ML20083R150
| ML20083R150 | |
| Person / Time | |
|---|---|
| Issue date: | 04/30/1984 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| References | |
| NUREG-1056, NUDOCS 8404240014 | |
| Download: ML20083R150 (124) | |
Text
NURGG-iO56 l
Report on U.S.-Japan 1983 Meetings on Steam Generators U.S. Nuclear Regulatory Commission Offica of Nuclear Reactor Regulation p" < coy Y
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Report on U.S.-Japan 1983 Meetings on Steam Generators I
i M:nuscript Completed: March 1984 DIts Published: April 1984 d
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Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission W:shington, D.C. 20666 i
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4 A8STRACT This is a report on a trip to Japan by personnel of the U.S. Nuclear Regulatory i
Commission in 1983 to exchange information on steam generators of nuclear power plants.
Steam generators of Japanese pressurized water reactors have experi-enced nearly all of the forms of degradation that have been experienced in U.S.
recirculating-type steam generators, except for denting and pitting.
More tubes have been plugged per year of reactor operation in Japanese than in U.S.
i steam generators, but much of the Japanese tube plugging is preventative rather than the result of leaks experienced.
The number of leaks per reactor year is much smaller for Japanese than for U.S. steam generators.
No steam generators have been replaced in Japan while several have been replaced in the U.S.
The i
Japanese experience may be related to their very stringent inspection and main-tenance programs for steam generators.
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TABLE OF CONTENTS
.Page A85 TRACT..........................................................
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INTRODUCTION...................................................
1-1 2 JAPANESE STEAM GENERATOR OPERATING EXPERIENCE..................
2-1 2.1 0verview..................................................
2-1
- 2. 2 Plant Specific Experience.................................
2-2
- 2. 3 Genkai Units..............................................
2-3 3 STEAM GENERATOR DESIGN AND 0PERATION...........................
3-1 3.1 Steam Generator 0esign....................................
3-1 3.2 Steam Generator Inspection Programs.......................
3-2 3.3 Eddy Current Testing Techniques...........................
3-2 3.4 Tube Plugging and Repair..................................
3-3 3.5 Personnel Exposure and Automation of In-Service Inspection................................................
3-3 3.6 Monitoring of Personnel Exposure..........................
3-4 4 CONDENSER AND FEE 0 WATER SYSTEM DESIGN AND OPERATION............
4-1 4.1 Condenser Design, Operation, and Inspection...............
4-1 4.2 Feedwater System Design and Operation.....................
4-2 4.3 Secondary-System Water Chemistry..........................
4-2 5 EMERGENCY PROCEDURES AND OFFSITE DOSE CALCULATIONS.............
5-1 5.1 Emergency Procedures for Steam Generator Tube-Rupture Events....................................................
5-1 5.2 Offsite Dose Calculations for Steam Generator Tube-Rupture Events............................................
5-1 5.3 Event Monitoring Capabi11ty...............................
5-2 6 JAPANESE STEAM GENERATOR RESEARCH PROGRAMS.....................
6-1 APPENDIX - NRC Questions and Japanese Written Responses Concerning Steam Generators y
FIGURES
- 7. a,Lqe 6.1 Normalized Burst Pressure vs Crack Depth.....................
6-7 6.2 Normalized Collapse Pressure vs Crack Depth..................
6-7 TABLES Page 2.1 Summary of Nuclear Power Plants in Japan.....................
2-5
- 2. 2 Summary of S.G. Tube Degradation in Japan....................
2-7 2.3 Steam Generator Tube Leaks..............
2-8 2.4 Capacity Factors of Nuclear Power Stations in Japan..........
2-9 2.5 Genkai Nuclear Power Station.................................
2-11 3.1 Summary of Steam Generator Design Features...................
3-6 4.1 Materials Used in Feedwater Heaters..........................
4-4 4.2 Moisture Separator Heater....................................
4-5 4.3 Description of Water Control on Secondary Side...............
4-6 4.4 EPRI Guidelines on Secondary-Side Water Chemistry Control....
4-7 4.5 Typical Secondary Water Chemistry Monitoring Locations.......
4-8 4.6 Secondary Water Chemistry Sampling Frequency.................
4-9 4.7 Wet Layup Water Chemi s try Moni toring.........................
4-11 6.1 Conditions of Partial Corrosion Simulation...................
6-4 6.2 Steam Generator Properties and Heat Flow Conditions..........
6-5 6.3 Heating Pipe Rupture Test Items and Conditions...............
6-6 i
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1 INTRODUCTION During March 1983, staff members of the U.S. Nuclear Regulatory Commission held several meetings in Japan with officials of the Japanese Ministry of Interna-tional Trade and Industry (MITI), the Japanese Science and Technology Agency (STA), the Japanese Atomic Industrial Forum (JAIF), several Japanese utility companies, and Mitsubishi Heavy Industries and with officials of other govern-ments who attended the JAIF meeting.
The meetings with MITI constituted the 1983 Bilateral Exchange Meetings.
During the meetings, considerable time and attention was devoted to steam generator experience since earlier reports indi-cated that the Japanese experience has been quite favorable.
The U.S. participants in this series of meetings were as follows:
H. R. Denton, Director, Of fice of Nuclear Reactor Regulation (NRR)
J. D. Lafleur, Jr., Deputy Director, Office of International Programs i
D. G. Eisenhut, Director, Division of Licensing, NRR
- 8. D. Liaw, Chief, Materials Engineering Branch, Division of Engineering, NRR G. M. Holahan, Chief, Operating Reactors Assessment Branch, Division of Licensing, NRR C. E. McCracken, Section Leader, Chemical Engineering Branch, Division of l
Engineering, NRR J. R. Strosnider, Materials Engineering Research Branch, Office of Nuclear Regulatory Research R. Axtmann, Member, Advisory Committee on Reactor Safeguards The success in acquiring a considerable amount of information relative to steam generator experience and the many other topics of mutual interest is largely due to advanced planning (i.e., 16 pages of agenda items transmitted to Japan before the trip) and an extremely cooperative attitude on the part of the Japanese government and the Japanese utility companies.
In particular the Japanese Ministry of International Trade and Industry, Kansai Electric Company, and Kyushu Electric Power Company were instrumental in making the trip a suc-cess and they deserve much of the credit for that success.
l Prior to leaving for Japan, the NRC task force prepared and transmitted to the Japanese a list of questions regarding the subject of steam generators (SGs).
These questions and written responses given to the NRC group in Japan formed the basis for many of the discussions in Japan.
(See the Appendix.)
The Japanese were very cooperative and provided a great deal of useful informa-tion.
The purpose of this report is to document that information so that it might be used by NRC in evaluating the SG degradation issue in the U.S.
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2 JAPANESE STEAM GENERATOR OPERATING EXPERIENCE 2.1 Overview There are currently 11 pressurized water reactors (PWRs) in operation, five PWRs under construction, and four PWRs under planning in Japan.
In addition, Japan has 12 operating boiling water reactors (BWRs) in operation, six BWRs under construction, and four BWRs under planning.
Japan also has one operating gas cooled reactor.
The current electrical generating capacity of operating nuclear power plants in Japan is 17,177 MWe which ranks Japan third after the U.S and France in nuclear power generation capacity.
Japanese PWR plants have accumulated approximately 60 years of reactor operation.
Table 2.1 presents a
. summary of nuclear power plants in Japan.
Table 2.2 summarizes the SG degradation experienced in operating Japanese PWRs as of February 1983.
In their 60 reactor years of operation, Japanese PWRs have experienced nearly all the forms of degradation which have been experi-enced in U.S. recirculating type SGs with the exception of denting and pitting.
Excluding intergranular attack (IGA) at the tube support plates (TSP), the form and cause of the degradation modes listed in Table 2.2 are similar to what has been experienced in the U.S.
The column labeled "other" in Table 2.2 includes a large number of plugged tubes.
The majority of these tubes were plugged pre-ventatively.
This includes plugging of row 1 and row 2 tubes where cracking was observed in the small radius U-bends and area plugging performed as a pre-caution against wastage degradation.
It is interesting to make a comparison between Table 2.2 of this report and Tables 1 and 2 of NUREG-0866, " Steam Generator Tube Experience." As stated above, it is apparent that Japanese and U.S. steam generators have experienced many of the same modes of degradation.
Table 2.2 of this report indicates that approximately 4,670 SG tubes have been plugged in about 60 years of Japanese PWR operation.
From Tables 2 and 3 of NUREG-0866, similar statistics for U.S.
PWRs are approximately 17,166 tubes plugged in 360 years of PWR operation.
These statistics correspond to approximately 78 tubes plugged per PWR operating year in Japan to 48 tubes plugged per PWR operating year in the U.S.
- However, the distribution of tube plugging among units must also be considered, and it should be noted that SGs have been replaced at two U.S. plants and that re-placements are in progress at another unit and planned for a fourth unit.
These replacements are largely a result of extensive tube plugging due to dent-ing which has not been experienced,in Japanese SGs.
Also, it should be noted that the extent of tube plugging is much less in both U.S. and Japanese SGs that have operated exclusively on all volatility treatment (AVT) secondary water chemistry.
Another statistic of interest is the number of SG tube leaks which have been experienced in Japan and the U.S.
Table 2.3 summarizes the tube leak experi-ence in Japan.
Japanese PWRs have experienced a total of ten tube leaks, all of which were less than 0.3 gpm and eight of which were less than 0.1 gpm.
2-1
1 U.S. recirculating type SGs have reported approximately 255 SG tube leaks in-cluding four significant tube-rupture events.
Thus Japanese PWRs have experi; enced tube leaks at a frequency of approximately 0.17 leaks per operating year, while U.S. pressurized water reactors with ~ recirculating type SGs have experi-enced tube leaks at a frequency of approximately 0.71 leaks per operating year.
It is of particular interest to note that the Japanese have not experienced any denting or pitting degradation in their SGs.
The absence of these forms of degradation is most likely attributable to meticulous maintenance of secondary-side components, including the condensors, to avoid cooling water and air in-leakage.
An important neasure of a plant's perfumance is its capacity factor which is the ratio of its actual electrical output to its potential output at authorized capacity.
Table 2.4 presents the capacity factors for Japanese PWRs during the years 1970 through 1981.
During this period the average capacity factors were approximately 0.61 and 0.56 for U.S. and Japanese PWRs, respectively.
The above discussion of U.S. and Japanese operating experience irdicates that Japanese experience has definitely been favorable with regard to tube rupture and leakage events.
However, this favorable experience has been paid for through a higher rate of SG tube p' lugging and lower average capacity factors which may be in part due to more stringent SG inspection and maintenance pro-grams.
It should be noted, however, that Japan has not yet had to replace any SGs and that in the years 1980 and 1981 the capacity factors of Japanese nuclear plants exceeded those of U.S. plants despite the more stringent inspec-tion and maintenance requirements.
2.2 Plant Specific Experience A summary of plant specific tube degradation is included in Table 2.2.
Of particular interest, because it is apparently different from U.S. AVT experi-ence, is the intergrannular attack / stress corrosion cracking (IGA / SCC) found at Takahama-2, Ohi-1, and Genkai-1.
This corrosion was found at the tube support plates (TSP) on the secondary side of the tubes (outer diameter).
The cause of the TSP IGA / SCC has not been c1tegorically determined but may be related to carryover of treatment chemicals from the auxiliary boiler to the SG feedwater or impurities entering through the makeup demineralizers.
U.S. plants which have started on AVT have not yet reported this particular corrosion mechanism.
The only other major variation between Japanese and U.S. experience is the re-moval of approximately 4,000 explosively welded plugs from Mihama-1.
A number of explosively welded plugs in both countries have leaked at circumferential cracks which were initiated due to the high residual stresses produced by the explosively welding process.
Leaks from these cracks are significantly less than 0.1 gpm and it is highly unlikely that greater leakages would occur, due to the presence of the plug which will act as a flow restrictor.
Individual explosive plugs that have leaked in the U.S. were repaired by re-plugging.
At Mihama-1 all explosively welded plugs were drilled out and re-placed with mechanical plugs to prevent a recurrence of even minor primary to secondary leakage.
2-2
Additional information on integrity of steam generators is given in Section 5 of Appendix A.2.
2.3 Genkai Units Among those units with longer operating history, Genkai Unit I has been viewed as the one that has the best operating experience as far as steam generators are concerned.
In fact, Genkai 1 recently achieved a world-wide record for non-stop operation (367 days, ending 10/22/82) among Westinghouse designed plants.
In view of this, an arrangement was made for two NRC group members (R. Axtmann and 8. D. Liaw) to make a side trip to Kyushu to visit the Genkai site.
The Genkai site will eventually have four PWR units; two are currently opera-tional (Units 1 and 2) and two in planning (Units 3 and 4) with construction permits expected to be granted in August 1984 and with commercial operation expected in 1990 or 1991.
The capacity factors for both operating units are very good, except for two periods with low capacity factor.
The first (4/1/79
- 3/31/80) was due to TMI fixes, i.e.,
installation of a subcooling meter and core exit thermocouples.
The second (4/1/81 - 3/31/82) can partially be attri-buted to steam generator problems.
The Unit 2 capacity has been good since restart after the first refueling outage.
The second cycle lasted 318 days and the third cycle lasted 350 days, each with shutdowns.
The unit was scheduled for a refueling and mandatory maintenance shutdown on 3/25/83.
Both Genkai Units 1 and 2 started up with AVT chemistry in the secondary system and phosphate treatment in the tertiary system.
They are equipped with con-densate demineralizers.
Both units are two loop Westinghouse designs with two model 51 M steam generators per unit.
The Model 51 M design is essentially the basic Westinghouse Model 51 with slight modification to the lower surface of the tube holes in the tube support plate.
(Model 51 was used in Surry Units 1 l
and 2; the new Surry steam generators are Model 51 F, which has the support plate designs and material similar to the latest Model F.) Other than the tube leakage caused by a loose part (steel tape) during the startup tests in June 1975, neither Genkal unit has experienced a forced shutdown because of adverse steam generator experience.
Genkai Unit 1 first achieved synchronization with the electrical grid on February 14, 1975 and began its commercial operation on October 15, 1975.
In June 1975 during startup tests, the plant was shut down because of a steam gen-erator tube leak (about 0.35 gpm).
Subsequent investigation discovered a loos-ened steel measuring tape that wrapped arouno some tubes in one steam generator.
Apparently due to metal-to-metal wear, one tube was degraded to the extent that resulted in a primary-to-secondary leak.
Since the start of commercial operation on October 15, 1975, the steam genera-tors have been free of trouble through five cycles of operation.
All tubes (100%) were ECT inspected in the first three scheduled mandatory maintenance outages and 20% of tubes in the fourth outage when the MITI current policy on tube inspection became effective.
The current requirement is that 100% of tubes must be inspected in the first two scheduled outages and the inspection can be reduced to 30% (Genkai people said 20%, but MITI said 30%) if no problem / degradation is discovered.
The inspection then goes back to 100% if 2-3
i active degradation is identified during any inspection and in subsequent out-ages.
(The precise language of the requirement was not shown, but is said to be in the plant specific manual.)
During the fifth outage in 1981, the inspection uncovered an active degradation mechanism that resulted in plugging 233 tubes and another 176 tubes in the sixth outage between 10/22/82 - 2/10/83.
The inspectian was made by eddy current testing (ECT) using differential probes at frequencies of 100 and 400 kilohertz.
The degradation mechanism was identified to be stress corrosion of tube outer surfaces within the thicknesses of the first and second tube support plates.
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The vast majority (70%) of degradation indications were at the first support level.
As of 1982, a total of 6.1% of tubes (7.5% and 4.8% of tubes in steam generator A and B, respectively) have been preventively plugged using mechanical plugs.
Note that the Japanese do not have an explicit tube plugging limit; rather, tubes have been plugged at any " detectable". degradation which is about 20-30% ECT indications.
This may help to explain why Japanese have not found denting in their generators.
The plant personnel attributed this degradation to the residual phosphate that entered into the secondary system through the deaerator.
As indicated earlier, the auxiliary boiler water was treated with phosphate as a buffer to control pH, and sodium phosphate carried over to the deaerator during cold startup.
As a result of the SG tube degradation, Genkai has stopped this practice,and has switched to AVT for the auxiliary boiler.
They seem confident that,' before they reach 20% design margin (in heat transfer surfaces), the problem should cease.
No further specific remedial actions were indicated or discussed ~.
Clearly, the tube plugging is not necessarily done from a concern over safety.
They are more concerned with the plant reliability.
This practice is also con-l sistent with Kansai Electric's policy.
Genkai Unit 2 first achieved synchronization with the grid on June 3, 1980 and commenced commercial operation on March 30, 1981.
A 100% tube inspection was made in the first refueling / maintenance outage (1/24/82 - 4/10/82).
It was scheduled for the second outage commencing on March 25, 1983.
Further information about the Genkai nuclear power station is given.in Table 2.5.
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TABLE 2.1
SUMMARY
OF NUCLEAR POWER PLANTS IN JAPAN Feb. 1, 1982 Authorized Name of power station Type of Start of cadon C'
Y Name of company (Unit numbers) reactor construction Japan Atomic Power Co.
Tokal Ibaragt Prof.
GCR 166
'61 - Mar.
'66 - Jul. - 25 Japan. Atomic Power Co.
Tokal Daint Ibaragi Pref.
BWR 1,100
'73 - Apr.
'78 - Jan. - 28 Japan Atomic Power.Co.
Tsuruga (No.1)
Fukut Pref.
BWR 357
'67 - Feb.
'70 - Mar. - 14 Tokyo E.P. Co.
Fukuskima Dalichi (No.1)
Fukushima Pref.
BWR 46Q
'67 - Sep.
' 71 - Mar. - 26 Tokyo E.P. Co.
Fukushima Dailchi (No.2)
Fukushima Pref.
BWR 784
'69 - May
'74 - Jul. - 18 Tokyo E.P. Co.
Fukushima Dalichi (No.3)
Fukushima Pref.
BWR 784
'70 - Oct.
' 76 - Mar. - 27 fokyo E.P. Co.
Fukushima Dalichi (No.4)
Fukushima Pref.
BWR 784
'72 - May
'78 - Oct. - 12 Tokyo E.P. Co.
Fukushima Dalichi (No.5)
Fukushima Pref.
BWR 784
'71 - Dec.
' 78 - Apr. - 18 Tokyo E.P. Co.
Fukushima Dalichi (No.6)
Fukushima Pref.
BWR 1,100
'73 - Mar.
'79 - Oct. - 24 Tokyo E.P. Co.
Fukushima Daint (No.1)
Fukushima Pref.
BWR 1,100
'75 - Aug.
'82 - Apr. - 20 Chubu E.P. Co.
Hamaoka (No.1)
Shizuoka Pref.
BWR 54 0
'71 - Feb.
' 76 - Ma r. - 17 Operation Chubu E.P. Co.
Hamaoka (No.2)
Shizuoka Pref.
BWR 840
'73 - Sep.
'78 - Nov. - 28 Kansal E.P. Co.
Mihama (No.1)
Fukul Pref.
PWR 340
'67 - Aug.
'70 - Nov. - 28 Kansal E.P. Co.'
Mihama (No.2)
Fukui Pref.
PWR 500
'68 - Opc.
'72 - Jul. - 25 ro Kansal E.P. Co.
Mihama (No.3)
Fukul Pref.
PWR 826
'72 - Jul.
'76 - Dec. - 1 Kansal E.P. Co.
Takahama (No.1)
Fukul Pref.
PWR 826
'71 - Feb.
'74 - Nov. - 14 Kansal E.P. Co.
Takahama (No.2)
Fukul Pref.
PWR 826
'72 - Oct.
'75 - Nov. - 14 Kansal E.P. Co.
Oh!
(No.1)
Fukul Pref.
PWR 1,175
'72 - Nov.
'79 - Mar. - 27 Kansal E.P. Co.
Oh!
(No.2)
Fukui Pref.
PWR 1,175
'72 - Nov.
'79 - Dec. - 5 Chugoku E.P. Co.
Shimane (No.1)
Shimane Pref.
BWR 460
'70 - Feb.
'74 - Mar. - 29 Shikoku E.P. Co.
Ikata (No.1)
Ehime Pref.
PWR 566
'73 - Apr.
'77 - Sep. - 30 Sisikoku E.P. Co.
Ikata (No.2)
Ehime Pref.
PWR 566
'77 - Dec.
'82 - Mar. - 19 Kyushu E.P. Co.
Genkal (No.1)
Saga Pref.
PWR 559
'71 - Mar.
' 75 - Oct. - 15 Kyushu E.P. Co.
Genkal (No.2)
Saga Pref.
PWR 559
'76 - May
' 81 - Ma r. - 30 Total (24 units) 17.177
TABLE 2.1 Supe 4ARY OF NUCLEAR POWER PLANTS IN JAPAN (Continued)
Authorized Name of power station Type of Start of C'
C' Y
Name of company (Unit numbers) reactor construction
)
-Japan Atomic Power Co.
