ML20083L883
| ML20083L883 | |
| Person / Time | |
|---|---|
| Site: | Crane  |
| Issue date: | 12/07/1982 |
| From: | Moran T BABCOCK & WILCOX CO. |
| To: | |
| Shared Package | |
| ML20079G498 | List:
|
| References | |
| FOIA-83-243, FOIA-83-A-18 008, 008-R01, 8, 8-R1, NUDOCS 8212150120 | |
| Download: ML20083L883 (115) | |
Text
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ASSESSME:C CF TMI-l PLAIC SAFETY FCR RE""JR:: TO SERVICE AFTER STEAM GENERATOR REPAIR TCPICAL EEPORT 008 REV. 1 I
PRCJECT 2I0: 5000 51712 T. M. MCRAN e
Decerter 7, 1982
.k-XA CobY Has Been Sent to PDR APPRCVALS-
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s AB'STRACT A safety evaluation was performed which addressed the adequacy and safety of the TMI-l GTSG repair and the ability of the plant t'c be returned safely to service.
Analyses included development of a failure scenario, the evaluation of occupational exposure and Appendix I consideration for operapion with.a small primary-to-secondary leak, the s
development of an adequate repair and~ analysis of operational performance subseqcent to the repair of the OTSG, the evaluation of integrity of unrepaired portions of the OTSG tubing, the examination of the integrity of other reactor coolant system components and the analysis of design basis and hf.qMer primary to secandary
'.eak rates for procedure revie'p and operator training.
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The report concludes that TMI-l can be safely returned to aervice once the OTSG repairs.are completed.
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e NOTE As used throughout this report, except in those instances
, where the context otherwise requires, the terms " corrosion" and " corrosive" when used in relation to the damage to the TMI-l steam generator tubes shall mean the intergranular stress assisted cracking pPinomenon that took place when three conditions occurre imultaneously, namely (i) a sufficiently high tensila s. tress, (ii) a susceptible material microstructure, and (iii) an aggressive environment, and the combination of these conditions damaged the tubes.
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1 Table of contents t
I.
INTRODUCTION A.
Purpose
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' Background C.
Steam Generator. Repair Program D.
Safety Evaluation Logic II.
FAILURE ANALYSIS A.
Operational History B.
Metallurgical Test Program C.
Corrosion Test Program D.
Damage Scenario E.
Distribution of Damage III. CORROSION TEST PROGRAM A.
Introduction B.
Corrosion Mechanism Determination Tests C.
Corrosion Scenario Verification "ests
- 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 from Tubes E.
Conclusions V.
KINETIC EXPANSION REPAIR DESCRIPTION
SUMMARY
A.
Description of Process and Geometry B.
Design Bases of Kinetic Joint C.
Qualification Program D.
Repair Testing 5.
Conclusions VI.
EFFECTS OF EXPANSION REPAIR A.
Possible Introduction of Chemical Impurities B.
Possibla Effects on OTSC Structure C.
Corrosios D.
Effects of Expansions on Existing Plugs E.
Conclusions VII. PLUCCING REPAIR DESCRIPTION
SUMMARY
A.
Introduction B.
Plus Types C.
Plugging and Stablization Crittria D.
Post Repair Testing E.
Conclusions I
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Table of Contenes (cont'd)
VIII. COMPARISON OF TUBE PLUGGING '4ITH DESIGN BASES A.
Introduction 5.
Operational Performance C.
Accident and Transient Performance IX.
UNREPAIRED PORTION OF TUBES A.
In troduc e. ion B.
Damage Mechanism Is Arrested C.
Defect Detectability D.
Undetected Defects Are Acceptable I.
OPERATIONAL CONSIDERATIONS A.
Leakage Monitoring B.
Development of Procedural Guidelines for Steam Generator Tube Rupture C.
Conclusions XI.
ENVIRONMENTAL IMPl.CT A.
Introduction B.
Appendix I Considerations C.
Sampling and Monitoring D.
Conclusions XII.. TECHNICAL SPECIFICATION COMPLIANCE XIII.
SUMMARY
AND CONCLUSIONS APPENDICES A.
Process, Precritical and Critical Test Programs REFERENCES FIGURES-l Figure I-I TMI-l Steam Generator l
Figure I-2 OTSC Task Organization l
Figure I-3 Disposition of Tubes in TMI-l Steam Generators
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Figure I-4 Kinetic Expansion Process Figure I-5 TMI-l Steam Generator Typical Cracks Figure I-6 Kinetic Expansion Length Figure I-7 Plant Return to Service Safety Evaluation Overview Figure 11-1 Number of Tubes with Defects vs. SG Elevation Figure II-2 Three Mile Island Steam Generator B Figure II-3 Three Mile Island Steam Generator A i
Figure VIII-1 Reduction in RC Flow Race vs. Number of Tubes Plugged per Steam Generator Figure VIII-2 Comparison of FSAR Flow Coastdown to Flow Coastdown with 1500 Tube Plugged
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FIGURES - (cont'd)
Figure VIII-3 Effect of Tube Plugging on Natural Circulation - Tgog Loop 1 vs. Time Figure VIII-4 Effect of Tube Plugging on Natural Circulation - Total Core Flow vs. Time Figure IX-1 ECT Calibration Figure IX-2 Flow induced vibration load cycle Figure IX-3 ECT Detectability vs. Mechaeical Stability Figura IX-4 PRI - Sec Leak Race vs. Detectability Figure A-1 Steam Generator Post Rapair Testing Schedule TABLES Tatte IV-1 Three Mile Island Unit 1 Administrative Controls Primary Water Chemistry Table IX-1 Laboratory Induced Cracks E/C Correlation Table XI-1 Maximum Hypothetical Off-Site Doses for 1 lbm/hr. and 6 CPH Primary to Secondary Leak lii -
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I I.
INTRODtMTION A.
Purpst l
In November 1981 primary to secondary side leaks were discovered I
in both TMI-1 Cnce Through Steam Generacora (OTSG). Subsequent detailed failure analysis shoued that extensive circumferential cracking had occurred in the CISG 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.
B.
Background
TMI-1 is a 776 MWe pressurized water reactor having two verci-cal, straight tube and shall once-enrough-steam generators (CISGs). Each OTSG contains 15,531 Inconel-600 cubes, 0.625 in.
OD,.034 in wall, 56 f t. 2-3/8 in. long, rolled and sealed-welded into 24 in. thick carbon steel tube sheets at the top and bottom of the OTSGs. (See figure I.1)
The plant was shut down early in 1979 for refueling and has remained 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 case.s were performed in August-September 1981 and did not indicate any problems with the OTSGs. However, in November 1981, during pressurization for additionai tests, primary to secondary leaks were detected in the OTSGs.
As soon as CPU Nuclear Corporation realized the extent of damage to the TMI-l steam generators in early December,1981, a dedi-cated OTSG cask organization was established to coordinate the repairs of the steam 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 generaters 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-l 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, manufacturing, and research communities. 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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i FIGURE !.1 TMI-1 Steam Generator ELEVATION CROSS SECTION
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I INDEPENDENT TillRD VICE PRES. TECHNICAL VICE PRES.TMI-1 l
PAliTY REVIEW FUNCTIONS 1
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In order to provide added assurance that the TMI-1 OTSG repair was conducted in a prudent, safe and technically correct manner, an independent third party review was estabished made up of experts from throughout the utility and research industries.
This independent third party reported directly to the Vice-President'of Technical Functions and was essked to provide an independent and. objective safety evaluation of the failure anal-ysis program, eddy current examination program, OTSC performance evaluation, OTSG repair criteri's, and the overall OTSC repair program. The advice and recommendations provided by this third party review have proven very beneficial. Their participation providos added assurance that the OTSG repair activities both conform to the NRC rules and regulations governing the operation of TMI-l and assurance that the adequacy of the steam generator repair program allows safe operation of the TMI-1 nuclear unit.
C.
Steam Generator Renair Program The approach taken to restore the Steam Generatorr to service was.co evaluat's the condition of each cube witn eddy current techniques developed specifically for the geometry of this
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corrosion mechanism. Following ECT the status of each tube was evaluated and one of the available repair methods was chosan.
Figure I-3 summarizes the disposition of all the tubes in the TMI-l 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 metrilurgical examination an1 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 *MI-l OTSGs involves expanding s ad 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 Iccation of the cracking in the TMI-l Steam Generator tubes. Ihe majority of the cracking is located in the
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DISPOSITION OF TUBES IN TMI-1 STEAM GENERATORS k
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.crat s below 40% TW win conMoss at temperatuse prevent not propagate by mechanical chemscal psopagatsee I
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- These tubes are undergoing test pressam engineering evaluation at this j
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coerosien tests removed from service by plugging.
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upper ends of th't tubes of the two generators, at or near the upper 1 in. to 1.5 in. where the 56 f t.
long tubes were mechanically rolled and then seal welded to the tube sheet cladding (see figure I-5).
The combination of rolled joint and seal weld held the tubes tightly in place within the cubesheets.
At TMI-l both 17 in. and 22 in, long expansions will be utilized 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 face of the upper tubssheet (US+8). This length provides the dividing line between those tubes with defects which could be repaired by expansion and those that would be removed from service. For the TMI-l OTSC gaometry and matarials, a 6 in.
long joint below the lowest defect has been shown to provide adequate leak tightness and load carrying capability and is the basis for the joint qualification program. All tubes that
.. remain in servica.will. be kinetically. expanded-irrespective of whether or noc~ a' defect has bee'n 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 with ECT indications that are 1ess than 40% through wall. Since analysis indicates that these tubes will not fail by mechanical, ther: sal 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 information in future ECT inspections of the stability of these indications.
D.
Safety Evaluation 1,ogic To determine if the plant could be safely returned to service, a program was initiated to define all the significant ef fects of operation of the steam generators after 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 detined 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 references the sections of this report which describe the results which support the conclusion that the TMI-l 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; 3
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h (2) Other components in the RCS and stipporting safety systems were not visibly damaged by the failure mechanism;
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y (3) The plant can be operated such that this f ailure mechanism J..'
is arrested and will not recur;
.g (4) The Steam Generators can be repaired and operated within 4
the design basis; s
i (5) The plant can be operated with some tube leakage without adversely impacting the environment.
- 6 The re.nainder of this section provides a brief synopsis of the entire report with emphasis on the logic used to determine that
-ij the plant can be safely operated with repaired steam generators.
w9 Report Summarv*
"...A deta(1.ed failurecanalysis was performed in' itiding -(l')-review.
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M of the'OTSGs fabrication history, (2) coordination of metal-lurgical examinations of tubes pulled from the OTSGs, (3) review
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.of the OTSG operating plant chemis try histories, (4) coordina-tion of OTSG tube stress analyses, and (5) development of a
.g failure scenario. This failure scenario, which provides a y*
reasonable match between plant conditions and the mechanism which caused.he tube cracks, concludes that sulfur contamina-y 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.
h Section II summarizes the failure analysis.
1 f.;j An inspection of additional RCS components which included non-destructive testing was performed to determine if other com-7 ponents sustained similar dsmage to that found in the OTSG.
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Emphasis was placed on materials which were susceptible to attack in components which fulfilled critical functions. No damage was found. An inspection of RCS supporting systems is (3) underway. Details can be found in Section II.E.
lg As shown in Section IV, paths for chemical injection into the
'Z RCS and administrative controls on chemicals were examined in an
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effort to prevent future chemical contamination of the RCS.
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Additional periodic chemical analyses will be performed during plant operation and some adminis trative limits for chemical 39 concentrations have been changed. In addition a program is in progress to determine the safety and effectiveness of sulfur conversion and removal from the surf aces of the Reactor Coolant
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can be der.onstrated that it will make a positive contribution to g
the safety of operation.
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_u To determine that the OTSG is operable in accordance with the original design basis, the OTSG was analyzed in two sections:
the repaired portion and the unrepaired portion. In the re-paired region, both the expansion repair and tube plugging were considered. 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.
Details of this program are summarized in Section V.
In addi-tion to the qualification program, a process monitoring program was set up to oversee the expansion process.
Plugging repair is summarized in Section VII. B&W Weided Plugs, B&W explosive plugs and Westinghouse rolled plugs were quali-fied. Analysis verified that adjacent expansions would have no detrimental effect on existing plugs, and analyses documented in Section VIII show that the system will not be adversely affected by either the number or distribution of plugged tubes for normal, accident and trancient performance.
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.m (In.tne.unrepaired region of the OTSG,.various tests tnd analyses discussed 'in Section 'IX'~have shown that:
(1) Corrosion tests indicate that the cracking mechanism has been arrested and does not reactivate in low sulfur water chemis try.
If rapid crackint should reactivate due to an unknown mechanism at operating tempertures or during heatup and cooldown cycles, it is anticipated that the precritical testing sequence would allow sufficient time for defects to
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propagate through wall to a size that would allow leakage to be detected as shown in Figure IX-4.
Therefore the precritical leakage monitoring during the hot testing will detect crack propagation.
(2) Analyses have demonstrated that crae.:s belev a minimum range of length and through wall thickness will not propagate by combination of flow induced vibration and thermal cycles. Analysis has also calculated a minimum size below which a crack will not become unstable due to plastic tearing or ligament necking during a main steam line break (MSLB). This range of crack sizes is detectable by the ECT inspection system thst was used to inspect the steam genertors.
(3) Any defects in the detectable range that are undetected during the 100% ECT inscection because of equipment or an-4Lyst error will be exercised during the test program.and if they propagate to 100% through wall will be detected by leakage monitoring programs with sensitivities as shown in Figure IX-4.
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Both an ECT flaw growth program which monitored a sample of tubes for new defect indications and corrosion. testing on actual defective TMI tubes in the present primary coolant chemis try, showed that the damage mechanism had been arrested.
To determine if all unacceptabla defects were detected by ECT and those defects not detected would not propagate to failure, an extensive ECT calibration program was devised and the small-est size defect which could be consistently detected by ECT was determined. Comparison of field ECT results to metallurgical examination 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 showed that cracks of the size that could propagate to failure by combinations of flow induced vibration and thermally induced mechanical loads were within the ICT detectability limits.
Local IGA one to two grains deep ras examined during the metallurgical examination pregram and there was no indication that this effect was related to the failure mechanism.
~
.A precritical testing geogram has been designe'd'that will pro-N.
t"i *, *
. vide confirmation'of the adequacy of the' OTSG 'rspair'and: 0TSG 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 OTSG tubes from normal and accelerated cooldown transients. The acceterated cooldown will be at a rate larger than the normal cooldown rate based on past operating experience but will be within the cooldown race limitations of the existing Technical 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 small through wall cracks will be detectable during the test period.
Operation with a primary to secondary laak at the repair dcsign goal of 1 lb/hr. and at a more conservative rate of 6 gal /hr.
i have been evaluated. These leakage rates have been found to pose no threat to the health and safety of the public and allov the plant to operate within existing Appendix I Technical l
Specifications. Details can be found in Section XI.
This report concludes that TMI Unit 1 can operate with the re-paired OTSGs without undue risk to the health and safety of the public.
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II.
FAILURE ANALYSIS Threc Mile Island Unic I was in cold shutdown from March 1979 until September 1981. In September 1981 hot functional testir.g was performed.
The plant was returned to cold shutdown for some final modifications prior to startup. The plant was pressurized to about 40 psig in Nevember 1981 and small leaks from primary to secondsry side were detected in the tubes of the once through steam generators (OTSG's).
A detailed f ailure analysis was performed 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 program, a review of OTSG stresses and fabrication history, and the devc lopment of a failure scenario.
In addition, the districution of damage both in the,
OTSC's and the remainder of the RCS was investigated.
A.
Ocerational Historg
' The time'of the OTSG tube' failures may be bracketed based on-eJx. r.
'.' operational.,considerationa.. During MFT on September 4,1981 'th'e"
~~1eak race of the RCS at full pressure was measured and found to be within spec at.5 gpm. On November 21, 1981 with the RCS at about 40 psi, leskage through the OTSC tubes was observed.
A review of operational history of the TMI-1 steam generators was performed for the period April, 1979, through November, 1981 to determine whether instances of chemical contamination or excessive cube stress could be identified to determine the cause of the tube failures. A detailed des:ription of OTSG operating history is found in Reference 2 and Reference 22.
The operational history of the TMI-l OTSC's reveals that the tubes were not subjected to excessive stress, and generally, the reactor coolant system chemistry remained within specifications i
for the period extending f rom April 1979 through November 1981.
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 oil was intro-l dr 24 into the Reactor Coolant Blaed tanks probably by over-flowing the miscellaneous Waste Storage Tank through the vent heaoer. Some oil may subsequently have found its way into the RCS. Tube surface analysis has shown that carbon was present in large quantities (50-90%) on the As-received surface. This car-bon 's reported to be in several forms either as a hydrocarbon, a carbonate or el.emental carbon. Carbonate was present mostly on the surface, and hydrocarbon at greater depths ir. the oxide layer. It can not be determined whether the presence of carbon
(
or hydrocarbon on the tube surface resulted f rom contact with reactor coolant containing some oil or from exposure to normal 1 l
i j.
atmospheric contaminants after removal from the OT5G.
In October 1979 sulfuric acid was injected into the Reactor Coolant Makeup System.~ Although attempts were male to prsvent the acid from reaching the RCS, chemistry results indicate some contami-nacion of the RCS occurred (see Reference 22).
In July 1980, May 1981 and September 1981, a surveillance test was performed which may have allowed sodium chiosulfate f rom the Reactor Building Spray System 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 1980 were removed from the bulk liquid by d,emineralization in August 1980. The ionic species from the second contamination incident in May 1981 appear to have been only partly removed by processing through a risin water precoat filter in August 1981. A 1-2 ppm chiosul-ate residual could have still been present at the start of
. sp cember.1981. Additional sodium thiosulfate in the RCS may have resulted frca injections of Borated Water " enrage Tank (BWST) contents ducing cooldown from hot functional testing.
This, water had been previously mixed with water from the Reactor Building Spray piping. The quantity was not sufficient to be
..;g,,. detectable by. conductivity, s.
