ML20043A489

Nonproprietary Indian Point Unit 2 Steam Generator Insp, Repair & Restoration Program

ML20043A489
Person / Time
Site:	Indian Point
Issue date:	05/30/1990
From:	WESTINGHOUSE ELECTRIC COMPANY, DIV OF CBS CORP.
To:
Shared Package
ML100331227	List: ML100331226 ML100331228 ML20043A489
References
SG-90-05-022, SG-90-5-22, WCAP-12574, NUDOCS 9005220134
Download: ML20043A489 (31)

Text

...

(

WESTINGHOUSE PROPRIETARY CLASS 3

(.

SG-90-05-022'

.WCAP-12574 j

1

• l INDIAN POINT UNIT 2 STEAM GENERATOR INSPECTION, REPAIR, j

AND RESTORATION PROGRAM i

~

i Issue date: May 1990 PREPARED FOR CONSOLIDATED EDISON COMPANY This document contains information proprietary to Westinghouse Electric Corporation; it is submitted in confidence and is to be used solely for the purpose for which it is furnished and returned upon request. This document and such information is not to be reproduced, transmitted, disclosed or used otherwise in whole or in part without authorization of Westinghouse Electric Corporation.

WESTINGHOUSE ELECTRIC CORPORATION NUCLEAR SERVICES DIVISION P, 0. B0X 355 PITTSBURGH, PENNSYLVANIA 15230 Copyright by Westinghouse Electric 1990, @ All Rights Reserved 9005220134.900516

?

PDR ADOCK 05000247 j

F:

PDC

.I FORWARD This nonproprietary report bears a Westinghouse copyright notice. The NRC is j

_ permitted to make the number of copies of this report necessary for its internal use i

and such additional copies which are necessary in order to have one copy available

- for public viewing in the appropriate docket files in the public document room in Washington /D.C. and m local public document rooms as may be required by NRC regulationsif the number of copies submitted is insufficient for this purpose. The.

NRC is not authorized to make copies for the personal use of members of the public

who make of the NRC public document rooms. Copies of this report or portions i

thereof made by the NRC must include the copyright notice.

I, ia i

i XO464:1b-051590-A ll

L TABLE OF CONTENTS Page l'.0 INTRODUCTION 1

• 2.0 INSPECTION RESULTS 1

2.1 Girth Weld 2

j 2.2 Near Girth Weld Area 2

)

2.3 Feedring Supports and Nozzle inner Radius 3

2.4 Feedwater Nozzle Bore 4

2.5 Other inspections 5

2.6 Feedwater Pipe 6

3.0 BOAT SAMPLE EVALUATIONS 6

i 3.1 Girth Weld / Transition Cone 7

i 3.2 1989 Weld Repair Area 7

3.3 Nozzle Bore 8

3.4 Feedring Supports 8

3.5 Conclusion 8

4.0 B ASIS OF EVALUATION-9 1

4.1 Acceptance Criteria - Girth Weld 9

4.2 Methodology 10 4.3 Reference Crack Sizes 11 l

5.0 RESULTS 13 6.0 REPAIR AND MITIGATING ACTIONS 15 6.1 Girth Weld and brackets 15 6.2 Feedwater Nozzle Region 16

• 6.3 Oxygen Controlof Auxiliary Feedwater 17-

• 7.0 FUTURE PLANS 17

8.0 CONCLUSION

S 19 APPENDIX A 21 A mechanistic approach to integrity evaluations of the feedwater nozzle region.

i These sections were provided to Westinghouse by Consolidated Edison.

X0464:1b-051590-A iii

+

LIST OF TABLES Page

. Table 4.1 Reference Cracks for the Girth Weld, Transition Cones, Brackets and Straps 12 Table 5-1 Days of Service Based on Integrity Evaluation for the Girth Weld, Transition Cone, Brackets and Straps 14 Table A-1 Crack Growth Rates for Nozzle Region 24 Table A-2 Allowable Days at Hot Standby Based on the Integrity Evaluation 26 i

x0464:1b-051590-A IV

WCAP-12574 5-16 90 l

SG 90-05-022 l

lNDIAN POINT UNIT #2 STEAM GENERATOR INSPECTION, REPAIR, AND RESTORATION PROGRAM

-l

1.0 INTRODUCTION

On February 24,1990 Indian Point 2 shutdown to perform a mid-cycle inspection of the Steam Generators Girth Welds and Feedwater Nozzles. Results of the girthweld inspection were presented to the NRC on March 14,1990. Consolidated Edison committed to: (1) The maximum duration of the next operating period should be i

based on assuming the maximum observed crack growth rate for each steam generator and demonstrating that ASME Code factors of safety are satisfied. (2) The licensee should review its repair procedures to assure that the procedures fully comply with requirements of ASME Code Case N-432. The Code Case conditions should be satisfied or repairs should be made in accordance with the requirements of Section XI of the ASME Code. (3) All feedwater ring support brackets should be inspected and repaired,if necessary, before resuming operation.

i The inspection program included feedwater nozzles, feedwater ring brackets and other locations which, based on inspections during the outage, had been

~ determined to be susceptible to cracking. All indications identified as cracks were removed by grinding. In certain locations ground out areaswere repaired by welding utilizing qualified weld procedures in full compliance with the requirements of ASME Code Case N-432 or Section XI,1983 Edition, winter 1985.

l The following sections present a summary of inspections performed, the inspection results, repairs, mitigating actions and the technical basis to demonstrate safe and continued operation.

2.0 INSPECTION RESULTS i

Following the 1989 refueling outage at Indian Point Unit 2, a mid-cycle inspection program for the steam generator transition cone upper girth weld and feedwater nozzle was specified. This inspection effort included visual (VT) and magnetic particle (MT) inspections of 1/3 of the inner circumference of the SG 22 and 23 girth welds. This included areas of representative repairs, previously ground out areas, and non ground areas. If relevant linear indications were detected, the examination would be extended to 100% of the SG 22 and 23 girth welds and 1/3 of SG 21 and 24.

If additional relevant linear indications were found in SG 21 and 24, the examinationswould extend to 100% of these welds.

Simultaneously, inspection of the feedwater nozzle inner radius areas was planned.

A visual and MT (or PT) would be conducted on the nozzle inner radius section in the lower 180 degree segment and on the welds of the support brackets on SG 22 and XO464:1b/051590-A 1

i

23. If' indications were found, the examinations would be expanded to the SG 21' and 24 nozzles and/or brackets, as applicable.

