ML20059F580

Unit 1 SG Insp Rept

ML20059F580
Person / Time
Site:	Palo Verde
Issue date:	10/31/1993
From:	ARIZONA PUBLIC SERVICE CO. (FORMERLY ARIZONA NUCLEAR
To:
Shared Package
ML17310A746	List: ML17310A745 ML20059F580
References
NUDOCS 9311050007
Download: ML20059F580 (82)

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EXECUTIVE

SUMMARY

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PROBLEM DESCRIPTION AND SAFETY ASSESSMENT . . . . . ........ . .. ........ 5 j l Free Span Cracking Transportability .. . ....... ... . ..... . ... 5  ;

Circumferential Cracking . . .. . .. .. . . .... . ... ... ... 6 STEAM GENERATOR OPERATING HISTORY , . . .. ... ...... . .... . .. 7 l Steam Generator Chemistry .. . .... .... ...... ..... ,.... ....... 7 j Unit 1 Secondary Water Chemistry . . .. . .. .. ... ... .. . .. . . 7 i Chemistry Transients . . . . . . .. . . .. .. .. ..... . . ...... .. . 8 l l

Hideout Return Studies . . . . . . . ..... ... ..... .... .... ...... -8  !

Recent Secondary Chemistry Control Changes .... . .... ....... ...... 9 Summary . . .. . . .. . . . . .... . . ..... .... 9 FREE SPAN AXIAL CRACKING IN UNIT 2 . . . ... . .. .. ... .. 14 STEAM GENERATOR INSPECTION . . . . . . .. . .. ... . . 20 ROOT CAUSE CIRCUMFERENTIAL CRACKING . .. . .. . .. .. ........ 29 Scope of Mechanism . . . .. . ....... ........ ....... ... 29 inside Diameter initiated Cracks ... . . . ... .. .. .. . . ... 29 Outside Diameter Initiated Cracks . . .. .. .... . .... . 30 ,

Summary . . . . . . . . . . . . . . .. .. .. ..... . . . .. .. 32 l l 1 REGULATORY GUIDE 1.121 EVALUATION . . . . . . ..... 35 -l Structural Evaluation . . . .. . .. . . . . .. . ... . 35 . l l

l ECT and UT Results . . . . . . .. . . .. . . 37 s l

l In-Situ Pressure Test - . . . . . . .. .. .. . . ... .. . ... . 38 i Conclusion . . .... . , . .. . . ... .. . .. . . 39 )

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OPERATING PLAN . .. .. . , , . .. . ... . .......... ......... 42 j Corrective Actions .. . .. ... .. ...... .... ...... .. . .. 42 '

l Primary Water Stress Corrosion Cracking Corrective Actions . . . . ...... . . .. 42 Outside Diameter Stress Corrosion Cracking Corrective Actions . .... .... .. 42 Primary to Secondary Leak Rate Monitoring Program . .... . . .. ..... 43 i

OPERATING INTERVAL / BASIS FOR RESTART . . . .. . . .. .. . . . .. .. 58 REFERENCES . .. . .. . . .. . . . . .. 60 APPENDICES . . . ... . ... .. . . ..... .. .. . ...... 62 Industry Review . . .... . . . . . . .... 62 Steam Generator Description . .... . . ... . .. . . .. .. . . 64 Eddy Current Reports . . ... . . . ... ....., . ......... 74 I i i I

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l. EXECUTIVE

SUMMARY

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Prior to the Unit 1 fourth refueling outage, axial free span cracks in steam generator (SG) tubes were l detected in PVNGS Unit 2 during its fourth refueling outage. These axial cracks, located in the upper l

bundie, were found to be the cause of the tube rupture which forced shutdown of Unit 2. Due to the 1 complex variety of causal factors which could be transportable between the three PVNGS units, the Unit 1 SG inspection program was specifically designed to identify this degradation mechanism. Eddy current testing (ECT) in Unit 1 by both bobbin coil probe and motorized rotating pancake coil (MRPC) probe found no evidence of axial cracks in the upper bundle area which had been identified both by analysis and inspection in Unit 2. j However, the inservice eddy current inspection of the Unit 1 steam generators did identify circumferential cracking at the top of the tubesheet expansion transition region of SG 11 and SG 12. This cracking was identified with an MRPC probe and characterized as both outside diameter (OD) and inside diameter (ID)  ;

initiated. Ultrasonic testing (UT) methods were used on selected tubes to verify the ECT determination )

of their nature. In situ pressure testing was used to verify Regulatory Guide (RG) 1.121 compliance. j in addition to the circumferential cracks, ECT inspection also identified 17. axial cracks at the tubesheet I (primarily in underexpanded tubes) and 111 single volumetric indications (SVis). The axial cracks in underexpanded tubes is a well understood phenomenon associated with crevices between the outer tube )

wall and the tubesheet when tubes are either not expanded or partially expanded. SVis can be attributed to either manufacturing flaws such as burnishing marks or corrosion / wear mechanisms. They may indicate the presence of intergranular attack or pitting. The presence of six SVrs in the arc regions may indicate IGA in this area, but does not show the accelerated IGSCC axial cracking phenomenon observed in Unit 2.

The circumferential cracking mechanisms at work in Unit 1 are primary water stress corrosion cracking (PWSCC) and outside diameter stress corrosion cracking (ODSCC). PWSCC of Alloy 600 requires the simultaneous conditions of stress, a susceptible material, and a suitable environment (including l temperature). Additionally, the degradation is a function of time. Cracking is typically interganular. In l PWR SGs, high temperature primary water can cause PWSCC of Alloy 600 at locations of high residual  !

tensile stress. These areas of Alloy 600 PWSCC susceptibility are commonly located in the tubing at the top of the tube sheet, where there is a short transition section between tubing that has been expanded within the tube sheet and the remainder of the tube.

There is a known temperature effect on SCC in Alloy 600 tubing. At temperatures above approximately 500'F, PWSCC can occur in less time at constant stress levels. Failure rates as a function of temperature can be expressed by an Arrhenius relationship. Since PWSC^ is highly dependent on material properties, residual stress, and fluid temperature, preventative measures are limited to reduction in RCS temperatures (T ) and stress relieving the expansion zone. Tube sleeving is a potential repair mechanism.

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i Some corrective actions for ODSCC were previously implemented in Unit 1 and may have had a beneficial  ;

impact on ODSCC in the upper bundle. These included molar ratio control, elevated secondary system  !

pH (to reduce iron transport), and elevated hydrazine concentration. As a result of ODSCC freespan  ;

cracking in the upper bundle of Unit 2 SGs, enhanced leakage monitoring and response procedures were l 4

developed for all units. !mplementation of boric acid treatment is scheduled for the startup following the  !

, current outage (U1R4). In response to the circumferential cracking in Unit 1, sludge lancing was  ;

performed in Unit 1. Finally, all tubcs in Unit 1 with circumferential cracks will be removed from service  :

by plugging.

-l The probability and consequences of an accident previously evaluated is not increased as a result of the l circumferential cracking in Unit 1. In situ pressure tests were conducted to verify the margins of safety i

, specified in RG 1.121 were maintained. The observed crack sizes indicate RG 1.121 limits were not  !

exceeded in one cycle of operation. Therefore, there are no special restrictions placed on the Unit 1 inspection interval. l

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II. PROBLEM DESCRIPTION AND SAFETY ASSESSMENT i

Two corrosion mechanisms are addressed in this report: susceptibility of PVNGS Unit 1 SGs to free span axial cracking (similar to that which occurred in PVNGS Unit 2) and the discovery of circumferential ID and  ;

OD cracks at the top of the hot leg tubesheets of both SGs in Unit 1.  ;

I A. Free Span Cracking Transportability l l

The free span cracking phenomenon was first observed in PVNGS Unit 2 during the ECT j inspections conducted in the Spring of 1993 during the fourth refueling outage (U2R4). This  !

mechanism resulted in the rupture of a tube during power operation at the end of Cycle 4. This  !

event and the subsequent analysis is discussed in depth in the ' Unit 2 Steam Generator Tube l Rupture Analysis Report

• submitted to the NRC staff as enclosure (2) to William Conway's letter i 102-02569-WFC/JRP dated July 18.1993. Briefly, the report concluded that free span axial cracks had occurred in the upper bundle of the SGs in Unit 2 as a result of intergranular Stress  !

Corrosion Cracking (IGSCC) initiated at the outer diameter due to a combination of contributing  !

f factors including: tube-to-tube crevice formation, ridge depostis, increased sulfate ievels probably ;

due to a resin intrusion and mildly caustic crevice pH. Additional factors which played a part in some of the tubes analyzed included substandard microstructure and cold working from ,

manufacturing scratches. >

The complex synergistic effect of these causal factors did not allow the task force to conclude the f relative weights of these factors and lead to the concern that the corrosion mechanism might be transportable to Units 1 and 3. The scope of ECT inspection for U1R4 was adjusted to ensure I that if the phenomenon was at work in a manner similar to Unit 2 it would be discovered. l However, neither bobbin nor MRPC ECT methods have discovered any free span axial cracking in the Unit 1 steam generators. Slight freespan corrosion damage may be present on a small number of tubes in the form of volumetric indications in Unit 1. The lack of free spar' axial cracks is attributed to differences in chemical environments between the Units. Unit 1 is different from Unit 2 for the following reasons: there is no evidence of resin intrusion into the Unit 1 SGs, Unit 1 molar ratio control was successful in reducing crevice pH earlier in plant life than Unit 2, and Unit 1 has had more power reductions and trips over its life than Unit 2 which would promote the wetting and flushing of deposit areas minimizing the hideout of contaminant species. Factors which were present in Unit 1 include tube bowing, deposits high in the tube bundle and manufacturing burnish marks. The lack of axial cracks in Unit 1 indicates that the causal factors observed in Unit 1 alone have not produced the accelerated cracking observed in Unit 2.

Although no axial cracks were observed in Unit 1, it is understood that this phenomenon could occur if the proper combination of causal factors are permitted to develop. In order to prevent that from occurring a multi-tier approach to mitigation has been developed. This approach is set forth in the section entitled " Operating Plan.'

The free span cracking phenomenon has no safety impact on Unit 1. Based on the failure to observe any upper bundle axial cracking in Unit 1 it is concluded that the accelerated free span cracking phenomenon is not at work in Unit 1. The implementation of preventive / mitigating actions (see

• Operating Plan") further ensure that accelerated cracking will not initiate in Unit 1.

The multiple rupture of steam generator tubes during a main steam line break (MSLB) accident was analyzed as part of the Unit 2 restart effort (see Reference 13) and has predicted dose consequences well within 10CFR100 limits.

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B. Circumferential Cracking The circumferential cracking phenomenon was first observed in PVNGS Unit 1 during the ECT  :

inspections conducted during the current refueling outage (U1R4). This issue is reported for the )

first time in this document.  ;

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The circumferential cracks observed in Unit 1 occurred at the hot leg top of tubesheet initiating i from both the inside (PWSCC) and outside (ODSCC) of tubes (as determined by ECT) Both  ;

corrosion mechanisms have been observed throughout the industry, and do not represent new  ;

corrosion mechanisms. The PWSCC is primarily addressed by reduction of primary coolant temperature to take advantage of the temperature dependence shown by SCC rates. Secondary  ;

side ODSCC is addressed by changes in chemical environment as well as benefiting from j

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temperature reduction. Many of the actions which prevent free span axial c.acking have a similar effect on circumferential cracking at the tubesheei. Additional actions taken or planned to address circumferential cracking are:  ;

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. Studge lancing was conducted in both Unit 1 SGs to remove the sludge pile where corroding species can concentrate and attack the tube outer surface. ,

. Tubes with circumferential cracks will be plugged and staked 1o remove all cracked tubes  ;

from service. Sleeving, which requires Technical Specifications changes, may be used I in the future to repair circumferentially cracked tubes .

The conditions observed in Unit 1 that contribute to circumferential cracking are present in all three units, however no factors have been identified that could lead to more aggressive corrosion )

in any one unit. Analyses for Unit 1 determined that the RG 1.121 requirements are being met.

Therefore, although transportability of the circumferential cracking phenomenon from Unit 1 to Units 2 and 3 is possible it is not considered to be a significant issue.

The safety impact of this phenomenon is not significant in Unit 1 because the safety margins .

specified in RG 1.121 were maintain 3d, the use of the preventive / mitigating actions listed under

• Operating Plan

• are expected to retard the circumferential cracking, and the multiple rupture of steam generator tubes during a MSLB accident was analyzed as part of the Unit 2 restart effort (see Reference 13) and has predicted dose consequences well within 10CFR100 limits.

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Ill. STEAM GENERATOR OPERATING HISTORY A. Steam Generator Chemistry Steam generator chemistry is a primary factor affecting the rate of outer diameter stress corrosion cracking. Therefore, a review of steam generator chemistry was conducted to determine if I l

chemistry conditions could be identified that account for the lack of freespan axial cracks and the occurrence of circumferential cracks.

