ML20077H863

Rev 2 to Topical Rept 008, Assessment of TMI-1 Plant Safety for Return to Svc After Steam Generator Repair

ML20077H863
Person / Time
Site:	Three Mile Island
Issue date:	03/29/1983
From:	Moran T GENERAL PUBLIC UTILITIES CORP.
To:
Shared Package
ML20077H862	List: ML20077H863
References
008, 008-R02, 8, 8-R2, NUDOCS 8308110371
Download: ML20077H863 (169)

Text

--

t ASSESSME!C CF TMI-l PLANT SAFETY ,

FOR RE"~.'RN TC SERVICE AFTER STEAM GENERATOR REPAIR TOPICAL REPORT.

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March 29, 1953 AP-ROVA*S:

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Table of Contents I. INTRODUCTION A. Purpose B. Background C. Steam Generator Repair Program D. Safety Evaluation Logic '

I'. FAILURE ANALYSIS A. Operationr1 History B. Meta 11urgtcal Test Program'

~

• I:rr::i:r ^::- I:.;r.:

, D. Damage Scenario .

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E. -Distributien of Damage i

• • I III. CORROSION TEST PROGRAM .

A. Introduction B. Corrosion Mechanism Deter =ination Tests C'. Corrosion Scenario Verification Tests D. Repaired Tubing Corrosion Tests E. Conclusions ~

IV. PREVENTION OF RECURRENCE A. Introduction B. Prevention of Future Chemical Contamination C. Changes in Operating Chemistry -

D. Cleanup of Sulfur fro = Tubes -

E. Conclusions V. KINETIC EXPANSION REPAIR DESCRIPTION SDDGRY A. Description of Process and Geometry B. Design Bases of Kinetic Joint C. Qualification Program D. Repair Testing

~

E. Post-Repair Testing F. Conclusions.

VI. EFFECTS OF EXPANSION REPAIR A. Possible Introduction of Chemical Impurities B. Possible Effects on OTSG Structure C. Corrosion D. Ef fects of Expansions on Existing ' lugs E. Conclusions VII. P(UGGING REPAIR DESCRIPTION

SUMMARY

A. Introduction.

• B. Plug Types C. Plugging-and Stabilzation Criteria D. Post Repair Testing E. Conclusions 6 M

+

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Table of Conten:s (cont'd) i 1

VIII. CCMPARISON OF TUEE PLUGGING WITH DESIGN BASES l r A. Introduction

5. Operational Perfor=ance C. Accident and Transient Performance D. Moisture Carryover Considerations E. Conclusions IX. UNREPAIRED PORTION OF TUBES A. New Damage Not Occurring

^

B. Defect Detectability C. Undetected Defects D. OTSG Tube Failure Analysis for Unplugged Tubes

-. .an:.asa.n3 X. OPERAYIONAL CONSIDERATIONS

.* A. Pri=ary to Secondary Leakage

3. Radiological Concerns .

C. Secondary Side Chemistry D. . . Development of Procedural Guidelines for Steam Generator Tube Kupture E. Conclusions .-

XI. ENVIROR'. ENTAL IMPACT

' A. Introduction B. Offsite Dose Estimates C.- . Exposure Estimates

• D. Sampling and Monitoring

'7 E. Conclusions ,

4 i- X I. TECHNICAL SPECIFICATION COMPLIANCE 1

XIII. SLS.ARY AND CDNCLUSIONS i

APPENDICES

. ;,' A. Precritical and Post-Critical Test Programs B. Response to Questions REFERENCES FIGURES s Figure I-I TMI-1 Steam Generator figure 1-2 OTSG Task Organization Figure I-3 Disposition of Tubes in THI-1 Steam Generators

Figure I-4' Kinetic Expansion Process Figure I TMI-1 Steam Generator Typical- Cracks Figure I-6. Kinetic Expansion Langth ,

Plant Return to Service Safety Evaluation Overview

. Ficure I-7 Figure' II Number of Tubes with Defects vs. SG Elevation'

-Three Mile Island Steam Generator B 1

'~ Figure II-2 Figure II-3 Three Mile Island Steam Generator A Figure VII-1 Outline of Basic Tube Plugging / Stabilization Plan-Figure VII-2 Lane / Wedge,of Ibbes to be Stabilized-ii - .

, i

Table ef Centents (cont'd)

FIGUEIS - (cont'd)"

Figure VIII-1 Reduction in RC Flow Rate vs. Number of Tubes Plugged per Stes: Generator Figure VIII-2 Cc=parison of FSAR Flew Coastdown to Flow Coastdown with 1500 Tube Plugged Figure VIII-3 Ef fect of Tube ? lugging on Natural Cir'culation - THot Loop 1 v s . Ti=e Fign:e VIII-4 Effect of Tube ? lugging on Natural Circulation - Total Core Flow vs. Time F i - - e IX '. ECT Cilibratien Figure IX-2 Cri:i:ai Crack : :es'

-Figure IX-3 __0!SG Loading Cy ie for Tube Mechanical Evaluation Figure IX-a da/dn vs K for Inconel 600 1 Figure IX-5 OTSG Leak Rate as a Function of Crack Length and Tube Tensile Lead Figure X-1 Tube Rupture Guidelines Figure A TMI-1 Res:ar: Test Program Including OTSG Repairle Figure A-2 TMI-1 OISG Tube Repair Precritical Test Program A

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Tab.e IV-1 Three Mile Island Uni: 1 Administrative Controls Primary 'a'acer Chemistry .

T ab '.e X-1 Leakage Detection Methods Sun =ary Table *

"ab'.e IX-1 Laboratery Induced Cracks E/C Correlation Tab'.e IX-2 Critical Crack Sizes and Leakage Tab'.e XI-1 Maximum Hype:hetical Of f-Site Doses for 1 lbm/hr. and 6 GPH Primary to Secondary Leak

~ab".e XI-2 Exposures fr:2 0!SG Program Tab'.e XI-3 Radiation Fields at TMI-1 Tab'.e A-1 Post-Repair ECT Inspection Steam Line Fittings Inspection -

T ab_'.e . A-2

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!. INTECDUCTION A. Purcose In November 1981 primary to secondary side leaks were discovered in both TMI-1 Once Through Steam Generators (OTSG) . Subsequent detailed failure analysis showed that extensive circumferential cracking had occurred in the OTSG tubes. This safety evaluation describes the results of the failure analysis,-the evaluation of the methods of repair, and the operational, safety and environ-mental impact of operating the repaired generators.

3. Backcround ,

__ ~MIr1 is a 776 MWs' pressurized water reactor having two verti-cal, straight tube and shell once-through-steam generators

.* (OTSGs). Each OTSG contains 15,531 Inconel-600 tubes, 0.625 in.

OD, .034 in. wall, 56 ft. 2-3/8 in. long, rolled and sealed-welded,into 24 in. thick carbon steel tube sheets at the top and

. bettes of the OTSGs. (See figure I.1)

The plant was shut down early in 1979 for refueling and has re=ained in the cold shutdown condition since the TMI-2 accident at the direction of the NRC. In anticipation of bringing the unit critical and returning to service, hot functional tests were performed in August-September 1981 and did not indicate any problems with the OTSGs. However, in November 1981, during pressurization for additional tests, primary to secondary leaks were detected in the OTSGs.

As soon as GPU Nuclear Corporation realized the extent of damage to the TMI-1 steam generators in early December, 1981, a dedi-cated OTSG task organization was established to coordinate the repairs of the stea= generators. The structure of this task organization is shown on Figure I-2. The scope,of the task

? organization included determining the cause of ' damage to the steam generators, defining the status of the steam generators in terms of what type of damage and at what locations, evaluating the numerous repair options and implementing the one chosen, evaluating the effect of the repair on both OTSG and plant per-formance, and establishing whether or not additional TMI-1 com-ponents had been damaged by the aggressive environment which was apparently created in the once-through steam generators. An internal safety evaluation was performed which included these areas. Throughout the entire OTSG repair program, GPU Nuclear Corporation made every effort to obtain the advice and counsel of experts throughout the utility,l manufacturing, and research com= unities. As can be seen by reviewing the task organization on Figure I-2, the organizations and companies involved in de-fining the status of the steam generators and assisting in their repair cover a broad range of expertise.

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FIGURE I.1 TMI 'l Steam Generator ELEVATION -

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i In order to provide added assurance that the TMI-1 OTSO repair was conducted in a prudent, safe and technically correct manner, an independent third party review was established made up of ,

experts fro = throughout the utility and research industries. j This independent third party reported directly to the Vice- I President cf Technical Functions and was tasked to provide an independent and objective safety evaluation of the failure anal-ysis progrs=, eddy current examination program, OTSG performance evaluation, OTSG repair criteria, and the,overall OTSG repair program. The advice and recom=endations provided by this third party review have proven very beneficial. Their participation provides added assurance that the OTSG repair activities both conforn to the NRC rules and regulations governing the operatien ci iML-1 anc assurance ;na: :ne a-ecaecy u: ::.s s :a ;e.src::r

_- f.epair progra= allows safe operation of the TMI-1 nuclear unit.

C. Steam Generator Repair Procrem The approach taken to restore the Steam Generators to service was to evaluate the condition of each tube with eddy current technicues developed specifically for the geometry of this I

corrosion =echanisc. Following ECT the status of_ each tube was evaluated and one of the available repair methods was chosen.

Figure 1-3 su= ari:es the disposition of all the tubes in the i

TMI-1 Steam Generators af ter repairs have been completed. This figure indicates the four methods of disposition, the basis for selecting those methods and some other concerns that were con-sidered and resolved in selecting those methods.

The first category includes the tubes removed from service prior to the repair. These are tubes that have been previously plugged due to indications of defects from ECT inspections from previous operating cycles. Also included in this category are those tubes which had sections removed from the steam generator

.' for metallurgical examination and those tubes which indicated

' leakage during the initial tests af ter damage was discovered.

The second category is the primary repair method for the steam generators. This repair method for the TMI-1 OTSGs involves expanding and resealing the existing tube walls within the upper tubesheet at points below where the cracking of the tubes oc-curred. The expansion closes the gap between the tubes and the tubesheet. The expansion is done kinetically using explosives (detonating cord) encased in a polyethylene insert (see Figure I-4). The insert transmits the explosive energy to the tube wall causing an interference pressure.between the tube and the tubesheet.

The tube expansion repair method is feasible because of the specific nature and location of the cracking in the TMI-1 Steam l

' Generator tubes. The majority of the cracking is located in the 1

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DISPOSITION OF TUDES IN TMI-1 STEAM GENERATORS

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4 31,0G2 TUBES TOTAL 3 '

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- 347 20838 811 GG with ne known delects below willi delects be!aw US i a OD/ID indications < 90*, < 40%

. semoved leom sesvice IW below Ils e 8, psius to sepair US I 8 sepaised by espansion sepaised by plugging sepaired by espansion

-espansion joint qualified te plugging methods -csacks

-delects isom psevious Basis for . inspections os design bases qualified will not psopagate by D.isposel.lon mechanicalloads dusing

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-any thsough wallcracks below sepais whicli wess suissed dusing inspection piossans willleak dusing test program

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lliA is not a concesa and that c acks willnet peopagate by cossosion mechanisms

-paccaulians sahen which will prevent new c:ack losmation e

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upper ends of the tubes of the two generators, at or near the upper 1 in. to 1.5 in. where the 56 ft. long tubes were mechanically rolled and then seal welded to the tube sheet cladding (see figure I-5). The co=bination of rolled joint and seal weld held the tubes tightly in place within the tubesheets.

At TMI-l both 17 in. and 22 in. lcng expansions will be utili:ed depending on the axial location (within the upper tubesheet) of the lowest defect. The expansion length is chosen to provide the minimum length necessary between the lowest defect and the bottom of the expansion to serve as the new pressure boundary.

This expansion length corresponds to eight inches above the lower f ace of the upper tubesheet (US+8) . This length provides

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be repaired by expansion and those that would be removed from

-"- -service. For the TMI-1 OTSG geometry and materials, a 6 in.

leng joint below the lowest defect has been shown to provide adequate leak tightness and lo.ad carrying capability and is the basis for the joint qualification program. All tubes that remain in service will be kinetically expanded irrespective of whether or not a defect has been detected. (see Figure I-6).

The third category includes those tubes which cannot be repaired by expansion due to unacceptable defects in 'the region below eight inches above the lower face of the upper tube sheet.

These tubes will be removed from service by plugging.

The final category are those tubes uith ECT indications that are less than 40% through wall. Since analysis indicates that these tubes will not fail by mechanical, thermal and accident loads, they are being left in service to provide characterization of these indications after they have been exposed to operation.

Leaving this category in service provides infor=ation in future ECT inspections of the stability of these indications.

. D. Safety Evaluation Loeic To determine if the plant could be safely returned to service , a program was initiated to define all the significant effects of operatior of the steam generators af ter exposure to the damage mechanism and after the steam generators were repaired. The main product of this program was a logic diagram which defined the major areas that needed to be addressed and also defined the detailed tests, inspections and analyses which were performed to support each of these areas. A condensed version of this logic diagram is presented in Figure I-7. This diagram lists the major areas that were considered and ref.erences the sections of this report which describe the results 'which support the conclusion that the TMI-1 Steam Generators can be operated safely. The results of these programs demonstrate the following:

(1) The failure mechanism is understood well enough to define the root cause of the steam generator damage; l  ! -

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(0)' Other components in the RCS and supporting safety systeds were not. visibly damaged by the f ailure mechanism: ,

(2) The plant can be operated such that-this failure mechanism is arrested anc will not recur; (4) The Steam Generators can be repaired and operated within

- the design basis; (5) The plant can be operated with some tube leakage without

- adversely i=pacting tne environment.

The re=ainder of this section provides a brief synopsis of the enti-e -* ert .it' a-r':.t .i e en ib e !ccit ned :: deter-ine t'tt-

' the plant can be~tafely operated wi:n repaired stes= generators.

Reoert Su=marv AdetailedfailureanalysiswIsperformedincluding(1) review of the OTSGs fabrication history, (2) coordination-of metal-lurgical examinations of tubes pulled from the OTSGs, (3) review of the OTSG operating' plant ch'emistry histories, (4) coordina-I tion of OTSG tube stress analyses, -and (5) development of a ,

failure scenario. This failure scenario, which provides a '

reasonable match between plant conditions and the mechanism which caused the tube cracks, concludes that sulfur contamina-tion in the presence'of sensitized tubing material at the oxygenated, cold conditions' existing after hot functional tests led to the observed intergranular stress assisted corrosion.

Section II summarizes the failure analysis. .

1 i

An inspection of additional RCS components which included non-destructive testin! was performed to determine _if other com-1 ponents sustained similar damage to that found in the OTSG.

Emphasis was placed on materials which were susceptible to

-- attack in components .which fulfilled critica1' functions. No 1

damage was found. An inspection of RCS support'ing systems is 4 underway. Details'can be found in Section II.E.

l As shown in Section IV, paths for chemical injection into the-RCS and administrative controls on chemicals were f e::amined in an-effort to prevent ' future chemical contamination .of the RCS.

Additional periodic chemical analyses will be performed during plant operation and some administrative limits for chemical concentrations have been c. hanged. A sulfur conversicn and

. - - removal process will clean the surfaces of the Reactor Coolant System. This process will be conducted prior'to restart.

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To determine that the OTSG is operable in accordance with the j original design basis, the OTSG was analyzed in two sections:

the repaired portion and the unrepaired pertien. In the re-paired region, both the expansion repair and tube plugging were censidered. For the expansion repair the important character-istics were the load carrying capability and leak tightness of the new joint. A 6 in. expansion was qualified as the design basis , load carrying joint using mechanical and corrosion tests.

etails of this program are su=marized in Section V. In addi-tion to the qualification program, a process conitoring program was set up to oversee the expansion process.

Plugging repair is su==arized in Section VII. B&W Welded Plugs, Sp eyelesi e 71uns and W.=-inthouse . rolled >1ues were cuali-fied. Analysis verii:,ac tnat ac;acent expansions wcub: aave no detrimental ef fect on existing plugs, and analyses documented in Section VIII show that the system will not be adversely affected

, by either the nu=ber or distribution of plugged tubes for nor=al, accident and transient. performance.

In the unrepaired region of the OTSG, various tests and analyses discussed in Section IX have shown that:

(1) Corrosien tests indicate that the cracking =echanism has been arrested and does not reactivate in low sulfur water che=istry. If rapid cracking should reactivate due to an un'nown mechanism at operating temperatures or during he c p and cooldown cycles, it is anticipated that the.

precritical testing sequence would allow sufficient time for defects to propagate through wall to a size that would allow leakage to be detected. Therefore the precritical leakage monitoring during the hot testing will detect crack propagation.

(2) Analysis has deconstrated that cracks below a mini =um range of length and through wall thickness will not propagate

.. mechanically. A: 11yses included calculating a minimum size below which a crack will not become unstable due to plastic tearing or ligacent necking during a main steam line break (MS LS ) . This range of crack sizes is detectable by the ECT inspection system that was used to inspect the steam i generators.

(3) Any defects in the detectable range that are undetected during the 100% ECT inspection because of equipment or an-alyst error will be exercised during the test program. If they are 100*. through wall and of a size to propagate to failure under loading, they will ,be detected by leakage monitoring programs.

- , - - - - - ,.v. ~ e w ,, ,--- e

Soth an ICT flaw growth progra= which monitored a sample o f tubes for new defect indications and corrosion testing on actual defective ISI tubes in the present primary coolant chemistry, showed that the damage cechanis: had been arrested.

To determine if all unacceptable defects were detected by ECT and those defects not detectec would not propagate to failure, an extensive ECT calibration program was devised and the small-est sice defect which could be consistently detected by ECT was deter =ined. Comparison of field ECT results te =etallurgical exa=ination of tube samples removed from below roll transition in the TMI Steam Generators showed a one to one correlation between actual and ECT predicted defects. Stress analysis

< -- ?f t'- t : : 'o e f . tS t

1. -e ~5s t er,':! d e-e-t ste to failure 3

by co=binations of.=echanical leacs were within the IC cetect-ability limits. Local IGA one to two grains deep was examined during the metallurgical examination program and there was no indication that this ef fect wa,s related to the failure mechanism.

A precritical testing program has been designed that will pro-

' vide confirmation of the adequacy of the OTSG repair and OTSG operability.- The program tests for leakage in the repaired region using secondary to primary drip and nitrogen bubble tests, and a primary to secondary operational leak test. In the unrepaired region, axial stresses will be placed on the OISG tubes from nor=al and accelerated cooldown transients. The accelerated cooldown vill be at a rate larger than the nor=al cooldown rate based on past operating experience but will be within the cooldown rate li=itations of the existing Tachnical Specifications. A period of hot operation is included which will allow time for defects on the threshold of propagation to propagate or leak. Leakage calculations indicate that leakage from tubes with mechanically unacceptable through wall cracks will be detectable during the test period.

Operction with a primary to secondary leak ac 'the repair design goal of 1 lb/hr. and at a core conservative rate of 6 gal /hr.

has been evaluated. These leakage rates have been found to pose no threat to the health and safety of the public and allow the plant to operate within existing Appendix I Technical Specifications. Details can be found in Section XI.

This report concludes that IMI Unit 1 can operate with the re-4 paired OTSGs without undue risk to the health and safety of the public.

+ - ..

4 l'

II. FAII,URE ANAI.YS IS Three Mile Island Unit 1 was in cold shutdown from March 1979 until September 1981. In September 1961 het functional testing I was perfor=ed. The plant was returned to cold shutdown for some final modifications prior to startup. The plant was pressurized to about 40 psig in November 1981 and small leaks frem primary to secondary side were detected in the tubes of the once through s team generators (OTSG's ).

A detailed failure analysis was performe to determine the root cause of the steam generator damage. This analysis included a review of the steam generator operational history, a metal-lurgical and corrosion test procram. a. review of OTSG stresses anc fabricat on hiscory, anc cae caveicpcent ci a : allure

_- s.cenario . In addition, the distribution of damage both in the OTSG's and the remainder of the RCS was investigated.

< A. Operational Eistory

' . The time of the OTSG tube failures may be bracketed based on operational considerations. During EFT on Septe=ber 4,1981 the l leak rate of the RCS at full pressure was measured,and found to j be within spec at .5 gpm. On November 21, 1961 with the RCS at about 40 psi, leakage through the OTSG cubes was observed. -

l A review of cperational history of the TMI-l stea= generators

was performed for the period April,1979, through November,1981 to deter =ine whether instances of chemical contamination or.

excessive tube stress could be identified to determine the cause 4 of the tube failures. A detailed description of O!SG operating i history is found in Reference 2 and Reference 22.

1 4

- The operational hintory of the TMI-l OTSG's reveals that the tubes were not subjected to excessive stress, and generally, the i

reactor coolant system chemistry remained within specifications

.7 for the period extending from April 1979 through Fevember 1981.

i Operations did, however, have a significant impact on the chem-ical environment of the OTSG tubes. There were five identifiable instances of probable intrusion of chemical contaminants into the Reactor Coolant System (RCS). In March 1979 cil was intro-l

' duced into the Reactor Coolant Bleed tanks probably by over--

flowing the miscellaneous Waste Storage Tank through the vent - '

header. Some oil may subsequently have found its way into the R CS . ~ Tube surface ' analysis has shown that carbon was present in

.large quantities (50-90*) on the as-received surface. This car-bon is reported to be in several forms either as a hydrocarbon, a carbonate or elemental carbon. - Carbonate was' present mostly i on the surface, and hydrocarbon at greater . depths in the oxide i layer. It can not be determined whether the presence of carbon l l

or hydrocarbon on the tube -surface resulted from contact with reactor coolant containing some oil or from exposure 'to normal i

_7_

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atmospheric centa=inants af ter removal from the OTSG. In October 1979 sulfuric acid was injected into the Reacter Cooiant Makeup System. Although attempts were made to prevent the acid frc= reaching the RCS, chemistry results indicate some contami-nation of the RCS occurred (see Reference 22). In July 1980, May 1981 and Septe=ber 1961, a surveillance test was performed which =ay have allowed sodium thiosulf ate from the Reactor 3uilding Spray Syste= to find its way into the RCS. Sodium thiosulfate at levels of 4-5 ppm as thiosulfate is considered to be the most likely contaminant. The ionic species from the first contamination incident in July 1983 were removed from the bulk liquid by demineralization in August 1980. The ionic species frc= the second contamination incident in May 1981 appear to have been only partly removed by processing through a

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fate residual could have still been present at the start of

-September 1981. Additional s.dium thiosulfate in the RCS may have resulted from injections of Borated Water Storage Tank (SWST) contents during ceoldoyn fro = het functional testing.

This water had been previously mixed with water from the Reactor Building Spray piping. The quantity was not sufficient to be detectable by conductivity.

Significant to the localication of the attack was the history of the water level on the pri=ary side of the OTSG. Following the het functional testing in Septe=ber 1981, water level was promptly lowered on September 8, 1981 then slowly raised over the rest of the conth. This allowed a drying then rewetting of the tubes in the upper portion of the steam generator, causing

~

che=ical concentration in that region.

Oxygen introduction is also believed to have played a role in the damage mechanism. There were two occasions when oxygen was introduced into che system. When the water level was lowered, the OTSG pri=ary side was vented to the waste gas syste=. The caxi=u= oxygen specification in that system is 2%. Thus, oxygen

, was available at the liquid surf ace while the liquid level was being lowered. The RCS was vented to atmosphere through a CRDM vent on October 7, 1981 and remained open until filling in November when the leaks were discovered.

3. Metallurgical Test progra=

Af ter identification of the leaking OTSG tubes by nitrogen bubble testing, it was decided that in order to determine the cause of failure, tube samples would need to be removed from the steam generators for analysis. The initial selection of tube saeples was made af ter eddy-curren.t testing had been commenced and the choices were made based on maximizing the number of defect indications in each tube and providing an adequate sample of eddy-current signals for eddy-current qualification.

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4 j

Four tubes were initially selected from the "S" generator. One

':ube was a known leaker from the bubble test results, the other three tubes contained eddy-current indications of greater than 80* through wall penetration.

Af ter the initial samples had been removed, it was confirmed i

tha: eddy-current signal anomalies were showing up at the roll.

transition region. In order to determine the disposition of these tubes, additional tube sa=ples were selected for removal which contained these eddy-current s ignal,s . This time, fifteen (15) tubes were removed from the "A"

~

generator.

A third set of tube samples were removed which included 6 tubes frem :Se "3" ter.erate- and 4 tubes f cm the "A" tenerator.

These samples were :axen to oo:a n sch.e lo-a :evai cedec:s irem deep in the s:ea= generator, to sample tubes from specific aIreas, and obtain tube ends to be characterized (in previous

~~

. . samples the tube ends had been removed during pulling).

l 1. Analvsis Procram -

A multi-task program was conducted' co provide information related to the steam generator tube damage problem. This

! program contained the following analyses / examinations:

a. Visual Examination

b. Eddy-Current Examination

c. Radiography

d. Sectioning and Bending Scanning Electron Microscopy (SEM) and Energy Dispersive e.

4 X-Ray Analysis (EDAX)

f. Auger Electron Spectroscopy (AES)

g. Electron Spectroscopy for Chemical Analysis (ESCA)

h. Sodium Azide Spot Test

i. Metallography-Microstructural Analysis

j. Scanning Transmission Electron Microscopy (STEM),

- Electrokinetic Potentiostatic Reactivation (EPR) 'and Huey Testing

k. Residual Stress and Plastic Strain

1. Tension Testing.

! m. Hardness Testing.

n. _ Dimensional Measurements.

2. Test Program Results/ Conclusions t

The detailed test results are presented in Reference 2. .The'

' following summarizes those results'and sets forth some con-i clusions. ,

i' a. The tubing has failed .due to intergranular .s' tress as--

sisted cracking. The intergranular morphology has .been 9-e e

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h cenfirmed by Meta 11ography and Electron .7.icroscopy.

This has led in many cases to through wall penetrations l In all cases, and circu=ferenti.lly oriented cracks.

cracks have. initiated on the primary side surface. I 4

! b. Microstructural evaluation of the tubing from numerous locations , has indicated that the structure is repre-sentative of that normally expected for steam generator

- tubing. ests have concluded that the caterial is in a sensitized condition and hence is expected to be suscep-tible to intergranular attack in dxidizing acids.

! c. Transmission Electron Microscopy has also confirmed that no secendary =ede of failure is associated with the intergranuzar cerroalca, ca.; cs, no ev -sc:a .; ar., ..s or high cycle fatigue was observed on these fracture l'

~~~ - '

surfaces.

d. The consistent circumfgrential crientation of the cracks below the weld heat affected zone, indicates that an axial stress is part of the cracking mechanism. the Residual stresses in the roll alone were not responsible for the cracking. Therefore, the fact that the cracks

' occurred when the tube was under a higher 4pplied axial

, tension stress rather than hoop stress, confir=s that the cracks formed during cooldown or cold shutdown.

e. Axial cracks have been observed at the top end of the

! tubes near the seal weld. Some of these cracks pene-trate 100% through the wall but they do not penetrate the veld cetal. The axial orientation in this case is expected based on the residual stress distribution in the area of the seal veld.

f. Auger analysis of surface fi1=s on fracture surfaces and on the I.D. surface of the tubing indicates that sulfur is present up to levela of eight atomic. percent. The sulfur concentrations alcng the I.D. surface of the tubing down to the 9th tube support plate,'are generally uniform with pc haps a slightly decreasing level lower in the tube sa=ple. The form of sulfur is believed to be either in the form of nickel sulfide (Ni;S3 ), or some other reduced form of sulfur. The reduced sulfur form generated frc= the contaminating species is directly responsible for the cracking mechanism.

Auger analysis also showed that carbon was present at.

levels from 50-90 atomic percent on first and second 4

4 e

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,, . - , .,-,_m , _ . , . , , . . , , - . . _ _ . . ... . . . , . -_4, , , - - - _ . . , _ ,~.-_.-_.-m , , , . _ . , .

round tubes, but a caxi=um of 50% on third round tubes.

It is thus inferred that the extensive carbon contamina-tion en the first and second round tubes was the result of contamination either during or immediately after tube

i. re= oval.

In addition to sulfur and carbon, the Auger and ESCA i

- analysis have shown the presence of nickel, chromium, oxygen and nor=al trace quantities of fission products on the fracture surface. '

I d' g. In conjunction with the cracking, there has also been intergranular corrosion cbserved. These " islands" of IGA are not always associated with cracking and in 4;;;;;;.  ::.;. J.un: 1:

general are assac ata: ;;;c. ....

crack locations. tend to penetrate deeper than the ap-

~~~ --"

proxi=ately 1.5 to 3 mils of penetration typical of the ICA " islands." Most severe cracking in general relates to more severe intergranular corrosion.

i

h. In 39 out of 42 cases to date, cracks which have been examined either by metallography or by bend testing have shown the defects to be 100% through wall. The re-maining three cases exhibited penetrations of 66, 70 and 70%.

C. Corrosion Test Program A corrosion test program was put into place and addressed the i

areas of crack arrest, corrosive species and . verification of the corrosion scenario. The corrosion testing program is addressed in detail in Section III of this report.

t The following conclusions can be cravn ' from corrosion tests which relate to the failure scenario.

- a. Thiosulfate can produce cracking si=ilar to _that observed in the steam generator tubing.

b. In the absence of thiosulfate no cracking has been produced -

in the laboratory.in primary water chemistry.-

c. Tubing removed ~from the steam generators appears to have a e.

lower thiosulfate concentration threshold for cracking than an equivalent archive tube _which has been ~ sensitized.

d. Tubing thermal history is a key parameter in establishing i material susceptibility. _ A; threshold level of sensitization must exist. Data-suggests higher mill annealing tempera- '

tures" favor cracking in sulfur contaminated primary water.

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e. Crack initiation and growth rate are temperature dependent.

Fcr susceptible meterial, crack initiating time will be decreased and crack growth increased by raising temperature up to 170*F.

f. An oxidizing potential is required for cracking to occur.

In the absence of oxygen, cracking has not been observed in the laboratory. .

g. Crack growth rates appear to be very , rapid and can be as high as 1 mm/ day. Lab specimens have exhibited partial through wall penetration in areas of lower stress.

?  ?-:e ic = r:r . 3 - .

j}ut conditions needed for Intergranular Stress Assisted Cracking were evaluated and compared to,the conditions in the TMI

• • OTSG's. Based on stress analysis, fabrication history, the ti=ing of the cracking, metallurgical and corrosion testing and observed features of the cracking phenomer.a. a f ailure scenario was proposed.

1. Intercranular Stress Assisted Cracking (IGSAC)

The occurrence of stress assisted cracking requires that three conditions be satisfied simultaneously:

o a sufficiently high tensile stress o a susceptible material microstructure o an aggressive environment The information presented in Reference 2 relating to those three factors is sucmarized below.

a. Tensile Stress

' Since the cracks are oriented circumferential1y in the tubes below the veld heat af fected zone, the sum of the operating and residual stresses in the axial direction was greater than that in the hoop direction. Axial tensile stresses are of principal interest. Very little tensile stress is required to crack Inconel that is~this susceptible in the presence of reduced forms of sulfur.

'dowever, the higher the tensile stress the more rapid the crack propagation and the more cracks that actually occur.

e

The stress analysis results suggests that the cracking

=ust have occurred during cooldown or during cold shut-down because the axial tensile stresses are largest during this time. The analysis also indicates that the seal weld heat affected zone and the roll transition regions would be particularly prone to cracking due to locally high axial tensile. stresses which are possible in that region. More cracking occurred in the periphery than in the center of the tube bundle because the axial stresses at and below the roll are generally larger at the periphery than in the center 'of the tube bundle.

b. Suscentible Material Microstructure There is no indicatien that fuoe matertal, faerication or insta11'ation in the OTSG's was in any way extra-

_~

ordinary. The heat treatment of the whole OTSG foi-

• - loving assembly puts the tubing into service in the mill annealed plus stress relieved condition which is ex-pected to be heavily sensitized (i.e. , low grain boundary chromium content less than 10%) thus making it more vulnerable to ICSAC , Metallurgical examination has confirmed that the expected microstructure is present.

