ML20246J357
| ML20246J357 | |
| Person / Time | |
|---|---|
| Site: | McGuire  |
| Issue date: | 05/31/1989 |
| From: | DUKE POWER CO. |
| To: | |
| References | |
| NUDOCS 8905170056 | |
| Download: ML20246J357 (121) | |
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McGuire 1 Nuclear Power Station Evaluation of Degradation of Tube R18C25 and Justification for Return to Power May 1989 Duke Power Company 0 0 ' kb D' 4A neu888a p
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lO MCGUIRE 1 NUCLEAR POWER STATION EVALUATION OF DEGRADATION OF TUBE R18C25 AND JUSTIFICATION FOR RETURN TO POWER I
APRIL 1989 O
1 DUKE POWER COMPANY O
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9222M.1E-050489
- McGuire 1 Nuclear Power Station I Evaluation of Degradation of Tube R18C25 and Justification for Return to Power p.
d Abstract On March 7, 1989, a steam generator tube rupture event occurred at McGuire g Nuclear. Station Unit 1. The cause of the tube rupture'has been determined to V be intergranular SCC which initiated on the outside diameter of the tube. The degradation consists of a network of small axial and circumferential cracks which are linked together. The network of cracks is associated with and confined to a linear surface mark, which may have occurred as the tube passed through a baffle plate during manufacture. The subject tube had not been inspected since the baseline prior to the start of operation. The degradation, if inspected, would have been discovered. Inspection of the other tubes in the four steam generators in the plant revealed no indication of detectable OD SCC. It appears that some local surface contaminant was present within the stressed region of the surface mark at the time of initial.
service. This provided the impetus for crack initiation. Crack propagation then occurred at a slower rate over a longer period of time. Laboratory and field data suggest that this rate is approximately 0.7 mil / month.
The results of this evaluation indicate that the rupture of R18C25 is a unique event and not representative of the condition of tubes in service in the ;
McGuire Unit 1 steam generators. As a result of this determination, the results of the assessments completed and the remedial actions undertaken by Duke Power prior to restart, the McGuire Unit 1 steam generators can be operated for the remainder of the fuel cycle without resulting in an unreviewed safety question.
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TABLE OF CONTENTS O
Section 1.0 Introduction 2.0 Summary and Conclusions 2.1 Conditions 2.2 Examination 2.3 Interpretation (O 2.4 Conclusions V
3.0 Plant History 3.1 Description of Steam Generators 4.0 Description of March 1989 Tube Rupture Event 4.1 Conditions Prior to Tube Rupture 4.2 Indication and Extent of Tube Rupture 4.3 Tube Rupture Leak Rate Evaluation 5.0 In-Plant Diagnostics 5.1 Bobbin Coil Examination Results 5.2 RPC Examination 5.3 Tube Manufacturing / Installation Artifacts
('s) v 5.4 5.5 Summary of Eddy Current Inspections Ultrasonic Examinations 5.6 Video Examinations 6.0 Tubes Removed for Examinations 6.1 R18C25 Examination 6.2 R13C34 Examination 6.3 R19C24 Examination 7.0 Review of Operating Chemistry Experience 7.1 Operating Chemistry Data 7.2 Secondary Chemistry Excursions 7.3 Steam Generator Wet Layup 7.4 Steam Generator Hideout Return Data f 7.5 Conclusions 8.0 Thermal and Hydraulic Environment 8.1 McGuire Unit 1 Steam Generator Operating Conditions 8.2 Athos Results 9.0 Mechanism Leading to Rupture of R18C25 Q(3 9.1 OD SCC in PWR Steam Generator 9.2 General Aspects of Ruptured Tube R18025 9.3 Stress Corrosion Considerations 9.4 NDE Considerations m
9222M.1 E-Os0489
TABLE OF CONTENTS (Continued)
Section O 10.0 Plugs Installed in McGuire Unit 1 Steam Generators 10.1 10.2 Westinghouse Plugs Babcock and Wilcox Plugs 11.0 Measures Implemented in Response to SGTR .
11.1 Eddy Current Evaluation '
O 12.0 11.2 Future Activities Justification for Return 'to Power 12.1 Frequency of Occurrence of Degradation 12.2 Degradation Growth Rate 12.3 Eddy Current Inspection 12.4 Operation Interval Determination Tube 12.5 l.eak Before Break Considerations 12.6 Conclusions l
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3-1 General Arrangement of Model D2 Steam Generator 3-2 Model D2 Steam Generator Preheater Assembly
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4-1 Leak Rate as a Function of Crack Size 5-1 McGuire SG B Preheater Wear Indications o 5-2 McGuire SG B AVB Wear Indications b 5-3 McGuire SG B Hot Leg PWSCC Indications 5-4 McGuire SG B Hot Leg Free Span Indications 5-5 McGuire SG B Cold Leg Free Span Indications 5-6 McGuire SG A Preheater Wear Indications 5-7 McGuire SG A AVB Wear Indications 5-8 McGuire SG A Hot Leg PWSCC Indications 5-9 McGuire SG A Hot Leg Free Span Indications 5-10 McGuire SG A Cold Leg Free Span Indications g 5-11 McGuire SG C Preheater Wear Indications 5-12 McGuire SG C AVB Wear Indications 5-13 McGuire SG C Hot Leg PWSCC Indications 5-14 McGuire SG C Cold Leg PWSCC Indications 5-15 McGuire SG C Hot Leg Free Span Indications 5-16 McGuire SG C Cold Leg Free Span Indications 5-17 McGuire SG D Preheater Wear Indications 5-18 McGuire SG D AVB Wear Indications 5-19 McGuire SG D Hot Leg PWSCC Indications 5-20 McGuire SG D Hot Leg Free Span Indications 5-21 McGuire SG P Cold Leg Free Span Indications 5-22 Bobbin Coil Distorted Roll Expansion Signal 5-23 Rotating Pancake Coil Data at Roll Transition 5-24 Preheater Wear Scar Indication 5-25 Rotating Pancake Coil Data for Preheater Wear Scar 5-26 RPC Data for an AVB Wear Indication 5-27 RPC Data for Foreign Object at the Tubesheet Top 5-28 Manufacturing Buff Mark Indications 9222M.1E-050389 $$j
i List of Figures (Cont.)
5-29 RPC Data for Manufacturing Buff Mark 5-30 Linear Surface Groove Indication-5-31 RPC Data for Linear Surface Groove t 5-32 . Permeability Variation' Indication c 5-33 RPC Data for Permeability Variation 6-1 Sectioning Diagram for Tube R18C25 Section 3
'6-2 Sectioning Diagram for Tube R18C25 Section 2 (Control Material) 6-3 As-Received Tube R13C34 Sections 9-1 McGuire. Tube R18C25 Section 3 9-2 Bobbin Coil Eddy Current Results for R18C25 9-3 RPC Eddy Current Results for R18C25 i
10-1 B&W Roll Plug O
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List of Tables f
5-1 . March 1989 Bobbiri Coil Inspection Results 5-2 McGuire Unit 1 Plugged Tube Summary 5-3 Comparison of ECT/UT.Results 7-l' McGuire Unit 1 Secondary Chemistry Data 7-2 McGuire Unit'l Secondary Chemistry Data Summary by Year (1981-1985) 7-3 McGuire Unit 1 Secondary Chemistry Excursions 10-1 Westinghouse Mechanical Plugs Installed in McGuire Unit 1 Steam-Generators 10-2 Welded Plugs Installed in McGuire Unit 1 Steam Generators O
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9222M:1E-050489 y
tw MCGUIRE 1 NUCLEAR POWER STATION EVALUATION OF DEGRADATION OF TUBE R18C25 AND JUSTIFICATION FOR RETURN TO POWER
1.0 INTRODUCTION
This report contains the evaluation of the tube rupture event at McGuire
-Nuclear Station Unit 1, which occurred on March 7, 1989. The evaluation includes a description of the event, the examination of the subject tube, O. reviews of the operating. chemistry and thermal and hydraulic environment, and discussion of the mechanism of degradation. Two other tubes were also pulled and examined. Results of examinations of these tubes are also reported. The activities associated with the recovery from the outage are described, along with measures implemente'd in response.to the event.
The plug issue was also addressed during the current outage. Some of the existing plugs are of Westinghouse manufacture and some of B&W manufacture.
The locations of plugs, and the heats for those which are potentially susceptible, are given in separate sections for each manufacturer.
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1 2.0
SUMMARY
AND CONCLUSIONS 0
2.1 CONDITIONS The leakage occurring from tube R18C25 of SG B originated from an axial split O' in the tube. The condition prior to the split consisted of a series of intergranular stress corrosion cracks that were oriented along a shallow l groove, or mark, on the OD of the tube wall. The stress corrosion crack was q of OD origin and was essentially contained within the confines of the narrow b mark width. Fractography of the crack face revealed a series of deep short axial and circumferential cracks that had been separated by ligaments. Some of the ligaments had been penetrated by intergranular stress corrosion cracking and others had experienced ductile failure. The ID edge of the crack had been completely penetrated by intergranular corrosion in several locations along the length of the crack. The interconnecting areas between the l through-wall corrosion had parted as a result of ductile failure.
The crack extended from just above the crevice region of the lowest cold-leg baffle plate of the preheater, through the crevice region and terminated approximately two and one-half inches below the baffle plate.
2.2 EXAMINATION Fiberscope and video camera inspection of the tube was accomplished from the primary and secondary sides prior to removal of the tube. Deposits on the primary side were interpreted as arising from back drainage from the secondary side to the primary side as water level changes were made to identify the location of the leaks. Deposits on the secondary side were also observed.
Some of these were of wnitish appearance and most probably associated with flashing of primary water and the resultant deposition of boric acid and its associated compounds. The secondary side region around R18C25 had a relatively low quantity of dark colored deposits whose origin would have preceded the tube rupture. Some crevices were observed to contain significant deposits while others appeared to be relatively free of deposits. As the fiberscope was inserted further into the tube bundle, i.e., past row 18 to higher row numbers, the depo.-it build-up increased. In all cases, honever, 9222M:1E-050389 2-1
i p the deposits were observed to be present in light to moderate quantities. For
( example, no tube bridging was observed, and the underside of the baffle plate generally had a well defined crevice region that was observable and not obscured by a build-up of heavy deposits. No abnormal conditions were noted on the secondsry side of SG B.
hp Tube R18C25 showed evidence in the examination that localized residual stresses exi':ted in the area of the crack. Examination of pulled tube R13C34 g which also contained a groove, or mark, deeper than R18C25, showed no evidence
( of cracking either inside or outside the grooved area.
All active tubes of the four steam generators were eddy current inspected over the full length using the bobbin coil. In addition, selected tubes with bobbin coil indications were reinspected with the rotating probe technology and, in some cases, with ultrasonics. No tube, other than R18C25, gave any indication of detectable OD stress corrosion cracking. Additional testing of tubes using the RPC and focusing on the heat of material used for R18C25 has m also been accomplished. These results are consistent with the observation h that R18C25 was degraded uniquely. No evidence of OD SCC was observed as a result of RPC.
2.3 INTERPRETATION Interpretation of the local T&H conditions under full power operation shows that the water in this region would be saturated. The vapor content, however, I is low and the fluid has a horizontal velocity component of approximately one ft/sec. Low power operation, such as the unit experienced prior to the d pre-heat region modifications, would result in a higher vapor content in this region.
Although it is generally possible to understand OD initiated cracking as a
, result of a local secondary side chemistry transient that produces an aggressive local chemical environment, that conventional understanding cannot be rationally utilized in the case of this incident. For example, secondary side transients require a concentration region, such as a crevice, or a deep sludge pile, in which the dilute aggressive contaminants can be concentrated.
It is also commonly observed that the degraded region is essentially confined 9222 M.1 E-Os0389 p.g
- to the region where concentration has occurred. In addition Alloy 600 i () cracking proceeds more rapidly on the hot-leg side due to higher local i
temperatures. In the case of R18C25, most of the cracking is in the free span of the tube, on the cold-leg side, and no other tubes have been identified as 1 7 experiencing OD SCC, either on the cold-leg or the hot-leg.
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The deformed area of the OD surface of R18C25 contained high, localized !
residual stresses. These stresses appear to be the result of the mechanical m deformation and resultant cold work associated with the groove. The mechanical loading severity of this condition is much less severe than areas such as U-bend tangent points and skip rolls which have exhibited primary side stress corrosion cracking.
2.4 CONCLUSION
S The uniqueness of the degradation of R18C25 has been established by the extensive NDE evaluation that was undertaken following the leakage event.
Although reduced flow, and the potential for small area steam blanketing, tO) might well contribute to deposit accumulation, these factors are generally significant only if aggressive secondary side chemical environments are also present. Such aggressive environments usually act by affecting a large number of tubes rather than only one. In addition, they are commonly experienced first on the hot-leg side of the steam generator since the potential for concentration of dilute contaminants and the higher local temperature are more favorable for initiating corrosion.
The deformed area of the OD surface exhibits shallow, localized coldwork, which is associated with residual stresses that are both axial and circumferential in orientation. However, the residual stress level present is
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not considered to be sufficient for crack initiation in a relatively benign 2 environment such as secondary side AVT chemistry. The presence of both axial and circumferential cracking along such a narrow region is unique and suggests the presence of a local aggressive environment.
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It is therefore reasonable to assume that the presence of some surface contaminant in the stressed regions of the groove at the time of initial service provided the impetus for crack initiation. The absence of other instances of OD SCC suggests only local contamination or such low level contamination that only the most highly stressed tubes could experience crack initiation. Crack propagation then occurred at a slower rate over a longer ,
time period. Examination of laboratory and field data suggest that one j mil / month is a conservative estimated rate of crack propagation for the i secondary side environment, if such cracks have already been initiated.
(Note, however, that the 100% inspection has not provided any data that suggest such cracks are present.) R18C25 crack growth rate is equivalent to 0.7 mils per month, which is consistent with the estimated growth rates.
Based on examinations and historical data, it has been determined the R18C25 was unique and by examination it has been shown that no other similar tubes exist in the McGuire steam generators.
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3.0 Pl. ANT HISTORY
( McGuire 1 is a 4-loop Westinghouse PWR, rated at 3411 MWt, equipped with Model D2 preheat steam generators (fabricated in 1973). The plant underwent initial criticality in August 1981 and began commercial operation in December 1981.
/ Prior to 1989, 775 tubes had been plugged, mostly for PWSCC in Row 1 U-bends (mainly preventive) and in the expansion zones of the hot-leg tubesheet; a few tubes have been plugged for preheater wear and foreign object induced wear.
There was no evidence of systematic secondary side tube corrosion in the prior EC inspections. Table 5-2 delineates the tube plugging performed to date. The pre-service baseline inspection was performed in February 1978. The cold-leg portion of the tube in the SG B which experienced the tube rupture was only inspected as part of the preservice baseline inspection in 1978.
McGuire Unit 1, along with its sister unit, is equipped with an all-ferrous secondary system and full flow condensate polishers (FFCP). Since initial startup the prevailing secondary water chemistry treatment program has been All Volatile Treatment (AVT); combined with FFCP, this regime has sometimes been referred to as Zero Solids Treatment (ZST). Significant benefits of the McGuire Unit I secondary system configuration result from the absence of copper-bearing alloys in the various heat exchangers' tubing: 1) Reduced impact on secondary side corrosion mechanisms which are exacerbated by reduced copper . species as well as the reduced general corrosion which results from operating at higher pH levels, and 2) Enhanced Eddy Current inspection visibility for SG tubing in the absence of plated copper interference.
