ML20084E041
| ML20084E041 | |
| Person / Time | |
|---|---|
| Site: | Crane  |
| Issue date: | 03/30/1983 |
| From: | Moran T BABCOCK & WILCOX CO. |
| To: | |
| Shared Package | |
| ML20079G498 | List:
|
| References | |
| FOIA-83-243, FOIA-83-A-18 008, 008-R02, 8, 8-R2, NUDOCS 8304130440 | |
| Download: ML20084E041 (169) | |
Text
.
-w ASSESSMENT OF TMI-l PLANT SAFETY FOR RETURN TO SERVICE AFTER STEAM GENERATCR REPAIR TOPICAL REPORT 008 REV. 2 PROJECT NO: 5000 51712 l
T. M. MORAN l
l March 29, 1963 APPROVALS:
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D b* P3 Manager, Plant Analysis Date A
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Vice Presiden't Date Technical Functions k
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XA COPY Hos Been Sent to PDR P
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Table of Contents I.
INTRODUCTION A.
Purpose B.
Background
C.
Steam Generator Repair Program D.
Safety Evaluation Logic II.
FAILURE ANALYSIS A.
Operational History B.
Metallurgical Test Program O.
C:rr::i:- !s:: ? be t:
D.
Damage Scenario E.
Distribution of Damage III. CORROSION TEST PROCRAM A.
Introduction B.
Corrosion Mechanism Determination Tests C.
Corrosion Scenario Verification Tests D.
Repaired Tubing Corrosion Tests E.
Conclusions IV.
PREVENTION OF RECURRENCE A.
Introduction B.
Prevention of Future Chemical Contamination C.
I Changes in Operating Chemistry D.
Cleanup of Sulfur from Tubes E.
Conclusions V.
KINEIIC EXPANSION REPAIR DESCRIPTION
SUMMARY
A.
Cescription of Process and Geometry B.
Design Bases of Xinetic Joint C.
Qualification Program D.
Repair Testing E.
Post-Repair Testing F.
Conclusions VI.
IFFECTS OF EXPANSION REPAIR A.
Possible Introduction of Chemical Impurities B.
Possible Effects on OTSG Structure C.
Corrosion t
D.
Effnets of Expansions on Existing Plugs E.
Conclusions VII. PLUGGING REPAIR DESCRIPTION
SUMMARY
A.
Introduction B.
Plug Types C.
Plugging and Stabilzation Criteria D.
Post Repair Testing E.
Conclusions
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Table of Contents (cont 'd)
VIII. (DMPARISON OF TUBE PIEGGING WITH DESIGN BASES A.
Introduction B.
Operational Performance C.
Accident and Transient Performance D.
Moisture Carryover Considerations E.
Conclusions IX.
UNREPAIRED PORTION OF TUBES A.
New Damage Not Occurring B.
Defect Detectability C.
Undetected Defects D.
OiSG Tube Failure Analysis for Unplugged hbes 0.r.clas.;.c X.
OPERATIONAL CDNSIDERATIONS A.
Primary to Secondary Imakage B.
Radiological Concerns C.
Secondary Side Chemistry '
D.
Development of Procedural Guidelines for Steam Generator Tube Rupture E.
Cor.clusions XI.
ENVIRO} MENTAL IMPACT A.
Introduction B.
Offsite Dose Estimates C.
Exposure Estimates D.
Sampling and Monitoring E.
Conclusions XII. TECHNICAL SPECIFICATION COMPLIANCE XIII.
SUMMARY
AND CONCLUSIONS APPENDICES A.
Precritical and Post-Critical Test Programs B.
Response to Questions REFERENCES FIGURES Figure I-I TMI-l Steam Generator Figure I-2 OTSG Task Organization Figure I-3 Disposition of Tubes in IMI-l Steam Generators Figure I-4 Kinetic Expansion Process Figure I-5 TMI-l Steam Generator Typical Cracks Figure I-6 Kinetic Expansion langth l
Figure I-7 Plant Return to Service Safety Evaluation Overview Figure II-l 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 Figure VII-l Outline of Basic hbe Plugging / Stabilization Plan Figure VII-2 Lane / Wedge of Tubes to be Stabilized
- ii -
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g Table of Contents (cont'd)
FIGURES - (cont 'd)
Figure VIII-1 Reduction in RC Flow Rate vs. Number of Tubes Plugged per Steam Generator Figure V,III-2 Comparison of FSAR Flor Coastdown to Flow Coastdown with 1500 Tube Plugged Figure VIII-3 Effect of Tube Plugging on Natural Circulation - THot Loop 1 vs. Time Figure VIII-4 Effect of Tube Plugging on Natural Circulation - Total Core Flow vs. Time Ficure IX-1 ECT Calibration Figure IX-2 Critical Crack dizes Figure IX-3 OTSG Loading Cycle for Tube Mechanical Evaluation Figure IX-4 da/dn vs K for Inconel 600 Figure IX-5 OTSG Leak Rate as a Function of Crack Length and Tube Tensile Load Figure X-1 Tube Rupture Guidelines Figure A-1 TMI-l Restart Test Program Including OTSG Repairle Figure A-2 TMI-1 OTSG Tube Repair Precritical Test Program TABLES Table IV-1 Three Mile Island Unit 1 Administrative Controls Primary Water Chemistry Table X-1 Leakage Dete; tion Methods Summary Table Table IX-1 Laboratory Induced Cracks E/C Correlation Table IX-2 Critical Crack Sizes and Leakage Table XI-1 Maximum Hypothetical Off-Site Doses for 1 lbm/hr. and 6 GPH Primary to Secondary Leak Table XI-2 Exposures from OTSG Program Table XI-3 Radiation Fields at TMI-1 Table A-1 Pcst-Repair ECT Inspection Table A-2 Steam Line Fittings Inspection
- iii -
I.
INTRODUCTION A.
Purpose In November 1981 primary to secondary side leaks were discovered in both TMI-1 Once Through Steam Generators (OTSG). Subsequent detailed failure analysis showed that extensive circumferential cracking had occurred in the OTSG tubes. This safety evaluation describes the results of the f ailure analysis, the evaluation of the methods of repair, and the operational, safety and environ-mental impact of operating the repaired generators.
B, Backeround TMI-l is a 776 MWe pressurized water reactor having two verti-cal, straight tube and shell once-through-steam generators
( OTSGs ). 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-eelded.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 tests were performed in August-September 1981 and did not indicate any problems with the OTSGs. However, in November 1981, during pressurization for additional tests, primary to secondary leaks were detected in the OTSGs.
As soon as GPU Nuclear Corporation realized the extent of damage l
to the THI-1 steam generators in early December, 1981, a dedi-cated OTSG task 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 i
organization included determining the cause of dauage to the steam generators, defining the status of the steam generators in terms of what type of damage and at what locations, evaluating l
the numerous repair options and implementing the one chosen.
evaluating the effect of the repair on both OTSG and plant per-l l
formance, and establishing whether or not additional THI-1 com-ponents had been damaged by the aggressive environment which was apparently created in the once-through steam generators. An internal safety evaluation was performed which included these areas.
Throughout the entire OTSG repair program, GPU Nuclear Corporation made every effort to obtain the advice and counsel of experts throughout the utility, manufacturing, and research communities. As can be seen by reviewing the task organization on Figure 1-2, the organizations and companies involved in de-fining the status of the stear generators and assisting in their i
i repair cover a broad range of expertise.
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In order to provide added assurance that the TMI-1 OTSC repair was conducted in a prudent, safe and technically correct manner, an independent third party review was established 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 tasked to provide an independent and objective safety evaluation of the failure anal-ysis pr'ogram, eddy current examination program, OTSG performance evaluation, OTSG repair criteria, and the overall OTSG repair The advice and recommendations provided by this third program.
party review have proven very beneficial. Their participation provides added assursnee that the OTSG repair activities both conform to the NRC rules and regulations governing the operation of TMI-1 ano assurance :nat ene acequacy o cae. cac ser.cra: r repair program allows safe operation of the TMI-1 nuclear unit.
C.
Steam Generato'r P.epair program The approach taken to restore the Steam Generators to service was to evaluate the con'dition of each tube with eddy current techniques developed specifically for the geometry of this corrosion mechanism. Following ECT the status of each tube was evaluated 'and one of the available repair methods was chosen.
Figure I-3 summarizes thi disposition of all the tubes in the TMI-1 Steam Generators after repairs have been completed. This figure indicates the four! methods of disposition, the basis for selecting those methods ard some other concerns that were con-sidered and resolved in selecting those methods.
l The first estegory includes the tubes removed from service prior 15 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 tiose tubes which had sections removed from the steam generator for metallurgical examination and those tubes which indicated leakage during the initial tests after damage was discovered.
The second category is the primary repair method for the steam t
l generators. This repair method for the TMI-1 OTSGs involves expanding and rescaling 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 l
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 l
l vall causing an interference pressure between the tube and the tubesheet.
The tube expansion repair method is feasible because of the specific nature and location of the cracking in the TMI-1 Steam l
Generator tubes. The majority of the cracking is located in the i
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DISPOSITION OF TUBES IN TMi-1 STEAM GENERAT(.ilS 3,
3 31.062 TUBES TOTAL i
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anissed desing inspection psegram willleak desing test progsam long and sheet term cessasien tests den eastsated that local 1G A is not a concesa and that cracks will net psopagate by cessesies mechanism precautions taken which will yseven: new esach losmation I
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upper ends of the tubes of the two generate:2, at or near the upper 1 in. to 1.5 in. where the 56 ft. long tubes were mechanically rolled and then seal welded to the tube sheet cladding (see figure I-5).
The combination of rolled joint and seal veld held the tubes tightly in place within the tubesheets.
At TMI-1 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 5,
tottom of the expansion to serve as the new pressure boundary.
This expansion length corresponds to eight inches above the lower face of the upper tubesheet (US+8).
This length provides
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be repaired by expansion and those that would be removed from service. For the TMI-1 OTSC geometry and materials, a 6 in.
long joint belcw 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 service will be kinetically expanded irrespective of whether or not a defect has been detected. (see Figure I-6).
i 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 less.than 40% through wall. Since analysis indicates that these tubes will not fail by mechanical, thermal and accident loads, they are being lef t in service to provide characterization of f
these indications after they have been exposed to operation.
l Leaving this category in service provides information in future l
ECT inspections of the stability of these indications.
D.
Safety Evaluation Logic To determine if the plant could be safely returned to service, a l
program was initiated to define all the significant effects of operation of the steam generators after exposure to the damage mechanism and after the steam generators vera repaired. The main product of this program was a logic diagram which defined the major areas that needed to be addressed and also defined the detailed tests, inspections and analyses which were performed to support each of these areas. A condensed version of this logic diagram is presented in Figure I-7.
This diagram lists the major areas that were considered and references the sections of this report which describe the results which support the conclusion that the TMI-1 Steam Generators can be operated safely. The results of these programs demonstrate the following:
(1) The failure mechanism is understood well enough to define the root cause of the steam generator damage; I l
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(2) Other components in the RCS and supporting safety systems were not visibly damaged by the failure mechanism; (3) The plant can be operated such that this failure mechanism is arrested and will not recur; (4) The Steam Generators can be repaired and operated within the design basis; (5) The plant can be operated with some tube leakage without adversely impacting the environment.
The remrinder of this section provides a brief syrepsis of the entire reecrt vith erehtsia en the leti: used te e-terri-e th1t the plant can be safely operated with repaired ste m generators.
a Report Summary A detailed failure analysis was performed including (1) review of the OTSGs fabrication history, (2) coordination of metal-lurgical examinations of tubes pulled from the OTSGs, (3) review of the OTSG operating plant chemistry histories, (4) coordina-tion of OTSG tube stress analyses, and (5) development of a failure scenario. This failure scenario, which provides a reasonable match between plant conditions and the mechanism which caused the tubt cracks, concludes that sulfur contamina-tion in the presence of sensitized tubing material at the oxygenated, cold conditions existing after hot functional tests led to the observed intergranular stress assisted corrosion.
Section II summarizes the failure analysis.
An inspection of additional RCS components which included non-destructive testing was performed to determine if other com-pe'ents sustained similar damage to that found in the OTSG.
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 underway. Details can be found in Section II.E.
As shown in Section IV, paths for chemical injection into the RCS and administrative controls on chemicals were examined in an effort to prevent future chemical contamination of the RCS.
Additional periodic chemical analyses will be performed during plant operation and some administrative limits for chemical concentrations have been changed. A sulfur conversion and removal process will clean the surfaces of the Reactor Coolant System. This process will be conducted prior to restart. -.
I l
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 wer -
considered. For the expansion rapair 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 s ammarized in Section V.
In addi-tion ~to the qualification program, a process monitoring program was s'et up to oversee the expansion process.
Plugging repair is summarized in Section VII.
B&W Welded Plugs,
35W explosive 91uss and Westinghouse rolled plugs were cuali-fied. Analysis verified that adjacent expansions wouta nave 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 transient performance.
In the unrepaired region of the OTSG, various tests and 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 chemistry.
If rapid cracking should reactivate due to an unknown mechanism at operating temperatures or during heatup and cooldown cycles, it is anticipated that the precritical testing sequence would allow sufficient time for defects to propagate through wall to a size that would allow leakage to be detected. Therefore the precritical leakage monitoring during the hot testing will detect crack propagation.
(2) Analysis has demonstrated that cracks below a minimum range of length and through wall thickness will not propagate mechanically. Analyses included calculating a minimum size r
below which a crack will not become unstable due to plastic tearing or ligament necking during a main steam line break (MS LB). This range of crack sizes is detectable by the ECT inspection system that was useu to inspect the steam generators.
(3) Any defects in the detectable range that are undetected during the 1001 ECT inspection because of equipment or an-If alyst error will be exercised during the test program.
they are 100% through wall and of a size to propagate to failure under loading, they will be detected by leakage monitoring programs.
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e 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 chemistry, showed that the damage mechanism had been arrested.
To determine if all unacceptable 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 shreed that e-schs of the si:e that ceuld erocaeste to failure by combinations of mechanical loads were within the ECT detect-ability limits. local IGA one to two grains deep was examined during the metallurgical examination program and there was no indication that this effect was related to the failure mechanism.
A precritical testing program has been designed that will pro-vide confirmation of the adequacy of the OTSG repair and OTSG cperability. 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 accelerated 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 tubes with mechanically unacceptable through wall cracks will be detectable during the test period.
Operation with a primary to secondary leak at the repair design l
goal of 1 lb/hr. and at a more conservative rate of 6 gal /hr.
has been evaluated. These leakage rates have been found to pose j
to the health and safety of the public and allow the no threat plant to operate within existing Appendix I Technical Specifications. Details can be found in Section XI.
This report concludes that TMI Unit I can operate with the re-l paired OTSCs without undue risk to the health and safety of the public.
l l -
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II.
FAILURE ANALYSIS Three Mile Island Unit I was in cold shutdown from March 1979 until September 1981. In September 1981 hot functional testing 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 November 1981 and small leaks from primary ec secondary side were detected in the tubes of the once through steam generators (OTSG's).
A detailed failure analysis was performed to determine the root cause of the steam gecerator damage. This analysis included a review of the steam generator operational history, a metal-lurgical and corrosion test proeram, a review of OTSC stresses and faorication nistory, and cne cevelopment of a Iallure scenario. In addition, the distribution of damage both in the OTSG's and the remainder of the RCS was investigated.
A.
Operational History The time of the OTSG tube failures may be bracketed based on operational considerations.
During RFT on September 4,1981 the i
leak rate of the RCS at full pressure was measured and found to be within spec at.5 gps.
On November 21, 1981 with the RCS at about 40 psi, leakage through the OTSG tubes was observed.
A review of operational history of the T41-1 steam generators i
was performed for the period April,1979, through November,1981 l
to determine whether instances of chemical contamination or l
excessive tube stress could be identified to determine the cause of the tube failures. A detailed description of OISG operating history is found in Reference 2 and Reference 22.
The operational history of the THI-1 OISG's reveals that the tubes were not subjected to excessive stress, and generally, the reactor coolant system chemistry remai
- d within specifications for the period extending from 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 I
instances of probable intrusion of chemical contaminants into the Reactor Coolant System (RCS).
In March 1979 oil was intro-duced into the Reactor Coolant Bleed tanks probably by over-flowing the miscellaneous Waste Storage Tank through the vent l
l header. 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-l bon is reported to be in several forms either as a hydrocarbon, a carbonate or elemental carbon. Carbonate was present mostly l
on the surface, and hydrocarbon at greater depths in the oxide layer.
It can not be determined whether the presence of carbon or hydrocarbon on the tube surface resulted from contact with reactor coolant containing some oil or from exposure to normal l l 1
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s atmospheric contaminants af ter removal from the OTSC. In October 1979 sulfuric acid was injected into the Reacter Coolant Makeup System. Although attempts were made to prevent the acid from reaching the RCS, chemistry results indicate some contami-nation of the RCS occurred (see Reference 22). In July 1980, May 1981 and September 1981, a surveillance test wcs performed which may have allowed sodium thiosulfate from the Reactor J
Building Spray System to find its way into the RCS.
Sodium thiosulfate at levels of 4-5 ppe as thiosulfate is censidered to be the moet likely contaminant. The ionic species from the first contamination incident in July 1980 were removed from the bulk liquid by demineralization 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 essin wacer precca: i.;ar :n ac us:.:...
.s e
- nicau.-
fate residual could have still been present at the start of September 1981. Additional sodium thiosulfate in the RCS may have resulted from injections of Borated Water Storage Tank I
(BWST) contents during 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 detectable by conductivity.
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 then slowly raised over i
the rest of the month. This allowed a drying then rewetting'of the tubes in the upper portion of the steam generator, causing chemical concentration in that region.
Oxygen introduction is also believed to have played a role in l
the damage mechanism. There were two occasions when or.ygen was l-introduced into the system. When the water level was lowered, I
the OTSG primary side was vented to the waste gas system. The maximum oxygen specification in that system is 2%.
Thus, oxygen was available at the liquid surface while the liquid level was I
being lowered. The RCS was vented to atmosphere through a CRDM vent on October 7, 1981 and remained open until filling in November when the leaks were discovered.
B.
Metallurgical Test Program Af ter identificar#on of the leaking OTSG tubes by nitrogen bubble testing, it was decided that in order to determine the cause of failure, tube samples would need to be removed from the steam generators for analysis. The initial selection of tube samples was made af ter eddy-current testing had been commenced and the choices were made based on maximizing the number of defect indications in each tube and providing an adequate sample of eddy-current signals for eddy-current qualification.
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J three tubes' contained eddy-cur' rent indications of greater than 80% through wall penetration.,
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Af ter the initial samples $ad' be'en redovedbt was confirmed
[
that ed.dy-current signal anomalies v'ere^ showing up at the roll transition region. In order to determine the disposition.of these "tubel, additionas tu'be samples were selected for removal
-which contained these eddy-current signals. This time, fifteen (15) tubeT'were reinoved from the "A" generator.'
7 A third sec of t'ube samples were removed which included 6 tubes frem the "B" eenerator and /* tubes from the "A" generater.
,These samplee 1ere taxen to cocain some tow l ev e s' cetects from
(*
T, deep in tue.eceam generator, to sample tubes from specific areas, and obtSin tube ends to be characterized (in previous samples ths,cQbe ends had been removed during pulling).
1.
Andvs is ' Program N
A multi-task, program was conducted to provide information relatsd to'ths steam generator tube damage problem. This
~
program. contained'che following analyses / examinations:
.V sua ' Examination i
a.
b.
Eddy-Ourrent Examination c.
Radicti aphy d.
Sectioning-and Bending
+
Scanning Electron Microscopy (SEM) and Energy Dispersive e.
X-Ray Analysis (EDAX) f.
Auger Electron Spectroscopy (AES) g.
Electron Spectroscopy for. Chemical Analysis _(ESCA) h.
Sodium Aside Spot Test s
- i. Metallography-Microstructural Analysis Scannin( Transsission Electron Microscopy (STEM),
5
' j.-~ Electrokinetic Potenciostatic Reactivation (EPR) 'and 3
[
Huey Testing.
k.
Residual Stress and Plastic Strain 1.
Tension Testing.
__ a m.
Hardness Tegting.
-.n.
Dimensional Measurements.
s x -
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m,5 2.
Test Program Results/ Conclusions l
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' ' ' '. TheNdetaileF test results'are presented in Reference 2.
The sunucrizes thoie resulta and sets forth some con-followings
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N a.
The tubing has failed due to intergranular stress as-sissed cracking. The intergranular morphology has' been e
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confirmed by Metallography and Electron Microscopy.
This has led in many cases to through wall penstrations and circumferential1y oriented cracks.
In all cases, cracks have initiated on the primary side surface.
b.
Microstructural evaluation of the tubing from numerous locations, has indicated that the structure is repre-6entative of that normally expected for steam generator tubing. Tests have concluded that the material is in a sensitized condition and hence is expected to be suscep-J ti51e to intergranular attack in oxidizing acids.
Transmission Electron Microscopy has also confirmed that c.
no secondary mode of failure is associated with the intergranular corrosion, cnac s, no avleenca of ar.y.;-
or high cycle fatigue was observed on these fracture surfaces.
d.
The consistent circumferential orientation of the cracks below the veld heat affected zone, indicates that an axial stress is part-of the cracking mechanism. the Residual stresses in the roll alone were not responsible for the cracking. Therefore, the fact that the cracks occurred when the tube was under a higher applied axial '
tension stress rather than hoop stress, confirms that the cracks formed during cooldown or cold shutdown.
e.
Axial cracks have been observed at the top end of the tubes near the seal weld. Some of these cracks pene-trate 100% through the wall but they do not penetrate the weld metal. The axial orientation in this case is expected based on the residual stress distribution in the area of the seal weld.
f.
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 f
tubing down to the 9th tube support plate, are generally l
uniform with perhaps a slightly decreasing level lower in the' tube sample. The form of sulfur is believed to l
be either in the form of ni.kel sulfide (Ni 8 ), or 23 j
some other reduced form of sulfur. The reduced sulfur form generated from the contaminating species is directly responsible for the cracking mechanism.
Auger analysis also showed that carbon was present at levels from 50-90 atomic percent on first and second --. - - -
round tubes, but a maximum of 50% on third round tubes.
It is thus inferred that the extensive carbon contamina-tion on the first and second round tubes 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 presence of nickel, chromium, oxygen and normal trace quantities of fission products on the fracture surface.
g.
In conjunction with the cracking, there has also been intergranular corrosion observed. These " islands" of IGA are not always associated with cracking and in senerai are associe:ac stea.....
.....a.
- .. Ir.a..:
crack locations tend to penetrate deeper than the ap-proximately 1.5 to 3 mils of penetration typical of the ICA " islands." Most severe cracking in general relate.
to more severe intergranular corrosion.
h.
In 39 out of 42 cases to date, cracks which have been examined either by metallography or by bend testing have shown the defects to be 100% through wall. The re-a;ining three cases exhibited penetrations of 66, 70 and 70%.
C.
Corrosion Test program A corrosion test program 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 conclusions can be drawn from corrosion tests which relate to the failure scenario.
Thiosulfats can produce cracking similar to that observed in a.
the steam generator tubing.
b.
In the absence of thiosulfate no cracking has been produced in the laboratory in primary water chemistry.
Tubing removed frem the steam generators app' ears to have a c.
lower thiosulfate concentration threshold for cracking than an equivalent archive tube which has been sensitized.
d.
Tubing thermal history is a key parameter in establishing material susceptibility. A threshold level of sensitization must exist. Data suggests higher mill annealing tempera-tures favor cracking in sulfur contaminated primary water..
~
~
Crack initiation and growth race are temperature dependent.
e.
For susceptible material, crack initiating time will be decreased and crack growth increased by raising temperature up to 170'F.
f.
An oxidizing potential is required for cracking to occur.
In the absence of oxygen, cracking has not been observed in the laboratory.
g.
Crack growth rates appear to be very rapid and can be as high as 1 mm/ day. Lab specimens have exhibited partial through wall penetration in areas of lower stress.
7.
0: :?e S +-aria The conditions needed for Intergranular Stress Assisted Cracking were evaluated and compared to the conditions in the TMI OTSG's.
Based on stress analysis, fabrication history, the timing of the cracking, metallurgical and corrosion testing and observed features of the cracking phenomena, a failure scenario was proposed.
1.
Intergranular Stress Assisted Cracking (ICSAC)
The occurrSuce of stress assisted cracking requires that three conditions be satisfied simultaneously:
a suf ficiently high tensile stress o
a susceptible material microstructure o
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 weld heat affected zone, the sum of the operating and residual stresses in the axial direction was greater than that in the hoop direction. Axial tensile stresses are of principal interest. Very little tensile stress is required to crack Inconel that is this susceptible in the presence of reduced forms of sulfur.
However, the higher the tensile stress the more rapid the crack propagation and the more cracks that actually occur. -
~. - -
a The stress analysis results suggests that the cracking must have occurred during cooldown or during cold shut-down because the axial tensile stresses are largest during this time. The analysis also indicates that the seal weld heat affected zone and the. roll transition regions would be particularly prone to cracking due to locally hig'h axial ten'sile stresses which are possible in that region. More cracking occurred in the periphery than in the center of the tube bundle because the axial stresses at and below the roll are generally larger at the periphery than in the center of the tube bundle.
l b.
Susceptible Material Microstructure There is no indication that tuce material, faar cation or installation in the OTSG's was in any way extra-ordinary. The heat treatment of the whole OTSG fol-lowing assembly puts the tubing into service in the mill annealed plus stress relieved condition which is ex-pected to be heavily sensitized (i.e., low grain boundary chremium content less than 10%) thus making it more vulnerable to IGSAC. Metallurgical examination has confirmed that the expected microstructure is present.
A large number of heats of Inconel 600 are present in the OTSG's which differ in composition and which may have responded dif ferently to the stress relieving heat treatment. The degree of susceptibility as a function of the tubing heat number could not be established.
c.
Aggressive Environment As previously stated in Section II.A. the results indi-cate chat sulfur was present in the primary system water and three possible sources of sulfur have been identi-fied from the OTSG chemistry history.
If SO4 and S 02 3 were introduced to the primary water as the OTSG 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, hydrogenating and heating the water to perform i
a het functional test would be expected to result in the generation of S~~, possibly accompanied by S and other intermediate species. Subsequent cooling to room temperature and oxygenating following the hot functional.
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tests rapidly oxidize S-~ to S and could also result in the appearance of significant concentrations 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 functional 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 OTSG tubing.
2.
Proposed Failure Scenario This following scenario is consistent with all the observed features of the cracking phenomenon, the timing of the
- r::hin; :nd the reru*.t? ?f the -e:111ur:2.:-1 *Mami eti 9-and corrosion tests.
a.
During layup the primary system was contaminated with sulfur by the accidental introduction of sulfuric acid, sodium thiosultate, and possibly a sulfur-containing oil. The amount of sulfur present may have reached several ppm, but the contaminated water was not aggres-sive enough to crack mill annealed plus stress relieved Alloy 600. The corrosion tests confirm that cracking would not have been expected to occur at this stage.
b.
The *emperature and oxidation potential transient as-seciated 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 thiosulfate-contaminated oxygenated water was in-jected during the tests of the HPI and LPI systems.
i c.
When the water-level in the OTSG's was lowered following the hot functional test, high concentrations of aggres-sive metastable sulfur species developed in the dry-out region at the top of the generators due to the combined effects of solution concentration by evaporation and the comparatively high availability of oxygen. Changes in the sulfur species in the more dilute bulk solution proceeded more slowly resulting in lower concentrations of aggressive sulfur species.
d.
Sulfur-induced ICSAC of the Alloy 600 tubing occurred rapidly in the dry-out zone with preferential attack at high stress locations in the most highly sensitized tubes. Cracking occurred to a lesser extent lower in the generator. Statistically this would be expected
. ~. - -
.o.
1 because the bulk solution was less aggressive than the environment seen by tubes in the dry out zone. Cracks would cecur in areas low in the generator which were slightly more susceptible to IGSAC due to surface film anomalies or residual stress anomalies.
Cracking terminated either because continued chemistry e.
changes resulted in the formation of less aggressive sulfur species or because the environment in the dry-out regi;n 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
- fficit ti; di'fer?mt 'rce its state i==ediately after the hot functional tests to prevent a recurrence or steps C and D in the new dry-out zons.
f.
Cracking was discovered when the OTSG's were pressurized.
E.
Distribution of Damage To evaluate the extent of the damage, an eddy current testing (ECT) program was devised to examine the OTSG's.
In addition, an inspection of other components in the reactor coolant system (RCS) and supporting systems was conducted to determine if damage similar to that found in the OTSG's was evident.
~
1.
OTSO Eddy-Current Examinations Special eddy current techniques were developed and an ex-tensive testing program was established to provide an ac-curate description of actual OTSG tube cracking (Reference 20). In-situ eddy-current results exhibit tube wall defect indications at varied densities distributed both axially and radially in both OTSG 'A' and
'B' tube bundles. Ihe majority of the defect indications were in the upper tube-sheet (UTS) region and particularly confined in the tube roll transition zene. After an absolute probe inspection of the roll transition and mechanically expanded area of I
approximately 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 decision to repair the top 17 inches of t
l l
all the tubes. Figure 11-1 gives the number of tubes with l
defects by elevation in each generator. Radial distribution of tubes (as shown in Figure II-2 and 11-3) with defect indications requiring plugging in both ' A' and
'B' OTSG l
shows a higher percentage in the periphery with the defect l ~
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rate decreasing as you move toward the center of the bundle. Defects indicated below the upper tubesheet are located toward the periphery in the 16th span and were random below the 16th span. Reference 20 gives a detailed description of ECT results.
2.