~

A large number of heats of Inconel 600 sre present in the OTSG's which dif fer in composition and which may have responded dif ferently to the stress relieving heat treatment. The degree of susceptibility as a function of the tubing heat number could not be established.

c. Actressive Environment As previously stated in Section II.A. the results indi-cate that sulfur was present in the primary system water and three possible sources of sulfur have been identi-m fied from the OTSG chemistry history. .

If SO4 and S 02 3 were introduced to the primary water as the OTSG operating and che nistry histories - .

suggest, they would be expected to persist as long as the water was at roc = temperature even if the oxygen

' content of the water was reduced by hydrazine additions.

However, hydrogenating and heating the water to perform a hot functional-test would be expected to result in the generation of S- , possibly accompanied by.S and other intermediate species. Subsequent cooling to room temperature and oxygenating following the hot functional 4

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tests rapidly oxidize S-~ to S and could also result in the appearance of significant cencentrations of other species of higher oxidation states. Although it is not pessible to predict eiti.er the identities or the concen-trations of the sulfur species present following the hot functional test, it is clear that this transient is likely to have greatly af fected the aggressiveness of l the environment with regard to low temperature sulfu- '

induced attack of the OTSG tubing.

2. Proposed Failure Scenario ,

This following scenario is consistent with all the observed features of the cracking phenomenon, the timing ~of the

in; nd :2 2 re: 't: -f t'a ,2 :l".urpi::1 3::+mir-ti r-and corrosion tests.

a. During layup the primary system was contaminated with

sulfur by the accidental introduction of sulfuric acid, sodium thiosulfate, and possibly a sulfur-containing oil. The amount of sulfur present may have reached several pp=, but the contaminated water was not aggres-sive enough to crack mill annealed plus stress relieved Alloy 600. The corrosion . tests confirm that cracking

~

would not have been expected to occur at this stage.

b. The temperature and oxidation potential trantient as-sociated with t.he hot functional test resulted in a change in the types and concentratiens of sulfur species present in the primary water. Further changes occurred when thiosulfate-contacinated oxygenated water was in-jected during the tests of the F.PI and LPI systems.

c. When the water level in the OTSG's was lowered following the hot functional test, high concentrations of aggres-sive metastable sulfur species developed in the dry-out region at the top of the generators due to the cocbined

' effects ef solution concentration by evaporation and the co=paratively high availability of oxygen. Changes in the sulfur species in the more dilute bulk solution proceeded more slowly resulting in lower concentrations of aggressive sulfur species.

d. Sulfur-induced IGSAC of the Alloy 600 tubing occurred rapidly in the dry-out zone with preferential attack at high stress locations in the most highly sensitized

- tubes. Cracking occurred to a lesser extent lower in the generator. Statistically this would be expected

?  :

because the bulk solution was less aggressive than' the enviro nment seen by tubes in the dry out zone. Cracks would occur in areas low in the generator which were l

slightly more susceptible to IGSAC due to surface fil=

anomalies er resicual stress anomalies.

Cracking ter=inated either because continued chemistry l e.

changes resulted in the for=ation of less aggressive l sulfur species or because the environment in the dry-out region was diluted by the slow!y-rising bulk solution.

Sy the time the water level was dropped again, the 4

che=ical state of the sulfur in the primary water was i

u_' i:ianti; ti it-t-t irr- its et:ta i 2distel siter  !

i the hot function &1 tests t'o prevent a recurrence o:

steps C' end D in the new dry-out zone. l

__ _ __ l l

. f. Cracking was discovered when the OTSG's were pressurized.

E. Distribution of Da= age To evaluate the extent of the damage, an eddy current testing In addition, i (ECT) program was devised to examine the OTSG's. ~

an inspection of other components in the reactor coolant system (RCS) and supporting systems was conducted to determine if damage similar to that found in the OTSG's was evident.

i 1. OTSG Eddy-Current Examinations Special eddy current techniques were developed and an ex-tensive testing program was established to provide an ac-curate cescription of actual OTSG tube cracking (Reference 20). In-situ eddy-current results exhibit tube wall defect indications at variec densities distributed both axially and radially in both OTSG 'A' and 'B' tube bundles. The majority of the defect indications were. in the upper. tube-sheet (UTS) region and particularly confined in the tube

' roll transition tone. After an absolute probe inspection of the-roll transition and mechanically expanded area of approximately 18,000 tubes EC,T indications were being j

reported with such frequency that it was decidad to affect-a j

kinetic expansion for all tubes in both tube bundles.'.

Further ECT data was not interpreted above elevation US+14 inches due to the decision to repair the-top 17 inches of all the tubes. Figure 11-1 gives the number of tubes with defects by elevation in each generator. Radial distribution of tubes (as shown in Figure II-2 and 11-3) with defect

" indications requiring plugging in both ' A' and 'S' OTSGJ shows a higher percentage in the periphery with the defect

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rate decreasing as you =cve toward the canter of the bundle. Esfects indicated belew the upper tubesheet are loca ed ceward the periphery in the 16th span and were ranos belev the 16th span. Reference 20 gives a detailed descrip:ica of ECT results.

2. Tube End ::=are .

In the fa'.1 ef 1982, corrosion and cracking proble=s were identified in the steam generator tube ends, where they ,

extend abeve the seal weld and upper tube sheet. The tube i end damage was evident with metallurgical analysis of tube ends re=oved free the generators with the last 10-tube sa=ple. Af ter kinetic expansion, damage was visible. The

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axial and cirev=ferential cracking, the pattern depending on stress due to v' eld shrinkage in the heat affected zone of the seal weld, and on other factors. Metallurgical evidence shows that the veld material arrested the cracks in all f sr=ples , although some cradks extend through the tubing  !

=aterial behind the weld to the tubing below. The force of kinetic expansien recoved parts of some tube tops where a circumferential crack was located in conjunction with verti-cal cracks. Other tube tops were billed out..where vertical ,

cracks were through wall but circumferential cracks were in i regions with ductile =aterial remaining.

In order to further define the problem, CpUNC removed tube end pieces from the tops of approximately 12 tubes and con- ,

i ducted a =etallurgical exa=ination in order to define what, if any, ductility re=ained. The evidence from this exa=ina-I tion indicated that about 1/3 of those pieces removed were intergranularly cracked on all- sides (both circumferential1y .

and axially).

i Evalua:icn cf the =etallurgical evidence indicated that the weld caterial arrested the cracks in all c'ases noted. (Re f . .

57). Additional dye penetrant tests were cbnducted on seal i welds in the upper tubesheet to further confirm that the welds and the heat affected zone between the tube seal veld.

and the :ubesheet cladding were not cracked. The absence of '

cracking as noted in these dye. penetrant checks provides '

assurance that the seal welds themselves and the upper tube-sheet cladding were not cracked. Similar examinations of i I

the 1cuer tubesheet velds and tube ends also showed no damage. r i

16 -

9

• 'ith a the damaged areas defined, GPUNC evaluated the poten-tial for loose pieces from the tube ends both above the seal weld and in the area behind the weld where vertical and circu=ferential cracks existed. This evaluation is docu-mented separately in Reference 55. It was concluded that tubing below or behind the seal veld was unlikely to be degraded to the point of loosening under the lov leading in these areas. However, tubing above the seal weld was con-sidered to have potential to break loose. Thus, the deci-sion was made to remove all tube ends, above the seal weld by milling.

C

3. RCS Insoection The sulfur incucec attack on :na ii!id tuce prc:p: 2c 4n n-spection of other elements of the Reactor Coolant System, to

- determine if other co=ponents sustained similar damage. An

., inspection plan was developed based on a review of the materials involved and the, accessibility of the materials within the system. Representative items in the Reactor Coolant System that were most likely to have suffered attack

.' were selected for examination. The items chosen represented the most susceptible materials and reflected environ = ental and stress concerns.  :

Materials located in either of three environmental condi-tions were evaluated.

a. Primary coolant-air interface where most of the defects occurred in the OTSG.

b. Dry areas since the last refueling, but which have been previously wet.

c. Wet areas, covered by primary coolant.

-. Since the known attack had occurred in the .0TSG on stress-relieved Inconel 600 tubing material (PWHT) which was under stress in the cold shutdown condition, this same and other similar conditions were, therefore, to be suspected in other parts of the RCS. In addition, attention was given to other matericis which are known to be susceptible to IGSAC. Other than the OTSG tube preload stress, areas of concern with respect to stress included bolting that has a steady load due to torqueing, residual stresses induced by welding, and force-fit items.

4 4

. . - . - - -- . - . - -. . .- __ = .

4 The plan included tests of suf ficient diversity to reflect the different caterials, stresses, and environments that are present in the RCS. The premise for this logic is that generic material groups will behave similarly. Therefore, heat-to-heat variations were not considered unless evidence of intergranular attack and stress assisted cracking existed.

The inspection plan was developed to also account for criti-cal functions of the RCS items. The function of the pres-sure boundary, core support, and fuel, integrity received the most emphasis. This was to determine the general condition of the system and, of course, because they are the most i directly safety-related.

1 The non-destructive examination c'ethods used were; ultra-4

--_ - . sonic, liquid' penetrant, eddy current, radiography, visual, and wipe sampling. Other examinations included functional j

. check on equipment and destructive metallurgical examina-i tions, both at the TMI-1 site and at B&W Research Laboratory at Lynchburg. The selection of examinations was governed by factors relating to the type of material, geometry of caterial, location and accessibility, and radiological con-trol limitations. The following is a summary..of methods used and example materials examined by each method.  !

Ultrasonic Examination Method - this inspection included the pressuri:er spray no:zle safe end, CRDM motor tube exten-siens, make up piping nozzles, plenum lif ting lug bolts, plenum cover to plenum cylinder bolts, pressurizer surge nozzle, core barrel bolts and low pressure injection pipe

welds.

• The ultrasonic method used to examine bolts of the TMI-1 core barrel assembly had the capability of detecting indi-cations having a depth of 20 percent of the diameter of the bolts. This sensitivity is considered sufficient primarily l

-- because a large number of bolts were examin'ed at TMI-1 and no evidence of intergranular attack or ICSAC was found. For i

example, C6 of the core barrel assembly Inconel X750 bolts were UT inspected;-if intergranular attack or IGSAC had occurred, it is likely to have been detected in this exten-

- sive sample.

i l Radiographic Examination Method - This method is a volu-metric type of examination that produces a visual image of l

.the test specimen. For this reason, this method was chosen ,

to validate the structural integrity of the thermal sleeves for the safe end nozzles. The pressurizer spray nozzle and

the three make up nozzles were located in a coolant / gas *

! interface and the coolant dry area respectively.

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Liquid penetrant Exa=ination - Special consideratien was given to the welds of the secondary oversheath to assembly oversheath of the incere detectors. Items examined by this method were: Upper OTSG Incone'. (tube sheet) and stainless steel weld cladding and the incere detectors closure and sheath, incere detector the dry region portion make up noz-

le, lower OTSG cladding surf ace and incore detector por-a tions from the wet regions.

Eddy Current Examination Method - The ID surfaces of the RV vent valve thermocouple and the CRDM' nozzle were the areas of special concerns which required this method of volumetric and surface examination. Both components are located in the area basically dry of coolant.

J Visual Examination Method - Concern for the fuel integrity was the major reason for incorporating.these inspections.

The areas of interest were submerged by the reactor coolant;

• • the top of core control components, the baffle plate region and the annulus between CSA and RV. Areas of similar condi-tions, even though they were dry of reactor coolant, were the plenum assembly and the vent valve assembly.

'n'ipe Sa=pling Method - This cethod was perfor=ed prior to non-destructive examination other than visual. The samples were chemically analyzed to determine the concentration of any aggressive species.

The results of the inspections and tests which involved over a thousand selected components, indicated that there was no evidence of a probicm si=ilar to that seen on the OTSG tubes. The functional tests all indicated that the tested assemblies were eperational. The destructive examinations revealed that even on a microscopic level, no evidence of intergranular attack could be found. Therefore we conclude that based on this Inspection & Test plan, the materials in ,

the Reactor Coolant System are re-certifi'ed for continued safe operation. The details of this inspection are reported in Reference 28.

4. Suoporting Svstems Inspection An ICSCC problem was originally detected in the Spent Fuel System in 1979, and a three year inspection program was established which was specific to Spent Fuel, Decay Heat and Building Spray Systems. As of June 25, 1982 all required volumetric examinations of the first cycle on the IGSCC schedule were completed and no discrepancies were noted. As I

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4 of August 5,1982, visual examinations were co=pleted for Decay heat and Building Spray with no additional indications identified. The plotting and trending of the known indi- i l' cations did not reveal evidence of growth. - In March 1982, cracks which were attributed to IGSCC were found in the Waste Gas System. Additional supporting systems inspections are unde:vay. Results will be reported in response to LIR

- 82-02.

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. CORROSION TEST PROGRAM

.A. Introduction An extensive corrosion testing program was initiated in December of 1981 to support the steam generator repair program. The pro-gram in several phases was designed to accomplish the following:

(1) Determine the conditions under which the corrosion mechanism

, oc. curred and how it could be arrested, (2) Verify the proposed corrosion scenario to provide assurance'that the mechanism was un'derstood (3) Determine whether tubing that has been kinetically expanded would be more susceptible to corrosion in service than other tubing and (4) verify that cleaning using

'-'. ~31: ->r-~i :.'.'. -- c 1us m ec--~ n :~ ' ' f n ' ' ~ ::.- r sections describe the results of this' program.

E. Corrosion Mechanism Determination Tests In December 1981, analysis of tube samples removed from the TMI-1 "B" Steam Generator identified the corrosion mechanism as stress assisted intergranular cracking. Cracking was circum-ferentially oriented and initiated from the primary side surf ace of the tubing. Analysis of the cir.cumstances whi,ch led up to failure indicated that through wall penetration of cracks oc-curred sometime after the hot functional test secuence and. prior -

to the pressurizing of the unit in November of 19S1. In view of this fact, a concern existed that the corrosion mechanism might still be active.

A corrosion test program was immediately put into place to ascertain whether or not significant corrosion was still occuring. The first of these tests was initiated in February of 1980 In this test, sensiti:ed samples of 304 stainless steel and Inconel 600 were immersed in primary coolant removed from the decay heat loop. This coolant was analyzed and found to contain 350 ppb sulfate. Specimens utilized in this test were e' bent strip specimens spring Icaded to apply con *stant loads near the yield point of the material. Tests were conducted for two week periods at 100 F. Specimens were examined periodically for evidence of cracking an ultimately examined metallurgically to assess if any cracking had taken place. The result of this test indicated that the current environment in the primary circuit of the steam generators was not sufficiently aggressive to initiate cracks.

The next concern was whether or not existing incipient defects

~ would, in fact, propagate under the environmental conditions which currently exist in the unit.; To this end, an actual tube sample removed from the OTSG with a known eddy current defect determined to be a crack greater than 90% through wall was tested in primary coolant removed from the decay heat loop.

This would have been a similar solution to that used in the l

initial screening test. This test consisted of filling the tube specimen with the decay heat solution on the internal surfaces, then axially loading the specimen to 1100 lbs. at a test temperature of 100*F. However, prior te putting the primary coolant into the tube, the sa=ple was also tested with load in dry air as well as air of high humidity. In neither case were any cracks observed. After all testing was completed, the specimen was examined metallurgically to look for signs of grcwth. There was no ebvious extension of the intergranular cracks and no evidence of additional attack in the area of this crack. It thus appeared that crack growtn was also arrested and no further tube degradation was expected. This was confirmed by the eddy current examination performed on the 100 tube sample e-- ^ ~ - e a , tnt ea tral - ene.s . ~W taidence of anr vreuth cf known defects or cetection of new cefects was cbservec trem December 1981 to t'ne termination of program in July 1982.

In March of 1982 after this initial testing had been completed, indicating that cracks were neither propagating nor initiating, a program was initiated which would define the environmental

. conditions necessary to produce the type of intergranular corrosion observed in the TMI tube samples.

A number of tests utilicing stressed bent strip s'pecimens were begun at the B&*J Alliance Research Laboratory (Reference 34).

These tests utilised anodic polarization to accelerate the i

cracking process and help to define electrochemical potential regimes for this cracking to occur. Solutions of boric acid containing various concentrations of thiosulf ate contaminant were tested. Those tests showed that thiosulfate at levels in excess of 5 ppm would cause cracking in sensitized archive tubes provided the degree of sensitization was suf ficient. It was also deter =ined that an oxidizing potential in the presence of a reduced sulfur form was required for this cracking.

Specimens made from actual TMI tube samples removed from the

-~ steam generator were tested. These samples appeared to be more sensitive to the cracking phenomena since they cracked at thiosulfate concentrations as icw as 1 ppm. ' This is believed to be due to either a difference in degree of sensitization of material removed from the generator or due to the ef fects of previous exposure of these samples to the thiosulfate contaminant in the primary system.

Sa=ples ware also tested in clean borated water during this phase of the corrosion program. It was found that in all cases,

' even when polarized in the cracking potential range, that in the absence of thiosulfate, specimens ,would not crack. Cracking was observed at open circuit potential in'an air saturated eviron-ment in thiosulfate contaminated solutions. However, if the e

9 6

solution was deserated and an inert cover gas utilized, cracking was not observed in any specimens, Based on the results of approximately 60 tests it appears that thiosulfate or reduced metastable sulfur can produce and is a necessary requisite for the cracking observed. Additional results indicated that time to failure decreased as thiosulfate concentration was increased and also as temperature was increased up to 1700F.

During this same time period testing was also being conducted at Brookhaven National Laboratories for the NRC. These tests were constant extention rate tests (CERT) utificing solution annealed and sensitized Inconel 600 test specimens. The purposes of these tests were to define the minimum thiosulfate concentration rec.uired for cracking as well as to establish the effect of tempera:ure ans ;tc.au :yarcaica ::.t:an:rs:icn en cr.:..in, sus ceptibility. The results of these tests indicated the cracking in the absence of Lithium could be. expected in highly

, sensitized material at thiosulfate levels on the order of 70 ppb. However, in the presence of Lithium it was found that cracking would not be experien'ced on sensitized materials provided the ratio of Lithium to sulfur remained greater than or

- equal to 10. Although additional tests are being planned to expand on the knowledge and understanding of the influence of Lithium on inhibiting cracking, this data has been utilized in preparing new administrative chemistry guide' lines for TMI-1 operation. The lower limit on lithium has been raised such that a concentration of 100 ppb sulfate can be tolerated in the RCS.

Brookhaven also conducted a series of tests to establish the 4

influence of temperature on crack growth rate. Results of their tests indicated that approximately 170 F0produced the maximum cracking velocity.

i At this phase the evaluation had established that:

o Cracks in the OTSG were not currently propagating o Cracking in non reduced sulfur contaminated environment was not anticipated o The corrosion appeared to be a low temperature phenomenon o Oxidizing conditions were required for cracking o A highly sensitized microstructure was required o Lithium hydroxide could be used a: an effective inhibitor of crack initiation or propagation.

From a metallurgical and corrosion viewpoint it therefore ap-pears that a repair process is feasible, that the tubing was not damaged to the point where it no longer was serviceable; rather it exhibited properties of material which are typical for any currently operating generator. -

1 l

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C. Cerrosien Scenario *Jerification Tests During the su=mer of 1952, testing was conducted at Oak Ridge National Laboratories in an attempt to verify the proposed scenario. As defined in the f ailure analysis, it was . believed that corrosion occurred during the cooldown phase af ter hot functional testing, a period in which oxygen was introduced into the primary system as well as lowering of the water level in the CTSG's. It was felt that the lowering of the water level allowed reduced sulfur species to concentrate in the thin water film on the tube surface and in the presence of oxygen caused cracking.

Although it would net be oossible to totally duelicate the cor-resion scenario, an at:enpc was maceico es:aolish :es; para-meters which were 4 close approximation to a hot functional test

~~

-secuence. This included chemistries similar to that which ex-isted at the time of the hot functional test as well as tempera-ture cycles, plus exposure of test specimens in vapor as well as liquid phase. In additien, in order to account for any influence of tube surface films on the cracking mechanism, all test specimens were actual tube samples removed from the TMI steam generators. This allowed an assessment of whether oxidizing /

reducing conditions in the steam generators .could change surface films and for= metastable sulfur compounds which could lead to intergranular corrosion. Autoclaves were set up to test sulfur centaminated borated water solutions with I ppm and 5 ppm thiosulfate and 30 ppe sulfate. This latter test assessed if oxidiced forms of sulfur of themselves would be aggressive. The test sequence allowed for examination of specimens af ter an initial exposure at 170*F. In all cases, no cracking was observed at that phase.

The specimens were then put back into the autoclave and the teeperature was raised to 500*F. Subsequently during the cool down to ambient phase, air was introduced into the system when

., the temperature reached 212*F. The specimens were then taken down to 130*F at which time they were held for several days.

Examinations of specimens removed af ter the hot functional sequence showed no cracking for the 1 ppm thiosulfate solution and no cracking for the 30 ppo sodium sulfate solution.

Ecwever, cracking was observed on specimens ir. the liquid phase of the 5 ppo thiosulfate test. No cracking was observed in the vapor phase of any test. This indicated that a threshold concentration of thiosulfate may be required for cracking to occur. What is not known, however, is whether the cracking occurred during heat up or cool down for this particular sequence. It may logically be assumed that cracking occurred during the heatup phase as tests cond'ucted have thus far shown cracking does not occur at elevated temperatures. In addition, testing conducted in the 1 ppm thiosulfate and the 30 ppm

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~~ -acid, lithium hydroxide, and ionic species concentrations being measured. Specific analyses based upen the conditions under which the changes take place can then further define conditions.

The increased adninistrative controls, removal of the sodium thiosulfate tank and increased sa=pling requirements will ensure prevention or quick detection of unwanted chemical contamination of the RCS.

C. Changes in Ocerating Chemistrv Administrative pri=ary water chemistry limits were implemented to prevent recurrence of the damage mechanism. This included an increase in the lower concentration limit for lithium due to its inhibiting effect on crack initiation and propagation, and an analysis for sulfur (as sulfate). A consistency check of pH and cenductivity will be implemented. The check will improve our ability to detect the presence of potentially harmful ionic species. Table !!I-1 shows the changes in the primary Water Chemistry Administrative Limits.

4 '

1. The lower limit for lithium concentration vas increased from

.2 ppm to 1.0 ppa. This was done because lithium has an inhibiting ef fect on crack initiation and propagation when its concentration is maintained at about ten times greater than the sulfur concentration in the Reactor Coolant System (RCS). The upper limit for sulfur (as sulfate) is .1 ppm, '

thus the lower limit for lithium is 1.0 ppm.

Lithium concentration is based on boron concentration, with a maximum allowable concentration of 2.0 ppm. The lithium concentratiens range has thus been changed to 1.0-2.0 ppm.

2. Chloride was changed to meet revised B&W Water Chemistry Guidelines.

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l TABLE IV-1 THREE MILE ISLAND UNIT I PRIMARY WATER CHEMISTRY ADMINISTRATIVE LIMIT CHANGES OLD NEW SAMPLING SA.T LING ,

FREOUENCY FREQUENCY OLD LIMIT NEW LIMIT PAR /O'ETER Daily 0.2 - 2.0 (ppm) 1.0 - 2.0 (ppm)

Lithium NONE Varies wich boren a ec.:s.~.c: ::.: .

Chlorides ~ SX/wk SX/wk 10.15(ppm) {0.1 (ppm)

Sulfate, (S0 4=) NONE Daily . NONE f,100 (ppb)

Sodium.. NONE 2X/wk NONE (1.0 ppm 4.8-8.5 4.6-8,5 pH 5X/wk $X/wk Conductivity SX/vk SX/wk NONE ,

-- Check for Con-sistency With Boric Acid and LiOH Concentration p

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3. Sulfur '(reported as sulfate) was added to the Administrative Limits because of its deleterious effects en crack initia-i tien and growth in Alloy 600.

4. Because sedium becomes easily activated and is an important contributor to total activity in the RCS, it will be moni-

• tored. l D. Cleanus of Sulfur from RCS '

To preclude corrosion by sulfur contaminan'ts already in the RCS, GPUNC plans to conduct a chemical cleaning program to remove or oxidi:e residual sulfur. Testing has shown that near the outer

-urf::e of the er.ide film, sulfur is tredominantly eresent as suliste. Furtner into :ne sur: ace riis, metal suliices pre-dominate.

• The cleaning process was select'ed to chemically convert the metal sulfides on the steam generator' tubing into soluble sul-i -fates. In general, the process to be used in the plant is as  :

.follows: . ,

The RCS, Makeup and Purification. System, and the Decay Heat ,

a Removal Systems will be in use. .  ;

t The pressurizer will be-used to increase system pressure to approximately 320 psig.

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• Main coolant pumps will alternately operate and cooling water flow through the Decay Heat . Removal heat exchangers  ;

will be adjusted so that the entire system operates at j approximately 130*F.  !

• The coolant at this point will contain a boric acid concen-

~

tration between 1800 and 2300 ppm as 3 and lithium con-- ,

centration of.2.0 - 2.2 ppn.  ;

• Af ter- temperature and pressure have been established, con-

'- centrated ammonia hydroxide ( 30 wt %) will be added via the ' ;

caustic mix tank and Decay Heat Pump- suction.to increase the - i reactor coolant pH to 8.0 -- 8.2  ?

• 30 wt % Hydrogen Peroxide will be similarly ' charged into the - !

reactor RCS to establish a final concentration of 15 - 20 l ppm. Since the peroxide will decompose, further_ additions will be made as .needed throughout the test to keep the .

peroxide in specification. +

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i L

e'* w  :., $ b + ,.-,,-.r4 -,r1 ,,,..wI - - .Ev e- .y ,n- r--y, , ,,--r.,

• The cleaning solution will be continuously circulated.

Cleaning is expected to take approximately 2-3 weeks. ,

Termination of the cleaning process will be based on the determination that no further sulfur is being solubilized and results from the process development tests.

Both.the dissolved sulfate and the a=monia added will be ,

removed from solution by ion exchange resin in the normal purificatien systems to levels consistent with nor=41 RCS chemistry values. ,

A comprehensive test program was performed to determine the  ;

ef fectiveness of the cleaning process , and to verify that the conditions of cleaning would not introduce a corrosive environ-cen:. ~he prcgram and reau.;a are -ticassec tr. a Jap-rs a s_afety evaluation. Hydregen peroxide appears to be effective in recoving sulfur from both tubing surfaces and from inside

- ~

.. crevices. Based on testing, 350-400 hours of exposure to the ,

I hydrogen peroxide solution is expected to be adequate to remove 50-80% of the sulfur present.

I. ' conclusions  !

GPUNC has i=plemented corrective acEions in four areas in order to prevent recurrence of OTSG corrosion. The sodium thiosulfate tank has been removed fro = service to prevent additional in-advertent introductions of sulfur, and chemical cleaning is planned to remove existing sulfur. Stricter administrative controls have been placed on introduction of other potential che=ical contaminants. Stricter controls have also been placed i on RCS chemistry to maintain a non-corrosive environment. These -

actions are expected to prevent contamination and corrosion-by ,

sulfur and by other chemicals.

i l l

. l

[ .

I

. - - - - - ---s a e s - - - - -

.f.......

. . , . . , . r.3.

.. n..-c....

.a..... ,;e.:.;.................e.,,,,.:. . . . . . .

T A. Le scrirtien cf irr:es s and Ge:tetry

.. . . . . C ce L.. .. .. .: ., ..

e . . .

. . *.. ... 6.d - * 'J I t e Xar.ina:ier.s ha*.e revi a.e.j a .arje

• .L.*er ;;

.. . . k. ,. g y:.. .Je.t,. . .g n. :...1.. . . . .

.. t . 7 7..

.. .. .. o. '.. t s .b . t g .. .

a

r. f ,. :. t .. . .. .

s

> defined as anv eddv curren: indi:adion interrre:ed as

'.. v.a.l. *A.: . .2 . s c .' e d. . ' ". c u . .-e. . .

g ..

., s.. ..e.. ...s..g. I.C'. .h.e cete:: art,. :y are ce,"inec .. . .

.. . . in ,e:: en .

..y. ..4ne repair approach is to es:ablish a new pri=ary syste: pressure A kine:ic expansien of :he bound ar.v belov'these defec:s.

ube within :).e :ubeshee: vill be :he apprea:h used :c e'- e

..- . . . n : s . .,. :

..... . . . . a11 .. w.es y..:c

. . . 3., n .. .-.

g

. . .e.

3.y f. s s. . .

. . . . .i.a..

viii be .:. e ne:::al.y expanded irrespe :ive c. v.ne:y..er er ne:

3 they have a defe::, and .irrespe::ive :f whether they vill be .

,a

.,...,: :. . . ,. n . . . L.. ..u . e . ... s . e.,:. y:. ,. . e. . .. : a.. e a $c

r. 33 . . .

. . . .:.6 . . . E4***E830..:*.3,y -. , E '. .A..: .. *-**- i*...s...**'-**CI.

.s.. * * * - **e*- .

s._.g.:.e .g.g:... .. ....

. s 1'0,..s

~. , ' : 0 } 1 c y:. . . .s,. g.s..

Detal,.s can be .Ount. in 6 t.e.geren0e e . .' . 100. .eferer. e

... . . 7

.e .s. . .. . .

s

. p . .

t. a.7.

s t

d

.. Eine* c euy.e -XDansion s.. ,

4 i p., y:--*.yE 4 : . . -**-**

. . ' . .g. J* ..: u ..: *

• • • y .g.g:- y g ,*,,-

.ne ....,,s s .-r- - - - * - r -

r.....

. c u. ;: s..... . : y ,- C .t y..w.. . . . . . : e ..g .: . .a. .. . . .. . 7...'.,"s...,...a.<...

... . . . ..; u s. '. 3.. .

... O .... c ,.z...s

.:...- 1- ( E.. .'. r . . s .-.V e l' ex y a.s:... C.e e. s.. a.

.u.. ....u .

.r.. .c.. . ..6** **** .

. ..: . u..e

b. :..u.... .

t L.b,. s ..e u e .'5 ..

u.s ce.t. :..,,.2 .. u. . s. .. a $.u :c. eX.4.s:. .

.. e . :. : . a.).

.es.;.

. . . . . 7 .. ..

Delov :Ge .Cres: CtleC: v ,1.

. . , 3

...6.'s .

. 3 prC\*:c e :.ne Oesire:

. .3.Ca; car *y-ing' r.argins . 4:e expans.o . servin; as :. en new pre ssure beundary-is :he be::c:. six-inches Of a 1" in:h ex;znsien ... s: .. . . . . . .

., 1 ex...,w: .....e..3 .. g....s . , 3. . .. h ,. c .a ,.. t .; s.. ..

..r.6- -- rr--

, . , ~.

= . ..u. . . . u 2 ,. s. ,. . :

s ta ...o,s . .

.. t. u., ,. s . .c.. . . . . . .

s .w  :

s.. s 1u c.. a.. y cy e s.a . e . ,...e.7 . 0y.: .a. , a. .. ...: . a . . .

u .a . 7. . : . . ..

jcin:. Tubes vi:h defects lever than 11" vi'.'. '!c cc .sidered ind ivi du a11v. Th:se vi:h the-1:ses: defa:: between 11" and

.n se vi:.n

., . o .

