05000499/LER-1997-002-01, :on 970215,Steam Generators 2A Eddy Current Insp Results Fell Into Category C-3.Caused by Stress Corrosion Cracking at tube-to-tube Support Plate.Sg Tubes Were Plugged in Four Unit 2 Steam Generators

:on 970215,Steam Generators 2A Eddy Current Insp Results Fell Into Category C-3.Caused by Stress Corrosion Cracking at tube-to-tube Support Plate.Sg Tubes Were Plugged in Four Unit 2 Steam Generators

ML20136G939
Person / Time
Site:	South Texas
Issue date:	03/13/1997
From:	Head S HOUSTON LIGHTING & POWER CO.
To:
Shared Package
ML20136G899	List: 05000499/LER-1997-002, Forwards LER 97-002-00,for Hlp Re All Four Steam Generators Being Classified Category C-3 05000499/LER-1997-002-01, :on 970215,Steam Generators 2A Eddy Current Insp Results Fell Into Category C-3.Caused by Stress Corrosion Cracking at tube-to-tube Support Plate.Sg Tubes Were Plugged in Four Unit 2 Steam Generators
References
LER-97-002-01, LER-97-2-1, NUDOCS 9703180257
Download: ML20136G939 (9)

LER-1997-002, on 970215,Steam Generators 2A Eddy Current Insp Results Fell Into Category C-3.Caused by Stress Corrosion Cracking at tube-to-tube Support Plate.Sg Tubes Were Plugged in Four Unit 2 Steam Generators

Event date:
Report date:
Reporting criterion:	10 CFR 50.73(a)(2)(i) 10 CFR 50.73(a)(2)(viii) 10 CFR 50.73(a)(2) 10 CFR 50.73(a)(2)(x) 10 CFR 50.73(a)(2)(iii) 10 CFR 50.73(a)(2)(iv), System Actuation 10 CFR 50.73(a)(2)(v), Loss of Safety Function 10 CFR 50.73(a)(2)(vii), Common Cause Inoperability
4991997002R01 - NRC Website

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RC FORM 366 U.S. huCLEAR RE@ULATORY COMMISSION APPROVED BY OMB NO. 3150 0104 (4-95)

EXPIRES 04/30/96 NNY l MAT NC O RE ET H

j LICENSEE EVENT REPORT (LER)

OE gs E l R"

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ED gRW sN p 0 FED B AC N S Y

D T !eisa?s% "A"!eWEN9' RANC F "1 9 "u ? ~T i m ES" i

(See reverse for required nurnber of REcuLAToRY COMMISSION WASHINGTO DC 55-0001. AND TO digits / characters for each block)

THE PAPERWORK REDUCTIDN PROJECT FACluTY NAME (1)

DOCKET NUMBER (2)

PAGE (3)

I South Texas, Unit 2 05000 499 1 of 9 mam Steam Generators Classified as Category C-3 EVENT DATE (5)

LER NUMBER (6)

REPORT DATE (7)

OTHER FACluTIES INVOLVED (8)

MONTH DAY YEAR YEAR SEQUENTIAL REVISION MONTH DAY YEAR F ACluTv NAME DOCKET NUMBER NUMBER NUMBER 05000 2

15 97 97 -- 002 -- 00 3

13 97

'^c'uTv NAuE DOCxETNvMacR 05000 OPERATING THIS REPORT IS SUBMITTED PUOSUANT 70 THE REQUIREMENTS OF 10 CFR 9: (Check one or more) (11)

MODE (9) 6 20.2201(b) 20.2203(a)(2)(v) 50.73(a)(2)(i) 50.73(a)(2)(viii)

POWER 20.2203(a)(1) 20.2203(a)(3)(i)

X 50.73(a)(2)(li) 50.73(a)(2)(x)

LEVEL (10) 4 0

20.2203(a)(2)(i) 20.2203(a)(3)(ii) 50.73(a)(2)(iii) 73.71 20.2203(a)(2)(ii) 20.2203(a)(4) 50.73(a)(2)(iv)

OTHER g, ;, g, gggg(:

~SpecWy in Abstract below or MIjh[A W[ON"4 G y '7y Q.p p%.