The chemistry control program at PVNGS was originally developed under the guidance of Combustion Engineering (Reference 10). The program's purpose was to establish specific limits for impurities in the SGs, action levels for exceeding limits, and hold points during power ascensions to ensure chemistry was satisfactority maintained. This program has been revised and enhanced to reflect developments identified in EPRI guidelines, as well as the incorporation j of lessons leamed at PVNGS and other utilities. Initially, action was taken when SG chemistry l exceeded the stated guidelines. In late 1989, an ALARA (As Low As Reasonably Achievable) philosophy was implemented in order to keep contaminant levels as low as practical. In an )

attempt to improve the chemistry in the crevice region of the SGs, this ALARA principle was later enhanced with

• min / max' chemistry control (see Figure 111-1). Min / max objectives are to minimize contaminant input into the SG, maximize the retum or removal of SG contaminants, and to mitigate the corrosive environment within the SG.

B. Unit 1 Secondary Water Chemistry Plant bulk water chemistry (daily operating chemistry parameters)was maintained in accordance l

with plant procedures, CE Owners guidelines, and EPRI guidelines. Since initial startup, all three units have operated with essentially identical chemical control programs (ammonia /hydrazine with full flow condensate polishers) and the SG bulk water chemistry data for Unit 1 was consistent with Units 2 and 3 data. In January 1993 elevated hydrazine was implemented and on April 19, 1993 the use of ethanolamine (ETA) for secondary system pH control was initiated in Unit 1. The operating parameter that best depicts the SG bulk chemistry condition is the molar ratio (the .,

equivalent ratio of sodium to chloride). Prior to 1993, the molar ratio trends for all three units  !

indicated a chronic caustic chemistry control pattem. The concentrations of sodium in SG j blowdown, while consistently within EPRI and Combustion Engineering Owner's Group (CEOG)  ;

specifications, were higher (on an equivalent weight basis) than chloride levels, l l

Despite having a common feedwater source, operational bulk water chemistry differs between SGs within a particular unit. This difference may be due to blowdown efficiency or steaming rates, j however, operational bulk water chemistry is maintained through control of blowdown flow rates. ,

Prior to March 1993, operating bulk water chemistry was monitored via the hot leg blowdown i sample point. Since then, the downcomer sample point has been used to monitor impurity levels. ,

The downcomer sample impurity concentrations are approximately a factor of two times higher i than hot leg blowdown sample concentrations (based upon recent sampling in Units 2 and 3).

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R in summary, the Unit 1 bulk water chemistry has been similar to Units 2 and 3. Recent l modifications in condensate polisher operation have resulted in improved molar ratio control. ETA pH control has demonstrated a positive reduction in iron transport from approximately three  !

pounds per SG per day to 1 pound per SG per day. Furthermore, hydrazine levels have been increased in an attempt to reduce the electrochemical potential in the SGs.

i C. Chemistry Transients 7 A review of operating chemistry data, shutdown hideout return data, and sludge sample data for Unit 1 has been conducted. This review has identified only one significant chemistry excursion.

That event, a condenser tube rupture with subsequent ionic impurity breakthrough from the  !

condensate polishers, occurred December 11,1985. During this event, SG 11 pH dropped to a low of 2.4 and SG 12 pH dropped to 2.5. The highest impurity levels recorded were: i Cation conductivity 1250 micrombos Chloride 35 ppm i Sulfate 27 ppm Sodium 14 ppm The unit was shutdown and pH was restored to normal ranges approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following initiation of the event.

1. Condenser Leaks i A condenser tube leak assessment report from August 1992 (Reference 11) discusses the Unit 1 condenser tube leak history since 1986. Other than the event noted above, Unit 1 tube leaks have been significantly below 1 gpm, with an aversge of 0.07 gpm per i event. Five different events wei:: identified between 1987 and 1989. Unit 1 has had no l tube leaks since condenser modifications were completed in May of 1989.

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2. Steam Generator Layup The layup conditions were reviewed for any impact on SG tube degradation. Unit 1 had l experienced some periods when the SGs were dry and/or without a nitrogen overpressure. Those transient layup conditions were not considered to have aggravated the SG tube condition. SG layup conditions were evaluated by Combustion Engineering (Reference 8).

D. Hideout Return Studies Hideout return data is considered the most accurate indicator of the chemistry present within SG crevices during operation and, as such, can provide insight into potential damage mechanisms.

A review of data obtained during shutdowns was conducted for the three PVNGS units to determine what, if any, differences had existed between the hideout retum characteristics of the six SGs. A total of 53 shutdown data sets covering January 1987 through March 1993 were reviewed. The complete results of this review are documented in Reference (1).

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This review of hideout return chemistry data analysis concludes that all three units have operated with caustic crevice environments. MULTEO pH predictions for four Unit 1 shutdowns prior to Septernber 1993 were between 9.7 and 10.6 (see Table 111-1). Due to corrective actions begun i in late 1992, Unit 1 crevice chemistry now appears to be in the acidic regime (MULTEO calculated i pH values of 1.7 and 2.8). This change in crevice chemistry will assist in the mitigation of free )

span ODSCC in Unit 1. l l

E. Recent Secondary Chemistry Control Changes l r

PVNGS has implemented several changes to the secondary chemistry control program. The  !

changes have included modrfications to the condenste demineralizer operating practices in order j to reduce the sodium source input into the SGs. The following policies were implemented:

. Improved resin separation techniques (January 1989)

. Reduction in anion regeneration frequencies (November 1990)

. Performance of a second cation resin regeneration in each regeneration cycle to ensure i maximum cation resin capacity is available (1992) ,

In addition, in 1992, an ovemight soak of the regenerated anion resin charge to reduce sulfate levels was implemented. Dedicated operators were assigned to the system to give greater i consistency in system operations. Finally, condensate demineralizer bypass operation is being used successfully to reduce the molar ratio.

Other changes were also initiated in 1992. Feedwater pH was optimized to >9.15 with full flow I condensate demineralizer operation to reduce iron transport. Secondary system air inleakage  ;

l was significantly reduced. In conjunction with the operational changes to reduce iron transport, 1 l feedwater iron specifications were reduced by 50% (to < 10 ppb). In late 1992, the feedwater 'j hydrazine specification was increased to > 100 ppb (from the 40-50 ppb range). This change  !

w cs made to reduce the electrochemical potential in the SG. I J

Molar ratio control was also implemented in 1992. Figure lil-2 provides trend data of Unit 1 molar ratio data back to December of 1991. The molar ratio control program is intended to maintain the  !

l sodium to chloride ratio < 1.0. The PVNGS specification was adjusted to 0.5 to 1.2 to prevent I the development of excessive acid conditions in the SG. The success of this program is evident in the reduced crevice pH values calculated following the September 1993 shutdown.

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F. Summary I

Unit 1 SG chemistry has been maintained within plant and industry guidelines. Out of i specification conditions were corrected within the time periods specified in EPRI guidelines. Prior- l to 1993 Unit 1 bulk chemistry did not significantly differ frcm Units 2 and 3. All three units had 1 l operated with caustic crevice chemistry and high levels of contaminant return from downpowers, i

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Beginning in 1993, the following improvements in chemistry control were initiated in Unit 1:

. Elevated hydrazine to reduce electrochemical potential

. ETA injection for pH control (reduced iron transport)

. Improved molar ratio control through optimization of condensate polisher operation The information above leads to the conclusion that SG bulk water chemistry has historically been similar from one unit to the next. Unit 1 differs from Unit 2 in that it is not known to have had a resin intrusion problem, and recently has operated with a lower crevice pH and reduced corrosion product transport. These factors may account for the lack of freespan axial cracks in Unit 1.

The attempt to identify chemical accelerants causing ODSCC circumferential cracking was not successful. However, the empirical dria shows a strong correlation between the location of the circumferential cracks and the sludge pile. The presence of both ID and OD cracks in this area leads to the conclusion that the insulating proporties of the sludge may be a dominant factor that causes wall temperature to drive the SCC rates on both inner and outer diameter.

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TABLE 111-1 UNIT ONE STEAM GENERATOR HIDEOUT RETURN DATA

SUMMARY

I I I I I 6Date Jan 91 Sep 91 Jan 92 Feb 92 S(pt 93 KXJTAGE T(PE ST FORCED FORCED REFUEL REFUEL lETPD 169 380l 473 500 438 l DAYS ON LINE 109 210 63 31 109 (11NAL TEMP. OF l DATA SET 110'F 350'F 257'F 317'F 338 GENFRATOR 1l 2 1l 2 1l 2 1l 2 1l 2 EPRI MULTEQ CODE PREDICTIONS DELTA B P. 32 4 16.5 16 8 23.2 37.2 22 4 29.2 19.5 25.28 34 94 ipli et DELTA B.P. 10.6 103 103 10.5 9.7 9.7 103 10.2 1.7 2.2 NEUTRAL pli 48 4.9 49 4.9 4.7 4.9 48 4.9 4.9 48 CEOG TASK $75 SPREADSHEET CALCULATED VALUES l SODIUM. gm. 13 31 26 40 $1 91 13 13 MAGNESIUM. Fm 8 15 11 15 12 12 19 18 CALCIUM, gm. 14 37 87 51 80 f.3 166 168 POTASSIUM. gm. - -

1 1 7 6 6 10 CIILORIDE, gm. 1 2 12 18 6 12 3 4

! SILICA. gm. 92 273 314 353 318 526 414 463 ISULFATE. gm. 17 41 80 113 26 39 564 379 iCAT/AN RATIO 51 2.3 3.2 '.j _

9 10.3 7.6 09 1.3 Na + K / Cl RATIO 19 23 34 3 _5 14 12 7.7 68 EQUIV. CATIONS 1.9 44 64 5.5 7.2 9.1 10.6 10.7 EQUIV. ANIONS 0.4 1.9 2 29 0.7 1.2 11 8 8 EQUIV. SILICA 1.5 4.5 5.2 5.9 5.3 B.8 69 7.7 l

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FIGURE 111-1 Min / Max Chemistry '

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IV. FREE SPAN AXIAL CRACKING IN UNIT 2 A tube rupture event in Unit 2 (March,1993) led to extensive evaluation of the failure mechanism. This evaluation in Unt! 2 included eddy current testing, tube pulls, laboratory analysis, historical review, and failure mode ana!ysis. The failure occurred in the free span area above the 08H tube support. The evidence indicated that the rupture was due to IGA 1GSCC which developed as a result of tube >o-tube l crevice formation. This crevice formed as a result of tube bowing between the tube supports. The  !

crevice, together with the consequential heat flux, led to an aggressive environment under a ridge deposit.

As a consequence, a long deep crack initiated under the ridge deposit, leading to a loss of structural integrity under normal operating conditions.

The scope of ECT inspection during the U1R4 outage was designed to ensure that if a similar problem existed in Unit 1, it would be discovered. This included an inspection of 100% of the tubing using the bobbin coil probe, a sample inspection of bobbin indications associated with the 07H through the first vertical support structures with the MRPC probe, an MRPC inspection of apprcximately 1800 tubes from the 08H support through the first vertical support encompassing the *MRPC* arc (the area where almost all of the free-span axial indications in Unit 2 were located - see Figure IV-5), and a checkerboard MRPC l

l inspection sample of approximately 500 tubes from the 08H support through the first vertical support.

Several improvements in ECT techniques and training enabled the analysts to determine the extent of bowing and ridge deposit formation. Figures IV 1 and IV-2 indicate the location of possible deposits as determined by ECT. Figures IV-3 and IV-4 indicate locations of tube bowing, a mechanism which may -

promote the formation of free span deposits. These indications of bowing and deposits are based upon ECT (MRPC) analysis and there does not appear to be a significant difference between Unit 1 and Unit i 2 in the generallocatior and number of tubes with deposits. Bowing was visually observed in Unit 2, SG 22 during U2R4. Since U2R4, ECT methods have become available to assist the analyst in detecting bowing, and this phenomenon was observed in Unit 1. Due to the lack of bowing data from U2R4, it can only be said that bowing is present in both units, but a quantitative comparison can not be made at this time. )

Upon completion of the ECT inspection program no axial indications were found in the areas inspected from the 08H to vertical support area of the steam generators. However, a review of the inspection results indicate that slight freespan corrosion damage may be present on a small number of tubes in the form of volumetric indications (refer to Table XI-5 through XI-7 in the Appendices) in the Unit 1 SGs. In SG 11, two tubes were found to have an SVI associated with linear ridge deposits. This indication was not present in earlier ECT inspections. Three tubes in SG 12 were identified as having an SVI and an associated deposit. Tube R122C101 in SG 12 was also inspected by UT examination to confirm that the SVI defect (identified by ECT) was volumetric and not SCC. The UT examination confirmed the ECT disposition of the defect. It is postulated from the NDE inspections that the indications are representative of intergranular attack (IGA) or pitting. The rate of attack by these mechanisms is significantly slower than IGSCC observed in Unit 2.

This discovery of slight corrosion refued damage in the arc region is not unexpected. The analysis performed in support of the Unit 2 SG tube rupture event indicated a region of deposit formation and contaminant concentration. The lack of significant resin intrusion and improved chemistry control could explain the difference in quantity and severity of defects found in Unit 1 as compared to those found in Unit 2. Based upon the SG inspection it is concluded that the accelerated damage mechanism found in Unit 2 is not active in Unit 1 SGs. Consequently, the basis for the transportability position taken in APS Letter 102-02585 (Reference 13) is supported by the U1R4 inspection results.

Note: The *MRPC' arc is the area of 1800 tubes included in the original MRPC scope. The

• Bobbin

• arc is a buffer region of 2000 tubes surrounding the *MRPC* arc. The data evaluated is from the OBH through the first vertical support. See Figure IV-5.