3.1 DESL<IPTION OF STEAM GENERATORS The Model D2 is a vertical preheat steam generator with 4674 tubes, having an outside diameter of 0.750 inches and a wall thickness of 0.043 inches. The tube material is mill annealed Inconel 600. The general arrangement of these steam generators is shown in Figure 3-1. The general details of the preheater Q section design are shown in Figure 3-2. The baffle plates are 0.75 inches thick. The baffle plates are carbon steel and have drilled holes, 0.766 inches
} in diameter. The lower baffle plate holes are 0.800 inches in O MV 3-1
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g diameter. The partition plate separating the hot-leg from the cold-leg
( censists of three sections. The lower section extends from Baffle Plate 17, a '
full diameter plate, to the tube sheet. The second plate extends between !
Baffle Plates 17 and 14, (another full diameter plate). The third section extends from Baffle Plate 14 to the top plate of the preheater assembly,
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s Baffle Plate 12. Plate 12 is a cold-leg plate. The lowest baffle plate is designated Plate 20 by Duke Power and Plate B on the Westinghouse drawings.
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4.0 DESCRIPTION
OF MARCH 1989 TUBE RUPTURE EVENT 4.1 CONDITIONS PRIOR TO TUBE RUPTURE Prior to the tube rupture event, the Unit was operating at approximately 100%
O power with reactor coolant and secondary system conditions considered normal.
The most recent leak rate determination indicated a primary to secondary leak rate of between 10 and 15 gallons per day (gpd). Leak rate measurements were taken once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> using both the air ejector radiation monitor and manual blowdown sampling. Over the previous three months the leak rate had varied between 5 and 30 gpd with one determination of 45 gpd. This high indicated leak rate was later attributed to problems with air ejector flow.
4.2 INDICATION AND EXTENT OF TUBE RUPTURE The initial indication of a large primary to secondary leak was the alarming of a steam line radiation monitor. The subsequent decreasing feedwater flow with constant steam generator narrow range water level indication and decreasing pressurizer level provided the indication that a steam generator tube leak was in progress. The next indication of a tube leak was an alarm of the condensate air ejector radiation monitor. The actions of the control room operators are detailed in Reference 4-1 and are not discussed in this report.
The initial estimation of the flow rate of the tube leak was 100 to 150 gallons per minute (gpm) based on flow to the cold-legs and the mismatch between charging and letdown lines. Subsequently the estimate of flow rate was revised to approximately 540 gpm based on pressurizer level change. The later flow rate is consistent with the size of the opening found during the inspection of the tube.
4.3 TUBE RUPTURE LEAK RATE EVALUATION Leak rate calculations were performed using the CRACKFLO computer program.
CRACKFLO has been developed for predicting leak rates through axially oriented cracks in steam generator tubing. The analytical model is based on one-dimensional flow assumption and accounts for crack entrance pressure 9222M:1E-050389 4y
losses, tube wall friction, and flashing. Choked flow is evaluated according
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v to Henry's non-equilibrium formulation. Verification of CRACKFLO has been completed by comparison with Westinghouse R&D test data. Comparison of measured and predicted leak rates for 0.74 X 0.041 (sleeve), 7/8 X 0.050, 3/4 X 0.044, and 11/16 X 0.040 tubes indicates good agreement with the test (g,/ data.
The background leakage prior to the rupture is consistent with the presence of a large number of small cracks.
The discharge of primary liquid from the crack was estimated based on operating pressures and crack dimensions from the interior video inspection.
The results, shown on Figure 4-1 indicate that the tube cross sectional area was the limiting parameter, rather than the crack dimensions. The crack ieakage rate is equivalent to a circumferential separation of the tube. '
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REFERENCE 4-1 McGuire Unit 1 License Event Report 89-004, Rev. 00 O
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5.0 IN-PLANT DIAGNOSTICS FOLLOWING TUBE RUPTURE 5.1 BOBBIN COIL EXAMINATION RESULTS All active tubes in the McGuire Unit 1 steam generators were examined full length using standard saturating (magnetic bias) bobbin coils. In addition, selected tubes with bobbin coil indications of interest were also reinspected using rotating probe technology and ultrasonics for further diagnostic purposes (discussed in subsequent sections). Duke Power Company Eddy Current Analysis Guidelines were used to assure consistency between analysts. Since steam generator inspection and eddy current data reduction were completed prior to the removal and destructive analysis of the ruptured tube (SG B R18C25), some assumptions had to be used to formulate the initial analysis guidelines. These initial analysis assumptions as they relate to actual defects are discussed in Section 9.4. Demonstration of analyst understanding of the analysis guidelines and reporting criteria was accomplished by giving each analyst a site-specific practical examination. Only those analysts who successfully completed the examination were permitted to analyze McGuire 1 production eddy current data.
A summary of the bobbin coil inspection results for all four generators is given in Table 5-1. Listed are the total number of tubes with indications attributed to a specific cause or degradation mechanism. Numbers in parenthesis denote the number of tubes with similar types of indications identified during the previous (September 1988) refueling outage. As can be seen, the only strong evidence of recent change in steam generator condition is the apparent onset of tube wear at AVB's. However, this is most likely due to the 100% examination conducted during the forced outage rather than a real increase in growth. In Table 5-1 reportable indications occur in two broad l categories; 1) those due to steam generator operation and 2) those attributable to tube manufacturing or installation artifacts, e.g, " free-span" indications. This latter class of indications is described in more detail in Section 5.2 and were basically present prior to plant operation. With the exception of the O
9222M:1 E-Os0489 5-1
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1 single isolated ruptured tube in SG B, i.e., R18C25, all of the remaining '
degradation, including the free span indications, is within the bounds of expected Model D steam generator experience.
l Tube sheet maps for various degradation mechanisms using SG B (the generator in which the tube rupture occurred) as an example are presented in Figures 5-1 through 5-5. Figure 5-1 shows the location of tubes with eddy current indications attributable to preheater wear; historically this phenomenon has been limited to the cold-leg preheater section near the feedwater inlet as shown in the figure. Tube wear at AVB's is considered a hot-leg degradation mechanism since by convention the hot-leg extends around the U-bend to the eighth support plate. A map for all SG B AVB wear indications is shown in Figure 5-2; in general, tubes with wear indications are bounded by Rows 25 through 45. Evidence of foreign object wear was also discovered in SG B on the hot-leg side near the outer periphery at the top of the tube sheet. A total of three tubes with foreign object wear were identified and are also shown on the tube sheet map in Figure 5-2. Eddy current indications attributable to PWSCC within the hot-leg F* region are shown in Figure 5-3.
These types of indications would be expected to be scattered throughout the tube bundle as suggested by the tube sheet map. There were no reported cold-leg PWSCC indications within the F* region. Tube sheet maps for the ruptured tube along with other tubes with free-span indications--both cold-leg and hot-leg--are shown in Figures 5-4 and 5-5 respectively. As can be seen, tubes with free-span indications are scattered randomly throughout the tube bundle. Tube sheet maps for the other three steam generators showing tubes with reported indications attributable to different causes are given in Figures 5-6 through 5-21.
A summary of tubes plugged during the March 1989 forced outage is given in Toble 5-2. The cumulative number of tubes plugged prior to the March 1989 forced outage for each of the four steam generators is also provided; these totals also reflect the preventative plugging of all Row 1 U-bends. McGuire 1 tube plugging history has been dominated by wear in the preheater section and PWSCC within the tube sheet crevice F* region. The incidence of preheater wear has declined as the result of steam generator modifications, at the end of Cycle 1.
9221 M:1 E-050389 5-2
5.2 ROTATING PANCAKE COIL EXAMINATIONS r%
h To assist in characterizing the condition of the McGuire Unit I steam generators, examples of all the different classes of bobbin coil indications were examined using rotating pancake coil (RPC) technology and ultrasonics. Approximately 300 tubes among the four steam generators were V examined using RPC probes for this purpose. The use of an RPC is useful in estimating the morphology of the signal source which in conjunction with the location in the steam generator can be used to provide a more
) reliable estimate of da .: o mechanism. In addition the RPC is somewhat
( V more sensitive to tube wc degradation than the bobbin coil. Ultrasonics provides an independent means of confirmation of tube wall loss.
5.2.1 Inspection Activity in Support of Return to Power Notwithstanding the singularity R18C25 as demonstrated by the 100% bobbin coil inspection and the RPC characterizations which supported it, Duke Power responded to an NRC staff suggestion that inspection of 100 tubes from Heat #3835 on both hot leg and cold leg would provide additional assurance that significant depth cracking similar to that on R18C25 had not gone undetected. Therefore RPC inspection was performed on 118 hot leg tubes from the top of the tubesheet to the #1 support plate and on 113 cold leg tubes from the top of the tubesheet to the #19 baffle plate level. These tubes included 6 tubes specified by the staff and 29 tubes t (17 hot leg and 12 cold leg) exhibiting manufacturing buff marks. None of the 231 tube sections tested exhibited indications of OD SCC; none exhibited behavior similar to the " precursor" signals seen on R18C25 above the major crack. In addition, RPC testing of 27 tubes in SG B cold leg ,
and 209 tubes in SG D cold leg in the region of the #20 baffle plate detected no evidence of OD SCC. These results reinforce the conclusion drawn from the bobbin coil inspection, that no other instances of OD SCC p are present, and previde heightened confidence that tube integrity has (beendemonstrated.
5-3
5.2.2 Roll-txpansion PWSCC
[) An example of a bobbin coil distorted roll expansion signal is shown in U Figure 5-22. Distortion to the roll expansion signal is caused by the presence of primary-side cracking occurring within the roll expansion at the top of the tube sheet. No clear evidence of crack signals are
(' apparent in the distorted roll expansion signal; rather, the presence of-cracking distorts the normal roll expansion signal by causing loop-opening which is used as an aide in recognizing the possible presence of cracking. Rotating pancake coil (RPC) data for this same tube is shown in Figure 5-23. The rotating pancake coil data can be envisioned as the amplitude response due to a small point probe as the probe is both rotated about and translated along the tube inner wall. Figure 5-23 shows RPC data at the roll expansion; The RPC data shown in Figure 5-23 suggest the presence of linear indications characteristic of axial primary-side initiated stress corrosion cracking.
5.2.3 Tube Wear b
V Three sources of tube wear have been identified in steam generators to date. These include wear in the preheater section at baffle plates, wear at the antivibration bars (AVB's) and tube wear caused by the presence of foreign objects.
5.2.3.1 Preheater Wear An example of a typical bobbin coil preheater wear scar indication is shown in Figure 5-24. RPC data for this same bobbin coil indication is shown in Figure 5-25. Based on an extensive number of pulled tubes from other plants, these wear scars are volumetric, sometimes tapered, and are bounded axially by the thickness of the baffle plate. Special preheater O
5-4 O
wear scar standards are used to provide statistically conservative estimates of wear scar depth. The bases for this approach has been
( ) documented in References 1 and 2. The RPC data shown in Figure 5-25 supports the contention of shallow volumetric wall loss, less than 20% TWD, with minor axial tapering and a circumferential extent of m approximately ninety degrees. This data is consistent with previous wear scar operating experience.
5.2.3.2 AVB Wear O
.{) Tube wear indication at AVB's are relatively common in steam generators. An increase in the number of tubes with wear at AVB's--with depths on the order of 20%-30% through-wall--was reported during the current outage. Special bobbin coil AVB wear scar standards and signal amplitude sizing methods are used to provide depth estimates with a basic uncertainty on the order of +/- 10% in depth (2). Both single-sided and double-sided wear scars have been observed at AVB's. The use of a single-sided wear scar standard and signal amplitude has generally provided a conservative est imate of
( depth for both single- and double-sided AVB wear. RPC data for an AVB wear indication is shown in Figure 5-26. The RPC data shows single-sided wear at an AVB; the shallow volumetric nature of the wear is apparent in the RPC data.
5.2.3.3 Foreign Object Wear
{
Tube wear attributable to foreign objects is caused by the fretting of the foreign object against one or more tubes. This has typically
' been noted to occur on the outer periphery of the steam generator.
Three such tubes with suspected foreign object wear were identified in SG B on the hot-leg at the top of the tube sheet during the current forced outage by noting the presence of distorted bobbin coil Otube sheet entry signals and the relatively strong response of the low-frequency eddy current data channel which is more sensitive to !
conditions external to the tube wall such es that caused by the 5-5
presence of a foreign object. RPC data for one of these tubes at the tube sheet top is shown in Figure 5-27. The top of the tube sheet is t evidenced by the horizontal offset in the isometric map whereas the
\-
presence of significant tube wear is shown by the relatively large amplitude signal just adjacent to the top of the tube sheet signal.
O
( 5.3 TUBE MANUFACTURING / INSTALLATION ARTIFACTS Three additional classes of indications not attributable to
,. operationally related degradation have also been observed in the
( McGuire Unit I steam generators. Two of these classes are artifacts of tube manufacturing, e.g., buff marks and permeability variations, whereas the third class, i.e. installation marks, is probably due to difficulties encountered during tube installation. All three signal classes are somewhat common in operating recirculating steam generators.
5.3.1 Manufacturing Buff Marks Buff marks are generally localized cosmetic repairs made to the tube during manufacturing to remove small pits or tube discoloration.
These types of artifacts are typically tapered; because of this they are more pronounced in absolute channel bobbin coil eddy current data rather than the differential coil channels. This is apparent in bobbin coil data shown in Figure 5-28; both differential and absolute coil strip chart data--shown in the upper left--is illustrated. The absolute coil channel response, shown on the right (Channel 6 vertical), is more pronounced than the differential channel hresponse. These indications are generally localized and have been observed in all areas of steam generators; i.e., there is no preferential location within a steam generator in which they occur.
Depth estimates derived from absolute coil bobbin data show these ypes of discontinuities to be typically less than 20% through-wall.
These depth estimates are supported by RPC data and by direct tube pull evidence from other steam generators (3). RPC data for the obbin coil burnish mark indication is shown in Figure 5-29. This
]Vparticular indication was reported on the hot-leg side at the 4th support plate + 18.2".
l 5-6 l
( -___- _ _ _ - _ _ _ _ - _ _ _ . - - - - ._ _ _ -
Again, the RPC data supports the presence of a shallow less than 20% TWD g volumetric discontinuity consistent with other innocuous industry experience.
(
5.3.2 Probable Tube Installation Marks Bobbin coil eddy current data for another type of eddy current indication
/ identified in the McGuire Unit I steam generators and observed in another Westinghouse plant is shown in Figure 5-30. This type of indication is characterized as a linear mark with significant axial length. The source of these indications has been attributed to tube installation through a large number of closely spaced plates whose hole locations vary statistically within their tolerance. Occasionally this variation in location may result in the tube being held against the plate tightly enough to mark the tube surface as the tube slides through the hole. Because of probable tapering, these indications are usually more pronounced in the bobbin coil absolute channel (Channel 6 vertical) as can be seen in the strip chart data shown on the upper right of Figure 5-30. RPC data, shown in Figure 5-31, for this type of bobbin coil indication supports the contention of shallow tube wall loss distributed axially along the tube.