36n vit.

.3 .ce expa.ded using a: .a. expa.sien. -

n  : .

. . ,.. .... ......wg5 .....

.s..a. ,a. u.,......,

a. .u, .. .,.y d e .ee .. .s .o.... ... . . . . . . .

vill be taken cu: cf servi:e'.

- 2

.9

• w ~ .v - .- , , v- --r.--g

The ~h*.-1 CT5G repair p;c:ess is as f:'.'.:vs.

.c.... .

ves .:..:C.-

A .~us..

A u .he . s....;t...

s:.., .. ..... e .-- ....,. rr..

ubeshee: Crevi:e.

u. .,. .. .e......

.  : . e ....a.:.., ..... ..

.. ... ... .:s....e (vaporize wa:erl.,

.e i

4 Kinetically e y. rand tubes a 5 Clean debris free. kine:iC er. pans ion

-- ._ u

• 6 .u.ill tube ends l t

e

.,Ush t* C.5v, .

5 Flug necessary :ubes

=

c Clean OTSG vi:h fel: p'.ugs.

,. s :... s ..a .: t , ,. ., .: ..

...,. so...

ts.......

~s

. . -- .: 6 * ..-- .- ,' C- --

...e . e. ... . ;w...

~.

.: . . . C ...:..ses a k:.c..:. . . . ... e h.r-- . , . S .-*-

s" "g s ". *. .' n . ' a

...gg g .w ...: ... s. .. ,. s. : .. s ) u s *. D e l."V

• h. .". u'~r ~re ". *. ".'- *.. s '. . *. *. . . .

Ane ,R:ne ::

in :ne area C: the origina. shCp re,.1 expans. en.

3 t%.a.s:w,... . ...

. . 1 O t- .. .nt ,.t g. s s .. e D . .. , s. s. .,

. . . . . .y z.; . . e.. . ....u..a., .. . .a .. . . a s. u.. .

y .. .

.w,

. . . . ..u. D ,. s . . , .s....

... C

- . . . . . . .he .u.s,..C . .

...g .:. ... g *. (~. .w c

• f g S :*6 .U y g 3 : ,- -;3 S*- *..*-- .,e- --

.t' 'E : , ,* *. . . ,

• 4.y C .: .ae s :. g.... uwa . s :. .s . ...

. . .u. . a.

. . c.  : C '. '. .....e

. ...:.. . s& S.. ., "

kine:ical'.y expanded jDint. ,

3. . .ne repaired tube sha.3 & sustain :.en sax =ur.Ces;gn Dasis

• - : r.. e* :

. J ax . ?. .e.s.Ae . ..

• e -

A wa.d C. .1*. .1 %. . ....

5 a. .. .s..,.

. . . . . . . C As/ .

ge... .v. w .-

T. ., a c ,

).. .. 2. . .. ..e a a..:a......s... a. s. '.). s :.S:one.e s .

• o ..n:s is e. u. ..s.. .. '.. s

.%: ..  : . , C .e.

... ...C..e._e..

....e s s! s .* .*r. .

6 6. ..e.

s e. . :. . s :. , . . 6. ***3 C.l.f.

.* -- A . . .

u .. .u,

.u, ....*-e*,,.

..~,% u,...,t. -- *- - - .ht t y . *. rC 2 , ~2 g --. a *. l f

~ ' - --- ~ ~-- *- - * ~

r=k-' **** .. . . . .:.... r' .

'..h..,,e.

as :,.a'. e. 4.... CC.res., .

r v.2... w;.g .. .v .w:. . . . s '. C s.. . .us..

3 ,.

4. .r.t :C a t e r re ssure CVC.A es eX-ane .int:ial Cesign 11.,e 00'e::1Ve IC: O,n e tube ,K1:e*1C i

par.s'.en is 5 years.

c..

.... . 1'.1,...

... C ,g.

. . i..t. . gee.,1'n. . 6 . -

8.s/O. 3 *'3 *...a.: s ..:. 11

. a.e7 .._.: ... . ,/.

u. .; ....t.

C....e

.. . : , . .. s..e qu. .a.: 1:. : C

. o. . 10 .......a... .C

. s ,. .

..  : s .2  ; . w  :

. . . . s .

r--6..e

A design life of 35 years has been established as a goal. ,

I The qualification program will include test specimens for cyclic testing for a 35 year life separate from those used to initially qualify the repair for a 5 year life. These specimens will be tested using the same key parameters but with greater numbers of cycles in order to satisfy the 35 year life goal.

3. Tube Preload ,

The design objective stated in the original steam generater equipment specification for TM1-1 OTSGs was that the tubes .

ret be in e:mpressien when cold. ,

The repaire"d tube tensile preload shall not be changed by

_~

= ore than 3C lbf at ambient temperature. This design ,

• - objective is intended t'o assure that tube preload tension is maintained so that the vibrational characteristics of the tube will be unchanged for a preload change of this magnitude.

4. Resicual Stresses .

One design objective is to minimize tensile stress in the transition region between the expanded and unexpanded  ;

portions of the tube. Analysis shows that an abrupt transi-tion results in higher residual stresses and larger stress  ;

concentraticns. A transition length between 1/8" and 1/4"

• has been established as a goal.

An objective of maintaining additional residual tensile stresses (both circumferential and axial) resulting from kinetic expansion in the transition less than 45% of the .2%

of f set yield stress at room temperature has been established.

d

-- - 5. heat Transfer Recuirements .

No credit is taken for heat transfer within the tubesheet.

6. Pressure Boundary Leakage The original design basis for steam generator tube leakage

.was to provide generators with no detectable leaks at ship-l ment and to control leakage to an acceptable operating level by monitoring and repair over the 40 year life of the plant.

The kinetically expanded' joints used for repair of the TMI-l l

steam generators are designed to be essentially leak tight.

l The expansion is designed to provide a seal b'elow potential l

t e

- -. s - - . - ;e- - , - + - --

, ,- - - - - , , .v-- y---

I 1

'. ear. pa:hs in a'.1 tubes :: be repaired.  !;':e s vi:5 una:cep:ab'.s leakage as indi:a:ed by the ; e::itical d-ip and ni::csen bubble tests (see Appendix A =ay be roll expanded abeve the icver 6" :o a::e:p: :c seal the leakage.

If :his is unsuccessful the :ube vill be ;'.ugged and/or , ,

s:abilized if necessary. l f

,4

... r.

... sr.. .:.., r.._

..:_,.....e., . . e.2. 3..;. ,..,_.. . ....,.g...

leaka.re lini

s vill centinue to be se:,tv :he e:hnical .

i Specification li=it of 1 sp=. however, in c der :o cen::e!

.ne a=eun: o,. vaste that requ :es processing, a cesign g:a.

J of 1 lb/h 7:0jected total leakage fro: D0th genera 0:s has

. been se fer the qualification p cgra . '

Eubble testing can

! distinguish a leak tha: is of the =a;nitude of C.1 gallens

_m. .yer. day. An eng'inee:ing evaluatien cf bubble tes: results

! as they rela:e to expe::ed leakage vi'.1 be condu::ed in

• • c: der :o de:er=ine wha: tubes require plugging. 5:a:isti:a. .

analysis vill be applied :e 5he verification tes: results.

C. Oualificatien Pretrac A series of =e:hanical tests and che=i:a'.. and cer:qsien tests

!' vere perfer=ed :e qualify :he kine:i: ex;ansion, and :Se kine:i: ..

i expansion' process :c =ee: the design gea..s c:. produe.:.; a ;cin: ,

capable .of carrying required 1 cads , providing a leak :ish: s,,.:,a e a '. ,

s, a.a ..v.. ..e .a> .....,s. .

.es:.s.a1 .. ...e

.u ... ..

c. .. . 3 e. ......

cf preli=inary tes:s was cendue:ed :e es:ablish :he cpti:n=

> para.e:ers fe: a kine:i: expansien p ccess tha: vill yie'.d 4, a::eP:arte scin:s vi:.n lov residual stresses. A_, ., : t :n a . :es:s. .

vere cendu::ed en a full si:e s:ca: generate: at b5V's M: .

• 'ernen W::ks .

. A core detailed des: ip;ict cf :he tes:s and '

re s e'. : s can be fo nd in Referen:e 23.

a

1. Me:hanical Tests

a. preli=inary Leak and Axial Lead Tes ts

, T.inetic expansions were tested :: deter =ine the asii ::

axial load which eculd cause :he expansic: :o slip.

Af:er'a se: cf expansien parare:ers were p:s:u'.a:ed, leak rate and axial lead tes:s we re ;erferred te de:a:- ~

! =ine whe ther :he exp ansien v:uld s:i'.1 appe a: adequa:e

! for a cc :cded tubesheet, cf:e: :her a*. ::.d pressure i .

cycling, and af:e: adjacent tubes have been er.panded.

f The following c.ccep:an:e sea.ls vere a;;1ied. .

l l

(1) Wa e leak at a p:essere differen:ial ef 1175 psi;

(? izary . :e Se:endary ) 3.3 x 10-5 lb/h: pe :ubt.

[ +

L

• 1 b

. 37 _.

i .

l -

e6 --. ,w-' i--.,,..e - ~ ,--+ e--- -,.,e,,- - -.,,.--p r-.m e-- . , - - 4

• e -mm w , w g -

\

1 e l l

(..,,....z...

) .. -

.3 .

. c.s:s......

.. . .....; 3 9. ..., . .v. . ... . r... . . . .

(3) Margin in ;;' iou: icads and leak rate te acccu .: fe:

p:,..e c sr=s a' ' 3e cv:,.:ngd *. . *. anc

. a - :. .- .. . ' g; : .. .s:a..vs

. .....-.:. . '-e-

s:::a.

s. tea..v

<.. w: : :., e>..a ,:..

.. . . . .... .e...

i

($) u.; . . . :_:.e . c. g.:.us.:.

.. s..s:

.2

. . . . u... s .a  :. .. .. .n e . ... n. . ...

.. u. . ,. e ,x. .. .. s :. n ...ess.

I (6) Mini =i:e in plane defer =a:icn cf :he expanded :ute

! ' clock hele and adjacen:. hole s.

J f

• t,

. .,, e .z e.c. . .. s c .s - .. u.. ,. . a ~. a ....a

... p.e.ss..., . .. ....:.. ..

~,. ,.1 c. . .. '. c as . v =. . e - .' .. :. a '. .

1

b. i.eak and Axial 1. cad Oualifi

stien Tests

,a

. . .,. .e. g .e. s. r- s .. ,;; *--,.* ;

- - ,.- ,- , gr.

--s .: -...,,,

- s.a- .

.y.,.

. gxi , 8. .. , a. . . .y : . .,.......

. .g.,..:1:..v..

. .. .. . a. . .. .. .. .. ,. e. . e ,. ., . -

s :. ... .- e u... :. .,. .,e,

. g s n ...

. ., a. ....g.. e :. :. e . . ..,.. .: n.... : . e x.7.., . s :. .

y :. ,. ,. n ,v ,. c.. n.s:g.e..

a . ... . s.,,,:.. .c... .gn...<. .; ... .;e.,. . . . . .:.a.2 ..e . . .

e::e:: c, re-expan:ing prev us.y expance: :u:es.

- . - . s a

+

4 4

i 4 f g - * . . . . - ++ +-N-r -+ *'-'s- y +7 *.+t V3 -? y v'  ? Y -- T. *v' y - d ---

p~.. , e..f . a,. ,. ....

..:.e.:a.. . .e...:. 3...

.u.. ..a s.a.:s.:.a.. . . . e . . s. . . a .

len :: '--

-asults snew c y . :cn:::ence . eve,. :.na: --

c' ..'. .<.-.s ex,.-...v..'...-..- .- , . ' . . . - . . '. c .- '. - .. s. .' . e .

than 3140.lbs. A cean leaka6e ra:e, c. : a'. : # 1ess :han -

3.2 x 10-3 lbs/h /:ube was desired.

Results indicate tha: ther=41 cycling : ends :o de:: case pullce: Icad, however th :=al'y cycled blocks pulled a:

70'? gave a 99 - confiden:e level :ha: 990 cf the tube expanded vill have pullout leads in ex:ess of 4170 lb.

- -' One block which was pull tes:ed a: 330*F save 99/99

~

sta:is:i:a1 ccnfidence tha: pelleu: lead veuld be in c,.r.e.,..

excess c.a e .z e, 0 l.es. .

ane ges.. cen.z :en:e :.r.a e. ....

cf the tubes have pulleu: above 2110 *.b is easily =e:.

In addi:icn, an expansien pull :es: perfer=ed en a fu'.1 s.- a.e ge . e.a.c. . . . . a.. v.... .. . . .. . . s....; .

. . .. . a . ... a. ;. .. ... ..... .: ..

capabili:y of a: less: 3600 ppends.

Le .r,.. a . e . e s .'. s a .# . e . .'..e . a '. c v. .- '. 3. - .- . .- . .v .'.-- .... x i

1 ':

e-

. a.- - : .e . . e- a . .- x . s

. - 6 s. u. . .ru...

. . . . /. . ,. . .-.

a... .. ,... .. ..3,.

g..e; .e -e e.-. ...e... --:....e ...a. .,r.

v. e .s. . . ,

..,. ,...s .. .-.. .. .. . ..

-..c... x. ..,~ . ..t ....e.-.n: s,.. .e . a . x. . . : . s :.a.:...e

. . , . . . ... ... e.... . .... .

fiden:e :ha: 99% cf the nor= ally expanded,:ubes vill have leakage ra:es ne greater ther.132.4 x.. '.S~; ib=/h /:ube. - . . .

...le ant th. s ra:e exceeds :.ne ces t.en c:.e:::ve c: 3.2 x 1C c Ib=/hr/:ube, 1: is s::11 a very ice .eak rz:e.

F.esults cf 1eak ra:es af:e: axial loading are f:und in Referen:e 23.

ll u.,. .:. .. u, c ..-..C . m~ s~ e. 1 e .- >. . a. .' .- . . v. . '. s _ .- 7. 3 - - . a . >. .~.. e A. e.......

. . - .,.i . ..: v ,. ,. e .,... . ... ...v . , . . s> . : ..., . u. e ,. e s . ....

.. . . . . .. ,. .u.

. . . 2. .. ,. .a . .. .. .

.. .:.. , Sp,.. z1..a.:c .. .. s

. . . .. a r.

c .c .. h ,. .e . .-..

m

.. 8. : _.: ...:

. .. ..v ar- - - .

rate of the ene block showed an intresse ietkee- 10'? and 400*F (61 ef the :otal range of leak rates) lea'ing :e .he I conclusien tha: the leak ra:e fer.a.:cie  :...

a cperating ten-y u. . a. ~ s. e p......u .. . , s

v. t.. g c : a.e .z, . c .. ... .... s . :. .u

3. .. . .. .. - . ..u....  :

a.. . .o- .e

. ,,,..a.u....

. . .. e

c. .i.e sic.;a,, ::ress -testine

(,. ,3..: ..

.e  :.. . .v . . . , : . : e.

. . . . . . . . . . . . .. e> .,

: ..4....

........:n.,

. .is ..e s. . de.e._:new;

.u..,.

ea r ..,:.. . . . . . . .. e......... ...,..... s . ....

. u. .

u..ulg

. .ead t .o. a . . ..... :. .. r. .. .. ...a . ., ... ......g ..: ..:.e...

.a . . . e s s _ . . ...... .... .:c.

.. .s:..to. .esic..

.. . .. . ...,,.s

. 3c. -

9 e

A.

.m. m m . .

f.

!' f i  !. g e... g... ** ya.s Cw... *..

.,4

.. .b...

. . e

...s...J....

. . g . . : . ., *.. ,

..g-*. .'. ,

D e. . . . . . .. . . . . . 1.n

. 5 e..s. ...

.s . . %. . ..';.%.,.

e ...

.e . .-.., ....

aCCe ...,E .- .-*.. S;.:..

. ., e *1 4.C. .

.^

r *--Snapes .

.:... :... . w - - - - E.... A-- -- * * - + -

• nu Der C:. InSer Vere eval.ua:td 00 de:er:#ne s.... ..a.s..:..

g: . ..CVLgeg

.. y. a. . . . . . . . . . . . . .

(2) ?.e sidual Stre ss Me asure ent s

+ .ne a::ual residual s::ess was ceasure: n spe: a.

te st . .. clocks using X-ray. di.,::a:: ion an,. strain gage

et. .:9ues te ce:er=ine Pest .,ane::: exransion tu:e stresses in t.ne :: ansi :.:n area a: :ne bc::o= c:. :ne expansien anc at a se:ene pc :: nea: :ne c1,.d.te. c:.

>. .... y v... .. :.C .a .h..... . : . . 1..a. n. .. ,r.

, e x . s. y n , .; C . . . . . ~. ~4 ,. a. . . .

gg..nfe.

,s 2 ... Des y .e ex.: :.,J. .. . .. ..

.. .. . .e . 2. . g s... :.s6 , a .#. '... .

yield s::eng:.n ca:ertaas.

.. e $ a1 e.C .b. 4.S .,. s.. ....s

. . . s..a. .b..,. s . .

.e. . s i. . : , . s. *. .es..

dua.a stress in :.ne Oute ' re su,.:;ng ::c: . ca.ne:1: ex- . .

y s. .. s:.C. .. e. 1. .; .C..

.. y .. eX.te.2 1 t,..,' C :. , .. : e . . s..e

. . . .. ..g. %...

3 T. .a. s ". '. . s .-. - >. . e , .- . . e .#. - #. ... 7.'. .' e_ . e . .' . . . .i .

(.1,) u....a

_: s , c.e

.. x...:..: . .. ...

> c... ,.,.. . =x....: . . . . . . . .

4 s ,.,, _ .. .n c,..,.1 eoc ..A..s .. . ye.e . e. ,a.e...e.e w.v- .

..n e...... . .

a ... .. . * . . . -. ,...e.cses 1.. c. *.. .o .- ,s-.e

. ..*.. .e-st .:. ,., ..a ,ss- .; ..:. ...........

w e J

+

m d g,

)'+

e- 4 f

/?  : "

. L c. .

- , '.I.

r

.r.,

/<

.Yn .4*

. , s a-

.,el, ,_( > er q<< .,

g

=

% 'y~ .y-,_ N

e. y_

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e. , 4 _. .~,

, .+ - --- s . . s ., -,m n ,_. , , q, - , ,

(-).Cerrerien esti-_: cf Transiti: s a

• e

=.

d. ,. . . .a .... . a .c.. :.. AeS.S

", e s . s v e . e p e '. - . =.. ' . c ' c. . *. . . .

. . .e ~. b.

. . =. =. '. .' e - . s c ' . '. . =..

eXpans 0:. cn :.ne :ube-00-:Obeshee: VeAcs, at: One tcDe

,e...n,

... .o

. ce.e . . . :n,. .,.. s. .. a.:...

s...,a : . . . , , . . . .

.3 pznsion. A design scal of chtni;ing :he 7:e'. cad by less

...,.e,.

. . . . . -. s ,t.s

. c,,,. .c

. e.s . ..a.:..

..s .... ...

..,, ,r.,:..

c i

l'

\

y e. 2 :. c _ , .. . D 4. .= ~. e .

_. 4. . n a.~

rne ef fects cf explosive expa .sien e- :he tubeshee:

. g g ,. ... . . y.., a

-e.e.-.nec.

>:-=..,:....... ..

-- .:- . . 3.:. .,..

.no,.es in :he :u.oesnee were reasured - bef ere and a,:e: .

he expansion and cc: pared.

9

' e s

T

~

_ 41 maa- -h '

• h__m___________m.m__m__.m._____m._---m.__u..

n a$s..

a c .. ..%. . g ~4 ' . &.:.

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t

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425 ...3;..

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4 .,..

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s... .. }.y., e O . 6x . i. .. E :. ... ' . .t S ;. w . , .J.. .wv. . s. .. S w. . . 1 -De a

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• m- #g 8%...S*e.

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y. s.... , ... .. . . . . ... ..., ..u..,.,

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y..., 2 =. '. . ... .,2 ..

s .. 2

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g n.. s . . e . .. n.L. . o. c. ...g ... g y.r'---- . . . ; , 2 c. .

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6 ..s

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.,.e .., .

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• refer.ted belCV O f b C th *ht eXp5T.fici. ler.ith in-

• .*2 5 spe C*iC . p;Ojr&O and the p;Cg!2O 00 Ve-iiy *hnt e 3 *h

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• 3- .

1 l

l

1. Results of the Expansion length Inspection procram Dat-of-generator expansions indicated that the process expansion inserts and detonating materials performed as those used in the qualification program. Profilometry and dia=eter and depth gauge checks showed that the in-generator expansions were within the range of variation of the quali-fication progra= expansions. In addition, eddy current examination using the absolute (8x1) probe was conducted for the first lot of kinetically expanded , tubes in both steam generators. The 8x1 absolute probe has been chosen for this in-process monitoring in the newly expanded area because the coining process of the expansion creates so much background ci e tht: the .566" ?ttnderd diff.srentici eribe it not useful fol'.owing kinetic expansion. The 5xl absolute probe

~

-_ - _ provides 360* coverage. A judgement concerning defect are length can be made depending on how many coils of the 8xl

• • probe detect an indication. Laboratory testing has shown

~

l that a 1 coil indication can have an are length of 5' to  :

40* , a 2 coil indication has an are length up to 85* , and a 3 coil indication has an are length up to 130*. Although

, the 8xl absolute probe can be used to quantify the circum- j ferential extent of a particular indication, it cannot be used to accurately determine the percent thru-wall of the l indication. The scope of the examination included 151 tubes in OTSG S and 284 tubes in OTSG A. The eddy current data ,

was analyzed from the top of the 6" qualification length for -

kinetic expansion down through the bottom of the upper tube- l As a result of this data evaluation, 9 tubes in OTSG i sheet.

B and 6 tubes in OTSG A were reported as having indications which had not previously been detected by the .540" OD ,

high-gain standard dif ferential probe. I These new Sxl ECT indications were evaluated to determine their significance. The evaluation included 1) Fiberscope i examination of selected tube areas where ihdications were detected, 2) Comparison of the size of any visual indica-tions to the ECT sensitivity curves, and 3) Laboratory '

metallographic and ECT examination of known cracks which had been expanded. The following was concluded from this evaluation:

1. The only visual evidence seen which correlates with the ECT indications is small pits and a mechanical scratch.

2. Laboratory expansion of known cracks confirms no growth (no ductile tearing) and indicates no change in 8x1 ECT  !

signal from known cracks. l l

l l

l -

- 44 _

O

.~.

.. s .- ,. .: ..s..es,.

.. . . :.nc:..a.:..s . . . . . . 1.e . .s.--..s.....s..s

-s. .. .w which vere previ:usly belev the 5 0 E T s ensitivi::.

v :. .. u. . . .. . . y. er u. p. .e . . .u. e u s ..e e . (.. . .< , .. u. ,... : . 6. e .-

,. . ..y :s s -

s:all : hat the reliability cf :he new j:in: is no:

L .: :t . .t .a .

u u s.. ..

. . .., - ... r..s.a..e .easc.

. . . .:. . .u..a.:...

.u

. g.. . u. ... . .cx.- ._.u.,. :.s-.,...s:.:..,.. .. .... ..... .....

..a...,-. . .e . r. .,..u.,.

vi:hin the UTS. The Sx1 p::be a;;<ars :: he s: sensi-

...: y e e .....s .. . .u.. .o .es.y...> .6 .0 .:.8 r-. V:.--

• E.- 8 8, 8 1,* ,4 .u,J are c.2 no consequance.

Section IX documents extensive vor.k done to evalua:e the a x: .._ ., : e c .a. ... r. u.u_ .a u ca. y.e ,.e.

1- s e.s.:

s

.c.. - .yie ...,. .::

_ _.c.f :he plan: and'ne: cause tube failure under ner:21 or a::iden: tube loadings. A:cep:sile circu ferential ex:en:

. vs. throughvall dep:h curves fer various leading and 3

.g . . .

ana.ys s c end :.:1ons in :.ne .ree span are snevn n sigure

.ue:.  :  : -

s .:o.. . . . .:. ...- -,. a.e .e

.\,

. . . . . r-- *n>. Ct .1c.. - . .. . . n e .; ., :. n . .

a . e s a '. l e . *.*. . a .. ~'n e .- . .- .'.. s ..- e '. e .- '. . . 3 ~ . ~ *. a -

. '4 u". *. '.. s .- -; '

ce:yani:a. means in :.ne .eree s pan.

These curves are con-serva::ve :c: in.,::::: ens in :.ne j:: : since ,. pads i= pose.,

en :he tubes are trans i: ed to the :ubeshee: in the area of

, g,..c, .,

ex a .:.,. toa>.s c.. . .tu.:...:..

.v..e ..3 . . . v. . . . a .. e c .s ..

viz. ee equal :e c .ess

.c . . . . . . .

t

. nan :.n o s e an a .v. :e ., ., e: :.ne :ree- .

span. .- ec a. age in:ce;h an.

s:2. . ce:e::s wht:. are ....c. .. . ..

th:: ghwall is also expe::ed :: be less than c: e:u s '. to .

si ilar cracks in the freespan. Una: ep stle leakaze vill be identified during precritical :es:ing and :he :ute vill

y. e e :. .:ner p,.cgge, or repairec.

-sc: :u..ese ressens, it is c c . . '. u ' e '. '.'.~. s ~. s ~ a '. '. e .i ~. s c . u . .' =. ~. e .- .. s. ' .- . .- . 'c s . . ~. '. =. "3 " t '. .: -

,a. g.ea . a n , a .:. :. e . . y.. e. . e ,.. :. a . .:u ,. :. .; . . c .: .y, . . . .e.. . ...;......

.. :. sy.r,.

.. .. .eg .u..n.

. . . g ..a .: . c,.. ,. :. n.3 :. s ...s  : .. ..s , :..., , u. e .: .3 . . ,. . .:

: e .a c...a

.. . . : n s. . , y e y s. s ,. ,. :... e c.x,. e .a a.y .

....s..

. .. . . . exo. -- :..a.:...a... .e. . ..u.. e ,

expanded regien to be condue:ed foll:ving :he kinetic expan-- _j sien. .nese indica: ons vil,a be eva*.ua:e,. to ccn:::: t.es: ,

a

hey are a::eptable, and vill be lef: in service and re-ex :ined during ' he 90 day ECT p:cg:t .

. Ide-:i fica tion a-d Expansion of Mis fires E  :

I d

{

)

e r

s ..

e,

...u.,. .....'. **

a-t

~. s. .

...s..

a ..  ;.

.a. u. . c. .p

. . y.......&.1., ,

E.. cte:*****"f * .** *}* .* ..*

'

• J .y, ...%s * * * * * * *3

%.,.... . . . * . s * .. ** ..**

• • ..J f* A 1** d"p . . . .

• • • ..6 .e .**

. *- ' . * * * * . n=C. 1. C. * . . . * * = . *** .

• t....,* =.e, a~. e .= .= . ~ s~ *. . s. ..* ...

l .s. , .

. . C=.=..*.*E=..*. 6.. ..

A.. : .

.z a

p1a . . C. u  ; ... . .J a.. . t . :. ..a.. . %. . e 11' 'e'. a '. : %. . . . m. S.: ....

rr*65 ***-**6 C s7 o. . . : . , s.w

. . . . . . . ... : .he . pC.e. o . .1El .

CC See..un

.. g. ..,5 ..: . %.. . e

.....,. ..g.,

. .. Pgg66g s,....*-.1.

- - - g. 1,,

- -- - . . . g g . .g.-- .,

• A A

~

=.A c.r.... ag, .,s ., .s.. .s .

.... .'D ,. S 15 s .. '. *. . L*

2..,. .e...

... w

. %. 4,. .

p.. t :. . . ..c., . . g.

C, " E l l '..' C c* *. *. *. *.. p *. C3* . 4 #.*".* 2 d *. .#5..

. . * * ' .*.*. e* e ' . 8. .. *3 . ". C .# C.n.

.. n ;. s l e . .u.. , ..* , a ..

.. s. . e i s e x,... ., . e . ' ... %. ,. - ...... s .. : :: . .: e.. . w. m. L. e .

1.. C P, *.. *.e# *.. .".#"..'.. '.*... 3. p* *. *. * *.1

. *w ** C E L . **a**."*~g'.

• . . .C.*... 1 a* *. .' ,V , 1 6c*. W.. *tS.

.AL - *. I. *. S '. . .* *. *. t *. C '. . *. . #. #. #. *.. * *. #..* G e 'L 8. 7. F * '. . . ~. 7.

g.  : ' * - b ,e $ *.,.*.. .e s* *. *.s....

..e... *.. ..*.. .% . . . e- c c.A .. . . . L. a. *. p g *.

aJ..w*J:.lO ..

}US L.,c. ... . ..,

..g .

. . . .. t.%.

=

.. .. . '.a

.; - b.: .} %. p ..v. v... . . : ; , & e k %. s.. .s .... w. .3 '1.

. e$ . .:...

. . . . . ' . .. s . . ,y . '. q c'*. 86*

s

e. <e.

s 4

.-__-----------w---s.--- __-x - - --2,-- ., - - - - - - - - - -.m a.--,

t t

.  : . .. v. -

. ea s. .- .. .. .: . . .. ....-

'.eak length and a ucrs: case C.0C1" radia*. annulus, the '.eak

. 3. C b e .- *. s . . "w . .*. ef --. -. . -...

. . .e .as p . . .,. ex. f. :C...y.., L. *

.: *:_: ~.%. . :. S .. .. ... .. .. ..., I g ...,.

..... .c .o n e Ae u... : a . ...1 .c m, . :g.....e . .. ... .. .. ..

s #. . e .s *. .-...c .0e.*.'. ~. C k. '. C . . . s e . ". *s *. *. '. *. '.*..*.*'.S*. . . .'; s . . . " . . " .

I

. g 'r.. ...y y.... 7 . .c . . L. t . - t sv-s=*s---=

r-

=

-= ss ~~ E -~I- s's ---

.y.. . . v.. s u es os s .....C e

. ..x S

. r *- c. l . s..:.. '. ^5 *..e.A r... ...s.,. ......

a L. ,. 1. .

. .a . t .; ...;

..y...:C.

1 e .s .. o.nf yCL.*d . D,. .*.33,.5 y.... .J.

• • . , a. a. e . . .

4

. stao:1.:ec. .

i Of the app cxi=stely 7000 tubes

• eniv. about 101 were to be ele sr.ed.

.e..: r p e. c.' .- p1ue~.6 ... *.ube ceL'.' .. o . '- . '.'=...-: . . .....' ... ' . * . . . -

• - - -  :-g y 3... -...s

. . . . . :.s .ne

.. ...y,.

.. .... ,,,:cr.. a . > 1 c .-y.,. .a... :. cou,.g u..~

c: be dync=ica11v, uns:able in cross fiev areas and cause 4 _

ves: da= age to adjacent tubes. i.ppr:xi=stely ha'.f cf the

1:. ,.a, .. .u.

.. a .....y ,. s y : t .- .u.e s..u. .. ... .. : . u. s .. -..;. . ..e.,... v . . . . ..

...33 r . .

da=sge. ~he re=ainder are in areas Of =ini=ci :::sS fic ,

sw.. .,. c .. .,.. .w.

. : . s . .b :.11.y

. s d yn ... . . . .. . . .. ...t....

7.. ...

- s

., a . e ,. . ..: v ,. . .;

n... ... . u. e .e u. ,. ,. .. ..... ....,~

.r..... .,:.. Ic ;. . .. :.s. . . . . .he neig5..b ...3 .:.. .,.-,, ..... ,

s . . . . . .

.. . . . , . ,n..

. ..o.c.....a.: . . . . . . . . . 7.......

i t

r T

-. t. $.. ;. ~, .. .,. : . . ,. .e ...  : ns.