2.1 Girth Weld During the visual and magnetic particle inspections of 1/3 of the inner circumference of the girth welds of SG'22 and 23, linear indications were noted. The indications were located in virgin and previously ground areas. The areaswelded in SG 22 and during the 1989 repair exhibited some pitting but no linear indications. With the finding of new indications,100% of the inside circumference of the girth welds in all t

- four steam generators was inspected. During this additional inspection, linear indications were noted in all steam generators. Allindications were removed by grinding and the surface was examined by magnetic particle techniques so that no o

linear indications remained. The number of indications, maximum depth and average depth for the indications at the girth weld are shown below:

GIRTH WELD L

SG 21 SG 22 SG 23 SG 24

- No. of Indications 42 26 14 10 Max. Depth (inch)*

0.36 0.53 0.28 0.34 Avg. Depth (inch)*

0.13 0.11 0.08 0.16

• Depth ground to remove indication a

2.2 Near Girth Weld Area Four indications, ranging in depth from 0.05 in to 0.73 in, were seen in one area in SG21,6 to 7 in, above the ID centerline of the girth weld. Remnants of an attachment weld were evident in that area.

For the weld repair method utilized in SG 22, inspection requirements for the weld repairs stipulated that an area 1~0" around the weld repair be examined by RT, UT and MT. MT and UT indications were identified in the area 8"- 10" below the weld.

The grindout in the 24 areas verified by MT to date, ranged in depths from 0.135 in.

to 0.566 in. The examinations were expanded to include the remainder of the girth weld which was not weld repaired. Several similar indications were identified in this area also. A one third section of transition cone plate was ultrasonically examined.

This section of plate included a longitudinal weld (one of three) and one third of the lower girth weld.

A second area was selected in SG 21 to include the 10" area below the girth weld, a one third section of transition cone, one of three longitudinal welds, and one third i

of the lower girth weld.

W X0464:1b/051590-A 2

l

~

A third area was s31::cted in SG 23,10" area b2low the girth wald, for additional i

' examinations. The remaining length of girth weld was examined and indications l

~-

were found.

The examination of the remaining areas 10" below the girth weld in three steam

- generatorsindentified additional ultrasonic indications. Examination of the fourth steam generator remains to be performed.

i Most of the indicatians result primarily from complex internal surface geometry left r

~ from earlier grind outs.- Resolution and characterization of all of the indications are Jin progress. UT indications are summarized below:

UltrasonicIndications SG21 SG22 SG23 SG24 Preliminary Evaluation (1) 20 114 28 (2)

Geometry, indications possibly related to internal / external surface configurations j

and sound redirection.

8 39 15 (2)

Possible sur face linear indications.

6 0

(2)

Possible subsurface inclusions in the 8" -

(

10" area below the girth weld.

(2)

Possible subsurface inclusions in the girth 1

5 weld area.

' Note (1) Ultrasonic indications listed are unique data points, e.g., one transducer, one location, one direction, and one signal. More than one ultrasonic indication typically results from one reflector.

i (2) SG 24 girth weld is scheduled to be UT examined when welding is complete in the upper areas.

2.3 Feedring Supports and Nozzle inner Radius (Knuckle) l 1

Visual and magnetic particle inspection of the nozzle inner radius, knuckle and welds of the support brackets beneath the feedring/ nozzle area for SG 22 and 23 revealed a number of linear indications. Subsequent inspection in $ team Generators 21 and 24 revealed similar indications. With the finding of linear indications in the nozzle area near the feedring support brackets, the inspection was extended to include all the other feedring support brackets and straps in all four steam generators. The indications associated with the feedring brackets and straps were predominantly in the shell/ nozzle heat-affected-zone (H AZ) adjacent to the weld.

All indications were removed by grinding. The indications and grind out depths are summarized below:

x0464:1b/051590-A 3

l i

y FEEDWATER RING SUPPORT BRACKETS AND STRAPS o

SG Location Minimum / Maximum Depth (!

21 Nozzle 0.09/0.44 Shell 0.12/0.45 22 Nozzle 0.20/0.40 Shell 0.10/0.60 23 Nozzle 0.05/0.70 i

Shell 0.12/0.48

-j 24 Nozzle 0.14/0.70 Shell 0.12/0.43 i

NOZZLE INNER i

RADIUS (KNUCKLE)

SG Maximum Depth (Inch) 21 0.125 to 0.4 22 None 23 0.13 f

24 T.B.D 2.4 Feedwater Nozzle Bore

' During the course of the grinding repair of the indications observed in the nozzle inner radius of Steam Generator 24, a number of indications appeared to extend

upstream along the bore of the nozzle. Access to this area is restricted by the -

- thermal sleeve which is attached to the feedring. As a result of this finding, thermal sleeves were removed from all four steam generators to allow an expanded inspection program for the feedwater nozzles. This program included visual, liquid penetrant and radiographic examination of all four nozzle to feedwater inlet piping welds; visual, liquid penetrant and ultrasonic examinations of all four nozzle bores, and a visual examination of the thermal sleeves. Linear indications were noted in the nozzle bore and feedwater pipe to nozzle weld. All indications were removed by grinding and subsequently weld repaired to original configuration with machining tolerances.

A summary of the indications seen as a result of the additionalinspections performed in the nozzle bores are summarized below:

i x0464:1b/051590-A 4

7 Q

NOZZLE BORE / NOZZLE TO PIPE WELD Maximum Depth (Inch)

SG Nozzle Bore Nozzle to Pipe Weld 21-0.198 0.318 22 0.295 0.388 23 0.217 0.200-24 0.347 0.270 2.5 Otherinspections in view of the reoccurrence of cracks found in the girth weld region and the UT indications found in the areas 10 inches below the girth weld, several other areas of steam generators which could be susceptible to cracking were inspected. The results of the inspection of areas away from the girth weld are as follows:

a)

Upper demister to shell weld, SG24 Visual examination; no indications b)

Level instrument tap, SG's 21 & 24 Visual examination; no linear indications c)

Secondary manway, SG 21 Magnetic Particle examination; no indications d) 6" handhole, SG 23 Dye penetrant examination; no linearindications e) 8" handhole, SG 23 Dye penetrant examination; no linearindications

- f) 1/3 sector of transition cone plate, UT examination; no indications including a longitudinal weld (full length) and 1/3 lower girth weld, SG 21 and 22.

g) 1/3 sector of the stub barrelto lower UT examination; no indications shell weld, SG 21 Indications had been earlier noted at locations which had been drilled in the field for the installation of inspection ports. These indications in the 1" inspection ports in the lower steam generator shell were located mainly in the 12 o' clock and 6 o' clock position relative to the axis of the hole. These were attributed to stress corrosion cracking resulting from the stress concentration from the drilled hole and aggravated by pitting. There have been no other indications in the base material or I

l

' x0464:1b451590 A 5

in cny undisturb:d crecs in the lower or the upper sh:ll below and above the girth weld.