5.3.3 Permeability Variations Bobbin coil indications not indicative of tube wall degradation can also occur. Probably the most common indication is what has historically been attributed to permeability variations which occur within the tube wall. As a general rule, these indications exhibit signal features indicative of tube wall loss which has initiated in the tube inner diameter. They can generally be distinguished from real tube wall degradation by the use of magnetic bias
[ saturating coils which suppress permeability variations. RPC data for several i tubes with permeability indications is shown in Figures 5-32 and 5-33. In some cases, the permeability distribution can be localized as shown in Figure 5-32, or may exhibit some axial extent as shown in Figure 5-33.
I G
l 5-7 i
5.4
SUMMARY
OF EDDY CURRENT INSPECTIONS Inspection of 100% of tubes in service by bobbin coil probe was performed in the wake of the tube rupture event in the cold leg of SG B R18C25; no evidence of similar degradation was found. Expected findings unrelated to the tube d rupture included PWSCC in expanded tube sections, wear indications at AVB's and preheater baffles, and assorted as built tubing variations. Special attention was given to detecting scratches or grooves similar to those observed on R18C25 and R13C34; this resulted in plugging tubes with signals of extended length, O even though no tube penetration was evident.
V All classes of eddy current signals identified by bobbin coil testing were characterized using the RPC probe to maximize detection of degradation. Except for the tubesheet PWSCC and wear indications, no significant tube wall degradation was observed on any tube examined other than the ruptured tube. At the request of the NRC staff, to provide additional assurance that no significant cracks passed undetected, approximately 100 tubes of the same heat as R18C25 in SG B were subjected to RPC testing. The testing included the length from the tubesheet to the first support plate on the hot leg and to the
- 19 baffle level on the cold leg. No evidence of OD SCC above the top of the tubesheet was observed on these tubes.
These findings indicate that the rupture of R18C25 was a unique event, arising from circumstances peculiar to that tube. The conservative action of plugging otherwise undegraded tubes with extended surface marks removes from service all tubes known to have any similarity to R18C25. Appropriate surveillance of the tube bundles in accordance with industry guidelines and NRC Reg. Guide 1.83 will provide adequate assurance that tubes undergoing degradation in unsupported tube sections will be detected in a timely fashion.
5.5 ULTRASONIC EXAMINATIONS 1
l Ultrasonic examination of selected tubes was also conducted as a means of independently confirming bobbin coil and RPC eddy current indications. The I ultrasonic examination was conducted using a radial longitudinal beam which is l 1
5-8 i
I
primarily sensitive to volumetric tube wall thickness changes. This method exhibits little sensitivity to the presence of cracking but is very sensitive (n} to small changes in overall tube wall thickness. Alternate axial or circumferential directed shear wave beams would have to be utilized respectively if circumferential or axial cracking were expected. I Table 5-3 presents a comparison of eddy current and ultrasonic inspection I
results. The presence of minor wall loss, less than 20-30% through-wall, as reported by both the bobbin coil and RPC for voluinetric indications is confirmed by ultrasonics. No significant wall loss was evidenced in the ultrasonic data for the eddy current permeability indications.
5.6 VIDEO EXAMINATIONS Visual examination of the RI8C25 tube was accomplished by the use of the Welch Allyn Video Probe (TM) from the tube ID. In addition the region around this l
tube was examined from the secondary side both from the tube lane region and also from the tubesheet access hole created by the removal of tube R19C24. The results of these examinations are briefly summarized below.
\
5.6.1 Tube Examination from the ID The examination of R18C25 was done on March 14, 1989 by insertion of the Video Probe from the cold leg channel head. As the probe ascended into the region of the tube rupture a band of lightly colored or white deposits was observed. With continued ascension the band was observed to split into two arcs of whitish deposit which emanated from the lower portion of the open tube crack. These deposits occurred only on the lower portion of the tube and are most likely the g result of build-up along the edge of the stream lines of water leaking from the secondary side after the water level of the reactor coolant had been lowered.
The boric acid concentrations on the secondary side had reached values coraparable to those of the primary side leading to the conclusion that the deposits are primarily composed of boric acid.
5-9
(
\
Closer examination of the tube ID showed that the white deposits terminated part way up the crack opening. This is consistent with the deposit build-up on the ID as a result of drainage back through the crack.
l l 5.6.2 Visual Inspection of Inter-Column t. anes 24/25 and 25/26
( A fiberscope examination from the tube lane was done by counting down the tubes to the lane between columns 24 and 25 and then proceeding down that lane to row 18 for observation of the subject tube. Although the tube fracture was not
[
visible it was possible to observe that the region below the baffle plate had irregular deposits. Some of the deposits formed a ring on the tube and had the l appearance of growing as a result of the water level draining back through the crack. Other deposits were observed higher on the tubes, i.e. closer to the baffle plate. It was noted that some of the crevices were filled with deposits. Others appeared to be relatively clean. The quantity of deposits observed increased with increased penetration of the bundle. Much of the deposit was whitish in appearance and probably related to flashing of the primary coolant into this region of the bundle. Other deposits were darker and 7
probably of earlier origin. Some of the crevices contained dark deposits and others were decorated with a white lining along the lower edge.
Subrequent to the examination of the lane formed by columns 24 and 25, the fiberscope was moved to the lane between columns 25 and 26. The observations made in this lane were quite similar to those of the adjacent lane. Deposit build-up occurred with increasing penetration into the tube bundle, as previously observed. However, the overall quantity appeared to be somewhat less with the deposits slightly darker in appearance. The deposit build-up was relatively minor in both cases. There was r.o observed bridging of deposits
[ between tubes and no deposit build-up interfering with observation of the edge of the tube hole in the baffle plate.
O 5-10
\
5.6.3 Fiberscope Inspection of R18C25 as Viewed from Removed Tube Hole R19C24
- following the removal of tube R19C24 the fiberscope was inserted to permit viewing of the fracture as it appeared below the twentieth baffle plate. The fracture appearance was generally as expected based on the previous ID examination. Deposits were present at varying levels on the tube OD. These included an encrustation of whitish deposits along the lower portion of the fracture edges that corresponded to the deposits observed from the ID.
The appearance of the fracture was also documented from just above the O twentieth plate. Only a very short segment of tiie crack could be seen. The overall deposit appearance was relatively sparse above the baffle plate.
Crevices of the twentieth plate, in the immediate vicinity of R18C25, appeared to be relatively open.
5.6.4 Summary of the Video Probe and Fiberoptic Inspections Both ID and OD inspections were performed in and around tube R18C25. These inspections provided documentation of the tube appearance prior to removal from Othesteamgenerator.It was also possible to observe that some of the crevices contained deposits and that the surface deposits on the tubes varied with their position in the steam generator. Although the whitish deposits observed were believed to be associated with boric acid, other darker deposits, with origins that are believed to pre-date the leakage event, were also observed. Aside from the deposits believed to be associated with boric acid, no abnormal conditions were noted on the secondary side of the steam generator, and no observations were made during the visual inspections which would provide direct insight into the cause of the tube leakage event.
O 5-11 s
A TABLE 5-1 U
MARCH 1989 BOBBIN C0ll INSPECTION RESULTS
' .r'\
L)
SG A SG B SG C SG D HL CL HL CL HL CL HL CL Operational Degradation
[),
v o PWSCC within F* region 9(17) 3(3) 10(16) 0 11(20) 1(6) 6(17) 0(1) o Wear
- Preheater Wear -
27(38) -
4(4) -
7(8) -
7(6)
- AVB Wear 10(4) -
20(1) -
33(7) -
11(0) -
- Foreign Object - -
3(0) - - - - -
o Stress Corrosion - - -
1(0) - - - -
Cracking q Total Tubes 19 30 35 5 44 8 17 7 Manufacturing Artifacts
- Free Span 6 9 8 4 11 15 9 7 Indications
- Permeability 6 7 19 10 8 8 4 7 Variations Total Tubes 12 16 27 14 19 23 13 14 O
V Note: Numbers in parenthesis denote number of tubes with indications attributable to operation identified during previous refueling outage.
,. Some of these tubes were subsequently removed from service and were, therefore not subject to further inspection.
O 9222M:1E-050489
l TABLE 5-2 MCGUIRE UNIT 1 -
PLUGGED TUBE
SUMMARY
SG A SG B SG C SG D Previous Plugged (180) (198) (169) (228)
Tubes (Total)*
Tubes Plugged During March 1989 Outage o PWSCC within 11 12 12 6 F* region o Wear
- Foreign Object 3 o Stress Corrosion 1 Cracking (R18C25) o Manufacturing F Artifacts
- Free Span 4 5 4 13 Indications o Other Reasons
- Secondary-side 1 access to R18C25**
- Pulled tubes *** 2 Total 195 222 185 247 b Tubes d 4 Row 1 tubes preventively plugged in each steam generator.
- Tubes R18C25, R13C34 & R19C24 9222M 1E-050389 . - .
TABLE 5-3 COMPARISON OF ECT/UT RESULTS id O Tube Location Eddy Current Analysis UT Analysis R13C34 14 TSP Axial wear 26% TWD Axial wear 20% TWD (0.5" to -9")
NJ R49C52 16 TSP Wear, 32% TWD Wear, < 20% TWD
(+0')
19 TSP Wear, 26% TWD Wear, < 20% TWD
(+0")
R49C57 17th TSP Wear, < 20% TWD Wear, <20% TWD
(+0")
19th TSP Wear, < 20% TWD Wear, < 20% TWD
(+0")
R21C39 20th TSP MBM, < 20% TWD MBM, <20% TWD
(-3.7")
R19C24 17th TSP Permeability NDD
(+0")
O v R28C61 10 TSP Permeability NDD
(+0")
l R47C76 9 TSP Permeability < 20% TWD
(-1.6")
9 TSP Permeability NDD
(-17.6" to -23.0")
9222M.1 E-050389
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Figure 5-21. McGuire SG D Cold-Leg Free Span Indications 9222M.1 E-050289
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- CH M 1 VEFT+ - CH 6 VEFT + CHAHHEL HQ -- M!x# 1 50 B ROW 20 COL 52 j F.Y DIEFLLY
- I CH'II!!'ri'1' A
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. EFAH 240 CN g1, FOTATION - 43 DEG f
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l . FFEQ 100 kH:
EFAta 1(0 j t;.H VQLTi 10i' int 40. EDTAT10H - 320 DEO
. TT5-wt + 0. 0 f G - l
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I i ..?$ El i i' 100. H e a; I
t 100 L1 ie i et i 7i 6O FLANT UHIT SG LEG DATE ELF 56611 H;GUIFE TAFE edi 1 E IHLET Ok 13.'E 9 l 14:0i:0! sn H&.;CH 11 1919 { TTI-HL + 0. 0 o { 50 6 Fou 20 COL 5?!
l,,, '
CHan* -- 1 CHAn* -- & CHAne -- 5 CHAH+ -- 7
> FFE0 400 kH: FFEQ ----- 500 kH: FFEQ 100 6 H: FEEQ ----- 25 k H:
L trAu ----- g!! treu ----- 3?? !FAo ----- 90 ! Fan ----- ??
ScT;ttou - ;; c . TAT!90 - 73 scTAT!Ou - 159 SOTATISH - t!!
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l TT E-HL + 0.0 I CHAN* -- 2 CHAN* -- 4 CHana -- E. CHAna -- M &
FFEO ----- 400 kH: FFEQ S00 kH: FFEQ---------- 100 k H: Chant -- 4-6 ceAn ----- 970 !FAH ----- 743 SFAN EIT EFQH 4?O
(~N .?TATino - :0? POTAT10u - Eds F?TOTyrw - ;;0 sovcT;5n - ;?p m -
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!O.59 V ~!! D 0*. 20.90 V T43 0 0*. 9.52 V ?O! 0 ON 11.06 5 14? D FEE FLANT UNIT S. O LEG DATE McCutsE Tact 041 1 E 1HLET 01.12 69 m -
t (m Figure 5-22. Bobbin Coil Distorted Roll Expansion Signal 5222M.1E-050289 l
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- i. ) UTILITY: DUKE POWER CO. I PLANT: McGUIRE NUCLEAR STATION l GEN: R$G ' E; ' INLET l DATE: 3/25/89 l TIME: 22:17:18 O ANALYST: E5926 k
CHRHfiEL r VEFT FPEQUENCY ( K H2) : 3 Dr.
P0H: 20 COL; SE PLRTE: TE HR:( INC(VJ: 9.3E VERTICAL 2N0(%TWCJ: 70 LIES FULL ECRLE t20.0 V ID HOT LEG LIES FHREE: E9 DEG z NR4 IhD POET inctil t -0.10 TT5-HL + 0.0 (CIPCM L3E51 e.
ic.c voLTE -
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l (\ Figure 5-23. Rotating Pancake Coil Data at Roll Transition I
l 9222M:1E-0502E9
_ ._ _ - -- _ - - _ _ _ _ _ - _ _ . _ _ _ _ _ _ _ _ _ __ -- = - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - =
l
- CH M i VERT + - CH 3 VERT + CHAHHEL NO -- MIX
- M
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SPAN $7
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LEFT STPIP chart ~~
F chi,5#~~- M JV g j CHANS $
SPAH 29 ROTAT10H - 56 DED PIGHT STRIP CHari CHate -- Sv
- - FREG 900 kHz SPA,4 S?
h . . 1.87 fia;mM itTH TSP 0 JEG S2 f FOTAT10H - 3 DED
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) sysIg_ggfigy_gIIgf NAME - ISI-424P11
- of CHAH- 0 1:33:06 AM I , , MAPCH 1$ 1999 I , C0' La
. . . . . . FEE 9 112 ? 4 *fs 7 9
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-t 7 et PLANT UNIT S/G LEO DATE BLK 19133 MCOUIRE_TAFE 2_ !. B__ DUTLET 03/15<99 t l 13 3 33 06 Af1 NARCH 15 1999 j 16TH TSP - tl.3 ok l$G B RCW 49 COL 5dj
-\' CHANe - 1 CHAHe -- 3 CHAHe == $ CHAhm -- M 1 FAEQ - --- 4ee kHz FREO cpAN -
See kHz FEEQ ----- 1('e kHz CHANS -- 1-5 63 $FAH 77 SPAN 53 gPAN ---- 33
..JTAff0H - 44 00 TAT 10H - "'S 50 TAT 10N - 162 POTATION - 56 0 f "9 4 %'l e.?5 v eI ef 0.e7 v eI eE e.92 v e0 e$. e.27 Y eI ef 1
l 1ETH TSS - e.S l CHAH* -- 2 CHAH# -- 4 CHAHe -- 6 CHAN# -- M 2 FE EQ ---- 400 kHz FPEQ spAH
260 kHz FEEQ 100 kHz CHANS -- 4-6 ccAH g33 125 spgH .-- - 3g spa >4 gg
! ,)TATION - 91 ROTATION - 245 POTATION - 129 E0Tcff0N - 264 e
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2.62 V e0 0*,
1.09 V e0 et. 1.85 Y e0 0*. 1.87 5 e0 32E PLANT UNIT S/O LEG DATE MCOUIP.E. TAPE 2_ !. B__ OUTLET 03/15/89 O
V Figure 5-24. Preheater Wear Scar Indication 9222M:1E-050289
. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _. I
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V a UTILITY: DUKE POWER COMPANY
[7 PLANT: MCGUIRE UNIT 1
~h GEN: "B" S/G COLD LEG DATE: 3/22/89 TIME: 6: 41:52 ANALYST: R9615 CHRHNELt- VERT FFEQUENCY (KHZ): 300 P0H: 49 COL: 52 PLRTE: EPECIRL MRX INC(V): 5.00 PHREE IN0(ITWult IS LIE 5 ruLL SCRLE 333.0 V 00 COLD LEG LIES FHREE: 121 CEG MAX ING P05( trich l:-0.3B PREHERTER WERR INDICRTION RT THE lETH TEP
[CIRCM LIEE]
10.c YOLT5 _.-
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. -q
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-1.2 270 3'O
-2.1 RXIRL LENGTH-INCHE5 eD ME-CEGFEEE
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l Figure 5-25. Rotating Pancaka Coil Data for Preheater Wear Scar 9222M:1E-050289
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UTILITY: DUKE POWER COMPANY PLANT: MCGUIRE UNIT *1
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GEN: "C" S/G AVB DATE: 4/ 5/89 TIME: 17: 5I50
-ANALYST: B5926 CHRt4NEL: VERT FPEQUENCY ( K HZ): 250 P0H 39 COL: 35 PLRTE: TEP 2 MRX IN0(V): 1.El VEFTICRL If40(;;TWO): 15 LIEE FULL ECRLE 210.0 V 00 HOT LEG LIEE PHREE: !!3 CEG MRX INO POET inch ).: 0.00 WERR AT 2RVE (180 CEGFEEE FPCM RVE EIGNRL)
(CIFCH LIEE3 3ED
-B.5 R/IRL LENGTH-IN': HEE SD ANGLE-CE G~EE E
-1,2 O
- NOM VOLTE]
v
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Figure 5-26. RPC Data for an AVB Wear Indication s222 mas-cso2ss f
1 L____--_____-__
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t UTILITY: DUKE POWER CO.