Tsuruga (No.2)
Fukui Pref.
PWR 1,160
'82 - Jan.
'87 - Jun.
' ~
Tohoku E.P. Co.
Onagawa (No.1)
Niyagi Pref.
BWR 524
'71 - May
'84 - Jun.
Tokyo E.P. Co.
Fukushima Daint (No.2)
Fukushima Pref.
BWR 1,100
'79 - Jan.
'84 - Jan.
Tokyo E.P. Co.
Fukushima Daini (No.3)
Fukushima Pref.
BWR 1,100
'80 - Nov.
'85 - Jul.
Umler Tokyo E.P. Co.
Fukushima Daint (No.4)
Fukushima Pref.
BWR 1,100
'80 - Nov.
'86 - Feb, construction Tokyo E.P. Co.
Kashiwazakt-Kartha (No.1)
Niigata Prof.
BWR 1,100
'78 - Nov.
'85 - Oct.
Chubu E.P. Co.
Namacka (No.3)
Shizuoka Prof.
BWR 1,100
'82 - Jun.
'86 - Sep.
Kansal E.P. Co.
Takahama (No.3)
Fukul Prof.
PWR 870
'80 - Nov.
'85 - Feb.
Kansal E.P. Co.
Takahama (No.4)
Fukul Prof.
PWR 870
'80 - Nov.
'85 - Aug.
Kyushu E.P. Co.
Sent'ai (No.1)
Kagoshima Prof.
PWR 890
'78 - Nov.
'84 - Jul.
Kyushu E.P. Co.
Sendal (No.2)
Kagoshima Prof.
PWR 890
'81 - Nar.
'86 - Nar.
t Total (11 units) 10.704 Hokkaido E.P. Co.
Tomarl (No.1)
Hokkaido PWR 579
'88 - Sep.
Hokkaldo E.P. Co.
Tomari (No.2)
Hokkaido PWR 579
'90 - Feb.
Tohoku E.P. Co.
.Naki Niigata Pref.
BWR 825
'90 - Feb.
Under Tokyo E.P. Co.
Kashiwazaki-Kariha (No.2)
Niigata Pref.
BWR 1,100
'89 - Apr.
7 Planning Tokyo E.P. Co.
Kashiwazaki-Kartha (No.2)
Niigata Pref.
BWR 1,100
'89 - Oct.
cn Chugoku E.P. Co.
Shimane (No.2)
Shimane Pref.
BWR 820
'88 - Sep.
Kyushu E.P. Co.
Cenkal (No.3)
Saga Pref.
PWR 1,180
'90 - Oct.
Kyushu E.P. Co.
Genkal (No.4)
Saga Pref.
PWR 1.180
'91 - Oct.
i Total (8 units) 7,363 Grand Total (43 units) 35.244 i
(Note) 1.
The date of start of, constructlee given here is the month of construction permit.
2.
The scheduled commission month is based on the fiscal 1982 power plant construction program.
3.
"Under planning" refers to the power plant whose construction was decided by the Electric Power.
Development Coordination Council but the construction plan has not been authorized yet.
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TA8LE 2.2 SisemRY OF 5.G. TURE DEGRADATION IN JAPAN NUMBER OF TUBES f1.UliGED FOR THE CAUSE STATED FIRSI NteeER SECONDARY WALL IGA / SCC SCC CAPACliY C0f01ERCIAL MANUFACIURE OF CHEMISTRY THINNING TIGHT
~ FRETTING FOREIGN OTIER TOTAL X
( edE) OPERAil0N TUBES CONiilot T.S.P.
T.S.P.
T.S. CREVICE U-BEND fl0LL A.V.S.
MAllER PLUGGED 4
PLANI MADE 1
(00)
(00)
(00)
(10)
(00)
(00)
I'II II I P0 MlHAMA 1 340 1970/11 C.E.
4,426M2 4+AVT 1,329 0
0 0
0 0
0 885 2,214 25 (1974/07)
I II I PO MlHANA 2 500 1972/07 M.H.I 3,260M2 4+AVT 266 13 42 0
0 0
0 13 334 5.1 (1975/01)
(8)
MlHAMA 3 826 1976/12 M.H.l.
3,388M3 AVT/CD 0
0 0
0 0
0 0
2 2
< 0.50 (a)
TAKANAMA 1 826 1974/11 W.H.
3,388M3 4+AVT 98 0
78 97 1
0 0
186 460 4.5 (1974/10)
(8)
TAKANAMA 2 826 1975/11 M.M.I.
3,388M3 AVT 0
196 0
0 0
0 0
1 197 1.9 7a
(')(s 3 OMI 1 1,175 1979/03 W.H.
3,388M4 AVT/CD 0
26 0
31 46 0
0 723 826 6.1
( 8 )(8)
OHL 2 1,175 1979/12 M.H.I.
3.38BM4 AVi/CD 0
0 0
0 63 0
0 3
66 0.5 (8)(s3 GENKAl 1 599 1975/10 M.H.I.
3,388M2 AVT/C0 0
409 0
0 0
0 1
6 416 6.1 GENKAl 2 599 1981/3 N.H.I.
3,388M2 AVi/C0 0
0 0
0 0
0 0
0 0
0 (8)
IRATA 1 566 1977/9 M.H.I.
3,388M2 AVT/CD 0
0 0
0 134 9
0 12 155 2.3 IRATA 2 566 1982/3 M.H.I.
3,382M2 AVT/CD 0
0 0
0 0
0 0
0 0
0 NOTE ( 8 ) LAW PA000CEO OURING MANUFACTURIIIG (3) PREVENTIVE PLUG (3) SAfrLIIIG 4.670 A.V.O.: activibration bar 00: outer diameter AVT: all volativity treatment PO4: phosphate CD: condensate polisher SCC: stress corrosion cracking C.E.: Combustion Engineering T.S.: tube. sheet 10: inner diameter T.S.P.: tube support plate IGA:.intergranular attack W.H.: Westinghouse M.H.I.: Mitsubishi Heavy Industrites
TABLE 2.3 STEAM GENERATOR TUBE LEAKS PLANT LEAK RATE CAUSE Mihama 1
.03 gpm 6/13/72 Wall Thinning Mihama 1
.01 gpm 7/17/74 Wall Thinning Mihama 2
.02 gpm 1/8/75 Wall Thinning Mihama 2 10/24/79 Stress Corrosion Cracking (SCC)
Mihama 2
.002 gpm 2/8/83 Stress Corrosion Cracking (SCC)
Takahama 1
.1 gpm 1/23/77 Stress Corrosion Cracking (S CC)
Ohi 1
.003 gpm 9/1/81 U-Bend Cracking Genkai 1
.35 gpm 6/75 Loose Part (Steel Type)
Mihama 1
.0004 gpm 3/19/82 SCC of Tube Plug Mihama 1
.0003 gpm 7/27/82 SCC of Tube Plug i
t i
l 2-8
TABLE 2.4 Capacity Factors of Nuclear Power Stations in Japan g
Name of power Author-I982
'f',"of start tied 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 of operation)
"III semaikn Jun.
I "8*
'P"*
Tokal'25, 1966) 8[.5
- 83. h 166 80.3 86.9 85.5 88.2 85.3 87.8 86.6 77.5 82.1 93.5 43.0 100 100 100 (July Jrpm Atomic Tokai Deino Wder 4th annual cover (Nov. 28, 1978) 2,100 489.2 66.3 74.5 69.5 78.0 0
0 0
in.pection
(_J""* 23 3982 --)
e g'"8*"*j,l under 13th annual 357 81.5 72.6 80.2 85.6 55.8 49.1 76.4 41.1 73.1 69.0 75.8 24.5 62.5 71.1 0
24.0 in.pectino
,o)
Fukushima Delich!
(July. U. 1982.--).
Under 9th annual i
Nuclear No.1 460 a100 72.3 68.1 58.7 36.2 21.8 30.1 9.2 50.8 66.3 62.6 33.3 90.6 83.2 100 72.6 inpsection (Har. 26,.19 71),,,_
(Setp. I1,,1982 --)
Fukushima Da!!cht i
Nuclear No.2 784 472.9 20.9 59.1 7.9 66.7 79.0 52.5 54.0 100 100 100 100 (July 18 1974) 7 Fukushima Detichi Under 5th annual m
Nuclear No.3 784 e100 86.8 49.4 50.4 57.3 74.0 79.5 3". 0 0
0 0
inspection Tthys
_(Ma r. 2 7, 1976)_,
E.P.
Fukushima Da11 chi (May i,1982 --)
t Co.
Nuclear No.4 784 899.7 68.7 47.2 75.2 100 100 100 100 (Oct. 12, 1978)
Fukushima Datichi Under 5th annual Nuclear No.5 784
- 83.0 81.0 75.5 75.5 98.5 95.7 0
32.2 inspection (Apr. 18 _I.p 8)
(May,1, 1982 --)
t i-Fukushima Daticht Nuclear No.6 1,100
- 100 67.9 71.2 94.3 98.4 100 99.5 (Oct. 24, 1979)
Fukuohles Daint Nuclear No.1 1,100
- 100 100 100 100 (Apr. 20, 1982)'
Namsoks Nuclear No.1 540
- 97 61.1 4.40 27.3 63.3 75.5 76.6 0
96.6 100 98.8
,jMar. 17, 1976).
Nasseka Nuclear C3.
No.2 840
- 100 67.1 71.7 69.3 100 69.8 100 89.8 juov. 29.'1978) 4 MIbase No.1 Under 5th annual 340 872.2 74.3 45.2 47.2 12.9 0
0 0
20.8 8.9 69.7 23.1 0
27.7 0
9.3 inspection (No. 28, 1970) use,c1 (Aug. 1, 1982 --)
E.P.
Mihaan No.2 Cn.
(July 25, 1972) 500 478.8 57.0 64.5 32.1 55j,54.2
_ 76.1 16.1 60.1 75.5 0
87.8 100 95.9 Hahama No.3 826
- 100*
63.0 45.9 50.8 55.0 95.4 35.4 100 100 100 j0ec.,,_1976)
(enntinued)
i l
TABLE 2.4 (continued)
Name of power I982 uthor-
'*ft imed 1970 1971 1972 1s73 1974 1975 1976 1977 1978 1979 1980 1981 ac arks (D
of start capacity 3p,,_
July Aug.
Sept.
p of operationy J""*
(HW)
Under 6th aniusal Takahama No.1 826 882.3 53.7 52.1 6.8 33.6 48.2 38.9 47.7 99.8 99.8 99.8 72.4 innpection (Nov. 14, 1974)
(Aug. I, 1982 --)
Takahama No.2 Kcn:ci 862
- 77.6 38.3 77.2 67.0 28.4 65.6 63.2 41.0 100 IM le (No.v 14, 1975) f[-
- 'd " 3'd """""I Oh1No;;'
1,175 aioO 34.i 50.1 44.0 100 80.0 60.7 ina,ection c,,,,
1,,,3 (Aug. 28, 1982 --)
Ohi No.2 1,175
- 99.1 53.8 51.9 90.9 62.1 89.6 83.6
{ttar. 27. 1979)
Chugoku Shimane Nuclear Under 8th annual E.P.
do.1 460
- 100 75.6 76.1 63.3 56.2 70.1 75.7 66.6 72.1 55.4 0
0 0
inspection (Hay 22, 1982 --)
C%
(Har. 29, 1974)
Under 5th anunni I ***
7 Shikoku 566
- 94.7 62.2 61.3 60.3 74.9 99.9 99.8 100 94.4 inspection (Sept. 30, 1977)
E.P.
(Sept. 26, 1982 --)
C3.
Ikats No.2
- 100 99.9 99.8 96.6 98.8 566
. (Har. 19. 1982)
Cenkai Nuclear No.1 559
- 87.2 73.5 76.7 81.1 56.1 76.7 59.1 99.9 99.9 99.8 99.9 (Oct. 15, 1975)
E*
Genkai Nuclear Ca.
No.2 559 a100 81.7 82.8 100 100 100 (Mar.'30 1971)
Total 17,177 73.8 68.9 62.0 54.1 54.8 42.2 52.8 41.8 56.7 5'4.6 60.8 61.7 75.5 76.1 74.7 71.6 Fower output (HWhr)
(N:ts) 1.
Capacity factor Authorized capacity (NW) a 8,760 (hr)
=
2.
%e fiscal year under which a figure marked with a. comma represents the initial year of the operation of the power station concerned.
So, the capacity f actor 8 ven was calculated on the basta of the ntueber of calendar hours f rom the start of the operation.
1 I
l l
l Table 2.5 cenkai nuclear Power station-roaay (as of u...: b 1.1985) 1.
General Data I
Unit No. 1 Unit No. 2 Unit No. 364 (Increase Plan)
Site Location Imamura, Genkai-Cho,14tgeshl-Hatsuura-Gun, Saga (on the tip of Chigasaki Cape) 2 Plant Area About 830,000m2 (Main buildings are located on the about E.L lla heights that has 130,000m g Reactor type Pressurized Water peactor (PWal Electric Power
$59,000 RWe 558,000 Ewe 1,180,000 Kwe each Construction Cost 54.5 billion Yen 1Jie billion Yen F 10.0 billion Yan (Es t lane t ed )
Initial Criticality Jan. 28, 1975 May 21, 1980 sep.21,1982 :Ashmewledsenwat of Electria Power Develepanent Firstl>nchrontaation Feb. 14, 1975 June 3, 1980 Coordlastles Ceemell(sagt) 1770-1FPt : 8eheduled Comunerales Commercial Operation Oct. 15, 1975 Mar. 30,1981 Operaties m
Number of Employee About.266 eW W
1 Operating Esperlense 3.
Ogega dna Conditione Plant Un a i fit i Un i t NL 2 TotaI (billle-Arnes,apaalty im=!e%%
Plant
% r.51,tt81
~ Mar.51,1982
~ Mar.51,1985 w
C Capselty
( a> PJl "::::%
. e 4. r i.,
, a e t e r <.>
9f6 2.99*
87.2 2.77 87.2 5.
$7 b n Is Is
$s A pr.1,1976 gi 160 715 540 7 15 Mar.51.ft17 Apr.f.1977 Ma r.51,1978 175 7&7 175 7 &7 Feer 4h Faftb tiiatb Periedles1 Perledleal Perladleal A pr. l.197 M.,.5,.,,8,,
i.,
8,.1 1,7 81.1 8..peei1.a l..pestie.
...p.etie.
275 56.1 2.75 56.1 Faret Fonsee r s i a l 8 ebrantention 3peration A
.1.1980 F
M.51,1981 175 7&7 2.41*
1000 age 748 g
sg,,
g,
,y',
IHh El Eil
^ *z ' "a '
"a2 u,
5,..
- 00 81.7
.8, 104 maoum
,tr.t
^'h.
85 2.F 2 65,1 427 95.5 7.17 80.2 8e e d p.,g,a
,,g
- f",,,,g 2&62 7 0.P 10.48 882 57.30 745 Notes Capacity factor = Calen er H 'e 1
x100, The langest Continuous Operatingreeerd et malt la t t 567 days r
(t)
- Electris Power Generated counts Trial rua. Capaalty f aster does not coast Trial rea.
l r
3 STEAM GENERATOR DESIGN AND OPERATION l
3.1 Steam Generator Design j
The first PWR put on line in Japan, Mihama Unit 1, utilized Combustion Engineer-ing (CE) SGs fabricated to Westinghouse specifications.
These SGs are similar in design to those used in domestic plants.
Takahama Unit 1 has Westinghouse I
(W) model 51 SGs, and Ohi Unit I has Westinghouse model 51A SGs which are the same design as those operating in the U.S.
All other PWRs in Japan use SGs manufactured by Mitsubishi Heavy Industries (MHI).
operation at Mihama Unit 2 and the MHI series 51 SGs in operation at Takahama Unit 2, Genkai Unit 1, Mihama Unit 3, and Ikata Unit 1 are identical in design
.j to the Westinghouse series 44 and series 51 SGs in operation in the U.S.
The SGs for Mihama Unit 3 and Ikata Unit I had full-depth expansion of the tubes in the tubesheet while earlier units were not full-depth expanded.
Work is cur-rently in progress in the field to full-depth expand the tubes in those units where full-depth expansion was not originally performed.
The full-depth expan-sion is being performed using mechanical or hydraulic expansion techniques and 1
is scheduled for completion by the end of 1984.
In the MHI series 51M SGs in service at Genkai Unit 2 and Ikata Unit 2, the flow velocity of the circulation i
water was increased and a flow distribution baffle was installed to improve flow conditions on the tubesheet.
In addition, the moisture separators were improved to accommodate the increased circulation.
Sendai Unit 1 also utilizes l
MHI series SIM SGs but in addition to the thermal hydraulic improvements men-tioned above, the Sendai SG tubes were subjected to a 700*C, 15-hour heat treat-ment to improve their resistance to stress corrosion cracking.
Finally, the MHI series 51F SGs to be used in those plants under construction have all of the design improvements in the MHI series SIM SGs, including the special tubing heat treatment plus an improved tube-to-tube support plate annulus design (quatrefoil) to provide additional assurance against denting.
i It should be noted that in SGs manufactured by MHI, the small radius U-bends were bent using a bullet shaped internal mandrel which reduces the residual stresses in the U-bends.
To date, no stress corrosion cracking has been ob-served in these U-bends.
No Japanese SGs have incorporated a preheater design as in the Westinghouse model D and CE's System 80 SGs.
Table 3.1 presents the l
model of the SGs used in Japanese PWRs in operation.and under construction and summarizes some of the important SG design features for each PWR unit.
The historical development of SG designs in Japan parallels that in the U.S.
very closely.
This is not surprising because of Japanese licensing agreements l
with U.S. vendors of nuclear steam supply systems and because the Japanese fol-low U.S. operating experience very carefully and factor this experience into their nuclear power generation program.
The Japanese do not appear to have incorporated any improved design features in their SGs which have not already.
been recognized and-incorporated in later model SGs in the U.S.
Japan currently has in progress a program to develop advanced PWRs, and develop-ment of an improved SG design is listed as one of the most important tasks.
The study includes evaluation of alternative materials and mechanical designs.
3-1
This program is jointly sponsored by MITI and the Japanese utilities and is i
being conducted in cooperation with Westinghouse.
A safety evaluation report 1
on the next generation of SG design is scheduled to be completed in March or April of 1985.
It should be noted, however, that in discussions with Japanese officials they indicated a conservative approach to modifying SG designs.
They are very cautious about implementing changes which have not had extensive test-ing or have not been demonstrated as successful _in actual operation.
- Hence, it is not likely that they will implement any radical design changes.
Additional information on SG design and material selection is given in Section 2.1 of Appendix A.2.
i i
3.2 Steam Generator Inspection Programs Steam generator inspection requirements in Japan are much more stringent than those mandated by NRC for U.S. plants.
Preservice inspection includes eddy
{
current testing (ECT) of all tubes in all SGs over their entire length.
Eddy current signals are compared with the results of ECT performed at the tube manu-facturing facility and serve as a baseline for future inservice inspections.
Inservice inspections of the SGs are conducted every 12 (plus or minus 1) months during scheduled outages for plant refueling and maintenance.
The inservice inspections include ECT of the entire length of all tubes in all SGs unless two consecutive inspections after the initial startup or converting to AVT' secondary water chemistry have revealed no degraded tubes, in which case the sample size can _be reduced to 20L However, if only one degraded tube is detected, the sample size is expanded to 100L A degraded tube is any tube with a detectable l
ECT indication.
l In addition to ECT, inspections of the secondary side of the SG for loose parts are also conducted.
Following the 1975 tube leak at Genkai Unit 1 which re-sulted from a loose tape measure left in the SG, the Japanese utilities estab-lished careful procedures for controlling loose parts in SGs.
These controls consist of detailed quality-assurance (QA) procedures during SG maintenance, 4
visual and television inspections of the secondary side of the SGs, and contin-uous secondary side loose parts monitoring.
The QA procedures consist primarily of well defined work descriptions and an inventory of all tools 'and equipment prior to and following entry to the work area.
Visual and television inspec-tions are conducted on the secondary side of the SGs at each scheduled refuel-ing and inspection outage.
In addition, the Japanese have loose parts monitor-ing systems on the SGs in all plants.
=
Unscheduled inspections are required in the event of a SG tube leak.
These inspections include the entire _ length.of all tubes in all SGs.
The Japanese have no leak rate limits, and operation with detectable _ leakage.is not allowed.
f 3.3 Eddy Current Testing Techniques Eddy-current testing is generally perfurmed using a multiple frequency differen-tial probe, although four-segment type. probes are used to inspect the tube-i_
sheet region.
The probes are calibrated using three flat bottom holes of vary-ing depth and 0.8 mm diameter; a " struck mark", the nature of which is not well I
defined; and a 360' circumferential groove that is 0.3 mm wide and 50% through-
-wall.
These calibration standards are more stringent than the five flat bottom drilled holes currently required as a' calibration standard by Section XI:of the 3-2
ASME Code.