The lack of indicatiens in the base material and in areas away from the girth weld can be attributed to several factors. Among them are 1) the girth weld stresses are higher due to the geometric discontinuity of the transition cone, and 2) the region of the girth weld is the region where the transients are the worst due to feedwater injection and mixing with the recirculating flow - away from the girth weld the thermal conditions are less severe. There has been no evidence of cracking in the undisturbed regions away from the girth weld.

2.6 FEEDWATER PIPING Feedwater piping upstream of the nozzles were inspected by VT and MT as far as accessible. Cracking was found along the bottom portion of all four leads. As a result sections of all four leads will be replaced prior to return to service. The approximate lengths to be replaced are: 9 ft,1 ft,4 ft and 9 ft for SGs 21,22,23 and 24, respectively.

The feedwater pipe cracking observed in this area is considered to be the result of thermal stratification. This occurs in the horizontal section of the feedwater pipe during the low flow auxiliary feedwater injection.

The Tee section of the main feedwater line where the auxiliary feedwater is injected (outside the vapor containment) was also examined with a fiberscope. No evidence of cracking was seen.

3.0 METALLURGICAL EVALUATIONS This section summarizesthe results of the metallurgicalinvestigation of boat samples containing indications from the steam generator girth weld, cone, feedring support and nozzle regions removed during the 1990 outage. The investigations included the following samples:

One boat from girth weld of SG #24 One boat from girth weld of SG #22 (at 1989 weld repair)

One boat from transition cone of SG #22 One boat from nozzle bore of SG #24 Three Feedring Supports from SG #22,23 and 24 The evaluations included surface examinations, non destructive evaluations, metallographic examinations, fractographic examinations, chemistry evaluations, mechanical property and hardness measurements. The overall results of the evaluations are summarized below.

x0464:1b951590 A 6

3.1 Girth Weld / Transition Cene Sampl2s The results of the surface examinations showed evidence of surface pitting and corrosion products on the boat samples. The ID surf ace indications seen were prirnarily associated with linked up surface pits and were oriented circumferentially at the cone and girth weld region. The results of the metallographic examinations by light optical and scanning electron microscopy techniques on transverse sections of the boat samples showed that the indications were cracks, initiated from the surface pits and covered with oxide. Multiple crack initiation was often seen originating from the pitting in the vicinity of the major cracks. The tracking exhibited minor branching although the crack growth was generally straight and followed a radially outward direction. The cracks were extensively filled with iron oxide deposits including the crack tip regions. The metallographic examinations showed that the pitting and crack initiation in the cone and girth weld samples occurred at either the weld metal, weld to base metalinterface or in the heat affected zone regions where residual stresses are likely to be present. The crack depths varied itom 0.065 in to 0.33 in, depending on the boat sample. The presence of copper, and occasionally zine and sulphur was seen in the crack deposits.

Chemistry evaluation of the crack deposits by Edax analysis ano wet chemistry analysis of the surf ace scrapings confirmed the presence of copper. Tht tewits of the hardness measurements of the heat affected zone and base metal regions in the near vicinity of the pitting and cracks, showed hardness values ranging from 20 to 37 Rockwell'C'in the heat affected zone region, and an average value of 91 Rockwell

'B'in the base metal.

The results of the fractographic examinations of samples taken during the 19G7, 1989 and 1990 inspections revealed evidence of two distinctly different modes of fracture morphology depending on the crack examined and the location of boat sample taken. The fracture morphology showed evidence of extensive beach marks in some cracks, suggesting crack extension under intermittent loading conditions, while other cracks showed smooth continuous crack extension characteristic of environmentally assisted crack growth under static load conditions.

3.21989 Weld Repair Area Sample Some light pitting was seen on the welded surface. These were shallow and widely scattered. Hardness survey showed values of 25 28 Rc in the weldment,23 31Rc in the heat affected zone, and 89 91 RB n the base metal. There were no cracksin this i

sample.

3.3 Nozzle Bore Sample Surface examination of the nozzle bore sample from steam generator 24 showed axial cracking associated with linked up surface pits. Metallographic examinations showed multiple crack initiation from oxide covered pits. The examinations further showed that the nozzle bore crack measured approximately 0.07 in. at its deepest location. Scanning Electron Microscope (SEM) fractographic examination of the endoxed fracture faces confirmed evidence of fine fatigue striations in the cracks x0464:1b@s1s90 A 7

c:ntaining beach marks suggesting the rcle of Inng:r rcnge f atigua lecds in th2 cracking process. The evidence of oxide covered pits, multiple crack initiation from the pits and the presence of copper contaminants suggest that cracking was initiated by the surface pits caused by corrosion. Replica transmission electron fractography examinations confirmed the presence of fine fatigue striations. The presence of fatigue striations confirm the mechanism of propagation to be corrosion fatigue.

3.4 Feedring Supports The feedring thermalliner support consists of two triangular gusset plates spanned by a shelf plate. The gussets were welded to the shell with a f ull penetration and a fillet weld all around. The shelf was welded to the gussets with fillet welds.

Cracking was seen in the gusset plates and at welds. Samples of brackets from all four generators were examined by Westinghouse, MIT, Lehigh, and Lucius Pitkin Inc.

Examination of SG 22 bracket showed straight, heavily corroded cracks with blunt, rounded tips, indicating that the cracks had been present for a long time and were non propagatmp Wiechanical properties, including fatigue endurance limit and impacutrengin were within 2hu:ceptable range and did not show any noticeable degradation.