2 20.2203(a)(2)(iii) 50.36(c)(1) 50.73(a)(2)(v) n1 e

in NRC Form 366A 20.2203(a)(2)(iv) 50.36(c)(2) 50.73(a)(2)(vii)

LICENGEE CONTACT FOR THIS LElt (12)

S tt M. Head - Sr. Consulting Engineer

2) 9 7136 COMPLETE ONE UNE FOR EACH COMPONENT FAILURE DE SCRIBED IN THIS REPORT (13)

CAUSE

SYSTEM COMPONENT MANUFACTURER REPORTABLE v -

CAUSE

SYSTEM COMPONENT MANUFACTURER REPORTABLE

}b TO NPRDS TO NPRDS

gy

,w SUPPLEMENTAL REPORT EXPl;CTED (14)

EXP ECTED MONTH DAY YEAR SUBMISSION 1

DATE (15) i YES X NO (if yes. complete EXPECTED SUBMISSION DATE).

j AB 5 TRACT (Larnit to 1400 space =, i.e., appiuxirnately 15 single-spaced typewntten hnes) (16)

On February 15,1997, South Texas Project Unit 2 steam generator 2A eddy current inspection results fell into s

Category C-3 and the NRC was notified within four hours pursuant to 10CFR50.72(b)(2) and Technical i

Specification Table 4.4-2. Additionally, on February 17 and February 18,1997, the inspection results for steam generators 2B,2D, and 2C fell into Category C-3 and the NRC was notified within the required time. Eddy current inspections were conducted on 100% ofin-service tubes on all four Unit 2 steam generators.

l As a result of these inspections, a total of 601 steam generator tubes were plugged in the four Unit 2 steam generators. All but 20 of the 601 tubes plugged were the result of outside diameter stress corrosion cracking at tube-to-tube suppon plate intersections. The cause may be summarized as improper selection of tube material and improper design of the tube-to-tube support plate intersection locations. A contributing factor is the high reactor coolant system hot leg temperature design values.

South Texas will evaluate submitting a license amendment for application of the voltage-based repair criteria to Unit 2 per Generic letter 95-05. For subsequent steam generator eddy current inspections on the currently installed j

generators conducted to satisfy Technical Specification surveillance requirements, the first sample will be a 100%

bobbin examination of the full length of all in-service tubes.

NRC FORM 366 (4-95) 9703180257 970313 PDR ADOCK 05000499 S

PDR ST130209423

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i NRC PORM 388A U.S. NUCLEAR REGULATORY COMMISSION l

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South Texas, Unit 2 05000 499

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00 YEAT tifmore space is required, use additional copies ofNRC Form 366A) (IU DESCRBYrION OF EVENT i

j

. South Texas conducted eddy current testing on all four steam generators during the fifth refueling outage of Unit 2 (2RE05). This report provides the results of the testing.

l Eddy Current Examinations Performed i

l The basic eddy current examination scope for this outage was inspection of all inservice tubes by the bobbin j

coil probe from tube end to tube end (100% scope) in all four steam generators. All bobbin indications which were non-quantifiable or distorted and could not be traced back to the baseline inspection data were also i

examined by three coil rotating pancake probe. In addition all in-service tubes in all four steam generators 1

[

were examined with a three-coil rotating pancake probe at the hot leg top of tubesheet expansion transition.

Additionallocations ofinterest selected for examination by three coil rotating pancake probe were some 1

preheater baffle plate expansions and volumetric signals identified in the previous inspection.

Examination Results No circumferential cracks were found in this inspection. Identified degradation consisted primarily of axial

)

indications at the hot leg tube support plate to tube intersections. Eddy current data for these indications is j

consistent with data from other plants (including South Texas Unit 1) where tube pull information has proven such cracking to be the result of outer diameter stress corrosion cracking in the tube support plate crevice region. As described later, the vast majority of these indications yielded a bobbin coil signal ofless than one l

volt. In addition, a cold leg axial indication at a " ding" location was found in each of two tubes in the 2A 1

generator. As used here, a " ding" means minor damage to the tube in the free span region introduced during the manufacturing processes that is apparent in baseline data. Fifteen volumetric indications were also classified as defective. The inspection results are summarized on the last page of this report.