Eddy current inspection of sleeves which have been installed in the tubesheet region are performed using the same ECT techniques, but the original ECT trace from the inspection at installation is used as a reference standard by which to evaluate the inspection results.
A comparison of ECT signals on a yearly basis is also used to evaluate the condition of the small radius U-bends and the tube sheet area.
ECT signals are evaluated using an oscillo-scope and X-Y strip chart recordings.
Real time or computerized ECT evaluation are not used in the field.
3.4 Tube Plugging and Repair The Japanese philosophy regarding tube plugging is to plug any tube that has a significant ECT indication.
What is considered "significant" is not well defined.
However, discussions with the Japanese indicated that they are very conservative with regard to this subject.
In contrast to tube plugging criteria which incorporate specific margins of safety for continued degradation between inspections and for ECT error, as are employed in the U.S., the Japanese phi-losophy is to plug any tube in which there is indication of degradation.
In the past, explosively welded plugs were used; however, because SCC has j
occurred in explosive type plugs, mechanical tube plugs are now being used.
The Japanese have also used a limited number of tube sleeves to repair defects in the tubesheet region.
These sleeves are installed using a mechanical expan-sion process. The Japanese find that mechanical expansion allows better con-trol of the installation process than the explosive technique.
When expanding sleeves, the tube is also full-depth expanded if not previously expanded.
3.5 Personnel Exposure and Automation of In-Service Inspection The Japanese have devoted a great deal of effort to automating SG inspection and maintenance work and to reducing the personnel exposure associated with these activities.
Steam generator ECT is currently performed using " finger walker" type of probe positioners.
Although it was not observed by the NRC group in Japan, the Japanese have indicated that a new generation of finger-walker probe positioner and a special tool for installing it in the SG without personnel entry has been developed.
Using this new probe positioner and in-stallation tool, the Japanese have reduced personnel exposure by a factor of over two thirds per installation.
The earlier model of probe positioner, apparently still being used to perform most of the SG inservice inspections, requires entry of two people into the channel head for installation.
The new probe positioner, which was observed in operation at the MHI facilities in Osaka, had the capability of changing ECT probes without personnel entering the SG channel head.
This was accomplished by a long stainless steel belt which could be remotely unrolled from the finger walker carrying the ECT probe assem-bly with it.
The tethered belt and probe assembly are pulled out of the chan-nel head through the manway to change the probe assembly.
Discussion with the Japanese indicated that they have not done much work in the development of multiple ECT probe pushers or real-time ECT signal evaluation.
Tube plugging has also been greatly automated in Japan.
The Japanese have developed two machines for remotely performing tube plugging.
One of these units is mounted on the floor of the SG channel head and can be installed with-i out entering the SG.
The second unit is of the finger-walker type and requires 3-3 I
l
l entry of one person into the SG for installation.
With either of these units, l
mechanical plugs are transmitted to the unit from outside the SG and mechanical plug installation and inspection are performed remotely.
The Japanese have estimated that these units have reduced the work time and personnel exposure inside the SG to about one-tenth of the time and exposure associated with plugging performed by jumpers (temporary workers).
These units are also capable of installing tube sleeves.
Cleaning of the tube by brushing, inser' ion of the tube sleeves, expansion and welding of the tube sleeve, and dye penetrant examination of the seal weld can all be performed from outside the SG channel head.
Other actions taken to reduce personnel exposure include decontamination of the channel head using a boron blasting process when extensive work in the channel head is anticipated, development of a special SG manhole cover installation and bolting device, permanent installation of a greenhouse framework and air puri-fying system for use during SG inspection and maintenance, permanent installa-tion of ECT probe pushing cables, and permanent installation of pipes and re-mote jet driving devices to facilitate sludge lancing.
As indicated above, the Japanese have expended a great deal of effort on re-ducing the personnel exposure associated with SG inspection and maintenance.
The average exposure associated with SG inspection and maintenance activities is about 15% of the average total exposure during a scheduled inspection and maintenance period and corresponds to approximately 30-man rems per SG.
Many of the improved ECT and tube plugging and repair devices described above are recent introductions, and the Japanese indicate that they expect a reduction in personnel exposure associated with SG inspection and maintenance once these devices are put into routine use.
Part-time workers are used for some SG inspection and maintenance activities in Japan.
Exposure records for these workers are kept by the workers' employer and the power company.
Exposure records are elso given to the workers and re-corded at the Central Registration Center which is a public organization.
Each time a worker enters a power station his exposure record is checked by his em-ployer and the power company.
Hence the Japanese believe that no problems exist with migrant radiation workers in Japan.
Because of the extensive nature of the SG inspections and maintenance performed in Japan, these activities often lie on the critical path of scheduled mainte-nance and refueling outages.
During the years 1979, 1980, and 1981 the per-l centage of total plant outage time due to scheduled SG inspection and mainte-I nance was approximately 40%, 30%, and 40%, respectively.
The percentage of total plant outage time due to unscheduled SG inspections and maintenance during those years was approximately 3%, 0%, and 20% respectively.
l Additional background material relative to inservice inspection is given in Section 4 of Appendix A.2.
3.6 Monitoring of Personnel Exposure While at the Mihama site, the NRC group had the opportunity to enter the con-tainment building and to observe the Japanese health physics practices.
In many respects these practices parallel U.S. practices.
One advance worthy of 3-4
1 note was the computerized thermoluminescent-dosimeter monitoring system.
In this system each person is assigned a card similar to a plastic credit card with a magnetic strip attached.
By entering the card in a whole-body dose monitor when leaving a radiation area, the measured dose is immediately avail-able and automatically entered into the computer system for daily printout.
i i
I 1
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4 CONDENSER AND FEEDWATER SYSTEM DESIGN AND OPERATION As in the U.S., Japanese PWRs began operation using phosphate secondary-water chemistry, but because of difficulties in maintaining the water chemistry with-l in specified limits and resulting SG corrosion problems they converted to all l
volatile treatment (AVT) of the secondary-system water in 1974.
The basic philosophy of AVT water chemistry in Japan is to maintain the highest purity secondary water possible and to control pH through injection of hydrazine.
Effective AVT water chemistry requires a very " tight" secondary system to avoid
'l leakage of contaminants into the secondary water and quick response to mitigate the effects of any contamination of the secondary water that might occur.
This j
is particularly true of Japanese PWRs, which all utilize ocean water for con-i denser cooling.
This section discusses the design, operation, and inspection
]
of condensers, feedwater system design and operation, and secondary-water chemistry in Japanese PWRs.
4.1 Condenser Design, Operation, and Inspection i
j The condensers in all Japanese PWRs were manufactured by MHI.
As in the U.S.,
aluminum-brass and cupro-nickel tubing were originally used in the condenser,
{
feedwater heater, and moisture separator reheaters.
In more recent units,'how-ever, titanium and stainless steel are being used for condensers and feedwater heaters, repsectively.
J f
The Japanese condenser design. incorporates several features to facilitate de-tection of oxygen and cooling water inleakage.
These include six isolatable l
water boxes which can be filled with water, conductivity meters in each water l
box, and Na (sodium) meters in the condensate line.
During normal operation, the conductivity'of the condensate is 0.1 to 0.2 ps/cm (micro-siemens per cen-l timeter; a siemen is the same as a mho or reciprocal ohm).
A change in the
~
normal conductivity by 0.1 ps/cc is considered indicative of a leak and re-quires corre.ctive actions as dis:ussed in Section 4.3.
Regarding oxygen inleakage, dissolved-oxygen meters are installed at the outlet of the condensate water pump, manometers are located at the condenser vacuum pump or the air ejector, and the vacuum level is monitored.
During vacuum testing, inspections for oxygen leaks are conducted using smoke (joss stick) i and by listening for the hissing sound.of air leakage.
In addition, bellows l
and water sealing valves are used in the vacuum line to prevent air inleakage.
l l
Preservice condenser inspections consist of 100% eddy current testing (ECT) of the condenser tubing plus hydrostatic tests or foaming. tests.
For titaniue tubing, ultrasonic, radiographic, tnd air tests are also conducted during fab-rication, and ' dye penetrant exam:, are conducted during the preservice'inspec-I tion. As noted in Section 3.2, annual plant inspection and maintenance outages
)
are conducted every 12~(plus or minus 1) months.
During these inspections 100%
of the condenser tubes are inspected using ECT, although the list of items for.
inspection mandated by MITI does not include the condenser.
Hydrostatic or vacuum foaming tests are also conducted to detect leaks in the tube to tube-sheet junction.
No such degradation has been observed to date. Any tube with l
4-1 L
.u
a greater than a 50% throughwall indication is plugged or replaced.
Tube sleev-i ing has not been used as a condenser tube repair procedure.
Condenser inspec-tion during scheduled inspection and maintenance outages are not on the criti-cal path.
1 l
Although no standards exist for performing unscheduled condenser inspections,
~
the philosophy is to conduct such inspections any time the secondary-water chemistry quality cannot be maintained owing to cooling water inleakage.
The scope of the inspection would include all tubes in the water box in which the j
leak was detected.
No unscheduled inspections as a result of cooling water inleakages have been experienced to date. Only one unscheduled outage, for condenser cleaning, has occurred.
i 4.2 Feedwater System Design and Operation With the exception of Mihama Units 1 and 2 and Takahama Units 1 and 2, all Japanese plants operate.with condensate polishers.
In addition all units ex-cept Ohi Units 1 and 2 are equipped with deaerators.
All Japanese PWRs are on ocean sites and cooling water is taken from the sea.
All condensate polishers in Japanese PWRs are of the full flow, deep bed type.
Continuous full flow is maintained during operation at Mihama Unit 3, Ohi Units 1 and 2, and Takahama Units 3 and 4.
Water can also be circulated prior j
to initiating power operation.
The condensate polisher cation resins are re-i generated using hydrochloric acid (hcl) as opposed to sulfuric acid. in the U.S. Anion resin is regenerated with sodium hydroxide in both countries.
To minimize the potential for ionic leakage from the condensate polishers, they are maintained in the hydrogen / hydroxide form and regenerated at.75% exhaustion in Japan rather than at ionic breakthrough as is typical in most U.S. plants.
The lack of denting in Japanese SGs is convincing evidence that ionic quanti-l ties of hcl are not being released to the steam generators.
Additionally, j
hideout recovery tests show significantly less chloride.in Japanese plants.
1 i
Table 4-1 summarizes the tubing materials used in the low and high pressure feedwater heaters of Japanese PWRs operated by the Kansai Electric Power Co.
As indicated in the note to the table, the newer plants utilize stainless steel
)
in all feedwater heaters.
Water sealing and bellows type valves are used on the feedwater heaters to prevent air inleakage during operation.
In the last ten years, welded rather than flanged connections have been used in the feed-water heaters.
Table 4-2 summarizes the features of the moisture separator reheaters at PWRs
~
operated by the Kansai Electric Power Company.
4.3 Secondary-System Water Chemistry As indicated in the introduction to this section,' Japanese PWRs began operation using phosphate secondary-water chemistry treatment but,. because of associated I
l SG corrosion problems, converted to an all volatile treatment (AVT) of the secondary chemistry-in'1974.
4-2
All volatile water chemistry has no buffering capacity against aggresive impu-rities, and a very " tight" secondary system is required for effective operation on AVT.
As indicated in the previous sections, the Japanese through meticulous inspection and maintenance have been very successful in achieving the necessary secondary system integrity.
The Japanese utilize only hydrazine injection in the AVT water chemistry, whereas in some plants in the U.S. both hydrazine and ammonia or morpholine are typically used in AVT water chemistry.
Table 4.3 summarizes the secondary water chemistry limits specified for Japanese PWRs.
Table 4.4 presents similar limits which have been suggested as guidelines by the EPRI steam generator owners group.
Also important to a good secondary water chemistry program are the sampling u
points, techniques, and frequencies.
Table 4.5 presents the sampling points and Table 4.6 the sampling techniques and frequencies during normal operation.
Table 4.7 presents the monitoring locations and frequencies during plant shut-down.
During normal operation the conductivity of the condensate is 0.1 to 0.2 ps/cm.
A change in the normal conductivity by 0.1 ps/cm is considered indicative of a condenser leak and requires the following corrective actions:
a)
If monitoring of the condensate and SG blowdown indicates deteriorating secondary water chemistry quality (rising conductivity or sodium levels),
the SG blowdown rate is increased, b)
If the conductivity of the SG blowdown water exceeds the standard value (2.0 ps/cm), output is reduced and the section of the condenser where the leak is occurring is isolated and the leaking tube found and plugged or repaired.
c)
If the quality of the SG blowdown is judged to rapidly exceed the speci-fied limits.(conductivity: 120 ps/cm, chlorine ica concentration: 10 ppm),
the plant is shut down until the leaking condenser tube is identified and repaired.
These corrective actions may be relaxed if the plant is equipped with a conden-sate demineralizer capable of controlling the leak.
Actions to correct other out-of-specification parameters were not detailed by the Japanese.
Additional information on water chemistry in the secondary side of the steam generator is given in Sections 2.2 and 3 of Appendix A.2.
4-3 i
TABLE 4.1 Materials Used in Feedwater Heaters low pressure high pressure plant feedwater heater feedwater heater existing plants aluminum brass tube cupro-nickel tube we (Mihama Units 1, 2, and 3; Takahma Units 1 and 2; and Ohi Units 1 and 2) new plants same as above, except same as above (Takahma Units 3 and 4) for use of stainless steel in some parts (see Note below)
Note:
In Takahma Units 3 and 4, stainless steel is used in the air cooling zone of low pressure feedwater heaters Nos. 1 and 2 as a countermeasure against ammonium attack.
In Sendai Unit 2, stainless steel is used in low pressure feedwater heaters Nos. 1 and 2.
In Tsuruga Unit 2, stainless steel is used in all feedwater heaters.
4 I
4-4 l
TABLE 4.2 Moisture Separator Heater plant type heating tube n.oisture separa-tion type Mihama lu horizontallly cupro-nickel SUS wire mesh placed one-tube with fin stage heating Mihama 2u the same as the same as the same as abve above above Takahama 1, 2u the same as the same as the same as Mihama 3u above above above Ohi 1, 2u horizontally the same as SUS chevron placed two-above stage heating Takahama 3, 4u super size the same as the same as two-stage above above heating 4-5
Table 4.3 Description of water control on secondary side Typical Japanese PWR sample item unit standard value condensate acid conductivity at 25*C ps/cm 10.2 dissolved oxygen (0 )
ppm 10.05 2
pH at 25*C 8.8 - 9.3 feedwater conductivity at 25*C ps/cm
<5 dissolved oxygen (0 )
ppm
<0.005 2
total iron (Fe) ppm
<0.02 total copper (Cu) ppm
<0.005 total nickel (Ni) ppm
<0.005 hydrazine (N H )
ppm
<0.002 2 4 pH at 25*C 8.5 - 9.1 steam conductivity at 25*C ps/cm
<5 generator acid conductivity at 25*C ps/cm
<2.0 blowdown silica (SiO )
Ppm
<0.5 2
chloride (C1")
ppm
<0.1 i
sodium (Na*)
ppm
<0.1 free alkalinity ppm
<0.15 turbidity ppm
<1 main steam silica ppm
<0.02 i
f l
4-6
Table 4.4 EPRI guidelines on secondary side water chemistry control l
sample item unit EPRI guidelines I
condensate acid conductivity at 25*C ps/cm dissolved oxygen (0 )
ppm 10.01 2
pH at 25*C i
feedwater conductivity at 25*C ps/cm cation conductivity 1 0.2 a
j dissolved oxygen (0 )
ppm
<0.003 2
i total iron (Fe) ppm
<0.02 l
total copper (Cu) ppm
<0.002 i
total nickel (Ni) ppe
<0.005 j
hydrazine (N H )
ppm 13 x [0 3 2 4 2
pH at 25*C 8.8 - 9.2 i
sodium ppm 10.003 i
l steam conductivity at 25*C ps/cm generator acid conductivity at 25*C ps/cm 10.8 blowdown silica (SiO )
PPS 10.3 2
l chloride (C1").
ppm 10.02:
j sodium (Na+)
ppa 10.02 l
free alkalinity ppa l
turbidity ppa i
j ph 8.5 - 9.2 i
main steam silica ppe
<0.01 i
l i
1 I
4-7 i
,.n.-
,y n
r
- =.. - - -.,
-. -. - -.. -.. ~..
I i
TABLE 4.5:
TYPICAL SECONDARY WATER CHEMISTRY MONITORING LOCATIONS t
i ACID DISSOLVED CON 00CTIVITY CONDUCTIVITY OXYGEN HYDRAZINE
~
METER METER PH METER METER METER Na METER i
4 I
CONDENSER HOT WELL X
X C0 SENSED
- I CONDENSER WATER OUTLET PUMP X X
X1 X
t DEAERATOR INLET X2 DEAERATOR OUTLET X2 i
FEEDWATER FEEDWATER HEATER OUTLET X
X X
.i
?
STEAM GENERATOR SECONDARY WATER X
X X
.X
[
i f
STEAM X
i b
I L
6 i
F I
l 1
=.
=
y m
5 E5 Y Y
2
~y 2
m<
r
<=
50 5-
- 5. 55 gt
=
't "s mi a 23 r2 E<
8 k
6 4,,
5
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E!
3
=
8 f
3 jm
-55 5*
E E
E 5
i
=w R
"5 8
8 3
l W
5" W
1 S
>a-g E
ma of R
R
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g 8
8 8
8 8
E E
E E
38 E
Og *9 =
g m
3 e=
~
5
~$
5
$~
ma g
8 8
E E
E 8
=
5
=
.E
=W e
5-
~$
$~8
..9
=
E E
E 8
5
-5 i
t is JE i
l w
w E
3d G
x8 R
8 8
8 2
8 8
g gl m
e 5
8 8
E h
W E
2
)"
O e
f l
E E
5 8
E 5
's
=
a z
v M
r O
2 S
E e.
E a
e 5
a e
a 2
W m
o
=
u o
4-9
_m TABLE 4,6: SECONDARY WATER CHEMISTRY SAMPLING FREQUENCY (Continued)
STEM MAIN STEM REHEAT M0thiustE SAMPLE CONDENSATE FEEDmTER GENERATOR LINE STEM SEPARATORS CONDENSATE L.P. FEED mTER H.P. FEED MTER 5.G. SECONDARY CON HOT WELL PUMP 0UTLET MEATER DUTLET HEATER DUTLET SIDE W TER AMM0hlA OW OW OW OW OW OW ALKALI 00 MYORAZINE 00 s
O b
.---r m--
l I
TABLE 4.7 WET LAYUP WATER CHEMISTRY MONITORING SAMPLE LOCATION ITEM DEAERATOR STORAGE TANK STEAM GENERATOR WATER PH W
W HYDRAZINE W
W TURBIDITY W
4-11 l
5 EMERGENCY PROCEDURES AND OFFSITE DOSE CALCULATIONS 5.1 Emergency Procedures for Steam Generator Tube-Rupture Events The emergency procedures for handling steam generator tube-rupture (SGTR) events in Japan are similar to the SGTR procedures used by Westinghouse plants in the U.S.
The procedures were developed to direct the operator's response to the dou-ble-ended rupture of a single SG tube.
The Japanese government indicated that i
they believe that the SGRTR emergency procedures could also be effective in the case of multiple tube ruptures but that the subject of emergency procedures for multiple tube ruptures deserves additional study.
Since the largest tube leak in Japan was 0.3 gpm, none of the 10 events involving steam generator tube leakage has required the use of the emergency procedures.
The major steps in the SGTR emergency procedures are as follows:
a) identification of the leaking SG, b) isolation of the leaking SG, c) restoration of electric power to the non-safety-related bus (note that a safety-injection signal sheds this bus, including the reactor coolant 3
pumps),
d) cooldown through the unaffected SG, e) depressurize the reactor coolant system (RCS),
j f) recheck SG isolation, g) terminate the emergency core cooling system, h) restart the reactor coolant pumps.
i The emergency procedures also address steam formation in the RCS and natural circulation.
5.2 Offsite Dose Calculations for_ Steam Generator Tube-Rupture Events f
The offsite dose calculations done for the design basis SGTR are performed in a similar manner in the U.S. and Japan.
There appear to be only two areas of l
significant difference.
The first one relates to the treatment of iodine spik-ing during an SGTR.
For U.S. plants, NRC requires the assumption of a 500-times increase in the iodine production rate (i.e., iodine release rate from the fuel l
into the primary coolant).
In Japan, the analyses assume that the iodine pro-duction rate is proportional to the RCS depressurization, so that, if the RCS pressure drops by a factor of 2, the. iodine production rate is increased by a factor of 2.
This is therefore less conservative than the U.S. model assump--
tion.
I 5-1 l
The second area of difference relates to the offsite dose limits.
The U.S.
thyroid dose limit is "a small fraction of 10 CFR 100" (i.e., of 30 rem) while the Japanese thyroid limit is 1.5 rem.