3.5 Conclusion Samples taken during the 1987 and 1989 inspections showed extensive beach marks in the cracks, suggesting crack extension under intermittent loading. The fracture morphology of one of the 1989 samples and the 1990 samples, however, showed primarily a smooth continuous crack extension with slight branching characteristic of environmentally assisted crack growth under static load conditions. Since extensive corrosion was seen on the fracture surface, fatigue cannot be ruled out in these samples. Based on the overall results of the evaluation it is concluded that the cracking in the Indian Point Unit 2 steam generator girth weld and transition cone is caused by ' corrosion fatigue' and/or ' stress corrosion' mechanisms depending on the location, loads and environmental conditions. The cracking in the nozzle bore region is clearly caused by a corrosion fatigue mechanism." The presence of multitude of fine fatigue striations suggeststhat the cracking in the bore may have been induced by high cycle fatigue loads and may have occurred over a long period of time. Surface pitting contributed to the crack initiation.

4.0 BASIS OF EVALUATION In response to the NRC guidelines, fracture analyses were performed for all shell areas exhibiting indications to determine the necessary repair to meet flaw size allowables and to allow plant operation untilthe regular refueling outage. [

Ja,c are the most limiting transients since they cause the maximum temperature change in the girth weld region. With the implementation of the main feedwater bypass flow valve x0464:1bC51590-A 8

modificati::n during the 1989 refueling cutage, tho [

Ja.c is no longer considered limiting. This modification installed a timer that delays closure of the main feedwater flow regulator valves following a reactor trip. By providing hot main feedwater flow to the stream generator following a trip, the girth weld and feedwater nozzle are maintained in relatively warm water wher, the auxiliary feedwater enters these regions, thereby reducing the thermal loading.

With the elimination of [

Ja,c as a limiting transient, feedwater cycling was determined to be the likely limiting loading transient, and was selected for performing the stress and fracture mechanics analyses. Using the [

Ja,c and developing a stress intensity f actor for the various grind out areas, fracture mechanics evaluations were carried out for regions of the steam generator shell where indications were observed. At each grind out area, an indication was postulated with a growth rate equal to the maximum extension during the recent cycle. The depth of this indication was evaluated to assure that the NRC requested margin was demonstrated.

4.1 Acceptance Criteria - Girth Weld Region The criterion described in thissection has been applied to those areas where stress corrosion cracking may still be an active mechanism during the next nulf-cycle of operat!on.

i Failure by flaw instability at operating temperature will be by ductile tearing and not brittle fracture. The criterion discussed below does not take advantage of the much higher fracture resistance that would exist for limited stable crack extension.

The criterion is extremely conservative for the application at hand.

The approach used to demonstrate adequate margin for continued operation is based on a modification of the fracture mechanics criteria of Section XI of the ASME Code. The Section'XI fracture criteria are contained in paragraph IWB 3600 and are normally used to justify continued operation with cracks knowingly left in service.

For the case at hand, all cracks are being removed by grinding. Therefore, the Section XI criteria no longer explicitly applies. However,to provide further assurance that the steam generator integrity will be maintained through the operating cycle to the next refueling outage, modified Section XI fracture criteria have been applied to the repaired configuration, to show that any cracks which might initiate and grow during the next operating cycle will remain acceptable.

Specifically, the criterion to be applied has been obtained by reducing the material fracture toughness by a factor equal to the square root of 10, as taken from paragraph IWB 3612 of Section XI. Since the governing transient does not lower the temperature of the vessel to below 300*F, the fracture toughness of the materialis on the upper shelf, or at least 200 ksiVin. The allowable fracture toughness then becomes 200 divided by the square root of 10, or 63.2 ksi v'in. For each of the regions this criterion has been applied to hypothetical projected future crack growth. That is, the applied stress intensity factor for postulated flaws in each XO464:1bes1590-A 9

I ragion has b:en calculated as a function of flaw depth and limited to an allowable value. The evaluations, with results expressed in permitted days of operation as summarized in Section 5.0, have assumed flaws recur in all affected regions, with shape and orientation as found in the present inspection.

4.2 Methodology A methodology was developed for assessing the integrity of each area for which stress corrosion cracking remains a concern and for determining the appropriate actions to be taken to permit safety and operability. This methodology encompasses general integrity evaluations, grinding limitations and grindout contouring, and weld repair. The steps, generally, are as follows:

1)

Conservatively assuming that the existing stress corrosion cracks developed during the last operating cycle (212 days), the postulated cracks for an assurned operating cycle of 300 days are obtained by multiplying the depth of the observed cracks by 300/212. Such cracks will be referred to as " reference cracks".

2)

Obtain the stress distribution through the thickness of the wall for the load condition which producesthe maximum stresses normal to the observed cracks from the appropriate finite eiement analysis performed previously.

3)

Adjust stress distribution through thickness to account for reduced thickness after grindmg and for a range of stress concentration factors that could be introduced by the grind contour. The adjusted stress distributions have the same net force and moment acting on the reduced section as did the original stress distribution in step (2).

4)

Perform critical flaw size calculations for a range of aspect ratios for each of the stress distributions determined in step (3). Determine the maximum crack depths that satisfy the fracture criterion under consideration for each stress concentration factor and aspect ratio considered.

5)

The grind geometry after contouring is assumed to be a [

la,c The stress concentration produced by this geometry is obtained from the literature.

6)

The crack depth from step (1) along with the appropriate aspect ratio are used to determine the allowable stress concentration factor from the results obtained in step (4). If that stress concentration factor is greater than the one determined in step (5), then the [

la,c assumed for the grind geometry is acceptable. Otherwise, a slope is specified for the sides of the notch to reduce the stress concentration factor.

7)

The inspection reports of the grind locations and depths are then checked to determine whether the required grind contour can be performed without undercutting any adjacent structures, such as feedring support brackets.

x0464:1b/051590-A 10

Steps (1) through (4) above apply to all regions evaluated, while steps (5) through (7), as an example, are specific to the feedring support brackets A, B, C and the feedring strap weld pads, 4.3 Reference Crack Sizes Extensive evaluations were made of the cracking observed in the girth weld, transition cone brackets and straps after the last 212 days of operation, as determined by grinding cut the cracks. Per the definition of item (1) above, reference cracks for each of the locations and steam generators are given in Table

41. The crack growth rates are also given in terms of per day of service, The aspect ratios in Table 41 were conservatively determined by examining the array of crack lengths and depths measured in grinding out cracks. A statistical approach was used for determining aspect ratios associated with the girth welds and transition cones.