Page 14

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V. STEAM GENERATOR INSPECTION The original scope of ECT inspection for the Unit 1 founh refueling outage consisted of the following:

. An inspection of 100% of the tubing using the bobbin coil probe

. A 20 % sample of the top of the tube sheet (hot leg) and at the flow distribution baffle plate using the MRPC probe

. A sample inspection of the bobbin indications associated with the 08H through the first vertical support structure with the MRPC probe

. An MRPC inspection of approximately 1800 tubes from the 08H support through the first vertical support, referred to in this report as the *MRPC' arc, the area where almost all of the free-span axial indications in Unit 2 were located (see Figure V-1).

An MRPC inspection sample of 500 tubes from the 08H support through the first vertical support in the remainder of the SG All non-quantifiable or distorted indications detected during the bobbin coil examinations were inspected with the MRPC probe All expansion transition areas with distorted non-quantifiable signals detected during bobbin coil examinations were inspected with the MRPC probe An MRPC inspection of all No Tube Expansions (NTEs) (condition where no tube expansion exists)

The scope of eddy current analysis was subsequently expanded to include:

. An MRPC inspection of 100% of the hot leg tubesheet expansion transition area

. A 20% sample of the cold leg tubesheet expansion transition zone in SG 12 The bases of the initial scope was to perform bobbin coil inspections to provide assurance that a widespread pattern of flaws did not exist, and to perform MRPC inspections for several known issues.

These issues included inspection for tubesheet circumferential cracking noted elsewhere in the industry, inspection for lower support axial cracks noted in previous PVNGS outages, inspection for axial cracks in the area shown to be susceptible in the U2R4 outage, and inspection of a sample at high elevations to ensure defects do not exist outside the are regions (see Figure V-1).

During this inspection no axial defects were noted in the areas inspected from the 08H to vertical support area of the steam generators. A total of 7 circumferential cracks were found at the hot leg tubesheet in SG 11, and 76 circumferential cracks were found at the hot leg tubesheet in SG 12. These are the final results after expanding the ECT scope. Tubesheet maps indicating the location of a!! circumferential cracks are included as Figures V-2 and V-3.

Page 20

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Table V-1 summarizes the OD/lD nature of the circumferential cracks as determined by MRPC analysis. l TABLE V-1 l INITIATION SITE FOR CIRCUMFERENTIAL CRACKS ,

i Steam Generator 11 Steam Generator 12 i OD Initiated 2 37 l ID Initiated 5 31 OD & ID Initiated 0 8 l

Of those cracks identified as OD, all but one occurred in tubes located in the sludge pile. Figures V-4  !

and V-5 show the location and depth of the sludge pile in both SGs. An UT evaluation was undertaken to compare lengths of indications found during ECT, compare whether the indications were ID or OD l initiated, and to estimate the depth of the circumferential indications. j Due to the orientation of flaws in SG tubing, specifically axial and circumferential indications, it is  !

necessary to use variously oriented ultrasonic transducers to disposition particular flaws. An axially 1 oriented shear wave UT transducer is required to locate circumferential!y oriented cracks. Conversely, to locate axial flaws it is necessary to employ a circumferentially oriented shear wave transducer. For determination of wall thickness and location of the expansion zone, a zero degree UT transducer is used.

All eighteen of the tubes examincd by UT were analyzed using a circ / axial shear wave probe head.

Thirteen were run with a zero degree probe head. It should also be noted that the UT examination with the axially oriented transducer was used looking down.

A preliminary review of MRPC data at the hot leg tubesheet of SG 12 resutted in a selection of 17 tubes as UT candidates for circumferential crack inspection. The selection criteria included:

. Single circumferential indications greater than one inch in circumferential length.

. The summation of multiple circumferential indications in a tube is greater than 1 inch in circumferential length.

. Top of tubesheet SVis.

The UT and ECT examination results are listed in Table V 2 (for the UT sample). The depth of sludge in 1992 and 1993 at the tube location is also listed in the table.

The ID/OD comparison resulted in one tube having an indication classified as ID initiated using the UT technique and classified as OD using ECT analysis. With the ex:cption of that tube, the remaining ID/OD comparisons were consistent. The majority of the ECT data length dimensions were conservative when compared to the UT length dimensions.  ;

i One additional tube (R122C101) was examined by UT at an SVi location 0.58 inches above the batwing (as described in Section IV).

Page 21 l

The disposition of volumetric indications at PVNGS is based upon location and defect growth. All volumetric indications at support locations are considered wear and are evaluated to the established j PVNGS plugging criteria. Freespan or tubesheet volumetric indications (SVis) are evaluated separately by determining if a change is in eddy current signal has occurred over previous operating cycles. SVis  :

which have not changed are typically classified as baseline indications (BLt) or manufacturing buff marks l (MBM). Generally, BLis are ID marks whereas MBM indications are OD marks. For volumetric indications i which are freespan and/or are at the top of the tubesheet, and are considered new or changed  !

indications, PVNGS elected to plug these defects regardless of depth. Add't ionally a small number of l tubes with MBM indications were preventatively plugged if the manufacturers mark could partia!!y mask [

a future indication or was associated with a deposit in the arc region. The disposition of all SVis which j were plugged in Unit 1 are summarized in Tables Vill-1 and Vill-2. Volumetric indications associated with !

the arc regions are identified in Tables XI-5, XI-6, and XI-7 in the Appendices. ,

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I TABLE V-2 COMcAsuSON OF MRPC AND ULThASONC TEST RESULTS FOR UNIT 1 STEAM GENERATOR 12 ULT 8MSONC EDDY CURRENT (MW SLUDGE Tute t.acanon 000 Length (mches) %TW 000 t.engm (mches) Depth 92 Depm 93 Onches) (mches) 23 Se TSH O O 710 40 0 1.32 0 94 1 81 2340 TSH O O 650 90 0 0.99 0 96 1 E2 2540 TSH 00 0 3a0 45 OD D 26 1 18 1 90 0 0 643 75 0 122 35 00 TSH O O E75* 100 0 1.05 0 81 1 45 1 50" O 0 25 47 62 TSH OD 0117 33 0 1 15 0 44 1 21 O D 168 50 0 0 001 20 434st TS*4 0 0128 50 0 0 45 NA 1 87 OD C 27 54-71 1 TSH O CB64* 100 0 1 67 C 63 1 84 1 44**

M73 t TSH O O 162* 100 0 C 51 1 C7 1 B4 2 09" O D.30 0 C 43 O C.38 54 4 t TSH O 1 560* 100 0 2 01 0 90 1 52 1 96 " OD C 28 132-75 t TSH OD C 091 25 OD C 94 c.71 1 42 00 0 450 30 OD C 26 00 C 064 2S 64 75 t TSH O D215* 60 OD D.33 0 63 1 31 1 30**

49761 TSH O D 363* 90 O C 50 0 G2 1 60 l c B5" OD S'e 53 76 i TSH O O 151' SO O O 32 NA 1.36 i 1 30" OD 0 18 6477i TSH OD 0.370 75 0 0 68 D 77 1 SO 00 0 57 5178 t TSef No edcahon No mdn.a?w No 0 0 41 c.82 1 52 mdmanon OD S4 46791 TSH O C 540* 7D D 1.33 N/A 1.35 1 57 "

BS.841 TSH OD D110 20 OD 0 43 C 78 1 BS OD 0 36 OD 022 122-101 Pwi + C D6 OD 1 015 40 OD 025 NiA N, A

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VI. ROOT CAUSE CIRCUMFERENTIAL CRACKING A. Scope of Mechanism Circumferential cracking of Unit 1 steam generator tubes at the tubesheet has been detected by }

eddy current examination during the fourth refueling outage. While some axially ciriented tubesheet flaws were detected, the majority are circumferentially oriented similar to those found at other Combustion Engineering plants. The cracks are located at the hot leg top of tubesheet bundle, with the highest concentration of defects occurring in the low-velocity flow area near the center of the tube sheet. In this area, commonly referred to as the

• kidney bean' (see Figure VI-1), particles present in the secondary fluid tend to deposit and accumulate. Ultrasonic testing has confirmed that the circumferential cracks originate in some cases from the inside diameter, while I in other cases, from the outside diameter. The cracks are located slightly above the upper surface of the tube sheet, in the tube-expansion transition zone. In general, the elevation of the '

ID initiated cracks is slightly higher than the elevation for the OD cracks due to the stress pattern in the expansion transition.

B. Inside Diameter Initiated Cracks l I

Based on physical location and industry experience it was concluded that the defects initiating on the inside diameter are PWSCC. This position is supported by a lack of any primary system contaminant excursion events. PWSCC results from a combination of residual and applied ,

stresses, a susceptible microstructure, and a suitable environment. Temperature is the most  !

critical environmental factor in PWSCC, with an increase in temperature resulting in a decrease in the time to cracking (Reference 6 and 17). The driving force for PWSCC is therefore the ,

residual stresses in the tube transition zone from expanded to unexpanded, along with the high [

primary coolant temperature. j The transportabilrty of PWSCC from unit to unit, based solely upon operating primary temperature, would indicate all three units would expect to experience PWSCC in the same time frame. f Studies by Aptech Engineering and EPRI (see Figure VI-2 derived from EPRI NP-7198-S), based upon cumulative operating time, predict the onset of PWSCC after approximately four cycles of i operation. Other factors may, however, influence the initiation of PWSCC. The more sensitive the materialis to PWSCC and the higher the tube temperature due to the isolating effects of sludge  !

deposits, the more rapidly the cracking appears. Thus, the worst-case tubes would experience s PWSCC earlier than the majority of the tubes. I Flow differences which may lead to differences in sludge characteristics, such as deposit chemistry and sludge depth and extent, can vary greatly from one steam generator to the next.

The effect of different flow and sludge characteristics can have an effect on the insulating properties of the tubing and on the rate of PWSCC.

Based upon the potential differences in tubing microstructure, flow, sludge characteristics and L residual stresses, a direct correlation of PWSCC at Unit 1 cannot be readily assumed with Unit 2 or Unit 3. These factors can account for the fact that Unit 1 has demonstrated this corrosion mechanism at this time.

i Page 29

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C. Outside Diameter initiated Cracks While the degree of PWSCC is limited to the effects of stress, material microstructure and temperature, the mechanisms contributing to outside diameter circumferential cracking can be more complex. The additional contributing factors for OD cracking, as observed throughout the .

industry, include chemical aggravators such as caustic or acidic conditions, accelerators such as lead, copper and sulfur species, electrochemical potential, and the ingress of contaminants such as oxygen and polisher resins.

Circumferential and axial outside diameter cracks at the top of the tubesheet were observed at Palo Verde Unit 1. As is the case for the tubes exhibiting PWSCC, the circumferential defects are predominantly located within the hot leg kidney bean area, with the cracks originating within the '

tube expansion transition zone near the top of the tubesheet. The axial cracks were predominantly located in tubes with incomplete or nonexistent tubesheet expansion. The axial r orientation of these defects would be expected since the residual stresses of a roll transition are not present and only applied hoop stresses define the stress field.

A review of operating chemistry data, shutdown hideout return chemistry data and sludge sample data has been conducted. This review of Unit 1 chemistry has identified only one significant chemistry excursion. That event, a condenser tube rupture occurred in December of 1985. SG .

pH values dropped below 3 and chloride, sulfate, and sodium values peaked at 35 ppm,27 ppm, and 14 ppm respectively. The plant was shutdown and pH was restored to normal values within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The other units have not experienced a condenser tube rupture which resulted in

• significantly degraded chemistry conditions.

Due to the short duration of this excursion it is unlikely that this single event would account for the presence of OD cracks in Unit 1. It is more likely that the defects are slow in initiation and growth until sufficient attack has occurred to be detectable by eddy current. Based upon a historical review of operating chemistry data and hideout return chemistry data, the most likely contributor to the IGSCC is caustic crevice chemistry. During periods of full flow condensate polishing (1985 through the beginning of 1993), Palo Verde secondary water has been found to be alkaline-forming with concentration of caustic species in flow restricted areas such as steam generator crevices and under the sludge pile. The free caustic formed when feedwater ,

concentrates at the superheated tube wall can corrode the Alloy 600 tubes. The degree of .

cracking is a function of all the contributing factors outlined above. l Note that analysis of Unit 2 pulled tube samples with flow distribution plate (01H) axial cracks .'

were examined during the summer of 1993. The results confirmed classic caustic OD initiated IGSCC in the lower region of the tube bundle. l With respect to hideout return chemistry data, all three units have operated with similar chemica! ,

environments. MULTEO pH predicticas have averaged between 10.20 and 10.35 in all three units during 1991 and 1992. Prior to 1991 a formal hideout retum program was not in place however, peak concentrations of sodium, chloride and sulfate indicate similar operating conditions. Due to corrective actions begun in late 1992, Unit 1 and 3 appear to be operating with crevice chemistry which is near neutral or acidic. MULTEO analysis provides pH values less than 3.0 in .