5.3 Event Monitoring Capability During the tour of the Mihama site, the NRC group was shown the Mihama-3 con-trol room, which included several advanced features for the monitoring of events.
These features are in addition to the normal arr'ay of instruments and annunciators provided for Westinghouse designed PWRs inud include 14 closed cir-cuit television cameras inside containment with a monitor'and camera control in the control room.
The control room also had the capability for color graphics displays of plant computer information.
This included the capability to trend several parameters vs time; parameter vs parameter (pressure vs temperature, for example) as is done in some proposed Safety Parameter Display Systems; and a mimic of the reactor coolant system showing temperatures, pressures, flow valve status, etc.
Hard copy printout of this information was also immediatsly available in the control room.
Additional information on system response to an SG tube rupture and evaluat'icn of released activity is given in Section 6 of Apperdix A.2.
W e
,,W 5-2 j.
-~
. ~. - -.
4 4
6 JAPANESE STEAM GENERATOR RESEARCH PROGRAMS During the period from 1975 to 1981, a series of experiments.was conducted in Japan to demonstrate the reliability and safety of steam generators.
These experiments, called verification tests by the Japanese, addressed secondary-side thermal hydraulics, corrosion of SG tubes and tube support plates, and burst behavior of SG tubes.
The tests were conducted by the Japan Power Plant Inspection Institute at the Takasago Research Institute of Mitsubishi Heavy Industries.
The results of these test programs are presented in Section 4.5 of Appendix A.2.
The corrosion tests and SG tube burst tests, which are of par-
[
ticular interest, are summarized below.
)
The corrosion tests consisted of both pot boiler and large model steam genera-l tor experiments.
The pot boiler tests investigated corrosion of SG tubes and l
tube support plates with heat flux, impurity types and levels, and time as test parameters. Table 6.1 presents the matrix of pot boiler tests that were con-ducted.
The following results from the pot boiler test were reported.
- First, corrosion of Inconel 600 was observed under phosphate water chemistry, with e
I little difference noted between 3 to 5 ppm and 40 ppm phosphate treatment.
Wastage of Incoloy tubes was observed under low phosphate water chemistry treat-ment.
Relations between chloride concentrations in AVT secondary water chemis-try and pitting in Inconel 600 and thermally-treated Inconel 600 SG tubes and 1
^
corrosion of various tube support plate materials were developed. The main en-vironmental factors found to be related to denting were oxygen content, pH, and i
chlorine concentration. The presence of copper was also found to accelerate-l the denting process.
These results are all generally consistent with research l
results generated in the U.S.
l The large model SG corrosion experiments were conducted in a model SG with'a 3x4 array of U-bend tubes.
Each tube had a 15.9 mm diameter and a 1.2 mm wall i
thickness and was approximately 7 meters in height.
Table 6.2 summarizes the l
features of the model SG and the test conditions.
The large model test con-l sisted of one year of continuous operation on AVT water chemistry followed by inspection of the model SG tubes and support plates.
I The conclusions reached by the Japanese as a result of these tests is that inte-grity of the SG tubes can be maintained under strictly controlled AVT secondary-water chemistry.
Specific recommendations for avoiding denting were (1) avoid condenser leaks at all costs and (2) use support plates fabricated from corro-sion resistant materials with improved tube hole designs.
The. effectiveness of controlling condenser leakage to avoid denting is demonstrated by the operating experience in Japanese PWRs where tight condensers have lead to dent-free.
operation.
The SG tube burst tests included evaluation of burst and collapse strengths as a function of defect type and size, evaluation of the leakage rate and jet forces from a ruptured tube, and the effect of jet impingement and pipe whip-ping on adjacent tubes.
Table 6.3 presents the type of tests conducted.
H s
6-1
l l
Burst and collapse tests "ere conducted on Inconel 600 tubes with a radius of 10.48 mm and a wall thicknesi er 1.27 mm.
Electric-discharge machined slots I
and holes were placed in the tubes and the relation between crack geometry and l
burst pressure presented in Figure 6.1 was developed.
Tests were also con-l ducted on specimens containing stress-corrosion cracks to validate the relation I
between crack geometry and burst pressure for more realistic crack conditions.
The curves in Figure 6.1 agree reasonably well with the empirical burst strength relations developed in the NRC steam generator research program at the Pacific Northwest Laboratory (PNL); however, two discrepancies are noted.
First, the burst pressure for normal (undefected) tubes reported by the Japanese is ap-proximately a third lower than those reported in the U.S. by PNL.
This differ-ence results because the yield stress and tensile stress defined by MITI ere lower than those of actual tubes, and the experimental burst pressures were normalized by these defined stresses.
Thus the normalized burst pressure is lower than that of the test results.
The second discrepancy noted is that the l
Japanese relation for burst strength versus crack length shown in Figure 6.1 indicates that the pressure carrying capacity goes to zero as the crack depth approaches through-wall.
The experimental data from the PNL program indicate that even with a through-wall crack the tubing will continue to carry some pressure load.
For relatively short cracks, on the order of 0.25 inch, the tube will carry as much as 50% of the normal (undefected) burst pressure, and l
only for long defects, approaching 1.5 inches, does the pressure carryingr capa-bility approach zero.
Regarding collapse pressures of cracked tubes, the Japanese empirical ~ relation-ship between collapse pressure and defect size, shown in Figure 6.2, indicates similar trends to the PNL data except that the collapse pressures are again lower by approximately 25% or more.
This difference also results from normali-zation of the experimental collapse pressures by the MITI specified tensi?e strength.
In addition, the Japanese curve indicates a more rapid decrease in j
pressure carrying ability with increasing crack depth than the PNL data.
Despite the discrepancies observed in the Japanese and U.S. data on burst and collapse strength, both sets of data demonstrate the adequacy of current SG tube plugging criteria in the U.S.
In addition to tube rupture and collapse tests, the Japanese conducted a series of tests investigating the degree of erosion occurring due to emissions through SG tube defects and the effects of jet impingement on adjacent SG tubes.
The i
results of the tests were that up to 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> of continuous emission through slits and holes did not cause significant expansion'of the openings.
Studies' regarding jet impingement shov?! shct jet forces from leaking tubes had'no significant detrimental effo ts c a adjacent tubes.
The results of these tests' are significant with res-tri co
- se issue of multiple tube failures; however, none of the target tube. !? A5..vt tests were degraded, which might have been a more interesting test sit 9ation.
Table 6.3 indicates that leak rates were mea-sured as a function of defect dimension; however, when questioned about SG tube leak rates, the Japanese emph4 sized that none of the above-mentioned' tests were-performed as leak rate tests.
They explained that, since they do not rely on leak rate limits but on plant shutdown due to any detectable' leakage, they have no significant interest in leak rate testing. ERe:ults of the leak rate tests
'were not presented.
ss 6-2 29, i
I i
Regarding future research, the Japanese have divided their efforts into three different areas addressing SGs to be constructed in the future, SGs under con-struction or planning, and SGs in service.
As discussed in Section 3.1, a major part of the development of advanced PWRs is the development of improved i
SGs.
Regarding SGs under planning or construction, the results of research and field experience have been incorporated in SG designs as they become avail-able.
The history of SG design changes is covered in Section 3.1.
- Finally, regarding operating SGs, the research emphasis is on inspection and maintenance procedures to prevent degradation and ensure integrity of the SGs for their i
remaining life.
t l
l l
6-3'
Table 6,1 Conditions of Partial Corrosion Simulation top corrosion simulation el eme ntary corrosion simulation test time 50, 100, 300, 1,000, 2,000, 3,onq go00, 7.000, 9,000, 12,000 h 1
heat flow quality q=25 x 109kcal/m'h q =15 x10 4 kc2/,_q = 30 x 10*kcal/m2h 2
mh x=0 X=0.1 X=0.3 decree of subcoolino 0.100C
. mass velocity 82, 165, 329 ko/m s d
1.
AVT 2.
AVT + C1 (Cl=0.1, 0.5, 2,
6 ppm, etc.)
3.
AVT + sodium hydroxide (Na Oll= 0. 0 5, 0.5, 2 ppm, etc.)
water treatment 4.
sodium phosphate 5.
sodium phosphate + C1 (Cl=2 ppm, etc.)
6.
others (AVT + Cl +DO2, salt water + CuCl2, etc.)
heating pipe material Inconel 600 Inconel 600, Incoloy 800 TT Inconel 600 Improved Incolov 800, Inconel 690 m
A cooler material carbon steel carbon steel stainless steel shape of heating pipe straight pipe straight pipe U shaped pipe buffer B,
C, C-1 A,
B, C,
C-1, D.
T, T-1 pipe plate buffer plates i
g broach model drill mode:
fin model T model egg crate mode (* d*1 C),
(model C)
(model D)
(model A)
(
-N h
drill model with chad >er (C-1)
T-1 model h+
h+
i l
l r
Table 6.2 Steam Generator Properties and Heat Flow Conditions Jtem Property heat input (kW) 1,500 primary side pressure (Kg/cm g) 157 temperature
(* C) 320 secondary side pressure (Xg/cm g) 58 temperature (* C) 273.2 main steam flow (kg/h) 3,000 heating pipes
' umber 3 x 4 U bend n
diameter (mm()
15.9 thickness (mm) 1.2 material Inconel 600 l
buffer plate 7 steps (model C) thickness (mm) 19 material SB 42 perpendicular mass velocity (kg/m s) 229 degree of inlet subcooling
(*C) 5 l
ciruelation ratio 3.8 4
heat flow * (kcal/hr) 28 x 10
- heat flow is the maximum value l
t 6-5
)
l l
l Table 6.3 Resting pipe pupture Test items and Conditione tset itema test detaile test conditione semple pipe type of damage detalle of studies temperature preseuge testing time
(*C)
(ka/cm )
l caudies on strench internal pressure 320 pressure inconel 600 (actuet aire anlet erosion Correlation between length and l
Et deneged pipes-break strength of difference pipe) eslal fractures depth of deesse sad laternal and enount eeltted damaged pipes and 80-700 Incomet 600 (scaled pipe) pressure break strength ves from rupture pipes in good lacanel 800 (actnet else) determined, opening condition under actual operation conditione study of enount of 320 and pressure 10-60 seconde Incenel 600 (actuel else) esist eroelen Ceareletles between the disenelene of esteolon from rupture normal difference estal fractures the doene and eenuet of esloelon free opening during temperature 100 opening uos deterelned, rupturing studies on esternal 320 esternet Inconel 600 (actual else)
IIst Correlation between disenelone of the pressure break pressure estal eroelos densee and outelde pressure break strength of demoged 550 strength one determined, pipes and pipes in good condition ender actual operation conditione study of erosion studies on damage to prisery side primary side B-20 hours laconel 400 (actual else) sound helee pengreselon of rupture opening due to emission rupture openings due to 200-320 137 Inconel 800 (setual else) elite erosion up to plant eheduon ef ter current erosion under setual secondary side secondary side rupturleg use studied.
operaties eenditione 273 58 h
study of deesse in 1-20 heure Inconel 600 (setual else)
Demoge to edjacent pipes du, to beati g pipes due to incomet 800 (actuel sized) erosion free jet etrese during erosion free emiselee ruptering uso studied.
current under actual operetnos coedieions tests on dynamic preliminary testo serust primary side 30-60 seconde Incenel 600 (netual else) estal erosion Tieval eteervatione of dyneetc beheolor of on beheelee of temperature 80-520 Incomet 600 (% oceled pipe) guillotine ruptures behetfor under normel teegeratures.
damaged pipes ruptured pipes and seco6dery side (rupture disc) desi 3 rupturing adjacent pipes under atmospheric moreal temperatures pressure teste se thrvet end primary side primary side 30-60 seconde Inconel 500 (setual sise) 5tueles df thrust en ruptured pipes jet force during 320 130-154 Incomet 600 (% ocated pipe) free enleelen current and jet force on rupturing underectual secondary side secondary side adjacent pipes free eeleolon current operettom conditiene 270 46-54 under actual operetten conditione.
dyneele bebevior of primary side primary side 30-60 seconde inconel 600 (actual else) 5tudies on conneetl E between ruptured pipee 320 330-860 inconel 600 (% ecaled pipe) dyneele bebevlor of ruptured pipes and end adjacent pipes secondary side
. co.g.,y agge adjacent pipes under actual operation under actual 270 40-40 conditione and dimenolone of rupture.
operation conditione
crack coonditions see ac sc
)
=
y e
_r 1_ e h
h Soo -
No corrosion conditions 5
m c-s =
i ge's
,=
c - i...
..ww e
,c k
D a
5 200 -1M 2C-20..
8, 2c-..
. d,4 X 3co eekD e
e 20 do ao so aco Ct'6ck & & % We) 1 Figure 6.I Normalized Burst Pressure vs Crack Depth i
i l
I
~n l
g u
l N
l o
X 30c s c - zo.,
~
u 2c-so..
a ed< S 200 1.s Da sc
-M8
,$t' i go corrosion conditions
' sam ett 4
l ne e
as ao so ao no e40 a/t (*)
o Cros k kp+4 Figure 6.2 Normalized Collapse Pressure vs Crack Depth 6-7 r
I i
i i
APPENDIX i
NRC Questions and Japanese Written Responses 1
i Concerning Steam Generators i
I e
I I
e I.
4 1
I i
a 1
l l
l i
1 e
d i
l I
APPENDIX A.1 AGENDA AND QUESTIONS ON STEAM GENERATORS BY NRC FOR MEETINGS WITH THE JAPANESE i
P_a_ge 1.
Introduction 2.
Steam Generator Design A.1-2 3.
Secondary Water Chemistry A.1-5 4.
Inservice Inspection A.1-6 5.
Steam Generator Integrity A.1-11 6.
System Response A.1-13 7.
Other Issues A.1-16 8.
Conclusions J
Y I
i A.1-1
2.
STEAM GENERATOR DESIGN 2.1.
Design and Materials Selection for Steam Generators Which steam generator designs are in operations and under construction?
Materials and heat treatments used for tubes, tube sheet and tube support plates.
Tube support plate' design with respect to its interaction with tubes.
Designed flow velocities across tube sheet.
Percentage of tube-to-tubesheet annulus eliminated' by expansion.
Tube bending processes.
- Thermal treatment of tubes versus mill-annealed tubes for purpose of resisting SCC.
Has any thermal treating or shot peening of u-bends been performed to reduce residual stresses.
What design modifications have you made when doing your own steam generator manufacture.
What design modifications have been made in the field.
l Are tubesheet crevices eliminated by expansion.
e method used a to what depth 1
A.1-2
2.2.
Design and Materials Selection for Balance of Secondary Cycle Condenser tubes and tubesheet.
Condenser air removal capabilities.
Moisture separator / reheater.
Condensate polishers.
e full flow or partial flow e powdex or deep bed e operated continuously or intermittently de-aerators
- What variations exist from plant to plant.
l l
l A.1-3
2.3.
Induction Heating Stress Improvement (IHSI) o What is your experience with IHSI? What are the critical variables in IHSI application? Can IHSI apply to any pipe sizes, elbows, branch connections or smeepolet? What is the possibility of long term relaxation of compressive stress?
o How effective is the IHSI on the cracked pipe?
O Could IHSI increase the material sensitization or low temperature sensitization in the pipe?
i o What is the result of the accelerated corrosion test or the pipe weld with IHSI?
o What is the effect of IHSI on the efficacy of ultrasonic testing of pipe welds?
l 1
l A.1-4
I i
3.
SECONDARY WATER CHEMISTRY e Description of secondary water chemistry (are limits applied uniformly to all plants) e Means used to maintain chemistry within limits.
Instrumentation Sampling frequency Corrective actions in response to out-of-spec parameters (limits which require power reduction or plant shutdown)
Wet layup practices (frequency of surveillance sampling).
Who is responsible for water chemistry control Flushing and blowdown from steam generators / balance of plant l
e Experience with closed loop cooling systems (cooling towers) vs straight through cooling systems e Condenser inspection and repair practices How are leaks located / repaired What is the quantity of leakage which can be found How frequently are condensers inspected /how many tubes What are the criteria for tube plugging e How are air leaks detected / repaired It is our understanding that condensate polishers are regenerated e
using H+CL.
What is the reason for this practice Does not HCL cause denting in steam generators What variations are allowed from utility to utility e
A.1-5
4 l
- 4. INSERVICE INSPECTION 4.1 STEAM GENERATOR INSPECTION l
)
1.
What techniques are used in conducting preservice and inservice steam generator inspections (i.e., eddy current testing, profilometry, radiography, visual, etc.)?
2.
What are the preservice and inservice inspection parameters (i.e., what do you look for:
tube thinning and cracking.
l tube denting, crude buildup in crevices, sludge pile, support plate cracking, tube ovality, etc.)?
3.
What is the scope of preservice and inservice inspections t
(i.e., how many steam generators are inspected; how many tubes are inspected in each steam generator; what portion of each tube:
hot leg, cold leg. U-bend, is inspected; what type of loose parts and secondary side inspections are perfonned)?
4.
What is the frequency of inservice inspections (i.e., how often are scheduled inspections required; what type of events such as tube leakage, earthquakes, or system transients require that unscheduled inspections be perfonndd)?
5.
What are the primary to secondary leakage rate limits?
How is the leak rate monitored and what actions are required in the event of a leak exceeding the leak rate limits?
6.
What are the bases for the leak rate limits? Has a correlation between leak rate, crack size, and tube burst strength been developed?
7.
What are the bases for the scope and frequency of the j
preservice and inservice inspections (e.g., are they based on operating experience, statistical analyses, i
economic considerations, etc.)?
8.
What design features are incorporated in steam generators j
to facilitate inspections (e.g., number and location of inspection ports, etc.)?
9.
What is the percentage of total plant outage time due to scheduled steam generator inspection and maintenance?
- 10. What is the percentage of total plant outage time due to unscheduled steam generator inspection and maintenance?
A.1-6
l l
- 11. What type of eddy current testing techniques are used?
Single frequency, multiple frequency, analog or digital subtraction, absolute, differential, pancake prob'es, etc?
- 12. What standards are used for calibrating eddy current i
testing equipment?
- 13. What electrical frequencies are used for various types of eddy current testing?
- 14. What type of eddy current or other inspection techniques are used for inspecting tube sleeves? Have standards for the inspection of tube sleeves been developed?
15.
How are addy current testing data evaluated - visually on oscilloscopes or by computer?
16 '.
Is real time data evaluation used in the field?
- 17. What type of eddy current or other inspection techniques are used to inspect for tube. degradation in the tube to tubesheet crevice? Have you had difficulty in detecting degradation in this area?
- 18. What type of eddy current testing is used to inspect for -
stress corrosion cracking in small radius U-bends? Have you had difficulty in detecting such cracking?
- 19. What type of eddy current testing do you use to inspect for cracking just above the tubesheet in the transition region between the expanded and unexpanded section of the tube?
20.
Do you routinely inspect for circumferentially oriented degradation?
- 21. What are the tube plugging criteria? Do the criteria l
consider both depth and length of defects?
- 22. What are the criteria for sleeving degraded tubes?
l
- 23. What margins are included in the tube plugging criteria j
to account for eddy current testing error and degradation between inspections?
24.
Are tubes preventively plugged on the basis of ovality or reduction in diameter?
A.1-7
25.
What are the bases for the steam generator tube plugging criteria? What experiments have been conducted to detemine rates of degradation and tube burst and collapse' strengths?
26.
What methods of tube plu ging are used (e.g., explosive, welded, mechanical, etc. ?
l 27.
What methods of tube sleeving are used (e.g., hydraulically or mechanically expanded)?
28.
Please provide a list of references related to steam generator inservice inspection programs, techniques, and regulatory requirements.
4.2 CONDENSER INSPECTION 1.
What special features are incorporated in the condenser design to facilitate oxygen and circulating water leakage detection and tube inspections (e.g., leak detection troughs at each tubeshr-t, design of condenser internals to withstand water solta conditions for leak testing, isolatable water boxes, etc.)?
2.
What techniques are utilizdd to monitor for condenser air inleakage?
3.
What techniques are used for detemining the location of oxygen inleakage (e.g., tracer gases, etc.)?
4.
Have standards been developed for detecting and identifying the location of oxygen leaks into the condenser?
If so, what are the major elements of these standards?
5.
What techniques are used for identifying and detemining the location of condenser-circulating water inleakage (e.g., tracer testing, etc.) gases, hydrostatic tests, eddy current
?
l l
6.
What techniques are used during scheduled condenser prescevice and inservice inspections?
7.
What is the scope of scheduled condenser preservice and inservice inspections? How many tubes are inspected?
What portion of each tube is inspected?
8.
What is the frequency of scheduled condenser inspections?
9.
What are the criteria for conducting unscheduled condenser inspections? What is the scope of unscheduled inservice inspections?
A.1-8
- 10. What type of eddy current testing is used for inspection of condenser tubes?
- 11. What techniques ire used to inspect for tube to tubesheet degradation?
12.
What are the criteria for condenser tube repair (e.g.,
degree of tube wall thinning, etc.)?