PLANT: McGUIRE NUCL E AR STATION L GEN: RSGB' INLET DATE: 3/26/89 '
TIME: 9:12:43 ANALYST: R9615 CHRt1NEL: VEFT FFEQUENCY ( KH2): 300 R0W: 48 COL: 50 PLRTE: TE NRX ItdatV) 10. E 3 g VERTICAL IND('4TWD): 31 LIEE FULL ECALE :30.0 V g 00 HOT LEG LIE 5 PHAEE: 5E DEC jl NR4 IND F05( inch)t D.17 LARGE VOLUME HERR Tf FE INCICRTION RT TTS-HL + D. Z*
,... (CIFCM L3553 10.c VOLT 5 ,
, N\ \0 e
g . ..
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- I 3EU D.E 0,2 270
~N - J lEc 3,3 RXI AL LENGTH-INCHES g0 R R E- E FEEE 0
( lNCH VOLTS 3 j^
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s
\ Figure 5-27. RPC Data for Foreign Object at the Tubesheet Top 9222M:1E-050289
6 VERT + CHAHHEL tl0 - 1 50 B ROM 15 COL 92
>:Y ~
DISFLAY ~~
i ! CHAl5~~ ~~1 -
~
I FFEQ 400 kH:
i' .f ,
SPAli ----- 10 ROTATI0tt - 40 DEO "t.
.* /p
~; % w T sIntr_ctstI-
/ CHAna -- M tv
,L /- ' CHAH3 -- 1-5 SFAtt - 40 ROTAT!014 - 43 DEG
. .s~
7,] RIGHT STRIP CHAPT CHAH* -- 6V I PFI. 1 FFE0 ----- 100 kH:
- SEC# 1 Spgn 49 0.29 VOLT 5 91 Lgt t<N okROTAT10tl - ' 323 DEO d 4TH TSP + 18.2 ok
' *- ?YSTEM CONFIGUPAT!0>8 o ,
14ANE -- ISI-424F.11 ,
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_ _ . M 7I dH FLANT Ut4IT S<0 LEO DATE ELP 46466 MCOUIAE TAPE 04S 1 B IHLET 03/18 83 b
( l3:51:16 An MARCH 19 1919 l 4TH TSP + 18.2 l $G B F0W 15 COL 93]
CHAH# -- 1 chaff # -- 3 CHAN# -- 5 CHAN# -- M i FEE 0 400 kH: FPEQ - 300 kH: FREO 100 kH: CHANi ~~ 1-5 eppt; _ . 10 SFAH 10 SFAll 10 SFAH 10 3TcT10H - 40 r0TcTIOH - 74 50 TAT 10N - 163 80TcT!0H - 43
)i w %
s 3G %
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o 0.29 v 91 I E3f 0.?2 v 91 E 4tf 0.26 v e3 I eE 0.?s v as E 90E l 4TH TSP + 18.2 l CHAN# - 2 CHAN# -- 4 CHAH# -- 6 CHAH# -MS FE EQ --- 400 kH: FPEG 300 kHz FGEQ ---- 100 kH: CHANS -- 5-1-5 ceau . . 30 span --- 10 span --.-- 10 TFAH 10
.JT&Tiow - 192 FOTAT104 - i?? POTctf0N - ??? POTAf f 0+J - 20 ,
0.24 V 150 0 0-0?. 0.17 V 94 0 ON O !/b
,0.28 v E0 E 7E J I
0.24 V 1 't D 0% '
PLAT 4T UNIT S/0 LEO DATE MCOU!FE TAFE 048 i B !HLET 03.'18/89 L Figure 5-28. Manufacturing Buff Mark Indications 9222M.1 E-050289
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A l' O UTILITY: OUKE POWER CO.
PLANT: McGUIRE NUCLE AR STATION GEN: R$G 'B' INLET DATE: 3/26/89 TIME: 1:52:43 ANALYST: R9615 CHRNNEL: VEFT FFEQUENCY (KHI)! 320 PON: 15 COLT SI PLRTE: TEP 4 t1RX INDty): 4.7E VERTICRL IND(%TWDI: 15 LIE 5 FULL SCRLE 125.0 V C3 HOT LEG L755 PHREE: 132 DEG
\ HRX IND F05(inch): 18.24 FF0ERELE f1Eri RT 4TH TEP + IE.2'
[CIPCM LIEE3 10.0 VOLTE .m _.
~
- 4. -
m, ,- t
=
>4 2 0. D .' - .A r-]
- 3CD 19.0 lE.D 8 270
- 1ED 17.0 RXIRL LEtlGTH-INCHE5 90 RR E-DE GFE E D
. f" Figure 5-29. RPC Data for Manufacturing Buff Mark 9222M;1E-050289
__________ _________ ____ __ ___.___ __ _ ]
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- CH M 1 VERT +l- CH 6 VERT + CHAl#4CL HO - 1 SG B F0H 13 COL 34 !
ih i Ny 015 FLAY
(
, g4 i
,4 CHAna -- 1 7
l \ J -
FPEQ 400 kH:
7 ,,5 SPAti 40
} POTATIOH - 43 DEG i
' LEFT STP!P CHAET
' ~
J O Es5tf-- n tv I f' CHAHS -- 1-5 l ; 1. '
5FAH ----- 40
\ _ .. L ROTAT!0tl - 49 DEG
' -- i P!GHT $TP!P CHART l 'CAAN* -- 6V P
1 FREQ 100 kH:
.. SPAH 111
'3' 1.0i VOLT 5 144 W L6 f ROTATIDH - 318 DEO h I 14Tw T$p + fL
'd' SYSTEM COF_lEIGUF A710t_4 NAME -- 15I424-R14 e e of CHAH- 8 I
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FEEU 142 z 4 5N~- 5 400 m 25 3.Oss yl 4 100 S 6
-~ 35 71 6 40 PLANT Uti!T S/G LEO LATE BLK 206 MCOUISE TAFE 057 1 B OUTLET Ohls/es l 11:42:E7 PM MAFCH 19 1939 l 14TH TiF + 0' l SG B FCW 13 COL 34l CHAh* -- 1 CHAn* -- 3 CHAN# -- $ cygne -- g g g FFEQ - 400 kH: FFEQ 300 kH: F;EQ - *-- 100 kH: CHAH$ -- 1-5 s 3FAH - 16 SFAH 16 SFAH - --- 10 Spat; ---- 13 E0Totf0H - 49 50TQTION - 76 POTQl. ION - 161 p0TsTfou - 49 b,s -
r -- g
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/ 0 6 0.57 V 119 E ??E 0.01 V 104 E 2?] 0. 4 3 V . 75 E OE 0.65 V 94 E 4 t E l 14TH T1F + 0. 5 l CHAtl* -- 2 CHAna -- 4 CMAH* - 6 CHAH# -MS F R E a ---- 400 kHz FFE0 300 kH: FFEQ - -- 100 kH: CHAtG -- 44 IFral 34 SFAH 37 SFAN - -- 20 SFAH 22 COT = TION - 24 EOTATION - 241 E0T ATIO!! - 914 entot t r'+# - Ett e ,
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\ 0.?9 V S19 0 0% 0.?6 V 123 0 0% 0.d5 Y _.56 0 0': 0.?7 E 105 0 !?E PLAttT UNIT $/G LEG LATE MCGU!FE TAPE 057 1 B OUTLET 03/19/99 l Figure 5-30. Linear Surface Groove Indication 9222M:1E-0E0289
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a UTILITY: DUKE POWER COMPANY PLANT: MCGUIRE UNIT 1 GEN: "B" S/G COLD LEG DATE: 3/22/89 TIME: 5:25:33 ANALYST: R9615 CHRtJNEL: VEFT FFEOUENCY (KHZl 300 R0W: 13 COL: 34 PLATE: EPECIRL F1RX IMOf V): 1.'2 VERTICRL INC(%THO): 32 LIEE FULL ECALE 120.0 V 00 COLC LEG LIES FHREE: 12S DE; itR4 IND F05( inch ): 2.19 V EIMILRR LOWER RtWLITUDE INCICRTION t IED CEG. (14-22% TWD)
- CIFCM LI55]
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10.c YDLTE g. W h N
.- {.'M p -
.. -cam. i
% ;,# J^~ - -- _ _.QQ s 4 x+. ' '%" ' ,EC
-2.] '
Y 3:; ' -
f -5.4 - 'N4A *f# 270 k _E.E ,
8 JED RXIRL LENGTH-INCHEE ;.
90 RNGLE-CE"JEEE
-12.2 E
7._
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v ) Figure 5-31. RPC Data for Linear Surface Groove 9222M:1E-050289 l
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j r UTILITY: DUKE POWER COMPANY
\ PLANT: MCGUIRE UNIT al GEN: "D" $/G DATE: 3/26/S9 TIME: 17:53:19 ANALYST: W6871 CHAFJt4EL: yERT FREQUEfJC f (KH2): 3CD POW: 17 COL: G 4 PLRTE: TEP 1 MRX IN0tVI: 42.E3 LIEE FULL ECRLE ]Q.0 y HOT LEG LIEE PHREE: 45 CEG ,
NRX Iflu POE( inch 1: 9.91 FFri INDICRTIOf45 RSOVE 157 TEP (CIPCM LIEE3 fm .
20.0 VOLT 5 s .. -= - it
> c w '
12,0*
3Ell 10.E y 9.] 270
- 1ED 7.E RXIRL LEflGTH-IfiCHEE ,0
\
g,) -
RttGL E-CE 7EE E D
/"T t
b Figure 5-32. Permeability Variation Indication 9222M:1E-050289
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.( UTILITY: DUKE POWER COMPANY ,
PLANT: MCGUIRE UNIT al '!
GEN: "D" S/G DATE: '/31/89 TIME: <:34: 2.
ANALYST: B5926 CHANNEL: VERT FPEQUEllCY i kH2): 300 ROW: IE COL: BE PLRTE: SPECIAL MRX INC(V): 9.2E \
COLD LEG LIEE FULL ECRLE 333.0 V LIEE P R EE: 33 CEG
\ g MA:' INO POE( inch 1: 5.97 FFt1 FFON TT5-CL +11. 0 TO 5.7 CCIFCM LI553 10.0 VOLTE - t ;
s1 l '*- [
. ~) "
+ -
,p -
1D.3 hhy:. . 5' 3gg 270 B.E A 10 E.9
(
f R.tIRL LENGTH-INCHE5 ga ANGLE-CE GREE 5 5.2
- 1. 0 l
l l' .
r i
Figure 5-33. RPC Data for Permeability Variation 9222M:1E-050289
q 6.0 TUBES REMOVED FOR EXAMINATIONS v !
Segments of the cold legs of three tubes were removed from SG B for metallurgical examinations. These were from tubes R18C25, R19C24, and p R13C34. Tube R18C25 contained an axial through-wall crack and was extensively V investigated. Additional work is currently in progress on tube R18C25. Tube R13C34, from the same heat of Alloy 600 as tube R18C25, exhibited an extended eddy current indication suggestive of the groove feature on R18C25.
Examinations of this tube are in progress. Tube R19C24 has undergone (qJ non-destructive evaluations (NDE) only; additional characterizations of tube R19C24 are planned. The results of the individual tube examinations are synopsized below.
6,1 TUBE SG B R18C25 CL EXAMINATION Visual examination revealed a predominantly axial through-wall crack approximately 3-5/8 in. long, extending above, through, and below the location of the 20th support plate, the lowest plate of the preheater. The support plate zone exhibited bright metal patches with circumferentially oriented
" swirl" marks indicative of recent oxide removal associated with localized tube motion against the drilled hole in response to the rapid primary-to-secondary leakage. The OD surface at the elevation of the bottom of the plate displayed a ring of small circular areas of bright metal, almost pit-like in appearance. Low-magnification stereomicroscopic examination gave l no evidence that these superficial features were corrosion induced. The j remaining tube surfaces were covered with a thin black oxide-appearing deposit l that is typical of all volatile treatment (AVT) chemistry op0 rations.
l O A prominent OD feature was an axial " groove" or score mark, 0.045 in, wide, j e5 tending visibly from the upper in plant cut end of the tube section through the main crack and below the main crack. The groove was about 1 mil deep and O
g was visible after cleaning to 16 inches below the end of the main crack. The total linear extent of the groove has not been established. The main crack was approximately centered in this groove. The groove also contained short circumferential cracks above the main crack. These tended to run the width of the groove.
9221M 1E-050389 g,y
I The main crack was open about 1/16 inch in the central region (but not O "fishmouthed"). The fracture edges were " jagged" or "sawtoothed", and short OD circumferential cracks emanated from the tips of several " jags". The main, open crack extended about 1/4 in above the upper surface of the 20th plate p and terminated in two short branched cracks, about 45* apart. Slight tube J
" bulging" was suggested in the upper termination region. Two short cracks in i
the groove were observed beyond the lower termination of the main crack. l These were approximately 45" to the main crack and were not connected to it. )
The fracture faces were discolored irregularly with thin deposits that sO appeared brown, tan, or copper colored in places or dark with intermittent whitish zones in the lower half of the fracture. The bronze-straw colored zones appeared as a dull luster. Overall, there was little evidence of yielding or fishmouthing, although slight plastic deformation appeared to have occurred at the fracture ends, particularly the upper ends where the oxide spalling exhibited a chevron pattern. There was no visible evidence of wall thinning due to corrosion or wear.
The tube segment was examined by laboratory eddy current testing (ECT) and by X-ray double wall radiography. The ECT identified an intermittent axial indication that extended from the upper in plant cut to 1.3 inches below the main fracture. This indication was sized as 40% through-wall (maximum) using an EDM notch standard and vertical amplitude comparisons. Subsequent re-analysis of field bobbin and the RPC field data using the destructive l examination results, indicated possible areas of discrete cracking with both l
eddy current techniques.