Unit 1 (September 1993 shutdown) and less than 5 in Unit 3 (September 1993 downpower). Unit 2 crevice pH conditions are being evaluated. Based upon past operating and shutdown chemistry at all three units, the possibility exists for caustic induced IGSCC in all Palo Verde units.

i Page 30

i e

A comparison of sludge samples obtained from Unit 1 during the third refueling outage and the  !

current refueling outage (U1 R4) has not shown a likely contributor to lGSCC. Lead concentrations  !

were below the levels typically observed at other utilities which have identified lead as a contributor to ODSCC. Bugey 2 and 3 have sludge lead levels over 500 ppm (Reference 18).  !

Copper levels are well below those observed at other CE facilities with ODSCC (over 50,000 ppm -

at ANO 2 and over 100,000 ppm at SONGS 2). Sodium, sulfur and chloride levels are considered low. However these species are volatile and therefore the sludge analysis may not be  ;

representative of operating chemistry.

l TABLE VI-1 UNIT 1 SG SLUDGE ANALYSIS i Analyte U1R3 Flow U1R4 Tubesheet U1R4 Flow Distribution Plate Distribution Plate  ;

i Lead 78 ppm 98 ppm N/A  ;

Copper 106 ppm 1214 ppm 74 ppm [

+

Sodium 230 ppm 22 ppm N/A [

s Chloride 30 ppm < 9 ppm N/A Sulfur < 50 ppm as SO 3 < 9 ppm as SO, N/A j tron > 98% N/A N/A j Note: All analyses conducted during U1R3 were from a flow distribution plate sample. i The U1R4 analyses were conducted on tubesheet samples with the exception of  ;

copper which was performed on both the tubesheet and flow distribution plate j samples.

Comparing the concentration of contaminants in the sample taken from the Unit 1 tubesheet to  !

typical industry values, it does not appear that a specific aggravator in the sludge led to the {

ODSCC observed.  !

An ingress of resin has been documented for Unit 2 (Reference 1) however, there is no evidence to suggest a significant ingress of resin has pecurred in Unit 1. A secondary side inspection in Unit 2 identified resin beads on the SG can deck, howw a similar inspection in Unit 1 revealed no visual evidence of resin. Therefore, it is doubtful that resin ingress contributed to the i circumferential cracking in Unit 1.

I The extent to which elevated electrochemical potential (ECP) may have impacted the cracking is an unknown at Palo Verde, as it is at most operating plants,11 is likely that elevated ECP is not a major contributor due to 1) very low ingress of oxygen historically, 2) a large excess of hydrazine (most recently Palo Verde has complied with the 100 ppb hydrazine EPRI guideline) ,

and 3) and a nearly copper-free secondary system.

Page 31 i

i

I i

i Based upon the hot leg temperature, sludge characteristics, residual stresses, and chemical environment, the presence of OD defects at the tubesheet are not unexpected. The crack growth _ J

, rates do not indicate an accelerated condition which would result in exceeding the structural limits j of RG 1.121. )

i D. Summary ,

t The root cause effort attempted to examine the material, stress and environment in the area where i circumferential cracks were found. Metallurgical data on the cracked tubes is not available, so  !

it is speculative as to whether these tubes have a substandard microstructure that accounts for l early crack initiation. While Unit 2 metallurgical analysis showed that substandard microstructure  !

can occur, the correlation of crack location to sludge would indicate that microstructure is not the !

driving force behind circumferential cracks. Residual stress, caused by slight overexplansion at  ;

the top of tubesheet, can account for the pattern of ID cracks discovered. The chemical  !

environment in the sludge is not anomalous based upon the chemical analysis of the sludge. It is concluried that the high operating temperature at PVNGS is the primary root cause contributor l with some contribution from the presence of studge. i I -

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Predicted PWSCC at Explosive Transitions HTMA Tubing .

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Page 34

I Vll. REGULATORY GUIDE 1.121 EVALUATION l l

i NRC RG 1.121 provides the requirements for evaluating the structural integrity of degraded steam  !

generator tubing.The requirements are designed to maintain specific margins for degraded tubing against l rupture. An evaluation must be performed to ensure that the safety margins specified by the RG are not violated during the next operating cycle. The evaluation of the circumferential cracks at the top of the tubesheet in the Unit 1 steam generators was performed by demonstrating that the safety margins were maintained over the previous operating cycle and then determining that degradation during the upcoming cycle should be no worse than the previous cycle.

To determine whether the required safety margins were maintained over the previous cycle, a structural evaluation was performed to determine the maximum crack size that would be expected to meet the required safety margins. Eddy current test results were then reviewed to identify all cracks that exceeded or approached the calculated allowable crack size. These cracks were then examined by ultrasonic (UT) techniques to provide further characterization of the defects. Finally, the largest defects were in-situ pressure tested at the pressure corresponding to the required safety margins specified in RG 1.121. All the tubes tested passed the pressurization test, indicating that the required safety margins had been maintained over the previous operating cycle in Unit 1.

A. Structural Evaluation

1. Circumferential Cracks f~he tube integrity with postulated circumferential flaws was evaluated to the requirements of RG 1.121. These requirements are designed to maintain specific safety margins for  ;

degraded tubing against potential rupture during normal plant operation and postulated t accident conditions. The recommendation of RG 1.121 specify that steam generator tubes should have a safety factor against failure by bursting during normal operation of not less than 3. The specified margin for accident conditions is taken to be equal to 1.4.

I Because the flaw orientation is circumferential, the principal stress affecting tube integrity will be the axial stress resulting from the differential pressure between the primary and l secondary side of the steam generator tubing. Therefore, the axial stress will be bounded by the following loadings:

Norma! Operating Accident (MSLB) ,

Primary (psia) 2250 2400 Secondary (psia) 1u70 0 Differential Pressure (psia) 1180 2400 Safety Margin 3 1.4 Limiting Differential Pressure (psia) 3540 3360 Therefore, in order to meet the required safety margins specified in RG 1.121, the degraded tubing must be capable of withstanding a differential pressure of 3540 psid.

I Page 35  ;

i t

i l

The burst condition of e tube with a circumferential through wall flaw over some circumferential extent was determined from a net section collapse formula developed by .

Belgatom (EPRI NP-6626-SD

• Belgian Approach to Steam Generator Tube Plugging for i Primary Water Stress Corrosion Cracking") which predicts tube rupture when the local  :

axial stress reaches the materiars flow stress and considers either an unsupported tube  ;

or a tube with a lateral support such as would be provided by the flow distribution plate.

Using this correlation, the maximum allowable circumferential crack length (assuming .

100% through wall over the entire circumferential extent of the crack) can be determined as shown in Figure Vil-1. As illustrated, based on a limiting differential pressure of 3540 psi, a crack of up to approximately 280" (or 1.6 inches based on inside diameter) would '

be expected to maintain the required safety margin. This conservative approach takes no credit for partial depth crack extent or ligaments which would be expected to be present based on typical stress corrosion crack morphology. Figure Vil -1 also provides l burst pressure data for a tube with no lateral support and using classic net axial stress l area (axial force limit) methods.

2. Axial Cracks l

The integrity of tubes with OD axial cracks at the tubesheet was also evaluated to the requirements of RG 1.121. The structural analysis (Reference 1) for the Unit 2 SG tube .

rupture event was used as a basis for the evaluation. A summary of the crack length, l depth, and location is given in Tables Vil-1 and Vll-2. Based on the results of the l analysis, the maximum allowable throughwall defect is 0.787 inches in length. Where no ECT depth call was made, the depth was assumed to be 100% throughwall. The longest defect meeting this assumption was 0.66 inches in length and is bounded by the analysis.

The largest flaw with both an ECT depth and length characterization is tube R93C120 with i an 86% throughwall extent and 0.76 inches in length and is also bounded by the i structural analysis. Additionally, with one exception, the OD axial cracks found at the tubesheat were within the confines of the tubesheet structural support and would not be candidates for axial fishmouth ruptures based on the small diametrical clearance (0.004 )

inches). The defect in tube R46C35 was located at TSH+0.15 however it was only 0.17 inches in length. Finally, a single ID initiated axial defect was found within the tubesheet l (TEH + 1.51) in a tube which was expanded. The defect was 1.03 inches in length at 79%

throughwall. This defect is not considered to exceed RG 1.121 guidelines since structural integrity is maintained by the tubesheet.

3. Single Volumetric Indications The RG 1.121 structural requirements for volumetric indications are based on wall thinning analysis performed by ABB-CE for wear type defects. A 63% throughwall extent has been justified by this analysis (Reference 20), The deepest SVI sized by bobbin ECT analysis was 59% throughwall and therefore is bounded by the structural analysis.

4 Page 36 I I

B. ECT and UT Results The MRPC eddy current probe was used to size and characterize the indications. Due to the i difficulty in obtaining a reliable depth call with MRPC, only circumferential extents (lengths) were )

assigned to each defect. Consentative guidelines for determining the circumferential extent were j used to ensure the cracks were not undersized. Since depth calls were not made, all cracks were i conservatively assumed to be 100% through wall over the entire circumferential extent of the flaw.

This very conservative assumption allows direct comparison with the allowable crack size t determined in section Vll.A. The comparison identified 3 tubes which potentially exceeded or  :

approached the allowable crack size of 1.6 inches. These indications were subsequently  !

examined by UT to further characterize the defect and to obtain a measure of the crack depths.

Additionally, all tubes with circumferential indications greater than 1 inch or multiple indications with the sum of the indications greater than 1 inch were examined by UT to obtain }

characterization of all larger cracks and to provide a comparison between MRPC and UT results. i Other tubes with smaller indications were also examined for further characterization. Based on  !

this criteria, the following tubes with circumferential indications were inspected Table Vil-3 ,

SG 12 Tubes Examined by UT  ;

Row! Col MRPC Lenoth (in) Max UT Depth (%)

54/75 2.01 100 54/73 1.9* 100

• 54/71 1.67 100 35/60 1.31* 100 +

48/79 1.33 70 23/56 1.32 40 0.99 23/60 90 25/60 1.22 75 47/62 1.15 50 43/68 0.45 50 62/75 1.12* 30 64/75 0.3 60 49/76 0.5 90 53/76 0.32 50 60/77 0.57 75 51/78 0.41 N/A  ;

65/84 1.01* 20

{

Indicates summation of roultiple indications at the same axial location. Some tubes  ;

exhibit both ID and OD indications. The indications do not occur at the same axial location, therefore are not summed together.

i f

Page 37 i

t t

l

C. In-Situ Pressure Test Based on the MRPC and UT examinations, several cracks appeared to approach or exceed the conservative maximum allowable crack length of 1.6 inches and potentially did not maintain the required safety margins over the previous operating cycle. Therefore, 5 tubes were selected to be in-situ pressure tested for final determination as to whether the required safety margins had been maintained. These cracks were chosen as being the bounding, or worst case cracks, based on length or potential through wall depth. All 5 tubes were pressurized to 3900 psia, based on the limiting drfferential pressure of 3540 psi adjusted for room temperature conditions, and held for approximately 8 minutes. All 5 tubes, as tabulated below, were successfully pressure tested to 3900 psi, indicating the required safety margins against bursting were maintained.

Row / Col Pass / Fail 54/75 Pass 54/73 Pass 54/71 Pass 35/60 Pass (leak) 48/79 Pass As indicated, tube 35/60 developed a small leak during the pressurization test. This was not unexpected since the UT examination indicated potential through wall degradation over a short circumferential extent of the defect. The test was conducted by bringing the pressure up in increments and then holding pressure at 1000, 2000,3000, and 3900 psi. Tube 35/60 indicated very small leakage at the 2000 psi plateau. At 3000 psi (greater than MSLB pressure), leakage increased to approximately 16 gpd. Leakage of this small of magnitude at 3000 psi indicates the actual through wall circumferential extent of the crack to be extremely short. At 3900 psi, leakage was measured at approximately 90 gpd, essentially equal to the maximum capacity of the hydrotest pump. However, pressure was maintained at or around 3900 psi for approximately 8 minutes before the test was terminated, indicating the structural integrity of the tube was maintained. After completing the pressure test on all 5 tubes,35/60 was retested to ensure the validity of the first test. In the second test, slight leakage occurred at 1000 psi. and increased at the 2000 and 3000 psi plateaus. While attempting to raise pressure up to 3900 psi, leakage exceeded the 90 gpd capacity of the hydropump and only approximately 3500 psi was achieved.

However, pressure was maintained at 3500 psi indicating no change to the gross structural integrity of the tube. In fact, a smallincrease in leakage during a second pressure test is entirely consistent with laboratory experience with tube burst tests, wherein leakage is typically observed to occur at a lower value and at an increased rate during a second test. This is due to the tube sweFing during the first test causing a through wall crack to open slightly. Laboratory experience indicates this does not represent a decrease in the burst strength of the tube. Therefore, APS has concluded that the test data indicates successful capability to withstand 3 times normal operating pressure without bursting as required by RG 1.121. All 5 tubes were re-inspected by MRPC after completion of the in-situ pressure test. None of the tubes, including 35/60, showed any appreciable change in the eddy current signals, further evidence that the burst capability of the tubes was not exceeded.

I h

Page 38 C

D. Conclusion Based upon the assumption that in situ pressure testing was performed on the

• worst case' tubes, all the tubes with circumferential defects at the top of the tubesheet have maintained the required safety margins specified over the previous operating cycle. Accordingly, it is concluded that the safety margins will be maintained over the upcoming cycle.

