ML20078C518

Technical Evaluation of Hybrid Expansion Joint Sleeved Tubes Containing Indications within Upper Joint

ML20078C518
Person / Time
Site:	Point Beach
Issue date:	08/31/1994
From:	WESTINGHOUSE ELECTRIC COMPANY, DIV OF CBS CORP.
To:
Shared Package
ML20078C290	List: ML20078C288 ML20078C316 ML20078C347 ML20078C361 ML20078C518 ML20078C522
References
SG-94-09-018, SG-94-9-18, WCAP-14182, NUDOCS 9410310294
Download: ML20078C518 (50)

Text

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Westinghousa Non-Proprietary Class 3 I

_ WCAP-14182_

SG-94-09-018 t

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i Technical Evaluation of Hybrid Expansion Joint (HEJ) Sleeved Tubes Containing Indications Within the Upper Joint August 1994 t

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@ 1994 WESTINGHOUSE ELECTRIC CORPORATION l

All Rights Reserved t

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9410310294 941021 PDR ADOCK 05000266 PDR

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Technical Evaluation of Hybrid Expansion Joint (HEJ)

Sleeved Tubes With Indications Within the Upper Joint Zone TABLE OF CONTENTS SECTION PAGE 1.0 Intradefm 1-1 2.0 Summary and Conclusions 2-1 2.1 Indication Location 2-1 2.2 Allowable Beginning of Cycle Indication Arc Length 2-2 2.3 AxialIndications 2-2 3.0 RegulatoryRequirements 3-1 3.1 Regulatory Guide 1.121 3-1 l

3.2 Accident Condition Allowable Leak Rate 3-2 4.0 Field Experience 4-1 4.1 HEJ Sleeved Tube Indications 4-1 4.2 CircumferentialIndication Growth Rates 4-2 5.0 Test Program and Results 5-1 5.1 Test Samples 5-1 5.2 Test Program 5-2 I

5.2.1 Pull Out Test 5-2 '

5.2.2 LeakageIntegrityTests 5-2 5.2.3 Hydraulic ProofTests 5-3 5.3 Test Results 5-3 5.3.1 Pull Out Test Program 5-3 5.3.2 Leak Tests 5-4 L

5.4 Hydraulic ProofTests 5-4 5.5 Supplemental Axialload and Leak Rate Tests 5-4 l

6.0 Analytical Approach 6-1 6.1 StructuralModelDescription 6-1 6.2 Tube Integrity Considerations 6-1 6.3 Additional Tube Integrity Considerations 6-3 7.0 Plugging or Repair Criteria for Parent Tube Indications 7-1 i

7.1 Compliance With Regulatory Guide 1.121 Tube Integrity Criteria 7-1 7.2 Offsite Does Evaluation For a Postulated Main Steam Line Break 7-2 Event Outside of Containment but Upstream of the Main Steamline l

Isolation Valve 7.3 Evaluation of Other Steam Loss Accidents 7-2 i

7.4 HEJ Inspection Requirements 7-3 l

l 8.0 Sumnwy of Sleeve Degradation Limit Acceptance Criteria 8-1 i

8.1 StructuralConsiderations 8-1 1

8.1.1 Crack Indications Below the Upper Hardrolllower Transition 8-1 8.1.2 Sleeved Tube with Degradation Indications with Non-Dented 8-1 Tube Support Plate Intersections 8.1.3 Dented Tubes 8-1 8.2 Leakage Anaument 8-2 8.3 Defense In Depth and Primary to Secondary Leakage Limits 8-2 9.0 References 9-1

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Technical Evaluation of Hybrid Expansion Joint (HEJ)

Sleeved Tubes With Indications Within the Upper Joint Zone I

1.0 Introduction The purpose of this document is provide modification information related to the structural integrity of the hybrid expansion joints (HEI) in sleeved steam generator (SG) tubes. A listing of Westinghouse WCAP documents modified by this report is contained in Table 1-1. Analytical and testing evaluations have been performed which indicate that the parent tube has significantly more stmetural integrity relative to that originally specified in the original qualification documents (Table 1-1) with regard to operation with implied or known crack-like nondestructive examinations.

Information is presented herein which supports the implementation of revised inspection criteria relative to repairing or removing HEJ sleeved tubes from service.

In accordance with Plant Technical Specification requirements, steam generator tubes are periodically inspected for degradation using non-destmetive examination (NDE) techniques. If established degradation acceptance criteria are exceeded, the indication must be removed from i

service by plugging or repairing the tube. Tube sleeving is one repair technique used to return a tube to an operable condition.

In the sleeving technique, a smaller diameter tube, or sleeve, is positioned within the parent tube so as to span the degraded region. The ends of the sleeve are then secured to the parent tube forming a new pressure boundary and structural element between the attachment pcints. Sleeves may be positioned at any location along the straight length of a tube, but are typically placed to repair tube degradation at the top of or within the tubesheet, or at tube support plate (TSP) intersections.

Sleeves may be ofvarious lengths and may be attached to the parent tube in a variety of ways. In the case ofWestinghouse sleeve designs, the method of attachment is generally restricted to either a leak limiting mechanical HEJ or a hermetic Laser Welded Sleeve (LWS) joint. The type of the particularjoint configuration is a function of the date ofinstallation and/or the customers needs and the current plant operating conditions. Figure 1-1 shows a schematic of a typical HEJ tubesheet sleeve installation. Figure 1-2 illustrates the details of the upperjoint along with terminology used j

in this report. Note that only the upperjoint is an HEJ, however the sleeve is referred to as an HEJ sleeve. Although the lowerjoint of an HEJ sleeve consists of a hydraulic expansion and hard j

roll as well, it is not referred to as an HEJ Joint.

