, with precipitation of carbides occurring 'on the grain. boundaries
during cooling from the annealing temperature.
Review by the inspectors of l - the certified material test reports for the ANO-2 tubing showed, however,
0.2 percent yield strength and ultimate tensile ' strength values which' ranged,-
respectively up to 17,500 psi and 19,000 psi above the minimum recorded i values. This spread of mechanical property values. indicated to the inspectors that variations had occurred in' the actual annealing-temperatures used for the j steam generator tubing.
It would, thus, appear that the resistance of the i tubing to primary water stress corrosion cracking is not as uniform as suggested by the contractor report. To date, however, no evidence of primary water stress corrosion cracking has been found~in ANO-2 steam generator
tubing.
l ' 2.3 Tube-to-Tubesheet Fabrication , The inspectors ascertained that after insertion of the tubes into-the drilled j ' holes in the tubesheet (i.e.v the forging used to support the U-tubes), the i fabrication sequence consisted initially of performing the tube-to-tubesheet.
i welds on the clad primary side of the tubesheet.
Verification of weld quality ' , ' was accomplished by liquid penetrant examination ~. _ Subsequently, the tubes' , were explosively expanded into the tubesheet by use of detonating -cords. -This .I expansion was to have been performed over the full height'of the tubesheet, ! with the intent of eliminating all of the tube-to-tubesheet crevices. During j review of the procedural requirements for the explosive expansion hetivity, ! the inspectors observed that there did not appear to be any post-expansion inspection verification that the expansion _ process had been satisfactorily ! accomplished.
! ! The licensee confirmed from discussion with ABB-CE representatives that j quality verification activities were restricted to the control of the explosive expansion process, with no post-expansion inspection performed.
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l < 2.4 Steam Generator Tube Degradation History i a i Prior to operational service, Steam Generators A and B contained, l respectively, 15 and 29 plugged tubes. Table 1-provides the plugging / sleeving
history for the two steam generators as a function of effective full power ! years (EFPYs) at the time of each repair.
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Table 1 !, i , Time of Operational Repair Time (EFPYs) Steam Generator A Steam Generator B .l (Outage) f Plugged Sleeved Plugged Sleeved !
Preservice
15
29
! i 2R2 (1982) 1.69
0
0 [ t 2R6 (1988) 5.38
0
0 l j i 2R8 (1991) 7.67
0
0 l 2F92 (1992) 8.51
392
56 l e i 2R9 (1992) 8.85
-4 132
- Total 111 388 252
i Repairs The tube plugging activities in Steam Generator B during Refueling Outages 2R2 (1982) and 2R6 (1988) resulted from the bobbin coil eddy current examination
identification of repairable tube wear at batwing support locations.
Tube ! denting, although not requiring repairs, was also initially identified in i Steam Generator A during Refueling Outage 2R2 at the partial drilled supports.
! The licensee connenced secondary side boric acid additions in 1983 to arrest l or inhibit the progress of denting (see Section 6.2 for further details).
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Primary to secondary leakage was initially detected in Steam Generator A in i August 1990 during a plant transient. Leakage was again detected during a i plant transient in February 1991.
Leakage decreased below the detection limit
for both cases when the unit reached steady state power. A helium test was . performed during Refueling Outage 2R8 (1991) in an attempt to locate the l source of the leak, but was unsuccessful.
Axial tube defects requiring repair . were found during Refueling Outage 2R8 at eggcrate locations in Steam Generator B.
These defects were identified primarily by the bobbin coil eddy ? current method, with a limited number of motorized rotating pancake ! coil (MRPC) examinations also performed to assist in characterization of the ! defects.
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t e i i In March 1992, a step change in Steam Generator A leakage occurred, with the leak rate increasing to 0.25 gpm. ANO-2 was taken off line.as a result of the leakage exceeding an administrative limit of_0.1 gpm.. Testing showed that the j leak occurred in Tube 67-109 on the hot leg side of Steam Generator A.
Bobbin-l coil and MRPC eddy current examinations confirmed that the leak was caused by-i outer diameter circumferential cracking at a tube location slightly above the i tubesheet (i.e., tube expansion transition area).
As a result of this j finding, the licensee performed during the resulting Outage 2F92 an MRPC i examination of the expansion transition area of 100 percent of the active -! tubes in both steam generators on the hot leg side.
These examinations resulted in a significant_ incidence of repairs as denoted ! by the plugging and sleeving totals shown in Table 1 for. 0utage 2F92.
l Sleeving was the primary method utilized during this outage for repair of
expansion transition area defects.
Prior to performing the sleeving operation j a bobbin coil examination was performed of those tubes exhibiting defects at
this location, in order to establish whether additional repairable indications ! existed at other locations.
Those tubes showing additional repairable defect [ indications at locations away from the expansion transition area were plugged .! ' and stabilized.
In addition to the hot leg side examinations, MRPC ! examinations were performed on a 20 percent sample in the sludge. pile region of Steam Generator A on the cold leg side. The sludge pile region is the area.
on the tubesheet surface in which erosion / corrosion products from the condensate and feedwater systems accumulate. No defects were. identified i during these examinations.
v As of Refueling Outage 2R9 (1992), the licensee had identified 416 and 67 l repairable defect indications, respectively, in the expansion transition areas ! of tubes in Steam Generators A and B.
The licensee had made spatial ! distribution plots for those tubes that exhibited defect indications at this l location, and determined that the tube defect distributions coincided with.the i sludge pile region in the steam generators. The licensee conducted sludge [ lancing at each refueling outage since Refueling Outage 2R3 (1983). The j sludge piles were described by licensee representatives to be hard and l concrete like, and impossible to remove completely. Through Refueling q Outage 2R9, the licensee had removed a total of 2879 pounds of sludge from - Steam Generator A and 1207 pounds from Steam Generator B (see Table 2 in Section 6.2).
The reason for the difference in sludge quantities between the l two steam generators was probably related to a plant design feature, which is ! discussed in Section 6.8 of this report. This sludge differential appeared to ! correlate with the observed difference between the two steam generators in j repairable indications at the expansion transition area of the tubes.
l 't Two other differences were noted between the two steam generators with respect-l to incidence of repairable defect indications.
Licensee data indicated that ' the cumulative defects at the eggcrate supports and batwing supports were ' significantly higher for Steam Generator B than Steam Generator A (i.e., , ! I i f r i f - _ _
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- _ _ - _ _ m . .' . - . -8- -through Refueling Outage 2R9 the respective defect numbers for Steam Generators A and B were 30 versus 147 at the eggcrate supports, and 10 versus 46 at the batwing supports). The inspectors were unable to ascertain the reasons for these apparent differences.
The licensee's current safety analysis allowed for each steam generator to have 5 percent plugging without derating the unit. - For heat transfer analysis purposes, the licensee considered 20 sleeves to be equivalent to one plug.
Using this criterion, the plugged and equivalent plugged (i.e., sleeved) tubes as of Refueling Outage 2R9 equated, respectively, to 1.56 percent and 3.04-percent for Steam Generators A and B.
At the time of the inspection, the licensee was exploring the possibility of reevaluating the loss-of-coolant accident to determine whether the plugging limit'could be increased to 10 percent per steam generator.
2.5 Conclusions The plant design is unique to ANO-2 and utilizes two vertical U-tube recirculating steam generators, each containing 8411 high-temperature mill annealed Inconel 600 tubes. Review of the range of mechanical properties in the certified material test reports for the tubing suggested that variations occurred in the actual annealing temperatures used.
During vessel fabrication, the tubes were explosively expanded into the tubesheet to eliminate a crevice condition. Quality verification activities for this operation appeared to have been restricted to control of the explosive expansion process, with no post-expansion inspection performed.
The highest incidence of repairable defect indications occurred at the tube expansion transition area, with Steam Generator A exhibiting a significantly greater number than Steam Generator B.
These defect indications were first identified in March 1992 after 8.51 EFPYs subsequent to a tube leak. The defects' originated at the outer surface of the tubes, and were determined to have been confined to the sludge pile region of the steam generators. The difference.in-repairable defect indications between the two-steam generators appeared to the inspectors to be related to the significantly greater amount of sludge that-has been deposited in Steam Generator A.
Axial cracking in tubes at eggcrate support locations and wear at batwing support locations was also detected in both steam generators, with Steam Generator B showing a significantly higher frequency for these defect types than Steam Generator A.
The inspectors were unable to ascertain the reasons for this difference.