1 When the results were found to fall in Category C-3, no sample expansion was necessary because the first i

sample included 100% of the inservice tubes.

Unit 2 Steam Generator Design / Operating History l

j Relevant background information includes the following:

Age of Unit 2 steam generators at 2RE05: 5.2 effective full-power years Length of preceding cycle (Cycle 5): 439 effective full-power days e

Tube to tubesheet design: hydraulic expansion e

i Previous outage (2RE04) inspection scope: 22% bobbin tube end to tube end; 100 % three coil e

rotating pancake probe at top of tubesheet j

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NRC PORM 300A U.S. NUCLEAR REEULATORY COMMISSION

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0 95) j LICENSEE EVENT REPORT (LER) l TEXT CONTINUATION I

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I Previous outage (2RE04) inspection results: 11 tubes plugged j

e Tube support plate design: Drilled-hole stainless steel e

Tube material: Alloy 600 mill annealed e

Shot peening: hot leg after first cycle, cold leg after second cycle U-bend heat treatment performed on Row I and Row 2 tubes prior to initial operation.

i e

l During Cycle 5 (November 1995 - Febmary 1997), Unit 2 experienced consistently low primary-to-secondary leak rates in all four steam generators. The total leak rate from all four steam generators averaged less than 1

i one gallon per day during the cycle based on tritium measurements.

Steam generator water chemistry during this cycle was consistent with current industry guidelines.

i Unit 2 Cycle 5 Condition Monitoring Distorted Supnort Plate Indications The number of defective tubes found during this inspection, which resulted in the C-3 category in each steam generator, occurred from a population of axial indications located at tube support plate intersections. Had the j

voltage-based repair criteria of NRC Generic Letter 95-05 been licensed for Unit 2 application at 2RE05, only 1

32 of these 601 tubes would have been plugged. In evaluating the axial indications found at support plate j

crevices the following is of note:

No axial indications extended outside of the tube support plates.

j No primary water stress corrosion cracking was found at any of these support plate locations or at any e

other locations.

I No circumferential indications were found at the support plate or at any other location.

e The largest distorted support plate signal found in the inspection was 1.86 volts (bobbin), which is i

well below the Unit I structural limit of 4.70 volts and even below the upper repair limit of 2.85 volts calculated for application of voltage based repair criteria to Unit I per Generic Letter 95-05.

The bobbin results for outer diameter stress corrosion cracking axial indications at tube support plate intersections were evaluated to the analysis guidelines of Generic Letter 95-05 to support the condition monitoring assessment. All bobbin indications were included in the analysis independent of confirmation by

,i rotating pancake coil. Non-destructive examination uncertainties consistent with Generic Letter 95-05 are also included. The results of the analyses for all four steam generators are tabulated below. It is seen that the mean and maximum voltages are very small (largest of 0.48 and 1.86 volts, respectively) such that low main steam l

line break leak rates and low burst probability would be expected. The largest main steam line break leak rate predicted is 6.6x10" gpm (SG 2A) and the largest burst probability is 4.2x10-5 (SG 2B). This leak rate is 4

j negligible compared to the UFSAR Section 15.1.5.3 faulted and intact steam generator assumed leak rate for a snmwm i

i l

d NRC FORM 306A U.S. NUCLEAR REGULATORY COMMISSION (4 95)

LICENSEE EVENT REPORT (LER)

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South Texas, Unit 2 05000 499

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00 L MT (Ifmore space is required, use additional copies ofNRC Form 366A) (li) main steam line break. The tube burst probability is negligible compared to the Generic Letter 95-05 reporting guideline of 10-2. Consequently, the end of Cycle 5 (EOC-5) indications at tube support plate intersections satisfy tube integrity requirements with large margins.