.e .:.. -

.8.e,- .; -. -* . ..* 4-*. : e . . **. -, ,

m. &. ....: . . . .,. ..**6 yla1 w, F

. .f

.. m -*-

..,.e 4..* As.

.. 2 .o n,. ;: C :.. .s. Os... r',.$:. - - - - - -- --*

...e e. 7 . L. . T. .: . y..O. s.. r

• A g p s :. ,-6 kb.k -- s A g .CS. * -* *bry

..e. . . L. t. ,. s L...

. . . ,. . f 1..g . . . s , . .. . . L. &.i . .6 *; .--

4 expansiens leak :es:.

u,e.,,. -u:..E; a .

.. S. .c -L r S:'E g.:p tCS. '-

• g..,. -- ---c*- -- .,-.$s t**t - -*k. -

e}.p

. ..J

.S. ..

.. 1....

e r. .e!.

.. =..,

. . 0 4. G .,.s.:,g g

no : 0.a,.w testing vil3. inc.uce transien:s :.a: v :1 p.a:e

.- = . g .

. . .- 3.,:

cpera:ing Icads'en :.ne new join:.  :. ..ese ::ansien:s e incluCe F

'7- .

_O ,

{

t g y9 -p-%... ,- , *. g.-,- - - -g,e . . , _ . , r-v.. , , , - . -

l l

a. normal cooldown

b. accelerated cooldown l

c. 1400 psid operational leak test.

I Leakage will be monitored before and after the transients.

l i

A = ore detailed explanation of the testing programs can be found in Appendix A.

l In the event unacceptable leakage is identified for par-ticular tubes, they will be repaired, if ~ possible , or removed from service. The backup repair method which has been selected is to place a hard mechanical roll expansion above the kinetic expansion joint 6" qualification length. ,

~

The roll expansion will ce cen:ere'c some discance acove ene

___ top of the 6" q'dalification length of the kinetic expan-sion. This distance has been preliminary selected as 1". i

- '

• Although the roll expansion' will extrude some metal, it is considered intuitively obvious that it will not affect the  !

I ability of the qualification length to carry normal and accident loads. In fact, the roll may actually increase  !

j pullout load capability.

The leak sealing ability of the roll expansion'will not be {

tested. Roll expansion will be used only in tubes needing additional sealing as determined by visible N2 bubbles.

There will be subsequent leak testing prior to HFT, which 8 vill demonstrate the effectiveness of the expansion as a l

seal. Additionally, early expansion t'esting using hard roll i expansions demonstrated that such expansions sealed leaking tubes.  !

If any expanded, then rolled, tube continues to leak exces- ,

sively af ter given the chance to "self seal", plugging vill j be necessary. l l

~' - F. Conclusions Based on a qualification program, the kinetic joint meets or exceeds the design bases of the original joint, including the following factors:

G e

~

I

- l

a. 1,oad-carrying capability.

b. Tube preload,

c. Minimization of residual stresse s.

Leakage is projected to be less than one-one hundredth of the technical specification li=it of 1 gpm.- Kinetic expansion in the upper tubesheet is a safe and reliable method of repair for -

all tube s that will remain in service in the D'.I-1 steam genera-tors. The tube joints vill remain structurally sound and essen-tially leak-tight during all design conditions over at least a five year period.

Ow se 9 4 e

f

• m

+

e e

49 -

I

-. q# + e p g y g

l i

l l

VI. EFFECTS OF EXPANSION REPAIR ,

The possible effects of the kinetic expansion process with respect to introduction of chemical i= purities, the effect on the OISG structure, the effect on tubesheet corrosion characteristics and the effect on existing plugs have been evaluated.

A. possible Introduction of Che=ical I= urities The specification for OISG tube repair addresses the issue of impurities in the system. It specifies that the inside of the steam generator will not be exposed to materials containing more than 250 pp= sulfur and 250 ppm total chlorides and f1'uorides ,

L :72:ifi2d 12:2:::512 ::::n:: c f 1:" :si tin;  :#-: 22::1:.

Required deviations,will be addressed on a case basis. A

- - - material control program with quality controls was required for confir=ation that material is not introduced inside the steam generator without assurance th.at its constituents are known and

~ l acceptable was implemented. l l ' The large majority of the debris was demonstrated (testing in mockups and a full-scale OTSG) to be particulate matter. The large particulate debris was removed by manually picking up

pieces by hand, and by vacuuming in both the ' lower and upper heads. Particulate debris in the tubes was removed by forcing l felt plugs through each tube.

In addition to the easily removed particulate debris, laboratory tests showed a thin layer of material was deposited on the ec- l posed OTSG surfaces. This film consists primarily of carbon, ,

identified as polypropylene. The amounts of contaminants , sul- .

far and other elements, in this layer are low (traces only). In order to minimize the potential for the film interfering with a subsequent sulfur treatment, steps were taken to minimize film i thickness. The CTSG surfaces were coated prior to expansion with a substance which, when flushed with water,. reduced the film thickness significantly.

This residual film is not uniform over the length of the tubes,  !

being thickest nearest the expansion. The results of tests show a remaining layer, after flushing, which averages 50 Angstroms '

thick over the length of the tube. A similar condition should ,

exist at the top of the tubesheet surfaces and the inner sur-  !

faces in the dome of the upper head. -

. As a worst case, it may be assumed that the 50 A film on the [

31,000 tubes melts as the reactor coolant approaches operating  ;

temperature. The polypropylene is not: soluble in hot water,- but .

ir i b '

e -

p-r , -

y e- --m- ,--n - ,r.-  % 2 a,-.m +

mr -- +-r- 'ee--*+--- - - --w++-we+ -,~vm+ w-+

the high velocity coolant through the tubes could entrain par- l ticles as they sof ten and lose fil= tension on the tube sur- f face. The turbulant reactor coolant flow would carry these minute dreplets of =olten plastic throughout the reactor coolant.

system as a very dilute e=ulsion of about 0.44 ppm polypro-pylene. The de=ineralicers and filters in the letdown syste=

would gradually recove this slight impurity from the reactor coolant. Industry experience shows that there =ay be a tendency for the molten droplets to collect in relatively stagnant areas of the reactor coolant system. The reactor head would be the ,

cost likely area of concentration, and during cooldown the poly ,

propylene =ay solidify as a film on the under side of the dome. j In the unlikely event that the total volume of plastic were to sapsrs a : : in :aa cac; cr;;, :n- - L.. 2a : :.: r-u icu.. ...-

lect a negligible amount of residue.

i Should there be a reactor cool'down, any molten droplets re-  ;

maining in the coolant would tend to solidify as a film on the l coolest surface available. Both the letdown and decay heat I syste=s will be cooling portions of the reactor coolant and the l polypropylene would redeposit as a thin film on the letdown andl decay heat cooler tubes. The hot surfaces in the core are the j least likely places for the plastic' to solidify. 'There is no i reasonable assu=ption which would indicate the half cup vol,u=e ;

of plastic film could cause a problem before it is re=oved from!

the syste=. ,

B. Possible Ef fects on OTSC Structure .

It has been postulated that the kinetic expansion may, because of the large nucber of tubes involved, have significant effects on the stea: generator as a structure as well as on the indi-vidual tubes.

For individual expansion, evaluation of the tubesheet ligaments has shown no significant ef fects of expansion. .It was pcstu-lated that with cultiple kinetic expansions there could be a shock wave reinforcement such that the sequence of explosions or the length of the prima cord should be controlled to insure that the tubesheet is not overstressed. The concern was that the shock wave may travel at about the speed of sound through the caterial, and if adjacent tubes exploded in a manner such that their shock wave reinforces shock waves from other tubes, there could be a condition where the tubesheet is overstressed.

Testing was performed in the steam generator at Mt. Vernon using strain gages and an accelerometer to demonstrate that the coin-cident explosions of the maximum number of tubes to be expanded

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Eased on the test results, tubesheet inspection and trevice flushing, extensive corrosion of the tubesheet by resi-cual sulfur deposits or reactor coolant is considered highly unlikely .

D. Ef fects cf Ex:ansiens on Existing plugs The TM1-1 OTSG tubes have been taken out of service by four different procedures: '

1. Explosively welded plugs - Plugs inserted into the tube and explosively welded in position within the tubesheet.

_. ne: cec plugs .:luga .e..=- c. - :. 4 tu.e ancs .: : _; -;.a u; a:

the top of the upper tubesheet.

3. Hydraulically expanded tubes sealed with a welded plug -

tubes that have been ic=obilized by expansion af ter a short section of the. tube within the tubesheet was removed. The tubes were then taken out of service by installing welded plugs in the tubesheet openings.

d 4. Mechanically rolled plugs.  :

B&W has evaluated the effect the forces of the kinetic expan-sions may have on the integrity of the first three of these plugs and expansions and has concluded the kinetic expansions will not affect their mechanical integrity or leak tightness.

Tests of the kinetic expansion process in steam generator model test blocks with conditions simulating those in the TMI-1 steam generators show that the kinetic expansion does not produce any permanent tubesheet ligament defornation. This leads to the conclusion that plugged tubes adjacent to kinetic expansions will not be altered by changes in the tubesheet ligament, since

~. no percanent change is noted. .

During additional tests on an actual GTSG, B&W examined, by dye penetrant tests, the tube-to-tubesheet welds and tubesheet ligaments of the kinetically expanded tubes and the tube-to-tubesheet welds adjacent to expanded tubes and have not seen any de gradation.

Thirdly, the extensive laboratory and field experience of B&W with explosive plugging tubes in operating steam generators

- indicates that damage to plugged tubes due to detonation of explosives in adjacent tubes does not occur.

b O

_- g , . , . . . - ,

Tests were performed on qualification blocks with rolled plugs in place and explosive expansions of all adjacent tube loca-tions. Leak rate and axial load tests were done to verify that the rolled plugs continued to meet the acceptance criteria to which they were originally qualified for use.

Lastly, a pre-operational post-kinetic expansion pressure test of each generator will be made to verify the integrity of the primary to secondary pressure boundary, thus providing added assurance that the plugged tubes have not degraded.

E. Conclusions

.:.;.;, .'. a:. .u : i : =7 = . - -

3aseo on ne euc.e ava. ae:.;r. a.

process will hr.ve no adverse ef fect on the OTSG In structure, addition,tube-a sheet corrosion, or plugs previously installed.

• cleaning process has been developed which will remove the resi-due from the expansion process. In conclusion, overall there are no adverse effects from the kinetic expansion process.

4

TlII. PLUGGING REPAIR DESCRIPTION SIEMARY A. Introduction 4

Those tubes which have defects below the 16" from the primary surface of the upper tubesheet (US) and cannot be recovered and returned to service by the above described Kinetic Expansion repair shall be removed from service by plugging. A defect is defined as any eddy current indication interpreted as greater than or equal to 40% through wall. For conservatism, any less than 40% I.D. indication with a large enough circumferential extent to be detected on three or more of the eight coils of the absolute probe will be treated as a defect for plugging pur-The limits of edd" current detectabilit r are defined in 1

rests.

i Section IX. There are a total of 259 tubes in A anc do tuces in a OTSG that have been plugged with either Westinghouse rolled plugs or E&W welded and explosive plugs. It' is projected that  !

an additional 627 tubes in A and 185 tubes in B OTSG will be removed from service by plugging after kinetic expansion. 19 tubes in A and 10 tubes in B steam generator which have been cut and removed for metallurgical examination were plugged with a B&W welded tapered cap on the top and an explosive plug at the 3 bottom tubesheet. Defective tubes in some locations will be stabilized as indicated in Table VII-1. 475 tubes will be s tabilized. The purpose of tube stabilization is to minimize the risk due to propagation of tube defects located in regions

- with high potential for flow induced vibration resulting in circumferential tube severence and causing damage to adjacent tubes or creating loose parts. The lower tube end will be plugged with an explosive plug. The following sections give an evaluation of the methods selected for tube plugging and stabilization, and a description of the types of plugs to be used.

A B. TVpes of Plugs

1. B&W Welded Tapered Plug, Welded Cap,' Stabilizer and B&W 2 j

Explosive Plug i

B&W Welded Tapered Plug is used to plug the bare upper tube-sheet hole for tubes where the tube end has been removed.

B&W's welded cap is used to seal the upper tube end for those tubes which will be plugged and stabilized. Prior to-installing the weld cap, the existing tube end will be machined off leaving a portion of the tube end and the existing weld protruding above the tubesheet surface. The weld of the nail cap will fuse with the existing seal weld,

~

providing the desired pressure, bou,ndary.

i

)

l t

t VII-1 0071.1NE OF DASIC TUSC PLUGGING /STABILIIING PLAM Dt able Pluggable Defect Pluggable Indication

>,401 TW 4 40 Percent Tw and 8 x 1 >2 Coils,ID

[ a E

m a a = n

.: r--

15th SP to LS - 4 15th SP to LS-4 US + f to ny Tube Spar 15th SP to LS-4 15th SP 15th SP to LS-4 in Lane / Wedge to in Lanc/ttc. Ige 8xl i 2 colls 48 and to =24

.:ot Isolated

.y Dottos 6*

US + 4 San > 2 colls Illstorical Defect Area (Note 4) LS -4 Nistorical (Notes 2 and 4) - ..! kinetic Defect Area (Note II spansion i 1 1 1 I . I Flug and Stabtlize to Plug Only . lug Only Fly and Stabittee PlugA Stabilise Plug and Stabilize to Bottom of 14 $P to Sottom of

• at least in Spari notto:n of leth SP (Kote 3) (Note 3) 14th SP of Defect

. 1. includes tube secttons f rom l>ottom of 15th support plate to 4-inches up into Lot tom of upgcr tutiesheet.

2. Include: tube section from bottom of 15th support plate to f inches down fron ene

• op of tiie lower tubesheet.

3. . See rigure Vil 2- for tubes in I.ane/ Wedge area.

4. Sal is ECT probe with 8 absolute coils e

' e

4y i

Imma E.

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o j u

Ob OO (o

c '

O f)

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3

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~

B&W Explosive Plug is used to plug LTS tube ends where B&W plugs are used in UTS. Both B&W plug types MK-1 and MK-3 have been qualified for OTSG tube plugging and used in the operating E&W units.

35W standard design stabilizer rods will be threaded onto the welded cap to form a stabilizer assembly of the desired length. . The stabilizer is a multi-piece assembly of solid red made of Inconel SB-166. Joint tightness. is maintained by crimping the pieces together beyond the threaded sec-tions. The segment length is dependent upon the tube bundle location.

' . ' ' :111:d : 7:r2d pl :;: . nliad :: . r:pl::3.ce < :, tri stablizer rods have been previously qualified see References

- -30 through 35.

2. Festinghouse Rolled Plugs ,

Westinghouse plugs were designed for a primary pressure of 2500 psi and 650*F and a secondary pressure of 1050 psi and 600'F. Cracks in the roll transition or the area of the seal weld do not exclude the use of Westinghouse rolled plug.

The Westinghouse rolled plug is machined from bar stock that has received a thermal heat treatment which has been demon-strated by laboratory testing to have improved resistance to intergranular attack in caustic and polytheonic acid envi-renments, compared to treatments at different temperatures and times.

The Westinghouse Roll Plug Qualification Program for TMI-l has been completed for a 5 year life, and results are docu-nented in Westinghouse Report WCAP-10084.

C. Plugging and Stabilization Criteria Final tube plugging and stabilization criteria were selected to minimize the possibility of cracks propagating to a size which could part under stress conditions, either plugged or unplugged tubes. Analyses presented in Section IX show that the vibra-tional effects of cross flow are not expected to contribute to crack growth in an unplugged tube. However , as a precautionary measure, plugged tubes with defects in the area of highest cross flow between the 15th support plate and US+4, are stabilized.

In addition, stabilizers have been used where eddy current in-dicates a crack of significant size in historical defect areas, and below the 15th support plate where.I.D. $x1 indications are greater than 2 coils. Measures to monitor for crack propagation due to flow-induced vibration or other means, including leakage I

i +

l l

l __ _~ _ _ _ _._ . _

monitoring (Section X) and eddy current inspection for wear

( Appendix A) are discussed separately.

I The steam generator has been divided into six areas for purposes TVo of dispositioning tubes for plugging and stabilization.' ,

areas are within the upper tube sheet: between US+8 and US+4, and between US+4 and US+0, where US+0 is the lower face of the i upper tubesheet. Tubes where the lowest defect is above US+8 l' are repaired by kinetic expansion. Tubing between the tube-sheets has been divided into three areas: tubes between the 15th support plate and US+4, tubes between the 15th support  !

plate and LS-4 in the lane / wedge area, and tubes between 'the 15th support plate and LS-4 outside the lane / wedge area. The

.; . .a : ai hin . .; 1 2r ::: :: c.2 2 : .

la;; r2;ien :::s ::::u Plugging and stabilization criteria are discussed in detail in Reference 25 and sum =arized below: ,

I

1. Tubes with Defects Between. US+4 and US+8" i t

Tubes with a defect between US+5 and US+8 may not be effec-tively repaired by the 22" Kinetic Expansion. A qualified i length of 6" expansion is required to insure a leak-tight, load-carrying joint to assure the OTSG integrity is retained ,

under the most adverse conditions during ' operation. There-  ;

fore, those tubes with defects between US+4" and +8" will be  !

i both kinetically expanded to 22" and plugged. Even if the existing crack would propagate in the future and sever at  ;

US+5", testing (Ref. 23) indicates that the expansion joint ',

below the severance would provide enough engagement to main- l tain the preload in the tube and carry the loads associated with the most severe transient during normal operation.

Thus tubes with defects in this area are not expected to wear adjacent tubes due to dynamic instability in high l crossflow. Therefore, it was concluded that these tubes j need not be stabilized (unless stabilization is required by  :

I defects of greater than 3 coils between US'+4" and US+5").

2. Tubes with Defects Between US+4 and US+0 i Even with a 22" expansion, these tubes would not have the 3" kinetic expansion joint below the defect to maintain preload i and assure that the tube will not slip under the most severe ,'

transient during normal operation (i.e . , 100*F/hr. cool-down). If the tube ratcheted down to the point where it was j

in compression during operation, the potential exists for i the tube becoming dynamically unstable or buckle. There- i fore , af ter receiving a 22" expansion, a tube with a defect in this area will be plugged and stabilized through the 14th {'

tube support plate.

9 O

I.

3. Tubes with Defects Between 15th Support Place to US+0  !

indication in this area, For conservatism, any eddy current or circumferen-regardless of type, through-wall measurementTubes with defects in tial extent, was treated as a defect.

this area received a 17" expansion snd were stabilized to the 14th tube support plate, unless a lower defect was located in an area requiring a longer stabilizer.

This criterion covers the high cross ' flow tube span in the Even if a tube were postulated top of the steam generator.

to become severed at this elevation, it could not get free and damage adjacent tubes.

4 Tubes with Defects from 15th Support Plate to LS-4 in Lane

~ ~

Wedge Area B&W plants have a history,of corresion and vibration prob-lems in the areas of the untubed inspection lane. As a precautionary measure, an area of potential problems has been defined one row on either side of the lane, widening to a wedge shape as the lane nears the periphery. For tubes indication,.regardless of in this area, any I.D. eddy current or circumferential extent, type, through-wall measurement,These tubes will receive a 17" will be treated as a defect.

expansion, then be plugged and stabilized through the 14th support plate unless other criteria require stabilization through the defect in the lower spans.

5. Tubes with Defects Between the 15th Support Place and LS-4 In the tube span between the 15th support plate and LS-4 outside the lane / wedge area defects were divided into two groups: 1) ECT indications greater than or equal to 40%

through wall with 8xl indication greater than 2 coils, and

2) ECT indications greater than or equal ~to 40% through wall with 8xl indicttion less than or equal to 2 coils.

After a 17" expansion, tubes with defects greater than or equal to 40 through wall and 8xl greater than 2 coils were stabilized through the span with the lowest defect for that tube. Tubes with greater than 40% through wall defects and Ex1 indications on 2 coils or fewer were expanded to 17" or 22" as appropriate and plugged with the Westinghouse rolled l

plug.

f

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

This criterion provides a means for determining the tube are length extent of a defect in order to decide if the' tube should be stabilized. The tube would be stabilized at least within the tube span containing the ECT indication if there i is any substantial size or are length involved in the ECT indication. If an ECT indication is seen on less than three coils on the 8x1 ECT probe it means that the arc length of ,

the degraded area of the tube of a maximum of about 0.41 inch long at the inside diameter of the tube. Because of 1 the " thumbnail" shape of the inside diameter cracks found at ,

TMI-l this means that the average are length of the largest !

l i two-coil ECT crack would be about 0.26 inch. This size  !

crack is accentable without stabilizint and is not excected to propagate to failure 'y omecnanical means during opera-tion (Ref. 25).

. This criteria for stabilizing, based on arc length as .

measured by the 8xl probe is not invoked for ECT indications i less than 40 percent through wall because such an indication is too small to fail the tube. Even if a tube had a 360* i indication, the tube would not fail with less than 40 percent penetration (Ref. 25). _

6. Tubes with Defects in the Lower Tubesheet Below LS-4 l Tubes with pluggable defects in the lower 20" of the LTS were removed from service using a Westinghouse rolled plug or an explosive plug. A welded plug was used in lieu of l mechanical rolled plugs if the defect was in the rolled area.~

1 D. Post Repair Testing The following post repair tests will be performed to verify plug 'l integrity.

1. 150 psig bubble test

2. 150 psig drip test

3. 1400 psid operational leak test l Details on post repair testing can be found in Appendix A.

i i

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1 l

E. Conclusions The OTSG Tube Plugging Pia, will restore the pressure boundary  ;

integrity of the steam ghirrators by removing defective tubes l from service for those tribes which have defects below the region available for expansion repair.

The plugs used have been previously qualified for use. Tubes i have been stabilized which have large defects in areas of high crossflow or areas of historic problems with vibration or cor-rosion at B&W plants. Thus plugged tubes with the highest potential for tube serverence in the future are prevented from j wearing adjacent tubes.

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Vill. COMP ARISON OF TUBE PLUGGING WITH DESIGN BASIS A. Introduction This section describes the results of analyses performed to determine if che steam generators could be safely operated with up to 1500 tubes plugged. The first part of this section re-views the operational consideration of operating with tubes removed from service for: reduction in total flow and margin to

• departure from nucleate boiling effects of asymetric flow dis-tribution, ef fects on flow coastdown rate, ef fects on steam generator mass inventory and capability of natural circulation.

The se.cond part reviews the ef fects of removing tubes from ser-vice on smatl anc serge aresa masa 02 cec 4:: a;;_cer..a a 41. ,

.as all other ac'cidents and transients analyzed in the FSAR. The third part considers the effects of plugging on moisture carry-

• over. These analyses have concluded that the margins of safety as defined in the Technical Specification will not be reduced by operating the TMI-l steam generators with up to 1500 tubes re-moved from service.

B. Operational Performance _

1. RC Flow Rate and Margin to Minimum DNBR i

The calculated RC flow rate for all four RC pumps operating as a function of an equal number of tubes plugged in each steam generator is shown in Figure VIII-1. Generally, a reduction in tubes available for RC flow will cause the tube bundle pressure drop to increase. Since the remaining sys-tem pressure losses- are about four times greater than the tube bundle pressure losses, only a slight reduction in total RC flow rate will result. The total RC core flow for 1500 plugged tubes will be the same as the symmetric case,-

i.e. 750 in each steam generator. From the figure, the reduction in total RC flow will be from .109% of design to 108. 2% , a change o f 0. 8% . (Reference 42)

In order to determine the impact on the existing steady state Departure from Nucleate Boiling Ratio (DNBR) resulting from the RCS flow reduction at steady state, a study was performed to determine the minimum RCS flow rate required to maintain the existing DNB ratio for the THI-1 licensed power level of 2535 HWt. The existing DNB steady state ratio of j' 2.0123 was determined at a conservative power level of 2568

~ MWt and an RCS flow rate of 106.5% of design flow.

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The methodology for the analysis was to calculate the hot' bundle flow by using a CHATA (Reference 36) core model which took heat balance input from the CIPP code (Reference' 37).

By using the hot bundle flow in the computer code TEMP (Reference 38), the Minimum DNBR (MDNBR) was calculated for the hot' sub cl.annel from the BAW-2 correlation (a cor-relation.

The results indicate that DNBR value of 2.0123 can be main-tained with an RCS flow rate of 104% of design and a power of 2535 MWt as compared with the original 106.5% flow and 2568 MWT. The minimum calculated RCS flow rate at TMI-1 has been 109.5% of design flow. Tne maximum error#' on this value T' i : r,:ul:2 .'- #a - - # **?"

. ; 1. ? *: . . : .i r:m :

of design. Th,is will be reduced to 107.2% after the tubes

- - - are plugged. This is substantially greater than the design basis flow rate of 106 5% which would be required to main-

• tain the design basis steady state DNBR value of 2.0123 at 2568 MWt. For the TMI-l power level of 2535 MWT, the 104%

design flow requirement to maintain the same DNBR provides for an even greater margin. It can thus be very conser-vatively cencluded that the plant design basis flow rate considerations will be preserved with 1500 tubes plugged.

2. Asymmetric RC Loon Flow Distribution The final plugging pattern will be about 6% of the tubes in the A Steam Generator and about 2% of the tubes in the B Steam Generator. In order to investigate the asymmetric ef fect of the RC loop flowrates, an evaluation of an exag-gerated plugging pattern of 1500 tubes in one of the TMI-l steam generators has been performed. The Loop A flowrate will be approximately 2-1/2% smaller than Loop B.

Field data at TMI-l during the last cycle has shown that the A loop has typically about 3% more flow than the B loop.

The result of more plugging in the A Steam Generator will thus be a somewhat more balanced loop flow distribution.

The new flow difference is expected to be approximately 0.5%.

3. RC Flow Coastdown Rate With a significant number of tubes being plugged, the resis-tance factor for the RC flow passing through the OTSG will ,

be increased. This increased resistance may change the flow distribution if one RC pump is tripped while the other pump in the coolant loop is maintained in operation. The com-bined core flow during the coastdown may also be different.

- 63.-

O 4

(

l Further, the minimum margin to DNBR during a less of flow eve nt is known to be dependent on pump coastdown rates. To address these issues the following analysis was done.

A cocputer analysis has been conducted using the B&W code "PUMF" (Reference 39) for the TMI-l type reactor coolant.

system's flow coastdown curves with zero and 1500 tubes plugged in the A Steam Generator. . The FSAR analyses served as the base case for the four pump -coastdown transient.

Results of the analyses with 1500 cubes plugged in one steam generator show that the FSAR coastdown rate is still bounding.

Figure VIII-2 su== arises the data obtained fron the four pump coastd'own transient performed with the TMI-l version of PUMP code and compares.this data with the FSAR analyzed flow coastdown. This comparison shows that the flow even with 1500 plugged tubes starts at a higher level than the flow assumed in the FSAR analysis and coasts down at approxi-

=ately the same rate since the flow is at all times greater than that assumed in the FSAR the minimum margin to DNB will not be changed. .

4. Steam Generator Water Inventory and Operating Level- 4 Indication The water inventory in the steam generator, will increase by a small amount due to the decrease in average quality in the plugged section. REIRAN-02 (Reference 43) and TRANSG (Reference 44), which are both one dimensional transient ther=al hydraulic computer programs with slip option, have been used. The inventory increase was calculated to be 5%

or less, which is less than 2000 pounds with 1500 cubes plugged.

- Total secondary side flow will increase only slightly with decreased steam outlet temperature. This would tend to cause a slight increase in pre ssure drop. This increase will be of fset by the reduction in average quality (increase in density). The net ef fect should be little or no increase in the startup level.

5. capability of Natural Circulation The impact of steam generator tube plugging on the capability of stable transition to natural circulation was examined by using the B&W compu,ter program AUX (Reference 49). Symmetric plugging of 1500 tubes in each side-was

x e

assumed to be the bounding case. Figures VIII-3 and VIII-4 ccmpare the analysis results of 1500 cubes plugged to no tubes plugged. At about 500 seconds af ter the/ reactor coolant pumps trip, the stable natural circulation flow with 1500 tubes plugged is about 8% less than that.with no tubes plugged. At no time is natural circula' tion lost,and the reactor coolant system remains subcooled. Ihe subcooling ~

margin for 1500 cubes plugged is only about,2*F'Iess than the case without plugging (about 90'F). Therefore these analyses have shown that natural circulation is still an ef fective method for decay heat removal. - 1 l

i C. A : idea.t sed Transient Serformance

_l . LOCA Analys&s

• The potential ef fects of SG tube plugging on ' generic Large Break LOCA (LBLOCA) and Small Break /LOCA (SBLOCA) analyses (Reference 40) with 1500 cubes plug'ged has been'eKamined.

With about 6% of the tubes in the A St.eam Generator-and about 2% tubes in the B Steam Generator _being plugged, the generic (2772 MWt) LOCA analyses for -B&W 177FA Lowcred Loop Plants remain valid for IMI-1, with continded operation at core power levels up to the licensed 2535 MWt at the existing LDCA limits. An overview of 'this examination is provided below.

a. SBLOCA Concerns The evaluation models used in the existing S510CA analyse's (Reference 40) assume equilibrium c'onditions within the control volumes used to model the SG secon-dary side. For this reason, the localized cooling .ef-fects of EFW spray on particular tubes,- and the ef fects on this cooling if particular tubes are deactivated, cannot be accurately predicted with enese models.

In the application of the revised SELOCA evaluation model (Reference 41), it was a'sseded that:

1. The percentage reduction in the number of peripheral

! tubes removed from service will degrade the EfW spray cooling heat removal capability in a 1:1' relationship.

l

2. The degradation in heat removal capability,from EFW spray cooling translates directly to a reduction in-

' depressurization ra'te by a l~:1 r'elationship.

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In reality, these relationships are expected to be con-servative. Since if EFW spray impacts a deactivated tube, it will not be heated and/or flashed immediately but will either:

1. Be redirected onto adjacent active tubes, or;

2. Flow inward into the tube bundle, providing cooling

' to active interior tubes, or;

3. Fall into the saturated steam or saturated water region, resulting in increased cooling within these regions and/or an increase in the fill rate to the appropriate level setpoint.

A more detailed discussion of EFW spray effectiveness and the THI-l response to SBLOCA with plugged tubes is

• given in Ref. 59.

Therefore the water is available in the steam generator and will result in greater EFW spray cooling and higher )

depressurization rate than predicted by the analyses.

In this evaluation (Reference 42), two break cases were considered. The first is the worst case with respect to peak clad temperature for a small break LOCA, identified as approximately a 0.07 ft2 cold leg break. The second, belongs to the category of breaks in which SG heat removal is needed to help depressurize the .RCS.

The 0 01 ft2 break was analysed because this was the largest break size which would result in RCS repres-surization.

Plugging 1500 SG tubes was used as a upper bound which represents a deactivation of approximately 5% of TMI-l's total tubes. Also, because substantial tube plugging will be done in the peripheral SG tubes regions, it is estimated that about 18% of TMI-l's total peripheral ,

tubes will be deactivated. i Worst Case 0.07 ft Cold leg Break with One HPI Train For this break size, the primary system pressure decreases below 1000 psi (approximately.the secondary Af ter this time ,

side pressure) at about 300 seconds.

SG heat removal is no longer possible, and the secondary side becomes'a heat source for the primary system. Core uncovery begins at about 1350 seconds -and ends at about The maximum time that SC (and EFW spray) 1750 seconds.

cooling can be of benefit during the accident is the first 300 seconds. This is very short when. compared with the time to begin core uncovery.