Tube End Damage In the fall of 1982, corrosion and cracking problems were identified in the steam generator tube ends, where they extend above the seal weld and upper tube sheet. The tube i
and damage was evident with metallurgical analysis of tube ends removed from the generators with the last 10-tube sample. After kinetic expansion, damage was visible. The
- p.
- s1 crac.< carte :a2 ;e;. a f. : i: 1 ::::in :i:n :f *:c S axial and circumferential cracking, the pattern depending on stress due to veld shrinkage in the heat affected zone of the seal weld, and on other factors. Metallurgical evidence shows that the veld material arrested the cracks in all samples, although some cracks extend through the tubing material behind the veld to the tubing below. The forca of kinetic expansion removed parts of some tube tops where a circumferential crack was located in conjunction with verti-i cal cracks. Other tube tops were billed out, where vertical cracks were through wall but circumferential cracks were in regior with ductile material remaining.
In order to further define the problem, GPUNC removed tube end pieces from the tops of approximately 12 tubes and con-I ducted a metallurgical examination in order to define what, if any, ductility remained. The evidence from this examina-tion indicated that about 1/3 of those pieces removed were intergranularly cracked on all sides (both circumferential1y i
and axially).
.I Evaluation of the metallurgical evidence indicated that the weld material arrested the cracks in all cases noted.
(Ref.
57). Additional dye penetrant tests were conducted on seal I
welds in the upper tubesheet to further confirm that the welds and the heat affected zone between the tube seal weld and the tubesheet cladding were not cracked. The absence of cracking as noted in these dye penetrant checks provides assurance that the seal welds themselves and the upper tube-sheet cladding were not cracked. Similar examinations of the lower tubesheet welds and tube ends also showed no l
dama ge.
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1 With the damaged areas defined, GPUNC evaluated the poten-tial for loose pieces from the tube ends both above the seal weld and in the area behind the weld where vertical and circumferential cracks existed. This evaluation is docu-mented separately in Reference 55.
It was concluded that tubing below or behind the seal weld was unlikely to be degraded to the point of loosening under the low loading in these areas. However, tubing above the seal weld was con-sidered to have potential to break loose. Thus, the deci-sion was made to remove all tube ends above the seal weld by milling.
3.
RCS Inspection The sulfur induced attack on tne OI50 tuce promptec an ;a-spection of other elements of the Reactor Coolant System, to determine if other components sustained similar damage. An inspection plan was developed based on a review of the arterials involved and the accessibility of the materials within the system. Representative items in the Reactor Coolant System that were most likely to have suffered attack were selected for examination. The items chosen represented the most susceptible materials and reflected environmental and stress concerns.
Materials located in either of three environmental condi-tions were evaluated.
Primary coolant-air interface where most of the defects a.
occurred in the CTSG.
b.
Dry areas since the last refueling, but which have been previously vet.
Wet areas, covered by primary coolant.
c.
Since the known attack had occurred in the OTSG on stress-relieved Inconel 600 cubing 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 to be susceptible to IGSAC. Other than the OTSG tube preload stress, areas'of concern with respect to stress included bolting that has a steady load due to torqueing, residual stresses irduced by welding, and force-fit items.
1 -
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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 developed to also account for criti-cal functions of the RCS items. The function of the pres-sure boundary, core support, and fuel integrity received the most emphasis. This was to determine the general condition of the system and, of course, because they are the most directly safety related.
The non-destructive examination methods used were; ultra-sonic, liquid penetrant, eddy current, radiography, visual, and wipe sampling. Other examinacions included functional check on equipment and destructise metallurgical examina-tions, both at the TMI-1 site anc at B&W Research Laboratory at Lynchburg The selection of examinations was governed by factors relating to the type of waterial, geometry of material, location and accessibility, and radiological con-trol limitations. The following is a summary of methods used and example materials examined by each method.
Ultrasonic Examination Method - this inspection included the pressurizer spray nozzle safe end, CRDM motor tube exten-sions, make up piping nozzles, plenum lif ting lug bolts, plenum cover to plenuu cylinder bolts, pressurizer surge nozzle, core barrel bolts and low pressure injection pipe welds.
The ultrasonic method used to examine bolts of the TMI-1 core barrel assembly had the capability of detecting indi-cations having a depth of 20 percent of the diameter of the bolts. This sensitivity is considered sufficient primarily because a large number of bolts were examined at TMI-1 and no evidence of intergranular attack or IGSAC was found. For example, 96 of the core barrel assembly Inconel X750 bolts were UT inspected; if intergranular attack or ICSAC had occurred, it is likely to have been detected in this exten-sive sample.
Radiographic Examination Method - This method is a volu-metric type of examination that produces a visual image of the test specimen. For this reason, this method was chosen to validate the structural integrity of the thermal sleeves for the safe end nozzles. The pressurizer spray nozzle and the three make up nozzles were located in a coolant / gas interface and the coolant dry area respectively.
' i m,- -.,. ~,
.m
o Liquid Penetrant Examination - Special consideration was given to the welds of the secondary oversheath to assembly oversheath of the incore detectors. Icess examined by this method 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 noz-zie, lower OTSG cladding surface and incore detector por-tions from the wet regions.
Eddy Current Examination Method - Th9 ID surfaces of the RV vent valve thermocouple and the CRDM nozzle were the areas of special concerns which required this method cf volumetric i
and 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 top of core control components, the baffle plate region and the annulus between CSA and RV.
Areas of similar condi-tions, even though they were dry of reactor coolant. were the plenum assembly and the vent valve assembly.
Wipe Sampling Method - This method was performed prior to non-destructive examination other than visual. The samples were chemically analyzed to determine the concentration of any aggressive species.
The results of the inspections and tests which involved over a thousand selected components, indicated that there was no evidence of a problem similar to that seen on the OTSG tubes. The functional tests all indicated that the tested assemblies were operational. The destructive examinations revealed that even on a microscopic level, no evidence of intergranular attack could be found. Therefore we conclude that based on this Inspection & Test Plan, the materials in the Reactor Coolant System are re-certified for continued safe operation. The details of this inspection are reported i
in Reference 28.
4.
Supporting Systems Inspection l
An ICSCC problem was originally detected in the Spent Fuel l
System in 1979, and a three year inspection program was l
established which was specific to Spent Fuel, Decay Heat and l
Building Spray Systems. As of June 25, 1982 all required volumetric examinations of the first cycle on the ICSCC schedule were completed and no discrepancies were noted. As i
l j l
I
of August 5,1982, visual examinations were completed for Decay liest and Building Spray with no additional indications identified. The ploccing and trending of the known indi-cations did not reveal evidence of growth. In March 1982, cracks which were attributed' to IGSCC were found in the Waste Gas System. Additional supporting systems inspections are underway. Results will be reported in response to LER 82-02.. -.
~
III. CORROSION TEST PROGRAM A.
Introduction An extensive corrosion testing program was initiated in December of 1981 to support the steam generator repair program. The pro-gram in several phases was designed to accomplish the' following:
(1) Determine the conditions under which the corrosion mechanism occurred and how it could be arrested, (2) Verify the proposed corrosion scenario to provide assurance that the mechanism was understood (3) Determine whether tubing that has been kinetically expanded would be more susceptible to corrosion in service than other tubing and (4) verify that cleaning using
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T'= f e' ' - eine sections describe the results of this program.
B.
Corrosion Mechanism Determination Tests In December 1981, analysis of tube samples removed from the TMI-1 "B" Steam Generator identified the corrosion mechanism as stress assisted intergranular crackir.g. Cracking was circum-ferentially oriented and initiated from the primary side surface of the tubing. Analysis of the circumstances which led up to failure indicated 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 corresion mechanism might still be active.
~
A corrosion test program was immediately put into place to ascertain whether or not significant corrosion was still occuring. The first of these tests was initiated in February of 1982. In this test, sensitized samples of 304 stainless steel and Inconel 600 were immersed in primary coolant removed from the decay heat loop. This coolant was analyzed and found to contain 350 ppb sulfate. Specimens utilized in this test were 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 removed from 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 tube specimen with the decay heat solution on the internal surfaces, then axially loading the specimen to 1100 lbs. at a test temperature of 100*F.
However, prior 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. After all testing was completed, 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 crack. It thus appeared that crack growth was also arrested and no further tube degradation was expected. This was confirmed by i
the eddy current examination performed on the 100 tube sample three35 cut t'e -ent se~ertl -er.ths.
Ne a"idence of
- n" trewth of known defects or detection of new defects was caservec f;ce 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 conditions necessary to produce the type of intergranular corrosion observed in the TMI tube samples.
A number of tests 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 electrochemical potential regimes for this cracking to occur. Solutions of boric acid containing*various concentrations of thiosulfate contaminant were tested. Those tests showed that thiosulfate at levels in excess of 5 ppm would cause cracking in sensitized archive tubes provided the degree of sensitization was suf ficient. It was also determined that an oxidizing potential in the presence of a reduced sulfur form was required for this crceking.
Specimens made from actual TMI tube samples removec from the steam generator were tested. These samples appeared to be more sensitive to the cracking phenomena since they cracked at thiosulfate concentrations as low as 1 ppm. This is believed to be due to either a dif ference in degree of sensitization of material removed from the generator or due to the effects of previous exposure of these samples to the thiosulfate contaminant 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 potential range, that in the absence of thiosulfate, specimens would not crack. Cracking was observed at open circuit potential in an air saturated eviron-ment in thiosulfate contaminated solutions. However, if the
.c,
.~ - - -
solution was deserated and an inert cover gas utilized, cracking was not observed in any specimens. Based on the results of approximately 60 tests it appears that thiosulfate or reduced metastable sulfur can produce and is a necessary requisite for the cracking observed. Additional results indicated that time to failure decreased as thiosulfate concentration was increased and also as temperature was increased up to 1700F.
During this same time period testing was also being conducted at Brookhaven National Laboratories for the NRC. These tests were constant extention rate tests (CERT) utilizing solution annealed and sensitized Inconel 600 test specimens. The purposes of these tests were to define the minimum thiosulf ate concentration required for cracking as well as to establish the effect of temperature and Licatum nycroxtee con:an: ration on ::.....;
susceptibility. The results of these tests indicated the cracking in the absence of Lithium could be expected in highly sensitized material at thiosulfate levels on the order of 70 ppb., However, in the presence of Lithium it was found that cracking would not be experienced on sensitized materials provided the ratio of Lithium to sulfur remained greater than or equal to 10. Although additional tests are being planned to expand on the knowledge and understanding of the influence of Lithium on inhibiting cracking, this data has been utilized in preparing new administrative chemistry guidelines for TMI-l operation. The lower limit on lithium has been raised such that a concentration of 100 ppb sulfate can be tolerated in the RCS.
Brookhaven also' conducted a series of tests to establish the influence of temperature on crack growth rate. Results of their tests indicated that approximately 170 F produced the maximum 0
cracking velocity.
At this phase the evaluation had established that:
o Cracks in the OTSG were not currently propagating Cracking in non reduced sulfur contaminated environment was o
i not anticipated o
The corrosion appeared to be a low temperature phenomenon l
Oxidizing conditions were required for cracking o
A highly sensitized microstructure was required o
Lithium hydroxide could be used as an ef fective inhibitor of o
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 fests During the summer of 1982, testing was conducted at Oak Ridge National Laboratories in an attempt to verify the proposed scenario. As defined in the failure analysis, it was. believed that corrosion occurred during the cooldown phase af ter hot functional testing, a period in which oxygen was introduced into the primary system as well as lowering of the water level in the OTSG's.
It was felt that the lowering of the water level allowed reduced sulfur species to concentrate in the thin water film on the tube surface and in the presence of oxygen caused cracking.
Although it would not be possible to totally duplicate the cor-rosion scenario, an attempt was mace co escaolisn cesc para-meters which were a close approximation to a hot functional test sequence. 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 influebce of tube surface films on the cracking mechanism, all test specimens were actual tube samples removed from the TMI steam generators. This allowed an assessment of whether oxidizing /
l reducing conditions in the steam generators could change surface j
films and form metastable sulfur compounds which could lead to intergranular corrosion. Autoclaves were set up to test sulfur contaminated borated water solutions with I ppm and 5 ppm thiosulfate and 30 ppm sulfate. This latter test assessed if oxidized forms of sulfur of themselves would be aggressive. The I
test sequence allowed for examination of specimens af ter an initial exposure at 170*F.
In all cases, no cracking was observed at that phase.
The specimens were then put back into the autoclave and the l
temperature was raised to 500*F.
Subsequently during the cool l
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 after the hot functional sequence showed no cracking for the 1 ppa thiosulfate solution and no cracking for the 30 ppa sodium sulfate solution.
However, cracking was observed on specimens in the liquid phase of the 5 ppe thiosulfate test. No cracking was observed in the vapor phase of any test.
This indicated that a threshold concentration of thiosulfate may be required for cracking to occur.. What is not known, however, is whether the cracking occurred during heat up or cool down for this particular sequence. It may logically be assumed that cracking occurred during the heatup phase as tests conducted have thus far shown cracking does net occur at elevated temperatures. In addition, testing conducted in the 1 ppa thiosulfate and the 30 ppm l k--
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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 intergranular cracking.
i D.
Reoaired Tubint Corrosion Tests This corrosion data base, supported the conclusion that an ef-fective repair could be made. The choice of explosive expansion appeared to be the most technically feasible solution, however, with the expansion process came a new geometry which would have i
a transition from the expanded portion to the unexpanded portion of the tube which was not stress relieved. An accelerated short term test was conducted to assess the impact of this transition on the tube susceptibility to corrosion (Reference 29).
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Even though all short term tests were done under accelerated conditions, it was still felt that a certain time dependency may be required for corrosion to initiate. Long term tests were f[
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- + =
- r developed to address this time dependent parameter (Rafer-i ence'8).
These tests have been scheduled to lead the actual
^
performance of the generator and thus provide additional insight as to the expected perfor=ance of the tubes. The long term corrosion testing program was developed to assess performance of the tubing both in the unsupported regions of the generator and tubing at the new expanded transition region. The test is designed to run for approximately 13 months of operating time and to lead actual operation of tha generator by a minimum of one month. As presently scheduled, lead testing will probably preceed operation of the generator by a minimum of 4 months.
s These tests will be conducted under si=ulated operational para-meters which will include load cycling as well as ther=al cycling. Chemistry will simulate that expected under normal reactor operations. This will include decreasing boron levels as well as decreasing lithium levels throughout the test period.
Test samples will be made from actual IHI steam generator tubes. Samples will be utilized both with known eddy current defects as well as without known eddy current defects. A mini-mum of 4 dif ferent heats of material will be utilized with samples from various elevations within the generator.
I Samples in the lead test loops include both defective and non-defective tubing in or'er to assess both the initiation and propagation phases of intergranular stress assisted cracking.
Tubes will be eddy current tested utilizing the.540" standard dif ferential probe as well as a single coil absolute probe. The size and eddy current signature of the currently known defective tubes will be monitored and any changes in crack shape or eddy current signal vill be closely watched. During the lead test, the tubes will be examined at the end of each test cycle (ap-proximately every other conth) and assessments will be made as to crack initiation or growth at each phase. In addition, at the end of each test cycle C-rings will be removed and destruc-tively evaluated by metallography te assess the initiation of.
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1 any intergranular attack. Through this lead test program, an assessment can be made regarding plant operation in the unlikely event that crack initiation or propagation is observed.
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l A third lead test loop will simulate the hydrogen peroxide l
l cleanir.g process, then continue through the hot functional tests and operating cycle simulations. Sulfur in solution will be j
s,ul f ate.
All tube specimens used in this loop will be six-inch sections of actual IKI tubing which have been L=nunol coated and
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subjected to expansien process debris. Additional specimens which are representa,tive of reactor coolant system materials will be included in this loop.
The long term corrosion test program will provide a means for making a comprehensive assessment of tube performance in actual l
generator operation over long periods of time.
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E.
Conclusions I
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IV.
PREVENTION OF RECURRENCE A.
Introduction Steps have been taken to ensure that an aggressive environment could not be reintroduced into the RCS and cause additional dama ge. Prevention of direct injection of contaminants will be accomplished by the removal of the sodium thiosulfate tank and by administrative controls. Chemistry changer have been made to include an analysis for sulfur, a conductivity consistency check which will indicate the need for reanalysis of samples, and an increase in the lithium concentration specification due to its inhibiting effect on crack initiation. In addition, to preclude l stetivatien of the snifu-vSieh is $resently in the OTSG and RCS, a chemical cleaning program will be conducted to recove or l
oxidize residual sulfur. This section discusses the steps taken to prevent recurrence.
B.
Prevention of Future Chemical Contamination Direct injection of foreign chemicals into the RCS during periods of operation is essentially limited to those substances which are placed into the Lithium Hydroxide Mix Tank or the Boric Acid Mix Tank. Injection through the reactor coolant l
bleed tanks during startup must also be considered. The probability of injection of a foreign chemical into the RCS from these tanks is dependent upon the administrative controls which are exercised over additions to the tanks.
When the RCS is cold and depressurized, additional paths for introduction of foreign chemicals exist. A path from the Caustic Mix Iank 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 from the plant, and the line to the thiosulfate tank cut, sodium hydroxide is the contaminant which could be introduced via either of the da-scribed pathways. In the event that very dilute caustic did
)
reach the tubes, damage would not be expected since increase in pH is toward a more benign condition. Introduction of other chemicals is prevented through administrative controls.
l 1
Administrative controls which are in effect include (1) clear f
labeling of tanks in the Chemical Addition Room, (2) locking open the breakers to pumps CA-P-2,3, & 4 and placing them under i
the administrative control of the Locked Valve and Component l
List and (3) review of applicable procedures to insure that adequate guidance is provided.
a
Since the range of chemicals which could be injected if adminis-trative controls were to f ail is wide, specific chemical analy-ses to detect the presence of the full range are not prac tica l.
However, because of its deleterious effect on the OTSG tubes sulfur (as sulfate) will be sampled daily in the RCS.
The otherl parameters which prove most useful in detecting ingress of un-wanted chemical species are pH and conductivity. These para-meters vary with lithium hydroxide an~d boric acid concentra*. ions with possible conductivity values ranging from a low of approx.
2 micrombos to a high of nearly 20 micromhos/cm and pH values from 4.6 to 8.5, depending upon operating conditions. Detection l of inadvertent additions depends upon changes in either or both of these parameters which do not correspond to known additions, dilutions or treatment to the system. A consistency check on conduccivity w;;. ce per:semec ::ve :: 42 per we r e. ;c ::n;;r:
that the conductivity reading is consistent with the pH, boric acid, lithium hydroxide, and ionic species concentrations being measured. Specific 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 detection of unwanted chemical contamination of *.he RCS.
C.
Changes in Operating Chemistrv 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 initiation 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. Table 111-1 shows the changes in the Primary Water Chemistry Administrative Limits.
1.
The lower limit for lithium concentration was increased from
.2 ppm 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 sulfste) is.1 ppa, thus the lower limit for lithium is 1.0 ppm.
Lithium concentration is based on boron concentration, with a maximum allevable concentration of 2.0 ppm. The lithium l
concentrations range has thus been changed to 1.0-2.0 ppm.
2.
Chloride was changed to meet revised B&W Water Chemistry Cuidelines.
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TABLE IV-1 THREE MILE ISLAND UNIT I PRIMARY WATER CHEMISTRY ADMINISTRATIVE LIMIT CHANGES OLD NEW SAMPLING SA)f LING PARAMETER FREQUENCY FREQUENCY OLD LIMIT NEW LIMIT Lithium NONE Daily 0.2 - 2.0 (ppm) 1.0,- 2.0 (ppm)
Varies with boren concentration Chlorides 5X/wk 5X/wk (0.15 (ppm)
<0.1 (ppm)
Sulfate, (50 =)
NONE Daily NONE (100 (ppb) 4 Sodium NONE 2X/wk NONE (1.0 ppm pH 5X/vk SX/wk 4.8-8.5 4.6-8.5 conduc tivity SX/wk 5X/wk NONE Check for Con-sistency With Boric Acid and LiOH Concentration i
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3.
Sulfur (reported as sulfate) was added to the Administrative i
Limits because of its deleterious effects on crack inicia-tion and growth in Alloy 600.
l 4.- Because sodium becomes easily activated and is an important contributor to total activity in the RCS, it will be moni-tored.
(
D.
To preclude corrosion by sulfur contaminants already in the RCS, GPUNC plans to conduct a chemical cleaning program to remove or oxidize residual sulfur. Testing has shown that near the outer surface of the oxide film. sulfur is oredominantiv eresent as sulfate. Furtner into tne sur:sce film, cetal suifices pre-dominate.
The cleaning process was selected to chemically convert the metal sulfides on the steam generator tubing into soluble sul-fa tes. In general, the process to be used in the plant is as follows:
The RCS, Makeup and Purification System, and the Decay Heat Removal Systems will be in use.
The pressurizer will be used to increase system pressure to approximately 320 psig.
Main coolant pumps will alternately operate and cooling-water flow through the Decay Heat Removal heat exchangers will be adjusted so that the entire system operates at approximately 130*F.
The coolant at this point will contain a boric acid concen-
+
tration between,1800 and 2300 ppm as B and lithium con-centration' of 2.0
.2. 2 ppm.
t Af ter temperature and pressure have been established, con-
/centrated ammonia hydroxide ( 30 wt :) will be added via the I
causti'c mix tank and Decay Heat Pump suction to increase the reactor coolant pH to 8 0 - 3.2 i
30 wt % Eydrogen Peroxide will be similarly charged into the !
reactor RCS to establish a final concentration of 15 - 20 i
ppa. Since the peroxide will decompose, further additions will be made as needed throughout the teat to keep the peroxide in specification.
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' ' The cleaning solution will be continuously circulated.
Cleaning is expected to take approximately 2-3 weeks.
Termination of the cleaning process will be based on the determination that no further sulfur is being solubilized and results from the process development tests.
Both the dissolved sulfate and the ammonia added will be removed from solution by ion exchange resin in the normal purification systems to levels consistent with normal RCS chemistry values.
A comprehensive test program was performed to determine the j
effectiveness of the cleaning process, and to verify that the conditions of cleaning would not introduce a corrosive environ-ment.
The program anc rescics are utscusseu la a separsca safety evaluation. Hydrogen peroxide appears to be effective in removing sulfur from both tubing surfaces and from inside crevices. Based on testing, 350-400 hours of exposure to the i
hydrogen peroxide solution is expected to be adequate to remove 50-80% of the sulfur present.
E.
Conclusions
[
t GPUNC has implemented corrective actions in four areas in order i
to prevent recurrence of OTSG corrosion. The sodium thiosulfate
~
tank has been removed from service to prevent additional in-advertent introductions of sulfur, and chemical cleaning is planned to remove existing sulfur. Stricter administrative controls have been placed on introduction of other potential chemical contaminants. Stricter controls have also been placed l
on RCS chemistry to maintain a non-corrosive environment. These actions are expected to prevent contamination and corrosion by I
j sulfur and by other chemicals.
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l V.
KINETIC EXFANSION REP AIR DESCRI? TION SW. MARY A' 'DE sc ri~o t ion o f P ro c e s s a nd Ce cce t ry 1.
Intro [ucch IMI-l OISC tube examinations have revealed a large number of tubes with defects within the upper tubesheet. A defect is defined as any, eddy current indication interpreted as greater than 401 through wall. The limits of eddy current decectability.are defined in Section IX.
The repair approahh is to establish a nre primary system pressure 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 ba'kinetically expanded irrespective of whether or not they'have a defect, and irl respective of whether they will be s
' plugged in the future. This repair will provide a load
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cairying and essentiallysleak-tight joint below known de-
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The following sections su==arize the repair program.
s Details can le found in Reference 1 and Reference 23.
2.
Kiretic Tube Exoansion s
3 The process steps which are involved with this repair have
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the objective of providing a new' pressure boundary below known defects throagh kinetic (explosive) expansion of the tube within.che tubesheet.
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' Preliminary. tes'ing had determined that' a' 6" loni expansion h
below the low $st Eefect will provide'the desiied _ load carry-ing margins. The expansion serving as the new prelisure boundary is the l ot Am s.x-inches of a 17 ' inch expansion 4
extending through the cracked area to the top of the upper tube sheet. Thus all tubes for which the lowest defect is
, at-il" or above. h..ve been provided with' a new-six-inch
- jaTnt. Tubes with defects lower thin 11" will be considered ind ividually. Those with the lowest defect lie:veen 11" and 16" will be expanded using a 22". expansion. Those with 1-defects lower than 16" below the top of the upper tubesheet will be taken out of service.
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i The THI-l OTSC repair process is as follows.
t Step Description t
1
' Flush'the secondary side tube to upper tubesheet crevice.
j 2
Heat crevice to drive out moisture (vaporize water).
3 k
Kinetically expand tubes 5
Clean debris from kinetic expansion 6
Mill tube ends 7
Flush OTSG 8
Plug necessary tubes 9
Clea'n OTSG with felt plugs.,
i i
B.
Design Bases of Kinetic Joint The new joint comprises a kinetic expansion of either 17 or 22 I
inches which begins just below the upper tubesheet top surface in ti,e area of the original shop roll expansion. The kinetic expansion will be the preasure boundary and structural attach-i ment of the tube to the tubesheet.
The original OTSG design basis is summarized in Reference 1.
l The following is a summary of design basis for the new l
kinetically expanded joint.
j 1.
The repaired tube shall sustain the maximum design basis
.t axial tensile load of 3140 lb. from the generic 177 FA MSL3
. accident analysis. Since this is a thermally induced load,,
satisfying this criteria requires no relative movement (slip-the page) between the expanded area and the tubesheet at axial strain corresponding to this load (about.0016 in/in).
2.
The rmal/P re ssure Cycles The initial design life objective for the tube kinetic ex-I pansion is 5 years.
Suf ficient cyclic testing and/or analysis will be performed during the qualification program to satisfy this objective..
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A A design life of 35 years has been establianed as a goal.
The qualification program will include test specimens for cyclic testing for a 35 year life separate from those used to initially qualify the repair for a 5 year life. These specimens will be tested using the same key parameters but with greater numbers of cycles in order to satisfy the 35 year life goal.
(
3.
Tube Preload h
i i
,The des gn object ve stated in the original steam generator
{j equipment specification for TMI-1 OTSGs was that the tubes not be in cecere ssion when cold.
The repaired tube tensile preload shall not be changed by more than + 30 lbf at ambient temperature. This design objective is intended to assure that tube preload tension is maintained so that the vibrational characteristics of the tube will be unchanged for a preload change of this magnitude.
4.
Residual Stresses I
One design abjective is to minimize tensile stress in the transition region between the expanded and unexpanded s
portions of the tube. Analysis shows that an abrupt transi-tion results in higher residual stresses and larger stress conc entra tions. A transition length between 1/8" and 1/4" has been established as a goal.
An objective of maintaining additional residual tensile stresses (both circumferential and axial) resulting from kinetic expansion in the transition less than 45% of the.2%
of fset yield stress at room temperature has been established.
5.
Heat Transfer Requirements No credit is taken for heat transfer within the tubesheet.
6.
Pressure Boundarv Leakage l
l The original design basis for steam generator tube leakage was to provide gener.ators with no detectable leaks at ship-ment and to control leakage to an acceptable operating level l
by monitoring and repair over the 40 year life of the plant.
The kinetically expanded joints used for repair of the TMI-1
)
steam generators are designed to be essentially leak tight.
/
The expansion i~s designed to provide a seal below potential m
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t leak paths in all tubes to be repaired. Tubes wit 5 unacceptable leakage as indicated by the precritical drip i
and nitrogen bubble tests (see Appendix A) may be roll expanded above the lower 6" to attempt to seal the leakage,.
If this is unsuccessful the tube vill be plugged and/or stabilized if necessary.
For plant operation, primary-to-secondary steam generator leakage limits will continue to be set by the Technical Specification limit of 1 gym. However, in order to control the amount of waste. that requires proce'ssing, a design goal of 1 lb/hr projected total leakage from both generators has been set for the qualification program. Bubble testing can distinguish a leak that is of the' magnitude of 0.1 gallons per day. An engineering evaluation of bubble test results as they relate to expected leakage will be conducted in order to determine what tubes require plugging. Sta.tistical-analysis will be applied to the verification test results.
C.
Qualification Program A series of mechanical tests and chemical and corrosion tests were performed to qualify the kinetic expansion, and the kinetic expansion process to meet the design goals of producing a joint capable of carrying required loads, providing a leak tight seal, minimizing residual stress, and tube preload changes. A series of preliminarf tests was conducted to establish the optimum parameters for & kinetic expansion process that will yield acceptable joints with low residual stresses. Additional tests were conducted on a full size steam generator at B&W's Mt.
t Vernon Works. A more detailed description of the tests and results can be found in Reference 23.
1.
Mechanical Tests a.
Preliminary Leak and Axial Load Tests Kinetic expansi'ocs were tested te determine the maximum axial load which could cause the expansion to slip.
'Af ter a set of expansion parameters were postulated, leak rate and axia1 load tests were performed to deter-uine whether the expansion would still appear adequate
(
l for a corroded tubesheet, after thermal and pressure cycling, and after adjacent tubes have been expanded.
The following acceptance goals were applied.
(1) Water leak at a pressure differential of 1275 psig I
(Primary to Secondary) 3.3 x 10-5 lb/hr per tube.
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(2) Pullout load consistently above 3140 lb per tube.
- I (3) Margin in pullout loads and leak rate to account for possible deterioration of joint integrity from.
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i thermal cycling and for statistical analysis.
(4) Minimize expansion length.
(5) Minimize longitadinal strain induced in the tube by the expansion process,.
1 (6) Minimize in plane deformation of the expanded tube block hole and adjacent holes.
i The ef fects of thermal and p'ressure cycling on pullout load were minimal.
b.