Significant to the localization of the attack was the history of the water level on the primary side of the OTSG. Following the hot functional testing in September 1981, water level was promptly lowered on September 8, 1981 chen slowly raised over the reat of the month. This allowed a drying then rewetting of the tubes in the upper portion of the steam gen.eraccr, causing chemical concentration in that region.
Oxygen introduction is also believed to have played a role in the damage mechanism. There were evo occasions when oxygen was introduced into the system. When the water level was lowered, the OTSG primary side was vented to the waste gas system. The maximum oxygen specification in that system is 2%.
Thus, oxygen was immediately available at the liquid surface. 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.
B.
Metallurgical Test program After identification of the leaking OTSG tubes by nitrogen bubble testing, it was decided that in order to determine the cause of failure, cube samples would need to be removed from the steam generators for analysis. The initial selection of tube semples was made after eddy-current testing had been commenced
[
and the choices were made based on maximi:ing 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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Four tubes were initially selected f rom the "B" generator. One (1) tube was a known leaker from the bubbla. test results (B11-23), the other three tubes contained eddy-current indica-tions of greater than 80" through wall penetration.
After the initial samples had been removed, it was discovered that eddy-current signal anomalies were showing up at the roll transition region.
In order to determine the disposition of these tubes, additional tube samples were selected for removal which contained these eddy-current signals. This time, fifteen (15) tubes were removed from the "A" generator.
A third set of tube samples were removed which included 6 tubes from the "B" generator and 4 tubes from the "A" generator.
These samples were taken to obtain some low level defects f rom deep in the steam generatar, to tample tubes from specific areas, and obtain tube ends to be characterized (in previous samples the tube ends had been removed during pulling).
1.
Analysis Program
~
,g,.
'... ; A.miulti-task program-was conducted to provi'de information
'rel' aced 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.
X-Ray Analysis (EDAX) f.
Auger Electron Spectroscopy (AES) 3 niectron Spectroscopy for Chemical Analysis (ESCA) h.
Sodium Aside Spot Test
- i. Metallography-Microstructural Analysis
- j. Scanning Transmission Electron Microscopy (STEM),
Electrokinetic Potenciostatic 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 The detailed test results are presented in Reference 2.
The following summarizes those results and sets forth same con-clusions.
The' tubing has failed due to intergranular stress as-a.
sisted cracking. The intergranular morphology has been
-9 s
}
confirmed by Metallography and Electron Microscopy.
This has led in many cases to through wall penetraticas and circumferential1y orienced cracks.
In all cases, cracks h&ve initiated on the primary side surface.
b.
Microstructural evaluation of the tubing from numerous locacicns, has indicated that the structure is representative of that normally expected for steam gen-erator tubing. Tests have concluded that the material is in a sensitized condition and hence is expected to be susceptible to intergranular accack in oxidizing acids.
c.
Transmission Electron Microscopy has also confirmed that no secondary mode of failure is associated with the intergranular corrosion, that is, no evidence of any low or high cycle fatigue was observed on these fracture surfaces.
d.
The consistent circumferential orientation of the cracks below the weld heat affected zone, indicates that an
' ~
.. axial stress is part of the cracking mechanism. Residual
~
~
~
stresses in the roll alone were not responsible for the cracking. Therefore, the fact that the cracks occurred when tha tube was under a higher applied axial tension stress rather than hoop stress, confirms that the cracks formed during cooldown or cold shutdown. Axial cracks have been observed at the top end of the tubes near the seal weld. Some of these cracks penetrate 100% through the wall but they do not penetrate the weld metal. The axial orientation in this case is expected based on the residual stress distribution in the area of the seal
- weld, e.
Auger analysis of surface films on fracture surfaces and on the I.D. surface of the tubing indicates that sulfur is present up to levels of eight atomic percent. The sulfur concentrations along the I.D. surface of the tubing down to the 9th tube support plate, are generally l
uniform with perhaps a slightly decreasing level lower l
in the tube sample. The form of sulfur is believ.d to be either in the form of nickel sulfide (Ni S ), or 23 some other reduced form of sulfur. The reduced sulfur form generated from the contaminating species is di-l rectly responsible for the cracking mechanism.
l As shown by surface analysis, carbon was present in large quantities (50 90%) on the as-received surface of the first and second round tubas. Similar analysis on the third round tubes revealed a maximum of 50% carbon.
l If the high carbon level on the Round 1 and 2 tubes was the result of OTSG/RCS operation and/or contamination, one would expect the high level to again be detected on l l
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the Bound 3 tubes. It is thus inferred that tKe exten-
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sive carbon contamination on the first and second round tuber was the result of contamination either during or immediately after tube removal. In addition to sulfur and carbon, the Auger and ESCA analysis have shown the pres.ence of nickel, chromium, oxygen and normal trace quantities of fission products on the fracture surface.
f.
In conjunction with the cracking, there has also been intergranular corrosion observed. These " islands" of IGA are not always associated with cracking and in general are associated with I.D. deposits. ICA found at crack locations tend to penetrate deeper than the aporoximately 1.5 to 3 mils of penetration typical of the IGA " islands." Most severe cracking in general relates to more severe intergranular corrosion.
g.
In 38 out of 4. cases ti date, cracks which have been l
examined either by metallography or by bend testing have shown. the defects to be 100%. through wall. The remain..
,, ing thrie' case,s' exhibited,p.cnetrations of 50, 70 and 70%.
J s,
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. i..
~
C.. Corrosio6' Test Proerse A corrosion test progra's was put into place and addressed the 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.
The following co..clusions can be drawn from corrosion tests l
which relate to the failure scenario.
t a.
Thiosulfate can produce cracking similar to that observed in the steam generator tubing.
l b.
In the absence of thiosulfate, or in the presence of sodium l
sulfate, no cracking has been produce.d in the laboratory in primary water chemistry.
c.
Tubing removed from the steam generators appears to have a lower thiosulfate concentration threshold for cracking than an equivalent archive tube which has been sensitized.
l d.
Tubing thermal history is a key parameter in establishing material susceptability. A threshold level of sensitization must exist. Data suggests higher mill annealing temperatures faver cracking in sulfur contaminated primary water.
l l
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Crack initiation and growth race are temperature dependent.
e.
For susceptible material, crack initiating cime will be decreased and crack growth increased by raising temperature up to 170*F.
f.
An oxydizing potential is required for cracking to occur.
In the absence of oxygen, cracking has not been observed in the laboratory.
g.
Crack growth races 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.
D.
Damage Scenario The conditions needed for Intergranular Stress Assisted Cracking were evaluated and compared to the conditions in the TMI OTSC's.
Based on stress analysis, fabrication history, the timing of the cracking, metallurgical and corrosion testing and
. observed. features of the cracking phenczena, a failure scenario was ' proposed..
~
~-
el L.
'L'. ' Interg'ranular Stress Assisted Cracking (ICSAC) l The occurrence of stress assisted cracking requires that l
three conditions be satisfied simultaneously:
l f
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 summarized below.
a.
Tensile Stress Since the cracks are oriented circumferentially in the tubes below the veld heat affected :ene, 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 reduc-d forms of sulfur.
However, the higher the tensile stress the more rapid the crack propagatien and the more cracks that actually occur.
The stress analysis results suggests that the cracking must have occurred during cooldown or during cold shutdown 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
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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 end below the roll are generally larger at the periphery than in the center of the tube bundle.
7 b.
Susceptible Material Microstructure There is no indication that tube material, fabrication i
or installation in the CTSG's was in any way extra-ordinary. The heat treatment of the whole OTSG following assembly puts the tubing into service in the mill annealed plus stress relieved condition which is expected 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 materials are present in the t
OTSG's which differ in composition and which may have responded differently to the stress relieving heat treatment. The degree of susceptibilty as a function of the tubing heat number could not be established.
c.
Aggressive Environment As previously stated in Section II.A. the results in-dicate that sulfur was present in the primary system water and three possible sources of sulfur have been identified from the OTSG chemistry history.
If SO4 and S:03 were introduced to the primary water as the CTSG operating and chemistry histories suggest, they would be expected to persist as long as the water was at room temperature even if the oxygen content of the water was reduced by hydrazine additions.
However, hydrogenacing 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 end oxygenating following the hot functional tests rapidly oxidize S-~ to S and could also result in the appearance of significant enneencrations of other species of higher oxidation states. Although it is not possible to predict either the identities or the concen-trations of the sulfur species present following the hot func tions1 test, it is clear that this transient is likely to have greatly affected the aggressiveness of the environment with regard to low temperature sulfur induced attack of the CTSG tubing...
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Proposed Failure Scenario This following scenario is consistent with all the observed features of the cracking phenomenon, the timing of the cracking and the results of the metallurgical examinations and corrosion tests.
a.
During layup the primary system was contaminated with sulfur by the accidental introduction of sulfuric acid, sodium chiosulfate, and possibly a sulfur-containing oil. The amount of sulfur present may have reached seversi ppm, but the contaminated water was not aggres-sive enough to crack mill annealed plus stress relieved Alloy 600. The corrosion ceses confirm that cracking would not have been expected to occur at this stage.
b.
The temperature and oxidation potential transient as-sociated with the hot functional test resulted in a change in the types and concentrations of sulfur species present 'in the primary water. Further changes occurred
.when'thiosulface-contaminated water was injected during N
the ' tests' of th.e' HPI 'and LPI systems.
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c.
When the water level in the OTSG's was lowered following the hot functional test, high concentrations of ag-gressive metastable sulfur species developed in the dry-out region at the top of the generators due to the combined effects of solution concentration by evapora-tion and the comparatively high availability of oxygen.
Changes in the sul'ur species in the more dilute bulk solution proceeded more slowly resulting in lower con-centrations of aggressive sulfar 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. Statiscically this would be expected be-cause the bulk solution was less aggressive than the environment seen by tubes in the dry out zone. Cracks would occur in areas low in the generator which were slightly more susceptible to IGSAC due to surface film anomolies or residual stress anomalies.
Cracking terminated either because continued chemistry c
e.
changes resulted in the formation of less aggressive sulfur species or because the environment in the dry-out region was diluted by the slowly-rising bulk solution.
By the time the water level was dropped again, the chemical state of the sulfur in the primary water was sufficiently different from its state immediately af ter the hot functional tests to prevent a recurrence of steps C and D in the new dry-out tone. '
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f.
Cracking was discovered when the OTSG's were pressurized.
.a 1O E.
Distribution of Damage
.=
7,j To evaluate the extent of the damage, an eddy current testing 5
(ECT) program'was devised to examine the OTSG's.
In addition, an inspection of other components in the reactor coolant system 1
ej (RCS) and supporting systems was conducted to determine if damage similar to that found in the OTSG's was evident.
1.~
OTSG Eddv-Current Examinations
'f Special eddy current techniques were developed and an exten-j sive testing program was es'*bli hed to provide an accurate s
'4 description of actual OTSG. bn cracking (Reference 20).-
ij In-situ eddy-current results exaibit tube wall defect indi-y cations at varied densitier distributed both axially and Q
radially in both OTSG 'A' and
'B' tube bundles. The majority
~
of the defect indications were in the upper tubesheet (UTS)
,. region and,particularly, confined in the tube roll transition
'Afteran abs'olute' probe inspe'etion of the roll
'*3'
zone.-
transition and mechanically expanded area of approximately
,a 18,000 tubes, ECT indications were being reported with such frequency that it was decided to affect a kinetic expansion for all tubes in both tube bundles. Further ECT data was not interpreted above elevation US+14 inches due to the J{
decision to repair the top 17 inches of all the tubes.
' Figure 11-1 gives the number of tubes with defects by
..,j 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 'B' OTSG shows a higher percentage in the periphery with the defect rate decreasing W
as you move toward the center of the bundle. Defects indicated below the upper tubesheet are located toward the fd periphery. Reference 20 gives a detailed description of ECT results.
j 2.
RCS Inspection
.h The sulfur induced attack on the OTSG tube prompted an M
inspection of other elements of the Reactor Coolant System, to determine if other components sustained similar damage.
$j An inspection plan was developed based on a review of the materials involved and the accessibility of the materials g
within the system. Representative items in the Reactor Coolant System that were most likely to have suffered attack
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were selecttd for examination. The iteds chosen represented the most susceptible materials aad reflected environmental and s tress concerns.
Materials located in either of three environmental condi-tions were evaluated.
Primary co~olant-air interface where most of the defects a.
occurred in the OTSC.
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 OTSC 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
? materials.which are known co be.suscept.ible to IGSAC..- Other
?. : ;.cy,, ;,. :. l i -
~. / *5: than.[theiOTSG < tube' preload?.s tres s, areas of clin'ces ulch -
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'l respect to stress included bolting that has a steady load due to torqueing, residual stresses induced by welding, and force-fit items.
The plan included tests of sufficient diversity to reflect the different materials, 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 develcped to also account for critical functions of the RCS items. The function of the pressure boundary, core support, and fuel integrity re:eived the most emphasis. This was to determine the general con-dicion of the system and, of course, because they are the most directly safety-related.
The non-destructive examination methods used were; ultra-sonic, liquid penetrant, eddy current, radiography, visual, and wipe sampling. Other examinations included functional check on equipment and des tructive metallurgical examina-tions, both at the TMI-l site and at 3&W Research Laboratory at Lynchbere. The selection of examinations was governed by factors relating to the type of material, geemetry of material, 'socation and accessibility, and radiological con-trol limitations. The following is a summary of methods used and example materials examined by each method.
r.
Ultrasonic Examination Method - this inspection included' tie pressurizer spray nozzle safe end, CRDM motor tube exten-sions, make up piping nczzles, plenum lifting lug bolta, plenum cover to plenum cylinder bolts, pressurizer surge nozzle, core barzel bolts and low pressure injection pipe welds.
The ultrasonic method used to examine bolts of the TMI-l core barrel assembly had the capability of detecting indica-tions having a depth of 20 percent of the diameter of the bolts.. Thi's sensitivity is considered sufficient primarily n.
blocause a large number of bolts were examined sc TMI-l and no evidence of intergranular attack or IGSAC was found. For example, 96 of the core barrel assembly Inconel X750 bolts I
were UT inspected; if intergranular accack or IGSAC. had occurred, we would have expected to see at least some evidence o.' rc.ls.
Radiographic Examination Method - This method is a volumetric type of examination that produces a visual image of the test specimen. For this reason, this method.was. chosen to vali s.
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- egrity' of tiie Jehermalisleeves 'for' the -
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safe end nozzles. The pressurizer spray nozzle and the three make up nos?.les were located in a coolant / gas interface and departure of the coolant dry area respectively.
Liquid Penetrant Examination - Special consideration var given to the welds of the secondary oversheath to assembly ove'rsheath-of the incore detectors. Items examined by this machod were: Upper OTSG Inconel (tube sheet) and stainless steel weld cladding and the incore detectors closure and sheath, incore detector the dry region portion make up nozzle, lower OTSG cladding surface and incere detector portions from the wet regions.
Eddy Current Examination Method - The ID surfaces of the RV vent valve thermoccuple and the CRDM nozzle were the areas of special concerns which required this method of surface examination. Both components are located in the area basically dry of coolant.
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 tcp of core control components, the baffle place region and the annulus between CSA and RV.
Areas of similar conditions, even thcugh they were dry of reactor coolant, were the plenum assembly and the vent valve assembly.
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G Wipe Sampling Method - This rethod was performed prior to J.,j non-destruccive examination other than visual. The samples c';
were chemically analyzed to determine the concentration of
,5 any aggressive species.
- 43 The results of the inspections and tests which involved over
' /j a thousand selected components, indicated that there was no
).3 evidence of a problem similar to that seen on the OTSG
, f.1 tubes. The functional tests s'11 indicated that the tested f.'f -
'assemblie's were operational. The destrue.tive examinacions i
+
. revealed. that even on a microscopic. level,. no evidence' of.
j /2
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'N intergranula'r attack could be found. Therefore we conclude
~
that based on this Inspection & Test Plan, the materials in
,s the Reactor Coolant System are re-certified for continued a
safe operation. The details of this inspection are reported
]
in Reference 28.
3.
tapporting Systems Insceetion i.!
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. An JGSCC. problem tias origintily detected in the. Spent Fuel: -
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ee'tablished which wa's specilic to Spent Fuel, Decay Heat and '
B.silding Spray Systems. As of June 25, 1982 all required f
volumetric examinations of the first cycle on the IGSCC g
,5 schedule were completed and no discrepancies were noted. As of August 5,1982, Visual Examinations were completed for
,,4 Decay Heat and Building Spray with no additional indications Q,,3 identified. The plotting and trending of the known indica-
,Q
. tions did not reveal evidence of growth. In March 1982, cracks which were attributed to IGSCC were found in the t
g j
Waste Gas System. 'Ihis cracking is believed to be unrelated u
s
.7, to the failure mechanism in the OTSC. Additional supporting
-l systems inspections are underway. Results will be reported in response to LER 82-02.
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III. CORROSION TEST PROGRAM I-A.
Introduction An extensive corrosion testing program was initiated in December of 1981 to support the steam generator repair program. The program in soveral phases was designed to accomplish the following:
(1) Determine the conditions under which the cor-rosion mechanism occurred and how it could be arrested, (2)
Verify the proposed corrosion scenario to provide assurance that the mechanism was understood and (3) Determine whether tubing,
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. subjected.co the mechanism could.tHi repaired and show the Steam i
Generators cculd be operated after the repair (by long term testing). The following sections describe the results of this program.
i 3.
Corrosion. Mechanism Determination Tests In December 1981, analysis of tube samples removed from the
.TMI-1 "B" Steam Generator identified th i
h i
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'.stiess ass'is'ced' intergranular' crackib.g.e corros on mec an sm as s '.
I-
, Crackin'g'was circum,
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' Isrentiallyt.orienced'and. initiated 'from.the primary side. surf ace -
s -
6g ch's tubing? ' Analysis of'the circumst'ances which led up to failure indi.cated that through wall penetration of cracks oc-curred sometime af ter the hot functional test sequence and prior to the pressurizing of the unit in November of 1981. In view of this fact, a concern existed that the corrosion mechanism might still be active.