Radiography revealed several zones of small circumferentially oriented cracks in the axial groove above the main fracturb. Cracks that were not detected by low power stereomicroscope examination were identified. Some of these were faint axial cracks that appeared to join the faint or shallow circumferential
, cracks in the groove area above the main fracture. Significantly, radiography did not reveal any cracking outside of the groove area and showed no wall thinning in the support plate intersection region or elsewhere on the tube sections. The groove was not a strong radiographic feature; only a faint shadow-like display was obtained on the film. .
O 9221M:1E-050389 gg l
g The tube was sectioned according to the diagrams given in Figures 6-1 and 6-2. A 3/8 in. long ring section at the upper end of the as-received tube was examined by SEM and EDS before and after flattening. This section contained relatively deep OD-initiated axial and circumferential cracks that met and q crossed. All cracks were in the groove and extended axially for the full ring Q length. The cracks were intergranular and were approximately 1/3 through-wall. EDS analyses of the intergranular zones consistently showed the presence of Inconel 600 constituents, Fe, Ni, and Cr. EDS spectra of adjoining 00 surface deposits revealed Fe and patches of material richer in Cr d than the base metal.
An additional ring (transverse section) just above the termination of the main fracture was mounted, polished and etched. Several features were established by optical metallography on this cross section:
(1) Dual etching indicated that the carbides were predominantly intragranular with little grain boundary carbide precipitate. This is typical of the microstructure of Alloy 600 tubing from the mill during the production era of McGuire tubing.
(2) The grains were equiaxed, indicating an effective mill anneal.
(3) The grain size was relatively small, typically ASTM 10, consistent with the mill annealing practice of the time of production.
(4) Only 00-initiated, discrete SCC was present; no general IGA or ID-initiated SCC was detected.
(5) Carbide banding was present in about 1/3 of the wall near the ID. This banding occurs frequently in mill annealed Alloy 600 tubing, plate, and sheet and has not been implicated in any surface-induced corrosion degradation.
(6) The OD surface of the groove, particularly at the edges of the groove, had a thin grey-appearing deposit that was relatively rich in chromium.
This thin deposit was also present on OD surfaces away from the groove.
s__s e., j
I
,, The material was about 0.5 to 1.5 microns in thickness and was consequently much thicker than the typical passive film of Fe-Cr and l Fe-Cr-Ni alloys. I l
)
(7) The Cr-rich deposit was in turn covered with a thicker, darker, Fe-rich G
V deposit typical of the normal magnetite of AVT chemistry exposure.
(8) The groove measured 0.00066 in. (0.66 mils) in maximum depth at this elevation.
G (9) The subsurface metal at the OD adjacent to the edge of the groove showed a " smeared" appearance with no grain boundaries for a depth of about 2 grains. This is suggestive of high local cold work at the edge of the groove.
(10) The initial etching produced shallow grain boundary ditching in a crescent-shaped zone centered on the groove and extending about 1/3 of the wall thickness under the groove at its maximum depth.
m (11) Sensitization in the ditching region was not detected by a modified Huey test of a thin ring cut from the metallographic section.
(12) Microhardness readings that convert to 89-95 RB were obtained under the groove, midwall, and near the ID surface. Higher microhardness readings (converting to R C~24) were obtained on subsequent grinding, but these were nearer the tips of the main crack where plastic deformation had occurred. The hardness values were approximately equal near the groove and near the ID and were lowest in the midwall region.
Above the main crack, an SEM study of the surface within the groove revealed a network of fine cracks that consisted of intersecting axial and l O
'J circumferential cracks. Some axial cracks changed direction by about 90' and then reverted to axial. This suggests a relatively uniform biaxial residual stress pattern in the surface regions of the groove with dominant stresses that were both axial and circumferential.
A U
9221M:1E-050389 g4
A 7-1/2 in. long tube section below the main crack was.used for. tensile
.Q property determinations. The observed tensile properties were:
YS .= 65.4 KSI UTS ='108.6 KSI RA = 34.3%
El = 20% within gage marks *
, The sample broke outside the gage marks where OD cracking opened l during the pull.
The yield and ultimate are normal for a relatively low temperature mill anneal in Alloy 600 and are close to the mill certification values for this tube heat.
Ring. specimens near the fracture and near the top of the tubesheet, well away from the fracture, are being characterized for residual stresses by X-ray diffraction line broadening techniques. Preliminary results for the specimen near-the main crack indicate relatively high residual tensile stresses under the groove for both hoop and longitudinal stress. The reported values are near the observed yield strength or above it. Additional quantification of the residual stresses and their distribution -
in progress.
SEM fractography of the main crack revealed only intermittent narrow shear lips adjacent to the ID surface. Approximately 50% of the axial extent of the main fracture contained no detectable shear (less than several grains) at the ID.- Most.of the narrow shear lips, when present, appeared new (essentially bare metal). One shear lip near the lower surface of the 20th plate appeared
[ to be covered with a thin deposit. All of the shear lips exhibit normal dimple rupture ductile fracture features.
The SEM-EDS analyses of the fracture face and adjacent OD surfaces did not reveal the presence of scale forming elements such as Ca or Si. Elements that can be associated with environments leading to stress corrosion cracking were also absent in the analyses. In particular, no Na, S, or Pb was detected.
The EDS results are consistent with well maintained AVT that was free of condenser in-leakage species or resin throw materials.
9221M:1E-050389 6-5 I
i
6.2 TUBE SG B R13C34 CL EXAMINATION This tube was removed in 7 sections that extended from near the bottom of the tubesheet through the 14th support plate. Figure 6-3 is a schematic of the c as-received sections. Prominent on the tube was a deep axial scratch I
( extending from the bottom end upward through the tubesheet to 10 1/2 in. above the top of the tube sheet. Other shorter axial scratches were present between plates 17 and 18 and between plates 14 and 15. Cracking was not detected by radiography or laboratory ECT.
O A ring section at the deepest scratch region was cut and bent to open the scratch. No cracking was observed. Three lengths were burst pressure tested.
The burst pressures, in excess of 12 KSI, were typical of undegraded tubing.
The burst fractures exhibited standard fishmouthed ductility, and no OD stress corrosion cracks were opened up by the burst deformation process.
The surfaces of tube SG B R13C34 CL also exhibited a Cr-rich oxide-like deposit approximately 1 micron deep all around the circumference of the tube.
( This tube is from the same heat of Alloy 600 as tube SG B R18C25 CL.
6.3 TUBE SG B R19C24 CL EXAMINATION This tube has been dimensionally characterized and subjected to NDE. No cracks have been identified. Additional work on R19C24 will be developed as indicated by the results of the first two tubes.
O .
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I l
7.0 REVIEW 0F OPERATING CHEMISTRY EXPERIENCE O '7.1 OPERATING CHEMISTRY DATA During the operating period, 1-1-86 to 3-7-89, McGuire Unit 1 had excellent !
secondary chemistry as indicated by a statistical review of pertinent chemistry parameters. Attachment 1 summarizes chemistry data for key
]
parameters from 1986 to 1989, including steam generator cation conductivity, l steam generator sodium, steam generator chloride, steam generator sulfate and .i condensate dissolved oxygen. l i
1 Attachment 2 summarizes chemistry data for the 1981 to 1985 operating period.
While contaminant levels were not as low during the early years of operation as at present, the values are well within the current recommend guideline values.
7.2 SECONDARY CHEMISTRY EXCURSIONS A review of secondary chemistry excursions over the 1/1/86 to 3/7/89 review period indicates that McGuire Unit 1 had few significant problems.
Attachment-3 lists the secondary chemistry excursions that occurred during j
.these periods. These excursions are grouped by severity in accordance with Action Level 1, 2, and 3 of the EPRI PWR Secondary Chemistry Guidelines.
McGuire Unit I had three Action Level 2 chemistry excursions and no Action l Level 3 chemistry excursions during these periods. The first Action Level 2 excursion was caused by a condenser leak in September 1986. The unit was at )
50% power at the time, and power was subsequently reduced to 10% to minimize hideout.
The second and third Action Level 2 excursions during this period were caused by plant heating converter tube leaks in February 1987 and February 1988 that allowed sodium nitrite corrosion inhibitor to contaminate the condensate storage tank. In each case the unit was at 100% power at the time, and power was subsequently reduced to 33% and 28% for each of the events, respectively, to minimize hideout.
9221M:1E-050489 ,
7,y
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - _ _ _ - _ _ _ _ _ _ _ J
l
,m 7.3 STEAM GENERATOR WET LAYUP
!v)
A review of steam generator wet layup data for outages of one week or longer at cold shutdown conditions indicates that wet layup conditions were effectively implemented during each of these outages. The following
/c\
V summarizes these outages and wet layup implementation for each during the 1/1/86 to 3/7/89 review period.
,- Outage Start Date of 5-16-86
() All Four Steam Generators in Wet Layup by 5-17-86 Outage Start Date of 10-29-86 All Four Steam Generators in Wet Layup by 11-1-86 ,
Outage Start Date of 9-3-87 All Four Steam Generators in Wet Layup by 9-6-87 1
Outage Start Date of 10-11-88
( All Four Steam Generators in Wet Layup 10-14-88 L.
During the 10-86 and 10-88 outages, the steam generators were sludge lanced.
This required the steam generators to be drained while sludge lancing was performed. However, for both outages, the steam generators were returned to wet layup conditions after sludge lancing was completed.
A review of the operating chemistry data prior to 1986 indicates that the unit operated with a good secondary chemistry since initial startup. Although (n.
t contaminant levels in the early years of operation were not as low as they are now, they were well within the current guideline values in EPRI "PWR Secondary Water Chemistry Guidelines, Revision 2".
7.4 STEAM GENERATOR HIDE 0UT RETURN DATA (v)
During refueling outage shutdowns, the steam generators are soaked at approximately 350*F to promote hideout return. For each of the three McGuire b;
U Unit 1 refueling outage shutdowns that occurred during the subject review 9221 M:1 E-050389 7_g
l l l i
period, chemistry data was taken during the cooldown and soak period to assess j O hideout return. l Generally, hideout return data from the McGuire station indicate alkaline crevice conditions when analyzed using EPRI's MULTEQ equilibrium chemistry iq computer model. The crevice alkalinity predicted by MULTEQ depends on the 1
assumptions made regarding the influence of precipitates on crevice chemistry (i.e., whether the precipitates that are formed remain in contact with the crevice liquid or are continuously removed).
L For the three refueling outage shutdowns during the subject review period, the first two (1986 and 1987) were characterized by relatively small quantities of hideout return. MULTEQ analysis of the hideout return data indicated that crevice solutions had the potential to be moderately alkaline.
During the most recent shutdown (1988), an increase in the amount of hideout return was observed for most contaminants, particularly sulfate. This increase in hideout return is believed to be due to the ingress of filtered water into the demineralized water header over an extended period of time at levels that were too low to detect with normal sampling. This problem was corrected in August 1988 after it had worsened to the point of measurable impact on steam generator chemistry. The increase in sulfate in the hideout return resulted in the prediction of less alkaline crevice conditions compared to the two previous shutdowns, as the MULTEQ analysis indicated the likelihood of slightly alkaline conditions for this data.
7.5 CONCLUSION
S O A review of chemistry data covering the past three fuel cycles indicates that McGuire Unit 1 has had generally excellent secondary chemistry during this period. From the review of operating chemistry data, chemistry excursion data, and wet layup data, there were no significant concerns identified which would suggest that secondary chemistry might have promoted a corrosion condition in the McGuire IB steam generator, notwithstanding the fact that the hideout return data for McGuire Unit 1 indicated the formation of alkaline O
9221M 1E-050389 7-3
crevice conditions. However, if chemical attack from alkaline crevice conditions were occurring it would be expected to be most prevalent in flow restricted areas on the hot leg.
O O
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9221M;1E-050389 j_4
i
- TABLE 7-1 MCGUIRE UNIT 1 SECONDARY CHEMISTRY DATA
SUMMARY
BYYEAR(1986-1989)(1)
Parameter 1986- 1987 1988_ 1989(2) Guidelines (3)
Cat. Cond. (umho/cm) .183 .163 .157 .158 0.8 Sodium (ppb) 2.6 2.7 2.2 2.3 5 20-Chloride (ppb) 1.6 '1.6 1.7 1.2 5 20 Sulfate (ppb).- 2.9 1.5 2.0 1.4 5 20 HW 00 (ppb) 3.1 1.8 1.1 2.0 <5 CPI (4)- .178 .135 .120 .129 l
Notesi (1) Pertinent chemistry data as reported to INP0.
Data represents the average of daily maximum values for > 30%
power operation.
(2) McGuire Unit 1 1989 data for the period 1-1-89 to 3-7-89. -
(3) EPRI guidelines for secondary chemistry (blowdown).
(4) INPO Chemistry Performance Index !
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U- TABLE 7-3 i
MCGUIRE UNIT 1 SECONDARY CHEMISTRY EXCURSIONS FOR THE SUBJECT REVIEW PERIOD (1986-1989) (1)
,_ Minor Chemistry Excursions (Action Level 1)
Date' Parameter Max. Value Duration Cause 04/16/86 Sulfate 23 ppb 5.0 hrs Startup 09/14/86 Cat. Cond. 1.0 umhos 5.5 hrs Startup 09/26/86 Sulfate 28 ppb 4.7 hrs Startup 11/16/87 Cat. Cond. 1.2 umhos 1.3 hrs Startup 11/17/87 Chloride 21 ppb 1.2 hrs Startup 11/20/87 Sulfate 21 ppb 1.6 hrs Startup 11/20/87 Sodium 25 ppb 2.3 hrs Startup 01/20/88 Chloride 22 ppb 3.7 hrs Polishers (2) 06/21/88 Sodium 30 ppb 3.2 hrs Startup 07/04/88 Sulfate 21 ppb 2.2 hrs Load Follow 08/25/88 Sodium 23 ppb 3.5 hrs YM Contamination (3)
Moderate Chemistry Excursions (Action Level 2)
Date Parameter Max. Value Duration Cause 09/16/86 Cat. Cond. 5.3 umhos 15.2 hrs Condenser Leak 09/16/86 Sodium 480 ppb 8.0 hrs Condenser Leak 09/16/86 Sulfate 202 ppb 23.3 hrs Condenser Leak 09/16/86 Chloride >20 ppb 8.0 hrs Condenser Leak 02/17/87 Sodium 160 ppb 12.0 hrs YHHxTubeLeak(4) 02/02/88 Sodium 125 ppb 24.2 hrs YH Hx Tube Leak (4)
Severe Chemistry Excursions (Action Level 3)
NONE Notes: (1) Pertinent steam generator chemistry parameters per the EPRI Secondary Chemistry Guidelines for Mode 1 operation.
/^ (2) Leachable chloride from powdered resin upon valving condensate T polisher vessel in service.
(3) Filtered water ingress into demineralized water (YM) header.
(4) Plant heating converter (YH) tube leak resulting in contamination of condensate storage tank with sodium nitrite corrosion inhibitor.
O 9221M;1E-050389 7-7
8.0 THERMAL AND HYDRAULIC ENVIRONMENT O This section presents the results of a thermal and hydraulic analysis of the flow field on the secondary side of the steam generator using the ATH0S three
, dimensional computer code. The major results of the analysis are the void fraction, density, water / steam velocity components and the primary and secondary fluid and wall temperatures. The velocity and density results from the ATH0S model were used as input to the vibration analysis performed to guide the stabilization of the tube remnants remaining following the pulling of these segments for examination.