4

I t

The plugging of 1500 SG tubes will result in a reduction of the initial RCS liquid inventory by about 200 ft3

' This results in the core being uncovered about 3 seconds e

earlier and in approximately a 10F increase in peak cladding temperature (to about 1100*F). This will have minimal Lapr.ct on the outcome of this accident. It should also be noted that the generic analyses show

• that, for a 0.07 ft2 break with 2 HPI trains, the core

' does not uncover and temperature remains below 700*F.

0.01 ft2 Cold Leg Break Ta : . :'. f:2 ::'i 12; ir2 2; :221 n: sa a 'c: 2; t d u c #. q the revised SBLOCA mocel. All of the original analysis

' assumptions were preserved, including a 20 minute operator delay in initiating emergency feedwater. Two cases were analyzed considering the effects of tube plugging on the decrease in RCS depressurization rate which could increase the time to initiate ESFAS and the rate of heat transfer in the boiler condenser mode. It was found that:

With a 1600 psig low RCS pressure' ESFAS setpoint, the 0.01 ft2 case will result in ESFAS actuation regard-less of the reduced peripheral and internal SG heat removal caused by the plugging of 1500 SG tubes. Before ESFAS actuation, the RCS was subcooled and either forced or natural circulation existed. Consequently, SG heat removal was found to take place throughout the entire SG tube region, not predominantly in the peripheral regions. Therefore, the SG heat removal rate is not reduced by more than 5% during the period prior to ESFAS, and this will delay only slightly the activation of ESFAS.

^

The 0.01 ft2 break case will cause the RCS to enter the boiler-condenser (B-C) mode. In this mode, EFW spray cooling of the peripheral tubes is an important factor in the RCS depressurization. Thus, peripheral SG tube plugging could have a more significant effect on this cooling mode. The evaluation showed that, with 18%

of all peripheral tubes plugged, suf ficient steam

=

generator EFW spray heat removal capability remains so that the rate of RCS depressurization is reduced by only about 12%. Even with this reduction, calculations with all other original analysis assumptions unchanged show a minimum of five feet of coolant remains above the core throughout the event. Since the 0.01 ft2 break is

approximately the largest break which would result in RCS repressurization, the plugging of 1500 SG tubes is expected to have only minimal ef fect on SBLOCA e transients.

In summary, these small break size LOCA analysis show that for the previously limiting case of 0.07 ft 2 cold leg break with only one EPI train available, peak clad temperature increased by only 10*F to about 1100*F. For the 0.01 ft2 cold leg break, the slight delay in ESFAS actuation and the reduced area for EFW cooling have an insignificant' ef fect on the outcome of the transient

2 mini um :f Ji a f:-:: :f :::':-: r:::in: ::: n the core for both the plugged tube and unplugged tube

-- - - cases. Therefore the generic LOCA analyses remain valid for TMI-l even with a small reduction in SG heat removal caused by tube plugging.

b. LBLOCA The important parameters for the LBLOCA which are effected by plugging of tubes are the initial flow and flow coastdown. The ef fects of the reduction in coolant volume associated with 1500 plugged tubes (200 f t3 )

are negligible for this event. The plugging of 1500 SG tubes at IMI-1 will reduce total system flow. However, the reduced flow will still be greater than the flowrate used in the generic LBLOCA analyses. This, coupled with IMI-l's lower core power (2535 MWt vs the generic 2772 MWt) provides margin in initial conditions for TMI-1, relative to the generic analysis. During the early portion of a LBLOCA transient when the reactor coolant pumps are coasting down, the analyzed system flow rate (see VIII.B.I.3) with additional resistance due to plugging will be greater than assumed designed flow rate

~~

with the case of no plugging.

The reduction of 200 ft3 of primary coolant volume will have little impact to the consequence of LBLOCA.

Since the OTSG's are unevenly plugged with more tubes plugged in A than B. If a cold leg break occurs in the A side, the reduction of RC fluid is part of that blown out of the break, and there will be no impact to the result at all. However, a break in the B side will result in slightly less total fluid passing through the l

core during the blowdown period. For about 11,000 f t3 total fluid loss within.approximately 24 seconds, the reduction of 200 ft 3 will correspond to 0.4 second O

n, n

shorter blowdown time and thus a slightly earlier fuel heatup between blowdown and refill. This dif ference is minimal and therefore, the resulting peak cladding te=-

perature that occurs during this developed reflood stage should not be changed. Also, vent flow is conserva-tively neglected during the refill /reflooding phases .of LELOCA analyses for the 177FA Lowered Loop plants. Tube plugging will therefore have no impact on core flooding rates.

2. FSAR Analyses of Other Transients

' An assessment of the icoact of the plugged steam generator cuces on cae ao: A;;y of che .545 ca sa:aly respcac co E5Al transient ebnditions has been performed. The plant is ex-pected to be operated with up to a total of 1500 SG tubes

. plugged for both steam generators at the licensed rated power level. Each event in the TMI-l FSAR will be addressed in light of the expected impact of steam generator tube plugging on assumptions used to produce the current FSAR analysis.

a. Unco =censated Operating Reactivity Changes This event is core burnup related and is normally com- ,

pensated for by Integrated Control System action over the life of the fuel cycle. Steam generator plugging will not affect the core kinetics and thus have no

~

impact on the event.

b. Startup Accident /CRA Withdrawal at Power The CRA Withdrawal from Startup conditions and at power results in primary system overpressurization. The FSAR prediction of RC pressure and peak thermal power is based on the conservative assumption that all heat pro-duced in the core remains in the primary system, i.e.,

no steam generator heat transfer. The tube plugging will result in a 200 ft3 volume reduction of the primary coolant ( 2%). At peak thermal power the reactor coolant pressure increase was 118 psi in the FSAR. With the small volume reduction and consequently slightly higher heatup rate the peak pressure may in-crease slightly but will remain well below the 2750 psig limit. Therefore, the FSAR analyses remain bounding

. with respect to the acceptance criteria on thermal power and system pressure. .

9 R

c. Moderator Dilution Accident The moderator dilution event is a relatively slow over-l pressurization transient due to increased reactivity by boron dilution. Change in steam generator plugging will not affect the basic assumptions of this analysis and

( therefore the FSAR remains bounding.

d. Cold Water Accident (Pump Startup)

The pump startup event is a small ovtricoling transient due to an increase in flow from an idle loop. The analysis nerformed for See, tion 8.B.3 demonstrated that tae pu=p cnaracteriscic curves ca.ierance s are negii-gible fbr the unplugged and the 1500 plugged tube cases. The reactivity change will cause a power and RCS pressure increase. The transient will be terminated by either the high reactor pressure trip or the power / flow trip. The FSAR remains bounding.

e. Loss of Coolant Flow See Section VIII C.1.

f. Stuck / Dropped Rod Event The FSAR analysis is bounding since SG heat transfer and RCS flow do not ef fect this event. .

g. Loss of Electric Power The unit will trip on loss of electric power. With the loss of the reactor coolant pumps, natural circulation in the primary loop and heat removal by the emergency feedwater system are required. The impact of tube plugging on the ability of natural circulation is demon-strated in Section B.S.

h. Steam Line Failure The licensing basis for TMI-l is the double-ended rup-ture. This FSAR analysis is based on a very conserva-tive prediction of SG secondary inventory. Operation with plugged tubes results in a secondary inventory greater than operation without plugged tubes but it is l

not as great as that considered for the FSAR analysis.

Secondary inventory is one of the parameters that deter-mine the safety considerati'ons of return to criticality, 1

70 -

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4-- -, - - - - - , -+ .- - , - , , - - ,y,

and reactor building pressure. The calculated water increase with 1500 plugged tubes is less than 5%, which will result in a maximum steam generator inventory of 42,000 lb. per steam generator in contrast to the FSAR analysis assumption using a steam generator inventory of 55,000 lb per steam generator. .It is therefore con-cluded that the FSAR case remains bounding.

i. Steam Generator Tube Failure ',

The steam generator tube rupture accident is analyzed assuming a 435 gpm leak from a completely severed OTSG tabe. The RCS is decressupi ed and iselsted at 34

=inutes, at vnich time leakage from the RCS is assumeo to stop. The reduced RC flow as a result of the plugged tubes is greater than the RCS flow assumed for this a

cooldown rate (even the 100% design flow is not required to cool the RCS) . Similarly, more than enough OTSG heat transfer area is available to cool the RCS.

Of fsite dose from the Tube Rupture Event will not be affected by plugging 1500 tubes because neither the time required to isolate the OTSG nor the leak rate from the

~ broken tube is af fected by the tu'be plugging.

j. Fuel Handling Accident This accident is assumed to occur during outage a l refueling outage while the reactor is shut down. Change in steam generator plugging pattern has no impact to the assumptions.

k. Rod Ejection Accident Fast reactivity excursions are not influenced by SG heat removal. The event is an adiabatic heatup. The FSAR analysis remains bounding.

1. Maximum Hypothetical Accident The analysis assumed that a given amount of radio-activity has been released following core exposure and I studied the ef fectiveness of the building spray system and Engineering Safeguard systems leakage on to the enviro nment. The steam generators are not related to the scenario and thus have no impact on the conclusion.

O e

b - - - -

_ _ _ _____ m ___ --m -----_ - _ . - -

m. Waste Gas Tank Ruoture The Waste Gas Tank is located in the Auxiliary B6ilding i

and the analysis of its rupture is not related to the steam generator's function. The event is thus un- ,

affected.

n. Loss of Main Feedwater/Feedwater Line Break i i

A loss of feedwater accident is an event resulting in primary systec heatup, increased pressurizer level and * ,

pressure, and reactor trip either by anticipatory fune-tion (loss of tain feedwater pumps) or high RCS pres-

3. .--- t - --.':- ,731: 3 , .-.-7.-e- f.34-

- r.

water heat ren: val through the steam generators. With

-- - - - the plugging of 1500 tubes in the steam generators, the intitial heatup rate will be slightly faster. However,

• the anticipatory trip on high pressure will shut the reactor down and reduce the heat input to its decay heat level regardless of the minor dif ference in heatup rate. Emergency feedwater has.the flow capability of ~

removing decay heat up to about 7 percent power. This is greater than the decay heat at any time after shut-down. In the SBLOCA analysis using the revised LOCA model it was demonstrated that heat transfer rate is not significantly changed with the amount of plugged tubes.

Therefore the FSAR analysis of the loss of feedwater accident remains valid,

o. Steam Generater Overfill Steam generater overfill was analyzed as a part of the TMI-1 Restart Report, (Reference 50). This analysis identified that it takes at least 10 to 17 minutes for auxiliary feedwater to overfill to the top of the steam generator's shroud. Operators are instructed to isolate

"'

• the feedwater flow path as soon as the'OTSG water level reaches 82.5% on the operating range (high level alarm) and to trip or throttle feedwater pumps if the level reaches 90%.

The impact of up to 1500 plugged tubes in one steam generator will be about 5% inventory increase at about the same level indication. This has been shown in Section B.4. This implies a reduction of the over-l l

filling time by about 60 to 100 seconds. The time for the operator to respond to the high level alarm will be shortened. Moreover since there is still sufficient 1

1

,-,. -3 - -

time and uncmbiguous symptoms available for the opera-tors, their prompt response is expected and thus the overfill would be corrected. In addition, a stress analysis has been performed on the consequences of flooding the TMI Unit 1 Main Steam line. The results of 1 deadweight internal pressure and thermal expansion l l

analysis show that the main steam piping can withstand these affects. Therefore operatin,g the steam generators with 1500 plugged tubes will not present a safety con-cern with respect to steam generator overfill. j D. Moisture Carrv-over Considerations i E~ilustions vere nerformed to determine whetSer the clueging pattern would allow moisture to be carriec up with the steam, l

_ causing potential'for erosion of components or steam lines. i

' Calculations of steam conditions at the entrance to the turbine

• show approximately 33*F of superheat, indicating no moisture problems in the bulk steam. Evaluations were also done, to determine the potential for local ef fects in areas of high plugging before mixing equalizes temperature. Calculations j include multidimensional thermal hydraulic simulation of the OTSG with plugged tubes using the THEDA II Code. ,Results indi-cate that moisture carryover from the clustered plugging of tubes should not be a problem. The effects of the aspirator bleed ports and the geometric design of the 15th tube support plate (outermost holes are not broached) work together to sub- j stantially reduce moisture carryover. An ISI program will be implemented to further assure the integrity of peripheral tubes and downstream components and piping. Peripheral tubes in areas of high plugging are included in the post repair eddy current ,

program. A supplemental ISI program of steam system fittings will be implemented. Both programs are described in Appendix A.

E. Conclusions a

.- Evaluation has shown that up to 1500 plugged tubes per steam

generator have no adverse ef fects on performance of the steam generators. The reductions in flow and heat transfer are not large enough to affect the licensing basis analyses for transients or accidents. In addition, moisture carryover is not expected to cause erosion problems, but monitoring of the steam system fittings will identify erosion should it occur.

1 T

f l -

l t _ -

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l l

IX. UNREPAIRED PORTION OF TUBES Reference 2 and Sections IV through VI of this report discusses tubes in the area of the kinetic expansion, plugged tubes and how they meet the design basis. This section discusses how tubes in the remainder of the steam generator meet the design basis. The rationale for resuming operation with the existing steam generator

! tubing is based on these facts:

1. Corrosion tests indicate that the crac. king mechanism has been arrested and will not reactivate in low sulfur primary 4

j coolant water chemistry. If the cracking does. reactivate due to an unknown mechanism at operating temperatures or I, durinq heatuo and cooldown cycles, it is anticipated that i

une precr cical cescing sequence iculc allow autiiciene cime ,

for defects to propagate through wall to a size that would

_ allow leakage to be detected. l

2. Analyses have demonstrated that cracks below a minimum range of length and through wall thickness will not propagate to i failure by combinations of flow induced vibration, thermal cycles, and mechanical loading. Analyses have also cal-

culated a minimum size below which a crack will not become unstable due to plastic tearing or ligament necking during a MSLB. The range of crack sizes above this was detectable by 4

the ECT inspection program that was used to inspect the '

l

- steam generators, and were removed or plugged.

3. Any through wall defects that are large enough to propagate unstably and are not picked up during the 100% ECT inspec-tion because of equipment or analyst error will be detected by leakage monitoring programs during the test program.

A. New Damare Not Occurring

! The following paragraphs address the subject of new damage not occurring in the steam generators. _ Short term corrosion testing t program has provided evidence that the crack mechanism is ar-

rested and the long term corrosion tests will act as an antici-patory program for crack initiation. An eddy ' current flaw growth program has shown that cracks are not initiating or pro-pa gating. Defect indications which are less than 40% through wall and less than 90* in circumferential extent will .be left in service and monitored for crack propagation. ' The precritical i testing program will detect reinitiation of corrosion through

-leakage monitoring.

b w , , - - . . - . . . . . , ,, . , . _ , , , , , , , . - . _,-,-..w i.-_,_,,,...y r .,,. , , , - -. , . . , .,-,m

The corrosion testing program results are described in Section III. Tests on actual and archive Steam Generator tubing to date have established:

(a) Cracking will not occur unless an active reduced species of ,

sulfur is present and cracks in SG gubing will not propagate I in the present chemical environment ;

(b) Sulfur induced cracking requires an oxidizing potential which does not exist under normal hot operating conditions ;

(c) Lithium hydroxide is an ef fective inhibitor of the' cracking nah:ni:r.

-- - -Tubing which has undergone the repair and chemical cleaning process has also been tested. Accelerated tests performed on this tubing under severe chemical environments has not produced any cracking. To provide assurance that the mechanism has no long term time dependency, a long term corrosion test program has been initiated to provide an anticipatory assessment of tube performance under actual steam generator operating conditions.

This program will lead plant operation and will run for approxi-mately one year.

Since identification of the steam generator problem, cracks in the generators have been monitored for growth. Eddy current testing of about 100 tubes in each steam generator was conducted on a repetitive basis to attempt to ascertain if the inter-granular attack mechanism was continuing to damage the OTSG tubing during continued dry primary side lay up conditions. The sample selected for this monitoring assumed half tube sheet symmetry and included tubes with no defects, tubes with a variety of defect indications and tubes in periphery and in-tarior areas of the bundle previously identified as high and low defect rate areas, respectively. The method used involved a

~

relative comparison of the low gain .510 sta'ndard dif ferential probe eddy current responses from seven repetitive examinations of the sace tube population over a period of time extending from December 1981 through July 1982. The eddy current data was evaluated and compared with previous data for each tube to determine if reported variances from test to test were related to variability in the physical repeatability of analysis of threshold-level defects or to the appearance of fresh defects grown in the interim period between tests. In July 1982, a "new baseline" condition was established with both the .510" std.

-gain technique and the .540 high gain technique performed con-secutively (within 3 days of each other).

6 O

d The consistent pattern of the test comparisons indicated that significant growth of new intergranular cracks was not detected.

Sece variability in repeatability of recorded results was ob-served, hcwever careful review and comparison with previous data established these as expected variances due to such things as

" probe =otion" noise levels, and previous indications inad-vertently not recorded.

The comparison of the July 1982 .540" 'high gain technique data to the July 1982 510" standard gain technique data run 3 days apart showed a 94% (188 of 201 tubes) agreement with a "no-growth" result. Where 6% (13 of 201 tubes) of the tubes had

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nique, these are established as a product of the higher sensi-

~

~ 'tivity of the .540 technique. This result is consistent with other cecparisons of these two techniques. As further confir-mation, in August 1982 about 29 tubes were selected from OTSG-1B at-large, where reinspection with .540 high gain techniques had revealed defect indications in addition to those previously identified by the .510" standard gain technique. These 29 tubes were rerun with the .510 standard gain technique and in all cases, a comparison of the two .510 data sets revealed that the tube's condition was unchanged.

It is also noted that these findings are not altered by the results cf the 100% inspection of both OTSG's by the .540" high gain technique (when compared to .510" data from about 6 months earlier). No significant patterns of crack growth were apparent in this bulk comparison of data.

Within the limits of eddy current test sensitivity and repeat-ability, no new cracks were formed or developing in the OTSG tubing during the period from December 1981 to August 1982.

Tubes with ECT indications below US+8" of I.D. 20-40% through wall and verified by the 8xl probe to be actual defects are considered degraded tubes. Depending on their circumferential i extent, the tubes will be lef t in service and monitored on an l extended ISI program. The extended ISI program will include 100% reinspection of the 40% and less through wall indications as a separate subset for three continuous refueling outages. If these eddy current examinations show no substantial growth in the cracks, they will be lef t in service. Tubes showing signs of crack propagation will be taken out of service based on normal and accepted criteria. Lack of defect propagation will give additional assurance that the mechanism is arrested in the long term.

l l

l l 1 l 1 l

.- - . - - - - -_ - = . .- - . . -.- - - - - - .- . _ - .

l More rapid propagation if it occurs, will be evident during the precritical and power ascension test program described in  !

I Appendix A. This program will subject the tubes to normal heat-up and cooldown stresses and to one accelerated cooldown stress test. Between each of these tests the plant will be maintained l

in hot, pressurized condition to allow time.to determine if l

cracks have propagated to a through wall extent and to allow

sufficient time to detect any changes in leakage. The test program will be completed by a cooldown from hot conditions to l

cold shutdown temperatures as a final test of tube integrity.

Leakage monitoring will be continuous during and af ter this test.

i leakage monitoring programs are adequate to detect 100* through

. .1 ::1:12 ini ;ul i: U. iurin; L :::nsiant :: v::idt,:

l condition. Adequase time for propagation will be allowed during l

- the test program. Since previous experience indicated that the mechanism propagates rapidly, a lack of any significant leakage would provide added assurance that cracks are not propagating.

Corrosion testing indicated that the mechanism will not be active in high temperature environments such as those that will exist during the test period. Eddy current examination is not planned to be conducted at this phase of the test program since leakage detection has higher integral sensitivity.and reli-ability. In addition, opening the steam generator for inspec-tion would expose the tubing to an unnecessary oxidizing environment. Good engineering practice dictates that exposure l

to air should be minimized.

1 Both long and short term corrosion tests provide evidence that the crack mechanism is arrested. The flaw growth program has shown that cracks are not propagating or initiating within the steam generators. The precritical and power escalation test program will give assurance in the short term, and in the long term, steam generator leakage monitoring and the long term cor-rosion test program will give tube integrity data and assurance that cracks are not initiating or propagating 'during operation.

In addition the monitoring of degraded tubes will give addi-tional assurance that the cracking mechanism is arrested.

B. Defect Detectability An eddy current inspection was conducted of 100* of the in-service tubes in both steam generators for the full length below the top ten inches of the upper tube sheet. The system that was used for this inspection was a .540 inch diameter.

standard differential probe with a effective gain of approxi-mately 60. Any high noise or otherwise difficult to interpret-indications were resolved in conjuncti.on with ~ data. from an eight 1

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

I l

I coil absolute probe. The selection of this system is documented in detail in Reference 20. The following summarizes the quali-I i

fication process which resulted in determining that this system demonstrated adequate sensitivity to detect defects that should be removed from service. This section discusses laboratory calibrations, comparison of field data to metallurgical inspec-I tions, measurement of laboratory grown cracks and comparison of differential probe data to absolute probe data.

(

The eddy current probe systems were tested against electro-discharge machined notch defects at the EPRI non-destructive l examination research center in Charlotte, NC. Circumferential machined notches of .187. 100, and .060 inches were machined on ene inside diameter of LG arenive aciam geners:or cue;a;. :en length of notch was machined to through wall depths of 20%, 40%,

60% and 80%. Minimum levels of detectability were determined by

- comparing defect signal to a field noise level of .3 volts.

The results of these calibrations for a .540 inch diameter dif- ,

ferential probe with a gain of 60 at a frequency of 400 HZ are shown in Figure IX-1. Cracks with geometries that fall to the

' right and above the curve are detectable, those to the left and below are undetectable. The perfectly horizontal geometry of the machined notch is not totally representative of the cracks in the steam generator, but it provides the'1 east detectable geometry for differential eddy current probes. This geometry, therefore, should provide a conservative estimate of defect detectability. Details of this qualification prog am are con-tained in Reference 20.

On three separate occasions tubes were removed from both steam generators for metallurgical examination. Details of these examinations are contained in References 3 and 4. One of the purposes of these examinations was to correlate the ECT signals with actual defect geometry. Eddy current reported thru-wall

- penetrations ranging from 40 to 95%; 39 of 42 cracks investi-gated in the laboratory had 100% wall penetration, and the three cracks were observed to penetrate 66, 70 and 70% through wall.

One possible explanation for the thru-wall discrepancy is that the cracks may not be open in-situ. Although the Intergranular.

attack penetrates the entire wall, sufficient continuity exists across the grain boundaries to give a less than thru-wall eddy current signal. There were no cases below the roll transition area in which a defect had not been detected by ECT. Details on metallurgical correlations are included in Reference 20

. The particular geometry of these defects were tight circum-ferential cracks that in most cases, were undetectable by visual e

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examination under microscope or even by high resolution radio-l graph. The primary means of detecting these cracks is by tube axial sectioning and reverse bending on a 1/4 inch mandrel to open up the cracks. Tubes were examined by this method not only in areas where defects had been detected by ECT but also in good areas of defective tubes and in good areas of tubes taken from '

low defect areas of the steam generators. In all, 24.6 feet of tubing was examined by this method and no defects were detected except where ECT inspection had indicated a defect. These results increase the confidence level that the sensitivity of the ECT inspection method is sufficient to detect all defects in the steam generator tubing.

To compare the absolute to the .540 high gain standard differen-

~

- tial (S.D.), the sample of 3230 cubes previously tested by Absolute ECT (4x1) was retested using the .540 high gain S.D.

technique. The sample was predominantly from the high and low reject areas of OTSG "A". The first comparison using the normal S.D. .540 technique indicated a correlation of 99.5%. The quantity of tubes that did not correlate was 16 low level in-dications. With absolute data, it was determined that these indications were all one coil, suggesting that the circumferen-tial extent was relatively small. In reviewing the .540 scans, it also appeared that the 16 indications not detected we're consistently in the field of the high noise level. To better detect these 16 indications, an I.D. frequency mixing (to remove tube noise / chatter) was added to the S.D. .540 technique. With the added 1.D. mixing, S.D. 540 capabilities were enhanced to 100% correlation with the absolute technique as the remaining 16 indications were detected.

This ccmparison establishes that the normal S.D. .540 technique is as sensitive a method for flaw detection as the absolute.

B & W Alliance Research Center conducted a program to artifi-cially induce 1GSAC in archive Inconel tubing. Following exposure to thiosulf ate-bearing solutions, the tube specimens were eddy current tested. Scanning Electron Microscopy clearly showed the intergranular nature of the cracking and confirmed that the laboratory induced cracks reproduced the type of cracking and crack shape found in the service failures. For cracks investigated by successive grinding and polishing, measured axial extent ranged from .006 .017 inches. This ia somewhat larger than that of the EDM notches used during the previous 0.540" probe qualifications tests. This value is also larger than the .002" minimum seen during failure analysis on actual tubing. However, the measurements on service tubes were usually estimates made on SEM photos rather than metallographic i

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_ _ . _ . . . . . _ . . _ _ - _ _ =,. _ . - _ _. ._ _ .

J I sections, and would be expected to be lower. The crack axial  ;

extent in service and laboratory induced cracking can th's u be 1 i concluded to be comparable.

Correlation of eddy current results with metallographic observa-tions was performed on samples with the following results. A summary is shown in Table IX-1.

1. The threshold of detectability appears to be comparable to that determined by the original qualification testing. A crack, .040" x 40%, was below the level previously found detectable and sas in fact not de-tacted. C-m e':s o f . ? 1.5 " t ? ' T n e d 0 .110" x ca% ere

detectabig by G.540" probe. This is illus

ratac further

-- - by plotting the points on Figure IX-1.

2. Using the GPUN ECT 2-step screening technique, 8 samples were tested. Four sa'mples were dispositioned as accep-table and four samples were dispositioned as having unacceptable defects. When confirmed by metallography there was 100% correlation.

From these tests it can be concluded that the detectability of ,

laboratory induced cracks confirms .the qualification of the .540 differential probe using actual steam generator tubing as well as EDM notches. Similar qualification programs were conducted to determine sensitivity of the 8x1 absolute probe, and to cor-

- relate sensitiv*ities of both probes in the high noise area of the tubesheet.

The ECT system used during the steam generator inspection has the sensitivity to detect crack of the sizes indicated in Figure IX-1. All defects above that size have been identified except' for a small number that may have been missed due to random equipment or interpretation errors. ,

C. Undetected Defects Some number of undetected defects or other tube surface anomalies may remain in' service after the repair is completed.

These defects fall into the following categories

1

1) Local Intergranular Attack l . 2) Below the detectable limits of ECT

3) Detectable by ECT but missed through random error i

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TA111.1-: IX - 1 I.AllOHATOltY IllDilCED CllACKS E/C COHitEl.ATIOli I

i EDDY CilitHEllT EXAtt _

!! ETA 1.LOGRAPilIC COHitEl.ATIOtt PIIYSICAL .510 .540 4x1 SAtlPI.E ID APPEARAtlCE GPuti 1 CIHC. Tilnu

& T.W. 1 T.W. I COILS DISP., d.EllGTil llIrl. AXIAI.

WALL t EXTEllT A - 1.75 5 DISTORTED 20 - OD llE 1 - ID R 0.2" 50% .014" A - 2.32 DISTORTED 35 - OD 11E 1 - ID R 0.17" 63%

• .017" 5

D - 3.32 DISTORTED 20 - OD 420 - OD 1 - ID A 0. "-0.5" 181 .006" C- . ~/ 6 ACCEPTABLE 20 - ID < 20 - ID llDD A SURPACE At10!!ALITY D - 1.9 ACCEPTADLE IIDD 35 - ID llDD A  !!O VISIBLE DEPECT E - 4.0 ACCEPTABLE IIDD 65 - ID 1 - ID R .315"!! 30% .0065 E - 4.3 ACCEPTA11LE IIDD llDD llDD A .030 251 P - 4.8 ACCEPTABLE 85 - ID 55 - ID 1 - ID R .14" p41 .012

1. R = REJECT A = ACCEPT 2.

IlE = Il0T EXAtilllED (TUDE ID REDUCTIO!1 DID 110T ALLOW PASSAt..:OP 0.540 PIOnE) 3.

IIIGil GAlti PARAMETEll S1HUI.ATED 0.540 SEllSITIVITY

4. Il = MLILTIPI.E

5. It is believed the physical OD distortion on the tube ha:. produced the

. OD differential eddy current response.

4 4

Specimens of actual OTSG tubing have exhibited areas of general surface IGA one to two grains deep. This local ICA is similar i to that seen in other Inconel 600 tubes and is generally agreed to be the result of the tube manufacturing process. A few isolated instances of IGA from 6 to 10 grains deep have been found; they are associated closely with visible multiple cracking.

One use of the long term " lead" corrosion testing program described in Section III will be to show that these phenomena .

i are not contributors to tube failure. Specimens selected for

' this test program will contain general surface ICA as well as j crack indications. IGA islands cannot be specifically included 1 as :a;; apecisans 24 L. ; ;;. Occur:2a;t 1 ::. Je , ir.c : : :-

not be detected other than by destructive examination. However, j b-'y~ bounding this condition with specimens containing surface IGA and actual cracks, the influence of this condition can be assessed especially on consideration of the fact that metallo-graphy has shown that the most extensive IGA is in the vicinity of major cracks. The development of IGA and/or cracks will also be assessed during the test program as specimens will be period-ically rem >ved from the test solutions and metallographically evaluated. Both the metallurgical examination program and the long term corrosion testing program provide a'ssurance that the steam generators can be operated safely with local ICA on the tubing.

l In addition to surface IGA, the existence of small cracks below I the threshold of eddy current detectability has been con- ,

i sidered. Corrosion tests have shown that crack propagation by 1 chemical means is unlikely. Stress analyses were conducted to determine whether small cracks could propagate under conditions of mechanical loading during normal operating, transient, or 1 accident conditions. The evaluation performed.had determined the maximum flaw size which will remain stable under ~

steady-state and transient loading. The acceptability of small cracks in service is based on demonstration that eddy current examinations have identified existing cracks of this maximum 9 flaw, and that the small cracks will not propagate rapidly to this size during operation.

The tube loads are derived in part from the design basis docu-

! ment (Ref. 52) and in part from measurements of the TMI-2 OISG -

tubes (Ref. 51). Recourse is made to field measurements because the steam generator performed better than design assumptions predicted. TVenty degrees more superheat is measured than i predicted.

4 l

(.

I

The axial load on the tube during anticipated transients, such as heat-ups , power changes, and reactor trips , and steady-state operation are due to:

a. Dif ferences in tube average temperature and the average temperature of the steam generator vessel wall.

b. By virtue of the end fixity of the tube', a longitudinal pressure stress evolves through Poissen's ratio.

1 c. A residual tube axial load component exists from fabrication.

d. Tbbesheet fixit" mitigstes axisi lead, especially near the unit center-line.

S'uperimposed on the steady axial load is a high cycle, flow

• induced vibration (FIV) bendin'g load. The frequency and dis-placement magnitude of FIV was measured at THI-2 (Ref. 51).

. Potential for crack propagation was evaluated in two ways, a fatigue fracture mechanics calculation incorporating FIV and normal operating transients , and solid mechanics calculations of one time transient and accident loads. These calc'ulations were l used to generate curves showing crack depth vs. circumferential extent for the maximum stable crack configurations. The results are shown in Figure IX-2.

D. OTSG Tbbe Failure Analysis for Unplugged Tubes (Proprietary)

Curve A in Figure IX-2 represents the maximum crack size found to be stable with respect to f atigue flaw growth over a 40 year lifetime. The fracture mechanics model uses a preexisting crack and evaluates its propagation under high cycle and low cycle fa tigue .