A corrosion cast 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 1982. In this test, sensitized samples of 304 stainless steal and Inconel 600 were immersed in primary coolant removed from the decay heat loop. This coolant was analyzed and found to contain 350 ppb sulface. Specimens utilized in this test were bent strip specimens spring loaded to apply constant loads near the yield point of the-material. Tests were conducted for two week periods at 1000F.. 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 remored frem the decay heat loop.
This would have been a similar solution to that used in the.
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initial screening test. This test consisted of filling the cube 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 to putting the primary coolant into the tube, the sample was also tested with load in dry air as well as air of high humidity. In neither case were any cracks observed. 'Af ter all testing was complaced, the specimen was examined metallurgically to look for signs of growth. There was no obvious extension of the intergranular cracks and no evidence of additional attack in the area of this t.
. crack.
,It thus appeared that crack growth was also arrested and fuo.further tube,. degradation was expected. This was confirmed by the eddy current examination performed on the 100 cube sample throughou t the next several months. No evidence of any growth of known defects or detection of new defects was observed from December 1981 to the termination of program in July 1982.
In March of 1982 af ter this initial testing had been completed,.
indicating that cracks were neither propagating nor initiating, a program was initiated which would. define the environmental
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- i. (h.if,d M.*,.;.E i;donditions *.neesssary to' 'p'roduce'. th'. type'. of,intergranulkr t
e
'.forrosion observed 1 in.the TMI tube samples.
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A number of tasts utilizing stressed bent strip specimens were begun at the B&W Alliance Research Laboratory (Reference 34)'.
These tests utilized anodic polarization to accelerate the cracking process and help to define potential regimes for this cracking to occur. Solutions of boric acid containing various concentrations of thiosulfate contaminant were c2:ted. Those tests showed that thiosulfate at levels in excess of 5 ppm would cause cracking in sensitized at:hilve tubes provided the degree of sensitization was sufficient. It was also determined 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 phencmena since they cracked at thiosulfate concentrations as low 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 contaminent in the primary system.
Samples were 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 potencial range, that in the absence of thioscif ate, specimens would not crach. Cracking was observed at open circuit potential in an air saturated eviron-ment in thiosulfata contaminated solutions. However, if the ---
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solution was deserated and an inert cover gas utili'Ted, cracking was not observed in any specimens. Based on the results of approximately 60 tests it appears that thiosulfate or reduced metastable su' fur can produce and is a necessary requisite for the cracking observed. Additional results indicated that time to failure decreased aa 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 race tests (CERT) utilizing solution annealed and sens'itiz'd Inconel 600 test specimens. The purposts of e
these tests were to define the minimum chiosulfate concentiation required for cracking as well as to establish the effect of temperature and Lithium Hydroxide concentration on cracking susceptibility. The results of these tests indicated the cracking.in the absence of Lithium could be expected in highly sensitized material at thiosulf ate levels on the order of 70 ppb.'
However, in the presence of Lithium it was found that
,, cracking would not be. experienced. on s.ensitized materials
- provided.the. ratio of-Lithium. to'; sulfur.remiined ~ greater -than'.oi,
,. a.>.q. c.A,.y' :, 1 - y /.*
c
,7 equal Mo 10. ( Altho' ugh additional tests"are being.. planned to'
' ~
expasd on the knowledge and understanding of the influence'of Lithium on inhibiting cracking, this data has been utilized in preparing new administrative chemistry guidelines for TMI-1 operation. Lithium levels have been raised such that a Lithium concentration 10 times the allowed sulfur analyzed as sulfate concentration of 100 ppb can be maintained.
Brookhaven also conducted a series of tests to establish the influence of temperature on crack growth rate. Results of their tests indicated that approximately 1700F produced the maximum cracking velocity.
At this pheae 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 A highly sensitized microstructure was required o
o Lithium Hydroxide could be used as 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.
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C.
Corrosion Scenario verification Tests During the summer of 1982, testing was conducted at Oak Ridge National Laboratories in an attempt to verify the proposed I
scenario. As defined in the failure analysis, it was believed l
that corrosion ccentred 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 OTSG's.
It was felt that the lowering of the water level l
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 not be possible to totally duplicate the cor-rosion scenario, an attempt was made to establish test para-I meters which were a close approximation to a hot functional test seque nce. 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 addition, in order to. account for any influence 4.of tube '. surface films on the. cracking mechanism, all' test...
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reducing conditions in the steam generators could change surface films and form metastable sulfur compounds which could lead to intergranular corrosion. Autoclaves were set up to test sulfur contaminated borated water solutions with 1 ppm and 5 ppm thicaulfate and 30 ppm sul' ate.
This latter test assessed if oxidized 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 vac observed at that phase.
The specimens were then put back into the autoclave and the temperature 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 ppm sodium sulfate solution.
However, cracking was observed on specimens in the liquid phase of the 5 ppm 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 crackin3 occurred during the cool down phase as tests conducted have thus far shown cracking does not occur at elevated temperatures. In addition, testing conducted in the 1 ppm thiosulfate and the 30 i w..
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ppa sodium sulfate indicates that a threshold level of available reduced sulfur is necessary and that sulfur in the surface film of itself is not sufficient to produce intergrani.nlar cracking.
D.
Repaired Tubing Corrosion Tests (P.2.w 2-WWN
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Conclusions Looking back at what has been learned about the TMI OTSG tube corrosion mechanism some conclusions can b+ drawn. Test results show that an active reduced sulfur species.s required for damage to the Inconel 600 cubes. In the absence of this active species no crack initiation or propagation has been observed.
Therefore, in the presence of clean borated water during normal operation, one does not expect cracking. If for some unforeseen circumstance cracking would occur by reduced sulfur after return to operation, it would most undoubtedly occur when the system is open to air at low temperatures. Cracking at elevated tempera-tures under deserated conditions will be governed by those mechanisms and parameters which could affect any operating generator in the industry. As such, industry experience suggests crack propagation rates are slow and leak before break concepts would apply. To fustaer address the low temperature concern regarding the oxydation of reduced sulfur species in the tube surface film, Lithium levels will be administratively controlled at higher concentrations than previously specified.
Therefore, in the event there is formation of metastable sulfur species during an oxydizing transient Lithium will be present to cet as an inhibitor..
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2 IV.
PREVENTICM OF RECURRENCE A.
Introduction Steps have been taken to ensure that an aggressive environment could not be reintroduced into the RCS and cause additional damage. Prevention of direct injection of contaminants will be accomplished by the removal of the sodium thiosulfate tank and by administrative controls. Chemistry changes have been made to include an analysis for sulfur, a conductivity consistency check which will be a signal for unwanted chemical contamination, and an increase in the Lithium conecntration specification due to its inhibiting effect on crack initiation. In addition, to prevent reactivation of the sulfur which is presently in the CTSG and RCS, consideration is being given to remove or oxidize this sulfur. This section discusses the steps taken to prevent recurrence.,
3.
Prevention of' Future Chemical Contamination
,' r f '. - ? ?/.-
3
, ", " Dir,ectiinj'ection:of-foreign chemi)als ;into. Qhe.RCS. during a.
r.
.; periods <of. op' ration ~ is essentially limited to those ' substances.
e
which are placed into the Lithium Hydroxide Mix Tank or the
~
Boric Acid Mix Tank. Injection through the reactor coolant bleed tanks, while not a direct path, must be considered. The probability of injection of a foreign chemical into the RCS frem these tanks is entirely dependent upon the degree of administr-ative controls which are exercised over additions to the tanks.
When the RCS is cold and depressurized, additionel paths for introductica of foreign ~ chemicals exist. A path from the Caustic Mix Tank to the suction of the Decay Heat Pumps is one potential mechanism, and contaminants from the Borated Water Storage Tank and its associated piping systems is another. Since the Sodium Thiosulfate has been eliminated, Sodium Hydroxide is the contaminant which could be introduced via either of these sources. Introduction of other chemicals would depend upon the effectiveness of administrative controls.
Administrative controls which are in effect include (1) clear labeling of tanks in the Chemical Addition Room, (2) locking open the breakers to pumps CA-P-2,3, & 4 and placing them under the administrative control of the Locked Valve and Component List and (3) review of applicable procedures to insure that adequate guidance is provided.
Assuming the effectiveness of administrative controls, the only chemical which has a potential for inadvertent introduction into the RCS is Sodium Hydroxide and this appears possible only when the RCS is depressurized. Under these conditions, additions potentially would not reach OTSG tubing and even in the event..
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that very dilute caustic did reach the tubes, damage would not be expected since the increase in pH value is toward a more benign condition.
Since the range of chemicals which could be injected if adminis-trative controls,were to fail is wide, specific chemical analyses to detect the presence of the full range are not prac-tical. However, because of its deleterious effect on the OTSG tubes sulfur (as sulfate) will be samplad monthly in the RCS.
The other parameters which prove most useful in detecting
. ingress.of unwanted chemical species are pH and conductivity.
These pa'ameters vary with Lithium Hydroxide and Boric Acid-b' r
concentrations with possible conductivity values ranging from a low of approx. 2 micromhos to a high of nearly 20 micromhos and pH values from 4.8 to 7.5, depending upon operating conditions.
Detection of inadvertent additions depends.upon changes in-uicher or both of these parameters which do not correspond to known additions, dilutions or treatment to the system. A consistency. check on conductivity will be performed two times per. week ~ to. conf.irmitbat thelconductivity, reading.is consis. tent:
a,..
- e. c.
s,
~'
.s
..j ; l..?.
with t'hi* kil' b'o'cle 'aEidi lithiudi hydroxide', an'd ionic spec'ies *
~
~
i.
I'
' concentrations.being'me'asured. Spe'cific analyses based upon the conditions under which the changes take place can then further define conditions.
The increased administrative controls, removal of the sodium thiosulfate tank and increased sampling requirements will ensure prevention or quick dete.ction of unwanted chemical contamination of the RCS.
C.
Changes in Oeerating Chemistry Administrative primary 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 initiat.on and propagation, and an analysis for sulfur (as sulfate). A consistency check of pH and conductivity will be implemented. The check will improve our ability to detect the presence of potentially harmful ionic species. When confirmed inconsistencies are identified, addi-tional chemical analysis will be completed in order to identify the unwanted chemical contamination and take steps to remove it.
In addition, analysis will be made for silica, calcium, sodium
-and magnesium. Table 111-1 shows the changes in the Primary Water Chemistry Administrative limits.
1.
The lower limit for lithium concentration was increased from
.2 ppa to 1.0 ppm. This was done because lithium has an inhibiting effect 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...
w-m
'WE*M,-'__--,_,-__K_-'_fT---fl_
- ~ _ _ _ _. - - - - _ _ _ _. - - - -, _. - - - _ _ _ _ - - - _. _
~.
Reactor coolant pH is controlled by addition of lithiu.
hydroxide. Lithium concentration is based-en boren cor tration, and by maintaining it at the maximum allevabl range of 1.0-2.0 ppm, the transport of crud is minimi:
throu ghout the primary system.
2.
Chloride was changed to meet revised B&W Water Chemistry Guidelines.
3.
Sulfur (reported as sulface) was added to the Administrative Limits because of its deleterious effects on crack initiation and growth in Alloy 600.
4.
Because sodium becomes easily activated and is an important contributor to total activity in the RCS, it will be moni-tored.
5.
Silica, calcium and magnesium were added to the
. Administrative Limits to minimize impurities in the reactor s.
? . '
m.,...
- r.'.Q..s e. coolant whichlcould. deposit ca. fuel soi fac e s_.C u.</.. t., 7. ',
4
?.e.*
i
,. g..
D.
Cleanup of Sulfur from' RCS '.
This section summarizes the status of plar.? and testing to either clean the existing sulfur from the RCS surfaces, or put the sulfur into a form that will not reactivate and cause damage. The extent of salfur contamination was idecified and a cleaning process is being developed. However, GPUNC plans to conduct the RCS cleanup using hydrogen peroxide pending successful completion of the process qualification program.
1.
Levels of Sulfur.
The first step in identifying a cleaning process is to evaluate the amount and form of sulfur now present. During steam generator tube inspections performed as part of the overall evaluation of the TMI-l failures, many swipe samples were taken from the inside of the tubes in the area of the inlet (cop) and outlet (bottom) tubesheets. In general, the tubes at the inlet end contained 970-3600 micrograms SO /f t2 and the outlet contained 770-930 micrograms 4
SO /fg2 Measurements of sulfur contamination made on 4
these same tubes during fabrication showed less than 220 micrograms SO /ft2, thus indicating that both upper and 4
lower ends of the tubes are contaminated and that the upper ends have a higher degree of contamination. This is con-sistent with the vacar level fluctuation scenario.
TABLE III-1 THREE MILE ISLAND UNIT I PRIMARY WATER CHEMISTRY ADMINISTRATIVE LIMIT CHANCES OLD NEW SAMPLING SAMPLING PARAMETER 51tEQUENCY FREQUENCY OLD LIMIT NEW LIMIT Lithium NONE
, 2X/vk 0.2 - 2.0 (ppm) 1.0 - 2.0 (ppm) i Varies with boron concentration Chlorides ~
-5X/wk SX/wk O.15 (pp) 10.1 (ppm' Sulfate, (SO =)
NONE Monthly NONE 1100 (ppb) 4
- ..Sodtum NONE' 2X/wk.,
,,.NONE
.* ~.. ll;. a,' ~~;
p, ;.0
-(l.0 ppm i-
':..i :,
., ; ?..,'...., z,...:
v ;
s,..
, '. ; *...,;, V..*
5 3X/wk ~
2X/wk '
4.8-8.5 Check for
. pH
- Conductivity 5X/wk 2X/wk NONE Consistency With Boric Acid and LiOH Concentration Silica NONE 2X/wk NONE 1 2 ppm Calcium NONE Monthly NONE 10.5 ppm Magnesium NONE Monthly NONE 10.5 ppm
- Conductivity is monitored routinely with boren and lithium to establish the expected conductivity of the reactor coolant. An increase in conductivity j
can ' indicate an increase in ionic impurity levels and an investigation should be made to determine the reason for the change so that corrective l'
actions can be implemented.
l
\\
i I?
,--4-.-
l Examinations made in other parts of the RC3 have shown no '
evidence of damage but have shown evidence of sulfur con-tamination. Swipes were made of some plant surfaces with the following results:
2 Fuel Rod (new fuel)
- 522 micrograms SO /ft 4
2 Grid
- 413 micrograms SO / f t 4
100 micrograms SO / f t2 Coolant 4
Regenerative Neutron Source Retainer
- 530-700 micrograms Sor /f t2 144 micrograms SO /f tY
{
RNS. Spring 4
These levels in some cases are even lower in sulfur con-tamination than new steam generator tubing but in other cases show some level of contamination, although it is still below that now found on the steam generator tubes. A con-sideration more important than the level of contamination is the form of the sulfur and the potential for converting from one form to another during temperature transients. It is 5... p f,likely.that the sulfur on the new tubing was in th,e form,of,ggf,gg.,gg,.j g;; ggy, if mo
' e *,
40,.: ; y,
g acnc." The sulfate form is'usually considered stable and relatively non-corrosive under normal reactor conditions.
However, it is probable that the sulfur now present was once in a corrosive form and the possibility exists that it may again be converted to a corrosive form during the formation of reducing conditions in plant startup. The form of sulfur now on the surface, whatever that may be, does not appear to be harmful under shutdown conditions, since repeated in-spections with ECT have not shown evidence of new defect formation or of crack growth.
The fact that no other sulfur related material failures were found throughout the system is comforting. There are certainly other materials present that will be attacked by reduced sulfur compounds, e.g. sensitized austenitic stainless steel. This indicates that although reduced sulfur may have been present, other factors such as metallurgical state and stress were not suf ficient to allow cracking at that level of sulfur.
2.
Cleaning Process Develoement Plans are being formulated for possible cleaning cf the steam generators and perhaps the entire primary coolant system.
The intent is to find an oxident that would quickly convert the sulfur present to a soluble sulfate under alkaline conditions. In additien, the chemical (s) used must be qualified or be readily qualified for use in nuclear power plant cleaning. :
-_Y_
'_C
The process that is currently being explored as the pri=ary approach is the use of hydrogen peroxide. This oxidizing chemical.is formed by the reactor itself during shutdown when coolant hyurogen concentration is icw.
In addition, Westinghouse plants routincly make peroxide additions to solubilire crud early in the refueling cycle to prevent radiological problems later when the system is opened to the atmosphere. A cast program is being carried out at BMI-Calumbus to identify the optimum conditions for use.
Pre-liminary results indicate that the process can be carried out at pH 8-9 with about 25 ppe peroxide at ambient or slighty higher temperatures in 50 to 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br />.
A loop test / simulation will be car _ied out to evalua'e the process on real stressed steam generator tubing and to further evaluate any material effects. A workshop was arranged with technical representatives of the three reactor vendors, EPRI and outside consultants to assure that all areas are covered in these tests. Engineering tasks to determine optimum plant parameters and to develop a plant
'.3 :./ s.i,~ '.. -
',4.r.' :,, 3,. Procedure.are procee. ding.in-l parallel.
It:is.. anticipated I
'that the'pr'oces s' will be ready. for plant' use.in early-to-mid
' Decemb er.. "
E.
Conclusions Greater controls on chemical contaminants, greater controls on primary system chemistry and reduction of existing contaminants level will assure that unwanted chemical contamination and damage to RCS components will not occur in the future..
w.m meo-.
.--e.-
4
1 V.
KINETIC EXPANSION REPAIR DESCRIPTION SUM'd.ARY A.
Description of Process and Geometrv 1.
Introduction TMI-1 OTSG tube examinations have revealed a large numoer of tubes with defects within the upper tubesheet. A defect is defined as any eddy current indication ir.cerpreted as g~sacer than 40*. through wall. The limits of eddy current detectability are defined in Section IX.
The repair approach is to establish a new primary system presture boundary below these defects. A kinetic expansion of the tube within the tubesheet will be the approach used to ef-fact this repair. All tubes which are not currently plugged -
will be kinetically expanded irrespective of whether or not they have a de ~ect, and irrespective of whether they will be plugged in the future. This repair will provide a 1,ad carrying sad essentially leak-tight joint below known de-facts. The following sections summarize the repair program.