The largest cracks were PWSCC-initiated ID defects. The occurrence of PWSCC is dictated primarity by temperature and stress and, accordingly, industry experience indicates a controlled rate of progression. Growth rates observed within the industry have not typically indicated a damage progression from undetectable to RG 1.121 violation in one operating cycle. Since 100%

of the hot leg tubesheet transition area has been examined by MRPC, and all tubes with a circumferential indication have been removed from service, it is expected that inspection results at the end of the next operating cycle will show a reduced progression rate in terms of size of defects discovered without any corrective actions. The mitigating actions planned should reduce the progression rate even further.

The circumferential OD indications are considered to be classical sludge pile ODSCC. These defects were typically much smaller than the largest ID indications, none of which were potential challenges to the structural integrity of the tube. Mitigative actions consisting of reduced temperature, sludge lancing, implementation of boric acid treatment, molar ratio control, and elevated secondary plant pH will be implemented during the next cycle. Since ODSCC growth rates are influenced by the sludge pile environment, these mitigative actions are expected to slow the rate of progression of this mechanism.

APS will operate Unit 1 at reduced temperature as much as practical to slow the rate of progression of PWSCC and prevent IGSCC in the upper bundle arc region. Such an adjustment will also result in a lower secondary side steam pressure and consequently a larger normal operating differential pressure. This results in a slightly smaller allowable crack size. For example, if secondary side pressure is reduced to 970 psi,3 times normal differential pressure would be increased to 3840 psi. Based on Figure Vll-1, this would reduce the allowable through wall crack from 280' to approximately 270 . This negligible decrease in allowable flaw size would be more than compensated by the expected reduction in crack growth rate associated with the temperature reduction.

Page.39 I

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TABLE Vil-1  ;

TUBESHEET AXIAL CRACKS, SG 11

[

Row Column Location Percent Call Length Through (inches) ,

wall  !

49 10 TSH-1.36 N/O MAI 0.51  !

i 54 11 TSH-0.76 52% IAAI 0.48 l

62 21 TSH-0.70 59% IAAI 0.65 27 78 TSH-0.65 58% SAI 1.00 f l 33 84 TSH + 1.51 79% sal 1.03 30 163 TSH-0.20 N/O SAI 0.19 i

56 181 TSH-0.99 N/O SAI 0.66 I TABLE Vil-2 TUBESHEET AXIAL CRACKS, SG 12 Row Column Location Percent Call Length  :

! Through (inches) I wall [

23 6 TSH-1.15 N/O MAI 0.50  !

I i 46 35 TSH + 0.15 N/O sal 0.17  !

87 72 TSH-0.83 86 % IAAI 0.53  ;

87 74 TSH-0.67 N/O IAAl 0.28 ,

28 111 TSH + 0.50 N!O SAI 0.25 93 112 TSH-0.52 N!O FAAl 0.36 89 116 TSH-0.58 N/O SAI 0.19 118 93 TSH-0.96 86% mal C.76 ,

93 126 TSH-0.56 N/O MAI 0.47 I

123 111 TSH-0.74 N/O SAI 0.35 56 181 TSH-0.99 N/O SAI 0.66 I 4

i 4

Page 40 f l

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FIGURE Vil-1 Circumferential Flaw Size Evaluation 10000 s

\ Unflawed

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3. Page 41

Vill. OPERATING PLAN A. Corrective Actions Corrective actions were based upon a conservative approach which addresses not only the observed phenomenon, but also seeks to preclude the development of the freespan cracking seen in Unit 2 and to provide mitigating actions that would minimize the impact of a tube failure. Therefore the actions presented here address circumferential cracks, freespan axial cracks, early detection of leaks and minimization of offsite dose consequences from a tube failure.

Corrective actions fall into three categories:

1. Those for mitigation of PWSCC

2. Those for mitigation of ODSCC and

3. Improvements in leak detection.

In addition to the corrective actions listed here, PVNGS will plug and stake all tubes that are identified as having circumferential cracks. Tables Vill-1 and Vill-2 provide details of the U1R4 tube plugging process.

B. Primary Water Stress Corrosion Cracking Corrective Actions

1. Temperature reduction: Unit 1 will be operated at a reduced temperature, as practical, providing mitigation of the temperature effects of PWSCC.

C. Outside Diameter Stress Corrosion Cracking Corrective Actions

1. Temperature reduction: The temperature reduction actions listed above for PWSCC also apply for ODSCC.

2. Molar ratio control: To assist in the prevention of caustic or acidic environments in crevices, molar ratio control has been implemented to promote a proper balance between cations and anions. This parameter is currently being contro!!ed via manipulation of the condensate domineralizers.

3. Reduce iron transport: The existence of sludge on the tubesheet provides a corrosive environment for ODSCC. Iron transport to the SGs is the primary source of sludge. Iron transport will continue to be minimized by maintaining an elevated pH in the steam plant.

4. Elevated hydrazine: A corrosive environment is expected to be mitigated by operating with an elevated hydrazine concentration in the secondary system. PVNGS is currently operating with the EPRI hydrazine guideline of greater than 100 ppb. This promotes a reduced electrochemical potential, thereby reducing ODSCC.

5. Sludge lance: Sludge lancing of the tubesheet was performed and a total of 67 pounds of sludge was removed from SG 11 and 68 pounds from SG 12 Page 42 e

t

6. Boric acid treatment: The unit will implement a boric acid treatment program. The purpose of boric acid treatment is to replace contaminants removed from tubesheet crevices during the sludge lance and to buffs. these crevices.

D. Primary to Secondary Leak Rate Monitoring Program

1. SG blowdown radiation monitors: The sensitivity of the SG blowdown radiation monitors was improved by selecting the downcomer (instead of the hot leg blowdown) as the monitoring point. This sample point has greater sensitivity to leakage activity.

2. Condenser vacuum exhaust monitor: The alert setpoints for the condenser vacuum i exhaust monitor was decreased to a level four times above background readings. This l new setpoint provides earlier alarms for plant operators during tube leak events.

~

3. Procedure for determining primary to secondary tube leak rate: The preferred hierarchy of leak rate calculation methods has been revised to use noble gas grab sample from the condenser vacuum exhaust for the most accurate leak rate determination. lodine in the SG bulk water may be utilized if the leak is so small noble gasses are not detected in the l' condenser vacuum exhaust grab sample. The tritium method should be used in the absence of other radionuclides. ,

4. Leak rate administration action plan: The leakage monitoring frequency will be increased on an increasing leak rate. A formal evaluation for continued operation will be conducted when a 10 gpd leak rate increases by more than 50% in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period, or a stable leak rate of 25 gpd is reached. At 50 gpd, the Shift Supervisor initiates an orderly plant shutdown, then informs plant management.

5. Modifications are currently underway to install N-16 monitors in Unit 1.

a I

Page 43

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i-TABLE Vill-1: STEAM GENERATOR l-1 l' LUGGING LIST (continued)

1. Row ~ L Column - Elevation EC193(%) ECT92(%) Connnent Crack Extent PLUG DESIGN STAKE LENGTil ,

14 '81 60 VS3 40.91 49% h9% Wrtical Strap wcar N/A H&W Rolled on llL & CL 15 125-- 64. VS5 44.16 SVI/DEP NDD SVI with dernit (not a N/A Il&W Rolled on llL & CL

ridge depnit) 16 50 75 TSil .0.15 SCI (ID) SLG PWSCC 0.44"or 76 H&W Rolled on HL & CL 48" ATTACilED AT llL 17 27 78 TSil.0.65 sal /58% NTE Axial indication in tube l#r R&W Rollalon llL & CL not fully expanded in tubesheet (NTE). Defcct contained within tubesheet 18 .51 .79 TSil .0.15 MCI (ID) SLG PWSCC 0.91"or 157" ll&W Rolled on HL & CL 48" ATTACllED ATllL 19 $2 31 TSil 0.23 SCI (ID) SLG PWSCC 0.86"or 148" ll&W Rolled on llL & CL 48" ATTACilED ATllL i 20 155 82- HW1 +L93 50% 32% Hatw mg Wrapper Har N/A ll&W Rolled on llL & CL

Wear 21 52- 8L TSil.0.08 SCI (00) S t.G Sludge plc ODSCC 0.41" at 63* 11&W Rolled on IIL & CL 48" ATTACilED Arill 22 116 - 83 HWI + 1.02 SVl/PDP NDD Several s olumetric indi. N/A Il&W Rolled on IIL & CL catium all with slight ridge deposit mdication 23 33 84' TEll + 1.51 sal /7W NDD ID deleti found withm 1 33 " H&W Rolled on llL & CL lubsheet 24 36 87 HWI +1.86 27 % (20% Stay CyImder llatwing N/A Il&W Rolled on llL & CL 3Ml" ATTACllED AT llL Wear. Per PVNGS crite.

ria defects are plugged at

> 20%

25 156 87 IlW1 +1.8 40% <2n % Ratwing Wrapper liar N/A H&W Rolled on llL & CL Wear 26 149 88 0811 +12.0 SVi/PDP NDD Several volumetric indt. N/A fl&W Rollat on HL & CL to 37.82 (4 cations all with slight seperate indi- ridge deposit indicatkm cadois) .,

hi

. it e

TABLE VIII-1: STEAM GENERATOR l-1 PLUGGING LIST (continued)

1. Row i Column Elevation ECW3(%) EC172(%) Comment Crxk Extent PLUG DESIGN STAKE LENGTII 27 55' $0 TSli -0.09 SCI 5LG/DTI PWSCC 1991 distorted 0.:lt"or 59 H&W Rolled on llL & CL 48" A1TACilED AT IIL signal may have been precursor 28 33 91 11WI-1.92 2.1 (20% Stay Cylinder llatwing N/A Il&W Rolled on llL & CL 3M7"A1TACIIED ATllL Wear 29 158 97 OIC + 1.50 PLl/36% NDD PLP w::h wear N/A H&W Rolled on ill & CL 85.5"ATTACifED AT CL 30 157 48 - CIC +1.53 l'LP NDD Tube does not nhiht N/A Il&W Rolled on ill& CL 85.5"A1TACilED AT CL wear but will h removed from service per Study 02-MS A72 31 159 93 OIC +1 Al PL1/8W NDD Asseeinted with N/A Il&W Rolled on ill & CL 85.5"ATTActIED ATCL

, R158C97 32 37 100 llW1 l.82 21% <20 Ilatwing Stay C3hnder N/A il&W Rolled on llL & CL 3M" ATTACllED ATllL

, Wear 33 35 104 IlW1 -1.96 28%- (20% llatwing Stay Cylmdct N/A Ti&W Rolled on llL A CL 379" ATTACllED ATllL Wear 3* '34 105 IlW1 +2.27 23 % NDD llatw mg Stay Cyhnder N/A Il&W Rolled on IIL & CL 376" ATTACilED AT llL Wear i

35 33 106 IlW1 -2.03 25 % NDD 13atsmg Stay Cyhnder N/A It&W Kolled on HL & CL 373" ATTACilFD AT llL Wear 36 35 106' IlW3 1.9 3 25 % NDD Stay Cylmder Hatwmg N/A R&W Rolled on llL & CL Wear- No Stake is required per Staking Guidelme 37 158 '107- ntC +32 SVl/ADR SVI based on Considered Iluff Mark N/A Il&W Rolled on ill& CL

ReReview Preventative Plugged based on severity of sig.

nal to prevent future detectability problems 38 157' 110 IlW2 1.86 41% 27 % Ilatwing Wrapper ilar N/A Il&W Rolled on llL A CL

[ Wear t

~

4

%i

..,~-.-._.,_..,-,,......,_.---_-,~~_-.-,-mm

TAllLE VIII-1: STEAM GENERATOR l-1 PLUGGING LIST (continued)

1. ~ Row' ; . Column - Elevation ECW3(O ECW2('7e) Comment Crack Extent PLUG DESIGN STAKE LENGTil 39 137' 120~. VS5 +17.12 SVl/ del' NDD Volumetric irxlication Il&W Rolled on llL & CL '

ass >ciated with a de;vsit. Dep* sit not a linear type ridge deposit 44 137 130' TSil.013 SVI (OD) NDD OD Volumetric mihca- it&W Rolled on llL & CL 48" ATTACilED AT llL tion fourxl at Tubesheet.

May be SCC precursor 41 60 131 niil +10.51 SV1 NDD UD Volumetnc indica. Il&W Rolled on llL & CL tion whk h appears to have t hanged shghtly from last inspettion '

42 83 '.134 VS 3 + 1.110 42"c 21 % Vertical Strap Wear N/A It&W Rolled on Ill & CL

, 43 97 138 IlW1 +2.85 PDP/SVI NDD Volumetric irnheation N/A Il&W Rolled on llL & CL (Iluff Mark) Since mdi-catitm is aasociaicd with PDP tube will be pre-ventatively plugged based on Unit 2 'essoris leamed 41 130 149 TSC +1..tS PI I!4Mi NDD PLP wi:h wear. Pl.P N/A Il&W Rolled on lil & CL remoch tonng iOS AR.

Therefore no uake is required 45 30 163 TSil 0.20 S AI/ETIJNill NDD Small analindication 019" 11&W Rolled on llL & CL not seen with bobbin.

