ML20006E290

Forwards Safety Assessment of Eddy Current Testing Insp of Unit Steam Generators.Continued Operation Through Current Cycle 10 Fully Justified

ML20006E290
Person / Time
Site:	Millstone
Issue date:	02/07/1990
From:	Mroczka E NORTHEAST NUCLEAR ENERGY CO., NORTHEAST UTILITIES
To:	Russell W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
References
B13443, NUDOCS 9002220526
Download: ML20006E290 (19)

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i February 7, 1990 Docket No. 50-336 B13443 Re: ECT Inspection Mr. William T. Russell Regional Administrator, Region I U.S. Nuclear Regulatory Commission 475 Allendale Road King of Prussia, PA 19406

Dear Mr. Russell:

Millstone Nuclear Power Station, Unit No. 2 Steam Generator Insoection On June 5, 1989,II) NRC Region I requested that Northeast Nuclear Energy

. Company (NNECO) perform an in-cycle steam gentrator eddy-current testing (ECT) examination for M On July 12,1989,gstone Unit No.

. NNECO 2 during responded bythe letter current to the Cycle Region10 operation.

I request and committed to perform an ECT inspection of the Millstone Unit No. 2 steam generators with an estimated shutdown time frame between September and October of 1989. . A more definitive gegedule and detailed woik scope was provided by letter dated August 30,-1989.

In continuing dialogue with the NRC Staff, NNECO had been requested to present the latest steam generator ECT results and an overall safety assessment of the steam generators to the Staff in a meeting to be held on February 8,1990, in the NRC Headquarters in White Flint, Maryland. In preparation for that meeting, NNEC0 intended to submit relevant information to allow the NRC sufficient time for review of this matter. On February 1, 1990, NNECO requested from the NRC Staff, a one-week extension for submittal of the steam generator ECT results and an overall safety assessment of the Millstone Unit No.: 2 steam generators. This extension was needed to finalize and document I

(1) W. T. Russell letter to E. J. Mroczka, " Millstone Unit No. 2 Mid-Cycle Steam Generator Inspection," dated June 5, 1989.

(2) E. J. Mroczka letter to W. T. Russell, " Millstone Nuclear Power Station, Unit No. 2, Steam Generator Inspection," dated July 12, 1909.

(3) E. J. Mroczka letter to W. T. Russell,

• Millstone Nuclear Power Station, Unit No. 2, Steam Generator Inspection," dated August 30, 1989.

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> B13443/Page 2 1 February 7, 1990 NNECO's internal safety assessment. The NRC Staff granted this extension and subsequently- rescheduled the February 8,1990, meeting to February 22, 1990.

Attachment I to this letter provides NNECO's safety assessment for Millstone Unit - No. 2's steam generators with an overall conclusion, based upon our analysis of current Millstone Unit No. 2 testing results and other industry  !

data, that continued operation through the current Cycle 10 is fully justi- l fied. '

Should you need additional information or clarification prior to the '

February 22, 1990, meeting, please contact us.

Very truly yours, 5

NORTHEAST NUCLEAR ENERGY COMPANY 4

E. 'Kffro'czka f Senitrr Vice President Attachment l

cc: G. S. Vissing, NRC Project Manager, Millstone Unit No. 2 i W. J. Raymond, Senior Resident Inspector, Millstone Unit Nos. 1, 2, and 3 U.S. Nuclear Regulatory Commission, Document Control Desk

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Millstone Nuclear Power Station, Unit No. 2 Steam. Generator Safety Assessment February 1990

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p Mr.' William T. Russell 513443/ Attachment I/Page 1 February 7,1990 SAFETY ASSESSMENT OF THE MILLSTONE 2 STEAM GENERATORS i

DirRODUCTION E

The purpose of this assessment is to evaluate the structura'l integrity of the

' Millstone Unit No. 2 (MP2) steam generators (SGs) with regard to safety and reliability. The SG tube bundle forms a portion of the primary pressure boundary. Corrosion induced degradation of the tubes and tube supports has occurred as a result of past operation of the unit. This degradation is identified by nondestructive inspection of the SG tubes. A in-cycle inspec-tion of the SG tubes has been recently completed. The intent of this addi-tional inspection was to identify any stress corrosion cracks which may have developed and to ascertain whether the corrosion process was under control.