3-VISUAL EXAMINATION FOR LOOSE PARTS 3.1 Replacement of Steam Generator A Feedwater Distribution Box and Thermal Sleeve The inspectors reviewed the programmatic requirements that were applicable to the control of tools and equipment during. replacement (because of erosion damage) of the feedwater distribution box and thermal sleeve in Steam.
Generator A.
This replacement activity was performed by ABB-CE in Refueling - Outage-2R9, with the work accomplished using the contractor's welding and _ __ _ _,, . .-. - . .-..- . - -- . .- .- ,. .. . , , .: - _ ! - .
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-9-l i ' ' i quality assurance programs.
It was noted from this review that the' licensee's l , t procedures (i.e., 2402.144, "CE Unit 2 Secondary Side Inspection 2E24A&B," Revision 1; and 2402.102, "2E24 Secondary Manway/Handhole Cover. . . Removal / Reinstallation," Revision 5) required use of lanyards on tools and parts, and verification of removal of the tools and equipment after completion of work activities. ABB-CE Traveler 1611920-002, Revision 0, similarly required use of lanyards on tools and equipment prior to entry. into the steam generator when the annulus seal was not present. The traveler additionally specified that a material and tool accountability system be implemented for-work performed inside the steam generator.
The inspectors requested the licensee obtain from.the contractor the document ! which described the material and tool accountability system requirements { referenced in ABB-CE Traveler 1611920-002.
Section OP-8.3, " Personnel and
Material Accountability for Controlled Access Areas," Revision 7, of the l ABB-CE Operating Procedures Manual was provided in response to this request.
Review of paragraph 4.3 of this' document showed that a material accountability log was required to be maintained with a record made of all materials, tools, and equipment entering or leaving the area. The log was required to be reconciled each shift (for multi-shift operations), with each item logged into the area (but not logged as having been removed) to be identified, its ! location verified, and the log corrected accordingly.
! t The inspectors reviewed the log that had been generated for the ABB-CE ! Traveler 1611920-002. work activities and noted' that the log.did not provide a I clear accountability for items that had entered Steam Generator A during the .l work activities. Although the log contained statements indicating !' reconciliations were performed on given days, it was not possible from the.
available records to determine what was the nature of the reconciliations performed. Examples selected by the inspectors to illustrate the problems > with the logs were' control of flashlights and lead blankets. _In.the case of ) flashlights, the log records indicated four more flashlights entered the steam- ' generator than ultimately came out.
In the case of. lead blankets, the records indicated an undefined number entered the steam generator on September 16, 1992. Subsequent to that date, the records showed a total of 72' lead blankets I entering the steam generator, with a. total of 201 ultimately being removed.
! The inspectors noted that an annulus seal (18 feet in length) was used during ! ABB-CE Traveler 1611920-002 activities to reduce the risk of passage of ! dropped objects into the tubesheet area. A final inspection was also l performed prior to removal of the' annulus seal to assure removal of any l foreign material.
Review of sludge lancing records indicated that appropriate
log keeping with respect to removal of observed foreign objects was being i performed as part of this work activity.
Reasonable assurance of the ] effectiveness of the inspection process during sludge lancing was indicated by j the recovery of all but one battery from flashlight parts that were documented
as having been dropped during removal 'of the annulus seal. The licensee ' initiated Condition Report CR-2-92-04/8 to develop corrective actions with-i respect to procedural compliEnce during future contractor work activities.
'l The failure to comply with procedural requirements for material accountability ! , I i f x -. -
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is a violation of Criterion V of Appendix B to 10 CFR 50. The violation is not being cited because it was isolated in nature and of minor safety -{ significance, and met the criteria specified in Section VII.B.1 of Appendix C ' to 10 CFR 2.
3.2 Conclnsions . The contractor failed to comply with procedural requirements for the )
control of tools and equipment, for which a noncited violation was
identified.
j Appropriate inspection provisions were established for identification of = loose parts and foreign materials that were present at the end of the -! work activities.
! t 4 REVIEW OF TUBE EXAMINATION HISTORY, PROGRAM REQUIREMENTS, AND DATA l , 4.1 Review of Tube Examination History j t Through Refueling Outage 2R7 (1989), the licensee performed differential I bobbin coil eddy current examinations of the minimum 3 percent tube sample i required by the Technical Specifications (TS). No repairs were required in
Steam Generator A in this period, with only very limited repairs being
required in Steam Generator B due to identified wear at batwing support .' locations. During performance of the bobbin coil examinations on the ! 3 percent tube sample in Refueling Outage 2R8 (1991), defects (i.e., axial
cracking) were discovered in Steam Generator B tubes at eggcrate support , -locations.
In accordance with TS requirements for an identified Category C-3 l' (more than 1 percent of the sample defective) condition, the inspection scope was increased to 100 percent of the tubes in Steam Generator B and 9 percent of the tubes in Steam Generator A.
In addition to the bobbin coil
examinations performed on tL se tubes, limited MRPC examinations were ' performed (i.e.,17 at tube support plate locations and 2 in the sludge pile region). As noted in Table 1 in Section 2.4, the examinations resulted in 73 ? tubes being repaired in Steam Generator B and no repairable indications being i found in Steam Generator A.
l Following the tube leak in Steam Generator A in March 1992, and confirmation f that it was caused by circumferential cracking at a location just above the tubesheet surface, the licensee extensively utilized MRPC examinations for the i first time.
This method was used to examine the expansion transition area of i the tubes because of the recognition that it was far superior to the bobbin j coil technique in its ability to detect circumferential defect indications.
As identified previously in Section 2.4, MRPC examinations were performed on
the hot leg side of 100 percent of the tubes at the expansion transition area i for both steam generators. These examinations resulted in a total of 488 ! repairs (i.e., Steam Generator A - 421, 392 sleeved /29 plugged; Steam l Generator B - 67, 56 sleeved /ll plugged). MRPC examination of a 20 percent
' tube sample on the cold leg side of Steam Generator A in the sludge pile i
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. -11-t i i region revealed no defect indications.. In addition to the eddy current -! examinations performed, a limited number of ultrasonic examinations using a l specialized technique were performed.
Five tube samples containing defect
indications were also removed during Outage 2F92 for laboratory examination, in order to assess the operative damage mechanisms and. establish by l metallography the capability of eddy current examination techniques (bobbin
and MRPC) and ultrasonic examination to detect and characterize defects.
The j results of the laboratory examinations are discussed in Section 5.
j i During Refueling Outage 2R9 (September 4 through October 20, 1992), the ! licensee performed in both steam generators a 100 percent MRPC. examination on - l the hot leg side of the active (and unsleeved) tubes in the expansion ! transition area. A 20 percent sample was similarly inspected at the -same location on the cold leg side of both steam generators.
In addition, a . full-length bobbin coil examination was performed on 100 percent of the active { tubes in both steam generators. These examinations resulted in a total of 199 ! repairs (i.e., Steam Generator A - 67,17 tube expansion transition area
, ' circumferential indications /50 defect indications at other locations; Steam- .} Generator B - 132, 8 tube expansion transition area circumferential { indications /124 defect indications at other locations).
Two additional tube samples were removed durirg Refueling Outage 2R9 for laboratory examination.
} The results from these examinations are discussed in Section 5.
l 4.2 Review of Examination Program Reauirement's i ! 4.2.1 Current Program The inspectors reviewed the current eddy current examination program
requirements which were contained in: (1) Procedure 5120.501, " Steam _ , Generator Integrity Program - Unit 2," Revision 3;-(2) Engineering i Standard ;iES-28, "AND-2 Steam Generator ECT Data Analysis. Guidelines," < Revision 0; and (3) Engineering Standard ties-29, "ANO-2 Steam Generator ECT 'j Performance Demonstration," Revision 0.
The inspectors also compared the i j current program against prior program requirements and the recommendations ! contained in Electric Power Research Institute (EPRI) NP-6201, "PWR Steam i Generator Examination Guidelines," Revision 2.
Although.no specific ! commitment to EPRI NP-6201, Revision 2, was noted in the program, it was j observed that the program, with two exceptions, was generally consistent with-l the recommendations contained in the EPRI guidelines.
The two exceptions ' i pertained to sample size and criteria for noisy data. The program established f that the Engineering ' Programs organization was responsible for selection of l the steam generator inspection vendor and planning of the scope of the
vendor's outage work, with an approved test plan to be prepared which ' identified the tubes to be inspected. The program did not reference the EPRI ] recommended 20 percent sample or provide governing. criteria for the sampling
approach that has been used since Outage 2F92. No program guidance was
provided with respect to the EPRI NP-6201 recommendation concerning j establishment of criteria for noisy data.