Found by Ifxf5 TSil MRPC inspection 46 12- '169 TSil.0.24 SCI (OD) NDD ODSCC 0.31" or 47' il&W Rolled on ill& CL 48" A1TI AcilED1U llL ;

47 78- 169 VS3 0.80 41% 31% Vertical Strap Wear N/A Ile W RoIIed on ill & CL 48 30 17$ 0711 +16.10 SVl/DEP/ 20% SVI with Degu<it (not N/A Il& W Rolled on ill & CL  :

30% ndge deposit)

N t

TABLE Vlli-1: STEAM GENERATOR l-1 PLUGGING LIST (continued)

~

1. Row. Column Elevation ECW3(%) ECW2(%) Comment Crack Extent PLUG DESIGN STAKE LENGTH e

49 77-- 176- TSC 40.51 PLP NDD Awriated with PLP at N/A fl&W Rolled on ill& CL 48" AITACllED AT CL .

R79C176 50 79 176- TSC +0.51 PLI/34% PLP PLP with wem N/A il&W Rolled on ill & CL 48" A1TACllED AT CL i

NA NA NA i 51 1 .180 Preventative _r Plug NA Il&W Rolled on ill & CL 188" A'ITACilEDTO CL 52 2 181 NA NA NA Preventatis ety Plug' NA H&W Rolled on ill & CL 18X" ATTACilED'IU CL 4

2 53 56 151 TSit -039 5 Al (OD) NTE Axial indwation in tube 11&W Rolled on ill& CL not fully expanded in tubesheet t NTE). Defect i contamed within tubesheet 54 2 183 NA NA NA Preventatively Plug' NA Il&W Rolled on llL & CL 188" ATTACIIEDTOCL 55 NA NA NA Preventatively Plug i NA Il&W Rolled on llL & CL 1 1%1 18M" A1TACllED TO CL NA i j 56 2 185 NA NA Preventatis ely Plug NA H&W Rolled on ill & CL 188" ATTACllLDTO CL 1

, Note 1: These tubes will be preventatively plugged and cold leg staked due to the high wear rate region (Cold Leg Corner) and the inaccessibility of the tubes without removal of the patch plates.

7 it

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7 8

7 8

9 8 9 1 1 9

i 9

0 1

0 1

0 1 1 0 0 1

w --

o R .

2 9 8 8' _

7'

)

5 4 7 9 4 4 8 0 9 2 5 5 4 5 4 6' 6

• 4 6 5 M 6 3 4 3 1 1 1 3 1

1. 0 1 2 3 1 L 5 6 7 8 9 0 1 5 6 7 M 9 0 0 0 0 0 0 0 0 0 l _

9 9 9 9 9 1 1 1 1 0

1 1 1 1 1 1 1

1 1

1 5ti 0 _

4 : ,1 ,  !  ; , I , '  : i

TABLE VIII 2: STEAM GENERKTOR l-2 PLUGGING LIST (continued)

1. . Row. [ Column Elevation ECP)3(%) ECT92(%) Comments Crack Extent PLUG DESIGN STAKE LENGTil i

112 28 - til ' TSit -0.50 sal /NTE NTE Axial indication in tube .25" H&W Rolled on ill& CL 3NT ATTACilED ATIIL not fully expanded in (Preventatively Staked for tubesheet (NTE) Stay Cyl Hat Wing Wear)

113 93 112 TSit -0.56 mal /NTE NTE Axialindications in tube .36" H&W Rolled on llL & CL 48" ATTACilED AT llL not fully expanded in tubesheet (NTE) 114 148 115 HW1 +1.72 SVl/NQI/PDP NDD Single Volumetric Indi. 0.5" Il&W Rolled on llL & CL NONE catum associated with PDP and HOW.

115 89 - 116 TSit -0.58 sal /NTE/ NTE Axial indication in tube .19" 11& W Rolled on ill & CL NONE NVI not fully expanded in tubesheet (NTE) 116 22 -117 ~ Olli .0.0M SVI(OD1/DSI NDD OD Wlumetric In<.hca. N/A H&W Rolled on llL A CL NONE tion at ITDP.

I17 60 ~ 119 HW1 415.25 SVI NDD ArcSVI N/A R&W Rolled on llL & CL NONE 118 93 120 TSit -0.96 mal /NTE NTE A sial indwations in tube .76" R&W Rolled on llL & CL 48" ATTACilED AT llL (86%) not fully espanded in tubesheet (NTE) 119 110 121 HW1 +1.lN SV!t 51% NDD Art Smgle Wlumetne N/A B&W Rolled on llL & CL NONE PDi'/IM)W Indwation amciated with PDP and HOW.

I20 93 126- TSil 0.56 mal /NTE! NTE Axial indwaiions in tube .47" R&W Rolled on llL & CL 48" AITACllED AT llL NQI not fully espanded in tubesheet (NTE) 121 .101 132 IlWI +2.73 4% NDD ArcSVI N/A R&W Rolled on llL A CL NONE 122 73 160 VS5 +1.05 45G 247 Vertical Strap Wear N/A R&W Rolled on llL & CL NONE I23 111- -160. TSil.0.74 sal /NTE/ NTE Axial indication in tube 35" H&W Rolled on llL & CL NONE NQI not fully expanded in 4

tubesheet (NTE) 124 1- J174 02C .0.97 21 % NDD Cold Leg Corner Wear N/A R&W Rolled on ill & CL 188" ATTACllED ATCL 2

tn m

- . . . - . - _ - _ . , _ . . . - . _ . . . , . . - . . . . . - . ~ . - _ _ . - _ _ - - - _ ~ - . .---

- --- - - . - - - - , - . _ - . ~.- - _ _ --_. _ - - __.

TABLE VIII-2: STEAM GENERATOR l-2 PLUGGING LIST (continued)

1. 1 'RoWL ICoiumn.- Elevation EG93(%) ECTV2(%) Comments Crack Extent PLUG DESIGN STAKE LENGTil 125 1' 176.- 03C .I .03 20% NDD Cokileg Comer Wear N/A B&W Rolled on ill& CL 188" ATTACilED ATCL 126 '1 l180 03C 0.17 22% NDD Coki leg Comer Wear N/A RAW Rolled on llL & CL 188" ATTACilED ATCL 127 1 151' NA NA NA Preventatively Plug l NA H&W Rolled on llL & CL 188" ATTACl{ED TO CL 128 7 'l&t 03C + l .00 20% NDD Cok! Leg Comer Wear N/A H&W Rolled on llL & CL 188" ATTACilED ATCL 129 26 - 185 TSC 40.27 SVI NDD OD Volumetric indica- N/A RAW Rolled on llL & CL 188" ATTACilED ATCL tion at Tubesheet

133 .3 1M6 03C +0 06 22% NDD Cuki Leg Comer Wear N/A 11&W Rotkd on llL & Cl, 188" ATTACilED ATCL 131 31 188 02C d.i t 31 % NDD Cok! Leg Comer Wear N/A H&W Rolled on ill& CL 188" ATTACilED ATCL Note 1

These tubes will be preventatively plugged and cold leg staked due to the high wear rate region (Cold Leg Comer) and the inaccessibility of the tubes without trmoval of the patch plates.

i 2

l J

ix. OPERATING INTERVAL / BASIS FOR RESTART APS has determined that PVNGS Unit 1 is safe to operate for a complete fuel cycle. This conclusion is based on the results of a comprehensive ECT inspection program which included a 100% bobbin inspection and extensive inspection by MRPC probe including 100% of the hot leg tubesheet transition area in both SGs as well as over 2300 tubes in each steam generator from the 08H support to the vertical strap. The scope of this inspection ensures that conditions such as the circumferential cracking problem were discovered.

There were no free span upper bundle axial crack indications observed in this ECT program, and all T code indications were resolved or plugged. A total of four SVis were located in the 'MRPC' arc region and may be indicative of early intergranular attack, and UT inspection of an accessible SVI did not indicate a crack. This supports the conclusion that accelerated upper bundle IGSCC, such as that observed in Unit 2, is not present in Unit 1, and confirms that differences in chemistry controls between the units can affect the initiation and growth of IGSCC.

Circumferential cracks observed in each steam generator were sized for length using MRPC and UT methods, and UT methods were used to estimate depth. The most conservative (longest) crack value of length was used and a through wall crack was assumed to identify which cracks would be used in the RG 1.121 analysis. Five tubes were tested with in situ pressure test methoos to verify compliance; all passed the test. This provided assurance that the corrosion mechanisms (PWSCC and ODSCC) did not produce cracks in excess of the R.G.1.121 limits since the last inspection in the third refueling outage.

Corrective actions have been taken or are planned to be implemented to address the environment producing PWSCC. As a conservative measure preventive actions have been taken or are planned to be implemented to prevent the accelerated IGSCC observed in the Unit 2 free span areas. Therefore, these corrosion mechanisms are not expected to be a factor significantly degrading tube integrity during Cycle 5.

Following the tube rupture event in Unit 2 a number of actions were implemented to minimize offsite doses in the unlikely event of a multiple tube rupture with a MSLB. These include administrative limits on primary to secondary leak rate and a maximum permitted Dose Equivalent lodine concentration, revised leak rate determination methods, improved diagnostic methods, and enhanced radiation monitoring. These actions are described in References 13 and 14, and have been implemented in all three PVNGS Units. A safety analysis was performed in support of the Unit 2 restart as described in References 13 and 14. This safety analysis was generic to the three PVNGS Units and predicts that in the event of a multiple tube rupture MSLB accident, with the mitigating actions described above, the offsite dose consequences are less than 10CFR100 limits.

This multi-tier approach:

Identifies by inspection any accelerated corrosion mechanisms that are present, allowing APS to identify the proper corrective actions Implements actions conservatively to address not only observed corrosion mechanisms but preclude the accelerated mechanism observed in Unrt 2 Page 58

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. Specifies monitoring and mitigating actions in case a tube rupture should occur j i

. Analyzes the impact of a tube rupture to confirm that the consequences do not exceed 10CFR100 limits.

It is by this defense in dep*h approach that APS concludes operation of Unit 1 for a full fuel cycle would i not constitute a safety concern.  !

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j X. REFERENCES )

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1. " Unit 2 Steam Generator Tube Rupture Analysis Report", submitted to the NRC staff as enclosure 2 to William Conway's letter 102-02569-WFC/JRP, dated July 18,1993

2. EPRI TR-102134, PWR Secondary Water Chemistry Guidelines', Revision 3, May,1993.  !

j

3.

• Secondary System Iron Transport Study", PVNGS, Unit 2. August,1991, i

4. APS Memorandum 237-01165-JNH," Unit 1 Shutdown Hideout Retum Data - September 5,1993',

October 27,1993.

{

5. APS Memorandum 237-01164-JNH, ' Unit 3 Downpower Hideout Retum Data - September 25, 1993', October 25,1993.

6. AES 92071723-1-1, ' Predictive Modeling of Steam Generator Tubing Degradation for Palo Verde Nuclear Generating Station, Units 1,2, and 3', Aptech Engineering Services, Inc., April,1993.

7. EPRI NP-5558-SL, " Boric Acid Application Guidelines for Intergranual Corrosion inhibition *,

Revision 1, December,1990.

I

8.

• Evaluation of Steam Generator Wet Layup Out-of-Specification Condition for Palo Verde Units 1 j and 3, Arizona Public Service, EERs 89-RC295 and 89-RC296', ABB-Combustion Engineering i Nuclear Power, June,1990.

9. ASM Metals Handbook,9th Edition, Volume 13, Pages 941-944.

10 CENPD-28, ' Combustion Engineering Nuclear Steam Supply System Chemistry Manual *, Revision 3, September 1982.

11. PVNGS Engineering Report, ' Condenser Tube Leak Assessment, August 1992.

12. Letter dated June 25,1993, from C.M. Trammell, Senior Project Manager, Project Directorate V, Office of NRR, USNRC, to W.F. Conway, Executive VP, Nuclear, APS, " Steam Generator Tube Evaluation".

13. Letter 102-02585, dated July 25,1993, from W.F. Conway, Executive VP, Nuclear, APS, to NRC,

" Steam Generator Tube Evaluation'.

l

14. Letter 102-02593, dated July 30,1993, from W.F. Conway, Executive VP, Nuclear, APS, to NRC,

' Steam Generator Tube Rupture Analysis'.

11. EPRI NP-6626-SD,' Belgian Approach !o Steam Generator Tube Plugging ior Primary Water Stress Corrosion Cracking", March 1990.

16. USNRC Regulatory Guide 1.121, " Basis for Plugging Degraded PWR Steam Generator Tubes', For ,

Comment, August 1976. '

Page 60

17. EPRI NP-7198-S, " Proceedings: 1990 EPRI Workshop on Circumferential Cracking of Steam ,

Generator Tubes', March 1991. j i

18. EPRI TR-101103, ' Proceedings:1991 EPRI Workshop on Secondary Side Intergranular Corrosion ,

Mechanisms", August 1092. j

19. Minutes, CEOG Materials and Chemistry Subcommittee, April 29-30,1993. l t

20. V-CE-35658, 'CE Assessment of Palo Verde, Unit 2 Steam Generator Tubes ECT inspection i Results Obtained in April 1988', April 21,1988.