Upper bound values were used at the other locations. If the fracture toughness criteria under consideration (Sections 4.1) are satisfied, then 300 days of operation have been demonstrated, e

i x0464:1bS$1590-A 11

TABLE 41 REFERENCE CRACKS (300 DAYS OF OPERATION) FOR THE GIRTH WELD, TRANSITION CONES, BRACKETS AND STRAPS Crack Growth Crack Depth Steam Generator Location Rate (in./ day)

(in)

Aspect Ratio 21 Girth Weld 0.00170 0.51 4.4 22 Girth Weld 0.00250 0.75 4.4 23 Girth Weld 0.00130 0.39 4.4 24 Girth Weld 0.00160 0.48 4.4 All Transition Cone 0.00267 0.80 4.4 All All Bracketsa 0.00227 0.68 20b

& Straps T The brackets at the icedwater nozzle have been removed and new brackets installed away from the feedwater nozzle.

b This value is approximate.

l'

>5 xo464:1W$1590-A 12

5.0 RESULTS The reference cracks are given in Table 41. The fracture toughness criterion are presented in Section 4.1. Stress analyses results were obtained for all the pertinent configurations including contoured grinds for the situations where weld repairs are not made or are not made in full.

Fracture mechanics evaluations were performed using the reference cracks and stresses. The allowable toughness (63.2 ksiv'in) was used in establishing the days of operation for the steam generator girth weld / bracket / transition cone region during the next half cycle.

The results of the evaluation are summarized in Table 51. The fracture toughness criterion is satisfied for 300 days service in all areas except for the girth weld in steam generator 22 (271 days). With the extreme conservatism incorporated in the fracture toughness criterion,it is judged that 300 days of operation can be accomplished without compromising safety and reliability. It should be noted that the next operating cycle is to be 240 days.

xoas4:1 bests 90-A 13 l

TABLE 51 DAYS OF SERVICE BASED ON THE INTEGRITY EVALUATION FOR THE GIRTH WELD, TRANSITION CONE, BRACKETS AND STRAPS Days of Service Reference Based on

~

Steam Crack Aspect Kk = 63.2 Generator Location Depth (in.)b Ratio ksi Vin.

21 Girth weld (max. grind

{

depth of 0.78in.)

0.51 4.4

> 300 22 Girth weld (weld repaired to max. of 0.68 in.)a 0.75 4.4 271 23 Girth weld (max. grind depth of 1.01 in.)

0.39 4.4

> 300

=

?

?

24 Girth weld (mak. grited I

depth of 0.80 in.)

0.48 4.4

> 300 su All Transition tone 0.80 4.4

> 300 l

E All Brackets and straps s

(areat wed renaired tc

~

original configuration) 0.68 20

> 300 B

E E

All Brackets and $iraps g

(no we!d repairs) 0.68 20

> 300

-k Weld repaired to return wall thickness to within 0.68 inch of original.

a b Does not include the effect of mitigating actions to remove dissolved oxygen from the auxiliary feed water.

I W

E M

M x0464:1b/051590-A 14

~

6.0 REPAIR AND MITIGATING ACTIENS Based on the results of the evaluations described above, the actions taken have been either to restore the geometry to the original or modified configuration (nozzle area feedring support) by repair welding using the temper becd technique or to remove the indications by grinding and blending. Specific repair actions are described below for each affected region.

6.1 Girth Weld and Brackets Several areas have been repair welded. These are 1) the girth weld in SG 22 (to a maximum thickness reduction of 0.68 inch),2) shell regions adjacent to feedring support brackets and straps. Except for the girth weld in SG 22, the repair welding I

has restored each region to its original geometry. In addition, the feedring support at the feedwater nozzle has been redesigned to relocate the brackets welded to the shellin a more favorable position.

As described in Section 5.0, the girth weld in SG 22,in its repair walded condition (maximum thickness reduction of 0.68 inch), satisfies the ASME Code for an operating period of 271 days.This result is based on the assumption that the most recent maximum rate of increase in crack depth will continue during the next operating period with an aspect ratio developed in Section 4.3.

j A number of regions of the shall adjacent to the feedring brackets straps away from the feedwater nozzle have been repair welded. This action has been taken even though it is our opinion that it is not required. It is our judgment that the cracking in these regions is induced by SCC and has occuned over the total operating period of the plant, and not during the most rerer;t cycle. Also, the maximum depth of penetration has been considerably less than that in the girth weid region. Due the lack of precae measurements in comparison to the girth weld region, considerab!y higher aspect ratics had to be assumed than could be justified for the girth weld.

The A bracket in SG 24 and the A & B brackets in SG 22 were detected to be cracked at the joint between the gusset and the stub that is welded to the shell. This degradation is not believed to be associated with any mechanically or thermally induced load. None of the brackets reflect any evidence of vibratory motion of the feedring and none of the feedring brackets away from the feedwater nozzle are bent or otherwise distort d. The brackets have been restored to their original configuration.

The feedring support adjacent to the feedwater nozzle has been redesigned to allow locating the brackets that are welded to the shell in a lower stressed region and to minimize the potential for cold bypass flow below the liner which can cause thermally induced loadings on the brackets. The stiffness of the bracket support for the feedring has been retained to avoid any vibration induced loadings of the feedring. T;. potential seismic loadings on any of the feedring supports is well within the capability of the supports to meet ASME Code allowables.

X0464:1tW51590-A 15

The degraded areas rapaired by grinding and conteuring include 1) areas not welded in the girth weld of SG 22 and the girth welds of SG 21,23, and 24,2) the transition cone below the girth weld in SG's 22 and 3) the unwelded regions of the shell adjacent to the feedring supports away from the feedwater nozzle. As described in Section 5.0, all of these regions meet the factor of safety of the ASME Code, as applied to critical flaw size, for an operating period of 300 days.

6.2 Feedwater Nozzle Region The feedwater pipe, feedwater nozzle / pipe joint (counterbore), the nozzle inner bore, the knuckle region (inner radius) and the shell face of the nozzle forging just below the knuckle have all been restored to the original design configuration by repair welding, using the temper bead technique.

The cracking at the feedwater pipe and feedwater nozzle to pipe joint are judged to be consistent with prior experiences in this region at other plants where the cracking mechanism was concluded to be the result of thermal stratification and striping during periods of auxiliary feedwaterinjection. Several other utilities have replaced in kind in this region previously and the action taken at Indian Point 2 to replace pipe section and to reweld the nozzle / pipe joint is consistent with these prior actions. The time to crack in this region by corrosion fatigue requires years to initiate and is therefore a sufficient action for the remainder of this current cycle.