In general, the current program
requirements (which were applicable to the examination activities performed ' ! ! !
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! . . r-12-i t - . .. during Refueling Outage 2R9) were found to be more comprehensive than those in ! effect during prior outages. The two main arear of improvement noted were in-l the content of data analysis guidelines and the adoption of formalized training and testing of data analysts, l
The data analysis guidelines were found to be much more detailed than the l limited guidelines that were in effect for prior outages.
It was noted, j however, that the guidelines were written to address both ANO-2 and j Waterford 3.
The inspectors informed cognizant licensee personnel that, while
it was beneficial to be aware of degradation mechanisms at other plants, the l use of plant and outage specific guidelines was considered-the best appro'ach ! for ensuring an optimal inspection. Two subject areas were noted in which the f inspectors believed further improvements in the data analysis guidelines might j be made (i.e., inclusion of guidance on allowable noise in eddy current scans,. i as discussed above; and inclusion of' guidance for examination of sleeved areas
of tubes). Some clarification of certain figures in the text to more clearly indicate the region of interest or the point the figure was illustrating was - also considered beneficial. . ! Prior to the issue of Engineering Standard HES-29, Revision 0,-on l September 10, 1992, the. licensee did not have any criteria for training and i testing of eddy current personnel other than SNT-TC-1A requirements, j SNT-TC-1A requirements for this discipline were considered by the inspectors
to be minimal and non-specific. The current program provided 3 days for ! training and testing of data analysts, with significant time. allotted for j review of tapes from prior outages. A review of the. testing records for the
data analysts employed during Refueling Outage 2R9 identified no problems. with j the implementation of program requirements.
j The NRC consultant also noted, with respect to inspection methodology, that l , the current reliance on bobbin coil examination for drilled tube support-
' -locations could potentially result in a failure to detect any existing axial i or circumferential cracking, because of the masking effect.of dent signals at !
these locations. Accordingly, the licensee was informed of this matter and'a i similar concern in the steam blanketed region.
! 4.2.2 Response to Generic Communications f The inspectors performed a limited review of the licensee's handling of NRC l generic communications pertaining to steam generator problems. The sample ! ' used for this revi sw was Bulletin 89-01, " Failure of Westinghouse Steam l Generator Tube Me.hanical Plugs," and Information Notice 90-49, " Stress
Corrosion Cracking in PWR Steam Generator Tubes," and 91-67, " Problems With l the Reliable Detection of Intergranular Attack (IGA) of $ team Generator i Tubing."
j i The review indicated that the licensee appropriately responded to .i Bulletin 89-01 and Information Notice 91-67. The inspectors questioned j licensee personnel, however, regarding the timeliness of actions in response
to Information Notice 90-49.
Information Notice 90-49, " Stress Corrosion
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l Cracking in PWR Steam Generator Tubes," dated August 6,1990, specifically j alerted licensees to the identification of circumferential cracking in the t-tube expansion transition area. This identification included reference to two plants, for which CE was the nuclear steam system supplier, and noted that cracking was generally only detectable through the use of specialized probes ! such as the MRPC probe.-- During the 1991 Refueling Outage 2R8, only very ! limited MRPC examinations were performed (see Section 4.1).
Licensee
personnel informed the inspectors that, because of concerns about time in ! reduced inventory, significant MRPC examinations were not performed during i Refueling Outage 2R8.
These examinations were indicated as having been ! ! planned to be performed during Refueling Outage 2R9 following acquisition of nozzle dams.
[
4.2.3 Vendor Utilization j In the last three outages (i.e., 2R8, 2F92, and 2R9), three vendors were used, either singly or in combination, for performance of eddy current examinations-i of steam generator tubing.
In each of these outages, a process was in place i to provide for at least two separate reviews of data by analysts (i.e., ! primary and secondary analysts). When the primary and secondary analysts i differed in specific data interpretation, a resolution process was entered l into.
i > During Refueling Outage 2R8, Westinghouse provided the primary, secondary, and i resolution analysts for the 3 percent TS sample.
For the examination of the ! augmented sample during this outage, licensee personnel acted as ' secondary ' analysts. A consultant from ABB-CE also acted as the lead resolution analyst [ during the last 80 percent of the outage.
Babcock and Wilcox Nuclear ! Services (BWNS) provided the primary, secondary, and resolution analysts ! during the forced 2F92 outage. During Refueling Outage 2R9, ABB-CE acted as j the primary analysts, BWNS as the secondary analysts, and a consultant from
ABB-CE as the senior analyst for resolution.
The inspectors observed that the-1' current program did not provide any specific criteria regarding vendor utilization and ground rules for independence.
Licensee personnel indicated j that it was planned to~ address such subjects in programmatic documents.
i 4.2.4 Eddy Current Program Oversight ! During Outage 2f92, the inspectors ascertained that nine surveillance reports, f NDE 92-001 through NDE 92-009, were issued by quality assurance with respect
to BWNS activities in the area of steam generator inspection.
Five ! surveillance reports, 2R9ECT-001 through 2R9ECT-005, were ascertained to have } been issued with respect to ABB-CE steam generator inspection activities
during Refueling Outage 2R9. A weakness had been identified in a previous NRC l inspection (Inspection Report 50-368/92-07) pertaining to the scope and j effectiveness of the quality assurance oversight of the eddy current ' examination contractor during Refueling Outage 2R8. Based on review of the ! I i ' ,
.- ~- ~. .. - -- - -- - .. -.. . ! .. q . .
. ! ! -14-
- !
! ! .l surveillance reports, it appeared that this weakness had been corrected.
No-i l problems with the surveillances were noted by the inspectors during this
review, other than a minor administrative matter regarding.signoff of some of-
the reports after review by management.
4.3 Review of Tube Examination Data l The NRC consultant reviewed the bobbin coil examination data for Tube 67-109 ! that was obtained during Refueling Outage 2R8. The defect was observed to be i visible during this outage, but was not detected because of analyst error.
i Simulating the required span in the setup procedure, the actual defect was ' off-screen due to the presence of a dent signal.
Examination at a reduced- . gain setting showed the defect. The failure of the analysts to follow the j off-screen excursion and examine the entire signal was attributed by the NRC .t consultant to a lack of appropriate guidelines, training, and testing during .i the outage.
l
All 488 tubes, that were identified during Outage 2F92 to contain i circumferential defect indications, were inspected by the bobbin coil as part i f of the process to determine whether the repair would be accomplished by sleeving or plugging. Examination of the bobbin coil data for a sample of 67
of these tubes showed only 5 or 6 which exhibited.even a distorted indication.
These results confirmed that the bobbin coil is not an effective method for ! screening for circumferential cracking.
,l Review of MRPC data from Refueling Outage 2R9 indicated that the scans were .h less noisy than those performed in the previous two outages. As noted in l Section 4.1, 25 additional circumferential defects:(17 in Steam Generator A, 8 - in Steam Generator B) were identified in the tube expansion transition area . during Refueling Outage 2R9. A re-evaluation was performed of the previous , , Outage 2F92 data for these tubes and a comparison made against"the Refueling l Outage 2R9 data. The NRC consultant concluded from review of the two data sets that there was no evidence in the Outage 2F92 data of a defect being
present in seven of the tubes.
For eight of the Refueling Outage 2R9 identified defects, it was inconclusive from data review whether a defect was ! present in the prior outage. Eight of the Refueling Outage 2R9 identified
' t defects did appear to be present during Outage 2F92 and to be of the same size. The remaining 2 of the 25 Refueling Outage 2R9 identified defects also
appeared to be present during Outage 2F92, with thc data indicating definitive I crack growth between the two outages.
i The NRC consultant concluded from the data review that some of the defects j were missed during Outage 2F92 because of MRPC probe noise. The reasons for t it being inconclusive whether certain defects were or were not present during _!
Outage 2F92 were also related to the data being too noisy to be certain. As discussed in Section 4.2.1, no program criteria currently existed with respect to noisy data. The inspectors were unable to fully establish the reasons for ! repairable defects being found during Refueling Outage 2R9, for which there
was no evidence of their existence a matter of months previously.