Leak and Axial Load Qualification Tests
,i These tests predicted the leak tightness and confirmed I
the axisi load carrying capability of the chosen expan-sion technique, and showed what ef fect kinetic expansion will have on adjacent repaired tubes and determined the ef fect of re-expanding previously expanded tubes.
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5 Acceptance criteria required that a statistical evalua-tion of the results show a 99% confidence level that 99%
i of all. tubes expanded would have a pullout load greater than 3140 lbs.
A mean leakage rate goal of less than 3.2 x 10-5 lbs/hr/ tube was desired.
Results indicate that ther-;l cycling tends to decrease pullout load, however thetaally cycled blocks pulled at 70*F gave a 99* confidence level that 99% of the tube expanded will have pullout loads in excess of 4170 lb.
One block which was pull tested at 330*F gave 99/99 seatistical confidence that pullout load would be in excess of 3590 lbs. The goal of 99% confidence. chat 99%
of the tubes have pullout above 3140 lb is easily met.
In addition, an expansion pull test perfor=ed on a full scale genererer at Mt. Vernon showed a load carrying capability of at least 3600 pounds.
Leak rate results af ter ther=al cycling vary from 1.18 x 10-6 to 137,4 x to-6 lbm/hr/ cube. The average tube
{
l leakage was considered to be one-tenth of the total test bl'ock leakage in each case. Statistics indicate a 99% con-fidence that 99% of the normally expanded tubes will have t
leakage rates no greater then 132.4 x 10-6 lbm/hr/ tube.
I j
While this rate exceeds the design objective of 3.2 x 10-5 i
Ibm /hr/ cube, it is still a very low leak rate. Results of leak rates af ter axial loading are found in Reference 23.
l If every tube in both OTSGs leaked. at this maximum rate the cumulative leak zate would still be less than one-hundredth i
l of the Technical Specifications limit of 1.0 gpe.
The leak rate of the one block showed an increase between 10*F and l'
400*F (6% of the coral range of leak rates) leading to the conclusion that the leak rate for a tube at operating tem-peratuies would dif fer only slightly from what it would be at room temperature.
c.
Residual Stress Test ng (1) Preliminary Transition Geocetric Limitations This test determined the expansion parameters which would lead to a transition that would minimize the transition residual stress and stress concentration i
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E factor. It was concluded that a transition length between.125 and.2$ inch would be a g al, with a minimum acceptable transition length of.1 in:h. A nu=ber of insert shapes were evaluated to determine which provided a smooth transition.
(2) Re sidual Stre ss Measurecents s
The actual residual stress was measured in special test blocks using X-ray dif fraction and strain. gage techniques to determine post-kinetic expansion tube i
stresses in the transition area at the bottom of the expansion and at a second point near the middle of the expansion. Both hard rolled and kinetically expanded tubes were examined using higk sad low yield strength materials.
The goal for this test was that the additional resi-dual stress in the tube resulting f rom kinetic ex-pansion would not exceed 45% of yield strength.
i Results are reported in Reference 23.
(3) Comparison of Kinetic and Roller Expansion 4
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Sample Inconel 600 tubes were expanded by rolling l
and kinetic processes in order to cocpare the re-i sulcing hardness and microstructure.
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t-l (4) Corrosion Testing of Transitions t
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d.
Induced Strain Tests Tests were performed to determine the ef fects of the expansion on the tube-to-cubesheet welds, and the tube r
length', and to determine the strain stored in the ex-I l
pansion. A design goal of changing the preload by less than + 30 lbs due to elongation was applied.
e.
Ligament Distortion
. The ef fects of explosive expansion on the tubesheet ligament were determined. The dimensions of adjacent holes in the tubesheet were measured before and af ter the expansion and compared.
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1 Based on.che mechanical qualification tests it can be con-cluded that the kinetic expansion joint will meet the five year design life objective. The repaired tube will sustain l
the maximum design basis axial. load of. 3140 lbs., residual j
stresses will be minimiced, tube preload will not change more than + 30 lbf, and leakage will be much less than tech-nical specification limits.
2.
Chemical and Corrosion Testing a.
Residue Test The amount and type of explosive residue that should be expected to remain in the steam generator af ter all tube repairs are ecmpleted was determined. A satisf actory cleaning method to reduce contaminants to acceptable i
l primary system water chemistry levels was identified, i
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b.
Crack Change Tescs i
l The ef fect of kinetic expansion on existing cracks was de t e rmined.
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Effects on Residual Sulfur Testing was perfor=ed to assess what happens to the sulfur on the surf ace of steam generator tubes (i.e.
driven into the base metal) af ter kinetic expansion.
D.
Rapair Testing The in-process inspection and monitoring program was designed to verify that the in-generator expansion's are similar to those obtained in the qualification program.. Actual OTSG expansion l
profilometry and ECT results were compared to test progra= data to verify that the expansions are similar. Data obtained from TMI-l was also compared statistically to test program data.
The program consisted of video surveillance, profilometry measure-i ments, and eddy current (ECT) examinations.
' Video surveillance of operations during the expansion process were conducted where practical to verify that proper procedures were followed and that the correct tubes were expanded or examined. Random out-of-generator expansions were also con-3 ducted to verify that expansion inserts had not changed since the qualification program.
I I
Verification sampling was performed on the tubes expanded by the initial charge strength in the first three lots in each OTSG and consisted of ECT and profilometry. ECT using an 8xl probe was performed on almost 100% of the tubes expanded in the first lot l
in both OTSG's. ' Profilometry was performed on expanded tubes selected at random from the first three lots.
In addition to verification sa=pling, random diameter and depth checks sampling were done following initial expansion. The sampling plan can be found in Reference 19 Results are pr'esented below of both the expansion length in-spection program and the program to verify that each tube was expanded as required.
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1.
Results of the Expansion Iangth Inspection Program Out-of-generator expansions indicated that the process expansion inserts and detonating materials performed as those used in the qualification program. Profilometry and diameter and depth gauge checks showed that the in-generator expansions were'within the range of variation of the quali-fication program expansions. In addition, eddy current examination using the absolute (8x1) probe was conducted for the first lot of kinetically expanded tubes in both steam generators. The 8xl absolute probe has been chosen for this in-process monitoring in the newly expanded area because the coining process of the expansion creates so much background neise that the.%0" standard differential probe is not useful following kinetic expansion. The 8xl absolute probe provides 360* coverage. A judgement concerning defect are length can be made depending on how many coils of the 8xl probe detect an indication. Iaboratory testing has shown l
that a 1 coil indication can have an are length of 5' to
+
40*, a 2 coil indication has an are length up to 85*, and a 3 coil indication has an are length up to 130*.
Although the 8x1 absolute probe can be used to quantify the circum-l ferential extent of a particular indication, it cannot be i
used to accurately determine the percent thru-wall of the l
indication. The scope of the examination included 151 tubes in OTSG B and 284 tubes in OTSG A.
The eddy current data was aaalyzed from the top of the 6" qualification length for kinetic expansion down through the botcom of the upper tube-aheet. As a result of this data evaluation, 9 tubes in OTSG B and 6 tubes in OTSG A were reported as having indications which had not previously been detected by the.540" OD high-gain standard differential probe.
These new 8xl ECT indications were evaluated to determine l
their significance. The evaluation included 1) Fiberscope examination of selected tube areas where indications were detected, 2) Ccaparison of the size of any visual indica-tions to the ECT sensitivity curves, and 3) laboratory metallographic and ECT examination of known cracks which had been expanded. The following was concluded from this evaluation:
l 1.
The only visual evidence seen which correlates with the ECT indications is small pits and a mechanical scratch.
2.
Iaboratory expansion of known cracks confirms no growth (no ductile tearing) and indicates no change in 8x1 ECT l'
signal from known cracks.
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I 3.
If some of these ECT indications are from small cracks which were previously below the.540 ECT sensitivity within the upper tubesheet (DIS), their geometry is so small that the reliability of the new joint is not affected.
I i
4.
The most probabl. reason for these new indications is that the 8x1 probe is more senskrive than the.540 probe within the UTS.
The 8x1 probe gypears to be so sensi-tive enough to respond to pits which are so small they are of no consequence.
Section IX documents extensive work done to evaluate the anicum s ee crack -a.ea can ce..:: In servica ;cr :a
..;4 of the plant and not cause tube failure under normal or accident tube loadings. Acceptable circumferential extent vs. throughwall depth curves for various loading and analysis conditions in the free span are shown in Figure IX.2.
The pit indications found in the area of the joint are smaller than the crack size leading to failure by any i
mechanical means in the free span. These curves are con-servative for indications in the joint since loads imposed on the tubcs are transmitted to the tubesheet in the area of the expansion. Loads on tubing in the area of the defects will be equal to ar less than those analyzed for the free-s pan.
Leakage thrcugh any small defects which are 100%
throughwall is a;so expected to be less than or equal to similar cracks in the freespan. Unacceptable leakage will t
be identified during precritical testing and the tube will be either plugged or repaired. For these reasons, it is concluded that small pits or undetected cracks in the quali-
~,
fied area do not af fect the reliability of the new joint.
It is expected that additional indications will be identi-1 fied during the baseline 8x1 eddy current examination of the i
expanded region to be conducted following the kinetic expan-sion. These indications will be evaluated to confirm that they are acceptable, and will be left in service and re-examined during the 90 day ECT program.
2.
Identification and Expansion of Misfires (Proprietary)
. t l
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i i
i i
1 The concern for a tube is that, potentially, being unable to carry sufficient axial load, the tube would fail, slip downward and lock. Therefore, an evaluation'was performed to determine the likelihood of slippage during operation, and the potential consequences if the tube were plugged, stabilized or left in service.
E Leakage data for tubes is available from the preliminary qualification program for a defect free length of 8".
Fo r this length, leakage is expected to be sufficient to be identified during precritical testing. Similarly, leakage will be greater the shorter the defect free length.
In addition, the tight annulus between the tube and tubesheet wil' provide a substantial restriction to any leakage.
e
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-.w
- ~**..
~ -
- - -. ~ - - -
Assuming a minimum 6" leak length and a worst case 0.001" radial annulus, the leak rate past the expansien would be about 0 25 gpm or one quarter of the Technical Specification limit. This annulus size is considered to be conservative,because any actual i
leak path past the expansion is expected to be a discrete i
path such as a scratch. A leaking tube would be located by l
conventional means and would be plugged and, if necessary, i
i stabilized.
f Of the approximately 7000 tubes I
only about 100 were to be plugged.
I l
Slippage of a plugged tube could not be identified due to leakage. Thus if the tube slipped and locked, it could bow i
or be dynamically unstable in cross flow areas and cause l
wear damage to adjacent tubes. Approximately half of the j'
plugged tubes will be stabilized, which should prevent wear j
damage. The remainder are in areas of minimal cross flow, I
so dyna =ic instability should not be a problem.
i s
i a relatively small l point load against the neighboring tubes or tubesheet could force a node at the point of contact and prevent wearing.
1 t
4 E.
Post Repair Testing Following repair, testing will be performed to verify the acceptability of the joints. Post Repair tests include:
j j
t 1.
150 psig bubble test. Upper tubesheet plugs, tubing and expansions leak test.
2.
150 psig drip test.
Lower tubesheet plugs, tubing and expansions leak test.
3.
Hot O TSG Te s ting Hot OTSC testing will include transients that will place i
operating loads on the new joint. These transients will include:.
- ~*=m.eem,,~e
-w e
a
i s.
normal cooldown b.
accelerated cooldown c.
1400 psid operational leak test.
laakage will be monitored before and af ter the transients.
A more detailed explanation of the testing programs can be found in Appendix A.
In the event unacceptable leakage is identified for par-ticular tubes, they will be repaired, if possible, or removed from service. The backup repair method which has been selected is to place a hard mechanical roll expansion above the kinetic expansion joint 6" qualification length.
The roll expanston will oe centerec sc=e ciscance acove cae top of the 6" qualification length of the kinetic expan-i sion. This distance has been preliminary selected as 1".
Although the roll expansion will extrude some metal, it is considered intuitively obvious that it will not affect the ability of the qualification length to carry normal at.d accident loads. In fact, the roll may actually increase pullout load capability.
l The leak sealing ability of the roll expansion will not be g
tested. Roll expansion will be used only in tubes needing additional sealing as determined by visible N2 bubbles.
There will be subsequent leak testing prior to HFT, which will demonstrate the effectiveness of the expansion as a seal. Additionally, early expansion testing using hard roll expansions descastrated that such expansions sealed leaking i
tubes.
l If any expanded, then rolled, tube continues to leak exces-sively af ter given the chance to "self seal", plugging will be necessary.
l 1
F.
Conclusions Based on a qualification program, the kinetic joint meets or exceeds the design bases of the original joint, including the following factors: -_,
- e:>
. _ _. _ _ - _ ~
I a.
Load-carrying capability.
b.
Tube preload.
c.
Minimization of residual stresses.
14akage is projected to be less than one-one hundredth of the technical specification limit of 1 gpm. Kinetic expansion in the upper tubesheet is a safe and reliable method of repair for all tubes that will remain in service ir the TMI-l steam genera-tors. The tube joints will remain structurally sound and essen-tially leak-tight during all design conditions over at least r five year period.
l I
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l l l 1
l
VI.
E77ECTS OF EXPANSION REPAIR The possible effects of the kinetic expansion process with respect to introduction of chemical impurities, the effect on the OTSG structure, the effect on tubesheet corrosion characteristics and the effect on existing plugs have been evaluated.
A.
Possible Introduction of Chemical Lapurities The specification for OTSG tube repair addresses the issue of impurities in the system. It specifies that the inside of the steam generator will not be exposed to materials containing more than 250 ppm sulfur and 250 ppm total chlorides and fluorides,
- nd :p2:ifi l 12:2:::ble :::::ts cf 1: r maltin; 7ein: 22::1:
Required deviations will be addressed on a case basis. A material control program with quality controls was required for confirmation that material is not introduced inside the steam generator without assurance that its constituents are known and acceptable was Laplemented.
The large majority of the debris was demonstrated (testing in mockups and a full-scale OTSG) to be particulate matter. The large particulate debris was removed by manually picking up pieces by hand, and by vacuuming in both the lower and upper heads. Particulate debris in the tubes was removed by forcing felt plugs through each tube.
In addition to the easily removed particulate debris, laboratory tests showed a thin layer of material was deposited on the ex-l posed OTSG surfaces. This film consists primarily of carbon, identified as polypropylene. The amounts of contaminants, sul-fur and other elements, in this layer are low (traces only). In crder to minimize the potential for the film interfering with a i
sub sequent sulfur treatment, steps were taken to uinimize film thickness. The OTSG surfaces were coated prior to expansion i
with a substance which, when flushed with water, reduced the film thickness significantly.
This residual film is not uniform over the length of the tubes, being thickest nearest the expansion. The results of tests show 8
a remaining layer, af ter flushing, which averages 50 Angstroms thick over the length of the tube.
A similar condition should exist at the top of the tubesheet surfaces and the inner sur-faces in the dome of the upper head.
As a worst case, it may be assumed that the 50 A film on the l
31,000 tubes melts as the reactor coolant approaches operating i
temperature. The polypropylene is not soluble in hot water, but j
. l t
i
the high velocity coolant through the tubes could entrain par-ticles as th?y sof ten and lose film tension on the tube sur-face. The turbulant reactor coolant flow would carry these minute droplets of molten plastic throughout the reactor coolant system as a very dilute emulsion of about 0.44 pps polypro-pylene. The domineralizers and filters in the letdown system would gradually remove this slight impurity from the reactor j
coolant.
Industry experience shows that there may be a tendency for the molten droplets to collect in relatively stagnant areas of the reactor coolant system. The reactor head would be the most likely area of concentration, and during cooldown the poly-propylene may solidify as a film on the under side of the dome.
In the unlikely event that the total volume of plastic were to asparata ouc in the hea: a r aa, c.ia J..; :.es; a ree; ara - ci.-
1ect a negligible amount of residue.
Should there be a reactor cooldown, any molten droplets re-maining in the coolant would tend to solidify as a film on the coolest surface available. Both the letdown and decay heat systems will be cooling oortions of the reactor coolant and the polypropylene would redeposit as a thin film on the letdown and decay heat cooler tubes. The hot surfaces in the core are the least likely places for the plastic to solidify. There is no i reasonable assumption which would indicate the half cup volume of plastic film could cause a problem before it is removed from the system.
i B.
Possible Effects on OTSC Structure 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.
For individual expansion, evaluation of the tubesheet ligaments has shown no significant effects cf expansion.
It was postu-lated that with multiple kinetic expansions there could be a shock wave reinforcement such that the sequence of explosions or the length of the prima cord should be controlled to insure that the tubesheet is not overstressed. The concern was that the shock wave may travel at about the speed of sound through the material, and if adjacent tubes exploded in a manner such that their shock wave reinforces shock waves from other tubes, there could be a condition where the tubesheet is overstressed.
Testing was performed in the steam generator at Mt. Vernon using strain gages and an accelerometer to demonstrate that the coin-cident explosions of the maximum number of tubes to be expanded
~-
l l
at any one time was acceptable. This was done by exploding 132 charges in the longest r.ow 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 gauges following expansion it is con-ciuded that no plastic deformation occurred. The maxi =um stress intensity recorded for the weld between the tubesheet and shell was less than 10,000 psi. The strain getge 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. The other strain guage locations clearly show that the stress diminishes as the distance from the expansion increases. The results was a maximum f atigue ust ge 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.
l i
In addition, Foster Wheeler has kinetically expanded over 2000 1
feedwater heaters and expanded as many as 5000 tubes 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 expand only 132 tubes simul-taneously plus any misfires from the previous row up to a total l.
of 137 total tubes for the TMI-1 Steam Generator repair.
I The combination of Foster-Wheeler experience and the strain gage t
data show the explosive expansion process to have no adverse effect on the steam generator.
C.
Corrosion Several concerns have been addressed relative to the sus-ceptibility of the repair to corrosion. In tubes with through wall cracks, a leak path for primary system water may still exist even after kinetic expansion ever the full 17 inches. The breech exposes the carbon steel tubesheet wall to the corrosive ef fects of a buffered solution of boric acid, i.e., clean reactor coolant.
As described esrlier in this report, ID tube cracking due to the corrosive ef fect of sulfur and/or sulfur containing ions has been identified as a probable contributing cause of the TMI-1 m.
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---_._.._.7___.._.
i steam' generator problems. De first concern is therefore resi-dual sulfur deposits in crevices above and below the repair =eal area, particularly in pockets that may have resulted from ce r-resion of the tubesheet wall. Such deposit could cause an j
attack on the Inconel tubing. Sulfur attack would be prefer-ential to the Inconel rather than the carbon steel tubesheet. It i
l is presumed that the source of sulfur contamination no longer exists and the RCS is essentially sulfur free. As in the ori-ginal design, a crevice will exist below the seal between the OD of the Inconel tube and the carbon steel tubesheet vall. ne crevice has been flushed to reduce soluble deposits, par-cicularly in' the crevice area below the repair seal.
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D.
Ef fects of Expansions on Existing plugs The EMI-1 OTSG tubes have been taken out of service by f our dif ferent procedures:
1.
Explosively. welded plugs - Plugs inserted into the tube and explosively. welded in position within the tubesheet.
". i.eloec plugs - E.ugs sciaew :o :... :...
s...
e r :
a..u. :.;
the top of the upper tubeshcat.
3.
Hydraulically expanded tubes sealed with a welded plug -
tubes that have been immobilized by expansion af ter a short section of the tube within '.ne tubesheet was removed. The tubes were then taken out-of service by installing welded plugs in the tubesheet openings.
4.
Hechanically rolled plugs.
B&W has evaluated the ef fect 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 expansioras will not af fect their mechanical integrity or leak tightness.
Tests of the kinetic expansion process in steam generator model test blocks with conditions simulating those in the TMI-l steam generators show that the kinetic expansion does not produce any permanent tubesheet ligament deformation. This leads to the conclusion that plugged tubes adjacent to kinetic expansions will act be altered by changes in the tubesheet ligament, since no permanent change is noted.
During additional tests on an actual OTSG, B&W examined, by dye penetrant tests, the tube-to-tubesheet welds and tubesheet ligaments of the kinetically expanded tubes and the tube-to-tubesheet welds adjacent to expanded tubes and have not seen any degradation.
Thirdly, the extensive laboratory and field experience of B&W with explosive plugging tubes in operating steam generators indicates that damage to plugged tubes due to detonation of explosive s in adjacent tube s does not occur.
. - ~ -........
_m
Tests were performed on qualification blocks with rolled plugs in place and explosive expansions of all adjacent tube loca-tion s.
Leak rate and axial load tests were done to verify that the rolled plugs continued to meet the acceptance criteria to which they were originally qualified for use.
Lastly, a pre-operational post-kinetic expansion pressure test of each generator will be made to verify the integrity of the primary to secondary pressure boundary thus providing added assurance that the plugged tubes have not degraded.
E.
Conclusion s 5asec on ca
.cuv. ava.uac en ne :.; _,, :.;...2:i: 2: - nri:n process will have no adverse ef fect on the OTSG structure, tube-sheet corrosion, or plugs previously installed. In addition, a cleaning process has been developed which will remove the resi-due. from the expansica process. In conclusion, overall there are no adverse effects from the kinetic expansion process. 1
~
VII.
PLUGGING REPAIR DESOLIFTION
SUMMARY
A.
Introduction Those tubes which have defects below the 16" from the primary surface of the upper tubesheet (US) and cannot be recovered and returned to service by the above described Kinetic Expansion repair shall be removed from service by plugging. A defect is defined as any addy current indication interpreted as greater than or equal to 40% through wall. For conservatism, any less than 40% I.D. indication with a large enough circumferential extent to be detected on three or more of the eight ceils of the absolute probe will be created as a defect for plugging pur-peses. The limits of eddv current detectabiliev are defined in Section IX.
There are a total of 259 tubes in A anc eo tuoes in B OTSG that have been plugged with either Westinghouse rolled plugs or B&W welded and explosive plugs. It is projected that i
an additional 627 tubes in A and 185 tubes in B OISG will be removed from service by plugging af ter kinetic expansion. 19 tubes in A and 10 tubes in B ocean generator which have been cut i
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 some locations will be stabilized as indicated in Table VII-1.
475 tubes will be stabilized. The purpose of tube stabilization is to minimize the risk due to propagation of tube defects located in regions with high potential for flow induced vibration resulting in circumferential tube severence and causing damage to adjacent tubes or creating loose parts. The lower tube end will be plugged with an explosive plug. The following sections give an l
evaluation of the methods selected for tube plugging and stabilization, and a description of the types of plugs to be l
used.
l B.
Types of Plugs 1.
B&W Welded Tapered Plug, Welded Cap, Stabilizer and B&W Explosive Plug B&W Welded Tapered Plug is used to plug the bare upper tube-sheet hole for tubes where the tube end has been removed.
B&W's welded cap is used to seal the upper tube end for those tubes which will be plugged and stabilized. Prior to installing the weld cap, the existing tube end will be machined off leaving a portion of the tube end and the existing weld protruding above the tubesheet surface. The weld of the nail cap will fuse with the existing seal weld, providing the desired pressure boundary.
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%/I1-1 OUTLINE Or BASIC TUSE PLUGGIkC/STAalLIIING PLAj Any Detectable P uggable Defect Pluggable* Indication f
j Indication
) 401 T'd 4 40 Percent TTv and S x I s2 Coils,Io m
=
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u 15th SP 15th sP to Ls.4 15th $P to Ls - 4 15th SP to LS-4 US + 4' to rur Tube Spar 15th sP to Es-4 t
in Lane / Wedge Sul i 2 colls
- O and
- ot Isolated la Lane / Wedge Sal s 2 Calls Historical Defect Area (Noto 4)
LS -4 to =24 y 90ttos 6*
Mi s,,t or ic a l US + 4 a
INotes 2 and 41
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j INote Il g
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g PlugE stabilise Flug and stabilise Flug and stabillas to Plug Only rlug Caly 7465 and stabilise to sottom of at least in Span Bottom of leth SP to sottom of 14 $P 14th $P of Defect INote 31 INote 31 1.
Includes tube sections f rom bottom of 15th support piste to 4-inches up into bot.om of upper tubesheet.
2.
Include: tube section from bottom of 15th support plate to 4 inches dous f ron 1 4 top of the lower tubes)eet.
3.
See Figure Vll 1 for tubes in Lane / Wedge area.
4.
tal is ECT probe with 8 absolute colle e
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B&W Esplosive Plug is used to plug LTS tube ends where B&W plugs are used in UTS. Both B&W plug types MK-1 and MK-3 have been qualified for OTSG tube plugging and used in the operating B&W units.
B&W standard design stabilizer rods will be threaded onto the welded cap to form a stabilizer assembly of the desired length. The stabilizer is a multi-piece assembly of solid rod made of Inconel SB-166.
Joint tightness is maintained by crimping the pieces together beyond the threaded sec-tions. The seguent length is dependent upon the tube bundle location.
';' :c ial t:;1r si ;'. :;:. :.iai :. 1: p'. :: L s '.:~- 1-1 stablizer rods have been previously qualified see References 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.
The Westinghouse rolled plug is machined from bar stock that has received a thermal heat treatment which has been demon-strated' by laboratory testing to have improved resistance to intergranular attack in caustic and polytheonic acid envi-ronments, compared to treatments at different temperatures and times.
The Westinghouse Roll Plag Qualification Program for TMI-l has been completed for a 5 year life, and results are docu-mented in Westinghouse Report WCAP-10064.
C.
Plugging and Stabilization Criteria Final tube plugging and stabilization criteria were selected to minimize the possibility of cracks propagating to a size which could part under stress conditions, either plugged or unplugged tubes. Analyses presented in Section IX show that the vibra-tional effects of cross flow are not expected to contribute to crack growth in an unplugged tube.
However, as a precautionary i
measure, plugged tubes with difects in the area of highest cross l
flow between the 15th support plate and US+4, are stabilized.
l In addition, stabilizers have been used where eddy current in-dicates a crack of significant size in historical defect areas, and below the 15th support plate where I.D. 8xl indications are greater than 2 coils. Measures to monitor for crack propagation i
due to flow-induced vibration or other means, including leakage i
l __
I
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, [__;
monitoring (Section X) and eddy current inspection for wear (Appendix A) are discussed separately. -
The steam generator has beda divided inte six areas for purposes of dispositioning tubas for plugging and stabilization. ho areas are within the upper tube sheet: between US+8 and US+4, and between US+4 and US+0, where US+0 is the lower face of the upper tubesheet.. hbes where the lowest defect is above US+8 are repaired by kinetic expansion. hbing between the tube-sheets has been divided into three areas: tubes between the 15th support plate and US+4, tubes between the 15th support place and LS-4 in the lane / wedge area,'and tubes between the 1
15th support plate and LS-4 outside the lane / wedge area. The
'..;;, : ragi:n :annnrai e.:: tha: ;i hin :ha '.: ::: :i:2:hnt.
Plugging and stabilization criteria are discussed in detail in Reference 25, ar.d sununarized below:
i 1.
h be s wi' n De f ec t s Be tween US +4 and US +8" i
I hbes with a defect between US+5 and US+8 may not be effec-tively repaired by the 22" Kinetic Expansion. A qualified I
length of 6" expansion is ree,uired to insure a leak-tight, load-arrying joint to assure the OTSG integrity is retained under the most adverse conditions during operation. There-l fore, those tubes with defects between US+4" and +8" will be both kinetically expanded to 22" and plugged. Even if the l
existing crack would propagate in the future and sever at j
US+5", testing (Ref. 23) indicates that the expansion joint below the severance would provide enough cagagement to main-tain the preload in the tube and carry the loads associated with the most severe transient during normal operation.
Thus tubes with defects in this area are not expected to wear adjacent tubes due to dpamic instability in high crossflow'. herefore, it was concluded that thest tubes need noc be stabilized (unless stabilization is required by j
defects of grenter than 3 coils' between US+4" and US+5").
l 2.
Tubes with I'efects Between US+4 'and US+0 1
I Even with a 22" expansion, these tubes would not have the 3" kinetic expansion joint below the defect to maintain preload i
and. assure that the tube will not slip under the most severe tracsient during norn.al operation (i.e.,100'F/hr. cool-
,down).
If the tube ratcheted down to the point where it was i
. in compression during operation, tne potential exists for
[
the tube becosing dynamically unstable or buckle. There-fore, af ter receiving a 22" expansion, a tube with a defect in this area vill be plugged and stabilized through the 14th l
tube support plate.
.., 1 i
- - r
3.
Tubes with Defects Between 15th Support Place to US+0 For conservatism, any eddy current indication in this area, regardless of type, through-wall measurement or circumferen-tial extent, was created as a defect. Tubes with defects in this area received a 17" expansion and were stabilized to the 14th tube support plate, unless a lower defect was located in an area requiring a longer stabilizer.
This criterion covers the high cross flow tube span in the top of the steam generator. Even if a tube were postulated to become severed at this elevation, it could not get free and damage adjacent tubes.
4 Tubes with Defects from 15th Support Plate to LS-4 la Lane Wedge Area B&W plants have a history of corrosion and vibration prob-lems in the areas of the untubed inspection lane. As a precautionary measure, an area of potential problems has been defined one row on either side of the lane, videning to a wedge shape as the lane nears the periphery. For tubes in l
this area, any I.D. eddy current indication, regardless of type, through-wall measurement, or circumferential extent, will be treated as a defect. These tubes will receive a 17" expansion, then be plugged and stabilized through the 14th support plate unless other criteria require stabilization through the defect in the lower spans.
5.