Summary of Calculations of Tube Leak Rate and Burst Probabi'ity Based on Actual Bobbin voltage 1

Number MSLB j

Steam ofIndications Mean Max.

Burst Probability Leak Rate

)

Generator yoh yoh (epm) 1 Tube 2 Tubes PREDICTIONS BASED ON EOC-5 DATA j

2A 193 0.48 1.47 2.5 x 10 5

< 4 x 10-6 6.6 x 10

2B 339 0.38 1.86 4.2 x 10-5

< 4 x 10 6 5.4 x 10-4 2C 262 0.42 1.07

< 4 x 10 6

< 4 x 10 6 1.4 x 10

2D 261 0.33 0.98 1.9 x 10 5

< 4 x 10 6 1.0 x 10'd Axial Free Soan Indications at " Dine" Locations The largest free span axial indication detected (one of two) was the cold leg axial indication at a " ding" location in the tube at R34 C64 in Steam Generator 2A (considered the largest based on length, voltage, and length of significant depth). Prior to the outage, criteria had been established for assessing axial free span indications, to readily determine whether they challenged either the leakage assumptions in the post-accident offsite dose calculations or the structural integrity calculations per Regulatory Guide 1.121. The action determined to be necessary in the event of a challenge to either of these limits was an appropriate in situ leak or proof test to provide definitive evidence of the ability of such a tube to withstand accident conditions.

Neither identified defect challenged the structural integrity calculations. However, the defect in the tube at location R34 C64 was identified as exceeding the predetermined calculational limit for leakage integrity. This tube was therefore in situ leak tested to main steam line break differential pressure adjusted for temperature and pressure uncertainty. The test resulted in zero leakage, i

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NRC FORM 306A (4-95)

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LICENSEE EVEBrP REPORT (LER)

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South Texas, Unit 2 05000 499

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The crack lengths for both indications, as measured by the 115 mil diameter rotating pancake coil probe, were shorter than the 0.51 inch throughwall crack length (based on lower tolerance limit properties) that would result in burst at the Regulatory Guide 1.121 burst margin guideline of 3DPuo = 3675 psi. For deep indications, rotating pancake coil probes overestimate crack lengths and a length increase for nondestmetive examination uncertainties would not be necessary. Thus, the burst margin is satisfied by the limited crack length and in situ proof testing was not required. Based on depth sizing of the two free span indications, the burst pressures would be estimated at > 5170 psi (using tube specific material properties) or well in excess of Surst margin guidelines, as expected from length considerations only. Since the in situ tests support no ieakage and burst pressure margins exceed Regulatory Guide 1.121, the indications satisfy stmetural and leakage integrity with considerable margin.

Volumetric Indications The volumetric indications that were repaired are believed to be manufacturing burnish marks that have had some change in eddy current response over the baseline response. If the indications were conservatively assumed to be a volumetric corrosion indications, the rotating pancake coil voltages and phase angles support a conclusion of small, shallow indications. The rotating pancake coil voltages are < 2 volts and bobbin voltages are of comparable magnitude. Volumetric corrosion indications (pitting, thinning, etc.) challenging structural integrity would have higher voltages. Similarly,if the indications were conservatively assumed to be cracks, the voltages are small and less than found for the free span indication at R34 C64 that was in situ tested. Thus, even with the conservative interpretation as a crack indication, the indications would not be expected to challenge structural integrity and leakage conditions are bounded by the indication that was in situ leak tested. Overall, it is concluded that the volumetric indications do not challenge Regulatory Guide 1.121 burst margin guidelines.

Conclusions The condition of the Unit 2 steam generators found at this inspection did not represent a challenge to tube structural integrity with the margins required by NRC Regulatory Guide 1.121, nor was a condition present during the last cycle of Unit 2 operation which would have exceeded the current UFSAR licensing bases for main steam line break steam generator leakage. It is concluded that the Unit 2 steam generators were capable of fulfilling all design functions throughout Cycle 5 operation.