In the'_ j judgment of the NRC consultant, MRPC examination would probably not detect l
i . > ' . i . g .,% -. ._%, _._ .. - ' . . - j s . , , -15- ! ! outer diameter cracks of this type if they were less than 40 percent ~ throughwall. As a result of the " normal" signal present at this location above the tubeshec-t, he considered the level of reliable detection would be
only about 6u percent to 60 percent throughwall. This level of detection i capability provided some explanation for the sudden detection of repairable , defects, but was not considered to fully account for this scenario.
i ) 4.4 Conclusions j ! The licensee performed bobbin coil eddy current examinations on the
minimum 3 percent sample required by TS through Refueling Outage 2R7.
Augmented sampling required by TS was performed during Refueling ! i Outage 2R8, as a result of identified defects at eggcrate support locations in Steam Generator B.
Following a tube leak in liarch 1992 and confirmation that it was caused
by a circumferential crack in the expansion transition area, the i licensee performed 100 percent 14RPC examinations of this region of the j steam generators in both the forced Outage 2F92 and the following
Refueling Outage 2R9.
Full-length bobbin coil examinations of all of , the active tubes in both steam generators were also performed during i Refueling Outage 2R9.
l The present eddy current examination program requirements were'found to
- !
be more comprehensive than what were in effect prior to the last ! refueling outage (2R9). The two main areas of improvement noted were in ! the content of data analysis guidelines and adoption of formalized l training and testing of data analysts.
Subjects the inspectors observed-l that were not addressed in the data analysis guidelines were allowable i noise in eddy current scans and criteria for examination of sleeved ! areas of tubes.
The licensee deferred response to the issue contained in Information }
Notice 90-49 (i.e., identified circumferential cracking at the tube. ! expansion transition area which was generally only detectable using " specialized probes such as liRPC) until concerns about time in reduced . inventory could be eliminated by acquisition of nozzle dams.
The licensee increased its scope and effectiveness of oversight of eddy i
current examination contractors during the last two outages.
Review of bobbin coil examination data confirmed that it is not an
effective method for screening for circumferential cracking.
i Comparative review by the NRC consultant of Outage 2F92 and Refueling e Outage 2R914RPC data (for 25 tubes in which additional circumferential ! cracking was identified during Refueling Outage 2R9) indicated the j following:
-. - .- - .- . - -- . ' . r . . ! w . !
-16-l
! (1) Eight of the defects appeared to have been present in.the 2F92-i data and were of the same size.
The defects were not, however, ! identified due, in part, to MRPC probe noise.
} (2) There was no evidence in the 2F92 data that seven of the defects.
! were present at that time.
The reasons for the sudden appearance l of repairable defects were not fully understood, but a partial.
explanation was the minimum size of a circumierential defect that l had to be present before reliable detection could be achieved.
! ! (3) It was inconclusive from review of the 2F92 data whether eight of l the defects were or were not present. This uncertainty was again i related to the data being too noisy to be certain.
! . (4) Two of the defects appeared to be present in the 2F92 data, with j the data indicating definitive crack growth between the two
outages.
. .i 5 LABORATORY EXAMINATIONS OF DEFECTIVE TUBES l ! The licensee pulled tube samples during Outage 2F92 and Refueling Outage 2R9 j for laboratory examination, in order to assess the operative damage mechanisms ! and establish the capability of nondestructive examination (NDE) methods in.
.l detection and sizing of defects.
5.1 Outaae 2F92 .! 5.1.1 Sample Selection .: ! During Outage 2F92 in Spring 1992, portions from the hot leg side of five - l steam generator tubes with defect indications were pulled from the generators for examination. Two tubes came from Steam Generator A and three tubes came from Steam Generator B.
These tubes exhibited eddy current defect indications
at either the top of the tubesheet or at eggcrate locations.
Comprehensive j examinations were performed which included radiography, burst testing, ' fractography, metallography, chemical analyses, and mechanical l characterizations. The results of these examinations were documented by the . contractor, ABB-CE, in three' volumes (marked proprietary) which were entitled l " Examination of Steam Generator Tubes From Arkansas Nuclear One Unit 2," dated August 1992.
The two tubes (R13L147 and R55L63) that were removed from Steam Generator A , were indicated by MRPC to contain 360 degree circumferential cracks at a 'i location just above the tubesheet. The average depth of these cracks was estimated by MRPC to be about 90 percent throughwall. A third tube (R36L130), removed from Steam Generator B, exhibited a similar defect indication which was estimated to have an average depth of about 80 percent throughwall.
During examination of Tube R36L130, it was' ascertained that a 4.5 inch length of this tube had-not been expanded into the tubesheet, resulting in a crevice condition at this location in the tubesheet.
(The presence of a crevice, - .- - - - -
. t _ - . . -17-r ! i however, has not been directly associated with the failure mechanism.) A fourth tube (R13C55), removed from Steam Generator 8, had several indications at eggcrate locations, which ranged up to about 50 percent throughwall. The ! licensee's eddy current examination did not identify the presence of five i circumferential cracks (about 30 percent throughwall) that were indicated by ultrasonic testing to be present. However, the metallographic examinations
subsequently revealed that the five ultrasonic indications were false ! positives. The remaining tube (R96L116), removed from Steam Generator B, had l a single defect indication at an eggcrate location, with an estimated average ! crack depth of about 40 percent throughwall.
l-l 5.1.2 Examination Results ! , Significant findings from the examination process are summarized below: l t In general, radiography did not detect tube wear that had occurred at i
eggcrate locations.
Radiography did, however, identify circumferential i cracking at locations above the tutesheet.
j ! Burst testing of three 8-inch specimens, one of which was defect free
and two of which contained axial flaws, resulted in failure pressures j which exceeded Regulatory Guide 1.121, " Bases for Plugging Degraded PWR t Steam Generator Tubes," minimum criteria of three times the plant i operating pressure differential.
} . Fractography revealed that circumferential cracks, which occurred just l
above the tubesheet, were associated with intergranular stress corrosion j cracking (IGSCC) and that there was no evidence of fatigue cracking.
Metallography confirmed the presence of throughwall IGSCC and I
intergranular attack (IGA), up to 25 percent of throughwall depth, for i defects located just above the tubesheet. Metallography also confirmed , IGSCC as the failure mode for axial cracks located in the eggcrate i support region. All cracking was found to have initiated on the outer surface of the tubes. There was no evidence of fatigue-related
cracking.
! l The chemical analyses showed that potentially detrimental surface !
deposits were present on the specimen tube surfaces which contained
(among other elements) lead, chlorine, copper, and sulfur.
Sulfur and
lead were the only elements that were found to be consistently present ' on the crack surfaces examined.
Diffraction (X-ray) studies showed the presence of magnetite fouling in !
the eggcrate locations.
! ! , ! I ! ! l !
. - - .. _ _ -l ,- l - . l - .
-18- ! 'I Ultrasonic testing with a shear wave transducer provided reasonably
accurate detection of circumferential cracks, but was established by j metallography to have provided some false positives of circumferential
cracks in Tube R19C55, and did not identify 50-60 percent maximum ll throughwall longitudinal cracks.
. Eddy current testing with a bobbin coil did not identify throughwall !
' circumferential cracks, but provided reasonably accurate detection of ! 50-60 percent maximum (with about a 35-40 percent average) throughwall longitudinal cracks.
l MRPC testing provided accurate detection of circumferential cracks, and !
provided good detection of 50-60 percent maximum throughwall
longitudinal cracks (of several tenths of an inch in length).
j The licensee's contractor report (and the second report addressing the
results of Refueling Outage 2R9 sample examinations that'is discussed below in Section 5.2) indicated that tubes with throughwall circumferential cracks may not have leaked during the helium pressure ' tests because these tubes were in a state of compression-that overcame the tensile stresses associated with the pressure test. The report surmised that the compressive stresses arose because of: (1) magnetite . fouling and mechanical restriction at the support plates or eggcrates, which restricted the free movement of tubes; and (2) difference;in tube (Inconel) and support material (carbon steel) thermal contraction
- '
associated with plant cooldown.
The inspectors questioned the licensee on this hypothesis and were subsequently informed by licensee personnel that " was believed that the steam generator tubes should be in a state of tensile stress during cold shutdown condition:. The licensee was unaware of any vendor's calculation to estimate the operational stress state of the steam , generator tubes. Therefore, to support this view, a licensee representative performed a rough estimation that showed that the tubes would be in a state of tension during shutdown conditions. The
inspectors concluded that the licensee's view on this issue appeared to be more realistic than that theorized in the examination report, and that the report's hypothesis on why perforated steam generator tubes ! passed the helium leak test appeared to be unrealistic. The inspectors ! questioned the licensee whether it had considered placing operational - restrictions on the steam generators to reduce the potential for ! increasing service tensile stresses in tubes containing incipient l defects. A licensee representative indicated there were no ~ considerations for such restrictions.