The following discussion addresses the effect of known and potential degra-dation on the integrity of the pressure boundary and its implications with regard to safety and reliability for the remainder of the current operating .,

cycle. I DISCUSSION Corrosion in'duced degradation of the tubes and supports has been identified in I the MP2 SGs by various nondestructive and destructive inspections including ,

eddy current testing (ECT), ultrasonic testing, radiography, fiberoptics and  !

removed tube examination. Corrosion of the tubes has occurred as a result of I

concentrations of corrosive chemical specias on the secondary side of the o tubes, primarily in sludge areas within 13 2nches from the top of the tube-

! sheet. Two corrosive mechanisms, pitting and stress corrosion, are principal-ly responsible for the existing tube degradation. Both the hot leg and cold leg sides of the SG have been affected by each mechanism to various degrees.

Tube support degradation has occurred principally on the hot leg side of all support levels. l o Pitting Pitting has occurred in the MP2 SG tubes as a result of acidic chemistry conditions and sludge build up on the tubesheet early in the life of the SGs. The pitting has occurred in all four SG plenums. Tubes with pits ,

identified by ECT as having depths of greater than or equal to 40 percent throughvall are either repaired or removed from service. Improvements in l secondary side water chemistry and chemical cleaning in 1985 which i removed a large portion of the sludge pile effectively stopped the L progression of pitting. Prior to 1985, a large inventory of pits less  !

than 40 percent throughwall was created. These pits have not shown any j '

significant growth over the last several cycles, indicsting that the

- conditions and environment which originally promoted the pitting no l longer exists.

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813443/ Attachment I/Page 2 ,

February 7,1990 i' o Tube Support Degradation Tube support degradation of the MP2 SGs has occurred as a result of acidic chemistry conditions early in the operating life of the SGs. The acid conditions caused the carbon steel material to corrode and form magnetite. The build up. of the magnetite corrosion product in turn caused denting of the tubes and shifting of the supports. Elimination of the corrosive acidic environment has stopped the further degradation of ,

the supports. The progression of support degradation, as measured by tube denting, has been approximately zero since Cycle 7. A fiber optic inspection of the first eggerate tube support was performed during the EOC9 Refueling Outage (RFO). This inspection revealed an eggerate con-dition much better than laboratory testing of the model boiler eggerates and. better than assumed in previous evaluations. Although tube bowing '

was noted, no loss of support was identified by the fiberoptic inspec-tion. No examination of the tube supports was performed during this outage.

o Stress Corrosion Cracking Stress corrosion cracking has developed in the MP2 SG tubes at the top of the tubesheet on both the hot let and cold leg sides. The cracking is OD initiated and circumferential1y oriented. The cracking was first dis-covered in a leaking tube (SG 1H L25/R19) in January 1987. At the time the safety significance of a circumferential1y oriented crack vas assessed and operation of the unit was concluded to be safe with a reduc-tion of the primary-to-secondary leak rate to 0.15 gpm.

Subsequent ECT inspections during the EOC8 RF0 identified 26 additional cracks, all in the SG 1 hot leg. In addition, during the outage, Tube L25/R19 was removed for examination. Based on the results of the exami-nation of L25/R19 and the ECT inspection results, the safety significance of the cracking was reassessed and found to be acceptable with a further reduction of the primary-to-secondary leak rate to 0.10 gpm.

Destructive examination of the leaking Tube L25/R19, removed after almost a year in operation while the tube was plugged, confirmed the presence of an OD initiated stress corrosion circumferential crack. The tube con-tained a continuous circumferential crack which was throughwall over 1908, and greater than 50 percent throughwall over 260*. The remaining 100' of the tube circumference contained several individual microcracks less than 50 percent throughvall. Based on examination of the fracture surface and review of MP2 SG chemistry, the best estimate of the causative chemical species was determined to be caustic.