Tubes with Defects Between the 15th Support Plate and LS-4 l
In the tube span between the 15th support place and LS-4 outside the lane / wedge area defects were divided into two
- 1) ECT indications greater than or equal to 40%
groups:
through wall with 8xl indication greater than 2 coils, and
- 2) ECT indications greater than or equal to 40 through wall with 8x1 indication less than or equal to 2 coils.
l After a 17" expansion, tubes with defects greater than or equal to 40% through wall and 8xl greater than 2 coils were stabilized through the span with the lowest defect for that tube. Tubes with greater than 40% through wall defects and 8xl indications on 2 coils or fewer were expanded to 17" or 22" as appropriate and plugged with the Westinghouse rolled plug.
l I
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_ _ _. _... _ [4'_..w N
1.
_L __. _
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+-
s 3
' vi.
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3 This criterion pravides a sedes for determining the tube are
-length extent of a de!edt~ in order to decide if the tube should be stabilized. 'The tube would be stabilized at least within the tube span conEaining the ECT in' icatics if there j d
- is any substantial siz;t or arc' length involved is the ECT IfanECTindicationisseenon14esthanthreel' indication.
~ coils on the 8x1 E,CT probe it'aeans that'the arciength of the degraded area of the tube of a maximum of about 0.41 inch long at the inside diameter'of the tube.
Because of
, the " thumbnail" shape of the inside diameter cracks found at TMI-l this means that the average are length of the largest i
two-coil ECT crack would be about 0.26 inch. This size l
' rack is accent'able without stibilizint 1nd is ot e ected c
to propagate to rallure oy mecnant:a1 means curing opera-
. tion (Ref. 25).
Ais criteria for stabilizing, based on are length as
~
measured by the 8xl probe is not invoked for ECT indications less than 40 percent through wall because such an indication is too small to fail the tube.
Even if a tube had a 360*
indication, the tube would not fail with less than 40 percent penetration (Ref. 25).
6.
Tube's with' Defects in the Lower Tubesheet Below LS-4 Tubes with pluggable defects in the lower 20" of the LTS were removed from service using a Westinghouse rolled plug or.an explosive plug. A welded plug was used in lieu of l
mechanical rolled plugs if the defect was in the rolled area.'
D.
Pos,t Repair Testing s
s The following po'st repair tests will be performed to verify plug,
integrity.
i s
1.
150'psig bubble test 2.
150 psig drip test 3.
1400 psid operational leak test Details on post repair testing can be found in Appendix A.
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E.
Conclusions 1
The OTSC Tube Flugr,ing Plan will restore the pressure boundary integrity of the steam generators by removing defective tubes l
from service for those tubes which have defecte below the region available for expansion repair.
I The plugs used have been previously qualified for use.
Tubes j
have been stabilized which have large defects in areas of high crossflow or areas of historic problems with vibration or cor-rosion at B&W plants. Thus plugged tubes with the highest potential for tube serverence in the future are prevented from wearing adjacent tubes.
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VIII. COMP ARISON OF TUBE PLUGCING WITH DESIGN BASIS A.
Introduction This section describes the results of analyses performed to determine if the steam generators could be safely operated with up to 1500 cubes plugged. The first part of this section re-views the operational consideration of operating with tubes removed from service for: reduction in total flow and margin to departure from nucleate boiling effects of asymetric flow dis-tribution, ef fects on flow coastdown rate, ef fects on steam generator mass inventory and capability of natural circulation.
The second part reviews the ef fects of removing tubes from ser-vice on small anc iarge creat loss sz coc.anc accicen:a as wel.
as all other accidents and transients analyzed in the FSAR. The third part considers the effects of plugging on moisture carry-These analyses have concluded that the margins of safety over.
as defined in the Technical Specification will not be reduced by operating the Dr.I-l steam generators with up to 1500 cubes re-moved from service.
i B.
Operational Performance 1.
RC Flow Rate and Margin to Minimum DNER The calculated RC flow rate for all four RC pumps operating as a function of an equal number of tubes plugged in each steam generator is shown in Figure Vill-1.
Generally, a reduction in tubes available for RC flow will cause the tube bundle pressure drop to increase. Since the remaining sys-tem pressure losses are about four times greater than the tube bundle pre ssure losses, only a slight reduction in total RC flow rate will result. The total RC core flow for 1500 plugged tubes will be the same as the symmetric case, i.e. 750 in each steam generator. From the figure, the reduction in total RC flow will be from 109% of design to 108. 2%, a cha ng e of 0. 8%. (Reference 42) l l
In order to determine the impact on the existing steady f
state Departure from Nucleate Boiling Ratio (DNBR) resulting from the RCS flow reduction at steady state, a study was I
performed to determine the minimum RCS flow rate required to maintain the existing DNB ratio for the IHI-l licensed power l
level of 2535 MWt.
The existing DNB steady state ratio of l
2.0123 was determined at a conservative power level of 2568 MWt and an RCS flow rate of 106.5% of design flow.
l l
i I
. 3r
The methodology for the analysis was to calculate the hot bundle flow by using a CHATA (Reference 36) core model which took heat balance inpur from the CIPP code (Reference 37).
By using the hot bundle flow in the computer code TEMP (Reference 38), the Minimum DNBR (MDNBR) was calculated for the hot sub channel from the BAW-2 correlation (a cor-relation.
The results indicate that DNBR value of 2.0123 can be main-tained with an RCS flow rate of 104% of design and a power of 2535 MWt as compared with the original 106.5% flow and 2568 MWT. The minimum calculated RCS flow rate at TMI-l has been 109.5% of design flow. The maximum error on this value
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of design. This will be reduced to 107.2% af ter the tu' eso are plugged. This is substantially greater than the design basis flow rate of 106.5% which would be required to main-tain the design basis steady state DNBR value of 2.0123 at 2568 MWt.
For the TMI-1 power level of 2535 MWT, the 104%
design flow requirement to maintain the same DNBR provides for an even greater margin.
It can thus be very conser-vatively concluded that the plant design basis flow rate considerations will be preserved with 1500 cubes plugged.
2.
Asymmetric RC Loop Flow Distribution The final plugging pattern will be about 6% of the tubes in the A Steam Generator and about 2% of the tubes in the B Steam Generator. In order to investigate the asymmetric effect of the RC loop flowrates, an evaluation of an exag-gerated plugging pattern of 1500 tubes in one of the TMI-l steam generators has been performed. The Loop A flowrate will be approximately 2-1/2% smaller than Loop B.
Field data at TMI-1 during the last cycle has shown that the A loop has typically about 3% more flow than the B loop.
The result of more plugging in the A Steam Generator will thus be a somewhat more balanced loop flow distribution.
t l
The new flow difference is expected to be approximately 0.5%.
3.
RC Flow Coastdown Rate With a significant number of tubes being plugged, the resis-tance factor for the RC flow passing through the OTSG will be increased. This increased resistance may change the flow distribution if one RC pump is tripped while the other pump in the coolant loop is maintained in operation. The com-bined core flow during the coastdown may also be different.
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i
Further, the minimum margin to DNBR during a loss of flow eve nt is known to be dependent on pump coastdown races. To address these issues the following analysis was done.
A computer analysis has been conducted using the B&W code
PUMP" (Reference 39) for the TMI-l type reactor coolant system's flow coastdown curves with zero and 1500 cubes 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 rats is still bounding.
Figure Vill-2 summarizes the data obcained from the four pump coastdown transient performed with the THI-l version of PUNP code and compares this data with the TSAR analyzed flow coastdown. This comparison shows that the flow even with 1500 plugged tubes starts at a higher level than the flow assumed in the FSAR analysis and coasts down at approxi-mately the same rate since the flow is at all times greater than that assumed in the FSAR the minimum margin to DNB will not be changed.
4 Steam Generator Water Inventory and Operating Level Indication The water inventory in the steam generator, will increase by a small amount due to the decrease in average quality in the plugged section. REIRAN-02 (Reference 43) and TRANSG (Reference 44), which are both one dimensional transient thermal hydraulic computer programs with slip option, have been used. The inventory increase was calculated to be 5%
or less, which is less than 2000 pounds with 1500 tubes plugged.
l Total secondary side flow will increase only slightly with decreased steam outlet temperature. This would tend to cause a slight increase in pre ssure drop. This increase will be of fset by the reduction in average quality (increase in density). The net effect should be little or no increase in the startup level.
5.
Capability of Natural Circulation The impact of steam generator tube plugging on the capability of stable transition to natural circulation was examined by using the B&W computer program AUX (Reference 49). Symmetric plugging of 1500 tubes in each side was l
9 l I
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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 flow with 1500 tubes plugged 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 cubes plugged in 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 remova l.
l C.
Accident and Transient Derfornanc e 1.
LOCA Analyses The potential effects of SG tube plugging on generic Large Break LOCA (LBLOCA) and Small Break LOCA (SBLOCA) analyses (Raference 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 (2772 MWt) 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 MWt at the existing LOCA limits. An overview of this examination is provided below.
a.
SBLOCA* Conc erns The evaluation models used in the existing SBLOCA analyses (Reference 40) assume equilibrium conditions within the control volumes used to model the SG secon-dary side. For this reason, the localized cooling ef-facts of EFW spray on particular 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:
1.
The percentage reduction in the number of peripheral tubes removed from service will degrade the EFW spray cooling heat removal capability in a 1:1 relationship.
2.
The degradation in heat removal capability from EFW spray cooling translates directly to a reduction in depressuriaation rate by a 1:1 relationship..m
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In reality, these relationships are expected to be con-servative. Since if EFW spray impacts a deactivated tube, it will not be heated and/or flashed immediately but will either:
1.
Be redirected onto adjacent active tubes, or; 2.
Flow inward into the tube bundle, providing cooling to active interior tubes, or; 3.
Fall into the saturated steam or saturated water region, resulting in increased cooling within these regions and/or an increase in the fill rate to the appropriate level setpoint.
A more detailed discussion of EFW spray effectiveness and the THI-l response to SBLOCA with plugged tubes is l
given in Ref. 59.
Therefore the water is available in the steam generator and will result in greater EFW spray cooling and higher depressurization rate than predicted by the analyses.
In this evaluation (Reference 42), two break cases were considered. The first is the worst case with respect to peak clad temperature for a small break LOCA, identified as approximately a 0.07 ft2 cold leg break. The second, belongs to the category of breaks in which SG heat removal is needed to help depressurize the RCS.
The 0.01 ft2 break was analyzed because this was the largest break size which would result in RCS repres-surization.
Plugging 1500 SG tubes was used as a upper bound which represents a deactivation of approximately 5% of THI-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.
t Worst Case 0.07 ft Cold Leg Break with One HPI Train For this break size, the primary system pressure decreases below 1000 psi (approximately the secondary side pressure) at about 300 seconds.
Af ter 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 SC (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. -. -.. ~. - -
. - c;.
The plugging of 1300 SG tubes will result in a reduction of the initial RCS liquid inventory by about 200 f t3 This re sults in the core being uncovered about 3 seconds earlier and in approximately a 10F increase in peak cladding temperature (to about 1100*F). This will have minimal impact on the outcome of this accident. It should also be noted that the generic analyses show that, for a 0.07 f t2 break with 2 HPI trains, the core does not uncover and temperature remains below 700*F.
2 0.01 ft Cold Leg Break 7.a 0.01 ft2 ::15 12- ' r:12 :::t ::: +":.2:ted urin:
the revised SBLOCA model. All of the original analysis assumptions were preserved, including a 20 minute operator delay in initiating emergency feedwater. Two cases were analyzed considering the ef fects of tube plugging on the decrease in RCS depressurization rate which could increase the time to initiate ESFAS and the rate of heat transfer in the boiler condenser mode. It was found that:
With a 1600 psig low RCS pressure ESFAS setpoint, the 0.01 f g2 case will result in ESFAS actuation regard-less of the reduced peripheral and internal SG heat removal caused by the plugging of 1500 SG tubes. Before ESFAS actuation, the RCS was subcooled and either forced or natural circulation existed. Consequently, SG heat removal was found to take place throughout the entire SG tube region, not predominantly in the peripheral region s.
Therefore, the SG heat removal rate is not reduced by more than 5% during the period prior to ESFAS, and this will delay only slightly the activation of ESFAS.
The 0.01 f t2 break case will cause the RCS to enter the boiler-condenser (B-C) mode.
In this mode, EFW spray coolir:g of the peripheral tubes is an important factor in the RCS depressurization. Thus, peripheral SG tube plugging could have a more significant ef fect on this cooling mode. The evaluatioh showed that, with 18%
of all peripheral tubes plugged, suf ficient steam generator EFW spray heat removal capability remains so that the rate of RCS depressurization is reduced by only about 12%. Even with this reduction, calculations with all other original analysis assumptions unchanged show a minimum of five feet of coolant remains above the core throughout the event. Since the 0.01 ft2 break is.
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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 summary, these small break size LOCA analysis show that for the previously limiting case of 0.07 f g2 cold leg break with only one HPI train available, peak clad temperature increased by only 10*F to about 1100*F. For the 0.01 ft2 cold leg break, the slight delay in ESFAS actuation and the reduced area for EFW cooling have an a
insignificant ef fect on the outcome of the transient
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the core for both the plugged tube and unpluggec tube cases. Therefore the generic LOCA analyses remain valid for IMI-l even with a small reduction in SG heat removal caused by tube plugging.
b.
LBLOCA The important parameters for the LBLOCA which are effected by plugging of tubes are the initial flow and flow coastdown. The ef fects of the reduction in coolant volume associated with 1500 plugged tubes (200 ft3) are negligible for this event. The plugging of 1500 SG tubes at TM1-1 will reduce total system flow. However, 4
the reduced flow will still be greater than the flowrate used in the generic LBLOCA analyses. This, coupled with TMI-l's lower core power (2535 )Nt vs the generic 2772 MWt) provides margin in initial conditions for TMI-1, relative to the generic analysis. During the early portion of a LBLOCA transient when the reactor coolant pumps are coasting down, the analyzed system flow rate (see VIII.B.l.3) with additional resistance due to plugging will be greater than assumed designed flow rate l
with the case of no plugging.
l i
The reduction of 200 f t3 of primary coolant volume will have little impact to the consequence of LBLOCA.
Since the OTSC'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.
Hcwever, a break in the B side will result in slightly less total fluid passing through the core during the blowdown period. For about 11,000 ft3 total fluid loss within approximately 24 seconds, the reduction of 200 f t3 will correspond to 0.4 second -
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l^
shorter blowdown time and thus a slightly earlier fuel he. tup between blowdown and refill. This difference is minimal and therefore, the resulting peak cladding tem-perature that occurs during this developed reflood stage should not be changed. Also, vent flow is conserva-tively neglected during the refill /reflooding phases of LBLOCA analyses for the 177FA Lowered Loop plants. Tube
<*O plugging will therefore have no impact on core flooding races.
2.
FSAR Analyses of Other Transients An assessment of the impact of the plugged steam generator tuoes on the actitty oc tae J555 to 4.ia Ay respona 40 45Aa transient conditions has been performed. The plant is ex-pected to be operated with up to a total of 1500 SG cubes plugged for both steam generators at the licensed rated power level. Each event in the TMI-l FSAR will be addressed in light of the expected impact of steam generator tube plugging on assumptions used to produce the current FSAR analysis.
a.
Uncompensated Operating Reactivity Changes This event is core burnup related and is normally com-pensated for by Integrated Control System action over the life of the fuel cycle. Steam generator plugging will not affect the core kinetics and thus have no impact on the event.
b.
Startup Accident /CRA Withdrawal at Power The CRA Withdrawal from Startup conditions and at power l
results in primary system overpressurization. The FSAR prediction of RC pressure and peak thermal power is I
based on the conservative assumption that all heat pro-duced in the core remains in the primary system, i.e.,
l no steam generator heat transfer.
The tube plugging l
will result in a 200 ft3 volume reduction of the primary coolant ( 2%). At peak thermal power the reactor coolant pressure increase was 118 psi in the i
FSAR. With the small volume reduction and consequently slightly higher heatup rate the peak pressure may in-crease slightly but will remain well below the 2750 psig limit. Therefore, the FSAR analyses remain bounding with respect to the acceptance criteria on thermal power and system pressure.
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c.
Moderator Dilution Accident The moderator dilution event is a relatively slow over-pressurization transient due to increased rsactivity by boron dilution. Change in steam generator plugging will not affect the basic assumprinna of this analysis and therefore the FSA3 remains bounding.
d.
Cold Water Accider.t (Pump Startup)
The pump startup e-sent is a small overcooling transient due to an increase in flow from an idle loop.'
The analysis performed for Section 8.B.3 demonstrated that ene pump cnaracceristic curves cif f erences are negil-gible for the unplugged and the 1500 plugged tube cases. The reactivigy change will cause a power and RCS pressure increase. ine transient will be terminated by either the high reactor pressure trip or the power / flow trip. The FSAR remains bounding.
e.
Loss of Coolant Flow See Section VIII C.1.
f.
Stuck / Dropped Rod Evert 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 emergency feedwater system are required. The impact of tube plugging on the ability of natural circulation is demon-strated in Section B.S.
h.
Steam Line Failure The licensing basis for TMI-l is the double-ended rs This FSAR analysis is based on a very conserv'a-l ture.
tive prediction of SG 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, 70 -
o
and reactor building pressure. The calculated water increase with 1500 plugged tubes is less than 5%, which will result in a maximum steam generator inventory of 42,000 lb. per steam generator in contrast to the FSAR analysis assumption using a steam generator inventory of 55,000 lb per steam generator.
It is therefore con-
, cluded that the FSAR case remains bounding.
- i. Steam Generator Tube Failure The steam generator tube rupture accident is analyzed assuming a 435 gpm leak from a completely severed OTSG tube. The RCS is deere ssurized nr.d isolated at 34 minute s, at vnich time leakage from the AJd is assumec 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.
Of fsite dose from the Tube Rupture Event will not be af fected by plugging 1500 cubes because neither the time required to isolate the OTSG nor the leak rate from the broken tube is af fected by the tube plugging.
s
- j. Fuel Handling Accident This accident is assumed to occur during outage a l
refueling outage while the reactor is shut down. Change l
in steam genera *or plugging pattern has no impact to the assumptions.
1 I
I k.
Rod Ejection Accident l
I Fast reactivity excursions are not influenced by SG heat removal. The event is an adiabatic heatup. The FSAR analysis remains bounding.
1.
Maximum Hypothetical Accident The analysis assumed that a given amount of radio-l activity has been released following core exposure and l
studied the ef fectiveness of the building spray system and Engineering Safeguard systems leakage on to the enviro nment.
The steam generators are not related to the scenario and thus have no impact on the conclusion.
l 1
m.
Waste Cas Tank Ruoture 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 un-affected.
n.
Loss of Main Feedwater/Feedwater Line Break A loss of feedwater accident is an event resulting in primary system heatup, increased pressurizer level and pressure, and reactor trip either by anticipatory func-tion (loss of main feedwater pumps) or high RCS pres-r :rs.
!?e 1e ; te-erati-- -e'J ee -- e m >-c a - -
f= water heat removal through the steam generators. With the plugging of 1500 tubes in the steam generators, the intitial heatup rate will be slightly faster. However, the anticipatory trip on high pressure will shut the reactor down and reduce the heat input to its decay heat level regardless of the minor difference in heatup rate. Emergency feedwater has the flow capability of removing decay heat up to about 7 percent power. This is greater than the decay heat at any time after shut-down.
In the SBLOCA analysis using the revised LOCA model it was demonstrated that heat transfer rate is not significantly changed with the amount of plugged tubes.
Therefore the FSAR analysis of the loss of feedwater accident remains valid.
o.
Steam Generator Overfill Steam generator overfill was analyzed as a part of the TMI-l Restart Report, (Reference 50). This analysis identified that it takes st least 10 to 17 minutes for auxiliary feedwater to overfill to the top of the steam generator's shroud. Operators are instructed to isolate the feedvater flow path as soon as the OTSC water level reaches 82.5% on the operating range (high level alarm) and to trip or throttle feedwater pumps if the level reaches 90%.
The impact of up to 1500 plugged tubes in one steam generater 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 m
time and unambiguous symptoms available for the opera-tors, their prompt response is expected and thus the overfill would be corrected. In addition, a stress analysis has been performed on the consequences of flooding the TMI Unit 1 Main Steam line. The results of 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 con-cern with respect to steam generator overfill.
D.
Moisture Carrv-over Considerations E'rsluatiens vera eerfermed to dettr-ine whether tha clueeine pattern would allow moisture to be carrieo up witn ene steam, causing potential for erosion of components or steam lines.
Calculations of steam conditions at the entrance to the turbine show approximately 33'F of superheat, indicating no moisture problems in tne bulk steam. Evaluations were also done, to determine the potential for local effects in areas of high plugging before mixing equalizes temperature. Calculations include multidimensional thermal hydraulic simulation of the OTSG with plugged tubes using the THEDA II Code. Results indi-cate that moisture carryover from the clustered plugging of tubes should not be a problem. The effects of the aspirator bleed ports and the geometric design of the 15th tube support plate (outermost holes are not broached) work together to sub-stantially reduce moisture carryover. An ISI program will be implemented to further assure the integrity of peripheral tubes and downstream components and piping. Peripheral tubes in areas of high plugging are included in the post repair eddy current program. A supplemental ISI program of steam system fittings will be implemented. Both programs are described in Appendix A.
E.
Conclusions Evaluation has shown that up to 1500 plugged tubes per steam generator have no adverse effects on performance of the steam generators. The reductions in flow and heat transfer are not large enough to affect the licensing basis analyses for transients or accidents. In addition, moisture carryover is not expected to cause erosion problems, but monitoring of the steam I
system fittings will identify erosion should it occur. _._
II.
UNREPAIRED PORTION OF TU3ES 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 discucses how tubes in the remainder of the steam generator meet the design basis. The rationale for resuming operation with the existing steam generator tubing is based on these facts:
1.
Corrosion tests indicate that the cracking mechanism has been arrested and will not reactivate in low sulfur primary coolant water chemistry. If the cracking does reactivate due to an unknown mechanism at operating temperatures or durine hestuo and cooldown cycles. it is anticioated that the precritical testing sequence woula allow sui:icient came for defects to propagate through wall to a size that would allow leakage to be detected.
l l
2.
Analyses have demonstrated that cracks below a minimum range of length and through wall thickness will not propagate to failure by combinations of flow induced vibration, thermal cycles, and techt.nical loading.
Analyses have also cal-culated a minimum size below which a crack will not become unstable due to plastic tearing or ligament necking during a MSL3. The range 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.
l 3.
Any through wall defects that are large enough to propagate unstably and are not picked up during the 100% ECT inspec-tion because of equipment or analyst error will be detected by leakage monitoring programs during the test program.
A.
New 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 ar-rested and the long term corrosion tests will act as an antici-patory program for crack initiation. An eddy current flaw growth program has shown that cracks are not initiating or pro-pagating. Defect indications which are less than 40% through wall and less than 90* in circumferential extent will be lef t in service and monitored for crack propagation. The precritical testing program will detect reinitiation of corrosion through leakage monitoring. -....
m
The corrosion te, sting program results are described in Section III. Tests on actual and archive Steam Generator tubing to date have established:
(a) Cracking will not occur unless an active reduced species of sulfur is present and cracks in SG tubing will not propagate in the present chemical environment ;
(b) Sulfur induced cracking requires an oxidizing potential which does not exist under normal hot operating conditions ;
(c) Lithium hydroxide is an effective inhibitor of the cracking 2:h: i:=.
Tubing which has undergone the repair and chemical cleaning l
process has also been tested. Accelerated tests performed on i
this tubing under severe chemical environments has not produced i
any cracking. To provide assurance that the mechanism has no long term time dependency, a long term corrosion test program has been initiated to provide an anticipatory assessment of tube performance under actual steam generator optrating conditions.
This program will lead plant operation and will run for approxi-mately one year.
Since identification of the steam generator problem, cracks in the generators have been monitored for growth. Eddy current testing of about 100 cubes in each steam generator was conducted on a repetitive basis to attempt to ascertain if the inter-granular attack mechanism was continuing to damage the OTSG cubing during continued dry primary side lay up conditions. The sample selected for this monitoring assumed half tube sheet symmetry and included tubes with no defects, tubes with a variety of defect indications and tubes in periphery and in-terior areas of the bundle previously identified as high and low defect rate areas, respectively. The method used involved a relative comparison of the low gain.510 standard dif ferential i
probe eddy current responses from seven repetitive examinations l
of the same tube population over a period of time extending from December 1981 through July 1982. The eddy current data was evaluated and compared with previous data for each tube to determine if reported variances from test to test were related to variability in the physical repeatability of analysis of threshold-level defects or to the appearance of fresh defects grown in the interim period between tests.
In July 1982, a "new baseline" condition was established with both the.510" std.
gain technique and the.540 high gain technique performed con-secutively (within 3 days of each other).
l i l
l n
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 ob-served, 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 inad-vertently not recorded.
The comparison of the July 1982.540" high gain technique data to the July 1982 510" standard gain technique data run 3 days apart showed a 94% (188 of 201 tubes) agreement with a "no-growth" result. Where 6% (13 of 201 tubes) of the tubes had
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.s nique, these are established as a product of the higher sensi-tivity of the.540 technique. This result is consistent with other comparisons of these two techniques. As further confir-mation, in August 1982 about 29 tubes were selected from OTSC-1B at-large, where reinspection with.540 high gain techniques had revealed defect indications in addition to those previously idencified 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 comoarison of data.
Within the limits of eddy current test sensitivity and repest-ability, no new cracks were formed or developing in the OTSG tubing during the period from December 1981 to August 1982.
Tubes with ECT indications below US+8" of 1.D. 20-40% through wall and verified by the 8x1 probe to be actual defects are considered degraded tubes. Depending on their circ tmferential e
extent, the tubes will be lef t in service and monitored on an l
extended ISI program. The extended ISI program will include 100% reinspection of the 40% and less through wall indications i
as a separate subset for three continuous refueling outages. If these eddy current examinations show no substantial growth in j
the cracks, they will be lef t in service. Tubes showing signs l
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.
.~
5 More rapid propagation if it occurs, will be evident during the procritical and power ascension test program described in Appendix A.
This program will subject the tubes to normal heat-up and cooldown stresses and to one accelerated cooldown stress test.
Between each of these tests the plant will be maintained 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 test program will be completed by a cooldown from hot conditions to cold shutdown temperatures as a final test of tube integrity.
Leakage monitoring will be continuous during and af ter this test'.
Leakage monitoring programs are adequate to detect 100% through
_:;; cr::.a.;;;a ::::: f il furin; : tran-i:n: :: -::ident condition. Adequate time for propagation will be 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 cracks are not propagating.
Corrosion testing indicated that the mechanism will not be active in high temperature environments such as those that will exist during the test period. Eddy current examination is not planned to be conducted at this phase of the test program since leakage detection has higher integral sensitivity and reli-ability. In addition, opening the steam generator for inspec-tion would expose the tubing to an unnecessary oxidizing environment.
Good engineering practice dictates that exposure to air should be minimized.
Both long and short term corrosion tests provide evidence that the crack mechanism is arrested. The flaw growth program has i
shown that cracks are not propagating or initiating within the steam generators. The precrit' cal and power escalation test program will give assurance in the short term, and in the long term, steam generator leakage monitoring and the long term cor-i resion test program will give tube integrity data and assurance that cracks are not initiating or propagating during operation.
In addition the monitoring of degraded tubes will give addi-tional assurance that the cracking mechanism is arrested.
B.
De fect De tectabiligg An eddy current inspection was conducted of 100% of the in-service tubes in both steam generators for the full length below the top ten inches of the upper tube sheet. The system that was used for this inspection was a.540 inch diameter standard differential probe with a effective gain of approxi-mately 60.
Any high noise or otherwise difficult to interpret indications were resolved in conjunction with data from an eight m m
-z
coil absolute probe. The selection of this system is documented in detail in Reference 20.
The following summarizes the quali-fication process which resulted in determining that this system demonstrated adequate sensitivity to detect defects that should be removed from service. This section discusses laboratory calibrations, comparison of field data to metallurgical inspec-tions, =cusurement of laboratory grown cracks and comparison of differential probe data to absolute probe data.
The eddy current probe systems were tested against electro-discharge machined notch defects at the EPRI nrn-destructive examination re earch center in Charlotte, NC. Circumferential machined notents of.187,.100, and.060 inches were machined on the insice diameter ot IMI arenive stets generator cubing.
La a length of notch was machined to through wall depths of 20%, 40%,
60% and 80%. Minimum levels of detectability were determined by comparing defect signal to a field noise level of.3 volts.
The results of these calibrations for a.540 inch diameter dif-ferential probe with a gain of 60 at a frequency of 400 HZ are shown in Figure IX-1.
Cracks with geometries that fall to the right and above the curve are detectable, those to the left and below are undetectable. The perfectly horizontal geometry of the machined notch is not totally representative of the cracks in the steam generator, but it provides the least detectable geometry for differential eddy currett probes. This geometry, therefore, should provide a conservative estimate of defect detectability. Details of this qualification program are con-tained in Reference 20.
On three separate occasions tubes were removed from both steam generators for metallurgical examination. Details of these examinations are contained in References 3 and 4.
One of the purposes of these examinations was to correlate the LCT signals with actual defect geometry. Eddy current reported thru-wall penetrations ranging from 40 to 951; 39 of 42 cracks investi-gated in the laboratory had 100% vall penetration, and the three cracks were observed to penetrate 66, 70 and 70% through wall.
j One possible explanation for the thru-wall discrepancy is that the cracks may not be open in-situ.
Although the Intergranular attack penetrates the entire wall, sufficient continuity exists across the grain boundaries to give a less than thru-vall eddy I
current signal. There were no cases below the roll transition i
area in which a defect had not b'een detected by ECT.
Details on metallurgical correlations are included in Reference 20.
I The particular geometry of these defects were tight circum-ferential cracks that in most cases, were undetectable by visual i.