13.
What repair techniques are used for degraded condenser tubes (e.g., plugging, sleeving, etc.)?
14.
What is the total number of hours (scheduled plus forced) of plant outage due to condenser inspection and maintenance?
15.
What is the number of hours of forced outage due to condenser inspection and maintenance?
16.
What is the percentage of total plant outage time due to scheduled and forced condenser inspection and maintenance?
f
- 17. What is the number of power reductions and forced outages due to condenser inspection and maintenance?
l
- 18. What percentage of forced dutages and power reduction are due to condenser inspections and maintenance?
19.
Please provide a list of references related to condenser inservice inspection and maintenance programs.
4.3 HOW ARE LOOSE PAP,TS C0tlTROLLED7 Quality assurance and quality control accountability measures on all work involving the inside of the steam generator?
Visual inspections? What parts of the SG7 Frequency?
Loose parts monitoring systems. Method of operation? (threshold alarms? Training requirements for LPMS to give reliable signals from the secondary system?
4.4 OCCUPATIONAL RADIATION EXPOSURE 1.
To what extent are steam generator tube inspection and plugging procedures automated?
2.
How is the eddy current testing probe positioner installed in the steam generator? Does it require entry of personnel into the channel head?
3.
Does the tube plugging procedure require entry of personnel into the channel head?
A.1-9
4.
What special techniques cr procedur;s are used to minimize l
personnel exposura (e.g., d2 contamination, shielding, etc.)?
5.
What is the average man-rem exposure associated with installation of eddy current testing equipment in the steam generator?
6.
What is the average man-rem exposure per tube inspected and per tube plugged?
l l
7.
What is the average man-rem exposure associated with a routine steam generator inspection and maintenance outage?
I 8.
To what extent has the tube sleeving process been automated?
4 i
9.
Are temporary employees used for steam generator inspection.
maintenance, repair, or replacement?
If so, are records kept of their radiation exposure and are these records cross-l checked between plants and utilities?
- 10. What are the occupational radiation exposure regulatory limits? Do utilities use any other limits?
- 11. What percentage of total personnel radiation exposure is a result of steam generator inspection, maintenance, and repair?
i
- 12. What are the financial costs associated with steam generator l
inspection, maintenance, and repair?
- 13. Have any cost benefit, analyses related to steam generator maintenance and inspection programs been conducted? If so, what are the results?
i i
14.
Please provide a list of available references on the subject of personnel radiation exposure related to steam generator maintenance and inspection programs.
I 4.5 RESEARCH 1.
Please discuss the results of reseerch conducted at the i
Mitsubishi Takasago Research Institute on the influcence of
]
fractured tubes on adjacent tubes.
Have the effects of jet impingement or whipping tube impact on adjacent dearaded tubes been studied? On the basis of the test results, what do you conclude about the potential for multiple tube ruptures?
2.
Please discuss the results of leak rate testing conducted at the tiltsubishi Takasago Research Institute. Have leak rate tests been conducted on burst tubes? How have the results of leak rate tests been used in establishing primary to secondary leak rate limits?
3.
What is the procedure for transferring research results and developments to operating plants?
4.
What areas of steam generator integrity have Japanese utilities i
identified for future research?
A.1-10
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+---+--y,y---+--,e---+-w m-m 1------,---
-<m
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- - - ~ - - - -
5.
STEAM GENERATOR INTEGRITY 5.1.
Do you have a document which discusses the overall history of operating problems?
e Experience with wastage stress corrosion cracking (primary or secondary side) denting U-bend cracking pitting fretting loose parts and foreign objects fatigue cracking other problems e Corrective actions taken for,above problems
- 5. 2 What is the frequency / Reactor year of leaks, rupture and forced outages due to each degradation mode?
Forced Mode 0.1 gpm 0.1.3 gpm
&.3-Rupture Outage Wastage SCC Denting U-Bend Crack Pitting Fretting Fatigue Crack Loose Parts Other l
1 A.1-11
5.3 What are Experiences with Steam Generator Tube Repairs What types of plugs are used/how are they installed.
What types of sleeves are used/how are they installed.
Do you have criteria for plugging dented tubes.
What is the operating experience with plugged / sleeved tubes.
e Do they come loose or leak.
1 t
i l
A.1-12
t 6.
SYSTEM RESPONSE 6.1 System Response to SGTR's and to Leaks II. System Response to SGTR's and to Leakt o Operating pmcedures provide for l
early identification of affected SG7 1
isolation of affected SG l
cooldown method chosen (by use of condenser or steam dumps?)
actions to respond to sultiple tube ruptures I
methods for RCS depressurization (PORY use pressurizers spray use auxiliary spray use)
{
o Use of Reactor Coolant Pumps Trip and restart criteria o Use of HPI pumps j
maintenance of subcooled margins?
o Avoidance of SG overfill?
o How are the following item considered in your procedures.
s Availability of Faulted SG Safety and Relief Yalve j
kitiple and Second Order Failure's Bubble Formation Cooling Faulted Steam Generator Cooling Intact Steam Generator i
Safety Injection Pump Temination and Restart Criteria Procedures Fomat and Clutter Criteria for Natural Circulation Detemination l
Acconnodation of Plant Differences from Reference Plant in Emergency Procedure Development A.1-13 4
_ - - - - - - - ~ _ _ - -
Rapid Detemination and Isolation of Faulted SG and Timely
[
Depressurization of RCS to Minimize RCS Inventory Loss and Releases MSIV Closure During Plant Cooldown l
Use of Charging and Letdown Systems i
Operation of the Reactor Coolant Pump in the Damaged Loop Operation of Loop Isolation Valves Use of Pressurizer PORY Potential Complicating Events Site-Specific Operator Training 1
Steam Generator Level Control for CE Plants 1
6.2 III.
Radiological Consequences Experience with release of radioactivity during any leaks or ruptures.
j o
1 o Regulatory criteria for release of radioactivity.
o Design basis SGTR analysis.
Single or multiple tube ruptures.
Iodine limits (with or without Iodine spiking)
How do your tube rupture analysis' compare with the German & US accident assumption (attached) i J
6.3 Design Base Accident
- How does the Japanese Design Basis Accident Analysis compare to the NRC Design Basis Accident?
A.1-14
l TABLE 1
$1gnificant Steam Generator Tube Rupture Accident Assumptions Gerunn Study letC Design Basis Accident Japanese Design Basis Accident i
- 1) 10 tubes ruptured.
I tube with a double ended rupture, as the limiting case for leakage of multiple tubes.
- 2) 0.9 uC1/ge I.131 inital plan specific Technical Specification limit primary coolant on initial coolant concentration. (1.0 uC1/ys concentration.
dose eq alvalent I-131* for plants with Standard Technical Specifications and between 2.0 uC1/yn l
J dose equivalent I-131 and no specific limit on
]
radiofodines for plants without Standard Technical t
Specifications) i
- 3) 9.5 hr. accident duration.
plant specific accident duration almost alueys l
0.5 hr.
I 4)
Relief valve stock full Relief through atmospheric dump or relief valves epen for duration of
- y untti pressure reduction in the affected steam
{
the accident.
generator, plant specift,c almost alueys 0.5 hr.
- 5) Decentaminetten factor of Condition-dependent decontamination factor.
5 for virtually the whole Simplified calculations have used an average accident.
value of 10 for Westinghouse and Combustion Engineefing plants and 1 for Babcock and W11com plants.
- 6) Spiktag of I-131 above the Spiking)of dose equivalent I-131 release rate (C1/sec by a factor of 500.
tettfal veise: an increase in the I-131 concentraties-(eC1/ge) W e factor of ISS Ifnearly over 25 seconds.
constaat thereafter.
l
- 7) inyreld dose Iteit of Thyroid dose guideline of 30 Ren.
I 15 Ass.
l l
That concentratten of I-131 which alone umuld produce the same thyroid dose as the quantity and isotopic I
misture of radiotodines actually present.
i
?
7.
OTHER ISSUES (Those Involving Steam Generators) 7.1 Water Hammer Have you experienced any water hammer events in the main steam or the main or auxiliary feedwater system?
What procedural changes or modifications have you made with respect to water hanner?
Have you had any experience with thermal cycle fatigue cracking in I
feedwater line?
j Do you have a program related to thermal cycle fatigue cracking in feedwater lines?
j Are the main steam lines designed to withstand steam generator overfill (water solid con,dition)?
7.2 Risk What is your assessment of the risk of core melt or of a I
significant radiological release from single or multiple tube ruptures?
i i
4 I
i i
r A.1-16 1
l
I APPENDIX A.2 WRITTEN RESPONSES BY THE JAPANESE TO NRC QUESTIONS P_a2_e 2.1 Design and Materials Selection for Steam Generators A.2-2 2.2 and 3.
Water Chemistry in the Steam Generator Secondary Side and Design of the Secondary System A.2-10 4.
Inservice Inspection A.2-20 1
5.
Integrity of Steam Generator A.2-46 6.
System Response A.2-57 7.1 Water Hammer A.2-63 A.2-l
~._ _ _.._, __ _
l l
l 2.
STEAM GENERATOR DESIGN
]
l 2.1 Design and Materials Selection for Steam Generators l
Domestic steam generators are being designed and manufactured by Mitsubishi Heavy Industries under the technological agreement with Westinghouse of the U.S.A.
i History of Design and Improvement of Steam Generators Since the first steam generator was manufactured in Japan for Mihama No. 2 in i
1970, 20 steam generators have been manufactured already in Japan, and Japan has
)
ten years' experiences of steam generator operation.
(Refer to Table 1.)
l Meanwhile, various improvements have been made to improve reliability, taking l
j advantage of operating experiences both within and outside the country.
i j
Translation of Japanese entries in the figure of a steam generator on the next page:
j 1.
steam outlet nozzle 9.
tube bundle l
2.
moisture separator
- 10. tube sheet 3.
manhole
- 11. manhole 4.
upper shell
- 12. partition plate 1
5.
swirl vane moisture separator
- 13. water chamber 6.
feedwater inlet nozzle
- 14. primary water inlet nozzle 7.
Iower shell
- 15. primary water outlet nozzle 8.
tube support plate 4
Translation of Japanese entries in Table 1, giving a list of domestic steam generators:
i 1.
electric power company 7
2.
power station 3.
number of steam generators 4.
type of steam generators 5.
commencement of operation i
6.
remarks 7.
troubles occurred I
8.
wastage 9.
damages in crevice
- 10. cracks on U-bent part
- 11. damages on tube expanded part i
- 14. Kansai Electric Power Co. Inc., Mihama No. 2 l
- 15. Kansai Electric Power Co. Inc., Takahama No. 2
- 16. Kyushu Electric Power Co. Inc., Cenkai No.1 l
- 17. Kansal Electric Power Co. Inc., Mihama No. 3
- 18. Shikoku Electric Power Co. Inc., Ikata No. 1 l
- 19. Kansai Electric Power Co. Inc., Ohi No. 2
- 20. Kyushu Electric Power Co. Inc., Genkai No. 2 A.2-2
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- 52. 9 (M N E M X E 29) 4 5tA
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A.2-3
- 21. Shikoku Electric Power CO. Inc., Ikata No. 2
- 22. Kyushu Electric Power Co. Inc., Sendai No. 1 _
- 23. Kansai Power Electric Co. Inc., Takaharta No. 3
- 24. Kansai Electric Power Co. Inc., Takahama No. 4
- 25. Kyushu Electric Power Co. Inc., Sendai No. 2
- 26. Japan Atomic Power Co. Inc., Tsuruga No. 2
- 27. Import:
Kansai Electric Power Co. Inc., Mihama No. 1; Kansai Electric Power Co. Inc., Takahama No. 1; Kansai Electric Power Co. Inc., Ohi No. 1
- 28. planned
- 29. under production
- 30. manufactured by CE In the order of development, Japanese steam generators may be classified into Types 44, 51, 51M and 51F, all of which are basically the same.
Experiences have been accumulated to develop all these types.
Another characteristic in our development of steam generators is that new design features have been adopted step-by-step only after thorough verification, experiments and analyses.
Steam Generator Operating Experiences and Design Improvements Since the beginning of the 1970's when operation of steam generators was commenced, damages have occurred on the heat transfer tubes due to the sodium phosphate which was added to control the water chemistry in the secondary system.
Representative cases of damages are stated below.
As shown in Table 1, troubles have occurred only in the plants of early times.
(1) Wastage of Heat Transfer Tubes due to Sodium Phosphate Initially, sodium phosphate was added to the secondary water system as a buffer to prevent corrosion and also as a buffer.against foreign chemicals leaked from the condenser. This chemical was concentrated within the crevices between the tubes and tube support plates and within the sludge-(deposits of rust, etc.) on the tube sheet to waste the heat transfer tubes due ta corrosion.
(2) Crack on Heat Transfer Tubes by Alkali (Sodium Hydroxide)
After experiencing wastage of heat transfer tubes, yater treatment method has been changed at plants, but sodium phosphate leftdn the crevices between tubes and tube sheet holes went through chemical changes to produce sodium hydroxide which caused damages on the heat transfer tubes.
(3) Damages on Heat Transfer Tubes due to Denting i
At the plants abroad where the secondary water was deteriorated due to leak from the condenser, a phenomenon of denting of heat transfer tubes has been j
occurring owing to corrosion of carbon-steel tube support plates.
(Such denting has not occurred in Japan where water chemistry control is strict.) At the '
Surry and Turkey Point plants in the U.S.A. where denting is extensive, replace ments by new steam generators have been effected or are under way.
>I s
k i
A.2-4 s
i
(4) Damages on Heat Transfer Tubes at Small Radius U-Bent Region In some U.S.-made steam generators, stresses left from bending operation have l
caused stress corrosion cracks on small radius U-bent regions at some, plants.
(5) Stress Corrosion Cracks on Tube Expanded Region High stresses left on the tube expanded region have caused stress corrosion cracks at several plants.
(6) IGA on Tube Support Plate IGA (intergranular attack) has occurred at some plants owing, it appears, to intrusion of dissolved oxygen or a very small amount of impurity.
Though the troubles of (1) through (3) above have been caused primarily by deterioration of water in the secondary system, design improvements of steam generators have also been effected on the basis of the following thinking.
(a) The structure of the tube support system is such as to control impurities to the largest possible extent when impurities enter into the secondary system.
(b) As sludges may produce crevices if they accumulate on the tube sheet, the structure is such as to prevent accumulation of sludges.
(c) Materials with excellent corrosion resistance are used for heat transfer tubes and tube support plates.
i (d)
In order to improve SCC (stress corrosion cracking) resistance, a produc-tion method to leave stresses as low as possible on the heat transfer tubes is adopted.
Types and Characteristics of Steam Generators Types of steam generators have undergone changes.
Currently, Type 51F is being manufactured.
The various types have features as follows:
(1) Type 44 Steam Generator l
The design of Westinghouse has been directly adopted.
In comparison with Type 51 Steam Generator, it has a somewhat smaller heat transfer area.
It hardly differs from Type 51 with respect to the structure and materials of major parts.
1 (2) Type 51 Steam Generator The majority of steam generators in operation in the U.S.A. and Japan are this type.
Type 51 of Mitsubishi and that of Westinghouse are basically the same in design.
As for design improvement, those manufactured later are provided with full-depth tube expansion to prevent crevices on the tube sheet holes.
Type 51 Steam A.2-5.
Generator which adopted all volatile treatment (AVT) from the beginning, is con-sidered to have demeurtrated from past operation experiences that its basic design is adequate.
(3) Type 51M Steam Generator In order to prevent damages on the heat transfer tubes in sludges which have occurred abroad, the flow in the secondary side of the steam generator was improved to reduce the stagnation area on the tube sheet.
In other words, the flow velocity of circulating water was increased and a flow distribution baffle (FDB) was installed.
As a load increase on the moisture separator was expected as a result of the above-mentioned improvements, the primary and secondary moisture separators were improved.
Additionally, in those manufactured later, Inconel 600 with special thermal treatment (TT Inconel 600:
Special Thermal Treatment Inconel 600) and SUS 405 were adopted for heat transfer tubes and tube support plates, respectively, as highly corrosion-resistant materials.
(4) Type 51F Steam Generator Type 51F is being manufactured.
In this type, the configuration of the tube support plate has been modified to improve anti-concentration performance and measures against denting have been further improved, in addition to the improve-ments and modifications done with Type 51M.
This is a fruit of research and development efforts since 1972.
In designing and manufacturing individual parts, detailed verification and optimization have been done.
As for various troubles I
experienced, higher margins are provided to improve the quality of this steam generator.
Q.2.1-1.
Which steam generator designs are in operation and under construction?
In operation....
Mihama No. 1 CE design, manufacture Mihama No. 2 MHI 44 Series (similar to W44 Series)
Mihama No. 3 MHI 51 Series (similar to W51 Series)
Takahama No. 1 W 51 Series l
Takahama No. 2 MHI 51 Series l
Ohi No. 1 W 51A Series Ohi No. 2 MHI 51A Series Genkai No. 1 MHI 51 Series Genkai No. 2 MHI S1M Series (similar to W SIM Series)
Ikata No. 1 MHI 51 Series Ikata No. 2 MHI SIM Series Under construction..Sendai No. 1 MHI 51M Series Sendai No. 2 MHI 51F Series (similar to W 51F Series)
Takahama No. 3 MHI SIF Series Takahama No. 4 MHI 51F Series Tsuruga No. 2 MHI 51F Series s-t A.2-6 7
Q.2.1-2.
Materials and heat treatments used for tubes, tube sheet and tube support plates.
j materials heat treatments Tubes (a)58-163 Ni-Cr-Fe alloy mill annealed (b) SB-163 Ni-Cr-Fe alloy thermally treated (In order to improve anti-SCC sensitivity, tubes for Sendai i
No. 1 and thereafter were treated at 700*C for 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br />.)
i Tube Sheet (a) SA-508 Class 2 quench and temper (b) SA-508 Class 3 quench and temper i
l (Genkai No. 2 and thereafter adopted Class 3 material which j
is less likely to get under-clad cracking.)
Tube Support Plates (a) JIS G3103 none SB-42 (6) JIS G4304 annealing SUS 405 (Ikata No. 2 and thereafter adopted SUS 405 to increase an allowance for denting phenomenon on the tube support plates.)
Q.2.1-3.
Tube support plate design with respect to its interaction with tubes.
i Shape of the tube hole of the tube support plate to support the tubes.
Design-changes to reduce concentration phenomenon to be caused by corrosion on the crevice part of the tube support plate which may occur when sodium hydroxide is used to control water c _aistry in the secondary system.
51/51A Series:
drilled hole 51M Series:
(a) drilled hole with reduced flow hole i
(b) drilled hole with chamfer 51F Series:
flatland quatrefoil f
Q.2.1-4.
Design flow velocities across tube sheet.
l 51 Series:
about 2m/sec at the tube bundle inlet 51M/51F Series:
about 4m/sec at the tube bundle inlet In order to reduce accumulation of sludges on the tube sheet, the circulation ratio has been increased and the wrapper opening height has been reduced in Genkai No. 2 and thereafter.
Translations of Japanese entries in Fig. 2.1.4:
- 1. wrapper, 2. wrapper opening height l
l u
.A.2-7
l Q.2.1-5.
Percentage of tube-to-tube sheet annulus eliminated by expansion.
l l
In the steam generators under construction, full depth expansion has been l
effected for 100% block.
l Some of the steam generators in operation are partially expanded, including Mihama No. 2, Takahama No. 1, Takahama No. 2 and Genkai No. 1.
In these steam l
generators, about 10% from the primary side surface of the tube sheet is closed by expansion.
See Fig. 2.1.5 on the next page.
Q.2.1-6.
Tube bending processes.
Tubes with a small bending radius are be.it along the guide roller, using a mandrel.
Q.2.1-7.
Thermal treatment of tubes versus mill-annealed tubes for purpose of resisting SCC.
Sendai No. 1 and thereafter adopted special thermal treatments at 700*C for 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> on Inconel 600, as such treatments improve SCC resistance.
All steam
. generators in operation are provided with mill-annealed tubes.
Q.2.1-8.
Has any thermal treating or shot peening of U-bends been performed to reduce residual stresses?
SCC on the U-bends has occurred both in Takahama No. 1 and Ohi No. 2.
Since bending of U-bends is highly likely to leave residual stresses, special thermal treatments (700*C for two hours) were performed on tubes of small bending radius to remove residual stresses in Sendai No. 1 and thereafter.
All steam generators in operation were neither special-thermal-treated nor shot peened.
Q.2.1-9.
What design modifications have you made when doing your own steam generator manufacture?
Domestic steam generators are 44, 51, 51A, 51M and 51F Series.
The designs of these types are basically the same as those of Westinghouse.
These types have undergone changes as shown below and their characteristics are as presented in Table 2.1.9.
Type 44................ Type 51.............. Type 51M.............. Type 51F going larger modification of flow improvement of pattern, improvement crevice of materials and concentration processes Improvement of reliability.