Evaluation of the observed crack size indicated that the tube should not have been able to withstand operating loads and therefore the crack must have grown during the time the tube vas plugged. Careful evaluation of the fracture surface showed that the continuous segment ref the crack h , + - < - = a--r-- g - - ' -

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Mr.'Villiam T. Russell B13443/ Attachment I/Pege 3 February 7, 1990 +

actually initiated as approximately 20 separate microcracks which even- ,

tually linked up by stress corrosion. It was postulated that the crack developed by the following scenario:

1. Caustic concentrating in the sludge area initiated circumferential1y oriented microcracks on the OD surface of the tube..

2. Existing microcracks propagated as additional microcracks initiated.

3. As the microcracks propagated, the ID of the tube was breached when a crack was propagated between 14' and 21' around the circumference.

This aspect ratio is typical for stress corrosion of SG tubes.

4. The throughwall portion of the crack enlarged and the tube began to leak. The remaining ligaments between the microcrack provided sub-stantial structural strength. The initial 0.10 gpm leak rate indi-cated a throughwall opening of approximately 35'.

5. The tube was plugged. ,

6. The remaining ligaments between microcracks stress corroded during the operating period while f.he tube was plugged, forming the observed continuous crack.

The postulated cracking scenario was reviewed with Vestinghouse Electric Corporation. Vestinghouse agreed that the postulated scenario was reasonable and closely matched results observed for tests of circumfer-ential cracks in North Anna SG tubes. Using the postulated cracking scenario and the observed leak rate, calculations were performed which demonstrated that the crack in Tube L25/R19 shoved acceptable " leak before break" behavior and at the initial leak rate of 0.10 gpm main -

tained the structural margins required by Regulatory Guide 1.121. -

Corrective actions to control the stress corrosion cracking af the tubes were instituted in Cycle 9. These actions consisted of on-line botic ,

acid addition, begun approximately two months into Cycle 9, and further l improvement in bulk vater chemistry impurity levels. The addition of P boric acid was expected to slow the propagation of incipient caustic

! stress corrosion cracks and halt the formation of nev caustic stress corrosion cracks. The unit successfully operated the entire Cycle 9 p without the development of any primary-to-secondary leaks.

l l An inspection of the MP2 SGs was performed during the EOC9 RF0 using the best equipment and techniques available in the industry at the time.

l' Improvements in the equipment and techniques had been made since the l- previous refueling outage inspection. Following the completion of all l

EOC9 nondestructive testing, E9 tube ends were identified as being l cracked at the top of the tubesheet. Cracks were identified in all four L

plenums with 85 percent of the cracking taking place in SG 1, with a l

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Mr. Villiam T. Russell 513443/ Attachment I/Page 4 February 7, 1990 60 percent /40 percent split between the hot leg and cold leg, respec-tively. The location of cracking within the- SG tube bundle corresponds with both a corrosive environment and high tube stress. The sludge pile provides the corrosive environment, while high tube stress develops as a c- result of tubesheet denting and support corrosion. The support corrosion causes shifting of the tube bundle and boving of the tube. Tube boving has been demonstrated by the inability to successfully pass long rigid objects (such as sleeves and stabilizers) through the top of.tubesheet region of some tubes. The fact that. support corrosion as measured by tube denting has been inactive over the last three operating cycles pro-vides reason to suspect that the tube stresses at the top of the tube-sheet have been present since 1985 or earlier and are not increasing.

The identification of 309 cracks during the EOC9 RF0 created the impres-sion that the number of cracks was rapidly increasing. However, increased rotating probe testing (468 tube ends EOC8 versus 12,556 tube ends EOC9), reduced probe speed and a tighter crack determination criteria contributed to the large number of cracks detected during the  !

'EOC9 RFO. In addition, the criteria for determining which tubes to test  !

vith -the rotating probe technique changed from bobbin Distorted Roll  !

Indications (DRI) EOC8 to 100 percent of the crack boundary region EOC9.