As shown in Table 1-2, since its inception in 1980, the HEJ sleeve has been successfully used to restore over [

[ to operational status. However, due to

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]d The purpose of this report is to provide an assessment of HEJ integrity for HEJ sleeves in service in 7/8" outside diameter tubes. Operating HEJ sleeves are currently in service in the United States at the Point Beach Unit 2, Zion Unit 1, D. C. Cook Unit 1, and Kewaunee nuclear power plants.

The HEJ sleeves listed in Table 1-2, installed over the time period of from April 1983, to May 1993, have operated without incidence ofleakage through the upperjoint. Moreover, until April of 1994 there had been no reports of apparent degradation. [

8]d In April of 1994, seventy-eight (78) indications were reported in the vicinity of the upper sleeve joint (above the top of the tubesheet) of tubes at the Kewaunee Nuclear Power Plant (KNPP).

Sixty-six (66) of the indications were determined to be within the upperjoint region. Of these, forty-eight (48) were reported in SG A and eighteen (18) were reported in SG B. The indications were found during an eddy current examination of sleeved tubes using a Motorized Rotating Pancake Coil (MRPC) eddy current probe designed to inspect the sleeve expansion joints. The indications were initially identified as axial indications in the upper sleeve joint zone of the parent tube, but laterjudged to be circumferential in nature. Owing to their location the indications are thought to be outside diameter stress corrosion cracking (ODSCC).

Structural analyses and strength tests were performed which demonstrated that degradation of any extent below the bottom of the hardroll transition could be tolerated without separation of the tube from the sleeve. The requirements considered for these assessments were a margin of three against separation during normal operation, and a margin of 1.43 against separation during a postulated steam line break (SLB) event. These parallel the draft Regulatory Guide (RG) 1.121 requirements l

for protection against burst for tubes subject to degradation. Assuming the circumferential indications to be crack-like in nature, analyses were performed which demonstrated that the same margins against failure of the tube-to-sleevejoint would be present if the circumferential extent did not exceed 224 for lower tolerance strength tube material without consideration of strain l

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r hardening during the formation of thejoint. [

]" could be tolerated without violation of the RG 1.121 requirements for a cycle of operation (taken as about 1 year).

Testing was also performed to estimate the potential leakage from tubes which experienced j

postulated 360* throughwall cracking. The results of these tests indicated very low leakage could be expected if the cracks were located at the bottom of the hardroll tower transition or lower.

To provide the technical basis for the operating integrity ofHEJ sleeved tubes, the regulatory guide j

requirements were evaluated (Section 3.0), and the field operating experience scomudated for tubes repaired using the HEJ sleeve were reviewed (Section 4.0). A review of the test programs performed to support continued operation with parent tube indications remaining in service is provided in Section 5.0 of this report. A summary of the analysis performed on the HEJ sleeve design is provided in Section 6.0, and proposed plugging or repair criteria for the parent tube indications is contained in Section 7.0.

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Table 1-1: Document Applicability, Sleeving Design Documents Modified by this Evaluation Report Design Document Subject Reference (s)

WCAP-9960 Point Beach Unit 2, Alloy 600 sleeves 1, 2 WCAP-11573 Point Beach Unit 2, Alloy 690 Sleeves 4

WCAP-11643 Kewaunee, Alloy 690 Sleeves 5

l WCAP-11669 Zion Units 1 & 2, Alloy 690 Sieeves 6

WCAP-12623 D. C. Cook Unit 1, Alloy 690 Sleeves 7

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2.0 Summary and Conclusions This repon documents the technicaljustification and outlines the particular aspects of proposed criteria to support the continued safe operation of sleeved tubes with [

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The burst criteria of draft RG 1.121 are used to establish operability of parent tube degradation such that continued safe operation of the steam generators is not compromised. In addition, ongoing testing is being performed to establish and validate the operating safety margin associated with degraded HEJ joints addressed by this report.

Potential primary-to-secondary steam generator tube leakage will be calculated for indications remaining in-service due to application of the proposed criteria. This leakage will be compared against the allowable leakage as determined using NUREG-0800 calculation guidelines.

The criteria will be implemented in concert with an operational leakage limit of 150 gpd and enhanced inspection criteria designed to quantify the size and location of potentially crack-like indications. [

]* Further thejoint integrity is based l

on an ongoing mechanical test program supplemented by analytical assumptions. This l

document is applicable to the HEJs in service in SGs at Point Beach Unit 2, D. C. Cook Unit 1, Zion Unit 1, and Kewaunee.

2.1 Indication Location Tests conducted in joints designed to simulate a 360 throughwall crack have shown that the l

upper hardroll must have additional axial load carrying capability to supplement the radial I

contact pressure of the sleeve-to-tube interface. To comply with this condition,360 circumferential indications in the sleeve joint must be limited to the lower traraition region of tre hardrolled zone.