Modifications on the basis of the basic form (Type 51) which has been proved.
1
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A.2-8
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A.2-9
History of Domestic Steam Generators l
Main Features of Steam Generators l
l Translations of Japanese entries in Table 2.1.9 on the next page:
1.
modification of secondary side flow
- 16. conventional type 2.
configuration of tube support plate
- 17. Inconel 600 (no special l
3.
material for heat transfer tube thermal treatment) 4.
removal of stresses on small U-bends
- 18. TT Inconel 600 (with 5.
material for tube support plate special treatment) 6.
methods of expansion in tube sheet
- 19. modified type 7.
modification of moisture separator
- 20. stresses removed 8.
Type 51
- 21. stresses not removed 9.
Type 51M
- 22. carbon steel
- 10. early design
- 23. ferrite stainless steel
- 11. later design
- 24. partial expansion
- 12. Type 51F
- 25. full-depth expansion
- 13. conventional type
- 26. conventional type
- 14. modified type
- 27. partially modified type
- 15. partially modified type
- 28. modified type Q.2.1-10.
What design modifications have been made in the field?
Rerolling is being done to close the secondary-side crevices on the steam generators with partial expansion.
No other field modifications of design were made.
Modifications of secondary-side flow (removal of downcommer resistance plate, etc.) done by Westinghouse on 44 and 51 Series have not been done in Japan on 44 and 51 Series.
Q.2.1-11.
Are tube sheet crevices eliminated by expansion?
method used to what depth As stated above, some of steam generators in operation are partially expanded and some others are fully expanded.
As for the method of expansion, all steam generators in operation adopted mechanical roller expansion.
Those steam gen-erators under construction adopt the combination of hydraulic and mechanical roller expansion methods.
2.2 and 3 Water Chemistry in the Steam Generator Secondary Side and Desian of the Secondary System As for water chemistry in the steam generator secondary side, all_ volatile treatment (AVT) has been carried out since 1974 following occurrence of tube wall thinning caused by local concentration of sodium phosphate.
In carrying out AVT, our basic thinking is not to allow any existence of impurity and only to control the concentration of hydrazine which makes pH and environment reductive.
As there are problems of inability to avoid corrosion to the extent not to damage the integrity of the plant and of limitation in accuracy A.2-10
1 l
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A.2-11
of water quality analysis, however, the water quality control standard is deter-mined on the basis of experimental results and experiences.
In order to confirm that water quality is maintained at a favorable level and to take prompt correc-tive actions when the water quality is less than the standard level, monitors are provided in the secondary system to continuously measure pH, conductivity, and sodium concentration.
In addition, frequency of sampling is established to analyze predetermined items.
It is easy to control pH and hydrazine concentration by continuously injecting hydrazine into the condensate system.
As for condenser cooling water and oxygen leaking from the condenser and the negative pressure system, Japan fortunately has been using sea water to cool condensers, including those at fossil fuel firing thermal power stations, and has been designing and manufacturing tight condensers.
In periodical inspections, the integrity of the condenser is in-spected.
Additionally, it is determined to take prompt measures by detecting leak from the condenser tubes in the early stage during operation.
A characteristic of the design of the secondary side is installation of deaera-tors, excluding Ohi Nos. 1 and 2.
The deaerator is capable of supplying deaer-ated water to the steam generator not only during operation but also at the time of starting.
Excluding Mihama Nos. 1 and 2 and Takahama Nos. 1 and 2, a deep-bed condensate polisher is provided.
As a result of installation of a condensate polisher, it has become possible to operate at a high hydrazine concentration and to considerably reduce assimulation of sludge on the secondary side of the steam generator.
Aluminum brass and cupro-nickel were used in the past for tubes of condenser, feedwater heater, and moisture separator reheater.
In recent plants, however, titanium and stainless steel have become to be used for condenser tubes and feedwater heater tubes, respectively.
Q.2.2(1) Condenser tubes and tube sheet (1) At existing plants (Mihama Nos. 1, 2, and 3, Takahama Nos. 1 and 2, and Ohi Nos. 1 and 2), aluminum brass is used for tubes and naval brass for the tube sheet.
At new plants (Takahama Nos. 3 and 4, Sendai Nos. 1 and 2, and Tsuruga No. 2),
titanium tubes are used for tubes (wall thickness of 0.7mm) and titanium for tube sheets.
Q.2.2(2) Condenser air removal capacities To extract air from the condenser, a vacuum pump is adopted, and its capacity is as follows:
plant vacuum pump capacity units Mihama lu 10SCFM 2
Mihama 2u 10SCFM 3
Takahama 1, 2u, Mihama 3u 12.5SCFM 3
Oh! 1, 2u 24SCFM 3
Takahama 3, 4u 24SCFM 3
SCFM: Standard Cubic Feet per Minute A.2-12
Q.2.2(3) Feedwater Heater
~
Material, Design plant low pressure feed-high pressure feed-water heater water heater existing plants (Mihama aluminum brass tube cupro-nickel tube 1, 2, 3u, Takahama 1, 2u, Ohi 1, 2u) new plants (Takahama 3, 4u) the same as above the same as above (Note: stainless steel in some part)
Note:
In Takahama 3 and 4, stainless steel is used in the air cooling zone of Low Pressure Feedwater Heaters Nos. 1 and 2 as a countermeasure for ammonia attack.
In Sendai No. 2, stainless steel is used in Low Pressure Feedwater Heaters Nos. 1 and 2, and in Tsuruga No. 2, stainless steel is used in all feedwater heaters.
From about ten years ago, connections of shell and channel head were changed from flange to welding.
4 As valves of low pressure feedwater heaters and condensers which become vacuum while in operation, water sealing valves and bellows valves are adopted to pre-vent ingress of air.
Q.2.2(4) Moisture Separator Reheater Examples of Kansai Electric Power Co. Inc. are shown below:
plant type heating tube moisture separation type Mihama lu horizontal type, cupro-nickel SUS wire mesh one-stage heating tube with fin Mihama 2u the same as above the same as above the same as above Takahama 1, 2u the same as above the same as above the same as above Mihama 3u Ohi 1, 2u horizontal type, the same as above SUS chevron two-stage heating i
Takahama 3, 4u super size type, the same as above the same as above two-stage heating A.2-13
Q.2.2(5) Condensate polisher Condensate polisher is provided in Mihama No. 3, Ohi Nos. 1 and 2, Ikata Nos. 1 and 2, Genkai Nos. 1 and 2, Takahama Nos. 3 and 4, Sendai Nos. 1 and 2, and Tsuruga No. 2.
a.
Full flow b.
Deep bed
)
c.
Continuous service during operation In Mihama No. 3, Ohi Nos. 1 and 2, and Takahama Nos. 3 and 4, a prefilter which passes water only at the time of starting is provided.
Q.2.2(6) Deaerator Deaerator is provided in all plants, except for Ohi Nos. 1 and 2.
Q.3(1) Description of secondary-water chemistry Standard values at Kansai Electric Power Co. Inc. are shown in Table 3(1) for reference purposes.
Table 3(1) sample item unit standard value condensate acid conductivity at 25 C ps/cm
< 0.2 dissolved oxygen (0 )
ppm
< 0.05 2
pH at 25*C 8.8 - 9.3 feedwater conductivity at 25 C ps/cm
<5 dissolved oxygen (0 )
Ppm
< 0.005 2
total fron (Fe) ppm
< 0.02 total copper (Cu) ppm
< 0.005 total nickel (Ni) ppm
< 0.005 hydrazine (N H )
ppm
> 0.002 2 4 pH at 25*C 8.5 - 9.1 i
steam conductivity at 25*C ps/cm
<5
)
generator acid conductivity at 25"C ps/cm
< 2.0
)
blowdown silica (SiO )
ppm
< 0.5 2
chloride (C1')
ppm
< 0.1 sodium (Na*)
ppm
< 0.1 free alkalinity ppm
< 0.15 turbidity ppm
<1 main steam silica ppm
< 0.02 Q.3(2) Means used to maintain chemistry within limits a.
Instrumentation Points where a monitor is installed at Kansai Electric Power Co. Inc. are shown in Table 3(2)a, with translations of Japanese entries given below:
A.2-14
i 1.
condensate
- 10. acid conductivity meter 2.
- 11. conductivity meter 3.
condenser hot well
- 12. pH meter 4.
condensate pump discharge
- 13. dissolved oxygen meter 5.
deaerator inlet
- 14. hydrazine meter 6.
deaerator outlet
- 15. Na meter 7.
high pressure feedwater heater outlet
- 16. or 8.
steam generator blowdown
- 17.
- indicates alternate type 9.
steam Q.3(2)b sampling frequency Frequency of sampling secondary-system water at Kansai Electric Power Co. Inc.
is shown in Table 3(2)b, with translations of Japanese entries given below:
1.
sample
- 18. silica 2.
condensate
- 19. total iron 3.
- 20. total copper 4.
- 21. total nickel 5.
- 22. sodium 6.
reheated steam
- 23. turbidity 7.
drain of high and low pressure
- 24. dissolved oxygen feedwater-heater and moisture
- 25. ammonia separators reheater
- 26. free alkalinity 8.
item
- 27. hydrazine 9.
hot well
- 28. Icw pressure feedwater
- 10. condensate pump discharge heater
- 11. low pressure feedwater heater outlet
- 29. manual analysis
- 12. high pressure feedwater heater outlet
- 30. daily i
- 13. steam generator blowdown
- 31. more than two times per week
- 14. conductivity
- 32. meter indicated record
- 15. acid conductivity
- 33. more than three times per
- 16. total hardness week i
17, chloride
- 34. more than once per week Q.3(2)C Corrective actions when the standard value is exceeded (indicate standard values to demand output reduction or stopping of plant)
The following measures are taken when leak occurs from the condenser tubes:
1.
If reading of water quality monitoring meters in the condensate system and the steam generator blowdown system (acid conductivity and sodium meters) rises, l
blowdown water of the steam generator increases to remove sea water even if the standard value is not exceeded.
I 2.
If the acid conductivity of steam generator blowdown water is expected to exceed the standard value (2.0 ps/cm), output is reduced and the condenser on the side where sea water has mixed in is isolated to stop passing of sea water.
Then, leak from tubes is detected to install plugs.
3.
If there is a large amount of sea water ingress and the water quality of steam generator blowdown water is judged to rapidly exceed the limiting value (acid conductivity: 120 ps/cm, chloride concentration: 10 ppm), plant operation is stopped to detect leak from condenser tubes and to install plugs.
A.2-15
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At a plant provided with a condensate polisher, there is no problem even if a leak occurs from condenser tubes if the leak is within the extent of the capa-city of the condensate polisher.
The above-mentioned measures are taken, however, if sea water ingress increases to exceed capacity of the condensate polisher.
Q.3(2)d Wet layup (sampling frequency)
Sampling items and frequency during wet layup at Kansai Electric Power Co. are presented in Table 3(2)d, with translations of Japanese entries given below:
1.
sample 6.
hydrazine 2.
during layup 7.
turbidity 3.
Item 8.
remarks 4.
deaerator storage tank 9.
more than once per week 5.
water in steam generator Q.3(2)e Who is responsible for water chemistry control?
Expert chemistry groups are responsible for water quality analysis and control, and the manager of radiological protection section manages the groups and is responsible.
Q.3(2)f Steam generator flushing and blowdown SG blowdown during normal operation is as follows:
plant SG blowdown (t/hr per SG) proportion to water supply during normal operation (%)
Mihama Nos. 1, 2 and 3 5
0.3 - 0.5 Takahama Nos. 1 and 2 10 about 0.6 Ohi Nos. 1 and 2 10 a'cout 0.6 Genkai Nos. 1 and 2 20 about 1.2 Ikata No. 1 20 about 1 2 Ikata No. 2 25 about 1.5 l
l
[
Q.3(3) Experiences on closed-loop cooling system (cooling tower) versus l
straight-through cooling system l
All Japanese nuclear power stations adopt condenser cooling of the straight-through type.
l l
Q.3(4)c Condenser inspection l
l All tubes are inspected in each regular inspection.
Q 3(4)d Tube plugging criteria Those with 50% wall thinning wastage or with rapid wall thinning.
Q.3(4) Condenser inspection and repair method a.
Leak detection and repair method A.2-17
4 y hle. 3. G c. d.
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OR*5579 dRR$kW5Pi*
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l Vinyl sheet method during operation and vacuum method during annual inspection.
4 Q.3(4)b Detectable leak quantity During normal operation, acid conductivity meter and sodium meter are used for detection.
Leak rate estimates are made by acid conductivity value of the condensate or the SG blowdown.
During normal operation, conductivity is 0.1 to 0.2 ps/cm. When this value is changed by as much as 0.1 ps/cm, a leak is judged to have occurred.
In this case, the leak rate is about one liter per hour in the case of a three-loop plant.
{
Q.3(5) Air leak detection and repair method During vacuum rise testing, sound (sucking sound) and smoke (joss stick) are used to detect air leak.
During normal operation, air inspection is detected by confirming water level from reading of the glass water-level meter installed at the top of the condenser.
I Q.3(6)a Reasons for using hydrochloric acid for regeneration of condensate polisher When using a condensate polisher, care must be taken so that Na* 1eaked is not in the free alkalinity form (Na0H).
It is therefore necessary to convert Na* of a very small amount (< 0.1 ppb) to Nacl or Na 50 by letting Cl-or 2 4 50-- of more than equal amount leak.
To that end, it is necessary to control the Na/C1 molar ratio or the Na /SO 2
4 molar ratio.
As it is possible to analyze a smaller amount of Cl than S0, we 4
adopt hcl regeneration.
Q.3(6)b Does hydrochloric acid not cause denting in the steam generator?
4 l
Chloride leaks from the condensate polisher not in the form of hydrochloric acid but in the form of sodium chloride which is a neutral salt, and its con-centration is very low (below 0.1 ppb).
There is therefore no possibility of it causing denting.
i Q.3(7) Discrepancy allowed to electric power companies l
The water quality-control standard value is almost equal among the electric power companies, but there is some difference depending on facilities and control method.
l f
A.2-19
~
4.
INSERVICE INSPECTION Idea of SG Inspection Inspection of SG tubes in inservice inspection is performed on the entire length of all tubes of all steam generators at each annual inspection, as a rule.
Such defects as wall thinning and cracking are inspected, and individual plants have their own specific positions where such defects occur.
In Japan, such specificity is not taken into consideration, and inspection is performed on the assumption that troubles occurred in the past could occur at any plant.
If a trouble of new phenomenon is discovered at any plant, inspection is made at other plants to detect the same trouble.
If no defects which necessitate plugging or repair of tubes occur at a plant for two consecutive years, however, it is sufficient to make about 30% sampling inspection at that plant for eddy current testing (ECT).
The plugging criteria of tube defects is as follows:
for wall thinning, 20% wall thickness reduction or more; for other types of defects, all tubes which have ECT indications.
In case of defects which are found in the tube sheet region, sleeve repair could be applied.
4.1 Steam Generator Inspection Q.4.1-1 What techniques are used in conducting preservice and inservice steam generator inspections (i.e., eddy current testing, profilometry, radiography, visual, etc.)?
Preservice inspection and inservice inspection of steam generators are all performed by ECT.
Q.4.1-2.
What are the preservice and inservice inspection parameters (i.e.,
what do you look for:
tube thinning and cracking, tube denting, crud buildup in crevices, sludge pile, support plate cracking, tube ovality, etc.)?
In preservice inspection, comparison with ECT results at the tube makers is mainly done.
In inservice inspection, detection of wall thinning and cracking is considered.
Q.4.1-3.
What is the scope of preservice and inservice inspections (i.e., how many steam generators are inspected:
how many tubes are inspected in each steam generator; what portion of each tu e:
hot leg, cold leg, U-bend, is inspected; what type of loose parts and secondary-side inspections are performed)?
In preservice inspection, all steam generators and all tubes are inspected over their entire length.
In inservice inspection, inspection is performed to the same extent as preservice inspection as a rule.
Provided that about 30% sampl-ing of tubes and steam generators is considered sufficient if no new troubles are detected for two consecutive years.
As for loose parts on the secondary side, the outer circumference of the secondary-side surface of the tube sheet is monitored by ITV (closed-circuit television).
l A.2-20
l Q.4.1-4.
What is the frequency of inservice inspections (i.e., how often are scheduled inspections required; what type of events such as tube leakage, l
earthquakes, or system transients require that unscheduled inspections be I
performed)?
(1)
Inservice inspection is performed during scheduled inspection once a year (12 months i one month) in accordance with the law.
(2)
If leak occurs from the steam generator during operation, the plant is shut down and 100% ECT is performed principally to confirm integrity of other tubes.
1 Q.4.1-5.
What are the primary-to-secondary leakage rate limits? How is the leak rate monitored and what actions are required in the event of a leak exceeding the leak rate limits?
In Japan, operation with a steam generator leak is not being done.
Q.4.1-6.
What are the bases for the leak rate limits? Has a correlation between leak rate, crack size, and tube burst strength been developed?
In Japan, operation with a steam generator leak is not permitted and therefore there is no leak rate limit.
Q.4.1-7.
What are the bases for the scope and frequency of the preservice and inservice inspections (e.g., are they based on operating experience, statistical analyses, economic consideration, etc.)?
(1) Preservice inspection... 100% ECT i
Inservice inspection....(a) A plant wth AVT from the beginning, whose steam generators have no ECT indication in first and second inservice inspections:
years 1 - 3... 100% ECT once per year years 4 or over... 20% ECT once por year (b) a plant with steam generators with troubles:
100% ECT once per year Q. 4.1-8.
What design features are incorporated in steam generators.to facilitate inspections (e.g., number and location of inspection ports, etc.)?
(1)
In recent steam generators, inspection holes are additionally provided l
just above the tube sheet and above the No. 1 tube support plate in the lower shell to facilitate inspections.
a.
In conventional steam generators, two inspection holes are provided in the tube lane direction just above the tube sheet.
In recent steam genera-tors, however, two inspection holes are additionally provided in the direction perpendicular tc the tube lane, a total of four inspection holes.
b.
Two inspection holes are added also in the tube lane direction above the No. 1 tube support plate.
l A.2-21
Q.4.1-9.
What is the percentage of total plant outage time due to scheduled steam generator inspection and maintenance?
It accounts for about 40% on the average in the period from 1980 to 1982.
The i
annual percentage is as follows:
1 1980 1981 1982 about 40%
about 30%
about 40%
Q.4.1-10.
What is the percentage of total plant outage time due to unscheduled steam generator inspection and maintenance?
/
It accounts for about 8% on the average in the period from 1980 to 1982.
The annual percentage is as follows:
1980 1981 1982 about 3%
0%
about 20%
In the above figures, time required for countermeasures against troubles dis-covered in steam generator tubes in regular scheduled inspections is not included.
This time is included in the period of shutdown under Q.4.1-9.
Q.4.1-11.
What type of eddy current testing techniques are used? Single fre-quency, multiple frequency, analog or digital subtraction, absolute, differen-tial, pancake probes, etc.?
The technique used is analog subtraction of multi-frequency.
The probe is of differential type.
Q.4.1-12.
What standards are used for calibrating eddy current testing equipment?
Test procedure is indicated in Fig. 4.1-12, with translations of Japanese entries given below:
1.
three 0.8 mm$ drilled holes 3.
0.3 mm wide, 50% deep, entire 2.
dent circumference slit Q.4.1-13.
What electrical frequencies are used for various types of eddy current testing?
Mainly 100 KHz and 400 KHz.
Q.4.1-14.
What type of eddy current or other inspection techniques are used for inspecting tube sleeves? Have standards for the inspection of tube sleeves been developed?
The same method as tube ECT.
ECT is performed as base line data immediately after the sleeving and, in inservice inspection, yearly comparison is made.
A.2-23
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Q.4.1-15.
How are eddy current testing data evaluated - visually on oscil-loscope or by computer?
Evaluation is made mainly on the basis of computer output of the same wave form as that from an oscilloscope.
In special cases, an X-Y chart is used for evalua-tion.
l Q. 4.1-16.
Is real time data evaluation used in the field?
No.
Q.4.1-17.
What type of eddy current or other inspection techniques are used to inspect for tube degradation in the tube-to-tube sheet crevice? Have you had difficulty in detecting degradation in this area?
Year-to year comparison of 400 KHz X-Y chart and multi-frequency X-Y chart are used.
It is difficult to detect cracks very long in the axial direction.
Q.4.1-18.
What type of eddy current testing is used to inspect for stress corrosion cracking in small radius U-bends? Have you had difficulty in detect-ing such cracking?
Special probes for small radius U-bends are used, and year-to year comparison is made.
Q.4.1-19.
What type of eddy current testing do you use to inspect for cracking just above the tube sheet in the transition region between the expanded and unexpanded sections of the tube?
Specially developed probes of four segments surface-riding type are used fer detection of such defects.
Q.4.1-20.
Do you routinely inspect for circumferentially oriented degradation?