- During steady state operation the steam generator could have an axial tension of 500 lb. act on the tubes. In the analysis, the load cycle imposed on the tubes included mechanical and thermal factors. Low cycle, long duration loads were combined with high cycle flow induced vibration (F.I.V) loading. A graphical representation of the load cycle is shown in Figure IX-3. The analytical model, which used EPRI fracture mechanics code BIGIF, l cycled load about 500 lbs. axial tension, the steady-state value

! calculated from THI-2 test data. The F.I.V. deflection selected f corresponds to the largest peak deflection seen at a T41-2 sensor during a steady state condition. This is 3 mils, peak half-amplitude displacement. The sensor was located at a " lane" tube which experiences higher crossflo'w than the average tube.-

l -

.a

OTSG Tube Critical Crack Sizes i

2.00 -

0.D. MAX ARC-LENGTH g

,100 F/HR COOLDOWN \ 1

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s {l M AX INITIAL CRACK SIZE TO ALLOW 40 YRS. 0F STABLE CRACK PROP 0GATION.

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O 20 40 60 80 100 DEFECT DEPTH IN % WALL THICKNESS FIGUf1EIX 2 l

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1 1

The vibrational load amplitude was selected for conservatism to be the maximum tube displacement seen under steady-state loading.

Combined with high cycle loading was the maximum tension excur-sion represented by the 100*F/hr. cooldown, which imposes an t

I axial load of 1107 lbs. The FIV and one cooldown comprise a l

load block as shown in Figure IX-3, with 'six cycle times per year.

Lapirically derived values were used to rdpresent tube 1cading.

The value of R (K minimum /K maximum) thus is approximately equi-valent to actual conditions.

Iha :s: ;ua calca.a i n ::na;. era. :. e lac: . . . .  :.; t: 2 a:

point at which small indwelling cracks have no ef fect on fatigue resistance (the endurance limit). This value of the stress intensity, below which cracks do not propogate, is the stress l intensity threshold (delta KTH)*

A modified Paris equation was incorporated in "BIGIF" with the feature that if the stress intensity range did not exceed threshold, no growth would occur.

The THI-1 calculation was performed using delta KTH=4.0 KSI (in) 1/2. This value is based on the empirical data for Inconcel 600 shown in Figure IX-4. The intercept of the abscissa is the threshold for propagation. The relationship has ,

been determined for threshold stress intensity and R values so that data taken at different R values has. been used to calculate the appropriate threshold for TMI-1 conditions. Delta KTH "

4.0 KS1 (in) 1/2 is judged a conservative value.

The evaluation has shown that the high cycle flow induced vibra- i tion does not contribute to propagation for ID circumferential  !

cracks. Low cycle loading from the startup and cooldown is the l significant contributor to stable crack growth'. Curve A in t Figure IX-2 represents the maximum crack size which can with-stand 40 years of heatup and cooldown cycles witnout reaching a size which will propagate rapidly to a through wall defect based l on the conservative analytical assumptions made. Since this curve is to the right and above the eddy current detectability curve, cracks of this size will not exist in the free span area of the repaired steam generator. l Curves B and C represent solid mechanics models of the ability {

of cracked tubing to withstand one time transient loads. The ,

, maximum accident axial loading on the tubes is during a main steam line break, and is defined as 3L40 lbs for peripheral tubes and 1408 lbs for core tubes in generic licensing FIGU RE IX-4 Fatique - Crack Propagation Behavior of inconel 600 da/dn vs AK forINCO SOO 10-4

_ A 75 JOURNAL OF ENGINEERING MATERIALS CURVE O 600 JOURNAL OF ENGINEERING MATERIALS CURVE

~

G 77* MIT CURVE

_ ^

O d54' MIT CURVE /

/

f. . '

O 10-5 _

e

, _ OC .

i? -

e

) _

l

{

l-4 -

2 a=,=

es/

il e

_ .10 - 6 g

A 1

A 608 POINT BORATED WATER l

\

l 10-7 ' ' ' ' ' ' ' '

1 100 110 LOG AK, KS1 O STRESS INTENSITY FACTOR RANGE .

I e

documents. The maximum axial loading during normal transients is the 100'F/hr cooldown, which corresponds to 1107 lbs tension i for peripheral tubes and 649 lbs for core tubes. These axial ,

loads include preload, pressure effects and tube-to-shell l temperature differentials. *  !

Curve C on Figure IX-2 was derived using the 1107 lbs transient axial loading, Curve B is for MSLB. In the analysis, the fact that a flawed tube will move laterally under the axial load is ,

included so that the centroid of the damaged cross section lines '

up with the line of action of.the load thr'ough the intact tube '

l centerline. With this model, the induced bending moment at the flaw is reduced. Assumptions on the tube stif fness remaining  !

. and the manner in which strain is absorbed in the area of the I cracA have acen se.ec:42 :: cada :aa rar;;;; cen;arr;;iii.

Curves B1 and C1 reflect conditione pertaining to the core -

~

f.

~

t'ubes .

Curves B and C show that the maximum crack sizes for failure under transient and accident loading is to the right and abova 1

ECT sensitivity. Thus the probability is very small that cracks of this size will remain in service after the completion of repairs.

The laboratory calibration results and the correlation of the differential production probe to the absolute probe results' provide confidence that all defects above the detectable size j l

l will be found. However, there is a small probability that some large cracks may not have been detected due to problems such as high noise levels, probe lift off or chatter, or data analysis errors. Because of this possibility, an evaluation was per-formed to determine if tube cracks.of the size that would pro-pagate can be detected due to leakage. ,

As discussed above in the OTSG tube stress analysis , the tube axial load is a function of several variables and may have either tensile or compressive values. The gre'atest uncertainty '

l is the tube tensile preload. Based on the TMI-2 test data at 97% full load a tube axial load of 500 lbs tension was cal-culated. In addition to this result, a calculation was per-formed on the basis of first principles in order to establish the tube loading. This calculation included the effects of dif ferential thermal . growth between shell and tube , preesure loadings and tubesheet deflection as well as a value for tube preload. The preload value was based on a gap measurement of 3/32 inch between parted tube surfaces. At THI-1 the result is

' a tube loading at full load to be approximately 500 lbs tension for peripheral tubes and 200 lbs tension for core tubes. The calculated results of tube loading' based on first principles

~- 84 -

, - , - -eemy.,wr-r-w--,*-v. y ~- , - ,-*w'v g -%4 ,y .--,y +

- =_ - - --

correspond fairly well with the values calculated from the TMI-2 '

test data. Therefore, we conclude that the model of tube load based on first principles is valid and that the tube is in ten-sion during operation.

After determining a conservatively small minimum crack opening displacement, leakage through the opening was calculated. The

! evaluati'on includes consideration of phase changes and pressure drop as the primary fluid passes through the crack.

Leak race has been calculated using various steady state tensile tube loads and through wall crack sizes. Figure IX-5 shows the relationship of tube leakare versus crack are length for various cuoe loaca waren coniroi cae C L. T.s ;c.iew ag :aaie . ..; - ,

shows the full pewer operational leak rates for peripheral and core tubes based on their respective critical crack size for a MSLB and for the Plant Technical Specification (100'F/hr) cool-down rate. -

Table IX-2 TMI-1 OTSG Tubes Critical Crack Sizes and Operating Leakrate Tube Location: Core Peripherv Tube Load 0100% Power (1bs.) 200 (tension) 500 (tension)

Transients:

1 - MSLB Transient Tube Load (1bs.) 1408 (tension) 3140 (tension)

Critical Crack Size (inches) 1.28 0.52 Leakrate (gph) 0100% .

Power Operation 14 6 2 - 100*F/Hr Cooldown (140'F Shell to Tube Delta T)

Transient Tube Load (1bs) 649 (tension) 1107 (tension Critical Crack Size (inches) 1.72 1.48 Leakrate (gph) @l00%

Power Operation 22 72 Fig. IX-5 was developed by Nuclear Safety Analysis Center (NSAC) based on a model for.two-phase flow through a crack with initial saturated or subcooled fluid, by Battelle, Collier, R'.P., et al., " Study-of Critical Two-Phase Flow Through Simulated Cracks", BCL-EPRI-80-1 Nov. 25, 1980. The curve was redrawn to include a 200 lb tensile tube load curve.

, , - ..-g

FIGURE IX.5 OTSG Leak Rate as a Function of l

Crack Length & Tube Tensile Load 100 -

i s0 -

1107 # tension  !

f

[ peripheral tube ,l

.. e ... . i .;;

[

_ 80 -

Cooldown 70 -

3 CL.

E 60 -

w 500 # tension Q

c=

peripheral tube load _ >

y @ Full Power w 50 - - -

a E

E 40 -

a ._

30 -

200 # tension 20 -

core tubs load

@ Full Power _

10 -

/ i i i i i i 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.1 1.2 1.3 TUBE CRACK 00 ARC LENGTH (INCHES)

I The leak rates indicated in Table IX-2 are above the detectable leakage shown in Section X.

An administrative limit on leakage has been established based on the lowest leakage value in Table IX-2. The tdministrative leak j rate limit assumes all increases in leakage to be from ene OISG  !

tube and has a value of 6 gph above the baseline on this basis. '

The action of that point will require bri,nging the plant to cold shutdown and leak testing the OTSG and repairing any identi-fiable leaks. Bubble tests are expected to identify individual leaking tubes. Bubble test sensitivity is .1 gpd/ tube. Thus, any cracks in service of a size which is or propagates to a

r 3 -3 0-1 size rill ' 3 3. d 2- t# f'. ? f .

_ In. addition to the' leakage limit, normal plant cooldowns will be accomplished at less than 100*F/hr and limit the OTSG shell to ,

tube delta T to 70*F. This will decrease the cooldown transient  ;

axial tube tensile load to app'roximately one half of the evaluated tensile load which results from 140*F OTSG shell to tube delta T.

E. Conclusions _

I Evaluations of tubing left in service have been performed to verify that they are acceptable for use. The possibility for j additional corrosion occurring after return to operation has ,

been considered and found unlikely. In considering existing i damage, the ability of cracked tubing to withstand steady state, j transient and accident loading has been examined. All cracks of I a size that could be expected to propagate under loading are I ,

within the range of detectability by eddy current testing. If a  !

through wall crack of critical size for growth has been in-  ;

advertently left in service, or grows at a later date, it will be detectable due to leakage before there is tube failure.

f i

l e

w -

r: l l

i X. OPERATIONAL CONS!DERATIONS The operational concerns of primary to secondary leakage were evaluated. Concerns included leakage monitoring during normal operations in both steaming and nonsteaming conditions, and sampling steps to be taken when leakage is detected. In additioh, a program has been formulated that includes procedure review and operator training which will provide improved operator guidelines for dealing with tube leakage and tube rupture events.

.e The operational guidelines discussed in this section are applicable during normal operation with low levels of primary to secondary leakage. A more detailed description of these euidelines can be found in reference 55. Fcr primary to sacencary leakage ra:_a v: ;U gpm or greater, these. guidelines will be superseded by tube rupture

' guidelines as discussed in Section X.B.

~

Operational concerns can be grouped into three general areas '

1 Primary to Secondary Leakage which includes leakage detection methods, and actions required based on primary to secondary leakage.

2. Radiological concerns which include detectio~n methods, worker protection measures and plant discharge limits.

3. Secondary side chemistry limits based on boron and lithium con-centrations. .

This section summarizes the guidelines for operating with tube leakage.

i A. primary to Secondary Leakage ,

During normal power operation the methods which will be used to

• detect and monitor leakage ares  ;

o%

1.' Offgas continuous monitor (RMA-5)

2. Tritium samples from the condensate and primary system.

3. Offgas grab samples 4 'N-16 activity measurements using portable steam line monitors I

i 5. Primary Leak Rate Calculation ,l '

I These methods are summarized in Table.X-1. l RMA-5 will be the first indication of increased -primary to i' secondary leakage. The monitor will continuously sample the t

?

l~

1 -.

- - , - -n., , , + , , . , -

,-n- .-

I l

l vacuum pump exhaust from the main condenser. Upon a 25% in-crease in 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> in RMA-5 count rate the primary and secondary systems will be sampled for tritium and the leak rate cal-culated. An of fgas grab sample will be taken and the primary to secondary leak rate will be calculated using Xe-133, Xe-135 and l

l total gas activities. The portable steam line monitor will l

detect N-16 activity and will be used to evaluate which steam generator is leaking.

Primary leak rate calculations which are done daily per Technical Specification requirement can also identify increased primary to secondary leakage. Since the leak rate cannot dis-tinguish between unidentified system leakage and primary to sacancary =..aga, ;; sn on.uan:::;25 .ncr4..e a . -.. ::::

occurs, a critium und offgas grab sample will be taken to allow for an accurate determination of the primary to secondary leak

. rate.

Shutdown limits based on primary to secondary leakage will con-sist of the Technical Specification limit of 1 gpm and an admin-istrative limit of 6 gph above a baseline leakage. Baseline leakage will be determined during the precritical hot testing program. When a leakage increase o'f 6 gph is reached the plant will be brought to a cold shutdown, the OTSG will be leak tested and the leaking tubes repaired. Tube leakage will be tested by the bubble test method. This method has a sensitivity of

.1 gal / day / tube or 4x10~4 gph/ tube, therefore if no leakage is ; '

detected during the bubble test it can be assumed that no individual tube has reached the critical crack size and primary I to secondary leakage is due to aggregate tube leakage. The baseline leak rate value will be redetermined based on an i evaluation of the OTSG leak rate test results and operating ('

history after the leak test is performed. When primary leakage reaches 6 gph greater than the new established baseline the ,

plant will again be shutdown and leak tested.~.

t

~

When shutdown is required by steam generator tube leakage, the  !

plant should be shutdown expeditiously but in.a manner to pre-clude reactor trip and subsequent lifting of relief valves or atmospheric dump valves. Cooldown rates should be limited to ,

100*F/hr and tube to shell delta T should be limited to further reduce the possibility of tube rupture during cooldown. j B. Radiological Concerns 1

- During normal operation with steam generator tube leakage,_

radiological concerns arise in the following areas: ,

l. General and specific area radiation level l

2. Turbine building sump activity (with respect to discharge to the environment).  ;

I

3. Powdex resin and backwash water activity.

Specific and General Area radiation limits will be determined and will be based on preventing the turbine building frem becoming an RWP area (greater than 5 mr/hr). Limits are needed due to the necessity for easy access into the turbine building .

during operation. Routine radiation surveys will be taken in the turbine building in the vicinity of the Powdex and Graver System vessel and in other selected areas. These areas will be l restricted if necessary to prevent unnecessary exposure to plant personnel . Precautions will also address secondary side system .

vent and drain operations.

In th e ?~<dex sunn. 9H and conductivity analysis will determine if the watar wnich has ceen processeo oy :ne (Ecocyne acaver s ,

-- Powdex Backwash Rec'overy system wi?1 be returned to the TMI-l condensate system or to the turbine building sump. Any radio-active powdex will be dewatered in High Integrity Con-tainers / Liners and shipped to commercial low Icvel waste burial sites.

C. Secondary Side Chemistry Secondary side chemistry limitations for Boron and' Lithium will  !

be based.on considerations of chemical introduction into the turbine.

D. Development of Procedural Guidelines for Steam Generator Tube Rupture A program has been formulated for providing improved operator guidelines for dealing with tube leakage and tube rupture events. The guidelines cover two categories of events. The first category addresses tube ruptures for which subcooling margin is maintained. The second category will deal with tube ruptures for which subcooling margin is not maintained and would include various contingencies including multiple tube ruptures in one or both SG's, loss of reactor coolant pumps and loss of condenser.

1. Contingencies for Consideration l

The following is an outline of the programs for developing guidelines for SG tube rupture.

a. Guidelines for Tube Ruptures for Which Subcooling Margin is Maintained The program to develop guid'elihes for tube ruptures for which subcooling margin is maintained will include the following basic assumptions.

---+.-_-m____ _ _ _ _ _ _ . _

TABLE X-1 LEAKAGE DETECTION METHODS

SUMMARY

TABLE Method Sensitivity Frecuency Soecial Actions RMA-5 0.48 gph with 3.8 uCi/cc Continuous strip When count rate and 20 cfm exhaust flow chart reading. increased by 25*

in 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, sample for tritium and take off gas grab sample.

' Tri:ium .3 gpm at .02 uC1/=1 S nours wl:a known leakage

_H3 after 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />' Offgas Grab .01 gpm at 3.8 uCi/cc 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency increased Sanple and 20 cfm exhaust flow with known leakage Portable When leakage is ,

Steas Line detected deter-Monitor mine which generator is leaking i

h l

S

~ ~ - ,7

(1) Break size small enough to maintain subcooling margin.

(2) One OTSG affected.

(3) Reactor Coolant Pumps operating.

< (4) Condenser available.

(5) Decay heat removal from the non-af fected SG.

(6) SG steamed at 95% operating range level to assure natural circulation. .

Contingency considerations for ddsign basis tube ruptures include:

(1) PORV unavailable. *

' ' ?a:::c ~ ~ *.:n: ' 7: ;n2 ::'.: .t.

(3) No condenser available.

(a) High radiation release considerations.

(5) Steam line flooding consideration.

(6) Both SG's are affected.

b. Guidelines for Tube Ruptures For Which Subcooling Margin is Not Maintained The program to develop guidelines for tube ruptures for which subcooling margin is not maintained will include the following basic assumptions.

(1) Break size from one SG large enough to cause loss of subcooling.

(2) No reactor coolant pumps running (since subcooling margin is lost).

(3) Condenser available.

(4) PORV available.

(5) Unaf fected SG is steamed.

Contingency considerations include:

^

(1) PORV unavailable.

(2) RCS voiding keeps pressure above SG safety valve setpoint.

(3) Primary feed and bleed heat removal.

(a) With PORV available (b) Without PORV available Both the analyses employ the RETRAN code. This code models TMI-l and has been benchmarked from transients on both TMI-1 and TMI-2. Use of this code ensures that plant response under various primary-to-secondary leak scenarios is under-stood.

i f

l

, --n - -y

FIGURE X 9 Tube Ruptura Guidelines l

Primary to Secondary Leakage

> 50 gpm J\

l k Manual Automatic Shutdown Shutdown 1

t u,

Cooldown 2

4 ,,

Natural HPI Forced Circulation Cooling .

Circulation L J

& w4 Decay Heat Removal New Guidance:

- multiple tube ruptures

- ruptures in both steam generators

- HPI cooling

- Secondary water management Improved guidance

- Minimum subcooling reduced

- RCP trip criteria -

- tube to shell AT l - steam generator steaming, feeding, flooding l

O

+ _____

._____ _.___ _ , ___--7. . - --- . . . , _,, - ,7,, - -

i The guidelines developed from the RETRAN analysis for tube ruptures are summarized below and have been used for writing new procedures and revising old procedures. Operator training prior to restart includes response to tube rupture events using new and revised procedures.

2. Gaideline Summarv The symptoms of a tube rupture define. entry conditions for this emergency procedure. It is only 'used when leakage exceeds 50 gpm. k* hen conditions require it (as defined by high leakage or significant of fsite releases), the plant will be shutdown and cooled as expeditiously as possible, n: ::rt:in : :1 7 r.t 114ri t: C? 't r? 2 n rtal tuh a '-'e'.1 delta T, and fuel-in-compression limits ) are waived.

a. Immediate Action I

The tube leak in question may not be large enough to ,

cause a reactor trip. In such a case, the operator i begins a load reduction as rapidly as possible without I causing a reactor trip (10%/ min.). Avoiding a reactor trip prevents lifting of the OTSG safety valves.

I

b. Followup Actions (1) Subcooling Maintained and Reactor Coolant Pumps Available Once the load reduction is initiated or a reactor trip has occurred, the operator has several major goals to achieve while bringing the plant to a cold ,

shutdown condition. First, he prevents lif ting of '

the OISG safety valves; second, isolates the af-fected OTSG to prevent unnecessary radioactivity releases; third, minimizes primary 'to secondary leakage by minimizing primary to secondary dif-ferential pressure; and, fourth minimize stresses on the OTSG tubes by limiting tube /shell delta T.

Finally, the operator will minimize offsite dose by allowing the leakage OTSG to flood if of fsite doses are large enough (approaching levels at which a Site Emergency would be declared).

The major differences between the existing plant procedure and the new procedure would be the following.

(a) Maintain a Minimum Subcooling Margin Minimum subcooling margin means that primary to secondary differential pressure is minimized.

Minimum differential pressure means that leakage is reduced ; thus reducing off site dose i and making the event more manageable. In order to maintain the minimum subcooling margin, several plant limits have to be violated: fuel in compression limits and RCP NPSH limits. The  ;

former is acceptable to violate during emer-gency conditions , while the latter is being  ;

reevaluated to determine acceptable emergency ocerstion of the euro.

(b) St-eaming/ Isolation Criteria for the Af fected

~ - - '

OTS G  ;

The present procedure allows the operator to let the OTSG flood anytime that RCS pressure is below 1000 psig. . The revised procedure has the j operator steam the OTSG as necessary for the .

following purposes. First, to prevent lifting '

of the OTSG safety ' valves. As the OTSG level

! increases, steam generator pressure in the  ;

l isolated generator could increase to' ward the safety valve setpoints. Pressure should be l controlled to prevent a safety valve lift. l The generator is also steamed to prevent it

• from flooding. Flooding is undesirable because I an RCS pressure increase under this condition could cause water relief out of the OTSG safety valves. A flooded OTSG would also act as a second pressurizer and slow depressurization of the RCS (as occurred in the GINNA tube rupture).

The OTSG will be isolated under two conditions.

First, if BWST level goes below 21 ft. indi-cated level. At this level, there is still /;

sufficient inventory to fill up both OTSG's to i the main steam isolation valves and have 30,000 t gallons of water left to go on feed and bleed l l cooling. A second reason to isolate the OTSG '

is for radiological considerations. If the Radiological Assessment Coordinator (RAC) ,

determines that offsite doses are approaching l

. 'g I

- t 9

6

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

l the levels which would require declaration of a Site Emergency, (regardless of cause) the affected steam generator will be isolated.

(c) Tube-to-Shell Delta T l

Plant administrative limits and precautions j will require maintaining the OTSG average tube temperature within 70'F of the average shell i temperature. Under emergency conditions, this '

limit can be relaxed to 140*F (Tech Spec limit) without adversely affecting OISG tubes. j i

( 2) Less of Subcooling Mari3 n with Natural Circulation Cooling When RCS subcooling is lost, the operator must treat

• LOCA, as well as tube rupture symptons. First he j trips RCP's and then verifies HPI and EFW have ,

initiated. He is then able to pursue the follovup l tube rupture actions. All of the guidance for i I

followup actions without loss of subcooling apply, as well as the additional guidance provided below. f The objective in this portion of the procedure is to maintain natural circulation, reestablish subcooling margin, restart a reactor coolant pump, and return i to the section of the procedure for forced flev ,

cooldown. 3 i

When subcooling is regained in the RCS.- then HPI is  !

I throttled, RCP's are started and the operator con-tinues with 1.67F/ min cooldown. If subcooling can-not be restored, the operator cools the plant down on natural circulation, steaming as necessary to meet the objectives described in the forced flow

- section. .

If the affected OTSG cannot be steamed for either radiological or equipment reasons, then EFW is used to control OTSG pressure. Essentially, EFW is used as a pressurizer spray to keep the leaking generator slightly lower in pressure than the RCS. The bene-fits in controlling steam pressure are:

(a ) safeties will not lift.

(b ) the steam generator will not control RCS pres- f sure. i l

s

_ 94 -

l

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

I (c) there will not be backleakage into the RCS of I unborated water.

(d) leakage from the RCS to the OTSG will be small i since differential pressure will be small and will also reduce tube tensile load due to pres-sure loads.

(e) the small flow through'the hot leg will help prevent void formation in the hot leg.

(3) Loss of Subcooling and Loss of Heat Sink 4

Natural circulation cooloown will continue uncil

~

subcooling is restored or the OTSG heat sink is lost (for example, due to loss of natural circulation in

~ ~

i +

. the unaffected loop). With no steam generator heat ,

sink, the operator must put the plant in a feed and bleed cooling mode. Feed and bleed cooling is ini-tiated by isolating the OTSG's, assuring full HPI is  !

operating, and opening the PORV. If RCS pressure j remains below 1000 psig, then the operator continues -

to control secondary side pressure just below RCS pressure. If the OTSG heat s. ink is restored, the i feed and bleed is terminated and a natural cir-  :

i culation cooldown is reinitiated. j If RCS pressure stays above 1000 psig during feed l and bleed cooling (e.g., the head bubble prevents

• depressurization or the PORV fails closed) then the secondary side safety valves have to be protected ,

from challenge. The operator controls OTSG pressure .

with whatever means are available (turbine bypass, EFW or ADV). When the OTSG is about to flood, the operator opens the ADV and leaves it open. This

. action minimizes the chances that safety valves will +

be forced to relieve water and/or steam and fail .

open. The steaming capacity of an ADV at 1000 psig exceeds decay heat levels within~ several minutes after reactor trip. HPI capacity exceeds the capacity of one ADV. Therefore, the RCS pressure ,

can be controlled at 1000 psig in this mode without -

lifting' safety valves. Subcooling margin can be regained and the plant cooled down in this mode '

until an OTSG heat sink can be restored or until the plant can be put on decay heat removal.

A simplified schematic of'the tube rupture guide-

! lines is shown in Figure X-1.

g ~ e

i I

A fourth possible scenario exists under current procedures which has not been considered a preferred

( course of action in formulating the guidelines:

l maintenance of subcooling margin but tripping of reactor coolant pumps on 1600 psi RCS pressure.

! Pump trip on loss of subcooling margin instead of RCS pressure allows the operator to maintain forced flow for about 3 ruptured tubes - 1600 psig SFAS is much more restrictive. Forced RC flow provides several benefits during a tube rupture.

1. It minimizes primary to secondary delta P and thus reduces tube leakage and tube tensile load.

2. Prevents steam formation in the RCS. (Steam votding prevents RCS depressurization.) l i

3. Provides pressurizer spray so that RCS pressure l control is not dependent on the PORV or pres-  ;

surizer vents.

Therefore, GPUNC is taking action to have the 1600 psi pressure pump trip requirement changed to trip on subcooling margin.

E. Conclusions Primary to secondary leakage will be monitored during non-steaming and steaming conditions. Sampling requirements on the detection of a primary to secondary leak have been established, and administrative limits on leakage are being considered.

The combination of analysis of tube ruptures, procedure improve-ment and training improvement give assurance that operators can safely respond to a primary to secondary leak.

4 e

m .

XI. ENVIRO! MENTAL D'. PACT A. Introduction The impact of operating TM1-1 with primary to secondary leakage was evaluated. Offsite dose estimates were determined at several leakage rates, using actual anticipated failed fuel percentages. These calculated estimates have been compared with Appendix I rechnical specificatien requirements.. The effect of leakage on onsite exposure was also consic'ered and found to be small. Exposures associated with steam generator work leading to return to service are also discussed below.

3.  :!!:i:- : 3 :2: :::

1 The maximum primary to secondary leakage rate at which TMI-l might operate can not be determined without operating ex- i perience. The offsite consequences of such operation will be  !

dependent on the failed fuel percentage and actual plant system )

and environmental conditions. Dose will be determined during operation by nonitoring. The technical specifications for THI-l incorporate the Appendix I offsite dose limitations. If offsite doses approach these limits due to primary to secondary leakage, it will be necessary to shut the plant down t'o look for leaks.

For planning purposes , two calculations were performed using different hypothetical leaks rates,1 lbm/hr and 6 gph. 1 lbm/hr is the repair leak, rate goal. 6 gph was selected as a leak rate with which similar plants have operating experience, and which is similar to the leak rate change at which admin-istrative procedures TMI-l would shutdown to look for leaks.

Both calculations assumed 0.03% failed fuel, which was seen at TMI-l at the end of cycle 4. Results of the two estimates are compared in Table XI-l to Appendix 1 technical specification limits. Source terms and methods for calculation can be found in Reference 11 and 54.

1

Table XI-l INpothetical Maximum Individual Offsite Dose (l) 0FFSITE DOSE AND FRACTION OF APP. I LIMIT 10 CFR 50 Source 1.0 LEM/HR 6 GPH App. I Dose  % o f App . Dose  % o f App . Limit j (mr/yr) I Limit (mr/hr) I Limit (mr/yr) ,

i Iodine & .7.68E-2 0.5 4.61 31 15 Particulates Noble Cases Ga=ma 5.68E-2 0.6 2.74 27 10 i e

Beta 6.96E-2 0.4 3.33 17 20 Liouid Effluent 1.6

• k'nole Body 1.04E-3 0.1 4.88E-2 3 (adults)  ;

• Liver 1. 52E-3 0.1 7. 28E-2 0.7 10 (teens)

(1) Based on 802 of the plant capacity factor. ,

i As can be seen in Table XI-1, offsite doses are not expected to approach Appendix I limits due to primary to secondary leakage.

However, monitoring of actual offsite exposure will be used to set leakage limits which prevent exceeding technical specifi-cation limits.

C. Exposure Estimates The projected man-rem exposures for the completed OTSG repair program are estimated to be 1260-1295 man-rem. Individual ac-tivities for the steam generator program are presented in Table XI-2, along with exposures to date. ,

1 0

.f

Table XI-2 Exposures f rom OTSG Program Actual to 2/23/83 Additional Projected

1. RCS Inspection 12 0 Eddy Current Testing 35 10

2. , _

3. Pre-Repair Testing 5 0 3 l 1 4 Tube Samole Pulling Plug.ging 120 0 anc staoill:ation n

--5. Plugging and Stabilization i

. a. E plugs - 75 l

. b. Stabilization 235

6. Kinetic Expansion L

a. Pre-expansion Preparation 16

b. First Pass Expansion 168 ,

O

c. First Pass Debris Removal 132 0

d. Second Pass Expansion 167 0

e. Second Pass Debris Removal 75 0

, 7. End Milling 125 0

8. Clean-up

a. Flush -

30

b. Soak and Clean -

30

c. Individual Tube Cleaning -

10-40*

9. Testing l

a. Drip Test -

5

.b. Bubble Test -

5

c. Final Inspection and Turnover -

5-10*

To tals 855 405-440

• Items for which planning is not complete.

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Table XI-3 Radiation Fields at THI-1 Location Upper and lower Heads 1.3 R /hr .

Manway 0.13 R/hr. .

Tent 0.01 R/hr. 1 Low Zone 0.001 R/hr. I Operating with the limited leakage associated with the repaired joint was also considered. The additional exposure is expected I

*:2 1 ~ .-

*: 2:!:' - -i:: d t.*t? 'ricti:11 "ill iden-tify any additional radiation areas and minimize related worker exposure in operating with a primary to secondary leak. The largest sources of radiation exposure are expected to be the Powdex Demineralizer vessels. , Associated contact radiation levels have been calculated for a 6 gph leak to range from 0.7 mr/hr for one day filter operation to 5 7 mr/hr for 15 day operation. In addition to these estimates, experience at simi-lar plants operating with small primary to secondary leakage has been exposure increases of less than one man rem per year.

Based on this information, the annual exposure at TMI-l is ex-pected to increase by less than 1% due to leakage.

D. Sampling and Monitoring Appropriate monitoring and sampling of all waste streams will be conducted per established Gaidelines. Modifications will be installed in the Turbine Building to provide radiation and con-tamination control and effluent release control / accountability.

These modifications will consist of Powdex and Turbine Building su=p painting, and liquid monitors to measure activity during operation.