,-e
.ee _ _,,..
..g
-n, y
,f
6 FIGURE X-1 METALLURGICAL CONFIRM ATION OF ECT SENSITIVITY FOR IGSAC 360* 1.7 5" - r-o. -
. r...
- 1. ietallurgical M,N Confirmation s i ^ ^ -~ ~
!,:i:i:i:i Tubes pulled i
di:i with IGS AC j
300' 1.46" 7:~ :::
' ' ' ' ' 4:.8
,i m:
- ~ ~ - ~ - "
Laboratory induced M'
- ::i:
lGSAC detected I '..
.c
=,.;;;;;j i.. j:i:
O Laboratory induced
_: ' . :i:!
U.:
IGS AC not desc..ted in 240" 1.17" M:i:
1 3
j=.!:
T$ii
-- Tested Q ' g:
boundaries of e
';li:i E/C detection 1.0"
.- 2:
e
- s:::
E 180*
- 875" -'W^
., E/C field of..
ij!
boundaries of
---* Projected
- -4:::
~
8 l
C-iJ:
C,(j iidetectability.ji E/C detection
- 1:::
=
O m._.m. z :::.:
- 5::
- Mi!
!!E 120
.58 vg N
- hk Undefined DEI - !!!
!!!b
.540 gain 60 boundarles
$^'
N};
8:"^!8
[ fill fac1or 94%
- S*i...I$::;: !!!
!!!b f
60*
.30"
'J:J :'
.g!!!. ;0ihN;::......
Test standards for ll.187"
+!:i8i:
i:i.8!!!h...
!!!h......!!!
J g,
o..g.p+
i
+
g.<:::::
E/C qualification
.100" Notch width (.004")(',.060"
^
, /6 :
i g
i. wpmw.
10 20 30 40 50 60 7
80 90 100 540
.540 Below UTS
% Through Wall in UTS g
o 0
examination under microscope or even by high resolution radio-graph. The primary means of detecting these cracks is by tube axial rectioning and reverse bending on a 1/4 inch mandrel to open up the cracks. Tubes were examined by this method not only in areas where defects had been detected by ECT but also in good areas of defective tubes and in good areas of tubes taken from lov defect areas of the steam generators.
In all, 24.6 feet of tubing was examined by this method and no defects were detected
'except where ECT inspection had indicated a defect. These results increase the confidence level that the sensitivity of the ECT inspection method is sufficient to detect all defects in the steam generator tubing.
To compare the absolute to the.540 high gain star.dard differen-tial (S.D.), the sample of 3232 cubes previously tested by Absolute ECT (4x1) was retested using the.540 high gain S.D.
technique. The sample was predominantly from the high and low rejec t areas of OTSG "A".
The first comparison using the normal S.D.
540 technique indicated a correlation of 99.5%.
The quantity of tubes that did not correlate was 16 low level in-dications. With absolute data, it was determined that these indications were all one coil, suggesting that the circumferen-tial extent was relatively small. In reviewing the.540 scans, it also appeared that the 16 indications not detected 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 absolute.
B & W Alliance Research Center conducted a program to artifi-cially induce IGSAC in archive Inconel tubing. Following exposure to thiosulfate-bearing solutions, the tube specimens were eddy current tested. Scanning Electron Microscopy clearly showed the intergranular nature of the cracking and confirmed that the laboratory induced cracks reproduced the type of cracking and crack shape found in the service failures. For cracks investigated by successive grinding and polishing, measured axial extent ranged from.004
.017 inches. This is somewhat larger than that of the EDM notches used during the previous 0.540" probe qualifications tests.
This value is also larger than the.002" minimum seen during failure analysis on actual tubing. However, the measurements on service tubes were usually estimates made on SEM photos rather than metallographic.
E
r
.ww J
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 observa-tions was performed on samples with the following results. A summary is shown in Table IX-1.
1.
The threshold of detectability appears to be comparable to that determined by the original qualification testing. A crack,.040" x 40%, was below the level previously found detectable and was in fact not de-u teeted.
Crte' s Sf
.31*" ~ 2 a;,73 9,15n es; y...
y detectable by 0.540" probe. This is illustratec furtner by plotting the points on Figure IX-1.
2.
Using the GPUN ECT 2 step screening technique, 8 samples were tested. Four samples were dispositioned as accep-table and four samples were dispositioned as having unacceptable defects. When confirmed by metallography there was 100% correlation.
From these tests it can be concluded that the detectability of laboratory induced cracks confirms the qualification of the.540 differential probe using actual steam generator tubing as well as EDM notches. Similar qualification programs were conducted to determine sensitivity of the 8x1 absolute probe, and to cor-relate sensitivities of both probes in the high noise area of the tubesheet.
The ECT system used during the steam generator inspection has the sensitivity to detect crack of the sizes indicated in Figure IX-1.
All defects above that size have been identified except for a small number that may have been missed due to random equipment or interpretation errors.
C.
Undetected Defects f
Some number of undetected defects or other tube surf ace anomalies may remain in service af ter the repair is completed.
These defects fall into the following categories:
- 1) Local Intergranular Attack
- 2) Below the detectable limits of ECT
- 3) Detectable by ECT but missed through random error i
i l
1 l l
==
TAul.E lX-1 1.AllODATOltY INDilCED CR ACKS E/C CORRELATIOli l
EDDY CURRENT EXAH
\\
HETALLOGRAPHIC CORREI.ATION PliYSICAL
.510
.540 4xl GPUN 1 CIRC.
TilRtl HIN. AXIAL j
SAMPT.E ID APPEARANCE 4 T.W.
1 T.W.
8 COILS DISP.
1.ENG711 WALI, t EXTENT I
5 A - 1.75 DISTORTED 20 - OD NE 1 - ID R
0.2" 50%
.014" A - 2.32 DISTORTED 35 - OD NE 1 - ID R
0.17" 63%
.017" 5
B - 3.32 DISTORTED 20 - OD
<20 - OD 1 - In A
0.:"-0.5" 184
.006"
[
C-
.76 ACCEPTABLE 20 - ID
<20 - ID NDD A
SURFACE ANOMAI,ITY D - 1.9 ACCEPTABLE NDD 35 - ID NDD A
IlO VISIBLE DEFECT E - 4.0 ACCEPTAllI.E HDD 65 - ID 1 - ID R
.315"H 30%
.0065 E - 4.3 ACCEPTABLE IIDD NDD NDD A
.030 25%
i F - 4.8 ACCEPTABLE 85 - ID 55 - ID 1 - ID R
.14" p4%
.012 3
i l
I 1.
R = ltEJ ECT A = ACCEPT
}
2.
NE = NOT EXAMINED (tulle ID ItEDUCTION DID NOT ALI.OW PASSAG,: OF 0.540 PitOllE) 3.
IIIGil Galli PARAMETER SIHtlI.ATED 0.540 SENSITIVITY 4.
It = ltill. TIPI.E 5.
It is believed the physical OD distortion on the tube bar, produced the OD differential eddy current response.
k
Specimens of actual OTSG tubing have exhibited areas of general surface IGA one to two grains deep. This local ICA is similar to that seen in other Inconal 600 cubes and is generally agreed to be the result of the tube umaufacturing process. A few isolated instances of ICA from 6 to 10 grains deep have been
~
found; they are associated closely with visible multiple cracking.
One use of the long term " lead" corrosion testing program described in Section III will be to show that these phenomena are not contributors to tube failure. Specimens selected for this test program will contain general surface IGA as well as crack indications.
IGA islands cannot be specifically included as test speci=ana becaau: ;;; ::: rr -=:2
.. : ::... =,
not be detected other than by destructive examination.
However,.
by bounding this condition with specimens containing surface IGA and actual cracks, the influence of this condition can be assessed especially e; consideration of the fact that metallo-graphy has shown that the most extensive IGA is in the vicinity of major cracks. The development of IGA and/or cracks will also be assessed during the test program as specimens will be period-ically removed from the test solutions and metallographically evaluated. Both the metallurgical examination program and the long term corrosion testing program previde assurance that the steam generators, can,.be operated safely with local IGA on the tubing.
In addition to surface IGA, the existence of small cracks below the thteshold of eddy currant detectability has been con-sidered. Corrosion tests have shown that crack propagation by chemical moann is unlikely. Stress analyses were conducted to determine whether small cracks'could propagate under conditions of mechanical leading during normal operating, transient, or accident ' conditions. The evaluation performed had determined the maximum flaw size which will remain stable under steady-state and transient loading. The acceptability of small cracks in service is based on demonstration that eddy current examinations have identified existing cracks of this maximum flaw, and that the small cracks will not propagate rapidly to this size during operation.
i The tube loads are derived in part from the design basis docu-ment (Ref. 52) and in part from measurements of the TMI-2 OISG tubes (Re f. 51). Recourse is made to field measurements because j
the steam generator performed better than design assumptions i
predicted. Twenty degrees more superheat is measured than predic ted. l
The axial load on the tube during anticipated transients, such as heat-ups, power changes, and reactor trips, and steady-state operation are due to:
a.
Differences in tube average temperature and the average temperature of the steam generator vessel wall.
b.
By virtue of the end fixity of the tube, a longitudinal pressure stress evolves through Poisson's ratio.
c.
A residual tube axial load component exists from fabrication.
d.
Tubesheet fixitv mitigates axial load, especially near the unit centar-line.
Superimposed on the steady axial load is a high cycle, flow induced vibration (FIV) bending load. The frequency and dis-placement magnitude of FIV was measured at THI-2 (Ref. 51).
Potential for crack propagation was evaluated in two ways, a fatigue fracture mechanics calculation incorporating FIV and normal operating transients, and solid mechanics calculations of one time transient and accident loads. These calculations were used to generate curves showing crack depth vs. circumferential extent for the maximum stable crack configurations. The results are shown in Figure IX-2.
D.
OTSG Tube Failure Analysis for Unplugged Tubes ( proprietary)
Curve A in Figure IX-2 represents the maximum crack size found to be stable with respect to fatigue flaw growth over a 40 year lifetime. The fracture mechanics model uses a preexisting crack and evaluates its propagation under high cycle and low cycle fa tigue.
i During cteady state operation the steam generator could have an i
axial tension of 500 lb. act on the tubes. In the analysis, the load cycle imposed on the tubes included mechanical and thermal factors. Low cycle, long duration loads were combined with high cycle flow induced vibration (F.I.V) loading. A graphical representation of the load cycle is shown in Figure IX-3.
The analytical model, which used EPRI fracture mechanics code BIGIF, l
cycled load about 500 lbs. axial tension, the steady-state value calculated from THI-2 test data. The F. I.V. deflection selected corresponds to the largest peak deflection seen at a THI-2 l
sensor during a steady state condition. This is 3 mils, peak l
half-amplitude displacement. The sensor was located at a '4ane" tube which experiences higher crossfigw than the average tube.
I 82 -
l l
1
s
\\l OTSG Tube Critical Crack Sizes d
y 2.00 0.0.M AX ARC-LENGTH 100*F/HR C60LDGWN \\
- 1 g~iw/140*F SHELL
\\
\\
- TO TUBE AT) s\\
\\
- \\
\\ (1107 W-(649 LBS) 1.75 - '
\\ LBS)
\\t ECT +
\\
\\
\\1
(.; -
.k 1.50 L MSLS LINE
+ \\'
\\
's
,(3140 lbs) ' \\ '
(1408 lbs)
O
-sf
\\
1.25 g
E 8
H' ECT +
o E
\\
W 1.00 o
N i
u.o
\\,
I N.
se
'N g
.75'-
's,
-f N
O
'N.
N l
s
'50 MAX INITIAL CRACK SIZE T0 ALLOW 40 YRS. 0F STABLE s
CRACK PROP 0G ATION.
AKth=4.0
.25 1
]
I I
l i
O 20 40 60 80 100 DEFECT DEPTH IN % WALL THICKNESS FIGURE IX-2
. _ _z
~
_n _._. -.J1 -
~-
FIGUREIX 3 OTSG Loading Cycle for Tube Mechanical Evaluation 1100-------------------
FIV - 2.4 X 108 CYCLES /YR.
HEATUP
\\
/
s
/'
s 00*T IMIT 500 --- V V
i NORMAL OPS 3
3,
\\
\\
y
/
\\
\\
\\
1 f
s
\\
100
,/
g N
N
\\
\\
\\
0 s
TIME +
e FIV ALTERNATING LOAD, REGION I ~
550 PSI,.004" MAX. DISP.
e HEATUP/C00LDOWN,6 CYCLES /YR.
e 40 YEAR LIFE e MAXIMUM AMPLITUDES
=
1 The vibrational load amplitude was selected for conservatism to be the maximum tube displacement seen under steady-state loading.
Combined with high cycle loading was the maximum tension excur-sion represented by the 100*F/hr. cooldown, which imposes an axial load of 1107 lbs. The FIV and one cooldown comprise a load block as shevn in figure II-3, with six cycle times per year.
Empirically derived values were used to represent tube loading.
The value of R (K minimum /K ma5 bum) thus is approximately equi-valent to actual conditions.
The fac: ue calcula:ien censi.<ra d..:.
.~a.
point at which small indwelling cracks have no ef fect on fatigue resistance (the endurance limit). This value of the stress intensity, below which cracks do not propogate, is the stress intensity threshold (delta KTH)*
A modifled Paris equation was incorporated in '41GIF" with the feature that if the stress intensity range did not exceed threshold, no growth would occur.
The EMI-1 calculation was performed using delta K;H=4.0 KSI (in) 1/2. This value is based on the empirical data for Inconcel 600 shown in Figure II-4.
The intercept of the abscissa is the threshold for propagation. The relationship has been determined for threshold stress intensity and R values so that data taken at different R values has been used to calculate the appropriate threshold for TMI-1 conditions. Delta KTH "
4.0 KSI (in) 1/2 is judged a conservative value.
The evaluation has shown that the high cycle flow induced vibra-tion does not contribute to propagation for ID circumferential cracks. Low cycle loading from the startup and cooldown is the significant contributor to stable crack growth. Curve A in Figure IX-? represents the maximum crack size which can with-stand 40 years of heatup and cooldown cycles without reaching a size which will propagate rapidly to a through wall defect based j
on the conservative analytical assumptions made. Since this curve is to the right and above the eddy current detectability curve, cracks of this size will not exist in the free span area j
of the repaired steam genetator.
l Curves B and C represent solid mechanics models of the ability
{
of cracked tubing to withstand one time trans.ent l oad s. The maximum accident axial loading on the tubes is during a main steam line break, and is defined as 3140 lbs for peripheral tubes and 1408 lbs for core tubes in generic licensing I l l
t l
l
I FIGUREIX 4 Fatique - Crack Propagation Behavior of Inconel 600 da/dn vs AK forINCO 600 10-4 A 75* JOURNAL OF ENGINEERING MATERIALS CURVE O 600 JOURNAL OF ENGINEERING MATERIALS CURVE
~
G 77* MIT CURVE 3
0 554* MIT CURVE
/
l 9
0 10-5 g
OC.
e/s
/
1.i ll g.a.
4 of 3
P
=*
10-6 A
t i
A l
t 1
8
?
608* POINT BORATED WATER
\\
10-7
'i
{10 1
100 LOG AK, KSI O STRESS INTENSITY FACTOR RANGE r <- --
r.
t-y e
y -.w wr#w,-.,--
,.ew.,,&---
documents. The maximum axial loading during normal transients is the 100*F/hr cooldown, which corresponds to 1107 lbs tension for peripheral tubes and 649 lbs for core tubes. These axial loads include preload, pressure effects and cube-to-shell l
temperature differentials.
Curve C on Figure. IX-2 was derived using the 1107 lbs transient axial loading, Curve B is for MSI.B.
In the analysis, the fact that a flawed tube will move laterally under the axial load is included so that the centroid of the damaged cross section lines up with the line of action of the load through the intact tube centerline. With this model, the induced bending moment at the flaw is reduced. Assumptions on the tube stiffness remaining and the manner in which strain is absorbed in the area of the crack have been seiectec to r.aAe :e raea.;; ;anar ta.-..
Curves B1 and Cl reflect conditions pertaining to the core tubes.
{
Curves B and C show that the maximum crack sizes for failure under transient and accident loading is to the right and above ECT sensitivity. Thus the probability is very small that cracks of this size will remain in service af ter the completion of repairs.
The laboratory calibration results and the correlation of the differential production probe to the absolute probe results provide confidence that all defects above the detectable size will be found. However, there is a small probability that some large cracks may not have been detected due to problems such as high noise levels, probe lift off or chatter, or data analysis Because of this possibility, an evaluation was per-errors.
formed to determine if tube cracks of the size that would pro-pagate can be detected due to leakage.
Aa discussed above in the 075G tube stress analysis, the tube axial load is a function of several variables and may have j
either tensile or compressive values. The greatest uncertainty
{
is the tube tensile preload. Based on the MI-2 test data at j
97% full load a tube axial load of 500 lbs tension was cal-l culated. In addition to this result, a calculation was per-formed on the basis of first principles in order to establish the tube loading. This calculation included the effects of dif ferential thermal growth between shell and tube, pressure loadings and tubesheet deflection as well as a value for tube preload. The preload value was based on a gap measurement of 3/32 inch between parted tube surfaces. At TMI-1 the result is a tube loading at full load to be approximately 500 lbs tension The for peripheral tubes and 200 lbs tension for core tubes.
calculated results of tube loading based on first principles,
w
correspond fairly well with the values esiculated from the TMI-2 test data. Therefore, we conclude that the model of tube load based on first principles is valid and that the tube is in ten-sion during operation.
Af ter determining a conservatively small minimum crack opening displacement, leakaga through the opening was calculated. The evaluation includ.
.onsideration of phase changes and pressure drop as the primary fluid passes through the crack.
Leak rate has been calculated using various steady state tensile tube loads and through wall crack sizes. Figure IX-5 shows the relationship of tube leakage versus crack are length for various cuee loans wnica control cae CCD.
Tae folaowing cac*e s i.s-2 s shows the full power operational leak rates for peripheral and core tubes based on their respective critical crack size for a MSLB and for the Plant Technical Specification (100*F/hr) cool-down rate.
Table IX-2 THI-1 OTSC Tubes Critical Crack Sizes and Operating Leakrate Tube Location:
Core Periphery Tube Load 6100 Power (1bs.)
200 (tension) 500 (tension)
1 - MSLB Transient Tube Load (1bs.)
1408 (tension) 3140 (tension)
Critical Crack Size (inches) 1.28 0.52 Leakrate (gph) 9100%
Power Operation 14 6
2 - 100'F/Hr Cooldown (140*F Shell to Tube Delta T)
Transient Tube Load (1bs) 649 (tension) 1107 (tension Critical Crack Size (inches) 1.72 1.48 Leakrate (gph) @l00 Power Operation 22 72 Fig. IX-5 was developed by Nuclear Safety Analysis Center (NSAC) based on a model for two-phase flow through a crack with initial saturated or subcooled fluid, by Battelle, Collier, R.P.,
et i
al., " Study of Critical Two-Phase Flow Through Simulated Cracks", BCL-EPRI-80-1 Nov. 25, 1980. The curve was redrawn to include a 200 lb tensile tube load curve. -
e.
e m.m.s4--Sea m
.,m.,a.a ew,
.a, FIGUREIX 5 OTSG Leak Rate as a Function of Crack Length & Tube Tensile Load 100 1107 # tension 90
[ peripheral tube ))
- ad ^&. 2 0 5.'i.:.-
Cooldown 80 70
=
~
rS 60 500 # tension w
Q
=
m 5
peripheral tube load
@ Full Power w
50 a
E E
40 a
30 1
200 # tension 20 core tube load
@ Full Power 10 I
I I
I f
f 0
0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.3 1.0 1.1 1.2 1.3 TUBE CRACK 0D ARC LENGTH (INCHES)
_ m m-we--
..e
+s.e-6
l 1
I The leak rates indicated in Table IX-2 are above the detectable leakage shown in Section X.
An administrative limit on leakage has been established based on the lowest leakage value in Table IX-2.
The administrative leak l
rate 1Luit assumes all increases in leakage to be from one CISG l
tube and has a value of 6 sph above the baseline on this basis.
The action of that point will require bringing the plant to cold shutdown and leak testing the OTSG and repairing any identi-fiable leaks. Bubble tests are expected to identify individual leaking tubes. Bubble test sensitivity is.1 gpd/ tube.
- Thus, any cracks in service of a size which is or propagates to a riti::1 71:e vill be identified.
In addition to the leakage limit, normal plant cooldowns will be accomplished at less than 100*F/hr and limit the OTSG shell to tube delta T to 70'F.
This will decrease the cooldown transient axial tube tensile load to approximately one half of the evaluated tensile load which results from 140*F OTSG shell' to tube delta T.
i
. E.
Conclusions l
Evaluations of tubing left in service have been performed to verify that they are acceptable for use.
The possibility for l
additional corrosion occurring after return to operation has been considered and found unlikely. In considering existing i
damage, the ability of cracked tubing to withstand steady state, transient and accident loading has been examined.
All cracks of l
a size that could be expected to propagate under loading are I
within the range of detectability by eddy current testing.
If a l
through wall crack of critical size for grovch has been in-(
advertently left in service, or grows at a later date, it will be detectable due to leakage before there is tube failure.
l l
l l
1 I
l l -
l l
i X.
OPERATIONAL CONSIDERATIONS The operational concerns of primary to secondary leakage were evaluated. Concerns included leakage monitcring during normal operations in both steaming and nonsteaming conditions, and sampling steps to be taken when leakage is detected. In additio'n, 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.
The operational guidelines discussed in this section are applicable during normal operation with low levels of primary to secondary leakage. A more detailed description of these guidelines can be founc in reference $o.
For primary to seconcary lea 4 age racio of 53 gpm or greater, these guidelines will be superseded by tube rupture guidelines as discussed in Section X.B.
Operational concerns can be grouped into three general areas '
1.
Primary to Secondary Leakage which includes leakage detection methods, and actions required based on primary to secondary leakage.
2.
Radiological concerns which include detection methods, worker protection measures and plant discharge limits.
3.
Secondary side chemistry limits based on boron and lithium con-centrations.
i This section summarizes the guidelines for operating with tube leakage.
i A.
Primary to Secondarv Leakage During normal power operation the methods which will be used to i
detect and monitor leakage arei
{
I 1.'
Offgas continuous monitor (RMA-5) 2.
Tritium samples from the condensate and primary system.
l 3.
Offgas grab samples g
I 4
N-16 activity measurements using portable steam line monitors 5.
Primary Leak Rate Calculation These methods are summarized in Table X-1.
I RMA-5 will be the first indication of increased primary to l
secondary leakage. The monitor will continuously sample the
, i en-* * =
c vacuum pump exhaust from the mein condenser. Upon a 25% in-crease in 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> in RMA-5 count rate the primary and secondary systems will be sampled for tritium and the leak rate cal-culated. An of fgas grab sample will be taken and the primary to secondary leak rate will be calculated using Xe-133, Xe-135 and total gas activities. The portable steam line menitor will detect N-16 activity and will be used to evaluate which steam generator is leaking.
Primary leak rate calculations which are done daily per Technical Specification requirement can also identify incre 2ed primary to secondary leakage. Since the leak rate cannc.
s.-
tinguish between unidentified system leakage and primary to seconcary leasage, 11 an on can::: :c.ne:2.44 ;n '....
.:3 occurs, a tritium and offgas grab sample will be taken to allow for an accurate determination of the primary to secondary leak rate.
Shutdown limits based on primary to secondary leakage will con-sist of the Technical Specification limit of 1 gpm and an admin-istrative limit of 6 gph above a baseline leakage. Baseline leakage will be determined during the precritical hot testing program. When a leakage increase of 6 gph is reached the plant will be brought to a cold shutdown, the OTSG will be leak tested and the leaking tubes repaired. Tube leakage will be tested by the bubble test method. This method has a sensitivity of
.1 gal / day / tube or 4x10-4 gph/ tube, therefore if no leakage is detected during the bubble test it can be assumed that no individual tube has reached the critical crack size and primary to secondary leakage is due to aggregate tube leakage. The i
baseline leak rate value will be redetermined based on an evaluation of the OTSG 1eak rate test results and operating history after the leak test is performed. When primary leakage reaches 6 gph greater than the new established baseline the plant will again be shutdown and leak tested.
j t
l When shutdown is required by steam generator tube leakage, the plant should be shutdown expeditiously but in a manner to pre-clude reactor trip and subsequent lifting of relief valves or atmospheric dump valves. Cooldown rates should be limited to 100*F/hr and tube to shell delta T should be limited to further reduce the possibility of tube rupture during cooldown.
l B.
Radiological Concerns i
During normal operation with steam generator tube leakage, radiological concerns arise in the following areas:
1.
General and specific area radiation level l
2.
Turbine building sump activity (with respect to dischatge to the environment). t l
I 3.
Powdex resin and backwash water activity.
l Specific and General Area radiation limits will be determined and will be based on preventing the turbine building from becoming an EdP area (greater than 5 mr/hr). Limits are needed due to the necessity for easy access into the turbine building during operation. Routine radiation surveys will be'taken in the turbine building in the vicinity of the Powdex and Graver System vessel and in other selected aress. These areas will be restricted if necessary to prevent unnecessary exposure to plant personnel. Precautions will also address secondary side system vent and drain operations.
In the Pevdex sumo, pH and conductivity analysis will determine if the water which has been processed oy cne sicccyne drasare Powdex Backwash Recovery system will be returned to the IMI-l l
condensate system or to the turbine building sump.
Any radio-3 active powdex will be dewatered in High Integrity Con-tainers / liners and shipped to commercial low level vaste burial sites.
C.
Secondary Side Chemistry Secondary side chemistry limitations for Boron and Lithium will be based on considerations of chemical introduction into the turbine.
D.
Development of Procedural Guidelines for Steam Generator Tube Rupture A program has been formulated for providing improved operator guidelines for dealing with tube leakage and tube rupture
(
events. The guidelines cover two categories of events. The first category addresses tube ruptures for which subcooling margin is maintained. The second category will deal with tube l
ruptures for which subcooling margin is not maintained and would I
include various contingencies including ruieinle tube ruptures in one or both SC's, loss of reactor cc.anc pumps and loss of l
condenser.
1.
Contingencie s for consideration The following is an outline of the programs for developing i
guidelines for SG tube rupture.
Ouidelines for Tube Ruptures for Which Subcooling Margin a.
is Maintained 1
The program to develop guidelines for tube ruptures for which subcooling margin is maintained will include the following basic assumptions.
l l
i ?
i
,m..,,,
1 TAB LE X-1 LEAKAGE DETECTION METHODS
SUMMARY
TABLE e
Method Sensitivity Frequency Special Actions WHA-5 0.48 sph with 3.8 uCi/cc Continuous strip When count rate and 20 cfm exhaust flow chart reading.
increased by 25%
in 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, sample for tricium and take off gas grab sample.
.3 gpm at.02 uCi/mi 6 nours vita H3 after 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> known leakage Offgas Grab
.01 gym at 3.8 uCi/cc
, 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency increased Sample and 20 cfm exhaust flow with known leakage Portable When leakage is Steam Line detected deter-1 Monitor mine which generator is leaking I
s t
k l
t l
l t
I i l l
l mee
1
___y._.,.._...__..___-
(1) Break size small enough to maintain subcoeling margin.
(2) One OTSG affected.
(3) Reactor Coolant Pumps operating.
(4) Condenser available.
(5) Decay heat removal from the non-af fected SG.
(6)~SG steamed at 95% operating range level to assure natural circulation.
Contingency considerations for design basis tube ruptures include:
(1) PORV unavailable.
' ' 7.s::::r :::'.:n- 'ucpr : : -i':'::*.
(3) No condenser available.
(4) High radiation release considerations.
(5) Steam line flooding consideration.
(6) Both SG's are affected.
b.
Guidelines for Tube Ruotures For Which Subcooline Margin is Not Maintained The progrem to develop guidelines for tube ruptures for which subcooling margin is not maintained will include the following basic assumptions.
(1) Break size from one SG large enough to cause loss of subcooling.
(2) No reactor coolant pumps running (since subcooling margin is lost).
(3) Condenser available.
(4) PORV available.
(5) Unaffected SC is steamed.
Contingency considerations include:
(1) PORV unavailable.
(2) RCS voiding keeps pressure above SG safety valve setpoint.
(3) Primary feed and bleed heat removal.
(a) With PORV available (b) Without PORV available Both the analyses employ the RETRAN code. This code models TMI-1 and has been benchmarked from transients on beth TMI-l and TMI-2.
Use of this code ensures that plant response under various primary-to-secondary leak scenarios is under-stood...., _.
.o
FIGURE L1 Tube Rupture Guidelines l
Primary to Secondary Leakage
> 50 gpm Jt I
b Manual Automatic Shutdown Shutdown w
a Cooldown s
7
'r v
Forced Natural HPI Circulation Circulation Cooling L
J r4 4
Decay Heat Removal New Guidsnce:
- multiple tube ruptures
- ruptures in both steam generators
- HPl cooling
- Secondary water management r
improved guidance
- Minimum subcooling reduced
- RCP trip criteria
- tube to shell AT
- steam generator steaming, feeding, flooding
-.e==
Ame
~
FIGURE Vill.1 REDUCTION IN RC FLOW RATE VSINUMBER OF TUBES PLUGGED PER STEAM UENERATOR 110 108 3
=
E 2
u.
e 106l I
C e
o
?seI 104 -
o a.
Oz s<
H O
102 100 I
I I
I I
I I
500 1000 1500 2000 2500 3000 3500 4000 Number of Tubes Plugged in OTSG L
e
1 The guidel'nes developed from the RETRAN analysis for tube ruptures.are sunmaarized below and have been used for writing new procedures and revising old procedures. Operator i
training prior to restart includes response to tube rupture events using new and revised procedures.