Since no circumferentially oriented degradations have been experienced so far, we do not do it routinely.
Q.4.1-21.
What are the tube plugging criteria? Do the criteria consider both depth and length of defect?
In Japan, the heat transfer tubes with ECT indications which are interpreted to mean defect are plugged.
(However, where sleeves are applicable, sleeve repair is performed.)
Q.4.1-22.
What are the criteria for sleeving degraded tubes?
(1) As for heat transfer tubes with ECT indications which are interpreted to mean defect, sleeve repair is performed where sleeves are applicable.
(2) Sleeves are presently applicable to damages in the tube sheet of steam generators with partially expanded tubes.
Periphery region of tube sheet where sleeves cannot be inserted are excluded.
A.2-24
l t
(3) Sleeves which are applicable to full-depth tube expansion region and roll transition region are under development.
Q.4.1-23.
What margins are included in the tube plugging criteria to account for eddy current testing error and degradation between inspections?
In Japan, the heat transfer tubes with ECT indication which are interpreted to mean defect are plugged.
Q.4.1-24.
Are tubes preventively plugged on the basis of ovality or reduction in diameter?
Reply:
(1)
In Japan, nether ovality nor changes in inner diameter of heat transfer tube have been experienced.
Thus, no plugging has been done preventively for these reasons.
(2) However, as cracking has been experienced on some small radius U-bent tubes, all of the smallest radius U-bent tubes have been plugged in steam generators in which the bending operation was done in the same manner as on those heat transfer tubes on which cracking occurred.
Q.4.1-25.
What are the bases for the steam generator tube plugging criteria?
What experiments have been conducted to determine rates of degradation and tube burst and collapse strengths?
In Japan, those heat transfer tubes with ECT indications which are interpreted to mean defect are plugged.
(However, sleeve repair is performed when sleeve application is possible.)
Q.4.1-26.
What methods of tube plugging are used (e.g., explosive, welded, mechanical, etc.)?
Today, mechanical plugs are used in all cases.
Except that welded plugs are used when there are no heat transfer tubes in the tube sheet region due to extraction of tubes.
In the past, explosive and welded plugs were used.
As stress corrosion cracks have occurred on explosive plugs, they are being replaced with mechanical plugs.
j t
l Q.4.1-27.
What methods of tube sleeving are used (e.g., hydraulically or j
mechanically expanded)?
Presently applied sleeves are welded at their bottom ends and have projected parts close to the top.
Sleeves are installed by mechanical tube expansion.
(
See Fig. 4.1-27, with translations of Japanese entries given below:
1.
heat transfer tube 6.
sleeve projected part 2.
tube sheet 7.
sleeve (mechanical expansion) 3.
damaged part of tube 8.
prior to installation i
5.
weld 9.
after installation of sleeve A.2-25
)
I i
emy 2.
,N.
Ol
\\b 3.e a T 4.Esta L V-4.
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l A.2-26 i
Q.4.1-28.
Please provide a list of references related to steam generator inservice inspection programs, techniques and regulatory rec,uirements.
There are no written materials for them.
The methods are similar to those under ASME Sec. XI.
4.2 Condenser Inspection Ingress of air and leaking of sea water from the condenser have considerable impacts, in the case of PWR, upon the secondary side equipment, especially upon the steam generator tubes.
It is therefore very important for improving reliability of plant to inspect and maintain the condenser from the standpoint of preventing leaking of sea water and air, and also to take necessary measures by detecting any leak in the early stage when the leak has occurred.
The condensers are ECT-inspected over the entire length of all tubes to confirm their integrity at the time of scheduled plant inspection (simultaneously with refoesing, in general).
If any damages are detected then, plugs are installed or tubes are replaced with new ones.
In Japan, therefore, there have been no experiences of unscheduled outage of plant caused by condenser leaks.
For detection of sea water and air, acid conductivity meters inside the hot well (separate type), condensate-line sodium (Na) meters, and dissolved oxygen (D0 )
2 meters are installed to continuously detect leaks.
As a result, when there is excessive leakage, necessary actions such as reduction of output or shutdown of plant are taken.
It is also common to install a condensate polisher deaerator to improve water quality on the secondary side.
At plants under construction or under planning, titanium tubes are adopted for condenser tubes to improve integrity.
1.
What special features are incorporated in the condenser design to facilitate oxygen and circulating-water leakage detection and tube inspections (e.g.,
leak detection troughs at each tube sheet, design of condenser internals to withstand water-solid conditions for leak testing, isolatable water boxes, etc.)?
1)
Against sea water leakage, the following structures and devices are installed.
1 The hot well is separated into six sections for condensers, and it is therefore possible to measure acid conductivity of each section.
The water box is isolatable.
It is possible to fill the condensers with water.
l l
Na meters are installed along the condensate line.
2)
The following structures and devices are installed against air leakage.
D0 meters are installed along the condensate line.
2 It is possible to measure air flow rate at the outlet of the vacuum pump (or the air ejector).
Bellows and water sealing valves are adopted for the vacuum line to prevent air leakage.
A.2-27
2.
What techniques are utilized to monitor for condenser air inleakage?
There are the following methods to detect condenser air inleakage:
a.
D0 meters at the condensate pump discharge.
2 b.
Reduction of the condenser vacuum.
c.
Manometers at the outlet of the condenser vacuum pump or the air ejector.
3.
What techniques are used for determining the location of oxygen inleakage (e.g., tracer gases, etc.)?
No special devices are provided.
Oxygen leakage is likely to occur at the valve gland belonging to the condenser or at the flange connection of the pipes.
Leakage location is identified by observing smoke flow.
There have been no troubles so far.
4.
Have standards been developed for detecting ano identifying the location of oxygen leaks into the condenser?
If so, what are the major elements of these standards?
There are no standards.
5.
What techniques are used for identifying and determining the location of condenser circulating-water inleakage (e.g., tracer gases, hydrostatic tests, eddy current testing, etc.)?
1)
During operation Acid conductivity meter and Na meter is used to detect circulating-water i
a.
leakage.
b.
The manhole of leaking water boxes is opened to detect leakage by the vinyl sheet method.
2)
While shutdown a.
Water fill test or vacuum and bubble test, b.
6.
What techniques are used during scheduled condenser preservice and in-service inspections?
1)
Preservice inspection a.
b.
Water fill test or vacuum and bubble test.
2)
Inservice Inspection a.
b.
Water fill test or vacuum and bubble test.
In the case of titanium tubes, UT (ultrasonic testing), RT (radiographic testing), and air tests are added at the stage of production and PT (liquid penetrant testing) is added at the stage of preservice inspection.
l A.2-28
1 i
7.
What is the scope of scheduled condenser preservice and inservice inspec-tions? How many tubes are inspected? What portion of each tube is inspected?
In preservice and inservice inspections (at each scheduled inspection), eddy current tests are performed along the entire length on all tubes.
On the expanded section of the tubes, vacuum and bubble tests or water-fill tests are performed.
8.
What is the frequency of scheduled condenser inspections?
Scheduled condenser inspections are performed during each scheduled plant inspection.
9.
What are the criteria for conducting unscheduled condenser inspections?
What is the scope of unscheduled inservice inspections?
1)
There are no standards for performing unscheduled inspections, but it is determined to effect unscheduled shutdown when the secondary-system water quality cannot be maintained normally, owing to sea water inleakage.
2)
The extent of inspection covers the tubes arranged in the water box from which tube leakage has been confirmed by the circulating-water leakage detector.
No unscheduled inspections due to sea water inleakage have been experienced at PWR plants in Japan.
10.
What type of eddy current testing is used for inspection of condenser tubes?
The following inspection methods are used:
a.
Differential ECT.
b.
Absolute ECT.
- 11. What techniques are used to inspect for tube-to-tube-sheet degradation?
There are the following techniques to inspect the tube sheet degradation:
a.
Vacuum and bubble test b.
Water fill test There have been no experiences of leakage owing to tube sheet degradation.
i i
12.
What are the criteria for condenser tube repair (e.g., degree of tube wall thinning, etc.)?
A wave height value is established in ECT, and plugs are installed or the tubes cre replaced with new ones when thc wave height value exceeds the prescribed cne.
(As wave height differs according to defect form, there are no rules in relation to wall thickness.)
13.
What repair techniques are used for degraded condenser tubes (e.g.,
l plugging, sleeving, etc.)?
l l
A.2-29
The degraded tubes are plugged or replaced with new tubes.
There have been no cases of sleeving.
14.
What is the total number of hours (scheduled plus forced) of plant outage due to condenser inspection and maintenance?
i There has been one case of plant outage for about ten days.
(Except that it was not due to leakage but for pre-summer cleaning to prevent reduction of capability.)
Work on condensers at the time of scheduled plant inspection is off-critical.
15.
What is the number of hours of forced outage due to condenser inspection and mainte' nance?
As stated under 4.2-14.
16.
What is the percentage of total plant outage time due to scheduled and forced condenser inspection and maintenance?
I Work on condensers at the time of scheduled plant inspection is off-critical.
There has been only one case of plant outage to inspect the condenser.
17.
What is the number of power reductions and forced outages due to condenser l
inspection and maintenance?
l There has been only one case of plant outage for about ten days to inspect the condensers.
l 18.
What percentage of forced outages and power reductions are due to condenser j
inspections and maintenance?
As stated under 4.2-17.
19.
Please provide a list of references related to condenser inservice inspec-l tion and maintenance programs.
Inspections are performed as a rule at the time of each scheduled plant inspec-tion, and there are no special materials.
4.3 How are loose parts controlled?
As serious damages could occur on steam generators, reactors, fuels, and other major equipment if foreign matter such as loose parts would exist within the primary and secondary systems, measures as stated below are taken for early detection and prevention of foreign matter in scheduled inspections and during normal operation.
In Japan, damages occurred to the tubes owing to a measuring tape (steel) left l
in the steam generator during trial operation of Genkai No.1 (in 1975).
From this experience, the power companies have established foreign-matter control rules, and no other troubles due to foreign matter have occurred up to today.
A.2-30
When working in vessels such as steam generators, workers, tools, and materials are controlled as they enter into or get out.
At the same time, check sheets are reconfirmed when all work has been completed, and it is confirmed that there is nothing left behind.
A loose parts monitoring system (LPMS) is provided in each plant for early detection of loose parts.
If there are any loose parts detected, proper mea-sures such as shutdown of plant are taken.
1.
Quality assurances and quality control accountability measures on all work involving the inside of the steam generator?
When working in the condition that vessels, such as steam generators, are kept open, the following measures are taken.
1)
Prior to work a.
Preparation and informing of work procedures.
b.
Establishment of an internal work area.
c.
Final visual inspection.
2)
During work Control of tools brought in and persons entering by check sheets.
3)
After work Confirmation that no foreign matter is left behind by recording on check sheets and visual inspection.
2.
Visual inspection? What parts of the steam generator? Frequency?
1)
Parts for visual inspection a.
Primary-side water chamber.
b.
To the extent possible, the secondary side of the tube sheet, etc.
2)
Frequency of inspection While a plant is shut down for fuel change.
3.
Loose parts monitoring system.
Method of operation? Threshold alarms?
i Training requirements for LPMS to give signals from the secondary system?
1)
Alarm set level l
About 200% of background noise during normal operation.
2)
Training Devices are inspected and adjusted during scheduled inspections.
a.
A.2-31 P
9 b.
Sensors are installed at the top of the steam generator, the steam gen-erator blowdown pipe, the steam generator drain pipe, and the steam generator feedwater pipe.
(Provided that it is possible to switch the sensor in the steam generator feedwa,ter pipe to on-line, though it is normally off-line.)
c.
Engineers were trained by the manufacturer for handling of devices and analyses.
4.4 Occupational Radiation Exposure Work related to the steam generator, especially work in the channel head, exposes workers to a large dose of radiation.
In order to reduce radiation exposure, various rationalization measures have been taken.
In the past, installation and removal of the ECT robot and steam generator outlet and inlet nozzle protection covers (to prevent foreign matter from dropping in), tube plugging, etc., required work within the channel head.
In order to make it possible to perform this work remotely from outside the channel head, developments have been done.
As for the steam generator ECT, hand probes were used first for manual opera-tion.
Then, X-Y fixtures were used.
It was hcwever necessary to enter the channel head to change the position of'the X-Y fixture three times in addition to installation and removal of the fixture.
Ihis aspect has been modified in the below-tube-sheet-driving type of robot. With this robot, work tim'e within the channel head has been dramatically reduced to decrease exposure.
- However, even with this robot, two workers are required to enter the channel head for installation and removal.
Recent development of a small powerful ECT-dedicated robot and adoption of an installation tool with which a robot could be installed from outside the channel head has reduced exposure.to less than one third per installation.
As for steam generator outlet and inlet nozzle protection covers, three pieces were brought into the channel head to be assembled there in the past.
A folding type has been developed.
This type can be installed inside the channel head by only opening it, so that work time is reduced considerably and exposure is decreased to a large extent.
A future development target is to develop a handling system which can install the nozzle protection cover from outside the channel head.
Many improvements have been made also as to plugging work.
In the past, all plugging work, including pre plugging cleaning, plug installation, welding and PT inspection, were performed inside the channel head.
With development of the mechanical plugging process, it has become possible to' reduce work time within the channel head and exposure to about one-tenth of That in the past.
For this work, two universal robots for inspection and repair have been developed.
SG-M is a floor type robot which can be installed from outside the channel head. SG-MR is a small and light weight robot of below-tube-sheet-l driving type; a worker is required to enter the channel head to install or to remove this robot.
s i
j A.2-32
.j
(
'k.
Using these robots on which mechanical plugging tools are mounted, it has become possible to perform all mechanical plugging work from outside the channel head.
Also, it is possible to deliver to or receive from the robot mechanical plugs from outside the channel head to reduce exposure to about one-fourth of that in the past.
It is also possible to use these universal robots to sleeve-repair tubes.
By attaching tools on the robots, all work (brushing, sleeve insertion, tube expansion, welding and PT inspection) related to sleeva installation can be performed remotely and automatically.
As seen above, it has become possible to perform almos= all work from outside the channel head.
There have been cases of decontaminating inside the channel head by the boron blast process when much work inside the channel head was planned.
No lead shield is used inside the channel head as workers get a large amount of exposure when installing or removing it.
So far, work inside the channel head has been described. Work related to steam generator exposes workers to a large amount of radiation even if they are per-formed outside the channel head, and thus various improvements have been done to reduce exposure.
In relation to steam generator manhole opening and restoration work, a manhole installation device and a manhole bolt fastening device have been developed, in addition to permanent installation of a greenhouse framework and local exhaust ducts (for the greenhouse and for the steam generator) to prevent spreading of radioactive dust.
As for ECT inspection works, improvements such as permanent installation of ECT cables and of lead shields on pipes where ECT is performed have been done.
Additionally, efforts are being made to develop devices with which ECT could be performed from outside the containment vessel.
As for sludge lancing on the steam generator secondary side, improvements such as permanent installation of pipes and remote automation of jet-nozzle driving I
device: have been done.
Comprehensive modifications and device development have been done as stated above to considerably reduce exposure.
Total exposure from steam generator j
work, including preventive and maintenance work and repair work, is about 15%
on the average of the total exposure during the refueling period and amounts l
to 30 man-rems per steam generator.
By adopting the above-stated automatic dovices, it will be possible to further reduce exposure related to the steam l
generator.
l l
.Part-time workers are used in this work.
Their exposure record is kept by emoloyers, contractors and power companies, and also entered in radiation l
. control books to be given to them.
Records are registered at the Central Registration Center which is a public organization.
Even when a part-time worker enters another power station, his records are checked by his employer and by the power company.
Thus, control of exposure records is perfect even
[
in the care of part-time workers.
A.2-33
The Japanese legal exposure limits are 3 rems per three months and D = 5(N-18) of accumulated dose as to the whole body and 8 rems per three months as to skin and 20 rems per three months as to limbs.
(D is the dose and N is the age of the worker.)
The power companies adopt 5 rems per year instead of D = 5(N-18) and follow the remaining legal limits.
Incidentally, they use more strict limits in their operation.
Q.4.4.1 To what extent are steam generator tube inspection and plugging procedures automated?
A dedicated small powerful robc? is used for steam generator tube inspection, which is performed remotely and automatically from outside the loop chamber. '.
An automatic tool has been developed for mechanical plugs to' be installed in practical steam generators.
Plugs are handed to the robot outside the steam generator channel head, and all work including plug. installation and inspec-tion can be done remotely.
Q.4.4.2 How is the eddy current testing probe positioner installed in the' steam generator? Does it require entry of personnel into the channel head?.
Workers enter the channel head for installation.
Work time is about two workers x 1.5 minute <:.
Q.4.4.3.
Does the tube plugging procedure require entry of personnel into the channel head?
In the past, workers entered the channel head to install mechanical plugs.
With development of an automatic installation device, it has become possible to install plugs without entering the channel head.
Q.4.4.4.
What special techniques or procedures are used to minimize' personnel.'
exposure (e.g., decontamination, shielding, etc.)?
When there is much work or, the inside of the channel head, it is decontaminated in advance by boron blasting.
t No lead shields are used as workers receive a considerable r5diat' ion when installing or removing them.
Q.4.4.7.
What is the average man-rem exposure associated with a routine steam generator inspection and maintenince outage?
.c There are consicerable differences depending on the plant.
It is 30 man-rems per steam generator on the average, including steam generator preventive maintenance and repairs.
Q.4.4.8.
To what extent has the tube sleeving process been automated?
9 Allsleevingprocesses(brushing,sleeveinsertion,tubeexpansion,weNing, i
PT inspection, etc.) except for robot installation ynd removal can be done, l
l both remotely and automatically without entering.the channel head.
n A.2-34
}
i
Q.4.4.9.
Are temporary cmployees used for steam generator inspection, main-tenance, repair or replacement?
If so, are records kept of their radiation exposure and are these records cross-checked between plants and utilities?
Full-time inspectors engage in usual inspections, including those that are scheduled.
In the case of repairs, some temporary inspectors may be used.
Radiation exposure records are kept by employers, contractors and power com-panies.
At the same time, radiation exposure is recorded in radiation control records to be handed to individual workers.
Matters entered in the records are registered at the Central Registration Center which is a public organization.
Records are checked both by employers and power companies.
Q.4.4.10.
What are the occupational radiation exposure regulatory limits? Do utilities use any other limits?
Legal limits are 3 rems per 3 months and D = 5(N-18) as to the whole body.
It is 8 rems per 3 months as to skin and 20 rems per 3 months as to limbs.
Power companies use 5 rems per year instead of D = 5(N-18), and other limits are as legally specified.
Incidentally, power companies use more strict limits than the above as their operation targets.
Q.4.4.11.
What percentage of total personnel radiation exposure is a result of steam generator inspection, maintenance and repair?
It differs considerably depending on the amount of steam generator repair work, but is about 15% on the average. This includes steam generator sludge lancing.
Q.4.4.14.
Please provide a list of available references on the subject of personnel radiation exposure related to steam generator maintenance and inspection programs?
There are no published ones.
4.5 Outline of Steam Generator Reliability Demonstration Test i;
I.
Necessity l
For treatment of steam generator secondary-side water at pressurized water reactor plants, phosphate was initially used.
Local concentration of phosphate caused thinning of steam generator tube walls, resulting in leak of coolant to the secondary side from the primary side.
Countermeasures against leaks were taken, such as all volatile treatment (AVT) for secondary-side water, and it was required to demonstrate the reliability and safety of steam generators following such countermeasures.
In order to remove social concerns over steam generators and also in order to promote construction of future nuclear power stations, it has become necessary to demonstrate the reliability and safety of steam generators, using large testing facilities.
E A.2-35
,r
II.
Execution of Tests In the six year period from 1975, demonstration tests were carried out to demonstrate the reliability and safety of steam generators in order to study thermal hydraulic behavior on the steam generator secondary side, corrosion j
behavior on the steam generator secondary side, corrosion behavior of tubes and plates, and fracture behavior of tubes.
The demonstration tests were commissioned to the Japan Power Plant Inspection Institute to be carried out at Takasago Institute of Mitsubishi Heavy Industries.
1.
Large-Scale Thermal Hydaulic Test With a large steam generator model, thermal hydraulic conditions within and moisture separation performance of steam generators were studied, and at the same time comparison with estimated values by the flow analysis code was made.
Through freon thermal hydraulic tests, thermal hydraulic conditions and sludge accumulation conditions within the steam generator were visually confirmed.
Conditions for both thermal hydraulic tests are shown in Tables 1 and 2, with translations,of Japanese entries as follows:
Table 1 Large Thermal Hydraulic Test Conditions 1.
item 8.
circulation ratio 2.
test conditions 9.
wrapper opening height 3.
pressure
- 10. flow distribution baffle plate 4.
subcool temperature
- 11. heat flux 5.
hot leg
- 12. yes, none 6.
cold leg
- 13. Note:
Heat flux at 100% power 7.
vertical mass velocity within of an actual plant (about tube bundle 28 x 104Kcal/m2h) is considered to be 100% heat flux Table 2 Freon Thermal Hydraulic Test Conditions 1.
item 8.
heat flux (hot leg) 2.
test conditions 9.
heat flux (cold leg) 3.
pressure
- 10. wrapper opening height 4.
subcool temperature
- 11. flow distribution baffle plate 5.
hot leg
- 12. yes, none 6.
cold leg 7.
vertical mass velocity within tube bundle 2.