8.1 MCGUIRE UNIT 1 STEAM GENERATOR OPERATING CONDITIONS Typical steam generator operating conditions for the McGuire steam generators were used as a basis for the ATH0S model. With these data, calculations were performed using the Westinghouse steam generator performance code, GEND3, to verify the plant data and to establish a co.tplete list of operating conditions required for the ATH0S analysis. The GEND3 code determines the primary side temperatures and steam flow rate required to obtain the specified steam pressure at the given power rating. In addition to confirming these parameters, the code calculates the circulation ratio which is used to ;
determine the total bundle flow rate and the average loading on the tubes. i 8.2 ATH05 RESULTS 1
The results of the ATHOS analysis consist of the thermal and hydraulic flow parameters necessary to describe the 3-D flow field on the secondary side of the steam generator clus the distributions of the primary fluid and mean tube wall temperatures. Since the velocity components computed by ATH0S are defined on the surfaces of a flow cell, the tube gap velocity and density distributions along a particular tube required for tube vibration evaluation are determined by a post processor from the ATHOS output.
The cases of open baffle plate crevices and closed baffle plate crevices were considered for the model.
O 9221 M.1 E-050389 g.y
1 8.2.1 Baffle Crevices Open Tube R18C25 is in a region where the resultant horizontal velocity component just below Baffle Plate 20 is less than 1.0 fps. The vertical velocity components below Plate 20, at the location of R18C25, is less than 0.1 fps.
bl The void fraction at the location of tube R18C25 is zero both above and below Baffle Plate 20.
, The tube wall temperature at this location, ~560'F, is high enough that low level boiling is present at the tube surface. However, the bulk water is subcooled so that bubbles, formed on the surface, collapse immediately. For this case, open crevices, significant chemical concentration is highly unlikely.
The conditions at tube R13C34, which has also been pulled for examination, are very similar to those at R18C25.
8.2.2 Baffle Crevices Closed The vertical velocity components both above and below Plate 20, at the location of R18C25, are less than 0.1 fps. The void fraction at the location of tube R18C25 is greater than zero below Baffle Plate 20 and zero above Plate
- 20. The ATHOS code is not able to accurately predict the void fraction in regions such as this, where the velocity is low relative to the bubble rise velocity. However, the significant point is that the code predicts that the saturation temperature has been reached and that the vapor formed is not condensed in the bulk fluid. The code's ability to perform this calculation
/ is not restricted by being a single fluid code.
Although the bubbles formed in this region are not condensed, the void fraction is low. The velocity, however, is low enough that bubble rise may r result in a concentration of vapor beneath the baffle plate. Such an accumulation could have a higher void fraction than that predicted by the code. Even in this circumstance, however, significant chemical concentration is unlikely. The conditions at tube R13C34, which has also been pulled for O
9221M 1E-050389 8-2
examination, are similar to those at R18C25 for this case, also. The greatest difference is that the void fraction beneath plate 20 would be somewhat greater at R13C34. This higher void fraction is insufficient to cause {
significant chemical concentration.
O O
O O
1 O
O 9221M.1E-050389 8-3
a 0 MECHANISM LEADING TO RUPTURE OF R18C25 tO V
9.1 OD SCC IN PWR STEAM GENERATORS The incidence of secondary side SCC in PWR steam generators has been
() correlated with regions in the tube bundles subject to local flow restriction and with temperature and available superheat. Thus an overwhelming proportion of OD cracking has occurred on the hot-leg portion of the tube bundle.
f- Cracking was observed in the tubesheet crevices of early model SG's, within sludge / scale deposit zones on the tubesheet, and above and in support plato crevices. The incidence of support pla n cracking tends to diminish as the distanco fmm the hot-leg inlet increases. This effect of temperature dependence is consistent with the well-known behavior of Alloy 600; i.e., SCC initiation and propagation in Alloy 600 increases with increasing temperature. Thus the paucity of cold-leg secondary side SCC in PWR steam generators is not unexpccted.
The existence of intergranular corrosion on the cold-leg has been confirmed in support plate crevices, and recent experience suggests that OD SCC has occurred in expansion transitions at the top of the tubesheet on the cold-leg. In all these cases, it is believed that aggressive solutions of contaminants had accumulated in restricted flow zones such as crevices and sludge piles. In the absence of such a contaminant solution, concentrated by boiling in low flow regions, SCC is regarded as a low probability event at nominal stress levels.
Instances of hot leg OD SCC in Model D steam generators have been confirmed by tube pulls at a number of foreign units. Cracking was observed in a foreign plant in 1985 in the sludge zone above the hot-leg tubesheet. Cracking observations, noted in 1988, in another foreign plant with D3 SG's were concentrated in sludge and scale deposits in the lower hot-leg portion of the tube bundle, in the sludge piles and at the elevation of the flow distribution baffle. Cracking was also found in a foreign plant in a hot-leg support plate crevice location during 1988. Eddy current indications of apparent SCC in O
9221M 1E-050389 g,y
I hot-leg support plate crevices have also been observed in three other foreign
, pl ants . Confirmatory tube exams are in progress. No evidence for cold-leg OD
( SCC in Model D SG's has been encountered to date, outside of the current l McGuire 1 event.
f i
,C Considering the general industry experience with OD SCC and the enumerated i examples from other Model D steam generators, it is apparent that all prior events fall within the conventional scenario for secondary side corrosion.
Cracking is observed in regions of the tube bundles where concentration of f
I contaminants is most likely. Furthermore, in these cases, reviews of the secondary side chemistry record for operating periods preceding the observation of the cracking showed strong correlation with contaminant ingress. Specific environmental circumstances, such as sodium throw from condensate polishers, excess air inleakage, or frequent condenser tube leakage, have been shown to be directly related to steam generator chemistry conditions which supported the occurrence of cracking.
The absence of notable chemistry upsets at McGuire 1 relates well with the
- hot-leg corrosion experience, i.e., no OD SCC, and suggests strongly that no k continuing contaminant source contributes to the observed cold leg event. The uniqueness of the McGuire 1 cracking event suggests strongly that this event has its roots in factors unrelated to abnormal operating chemistry conditions.
9.2 GENERAL ASPECTS OF RUPTURED TUBE R18C25 Tube R18C25 ruptured under normal operating differential pressure due to initiation, growth, and eventual coalescence of a series of closely spaced axial and circumferential intergranular stress corrosion cracks. The multiple
( co-linear axial cracks and relatively uniform growth led to the long crack that penetrated the tube wall in only a few locations. Ligaments between axial and circumferential crack segments existed along with a thin ID ligament over a substantial portion of the total crack length. Rupture occurred when stress Qcorrosion crack growth led to a total ligament area that was insufficient to withstand the differential pressure across the tube wall. The required ligament area is equivalent to a 0.007 inch ID ligament of uncracked material along the full length of the crack. Ductile overload of this ligament led to 9-2
an opening crack area essentially equal to the cross-sectional area of the f
- ^'s tube. The estimated leak rate is consistent with the crack opening area. The i
(/ process of multiple crack initiation, growth, partial coalescence and final ductile overload of the small remaining ligament is entirely consistent with the leak rate history of the plant, the tube fracture appearance, and strength
. ];
calculations.
/
9.3 STRESS CORR 0SION CONSIDERATIONS
[^') Multiple axial crack initiation sites are clearly evident in a free span region d of tube R18C25. In addition short, partial through wall circumferential cracks appear between axial crack segments. The appearance of a free span stress corrosion crack in the absence of a sludge pile or heavy tube wall deposits is unique to tube R18C25 when compared to the many miles of mill annealed Alloy 600 tubing in service. The familiar requirements of environment, susceptible material and sufficient stress for the occurrence of stress corrosion cracking lead to the following considerations.
l
/"N 9. 3 .1 Bulk Chemical Environment '
\v ]
The free span crack location which is free of heavy deposits makes it difficult to formulate any credible scenario which produces an aggressive environment by concentration of the chemical species in the bulk secondary side water. As transient .,econdary side water chemistry excursions have not been noted for McGuire 1, a normal secondary bulk water chemistry must be assumed as the main environment of interest. There is extensive experience with stress corrosion cracking in bulk primary water but, as noted above, the McGuire I secondary side free span cracking is unique. Lithium, boron and hydrogen addition to p)primarywateraddtoitsaggressivenessinstresscorrosioncracking.
, The absence of these additions to secondary water makes it less aggressive than primary water, even when chemical species which might mitigate the difference r N niaggressiveness of secondary water are considered.
( )
/
9.3.2 Material Susceptibility to SCC r
{h) Tuber 18C25hasafinegrainsize,ayieldstrengthinthevicinityof60ksi
" and a carbon level of 0.04%. These values are within the bounds of normal 9-3
- mill annealed Alloy 600 tubing. The grain size, strength and carbon level of
, this material make it a likely candidate for primary water stress corrosion cracking compared to lower strength, lower carbo.. level tubing. There is no abnormality in the microstructure of tube R18C25. It should also be noted that the 00 surface of mill annealed Alloy 600 tubing is more resistant to SCC than the ID surface as indicated by recent laboratory tests.
In terms of material susceptibility to stress corrosion cracking, tube R18C25 is a likely candidate to crack, but within the usual range of properties of mill annealed Alloy 600 tubing.
9.3.3 Mechanical Loading and Temperature Effects Service experience and laboratory tests nave demonstrated the importance of temperature in primary water stress corrosion cracking. Activation energies !
range from 20 to 70 kcal/ mole, with a typically assumed value of 45 !
kcal/ mole. Extensive eddy current testing by Duke Power shows that primary side hot leg indications precede cold leg indication by about a factor of four. However, hot leg primary water stress corrosion cracking is only observed in very highly stressed areas of general plastic deformation such as U-bend tangent points, rull transitions, dented tube support plate ;
intersections, roll overlaps and skip rolls. After 7 calendar years of operation one can expect to see cold leg indications in these areas begin to develop. However a very shallow, less than 0.001 inch deep, scratch on the i surface of a tube is not the mechanical equivalent of a skip roll. Cracking at a scratch in the less severe bulk secondary side water is not a reasonable expectation. Furthermore, any arguments for the sole sufficiency of scratches as crack initiation sites would predict the occurrence of hot leg free span cracking on both the primary and secondary sides years in advance of cold leg cracking. Obviously this is not the case. Scratching can produce localized deformation and tensile residual stress as evidenced by X ray residual stress measurements and metallography results on tube R18C25. Surface residual stresses have been observed to be somewhat less than the tube yield strength.
Metallography results indicate that severely deformed grains are present only sporadically and only then up to a depth of two grains. The presence of a very localized deformed region would also produce an occasional sporadically i 9221M:1E-050389 g4
,q high X-ray residual stress reading. In summary, the presence of a scratch V must be considered as a necessary but not sufficient cause of the long, cold leg, free span cracking of tube R18C25. Tne scratch provides for a long series of colinear, axial crack initiation sites, a disturbance of the polished 00 tube surface and some degree of stress elevation.
b 9.3.4 Additional Crack Initiation Considerations
,-q Since the scratch on tube R18C25 is considered a necessary but not sufficient V cause for the initiation of cracking in bulk secondary side water, another variable must be considered.
The presence of both axial and circumferential crack initiation sites indicates that an aggressive environment led to crack initiation. As the environment becomes more aggressive, stress becomes less important. Since a concentration mechanism is unreasonable in the free span, one is left with the postulate of a contaminant on the tube surface at the scratch location at the start of operation. As this contaminant must wash away with continued operation, it could only be expected to facilitate crack initiation.
i Before proceeding to a discussion of crack growth rates, soluble aqueous species that are known to produce discrete intergranular stress corrosion cracks (SCC) in mill annealed Alloy 600 are considered. Caustic and acid sulfate are known accelerators of cracking. Caustic can sometimes also produce intergranular attack (IGA), none of which existed on Tube R18C25.
Caustic attack would be expected to proceed at 560*F at about 35% of the 600*F rate from Arrhenius rate considerations using activatien energies of 20 to 30 O
Q kcal/ mole for 10% Na0H. No hot leg OD SCC has been reported for McGuire Unit 1. This is inconsistent with the possible development and persistence of a, caustic environment that led to OD SCC in the cold leg only. Furthermore, only Tube R18C25 was degraded: caustic and/or acid sulfate excursions would be expected to degrade more than one tube. Sulfate has been shown in 630 F tests to be aggressive at pH 3 (a solution of sodium sulfate and sulfuric acid) (Reference 9-1). Such an acidic condition would be expected to cause general corrosion of the carbon steel support plates. There is no evidence for general corrosion. Sulfate solutions of high pH do not induce SCC in mill 9221 M 1 E-050389 9-5 L--____--__-
g annealed Alloy 600. Neither sodium nor sulfur X-rays were detected in the EDS CI analyses of deposits on tube R18C25. The absence of these elements is not proof of a historical absence of either sodium hydroxide or sodium sulfate because of the soluble nature of these species, but the development of a bulk
, caustic or an acid sulfate condition that led to SCC in tube R18C25 is highly V unlikely.
The element lead or its compounds can also induce intergranular, g trarsgranular, or mixed SCC in mill annealed Alloy 600 in high-temperature V water. The absence of transgranular SCC on tube R18C25 is not proof that lead was absent. Lead was not detected by EDS in the McGuire tube deposits, in contrast to analyses of a service exposed tube with both trans- and intergranular lead induced cracking (Reference 9-2). Furthermore, laboratory studies of lead-induced SCC have been at 600'F or above, not 560*F. The current understanding of lead-induced SCC of Alloy 600 does not permit dismissal of a possible role of lead in initiating the McGuire tube degradation. However, extensive evaluation has not revealed any definitive chemical evidence for a start of life contaminant on tube R18C25.
U While definitive chemical evidence for a start of life contaminant on tube R18C25 has not been found, a number of other factors provide good arguments for this position. These factors are:
o The relatively low mechanical loading severity of tube R18C25 requires some type of aggressive environment for crack initiation to occur. The exposure time and temperature, in only bulk secondary water, is not sufficient to cause crack initiation, o The presence of both axial and circumferential crack initiation sites indicates the action of an aggressive environment. As the environment becomes more aggressive, stress becomes less important.
o There is no credible chemical concentration mechanism for the free span crack location.
O 9221 M.1 E-050389 gg
,q o There is no evidence of any other similar instances of cracking which C would indicate a general condition.
o McGuire Unit I has a good secondary side chemistry record free of g transient aggressive conditions.