As a separate possibility, the inspectors considered that a perforater
steam generator tube may have passed the helium leak test because the
presence of the sludge pile served as an unintended reactor coolant i system boundary.
" I
i - - .-- - . J
, .. .' , . --
. . -19-l , Circumferential cracks were the only cracks that extended completely .! + throughwall. The responsible stresses for the IGSCC were most probably the residual stresses created by the initial tube expansion process-L combined with service stresses (primarily attributable to thermal { expansion / contraction) associated with plant operation.
The responsible stresses for the IGSCC in tubes at the eggcrate supports !
were probably the hoop tensile stresses generated by the pressure ! differential at normal plant operation, in conjunction with restraint ! r imposed by the eggcrate supports.
Pitting did not appear to be an operative failure mechanism suggesting
that copper transport to the steam generators was probably not a i contributor to the observed tube degradation.
5.2 Refueling Outage 2R9 l 5.2.1 Sample Selection ! i ' Segments of two tubes were removed from Steam Generator A during Refueling.
Outage 2R9.
Both of these tubes contained defect indications that were ! located at the top of the tubesheet.
Significant damage occurred in the tube
extraction process which complicated the interpretation of the examination l results. The removed portion of one tube (R64L48) contained all of the ! circumferential defect indication.
The other tube (R79L83) sample, however, - , contained only the lower half of the circumferential defect indication (i.e., l the tube segment plastically deformed and fractured at the defect location j during the removal process).
~ The MRPC measurements on Tube R64L48 showed an average throughwall crack depth of about 60 percent over 360 ~ degrees, and about 90 percent throughwall over i 240 degrees.
It is notable that the previous eddy current examination in Outage 2F92 did not find a defect indication in this tube. The vendor's - report stated that Tube R79L83 exhibited an indication of a defect during the . Outage 2F92 inspection.
Examination by the NRC consultant of the Outage 2F92
data for Tube R79L83 concluded, however, that no detectable defect was i present. MRPC measurements during Refueling Outage 2R9 showed that Tube R79L83 had two circumferential cracks over about 50 and 130 degrees with
an average throughwall depth of about 90 percent.
The results of the examinations were documented by the contractor, ABB-CE, in a draft report (marked proprietary) which was entitled, " Examination of Steam ! Generator Tubes from Arkansas Nuclear One Unit 2 During Refueling Outage 2R9," dated October 1992.
! 5.2.2 Examination Results i i Significant findings from the examination process are summarized below: l l ! ! ~' . _ -.
_ _ __ _ _ __ _ , ~ ' , .. . . I i-20-i i , i Radiography identified circumferential and a few axial cracks at '
locations above the tubesheet.
i An in-situ pressure test of TtJe R64L48 determined that the tube met j
Regulatory Guide 1.121 criteria (i.e., the tube was able to sustain a
pressure that exceeded three times the plant operating pressure ~ differential).
t Fractography revealed that defects located at locations just above the
tubesheet were circumferential intergranular cracks which initiated from . ! the tube outer surface.
Measurements indicated that the defect located just above the tubesheet or, Tube R64L48 was 65 percent throughwall over , 360 degrees and 100 percent throughwall over 50 degrees.
Metallographic examination of the tubes confirmed that IGSCC had I
initiated on the outer surface of the tubes. The report stated that a . slight degree of IGA was associated with the stress corrosion cracks.
- In some areas, there was extensive axial cracks in the vicinity of the
, circumferential cracks. The morphology of the tracking was cellular in
nature, with non-corroded regions surrounded by interconnecting axial , and circumferential cracks. This cellular crack pattern was previously observed in a degraded steam generator tube that had been removed from a plant which had experienced a caustic environment (alkaline crevice chemistry).
The microstructures of the two tube segments were found to be distinctly j
different.
In particular, the two tubes differed in grain size and carbide distribution. Tube R64L48 had a fine grain size and carbide particles in the grains; whereas, Tube R79L83 had a moderate grain size , and grain boundary carbides. This finding suggested that the final anneal on lube RR64L48 was performed at a significantly lower temperature than that specified.
Following review of the examination reports, the inspectors questioned i licensee personnel on what impact the degree of steam generator tube ' degradation found in ANO-2 in 1992 would have had on a coincident main steam line break (MSLB) accident assessment. Specifically, it appeared to the inspectors that an increase in primary-to-secondary leakage would occur during the MSLB accident due to the existing 0.25 gpm leak increasing and additional
tubes with major defects commenting to leak as a result of exposure to the
differential pressure shock across the steam generator tube walls. The inspectors specifically questioned licensee personnel on the impact on the ! 10 CFR 100 dose calculations, because for the MSLB the Updated Final Safety Analysis Report description did not readily lend itself to estimating the
increased dose at the exclusion area boundary when the source term was
changed.
i
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i i The licensee had not previously addressed this question.
However, the ! licensee responded by developing a position, based upon the projected [ magnitude of a pressure shock in conjunction with existing accident dose i calculations, which showed that the design-basis accident (i.e., loss-of - , coolant accident) should remain the bounding accident.. The inspectors noted that this issue was being treated by NRC as a generic issue (Issue 163,_ " Multiple Steam Generator Tube Leakage"). l 5.3 Conclusions f The licensee's Outage 2F92 program for laboratory examination of steam i . generator tube degradation was considered outstanding.
The selection of tubes to pull from the steam generators was appropriate. The various tests that were performed on the specimens to determine the nature and ! extent of the degradation were extensive and sophisticated, utilizing ! state-of-the-art technology.
The examinations performed on the more , limited number of specimens removed in Refueling Outage 2R9 were equally ' extensive in scope.
Metallography confirmed that IGSCC was the operative failure mechanism
for circumferential tube defects located just above the tubesheet and - axial tube defects in the eggcrate support regions. All cracking initiated on the outer surface of the tubes.
Of the contaminants found on the surface of the specimen tubes, only
, sul#ur and lead were consistently present on crack surfaces.
j Metallographic examination of the tube specimens confirmed that: f
(1) MRPC testing was the most accurate and reliable method for detection l of circumferential cracking, and provided good detection capability for '! 50-60 percent maximum throughwall longitudinal cracks; (2) bobbin coil , testing did not detect some circumferential_ cracks, but provided ! , reasonably accurate detection of 50-60 percent maximum throughwall
longitudinal cracks; and (3) ultrasonic examination provided reasonably , accurate detection of circumferential cracks with the exception of some t false positives, and did not identify 50-60 percent maximum throughwall . l longitudinal cracks.
An in-situ pressure test of a tube containing a circumferential defect
indication (estimated by MRPC to have an average depth of 90 percent throughwall over 240 degrees, with an average crack depth of 60 percent . ! over 360 degrees) met Regulatory Guide 1.121 minimum criteria of three t times the plant operating pressure differential.
Burst tests of two i tube specimens containing axial flaws also failed at pressures which
exceeded this criterion.
> ! One of the seven pulled tube specimens exhibited a microstructure which !
indicated the tube had been annealed at a temperature below that i specified for a high-temperature mill anneal. The crack morphology in l l ! ! ! ! ,
' . ! - - . ! ! -22-s-t , this tube was cellular in nature and differed from the other specimens.
. In addition, grain size and carbide distribution were different in this
tube.
! 6 REVIEW OF SECONDARY WATER CHEMISTRY CONTROLS AND HISTORY ' Many impurities that enter the secondary side of steam generators can contribute to corrosion of steam generator tubes and support plates. While i the concentration of impurities needed to cause corrosion problems is normally
much higher than that present in steam generator bulk water, concentration of - l impurities to aggressive levels is possible in occluded areas where dryout - occurs. Typical areas where dryout and resulting concentration of impurities
can occur are tubesheet crevices, tube support plate crevices, and sludge
piles.
Impurities known to contribute to tube denting (i.e., squeezing of l tubes at tube supports or tubesheets as a result of the pressure of corrosion
products) are chlorides, sulfates, and copper and its oxides.
Pitting of steam generator tubes has been attributed to the presence of copper and ! concentrated chlorides.
Concentrated sulfates and sodium hydroxides are ! believed to be major causes of IGSCC and IGA in steam generator tubes.
Iron oxide tube deposits and sludge promote local boiling and concentration of
impurities leading to damage mechanisms such as IGSCC and IGA.
l 6.1 Program Evolution . The inspectors reviewed the licensee's secondary chemistry control program for ANO-2.