Details can be ' found in Reference 1 and Reference 23.
2.
Kinetic Tube Exeansion (Proprietary)
.~...
n g
en P
C.
Qualification Program A series of mechanical tests and chemical and <:orrosion tests were perforned to qualify the kinetic expansion', and the kinetic expansion process to meet the design goals of producing a joint capable of carry,ing required loads, praviding a leak tight seal, minimizing residual stress, and tube preload changes. A series of preliminary tests was conducted to establish the optimum parameters for a kinetic axpansion process that vill yield acceptable joints with low residual stresses. Additional tests were conducted on a full size steam generator at B&W's Mt.
Vernon Works. A more detailed description of the tests and results can be found in Referenca 23.
1.s sechanical' Tests Preliminarv Leak and Axial Load Tes M (Proprietary)
- a...
_.. 7 9
b.
- v:
- u s c.
Effects on Residual Sulfur Testing was performed to assess what happens to the sulfur en the surface of steam generator tubes (i.e.
driven into the base metal) af ter kinetic expansion.
It was determined that the sulfur concentration on the tube I.D. in the area of the kinetic expansion does not change, that it is not driven further into the base metal, and that the expansion does not significantly alter the grain boundary structure in a way that would trap sulfur.
D.
Repair Testing The following inspections and test programs were setup to provide additional assurance that the qualification program results are representative of in-generator expansions. An in process inspection and monitoring program will use ECT and profilometry and compare qualification testing results to sceual -
'. * ~
_ _ _ _ _ _ _ -,.. _ _ - - _ _ _ _, _... = _. _ _ _
expansions. The pose Repair and Hot OTSG Testing programs 'will test the expansions and plugs for leaks, and place operating and transient loads on the new joint.
1.
In Process Inspection and Monitoring The in-process inspection and monitoring program is designed to verify that the in-generator expansicas are similar to those obtained in the qualification program. Actual CTSG expansion profilometry and ECT results will be compared to test program data to verify that the expansions are simi-lar. Data obtained from TMI-l will also be compared statis-tically to test program data. The program consists of video surveillance, profilometry measurements, and eddy current (EC) examinations.
Video surveillance and recording of operations during the expansion process will be conducted to verify that proper procedures were followed and that the correct tubes were e,xploded oriexamined.
, ~ s.', V..r:
- l... s:...... :..
.y, tgichi;bn sam $in....ge 'shal1-b'e p.erforme'd onth'e' tubes 'ex-t. s:
- l.'.
,,.?
.i S-
.a n.. w-panded by the initial charge strength in the first three lots in each OTSG and will consist of ECT and profilometry.
ECT using an 8xl probe shall be performed on almost 100% of the tubes expanded in the first lot in one OTSG. Profilo-metry shall be performed on expanded tubes selected at random from the first three lots.
In addition to verification sampling, random diamater and depth checks sampling shall be done following initial expansion. The sampling plan can be found in Reference 19.
2.
Post Reoair Testing Following repair, testing will be performed to verify the acceptability of the joints. Post Repair tests include:
a.
150 psig bubble test.
Upper tubesheet plugs and expansions leak test.
b.
150 psig drip test.
Lower tubesheet plugs and expansions leak test.
ii i
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.. n
_?
s 3.
Hot OTSC Testine
~
Hot OTSG testing will include transients that will place operating loads on the new joint. These transients will include:
1 a.
normal cooldown b.
accelerated cooldown c.
1400 psi operational leak test.
A more detailed explanation of the testing programs can be found in Appendix A.
E.
Conclusions The following conclusions have been drawn from the qualification tests and analyses:
Based on.a qualificatiott program, the kinetic joint meets. or n.a,q, exceeds, the/'de'aign.basesg'o E. t.hcJoriginalgjointj.; including, the-( ; '. -
. /, ".
.g. r..
,. ; i T'y:, "s
-.A foll'owingffac tdrs: ' "
" ~ ~'
7'"
a.
Load-carrying capability.
b.
Tube preload.
c.
Minimization of resiuual stresses.
Leakage is projected to be less than one-one hundredth of the technical specification limit of 1 spm. Kinetic expansion in the upper tubesheet is a safe and reliable method of repair for all tubes that will remain in service in the TMI-l steam generators. The tube joints will remain structurally sound and essentially leak-tight during all design conditions over at least a five year period...
a.
ye 9
e
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- 3 VI.
EFFECTS OF EXPANSION REPAIR 4;
'I The possible effects of the kinetic expansion process with respect 2
to introduction of chemical impurities, the ef fect on the OTSG structure, the effect on tubesheet corrosion characteristics and the effect on existing plugs have been evaluated.
~
r
,]
A.
Possible Introduction of Chemical Impurities ( ['re frbsf6' i
4
- 4 C.
- h...,
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- .
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~;
". 3 4
R:
. M.
22 43 B.
Possible Effects on OTSG Structure hl Z
It has been postulated that the kinetic expansion may, because of the large number of tubes involved, have significant effects on the steam generator as a structure as well as on the indi-
~
vidual tubes.
i l
For individual expansion, evaluation of the tubesheet ligaments
~
has shown no significant effects of expansion. It was postu-c.
1 aced that with multiple kinetic expansions there could be a l
h shock wave reinforcament such that the sequence of explosions or
~
the length of the primer cord should be controlled to insure that the tubesheet is not overs tressed. The concern was that 3
the shock wave may travel at about the speed of sound through L
^7 the material, and if adjacent tubes exploded in a manner such l
that their shock wave reinforces shock waves from other tubes, there could be a condition where the tubesheet is overstressed.
l' s
- .J-)
m.
4 *b 13 a-
0 Testing was performed in the steam generator at Mt. Vernon using strain gages and an accclerometer to demonstrate that the coin-cident explosions of the maximum number of tubes to be expanded at any one time was acceptable. This was done by exploding 122 charges in the longest row in the generator. A maximum stress intensity of 95,000 psi at 800HZ was obtained at the strain gage closest to the expanded row.
This compares to a static yield strength of 70,000 psi for the tubesheet material. Since the yield strength of steel increases markedly at high strain rates (up to twice static yield) and that no residual strain was measured on the strain gauger following expansion it is concluded that no plastic deformation occurred. The maximum stress intensity recorded for the veld between the tubesheet and shell was less than 10,000 psi. The strain guage on the tube recorded very low values indicating that no significant excitation,of the tube bundle occurred. A fatigue analysis has been performed and the tubesheet at the periphery was found to
'be limiting. The analysis was conservative in that it assumes that the principal stresses occur simultaneously and that all blasts yielded.the same peak.value. lDus other strain guage
- .,,.W.', d; i
- l -
,'f 1,o'catio'nUclearlf 's'how that'.the;s tress ' diminishes as the '
distance from the expansion increases. The results was a maximum fatigue usage of.12.
From this data it was concluded that the use of up to 137 charges is acceptable and the total number of separate blasts will not present a fatigue problem.
In addition, Foster Wheeler has kinetically expanded over 2000 feedwater heaters and expanded as many as 5000 cubes in a heater in one detonation. They report that they have never experienced any tubesheet overstressing problems and do not believe this is of concern since the plan is to expcnd only 132 tubes simul-taneously plus any misfires from the previous row up to a total of 137 total tubes for the TMI-1 Steam Generator repair.
The combination of Foster-Wheeler experience and the strain gage data show the explosive expansion process to have no adverse effect on the steam generator.
C.
Corrosion (Proprietary) i
--~
mms:w_.---_.____r-
~-
_-mm-.
_-,,p l
D.
Effects of Expansions on Existing Plugs The TMI-1 OTSG tubes have been taken out of service by four different procedures:
1.
Explosively welded plugs - Plugs inserted into the tube and j
explosively welded in position within the tubesheet.
2.
Welded plugs - Plugs welded to the tube ends or tubesheet at the top of the upper tubesheet.
3.
Hydraulically expanded tubes sealed with a welded plug -
tubes that-have been immobiliced by expansion af ter a short section of the tube within the tubesheet was removed. The Cubes were then taken out of service by installing we.1ded
~
- I',. plugs in the 'tubeshee't openings. "
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 sill not af fect their mechanical integrity or leak tightnes s.
Tests of the kinetic expansica 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 pe rmanen t tubesheet ligament deformation. This leads to the j
conclusion that plugged tubes adjacent to kinetic expansions 1
will not be altered by changes in the tubesheet ligament, since no permanent change is noted.
During additional tests on an actual OTSG, B5W 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 degradation.
l Th ird ly, 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.
Tests were performed on qualification blocks with rolled plugs in place and e.< plosive expansions of all adjacent tube i
locations. Leak race 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. '
e
Lastly, a pre-operational post-kinetic expansion pressure test of each generator will be made to verify the integrf ty of thd primary to secondary pressure boundary thus providing added assurance that the plugged tubes have not degraded.
E.
Conclusions :
Based on the above evaluation and testing, the kinetic expansion process will have no adverse effect on the OTSC structure, tube-sheet corrosion, or plugs previously installed. In addition, a cleanin6 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 pro, cess.
4 0
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.g VII. PLUGGING' REPAIR DESCRIPTION
SUMMARY
,9 A.
Introduction
?.h Those tubes which,have defects below the 16" from the primary y
surface of the upper tubesheet (% ) and,cannot be recovered and 4
returned to service by the above described Kinetic Expansion
.i repair shall be removed from service by plugging. A defect is j
defined as any eddy current indication interpreted as greater
{
than 40% through wall. The limits of eddy current detectability j
are defined in Section IX.
There are a total of 259 tubes in A 4
and 88 tubes in B OTSG that have been plugged with either Westinghouse rolled plugs or B&W welded and explosive plugs. It is projected that an additional 625 tubes in A and 174 tubes in 4
B OTSG will be removed from service by plugging af ter 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 bottom tubesheet.. Defective tubes.in the.
- . *, */.
ar.ea of. high.ateam cros.a flow 46,th span,b.will,be s tabilized to
". 4
.th'e'14th' tube' support plate.- Approximately 450 tubes will be -
stabilized. The purpose of tube stabilization is to minimize 4
the risk due to propagation.of tube defects located in regions m/
with high potential for flow induced vibration resulting in
$g circumferential tube severence and causing damage to adjacent
.d tubes or creating loose parts. The lower tube end will be
,j plugged with.an explosive plug. The following sections give an evaluation of the methods selected for tube plugging and stabil-ap ization, and a description of the types of plugs to be used.
d B.
Types of Plugs g
M.
?!
'l.
B&W Welded Tapered Plug, Welded Cap, Stabilizer and B&W Explosive Plug 3
B&W Welded Tapered Plug is used to plug the bare upper tube-sheet hole for tubes where the tube end has been removed.
3 B&W's welded cap is used to seal the upper tube end for W
those tubes which will be plugged and stabilized. Prior to
.j, installing the weld cap, the existing tube end will be
~.( machined of f leaving a portion of the tube end and the .2 existing veld protruding above the tube'heet surface. The s M weld of the nail cap will fuse with the existing seal weld, ] providictg the desired pressure boundary. J B&W Explosive Plug is used to plug LTS tube ends where B&W j. plugs are used in UTS. Both B&W plug types MK-1 and MK-3 .;i have been qualified for OTSC tube plugging and used in the
- {
operating B&W units. 4i B&W standard design atabilizer rods will be threaded onto the welded cap to form a stabilizer assembly of the desired ? k s 4 w.w--.2 22_^'",_ _~_?__ ___[~ __}'___ [ __ [__
leng th. The stabilizer is a multi piece assembly 32 solid- ~ rod made of Inconel SB-166. Joint tightnes; is maintained by crimping the pieces together beyond the thrended sections. The segment lenSch is dependent upon the tube bundle location. B&W welaed tapered plugs, welded cap, explosive plugs and stabliaer rods have been previously qualified see Re.Terences 30 through 35. 2. Westinghouse 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. P , y, - The. Westinghouse rolled plug is machined from.bar. s tock. that has received a ch'ermal heat treatment which has been demon-strated by laboratory testing to have improved resistance to intergranular attack in caustic and polytheonic acid .envifonments,' compared' to ' treatments at dif ferent temperatures and times. The Westinghouse Roll Plug Qualification Program for TMI-l has been completed for a 5 yeat life, and results are documented in Westinghouse Report WCAP-10084. C. Plutning and Stablization Criteria The OTSG tubes were divided into seven areas in order for dispositioning for plugging and stabilization. These areas were: defects between US+5 and US+8, between US+4 and US+5, between US+0 and 'JS+4, between 15th TSP and US+0, between ist TSP and 8th TSP and between the 10th TSP and 14th TS?, defects in areas of low crossflow, and defects in the lower tubesheet. 1. Tubes with Defects Between US+5 and US+8" Tubes having defects between US*5 ana US+8 cannot be effec-tively repaired by the 22" Kinetic Expansion. A minimum length of 6" expansion is required to establish a leak-tight, load-carrying joint to assure that the OTSG integrity is retained under the nose adverse conditions during operation. Therefore, those tubes with defects between US +5" and +8" will be removed from service. They shall be kinetically expanded and plugged. Even if the existing crack would propagate in the future to a 360* circumferential crack and eventually the tube should sever at US +5" elevation, there is still 3" er.pansion joint below the severance, which will provide enough engagement to maintain the preload in the tube. A 3" kinetic expansion joint below the defect will assure that the tube is still in tension under the mos t, we e u ww +-sw, =_= A - =
-u.___ l I severe transient during normal operation. The natural ~ frequency of a severed tube with a 3" expansion below the defect is'about the same as an intact tube since tensile preload is maintained by the expansion. Therefore, its potential for flow induced vibrations (FIV) failure is about the same as for an intact tube. We concluded that these tubes need not bs stabilized. ~ Both B&W welded cap and Westinghouse rolled plug can be used to plug these defective tubes in addition to a 22" expan-sion. 2. Tubes with Defects Between US+4 and US+5 According to analysis performed by MPR Asscciates a tube which has at least 25% of its cross sectionci area intact would retain its preload. Therefore, tubes with less chan .f 75% circumferential-are length defect.can be simply plugged as in 1. above'whereas these tubes with greater than 75% circumferential are length. defect will be stabilized as in \\,0 -i ,'"h* f * '.'.? N'O : > ~j
- x.U' ' l Y. Y -l ;.
yQ.{ ' ':5 ' ' ' '. f ~ :'V h 4 / 3. Tubes with Defects Betseen US +0 and US +4" As described in the above paragraphs, a minimum of 3" kinetic expansion joint below the defect is required to inhibit the dynamic instability in the 16th span due to FIV. Tubes with defect at or below US+4" would not have enough joint length even with 22" expansion, to assure that the tube will not slip under the most severe transient during normal operation '.i.e., 100*F/hr. cooldewn). As the tube load decreases to zero, the natural frequency of the tube may reduce to a critical value that results in dynamic instability. Therefore, tubes in this category shall be plugged and stabilized. 4. Tubes with Defects Between 15 th TSP and US +0" Tubes having defects in the 16th span should be plugged and stabilized. The progressive degradation of the defect has the potential to cause severence of the tube in the high steam cross flow region. The severed tube could damage the adjacent tubes if it is not stabilized. The stabilizer vill function as a damping and capturing device which will inhibit tube fatigue failure Cue to FIV in the vicinity of steam cross-ficw. 5. Tubes with Defects Between 1st tsp to 8 th TSP and Between the 10th TSP to 14th TSP Either B&W welded cap or Westinghouse rolled plug can be used in addition to the kinetic expansion. Tubes with defects in this area do not need to be stabilized due to low steam crossflow. -. ,,,mp,e a g a.., a e '*'*A-f a .. m 3
i-Afk O & *hk ////p N$g IMAGE EVALUAT!ON k//77 \\! $7?/ TEST TARGET (MT-3) gf/// yl' %,'f'j;ji<gg {fA* /// + M, >$ ++4$ "$ y u O +@
9 ~gh 40 ~ T' 9 h>/ <[% ((g IMAGE EVALUATION kf777 %[4r '/% g TEST TARGET (MT-3) +>/ sq%p l.0 lS3a M 't.u BE i_ lllb D 1 l,l I!J1 1.25 I l.4 1.6 i 4 150mm 4 6" th,kr3,4 $3 [e,' 44' o (&
4 r--'-----~ i 6. Tubes with Defects in Areas of Low Crossflow the 1st Sean, 10th Soan and 15th Sean According to 3&W Analysis (Reference 48), flow-induced vibra-tion in these spans wi'l not be as significant as that occurrin6 in the upper most tube span (the 16th). The curbulence-induced vibration amplitude in these spans should not exceed 10% of that measured in the upper span. The maximum displacement seen in the 16th span during steady-state operation at TMI-2'(Reference $1) was 3 mils peak half amplitude. Therefore, the maximum displacement seen at the lowest span is estimated to be 0.3 mils during steady-state operation. Analysis is being conducted to define those crack geometries which would be stable when exposed to the turbulence induced vibration in these areas of reduced crer-flow. Thore tubes with defects that are predicted to be unstable w.1 be stabilized while those that are stable will not be stabilized. 7. Tubes with Defects. in the Lower Tubesheet f i ^J4 vr;,th.'.b. [. [ *,) $P. *.CTtie'r'e'kiddh b k' fd[tikb s.Ih[icS h$veid fhett iirY'Ne he*r Y .cubesheet. These tubes will be removed from service using Westinghouse rolled plug. An explosive plug may be used.if the defect is located at :he upper 10" of the lower tube-sheet. A welded plug shall be used in lieu of mechanical rolled plugs if the defect is in the rolled area. D. Post Reoair Testing The following post repair tests will be perfor=ed to verify plug integrity. 1. 150 psig bubble test 2. 150 psig drip tes t 3. 1400 psi operational leak test Details on post repair testing can be found in Appendix A. E. Conclusions The OTSC Tube Plugging Plan will rastore the pressure boundary integrity of the steam generators by removing defective tubes from service for those tubes which do not have suf ficient length in the upper tubesheet below defects to form a new load carrying and leak tight joint by Kinetic Expansion repair process, or for those tubes which have defects below the secondary surface of the upper tubesheet (US). I The plugs used have been previously qualified for use, and i testing indicates that previously plugged tubes will not be damaged by the expansion process (see seccian VI). Tubes which have defects in the 16th span will be stabilized, thus preventing tube severence due to flow induced vibration. - $1 - I ( me peasp se e a W,*
- VIII. CCMPARISCH OF TUBE PLUCOING WITH DESIGN Z ASIS A.