The inner bore boat sample examination confirms the expected mechanism of corrosion fatigue consistent with the pipe to nozzle joint. Compared to the pipe to nozzle joint, however,it is be!ieved that the inner bore is a less critical location. The inner bore is less susceptible to crack propagation from stratification and is in a much thicker region of the nozzle. The principalloading mechanism associated with the i

corrosion fatigue degradation is pronably striping, a high cycle low stress amphtude oscillation,that by itself would not cause rapn r: rap 49etion.

The relocation of the feedwater ring support brackets from the nozzle area removes a potential source of additional stresses from the nozzle shell face area.

With a corrosion fatigue mechanism induced during periods of injection of cold, oxygenated, low flow rate feedwater the critical mode of operation is [

]a.c During this time, thermal stratification and striping occur at various locations in the feedwater nozzle and pipe. This thermal i

loading phenomena was thoroughly evaluated previously and published in WCAP-12293 by Westinghouse. The operating history at Indian Point 2 a decline in the time spent at hot standby. From 1971 through 1987, the average number of days at hot standby was 25 per year. During the last full operating cycle in 1988-1989, the average was 14 days of hot standby per year, and in this last half cycle (1989-1990),

the operation corresponded to 7 days of hot standby per year.

An evaluation of each of these repaired nozzle regions has been performed assuming that corrosion fatigue cracks are regenerated (or continue to occur in unrepaired areas). The approach used and results obtained are described in detailin XO4r>A.1bC51590 A 16 l

Appendix A. The reprired r:gions satisfy the frtcturo critoria applird with the i

assumption of future cracking. This is very conservative as the mitigating actions taken to remove the dissolved oxygen from the auxiliary feedwater are expected to considerably retard the process of pitting, crack initiation and propagation.

1 6.3 Oxygen Control of Auxiliary Feedwater During normal plant operation, low levels of oxygen in steam generator feedwater is maintained due to operation of the condenser. This assures hot condensate collected under vacuum and the addition of hydrazine. The dissolved oxygen

)

content in the feedwater has declined over the past years and in 1989 averaged approximately 2 PPB. By comparison the industry guideline is 10 PPB. However, during hot standby, cold oxygenated water is drawn from the Condensate Storage Tank.

The Condensate Storage Tank contains a floating rubber diaphragm to inhibit oxygen from the atme: sphere dissolving in the deaerated water returned from the condenser. However, the space below the diaphragm is vented to the atmosphere by an 8" pipe to telease insoluble gas build-up. This same 8" vent provides a path for atmospheric oxygen to dissolve in the stored deaerated water. A modification is being implemented prior to return to service which will permit the introduction of nitrcgen into the bottom of the tank. The nitrogen will act as a cover gas between the water and the diaphragm. In addition the nitrogen will be maintained at a slightly positive pressure and will purge the vent line blocking the entrance of oxygen into the condensate tank. The presence of nitrogen wHi also inhibit the introducticn of air when the levelin the condensate Sterage Tank is lowered as well as provide a means of displacing any air which enters during a level change.

7.0 FUTURE Pl.ANS Con Edison has conciuded that the uscking which has been obsm ved in the girthweid and nearby shell, nozzles and support brackett is the result of a l

combination of fatigue and stress corrosion. The fatigue loading is created by the effects of thermal transients on the shell and internal materials and the corrosion is mainly caused by condensate storage tank, condenser and feedwater heater design and materials selection, which have contributed to oxygen and copper l

concentrations. Measures have been taken and are being taken to reduce or eliminate the adverse internal steam generator environmental conditions.

Reduction of the thermal transient and oxygen, coupled with the thorough examinations and extensive repairs performed during this outage on the girth weld, nozzles and support brackets,is expected to minimize the recurrence of cracking during the next cycle of operation. Nonetheless, Con Edison is preparing to reinspect during the 1991 refueling outage and to take appropriate measures based on the inspection results.

l l

l l

x0464:1b451590.A 17

}

l. Insp?ction Proaram for 1991 Refuelina Outaae 1.

Inspect by MT all steam generators girthwelds. Inspect by UT a band 360 deg.,

14" down from centerline of girth weld in SG 22. If defects are found, inspect all steam generators.

2.

Inspect by MT feed ring brackets and bracket welds in all steam generators.

3.

Inspect by UT one nozzle knuckle and accessible nozzle areas, if indications are found that extend into the inaccessible bore area, pull thermal sleeve from the nozzle and inspect bore by MT. If indications are found, inspect nozzle bores in all steam generators.

4.

Inspect by MT or PT lower 180 deg. of all nozzle knuckles, if indications are found, inspect 360 degrees of all steam generator nozzle knuckles.

5.

Radiograph one nozzle to pipe weld and compare with asleft radiographs. If indications are found, inspect the nozzle-to-pipe welds in all steam generators.

6.

Inspect by UT an area in the feed pipe from the nozzle-to-pipe weld to one foot out in SG 22. If indications are found, inspect horizontal runs to the first cibow for all steam generators.

7 inspect by MT or PT the upper Sin handhole in SG 23, hillside port in SGs 22 and 23, one-6 in, handhole, manway ar.d one 3/4 in. upper and lower level instrument tep penetration. It indications are found, inspect alllike components to the ones showing indications.

11. Conective Actions if the 1991 inspection shows a raunence of cracking, similar to that experienced during the most recent period of operation, con Edison wili be prepared to implement a corrective plan based upon the following:

1.

Implement repairs to provide for uninterrupted operation between refueling cycles. These repairs could include:

Machining a 360 deg band up to 6 in, wide and 1 in, deep in the girth weld a.

and build up to original contour.

b.

Resurface the feedwater nozzle bores by machining to a depth of 1/2 in.

and weld back to original contour, or replace the feedwater nozzle.

c.

Eliminate bypass flow ia the feedwater nozzle.

d.

Install new feedwater ring header brackets.

X0464:WO51590-A l8 m

m__

2.

During substquant outag2s, and continuing until the existing steam generators are retired from service, Con Edison will perform such inspections

~

and repairs as may be necessary to insure e.ompliance with the applicable provisions of ASME B&PV Code prior to return to service.

111. Condenser and Feed Water Heater Chanae Out 1.

Conduct a corrosion product transport survey during the upcoming operating period.