The ANO-2 secondary water chemistry control program during the period ' i from startup in March 1980 to March 1983 was based on CE chemistry manual water chemistry specifications. These secondary water chemistry specifications included only the normal operating chemistry specifications for
pH, hydrazine, and ammonia control in the steam generator blowdown and auxiliary feedwater. The sampling and analysis frequencies were infrequent (twice per week), and the required water chemistry control operating specifications did not require strict chemistry control.
ANO-2 has been i operated with an all volatile secondary water treatment since startup.
' i In March 1983 the licensee adopted and implemented the EPRI secondary water- ! chemistry guidelines.
These guidelines included requirements for chloride, i sulfate, and oxygen. The inspectors reviewed Administrative Procedure l 1000.043, " Steam Generator Water Chemistry Monitoring Unit II," Revisions 0 - through 13, which were first written and approved in March 1983 Jto establish a l secondary water chemistry monitoring program as required by Amendment 30 to l the facility operating license and to implement the EPRI secondary water ' chemistry control guidelines. Over the past 10 years the secondary water chemistry control program has progressively improved with few significant , changes since its implementation and has experienced very few "long-term" (several days) chemistry deviations from required specifications.
i ! !
? i
-
, -- , j . . -23-f i 6.2 Secondary Side Operating History , The inspectors reviewed the history of the ANO-2 steam generators with regard
to operating condition; significant chemistry, operational, and inspection events; and compliance with the EPRI secondary water chemistry -guidelines.
As part of this review, the inspectnrs obtained historical information from , the licensee for each steam generator pertaining to sludge removal and copper (Cu)/ iron (Fe) ratio values, and average annual sulfate concentration in the steam generator blowdown and feedwater. The information obtained is listed below in Table 2.
Table 2 Year / Outage Steam Generator A Steam Generator B
. Average Sludge Average Sludge Sulfate Sulfate (ppb) Cu/Fe Weight (ppb) Cu/Fe Weight ! Ratio Removed Ratio removed L (1bs) (1bs) < m Pre-Commercial - 2.6 - - 1.1 - I Operation 1981 (2RI) - 2.2 - - 0.9 - ! 1982 (2R2) - - - - - - 1983 (2R3) 97.2 0.8 575 86.6 0.5 200 1984 10.8 - - 6.8 - - [ 1985 (2R4) 8.0 0.6 800 6.8 0.4 400 1986 (2R5) 6.6 0.3 385 6.2 0.2 170 1987 2.2 - - 2.4 - - 1988 (2R6) 2.1 0.2 199 2.1 0.2
1989 (2R7) 3.1 0.3 36'9 3.3 0.3 107 1990 2.0 -- - 2.1 - - 1991 (2R8) 2.3 0.08 125 2.5 0.14
1992 (2R9)
426
163 _ TOTAL 2879 1207
- Information not availaole as of the inspection
'
- Year incomplete as of the inspection
.
- . -
. . -24- !
, Prior to the adoption of the EPRI secondary water chemistry guidelines in i ' March 1983, sulfate concentration in the steam generator blowdown and feedwater was not monitored or controlled. During this period, the major
emphasis for the startup and blowdown demineralizer regeneration was placed on i high sodium removal. As a result, excess sulfuric acid was typically used
during demineralizer regeneration to assure low sodium values.
This practice probably resulted in high sulfate concentrations in the steam generators.
The
lack of monitoring of sulfate concentrations prior to March 1983 precluded i specific verification of actual values present, but the recorded average for
1983 of 97.2. ppb and 86.6 ppb sulfate, respectively, for Steam Generators A i and B were confirmatory of high sulfate concentrations being present.
The adoption of the EPRI secondary water chemistry guidelines has resulted in a + significant reduction in sulfate concentration, with the average annual values > reaching a low plateau condition starting in 1987. The chemical parameter ' trends also showed a reduction in cation conductivity and chloride and sodium concentrations in the respective steam generator blowdowns, and in copper and . Oxygen concentrations in the feedwater system.
, .' The sludge Cu/Fe ratios listed in Table 2 indicate that high copper transport into the steam generators occurred during initial plant operation, which was l attributable to the interaction of high oxygen and ammonia concentrations ' I present in the feedwater system with the 90/10 copper-nickel alloy tubes in the feedwater heaters and the main condenser. The Cu/Fe ratio in this period was significantly higher for Steam Generator A.
It was additionally ascertained from review of licensee data that a large amount of cupric hydraxide was discovered in Steam Generator A during a 1981 inspection of the steam generators. The improvements in water chemistry controls have resulted ., in progressive reduction in copper transport, as draoted by the sigr.ificantly reduced sludge Cu/Fe ratios that have been present since 1986.
Additional i information on sludge chemistry is contained in Section 6.7.
l Other information noted by the inspectors which appeared significant with , respect to potential impact on the condition of the AND-2 steam generators is , listed below:
. During the Refueling Outage 2R2 steam generator inspection in 1982,
cracking was detected at two locations in the Steam Generator A, No.11 . hot leg drilled tube support plate. Tube denting was also discovered at l the drilled support plates in Steam Generator A.
Small amounts of resin
were found in Steam Generator B on the tops of some of the separator i cans. The presence of resin was probably the result of a lateral r breakthrough in one of the startup and blowdown demineralizers, which allowed resin to be carried over into Steam Generator B.
This resin carryover could have been a source of a large concentration of sulfates ! and chlorides being transported into Steam Generator B.
As a result of tube denting being discovered in Steam Generator A, boric
acid treatment was initiated in August 1983 in an attempt to arrest or inhibit the steam generator tube denting problem, and in March 1983 the , S
t ." ! . ' . . -25- , t ! ' ZPRI water chemistry guidelines were incorporated into a plant administrative procedure and implemented. The water chemistry parameter , specifications for the feedwater system and steam generators were much ? better defined and chemistry control limits and corrective actions were i established. These actions have resulted in essentially very little ! > increase in the steam generator tube denting problem since the third ! fuel cycle.
, , In 1983, better makeup water treatment and conditioning were implemented !
' with the replacement of old water treatment technology and the ' installation of new tri-bed startup and blowdown demineralizers. The tri-bed demineralizer physically separated the anion resin phase from < the cation resin phase in the demineralizer with a 6-inch bed of neutral i resin. This physical separation minimized the chance of sulfate - ' contamination of the anion resin as a result of cation regeneration with L sulfuric acid.
During Refueling Outage 2R3 in 1983, all of the copper-nickel alloy
feedwater heater tube bundles were replaced with Type 304 stainless
steel tubes.
. ! The steam generator inspection performed during Refueling Outage 2R3
, indicated no significant increase in the accumulation of deposits in the } crevices between the tubes and the batwing supports in the steam l generators.
Some denting was still evident at the No. 11 drilled l support plate in Steam Generator A, and both steam generators showed ! slight continued growth in the No. 11 hot leg tube support plate.
! Another crack was found between two tube holes in the No.11 hot leg
tube support plate in Steam Generator A.
In general, Steam Generator B l was cleaner than Steam Generator A, and there appeared to be a continual !' improvement in the condition of the steam generators over the last three inspections.
i ! ! During the period 1983-1985, numerous condenser tube leaks occurred due i
to under-deposit corrosion of the condenser tubes as a result of the ! buildup of silt deposits. A majority of the condenser tube leaks were
in Condenser B.
In October 1985, AND-2 operated in " hot standby" for approximately
4 days with makeup water from the condensate storage tank, which was ! saturated with approximately 7 ppm dissolved oxygen, being added at a i rate of 330 gpm. This event introduced a large concentration of oxygen i ' into the condensate system and the steam generators. As a result of this event, ANO-2 installed degassing equipment to remove dissolved j oxygen from the make>p water taken from the condensate storage tank and > also installed floating lids in the condensate storage tanks to reduce
the dissolved oxygen concentration in the water stored in the condensate storage tanks.
! . 1l ,m
. . { > - . i-26-l During the Refueling Outage 2R4 steam generator inspection in 1985, it
was noted that growth of the No.11 hot leg drilled tube support plates continued in both 2 team generators.
Three cracks were found in the - Steam Generator A No.11 hot leg tube support plate and one crack was discovered in the Steam Generator B, No.11, hot leg drilled tube support plate.
. During the Refueling Outage 2R5 inspection in 1986, both steam
generators were observed to be relatively clean and free of deposits, with Steam Generator B continuing to be cleaner than Steam Generator A, particularly in the feedring region. No new cracks were found in the No. 11 hot leg drilled support plates.
i Condenser tube leaks continued to occur from 1985 through 1989 in '
Condenser B.