V The factors may be summarized in the argument that an aggressive environment is needed for crack initiation. A general aggressive environment is not credible and therefore a local contaminant must be assumed, p
b 9.3.5 Crack Growth Rates After crack initiation due to the combined action of the scratch and a local start of life contaminant, growth must proceed due to the action of bulk secondary side water. There is no published data on rates of growth of stress corrosion cracks in secondary water. There is some laboratory data on crack growth rates of Alloy 600 in primary water and in pure water at high temperatures. The temperature dependence of crack growth rates leads to an Q activation energy of 33 kcal/ mole. The most relevant data on crack growth rates is actual service data on cracks in roll transitions in European steam generators. In Europe cracks are allowed to remain in service until reaching some size limit. Crack growth is followed by periodic RPC inspections. At a service temperature of 610'F crack growth rates are in the range of 4 to 6 mils per month. Using a temperature correction based on an activation energy of 33 kcal/ mole leads to a conservative cold leg growth rate prediction of 1.5 to 1.0 mils / month. Assuming start of life crack initiation in tube R18C25 due to a contaminant on the tube and subsequent growth through the wall in 61
( months at temperature yields a growth rate of 0.7 mils / month. Since bulk secondary water is less aggressive than primary water and the mechanical loading of tube R18C25 is much less severe than in instances of primary water cracking, the observed growth rate of 0.7 mils / month is in agreement with (O) available field and laboratory data, O
9221M:1 E-050489
.g ., 7 L ___--___ _ _ __
m 9.3.6 Cracking Mechanism Summary U
The pulled tube evidence, plant operating history, NDE inspection results and general operating experience with mill anneeled Alloy 600 steam generator tubing lead to the following explanation of SCC of tube R18C25. A contaminant on the surface of tube R18C25 at the scratch location led to crack initiatior, near start of life. Continued plant operation washed this contaminant away and subsequent crack growth occurred slowly over time under the influence of the bulk secondary side water environment. This scenario is consistent with O, cold leg cracking, no evidence of similarly cracked tubes, cracking in the free span where chemical concentration is not credible, good chemical operating history and low mechanical loading severity. Current evidence points to a unique event. Although it is possible that more than one tube is involved in a contaminant scenario, the number of possibly affected tubes must be very small. Additional Bobbin Coil and RPC inspection strongly supports this view. In addition, slow, long term crack rate behavior, which fully matches expectations from field and laboratory experience, provides for safe operation for a tube which may contain a shallow crack.
9.4 NDE CONSIDERATIONS The R18C25 tube rupture has been characterized as OD initiated intergranular SCC. The crack is observed to be confined to within a long axial
" groove-like" feature on the tube OD. A network of intergranular axial and circumferential micropenetrations linked up over a period of time (estimated to be several years), eventually rupturing when the macrocrack length exceeded the critical crack length associated with normal plant operating conditions.
Figure 9-1 shows an external view of R18C25 in the vicinity of the rupture region illustrating features described from the metallographic examination.
It shows the ruptured region of the tube that starts just above and extends below the 20th support plate (shaded region in the figure). Above the upper end of the rupture, there is a rectangular region (the " groove-like" feature mentioned in the previous paragraph) that extends upwards towards the 19th support plate. This region in cross-section has been described as exhibiting 9221M 1E-050489 g,g
mechanical upset'to a depth of approximately 1 mil over a width of 45 mils.
Within this-region, axial and circumferential microcracking to a depth of approximately 30% was observed.
Bobbin coil and rotating pancake coil data for R18C25 above the upper end of O the rupture are shown in Figures 9-2 and 9-3 respectively. Of immediate interest is the behavior of the absolute coil vertical channel starting from the iower edge of the 19th support plate on into the ruptured region of the tube. The absolute channel shows four' distinct offsets decreasing in signal O magnitude as the ruptured region of the tube is approached. The first two of these absolute offsets also have minor differential channel responses. RPC- l terrain maps for this same region of the tube is shown in Figure 9-3. At the far right one observes the large amplitude signal response from the upper edge of the crack. At the lower edge of the map, continuing upwards towards the 19th support plate from the crack signal, a much smaller amplitude linear indication with a series of four peaks is also observed. It is this region whien corresponds to the bobbin coil signals described previously. The upset groove-like feature with microcracking is believed to be a necessary precursor to further macrocrack formation and growth. Based on industry experience, it is not likely that the 30% through-wall depth microcracking is being detected by the bobbin coil or RPC, e.g., the source of the signals described previously is most likely not attributable to the microcracking. A more likely scenario is that the source of the eddy current signals observed above the ruptured region of the tube is localized changes in material electromagnetic property values which occur along the groove-like feature possibly caused by the upset condition. For instance, high residual stresses are known to be associated with this upset condition: it is well documented in the technical literature that eddy current methods are sensitive to the stress state of a material. Hence the eddy current signals that were observed ir) this precursor region above the rupture might be associated with the actual physical groove, the local stress state within the groove, or the two in combination.
Evidence of a possible precursor signal has been observed on R18C25 above the rupture area as described in a previous section in which the eddy current 9221M;1E-050389 gg
j observations on this tube were summarized. Clearly before more definitive NDE examination requirements can be specified in order to recognize a precursor p(,) condition, further metallurgical analysis on R18C25 is necessar validate this precursor signal. However, in light of this possible precursor signal, McGuire Unit 1 eddy current data are being reviewed for tubes which exhibit these signal characteristics.
Based on a review of the in-generator primary side visual examination data from the ruptured tube prior to the start of the eddy current examination, it was i
assumed that SCC was the most probable failure mechanism. Since the rupture
( occurred over some ' length of the tube, it was important to identify tubes with long axial indications. Thus, in formulating the analysis guidelines, differential channel eddy current data were to be screened for the presence of low level signals characteristic of cracking whereas the absolute channels were to be used to identify the presence of free span indications which exhibited significant length.
It should be made clear that the rupture occurred not because of a weakness in i [ eddy current inspection technology, but rather because of excessive crack k growth as a result of the tube not having been examined since the baseline inspection was conducted during 1978. This lack of more frequent inspection was justified because industry experience with cold leg free span tube wall degradation was such that the need for more frequent inspection was not warranted. Hence, the appropriate future action is to continue inspection of the cold leg side of the steam generators looking for evidence of cracking. It should be pointed out that even with the 100% examination of the McGuire Unit 1 steam generators subsequent to the tube rupture outage, only a single tube has been identified. Industry experience with SCC is such that single cracked y tubes are never encountered. Even with the concern about the reliability of bobbin coil inspection technology in detecting this kind of degradation mechanism, cracking, when present in other plants, has always been observed (qwith
) tubes. conventional This was not thebobbin coil case for the technology McGuire Unit I steamin a relatively generators. Thus large num the eddy current examination results further support an isolated tube condition.
9-10 l
l
REFERENCES I 9-1. W. M. Connor, " Summary of Westinghouse Experience with Acid Sulfate Induced SCC / IGA of Alloy 600", EPRI Contractor Meeting, Washington, DC, December 15, 1988.
9-2. K. R. Craig, "St. Lucie Unit 1 Steam Generator Condition", EPRI )
Contractor Meeting, Washington, DC, December 15, 1988. l O '
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9221M;1E-050489 9-12
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9221M:1 E-050389 g,p l
1 n 10.0 PLUGS INSTALLED IN HCGUIRE UNIT 1 STEAM GENERATORS Since June, 1988 both Westinghouse and B&W have discovered steam generator tube plugs manufactured from certain heats of Inconel 600 which exhibit increased susceptibility to pure-water stress corrosion cracking (PWSCC).
V This increased susceptibility to PWSCC occurs in heats of material where the microstructure is characterized by a lack of chromium carbide precipitation at the grain boundaries. )he potential for tube plug failure as a result of PWSCC varies with the heat of material, time in service, temperature and the V specific plug design. The following addresses the McGuire Unit 1 situation regarding tube plug concerns.
10.1 WESTINGHOUSE PLUGS 10.1.1 Introduction Several McGuire Unit 1 Steam Generator tubes are plugged with plugs of the
, Westinghouse mechanical plug design. The tubes plugged with Westinghouse !
l mechanical plugs are listed in Table 10-1. The generic information on the integrity of these plugs is found in reference 10-1 previously provided to the NRC. A summary of that information follows.
10.1.2 Discussion The potential for rapid release of the top of some Westinghouse designed mechanical tube plugs has been identified. While this is considered a low probability event, under certain conditions the release of the plug top can occur with sufficient energy to puncture the tube in which it is installed.
The tube plugs installed in the McGuire Steam Generators were evaluated for the potential for the plug top release mechanism.
The root cause of the plug top release mechanism has been determined to be PWSCC of the plug body in conjunction with certain design features of the Westinghouse mechanical plug. Evaluations of the various heats of Inconel 600 used to manufacture Westinghouse mechanical plugs revealed that Huntington 9221M:1E-050489 10-1
heats NX3962, NX4523 and NX3513 exhibited microstructural characteristics which
,A resulted in their being more susceptible to PWSCC. In particular, heats NX3962
( and NX3513 have little carbide precipitation at the grain boundaries.
A review of maintenance records indicates that no mechanical plugs installed in
/ McGuire Unit I were manufactured from heats NX3962, NX4523 or NX3513. Table
{ 10-1 lists the' heats of material used to manufacture the Westinghouse mechanical plugs currently installed in McGuire Unit 1. Archival material from those heats has been examined and tested to estimate PWSCC resistance. In all h cases, the plugs installed in McGuire Unit I have been identified as being from heats with a preferred microstructure.
Projections of potential service life based on expected materials and operating temperatures indicate that none of the currently installed Westinghouse mechanical plugs in McGuire Unit I would be expected to be susceptible to the plug top release mechanism during the remainder of the current fuel cycle.
In addition to Westinghouse mechanical plugs, a number of tubes were plugged
/ prior to the initial operation of the ur.it with Westinghouse welded plugs. The welded plugs were solid plugs welded to the end of the tube and because of the geometry are not subject to the plug top release mechanism. The tubes plugged with welded plugs are listed in Table 10-2.
10.1.3 Conclusion As stated coove, none of the Westinghouse mechanical plugs installed in McGuire Unit I were manufactured from the heats of material exhibiting increased susceptibility to PWSCC. In addition, none of the Westinghouse plugs are iOexpectedtodegradeinamannerwhichwouldadverselyaffectthepressure boundary between the primary and secondary systems during the remainder of the current fuel cycle. All currently installed Westinghouse plugs will therefore remain in service through the end of the current fuel cycle.
10-2
\
10.2 B&W PLljGS i O 10.2.1 Introduction l
In April of 1987, rolled plugs of two different heats of material were removed V from the hot leg at V. C. Summer. These plugs were removed so that the tubes could be returned to service under the P* and F* guidelines. In May of 1988 '
it was found that one of these two plugs had circumferential cracks in the
" heel" (non pressure boundary) section of the roll transition. See Figure i O 10-1. An examination of the microstructure of the cracked Inconel 600 plug revealed that the material was susceptible to Primary Water Stress Corrosion Cracking (PWSCC). This susceptibility was due to the lack of carbides at the grain boundaries. A second plug from another heat also removed from V. C.
Summer was examined and found to be free of PWSCC. This heat was found to have sufficient carbide in the grain boundaries.
B&W notified the utilities which had plugs installed in their plants from the susceptible heat, W592-1, and notified the NRC of the material problem. A plan was implemented to inspect installed plugs, to remove any plugs with cracks, to perform corrosion testing on W592-1 plug samples, and to destructively examine removed plugs. A comparison of results has shown that plugs made from W592-1 Inconel 600 may develop cracks in as short a period of time as one fuel cycle, and that eddy current techniques developed to inspect plugs can accurately detect cracks in-situ. To date, observed cracking in the field has been limited to the non pressure boundary " heel" region of the plug. Cracks in this area do not affect the primary-to-secondary sealing capability or joint strength of the plug.
10.2.2 Discussion B&W has ribbed, tapered welded, and rolled plugs that have been fabricated from the W592-1 Inconel 600 material installed into steam generators. There have been no failures of any of these plugs. There are few ribbed and taper welded plugs installed, while many rolled plugs were manufactured and installed from this heat of material.
9221 M.1E-050489 10-3
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The_following table presents the quantity of the W592-1 plugs installed at
- f McGuire Unit 1:
Total L W592-1 Plugs
- Remaining HL CL Taper Welded - -
Rolled 76 73-
- .All W592-1 plugs were installed in June, 1986.
During the October 1988 outage at McGuire Unit 1, thirty W592-1 plugs in SG D hot leg were inspected, per a' recommended plan, using B&W's rotating probe system " EDDY-360." None of these plugs had indications in the roll transition regions, although one plug had an OD indication within the effective roll area. 1 between the heel and toe trsnsition. In April of 1989, all 83 hot leg W592-l' rolled plugs were inspected by EDDY-360 at McGuire Unit 1. Of these, six had indications of circumferential cracks at the heel transition, and.one plug continued to have an OD indication between transitions. None of the plugs inspected in October of 1988 had any signs of crack growth when reinspected in April of 1989, including the plug with the OD indication. All seven plugs with eddy current indications were subsequently replaced. All W592-1 rolled plugs installed at McGuire Unit 1 have approximately two effective full power years of operation. Based on the results of previous destructive examinations of cold leg plugs and the information for tubing from operating steam generators which indicates that cracking occurs at a much slower rate in the cold leg, no inspections were performed on the cold leg plugs at this time.
O l O 9221 M:1 E-050489 10-4 l
L___ ___ -___--_ --
As part of B&W's evaluation program relating to the W592-1 plug material, all v heats of material used for plugs were examined for microstructure. During this examination, it was found that all other heats of material in use by B&W have acceptable microstructure with carbide decorated grain boundaries for ;
_g increased resistance to PWSCC. )
U 10.2,2.1 Ribbed Plug i
The rib plugs are subjected to the same amount of strain in their expanded '
( region as a rolled plug. While the rolled plug has a rather sharp transition leading into the expanded area, the ribbed plug has a gradual, tapered transition region which results in lower residual stress concentrations. The design of the plug is such that development of PWSCC would result in a leak before break. This leak would equalize pressure across the plug and not subject the plug to a missile failure.
While it is expected that the W592-1 ribbed plug would take longer to crack than the rolled plug, it is manufactured from a susceptible material and
! cannot be inspected with current NDE methods. Therefore, it is B&W's recommendation _to replace the W592-1 rib plugs during the first available outage. All rib plugs were replaced at McGuire Unit 1 in April, 1989.
10.2.2.2 Taper Welded Plug l The taper welded plug consists of a solid piece of metal which is fillet welded onto the tubesheet. By design, the plug is not subjected to the high residual stresses associated with PWSCC initiation. The size of the fillet is such that operating stresses are also minimized. McGuire Unit I has four taper plugs installed in April 1989, manufactured from a known good heat of material. Plugs manufactured from Inconel 600 with the preferred microstructure are not expected to crack due to low stresses within the plug and weld. Inspection of these plugs, performed at the time of installation, consists of a visual examination.
O 9221 M:1E-050489 10-5
10.2.2.3 Rolled Plug Of While the ribbed and taper welded plugs are not easily inspected through NDE methods, the rolled plugs lend themselves to eddy current inspections in the.
same way that a tube is inspected. Rolled plugs have also been removed from O
Q operating steam generators and destructively examined. During both the NDE and destructive examinations, some cracking has been found. All cracks noted have been in the heel roll transition region from plugs installed into the hot leg of steam generators. Eddy current inspections have been performed on plugs in the hot legs of three plats', while destructive examinations have been performed on plugs removed from the hot leg of one plant and the cold leg of two plants. The eddy current technique used during NDE of the plugs in the SG was EDDY-360. This is a B&W .ieveloped rotating pancake eddy current coil.
The results of the EDDY-360 inspection have been compared with destructive examinations on six plugs, and have been demonstrated to accurately detect and locate defects within the plug roll transition. This system has also been effective at locating defects placed in various areas of the plug during laboratory testing.