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2.2 Allowable Beginning of Cycle (BOC) Indication Arc Length In concert with limiting circumferential indications to the upperjoint lower hardroll transition region, for added conservatism, the arc length should also be controlled. [

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3.0 Regulatory Requirements In order to repair SG tubes, an integrated qualification plan was developed to demonstrate the acceptability of the sleeve-to-parent tube joint. Documentation of the sleeve design and attendant analyses of Alloy 600 and 690 thermally treated HEJ sleeves for the repair of SG tubes are contained in Westinghouse technical reports referred to as WCAPs. These reports describe the theory of the repair approach, the design basis for the repair, the testing and analysis used to support the acceptability of the repair technique, and the method used to demonstrate acceptability of the repair following its application. A similar approach is taken in this report. The limits of acceptable degradation of the parent tube in the HEJ hardroll lower transition are established such that the design basis of the sleeve is not significantly compromised. A listing of the WCAP reports applicable to the plants in question was provided in Table 1-1 (Section 1).

Current WCAPs define the sleeving application and repair limits. They define the zones ofin-service-inspection for the sleeve, and the limit of acceptable sleeve and sleevejoint degradation.

The sleeved tube inspection requirements and repair criteria are summarized in Figure 3-1.

Based upon the KNPP experience, it is evident that the parent tube material in the vicinity of the HEJ hardroll lower transition may be subject to in-service degradation. In order to prevent the unnecessary plugging of potentially degraded sleeved tubes, the structural integrity of the degraded joints may be evaluated against the burst criteria of draft RG 1.121. In addition, the leakage integrity of the sleeve-to-tubejoint of potentially degraded sleeved tubes should not represent r. potential for offsite doses to exceed the limits defined in Title 10 of the Code of Federal Regulations Part 100 (10 CFR 100).

RG 1.121 describes a method acceptable to the NRC staff for meeting General Design Criteria 14,15,31 and 32 by reducing the probability and consequences of steam generator tube rupture through determining the limiting safe conditions of degradation of steam generator tubing, beyond which tubes with unacceptable cracking, as established by in-service inspection, should be removed from service or repaired. The proposed criteria may result in tubes with both partial and complete throughwall cracks being returned to service. In the limiting case, the presence of a throughwall crack alone is not reason enough to remove a tube from service. The regulatory basis for leaving these indications in service is discussed below.

3.1 Regulatory Guide 1.121 In evaluating the proposed criteria, the elevation of the indications (in the tube span between the tubesheet and first tube support plate) must not be used to wholeheartedly eliminate its use.

The HEJ joint inherently provides protection to tube burst and significant leakage. The NRC staff has defined tube rupture in NUREG-0844 as an uncontrollable release of reactor coolant in nrma 3-1 m sa w -

excess of the normal makeup capacity. Examining the upper HEJ tube burst would only be expected if a circumferential separation of the parent tube is postulated, and the parent tube then pushed out ofintimate contact with the sleeve due to operational or faulted load conditions.

These loads are generated by the pressure differential across the tube wall, represented by the tube end cap loads. Draft RG 1.121 uses factors of safety consistent with Section III of the ASME Code. [

ju In order to satisfy the burst requirements of RG 1.121:

1) the tube must maintain a factor of safety of 3 against failure for bursting under the normal operating primary-to-secondary pressure difference,

2) the tube must maintain adequate margin against failure under postulated accident condition loadings and the loadings required to initiate propagation of the largest longitudinal crack resulting in tube rupture,

3) primary-to-secondary leakage must be limited such that a postulated single crack producing the leakage will not burst during faulted conditions, resulting in an accident xtside of the plant licensing basis (this is referred to as providing a defense-in-depth approach).

3.2 Accident Condition Allowable Leak Rate The accidents that are affected by primary-to-secondary leakage are those that include, in the activity release and offsite dose calculation, modeling ofleakage and secondary steam release to the environment. The steam line break accident represents the most limiting case due to the potential for increasing leakage due to the steadily increasing primary to secondary pressure differential during recovery from the accident and the direct release path to the environment provided by the break in the steam pipe.

A part of the criteria includes calculation of the maximum permissible steam generator primary-to-secondary leak rate during a steam line break outside of the containment building. Standard Review Plan (NUREG-0800) methodology will be used to establish the maximum permissible leak rate. This methodology has been used to justify primary-to-secondary leak rates greater than the value of 1.0 gpm normally assumed in the plants' FSAR. This methodology has been

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utilized previously by the NRC for the licensing of the steam generator tube support plate voltage based plugging criteria, described in drafi NUREG-1477. NUREG-0800 limits the wwce m _______ _ ___ _ _ _ _

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thyro;d dose to 10% of the 10 CFR 100 limit of 300 Rem for the accident initiated iodine spike case. The proposed criteria will utilize a conservative steam line break per tube leakage allowance based on test data to account for potential leakage from indications which would be cent:itted to remain in-service due to application of the criteria.

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l 4.0 Field Experience 4.1 HEJ Sleeved Tube Indications l

As noted in the introduction, the purpose of this report is to address the structural integrity of HEJ sleeved tubes containing indications within the upperjoint region. Also discussed was the finding of seventy-eight (78) indications in tubes in the Kewaunee power plant SGs. All of the sleeves were installed in either 1988 or 1989, with the greatest number ofindications appearing in tubes that were sleeved in 1988. Thus, the calendar time of operation for the tubes following sleeving ranged from five to six years. An illustration of the axial oflocations of those indications is shown on Figure 4-1. The distribution of the indications was as follows:

1. Sixty-six (66) of the indicauans were found in the upperjoint region consisting of the hydraulic expanded zone and the HEJ.

o One (1) circumferential indication was found at the hydraulic expansion upper transition. There was not operating leakage attributable to the presence of this indication. Eamination of the MRPC response to the indication implied an arc length on the order af 34* (~1/4*).

o One (1) indication was found to be axial and contained within the hardroll expansion.