An added effect was that the EOC9 rotating probe test was run at a slover i speed than during EOC8 (200 rpm and 0.1 inch per second versus 300 rpm I and 0.2 inch per second). The slover speed reduced the level of noise  !

generated by the rotation of the probe past the tube transition and allowed for cracks of smaller signal amplitude to be more easily detected. A comparison of the limited E0C9 ultrasonic test results with  !

the EOC9 rotating probe results demonstrated that the rotating probe data F analysis criteria used at EOC8 did not identify certain cracks, therefore, the analysis criteria was tightened.

l l The number and apparent growth of cracks in the cold leg did not appear l l to be consistent with the expected Arrhenius behavior with temperature  !

i- typical of caustic induced stress corrosion. Normally, the hot leg would be expected to show a larger growth rate. One possible explanation was  !

that the cold leg cracks which developed to a state identifiable by bobbin coil ECT during E0C9 RF0 actually initiated during Cycle 8 vhile I caustic chemistry conditions existed in the SGs, and propagated slover .

l due to the lover temperature. Variation in sludge consistency between l l the hot leg and the cold leg, variations in diffusion parameters with l .

temperature, solubility variations with temperature, variations in boric ,

acid effectiveness with temperature and other unknown factors also may  !

have contributed to the observed cold leg cracking. This indicated that additional cold leg crack propagation could be expected to occur during Cycle 10.

Based on review and interpretation of the E0C9 inspection results, the corrective actions to mitigate stress corrosion of the tubes were con-sidered to be effective. The historical ECT review indicated a dovnvard trend in the rate of cracking. The cracks which were identified as new

i. at the EOC9 vere consistent with the propagation of incipient caustic

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' B13443/ Attachment I/Page 5 February 7, 1990 cracks in a boric acid environment. The safety significance of the '

cracking was reassessed following the EOC9 RF0 inspection and found to be '

acceptable.- Projections of the number of new cracks expected to form in Cycle 10 were made assuming effective corrective actions. . On a best-estimate- basis, 60 new cracks were expected by the in-cycle inspection and 75 new cracks by EOC10. Upper bound estimates were 200 new cracks by '

the in-cycle inspection and 250 new cracks by E0010. If an active cor-rosion process were assumed, over 1,000 new cracks would have been expected by EOC10.

During October 1989..MP2 was shut dovn to perform an in-cycle inspection 1 of the SGs. The purpose.of this inspection was to identify stress cor-l rosion cracks which had developed to a detectable size since the EOC9 RF0 '

inspection. and to ensure that the corrosion process responsible for the cracking was under control. The inspection was performed with the best equipment and techniques available at the time and reflected improvements which had been made since the EOC9 RF0 inspection. The inspection pro- '

gram consisted of an examination for cracks by rotating pancake coil probe testing of all tubes within the region where cracks vould be expected to occur, plus bobbin coil probe testing for pits. In addition, ultrasonic tests were performed on tubes which RPC indicated that cracks were possibly present to obtain additional information on crack length and depth.

A total of 104 tube _ ends were identified as being cracked at the top of the tubesheet. Cracks were identified in all four plenums, with 90 percent of the cracking taking place in SG1, with an approximate 60 percent /40 percent split between the hot leg and cold leg, respec-v tively. Figure 1 illustrates the location and number of cracks. in a representative SG plenum. The location and distribution of the cracking is almost identical to the EOC9 RF0 inspection results. All tubes with identified cracks were staked and plugged. Determination of whether a tube was cracked was made conservatively and it is possible that some of the repaired tubes may not actually contain cracks. An additional 11 tubes were preventatively staked and plugged, since a positive determi-nation could not be made that a crack was not present in these tubes.

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A comparison of the February 1989 (E0C9) and October 1989 rotating probe data was performed for all but six tubes identified as cracked during the October examination. No rotating pancake coil probe data was collected in- February on six cracked tubes. The extrapolated results from this comparison identified 35 of the 104 cracks (35 percent) as not being detectable by ECT in February. A total of 69 cracks (65 percent of the total) were present in February. Identification of the cracks using February 1989 data was possible by lovering the threshold for crack determination to the level equivalent to that used for the October 1989 examination. The reasons for identifying cracks in October which vere present (but not identified) in February included:

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B13443/ Attachment I/Page 6 February 7,1990 ,

i 1. Improved training of the analysts prior to the October examination,

2. Independent review of data tapes in October versus an independent review of RPC graphics only, in February, 3.. Lovering the initial reporting threshold to include all "possible" ,

cracks versus "best estimate" cracks. ,

4. Ultrasonic testing of all tubes with "possible" cracks as identified by rotating pancake coil probe.

The small number and dovnvard trend of new cracks present during the October 1989 inspection is consistent with the best estimate prediction.