2.
Qaideline Sununarv The symptoms of a tube rupture define entry conditions for this emergency procedure.
It is only used when leakage exceeds 50 spa. When conditions require it (as defined by j
high leakage or significant of fsite releases), the plant
{
will be shutdown and cooled as expeditiously as possible, I
I
- nd c2-::in -er 21 -1:nt li=its /?.C? 'M *3 Sc-al tube /-M M delta T, and fuel-in-compression limits) are waived.
a.
Inunediate Action The tube leak in question may not be large enough to cause a reactor trip.
In such a. case, the operator begins a load reduction as rapidly as possible without j
causing a reactor trip (10%/ min.).
Avoiding a reactor j
trip prevents lif ting of the OTSG safety valves.
i b.
Followup Actions l
(1) Subcooling Maintained and Reactor Coolant Pumps Available Once the load reduction is initiated or a reactor trip has occurred, the operator has several major goals to achieve while bringing the plant to a cold shutdown condition. First, he prevents lif ting of the OTSG safety valves; second, isolates the af-fected O U G to prevent unnecessary radioactivity releases; third, minimizes primary to secondary l
1eakage by minimizing primary to secondary dif-I ferential pressure; and, fourth minimize stresses on the OISG tubes by limiting tube /shell delta T.
l Finally, the operator will minimize offsite dose by allowing the leakage OTSG to flood if offsite doses are large enough (approaching levels at which a Site Emergency would be declared).
The major differences between the existing plant procedure and the new procedure would be the l
following.
' _. ~...._
~-
(a) Maintain a Minimum Subcooling Martin Minimum subcooling margin means that primary to secondary differential pressure is minimized.
Minimum differential pressure means that leakage is reduced ; thus reducing off site dos 2 and making the event more manageable.
In order to maintain the minimum subcooling margin, several plant limits have to be violated: fuel in compression limits and RCP NPSH limits. The former is acceptable to violate during emer-gency conditions, while the latter is being reevaluated to determine acceptable emergency oeeration of the eu=o.
(b ) Steaming / Isolation Criteris for the Af fected OTSG The present procedure allows the operator to let the OTSG flood anytime that RCS pressure is below 1000 psig. The revised procedure has the l
operator stema the OTSG as necessary for the following purposes. First, to prevent lifting of the OTSG safety valves. As the OTSG level increases, steam generator pressure in the isolated generator could increase toward the safety valva setpoints. Pressure should be l
controlled to prevent a safety valve lift.
j The generator is alsi steamed to prevent it from flooding.
Floo ling is undesirable because an RCS pressure increase under this condition could cause water relief out of the OTSG safety i
valves. A flooded OTSG vould also act as a second pressurizer and slow depressurization of the RCS (as occurred in the GlNNA tube rupture).
The OTSG will be isolated under two conditions.
I First, if BWST level goes below 21 ft. indi-I cated level. At this level, there is still l
sufficient inventory to fill up both OTSG's to i
the main steam isolation valves and have 30,000 I
gallons of water left to go on feed and bleed l
cooling. A second reason to isolate the OTSG I
is for radiological considerations.
If the Radiological Assessment Coordinator (RAC) determines that offsice doses are approaching i
i I
the levels which would require declaration of a Site Bsergency. (regardless of cause) the affected steam generator will be isolated.
(c) Tube-to-Shell Delta T Plant administrative limits and precautions j
will require maintaining the OTSC average tute
~
i temperature within 70*F of the average shell i
temperature.
Under emergency conditions, this j
limit can be relaxed to 140*F (Tech Spec limit) without adversely affecting OTSG tubes.
l
( 2) loss of Subcooling Margin with Natural Circulation Cooling When RCS subcooling is lost, the operator must treat LOCA, as well as tube rupture symptons. First he j
trips RCP's and then verifies HPI and EFW have initiated. He is then able to pursue the follovup tube rupture actions. All of the guidance for I
followup actions without loss of subcooling apply, as well as the additional guidance provided below.
f The objective in this portion of the procedure is to maintain natural circulation, reestablish subcooling margin, restart a. reactor coolant pump, and return i
to the section of the procedure for forced flow cooldown.
j i
When subcooling is regained in the RCS, then HPI is I
I throttled, RCP's are started and the operator con-tinues with 1.67F/ min cooldown. If subcooling can-not be restored, the operator cools the plant down on natural circulation, steaming as necessary to meet the objectives described in the forced flow section.
i If the affected OTSG cannot be steamed for either radiological or equipment reasons, then EFW is used to control OTSG pressure. Essentially, EFW is used as a pressurizer spray to keep the leaking generator slightly lower in pressure than the RCS.
The bene-fits in controlling steam pressure are:
(a) safeties will not lift.
1 I
(b ) the steam generator will not control RCS pres-sure....
=
z-
~
=
t (c) there will not be backleakage into the RCS of f
unborated water.
l (d) leakage from the RCS to the OTSG will be small i
since differential pressure will be small and will also reduce tube tensile load due to pres-sure loads.
(e) the small flow through the hot leg vill help prevent void formation in the hot leg.
(3) Loss of Subcooling and Loss of Heat Sink Hatural circulacion cooicewn wi'1 concinue un::1 subcooling is restored or the OTSG heat sink is lost (for example, due to loss of natural circulation in the unaffected loop). With no sepam generator heat sink, the operator must put the planc in a feed and bleed cooling mode. Feed and bleed cooling is ini-tiated by isolating the OTSG's, assuring full HPI is operating, and opening the PORV. If RCS pressure remains below 1000 psig, then the operator continues to control secondary side pressure just below RCS pressure. If the OTSG heat sink is restored, the i
feed and bleed is terminated and a natural cir-culation cooldown is reinitiated.
If RCS pressure stays above 1000 psig during feed and bleed cooling (e.g., the head bubble prevents depressurization or the PORV fails closed) then the secondary side safety valves have to be protected from challenge. The operator controls OTSG pressure with whatever means are avsilable (turbine bypass, EFW or ADV). When the OTSG is about to flood, the operator opens the ADV and leaves it open. This action minimizes the chances that safety valves will be forced to relieve water and/or steam and fail open. The steaming capacity of an ADV at 1000 psig exceeds decay heat levels within several minutes af ter reactor trip. HPI capacity exceeds the capacity of one ADV. Therefore, the RCS pressure can be controlled at 1000 psig in this mode without lifting safety valves. Subcooling margin can be regained and the plant cooled down in this mcde until an OTSG heat sink can be restored or until the plant can be put on decay heat removal.
A simplified schematic of the tube rupture guide-lines is shown in Figure X-1. _
A fourth possible scenario exists under current.
procedures which has not been considered a preferred course of action in formulating the guidelines:
maintenance of subcooling margin but tripping of reactor coolant pumps on 1600 psi RCS pressure.
Pump trip on loss of subcooling margin instead of RCS pressure allows the operacor to maintain forced flow for about 3 ruptured tubes - 1600 psig SFAS is much more restrictive. Forced RC flow provides several benefits during a tube rupture.
t 1.
It minimizes primary to secondary delta P and thus reduces tube leakage and tube tensile load.
2 Prevents steam formation in the RCS.
(Steam voiding prevents RCS depressurization.)
{
i 3.
Provides pressurizer spray so that RCS pressure l
control is not dependent on the PORV or pres-i surizer vents.
g i
Therefore, GPUNC is taking action to have the l
1600 psi pressure pump tr,ip requirement changed to trip on,subcooling margin.
E.
Conclusions Primary to secondary leakage will be monitored during non-steaming and steaming conditions. Sampling requirements on the detection of a prima y to secondary leak heve been established, and administrative limits on leakage are being considered.
f The combination of analysis of tube ruptures, procedure improve-l ment and training improvement give assurance that operators can safely respond to a primary to secondary leak.
1 i
1
~ _.,, _
XI.
ENVIR0! MENTAL IMPACT A.
Introduction The impact of operating TMI-l with primary to secondary leakage was evaluated. Offsite dose estimates were determined at several leakage rates, using actual anticipated failed fuel percentages. These calculated estimates have been compared with Appendix I technical specification requirements. The effect of leakage on onsite exposure was also considered and found to be small. Exposures associated with steam generator work leading to return to service are also discussed below.
2.
Off-i:2 te 3 :- :ir-:3:
The maximum primary to secondary leakage rate at which TMI-l night operate can not be determined without operating ex-perience. The offsite consequences of such operation will be dependent on the failed fuel percentage and actual plant system and environmental conditions. Dose will be determined during operation by monitoring. The technical specifications for THI-l incorporate the Appendix I offsite dose limitations. If offsite doses approach these limits due to primary to secondary leakage, it will be necessary to shut the plant down to look for leaks.
For planning purposes, two calculations were performed using different hypothetical leaks rates, 1 lbm/hr and 6 gph. 1 lba/hr is the repair leak rate goal. 6 gph was selected as a leak rate with which similar plants have operating experience, and which is similar to the leak rate change at which admin-istrative procedures THI-1 would shutdown to look for leaks.
Both calculations assumed 0.03% failed fuel, which was seen at D11-1 at the end of cycle 4.
Results of the two estimates are compared in Table XI-l to Appendix I technical specification limits. Source terms and methods for calculation can be found in Reference 11 and 54.
. l 1
e:
~
.e..,
t -.,, - -.. -
. ~ ~ ~
0
Table XI-1 Hypothetical Maximum Individual Offsite Dose (l) 0FFSITE DOSE AND FRACTION OF APP. I LIMIT 10 CFR 50 Source 1.0 LBM / HR 6 GPH App. ' I Do se 1 of App.
Do se 1 of App.
Limit i
(ar/yr)
I Limit (ar/hr)
I limit (wr/yr )
Iodine &
- 7. 68E -2 0.5 4.61 31 15 Particulates Noble Gases
[
- Camma
- 5. 6 8E-2 0.6 2.74 27 10 e
- Beta 6.96E-2
- 0. 4 3.33 17 20 j
i Liquid Effluent
- Whele Body 1.04E-3 0.1 4.88E-2 1.6 3
(adults)
- Liver
As can be seen in Table XI-1, of fsite doses are not expected to approach Appenelix I limits due to primary to secondary leakage.
However, monitciring of actu..1 offsite exposure will be used to set leakage linius which prevent exceeding technical specifi-cation limits.
C.
Exposure Estimates I
The projected man-rem exposures for the completed OTSG repair program are estimated to be 1260-1295 man-rem.
Individual ac-tivities for the steam generator program are presented in Table XI-2, along with exposures to date. -.m
Table XI-2 Ekposures from OTSG Program i
Actual to 2/28/83 Additional Projected 1.
RCS Inspection 12 0
2.
Eddy current Thsting 35 10 1
3.
Pre-Repair Testing 5
0 4.
Tube Sample Pulling Plugging 120 0
and Stabilization 5.
Plugging and Stabilization f
a.
E plugs 75 b.
Stabilization 235 6.
Kinetic Expansion j
a.
Pre-expansion Preparation 16 b.
First Pass Expansion 168 0
c.
First Pass Debris Removal 132 0
d.
Second Pass Expansion 167 0
e.
Second Pass Debris Removal 75 0
7.
End Milling 125 0
]
8.
Clean-up a.
Flush 30 b.
Soak and Clean 30 c.
Individual Tube Cleaning 10-4 0*
l l
9.
Testing s.
Drip Test 5
l b.
Bubble Test 5
c.
Final Inspection and Turnover 5-10*
l l
l
~
Tbtals 855 405-440 l
- Items for which planning is not complete.
I i
i l
G --
- - =. - - -
Table II-3 Radiation Fields at Pil-1 Incation Upper and lower Heads 1.3 R/hr.
Manway 0.13 R/hr.
Tent 0.01 R/hr.
i Iow Zone 0.001 R/hr.
I t
l Operating with the limited leakage associated with the repaired joint was also considered. The additional exposure is expected
- a..
- . y, 5,,
e--, 5 -,....... :.... a e.--...:...
tify any additional radiation areas and minimize related worker exposure in operating with a primary to secondary leak. The largest sources of radiation exposure are expected to be the Powdex Demineralizer vessels. Associated contact radiation levels have been calculated for a 6 gph leak to range from 0.7 -
ar/hr for one day filter operatica to 5.7 mr/hr for 15 day operation. In addition to these estimates, experience at simi-lar plants operating with small primary to secondary leakage has been exposure increases of less than one man-rem per year.
Based on this information, the annual exposure at Dil-1 is ex-pected to increase by less than 1% due to leakage.
D.
Sampling and Monitoring Appropriate monitoring and sampling of all vaste streams will be conducted per established 02idelines. Modifications will be installed in the hrbine Building to provide radiation and con-tamination control and effluent release control / accountability.
These modifications will consist of Powdex and Wrbine Building sump painting, and liquid monitors to measure activity during l
l operation.
1 l
E.
Conclusions The operation of IMI-1 with small primary to secondary leakage is not expected to cause of fsite doses nearing the Appendix I l
Technical Specification limits. Final verification of estimates will be by monitoring during operation.
Should monitoring in-dicate that primary to secondary leakage is causing offsite doses to approach these limits, steps will be taken to reduce the activity contribution. Exposures oasite as a result of primary to secondary leakage are expected to be minimal compared to pric,r plant experience. Exposure during the investigation of the steam generator problem, the repair, and testing af terwards,
is not expected to exceed 1260-1295 man-rem.
- 100 -
c
XII.
TECHNICAL SPECIFICATION COMPLIANCE
)
1 This safety evaluation demonstrates that the TMI-1 OTSCs are operable par T.S.
3 1.1. 2, and have me t the surveillance conditions for operability given in T.S. 4.19, or as defined in the releated l
T.S. change request.
l In addition, the following technical specifications were evaluated in light of the sel1cted repairs. Operation with the repairs in place was found to be acceptable in each case.
SER T.S.
Subject Topic for Evaluation Re ference 1.5.6 Heat Ba1. Calib.
Flow asy= metry Section VIII 1.6 Def 'n, Quad. Pvr. Tilt Flow asymmetry Section VIII 2.1 Fig. 2. -1,2.1-3 Flow vs T Flow, flow asymmetry Section VIII
- 2. 3 Fig. 2.3-2, Table 2. 3-1 Nuclear Overp.
Fl ow Section VIII 3.1.1.1.a Permissible pump. comb.
Flow Section VIII 3.1.2 RCS heatup-cooldown Stress vs. Temp. change:
Section V and assumes vessel as limit IX 3.1. 4 RCS activity Leakage Section X 3.1.5 RCS chemistry Further attack in conj.
Section IV w/resid. S or following S distress 3.1. 6 RCS leakage Laakage Section IX 3.5 2.4 Quad Pwr. Tilt Flow asymmetry Section VIII 3.5.2.5 Quad. Ba1.
Flow asymmetry Section VIII 3.13 Secondary activity Appendix I w/ leakage Section X 3.22 Appendix I Imakage Section X 3.23 Appendix I Le akage Section X j
- 4. 2 RCS:IS I Testing of RCS ComponentsSection II.E
- 5. 3. 2.1 RCS code req.
Repair qualification Section V i
l I
i l
- 101 -
n.~-
~.
me
XIII.
SUMMARY
AND CONCLUSIONS The previous twelve sections along with the references and appen-dices associated with this safely evaluaticn provide a broad-ranging discussion of the adequacy and safety of the TMI-1 OTSG repair and the ability of the plant to be safely returned to service. The main points associated with determining that the plant is safe to operate
~
can be summarized as follows:
1.
Knowledge of the failure scenario is sufficient to provide a firm technical basis for OTSG repair decisions, insure that the environment for such a damage mechanism is not established in the future, and provide a technical basis for assuring safe,_;.:.
.i ;h: n o.
pericr:an;a ci fe,=
!20 :aae; ;i..t.
. c. e
.rs.
2.
Evaluation of operation of TMI-1 with small primary-to-secondary leakage has confirmed that Appendix 1 Technical Specification considerations are satisfied,.
3.
All tubes with no defect indications below an elevation 8 inches above the lower face of the upper tubesheet (UTS+8) have been adequately repaired by the kinetic expansion process.
T* ?
kinetic expansion process qualification program provides assurance that a load carrying and leak limiting joint acceptable for safe operation has been formed.
4 The performance of the OTSC/RCS considering the tubes to be plugged is satisfactory and no power limitations are required.
Tubes with defect indications below the UTS+8 elevation will be removed from service by approved plugging methods. The OTSG/RCS performance with these tubes plugged has been evaluated for both normal operating and emergency conditions.
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 mechanical loads during both normal operating or i
l accident conditions. Geometries which would propagate to a double ended tube rupture during 40 years of operation or during i
l an accident were characterized as " unstable." The results have been compared to the ECT sensitivity for various geometries of circumferential defects. This comparison shows that the GPUNC l
100% ECT inspection of the TMI-1 OTSGs was sensitive enough to find " unstable" defect geometries.
6.
The examination of Reactor Coolant System (RCS) has confirmed that the aggressive environment that caused damage to the OTSG tubes did not damage the remainder of the reactor coolant system.
The RCS examination results provide the basis for concluding
- 102 -
l
.a
o that there are no corroded components in service which will preclude the RCS from functioning properly and supporting safe operation of THI-1.
7.
Analysis of design basis and higher primary-to-secondary leak rates confirma that the operating an,d emergency procedures are technically correct. The procedures provide adequate basis for training the operators to respond to normal and emergency primary-to-secundary leakage. The procedures are being modified to improve even further operator guidelines and handle greater than design basis accidents.
8.
Steen generator testing together with long life continuing laberstor; testin; vill r-ide :enfir= ster data on -enair stability and the absence of new high velocity cracking. The steam generator testing vill be completed with essentially zero decay heat power and poses no safety risk.
Conclus ion In conclusion, TMI-l can be safely returned to service once the repairs and other activities discussed in this safety evaluation report are completed. This conclusion is based on sound analy-tical and empirical data developed by CPU Nuclear Corporation during the OTSG repair program. The scope of technical evalu-acions has been broad based and the involvement of numerous independent technical experte has been extensive throughout the THI-l 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 TMI-l steam generators can be safely operated.
- 103 -
o O
FIGURE A-1 TMI-1 Rootert Test Program Including OTSG Repair l
l l
1 l
EOMPLETE OTSG OTSG I
RESTORE FILL &
RCS h4.
OTSG DRIP BUBBLE ECT RCS VENT HO REPAIRS TEST TEST RCS CLE P
i I
L 4
i SEC. PLANT READY TO SUPPORT HEATUP
- 1 s
'i
'i i
ESTABLISH OTSG/FW tlEATUP OTSO Hal ZERO COOL DOWN FUNCTIOrJAL POWER AH CilEMISTRY FOR OTSG HOY TEST TO SUPPORT HOT TEST ANDSOAK TESTii.G PH SICS j
HEATUP I
S
- 2 i
NATURAL POWER RETURN OTSG I
Bb CIRCULATION ESCALATION TO 100'/
CURRENT TESTING TESTING
-- 90 DAYS TEST
- FormalManagement Review i
I i
49 % 75% 100%
e
FIGURE A-2 TMI-1 OTSG Tube Repair Precritical Test Program l
EVALUATL-F8LL AND PERFORM PERFORFJ COMPLETE
~
OTSG DR P OTSG BUBBLE PkSTORE N2 pA ps
, TEST TEST iiCS (2 DAYS)
(2 DAYS)
(3 DAYS) l l
CONDUCT RE-ESTABLISH H/O RCS CONDUCT THERMAL C
hU FOR OTSO
~
~
CHE STRY LEAK EST NG 532*F 2165#
130T/300 # -
' FOnit/U TUDE1ESTS 4
=_
{
12 WKS)
- (2 WM S)
(2 L. AYS)
-(2 DAYS)
(1 WK)
I 1
o I
l RCS RCS THFHt.1AL COOLDOWN
- II/U nCS COOLDOWN H/U RCS m_
@ 60*F/HR.
532*F/2155 #
@ 907/HR.
d32WM5 r -
M 532 F/ 155#
Foil 2 HRS.
FOR 2 IIRS.
_ l (12 IIRS)
(11 DAYS)
(12 IIP *)
4
,I THERMAL RCS MNGNT TO HFT g
SOAK COOLDOWN TO EVIEW k TESTING F,32*F/2155 #
130*F/300 #
v (11 DAYS)
(12 HRS) i
APPENDIX A PREGITICAL AND POST GITICAL TEST PROGAMS I.
INTRODU CTION The TEI-1 restart test program has been planned to provide a deliberate, methodical, well planned verification of proper installation and performance of the steam generator joint modifications, to verify conformance with design and licensing bases. Cold and hot precritical testing have been combined with the power escalation program to create a progressive testing program for the 0 5Ga.
Zha pregra inciucas tne :c.'cwing:
Verification of the adequacy of the OTSG Tube Repair Program by pre-service leak testing of individual tubes Verification of the adequacy of the OTSG Ibbe Repair Program by operational leak testing and on-line monitoring throughout the test program Verification of the adequacy of the repaired OTSG tube joint and tubing in service to carry loads under normal operating transient conditions.
Verification of a'cceptable system readiness and plant operation with new and modified plant operating, surveillance, emergency, and abnormal procedures Performance of sufficient modified system / plant steady state and transient operations to provide operator
'craining and familiarization with modified system / plant l
response throughout a range that is likely to be l
experienced during the design life of the plant The scope and chronology of testing planned to meet these goals are discussed below. The test sequence is summarized in Figure A-1.
I II.
Pkf 3ITICAL TESTING Both hot and cold (pre-service) testing will be performed prior to criticality.
The overall objective for the pre-service program is to demonstrate the success of the repair by providing adequate assurance of the post-repair primary to secondary structural and leak tightness integrity of the steam generators.
- 104 -
l l
l
=eo
tasted itelud2 thTh3 spesific post r spairsd factures plug instella 3
itetallations.ticas, tubing kinstic of th3 st and the expansions, eam generators to be loading addition, B&W weld plug and explosi In service.of partial the Westinghouse through wall defectthe testing will
{
A-2. sequence s in tubesshoulateve plug roll The of cold and hot prec i remaining inoperational r tical A.
Pre service Test P tests is shown in Pigure rogram Tests to be conducted prior to he 1
Drip test, whereby at up include the foll the leakage fton tubesecondr y side pressthe primary side
+
e owing:
urized observed in the lowe, and wat method leak ends to 150 psig the tubing expansitests plugs inst l remaining in service the full length ofa led in the l o
r head.
ns, and This 2.
Bubble test, whe u esheet, tubing inches reby the primary side i above the level is lowered and upper tubesheet, sec s drained tube upper tubesheet plugsexpansions, tubing ab pressurized to to 150 psig.ondary side water a few gas bubbles in the uare leakove the lowered wate Kinetic similar plants, thi pper head. tested by visuallr level, and limit of detectabili method is Based on s
(leakage expected experiencey observing Baseline at normal operating pty of about 01 gal /
to have at 3.
eddy ressure day per tubea lower expansion has current and a baseline fonot changedtesting, to temperature).
provide the verify that is discussed in g condition the reater detail in Sectir post-c itical ECT tubing, kine tic post-critical progra of r
\\
B.
and to on III withPrecritical ECT Hot m.
Tes ting the The initial period OTSC testing.
of hot on the threshold ofwhich will stress the OTesting l
to include transievoted solely TSG tubes s gned cracks further. Large defects, ifpropagation,r open prio up any cracks r to en ts addition, c itical operation by l o
r open up any undetectedwhich are simulate the testing sequ eakage,moni toring.then be detected any will most of the failurecracking initiated the ence conditions in whichand subsequent cooldo same In This that the OTSGmechanism will not testing sequencesequence will give original wn will
\\
month.
reactivate.
confidence that will take It is approximately onea ticipated n
ij
- 105 -
s
-e er w m,
p 4Mwns ww-n % v
++h ee e.-w
,-.e--g,r-----
,y-a
,e, n
When the steam generator hot functional test sequence is complete, a management review of the results will be conducted.
If the resulta are satisfactory, the plant will Proceed with the normal precritical hot functional program.
and subsequently with critical operation.
l The following tests will be performed as part of the OTSG hot functional test sequence.
I 1.
Normal Heatup l
The RG temperature and pressure will be raised to 532*F and 21554 in accordance with normal operating procedure.
2.
Operational Imak Test i
This test is required by technical specifications whenever work has been performed in the reactor coolant system.
The pressure in the primary system will be raised to approximately 2285#, creating a differential pressure between the primary and secondary of approximately 14004 (maximum normal operating differential pressure). This is expected to be the maximum differential pressure experienced by the repaired tubes.
l 3.
First Thermal Soak
}
Conditions will be allowed to equilibrate at 532*F and 21554 for approximately one week, to provide baseline leakage data and to allow monitor of leakage for trends.
4.
Normal Cooldewn Transient A controlled cooldown will be conducted according to normal procedure, at approximately 60*F/hr for approxi-mately three hours to 350*F.
Ibbe to shell delta T will j
be monitored to determine the stresses placed on the tube. 14akage will be monitored throughout the transient.
5.
Second Thermal Soak The RCS temperature and pressure will be returned to 532*F i and 2155#, and held there for eleven days. 14akage data i
vill be obtained for comparison with the earlier thermal f
soak, and to monitor for developing trends.
l 6.
Accelerated Cooldown l
A controlled cooldown using emergency feedwater will be
[
conducted at close to the maximum rate permitted by I
i i.
- 106 -
l l
i
=
.m.
technical specifications, at approximately 90*F/hr for approximately two hours. This transient is expected to apply greater loads to the repaired tubes than the earlier cooldown. Tube to shell delta T will be monitored to
~
determine ~ stresses.
14akage will be monitored throughout the transient.
7.
Third Thersal Soak The RCS temperature and pressure will be returned to 532*F and 21554, and held there for appro:.imately eleven days.
Leakage data will be obtained for comparison with the earlier thermal soaks, and to monitor for trending.
8.
Normal Plant Cooldown The plant will be cooled down to 130*F at 90*/hr or the maximum rate possible using normal feedwater if 90*F/hr is not attainable. The plant will be maintained at 300#,
130*F pending management review of the OTSG hot functional results.
9.
Flow Rate Testing Because tubes will be plugged during the repair process, the RCS flow rate must be measured af ter repair to verify compliance with technical specifiestion. This test will be performed when the plant is at normal operating temperature and pressure.
III.
POST-OLITICAL PLANT TESTING The deliberate, methodical approach to testing will be maintained throughout the power ascension program. The normal program has been lengtheced to permit ample time for leakage monitoring and trending, as well as for familiarization with plant performance following the modification. Af ter the power escalation program is complete, and again at the next refueling outage, special inservice inspection programs will be conducted to look for the effects of operation af ter the repair on tubing and components.
A.
Power Escalation Testing Power escalation testing is expected to serve two purposes in testing the steam generators. First, the slow progression from power level to power level will perait monitoring of possibly changing plant conditions such as leakage. Se cond,
several of the tests already planned for start-up testing will apply loads to the steam generator tubes. leakage monitoring before and af ter the transients will provide information on the condition of joints and tubing.
- 107 -
q The power escalation program is discussed chronclogically below. Transient tests of interest are noted for each power level.
1.
Iower power Testing Following hot functional testing and initial criticality, the normal plant zero power test will be conducted. After this approximately one week program, low power natural l
circulation' testing will be performed.
l i
This test verifies the tuning of the Integrated Control l
System (ICS) to maintain presec OTSG 1evels under loss of l
main feedwater and natural circulation conditions.
It also verifies proper response of tne EFW system as weil as the establishment and maintenance of natural circulation under varying conditions. Testing will be conducted at f
approximately 3% of rated thermal power to simulate the j
decay heat load that would correspond to significant core f
burnup. EFW initiation is expected to stress the 0TSG i
tubes. This test will also verify that plugged tubes have no effect on establishing natural circulation flow.
s A management review will be conducted following natural circulation testing. Satisfactory OTSG and plant performance will be necessary to increase power.
l 2.
Operation at Less Than 50% power l
Power escalstion testing will be conducted for several days each at 15%, 25%, and 40-48% power. The 40-48%
plateau testing will include a loss of feedvater test.
At a power level of approximately 40-48%, both main feedvater,
pumps will be tripped. All three emergency feedwater i
I pumps will start automatically and OTSG level vill be controlled at 30 inches +2 in. - 10 in, by emergency feed-water. The use of EFW will cool and stress the OTSG tubes.
The RCS Overcooling Control test will demonstrate that the control room operator can properly throttle EFW flow to prevent overcooling of the RCS following a loss of RCP's with OTSG 1evel initially at 30" on the startup range.
The effects of this transient and of operation to date will be monitored during a one month soak at approximately 48% power. The power level was selected as the minimum permitting two main feed pump operation.
Some operator training will also be conducted during the soak. Prior to increasing power, another management review will be held to evaluate test results and plant performance during the s osk.
- 108 -
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--w
+ - w e -w e
--w-e-m--,
m
-g-%-
,-,-----*t,ec*v-y e +'
V, v---r-e-
-,e 1
e+
s-
g 3.
Power Escalation to 1001 Power Testing at 75% and 100% power will conclude the power escalation program. The 75% plateau will include approximately five days of testing followed by another one month soak to observe plant performance. Power will then be increased to 100% power for approximately one week of testing.
Testing of interest at this plateau include the 100% turbine-generator trip.
A management review of plant performance will then be conducted before the plant procedes with normal power i
operation.
l 1
3.
Eddy Current Tes ting Either 90 calendar days after reaching full power, or 120 l
calendar days af ter exceeding 50% power, the plant will be i
l shutdown for the performance of eddy current testing. Te s t results will be compared with a baseline taken prior to restart to verify the lack of defect propagation during normal operation. The baseline, 90 day, and next refueling ECT examinations are discussed in detail in Raference 56 and summarized in Table A-1.