No axial indications were identiSed above the hardroll or below the hardroll. Should such an indication extend above the top of the hardroll by more than about 0.03", it would be expected to exhibit detectable leakage ifit was a throughwall crack.

e Two (2) indications were identified as volumetric within the hydraulic expansion below the hardroll lower transition. These indications did exlulit an axial component as implied by the circumferential coil of the inspection probe. Since the axial coil of the probe also indicated circumferential extent, the indications have been typified as volumetric in prior discussions of the topic.

• Sixty-two (62) indications were identified as circumferential and located at the hardroll lower transition. The distribution of the measured arc lengths of the sixty-two (62) indications found at the hardroll lower transition is shown on Figure 4-2. The circumferential extent of the indications ranges from 45* to 285* in SG "A", and from 55* to 275* in SG "B". Nine (9) of the indications were judged to be greater than 200* in extent.

2. Of the remaining twelve (12) indications, eleven (11) were located at and one (1) was located below the bottom of the hydraulic expansion lower transition.

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No other tube indications of the type found at Kewaunee have been reported in any other SGs with HEJ sleeves installed. In the absence of evidence to the contrary, the indications observed in the Kewaunee tubes are assumed to be crack like, and are hereafter referred to as cracks.

Without a metallographic examination of a pulled tube section, a determination of the root cause of the indication (s) is quite difficult and would likely be incomplete. However, some

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judgements may be made about unlikely sources of the cracking. The indications are above the j

sludge pile, so crevice corrosion is not likely. In addition, thejo*mt would be expected to significantly retard the replenishment of significant concentration of corrodent species on the ID of the tube, thus implying that primary water stress corrosion cracking (PWSCC)is not the likely source of the indications. Since most of the cracks observed in the Kewaunee tubes occur below the bottom of the hardroll it is likely that the source of the cracks is OD initiated, e.g.,

outside diameter stress corrosion cracking (ODSCC). A precise determination of the elevation i

of the indications in the Kewaunee tubes was attempted, however, due to eddy current uncertainties it was conservatively assumed that all of the indications were at the top of the hardroll lower transition. The average elevation of the sixty-two indications was found to be 1.42" below the top of the hardroll upper transition. The standard deviation of the elevation distance was 0.08". The average value corresponds exactly to the nominal distance to the bottom of the hardroll lower transition. Since the minimum distance is controlled by the physical size of the rollers, which are machined to small tolerances, it is likely that the most of the variation in the measured elevations is due to the accuracy of the eddy current measurement technique, and that the indications are at the bottom of the hardroll tower transition.

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]* Based on this observation, inference regarding the conservatism of the structural model discussed later can be made.

4.2 Circumferential Indication Growth Rates As noted previously, a summary of the arc lengths for the indications reported in the Kewaunee tubes is provided in Figure 4-1. The maximum indication arc lengths reponed were 282 in SG "A" and 271* in SG "B". The minimum arc lengths reported were 44' in SG "A" and 51' in SG "B". Of the sixty-two (62) indications found (in 62 tubes), sixty (60) were sleeved in 1988 and two (2) in 1989. The latter two had reported arc lengths of 44' and 220*. The average length of the indications in SG "A" was 132' with a standard deviation of 64'. For SG "B" the average length was 120* with a standard deviation of 68*. Based on these observations it is judged to be unlikely that they represent samples from different populations.

Since this phenomena has not been previously reported, there is no historical database upon which to estimate growth rates. In this case the growth rate in the circumferential direction is

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ye In addition, there are other data available, e.g., ODSCC at TSPs, which can be used to esthnate rotential growth rates for HFJ tube cracks. The ODSCC growth rates at Kewaunee have been small. This would tend to imply small growth rates for the HFJ tube indications. At another plant, designated as plant C, data for the growth of 100 circumferential indications at TSP elevations had an average of 7* with a standard deviation of 18*, and a maximum of-130* per year. Similar data from the same plant for twelve (12) circumferential indications at the top of the tubesheet (TTS) in explosively expandal tubes had an average growth rate of 9 per year, with a standard deviation of 12* per year, and a maximum of ~30* per year. Thus, using an estimate of 45* per year is about three standard deviations above the mean of the observed TFS data. This quoted for relative inference only since the distribution was obviously skewed right.

To put these observations in proper perspective, the hot leg operating temperature for the plant was 619 F. This is about 20 F hotter than any of the reference plants considered in this report.

The effect of a reduction of 20 F in the hot leg temperature would be expected to result in a reduction of the growth rates by a factor of about 2, bringing the maximum rate to about 1.4 pm/hr. Since the geometry in the vicinity of the HFJ tube cracks is more like an explosive expansion than a dent, which is probably not symmetrical, the growth rate for the TTS indications is more likely to be representative of the indications observed at Kewaunee.

A rough estimate of an upper one-sided 95% confidence bound on the growth rate can be made by assuming the data fits a log-normal distribution with a mean, p, of 9* per year and a standard deviation, o, of 12* per year. The mean log, growth rate, r, would then be expected to be i.69, 2

and the variance of the log, growth rate, s, would be 1.02. These are found as,

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6 A 95% confidence bound on the log, growth rate for 8 degrees of freedom would then be 3.57, with the 95% confidence bound on the actual growth rate being 35.5 per year. Based on the foregoing arguments, the use of 45 per year in plants with hot leg temperatures less than 600 F would be expected to be conservative.