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E. Conclusions The operation of Til-1 with small primary to secondary leakage is not expected to cause offsito doses nearing the Appendix I Technical Specification limits. Final verification of estimates will be by monitoring during operation. Should monitoring in-dicate that primary to secondary leakage is causing offsite doses to approach these limits , steps will be taken to reduce the activity contribution. Exposures onsite as a result of

- primary to secondary leakage are expected to be minimal compared l to prior plant experience. Exposure during the investigation of the steam generator problem, the repair, and testing afterwards , g is not expected to exceed 1260-1295 man-rem.

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XII. TECHNICAL SPECIFICATION COMPLIANCE This safety evaluation demonstrates that the TMI-1 OTSGs are operable per T.S. 3.1.1.2, and have met the surveillance conditions for operability given in T.S. 4.19, or as defined in the releated T.S. change request.

In addition, the following technical specifications were evaluated in light of the selected repairs. Operation with the repairs in place was found to be . acceptable in each case.'

SER Topic for Evaluation Reference T.S. Subject Section VIII 1.5.6 Heat Bal. Calib. .

Flow asymmetry Def 'n,- Quad. Pwr. Tilt Flow asymmetry Section VIII

-1. 6 Fig. 2. -1,2.1-3 Flow vs T Flow, flow asymmetry Section VIII 2.1

2. 3 Fig. 2. 3-2, Table 2. 3-1 ,

Nuclear Overp. Flow Section VIII Permissible pump. comb. Flow Section VIII 3.1.1.1.a 3.1.2 RCS heatup-cooldown Stress vs. Temp. change: Section V and assumes vessel as limit IX 3.1.4 RCS activity leakage Section X 3.1. 5 RCS chemistry Further attack in' conj.Section IV w/resid. S or following S distress 3.1.6 RCS leakage leakage Section IX Flow asymmetry Section VIII 3.52.4 Quad Pwr. Tilt 3 5.2 5 Quad. Bal. Flow asymmetry Section VIII 3.13 Secondary activity Appendix I w/ leakage Section X 3.22 Appendix I leakage Section X 1 3.23 Appendix I le akage Section X

4. 2 RCS:ISI Testing of RCS Components Section II.E 5 3.2.1 RCS code req. Repair qualification Section V 4

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I XIII.

SUMMARY

AND CONCLUSIONS The previous twelve sections along with the references and appen-dices associated with this safely evaluation provide a_ broad-ranging 7

discussion of the adequacy and safety of the TMI-1 OTSG repair and the ability of the plant to be safely returned to service. The main points associated with determining that the plant is safe to operate can be summarized as follows:

1. Knowledge of the failure scenario is sufficient to provide a firm technical basis for OTSG repair decisions, insure that the environment for such a damage mechanism is not established in the future, and provide a technical basis for assuring safe

arlernanca el

a3 T;J ::s=; be'..x :a= ar 2s el :a e nr. Join:.

~2. -Evaluation of operation of TMI-1 with small primary-to-secondary leakaSe has confirmed that Appendix I Technical Specification considerations are satisfied.,

3. All tubes with no defect indications below an elevation 8 inches above the lower face of the upper tubesheet (UTS+8) have been adequately repaired by the kinetic expansion process. The kinetic expansion process qualification program provides assurance that a load carrying and leak limiting joint acceptable for safe operation has' been formed.

! 4. The performance of the OTSG/RCS considering the tubes to be plugged is satisfactory and no power limitations are required.

Tubes with defect indications below the UTS+8 elevation will be removed from service by approved plugging methods. The OTSG/RCS

! performance with these tubes plugged has been evaluated for both normal operating and emergency conditions.

i 5. Circumferential defects smaller than the threshold detectability of-ECT or less than 40% through wall are acceptable. Fracture 4 Mechanics Analysis of circumferential tube defects has been conducted. The analysis identified crack geometries which would propagat'e from mechanical loads during both normal operating 'or accident conditions. Geometries which would propagate to a double ended tube rupture during 40 years of operation or during an accident were characterized as " unstable." The results have been compared to the ECT sensitivity for various geometries of circumferential defects. This' comparison shows'that the CpUNC

~

1 100% ECT inspection of the TMI-l OTSGs .vas sensitive enough to find " unstable" defect geometries.

6 .' The examination of Reactor Coolant System'(RCS) has confirmed that the aggressive environment that caused' damage to the OTSG tubes did not damage the remainder of the reactor coolant system.

The RCS examination results provide the basis for concluding

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that there are no corroded components in service which will preclude the RCS from functioning properly and supporting safe operation of TdI-1.

7. Analysis of design basis and higher primary-to-secondary leak rates confirms that the operating and emergency procedures are technically correct. The procedures provide adequate basis for training the operators to respond to normal and emergency primary-to-secondary leakage. The procedures are being modified to improve even further operator guidelincs and handle greater than design basis accidents.

8. Steam generator testing together with long life continuing i f; -9. : r;- t e c t .- . ii'. - : -id ? cenfirmsto-r data en recair stability and the 4osence of new high velocity cracking. The

- steam generator testing will be completed with essentially zero decay heat power and poses no safety risk.

Conclusion In conclusion, THI-l can be safely returned to service once the repairs and other activities discussed in this safety evaluation report are completed. This conclusion is based on.. sound analy-tical and empirical data developed by GPU Nuclear Corporation during ~ the OTSG repair program. The scope of technical evalu-ations has been broad based and the involvement of numerous independent technical experts has been extensive throughout the TMI-1 OTSG repair program. The mcthodical, technical approach to evaluating the various aspects of the problem in order to make the best and safest decisions provides a high' degree of confidence that TMI-l steam generators can be safely operated.

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FIGullE A-1 TMI-1 Restart

. Test Program Incimling OTSG Repair -

COMPLETE OTSG OTSG FILL & HCS I flESTORE OTSG - DRIP - DUDDLE - ECT A VENT HEPAIRS TEST TEST IICS _

l12 02 A

. IICS CLEANUP 1

SEC. PLANT HEADY TO -

SUPPOHT llEATUP

• 1 i

ESTABLISit MO OTSG/FW llEATUP OTSG COOL HO1 AH FOR OTSG HOTTEST FUNCTit..JAL POWER CllEMISTRY -- _ -

DOWN TO SUPPORT tlOT TEST ANDSOAK TESTit;G PilYSICS TESTS IIEATUP I

• 3 "4 NATURAL POWER RETURN OTSG ClHCULAllON ESCALATION TO'100% EDDY Di ._ _

CURRENT TESTING TESTING

. ~ 90 DAYS TEST

• FormalManagement Review I l 49 % 7S% 100%

i e

FIGullE A-2 TMI-1 OTSG Tulse Repair Precritical Test Program ,

o COMPLETE PERFORM PERFORM . EVALUAT' FILL AND

~ ~ ~ ~

PA i S OTSG DR P OTSG BUDBLE RESTORE h0 TEST TEST RCS 2 t

(2 DAYS) (2 DAYS) (3 DAYS)

Ph CONDUCT RE-ESTABLISH ll/U RCS CONDUCT TilERM AL t

' flCS 182 02 _ RCS _ 532* F/2155 # -

OPERATIONAL SOAK p CLEANUP CllEMISTRY FOR OTSO LEAK TESTING 532*F/2155 #

130*F/300 # FOR ll/U TUDE TESTS (2 WKS) (2 WKS) (2 DAYS) (2 DAYS) (1 WKl

. . L.

RCS RCS ll/U RCS THERMAL ll/U flCS t COOLDOWN COOLDOWN

@ 60*F/Hil. 532*F/2155 # -

532 F/ 155# @ 907/HR.

d32W2 m >

FOR 2 ilflS. FOft 2 ilRS. '

~

(1 2 1111S) (11 DAYS) (12 HilS)

TilERMAL flCS MNGNT SOAK COOLDOWN TO TO flFT p -

11EVIEW y TESTING 532*F/2155 # 130*F/300 #

(11 DAYS) (12 IIRS)

APPENDIX A PREGITICAL AND POST GITICAL TEST PROGRAMS

1. INTRODU CTION l

The IdI-l restart test program has been planned to provide a deliberate, methodical, well planned verification of proper installation and performance of the steam generator joint modifications , to verify conformance with design and licensing bases. Cold and hot precritical testing have been combined with the power escalation program to create a progressive testing progrea ior cae C %J4. raa prc;ra iac.cuas :ac f a' . .cwing:

~

~'.- Verification of the adequacy of the OTSG Tube Repair Program by pre-service leak testing of individual tubes

. Verification of the adequacy of the OTSG Tube Repair Program by operational leak testing and on-line monitoring throughout the test program

. Verification of the adequacy of the repaired OTSG tube joint and tubing in service to carry loads under normal operating transient conditions.

. Verification of acceptable system readiness and plant I operation with new and modified plant operating, surveillance, emergency, and abnormal procedures

. Performance of sufficient modified system / plant steady state and transient operations to provide operator ,

training and familiarization with modified system / plant )'

response throughout a range that is likely to be experienced during the design life of the plant The scope and chronology of testing planned to meet these goals are discussed below. The test sequence is summarized in Figure A-1.

II. PRECRITICAL TESTING Both hot and cold (pre-service) testing will be performed prior to criticality.

The overall objective for the pre-service program is to demonstrate the success of the repair by providing adequate assurance of the post-repair primary to secondary structural and leak tightness integrity of the steam generators.

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The specific post-repaired features of the steam generators to be l tested include the tubing kinetic expansions, the Westinghouse roll l plug installations , and the E&W weld plug and explosive plug installations. In addition, the testing will simulate operational loading of partial through wall defects in tubes remaining in l l

service.

The sequence of cold and hot precritical tests is shown in Figure A-2. ,

A. Pre-service Test Program Tests to be conducted prior to heat up include the following:

l. Drip test, whereby the primary side is drained completely, the secondary side pressurized to 150 psig, and water leakage from tube ends observed in the lower head. This method leak tests plugs installed in the lower tubesheet, the tubing expansions, and the full length of tubing remaining in service.

2. Bubble test, whereby the primary side is drained to a few inches above the upper tubesheet, secondary side water level is lowered and pressurized to 150 psig. Kinetic tube expansions , tubing above the lowered water level, and upper tubesheet plugs are leak tested by visually observing gas bubbles in the upper head. Based on experience at similar plants, this method is expected to have a lower limit of detectability of about 0.1 gal / day per tube (leakage at normal operating pressure and temperature).

3. Baseline eddy current testing, to verify that the kinetic expansion has not changed the condition of tubing, and to provide a baseline for post-critical ECT. Precritical ECT is discussed in greater detail in Section III with the post-critical program.

B. Hot Tes ting f The initial period of hot testing will be devoted solely to OTSG testing. Testing will be designed to include transients which will stress the OTSG tubes, open up any cracks which are on the threshold of propagation or open up any undetected cracks further. Large defects, if any, will then be detected prior to critical operation by leakage monitoring. In addition, the testing sequence and subsequent cooldown will simulate most of the same conditions in which original cracking initiated. This sequence will give confidence that the failure mechanism will not reactivate. It is anticipated l that the OTSG testing sequence will take approximately one g month.

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When the steam generator hot functional test sequence is complete, a management review of the results will be l conducted. If the results are satisfactory, the plant will l proceed with the normal precritical hot functional program, I and subsequently with critical operation.

l l The following tests will be performed as part of the OTSG hot functional test sequence: ,

1. Normal Heatup The RCS temperature and pressure will be raised to 532*F and 2155# in accordance with normal operating procedure.

2. Operational leak Test This test is required by technical specifications whenever 4 work has been performed in the reactor coolant system. l The pressure in the primary system will be raised to approximately 2285#, creating a differential pressure  :

between the primary and secondary of approximately 1400# i (maximum normal operating differential pressure). This is i expected to be the maximum differential pressure '

experienced by the repaired tubes.

3. First Thermal Soak l Conditions will te allowed to equilibrate at 532*F and 2155# for approximately one week, to provide baseline leakage data and to allow monitor of leakage for trends.

4. Normal Cooldown Transient i A controlled cooldown will be conducted according to normal procedure, at approximately 60*F/hr for approxi-mately three hours to 350*F. Tube to shell delta T will j be monitored to determine the stresses placed on the tube. leakage will be monitored throughout the transient.

Second Thermal Soak I 5.

The RCS temperature and pressure will be returned to 532*F and 2155#, and held there for eleven days. Leakage data will be obtained for comparison with the earlier thermal }

soak, and to monitor for developing trends. l

6. Accelerated Cooldown A controlled cooldown using emergency feedwater will be l conducted at close to the maximum rate permitted by 1

- 106 -

6

---,- c ,,-- - - ,

l technical specifications , at approximately 90*F/hr for (

approximately two hours. This transient is expected to l apply greater loads to the repaired tubes than the earlier cooldown. Iube to shell delta T will be monitored to determine stresses. leakage will be monitored throughout the transient. ,

f

7. Third Thermal Soak t The RCS temperature and pressure wil'1 be returned to 532*F and 21550, and held there for approximately eleven days. ,

leakage data will be obtained for comparison with the earlier thermal soaks, and to monitor for trending.

3. Normal Plant Cooldown -

The plant will be cooled down to 130*F at 90*/hr or the maximum rate possible using normal feedwater if 90*F/hr is not attainable.. The plant will be maintained at 300#,

130*F pending management review of the OTSG hot functional results.

9. Flow Rate Testing -

Because tubes will be plugged during the repair process, the RCS flow rate must be measured af ter repair to verify compliance with technical specification. This test will be performed when the plant is at normal operating temperature and pressure. -

III. POST-CIITICAL PLANT TESTING The deliberate, methodical approach to testing will be maintained throughout the power ascension program. The normal program has been lengthened to permit ample time for leakage monitoring and trending, as well as'for familiarization with plant performance following the modification. After the power escalation program is complete, and again at the next refueling outage, special inservice inspection programs will be conducted to look for the effects of operation af ter the repair on tubing and components.

A. Power Escalation Testing Power escalation testing is expected to serve two purposes in testing the steam generators. First, the slow progression from power level to power level will permit monitoring of possibly changing plant conditions such as leakage. Se cond , ,

several of the tests already planned for start-up testing will apply loads to the steam generator tubes. Leakage monitoring before and after the transients will provide information on the condition of joints and tubing.

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The power escalation prograc is discussed chronologically below. Transient tests of interest are noted for each power it. vel .

1. Lower Power Testing Following hot functional testing and initial criticality, the normal plant zero power test will be conducted. After this approximately one week program, low power natural circulation testing will be performed.

This test verifies the tuning of the Integrated Control System (ICS) to maintain preset OTSG levels under loss of ,

main 'eedvater snd natural circulation conditions. It  !

also verifies proper response of cne DEW system as well as

~  !

the establishment and maintenance of natural circulation under varying conditions. Testing will be conducted at

• approximately 3% of rated thermal power to simulate the decay heat load that would correspond to significant core burnup. EFW initiation is expected to stress the OTSG tubes. This test will also verify that plugged tubes have  :

no effect on establishing natural circulation flow. l t

A management review will be conducted follcwing natural l circulation testing. Satisfactory OTSC and plant j performance will be necessary to increase power. I

2. Operation at less Than 50% Power .

Power escalation testing will be conducted for several days each at 15%, 25%, and 40-48% power. The 40-48%

plateau testing will include a loss of feedwater test. At a power level of approximately 40-48%, both main feedwater ,

pumps will be tripped. All three emergency feedwater i pumps will start automatically and OTSG level will be  !

controlled at 30 inches +2 in. - 10 in. by emergency feed-water. The use of EFW will cool and stress the OISG tubes.

t The RCS Overcooling Control test will demonstrate that the l control room operator can properly throttle EFW flow to prevent overcooling of the RCS following a loss of RCP's with OTSG 1evel initially at 30" on the startup range. {

The effects of this transient and of operation to date l will be monitored during a one month soak at approximately  !

48% power. The power level was selected as the minimum .

permitting two main feed pump operation. Some operator training will also be conducted during the soak. Prior to -

increasing power, another management review will be held ,

to evaluate test results and plant performance during the

• soak.

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l l 3. Power Escalation to 100% Power I Testing at 75* and 100% power will conclude the power escalation program. The 75% plateau will include approximately five days of testing followed by another one month soak to observe plant performance. Power will then be increased to 100% power for approximately one week of I

testing. Testing of interest at this plateau include the 100% turbine-generator trip.

i' A management review of plant performance will then be conducted before the plant procedes with normal power i

operation. l I

l E. Edcy Current Ies cing

~ Either 90 calendar days afte.r reaching full power, or 120

• calendar days af ter exceeding 50% power, the plant will be l shutdown for the performance *of eddy current testing. Test j results will be compared with a baseline taken prior to restart to verify the lack of defect propagation during normal operation. The baseline, 90 day, and next refueling ECT examinations are discussed in detail in Reference 56 and summarized in Table A-1. Testing listed for the' preservice baseline will be performed after repairs are complete to s

provide evidence that no changes have occurred since the 1982 100% record inspection. Any new or changed ECT indications

< found in the three inspections will be evaluated. If evaluation shows they are unacceptable, they will be treated as new defects with subsequent actions taken as required by Technical Specifications.

a 1

• 109 -

Table A-1 Post Repair ECT Inspection Summary 9 I

90 F.P. Days Cycle 6 Inspection Refueling Outage Remarks SCOPE Pre-Service Inspection 0.540" S.D.ll.G. Repeated Repeated 1(a) All tubes 40% (i) i T.W. below the Full Length qual. length (ii) 8 x 1 to confirm S.D.

in both OTSG's Ind. & circumferential extent Repeated Repeated *Use ECT technique proven 1(b) All adjacent tubes

• Wear baseline exam. in by laboratory testing to to'10 selected area of interest. (Using be adequate for wear exam.

plugged unsta- ECT probe demonstrated bilized tubes adequate for wear examina- '

with defect tion in area near defect.)

in 15th, 10th &

Ist spans (10/Ea.

OTSG)

I Repeated Rep'eated *Use ECT technique proven C 1(c) All adjacent tubes.* Examine for 0.D. wear by laboratory testing to

'" baseline in the 16th span to 10 selected be adequate for wear exam.

' plugged unsta, (Using ECT probe demon-

. bilized tubes strated adequate for per each- ,

wear examination in area OTSG in the near defect.)

periphecy 8 x 1 absolute for 6" Q.L. Repeated Repeated 1(d) All. tubes had new indications ,

in the.6" qual.

length j , .__

0.540" S.D. high gain in- Repeated Repeated

,f l(e) 50 tubes"inLt:.e high . plugging spection for full length

!. density area

,- per each OTSG

i Table A-1 (Cont'd)

Post Repair ECT Inspection' Summary 9 i

. 90 F.P. Days Cycle 6 Pre-Service Inspection Inspection Refueling Outage- Remarks SCOPE 1(f) 3% of tubes in 8 x 1 examination in UTS Repeated THD s

addition to 1(d) ,

in each OTSG from top of 6" qual.

length to lower surface of UTS' Repeated Repeated *Use ECT technique proven 1(g) All adjacent tubes

• Wear baseline examination by laboratory testing to to 5' plugged at same elevation as defect be adequate for wear exam.

tubes per each indication in the plugged

• OTSC with 3V tube indications in lower part of OTSG's s

-0.540" S.D. high gain Repeated Repeated

[2 3% of tubes re-

"* maining in full length inspection 8 service per each See Note 1.

0TSG in addition -

.to above 1(a), ,

' (b), (c), (d),

(e) & (g)

No t. e 1: By doing pre-service examination in ab,ove categories 1(a) & 1(e), if'no new defere or no indication of defect growth from previous 0.540" high gain data, such data obtained in 1982 may be cos. ;idered representing condi-tions after expansion. No need to perform item (2) for the preservice baseline.

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APPENDIX B Responses to NRC Questions on TR-008

1. Clarify your position on removal of sulf ur from oxide films in the RCS. If will you intend to perform a sulfur removal process,Ifprovide inf ormation sulf ur removal is notwhich planned, demonstrate its safety and effectiveness.

provide information to demonstrate that future corrosion will not occur as a c:-satu res of extde-tourd sulfur,

-Resoonse: -

DPUN plans to remove sul f ur f rom oxide flims in the RCS using a hydrogen peroxide chemical cleaning process. A separate saf ety evaluation on chemical cleaning (Topical Report 010) has been supplled to the NRC.

2. On page 10, (e) you state that reduced sulfur is directly responsible for the cracking mechanism. On page 7, five sources of sul fur intrusion are listed, three of which were sodium thiosul f ate. What is the most probable source of sulur contamination that resulted in the observed corrosion? What specific steps have been taken to prevent re-introduction of sulfur? Make available for review those administrative procedures which addrus prevention of the impurity ingress to the RCS.

Response

As stated on page 8, sodlum thiosulf ate at levels of 4-5 ppm is considered to be most likely contaminant. Injection of leakage from the sodium thicsul f ate tank during reacter building spray system testing in May 1981 is the most probable source of the contamination.

The f ollowing steps have been taken to prevent reintroduction of sulfur or to identify sulfur if it were reintroduced.

a. The largest potential source for sulfur Introduction, the sodium thiosulf ate tank, has been drained and removed f rom service by cutting and blanking the supply line f rom the tank.

b. The breakers for chemical addltlon pumps CA-P-2, 3 and 4 are on the Locked Valve and Component List (Operating Procedure 1104-478).

~

'c. An lon ' chromatograph has been purchased and procedures are being implemented for sul f ate analysis. ,

d. Bulk Chemical Specifications are being written to control ingress of contamination. Copies of the administrative procedures to control chemical contamination will be in place and available for review prior to restart.

3. On, page 18 It.Is stated that cracking found in the waste gas system is It is our understanding that sul f ur unrelated to the OTSG f ailure mechanism.

4 9

e

If sulfur is the was defined as the corrosive species In the waste gas system.

cerrosive species in the waste gas system, why is It not related to the OTSG f ai l ure mechani sm? Additionally, what are the results from the inspections of supperting systems (LER 82-02).

Resocnse:

Failure of piping in the waste gas system has been characterized as lGSCC in the Analyses weld heat-af f ected zones (HAZ) at the 304SS socket weld connections.

of the corrosion products have confirmed that the HAZ's are sensitized and that iron pyrite.

the prima y contaminant is sulfur, predominantly in the form of Pl? ting and general corrosion have al so been identified in the PORVs put in  :

• -- *:2 *- *r- r-" un 1070 erd Julv 1081 Sulfur has been found in both valves. l These ecmponents, l i sa ine steem generarces, bonTu ca. , ;m:c prc.=2,

-and theref ore tne transport 6f sulfur to the corrosion site is not via an j aqueous medium. It can be postulated, theref ore, that a gaseous transport nfechanism was operative and corrosion was not the result of direct contact tsith thlosulf ste contaminated RCS coolant as was the case with the steam generator

tuces. It is logical to assume, hcwever, that thiosulfate did play a role in the

) cerrosi:n by providing a potential source of the production of sulfur bearing gases.

Further work to identify gaseous transport mechanism for, sulfur is underway and should provide insight to a possible corrosion scenario for the waste gas system and PORVs. When this work is completed, GPUN will then be better able to assess

' the relationships among the f ailure locations.

4. Provide informatien on the status of the RB spray system sodium thiosulf If not, ate tank (page 27). Has the tank been physically removed from the system?

wnat measures have been taken to ensure that all sodium thiosufate has been removec from the tank and its connecting lines.

Res:ense:

Fiping which connected the sodium thiosulf ate tank with the R3 Spray System has been cut and blanked.

5. On page 24 reference is made to corrosion test programs which In the event are in progress and will lead the actual OTSG by a minimum of 4 months.

these tests indicate progression or initiation of corrosion; how will this inf ormation be f actored into plant operations. Provide a schedule for completten of these tests and when the results will be supplied to the NRC.

Response

The long term corrosion test program will undcubtedly lead plant operation by a minimum of six months.

Should corrosion damage be observed on the tube samples a

during this test program, a more than adequate' time margin exists for evaluating this damage prior. to the steam generator tubes reaching the same operating time.

if the evaluation of th? 03 mage shows it to be relevant to plant experience,

corrective actions will be bken. Tests results will be made available to the if results' project manager and the resident inspector on a quarterly basis, indicare severe or rapidly propagating corrosion, notification will be given in a more timely manner. .

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In the event the ccercslen observed is severe and/or rapidly propagating, the plant woulc be shut down until such a time that Evidence the corrosten of minorproblem attack such can be as i

assessed and appropriate actions defined. IGA would be trended, potentially leading to plan pitting er shallow Prior to this, however, the need for enemistry or for additional NDE.

operational changes would be evaluated and implemented as necessary.

In either event tne long term corrosion test program will be an integral part of the decision-making cn plant operation with data frcm this program being updated every 66 days via eddy current examination of the tube specimens and metallographic examination of C-rings.

Sz.  ;  : --- 20

ls--

GFUt. aiisi prov ice ecp i es e r a .;.c.rur , , ; . :,.r; .: tif severe and/or rapicly propagation

_ manager and _to the resident inspector, in a more corrosion is cbserved in the test specimens, the NRC will be informed expedit;ous manner.

in

6. On page 27 it is stated that sul f ate analysis will be perf ormed monthly the RCS. .What is the justification for a monthly analysis en a species which What wliI be the frequency of testing fr.r sul fur can be so potential!y harmful?

and ph-concuctivity balance during all pre-criticial testing periods when one or r.cre reacter coolant pumps are running?

Resconse:

Subsequent to the submittal of Topical Report 008, Rev. 1 the Chemistry Speelfication was revised and sulf ate analysis will be performed daily on a RCS sample. Tepical Report 008, Rev. 2 reflects this change.

During precritical testing periods, sulfur analysis will be performed daily and pH conductivity balances will be perfccmed five (5) times per week.

7. It is our understanding that a 3% ECT (plus special interest tubes) will be conducted subsequent to repairs. Additicnally, on page 65 it is stated that a second ECT will be performed following 90 days of full peser operation. What are the criteria for selecting the inspection pattern and 'the special interest tubes?

It is our position that the inspection pattern should utill:e both in the the 8 x 1 span free and

.540 probes and include all tubes with indications (10 or OD)

(below US + 8) plus a statistically significant sampling Further,of unplugged the post peripheral critical ECT tutes which are adjacent to block plugged zones.

should be conducted either 90 days af ter reaching full power operation or 120

, days af ter exceeding 50% power, whichever comes first.

Response: .

The criteria for tube selection in the baseline ECT, 90 day testing, and testing at the first ref ueling are discussed in Appendix A, Section 11.B of Topical Report 003, Rev. 2.

8. Subsequent to initial expansion a number (-12) of new Adaress indications were the effect reported within the 6-inch qualification zone on some tubes.

r , , .- -~ ry.. ,, - - . . .e.-----.-r

- - , - - - . , , , --.y -,-w -

l l

I current signal was noted and no ducille growth was found during metallurgical evaluation of these samples. These results are consistent with crack groath studies done earlier which examined expanded cracks metallographically, but not with eddy current, and found no ductile tearing.

Concurrently, in order to f urther characteri ze these new eddy current indications, f iberscope examinations were conducted on 4 tubes in OTSG B and 2 tubes in OTSG A. The fiberscope examinations concentrated on the new eddy c urr e nt indications, but also incl uded other locations within thoce tubes if visual indications of interest were noted. Table 3 summarizes the results of The visual inspection of these four tubes. An estimate of the circumferential and axial size of the visual indication seen is also provided, based on video Tape

?cc- . *s 3 esult 9 "e di m c m s m inrlm. i' ns cercluded Tkr #cr a c? Tne 6 Tuces examinec Tne nea eccy curren? incicaricas resui? Trem siTner

_ small pits _or. mechanical s c'r a te n e s . For the remaning 2 tubes, no visible indications were found. The mechanical scratches may have been caused by the

• wire brush used to clean tubes selected for the in-process testing immediately af ter expansion, to allow the insertion of the eddy current probe.

It was then undertaken to check the correlation of the ECT sensitivity curves with the indcations visible via the fiberscope. These indication sizes were compared with eddy current sensitivity curves. developed used ID notch specimens and samples of laboratory-induced IGSAC. Curve development is discussed in greater detail in Section IX.B of Topical Report 008, Rev. 2 . Various curves were developed for the .540" dif ferential and the 8x1 abosolute probes within the tubesheet and in the freespan. The sensitivity curves are shown in Figure 1.

It was determined that background noise in the tubesheet resulted in a reduction fo sensitivity f or the .540" probe, but not for the 8xt. The pit size estimates shown in Table 3 are at or below the threshold for .540" probe detectabillity in the tubesheet. They are in the lower range of detectability of the 8x1 probe.

It remained to ascertain the impact of small pits or cracks below ECT sensitivity thresholds within the expanded zone considering both load carrying and leak tightness.Section IX of Topical Report 008, Rev. 2 documents extensive werk cone to eval uate the maximum size crack which can- be left in service for the lif e of the plant and not cause tube failure under normal or accident tube loadings. Acceptable circumf erential extent vs. throughwall depth curves for various loading and analysis conditions in the free span are shown in Figure IX.3 of Topical Report 008, Rev. 2. The pits / indications found in the area of the joint are smaller than the crack size leading to f ailure by any mechanical means in the free span. These curves are conservative for indicatiens in the joint since loads imposed on the tubes are transmitted to the tubesheet in the crea of the expansion. Loads on tubing in the area of the defects will be equal to or I ss than those analyzed for the freespan. Leakage through any small def ects which are 100% throughwall is also expected to be less than or equal to

' 'similar cracks in the freespan. Unacceptable leakage will be identified during precritical testing and the tube will be either plugged or repaired. For these reasons, it is concluded that small pits or undetected crac,ks in the quellf ied area do not af fect the reliability of the new joint, it is expected that additional indications will be identified during the baseline 8x1 eddy current examination of the expanded region to be conducted following kinetic expansion. These indications will be re-examined during the 90-day'ECT and evaluated to confirm the conclusion that they are acceptable.

of these Indications on reliability of the qualification zone. Assuming additional Indications or defects are found in the qualification zone during the i

l l

post repair ECT, how will they be handled?

Rescense:

Eddy current examination using the absolute (8x1) probe was conducted for the first lot of kinetically expanded tubes in both steam generators. The scope of The eddy this examination included 151 tubes in OTSG B and 2B4 tubes in OTSG A.

current data was analyzed from the top of the 6" qualification length for kinetic expansion down through the bottom of the upper tubesheet. As a result l cf this data evaluation, 9 tubes in OTSG B and 6 tubes in OTSG A were reported as having indications which had not previously been detected by the .540" 00

. . g :.- g a s t; siac, : c ci i tsrut. : ,;r : : w .; u r: t ha.  :

generators. The 8x1 absokute probe hac been chosen f or inis in-process

-menitoring 1n the newly expanded area because the coining process of the

. expansion created so much background noise that the .540" standard dif ferential probe was not useful following kinetic expansion.

The 8x1 absolute probe provides 360' coverage. A judgment concerning defect arc length can be made depending on how many co!!s of the 8x1 probe detect an ,

Indication.- 1.aboratcry testing has shown that a 1 coil Indication can have an )

are length of 5' to 40, a 2-col i Indication has an are length up to 85', and a i 3 coil indication has an are length up to 130*. Althougn the 8x1 absolute probe can be used to quantify the circumferential extent of a particular indication, it cannot be used to accurately determine the percent thru-wall of the Indication.

The first post expansion eddy current examination was conducted in 151 tubes of OTSG B. Table 1 documents the characteristics of the eddy current signal from those 9 Indications found which had not previously been seen by the 540" .

standard dif f erential probe. No previous 8x1 data existed for the tubes within which the defect Indications were found, and therefore, it could not be determined whether the Indications existed prior to expansion or had been caused by kinetic expansion. In an ef f ort to better understand this issue, an 8x1 absolute probe baseline examination was conducted on the 284 tubes in the first loi of kinetic expansion in OTSG A prior to expasion.' As a result of this examination, three Indications were Identi f ied which had not previousl y been detected by .540" di f f erential probe. Following kinetic expansion, these tubes were again examined and evaluated from the top of the 6" Icng qualification zone through the bottom of the upper tubesheet. During this second examination, three additional indications were reported, shown by an

• on Table 2. Table 2 summarizes the location and signal charateristics of the Indications found in OTSG A.