The steam generator inspections performed during Refueling Outage 2A7 in
- 1989 revealed five cracks in the No,11 hot leg drilled tube support
plate in Steam Generator A.
This was two more than previously
identified.
t 6.3 Quality Assurance of the Secondary Water Chemistry Program The inspectors reviewed the licensee's quality assurance audit records for the ' secondary water chemistry control program during the period 1981 through-1991.
The inspectors reviewed the licensee's audit plans and checklists and the + qualifications of the quality assurance 29ditors performing the audits. The quality assurance audit reports from 1981 through 1991 were reviewed for scope and depth to ensure thoroughness of chemistry program evaluation and timely ' followup of identified deficiencies.
The inspectors determined that the audit plans and checklists used to conduct the audits were comprehensive and appropriate for evaluation of the implementation of the water chemistry program. The quality assurance audits of the chemistry program were performed in accordance with station quality
assurance procedures by qualified auditors who were knowledgeable of chemistry requirements at nuclear power facilities. The inspectors verified that the audit reports had been reviewed by licensee's management and that identified deficiencies had been closed in a timely manner. The inspectors' review of- , the audit findings did not indicate any significant adverse findings which r would bring into question the quality of the water chemistry program.
l . l 6.4 Chemistry Laboratory Instrumentation and In-Line Process Chemistry Analyses The inspectors reviewed the inventory of secondary chemistry laboratory - analytical instrumentation and in-line process chemistry analyzers installed in the various ANO-2 water systems. The secondary water chemistry laboratory was equipped with stcte-of-the-art analytical instrumentation to perform the , i D r
, . . - . . , .: i-27- , i i required chemical analyses.
Past NRC inspections verified the analytical - capability of the licensee.
The inspectors verified that the licensee had. l adequate in-line process chemistry analyzers installed to monitor chemical parameters since plant startup in 1980. The original in-line chemistry
monitoring-capability was upgraded in 1985 by the additions of in-line sodium.
! analyze s in the two feedwater trains and in each of the four main' condenser l sections, the addition of an oxygen analyzer in the degassification building
! in 1987, the installation of pH monitors on both of the condensate discharge trains in 1991, and the installation of an in-line ion chromatograph in 1992 ! to provide real-time monitoring of anion and cation concentrations in the-j various secondary water systems simultaneously. During the period 1989 ' through 1990, the original conductivity, pH, hydrazine, and ox pcn n-line-j analyzers were replaced with state-of-the-art instrumentation.
An af these ( analyzer upgrades and additions were efforts made by the license to enhance l their ability to monitor secondary water chemistry conditions which could i affect the steam generators.
.r 6.5 Off-Normal Secondary themistry History The inspectors reviewed documentation of out-of-specification concentrations' t of chemistry parameters associated with the secondary water systems for the period 1983 through 1991. Only one significant.out-of-specification chemistry
condition was noted which could have contributed to the degrading-of the steam
generators.
This out-of-specification oxygen condition happened in 1985 when
the plant was operated in the " hot standby" mode for approximately 4 days with ' makeup water from the condensate storage tank, which was saturated with ! approximately 7 ppm dissolved oxygen, being added at a rate of 330 gpm.
It ~ , should also be noted that in the first 3 years of commercial operation, prior - to the implementation of the EPRI secondary water chemistry guidelines, many , of the secondary water chemistry parameters were-not analyzed and controlled i and may have been at concentrations now considered to be.off-normal r operational concentrations.
With the implementation of.the EPRI secondary
water chemistry guidelines in 1983, the secondary water chemistry. parameters
established limiting conditions o'n the operation of the unit'. Operations ! response to correct out-of-specification chemistry conditions within a i specified period in accordance with administrative procedure requirements was noted 'to have greatly improved over the AND-2 operational history.
t 6.6 Startup and Blowdown Demineralizer Operations The startup and blowdown demineralizer system has been in operation since i initial unit startup. The startup and blowdown demineralizer system treats. i both the full blowdown flow from the steam generators and 10 percent of the ! flow from the A condensate. header. This polished condensate and steam- .; generator blowdown water is then returned to the Hotwell B of the main i condenser. The startup and blowdown demineralizer system consists of;three i demineralizer tanks. One of the demineralizers is in operation at all-times while a second demineralizer is in a standby condition. The third- .j demineralizer tank is used as a storage tank to regenerate spent resin when , excessin sulfate slippage is determir.ed.
j i
l' ..
. -. - - . ~. -. . . .- .~
, .; - . . . i ~ l-28- . The inspectors reviewed the licensee's procedure for the operation of the i startup and blowdown demineralizers. The procedure-provided detailed ! instructions for the operation of the in-service demi _neralizer and the ! addition, removal, transfer, and regeneration of the demineralizer anion and i cation resins. The procedure also provided chemistry guidelines for the demineralizer regeneration and chemistry specifications required prior'to } placing a demineralizer in service. A review was conducted of the records.for-i the replacement and regeneration of resin for ANO-2.
Based on the inspectors' i review, it was determined that records pertaining to the replacement and
j regeneration of the startup and blowdown demineralizer resins were available only for the period July 1989 through October 1992.
'! One significant event involving the operation of the startup and blowdown i demineralizers resulted in a resin carryover into Steam Generator B which was- { detected when small amounts of resin were discovered in Steam Generator B.
j during the 1982 Refueling Outage 2R2 steam generator inspection. This event- { was caused by a lateral screen in one of the demineralizers turning-sideways ! and allowing the resin to carry over into the steam generator. This resin- ! carryover could have resulted in sulfates and chlorides being transported into i Steam Generator B.
' 6.7 Steam Generator Hot Leq Sludge Analysis The inspectors reviewed the ANO-2 steam generators' removed sludge analysis i data for the period 1981 (2RI) through 1991 (2R8). The sludge analysis data-from the 1992 (2R9) refueling outage was not available at the time of the i review.
l
Copper was a major contributor to the total amount of sludge in the steam '[ , generators, with the Steam Generator A content being typically higher than
! ' Steam Generator B.
This was indicative of a higher level of contaminates in t the A main condenser which feeds Steam Generator A.
Over the ANO-2 operating j
history, the copper content in the removed sludge has progressively decreased, r thus reducing the Cu/Fe ratio (See Table 2 in Section 6.2).
As discussed in i Section 5, however, examination of the pulled tube specimens did not indicate i that pitting was an operative failure mechanism in the ANO-2 steam generators.
! Iron was also a major contributor to the total amount of sludge in the steam i generators.
As a result of _the laboratory finding that sulfur and lead were consistently [ present on the crack surfaces in the pulled tubes (as noted in Section 5), a: review was made of the sulfur and lead content in the sludge.
It was ascertained that sulfur and lead analyses were not routinely performed on the removed sludge prior to Refueling Outage 2R7 in 1989, thus only limited data
were available..These data indicated that the highest sulfur and lead ! contents were 0.07 percent by weight, with the exception of Steam Generator A.
~j during Refueling Outage 2R7 when the sludge lead content was reported to be j 0.126 percent by weight.
i ! ! ! - . - -, . _ . .. _,-
' . - , . , -29-
Sulfur (as the sulfate ion) can typically enter condensate as a result of , condenser tube leaks and demineralizer operational problems. The licensee has made significant progress since 1983 in reducing the sulfate concentration in the feedwater,' as indicated by the average annual values shown in Table.2 in Section 6.2.
A recent EPRI study (EPRI NP-7367-M) published in June 1991 ' indicated that lead could cause IGSCC and IGA in Inconel 600 tubing. The available data was considered too limited by the inspectors to allow a
determination of whether lead was a contributor to IGSCC in the ANO-2 tubing.
6.8 ANO-2 Main Condenser Design and Operation The ANO-2 main condenser is a single pass, 2-shell (A and B), dual-pressure type with divided waterboxes.
Each shell is located below its respective low pressure turbine. The condenser tubes in each shell are constructed of 90/10 copper-nickel alloy and are oriented transverse to the turbine generator e longitudinal axis. The hotwell storaga is located under both shells. There ' is one condensate outlet per shell.
Each condenser shell has two tube bundles (north and south), each of which is connected to a separate circulating water , line through a waterbox. The waterboxes of the two shells are connected in series so that the circulating water passes through the low pressure shell and then the high pressure shell. A number of design modifications were added to the original design of the main condenser and condensate and feedwater systems, over the operating life of the unit, to reduce the time required to
locate, isolate, and repair a condenser tube leak.