Testing listed for the preservice baseline will be performed af ter repairs are complete to provide evidence that no changes have occurred since the 1982 100% record inspection. Any new or changed ECT indications found in the three inspections will be evaluated.
If evaluation shows th,ey are unacceptable, they will be treated as new defects with subsequent actions taken as required by Technical Specifications.
I l
- 109 -
. - - ~. ~
m
Table A-1 i
Post Repair ECT Inspection Summary l
90 F.P. Days Cycle 6 Pre-Service Inspectibn Inspection Refueling Outage Remarks l
SCOPE l
1(a) All tubes 40%
(i) 0.540" S.D.H.C.
Repeated Repea ted j
l i
T.W. below the Full Length qual. length (ii) 8 x 1 to confirm S.D.
j in both OTSC's Ind. E circumferential extent 1(b) All adjacent tubes
- Wear baseline exam. in Repeated Repeated
- Use ECT technique proven by laboratory testing to to 10 selected area of interest. (Using be adequate for wear exam.
plugged unsta-ECT probe demonstrated bilized tubes adequate for wear examina-with defect tion in area near defect.)
in 15th, 10th &
let spans (10/Ea, OTSG)
C 1(c) All adjacent tubes
- Examine for O.D. wear Repeated Repeated
- Use ECT technique proven by laboratory testing to to 10 selected baseline in the 16th span be adequate for wear exam.
plugged unsts-(Using ECT probe demon-bilized tubes strated adequate for per each wear examination in area OTSG in the near defect.)
periphery 1
j 1(d) All tubes had 8x 1 absolute for 6" Q.L.
Repeated Repeated i
new indications l
in the 6" qual.
l length 1(e) 50 tubes in the 0.540" S.D. high gain in-Repeated Repeated high plugging spection for full length 1
density area i
per each OTSC l
l y
Table A-1 (Cont'd)r Post Repair ECT Inspection Summary l
90 F.P. Days Cycle 6 Pre-Service Inspection Inspection Refueling Outage Remarks SCOPE 1(f) 3% of tubes in 8 x 1 examination in UTS Repeated TBD
- l addition to 1(d)
[(
in each OTSG from top of 6" qual.
l length to lower I
surface of UTS 1(g) All adjacent tubes
- Wear baseline examination Repeated Repeated
- Use ECT technique proven by laboratory testing to to 5 plugged at same elevation as defect be adequate for wear exam.
tubes per each indication in the plugged OTSG with 3V tube indications in Inwer part of OTSC's a
p2 3% of tubes re-0.540" S.D. high gain Repeated Repeated maining in full length inspection service per each See Note 1.
OTSG in addition to above 1(a),
(b), (c), (d),
(e) & (g)
By doing pre-service eFamination in abJve Categories 1(a) s 1(e), if no new defe.. or no indication of defect growth f rom previous 0.540" high gain data, such data obtained in 1982 may be cos,.idered representing condi-Note 1:
tions after expansion. No need to perform item (2) for the preservice baseline.
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1,*.,..,.
APPENDIX B Responses to NAC Questions on TR-008
- 1. Clarl fy your position on removal of sul fur from oxide films in the RCS. If you intend to perform a sulfur removal process, provide inf ormation which wiii demonstrate its safety and effectiveness.
If sulfur removal is not planned, provide information to demonstrate that future corrosion will not occur as a cersequence of exide-bcund sulfur.
Response
GPUN plans to remove sulfur from oxide films in the RCS using a hydrogen peroxide chemical cleaning process. A separate saf ety evaluation on chemical cleaning (Topical Report 010) has been supplied to the NRC.
2.
On page 10, (e) you state that reduced sulf ur is-directly responsible for the cracking mechanism. On page 7, five sources of sul f ur intrusion are Iisted, three of which were sodium Thiosul fate.
What i s the most probable source of sul ur contamination that resulted in the observed corrosion? What specific steps have been taken to prevent re-introduction of sulfur? Make available for review those administrative procedures which address prevention of the impurity ingress to the RCS.
Response
As stated on page 8, sodium thiosul f ate at levels of 4-5 ppm is considered to be most likely contaminant. Injection of leakage from the sedium thlosul f ate tank during reactor building spray system testing in May 1981 1s the most probable source of the contamination.
The following steps have been taken to prevent reintroduction of sulfur or to identify sul fur if it were reintroduced.
The largest potential source f or sul fur introduction, the sodium thiosul f ate a.tank, has been drained and removed from service by cutting and blanking the supply line from the tank.
- b. The breakers for chemical addition pumps CA-P-2, 3 and 4 are on the Locked Valve and Component List (Operating Precedure 1104-478).
- c. An lon chromatograph has been purchased and procedures are being implemented
~
for sul f ate analysis.
- d. Bulk Chemical Specifications are being written to control ingress of contamination.
Coples of the administrative procedures to control chemical contamination will be in place and available for review prior to restart.
3.
On page 18 it is stated that cracking found in the waste gas system is unrelated to the OTSG f ailure mechanism.
It is our understanding tnat sulfur n,
e-.-,,.r-w.,-
t
~
was defined as the corrosive species in the waste gas system.
If sulf ur is the
. corrosive species in the waste gas system, why is it not related to the OTSG fa..ure mechanism? Additionally, what are the results from the inspections of supporting systems (LER 82-02).
Res'ponse:
Fallure of piping in the waste' gas system has been characterized as IGSCC in the
~
weld heat-af fected zones (HAZ) at the 3045S socket weld connections.
Analyses of the corrosion products have confirmed that the HAZ's are sensitized and that the primary contaminant is sulfur, predominantly in the form of iron pyrite.
Pitting and general corrosion have also been identified in the PORVs put in service in Februe-v 1979 and Juiv 1981. Sul fur has been found in both valves.
These components, unlike tne s eam generarcrs, ccn7a.n ca. y p23:. 2 s u.cc,
and theref ore the transport of sulfur to the corrosion site is not via an aqueous medium, it can be postulated, theref ore, that a gaseous transport mechanism was operative and corrosion was not the result of direct contact with thlosulf ata contaminated RCS coolant as was the case with the steam generator tubes. It is logical to assume, however, that thiosulf ate did play a role in the corrosion by providing a potential source of the production of sulfur bearing gases.
Further work to identify gaseous transport mechanism for sulfur is underway and should provide insight to a possible corrosion scenario for the waste gas system and PORVs. When this work is completed, GPUN will then be better able to assess the relationships among the failure locations.
4.
Provide Information on the status of the RS spray system sodlum thiosulf ate tank (page 27). Has the tank been physically removed from the system?
If not, what measures have been taken to ensure that all sodium thiosuf ate has been removed from the tank and its connecting lines.
Response
Piping which connected the sodium thiosul f ate tank with the RB Spray System has been cut and blanked.
are in 5.
On page 24 ref erence is made to corrosion test programs which progress and will lead the actual GTSG by a minimum of 4 months.
In the event these tests indicate progression or initiat*on of corrosion; how will this Information be factored into plant operations.
Provide a schedule for completion of these tests and when the results will be supplied to the NRC.
Response
The long term corrosion test program will undoubtedly lead plant operation by a minimum of six months. Should corrosion damage be observed on the tube samples during this test program, a more than adequate time margin exists for evaluating this damage prior to the steam generator tubes reaching the same operating time.
If the evaluation of the damage shows it to be relevant to plant expe lence, corrective actions will be taken. Tests results will be made available to the project manager and the resident inspector on a quarterly basis, if results indicate severe or rapidly propagating corrosion, notification will be given in a more timely manner.
m
~
In the event the corrosion observed is severe and/or rapidly propagating, the plant would be shut down untt i such a time that the corrosion problem can be Evidence of mincr attack such as assessed and appropriate actions defined. IGA would be trended, potentially leading to plant s pitting or shallow for additional'NDE.
Prior to this, howev e r, the need for chemistry or operational changes would be evaluated and implemented as necessary.
In either event the long term corrosion test program will be an integral part of the decision-making on plant operation with data from this program being updated examination of the tube specimens and every 66 days via eddy current metallographic examination of C-rings.
- n.. : -- ---
7: :--; "-
GFLN willi prov ice copies er a sar 6r y ;.:..r> ;.if severe and/or rapicly propagation manager and to the resident inspector, corrosion is observed in the test specimens, the NRC will be informed in a more expeditious mannar.
On page 27 it is stated that sulf ate analysis will be performed monthly in is the justification for a monthly analysis on a species which 6.
the RCS.
What can be so potentially harmful? What will be the frequency of testing for sulfur testing periods when one or and ph-conductivity balance during all pre-criticial more reactor coolant pumps are running?
Response
I the Chemistry to the submittal of Topical Report 008, Rev.
Subsequent Specification was revised and sulfate analysis will be performed daily on a RCS sample. Topical Report 003, Rev. 2 reflects this change.
During precritical testing periods, sul fur analysis will be performed daily and times per week.
pH conductivity balances will be performed five (5)
Interest tubes) will be It is our understanding that a 35 ECT (plus special Additionally, on page 65 it is stated that a 7.conducted subsequent to repairs.
second ECT will be performed following 90 days of full power operation. What are interest the criteria for selecting the inspection pattern and the special tubes?
it is our position that the inspection pattern should utilize both the 8 x 1 and in the free span
.540 probes and include all tubes with Indications (ID or 00)
(below US + 8) plus a statistically significant sampling of unplugged peripheral Further, the post critical ECT tubes which are adjacent to block plugged zones.
should be conducted either 90 days after reaching full power operaticn or 120 l
, days af ter exceeding 50% power, whichever comes first.
l
Response
The criteria for tube selection in tNa baseline ECT, 90 day testing, and testing at the first refueling are discussed in Appendix A, Section l1.8 of Topical Report 008, Rev. 2.
Subsequent to initial expansion a number (-12) of new indications were
/. M ass the effect 8.reported within the 6-inch qualificaticn zone on some tubes.
I B
current signal was noted and no ductile growth was found during metallurgical evaluation of these samples.
These results are consistent with crack growth studies done earIler which examined expanded cracks metallographical1y, but not with eddy current, and fot i no ductile tearing.
Conc urr'ent l y, in order to further characterize these new eddy current Indications, fiberscope examinations were conducted on 4 tubes in OTSG B and 2 tubes in OTSG A.
The fiberscope examinations concentrated on the new eddy current Indications, but al so incl uded other locations within those tubes if visual indications of interest were noted. Table 3 summarizes the results of the visual Inspection of these four tubes. An estimate of the circumferential and axial size of the visual Indication seen is also provided, based on video tape r e cc'-d s. As a rest !? Of
- .e 'i bersecte exa-I n ?+'en. it *es cere? uded **T f 0r 4 of the 6 Tutes examinec Tne new eccy current incica71cns resu T Trem e:Taer small pits or mechanical scratches.
For the remaning 2 tubes, no visible indications were found. The mechanical scratchs may have been caused by the wire brush used to clean tubes selected for the in-process testing immediately af ter expansion, to allow the insertion of the eddy current probe.
It was then undertaken to check the correlation of the ECT sensitivity curves with the indcations visible via the fiberscope.
These indication sizes were compared with eddy current sensitivity curves developed used ID notch specimens and samples of laboratory-Induced IGSAC.
Curve development is discussed in greater detall in Section IX.B of Topical Report 008, Rev. 2. Various curves were developed for the.540" dif f erential and the 8x1 abosolute probes within the tubesheet and in the freespan. The sensitivity curves are shown in Figure 1.
It was determined that background noise in the tubesheet resulted in a reduction fo sensitivity for the.540" probe, but not for the 8xl. The pit size estimates shown in Table 3 are at or below the threshold for.540" probe detectabillity in the tubesheet. They are in the lower range of detectability of the Sxt probe.
It remained to ascertain the impact of small pits or cracks below ECT sensitivity thresholds within the expanded zone considering both load carrying and leak tightness.Section IX of Topical Report 008, Rev. 2 documents extensive work done to evaluate the maximum size crack which can be left in service for the lif e of the plant and not cause tube f ailure under normal or accident tube loadings.
Acceptable circumf erential extent vs. throughwall depth curves for various loading and analysis conditions in the free span are shown in Figure IX.3 of Topical Report 008, Rev. 2.
The pits / indications found in the area of the joint are smaller than the crack size leading to f ailure by any mechanical means in the free span.
These curves are conservative for Indications in the joint since loads imposed on the tubes are transmitted to the tubesheet in the area of the expansion. Loads on tubing in the area of the defects will be equal to or less than those analyzed for the freespan.
Leakage through any small def ects which are 100% throughwall is also expected to be less than or equal to
'similar cracks in the freespan. IJnacceptable leakage will be identified during precritical testing and the tube will be either plugged or repaired. For these reasons, it is concluded that small pits or undetected cracks in the quellfled area do not af fect the reliability of the new joint.
It is expected that additloaal indications will be identified during the basellne 8x1 eddy current examination of the expanded region to be conducted following kinetic expansion. These indications will be re-examined during the 90-day' ECT and evaluated to confirm the conclusion that they are acceptable.
. _a _
of these Indications on reliability of the qualification zone.
Assuming additional Indications or defects are found in the qualification zone during the post repair ECT, how will they be handled?
i
Response
Eddy current examination using tre absolute (8x1) probe was conducted for the first lot of kinetically expanded tubes in both steam generators. The scope of this examination included 151 tubes in OTSG B-and 284 tubes in OTSG A.
The eddy current data was analyzed from the top of the 6" qualification length for kinetic expansion down through the bottom of the upper tubesheet. As a result of this data evaluation, 9 tubes in OTSG B and 6 tubes in OTSG A were reported as having indications which had not previously been detected by the.540" OD nign-gain stancar: c:rrers.--
2.
- .
- :a
.44.
...i.-
u--
generators.
The 8x1 absolute probe haa been chosen for this in-process monitoring in the newly expanded area because the coining process of the expansion created so much background noise that the.540" standard dif f erential probe was not useful following kinetic expansion.
The 8xl absolute probe provides 360* coverage. A judgment concerning defect arc
' length can be made depending on how many coils of the 8x1 probe detect an Indication.
1.aboratory testing has shown that a 1 coil indication can have an are length of 5' to 40*, a 2-coli indication has an arc length up to 85*, and a 3 coil Indication has an are length up to 130*.
Although the 8x1 absolute probe can be used to quantify the circumferential extent of a particuIar indication, it cannot be used to accurately determine the percent thru-wall of the indication.
The first post expansion eddy current examination was conducted in 151 tubes of l
OTSG B.
Table 1 documents the characteristics of the eddy current signal from those 9 Indications found which-had not previously been seen by the.540" standard differential probe. No previous 8x1 data existed for the tubes within which the defect Indications w'ere found, and therefore, it could not be determined whether the Indications existed prior to expansion or had been caused i
by kinetic expansion.
In an of fort to better understand this issue, an 8x1 i
absolute probe baseline examination was conducted on the 284 tubes in the first lot of kinetic expansion in OTSG A prior to expasion.
As a result of this examination, three Indications were identified which had not previously been l
detected by.540" di f f erential probe. Following kinetic expansion, these tubes l
were again examined and evaluated from the top of the 6" long qualification zone j
through the bottom of the upper tubesheet.
During this second examination, u on Table 2.
Table 2 three additional Indications were reported, shown by an summarizes the location and signal charateristics of the Indications found in OTSG A.
- Investigations were made to consider several possible explanations for the new Indications. Additional laboratory testing was undertaken to determine whether or' not the kinetic expansion process was causing small cracks to open slightly, l
thus increasing their signal voltage.
it was postulated that Indications which were previously below the threshold sensitivity might become detectable subsequent to kinetic expansion.
The testing involved placing l abor atory-i nd uced intergranular cracks and TMI-1 tube samples with cracks l
Inside mockup tubesheets and expanding over them.
8x1 examinations were l
conducted prior to and af ter kinetic expansion. No significant change in eddy l
M
OTSG B OTSG Post-Expansion Eddy Current Absolute (Px1) Results 2 2 h ::::.2 151 tubes kinetically expanded and E/C examined. Nine (9) tubes were reported by 8x1 as having indications not seen by
.540 S.D.
Results ABSOLUTE NOISE LEVEL S.D.
Row / Tube location Coil Volts Distortion 400 Base Mix 4-19 US+11 1
.5 1
2V
.6V 4-30 US+12.9 2
2 2
3-27 US + 9.4 3
6 2
2V
.6V 3-25 US + 10.7 1
1 1
2V
.6V 3-24 US + 12.6 2
2 2
2V
.6V 3-21 US+10 1
1 1
2V
.6V 2-21 US+ 13.1 1
1 1
2V
.6V 2-22 US+ 13.2 4
1 (MULTIPLE) 2 1.8V
.5V
'2-25 US+0
1 1
1 1.5V
.5V I
- New Kinetic Transition l
Table 1
l l
l l
I l
OTSG A OTSG Post-Expansion Eddy Current Absolute (8x1) Results 2ackpourd 284 tubes kinetically expui and E/C examined before and after expansion. Gix (6) tubes were reported by 8x1 as having indications not seen by.540 S.D.
Results
- ALsolute -
- Level of Noise S.O. -
Row / Tube Location Coil Volts Distortion 400 Base Mix AFTER EXPANSION 2-12 Not expanded
.8V
.4V 6-43 US+4 1
1 1
.8V
.2V 7-54 US+1 TO 1
1 (MULTIPLE) 1
.6V
.3 V US + 10.7 4-4 U S + 9.1 1
<1 1
2V IV 4-32 US + 11.9 1
.5 1
1.8V 1V 2-7 U S + 6.3 1
.5 1
1.2V
.4V BEFORE EXPANSION
\\
- 2-12 US-3 TO 1
<1 (MULTIPLE) 1 i
US+7 3
<.5 1
- 6 43 US+4 1
<1 1
(
'7-54 US-8 TO 1
<1 (MULTIPLE) 1 l
US+13
'8x1 Reported 3 tubes as having indications before expansion
~
l Table 2
i i
1 i
...._.-,.--.m.
e
i OTSG Post-Expansion Eddy Current Fiberscope Examination Summary VISUAL SIZE (in.)
ECT OTSG ROW TUBE INDICATION LOCAT10N CIRC AXIAL COILS VOLTS B
3 24 Line of Pits US+13
.01
.02 2
2 8
2 22 Area of Pits US+13
.01
.06 4
2 B
3 27 Area of Pits US+10
.01
.03 3
6 B
2 25 Scratch US+7
>.05 1
1 A
4 32 No visible U S + 11.9 1
<1 indications A
2 7
No visible U S + 6.3 1
<1 indications l
l l
Table 3
O e
--.,-,,,,.,m-,w
._,,-..see ye... - - _. - -
FIGURE 1 M ETALLURGIC AL CONFlRM ATION OF ECT SENSITIVITY FOR IGSAC f
Metallurgical
}
360*
1.7 5"
,y..,1 JJJij',;
Confirmation
.z...,
. ~. -
^ - = 2 '-
Yi+5!!!,
Tubes pulled
!?
^
1 i
31::?
h;if
~i' O Laboratorv iaduced 300*
1.46" m.
i- -
IGS AC detected E
26i '
il!!ji iiiyiii O Laboratory induced M!,. ' : :'!!!
IGSAC not detected is 240*
1.17" i{
- nj!
g i;
i
=f
-- Tested boundaries of j
igg:
E/C detection 1.0 "
in jii
~-
Projected E
180*
875"
..u..
., ""C"f"ie'"ld o f.
,iij
'iidetectabilit.yji.
ii!Q boundaries of E/
.; N.....?
g 0..
~
I!
O z;.
1;:i:
E/C detection d
&_;N$!.!!.
W i
W;.. Ae.!.!!.
120'
.58"
- 3:
.,w
- i. - :W::.
i gain 60 i:i{_a
.5 @
u fill factor 94%
g:iggyjy*jii Undefined boundaries g:.
. -z::...i:!'"ni:i
- !:'"^
l i,
...v::.
- a w:.:,4;M<:.;y::..*( M ii: :.,
u...u.
60*
.30"
- .:..~.:.:
.:<u...
i:!Q
- .g:i::
- i:
- i:
- s:::
- 22:: '. i:::.
"Mp;;;;:.. i
"'iGi:::::
'q'i:i!
"w
- e+
- e:
Test standards for
,.18 7,,
l E/C qualification
.100" v..
Notch width (.004") [.060"
,g,
.)c;;;;w;jtsg.;p;.;
10 20 30 40 50 60 7
80 90 10(s
.540
.54 0 Below UTS
% Through Wall in UTS I
D
9.
On page 63 it is stated that flow induced vibratica an-inermal./ cling will not cause crack propagation. Prov i de more detai l ed i n f orma t i on to support that statement. Specifically, address the concerns raised in Cr. McDo n t. : 1 ' s letter of October 23, 1982 (provided to you earlier).
Responses in Section IX.B of Topical Report 008, Rev. 2 summarize; evaluatiens of crack propagation. Greater detail is available in GPUN TDR #388, lube Stress Report, Rev. I which has been supplied to the NRC. Much of the aark reported in tnese documents has been completed since Dr. McLnald's October 23, 1982 letter, and ac; ears to address his c: cer's.
10.
In the tube plugging and stabilization discussion (page $0) there doesn't appear to be a reference to tubes within the 10th scan which is a suspected high cross flow area. What is the plan for tubes with indications or def ects in the 10th span?
Response
The 10th span is a region with some crossflow, but considerably less than the high crossflow of the 16th span. Plans for plugging and s rabilization of the 10th span and for other regions of the OTSG are discussen in Section yll.C of Topical Report 008, Rev. 2.
11.
Figure IX-4 Identified the limit of detectability for tube leakage at.03%
FF as.46 gph. This figure is cited many times in the SER us a basis for being able to detect propagating cracks during precritical test;ng.
Clarify if these limits of detectability apply for pre-critcial testing wher e no noble gases or lodines are present.
Identify what the limit of catectability is for precritical testing if it is not.46 gph.
Response
l The.48 gph limit of detectabliity applies to the precri-lical testing as wel l.
Although this limit was originally set assuming the presence of noble gases and l
lodInes, this Iimit wiii stilI apply in their absence by eroploying a suitaoly long soak time to allow boron concentration to buildup in the steam generator.
12.
What are the adminsitrative limits for primary to so.codary leakage (page 74)? What is the basis of establishing these limits?
How do these leakage I
limits fit into leak before break?
Response
The bases for establishing administrat!ve limits on leakage are summarizec in Topical Report 008, Rev. 2.
Chapter X Final adminsitrative limits can be made available at a later date.
13.
Block plugging of tubes will result in moisture carryover and increase the erosion-corrosion potential for peripheral tubes (#7 above addresses ECT of these tubes). AdditionalIy, moisture carryover wiII increase the potent i aI for erosion of downstream components and piping. Provide an ist program to moni tor
potential erosion due to moisture carryover from the OTSG.
Response
A summary of the potential for moisture carryover erosion of tubes and piping is included in Section Vill.D of Topical Report 008, Rev. 2.
ECT of peripherai tubes is described in Appendix A, Section 11.B, and ISI of the stean system is summarized in Appendix A, Section ll.C.
14.
Provide single and multiple steam generator tube rupture gaidelines for staf f review when they are available. (page 74)
Ras::cr.se :
Tube rupture guidelines hive been suninarized in Topical Report 009, Rev. 2, in A more comp ete discussion will be available at a later date.
Section X. B.
l 15.
Prov ide additional information on the calculations and test data (page 44) which are used to demonstrate that the instantaneous stresses from tne kinetic expansion process are structurally acceptable.
Response
Additional information on the calcu-lations was included in tne Kinetic Expansion Technical Report, GPUN-TDR-007, dated November 1982, which has been sJpp l l ed to-the NRC.
16.
Chapter 7, Table 1 of your "TMI-1 Steam Generetor Repair Safety Evaluation", you provided a breakdown of estimated men-rem desce for OTSG repales from crevice drying through cleanup. The total esiimated dose for OTSG repairs, based on this table was 268 man-rems (327 man-rrs if remote cleaning was not possible).
In the December 10, 1982 letter from P.
C a
.-k, GPU to D.
Eisenhut, NRC, you stated that 322 man-rems had resulted f rem repair activities as of November 30, 1982 rith an additional estimated 700-800 man-rems envisioned to complete the OTSG repairs.
Describe, in detail, why your current man-rem estimated for the OTSG repair is three to four times your original estimate of 268 man-rems.
Response
The exposure estimate upon which Table 1, in Chapter 7 of the TMl-1 Steam Generator Repair Safety Evaluation is based was calculated prior to the start of the kinetic expansion repair.
The estimate included only those items in the steam generator program identi f ied as pa. t of the kinet i c expans ion repai r.
Other portions of the program such as investigation of th.> damage and piagging were not included.
The December 10, 1982 letter from P. R Clark to D. Eisenhut included all aspects of steam generator work not just the kinetic expansion.
The foilowing table shows the steam generator activities that were not included in the kinetic expansion review. The reasons for these activities are discussed in TR-008, Rev. 2.
Approximately one half of the exposure estimate is associated witn these activities. Some tasks have been better defined since the December 10 letter, but the total has not changed significantly. The following table shows
~.. -
Exposure Estimate Ccmparisons Table 1 Current Task Estimate Estimate 12(A) 1.
RCS Inspection 2.
Pre-Repair Tube Work 120(A)
(sampl ing/ stab /pl ugging).
3.
Pre-Repair Testing (bubble /
ficerscopes 1.
35(A) 4 Eddy Current Testing 5.
Kinetic Expansion
- a. Pre Expansion 3ctivities (precoat, crevice dry) 30 16(A)
- b. First expansion 45 168(A)
- c. First pass insert removal 50 132(A)
- d. Second expansion 35 167(A)
- e. Second pass insert / debris removal 55 75(A) 6.
Cleaning
- a. Flush 51 30
- b. Soak 30 125 ( A) 7.
End Milling 8.
Plugging 235
- a. Plugging & Stabilization 75
- b. W rolled plugs 9.
Post Repair Testing
- a. Bubble test 5
5
- b. Drlp test 10
- 10. Post-Repair Inspection 10-40
- a. Tube free path
- b. Final close out inspecticn 2
5-10
[
268 1260 - 1295 i
- Not included in Table 1 Estimate.
(A) Actual Exposure.
Provide a breakdown by job f unction of the currently est imated man-rem 17.
l doses for the OTSG repair (similar to Table 1 in Chapter 7 of your "TMI-1 Steam
~ Generator Repair Saf ety Eval uation").
Include in this tabie; 1) your original does estimates f or each job; 2) the actual doses recorded to date for each job,
- 3) the estimated cbses required for completion of each job.
Yo u shou l d a l so outline the bases f or inclusion of any new job functions which were not listed l
In the original dose estimate table.
See response to item 16 above.
t t
F7 m
current estimates.
As can be seen, items 5, 6 and 10b on the table represent all items in Table 1 of the Kinetic Expansion saf ety eval uation.
For these items, the total has increased from 268 to 623-628 man-rem.
This increase is largely due to the equipment difficulties described in response to Q. 18.
J
[
,o
- 18. Describe the ALARA features incorporated during the OTSG repair program to control occupational doses.
Describe any problem areas encountered (such as equipment breakdown or mal function) during the OTSG repair which resulted in higher than planned personnel doses, and how these problems were resolved.
Response
A detailed' description of planning activities and descriptions of each individual work event are avai l able on site as separate reports.
All preplanning and preparation activities were perf ormed so as to follow the guidelines set forth in Regulatory Guide 8.8.
A summary of major activities is provided below.
A.
Fieio impleme Tar;on ice ine envira u c.er.
es.:nn.:..
3;2.- ;r:ge:.
been preplanned and in all cases procedures have been validated my acekup training and dress rehearsal. Also, where possible, field tests fer major job functions have been performed in a steam generator at B&W's manuf acturing.
works at Mt. Vernon, Indiana. At these f acilities, equipment and tooling has been tested and work techniques practiced for the following:
(1) Kinetic expansion device testing and installation training.
(2) Debris removal equipment testing and procedure development.
(3) Fl ush systen testing.
(d) Tube free path verification testing.
During these tests, full dress mockup training was conducted, tooling co; repts evaluated and verified, and remote equipment operation critiquec and validated. While it is not possible to quanti f y the man-rem saved by this training / testing, the exposure savings is thought to be significant. Further mockup training and eval uation was also per f ormed in the mockup training facilities available on site. This ensured that each worker received training in the job he was to perform prior to actual steam generator entry.
The training / testing also allowed the evaluation of the use of temporary shielding to establish the optimum configurations for use in the generator and enable the evaluation and control of potential air born contamination problems.
B.
Af ter beginning process field implementation, several problem areas were discovered which raised actual exposures above estimates. Specifically in the area of equipment mal function the following were identified and changes made where possible to limit exposure.
(1)
During the performance of the expansion, there were problems mai ntai n ing the video camera in operating condition.
A short study analyzed equipment down time and concluded it was more man-rem ef ficient to spend the extra time prior to and af ter each blast in moving the camera into and out of the generator than it was to perform with the camera in generator repairs. This recormiendation was actsj on.
(2) Debris Removal Device: There were several p oblems associated with
- nitially making the debris removal tool operational and reliable. Much of the exposure received for this task segment is directly associated with q
corrective maintenance required to keep the equipment operational.
All maintenance entries were monitored and documented and the performance i
optimized through the use of briefings and training.
Through the use of tight monitoring controls, exposure for the performance.of corrective maintenance was held to a minimum.
The lessons learned about equipment ' reliability were incorporated into total equipment redesign. The redesigned equipment was used for second pass debris removal with a marked increase in equipment reliability and per formance. The exposure received during first pass debris removal was 132 manrem compared to 75.2 manrem for second pass debris removal.