This prediction was based on the observed effect of boric acid treatment on caustic stress corrosion in laboratory tests. The addition of boric acid to the MP2 SGs was expected to halt the initiation of new cracks, and slow the propagation of existing incipient cracks. The 35 new cracks are likely cracks which vere at an incipient stage prior to the boric acid addition and have now propagated to a detectable size.

Based on results from the previous _three inspections, the cracks in the MP2 SG tubes can be characterized as follows: the cracks are located at the top of the tubesheet, within approximately 0.2 inches from where the expansion transition meets the nominal tube diameter, and are circumfer-entially oriented. The macrocrack, as defined by rotating probe ECT, is  ;

j made up of several discontinuous microcracks which are separated by liga-ments of sound material. Circumferential extents of the macrocracks ranged from 14' to 329' by RPC and up to 360' by ultrasonic testing (UT).

Crack depths up to 100 percent throughvall vere estimated by UT. The ,

discontinuous nature of the array of microcracks was confirmed by UT and removed tube examinations. In general, the microcracks were located at ,

different axial planes, typically within a 0.1 inch band. A tube with a discontinuous array of microcracks is substantially stronger than a tube with a continuous crack of equivalent circumferential extent and depth.

, The actual circumferential extent and depth of the macrocrack is rela-L tively independent of the operating time. The circumferential extent is

! controlled by the number of microcracks which have initiated around the I

circumference and the uniformity of the stresses in the tube at the top of the tubesheet. The depth of the individual microcracks is also con-trolled by the stress field. Once a microcrack has passed the incipient stage, the crack vill propagate to the depth supported by the stress field fairly rapidly compared to the length of an operating cycle.

Projection of the number of cracked tubes expected by the EOC10 vere made by extrapolating the current cracking trends. On this b, sis, 45 tubes '

l' vill be identified as cracked during the E0C10 RF0 inspection. The cracks are expected to be the result of either the propagation of incip-ient cracks, which developed during the time period caustic conditions

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i Mr. Villiam T. Russell 313443/ Attachment I/Page 7 '

February 7, 1990 existed in the SGs, or the identification of existing cracks which vere previously below NDE detection thresholds.

A distribution of the circumferential extent of the macrocracks, as indi-cated by RPC, has been present for each inspection where cracks vere observed. The distribution of circumferential extents has remained the same, regardless of the operating. period between inspections. This is illustrated in Figure 2. This indicates that once macrocracks have formed, the overall population vill not show any significant growth in circumferential extent. The distribution of the cracks observed during the October 1989 inspection can be modeled by a gamma distribution with a median of 90', a mean of 102', and a standard deviation of 67', Figure 3.

It. is expected that the new cracks projected to be identified during the EOC10 refueling outage vill continue to follow a gamma distribution of the circumferential extents. Cracks with large circumferential extents are potentially more challenging from a structural standpoint. Using the gamma distribution model, statistical inferences can be made with regard to the number of observed macrocracks which vill have large circumfer-ential extents. Given a projection of 45 cracks,.the number of macro-cracks which vill exceed 240' at the 95 percent confidence level is four and the expected number is two, Figure 4. To date 36 cracks have been found which exceed 240' in circumferential extent, including the tube which leaked at 0.1 gpm in January 1987 (Tube L25/R19 254' circumfer-ential extent).

Three tubes were removed from the MP2 SG during the October 1989 shutdown for burst testing and destructive examinations. The tubes contained the '

following circumferential cracks:

TUBE RPC EXTENT UT EXTENT UT MAX DEPTH SG2 Cold L118/R14 291' 340' Clustar 80%

SG1 Cold L52/R22 191' 155' 80%

110' 60%

SG1 Cold L145/R23 88' 80' 40%

65' 40%

Tube SG 2C L118/R14 was considered a vorst case crack based on the combi-nation of circumferential extent and depth as indicated by nondestructive inspections. This tube was pressurized with water at increasing pressure until bursting at a pressure of 11,200 psi. The failure was axial, coin- .

ciding with a groove created by the removal process. Tube SG IC L52/R22 was also tested, developing a leak at 8500 psi. This tube could not be burst because of test equipment limitations. A virgin tube vould be expected to fail axially at a burst pressure between _1,000 psi and 12,000 psi.