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5.0 Test Programs and Results In order to quantify the effect of the tube indications on the operating performance of the HEJ, test programs were initiated aimed at characterizing the effect of the observed indications on the axial strength of thejoint, and at estimating the leak rate that could be expected during normal operation and under postulated SLB conditions for the case of a perforated tube.

Characterization of the axial strength of thejoint in the event of tube degradation of the type indicated in the Kewaunee tubes was explored via axial tensile (pull out) testing and hydraulic proof testing. A description of the test specimens, the test programs, and the results of the testing performed follows.

5.1 Test Samples The samples fabricated for testing were [

jo The samples were fabricated using the field procedures and tooling so as to arrive at a finaljoint configuration which would be representative of a typical sleeve installed in the field. [

]* This is not seen as a significant deficiency in the testing program since the integrity of thejoint is mainly dependent on the clastic preload following the rolling process.

This in turn is quantified by the radial interference fit of the tube on the sleeve and the modulus of elasticity. Since the modulus is independent of material heat, the elastic springback following yielding of both the sleeve and the tube would be expected to be relatively similar across a range of yield strengths and installation parameters (diameter changes). The rolling process is mainly a strain imparting process which results in the unrestrained OD of the sleeve being larger than the ID if the tube. Thus, the radial preload is due to dimensional interference like that found in a shrink fit.

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l such modified samples is shown on Figure 5-1. The tubes were completely severed by machining at various elevations in the hardroll lower transition. Thus, the initial testing was of specimens simulating 360* throughwall cracks. These tests are considered to be conservative since the added load required to initiate tube motion due to remaining material interference (for indications less than 360* in extent), and the resistance to motion provided by the bending stiffness of the non-degraded ligament are not included.

l 5.2 Test Program Three series of tests were performed: [

p.e A discussion of the leak test results is presented in Section 5.3 5.2.1 Pull Out Tests l

A series of eight (8) samples were fabricated for the tensile (or pull out) tests. Two (2) of the samples were retained in the as-assembled condition. [

}* The results from the pull out tests are summarized in Table 5-1. The pull out tests were performed without [

3m 5.2.2 Leakage Integrity Tests Six (6) samples were prepared for the leakage integrity testing of degraded HEJs. Unlike the I

pull out tests, and in the interest of time, baseline leakage tests were not performed, i.e.,

specimens were not retained in the as prepared condition. This is not considered necessary since leakage data are available from the initial qualification tests of the sleeves for comparison purposes. The specimen configuration was similar to that desenkd for the other samples of l

Figure 5-1. Indeed, the samples were as close to the Figure 5-1 arrangements as possible to permit the contention that the results would be coincident, that is, the leakage and pull force l

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resuhs were represented by the same tube physical condition. [

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Whde at normal operating temperature, the sample was pressurized to produce a pressure differential across the tube wall of similar to the normal operating pressure differential experience by a sleeve / tube joint in service. This was followed by increasing the pressure in the specimen to simulate SLB pressure differential conditions. For each condition the leakage past thejoint was condensed, collected, and measured in terms of drops per minute (dpm) or cc per minute. The results were later converted to gallons per minute (gpm) for presentation and to permit establishment ofleakage potentials for SLB offsite dose evaluations. The results of the leakage testing are summarized in Table 5-2.

5.2.3 Hydraulic ProofTests Following the initialleak tests, [

).4 5.3 Test Results 5.3.1 Pull Out Test Program The tested samples represented a conservative situation which would be typical of a completc tube separation or 360 throughwall crack in the tube.

The data contained in Table 5-1 shows that for the case where the tube was machined at the bottom of the hardroll lower transition and below, the maximum pullout loads exceeded the required loads determined as per RG 1.121 with appropriate safety factors applied. Therefore, any cracking existing below the bottom of the hardroll lower transition does not represent.

tube integrity issue, and may be allowed to remain in service.

For the tubes machined away at the top of the hardroll lower transition, first slip occurred between [

} The maximum developed forces were from (

}'^* Thus, for this condition, and for any cracking existing above the bottom of the lower transition, [

}" It is apparent from these tests that the [

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5.3.2 I4ak Tests j

[

]'" After the initial leak tests were performed, the specimens which had the tube [

]'" The maximum leak rate was found to be [

]'" Finally, j

the tubes [

]'" Relevant SLB leak rate data could not be gathered.

i The data illustrates the importance of the [

]'" The leak rates were all [

j

]'" Although the leak rate with the [

l jsu The conservatism of these tests must be weighed when evaluating the leakage potential of postulated in-situ cracks. Stress corrosion cracks inherently provide a tortuous leak path, and will act to reduce leakage. Additionally, the leak rate through a crack is approximately proportional to the length of the crack to the fourth power. The leak rates through in-situ cracks would be expected to be far less than the test data suggests due to the tortuosity of the crack and length effects, keeping in mind that the proposed criteria is designed to limit EOC crack length to approximately 224'. In addition, it has been demonstrated that circumferential -

cracks exhibit less leakage than axial cracks of the same length.

5.4 Hydraulic Proof Tests The inflection point leak rate test specimens were later pressurized to [

}'" but did approach pressures on the order of three time normal operating pressure differentials.