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_ - . - . . . . . _ . . __ . _ . _ _ . . _ . ... . . . . _ . . . ~ - . . . _ . . . . _ _ . _

i Xil. APPENDICES l A. Industry Review -

A review of Industry Events on INPO's Nuclear Network was performed to identify other Nuclear Utilities with circumferential cracking in the tubesheet expansion transition region. Among the Combustion Engineering units to identify this phenomenon are Arkansas Nuclear One Unit 2 (ANO 2), Maine Yankee, Millstone 2, San Onofre 2, and St. Lucie 1. These units were contacted by PVNGS to discuss the cause of their circumferential cracking, and the corrective actions initiated to reduce the potential for the reoccurrence of this cracking and to extend steam generator life.

1. Arkansas Nuclear One 2 ,

ANO 2 has experienced OD-initiated circumferential cracking at the hot leg *explansion* i (explosive expansion) transition region. These cracks are primarily located in the

• kidney bean

• area and are believed to be temperature-related. A review of chemistry data failed to identify any singular event that could account for these defects. Sulfates and lead nave been identified in sludge samples from the steam generators. ANO believes that  :

early poor chemistry control led to acid sulfate attack of the Alloy 600 tubing, causing IGSCC. The susceptibility of Alloy 600 to stress corrosion cracking, high residual stress in the transition region of the tube, the buildup of sludge containing a known activating i agent at the transition region, and high hot leg temperatures have been determined to be the contributing factors to this cracking. Corrective actions taken to mitigate this cracking include boric acid treatment, the use of morpholine to increase secondary pH, sludge lancing, and the reduction of hot leg temperature from 607*F to 599 F.

2. Maine Yankee >

Maine Yankee has experienced ID-initiated circumferential cracking at the hot leg explansion transition region. This cracking has been characterized as PWSCC. The buildup of sludge, high hot leg temperatures, high residual stress at the transition region, i

and the susceptibility of Alloy 600 tubing are believed to be the contributing factors to the cracking. The sludge buildup is believed to act as an insutator, increasing the i temperature of the affected tubes. Corrective actions include sludge lancing, reduction of the hot leg temperature from 602*F to 599"F, removal of copper-bearing feedwater heaters, and the use of morpholine to increase secondary pH in an effort to reduce l sludge buildup. l l

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3. MI!! stone 2 Millstone 2 experienced OD-initiated circumferential cracking at both the hot leg and cold leg explansion transition region. A root cause of the cracking was not identified; however, it was believed to have been a caustic crevice attack. The high hot leg temperatures, high residual stress at the transition region, and the susceptibility of Alloy 600 tubing to SCC were identified as contributing factors. Boric acid treatment was successfully used to increase the lifespan of the generators until they could be replaced. Millstone 2 is now operating with new steam generators using Alloy 690 tubing.

4. San Onofre 2 San Onofre 2 has ideritified circumferential cracking at the hot leg explansion transition region. At this time it has not been determined whether it was OD or ID-initiated or what the root cause of this problem was. A corrective action plan was not discussed with San Onofre.

5. St. Lucie 1 St. Lucie 1 has experienced OD-initiated circumferential cracking at the hot leg explansion transition region. Sulfates and lead have been identified in sludge samples from the steam generators. Improper operation of the feedwater demineralizers is believed to have caused acid sulfate attack of the Alloy 600 tubing resulting in IGSCC. Transgranular cracking has also been identified and attributed to the presence of lead. St. Lucie also determined the high hot leg temperatures, high residual stress at the transition region, and the susceptibility of Alloy 600 tubing to SCC as contributing factors to the cracking.

St. Lucie has reduced hot leg temperature from 604*F to 597*F, and instituted chemistry changes in an effort to increase the lifespan of the steam generators.

6. Summary industry reports show that circumferential cracking has been observed at the tube expansion transition region of steam generators at numerous CE and Westinghouse plants. Causal factors include the susceptibility of Alloy 600 to stress corrosion cracking, high residual stress in the tube transition expansion region of steam generators, inadequate control of secondary chemistry, the buildupof sludge at the transition expansion region, and high hot leg temperatures. Corrective actions taken to mitigate this cracking include boric acid treatment, the use of morpholine or ETA to increase secondary pH and reduce iron transport, sludge lancing of tubesheets to remove sludge deposits, molar ratio control, and the reduction of hot leg temperature. Additional corrective actions being evaluated in the industry include shot peening of the expansion transition region to relieve stress, and nickel plating the ID of the tubes to protect them from PWSCC.

Page 63 m

B. Steam Generator Description l

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1. Design Data and Performance Parameters ,

l Each Palo Verde Unit utilizes two SGs which are vertical tube and shell heat exchangers i approximatefy 68 feet in height with a steam drum diameter of 20 feet. The Palo Verde i steam generators were designed and fabricated by Combustion Engineering, and are i currently the only operating units of this design (System 80). The steam generator arrangement is shown in Figure XII-1.  !

The steam generators are designed to transfer 3817 MWt from the reactor coolant system  !

to the secondary system, producing approximately 17.2 x 10* LBM/HR of 1070 psia saturated steam when provided with 450F feedwater. Moisture separators and steam dryers in the shell side of the steam generator limit the moisture content of the steam to j 0 25% wt during normal operation at full power.

The primary side (high pressure) of the steam generator consists of the hemispherical  !

lower head, the tubesheet and the tubes. A divider plate with tongue and groove '

construction separates the head into inlet and outlet chambers. A 42-inch nozzle provides entrance of reactor coolant into the steam generator which passes through the heat transfer tubes and exits through two 30-inch outlet nozzles. The unit is supported by a skirt attached to the bottom head. The secondary side of the steam generator consists of two cylindrical shells. joined by a conical section to the steam drum. 1 The steam generator is of a stayed design to support the tubesheet, and as a result, the center of the tube bundle contains a cylindrical cavity. The stay cylinder is a hollow, cylindrical tube located in the center of the steam generator. The stay cylinder supports the primary plenum plate, the divider plate separating the economizer and evaporator regions on the steam generator secondary side, and provides rigidity to the tube sheet to minimize tubesheet bowing. A summary of pertinent design and operating data is provided below:

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-i STEAM GENERATOR DATA l

Quantity 2 l Type Vertical U-Tube  ;

Number of Tubes per SG 11,012 l

Primary Side j Design Pressure 2500 psia l Design Temperature 650*F i Design Thermal Power 3817 MWt i Coolant Flow in Each Loop 82 x 10' lbm/hr Normal Operating Pressure 2250 psia Normal Operating SG Inlet Temp 621.2*F ,

Normal Operating SG Outlet Temp 564.5"F l Coolant Volume 2317 ft' l Secondary Side ,

i Design Pressure 1270 psia j Design Temperature 575'F Normal Operating Saturated Steam i Pressure at 100% power 1070 psia l Normal Operating Steam Temp j at 100% Steam Flow per SG 553'F 8

100% Steam Flow per SG 8.59 x 10 lbm/hr Maximum Blowdown Flow 738,740 lbm/hr Dimensions Overall Height 817.5 inches Steam Drum Diameter (OD) 266.5 inches Lower She!! Diameter (OD) 189.5 inches Dry Weight 1,428,900 pounds Tube Diameter (OD) 0.75 inch

2. Steam Generator Materials The steam generator's pressure containing mambers are constructed of low alloy steel (P3). The tubesheet is a 23.5 inches thick low alloy steel base, with % inch thick Alloy 600 cladding on the primary surfaces. The tubes are made of high temperature m!!! annealed Alloy 600 (SB-163). All tube supports were constructed primarily from 409 ferritic stainless steel. The flow distribution plates are made from 405 ferritic stainless steel material. The structural tiedown sections of the supports, such as the partial eggerate scallop bars and '

eggerate and batwing wrapper bars, were constructed from carbon steel. To minimize tube denting, no carbon steels are in direct contact with the steam generator tubing except for the tubesheet and the scallop bars on the partial eggerates.

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3. Tube Design  ;

l Each steam generator contains 11,012 tubes which are % inch OD, and have a nominal j wall thickness of 0.042 inches and an average heated length of 57.75 feet. Tubes were i expanded into the tubesheet by a method known as explansion (explosive / expansion) for l the entire tubesheet thickness. The tube bundle is enclosed by a wrapper plate which forms the downcomer annulus just inside the shell. The top of the wrapper serves to .

support the separator deck. s The tubes are arranged in rows, with all tubes in a given row having the same length. The rows are staggered, forming a triangular pitch arrangement as is shown in Figure Xil-2.

!j The shorter tubes, which have 180* bends, are at the center of the tubs bundle in the first  !

18 rows. All subsequent rows have double 90* bends. The vacant space (4% inches) {

between the tubes in the first row is called the tube lane which is open through the j vertical legs of the tube bundle. The tube lane is the boundary between the hot leg side j and the cold leg side on the secondary side of the steam generator. j i

i

4. Internal Support Structures l

\

The steam generator tube supports were designed to provide tube bundle stability during }

normal plant operation or combined seismic / accident conditions while offering minimum restrictions to steam / water flow in the tube bundle to prevent formation of crud and  ;

deposit buildup.- 1 I

The steam generators were designed to ensure that critical vibration frequencies would ]

not occur during either normal operation or abnormal conditions. The tube l bundie! support configuration was designed and fabricated with consideration given to ]

secondary side flow induced vibrations. In addition, the steam generator support j assemblies were designed to withstand blowdown forces resulting from the severance of  ;

a steam nozzle. ,

1 There are four types of tube supports in the Palo Verde steam generators. Refer to Figure ,

Xil-3 for the location and cesignation of the tube supports. i

)

Flow Distribution Plate (01H and 01C)

The flow distribution plate is a 405 ferritic stainless steel plate with drilled flow holes. Different hole sizing forces downcomer/feedwaterto flow radially across the l tubesheet to permit fluid to pass evenly upward around the tubes in axial flow

! region. Although not considered a true support, the hot and cold side flow distribution plates are designated 01H and 01C respectively for eddy current ,

testing purposes.  !

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Page 66 l

Horizontal Eggerate Supports (02H-09H and 02C-09C)

Horizontal eggcrate supports are a diagonal eggerate design. The eggcrate design allows for the maximum flow area while providing sufficient horizontal stabilization for the tubes to protect the bundle from mechanical or flow induced vibration. The eggcrate supports are designated 02H through 09H and 02C through 09C for tracking purposes. The top two horizontal eggerate supports are partial eggerates and only support a portion of the tubes. The partial eggerates are stif'ened by a carbon steel scallop bar welded onto the face of the eggerate.

Batwings Batwing stabilizers horizontally support the bends in the U-tubes (see Figure Xil-4). The purpose of the batwing stabilizers was to prevent tube-to-tube contact between columns, not designed to provide structural support for the tubes. The batwing supports are designated EW1 (hot side) and BW2 (cold side).

Vertical Straps j he vertical straps (VS) and their associated support grids, provide vertical support for the tubes in the horizontal run at the upper region of the steam generators. The VS3 and VS5 are gridded from structural support straps that are 4

attached to T beams in the upper head. The other vertical supports float, and are

not attached to any T beams. The VS configuration provides vertical stabilization for the tubes (see Figure XII-4).

5. Flow Paths l There are two flow paths associated with a pressurized water reactor (PWR) steam generator design. On the primary side (tube side) reactor coolant enters the bottom of the steam generator through the single hot leg intet nozzle, flows through the U-tubes, 8

and exits through the two cold leg outlet nozzles. A vertical divider plate and stay cylinder separate the inlet and outlet plenums in the lower head.

On the secondary (shell side) flow paths (See Figure XII-5), feedwater is injected into the a steam generator via the downcomer and the economizer flow nozzles. The quantity of flow through each path depends on the reactor power level of the operating unit.

! The feedwater ring distributes downcomer flow entering the steam generator from the 1 upper feedwater nozzle. It consists of a pipe with ten 'J' tube extensions and is located 3 above the U-tube bundle, outside the wrapper plate. Downcomer flow enters the feed ring and is directed to the top of the moisture separator support plate, where it combines with moisture separated from the steam-water mixture, and drains to the downcomer annulus (between the wrapper plate and the secondary side she!!). The 'J' tubes minimize feed d

ring water hammer by minimizing the amount of water flashing to steam during shutdown

periods. Auxiliary feedwater is injected via the downcomer nozzle during emergency conditions to prevent thermally shocking the U-tuber.

]

Page 67 i

Economizer flow enters just above the tube sheet on the cold leg side of the steam generator. It increases steam generator efficiency by preheating incoming feedwater before the feedwater enters the evaporator .section. The economizer consists of a flow distribution box and flow distribution plate. A divider plate separates it from the steam generator hot leg side. Feedwater is introduced to the economizer distribution box through two economizer nozzles.

The distribution box encircles the cold leg side of the tube bundle below the flow distribution plate. Holes machined in the distribution box uniformly admit feedwater to the area under the distribution plate. The flow distribution plate is perforated to ensure uniform feedwater distribution in the economizer section.

6. Blowdown To minimize corrosion and solid deposit buildup, steam generator water chemistry must be maintained within specifications. Chemistry is controlled by feedwater chemical addition and steam generator blowdown. Both the hot leg side and the cold leg side (economizer) have blowdown capability. Blowdown provides the ability to remove concentrated impurities from the steam generator, and thereby lessens the possibility of steam generator corrosion. A normal continuous blowdown of 0.2% main steaming rate (MSR) is maintained. Abnormal (1% MSR) and High Capacity (10% MSR) blowdown are utilized as chemistry conditions dictate.