,1 Mr."Villiam T. Russell B13443/ Attachment I/Page 8 February 7, 1990 The burst. pressures of the removed tubes compare quite favorably with the normal operating differential pressure between the primary and secondary side -of the tube of 1375 psi and the maximum accident pressure, with dynamic effects considered, of 3150 psi. Applying .the Regulatory Guide 1.121 safety factors of 3 on normal operating loads and 1.4 on accident loads produce pressures of 4125 psi and 4450 psi respectively. Despite the large extent of cracking and potential weakening of the tube as a result .of removal from the SG, both of the tested tubes fully met the Regulatory Guide requirements.

For circumferential cracks of the type and location found in the MP2 SG, a substantial portion of the cross-sectional area must be corroded before the tube would no longer fail axially at virgin tube pressure in a burst test. The presence of the tubesheet provides restraint to bulging of the tube in the region of the crack and effectively increases the corroded area which can be tolerated without loss of margin to burst. In addi-tion, the stiffness of the tube, the tube supports, and the presence of ,

adjacent tubes restrain bending of asymmetric circumferential cracks, '

such that the corroded area averaged over the circumference of the tube can 'be used to provide a reasonable approximation of the burst strength of the tube. It is estimated that a tube vill continue to fail axially with no loss of margin to burst with circumferential cracks up to approx-imately 58 percent throughvall averaged over 360'. The Regulatory Guide 1.121 safety factors to burst continue to be met by a uniform 77 percent throughvall 360' circumferential crack. These estimates do not consider the additional strength provided by ligaments between the microcracks and the presence of microcracks at separate elevations.

Regulatory Guide 1.121 requires an operational allowance for tube degra-dation that may occur before the next scheduled tube inspection. SG tube rupture scenarios are restricted to single tube rupture events. There-fore, the operational allowance must incorporate both leak-before-break and frequency challenge criteria. The allovable operating period before the next inspection outage vill be the length of time required to accumu-late not more than one crack which could potentially exceed Regulatory Guide 1.121 margins.

Following the in-cycle inspection, UT depth information was analyzed to determine the depth profile of the cracks. This information was then used to calculate an equivalent throughwall degradation when averaged over the 360' circumference of the tube. Equivalent depths vere also calculated for the tube which leaked in January 1987 and the tubes removed for destructive examination. Similar to the distribution of circumferential extents, the distribution of equivalent depths was modeled by a gamma distribution with a mean of 22.3 percent throughvall and a standard deviation of 15.4 percent throughvall, Figure 5. A similar . distribution of equivalent depths is expected for any cracks which are identified in the future. Using this distribution, statistical inferences can be made with regard to the number of tubes with large equivalent depth cracks. Given a projection of 45 cracks, not more than

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.Mr. Villiam T. Russell B13443/ Attachment I/Page 9 February 7, 1990 two cracks are expected to have equivalent depths greater than 58 percent throughwall, Figure 6. In addition, not more than one crack vill have an equivalent depth greater than 77 percent at the 95 percent confidence level. Even this postulated low probability crack would not erode Regulatory Guide 1.121 margins due to mitigating factors known to be present- such as the discontinuous nature of actual cracks and the strengthening provided by the tubesheet.

The tube with the array of cracks with largest equivalent depth was tube 1H L25/R19, which leaked at 0.1 gpm in January 1987. This tube had an equivalent depth of 73 percent throughvall when averaged over 360' as indicated by the destructive exam. Tube 2C L118/R14, which burst axially in testing at 11,200 psi, had the largest equivalent crack of the tubes i removed in October 1989, estimated at 55 percent throughwall by UT and j 49 percent throughwall by the destructive examination. All of the l remaining tubes for which UT data was available had equivalent depths less than 55 percent throughvall, with the exception of tube IC L45/R13 and tube IC L28/R36 which had estimated equivalent depths of 70 percent throughwall and 60 percent throughvall, respectively. In all cases, the Regulatory Guide 1.121 margins to burst were satisfied, and in all but three cases, the tube vould fail axially in a burst test without loss of  ;

margins when compared to a virgin tube.