2.

During 1991 Refueling Outage:

[

Change one condenser from Admiralty tubing to titanium tubing.

3.

During 1993 Ref ueling Outage:

Change remaining Admiralty condensersto titanium tubing and remaining feedwater heaters from copper alloy tubing to stainless tubing.

IV. Lona Ranae Plannina Con Edison will continue to evaluate and monitor the causal mechanism for the existing cracking, as well as the cost, man-rem, safety, unit reliability and urit availability considerations associated with continued operatior' w;th the existing steem generators contrasted with steam generator replacement These issues will be g

reassessed following evaluation of steam generator condition during the 1991 outage.

E in addition, Con Edison will initiate planning for full reactor coolant loop

[-

decontamination (fuel removed) for possible implementation dunno the 1993 L

outage. If determmd to be feasible and effective, decontamination would reduce i

source term, thereby reducing routine worker exposure as well as exposure that might result at such time as the existing steam generators are retired.

8.0 CONCLUSION

S e

The inspection and subsequent repair and analysis has been performed to demonstrate continued operation of Indian Point Unit 2. The inspection program was expanded until all areas containing potential indications were enveloped.

Subsequent repair activities removed all indications, and, where applicable, the ground areas were restored to original geometry by welding.

As was specified during the March 14,1990 meeting, the approach used to demonstrate adequate margin in the steam generator girth weld for continued operation is based on a mooification of the fracture mechanics criteria of Section XI of the ASME Code. The Section XI fracture criteria found in paragraph IWB 3600 are normally used to justify continued operation without removal of cracks. In this case, x0464: 1 b/051590-A 19

cilindications have boon removsd by grinding and the grind out areas have been partially or completely restored by welding.

The repair of the indications observed in the feedwater nozzle area was accomplished by grinding and restoring to original geometry by welding. To further address the indications seen in the H AZ of the feedring brackets near the nozzle, the brackets were redesigned to relocate them to a more favorable position. The nozzle indications are caused by thermal striping and stratification during cold water injection. Results of the evaluation of the boat sample removed from SG 24 nozzle showed the cracking mechanism to be corrosion fatigue. Visual examination showed significant surf ace pitting with shallow cracks linking the pits.

Continued c2eration of the unit following removal of allindicationsin the girth weld, nozzle and feedring support brackets has been justified. All repaired areas exhibiting susceptibility to stress corrosion cracking have been evaluated against the ASME Section XI fracture criteria which is normally used to justify continued operation without removal of the indications. The corrosion fatigue mechanisms of the feedwater nozzle was evaluated using very conservative component fracture specific criteria. All cracks have been removed by grinding and where applicable the ground areas have been restored to original geometry by welding. Considering the conservatisms applied throughout the activities,it is our judgment that operation to the next refueling cycle is justified without any detriment to the structural integrity of the steam generator. The justification for continued operation assumes that the indications will initiate and contir.uo to grow at the same r.ste as in the previous cycle. We believe that the mitigating actionsto remove the dissolved oxygen Dom the auxi!!ary feedwater being implemented now will significantly retard the process of pitting, crack initiation and growth, and make the analysa presented in this report even more conservative.

l x0464:1bC51590-A 20 m

m---

APPENDIX A A MECHANISTIC APPROACH TO INTEGRITY EVALUATIONS OF THE FEEDWATER NOZZLE REGION

\\;

1 1

XO464:1t451590 A 21

A.1 INTRODUCTION in Sections 4.0 and 5.0 integrity evaluations were presented for these areas for which stress corrosion cracking may remain a concern. The areas evaluated were the girth weld, transition cone, brackets and straps. In this appendix, an integrity evaluation is presented for the feedwater nozzle face, knuckle, bore and nozzle-to-pipe joint (i.e., courterbore) where the mechanism is confirmed by boat sample examination to be corrosion fatigue.

A.2 CRACKING MECHANISMS Cracks have been found in the feedwater nozzle faces adjacent to the feedring support brackets,in the feedwater nozzle faces between bracket welds,in the knuckles and bores and at the feedwater nozzle counterbores.

At the feedwater nozzle brackets welds it is judged that stress corrosion cracking is a

=

large contributor to the crack extension. All the conditions for stress corrosion cracking exist in addition to a fatigue component due to bypass flow during the feedwater cycling at hot standby. However, the nozzle brackets have been removed and new brackets placed away from the feedwater nozzle. Since the potential for stress corrosion tracking would still exist for these brackets, they now fall under the category of " brackets and strans (areas weld repaired to original configurations),"

the integrity of which has been previously addressed in Section 5.0 (see Table 5-1).

j a

The cracking at the remaining locations et the fcedwater nezzle are judged to be due to corrosior. fatigue as confirmed by the boat sarapie removed from a nozzle a

bore (see Section 3.0). The root cause of the cracking in tne shell f ace, knuckle and bore is judged to be predominantly thermal striping (high cyck fatigue) due ta bypass flow behind the theimal sleese. Thermal str stification (Iow cy;te fatigue) is judged to be the dominant ioading for the counterbrxe based en prior experience.

These loadings occur dunng feedwater cycling at hot stardby.

I A.3 EVALUATION OF HOT STANDBY To date, Indian Point Unit 2 has been at hot standby 9860 hours0.114 days <br />2.739 hours <br />0.0163 weeks <br />0.00375 months <br /> including the last one-half cycle. Over the life of the plant,the average number of days at hot standby is 25 days / year. For the last full cycle the average is 14 days / year. For the half cycle just completed, the average is slightly less than 7 dayt' year.

The significance of the above numbers is two-fold. First,it is reasonable to assume that any crack growth in the remaining areas of interest occurred dunng hot standby as discussed previously. Secondly, the recently noted times at hot standby indicate a lessening of corrosion fatigue while at the same time enhancing plant performance.

A.4 CRACK GROWTH RATES AT HOT STANDBY Failure by fatigue of a component with a smooth surface consists of two stages -

crack incubation without crack formation and crack extension to failure. The cycles XO464 1 b/051590- A 22

=

1 of crack extension in some cases may be but a small portion of the total cycles,1 to 10 not being unreasonable.

For this evaluation it is conservatively assumed that the cycles associated with crack extension both by high cycle and low cycle fatigue makeup only [ ]a,c of the total number of cycles [

]a c in the counterbore and nozzle inner bore the crack initiation and propagation is considered to be the result of cycling at hot standby for the service life to date of the plant. On the other hand, for the cracking occurring in areas which previously contained no cracks or in which cracks were ground out,it is assumed that they have grown to the depth observed in the four days at hot standby experienced in the just completed one-half cycle.