(3) Misfire Rate: During kinetic expansion, the rate of expansion Inserts was consicerasiy nigner Tnan pre:ic;s: sy ir.e q....: car cn pre;.:. N misfires were caused by production problems in the detonation device, which were corrected, and by seepage of the liquid precoat into the Inserts. The precoat Insulated the detonating cord in the insert from the remainder of the detonation device. Each misfire required identification of the tube, removal of the insert, replacement and redetonation, thus adding to total exposure. Af ter the precoat problem was identified, it was necessary to change the precoat - expansion procedure. The original procedure had an Individual enter the generator, remove insert debris, insert the next row, exit. Precoating was then done remotely, and the tubes were expanded.
Af ter altering the procedure, two entry steps were necessary, with precoating done prior to inserting the candles.
This increased exposure resulting from this procedure change v.as unavoidable since the misfire rate was technically unacceptable.
(4) Misfire Juinp Out: When the first kinctic expansion was performed, the detonating cords attached to the Insects whipped in response to the force of the detonations. During the first pass, the whipping action pulled some inserts which had misfired free of the OTSG tube, adding to exposure.
The j
unexpanded tube could only be Identified by hand measurements of the tube by workers in the OTSG.
This activity was pointless after the first expansion, and thus eliminated in the second expansion. Other actions were taken to prevent jumpers, including the use of hold-down devices, additional debris removal to veri fy that jump-out had not occurred, and additional care in moving about the head area. These changes resulted in j
some increase in the time spent in the generator fer the second expansion.
i I
(5) Debris Removal: Debris that had been evaluated in the qualification program was found to be less manageable in the field. Detonated inserts broke apart during expansion, scattering pieces throughout the generator and forcing other pieces down in the tubes.
In order to work in the confined head area, workers had to continuously take additional time to pick up pieces. These pieces left in the tube were also more dif ficult to remove than the Intact inserts anticipated.
{
The f actors described above resulted in the kinetic expansion exposure increase from 266 man-rem to 541 man-rem.
19.
In Section XI, " Environmental Impacts", of your December 10, 1982 letter, j
you provide a table of projected doses to an Individual from anticipated primary to secondary leaks.
However, this section does not detail the specific 9
l
TABLE 1 PRIMARY COOLANT ACTIVITY CONCE::TRATIONS t
AC*IVITY (3)
NUCLIDE CONCENTRATION,dCi/ml I-131 0.071
- -122 1-135 0.170 Cs-134 0.006 Cs-137 0.004 Cs-138 0.605 Kr-85m 6E-2 to 1.45E-1 Kr-87 1.9E-1 to 4.9E-1 Kr-88 8.6E-2 to 2.6E-1 Xe-133m 1.4E-2 to 4.2E-2 Xe-133 3.81 Xe-135 0.66 B,
7 0.72 (1) Average values for the month of November 1978 with 96.5% of Average Power.
e #
5
_ _ =
e.
TABLE 2 SOURCE TERMS FOR THE MAIN CONDENSER AIR EJECTOR RELEASE RATE (*)
RADIONUCLIDE (uCi/ soc)
I-131 4.50E-3 1-133 1.01E-2 I-135 1.07E-2 Kr-85m 9.00E-1 Kr-87 3.10 Kr-88 1.60 Xe-133m
- 3. 0 E-l i
Xe-133 24.0 Xe-135 3.80
- Based on 0.03: FF and 6 gph of pri: nary-to-secondary leak.
l
.. ::-----,~.-
-. ~... :_..-.
TABLE 3 SOURCE TERMS FROM TURBINE BUILDINC VEMTS AND GLAND STEAM EXHAUST
- Turbine Building Cland Steam Isotopes Vents Exhaust (pC1/sec)
-(nCi/sce) l
- -121
- 5. ;-6
- 7.,;,
I-133 1.9E-5 1.7E-5 I-135
,2.0E-5 1.9E-5 Cs-134
- 1. 3 E-6 l.0E-6
\\
CS-137 8.7E-7 6.8E-7 Cs-138.
8.9E-5 9.0E-5 w
- Based en 0.03*. FF and 6 gph of primary-to-secondary leak.
'i 0
1-e A.
n 4
"C
0 assumptions, parameters, and source terms used in the dose calcul ations.
References 11 and 54 noted in this section may contain this Information. So that we may verify your dose projections, please provide a copy of references 11 and 54 and/or the assumptions, parameters, and sourte terms used in your dose projection calculations.
Respense:
(A) Primary Coolant Data (Table 1)
- The basis of all the radiation release data is the primary coolant (PC) activity concentrations obtained by the TMI-1 plant st af f just prior to last shutdown (November 1978).
In order to relate these activities in Table 1 to the conventional l y-usec term, Tuei failure SFF) rate, Tne cara nas oeen cc.T.paroc with the PC activity data presented in Table 2.3 of NUREG-0017, which assumes 0.12% of FF rate. With this comparison, the PC activity data given in Table 1 is determined to be equivalent to approximaTely 0.03% FF.
(B) Air Ejector Effluent (Table 2) Assumptions 1.
The primary-to-secondary (PS) leak rates are assumed to be: (a) 1 lbm/hr (the repair leak pal), and (b) 6 gph (experience at similar plants).
2.
100% of noble gases leaked to the secondary coolant are released directiy through Air Ejector without decay.
3.
1% of the radiolodines leaked are released through Air Ejector in the form of organic lodine. The NRC-suggested organic lodine release fraction in the NUREG-0017 Is 0.75%.
- 4. Plant capacity factor is assumed to be 80%, which is consistent with the NRC guideline given in NUREG-0017.
(C) Ef fluent from Gland Steam Exhaust (Table 3) Assumotions 1.
Steam in the main steam line leaks to the Gland Steam Exhaust at a rate of 9000 lbm/hr.
l 2.
Partition f actors (PF) used in the analysis are 100 for lodine and 1 for noble gases.
(0) Effluent Through Turbine Buildino Vents (Table 3) Assumptions l
1.
Secondary coolant leaks to Turbine Building (TB) at a rate of 20,000 gal / day (maximum anticipated based en experience).
2.
The secondary coolant leak is assumed to consist of: 99% as water (PF =
100 for lodine) and 1% as steam (PF = 1).
l (E) Liquid Source Term Data for Turbine Building Sumo (Table 4) Assumotions i
1.
Powdex filters decontamination factors (DF):
l OF = 2 f or Cesium i
l l
c
.I TABLE 4 LIQUID SOURCE TCM DATA FCR TURBINF. BUILDING SUMP (l)
CONCENTRATIONS TOTAL Ci( }
(uci/ml)
PER YEAR RADIONUCLIDE
I-1J3 1.07E-7 1.17 E-3 I-135 I.14E-7
- 1. 25 E-3 Cs-134 3.60E-8 3.93 E-4 Cs-137 Gross BY ( )
5.07E-7
- 5. 5 3 E-3 Cs-138 2.55E-6
- 2. 78 E-2,
H-3 1.65E-3
- 1. 81 E+1 (1) Based on 0.03* FF and 6 gph of primary-to-secondary leak.
(2) Gross B,Y activities were connervatively assumed to be Cs-137 for the offsite dose analyses.
(3) Based on 80" of plant capacity factor.
f I
4 t
o
=
1
/
b g
4 g
l 7--,
-se,,y
-.,-e.,---g g
e-
,, ~, -~n-gg -W av P v
+ - - - - ' -
r-'
4
?
l TMM S
!4 l
DILUTION PARAMETERS i
Mean River Wasco Dilucion Far Fiold Flow (cfs)
Factor (cfs)
Dilution Factor 4
i Low Flow 3,200 84.7 37.8 Aversgu Flow 3',410 84.7 406 High Flow 160,000 84.7 1890 O
e 9
l t
S M
TABLE 6 RECEPTOR LOCATIONS AND DISPL"lSION VALUES Distance Direction y /0 (*)
D/O("
$ (mrad) 600m SSE 5.57E-5 Gamma (mrad) 600m SSE 5.75E-3 Nearest Residence 644m E
3.84E-5 Nearest Garden 644m E
1.68E-7 Nearest Milk Animal 1690m E
1.25E-7 Nearest Beef Cattle 4667m SSW 5.80E-9 (a) assumes ground level release 9
d M
TABLE 7 HYPOTHETICAL MAXIMUM INDIVIDUAL OFFSITE DCSE(1) 10CFRSOl OFFSITE DOSE AND FRACTION OF APP.I LIMIT SOCRCC
- 1. 0 --"/IIR l
6 0?n "Q*]
Dose
% of App.
Dose
% of App.
(mrjY#)
(mr/yr)
T timte (mr/yr)
I tiefe 9.22E-2
- 0. 6 4.61 31 15 g,g,,
Nobic Cases Camma 5.48E-2 0.5 2.74 27 10 s
Beta 6.66E-2 0.3 3.33 17 2C Liquid Effluent
- Whole Body 9.76C-4
- 0.1 4.88E-2 1.6 3
(adults)
- Liver 1.46E-3
<< 0.1 7.28E-2 0.7 10 (ceens)
(1) Based on 80% of the plant capacity factor.
w
~
= 10 for all other Isotopes.
2.
TB sump capacity pf 10,000 gallons.
3.
Discharge rate of 10,000 gallons per day (typical anticipated discharge rate).
4.
The TB sump water is transferred to the Industrial Waste Treatment System collection Sump.
This liquid waste is then diluted with the MDCT (Mechanical Draft Cooling Tower) water and d!scharged at a rate of 38,000 gpm to the river.
Dilution parameters u..
In the analysis are given in Table 5.
(F) Rece: tor Locatien anc 0;scersion a.ues.
U :-s;Ts cis; rs.cn iscice s c. 6 calculatec based on grounc level releases and are listed in Table 6.
(G) Hyoothetical Maximum individual Of f-site Dese.
The off-site doses were analyzec by using tne TML Ottsite Dose Calculation Manual (00CM), which is based on guidelines given in the NRC Regulatory Guide 1.109.
The results of the analyses are presented in Table 7, which reflects the most recent evaluation and should replace Table XI-1 of the earlier Safety. Evaluation report.
The major changes in the revised analysis include 80% rather than 100% plant capacity factor and direct release of 1% of radiolodines to the Air Ejector in the form of organic lodine rather than partitioning from the main condensor. Both of these revisions are consistent with NUREG-0017 guidelines.
In addition, a typographical error which reversed the beta and gama contribution f rom the noble gases was corrected.
20.
With ref erence to the cracking observed in the 0-ring examination, state the basis for the contenticn that no stress corrosion cracking was observesd In l
the primary system. Scecifically, cite references which state that if cracking is not Intergranular it cannot be stress corrosion.
1 Resconse:
Defects observed in the reactor vessel 0-ring have been characterized as ductile rupture as Indicated by the dimpled feature of the fracture surf aces, it was noted the Intent of the report to Indicate that a stress corrosion cracking mechanism could not exist In the absence of Intergranular attack but rather that the surface topography of the existing defects was not Indicative of any typical SCC morphology.
Metallography revealed that the Indications observed on the surf ace were very shal low (.001".002") and that when opened by bending revealed only ductile
, rupture.
These def ects were most likely due to deformation of the 0-ring near
the seating surf aces.
21.
With reference to the Ultrasonic Testing of bolting, state the sensitivity of this inspection method (i.e., the defect size in the mockup). Further show that calculations assuming this defect size for all bolts will provide adequate margin and conformance with design codes.
Response
i There was no in-place standard for UT examination of bolts from the head of the bolt.
A test program was developed which would detect a small Indication wit ho ut ambiguity.
The sensitivity of ultrasonic testing of bolting is dependent in part on the size of the bolt and the depth of the threads.
In some cases, defect depths of 10% of the bolt diameter are detectable. Where threads are deeper, 20% is the maximum detectable def ect depth.
The " worst case" condit' on is the core. barrel assembly bolts, which hate a 20% detectaDility limit and are highly loaded. These inconel X-750 bolts had a preload of 24 to 30 KS1 at Installation, and were exposed to sulfur in solution with the j
remainder of the RCS.
It was concluded that at least one of the ninety-eight bolts Inspected would be expected to exhibit detectable damage if the bot ting were in an enviornment conducive to stress corrosion cracking. tb damage was sae..
75'.s ts:t n: :g: M s"m' t " =" t - ' - e ' - - " - = " ' ' d ~- t-
'-ct.
e l ".
were al so inconel X-750, were subject to a similar environment, anc nigner stress level s (100 KSI). The presence of a rejectable indication would have resulted in f urther examinations.
A varlety of non destructive and destructive techniques were used in the RCS Inspection, and a variety of dif ferent materials were sampled. tb portion of the program was intended to a be a rigorous requalification of a specific item.
Instead, the program as a whole was planned to generate a large data base to assess possible areas or types of damage in the remainder of the RCS. All tests were negative.
- 22. What is the 100% RCS design flow rate (p. 53).
Response
The original design flow rate used for analysis in the pre-operation TMI-1 FSAR was defined as 100% RCS design flow rate.
Testing at TMI-1 showed that as-built flow was significantly greater than 100".
design flow. After allowance was made for instrument error, etc., the minimum actual RCS flow rate was found to be 106.5% of the original design flow.
Based on the measured flow, DNBR calculations were redone using 106.5% design flow.
Other calculations were left unchanged. Current technical specification limits on flow are based on 106.5% of the original design flow rate.
l
[
l I
i
C.
Steam Fittings ISI Program GPUNC will inspect the main steam line fittings at TMI-I for potential water dropist erosion. The following criteria were used (in descending order of erosion probability) to select monitoring data points.
1 - Fittings close or adjacent to the OTSG 2 - Fittings of 90' configuration 3 - Fittings from the "A" steam generator Since there are more tubes plugged in the "A" OTSC than the "B",
the "A" steam lines will have a higher probability of erosion.
Therefore. inseections vill be made of steam lines from the A OTSG. Based on the above tne following II;c.c.5s.... Ja inspected before start-up and at the next refueling outage following restart.
Table A-2 Steam Line Fittings Inspection "A" OTSG Item Qty.
Description 1
2 First 45' Ells after OTSG exit This inspection will be done using ultrasonic testing techniques for measuring pipe (fitting) wall thickness according to an adaptation of ASTM E 797-81 " Standard Practice for Measuring Thickness by Manual Ultrasonic Pulse - Echo Contact Method."
The ultrasonic data density (number of data points) of the pipe wall surface will correspond closely to that already done on the turbine extraction piping at TMI-I.
Feture inspection frequency and scope will be determined after the results of the next refueling outage's inspection have been evaluated.
- 112 -
^
REPERENCES (1)
OTSG Repair Safety Evaluati (2)
TMI-1 OTSG Failure Analysi on Report, Aug. 1982.
(3) Final Report on Tailure A s Report, July 1982.
5 of Three Mile Island U i nalysis Laboratories.
- 1. June 30, 1982.-of Inconcel 600 T nt (4)
' Final Report:
Battell A and B&W #RDD:
Evaluation of e - Columbus 83:5390-03:01.
Tube Samples from TMI-1 (5)
Technical Specification f
, July 7, 1982; and Stabilizers SP-1101-12 03or OTSG Tube Plugg (6) 0.
Nuclear Safety /Environm keicec Caps Using B&W Welded cap with Sental Impact Evaluation (7) tabilizer.
OTSG Tube Plugging Phase I S r OTSG Tube Plugging (8)
P-1101-12-029.
Corrosion Testing, RevGPUN Specification SP-11 008.
R. C. Newman OTSG Tube Repair-Long Te 1.
(9) rm in Low Temper,ature Aet. al. " Evaluation of S Bureau of Standards,queous Solutions."CC Test Methods for I I
NUREG 0565, " Generic EvalGaithersburg, Maryland l
(10) nconel 600 April 26-28, 1982.
Accident Behavior of B&W Duation of small 1980.
esigned 177FA Operating Plaof-Coolan t (11)
MPR Report, "TMI-1 OTSC P i January nts."
1982.
r mary-to-Secondary Leakage "
(12)
NUREG-0017. " Calculation September 13, f
Gaseous & Liquid Effluent fof Release of Radioactive I
(13) rom PWR," April 1976.
erials in TMI-1 Plant Technical Sp ecifications.
(14)
EPRI NP-2146 Topica TMI-2 OTSC Tubes." l Report Dec.1981 ASME Section XI,1980 Edi i
" Static Strain Analysi (15) s of (16) t on.
Westinghouse Electric C Generator Tube Rolled Plorporation Report WCAP-10084 (17) GPUN TDR #388 Mechanical Iug Qualification Test Repo t, TMI-1 Steam r, April, 1982.
\\
(18)
GPUN Spec SP-1101-22-006 ntegrity Analysis of TMI-1 OT
, Rev. 5.
SG Tubes.
l
- 113 -
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REFERENCES - (Contd. )
(19) GPUN SP-1101-22-009 OTSG Kinetic Tube Expansion Process Monitoring and 5 Inspection, Rev. 5.
(20) Three Mile Island-1 OTSG hbing Eddy Current Program Qualification.
October, 1982. -Draft (21) GPUN 2R 343 RG Inspection, 6/14/82.
(22)
J. D. Jones, OTSC Failure Analysis Operational History Final Report, CPUN ER #336 May 12,1982.
t (23) Three Mile Is Aand Jn-t.
.a a.'..r.:usc. c.:...: 24 r.e r 2:. :.'- ; ;. _
Expansion Technical Report - GPUN-TDR-007 Rev.1. March 196 3.
( 24)
J. C. Griess and J. H. DeVan, Oak Ridge National laboratory, The Behavior of Inconel 600 in Sulfur Contaminated Boric Acid Solutions,
Se ptember 29, 1982.
I (25) GPUN Topical Report 010, TMI-1 OTSG Adequacy of hbe Plugging and Stabilizing Repair Criteria.
(26) GPUN ER #368 Primary to Secondary Imak and Imak Race Detetuination Methods.
(27)
J. V. Monter, "TMI-1 OTSC Test Results - Interim Report," B&W Report
- 543301-01, July 13, 1982.
(28) GPUN ER #359 Evaluation Criteria for a Primary to Secondary 14ak.
(29) GPUN SP-1101-22-007, Rev. 2, Short Term Corrosion Testing (30) Stress Report for OT36 Stabilizer Weld Cap, B&W 33-0231-00 (31) Welded Taper Plug Stress Report, B&W 1002581C-02 (32) Stress Report for HK-1, B&W 32-1127439-00 (33) Stress Report for MK-3, B&W 32-1127439-01 (34) OTSG Stabilizer Design Review, B&W 80-0150-00 (35) B&W Position paper on Use of hbe Stabilizers in IMI-10 S6, B&W 51-1132-602-00 (36) CHATA-Core Hydraulics and Thermal Analysis-Revision 4, BAW-230, Rev. 4, Babcock & Wilcox, June 1979.
(37) CIPP-CHATA Input Processing System (38) TDtP-Thermal Enthalpy Mixing Program, B AW-321, Rev. 2, Babcock &
Wilcox, June 1979
- 114 -
m
m REFERENCES - (Contd.)
(39) B&W Document No. 32-1135 309-00, " Pump Code Certification for Oconee II" by D. J. Halteman, July 1982.
(40) NUREC 0565, " Generic Evaluation of Small Break Loss-of-Coolant Accident Behavior of B&W Designed 177FA Operating Plants." January 1980.
(41) Topical Report BAW 10092P Rev. 3, October 1982.
(42) BAW-177 " Preliminary Calculations of the Ef fect of Plugged Steam Generator Tubes on Plant Performance" March 1482.
(43) RE1RAN-02, EPRI NP1850 CCM, May, 1981.
(44) Transient Model of Steam Generator Units in Nuclear Power Plants -
TRANSG-01 EPRI NP-1368 March 1980.
(45) Requests for Information on Steam Generator Feedwater Addition Events Letter from Thomas Cox of USNRC to J. M. Taylor, (B&W) dated June 20, 1982.
(46) Letter from G. T. Fairburn (B&W) to J. F. Fritzen (GPU) dated December 11, 1979, TMI-79-201.
(47) B&W Documen: 32-1138230-001 " Evaluation of Effects of 1500 Plugged Tubes on TMI-1 Post LOCA Core Safety, November 1982.
(48) B&W Document, Engineering Criteria for Tube Repair at TMI-l
- 51-1137529-00.
(49) " AUX. A Fortran Program for Dynamic Simulation of Reactor Coolant System and Emergency Feedwater System." B&W Document NPGD581, August, 1981.
(50) Report in Response to NRC Staff-Recommended Requirements for Restart of Three Mile Island Nuclear Station Unit One - Amendment 25.
l (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 l
OTSC's. BAW-10146, October 1980.
(53) Fracture Analysis of Steam Generator Tubes, Part II, Steam Intensity Factor and Crack Ope;.ing Displacement (COD) Displacements, by Prof.
F. Erdogan, Lehigh Univ., Prepared for GPU Nuclear, 9/15/82.
(54) TDR #399 Operation of TMI-l with Primary to Secondary OTSG Leakage and l l
its Onsite/Of fsite Radiological Impact.
- 115 -
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REFERENCES - (Contd. )
(55) GPUN Safety Evaluation 2.120012-C07 " Requirements for Cutting Upper OTSG hbe Ends, " Rev. 1; February 17, 1983.
(56) GPUN-S P-1101-22-014, Technical Specification for Post Repair Eddy Current Inspection Program.
(57) Intter Report, Examination of Three Mile Island I Third Pulling Sequence OISG hbes. RDD; 83:5068-03:03.
(58) IDR 400, Gaidelines for Plant Operation with Steam Generator Tube Laakage - D-aft (59) Evaluation of SB14CA Operating Procedures and Effectiveness of Emergency Feedvater Spray for B&W Designed Operating NSSS.
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- 116 -
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/b GPU Nuclear P.O. Box 480
- g gp Middletown. Pennsylvania 17057 717-944-7621 wnter's Direct Dial Numcer August 20, 1982 5211-82-200 Office of Nuclear Reactor Regulation Attn:
D. G. Eisenhut Division of Licensing U. S. Nuclear Regulatory Co= mission Washington, D.C.
20555
Dear Sir:
Three Mile Island Nuclear Station, Unit 1 (TMI-1)
Operating License No. DPR-50 Decket No. 50-289 OTSG Tube Repair Program Enclosed please find a copy of the '3I-1 Steam Generator Repair Safety Evaluation" which supplements our responses of Dece=ber 8, 1981 (LER 81-13) and February 16, 1982. This docu=ent describes the sm-ary analysis of safety considerations for the TMI-l OTSG tube repair process. The repair process has been evaluated against the criteria of 10 CFR 50.59 and does not represent an unreviewed safety question or require Technical Specifi-cation changes. Due to the proprietary nature of the information contained in this enclosure, it is requested that it be withheld from public disclosure in accordance with 10 CFR 2.790a(4).
l Sincerely, l
l l
H. D. Hukill Director, TMI-l HDH:CWS:vj f l
Ecclosures:
- 1) Affidavit l
- 2) TMI-1 Once Through Steam Generator Repair Safety Analysis i: i: M:"
h R. Jacobs VA0t l
[s[)ig 46 dk O MDO F
i GPU Nue: ear is a cart of the General Puche Utilities System M
Babcock &Wilcox AFFIDAVIT OF JAMES H.
TAYLOR A.
My name is James H. Taylor.
I am Manager of Licensing in tne Nuclear Power Generation Division of labcock & Wilecx, and as suca 1 am authorized to execute this Affidavit.
8.
I au familiar with the criteria applied ey Babcock & Wilcox te de-termine wnether certain information of Babcock & Wilecx is proprietary and I am f amiliar with the procedures es tablished within Babcock & Wilcox, particularly the Nuclear Power Generation Division (NPGD), to ensure the proper application of these criteria.
C.
In determining whether a Sabcock & Wilecx document is to De classi-fied as proprietary information, an initial determinatjen is made by the unit mansger who is responsible for originating the document as te whether it falls within the criteria sa: forth in Paragraph D norsof.
If the information f alls within any one of these criteria, it is classified as proprietary by the originating unit manager.
This iniiial determination is reviewed by the cogni: ant section manager.
If the document is designated as pr:prietary, it is re-viewed again by Licensing personnel and other management within NPGD as designated by the Manager of Licensin.; to assure tha: the regulatory requirements of 10 CFR Section 2.790 are met.
D.
The fellowing information is provided :: demonstrate that the pro-visions of 10 CFR Section 2.790 of the Commission's regulations have been considerec:
(i)
The information has been held in confidence by tne Babcock 5 Wilecx Comcany.
Cecies of sne docu=ent are clearly identified as proprietary.
In addition, wnenever Sabcock & Wilcox-transmits the information to a cus ccer, customer's agent, poten:tal customer or regula cry agency, the transmittal re-quests the recistent to hoic the information as proprietary.
Also, in order to s:rie:1y limit any potential or actual customer's use of proprietary inf:rmation, the fc11cwing e
emmme a_,,
n, y
BabcockAWDeux AFFIDAVIT OF JAME3 H. TAYLOR (Cont'd) provision is incluced in all proposals submitted by Sabcock
& Wilecx, and an applicable version of the procristary provision is included in all of Babcock & Wficox's contracts:
" Purchaser may retain Company's proposal for use in connection w1:n any centract resulting theref rom, and, for that purpose, make such copies thereof as may be l
necessary.
Any proprietary information concerning Company's or its Suppliers' oroducts or manufacturing
' processes which is so designated by Company er its Suppliers and disclosed to Purchaser incident to tne perfor=ance of such contract shall remain the property of Company or its Suppliers and is disclosed in confi.
dance, and Purenaser shall not publish or otherwise disclose it to others without the written approval of Company, and no rights, implied r otherwise, are granted to product or have produced any procucts or to practice or cause to be practicec any manuf acturing processes covered therecy.
Notwithstanding the above, Purchasar may provide the NRC or any other regulatory agency with any such pro-prietary information as the NRC or sucn einer agency may require; provided, however, that Purenaser shall first give Company written actice of such proposed disclosure and Company shall nave the righ
- = amend such proprietary information se as to make it non-pro-prie:ary.
In the event that Company cannot amend sucn proprietary information, purchasar shall, prict to disclosing such informa:icn, use its best efforts to cotain a commi tment from.1RC er suca other agency to nave such informatien witaneid f rom cutlic inspection.
(2) 1 D
k
hWAWilcox AFFIOAVIT OF JAMES W. TAYLOR (Cont'd)
Company.shall be given the rignt te participate in pursuit of such confidential treatment."
(ii) The following criteria are customarily applied by Babcock &
Wilcox in a rational decision process to catarmine whether the information should be classifiec as proprietary.
- nf o rma ti on may be classified as proprietary if one or more of the fcllowing criteria are met.
Information reveals cost or price information, commercial a.
strategies, production capabilities, or oudget levels of Babcock & Wilcox, its cus tomers or suppliers, b.
The information reveals data or material concerning labecek
& Wilcox research or development plans or programs of present or potentiti competitive advantage to Sabcock &
Wilcox.
The use of the' information by a competitor would cecrease c.
his expenditures, in time or resources, in designing, producing or marketing a similar procuct.
d.
The information consists cf test data or other similar data concerning a process, method or component, the acclication.
cr which results in a comoetitive advantage to Babcock 1
- Wilcox, e.
The afermation reveals special ascacts of a process, method, comoonent or the like, the exclusi'te usa of wnich results in a competitive advantage to Satcock & Wilcox.
i f.
The infermation contains ideas for wnich patent protection may se sought.
l
,Sabcock&Wilcox AFFIDAVIT OF JAMES H. TAYLO{ (Cont'd)
The document (s) listad on Exhibit " A", which is attached hereto and made a part hereof, has been evaluated in accordance with normal labcock & Wilcox procedures with respect to classification and has been found to contain information which falls wi-hin one or more of the criteria enumerated Abeve.
Exhibit "S", which is attached hereto anc made a part hereof, specifically identifies the criteria apolicable to the document (s) listed in Exhibit "A".
(iii) The document (s) 1*d in Exhibit "A", which has been made avail-able to the Uniten atates Nuclear Regulatory Commission was made available in confidence with a request that the document (s) and the information contained therein be withheld from public disclosure.
(iv) The information is not available in the open literature anc to the best of our knowledge is not known by Comoustion Engineering.
EXXON, General Electric, Wastinghcuse or other current or potential domestic or foreign competitors of B&W.
(v) Specific information with regard to whether public cisclosure of the informatien is likely to cause harm to the comoetitive position of Sabcock & Wilcox, taking into account the value of the information to Babcock & Wilcox; the amount of effort or money expenced oy Babcock & Wilcox coveloping the information; and the ease or difficulty with which tne information could be procerly duplicated by others is given in Exhibtw "B".
E. I have peetonally reviewed the cocument(s) lis ted on Exhibi t "A" and have founc that it is considered proprietary by Saccock & Wilcox because it contains information which falls within one or more of the criteria enumerated in Paragraph 0, and it is informa tion which i s cus tomarily held confidence and pec tactec as proprie:ary in-formation by Bacccch 6 Wilcox.
This report comprises information utilized by Baccock & Wilcox in its business whien afford Babcock
& Wilcox an opoortunity to obtain a competitive acvantage over (4)
l Babcock &W5ccx those who may wish to know or use the information contained in the document (s).
2 Y
s
/JAMESH.fAYLO[
State of Virginia City of Lynchburg)
James H. Taylor, being duly sworn, on his cata deposes and says that he is taa person who subscribed his name to the foregoing state-ment, and that the matters and facts set for:n in the statement are true.
/
h/
/dt-t'%
/ JAMES H. EAYLOA [
Subscrite/ and sworn before me, this
/f day of Mo.d 1982.
s
(, ew* n I
,& elcl m
//-
Notary Public in and for the City o.f Lynchburg. Sta te of Ytryinia l ' ~
- n. ~, n ps rm'v i+ n 3rn.ris b Oste.xi.,,4 My Commission Expires bals I,/Vf3
/
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(5)
-