Unit 2 Cycle 6 Operational Assessment The conditions found during the 2RE05 inspection satisfy condition monitoring tube integrity requirements with considerable margin. This result indicates that Unit 2 operation for an additional full cycle would not encroach upon the safe operation of the unit.

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All distoned suppon plate indications confirmed by rotating pancake coil in Unit 2 for axial outer diameter stress corrosion cracking at tube support plate intersections were removed from service by tube plugging.

Main steam line break leak rates and burst probabilities for the 2RE05 inspection results resulted in large margins and it can be expected that similar margins will be present at the end of Cycle 6 (EOC-6). Even if the Generic Letter 95-05 voltage based repair criteria had been applied at the 2RE05 inspection to leave bobbin indications in service, it would be expected that acceptable leak and burst margins would result at EOC-6 based on comparisons with other analyses such as that for Unit I and for other plants with 3/4 inch diameter tubing.

In a history review of the larger free span indication at R34 C64 that was in situ leak tested in 2RE05, a volumetric indication was found to be present at the prior bobbin coil inspections in 1993 and 1995. There was no measurable change in bobbin voltage (measured voltage actually decreased - see table below) from 1993 to 1997. This implies depth increased by only approximately 12% over this time period. These results suppon a conclusion oflow growth rate for the free span indications. The smaller indication at R31 Cl11 was not inspected in 1995 and was detectable only as a " ding"in the 1993 inspection. The lack of a 1995 inspection precludes a meaningful conclusion on the growth rate of this indication. The available results are consistent with initiation and modest growth over more than one operating cycle prior to the 2RE05 inspection.

AVAILABLE BOBBIN HISTORY FOR AXIAL FREE SPAN INDICATION AT R34 C64 IN SG 2A Baseline

• 19905

1993:

11995

'1997-

% Throughwall 0%

No Test 6%

15 %

18 %

Voltage N/A No Test 1.89 Volts 1.76 Volts 1.72 Volts

• - Prime frequency changed from 400 to 550 khz some time after baseline.

The more stringent 2RE05 inspection criteria required that bobbin coil indications not present in the baseline inspection (or significantly changed since the baseline inspection) be funher examined by rotating pancake coil inspection and plugged following rotating pancake coil confirmation of a flaw indication. The use of this criteria in 2RE05 provides additional confidence that the size of any new free span axial indications at EOC-6 should not exceed the indication found at R34 C64 and successfully in situ leak tested.

Cycle 6 duration is expected to be 555 effective full-power days compared to the 439 effective full-power days for Cycle 5, which represents an increase of approximately 26% in the operating cycle length. Given that the indications initiated prior to Cycle 5, that the indications did not progress to a leaker due to funher growth during Cycle 5, that the crack length at EOC-5 is less than allowable length for a uniformly throughwall indication (0.45" vs. 0.51" allowable for throughwall indication) and that the EOC-5 assessment indicates a significant burst margin (5170 psi predicted vs. 3675 psi for 3DPuo), indications that may be found at EOC-6 can be expected to satisfy the burst margin guidelines of Regulatory Guide 1.121 and the free span indications do not limit Cycle 6 operation.

i sTi30209423

NRC FORM 386A U.S. NUCLEAR REGULATORY COMMi3SION pas)

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Overall, it is concluded that the EOC-5 inspection results and any expected differences for Cycle 6 support full cycle operation for Cycle 6.

CAUSE OF EVENT

All but twenty of the 601 tubes plugged in 2RE05 were the result of outside diameter stress corrosion cracking at tube-to-tube support plate intersections. This tube degradation mechanism is well known to the industry (as documented in the EPRI Steam Generator Reference Book, Chapter 12) for plants employing drilled-hole tube support plates and Alloy 600 mill annealed tubes, and has been addressed in NRC Generic Letter 95-05. Outer diameter stress corrosion cracking at tube support plate intersections is the result of tube susceptibility to stress corrosion cracking in the tube support plate crevice environment as confirmed by tube pulls at South Texas Unit I and other plants. This stress corrosion cracking has been demonstrated to be a temperature-related corrosion process such that the higher the hot leg temperature, the more rapid the corrosion progression. The 2RE05 inspection results are consistent with this understanding of the outer diameter stress corrosion cracking at tube support plate corrosion phenomenon in that the lower hot leg tube support plate intersections contain the majority of the axial indications found.