5.5 Supplemental Axial Load and Leak Rate Tests A series of supplemental leak and tensile tests are being performed as this report is in 5 g e n. im

preparation. The results of these tests will be included in a subsequent revision to this document. [

] Sleeves were inserted, hydraulically expanded and mechanically roli expanded with the roller height set as to position the [

]"' The samples were dimensionally measured after roll expansion to indicate whether or not the [

js.

Also, samples were visually examined on a 100X optical comparator. The optical comparator indicated that a consistent flat length existed above the [

jsc,. g test specimens were tested at AP's of 1600 psi,2100 psi, and 2560 psi. Testing was conducted at 600 F.

The supplemental leak test results are furnished in Table 5-3. [

]'" compared to the data of Table 5-2. The largest leak rate was found to be

[

]su Supplemental tensile test specimens were prepared in an identical manner, however the test results are not yet complete. Preliminary results indicate that the [

)*v A preliminary observation from the supplemental testing program is that the [

]'" to the cracked tube section. This is j

evidenced by the small lateral deflections observed during the testing. In addition, it appears

)

that the [

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Figure 5-1: Schematic of test specimer preparation HUWC#.WP5 5-9 see=*er29,1994

6.0 Analytical Approach 6.1 StructuralModelDescription The structural model of the degraded tube cross-sectional area subjected to the applied loads is shown in Figure 6-1. The model assumes that the [

] The model assumes that [

] The flow stress is dermed as the sum of yield and ultimate strengths divided by 2. Lower tolerance limit (LTL) material property values were used to establish the flow stress for the analyzed tubes. In assessing the structural integrity of degraded tubes (or sleeved tubes since the Technical Specifications consider the tube as a whole, and RG 1.121 is applied universally within the tube) LTL material properties are generally assumed. Lewer tolerance limits on tube material properties are based on a statistical evaluation of the properties of over 1000 tube heats used in Westinghouse steam generators. These limits suggest that a 95% probability exists that 95% of the tubes will have actual material properties which exceed LTL. Past experiences with pulled tubes which contain degraded areas have found them to have tensile strengths of near mean or higher when tested in the laboratory. This provides an additional conservatism on the load carrying ability of the tube than that typically accounted for.

The results of the analysis are illustrated graphically on Figure 6-2.

[

]

6.2 Tube Integrity Considerations The tube support plate is conservatively assumed to offer no resistance to potential axial movement of the tube which may result from the differential pressure created end cap loads. Forces generated by the end cap effects load the tube axially. At the HEJ, the end cap loads are transferred to the sleeve. Finally the end cap load is reacted by the sleeve / tube lowerjoint mechanical roll. Since the WCAPs listed in Section I have been issued for the various operating plants defining the sleeve length between the attachment joints as the pressure boundary, the tube in this region is not considered in the load path even though it would be expected to cany a part of the end cap load.

While axial cracks in the lower transition of the upper hardroll are somewhat benign since they have a limited effect on joint integrity (because they do not effectively reduce the ability of the joint to cany tensile loads), circumferential cracks must be located within the lower hardroll transition wmu.m 6-1 sea im

and be oflimited size. Separation of the tube at the bottom of the hardroll transition or at any location below the upper hardroll lower transition is acceptable based upon the test data supplied in Section 5. The tested pullout strength ofjoints with circumferential tube separation below the bottom of the lower hardroll transition exceeded all RG 1.121 criteria. Lastly, the lower transition of the upper hardroll must have sufficient axial load capability to offset that load capability lost due to the lack of denting and, in conjunction with the tube to sleeve hardroll contact pressure, be capable of carrying the full end cap load.

Since no credit is taken for tube-to-support plate interface resistance, the parent tube must be inspected from the lower transition of the upper hard roll to the upper end of the sleeve to determine the location of the indications and orientation. The indications can be sorted into three basic groups:

[

P' In some instances, the potential for the tube to separate in a critical location can exist. If the tube separates there is a potential for the end cap load to cause the tube to pull off of the sleeve, especially in a tube functioning in a non-dented condition. [

P* These values are applicable considering contact at the apex of the U-bend. Considering contact at the tangent point of the straight leg to the U-bend results in an increase of the values of[

P' Dimensional characterization of the sleevejoint and the proposed limitations for location of defects show that pull out lengths ofup to [

P' would continue to significantly resist leakage due to the maintenance ofjoint overlap. Pull off movement on the order of[

P' confidence at the tangent point, would likely limit leakage to less than 10% of that expected with a [

P' pull off. Note that the distance from the bottom of the hardroll to the top of the sleeve is [

P', thus, axial separation of the tube from the sleeve would not be expected. Since no sleeves are installed in outer periphery tubes, the maximum deflection limit of about [

P' would apply to all HEJ sleeves at Point Beach Unit 2, D. C. Cook Unit 1, Zion Unit I and Kewaunee.

[

6-2

%,, i.

]

Circumferential indications require more specific considerations as they can lead to a separation of the tube accompanied by leak rates which could exceed the makeup capacity. Therefore, circumferential cracks in the lower transition region must be treated more conservatively. With this in mind, as augmented by test data, [

] Cracks may be left in service if they are [

] Because only limited data on crack growth rates exist, and until specific crack growth rate can be developed, a reasonable allowance for growth [

] Domestic field experience should be monitored to assure that the [

] adequate until plant specific growth data are available. When this data becomes available it should be evaluated at 90%

cumulative probability. The overall ODSCC corrosion rates at Cook Unit 1, Kewaunee and Point Beach Unit 2 are relatively low.