Introduction ~ This section describes the results of analyses performed to de-termine if the steam generators could be safely operated with up to 1500 cubes plugged. The first part of this section reviews the operational. consideration of operating with tube.s removed from service for: reduction in r2tal flow and margin to Departure from Nucleate Boiling effects of asymetric flow distribution, ef fects on flow coastdown race, effects on steam generator mass inventory and capability of natural circulation. The second part reviews the effects of re=oving tubes from ser-vice on small and large break loss of coolant accidents as well as all other accidents and transients analyzed in the FSAR. These analyses have concluded that the margins of safety as defined in the Technical Specification will not be reduced by i operating the IHI-l steam generators with up to 1500 cubes remove'd f rom service. -j3.r. t perational Performance, O ~ .n. .. - v ',, < m., 3,, : 1. RC Flow Rate' and Margin to Minimum DNBR The calculated RC flow race for 411 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 ceduction in tubes available for RC flow will cause the tube bundle pressure drop to increase. Since the remaining system pressure losses are about four times greater than the tube bundle pressure losses, only a slight reduction in total RC flow race will rtault. The total RC core flow for 1500 plugged tubes will be the same as the sy=:etric 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 of 0.8%. (Reference 42) In order te determine the impact on the existing steady state Departure from Nucleate Boiling Ratio (DN3R) resultic3 from the RCS flow reduction at steady state, a study was performed to determine the minimum RCS flow rate required to maintain the existing DN3 ratio for the T4I-l licensed power level of 2535 MWt. The existing DNB steady state ratio of 2.0123 was determined at a conservative power level of 2568 MWt and an RCS flow race of 106.5% of design flow. The methodology for the analysis was to calculate the hot bundle flow by using a CRATA (Reference 36) core model which took heat balance input from the CIPP code (Reference 37). By using the hot bundle flo f in the computer code TEMP (Reference 38), the Mini =um DNBR (MDNBR) was calculated for 52 - g a Amer-== a= = - -** -==JeC m
FIGURE Vill.1 REDUCTION IN RC_ FLOW RA E VS[NU$1bER OFTUBES PLUGGED PER STEAM GENERATOR - s 110 108 g 3 2;
- 2.. ;...'. 9; ~.~.,Wlh ' : &. b ' :. a Y ~'. :. ' '.g;:~ k ^ *: :.- ?
' n:: a ,' : :'r ' ~~ '. ' i.. i. ... ;G. _ i 106 c -o 6 w 3 104 2 &cc: J / b-0 102 100 1 I I I I I I 500 1000 1500 2000 2500 3000 3500 4000 Number of hubes Plugged in OTSG
- e. e
- p. m
- M98 g
- T@
-. i p y -- p 4,n q g y y .g gy =Mge pgy y eg g D< ,y@m--e= ~ -e
. ~ ,_g.. 4 1 the hot sub channel from the BAW-2 correlation (a correlac' ion. The results indicate that DN3R value of 2.0123 can be maintained 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 mininum calculated RCS flow rate at TMI-l has been 109 5% of design flow. The maximum error on this value is 1.5%. This results in a mininum available flow of 108% of design. - This will be reduced to 107.2% af ter the ~ tubes are plugged. This is substantially greater than the q design basis flow race of 106.5% which would be required to maintain the design basis steady state DNBR value of 2.0123 4 at 2568 MWe. For the TMI-l power level of 2535 MWI, the 104% design flow requirement to maintain the same DNBR ~ provides for an even greater margin. It can thus be very conservatively concluded that the plant design basis flow > rate considerations will be preserved with 1500 cubes ~ plugged.. 4 1' . l q,.Q.:
- . N ;. D Q' '* W.~.t.'; :. {..
5: '. . -:U. '. s '
- ? -r Asymm. r. d e 'C Looo Flow;.r.% Dis
- tribu t ton-i r
2. etric R t . The final plugging pattern will be about 6% of the tubes in the A Steam Generator and about 2% of the in the 3 Steam Generator. In order to investigate the asymmetric ef fect of the RC loop flowrates, an evaluation of' an exaggerated i plugging pattern of 1500 cubes in one of 'the TMI-l steam generators has been performed. The Loop A flowrate will be approximately 2-1/2% smaller than Loop 3. Field data at TMI-l during the last cycle has shcwn 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 } chus be a somewhat more balanced loop flow distribution. The new flow dif ference is expected to be approxicately 0.5%. o 3. RC Flow Coastdown Rate With a significant number of tubes being plugged, the resistance 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 combined core flow during the coas tdown may also be different. Further, the minimum margin to DNBR during a loss of flow event is known to be dependent on pump coautdown rates. To address these issues the following analysis was done. t -1 I l l L l .m
A computer analysis has been conducted using the S&W code " PUMP" (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 race is still bounding. Figure VIII-2 summarizes the data obtained from the four pump coastdown transient performed with the TMI-l version of PUMP code and compares this data with the FSAR analyzed flow coastdown. This ccmparison shows that the flow even with 1500 plugged tubes starts at a higher level chan the flow assumed in the FSAR analysis and coasts down at approxi-mately the sama rate since the flow is at all times grt &tir than th'at assumed ~in the FSAR the minimum margin to DNB will .not,be. changed. 4. Steam Generator Water Inventerv and Ocerating Level Indication l-,/...,,:. ::,,'.. ~ ?.} >.e,..\\ ".c, C-The water inventory in the steam generator, will increase by a small amount due to the decrease in average quality in the plugged section. KETRAN-02 (Reference 43) and TRANSG (Reference 44), which arc ooth one dimensional transient thermal hydrsulic computer programs with slip option, have been used. The inventory increase waa calculated to be 5% or less, which is less than 2000 pounds with 1500 tubes plugged. Total secondary side flow will increase only slightly with decreased steam outlet temperature. This would tend to cause a slight increase in pressure drop. This increase will be offset by the reduction in average quality (increase in density). The net effect should be littl4 or no increase in the startup level. 5. Capability of Natural Circulation The impact of steam generator tube plugging on the capabil-icy of stable transition to natural circulation was e:camined by using the B&W computer program AUX (Reference 49). Symmetric plugging of 1500 tubes in each side was assumed to be the bounding case. Figures VIII-3 and VIII-4 compare 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 flew with 1500 cubes plugged 1 t' i I i l i I ---m*me_.
- Pe* * -
~ u ,i COMPARISON OF FLOW COASTDOWN 'i CullVES - FS AR FOUR PUMP CdASTDOWN VS. FOUR PUMP FLOW COASTDO' WN WITH 1500 PLUGGED T UDE;- 120 I t; i 1 1 I c 90 en j O y 1500 klugged Tubes - o N M S o u. 60 C t I e FSAR a s o = o g, o ,.[J M ~ 30 1 '.s. I l p. i ~i 0 -* i I O 8 16 i Time (Seconds) o I 1 0
.. _, _3 ;;- - FIGURE Vill-3 mog* u -Q C. 4 e : ts eHo a en &o? O - m.= O w o. o o N" I O 2 o o o r4J ~ p O. .. g ~ ,Q I o J c .t 4 l j .,a3 g uJ - v. v. m2 r> 42$ 7 s 203 5 o 0 C ( e o Zd m -OW ~ Om .5 3 0 Jo G..J W4 m> O e w O HO ~ W W r w l W 4 O C 2 7 N O l 6 6 I i i i i e 1 4 4 I i i i i i i l O C C o o C o o a C N, o W e e ('38S/91 Mold aJoo lezol O-e 4. m
- l
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I! i' il. i! i ds g mc)c3m4 ?A gd 3 ue lPg g su el b P us Teb 0 u 0 T 51 O 0 0 2 1 N O 0 0 IT 0 A 1 L UC R .I C ., L A 0 R 0 - U' 8. e.- a5 '. 'A E 6 Tf NM ) NI s T d O S n GV oc N1 0 e I 0 S GP 6 ( GO e U O. m Lt i PT T E0 Bt i UT T F 0 0 O 4 T C E F F E 1-I M 0 0 T 2 k 0 0 0 0 0 0 0 0 9 8 7 6 5 6 5 5 5 5 5 n coo eof ? i5 i l 4 .4 j11' i ) 1;' a<
'J ..-,w. is about 8% less than that with no tubes plugged.- At no - ~ time is natural circulation lost and the reactor coolant system remains subcooled. The subcooling margin for 1500 tubes plugged is only about 2*F less than the case without plugging (about 90*F). Therefore these analyses have shown that natural circulation is still an effective method for decay heat removal. C. Accident and Transient Performance 1. LOCA Analyses The potential effects of SG tube plugging on generic Large Break LOCA (LBLOCA) and Small Break LOCA (S3LOCA) analyses (Reference 40) with 1500 cubes plugged has been examined. With about 6% of the tubes in the A Steam Generator and about 2; tubes in the B Steam Generator being plugged, the generic (1772 MWC) LOCA analyses for B&W 177FA Lowered Loop Plants remain valid for TMI-1, with continued operation at core power' levels.up to the licensed 2535 M'Je at the ~. .. existing',LOCA ' limits. An' overview of this examination is
- ..;2. l.
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- 3. ~ F. ;':.,' W ? '<'.i,
.a y . ~ g. :u,,; e.' ~. a. S3LOCA Concerns The evaluation models used in the existing SBLOCA analyses (Reference 40) assume equilibrium condir. ions within the control volumes used to model the SG secondary side. For this reason, the localized cooling effects of EFW spray on particultr tubes, and the effects on this cooling if particular tubes are deactivated, cannot be accurately predicted with these models. In the application of the revised SBLOCA evaluation model (Reference 41), it was assumed that: i ( l. The percentage reduction in the number of peripheral tubes removed from service will degrade the EFW i spray cooling heat removal capability in a 1:1 relationship. 2. The degradation in heat removal capability from EFW spray cooliag translates directly to a reduction in i depressurization rate by a 1:1 retationship. I 1 In reality, these relationships are expected to be conservative. Since if EFW spray impacts a deactivated tube, it will not be heated and/or flashed immediately i but will either: l l, 1 l I j - - ~ p_
1. Be redirected onto adjacent active tubes, or;- 2. Flow inward into the tube bundle, -providing coolin's to activa interior tubes, or; 3. Fall into the saturated steam or saturated water region, resulting in increased cooling within these regions and/or an incre.se in the fill rate to the appropriate level setpoint. 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 analses. In this evaluation (Reference 42), cwo 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 depress'urize the RCS. ~ ~ ~ E,.' ? N, # ',Y J.,';k.(f/.' O.*.l* tW : 'sj:.!,J.~.Tlie :0.~0'lJf tE. b)ldak'. wis[inalyze'd' becadse "thib.l war theI. -largest break size which would result in RCS repressurization. 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. Worst Case 0.07 ft2 Cold Leg Break with One HPI Train For this break size, the primary system pressure decreases below 1000 psi (approximately the secondary side pressure) at about 300 seconds. After this time, 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 1750 seconds. The maximum time that SG (and EFW spray) 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. i l The plugging of 1500 SG tubes will result in a reduction of the initial RCS liquid inventory by about 200 f t3 I This results in the core being uncovered about 3 seconds i earlier and in approximately a 10F increase in peak l cladding temperature (to about 1100*F). This will have minimal it:act on the cuccome of this accident. It l should also be noted that the generic analyses show that, I l ! l l
for a 0.07 ft2 break with 2 HPI trains, the core does not uncover and temperature remains below 700*F. 0.01 fg2 Cold Leg Break The 0.01 fg2 cold leg' break case was evaluated using the revised SBLOCA model. Two cases were analyzed considerin'g 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 cor. denser mode. It was found that: With a 1600 psig low RCS pressure ESFAS setpoint, the 0.01 fg2 case will result in ESFAS actuation regardless 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. .:,.. ~f.; s-. C.G;. y c.J .u..'r.:.y..t per.iphe'r,al' pe.gions.. Th' leforec.the'SG4 eat reinova tTateY, :,'t.I W e ?*-
- ^.
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 fg2 break :ase'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, sufficient steam generator EFW spray heat removal capability remains so that the race of RCS depressurization is reduced by only about 12%. Even with this reduction, 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 effect on SBLOCA transients. In sunnary, these small break size LOCA analysis show that for the previously limiting case of 0.07 ft2 cold leg break with caly one HPI train avail-able, peak clad temperature increased by only 10*F to about 110G*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 effect on the outcome of the transient since a minimum of five feet of coolant remains above the core for both the
- l 6
t
'v t
er-.**- - - + ' * -
1 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. L3LOCA The impocrant parameters for the LBLOCA which are effected by plugging of tubes are the initial flow and flow coastdown. The effects 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 TMI-l will reduce total system flow. However, the reduced flew will still be greater than the fleurate used in the generic L3LOCA analyses. This, coupled with TMI-l's lower core pcwer (2535 MWt vs the generic 2772 MWt) provides margin in initial conditions for TMI-1, relative to che generic analysis. During the early ~ Jportion of a L3LOCA transient when the reactor coolant pumps are coasting down, the analyzed system-flow rate 1.ce,. h :- 4 ' :?-(,: f c q :2..} '.N.Dee VIIp B'.'14)gitti.isdd_icional. resis cance dde. toc. '., c., t. - - ' ~ plugging wtrl 'be greater' than assumed designed flow race with the case of no plugging. The reduction of 200 f t3 of primary coolant volume will have little impact to the consequence of L3LOCA. 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 thrcugh the core during the blowdown period. For about 11,000 f t3 total fluid loss within approximately 24 seconds, the reduction of 200 f t3 will correspend to 0.4 second shorter blowdown time and thus a slightly earlier fuel heatup between blowdown and refill. This difference is minimal and therefore, the resulting peak cladding temperature that occurs during this developed reflood stage should not be changed. Also, vent flow is conservatively neglected during the refill /reflooding phases of L3LOCA analyses for the 177FA Lowered Loop plants. Tube plugging will therefore have no impact on core flooding races. 2. FSAR Analvses of Other Transients An assessment of the impact of the plugged steam generator tubes on the ' ability of the NSSS to safely respor.d to FSAR i transient conditions has been performed. The plant is expected to be operated with up to a total of 1500 SG tubes plugged for both steam generators at the licensed rated 1.. 8 m s e =s mo o wswo,=ewee o e =am.w-wwanums.me.-wm** -eiemoweme w -i,-- - = - - ' - - + - -b-e==-
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.
Uncomoensated Goerating Reactivity Changes This event is core burnup related and is normally compensated 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 produced in the core
- remains in the primary system,
.i 'i.e. (;no,. steaar generatoi.. heat ; trans fer. ;.The tub.e - - t s.
- f.. -. g,...
2l,.. g...,,..,..;i. - e o- - ' plugging 'wi'll'se'sult 'in a' 200 'f t3 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 consecuently slightly higher heacup race the peak pressure may increase 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. c. Moderator Dilution Accident The moderator dilution event is a relatively slow over-pressurization transient due to increased reactivity by bcron 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 (pumn Startue) l The pump startup event is a small overcooling transient l due to an increase in flow from an idle loop. Th e analysis performed for Section S.B.3 demonstrated that I the pump characteristic curves differences are negligible for the unplugged and the 1500 plugged tube cases. The reactivity change will cause a power and RCS pressure increase. The transient will b6 terminated by either the high reactor pressure trip or the power / flow trip. The FSAR remains bounding. i r i '~ ~ " N
e. Loss of Coolant Flow See Section VIII C l. f. Stuck /Droceed Rod Event The FSAR analysis is bounding since SG heat transfer and RCS flow do not effect 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 energency { eedwater system are required. The impact of tube 11ugging on the ability of natural circulation is l demonstrated in Section B.S. h. Steam Line Failure ~ sp: l'oN 3 g"Q E.i ~~IS.9 [ : ',',:,36,; ? @.licensins b'as'ishor'TMI-% is.the doubfehended'.rup-f 5,,:;3 .3., ture. *This FSAR analysis i' based on a very conservative ' ~ s prediction of SC secondary inventory. Operation with plugged tubes results in a secondary inventory greater than operation without plugged tubes but it is not as great as that considered for the FSAR analysis. Secondary inventory is one of the parameters that deter-mine the safety considerations of return to criticality, 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 contras t 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 a suming a 435 ~gpm leak from a completely severed OTSG tube. The RCS is depressurized and isolated at 34 minutes, at which time leakage from the RCS is assumed to stop. The reduced RC flow as a result of the plugged tubes is greater than the RCS flow assumed for this 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.
Offsite dose free the Tube Rupture Event will not be affected by plugging 1500 tubes because neither the time required to isolate the OTSC nor the leak race from the broken tube is affected by the tube plugging., .'e..94e e e.ere_o pseeeee-9. hg.96*- --...5. +.- g
,7._..