i t

I The root causes of outer diameter stress corrosion cracking at tube-to-tube suppon plate intersections may be summarized as improper selection of tube material and improper design of the tube-to-tube support plate intersection locations (crevices resulting from drilled holes). A contributing factor is the high reactor coolant system hot leg temperature design values.

l t

ANALYSIS OF EVENT

I This event is being reponed in accordance with Technical Specification 4.4.5.5c. The health and safety of the public was not affected.

CORRECTfVE ACTIONS i

t The following actions were proactively implemented in Unit 2 prior to 2RE05 due to nareness of the possible advent of significant steam generator tube degradation:

South Texas reduced the Unit 2 hot leg temperature from an initial average hot leg temperature a.

of ~624 F to an average Tw value of ~620 F at the start of Cycle 5 in 1995.

i b.

South Texas has undertaken steps to help mitigate steam generator tubing corrosion. Plant design was upgraded during constmetion to:

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Add a full flow feedwater deaerator for dissolved oxygen control Add cation condensate polishers in addition to the full flow mixed bed condensate polishers e

Double the capacity of the steam generator blowdown system to 1% of main steam flow, Remove copper components from the secondary system e

Use all volatile treatment c.

N-16 radiation monitors were added to provide continuous indication of individual steam generator primary-to-secondary leakage.

d.

South Texas performed the analysis and increased steam generator plugging limit from 5% to 10%.

As a result of 2RE05, the following actions have been or will be taken:

1. All defective tubes were plugged in accordance with Technical Specification requirements. (Note:

If the South Texas Technical Specifications are changed through a future license amendment to apply the Generic letter 95-05 voltage based repair criteria at tube support plates to Unit 2, many of these tubes could be restored to service.)

2. South Texas will evaluate submitting a license amendment for application of the voltage-based repair criteria to Unit 2 per Generic Letter 95-05 for use in 2RE06 or in subsequent inspections.

3. For subsequent steam generator eddy current inspections on the currently installed generators conducted to satisfy Technical Specification surveillance requirements 4.4.5.1 and 4.4.5.2, the first sample will be a 100% bobbin examination of the full length of all in-service tubes.

Additionally, South Texas will continue to do everything practical to enhance the performance and extend the life of the Unit 2 steam generators.

ADDITIONALINFORMATION This is the first time that any steam generator at South Texas has been classified as Category C-3.

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UNIT 2 STEAM GENERATOR 2RE05 INSPECTION RESULTS

' [SG 22 l'SG2B?

MG 2CE

' /SG 2D'i O'IUI'AL/

Total No. of Tuoes 1

4,864 4,864 4,864 4,864 19,456 Number of Tubes 21 17 24 19 81 Previously Plugged Total No. of Tubes 4,843 4,847 4,840 4,845 19,375 Inspected (100%)

1. Defective Tubes -

121 158 144 159 582 Tube Sunnort Plate (7)*

(4)*

(1)*

(0)*

(12)*

Indications

1. Defective Tubes -

2 0

0 0

2 Axial Indications at

" Ding" Locations

1. Defective Tubes -

1***

10 2

2 15***

Volumetric Indications Total Number of 123 168 146 161 598 Defective Tubes

% Defective 2.54 %

3.47 %

3.02 %

3.32 %

3.09 %

Inspection Category C-3 C-3 C-3 C-3 C-3 Preventative 2

1 0

0 3

Plugging Total Plugged in 125 169 146 161 601 2RE05 Total Plugging to 146 186 170 180 682 Date Total % Plugged to 3.00 %

3.82 %

3.50%

3.70 %

3.51 %

Date*

• The number in parenthesis indicates the number of tubes with an indication whose bobbin signal exceeded 1.0 volt.

South Texas design basis plugging limit is 10%.

One tube had both a defective TSP indication ano a defective volumetric indication STI 30209423