After having been installed for one fuel cycle, a W592-1 plug was removed from V. C. Summer to return tubes to service. During a metallurgical examination performed on this plug approximately one year after the plant had gone back on line it was found that the plug had circumferential cracks in its heel roll transition region. It is postulated that this plug, although the only one of its heat to be removed and destructively examined, was not the only one to have had cracks at the time of its removal. However, during the next fuel cycle, none of the other plugs made from heat W592-1 severed or became loose parts. By inspecting plugs during each outage, and removing those with indications, the plant may operate another cycle without any plug failures.
If the head of the plug would fail, however, it has been determined that the part would not challenge the safety systems of the plant and that the plug would retain its pressure boundary function.
The PWSCC in the heel transition of the installed plugs has been seen to l develop in as little as one fuel cycle. Other plugs from the same heat of lO 9221M:1E-050389 10-6
i g mtterial, in similar environments, have not cracked during three fuel cycles.
This difference in the rate of cracking can be attributed to the variability l of the microstructure of the W592-1 plug material and potential differences in residual stress resulting from the installation process.
h,m Small axial cracks were noted in the toe roll transition region during corrosion testing on W592-1 plug material. The presence of an axial crack in this region of a rolled plug would cause a small leak to develop, equalizing g the pressure across the plug. These indications are similar to axial cracks Q seen at the roll transition of tubing within steam generators which have similar geometries. Due to the similar geometry and the in-situ inspection results showing no PWSCC in the plug toe transition, it is unlikely that the plur would sever.
Cold leg plugs installed in the steam generators are expected to develop cracts at a rate approximately three to four times slower than hot leg plugs.
This is based on operating data from steam generator tubing at McGuire Unit 1. This increased time to crack in the cold leg can be attributed to the decrease in primary water temperature, which has a significant effect on
.d' cracking rates. The results of destructive examinations of the hot and cold leg plugs, installed and removed at the same time from V. C. Summer, verifies this. In this case the hot leg plugs had cracks ranging from no defects to 85% tirough-wall, 360' (five of six plugs examined had cracks), while none of the cold leg plugs (16 were examined) had cracks. The plugs had been in service for approximately 2-1/2 years.
10.2.2 Conclusions O Duke Power has initiated a program to inspect and replace all W592-1 plugs which have indications of cracking. Operating experience with roll plugs made from W592-1 material has shown that PWSCC in a plug will not propagate to a fully severed condition in one fuel cycle. Based on the 100% inspection of all hot leg plugs in April 1989, it has been established that the W592-1 plugs can re:nain in service for an additional fuel cycle. At that time, the plugs will be reinspected and/or removed. The removal of all ribbed plugs also O
9221 M:11 -050389 10-7
eliminates any questions regarding the suitability of these plugs for continued service. Thus, the B&W plugs currently installed in McGuire Unit 1 can continue to remain in service without concerns regarding plug integrity.
O O
O O
O O
9221M:1E-050389
(
l REFERENCES 10-1 WCAP 12244, Rev. 1 Steam Generator Tube Plug Integrity Summary Report, April 1989. .
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O 9221M:1E-050389 ,g
Table 10-1. Tubes Plugged with Westinghouse Mechanical Plugs O in McGuire Unit 1 Nuclear Station Steam Generators Steam Generator Tube Heat Number A R49075 NX2386 R49C44 NX2386 R49C63 NX2387 R48C58. NX1989 R49C56 NX1989 R49C59 NX1989 R49C60 NX1989 R49C61 NX1989 R49C84 NX1989 R49C55 NX1989
~C R49C40 NX1989
. Total Number of Tubes Plugged. 11
- Tube location is given in the Duke Power convention for these steam generators.
O l.
O O
9221 M:1 E-050489 10-10
I Table 10-2. Tubes Plugged with Westinghouse Welded' Plugs in McGuire Unit 1 Nuclear Station Steam Generators
-Steam Generator Tube A -RIC49-66 R2C50,C65 B RIC49-66 R2C50,C65 C RIC49-66 R2C50-C65 D RIC49-66 R2C50,C65 Total Number of Tubes Plugged 80 0 -
O 9221M:1E-050489 10-11
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~11.0 MEASURES IMPLEMENTED IN RESPONSE TO SGTR O As a result of the SGTR event a' number of follow-on activities are planned.
These activities will' address the rupture itself as well as issues related to the North Anna plug failure, They will apply to generic company programs and specifically to McGuire Unit l.
11.1' EDDY CURRENT EVALUATION The ability of the bobbin coil inspection to detect linear features, such as that present on R18C25, will be developed further. This work will use laboratory eddy current test and metallurgical data to improve the identification of potential crack precursors.
11.2 FUTURE ACTIVITIES 11.2.1 McGuire' Unit'l During.the upcoming E0C 6 refueling outage on McGuire Unit 1 two activities in addition to normal SG work are planned. First a 100% full length inspection of all steam generators using the bobbin coil technique will be conducted. The results of this inspection will'be evaluated using methodology which will include lessons learned from current ECT work, any future ECT work and laboratory analysis of the pulled tubes. Second, an RPC inspection of all B&W rolled plugs fabricated from Teledyne Heat No. W592, installed in hot legs, will be performed. Any plugs which exhibit any indication of cracking will be i removed from service.
4 11.2.2 McGuire Unit 2 l
l During the E0C5 refueling outage (July 1989) on McGuire Unit 2 three activities in addition to normal SG work are planned. First, a 100% full length insp etion of all steam generators using the bobbin coil technique will be conducted. The methodology used to evaluate the data will include all of the lessons learned from Unit 1. Second, an RPC inspection of all B&W rolled plugs O
9721 M;1 E-050389 g
fabricated from Teledyne Heat No. W592, installed in hot legs, will be
. g 3 conducted. Any plugs which exhibit any indication of cracking will be removed
( from service. Third, all B&W ribbed plugs from Teledyne Heat No. W592 will be removed from service.
' ] 11.2.3 Leak Rate Monitoring L.)
With respect to detection of steam generator tube leakage, McGuire utilizes a number of continuous radiation monitors which alarm in the control room. These
[ ] monitor the steam lines, SG blowdown lines, condenser steam air ejector and the V unit vent. In addition, at the time of the tube rupture, McGuire was adhering to an " Enhanced Leak Rate Monitoring Program" in accordance with NRC Bulletin 88-02.
An analysis of the event indicates that the condenser steam air ejector radiation monitor alarmed at essentially the same time the continuous decrease in pressurizer level was noted. The condenser steam air ejector monitor was set to alarm at approximately 2 times the current count rate or roughly when the
( 9 1eakrate doubled. The leakrate calculated 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and 30 minutes prior to the U event was 13.2 gallons per day. If any significant increase had taxen place prior to the event, the condenser steam air ejector monitor would have alarmed, and thus provided a warning of increased leakage. Since the condenser steam air ejector radiation monitor alarmed at essentially the same time the continuous decrease in pressurizer level was noted, the large increase in leakrate must have occurred almost instantaneously.
With the plugging of all tubes exhibiting EC behavior suggestive of the grooves (7,)on R18 C25Leakrate is minimized. and R13 C34 the monitoring likelihood will provide for anotice the desired repetition should there of the tube ru be a significant recurrence of tube leakage. It should be noted that in order to provide comprehensive leakrate monitoring, McGuire will continue to meet the
, m intent of the " Enhanced Leak Rate Monitoring" program outlined in NRC Bulletin !
- s s 28-02 even after all the actions required by Bulletin 88-02 have been completed.
v 11-2 i
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12.0 JUSTIFICATION FQR RETURN TO POWER The information presented in the previous sections has been used to establish a justification for return to power. Tho salient points of this information are outlined below. Based on the assessments completed as a result of the break in
[ the tube, the degradation experienced in tube R18C25 appears to be a unique case and not representative of the condition of tubes in service in the steam generators of McGuire Unit 1. As a result of this determination, the results of the assessments completed, and the remedial actions undertaken by Duke Power prior to restart, the McGuire Unit I steam generators can be operated for the k/ remainder of the fuel cycle without resulting in an unreviewed safety question.
12.1 FREQUENCY OF OCCURRENCE OF DEGRADATION Indication of cracking of the type experienced in tube R18C25 has not been found in any other tube in any location in any of the four steam generators of McGuire Unit 1. One would expect that if the cause of the degradation was widespread and affected a significant number of tubes, such cracking would have d been indicated by the current eddy current inspection in at least some fraction of tubes with the cracking. If the degradation mechanism is due to factors affecting many tubes such as operating chemistry, thermal hydraulic conditions, or material microsb ucture, it is very unlikely that one tube (R18C25) would have extensive through wall cracking while all other tubes had degradation not detectable by eddy current inspection.
Tube R13C34 which also had an installation mark on the OD surface of the tube was examined metallurgically. The tube was from the same heat of material and I, operated in a similar thermal hydraulic environment as R18C25. The examination of R13C34 found no evidence of cracking, supporting the position that the mechanism which initiated the cracking was not widespread.
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12.2 DEGRADATION GROWTH RATE As explained in previous sections of this report, the mechanism responsible for the growth of the degradation, that is stress corrosion cracking, would be expected to result in relatively slow propagation of the crack based on
,- 3 previous experience with stress corrosion cracking on the cold leg side of the
( )tubebundle. The rate of propagation can be estimated independently of a defined mechanism for initiation of the degradation. A growth rate has been assigned to the postulated continued growth for the purposes of estimating a g crack depth at the end of the current fuel cycle. The growth rate assigned is Q 0.7 r.ils (1.6% wall loss) per month. This growth rate is established in Section 9.3 of this report.
Previous experience with stress corrosion cracking in the McGuire Unit I and other steam generators has demonstrated that propagation of stress corrosion cracking has a significant temperature dependence and the rate of growth on the hot leg side of the tube bundle would be expected to be approximately a factor of four faster than for the cold leg location of the cracking in R18C25. The s absence of evidence of similar cracking on the hot leg side of the tube bundle y provides additional support for the position that the initiating condition for the degradation in R18C25 is not widespread.
12.3 EDDY CURRENT INSPECTION Correlation of eddy current data with metallographic results from Tube R13C34 demonstrates that the bobbin probe eddy current may be sensitive to tubes remaining in service which have a shallow outside surface groove. None of the tubes with extended indications suggestive of grooves were found to have
('
indications of cracking or other degradation within the groove, using the RPC probe. Nevertheless, those tubes with grooves of significant length have been removed from service. As noted in section 9.5, the estimated bobbin coil eddy current detectability limit is 50% of wall thickness at a 90% confidence level;
- Nfor a rotating pancake coil eddy current probe the estimate of detectability
\
for the same confidence level is 40% through wall. Thus, some number of cracks I with a depth of penetration smaller than the limit of detectability would be detected with lower confidence levels using a bobbin probe. Given the absence v
12-2
1 of indications of cracking of any size, widespread tube degradation of the type found in R18C25 is not considered a credible condition. Additionally, the existence of one or more tubes with degradation just below the limit of detectability would not be expected.
Rotating pancake eddy current inspection results of approximately 100 tubes in steam generator B of the same heat of material as tube R18C25 were reviewed for evidence of cracks between the top of the tubesheet and the first support plate on the hotleg and between the tubesheet and the second baffle plate on the cold leg. The results of the rotating pancake coil examination confirm the findings Ov of the bobbin probe examination supporting the determination that no tubes remain in service with indications of cracking or other tube degradation of the type found in R18C25.
A review of eddy current indications of other types of degradation extant in tubes in service found no substantial change from previous inspections. These findings support the conclusion that there is no significant widespread degradation mechanism adversely affecting the tubes in the McGuire Unit I steam l generators.
12.4 OPERATION INTERVAL DETERMINATION The maximum depth of a long crack which would meet all the analysis criteria of Regulatory Guide 1.121 has been established. The controlling value is the minimum wall thickness based on meeting a factor of safety of 3 against burst for normal operating differential pressure. The value of minimum wall is 0.015 inch. The method used to calculate the minimum wall uses lower tolerance limit material strength properties and is typical of the method used by Westinghouse for other recent determinations of minimum wall per the Reg. Guide 1.121 criteria.
I The comparison of the depth of penetration to the maximum allowable wall loss as a percentage of tube wall thickness is tabulated below and demonstrates compliance with Reg. Guide 1.121 Criteria:
12-3
L l Normal operation Accident condition
, loadinos loadinas I L
Postulated initial' depth 49% 49%
Estimated total growth
- 16% 16%
l PREDICTED DEPTH 65% 65%
l MAXIMUM ALLOWABLE WALL LOSS 65% 67%
' q f
(
- 10 months at 0.7 mils per month The value of degradation depth postulated is just below the limit of detectability value of 50% through wall and not dependent on an estimate of the depth based on an eddy current signal. Using a degradation growth rate of 0.7 (1.6% wall loss) mils per month and a postulated initial indication of 49%
through wall results in an estimated remaining wall thickness equal to or greater :han the controlling allowable wall loss at the end of the current fuel cycle.
12.5 LEAK BEFORE BREAK CONSIDERATIONS The leak before break rationale is to limit the maximum primary to secondary leak rate during normal operating conditions such that the associated crack length through which technical specification leakage occurs is less than the critical crack length corresponding to tube burst at a maximum postulated pressure condition loading (postulated Feedline Break). Thus on the basis of normal operation, unstable crack growth is not expected to occur in the unlikely event of a limiting accident.
v As noted in Section 6.1 of this report, the cracking that occurred in tube R18C25 was contained within the groove. Consequently, special attention has 12-4 0
1
\
been given to detecting scratches or grooves similar to those observed in R18C25 and R13C34. This resulted in plugging tubes which were interpreted to r i have signals with extended length even though minimal tube wall penetration was V evident. Therefore, it is expected that no tubes with detectable grooves j remain in service in the McGuire Unit I steam generators with a length that l exceeds the length that, if a single crack were to occur in this location, unstable crack growth would result during faulted condition loadings.
I
, Additionally, the use of a leak rate monitoring policy consistent with the requirements of NRC Bulletin 88-02 which emphasizes both absolute leak rate I
measurement and rate of change and includes the initiation of action prior to reaching the technical specification limit of 0.35 gpm yields additional safety margin.
12.6 CONCLUSION
The conclusions of all of the examinations and evaluations performed to consider the degradation in the R18C25 tube are consistent with the position that the stress corrosion cracking was initiated by a unique combination of
\ conditions. The results of eddy current inspections indicate that the tubes remaining in service are not likely to have degradation of the type found in R18C25. If, contrary to available evidence, a crack were to exist just below the limit of detectability and growth at the rate estimated for R18C25, then such a crack would not be predicted to exceed the maximum allowable wall loss for normal operation and postulated accident condition loads before the next refueling outage.
Based on the information outlined above, the probability or consequences of
} previously analyzed accidents, specifically tube rupture or steam line break
> would not be increased by operation of the McGuire Unit I steam generators until the next refueling outage with postulated tube degradation, below the detection limit, of the type associated with the break in tube R18C25.
Additionally any hypothetical accident as a result of such operation would be bounded by the previously analyzed tube rupture accident. The maximum 12-5 l
l
!4
. predicted' tube' degradation,would meet the allowable tube wall loss criteria in Reg. Guide 1.121 and does-not involve a significant reductic,1 in safety margin.. Thus, operation of the McGuire Unit I steam' generators for the remainder of the current fuel cycle does not represent an unreviewed safety 4
question as defined by the criteria of 10CFR50.59(a)(2).
O 12-6 4
n.