" ~ Investigations were made to consider several possible explanattor.s for the new indications. Additional laboratory testing was undertaken to determine whether or not the kinetic expansion process was cat, sing. small cracks to open slightly, thus increasing their signal voltage. It was postulated that Indications which were previously below the threshold sensitivity might become detectable subsequent to kinetic expansion. The testing involved placing laboratory-induced intergranular cracks and TMl-1 tube samples with cracks-Inside mockup tubesheets and expanding over them. 8x1 examinations were conducted price to and af ter kinetic expansion. No significant change in eddy 9

6

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

i l

OTSG B OTSG Post-Expansion Eddy Current Absolute (8x1) Res.ults II D.;;:xnf 151 tubes kinetically expanded and E/C examined. Nine (9) tubes were reported by 8x1 as having indications not seen by

.540 S.D.

Results -

• ABSOLUTE NOISE LEVEL S.D.

Row / Tube Location Coil Volts Distortion 400 Base Mix 4-19 US+11 1 .5 1 2V .6V 4-30 U S +12.9 2 2 2 -

3-27 U S + 9.4 3 6 2 2V .6V 3-25 US + 10.7 1 1 1 2V .6V 3-24 U S + 12.6 2 2 2 2V .6V 3-21 US+10 1 1 1 2V .6V 2-21 US+ 13.1 1 1 1 2V .6V

2:22 US + 13.2 4 1 (MULTIPLE) 2 1.8V .5V

'2-25 US+07 1 1 1 1.5V .5V

• New Kinetic Transition Table 1 6

l .

\

l 1

OTSG A OTSG Post-Expansion Eddy Current Absolute (8x1) Results 2 2 :h;.~ : x.7 d

~

284 tubes kinetically expanded and E/C examined before and after expansion. Six (6) tubes were reported by 8x1 as having indications not seen by .540 S.D.

Results - Absolute - - Level of Noise S.D. -

Row /Tuoe Location Coil Volts Distortion -

400 Base Mix AFTER EXPANSION ,

2-12 Not expanded .8V .4V 6-43 US+4 1 1 1 .8V .2V 7-54 US+1 TO 1 1 (MULTIPLE) 1 .6V .3V U S + 10.7 .

4-4 US+9.1 1 <1 1 2V 1V 4-32 US + 11.9 1 .5 1 1.8V IV 2-7 U S + 6.3 1 .5 1 1.2V .4V BEFORE EXPANSION ,

• 2-12 US-3 TO 1 <1 (MULTIPLE) 1 US+7 3 < .5 1

• S-43 US+4 1 <1 1

'7-54 US-8 TO 1 <1 (MULTIPLE) 1 US+13

• 8x1 Reported 3 tubes as having indications before expansion Table 2 l

i i

l l

l

i l

1

. l OTSG Post-Expansion Eddy Current Fiberscope Examination Summary VISUAL SIZE (in.) ECT OTSG ROW _ .. TUBE INDICATION LOCATION CIRC AXIAL COILS VOLTS B 3 24 Line of Pits U S'+ 13 .01 .02 2 2 B '2 22 Area of Pits US+13 .01 .06 4 2 B 3 27 Area of Pits US+10 .01- .03 3 6 B 2 25 Scratch US+7 >.05 - 1 1 A 4 32 No visible -

U S + 11.9 - -

1 <1 indications A 2 7 No visible U S + 6.3 - -

1 <1 indications Table 3 S

l

s FIGURE 1 s

I METALLURGIC AL CONFlRM ATION , ,,

OF ECT SENSITIVITY FOR IGSAC 360* 1.7 5" g-- x yg.. ...y. Metallurgical

" a~ ~ : ':^ Confirmation

&i- i ..

+:-

z: . :.:

Tubes pulled

a

nil!

35: with IGS AC 300* 1.46" E _h r..

. .ij. .:.i.-

pi- O Laboratorv inducea

lis IGSAC detected

. : ~: 15:

E 'wY i!!!!  !!!yii O Laboratory induced S i-Miii. IGSAC not detected

• 5 1.17" 240"  !.!: -

.i:J..ii.i

.'i_:i :n

.c

1;;;;;:

- i;i:!

-- Tested boundarles of E

E/C detection

• 1.0"  ::jjij o  !.7. !

z.:s E M!E " Projected

• 875" "" - --

180* -

f, E/C"f"ie"ld of ,

g g 4 ..... , jijh= boundaries of

!!detectabilit.yj; :i:i:i:i  :-

E/C detection i..:: _i

. = -

i!!!.jj Q . W.MM. . . E. .

120' .58" hdN!!!!

m+%.i:!

!!!d, 2

. ..--r

.~d:

'l. .

Undefined -i  !!!h .540 J' gain 60 fill factor 94%

boundar.nes Nes-9!K13. r:!

• i- . '

s.: . .... ....:.:. .

.:</ ~ .<.

sc .-

is. a 1

..;. f ' ". . .-.....w i:!('J1.!i .:.

GO' .30" ~

r i:!fytis.  :.:.;.:.

C*c~::i:q,!:i. ..

':::h::it:::..

"i . :p;;;. .

""w

. , :ib.. . Ji:i: < i:l.e.:.!:L.y Test standards for .187" 4:i:ii.:i:

, -";.::. .r.ii E/C qualification .100" . . ..:.

Notch width (.004") .000" ^ \. ......... .......

, , /.11 i i i i g i wpwis 10 20 30 40 50 GO 7 80 90 100

.540

.540 Below dTS  % Through Wall in UTS

9. On page 63 it is stated that flow induced vibration an inermal act ing will not cause crack propagation. Provide more detailed inf ore..ation to apport that j statoment . Specifically, address the concerns raised in Dr. McDont:1's letter of October 23,1982 (provided to you earlier).

Resoonse:

In Section I X.B of Topical Report 008, Rev. 2 sucinarize-. evaluations of crack propagation. Greater detail is available in GPUN TDR #388, lube Stress Report, j t Rev. I which has been supplied to the NRC. Much of the . ark reported in thess .

l documents has been completed since Dr. Mcdonald's October 23, 1982 letter, and n-- +: add m M s :: n "s.

10. In the tube plugging and stabilization discussion (page 50) there doesn't

_ appea- to be a reference to tubes within the 10th span whlen is a suspected high

. cross flow area. What is the plan for t'ubes with indications or defects in the i 10th span? -

Resoonse:

l' The 10th span is a region with some crossflow, but considurably less than the 4 high crossflow of the 16th span. Plans for plugging and sf abilization of the'

10th span and f or other regions of the OTSG are discussea in Section Vll.C of sopical Report 008, Rev. 2.

l

11. Figure IX-4 Identified the limit of detectability for tube leakage at .03%

1 FF as. 46 gph. This figure is cited many times in the SER es a basis for being able to detect propagating cracks during precritical test;og. Clarify if tnese j limits of detectability apply. for pre-critclal testing where no noble gases or lodines are present. Identify what the limit of cetectability.is for

precritical testing if it is not .46 gph.

Resoonse:

Ine. 48 gph limit of detectability applies to the precritical testing as well.

i Although this limit was originally set assuming the 7resence of noble gases and i lodines, this limit will still apply in their absence by employing a sultaoly j long soak time to allow boron concentration to buildup in the steam generator.  ;

i i 12. What are the adminsitrative limits for primary to soccodary leakage (page

! 74 )? What is the basis of establishing these limits? How co these leakage limits fit into leak before break?

i

Response

The bases for establishing administrative limits on leakage are su:rmarized in >

Topical Report 008, Rev. 2. Chapter X . Final'adminsitrative limits can De  :

i= made available at a later date.  !

, 13. Block plugging of tubes. will result in moisture carryover and increase the

erosion-corrosion potentlai for peripheral tubes (#7 above addresses ECT of.

l these tubes). Additionally, moisture carryover will increase the potential for. .

erosion of downstream components and piping. Provide an ISI program to monitor i g.

ya p , , ~ . ,

.-w~-.,.y. r -.w.. 4. n -,,w aw--, . ,7-w. , ,-,

potential erosion due to moisture carryover from the OTSG.

Response

A summary of the potential for moisture carryover erosion of tubes and piping is included in Section Vill .D of Topical Report 008, Rev. 2. ECT o f peripheral tubes is descrIDed in Appendix A, Section ll.B, and ISI of the steen system is summarized in Appendix A,Section II .C.

14 Provide single and multiple steam generator tube rupture guidelines for staf f review when they are available. (page 74)

%:mn .

_ Tube rupture. guidelines hav'e been sumarized in Topical heport 005, Rev. 2, in Section X. B. A more complete discussion will be availabl.a at a later date.

15. Provide additional information on the calculations and test dats (page 44) which are used to demonstrate that the instantaneous stresses f rom tne kinetic expansion. process are structurally acceptable.

Response

Additional information on the calculations was included in tne Kinetic Expansion Technical Report, GPUN-TDR-007, dated November 1982, which has been sJpp l ied to the NRC.

16. Chapter 7, Table 1 of your "TMI-1 Steam Generator Repair Safety Evaluation", you provided a breakdown of estimated men-rem doses for OTSG repairs from crevice drying through cleanup. The total estimated dos 3 for OTSG repairs, based on this table was 268 man-rems (327 man-rns if remote cleaning was not possible) . In the December 10, 1982 letter from P. Clark, GPU to D.

Eisenhut, NRC, you stated that 322 man-rems had resulted frcm repair activities as of November 30, 1982 with an additional estimated 700-80] man-rems envisioned to comp lete the OTSG repairs. Describe, in detall, why your current man-rem estimated for the OTSG repair is three to four times your originai estimate of 268 man-rems.

Resconse:

The exposure estimate upon which Table 1, in Chapter 7 of the TMI-1 Steam Generator Repair Safety Evaluation is based was calculated prior to the start of.

the kinetic expansion repair. The estimate included only those items in the steam generator program identi fied as pa. t of the kinetic expansion repair.

Other portions of the program such as investigation of tha damage and plugging '

were not included.

The December 10, 1982 letter f rom P. R Clar'k to D. Eisenhut included all j i

aspects of steam generator work not just the kinetic expansion. The following table shows the steam generator activities that were not included in the kinetic expansion review. The reasons for these activities are discussed in TR-0CS, Rev. 2. Approximately one half of the exposure estimate is associated witn l l

t these activities. Some tasks have been better def ined since the Cecember 10 l letter, but the total has not changed'significantly. The following table shows

~

t

Exposure Estimate Comparisons Table 1 Current Task Estimate Estimate

1. .RCS Inspection * '

12(A)

2. Pre-Repair Tube Work (sampling / stab / plugging)

• 120(A)

3. Pre-Reoair Testing (bubble /

zisarscopsa

. i.v 4 Eddy Current Testing ,

• 35(A)

. 5. Kinetic _ Expansion

e. Pre Expansion activities (precoat, crevice dry) 30 "

16(A)

b. First expansion 45 16B(A)

c. First pass insert removal 50 132(A)

d. Second expansion 35 167(A)

e. Second pass insert / debris removal 55 _75(A)

6. Cleaning

a. Fl ush 51 30

b. Soak

• 30 .

7. End Milling

• 125(A)

8. Plugging -

e. Plugging & Stabilization

• 235

b. W rolled plugs

• 75

9. Post Repair Testing

a. Bubole test

• 5

b. Drip test

• 5

c. Eddy current test

• 10

10. Post-Repale inspection

a. Tube free path

• 40 6, Final close out inspection 2 5-10 268 1260 - 1295

• Not included in Table 1 Estimate.

(A) Actual Exposure.

17. Provide a breakdown by job function of the currently estimated man-rem coses f or the OTSG repair (similar to Table 1 In Chapter 7 of your "TMI-1 Steam Generator Repair Safety Evaluation"). Include in' this table; 1) your original does estimates for each job; 2) the actual doses recorded to date f or each job,

-3) the -estimated cbses required for completion of each job. You should also outline the bases f or inclusion of any new job f unctions which'were not listed in the original dose estimate table.

See .respense to item 16' above.

-_h--___________._____

current estimates.

As can be seen, items 5, 6 and 10b on the table represent all items in Table 1 of the Kinetic Expansion saf ety eval uation. For these items,'the total has increesed from 266 to 623-628 man-rem. This increase is largely due to the equipment dif ficulties described in response to Q.18.

O e

• an -.

O e

4 4

4 .

4 i

m l

l l

t I

I j .

,n , , - en- e , -n. -.w , -, s- , . . ,

wwm.,. 4

I l

'3. Describe the ALARA features inccrporated during the OTSG repair program to control occupational doses. Describe any problem areas encountered (such as equipment breakcown or mal functlen) during the OTSG rspair which resulted in nigher than planned personnel deses, and hcw these problems were resolved.

-esconse:

I' detailed descriptior cf p l anning activities and descriptions of each individual work event are available on site as separate reports. All

replanning and preparaTica activities were performed so as to follow the

uidelines set forth in Regulatcry Guide 8.8. A summary of major activities is

rovided below.

A. Fiet c imp.emenTarice. f:r me :c,T.c3 .si neri c e, pr.as.cc. ra c i e pregc cm .n been preplanned and i r. a l.1 cases procedures have been validated by mockup training and cress rehearsal . Al so, where possible, .fleid tests for major job functions have been performed in a steam generator at B&W's manuf acturing works at Mt. Vernon, inciana. At these, f acilities, equipment and tooling has been tested and work techniques practiced for the following:

(1) Kinetic expansien device testing and installation training.

(2) Debris removal equipment testing and. procedure development.

(3) Fl ush system testing.

(4 ) Tube free path vert fIcation testing.

During these tests, ful! cress r.cckup training gwas conducted, tooling concepts evaluated and verifiec, and remote equipment operation critiqued and validated. While it is nct pcssible to quantif y the man-rem saved by this training / testing, the ex;osure savings is thought to be significant. Further mockup training anc ev al uation was also performed in the mockup training f acilities available on site. This ensured that each worker received training in the job he was to perform prior to actual steam generator entry. The training / testing also allcwed the evaluation of the use of temporary shielding to establish the optimu: ccnfigurations for use in the generator and enable the evaluation and control of potential air born contamination problems.

B. Af ter beginning process field implementation, several problem creas were

- discovered wnich raised actual exposures above estimates. Specifically in the area of equipment malfuncticn the following were Identified and changes made where possible to limit exposure.

(1) During tne performance of the expansion, there were problems maintaining the video camera in operating condition. A short study analyzed equipment cown time and concluded it was more man-rem ef ficient to spend the extra time prior to and af t.er ,each blast in moving the camera into and out of the generator than it was to perform with the camera in generator repairs. This recommendation was acted on.

! (2) . Debris Removal Device: There were several problems associated with l Initially making the cebris removal tool operational and reliable. Much of l the exposure received for this task segment is directly associated with y- -p -- = ,- ,t7 , - . = -e-a-wrw, -----r, v.-= - --,-e , n- - ---,..w g--, y 3 c -

y--

corrective maintenance required to keep the equipment cperational. All maintenance entries were monitored and documentec and the perfccmance optimized through the use of briefings and training. Through'the use of tight monitcring controls, exposure f or the perf ormance . of corrective maintenance was held to a minimum.

The lessons learned about equipment rel iabil ity were inecrporated into total equipment redesign. The redesi gned equipment was used for second pass debris removal with a marked increase in equipment reliability and per f ormance . The exposure received during first pass debris removal was 132 manrem compared to 75.2 manrem f or second pass debris removal .

(3) Misfire Pete: Durinq kinetic expansion, the rare of expansien 'inserts ~ ~:

was ccasi carras t m;w in, n yn := h ...: t- - --. - - -:

misfires were caused by p,roduction problems in the deTenation cevice, wnica

- were corrected, and by seepage of the liquid precoat into the inserts. The precoat insulated the detonating cord in the insert frcm the remainder of the detonation device. Each misfire required identification of the tube, removal of the Insert, replacement arid redetonation, thus adding to total exposure. After the precoat problem was identified, it was necessary to change the preccat - expansion procedure. The original procedure had an Individual enter the generator, remove insert debris, insert the next row, exit. Precoating was then done remotel y, and the tub _es were expanded. with After altering the procedure, two entry steps This wereincreased necessary, exposure precoating done prior to inserting the candles.

resulting fran this procedure change was unavoldable since the misfire rate was technically unacceptable.

(4) 141sfire Jump Out: When the first kinetic expansion was performed, the detonating cords attached to the inserts whipped in response to the force of the detonations. During the first pass, the whipping action pulled some inserts which had misfired free of the GTSG tube, adding to exposure. The unexpanded tube could only be identified by hand measurements of the tube by workers in the OTSG. This activity was pointless after the first expansion, and thus eliminated in the second expansion. Other actions were taken to prevent jumpers, including tne use of-hotd-down devices,

- additional debris removal to veri f y that jump-out had not occurred, and additional care in moving about the head area. These changes resulted in some increase in the time spent in the generator for the second expansion.

(5) Debris Renoval: Debris that had been evaluated in the qualification program was found to be less manageable in tne field. Detonated inserts broke apart during expansion, scattering pieces throughout the generator and forcing other pieces down in the tubes, in orcer to work in the confined head area, workers had to continuously take additional time to pick up p ieces. These pieces left in the tube were also more dif ficult to remove than the intact inserts anticipated.

The f acters described above resulted in the idinetic expansion exposure increase from 266 man-rem to 541 man-rem.

19. In Section XI, " Environmental impacts", of your December 10, 1982 letter, you provide a table of projected doses to an Individual frcm anticipated primary to secondary leaks. However, this section does not detail the specific 1

l .

.s --

-,.-.+-e . , , . ,% ,r.w--. $ w-m-ve- m -m-..

TABLE 7

!!YPOTHUTICAL MAXIMUM INDIVIDUAL OFFSIT2 DCSE( )

OFFSITE DOSE AND FRACTION OF APP.I LIMIT 10 CFR 50 ,

S Q.;; j 1.C ~ /li;; j 6 G?H "

ft Dose  % of App. Dose  % of' App.

(mr/yr) (mr/yr)

(mrjU)

T L!mit I Linit 9.22E-2 0. 6 4.61 31 15 Particulates Nobic C.1ses Can=a 5.48E-2 0.5 2.74 27 10 Be:a 6.66E-2 0.3 3.33 17 20 Licuid Effluent

'-lhala 3cdy

. 9. 7 6 E-4 m 0.1 4.88E-2 1.6 3 (adu*:s)

Liter 1.46E-3 << 0.1 7.28E-2 0.7 10

(:ae.s)

(1) Jased on 80% of the plant capacity factor.

4 9 ,

e 9

9 i .

l ..

__ _ ,. ~ - , . - . -

-a .

= 10 for all other Isotopes.

2. 73 sump capacity of 10,000 gallons.

3. Olscharge rate of 10,000 gallons per day (typical anticipated discharge rate).

4. The T3 sump water i s transferred to the Industrial Waste Treatment System collection Sump. This liquid waste is then diluted with the MDCT (Mechanical Draf t Ccoling Tower) water and discharged at a rate of 38,000 gpm to the river. Dilution parameters used in the analysis are given in Table 5.

/, Aaca: cr uccaric.n anc 7.n =ra ca .an.as. J:-s;ra cu p.2.:t. !:::: 2 .r a calculates basec cn grounc level releases and are listed in Taole 6.

,(G ) Hvoethetical Maximum Individual Of f-site Dose. The off-site doses were analyzec by using The TMI Of f site Dose CaJeulation Manual (ODCM), which is based en guidelines given in the NRC. Regulatory Guide 1.109. The results of the analyses are presented in To,le 7, which ref lects the most recent evaluation and should replace Table XI-1 of the earlier Safety Evaluation report. The major changes in the revised analysis include 80% rather than 100% plant capacity factor and direct release of 1% of radiolodines to the Air Ejector in the form of organic lodine rather than partitioning from the main condenscr. Both of these revisions are consistent with NUREG-C017 guidelines. In addition, a typographical error which reversed the beta and garrrna contribution from the noble gases was corrected.

20. With ref erence to the cracking observed in the 0-ring examination, state the basis for the contention that no stress corrosion cracking was observesd in the primary system. Specifically, cite ref erences which state that if cracking is r.ot intergranular it cannot be stress corrosion.

Res00nse:

Cejects observed in the reactor vessel 0-ring have been characterized as ductile rupture as indicated by the dimpled feature of the fracture surf aces. It was noted the intent of the report to indicate that a stress corrosion cracking mechanism could not exist in the absence of intergranular attack but rather that the surf ace topography of the existing defects was not Indicative of any typical SCC morphology.

Metallography revealed that the indications observed on the surf ace were very shal low ( .001" .002") and that when opened by bending revealed only ductile

. rupture. These def ects were most Ilkely due to deformation of the 0-ring near the seatin.g surf aces.

21. With reference to the Ultrasonic Testing of botting, state the sensitivity of this inspection method (i .e., the def ect size in the mockup). Further show that calculations assuming this defect size fer all bolts will previde adequate margin and conformance with design codes.

Response

9 e

1 l

i 1

There was no in-place standard for UT examination of bolts from the head of the '

bolt. A test program was developed which wou ld detect a small ~ Indication without ambi guity. The sensitivity of ultrasonic testing of bolting is dependent in part on the size of the bolt and the depth of the threads, in some cases, defect depths of 10% of the bolt diameter are detectable. Where threads are deeper, 20% is the maximum detectable def ect depth. The " worst case" condition is the core barrel assembly bolts, which have a 20% detectability limit and are highly loaded. These inconel X-750 bolts had a preload of 24 to 30 KS1 at installation, and were exposed to sulfur in solution with the '

remainder of the RCS. It was concluded that at least one of the ninety-eight bolts inspected would be expected to exhibit detectable damage if the bolting were in an envlornment conducive to stress corrosion cracking. Noe--s damage was

.g. uty

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were a.l so i ncone l X-750, wete suoject te a simi l ar env i rcament, anc nigner stress -level s (100 KSI). The presence of a rejectable indication woula have resulted in f urther examinations.

A verlety of non destructive and destructive techniques were used in the RCS inspection, and a variety of dif ferent materials were sampled. tb portien of the program was intended to a be a rigorous requalification of a speci f ic item.

Instead, the program as a whole was planned to generate a large data base to assess possible areas or types of damage in the remainder of the RCS, All tests were negative.

22. What is the 100% RCS design flow rate (p. 53).

Resocnse:

The original design flow rate used for analysis in the pre-operation TMI-1 FSAR was defined as 100% RCS design flow rate.

Testing at TM1-1 showed that as-built ficw was significantly greater than 100%

design flow. After allowance was made fcr instrument error, etc., the minimum actual RCS f low rate was found to be 106.5% of the original design flow.

Based on the measured flow, DNBR calculations were redone using 106.5% design flow. Other calculations were left unchanged. Current technical specification limits en flow are based on 106.5% of the original design flow rate.

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C. Steam Fittings ISI Program GPUNC will inspect the main steam line fittings at TMI-I for The following criteria were potential water droplet erosion.

used (in descending order of erosion probability) to select monitoring data points.

1 - Fittings close or adjacent to the OTSG 2 - Fittings of 90* configuration 3 - Fittings from the "A" steam generatcr "B",

Since there are more tubes plugged in the "A" OTSG than the the "A" steam lines will have a higher probability of erosion.

TSs efere. inceeetions vill be made of steam linesr... from4the A OTSG. Based on the above tne folioving r. : r.gs

- inspected before start-up and at the next refueling outage following restart.

k Table A-2 Steam Line Fittings Inspection "A" OTSG Item Qty. Description 1 2 First 45' Ells after OTSG exit This inspection will be done using ultrasonic testing techniques for measuring pipe (fitting) wall thickness according to an adaptation of ASTM E 797-81 " Standard Practice for Measuring Thickness by Manual Ultrasonic Pulse - Echo Contact Method."

"' The ultrasonic data density (number of data points) of the pipe wall surf ace will correspond closely to that already done on the turbine extraction piping at TMI-I.

Future inspection frequency and scope will be determined after the results of the next refueling outage's inspection have been evaluated.

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' REFERENCES l i,

(1) OTSG Repair Safety Evaluation Report, Aug. 1982.

(2) TMI-1 OTSG Failure Analysis Report, July 1982.

(3) Final Report on Failure Analysis of Inconcel 600 Tubes from OTSG A and B of Three Mile Island Uni: 1, June 30,1982 - Battelle - Columbus l Laboratories.

(4) Final Report: Evaluation of Tube Samples from TMI-1, July 7,198 ;

B&W *RDD: 83:5390-03:01. -

(5) Technical Specification for 0T5G Tuse Plugging wt:h 35W 4eldec Caps and Stabilizers SP-1101-12-030.

! * (6) Nucicar Safety / Environmental Impact Evaluation for OTSG Tube Plugging Using B&W Welded Cap with Stabilizer.

(7) OTSG Tube Plugging Phase I SP-1101-12-029. ,

(8) GPUN Specification SP-1101-22-008. OTSG. Tube Repair-Long Term '

Corrosion Testing, Rev.1.

l:

(9) R. C. Newman, et. al. " Evaluation of SCC Test Methods for Inconel 600 in Low Temperature Aqueous Solutions." Symposium held at National Bureau of Standards, Gaithersburg, Maryland, April 26-28, 1982.

J j (10) NUREG 0565 " Generic Evaluation of Small Break Loss-of-Coolant Accident Behavior of B&W Designed 177FA Operating Plants."- January-1980.

(11) MPR Report, "TMI-1 OTSG Primary-to-Secondary Leakage," September 13, 1982.

(12) NUREG-0017,'" Calculation of Release of Radioactive Materials in i Gaseous & Liquid Effluent from PWR," April 1976.

(13) TMI-1 Plant Technical Specifications.

(14) EPRI NP-2146 Topical Report Dec.1981, " Static Strain Analysis of-I TMI-2 OTSG Tubes."

(15) ASPE Section XI -1980 Edition.

- (16) Westinghouse Electric Corporation Report WCAP-10084, TMI-1 Steam Generator Tube Rolled Plug Qualification, Test Report, April 1982. -

(17) GPUN TDR #388 Mechanical Integrity Analysis of TMI-1 OTSG Tubes.

(18) GPUN Spec SP-1101-22-006,-Rev. 5.

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REFERENCES - (Contd. )

(19) GPUN SP-1101-22-009 OTSG Kinetic Tube Expansion Process Monitoring and i Inspection, Rev. 5

( 20) Three Mile Island-1 OTSG Tubing Eddy Current Program Qualification, October , 1982. -Draf t (21) GPUN TDR 343 RCS Inspection, 6/14/82. ,

1 (22) J. D. Jones, OTSG Failure Analysis Operational History Final Report, CPUN TDR #336 May 12,1982.

t i 3) Three Mile Isiana :nt:-L - : :1 ::.r:ugn 1:: = :s:. : ::: :.a ; - - - ' . : :!. : '

Expansion Technical Report - G?UN-TDR-007 Rev .1, March 1983.

(24) J. C. Griess and J. H. DeVan, Oak Ridge National Laboratory, The Behavior of Inconel 600 in Sulfur Contaminated Boric Acid Solutions ,

September 29, 1982.

I (25) GPUN' Topical Report 010 TMI-1 OTSG Adequacy of Tube Plugging and '

Stabilizing Repair Criteria.

(26) GPUN TDR #368 Primary to Secondary Leak and Leak Ra'te Determination Methods.

(27) J. V. Monter, "TMI-1 OTSG Test Results - Interim Report," B&W Report

1. 543301-01, July 13,1982.

(28) GPUN TDR #359 Evaluation Criteria for a Primary to Secondary leak.

(29) GPUN SP-1101-22-007, Rev. 2, Short Term Corrosion Testing (30) Stress Report for OT36 Stabilizer Weld Cap, B&W 33-0231-00 (31) . Welded Taper Plug Stress Report, B&W 1002581C-02 (32) Stress Report for MK-1, B&W 32-1127439-00 (33) Stress Report for MK-3, B&W 32-1127439-01

( 34) OTSG Stabilizer Design Review, B&W 80-0150-00 (35) B&W Position paper on Use of Tube Stabilizers in THI-1, OTS6, B&W 51-1132-602-00

( 36) CHATA-Core Hydraulics and Thermal Analysis-Revision 4, BN4-230, Rev. 4, Babcock & Wilcox, June 1979. .

(37) CIPP-CHATA Input Processing System (38) TEMP-Thermal Enthalpy Mixing Prograu, B AW-321, Rev. 2 Babcock &

l Wilcox, June 1979

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I REFERENCES - (Contd. ) j (39) B&W Document No.. 32-1135 309-00, " Pump Code Certification for Oconee II" by D. J. Halteman, July 1982.

(40) NUREG 0565, " Generic Evaluation of Small Break Loss-of-Coolant Accident Behavior of B&W Designed 177FA Operating Plants." January 1980.

(41) Topical Report BAW 10092P Rev. 3, October 1982.

(42) BAW-177 " Preliminary Calculations of the Ef fect of Plugged Steam Generator Tubes on Plant Performance" March 1982.

_(43) . RETRAN-02, EPRI NP1850 CEM, May,1981.

444) Transient Model of Steam Generator Units in Nuclear Power Plants -

TRANSG-01 EPRI NP-1368, March 1980.

(45) Requests for Information on Steam Generator Feedwater Addition Events Letter from Thomas Cox of USNRC to J. H. Taylor, (B&W) dated June 20, 1982.

(46) Letter from G. T. Fairburn (B&W) to J. F. Fritzen (GPU) dated December 11, 1979, TMI-79-201.

(47) B&W Document 32-1138230-001 " Evaluation of Effects of 1500 Plugged Tubes on TMI-1 Post LOCA Core Safety, November 1982.

(48) B&W Document, Engineering Criteria for Tube Repair at TMI-l

1. 51-1137529-00.

(49) " AUX. A Fortran Program for Dynamic Simulation of Reactor Coolant System and Emergency Feedwater System." B&W Document NPGD581, August, 1981.

(50) Report in Response to NRC Staff-Recommended Requirements for Restart of Three Mile Island Nuclear Station Unit One - Amendment 25.

(51) Flow-Induced Vibration Analysis e ! IMI-2 OTSG Tubes, EPRI NP-1876, Vol.1, Proj. S140-1, Final P po. , June 1981.

(52) Determination of Minimun Be<glj Tube Wall Thickness for 177-FA OTSG's. BAW-10146, October 1980, (53) ~ Fracture Analysis of Steam Generator Tubes, Part II, Steam Intensity Factor and Crack Opening Displacement (COD) Displacements, by Prof.

F. Erdogan, Lehigh Univ. , Prepared for GPU Nuclear, 9/15/82.

(54) - TDR #399 Operation of TMI-l with Primary to Secondary OTSG. Leakage and l its Onsite/Offsite Radiological Impact.

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I REFERENCES - (Contd. )

(55) GPUN Safety Evaluation Ib. 120012-007 " Requirements for Cutting Upper OTS G Tbbe Ends , " Rev . 1; February 17, 1983.

(56) G PU N-S P-1101-22-014 , Technical Specification for Post Repair Eddy Current Inspection Program.

(57) Le tter Report, Examination of Three Mile Island'1 Third Pulling Sequence OTSG Tubes. RDD; 83:5068-03:03.

l (58) TDR 400, Guidelines for Plant Operation with Steam Generator Tube tenha ge - D-s f t

_(59) Evaluation of SBLOCA Operating Procedures and Effectiveness of i Emergency Feedwater Spray for B&W Designed Operating NSSS. .

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