- j. Fuel Handling Accident This accident is assumed to occur during outage a refueling outage while the reactor is shut down.
in steam generator plugging pattern has no impact Change to the assumptions. k. Rod Eiection Accident Fast reactivity excursions are not influenc:d by SG heat removal. The event is an adiabatic heacup. The FSAR analysis remains bounding. 1. Maximum Hvoothetical Accident The analysis assumed that a given amount of radio-activity has been released following core exposure and studied the effectiveness of the building spray system and Engineering Safeguard systems leakage on to the environment. 6tn,.,7 <+a.N Mi ne:,scen.'ari l add 'thus' have no~ imp c' 'ori che'c5ns o ..,Y 5 '-7 d n.,; ;,.. v-; $ - i c-c s Vaste Cas Tank Rupture m. The Waste Gas Tank is located in the Auxiliary Building and the analysis of its rupture is not related to the steam generator's function. The event is thus unaffected. _ Loss of Main Feedwater/Feedwater Line 3reak n. A loss of feedwater accident is an event resulting in primary system heatup, increased pressurizer level and pressure, and reactor trip either by anticipatory function (loss of main feedwater pumps) or high RCS pressure. The long term cooling relies on emergency feedwater heat removal through the steam generators. With the plugging of 1500 cubes 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 le el regardless of the minor difference in heatup rate. icy of removing decay heat up to aboutEmergency feedwater has th 7 percent power. This is greater than the decay heat at any time af ter shutdown. In the SBLOCA analysis using the revised LCCA model it was demons trated that heat transfer race is not significantly changed with the amount of plugged tubes. Therefore the FSAR analysis of the loss of feedwater accident remains valid. , t t 5.M=' s 6 -*P .g.c. cw- ,-.e-
o. Steam Generator Overfill ~~ ~ Steam' generator 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 auxilary 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 reachas 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-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 . time-and unambiguious symptoms available for the .o Pera tor s ', their prompt, response is.e.xpected~,and/thus.
- /
.c <c 'O7.-. . i -~., r f i,. V g .ths'Weifill' duld' 'de 'c6rieched'. ' 'In addit' ion', a' s tres's ,e analysis has been performed on the consequences of flooding the TMI Unit 1 Main Steam line. The results of deadweight internal pressure and thermal expansion analysis show that the main steam piping can withstand these affects. Therefore operating the steam generators with 1500 plugged tubes will not present a safety concern with respect to steam generator overfill. i f 1 i, l a m e wowg e..%
- , er 4
4 rQ-
. - -. - - ~ - -. 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 indicace that the cracking mechanism has been arrested and will not reactivate in low solfur primary coolant water chemistry. If the cracking does reactivate due to an un-known mechanism at operating temperatures or during heacup 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 as shown in. Figure IX-4. Therefore the precritical leakage monitoring during the hot testing will detect crack propagation. .+ 2 '. Analyses have dem'onstrated that cracks' below a minimum range of. ' comb'in'acions of flow' tuducted vibration and ' chermal cycles.l 'l '.E Q h-i N.."i 9's M,%;.hjUd/Nength. add;jhroug'hf wal,lT.,thi.cknes st wijT.notipropagacy bf5. Analyses have also calculated a minimum size below which a e, rack will not become unstable due to plastic tearing or ligament necking during a MSL3. Thecrange of crack sizes above this was detectable by the ECT inspection program that was used to inspect the steam generators, and were removed or plugged. 3. Any defects that are not picked up during the 100% ECT inspec-tion because of equipment or analyst error will be exercised during the tes t program and if they propagate to 100% through wall will be detected by leaksge monitoring programs. 1 A. New Damage Not Occurring The following paragraphs address the subject of new damage not occurring in the steam generators. Short term corrosion testing program has provided evidence that the crack mechanism is arrested and the long term term corrosion tests [ will act as an anticipatory program for crack initiation. An eddy current flaw growth program has shown that cracks are not initiating or propagating. Defect indications of less than 40% will be lef t in service and monitored for ( crack propagation. The precritical testing program will detect reinitiation of corosion through leakage monitoring. The corrosion testing program results are described in Sec-tion III. Tests on actual and archive Steam Generator tubing to date have established: t (a) Cracking will not occur unless an active reduced species of sulfur is present and cracks in SG tubing will not propagate in the present chemical enviren=ent;
- 1 I
l l ~._.. -_. ,- y-g
1-- 6 (b) Sulfur induced cracking requires an oxidizing potential which does not exist under hot operating conditions; (c) Lithium hydroxide is an effective inhibitor of the cracking mechanism. Tubing which has undergone the repair 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 dependancy, a long term corrosion tes t program has been initiated to provide an anticipatory assessment of tube performance under actual steam generator operating condi-tions. This program will lead plant operation and will run for approximately one year. i Eddy Current Testing of about 100 cubes in each steam gener-i ator sas conducted on a repetitive basis to attempt to as- ~ certain if the intergranular attack mechanism was continuing .. to' damage the OTSC. tubing during' continued dry primary side ~ c/,7 c,q:,..{a[ up..coiidj.tio.nh',Thie sAmpile/ sele,ctedi.for. this moniedrin'g *.O. ~ %[:. : f*,* Q' ' " rt..f. ', r ~ assumed half tube sheet symmetry and included tubes with no defects, tubes with a variety of defect indications and tubes in periphery and interior areas of the bundle previously identified as high and low defect rate areas, respectively. The methcd used involved a relative comparison of. the low gain.510 standard dif ferencial probe eddy current responses from seven repetitive examinations of the same tube popula-tion 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 f cm test to test were related to variability in the pnysical 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 consecutively (within 3 days of each o ther). The consistent pattern of the test comparisons indicated that significant growth of new intergranular cracks was not detected. Some variability in repeatability of recorded results was observed, however careful review and comparison with previous data established these as expected variances due to such things as " probe motion" noise levels, and previous indications inadvertently 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 shewed a 94% (188 of 201 tubes) agreement with a "no-growth" result. Where 6" (13 of 201 cubes) of the, .e . _.., _ =...
tubes had recorded greater defect indications on the.540" high gai.n technique, these are established as a product of the higher sensitivity of the.540 technique. This result is consistent with other comparisons of these two techniques. As further confirmation, in August 1982 about 29 tubes were selected from OTSG-13 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 of 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. d Within the limits of eddy current tes t sensitivity and re-1. 3 ) 3 : r e ;, d.? git y. - Peatab.ilief>,yio new crack's were,fstmed or'developfng?in,thes. .. '.",0TSG:' tubing' 'during 'the' period f' rom Decemb' r 1981' to Augus t ~ e 1982. Tubes with ECT indications below US+3" of I.D. 20-40% through wall and verified by the 8xl probe to be actual defects are considered degraded tubes. The tubes will be left in service and monitored on an 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. A precritical test program is described in Appendix A. This program will subject the tubes to normal heacup and cooldown stresses and to one accelerated cooldown stress test. Between each of these tests the plant will be maintained in hot, pressurized condition to allow time to determine if cracks have propagated to a through wall extent and to allow sufficient time to detect any changes in leakage. The tes t program will be completed by a cooldown from hot cenditions to cold shutdown temperatures as a final test of tube integrity. Leakage monitoring will be continuous during and i after this test. 65 - -. 3. q. ..w ---.4 _-7 - * - - + -. ~ - - - - - - - - m -
.e. 2 . dl3 ..f p n ] through' wall cracks which coald fait during a transient or Leakage monitoring programs are adequate to detect 10 0 % 3
- ~3 accident condition. Adequate time for propagation will be
'y allowed during the test program. Since previous experience indicated,that the mechanism propagates rapidly, a lack of } any significant leakage would provide added assurance that j cracks are not propagating. Corrosion testing indicated 6 that the aechanism will not be active in high temperature 23 e'nvironments such as those that will exist during the tes t period. Eddy Current examination is not planned to be 3 conducted at this phase of the test program since leakage M detection has higher integral sensitivity and reliability. In addition, opening the steam generator fer inspection would expose the tubing to an unnecessary oxidizing environ- ~' N ment. Good engineering practice dictates that exposure to air should be minimized. 4 9 Both long and'short term corrosion t sts provide evidence that. the crack mechanism is arrested. The flaw growth. s ',.8 f g... g. ,..L .. d.)., y. program;has,. shown. that.; cracks.are - not. propagat.ing,or. g. A-initiit'ing'widiin' the' steam generators.. The precritical,
- 3.,
g. e Y test program will give assurance in the short term, and in %jd the long term, steam generator leakage monitoring and the long term corrosion test program will give tube integrity 0 data and assurance that cracks are not initiating or y propagating during operation. In addition the monitoring of degraded tubes will give additional assurance that the 4 cracking mechanism is arrested. ,Rh B. Defect Detectability 3 -li An Eddy Current inspection was conducted of 100% of the G in-service tubes in both Steam Generators for the full 4 length below the top ten inches of the upper tube sheet. g The system that was used for this inspection was a.540 inch diameter standard differential probe with a effective gain ..I of approximately 60. Any high noise or otherwise difficult i /,0 to interpret indications.were resolved in conjunction with 9 an eight coil absolute probe. The selection of this system l .9 is documented in detail in Reference 20. The following i summarizes the qualification process which resulted in ? determining that this system demonstrated adequate sensitivity to detect defects that should be removed from -+ 7 service. This section discusses laboratory calibrations, d. comparison of field data to metallurgical inspections, measurement of laboratory grown cracks and comparison of .4 2 differential probe data to absolute probe data. j The eddy curren~ probe systems were tested against electro-Q discharge machined notch defects at the EPRI non-des tructive a examination research center in Charlotte, NC. Circumferential l machined notches of.187,.100, and.060 inches were machined 8 1 Jn 3 t l ---m u
M .9 + 48 a, os -1 on the inside diameter of TMI archive steam generator 5 tubing. Each length of notch was machined to through wall e.j 2 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. .i;
- n...
A The results of these calibrations for a.540 inch diameter M, differential probe with a gain of 60 at a frequency of 400 HZ are shown in Figure IX-1. Cracks wi~th geometries that fall. to the right aid above the curve are detectable, those to the left and below are undetectable. The perfectly horizontal geometry of the machined notch is not totally ,hk representative of the cracks in the steam generator, but it i provides the least detectable geot er for differential edd.y el current probes. This geometry, th re# ore, should provide a -4 conservative estimate of defect dececcability. Details of ff this qualification program are contained in Reference 20. 4 - ki: ' On three separate occasions tubes were removed from.both~
- '~
M.%,.*'.1-@ f.,c. .T, ft * -. ' iceam generat. ors for:metallurgicairexaminatione ;' Details of N-J, these examinations are contained in References 3 and 4. One" ~ ~ 1 of the purposes of these examinations was to correlate the ECT signala with actual defect geometry. Eddy current reported thru-wall penetrations ranging from 40 to 95%; 38 of 41 cracks investigated in the laboratory had 100% wall penetratien, and the three cracks were observed to penetrate ~4 50, 70 and 70% through wall. One possible explanation for -n the thru-wall discrepancy is that the cracks may not be open
- .fr in-situ. Although the Intergranular attack penetrates the
?i entire wall, sufficient continuity exists across the grain vb}. } boundaries to give a less than thru-wall eddy current signal. There were no cases below the roll transition area $3 in which a defect had not been detected by ECT, Details on in metallurgical correlations are included in Reference 20. A The particular geometry of these defects were tight cir-cumferential cracks that in most cases, were undetectable by visual examination under microscope or even by high resolu-4' tion radiograph. The primary means of detecting these cracks is by tube axial sectioning and reverse bending on a l fs 1/4 inch mandrel to open up the cracks. Tubes were examined 'd by this method not only in areas where defects had been i l Ah detected by ECT but also in good areas of defective tubes gg 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 i
== i [I where ECT inspection had indicated a defect. These results 'd increase the conficence level that the sensitivity of the j $} ECT inspection method is sufficient to detect all defects in 4B the steam generator tubing. m
- e 33
_h,y
- w miaMe m
+wa' yews
i (* ,? i l '? 3 ECT cal;1L' RATION i 1 ! j Ill1111 11ll111 l l.1 1 I l l Illllli i111111 !{ i .i87. ....................4...........;..... i
- i Probe. S tandard I
~. i Differential X 540. Gain. 60 4OO Kitz l, ~ t ' X j 1 I Detected. e -l-.. &... +....... 5" .100. i g / 7' f, s j Not detected m g O -a
- a
.c t c I .060. ......i............. 4 I X = Laboratory i induced Cracks '. g.. 1 Detected lay ECT h
- = Lal> oratory
.>r h Induced Cracks '~ l ? Undetected l>y ECT 5 HESPONSE O.300 VOLTS MIN. SENSITIVITY lllllll lllllll ll'lllll lllllll l llllll i Tlirougli Wall 20% 40% 60% 80% 100% 'ee = en l
., _ _.. - - +, ~.- / To compare the absolute to the.540 high gain Standard Differential (S.D.), the sample of 3232 tubes previmasly tested
- by Absolute ECT (4x1) was retested using the.540 high gain S.D. technique. The sample was predominantly from the high and low raject 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 indications. With absolute data, it was deteenined that chese indications were all one coil, suggesting that the circumferential extent was relati vely small. In reviewing the.540 scans, it also appeared that the 16 indications not detected were 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 I.D. mixing, S.D. 540 capabilities were enhanced to 100% correlation with the absolute technique as the remaining 16 indications were detected. This comparison establishes that the normal S.D..540 technique is as sensitive a method for flaw detection as the abso lut e. B & W Alliance Research Center conducted a program to arti-ficially induce IGSAC in archive Inconel tubing. Following exposure to thiosulfate-bearing solutions, the tube speci-mens were eddy current tested. Scanning Electron Microscopy clearly showed the intergranular nature of the cracking and confirmed that the laboratory induced tracks 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 is somewhat larger than that of the ECM notches used during the previous 0.540" probe qualifications tests. This value is also larger than the.002" minimum seen during fail re analysis on actual tubing. Ecsever, the measurements on service tubes were usually estimates made on SEK photos rather than metallographic sections, and would be expected to be lower. The crack axial extent in service and laboratory induced cracking can thus be concluded to be comparable. Correlation of eddy current results with metallographic observations was performed on samples with the following re su lts. A summary is shown in Table IX-1. 1. The threshold of detectability appears to be comparable to that determined by the original qualification. test-ing. A crack,.040" x 40%, was below the level previ-ously found detectable and was in fact not detected. Cracks of.315" x 38% and 0.140" x 54: were detectable by 0.540" probe. This is illustrated further by plotting the points on Figure LX-1. 68 - me maan.e 6 ' *
- m e 48**
z . gu. .= ,a =w-. --+r +-- e e e.
TAlli.E lY-1 5, k LADORATORY INDilCED CRACKS E/d'. CORRELATION j l ] ; i,i EDDY CURRENT EXAM \\ i HETALLOGRAPilIC CORPELATION PHYSICAL .510 .540 4xl '] SAMPLE In APPEARANCE & T.W. % T.W. 4 COILS. ' ~ GPUN 1 CIRC. TIIRU MIN. AXIAL DISP. LENGTH WALL ' t ' EXTENT A - 1.75 DISTORTED 20 - OD NE 1 - ID, R 0.2" 50% .014" i A - 2.32 DISTORTED 35 - OD NE 1 - ID - R U.17" 63% .017" D - 3.32 DISTORTED 20 - OD <20 - OD 1 - In A. 0.4"-0.5" 18% .006" i l, C- .76 ACCEPTABLE 20 - ID < 20 - ID HDD A SURFACE ANOMALITY D-1.9 ACCCPTABLE NDD 35 - ID NDD A NO VISIBLE DEFECT i E - 4.0 ACCEPTABLE NDD 65 - ID 1 - ID R .315"M 30% .0065 E - 4.3 ACCEPTABLE HDD NDD HDD A .030 251 i 1 F - 4.0 ACCEPTABLE 85 - ID 55 - ID 1 - ID R .14" (41 .012 a 4' '4 1. R = RE. LECT i A = ACCEPT l l; 2. NE = NOT EXAMINED (TUDE ID REDUCTION DID NOT. ALLOW PASSAGE OP 0.540 PROBE) I t' 3. IIIGil GAIN PARAMETER SIMULATED 0.540 SENSITIVITY '. I i l.- 4. Il = HULTIPLE 4 4 j? I ' l t l
4 2. Using the G?UN ECT 2-step screening technique, 8 samples were tested. Four samples were dispositioned as accept-able 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. 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 trat size have been identified except for a small number that may have been missed due to random equipment or interpretation ectors. .C.. Undetected Defects . Some number 'of undetected. defects or. other. Cube surf ace. '. 'l" ~ a . ** anomalies may. remain in service af ter. the repair is" '~. ~ '. cdEpleted. 'These# defectsI all into.the following-cateiories: ~ f a) Local Intergranular Attack b) Below the detectable limits of ECT c) Detectable by ECT but missed through random error Specimens of actual.0TSG tubing have exnibited areas of general surface IGA one to two grains deep. This local IGA is similar to that seen in other Inconel 600 cubes and is generally agreed to be the result of the tube manufacturing process. A few isolated instances of ICA from 6 to 10 grains deep have been found; they are associated closely with viaible multiple cracking. One use of the long term " lead" corrosion testing program described in Section III will l e to show that these ( phenomena are not contributors to tube failure. Specimens j selected for this test program will contain general surface ICA as well as crack indications. IGA islands cannot be t. specifically included as cast specimens because its l occurrence is random, and it cannot be detected other than by des tructive examination. However, by bounding this conditon with Jpecimens containing surface ICA and ACCual cracks, the influence of this condition can be assessed l especially on consideration of the fact that metallography has shown that the most extensive IGA is in the vicinity of r 1 major cracks. The development of ICA an//or cracks will j l l l i ( l i 'S"*-"O$ M M ]'O * "*^**N
- '"""""M
'4 also be assessed during the test program as speci= ens will be periodically renoved from the test solutions and metallo-graphically evaluated. Bo th the mecalurgical examiration program and the long term corrosion testing program provide assurance that the steam generators can be operated safely with local ICA on the cubing. In addition.to surface ICA, the existence of small cracks below the threshold of eddy current detectability has been considered. Stress analyses were conducted to determine \\ whether small cracks could propagate under conditions of mechanical loading f rom thermal changes and flow induced vibration. Corrosion tests have shown that crack propaga-tion by chemical means is unlikely, however, if crack growth does occur it will be detected by leakage =onitoring. It is necessary to establish the tuae stresses and to interact these. stresses with the crack geometry in order to
- determine propagation rate. In addition, but s epara t'e ly,
~ the stresses are interacted with the crack geometry to i '., f r.q, ]^ determine che, crack' opening,di'splacmene't.- ' .,c.'.,
- .,.(-('.,..-]
f) Q, ";, *, G, .s, 2 '~ The ~ tube loads are derived ih p' art 'from the design basis document (Ref. 52) and in part from measurements of the TMI-2 OTSG tubes (Ref. 51). Recourse is made to field measurements because the steam generator perfor=ed better than design assumptions predicted. Twenty degrees more superheat is measured than predicted. 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: 1 Differences in tube average temperature and the average a. temperature of the steam generator vessel wall. l l b. By virtue of the end fixity of the tube, a longitudinal l pressure stress evolvec through Poisson's ration. i A residual tube axial load component exists from c. fab ricatio n. d. Tubesheet fixture mitigates axial load, especially near the unit center-line. The first of these effects is magnified during the anticipated 100*F/hr shut-down. l Superimposed on the steady axial load is a high cycle, flow i induced vibration (FIV) bending load. The frequency and l displacement magnitude of FIV was measured at TMI-2 (Re f. 51)..