The results of all nondestructive and destructive testing performed to date, including the burst tests, fully support the assumptions regarding the corrosion mechanism and crack morphology used to determine '.he allow-able leak rate of 0.1 gpm. The vast majority of cracks found to date l have been relatively small in circumferential extent and shallow in equivalent depth, such that margins to burst have not been affected. The o few cracks with large extents and equivalent depth either exhibited or i

vould be expected to exhibit a leak before break behavior. The number of cracks identified by the inspections has decreased by a factor of 3, i demonstrating that the corrosion process is understood and under control.

The redection in the number of cracks further reduess the risk of a tube rupture and enhances safety. Improved crack detection methods and con- i servative plugging criteria assure that existing cracks, which could  ;

potentially compromise Regulatory Guide 1.121 requirements, have been detected and plugged. The risk of a tube rupture is considered to be extremely lov. s In summary, based on our conservative assessment of the in-cycle steam generator tube inspection results (UT and ECT) and the available burst test data, it is concluded that the observed stress corrosion cracking j intent of the applicable structural integrity and meets the primary-to-secondary leakage criteria of Regulatory Guide 1.121.

CONCLUSIONS Continued operation of the MP2 SGs for Cycle 10 vith regard to concerns associated with degraded tube and support conditions has been evaluated and

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Mr.'Villiam T. Russell B13443/ Attachment I/Page 10 February 7, 1990 ,

found. to be safe in accordance with applicable regulatory guidelines. ECT performed during the October 1989 outage has identified tube defects due to

. corrosion which could potentially compromise the margins of safety required by Regulatory Guide 1.121. .These identified defects have been removed from service. Pitting and cracking of MP2 SG tubes have been analyzed and found to exhibit acceptable leak before break behavior. If additional pitting or cracking. were to develop'during the remainder of the operating cycle, struc-tural_ integrity of the tube primary pressure boundary. with the appropriate '

margins of safety required by Regulatory Guide 1.121, is maintained provided ,

the 0.1 gpm primary-to-secondary leakage rate of the MP2 technical specifica-tions is. not exceeded. Leakage in excess of the technical specification limits requires shutdown of the unit, ensuring safety.

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'CIRCUMFERENTIALLCRACK EXTENTS .

MILLSTONE 2 STEAM GENERATOR TUBES i NUMBER OF CRACKS

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-y-g ce <<,. y . , - . - . , . . - g ,, . wr - _ _ _ _ , _ , - _ _--

_ ___ _______________________2__mm______..__ _ _ _,_ _ , ______g

PROJECTED CIRCUMFERENTIAL CRACK EXTENTS MILLSTONE 2 STEAM GENERATOR TUBES FOR A POPULATION OF 45 CRACK 8 EOC10 NUMBER OF CRACKS 10 94 95% CONFIDENCE 8_

9M CONMENCE O EXPECTED NUMBER 7 -

1 6

t 5 -

4 1

3 -

l 2 -

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180 210 240 270 300

! CIRCUMFERENTIAL EXTENT (DEGREES)  !

! FIGURE 4 '

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-L CIRCUMFERENTIAL-CRACK DEPTHS MILLSTONE 2 STEAM GENERATOR-TUBES

. UT EXAM NUMBER OF CRACK 8 20 GAMMA DISTRIBUTION PjPJ L25/R19 (LEAK) 15 -

W- OCT-1989-INSPECTION MEAN = 22.3%

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5 - -

0 I -

O 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 95100 AIVERAGE CRACK DEPTH (% TW)

FIGURE 5

_1 PROJECTED CIRCUMFERENTIAL CRACK DEPTHS-MILLSTONE 2 STEAM GENERATOR TUBES FOR A POPULATION OF 46 CRACK 8 EOC10..

NUMBER OF CRACKS 8 -

% 95% CONFIDENCE 7

,  !' 90% CONFIDENCE i 6- O EXPECTED NUMBER l

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FIGURE 6

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