As with any concept during its initial application there is a high degree of conservatism applied to the criteria used tojudge the acceptability of the sleeve / tube condition. In all cases the evaluation of the indication assumes that the measured MRPC angle is indicative of an entire through wall crack. Experience has shown that the throughwall crack lengths are likely to be less than the indicated angle associated with 50% to 60% of the peak MRPC amplitude and much less than the full measured angle of the indication. Leak rates associated with circumferential HEJ indications in recent repair programs implied that the indications, although large, were not extensively throughwall. Another assumption is that the growth rate of the indication will be consistently throughwall as it progresses. Experience has shown that it is unlikely that new growth of a defect in one cycle will be entirely throughwall.

6.3 Additional Tube Integrity Considerations

[

jo.a.

A review ofpull forces required to remove tubes from Westinghouse Model 44 and 51 steam generators was conducted. It was found that typical pull forces for tubes without [

)** For similar tubes with [

J [

J In some of the cases the pull forces due to [ denting were so high that the tube pull attempt was unsuccessful. Examples of these conditions can be cited as North Anna Unit 1 (dented, 9000 lb,) and Trojan (non-dented,1500-2000 lb ).)** It should be noted that in all f

cases the tubes were cut above the tubesheet prior to the pull so that the forces described represent only the breakaway forces of the tube pull.

6 3 m m a.ws

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[

P" Typically, in a non-dented intersection it is conservatively===> mad that there is little or no resistance, or support, offered to the tube in question by the support plate. (

)* Additionally, even ifphysical denting has not been detected, packed tube support plate crevices can result in significant contact pressure, which would act to resist tube pull out and support axial tube loadings.

t i

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Figure 6-1: S*.:uctural model for a tube with a circumferential throughwall crack i

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d HEJ Joint Critical Tube Crack Locations I

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y Figure 6.3: Critical tube crack locations in a HEJ wnw+rs 6-7

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7.0 Plugging or Repair Criteria for Parent Tube Indications 7.1 Compliance with draft Regulatory Guide 1.121 Tube Integrity Criteria To remain consistent with the licensing basis addressing structural integrity, the proposed criteria must meet the burst requirements ofRG 1.121. As previously stated, tube burst in an HEJ is only possible if a circumferential separation of the parent tube is assumed [

P' In order to appropriately evaluate the applied loads, [

]*A' The required EOC non-degraded ligament defined by the structural model should transmit these loads without experiencing plastic overload failure, neglecting friction in the hardrolljoint, friction at the tube support plates, and bending restraint provided by the tube / sleeve lockup condition which will occur when the tube experiences significant loading.

In order for the tube to experience leak rates on the order of those associated with a steam generator tube rupture described in the FSAR, the parent tube must experience axial motion of

[

](for degradation in the upper HEJ lower hardroll transition). At this point the tube and sleeve would no longer be in close proximity and an unrestrained leak path would be produced. Reactor coolant system leak rates approaching those assumed in the FSAR could be realized. The diameter restrictions of the sleeve itself will limit the flow through the sleeve to values less than assumed in the FSAR. [

PA' [

miwee.m 7-1 m29. iow

F 7.2 ' Offsite Dose Evaluation For a Postulated Main steam Line Break Event Outside of Containment but Upstream of the Main Steamline Isolation Valve As stated in Section 3.0, the SLB event is the most limiting faulted condition with regard to offsite dose potential. Following the SLB any primary-to-secondary leakage is assumed to be entirely i

released to the environment. Equilibrium primary and secondary side activities are calculated based on the Technical Specification limit.

l NUREG-0800 is used to calculate the maximum allowable primary-to-secondary leakage limit during the event such that offsite doses remain within the licensing basis. Similar calculations have shown that the accident initiated Iodine spiking case is usually limiting. Doses are limited to 10%

- of the 10 CFR 100 limit of 300 Rem thyroid dose. For example, the maximum faulted loop leakage for Point Beach Unit 2 is found to be 25 gpm in the faulted loop, a-ming 150 gpd leakage in each steam generator prior to the event with a maximum RCS activity level of 1.0 micro Curies per gram dose equivalent Iodine-131. For Cook Unit 1, the value has been determined to be 12.6 gpm, and was approved by the NRC as part of the Voltage Based Interim Tube Support Plate Plugging Criteria for Cook Unit 1. Each tube permitted to remain in service due to application of the criteria will be assumed to contribute to the total leakage. If the total projected leakage exceeds the calculated maximum permissible value, tubes will be repaired or removed from service so that the projected SLB leakage value is reduced below the maximum permissible limit. As an alternative to tube repair, the RCS technical specification activity level can be reduced. For Point Beach Unit 2, lowering the allowable activity level to 0.25 micro Curies per gram dose equivalent Iodine-131 supports a maximum leakage value of approximately 100 gpm.

7.3 Evaluation of Other Steam Loss Accidents While the MSLB event outside of containment would represent the most severe static loading and

[

dynamic response condition upon the steam generator, no U.S. plant has ever experienced a double ended guillotine rupture of a main steam pipe. Plants have experienced however, random instances where a steam line relief valve or safety valve have stuck open. Of these two, the safety valve would have a greater dynamic response upon the system. This event, however, produces a limited response compared to the double ended SLB for the followmg reasons.

i 1.