The steady axial and high cycle bending loads define the tube loading. Flaw propagation is determined from a material specific crack propagation law that is itself a function of the stress intensity factor, a parameter quantifying the interaction of crcck size, shape, boundary geometry and stress field. The stress intensity factors for circumferential1y oriented 1 I.D. cracks are calculated in Ref. 53. In addition to the ^ loading components identified above, the stress intensity factor calculation includes the load caused by the tube i contents applying pressure to the parting faces of the flaw during FIV bending. These stresses intensity factors are integrated.using the Electric Power Research Institute Linear Elastic Fracture Mechanism (LEFM) code 'BIGIF' to identify when a crack of a given initial size can be expected to propagate through wall. 'During steady state operation the steam generator shell-to-a; ' cube temperature: difference.could.c'au'se an axial tension of ,4 .,7-c- .,s ', Op,' to. $QO 1b.: c,o. act.on'.the.' cube s 2: : Ini thesanalysis,' the -. e ~. '
- I
' load cycle' imposed on the' tubes. included mechanical and s 4. thermal' factors'. Low cycle, long duration loads were com- ] bined with high cycle flow induced vibration 'F.I.V) loading. A graphical representation of the load cycle is shown in Figure IX-2. The analytical model, which used EPRI fracture mechanics code BIGIF, cycled load about 500 lbs. axial tension, the steady-state maximum calculated at TMI-2. The F.I.V. frequency selected corresponds to the largest peak deflection seen at a TMI-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 crossflow than the average tube. The vibrational i 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 censita excursion represented by the 100*F/hr. cooldown, an axial load of 1107 lbs. The FIV and one cooldown comprise a load block which was cycled six times per year. 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. In the analysis a value of 1.0 KSI (in.)1/2 was used for the threshold stress intensity (delta KTh), the value below which a crack will not propagate at all. This value was used to govern the growth under high cycle loading since delta KTh is minimized for large values of R. ( A = minimum s tress divided by maximum stress.) A value of delta K h for R=0 was calculated to be somewhat higher, 3.34 KSI kin.)1/2, and is appropriate for evaluating the long steady cycles of l l l u. =
== a-
--..e.. FIGU RF. IX.2 FLOW INDUCED VIBRATION LOAD CYCLE ~
- FOR FAX =500 lb, ALTERNATING LOAD IS FIV ONLY
- 40 YEARS OF LOAD CYCLING 1 '107
~ - i.. '. t. :,, .+ L r.,...<, ~ ..r..,- W1.- ... r. e,..s. ... c. e - ~. 500 2.365 x 109 CYCLES /(R / 100*F/HR CC3LDOWN ~6 CYCLES /YR'/ H EAT UP g TO STEADY STATE l l TIME I I l l l ,..,.. e.gm.o mepe e d. - e-. e er +- * - L
- m.,
.- - ~ loading. The R value captures the well-known result of mean stress when evaluating fatigue strength. At higher mean loads, less is left for alternatic; load before failure. The results of these stress analyses are plotted in Figure 1X-3. Stable crack sizes are those to the lef t and below the curve. This curve can be compared with the laboratory ECT calibration results which are plotted on the same set of axis. Since these results fall to the left and below the crack stability curve, this shows that ECT is capable of detecting cracks smaller than those that can' propagate by mechanical cycles of stress. Addi6ional calculations were done to determine the maximum crack size that would remain stable during'the loads experienced in a Main Steam Line Break Accident. Results ~. are plotted on Figure IX-3. This' size ' crack is detectable by ECT'.. Therefore. cracks of chis, size have a small _ ~, probability of existing prior te the test. program. l Tha. laboratory calibration [ re_ _ults and the' correlation of, ';K t _ ' b, '.... ' +i. ..:, T. s 3,3 ? 4 c.L, ? .y' - (.- ,f s "the'd'ifferedeial' produc' tion pro'be to' the a'bsolute probc l . J.' results provide confidence that all defects abov'e the de-tectable size will be found. However, there is'a small s s, probability that some large cracks may not have been de-tected due to problems such as high r.oise levels,-probe lift off or chatter, or data analysis errors. Because~of this possibility, precritical-hot steam generator tests will be' conducted that place the tubes in tension under normal and accelerated cooldown conditions. These tests, which are described in Appendix A, will cause 100" through wall cracks to open and leak at levels which can be detected. If high or increasing leakage is detected during the test phase, the leaking tubes will be located prior to criticality and repaired or removed from service. In order to bound different crack geometries and plant-conditions, leakage races for various tube axial loadings and crack are lengths were calculated. This data is presented graphically in Figure IX-4. This graph compares leakage rates to detectabilities. As expected, leakage increases with tube axial load and becomes highly detectable under conditions which might cause tube failures. It should be noted that the minimum detectable leakage for various tube and loadings is.,well below the threshold crack size that would fail duiing MSLB conditions as can be seen by comparing cracks witA,similar are lengths on Figure IX-3 and Figure 1X-4. 72 ; s s ~ e m
- e e
. e me --a
- t,se.==
k g .m .~,,m .,m
FIGURE IX 3 ECT DETECTABILITY VS. MECHANICAL STABILITY 2-360* -~~~-~~~~~~~"""~~] ~~-~~-- i I 1 +M S L B I i i 1 1.5 - i m = I i i I ?. i 1 .. ;;. g.'., : E,. ;. i v: !# ;:.+. ':\\' E c' +- - I ' ' '- F a p i e. g. 1 E 1-i 1 5 i. I e i = I M i 1 .5 - ' -*- FIV UNSTABLE l AREA l I I ECT+ I DETECTED / .2 - STABLE I AREA
- 1 NOT DETECTED /*,
t 0 20 40 60 80 100 % THROUGHWALL (1/h) V --__i 2a j h ECT: DEFECT - 4 MIL WIDE NOTCP PROB E - DIFFERENTIAL FIV : AXth = 1.1 MPaVm .a40 IN DIA. DEFLECTION = 3 MILS (IN 16TH SPAN) GAIN 45 + RA (~60) MSLS: CRACK EQUIVALENT SENSITIVITY 300 MVIN Td.0415 SQ. IN. OF LAB EQUIVALENT TUBE CROSS SECTIONAL AREA TO FIELD -pg. geee - age .~ .._f w6ygm. ee--
- C ~
- C.'-
l 3 ...'.?' t i, l ~ t s l I. PRI-SEC LEAK RATE VS. DETECTABILITY 30 t ASSUMED CRACK GEOMETRY ~ i 26 - i t
- s.
'j [ [1 24 - Ap = 2200-900 psi 22 - 20 - P3 = +1100 #- l 18 - .j,. g JCRACK OPENING 16 - / c N 4-1 GTRETCH 2 c a A 14 - I ] 12 - ] 10 - P xx [ 'q ' .1 J v -W h, 6-P3 = +500 #-r 4-P3 = +100 #w 2_ lim 1T0f(( ~ yJ&l %5n%%N M h%%%%%%%%%%%%%Nj_ *fG 1 p BU LE kS 3 DETECTABillTY .02 .06 0.10 0.14 0.18 0.22 0.26 0.30 0.34 0.38 0.42 0.46,'O.50 1.D. ARC LENGill-2a (INCllES) t 0 30" 60' -[90* j I O ?. f
i X. OPERATIONAL CCNSIDERATIONS 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 addition, 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. A. Leakhte Monitoring During plant operations primary to secondary leakage will be monitored as follows: 1. Non-steamin6 conditions 'During ste'dy state operations analysis for Boron and Tritium a or degassed gross. beta gamma activity will be performed -r e., Q P. Y t ',. is. indica'ted and,'.6nce per shif t if -leak? ().;\\**-fd..[..$dh;.,.cM...-dailyif*'no'Jeakag'er..h '** kS*1If. indicated'.,i Du'r' ink tr.ansie s.l.* 1 and/or temperature), analysts for Boron and Tritium or degassed gross beta gamma activity will be performed during the transient (not to exceed four hours between samples), and approximately one hour and five hours after completion of the transient. The sensitivity of leak rata monitoring is a function of the time interval between samples. Using Boron as an indicator, if the time between samples is 5 minutes, the detectable leak race is.1 gpm. For 50 minutes between samples the detectable leak rate is.01 spm. Using Tritium or degsssed gross beta gamma activity as an indicator, the detectable leak race can be as low as.25 gpm depending on time between samples, counting time and RCS activity. 2. Steaming conditions During steaming conditions, the radiation monitor at the vacuum pump exhaust from the off gas condenser will be monitored hourly (RM-A5). At the first signs of leakage or when RM*A5 count rate changes by greater than 252, a grab sample will be taken from the vacuum pump exhaust and the RCS and analyzed for Xel33, Xel35 and total gaseous activity. A sample will also be taken from the hotwell and analyzed for tritium. After four hours the hotwell and RCS will again be sampled for tricium to calculate leak race. Determination of which steam generator is leaking will be accomplished by monitoring the main steam line for N-16 with a portable multi-channel analyzer with a Na I (TC) detector. 73 - ? i 1 ..-.m em..~ -.8 +' -~ mn, uagum-ew - Emine=epen. gp> = _m-- m. e'-w m e sma a--
-5 ~ More detailed information on leakage rate calculations ca.; ~ be found in Reference 26 and 28. The leakage limic will be governed by the tech spec. limit of 1 gpm. Additional administrative limits will be applied. B. 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 . eve nt s. The guidelines will 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 rupturee in one or both SC's, loss of reactor coolant pumps and loss of co ndenser. The following is an outline of the programs for developing guidelines for.. SG tube rupture. , "..,,,.. 3.:.
- c. W.....
..,.e.. ,,t. ~. '. *4',..'li!" Guidelines. fo'r ' Tube Ruot'ure's' fir' b'hich 'Sube'ooll5g Ma'rg'in i's' j'
- s a,
Maintained The basic plant state will cover the following considerations. Break size small enough to maintain subcooling (less a. than 2.5 tubes). b. One OTSG affected. c. Reactor Coolant Pumos operating. d. Condenser available. e. Decay heat removal f rom the non-af fected SG. f. SG steamed at 95~ operating range level to maintain natural circulation. Contingency considerations for design basis tube ruptures include: (1) PORV unavailable. (2) Reactor Coolant Pumps unavailable. (3) Ne condenser available. (4) High radiation release considerations. (5) Steam line flooding consideration. (6) Both SC's are af fected. .,, w.megy. mmmm..e w e.es.,mm-e =.-me-
2. Guidelines for Tubs Ouotures For Which Subcooling Ma? gin is Not Maintained The program to develop guidelines for tube ruptures for which subcooling margin is not maintained will include the following basic assumptions. a. Break size from one SG large enough to cause loss of subcooling (greater than 2.5 tubes). b. No reactor coolant pumps running (since subcooling margin is lost). c. Condenser available. d. PORV available. e. Unaffected SG is steamed. Contingency considerations include:
- 1) PO'RV unavailable.
(2) RCS voiding keet s pressure above SG safety valve .-.. v '... g.- ..'.' '.'...." *?; s e tpb int.. '... '.:.*-? .J.*f4 '. ' 3.' i N.h.-AN.INf,'//,f hf.W,';N.Q)..Pr,imary 'feedf.',and bl'e'ed heat'. remova1?. l.d ' k *, ,r. (a) With PORV available (b) Without PORV available Both the analyses employs the RETRAN code. This code models TMI-l and has been benchmarked from transients on beth TMI,1 and TMI-2. Use of this code ensures that plant response under various primary-to-secondary leak scenarios is understood. The RETRAN analysis and guidelines developed for tube ruptures will be used for writing new procedures and revising old procedures. Operator training prior to restart will include response to tube rupture events using new and revised procedures. C. Conclusions t Primary to secondary leakage will be monitored during non-I steaming and steaming conditions. Sampling requirements on the I detection of a primary'to secondary leak have been established, j and administrative limits on leakage are being considered. The combination of analysis of tube ruptures, procedure improve-I ment and training improvement give assurance that operators can safely respond to a primary to secondary leak. 8 t I,. he p, 4 pO W.. m .*++e 44
u....-. XI. ENVIRONMENTAL IMPACT A. Introduct'oy g The impact of operating TMI-l with primary to second.try leakage was evaluated. Appendix I limits were compared to calculated o'ffsite doses which would occur due to operation with a primary to secondary (PS) leak rate at the repair program goal of 1 lbm/hr, and at a PS leak rate of 6 GPH (50 lbm/hr). Calculations are based on source terms found in Reference 11. Both were calculated using a failed fuel value of.03% which is the maximum experienced at TMI. B. Appendix I Considerations 1. The following are the Appendix I considerations for operating with a primary to secondary leak of 1 lbm/hr. and 6 GPH.with .03% ' failed fuel. .03% failed fuel is the maximu> seen at TMI-1. 1 lbm/hr is the repair leak rate. goal. Table XI-l ' uis*.the cal'culated maximus' hypochetical of fsi:c6 doses f'or i l
- 3. 7: '".:[..'.*.'/.' J.., -T 'r.o'peraEion[1Aith a' I lbm/h'r. and.a 6 CPH' pfimary to isecondary' ;
' " l' I. .).- 7 f '0 - leak wich'.03".f ailed' fuel. Table XI-1 App. I Limit Source Calculated Dose For TMI-1 1 lbm/hr 6 CPH Iodine & Par-0.041 Mrem /Yr. 1.5 Mrem /yr. 15 Mrem /Yr. ciculates Noble Gases Gamma 0.12 Mrad /Yr. 4.2 Mrad /yr. 10 Mrad /Yr. Beta 0.10 Mrad /Yr. 3.4 Mrad /yr. 20 Mrad /Yr. Liquid Effluent Whole Body 8.4 x 10-6 Mrem /Yr. 3 x 10-' Mrem /Yr. 3 Mrem /Yr. Liver 1.4 x 10-5 Mrem /Yr. 5 x 10-4 Mrem /Yr. 10 Mrem /Yr. I lbm/hr is the repair leak rate goal. The value of 6 GPH (50 lbm/hr) was selected for analysis because similar leak races have been experienced at similar plants (Oconee, Crystal River) during continuous operation. Source terms and methods for calculations can be found in Reference 54 As Table XI-l indicates, operation with as high as a 6 GPH primary to secondary leak will give dc ses far below the Appendix I limits. _. e-. um y4._ _ esemus.wp e. 4 -w.y -,w-e ,e ---.g
C *. Sampling and Monitoring Appropriate monitoring and sampling of all waste steams will be conducted per established NRC Guidelinas. Modifications will be installed in the Turbine Building to' provide radiation and contamination control for plant personnel and effluent release control / accountability. These modifications will consist of Powdex end Turbine Building sump painting, and liquid / airborne monitors to measure activity during operation. D. Conclusions The operation of TMI-l with small primary to secondary leakage satisfies Appendix I Technical Specification considerations. ~.. :' e"c.,..;***;. *: . ' ' n.: :.. '..., ~ '~ .~
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. ~ _ _... XII. TECHNICAL SPECIFICATION COMPLIANCE This safety evaluat on demonstrate:, that the 2 1-1 OTSCs are operable per T.S. 3.1.1.2, and have met the surveillance conditions for operability given in T.S. 4.19, or equivalent. 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. T.S. Subject Topic for Evaluation Reference 1.5.6 Heat Bal' Calib. Flow asymmetry Section VIII 1.6 Def'n, Quad. Pwr. Tilt Flow asymmetry Section VIII 2.1 Fig. 2.-1,2.1-3 Flow vs T Flo w, flow asy= metry Section VIII 2.3 Fig. 2.3-2 Table 2.3-1 Nuclear Overp. Flow Section VIII 3.1.1.1.a Permissible. pu=p. comb. Flow Section VIII 3.1.2 RCS heatup-cooldown Stress vs. T change: Section V cnd assumes ve'ssel as limit IX . Section X i ~ .RCS activity. Leakage 3.1.4.'?..RC5~Sh'edistry" . s...' ~ ' S'Furtherit' tach}i'nconj. 'Se c t'io n IV. '.. ' b ;* 't ' ' ' ' '. '.., 3.15?.~,. - s :. .,j,;,gg, g ag.go13nying - S distress 3.1.6 RCS leakage Leakage Section IX 3.5.2.4 Quad Pwr. Tilt Flow asymmetry Section VIII 3.5.2.5 Quad. Ba1. Flow asynnetry Section VIII 3.13 Secondary activit; Appendix I w/leaka2e Section X 3.22 Appendix I Leakage Section X 3.23 Appendix I Leakage Section X 4.2 RCS:ISI Testing of RCS Components Section II.I 5.3.2.1 RCS code req. Repair qualification Section V i l l l 78-1 l .s.a.. --ogg ,w
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XIII.
SUMMARY
AND CONCLUSIONS The previous twelve s(_. tons along with 'che references and appen-dices associated with this safely evaluation provide a broad ranging discussion of the adequacy and safety of the TMI-l 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 performance of the OTSG tubes below the area of the new joint.