7. Steam / Moisture Separation The steam / water mixture leaving the tube bundle area has a steam quality of approximately 30%60% The steam exiting the steam gerserators must have a steam .

quality of 99.75% To remove the required moisture, the System 80 steam generators employ two stages of moisture separation: centnfugal separators and steam dryers.

The first phase of moisture removal is accomplished by 194 centrifugal separators located on the SG can deck. The System 80 moisture separator cans are provided with stationary spinner blades which impart a centrifugal motion to the steam / water mixture. The heavier water is thrown to the surface of the can where it passes through holes in the separators side. The remaining two-phase mixture flows upward to the top of the separator where additional moisture is removed by nine (9) layers of corrugated baffles. The moisture j removed from this phase drops back into the separator region and is recirculated though  ;

the steam generator via spillover from the can deck (see Figure Xil-5). .{

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FIGURE Xil-1 SYSTEM 80 STEAM GENERATOR ,

\ y 40* /

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@ \.j ,$ -

NO. i NO. SERVICE REO'D Rs

accananamaAa 1 Primary intet 1 SEPARATORS  ;

3 gg g gg 3 Downcomer Feedwater -

1 yqq1 a

@ d 3S3 o ====m s $g g g5555555BBea 4 Steam out'et 2 m o m a === _r 20'-5" 5 Blowdown 2

@QQ@Q O.D. 6 7

Primary lAanway Secondary IAar,way 2

2

sm wv - 8 Handhole 2 h  !

q <- g 9 Economizer Feedwater 2 r 3 "

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BOTTOIA VIEW OF  :

g h STEAIA GENERATOR inWg

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________._____.__t

r FIGURE X11-2 r SYSTEM 80 STEAM GENERATOR TUBES TRIANGULAR PITCII CONFIGURATION ,

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FIGURE XII-3 CE SYSTEM 80 STEAM GENERATOR TUBE SUPPORT DIAGRAM VS1 2 3 4 5 6 7 BW1 __,_ BW2 N

P 09H 09C 45" 08H 08C i

} l 45" 07H 07C i

06H 06C 051I 05C 43" 04H 04C 41" 03C 43" 43" 020 02H 15.5" 32.5" 01H 16.5" ,

TUBESHEET 23.5" i

INLET OUTIEf SUPPORT SPACINGS ARE ,

IDENTIFIED IN INCHES i BETWEEN THE SUPPORT -

IDENTIFICATION l ROW 1 LINE 2 SIDE I

COLD LEG MANWAY HOT LEG MANWAY s

LOOKING UP AT TUBESHEET Page 71 i

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l FIGURE XII-4 Palo Verde Upper Tube Bundle Supports Qu ,

Tube >

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Horizontal l '

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Page 72 l

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FIGURE Xil-5  ;

g wain s Secondary Fluid Flowpaths of Steam Linep

/p CE System 80 Steam Generator g\ f

',(' - '7 Shellside Flow Path p-

'k ,. .% .

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// DRYERSk l/c. sac ~h\cmsm 1 n .]

b . .,_.,_ ,_,,SEPAR i E +I. j ,ly 4 jM m!!l l[lIk,,,ATOf S'\m[+

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TD 0 0 0 0 Oh <

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-#o k, Downcomer Feedwaterinlet r $ . .@

b ) A 1 00% @100% Power)

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Page 73

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i C. Eddy Current Reports

-f The following tables of eddy current indications are attached. -l t

Table XI-1 Circumferential indications, SG 11  !

Table XI-2 Circumferential Indications, SG 12  !

Table XI-3 Wear Indications >35% SG 11 l Table XI-4 Wear Indications >35% SG 12 t-  !

Table XI-5 Single Volumetric Indications Within

• Bobbin

• Arc, SG 11 ,

i Table XI-6 Single Volumetric Indications Within *MRPC* Arc, SG 11 l

Table XI-7 Single Volumetric Indications Within *MRPC* Arc, SG 12  ;

-i i

Note 1: The *MRPC* arc is the area of 1800 tubes included in the original MRPC scope. l The

• Bobbin

• arc is a buffer region of 2000 tubes surrounding the *MRPC* arc.  ;

The data ptovided is from the 08H through the first vertical support. See Figure j IV-5. '

Note 2: No axial indications were found outside the tubesheet area.

Note 3: There were no SVis within the

• bobbin

• arc of SG 12. l P

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r Page 74  !

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1 TAP' E XI-1

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CIRCUMFERENTIAL INCICATIONS, SG 11 l t

Row Column Hot or Location ECT Length l Cold Leg Call (in.) )

77 16 H TSH-0.30 SCI 0.34 50 75 H TSH-0.15 SCI 0.44 52 79 H TSH-0.15 MCI 0.91 (

52 81 H TSH4.23 SCI 0.86  !

52 83 H TSH-0.08 SCI 0.41 55 90 H TSH-0.09 SCI 0.34 l r

12 169 H TSH-0.18 SCI 0.31  !

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Page 75 l J

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i TABLE XI-2 CIRCUMFERENTIAL INDICATIONS, SG 12 Row Column Hot or Location ECT Length Cold Leg Call (in)  ;

22 55 H TSH+ 0.00 SCI 0.55 23 56 H TSH + 0.11 SCI 1.32 23 60 H TSH-0.02 SCI 0.99 25 60 H TSH-0.01 SCI 1.22 TSH + 0.11 0.26 l 35 60 H TSH-0.04 SCI 1.06 TSH-0.04 0.25 39 60 H TSH+ 0.00 SCl 0.90 137 60 H TSH-0.29 SCI 0.68 j 32 61 H TSH-0.06 SCI 0.40 34 61 H TSH-0.03 SCI 0.38 36 61 H TSH + 0.09 SCI 0.75 44 61 H TSH + 0.00 SCI 0.32 35 62 H TSH + 0.16 SCI 0.21 43 62 H TSH+ 0.11 SCI 0.27 47 62 H TSH-0.01 SCl 1.15 30 63 H TSH-0.03 SCI 0.48 l l

29 64 H TSH-0.10 SCI 0.31 53 64 H TSH-0.02 SCI 0.60 28 65 H TSH+ 0.00 SCI 0.29 51 66 H TSH + 0.12 SCI 0.24 34 67 H TSH+ 0.06 SCI 0.18 TSH +0.11 0.28 38 67 H TSH + 0.13 SCI 0.23 40 67 H TSH + 0.06 SCI 0.24 i

i Page 76

TABLE XI-2 (continued)

CIRCUMFERENTIAL INDICATIONS, SG 12 Row Column Hot or Location ECT Length Cold Leg Call (in) ,

39 68 H TSH+ 0.09 SCI 0.21

{

43 68 H TSH+ 0.02 SCl 0.45 TSH + 0.22 0.27 i 51 68 H TSH + 0.18 SCI 0.13 -

45 70 H TSH + 0.11 SCI 0.42  :

42 71 H TSH + 0.13 SCI 0.26 44 71 H TSH + 0.07 SCl 0.22 52 71 H TSH + 0.28 SCI 0.45 54 71 H TSH-0.04 SCI 1.67 56 71 H TSH-0.12 SCI 0.34 TSH + 0.34 0.45 57 72 H TSH + 0.23 SCI 0.33 i 54 73 H TSH-0.02 SCI 0.51 [

TSH-0.02 0.30 i TSH-0.02 0.43  :

TSH-0.02 0.38 l 60 73 H TSH-0.08 SCI 0.28 ,

43 74 H TSH + 0.18 SCl 0.43 59 74 H TSH + 0.21 SCI 0.15  ;

61 74 H TSH + 0.16 SCI 0.21  !

42 75 H TSH + 0.05 SCI 0.35 .

46 75 H TSH + 0.14 SCI 0.25 }

t 48 75 H TSH-0.04 SCI 0.16  !

,4

) 54 75 H TSH + 0.00 MCI 2.01 l TSH + 0.23 0.28 +

56 75 H TSH + 0.21 SCI 0.55 i

e s

Page 77 j l }

TABLE XI-2 (continued)

CIRCUMFERENTIAL INDICATIONS, SG 12 Row Column Hot or Location ECT Length Cold Leg Call (in) l 58 75 H TSH+ 0.19 SCI 0.67 62 75 H TSH + 0.26 SCI 0.94 TSH +0.26 0.28 64 75 H TSH + 0.23 SCI 0.30 49 76 H TSH-0.02 SCI 0.50 53 76 H TSH-0.02 SCI 0.32 TSH + 0.11 0.18 55 76 H TSH + 0.01 SCI 0.79 59 76 H TSH + 0.16 MCl 0.55 TSH + 0.16 0.33 61 76 H TSH + 0.14 SCI 0.45 36 77 H TSH+ 0.21 SCI 0.25 48 77 H TSH + 0.10 SCI 0.61 58 77 H TSH + 0.00 SCI 0.58 60 77 H TSH-0.07 SCI 0.88 TSH + 0.26 0.57 49 78 H TSH + 0.04 SCI 0.76 TSH+ 0.18 0.35 51 78 H TSH-0.02 SCI 0.41 53 78 H TSH-0.03 SCI 0.87 63 78 H TSH+ 0.05 SCI 0.38 65 78 H TSH + 0.15 SCI 0.48 69 78 H TSH-0.02 SCI 0.30 48 79 H TSH + 0.02 SCI 1.33 54 79 H TSH-0.05 SCI 0.33 60 79 H TSH + 0.21 SCI 0.21 57 80 H TSH + 0.28 SCI 0.35 IN Page 78

TABLE XI-2 (continued) ,

CIRCUMFERENTIAL INDICATIONS, SG 12 i Row Column Hot or Location ECT Length Cold Leg Call (in) 54 81 H TSH + 0.12 SCI 0.44 53 82 H TSH+ 0.15 SCI 0.49 f 67 82 H TSH + 0.14 SCI 0.71 48 83 H TSH + 0.01 SCI 0.27 47 84 H TSH + 0.00 SCI 0.28 65 84 H TSH + 0.13 SCI 0.43 ,

TSH + 0.13 0.36 TSH + 0.13 0.22 l l

64 85 H TSH + 0.18 SCI 0.79 ,

47 86 H TSH +0.03 SCI 0.50 69 86 H TSH-0.01 SCI 0.60 i l

54 87 H TSH-0.01 SCI 0.58 f

64 87 H TSH + 0.13 SCI 0.42 64 89 H TSH-0.07 SCI 0.24 J

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Page 79

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TABLE XI-3 l

WEAR INDICATIONS > 35%, SG 11 ,

Row Column Hot or Location  % Wear  ;

Cold Leg l 84 , 19 C VS5+ 0.85 37 81 60 H VS3+ 0.91 47 155 82 H BW1 + 1.93 50 154 83 C VS7-0.84 36 156 87 H BW1 + 1.37 40 159 94 C VS7+1.27 37 ,

159 96 H BW1-1.66 37  ;

157 110 C VS7+ 0.83 37 C BW2-1.86 41 83 134 H VS3+1.00 42 76 159 H VS3 + 0.93 38 81 168 C VS5+ 0.12 36 -

78 169 H VS3-0.92 42

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Page 80

F TABLE XI-4 WEAR INDICATIONS > 35%, SG 12 Row Column Hot or Location  % Wear Cold Leg 1 2 C 02C-0.71 37 73 28 H VS3+ 0.57 48 85 74 C VS5-0.84 36 159 102 C BW2+ 1.97 40 158 103 C BW2+1.93 43 117 106 H 09H + 1.53 37 158 107 C VS7+ 0.74 44 154 119 C 05C-1.00 39 101 132 H BW1 +2.72 36 84 133 H VS3-0.59 37 144 135 C 03C + 0.80 38 76 141 H VS3-0.86 36 79 148 C VS5+1.03 39 71 154 H 08H-0.91 39 84 155 H VS3-0.84 37 73 160 C VS5 + 1.05 45 12 189 C 05C+ 0.16 36 i

Page 81

i TABLE XI-5 i SINGLE VOLUMETRIC INDICATIONS {

WITHIN

• BOBBIN

• ARC, SG 11  !

i Row Column Hot or Location ECT Call - Deposit Bowing l Cold Leg .;

r 116 83 H BW1 +1.20 SVI Yes Yes 97

• 138 H BW1 +2.85 SVI Yes No ,

t

• Tube R97C138 is included in this table as an SVI related to arc conditions although the tube is located one tube outside the

• bobbin

• arc.  !

t I

TABLE XI-6  !

SINGLE VOLUMETRIC INDICATIONS I WITHIN *MRPC* ARC, SG 11  !

Row Column Hot or Location ECT Call Deposit Bowing Cold Leg i

.i 149 88 H 08H +12.00 to SVI No No ,

+18.73 [

11 08H +21.55 to -!

+22.20 l H 08H +23.26 to

+ 28.37 {

H 08H +33.12 to

+37.62 {

TABLE XI 7 j SINGLE VOLUMETRIC INDICATIONS [

WITHIN *MRPC* ARC, SG 12 i Row Column Hot or Location ECT Call Deposit Bowing .i Cold Leg 100 31 H BW1 +3.15 SVI Yes No 122 101 H BW1 + 0.57 SVI Yes- Yes  ;

148 115 H BW1 +0.50 to SVI Yes No l

+ 1.00 .

Page 82 i

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