The flow through the safety valve is limited by design to 1/5 of the normal steam line flow. The pressure drop in the secondary system will be much less rapid than in the SLB case. Corresponding dynamic impact upon the steam generator will be much less severe than in the full SLB case. Ovo all system pressure differential would be expected to remain near the normal operating condition AP, based on more extensive evaluations m nem m 7-2 mme

performed for other plants.

2.

The corresponding impact to the RCS is a lesser cool down effect and less rapid RCS pressure and temperature decrease. Comparing Figures 14.2.5-14 and 14.2.5-5 of the Point Beach FSAR indicates that the for an==M failed safety valve the RCS pressure would not drop to 1000 psi until about 215 seconds into the event where the same time increment is only 40 seconds for the SLB case. Similarly, for a core average temperature of 400 degrees F, this condition is achieved in about 450 seconds during the failed safety valve event and in about 100 seconds during the SLB. The bene %1 effect of thermal tightening in the sleevejoint would be greater for the failed safety valve case as opposed to the SLB case due to lesser temperature reduction effects. Figures in the FSAR suggest that tim reestablishment ofRCS pressure due to SI and residual heat effects would be less rapid than in the MSLB case.

In both cases, if offsite power is not available, the maximum AP would be equal. However, for the failed safety valve, the path of getting to this condition is much less strenuous upon the steam -

generator.

7.4 HEJ Inspection Requirements A review of the current inspection criteria suggests that the HEJ parent tube regions be inspected using probes capable ofdetecting substantial axial and circumferential cracks in the expanded regions of the sleeve. As a minimum, the probes used should demonstrate the capability of detecting 40% to 60% deep EDM axial and circumferential notches of 0.25" (~35') and 0.50"

(~70* ) in length.

To assist in establishing a data base for continued evaluation, indications left in service in the sleeve regions subject to repair criteria should be inspected at the subsequent refueling outage. To assure that the data will be consistent from inspection to inspection the convention oflocating parent tube indications relative to the upper hardroll transitions should be used defining the defect size in angle or length.

7-3 "3*"9

% 29. i,w

i 8.0 Summary of Sleeve Degradation Limit Acceptance Criteria 8.1 Structural Considerations Based upon the information previously identified in this report, the following structural considerations are considered to be validated:

8.1.1 Crack Indications Below the Upper Hardroll Lower Transition

[

ya,a 8.1.2 Sleeved Tube with Degradation Indications with Non-Dented Tube Support Plate Intersections

[

pc.4 8.1.3 Dented Tubes

[

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~l 8.2 Leakage Assessment For indications below the upper hardroll lower transition, SLB leakage will be negligible and can be excluded from SLB leak rate calculations.

[

pc,4 8.3 Defense In Depth and Primary to Secondary Leakage Limits The conservative assumptions applied to the proposed criteria provide large margins to the burst criteria of RG 1.121 and leakage requirements relating to offsite dose evaluation. The proposed criteria is designed to limit EOC crack angles such that the non-degraded tube ligaments will not fail due to plastic overload. To provide additional safety margin, the Technical Speci6 cation normal operating primary-to-secondary leak rate limit will be lowered to 150 gpd per SG (0.1 gpm). This leak rate used in this evaluation for each plant will be selected to represent the expected leakage from an HEJ which has experienced a complete circumferential separation at the-top of the upper HEJ lower hardroll transition. This level ofleakage is readily detectable by plant I

leakage detection systems. The available axial translation limits of the tube and the relation of these limits to leakage limits are also addressed. Previous evaluations (WCAP-10949) have determined that the maximum amount of axial motion that a postulated circumferentially separated tube could experience is approximately [

P' inches. The length of the hardroll interference

]

lengthis approximately [

PA* inches. Therefore, even if a postulated circumferentially separated tube were to move [

P' inches, some length ofintimate tube-sleeve contact would remain. If the tube were postulated to move an amount [

.l l

i 8-2 "C^'N e n. im

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1 p.

In order to validate the growth rate assumptions used in Section 3, all indications which have been permitted to remain in service due to application of the proposed criteria must be inspected at each successive refueling outage.

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.)

t l

9.0 Ref;rences 1.

WCAP-9960 (Proprietary), " Point Beach Steam Generator Sleeving Repon,"

Weinghnuse Electric Corporation (1981).

l 2.

WCAP-9960 (Proprietary), Revision 1, " Point Beach Steam Generator Sleevmg i

Report," WM agWse Electric Corporation (1982).

t 3.

WCAP-10949 (Proprietary), "Tubesheet Region Plugging Criteria for Full Depth Hardroll Expanded Tubes," Westinghouse Electric Cs yvision (1985).

[

4.

WCAP-11573 (Proprietary), " Point Beach Unit 2 Steam Generator Sleeving Report (Mechanical Sleeves)," Westinghouse Electric Corporation (1987).

5.

WCAP-11643 (Proprietary), "Kewaunee Steam Generator Sleeving Report (Mechanical l

Sleeves)," Westinghouse Electric Corporation (1987).

t 6.

WCAP-ll669 (Proprietary), " Zion Units 1 and 2 Steam Generator Sleeving Report j

(Mechanical Sleeves)," Westinghouse Electric Corporation (1987).

7.

WCAP-12623 (Proprietary), "American Electric Power D. C. Cook Unit 1 Steaan J

Generator Sleeving Report (Mechanical Sleeves)," Westinghouse Electric Corporation (1990).

8.

Regulatory Guide 1.121, " Bases For Plugging Degraded PWR Steam Generator Tubes,"

~ United States Nuclear Regulatory Commission, Issued for Comment (1976).

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