For those locations where the service life to date can be associated with the corrosion fatigue crack growth, the hours for which the crack has been growing is

[

la.c (i.e., [

la.c) or [

]a.c The cracks associated with the bore and nozzle-to-pipe joint are postulated to have reached their observed depths over [

la c at hot standby while the recently observed cracks at the nozzle f ace between the bracket welds and the knuckle cracks are postulated to have reached their observed depths over just four days at hot standby. Thus the crack growth rates in these areas can be expressed in it'ch/DHSB where DHSB is cay at hot standby. T he rates at the four nozzle regions of interest are given in Table A-1.

A.5 AN ALTERNATIVE FRACTURITOUGHNESS CRITERION It must be recognized that failure for the cases at hand by flaw instability at operating temperature will bc by ductile tearing and not brittle fracture. By applying an arbitrary brittle fracture k criterion such as K c = 200 ksi s/in, advaraage i

is not taken of the mucn higher K values (as obtained from )-inteoral vt. lues) that would exist for limited stubie crack extension. It is also recognized tnat a fatigue mechanism dominates the crack extension of interest here, such a mechanism being reasonably well understood and quantifiable.

A fracture toughness criterion for the nozzle face, knuckle and bore is first investigated.

A data base was established for upper shelf Charpy impact energy vs. Kic as lower bound values obtained from fracture toughness specimens between 3 and 4 inches in thickness, cons; stent with the minimum thickness of the steam generator of 3.5 inches. Over 75% of the materialinvolved was either 302B steel or 3028 steel nickel modified. All heats were typical of the steel making practice in the 1960's. Charpy impact energy values varied between 35 and 124 ft. Ibs. while the measured K c i

values ranged f rom 153 to 399 ksi s/in.

A linear correlation was performed on the data. A good fit was obtained with the standard error being 18.6 ksi s/in. (i.e.,le;s than 12.5% of the least K ci of the data base).

XO464 ' 1 bo51590- A 23

TABLE A 1 CRACK GROWTH RATES FOR THE NOZZLE REGION Crack Days at Hot Crack Aspect Growth Steam Location St

{D Depth Ratio Rate Generator (in./DHSB)

All Nozzle Face 4

0.290 10 0.0725 All Knuckle 4

0.130 NAa 0.0325 All Knuckle 20.54 0.400b NA 0.0195 21 Bore 20.54 0.198 10 0.0096 22 Bore 20.54 0.259 10 0.0126 23 Bore 20.54 0.217 10 0.0106 24 Bore 20.54 0.347 10 0.0169 21 Counterborec 20.54 0.318 100 0.0155 22 Counterbore 20.54 0.338 100 0.0165 23 Counterbore 20.54 0.200 100 0.0097 24 Counterbore 20.54 0.270 100 0.0131

~~

~

Not applicable b Upper bould value bawd on prindout during 1989 outage c

Nozzle terpioe;o!nt The Certified Materials Tests Reports (CMTRs) were examinea for the feedwater nozzles. Charpy impact energy tests of 10 F were required for each heat. At operating temperature the Charpy data would be greater. A total of 12 Charpy energies were available. The lowest Charpy datum was used to establish the attendant Kic based on the above correlation at the lower 99% confidence limit. The corresponding Kic was 145 ksi Vin.

A similar evaluation as above was made to determine the appropriate Kic to use for the minimum counterbore thickness of 0.688 in. Data from specimens only with thicknesses between 0.394 in, and 1 in, were used in the correlation. The value at the lower 99% confidence limit is 93 ksi Vin.

In summary, the material specific statistically based 99% lower confidence limit K ci for the thicker section of the nozzle forging is 145 ksi Vin. This is the value to be used for evaluating the face, knuckle and bore of the feedwater nozzle. For the counterbore the Kic to be used is 93 ksi Vin.

The fracture toughness is conservative not only because the 99% lower confidence limits are used in establishing the value from the correlation but also because the x0464:1bS$1590-A 24

e i

Charpy impact data frcm the CMTRs wara cbtain d at 10'F, undoubt:dly in the transition temperature region of the material. Although at operating temperatures Charpy impact values approaching or exceeding 100 ft Ibs are anticipated, only the fracture toughnesses confirmed by actual data are used. Based on these conservatisms and those of the stress and fracture analyses,the conclusions stated j

below are fully justified.

{

A.6 STABILITY EVALUATION OF THE NOZZLE REGION As previously discussed this integrity evaluation is in terms of the number of allowable days at hot standby, not the days during power operation. Using the j

finite element through-wall stress results and the aspect ratios given in Table A-1 for each location, a parametric study of crack depths was made to determine the allowable crack depth satisfying the appropriate fracture toughnest criteria. Such a crack depth divided by the crack growth rate in inch /DHSB gives the number of l

allowable days of hot standby. The results are given in Table A-2.

A.7 DISCUSSION AND CONCLUSIONS Table A-2 shows that 14 days at hot standby are the limiting acceptable days at hot standby for the next one half operating cycle. Based on the recent operating experience at Indian Point Unit 2, a fuli year of operation should be attainable without postulated crack depths exceeding allowable values.

3 x0464:1b/051590 A 25

o TABLE A 2 ALLOWABLE DAYS AT HOT STANDBY BASED ON THE INTEGRITY EVALUATION Crack Allowable Allowable Location Crack Depth Asp h

p,t Ra Days at Hot Ge e a or II")

(in/DHSB)

Standby All Nozzle-f; ace 1.020 10 0.0725 14 All Knuckle 1.442 NAa 0.0325 44 All Knuckleb 1,442 NA 0.0195 74 21 Bore 0.929 10 0.0096 97 22 Bore 0.929 10 0.0126 74 23 Bore 0.929 10 0.0106 88 24 Bore 0.929 10 0.0169 55

~

21 Co'unterborec 0.472 100 0.0155 30 j

22 Counterboree 0.472 100 0.0165 29 23 Counterborec 0.472 100 0.0097 49 24 Counterborec 0.472 100 0.0131 36 Not applicable a

b Upper bound of 0.4 in. in 20.54 days at hot standby Nozzle-to-pipe joint c

x0464:1be51590-A 26 l