These modifications included the following: A 4-point condenser hotwell quadrant sampling system was installed for
the purpose of locating tube leaks; , ' A pumping system was installed to provide for quicker draining of the
condenser circulating waterboxes; , Special staging rungs and climbing rungs were installed inside the
circulating waterboxes to reduce the time required to plug tube leaks; ' ' A sample cooler was installed to improve the quality of the oxygen
' analysis; A sodium analyzer was installed in the secondary water sample system
which can sample and analyze either feedwater train. Multiple sample i points were provided to allow detection of leakage between the circulating water and the secondary coolant side of the condenser and - detection of contaminants from the heater drain pumps; and Permanent connections were installed to " slug feed" the condenser with I
hydrazine ror oxygen control.
j F $ j ., - .-
, . . . - _ . . -.. .-. .. - .. .. - - . ..' ]; . .
. . ! .: + -30-i ! ! The inspectorr reviewed the pH control requirements for the secondary water systems and circulating water system and found them to be in accordance with-l EPRI guidelines.
The pH history of the secondary water and the circulating i water was reviewed and found to be maintained within the specified normal- ' ' operating limits. The inspectors reviewed the operating history of the makeup . water purification system and noted that changes were made in-1985, 1987, and j 1988 to the makeup water purification system to improve the quality-of the ! secondary side makeup water as advances in water purification technology - .j became available to the industry.
i I The inspectors reviewed the chemistry control-of the circulating water.
j Various chemical treatments had been added to the circulating water for } corrosion control. The pH had been strictly maintained to optimize resistance j to corrosion and scaling, and an inorganic phosphate treatment was used to
also help prevent scaling and inhibit. steel (iron) corrosion.
In addition, a
dispersant for silt and metal oxides and en inhibitor for copper corrosion was ! added to the circulating water.
"! The inspectors reviewed the design features and operational characteristics of-the main condenser with specific attention as to how the condenser design-l might influence or create differences in the secondary water chemistry between ! . the two steam generators. The secondary side makeup water from the condensate ! J storage tank feeds into the Condenser B hotwell and mixes with the condensate.
!
The startup and blowdown demineralizer system draws approximately 10 percent l of the condensate flow from the Condensate A header, mixes and processes the
' - condensate with the steam generator blowdown, and returns the processed water-l to the Condenser B hotwell. Therefore, the water in_the Condenser B hotwell,_.
-; which provides feedwater to Steam Generator B, should be of. higher purity.and .j have less contaminates that the condensate in Condenser A hotwell, which j a provides feedwater to Steam Generator A.
Cation conductivity of the Feedwater i Train B was typically lower than-in the Feedwater Train A, confirming that the i water in the Feedwater Train B is of higher purity.
l . L The inspectors reviewed the main condenser tube history.for tube leaks and the l plugging of condenser tubes because of leaks and/or eddy current test results.
j It was noted that Condenser B had a significantly higher number of tubes ! plugged than Condenser A.
A total of 1930 tubes (942 tubes in B' north ! [= 6.5%] and 988 tubes in B south [= 6.8%]) had been plugged in Condenser D f , while only 690 tubes (235 tubes:in A north [= 1.6%]' and 455 tubes in A south j [= 3.1%]) were plugged in Condenser A.since_the main condenser was-installed.
[ , Of the 1930 condenser. tubes plugged in Condenser B, only 280-tubes were
plugged-because of leak-indication.
Only 133 out of.the 690 plugged tubes. in Condenser A were plugged-because of leak indication.
following Refueling
Outage 2R6 in 1988, there was a significant reduction in condenser tube leaks, and no tube-leaks were detected in Condenser A since May 1985.
During Refueling Outage 2R7 in 1989, 30,000 condenser tubes were eddy current tested .j with the results requiring a total of 9 tubes to be' plugged. During Refueling i i ! ' _ .. - . -. - - _ . ... -
. . .
. , !
-31-l , ! i Outage 2R8 in 1991, 40,000 condenser tubes including 100 percent of Condenser [ B were eddy current tested, with the results requiring 86 tubes to be plugged > in Condenser B and 14 tubes to be plugged in Condenser A.
During Refueling Outage 2R9 in 1992, 20,000 condenser tubes were eddy current tested, which ! resulted in the plugging of only 8 tubes in Condenser B and 3 tubes in , Condenser A.
l ' 6.9 Conclusions i For the first 3 years of commercial operation, ANO-2 was operated with
, no analysis requirements or concentration specifications for chloride, ! sulfate, and oxygen in the feedwater system and steam generators.
- During this period, high copper transport to the steam generators
' occurred and tube denting was observed at the drilled support plates in i Steam Generator A.
Since the adoption of the EPRI secondary water chemistry guidelines in
March 1983, progressive reductions have occurred in sulfate, chloride,
and sodium concentrations and cation conductivity in the respective
steam generator blowdowns, and in copper and oxygen concentrations in the feedwater system.
Little increase in tube denting problems was observed since the initiation of boric acid treatment in August 1983.
In-line chemistry monitoring capability was progressively upgraded since
1985 by replacement of outdated analyzers with state-of-the-art ! ' instruments, installing additional sodium and pH analyzers at critical control locations, and the addition of an in-line ion chromatograph to
provide real-time monitoring of anion and cation concentrations.
Only one significant out-of-specification chemistry condition was ncted
since adoption of the EPRI secondary water chemistry guidelines.
This ! condition (i.e., out-of-specification oxygen concentration) occurred in 1985 when the plant was in a " hot standby" mode for about 4 days, with makeup water containing approximately 7 ppm oxygen being added at 330 t gpm, t ! The licensee commenced in 1983 to improve its makeup water treatment
technology and secondary water conditioning. As part of this effort, new startup and blowdown demineralizer and degassing equipment (to e ! remove dissolved oxygen from makeup water) were installed.
Evidence of a small amount of resin carryover into Steam Generator B was f
observed during Refueling Outage 2R2, which could have resulted in the transport of sulfates and chlorides into the steam generator, j . The 1.icensee made several design modifications to the main condenser and
condensate and feedwater systems to help reduce the time required to
locaty, isolate, and repair condenser tube leaks.
The pH control
requirements for the secondary water systems and circulating water
. !
- -
.
- - -
.. -32-system were based on EPRI guidelines and were strictly enforced.
Operations response to correct out-of-specification chemistry conditions within a procedurally specified period was greatly improved over the unit's operational history.
Required plugging of condenser tubes was significantly higher for.
- Condenser B.
The licensee utilized a variety of chemical treatments to minimize corrosion and had also performed extensive eddy current examinations of condenser tubes to detect degradation prior to the occurrence of leaks.
Subsequent to Refueling Outage 2R6 in 1988, there was a significant reduction in Condenser 8 tube leaks, with no tube leaks detected in the Condenser A since 198.F
. ! . . . ATTACHMENT r ' PERSONS CONTACTED ' 1.1 Licensee Personnel D. Baker, Project Manager, Steam Generators
'
- S. Boncheff, Licensing Specialist A. Buford, Senior Lead Engineer, Design
' W. Eaton, Director, Design Engineering
- R. Edington, Unit 2 Plant Manager
- C. Eubanks, Supervisor, Engineering Programs
- J.
Fisicaro, Director, Licensing . <
- D. Harrison, Senior Lead Engineer, Engineering Programs
- R. Jones, Nuclear Chemistry Supervisor
,
- R. King, Supervisor, Licensing D. Lomax, Manager, Engineering Programs R. McCormick, Nuclear Quality Specialist, Chemistry / Radiochemistry
' W. McKelvy, Chemistry Superintendent J. McKenzie, Nondestructive Examination ,
- J. Taylor-Brown, Assistant Director, Quality
D. Wagner, Quality Assurance Supervisor M. Whitt, System Engineer, Unit 2 l 1.2 Contractor Personnel R. Maurer, Manager, NDE Technology, ABB-CE F 1.3 NRC Personnel .
L. Smith, Senior Resident Inspector i
- S. Campbell, Resident Inspector
' In addition to the personnel listed above, the inspectors contacted other licensee employees during this inspection period.
- Denotes-personnel attending the exit meeting.
2 EXIT MEETING An exit meeting was conducted on November 20, 1992.
During this meeting, the inspectors reviewed the scope and findings of the report.
The licensee was r informed that, as a result of the amount of reviewed material that had been ! ? marked by its contractor as proprietary, an opportunity would be provided to the licensee for review of the report for proprietary information prior to . distribution.
! ! ! = t I }}