7 2. Evaluation of operation of TMI-l with small primary-to-secondary leakage has' confirmed that Appendix I Technical Specification considera-tions are satisfied. '-..- b ..,., y. ".e.; ..I '
- 3. ~ ~All'iubesidith' no'ddfect 'indic'at' ions!below an eleva tion 3 inches
$ i ' ' ' ".-.> J# # ab'ovb 'the '.Iower " face of-th'e upper tubesheet (UTS+8) have been' ~ adequadely repaired by the kinetic expansion process. The kinetic expansion process qualification program provides su,fficient 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. 1 Tubes with defect indications below the UTS+8 elevation will be removed from service by approved plugging methods. The OTSC/RCS performance with these tubes plugged has been evaluated for both normal operating and emergency conditions. 5. Circumferential defects smaller than the threshold detectability of ECT or less than 40% through wall are acceptable. Fracture Mechanics Analysis of circumferential tube defects has been conducted. The analysis identified crack geometries which would propagate from c.echanical 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 FCT sensitivity for various gecmetries of circumferential defects. ihis comparison shoss that the GpUNC 100% ECT inspection of the TMI-l OTSGs was sensitive enough to find "uns table" defect geome tries. 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, I .m,,e.. .we m m.,. JNMM* 6
that there is no cor:osion damage which will preclude the RCS from functioning properly and supporting safe operation of 21-1, 7. Analysis of design basis and higher primary-to-secondwy leak races cor firms that the operacing and emergency precedures are technically correct. The procedures provide adaquate basis for training the operators to respond to normal and emergency primary-to-secondary leakage. 8. Steam generator testing together with long life continuing laboratory testing will provide confirmatory data on repair scability and the absence of new high velocity cracking. The steam generator testing will be corpleted with essentially zero decay heat power and poses no safety risk. Conclusion In conclusion, MI-l can be safely returned to service once the repairs and other activities discussed in this scfety evalution
- 3 report;are. completed...,Th4s-conclu.sion,ia. based on sound.analy-
' ~. '..~ ~. . i. .., '... ',. '., t] '. t.idal.and esipirical data.d' veloped by ~GPU Nuclesr Corporatio'n j-a - duking.~the 0TSG' repair program. The. scop'e.of t'edlin'i~ cal-evalu- .f l;. acions' has been bro' d based and the involvement of numerous a independent technical experts has been extensive throughout the 21-1 OTSG repair program. The methodical, 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 21-1 steam generators can be safely operated. I l l owe 4 = =o, em onm eww a-
APPENDIX A PRECRITICAL AND POST CRITICAL TEST PROGRiMS 1. PRECRITICAL Foll'owing the repair of the OTSG, special testing and monitoring will be performed to prove the operational capabilities of the steam generators. The program will include leak tightness testing, hot functional testing, eddy current examination and flow and ~ leakage monitoring. A. TMI-1 OTSC Repair, Pre-Se rvice Te st Pro gram 1. OBJECTIVES FOR THE TEST PROCPAX The overall objective for the pre-service program is to demonstrate the success of the repair by providing .ada'quate. assurance of the post-repain pr.imary..toi. secondary
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l. i.,, 3 generators. The specific post-repaired features of the steam genera-tors to be tested include the tubing kinetic expansions, the Westinghouse roll plug installations, and the B&W weld plug and explosive plug installations. In addition, the testing will si=ulate operational loading of partial through wall defects in tubes remaining in service. This testing program will culminate with the start of hot testing. 2. LOADING ON OTSG TUBES AND PRIMARY TO SECCNDARY ?RESSURE SOUNDARY Detail definition of loads is given in Re.'erence 18 and can be summarized as primary to secondary differential pressure loading for normal operation (1245 psi) and steam line break (producing the highest differential pressure design loading--2500 psi); secondary te primary differ-ential pressure loading due to loss of coolant accident (1050 psi differential pressure); and tensile loading on tubes due to cooldown transients (the steam line break transient producing the highest axial load). Flow-induced vibration loads on tubing will be addressed by the post-service test program. 81 - se wm e .w dage. w-d e
3. TEST METHODS Test methods include: a. 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 ' cube expansions and upper tubesheet plugs are leak tested by visually observing gas bubbles in the upper head. Based on experience at Crystal River Plant,-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). b. 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 and the cubing expansions.
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.~ l #.'.:p .. < ~, "~ 9 f.:. lHEt' Testing ?,'. B The initial period of hot esseing 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. 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 more confidence that the failure mechanism will not reactivate. It is anticipated that the OTSG testing sequence will take approximately one month. The following tests will be perfor=ed to stress the OTSG tubes. The testing sequence is shown in Figure A-1. All hot testing will be performed prior to criticality. 1. Normal Cooldown Transient This cooldown will be a controlled cooldovn of 70 to 100*F/hr. The maximum stress placed on ene tube will occur when there is a maximum Delta T between the tubes and shell. This will place 500 to 1100 lb. tension on tha tubes. 2. Heatup, Leak Test and Thermal Soak Heacup to normal operating temperature.nd re=ain hot for sume period of time. An operational leak test will be .g
.e_ performed at this time. The operational leak test establishes primary and secondary pressure at about the normal operating levels, but with a primary to secondary delta p exceeding the normal operating value. Primary temperature is maintained by pump heat. Leakage from primary'to secondary is monitored by measurement of tricium concentration in the OTSG secondary. The anticipated limit for maximum allowable primary to secondary leakage iu normal operation is 6 gal / hour. A period of thermal sotk will enable cracks which are on the threshold of perjassation to propagate and be detected by either leakage mer50ering. Other plant testing which in no way ef fects the GISG can be performed at this time. 3. 6ecelerated Cooldown Transient Th6 intent of this test will be to impose a larger than r,trmally expected tube load in the shortest period of time so,1s not to cause major plant problems such as low RCS pressure,3 ow pre.ssurizer. level, etc. 3The maximu:n, load,.g,.... 1,, . c:. 6 q.. 4..- ], c,.. *. 7,.., g wrt.l.be re's trteted to. prevent.d'amag.e to: other "pl' ant- * -. i., g . ;#com'ponenes and'not exceed des'ign loads en *th'e' S/G tubes'. ~ ,T' ,, ~ A large steam demand will be simulated by opening one or more turbine bypass valves to obtain a accelerated cooldown race. EFW will be used for system makeup. B2cause the EFW cools only the tubes and little or no inventory will gather in the downcomer region, there will be little shell downcomer region cooling. The primary side cooldown rate will be the same as the shell to tube temperature difference. 4. Complete Thermal Soak Following the accelerated cooldown, the plant will be heated up to normal operating pressure and temperature and remain there for some period of time. 5. Cooldown This will be a normal controlled cooldown to cold shutdown conditions. I 6. Following OTSG Testing, normal hot functional testing and power escalation testing will be performed. C. Flow Rate Testing i Because tubes will be plugged during the repair process, the RCS flow rate mus t be measured af ter repair. i , t I l a+,em.e.*
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. DK E. .i T; T N A N T AO W R E P S RE S I D E UT T T A l L E iT T S A F OC P WS AE T E i EP E O I E TM 0l l B L R R U l Kl l l i O AE S T l Ei T LT S O P H OT S A 0 YL l R G NT N 9 AAl E E S NI LWN W N 0 ITW A E I N S R OI O 0l NO l O T M E D S D l AI P E C l T C RLN L A D ML G OI E O0A O RN RN N0i O E[ L 0l l PO l i M CT C Pl f l M O AI A C ETS S N G E E Nl E0 l t N T A O 0 ST G l I I E K l RE T LM T U A A I L A AP Pl AN K U S O RITAL E l PM T ME S E NEA l E A Oi P L O EG I O O V C S C T I C E A ~ { ili i ' i'i
_e f II. POST-CRITICAL PLANT TESTING Power escalation testing will accomplish the following with respect to the steam generator tubing. It will place stresses on the tubes and will create flow induced vibration conditions. During the pre-critical testing phase there is little steam flow. As a result, although there are significant axial tensile loads placed on the tubes during the tests, the stress component due to flow induced vibration i's not present. However, FIV should not be a problem because flaws below the detectability of ECT will not propogate due to FIV as shown in Section VII. Power escalation will occur in steps; steady state plateaus will be obtained at 0,15, 25, 40, 60, 75, 95 and 100 percent + 2% of rated power, and tests will be performed at each power level! This slow rise in power will enable the early detection of leaks in the tubes if some flow induced vibration does occur. Although no leakage due to FIV is expected, leskage rate will be continuously monitored to detect leakage during cooldown transients. J -(., A * < ;.. [ Te,nsile. str, esses.will be.plac'ed,on-the. 0TSC tubes during the,, ,. j :,, f.o.11osing. test procedures : ~ 1. TP' 700/2 Low Power ratural Circulation Test This test verifies the tuning of the Integrated Control System (ICS) to maintain preset OTSG levels under loss of main feedwater and natural circulation conditions. It also verifies proper response of the EFW sytem as well as the establishment and maintenance of natural circulation under varying conditions. Testing vill be conducted at approxi-mately 3% of rated thermal power to simulate the decay heat load that would correspond to significant core burnup. This test will verify that plugged tubes have no ef fect on establishing natural circulation flow. 2. IP 800/2 Reactor Trip on Loss of Feedwater/ Turbine Trip i At a power level of approximately 40%, both main f eedwater pumps will be tripped. All three emergency feedwater pumps will start automatically and OTSG 1evel will be controlled at 30 inches +2 in. - 10 in. by Emergency feedwater. At a power level of 95-100%, the turbine will be tripped. OTSG 1evels will be controlled at 30 inches +2 in. -10 in. by main feed-water.. ep -.
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... _.. o 3. TP 800/8 RCS Otercooling Control Test This test demonstrates that the control roon operator can properly throttle EW flow to prevent overcooling of the RCS following a loss of RCP's with OTSG level initially at 30" on the startup range. t t These three tests will produce stresses in the ttibes due to initiation and' use of e:nergency feedwater. Primary leak rate will be monitored continuously to detect defects. B. Eddy Current Testing Af ter 90 calendar days the plant will be shutdown and ECT testing will be performed. This will verify the lack of defect propagation during nor: sal operation. ( z' ..t;., ? ;'.' ? :. h * ' 's, ; *. ' '.,, * ~ \\ ', s.' : W.*..l 1*. * '.',,';" f-].' ' " 1
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r REFERENC_ES, ~ ~ (1) OTSG Repair Safety Evaluation Report, Aug. 1982. (2) THI-1 OTSG Failure Analysis Report, July 1982. (3) Final Report on Failure Analysis of Inconcel 600 Tubes f rom OTSC A and B of Three Mile Island Unit 1, June 30,1982 - Battelle - Colvmbus Laboratorie s. (4) Final Report: Ev11uation of Tube Samples f rom TMI-1, July 7,1982; B&W #RDD: 83:5390-03:01. (5) Technical Specification for OTSG Tube Plugging with B&W Welded Caps and Stabilizers SP-1101-12-030. (6) Nuclear Safety / Environmental Impact Evaluation for OTSG Tube Plugging Using B&W Welded Cap with Stabilizer. l[.N -0 jjf.:. hSG huhkugkliig Ph'asy 'IUSPN10lk.1'2 O292. ' i' i 'I (8) GPUN Specification SP-1101-22-008. OTSG' Tube Repair-Long Term Corro sion Testing, Rev.1. (9) R. C. Newman, et. al. " Evaluation of SCC Test Methods for Inconcel 600 in Low Temperature Aqueous Solutions." Sumposium held at National Bureau of Standards, Gaithersburg, Maryland, April 26-28, 1982. (10) NUREG 0565,' " Generic Evaluation of Small Break Loss-of-coolant Accident Behavior of B&W Designed 177FA Operating Plants." January 1980. (11) MPA Oport, "ItI-l OTSG Primary-to-Secondary Leakage," March 11, 1982. O (12) NURIC-0017. " Calculation of Release of Radioective Materials in Caseo@( & Liquid Effluent f rom PWR," April 1976. (13) TdI-l Plaut Technical Specifications. (14) EPRI NP-2?46 Topical Report Dec.1981, " Static Strain Analysis of TdI-2 OT5G Tubes." (15) A3ME 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 24I-1 OTSG Tubes. (18) GPUN Spec SP-1101-2 2-006, Rev. 4. ~ ~86 m eme "P**"W #9 e w +9 --199 rwp +,.. p g w 9 y = --, g*w, ,,,p
REFERENCES - (Contd.) ~ ~ ~~ (19) GPUN SP-1101-22-009 OTSG Kinetic Tube Expansion Process Monitoring and inspection. Rev. 2 (20) Three Mile Island-l OTSG Tubing Eddy Current Program Qualification, October,1982. -Draf t. (21) CPUN TDR 343 RCS Inspection, 6/14/82. (22) J. D. Jones, OTSG Failure Analysis Operational History Final Report, GPUN TDR #336 May 12,1982. (23) Three Mile Island Unit Once Through Steam Generator' Repair Kinetic Expansion Technical Report - November 1,1982 - Draf t. (24) J. C. Griess and J. H. DeVan, Oak Ridge National Laboratory, The . Behavior of Inconel 600 in Sulfur Contaminated Boric Acid Solutions, ..' 'Se p tembec. 2 9 e.19 82.a.. ,:~... ; n. '.: ~ Q.- .c.. c ?...,'. -;.l5) ['C' l[N SP liOl 12'-038 'Rev/O' OTS'G $ be Plugging'.Criteiii.- i~
- ' ? '. K ('
P (26) GPUN TDR #368 Primary to Secondary Leak and Leak Rate Determination Me tho ds. (27) J. V. Monter, "'MI-l OTSG Test Results - Interim Report," 3&W Report
- 543301-01, July 13, 1982.
(28) GPUN TDR #359 Evalu.stion Criteria for a Primary to Secondary Leak. (29) GPUN SP-1101-22-007, Rev.1, Short Term Corrosion Testing (30)' Stress Report for OT36 Stabilizer Weld Cap, 34W 33-0231-00 (31) Welded Taper Flug 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, 3&W 80-0150-00 (35) B&W Position paper on Use of Tube Stabili:ers in Dt!-l GTS6, B&W 51-1132-602-00 (36) CHATA-Core Hydraulics and Thermal Analysis-Revision 4, 3AW-230, Rev. 4, Babcock & Wilcox, June 1979 (37) CIPP-CHAIA Input Processing System (38) TDIP-Thermal Enthalpy Mixing Program, BAN-321, Rev. 2, Babcock & Wilcox, June 1979. ~ Si ~
- 88*
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-g ~ f ~ REFERENCES - (Contd.) (39) 3&W Document No. II" by' D. J. Haltaman,' July 1982.32-1135 309-00, "Pu=p Code Certification for oco (40) NURIG 0565, " Generic Evaluation of Small Break Loss-of-Coolant Accident Bahavior of B&W Designed 177FA Operating Plants." 1980. January (41) Topical Report BAW 10092P Rev. 3, October 1982. (42) 3AW-177 " Preliminary Calculations of the Effect of Plugged Steam Generator Tubes on Plant Performance" March 1982. (43) RETRAN-02, EPRI NP1850 CCM, May,1981. (44) Transient Model of Steam Generator, Units.in Nucl. ear Power Planth.- ..' a.. -y. ' '. '. .TRAMSQ-01, EPRI..NP;1368 March 1980.2 ~ M.. ?,.1 ...T. ... e s.e. s. .. ~.. v... '.dl(45h../ Requestsifo'r InformAtion?on Steam Generator Feedwater Addition Events 3-s.
- ~
' Letter from Thomas Cox of USNRC to J. H. Taylor, (3&W) dated June 20,, 1982. (46) Letter from G. T. Fairburn (3&W) to J. F. Fritzen (GPU) dated December 11, 1979, TMI-79-201. (47) B&W Document 32-1138230-001 "Tvaluation 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-1
- 51-1137529-00.
(49) " AUX. A Fortran Program for Dynamic Simulatioe of Reactor Coolant System and Emergency Feedwater System." August, 1981. B&W Document NPCD581 (50) Report in Response to NP.C Staff-Recommended Requirements for Restart et Three Mile Island Nuclear Station Unit One - Amendment 25. 2 (51) Flow-Induced Vibration Analysis of TMI-2 OTSG Tubes, EPRI NP-1876, Vol. 1, Proj. S140-1, Final Report, June 1981. (52) Determination of Minimum Required Tube Wall Thickness for 177-FA OTSG's. 3AW-10146, October 1980. (53) Fracture Analysis of Steam Generator Tuves, Part II, Steam Intensity Factor and Crock Opening Displac=eent (C00) Displacmentag by Prof. F. Erdogan, Lehigh Univ., Prepared for GPU Nuclear, 9/15/82. (54) TDR #390 Operation of TMI-1 with Primary to Secondary OTSC Leakage; Radiological Calculations.
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Mid$etown. Pennsylvania 17057 717 944 7621 TELEX 84 2336 Writer's Girect Dial Numbe,r-April 20, 1983 5211-83-122 Office of Nuclear Reactor Regulations Actn: John F. Stol:, Chief Operating Reactors Branch No. 4 U. S. Nuclear Regulatory Cr=1ssion Washington, D.C. 20555
Dear Sir:
Three Mile Island Nuclear Station, Unit 1 (TMI-1) i Operating License No. DPR-50 Docket No. 50-289 TMI-l Steam Generator Repair Report (GPUN-IDR-007 Rev. 1/BAW 1760 Rev.1) Enclosed for use in your review of the TMI-1 Steam Generator Repair is Revision 1 of the "Once through Steam Generator hepair Kinetic Expansion Technical Repoit.." Revision 0 of this report dated November 1982 was sent to you by letter dated January 20, 1983 (5211-83-020). Some of the infor=ation in this submittal is considered proprietary to B&W and their subcontractor Foster Wheeler Energy Applications, Inc., as sworn by J. H. Tayler, Manager, B&W Licensing, in his af fidavit presented with Revision 0. Pages, paragraphs, tables and figures con-taining such information have been marked " proprietary" in the text of the document. Cross-references showing the relocation of proprietary material in Revision 1 from that shown in Exv.ibit S of the Affidavit for Revision 0 is attached. It is requested that this info.sation be protected from public disclosure under the provisions of 10 CFR 2.790(b). Sincerely, .uk Director, TMI-l C) HD11:lilG:v3 f Efclosures cc: J. Van Vliet - - -mwy PDR ADOCK 05000289 P PDR / GPU Nuctear Corporation is a sucsic:ary cf ne General PLth: Utiht;es Corecration t I ,.}}