Partial Corrosion Simulation Test By Pot Boiler Under the environmental conditions similar to those for the actual plant, corroson behavior of tubes and baffle plates when phosphate treatment and AVT are done and impurities are mixed in AVT were conducted as to the upper and
'er halves of the steam generator.
Table 3 shows partial corrosion test o.ditions, with translations of Japanese entries as follows:
l A.2-36
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T : ". %"&r%7S Y!l.:. 'T 1, @
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( Av E kf) 7~14%
4.
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1h 3.5 - 6.6
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/3. (E)
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7 TEFiB13 p O M 251-584 Lvds P. M R X (*v'kf) 1.6-2.'r x 10 4 W/Wh
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A.2-37
i i
1.
item
- 16. others 2.
upper part corrosion simulation
- 17. sea water test
- 18. Inconel 600 3.
lower part corrosion test
- 19. carbon steel
.l 4.
test time
- 20. straight tube 5.
heat flux, quality
- 21. Inconel 600 6.
subcool temperature
- 22. Incoloy 800 7.
mass velocity
- 23. TT Inconel 600 8.
water treatment
- 24. modified Incoloy 800 9.
tube materials
- 25. Inconel 690
- 10. cooler tube materials
- 26. carbon steel
- 12. tube shape
- 27. stainless steel
- 13. baffle
- 28. straight tube
- 14. caustic soda
- 29. U-bend tube
- 15. sodium phosphate 3.
Corrosion Test By Large Scale Model SG After operating a large scale model SG with AVT for a year continuously, it was opened for inspection to confirm the integrity of tubes and baffles.
Table 4 shows test conditions, with translations of Japanese entries as follows:
1.
item 6.
vertical mass velocity 2.
secondary sida pressure 7.
inlet subcool temperature 3.
test conditions 8.
circulation ratio i
4.
temperature 9.
heat flux l
5.
main steam flow
- 10. Note:
- indicates the highest heat flux value.
4.
Fracture Tests Fracture tests of steam generator tubes-are carried out to investigate the burst pressure and collapse strength of tubes having defects due to corrosion, etc.,
or the influences of a fractured tube on the adjacent tubes, and to verify the safety of steam generators in actual plants by making clear the fracture of one tube does not cause fracture of other tubes, at postulated tube rupture.
Table.5 gives tube fracture test items and test conditions, with translations
~
of Japanese entries as follows:
i 1.
test items 2.
content of test 3.
test conditions 4.
temperature 5.
pressure 6.
test time 7.
sample tube 8.
type of defect 9.
object
- 10. investigation of fracture strength of defected tubes and blow-off rate i
- 11. investigation of erosion phenomena at the fractured portion due to the-attack of blow-off fluid I
- 12. investigation of dynamic behaviors at defected tubes fracture
- 13. ctudy of burst pressure of integral'and defected tubes under the actual conditions l
A.2-38
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- SERtRES A.2-39 j
5
._--y.
- 14. study of blow-off rate from fractured portion
- 15. study of collapse strength of integral and defected tubes under the actual conditions
- 16. study of erosion of the fractured portion under the actual conditions
- 17. study of erosion of adjacent tube caused by blow-off fluid under the
'1 actual conditions
- 18. preliminary study of dynamic behaviors of fractured and adjacent tubes under roon temperature
- 19. study of thrust of jet forces when fracture occurred under the actual conditions
- 20. study of dynamic behaviors of fracture and adjacent tubes under the actual conditions
- 21. 320 C and room temperature
- 22. primary side
- 23. secondary side
- 24. the same as above
- 25. the same as above
- 26. primary side
- 27. secondary side
- 28. primary side
- 29. secondary side
- 30. pressure difference
- 31. pressure difference
- 32. external pressure
- 33. primary side
- 34. secondary side
- 35. the same as above
- 36. primary side
- 37. secondary side
- 38. atmospheric pressure
- 39. primary side
- 40. secondary side
- 41. primary side
- 42. secondary side
- 43. 10 to 60 seconds
- 44. 1 to 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br />
- 45. actual size Inconel 600
- 46. half size Inconel 600
- 47. actual size Incoloy 800
- 48. actual size Inconel 600
- 49. actual size Inconel 600
- 50. actual size Inconel 600
- 51. others
- 52. actual size Incoloy 800
- 53. actual size Inconel 600
- 54. Others
- 55. actual size Incoloy 800
- 56. actual size Inconel 600
- 57. half size Inconel 600
- 58. actual size Inconel 600
- 59. half size Inconel 600
- 60. actual size Inconel 600
- 61. half size Inconel 600
- 62. axial direction wall thinning, axial direction slit A.2-40
i
- 63. axial direction wall thinning, axial direction slit
- 64. oval, axial direction wall thinning
- 65. drilled hole, slit
- 66. the same as above
- 67. axial direction wall thinning, guillotine (rupture disk)
- 68. the same as above
- 69. to obtain correlation between defect depth and length and burst pressure
- 70. to obtain correlation between defect size and blow-off rate 71 to obtain correlation between defect size and shape and col. lapse strength
- 72. to study progress of erosion of fractured portion until shutdown of plant after occurrence of fracture
- 73. to study defects due to errosion of adjacent tubes which receive jet flow when a fracture occurs
- 74. to visually know correct dynamic behaviors under room temperature 75, to study jet force of adjacent tubes which receive blow-off and thrust force of fractured tubes due to blow-off under the actual conditions
- 76. to study dynamic behaviors of fractured and adjacent tubes in relation to fractured size under the actual conditions III.
Test Results Through large thermal hydraulic tests, no abnormal conditions were discovered at the secondary side of the steam generator, and it was confirmed that no phenomenon occurred to influence the integrity of tubes.
Also, through corro-sion tests by pot boiler and large scale model SG, it was confirmed that the integrity of the steam generator can be maintained if water on the steam gen-erator secondary side is AV-treated.
Through fracture tests, it was found that the tubes were strong enough against internal and external pressures even when the defect depth is 50% and that adja-cent tubes would not be defected even if one tube was fractured.
The details of these tests are given below 1.
Sample tubes Burst Test Collapse Test Material Inconel 600 Inconel 600 Inconel 800 Size Actual Size (*)
Actual Size (*)
1/2 }caled Size Type of Defect Axial Simulated Wastage Axial Simulated Wastage Axial EDM Slit Axial SCC
(*)0utside diameter of 22.22 mm and thickness of 1.27 mm 2.
Test results The gist of the results of the tests conducted with the actual-size tube samples at 320 C are as follows:
A.2-41
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(1) Burst test 2
a.
Burst pressure on the sound tube was about 630 kg/cm gauge.
b.
Burst pressure tends to decrease as the defect length and depth increase.
c.
The types of defect (wastage, slit) were not so influential on burst pressure, d.
With the same length of defect, the burst pressure of the SCC sample was somewhat higher than that of the slit sample.
(2) Collapse test 2
a.
The collapse pressure of the sound tube was about 320 kg/cm gauge.
b.
Collapse pressure tends to decrease as the defect length and depth and the tube ovality increase.
3.
Evaluation of results (1) Burst test a.
Burst pressure obtained from the internal pressure calcula-tion formula of sound or defective tubes was compared with those burst pressures obtained from the test, to find that the former is slightly lower than the latter.
Therefore, the calculated value was conservatively used for the evaluation, b.
The yield stress (oy) and tensile strenght (oB) of Inconel 600 tubes actually tested were found higher than those of the MITI Code.
Therr' ore, those of the MITI Code were conservatively used ior the evaluation.
Actual Data MITI Code 2
69.3 kg/mm2 oy 31.5 kg/am oB 19.5 km/mm2 51.1 kg/mm2 Note:
temperature-320*C l
Fig. 6-1 on page 6-7 shows the results of the calculation c.
l on the relation between burst pressure and defect geometry of an actual size tube.
i l
l d.
The burst pressure of a tube supposed to have a defect of either wastage or SCC in the size of 20 mm length and 50%
2 from Fig. 6-1, depth is estimated to be about 260 kg/cm 2
the safety margin of which will be 2.6 to about 100 kg/cm of differential pressure between primary and secondary sides.
A.2-43
i (2) Collapse test a.
An empirical equation for the-relation between collapse pressure and defect size was formulated based upon the test results, and the collapse pressure was calculated with the yield stress value of the MITI Code in the same conserva-tive way as for the calculation of burst pressure.
Such results are shown in Fig. 6-2 on page 6-7.
b.
The collapse pressure of a tube supposed to have a defect of wastage in the size of 20 mm length and 50% depth is estimated at about 180 kg/cas from Fig. 6-2, the safety margin of which will be 3.1 to 58 kg/cas external pressure at a time of hypothetical LOCA.
On the basis of the above-mentioned tests, it may be said that the steam gen-erators being used at pressurized reactor plants in operation or under construc-tion would remain reliable and safe if they are operated under normal conditions.
Q.4.5.1 We would like to discuss results of studies of impacts upon damaged tubes and neighboring tubes as conducted at Takasago Institute of Mitsubishi Heavy Industries.
Did you study effects of. impacts of swinging tubes and of jet collisions on damaged tubes in the neighborhood? What conclusions have been drawn about possibility of damaging tubes, on the basis of test results?
Test conditions for dynamic behaviors of defected and adjacent tubes are as shown in Table 5, but the adjacent tube used was an integral tube and not a degraded tube.
Preliminary analyses were carried out on the basis of the results of demonstration tests, in order to confirm reasonableness of the para-meter study of dynamic stress analyses and analysis methods.
Then the behavior.
of tubes was analyzed using a general purpose structural program to find that stresses occurring on fractured and adjacent tubes are within the allowable limits, and there is no possibility of breaks spreading to adjacent tubes one after another.
Q.4.5.2 We would like to discuss results of the " leak rate test" done by Takasago Institute of Mitsubishi Heavy Industries.
Was the leak rate test-done on damaged tubes? How were the-results of the leak rate test used to calculate limits of leakage to the secondary side from the primary side?
As shown in Table 5, the demonstration tests done in Japan are not so-called leak rate tests.
They were conducted for 1_to 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br />, using tubes with drilled holes and slits, in order to find erosion phenomena caused by blow-off' on the fractured portion and on the neighboring tubes.1 The results were that l
no changes were observed in the fractured portion and damages due'to jet col-lision with parts of the neighboring tubes were minimum.
In addition, nitrogen gas and room temperature water were ejected continuously, using damaged tubes, j
to maintain an internal pressure at 100kg/cm2 in order to measure blow-off rate.
j Then, the size of the opening area was calculated.
In Japan, a plant is it diately stopped when a leak from the steam generator primary side is j
detected, and thus there are no leak limits established.-
1 A.2-44
~
~
.~
i 1
)
Q.4.5.3 How are results of development and research being applied?
i Results obtained through demonstration tests are technically studied by the technical advisory group and the safety committee established within the i
Ministry of International Trade and Industry.
If their justification is con-1 firmed, they will be positively applied to plants in service or under construc-tion.
Q.4.5.4.
What areas of steam generator integrity have Japanese utilities identified for future research?
From our experience of operation, improvement of heat transfer tubes may be said to be most important to improve integrity of the steam generator.
To that end, it is necessary to make investigation in three stages:
(1) plants which will be i
constructed in the future, (2) those under construction or under plan and (3) those in service.
As for (1), efforts are being made to develop advanced j
PWRs, and development of the steam generator is listed as one of the most in-i portant development efforts.
Development efforts are being made in the fields of material, structure and strength, including investigation of materials for i
heat transfer tubes.
As for (2), relying upon operation experiences up to 1975, j
development efforts have been made and results are incorporated in Types SIM and 51F.
(Refer to Section 2.1 above.) As for (3), it is difficult to modify struc-tures and materials of existing steam generators, and thus the most important t
task will be to prevent degradation in maintaining their performance throughout their life.
It is also necessary to develop repair techniques to maintain i
their functions.
It is therefore necessary to conduct research efforts as to (1) and (3).
One pf the research efforts on plants in service is "Research on 4
l Measures to Improve Reliability of Existing Steam Generators by the Joint Study Group (phase 1)."
l l
4 i
i I
I r
)
A.2-45 i._-.__....-.___,_.---.
5 INTEGRITY OF STEAM GENERATOR In Japan, degradations of steam generator tubes have been experienced as follows:
(1) Wall thining (wastage) due to local concentration of sodium phosphate.
(2) Intergranular attack and/or stress corrosion cracking in the tube sheet crevices or in the tube support plate crevice due to concentration of caustic soda produced from a small amount of sodium phosphate left in the steam generator secondary side or mixed in from the auxiliary boiler.
(3) Stress corrosion cracking from the primary side of the small radius U-bend part and the mechanical expanded part with high residual stresses from processing.
(4) Fretting wear on the anti-vibration bar part.
(5) Fretting wear due to foreign matter.
Most of the, degradations mentioned above were discovered through inservice inspection performed during annual inspection.
Some were discovered through inspection performed after stopping of plant operation when a leak occurred in operation.
As countermeasures, it has been decided to place plugs or to perform sleeve repair in all defected tubes found by eddy current testing to be performed during inservice inspection.
As for the plug, an explosive type or a welded type was used formerly.
In recent years, however, mechanical types are being used to reduce exposure.
Sleeve repair is currently applied when there is SCC in the tube sheet crevices or in the partially expanded end.
As for leaks from steam generator tubes, a plant stops operation when indication of the radiation monitor installed there reaches the alarm point.
In recent cases, some plants were stopped when activity was detected in the steam generator blowdown water through analyses performed once every week, even though the monitor did not indicate the alarm point.
- Thus, there have been no cases of radiation discharged affecting the environment.
Q.5.1 Are data available which summarize operating problems and examine them?
(1) Problems experienced wall thinning....................yes stress corrosion cracking primary side........yes secondary side......yes l
A.2-46
i denting..........................none U-bend part cracking.............yes pitting..........................none r
j fretting.........................yes i
4 loose parts and foreign matter...yes 4
fatigue cracking................none j
others........................... SCC on explosive plugs T
(2) Corrective actions for problems of (1):
i i
wall thinning......................... change to AVT, removal of residual j
sodium phosphate by washing, installation of plugs in defected tubes i
SCC on the secondary side............. hot water flushing, reroll repair, l
sleeve repair (SCC measures on tube sheet crevice part), installation of plugs 1
SCC on the primary side............... sleeve repair, installation of plugs (expanded part) i l
cracking on the U-bend part........... installation of preventive plugs in tubes of row 1 and/or row 2 l
fretting.............................. installation of plugs i
4 loose parts and foreign matter........their removal l
SCC on explosive plugs................ replacement with mechanical plugs See Tables 5.1(1) through 5.1(5).
Q.5.2 Frequencies of leak, rupture and forced outage due to each degradation mode, for each item of 5.1(1):
Japan has experiences of about 60 years of reactor operation, but cases of l
1eakage are very few, and it is not proper to show them in terms of i
frequencies per year.
Thus, actual cases are listed below, t
I i
1 4
4 A.2-47
Table 5.1(1) 1.G.A./S.C.C. AT TUBE SHEET CREVICE AND IUBE SUPPORT PLATE CREVICE EXPERIENCED PLANT MIHAMA 2 (T.S., T.S.P.)
TAKAHAMA 1 (I.S.
)
TAKAHAMA 2 (T.S.P.)
0HI 1 (I.S.P.)
CAUSE LOCAL CONCENTRATION OF CAUSTIC SODA PRODUCED FROM SODIUM PHOSPHATE OR LEAKED FROM MAKE-UP DEMINERALIZER PREVENTIVE ACTIO*'
HOT WATER FLUSHING i
SLEEVING k
J l
i I
A.2-48 i
Table 5.l(2)
S.C.C. AT SMALL RADIUS U-3END l
EXPERIENCED PLANT IAKAHAMA 1 OHI 1 CAUSE HIGH RESIDUAL STRESS INDUCED BY PARTICULAR BENDING PROCESS AND LOAD INDUCED STRESS PREVENTIVE ACTION REGIONAL PLUGGING i
i l
1 1
i i
A.2-49
Table 5.1(3)
S.C.C. AT R0s.L EXPANSION EXPERIENCED PLANT OHI 1 OHI 2 TAKAHAMA 1 CAUSE HIGH RESIDUAL STRESS INDUCED BY INADEQUATE ROLLING t
PREVENTIVE ACTION PLUGGING SLEEVING (UNDER DEVELOPMENT) i REROLLING (UNDER DEVELOPMENT)
I i
l L
A.2-50
i Table 5.1(4) i S.C.C. OF EXPLOSIVE Ptus 4
1 EXPERIENCED PLANT MIHAMA 1 i
CAUSE HIGH RESIDUAL STRESS INDUCED BY EXPLOSIVE EXPANSION PREVENTIVE ACTION REPLACEMENT WITH MECHANICAL Ptus i
l i
1 l
I i
1 i
l 1
A.2-51
Table 5.1(5)
SILMI fiKRAIOR EX11Rl!KE (IMWER UF llNS PLUQ10 NRI It'S CAU2)
Kansai Electric Co.
FEB. 1983 CNIX FIRST SUWCR SECOWAltY El trN SCC SCC FKillNG ngt gg CAPEITY C0KKIAl. IWlufETUE IIF DEMISiltY
- THIMIF, 01ER TWAl 001D Oltilall0ll TUBES CONTROL T.S.lf T.S.P. T.S CEVitE IIGII Il0ll A.V.S. F0ElGil Il-N M IE (ce)
(un)
(uu)
(lD)
(00) j Miluim 1 345 1970/11 C.E.
4,426X2 1.329 0
0 0
0 0
0 N!"'" 2,214 MitgIm 2 500 1972/07 M.N.I 3,260X2 206 13 42 0
0 0
0 k$'"
334 MilWIm 3 826 1976/12 3.N.I.
3,38013 AVi/C3 0
0 0
0 0
0 0
Y#
2 TAKAINHL 1 826 1974/11 W.H.
3,38813 9R 0
78 97 1
0 0
186 460 TAIWWim 2 826 1975/11 M.N.I.
3,38013 Mi 0 1%
0 0
0 0
0 S'
197 ONI 1 1,175 1979/03 W.H.
3,388X4 AVT/CD 0
26 0
31 0
0 72$'"
82G lillt 2 1,115 1979/12 M.N.I.
3,388X4 AVi/C8 0
0 0
0 63 0
0 66 IIDIE su fUni PIIGeuCEB 808106 IWAFETWilIG enPEVOITIVE Plug en SN8tillG
- r.4, S.,,,.a ti. h 9e* Tw&e SLM
forced extent of leak outage name of unit (0-0.lgpm)(0.1-0.3gpm)(0.3-damaged)(frequency) wall thinning Mihama No. I 1
1 2
Mihama No. 2 1
1 stress corrosion Mihama No. 2 2
2 cracking Takahama No. I 1
1 cracking on U-Ohi No. 1 1
1 bend part foreign matters Genkai No. 1 1
1 others (SCC on Mihama No. 1 2
2 explosive plug)
See Tables 5.2(1) through 5.2(3).
Q.5.3.
Experiences of repairing steam generator tubes:
(a) type of and method of installing plugs used, (b) type of and method of installing sleeves used, (c) plugging criteria for tubes with denting, and (d) what operating experiences do you have on tubes with lugs or sleeves; have you had any experiences of loosening or leak?
See the general discussion at the beginning of this section.
Stress corrosion cracking, resulting in tube leaks, has occurred on explosive plugs, all of which are being replaced with mechanical plugs or sleeves.
No leak has ever occurred through mechanical plugs or through welded plugs for extracted tubes or leaking tubes.
No other problems, such as denting, have occurred.
A.2-53
[
i l
Table 5.2(1)
STEAM GENERATOR LEAK EVENT (1/3) t PLANT MillAm 1 DATE OF LEAK JUN. 13 JUL. 17 MR.19 JUL. 27 OCCURRENCE 1977 1974 1982 1982 i
l ACTIVITY LEVF8 IN 2RY SIDE 5
NNilTOR R-15 70 ~100 -+ 10 70~80 50 -* 140 55 -> 100 I
(CPM)
-*900 R-19 2,000~5,]10 600~700 i
200 200 t
(CPM)
-+ 6.4X
-+ 2,500 1
CONDENSER EJECTOR 1.4X10-4 3.1X10-5 (uC /cc)
S6 BLOWD0lNI (uCi/cc)
A-SG 9.7X10-3 A-SG 6.8X10-6 A-SG 2.5X10-7 A-SG B.G a x
B-SG 4.9X10-4 B-SG B.G A-SG 1.7X10-6 B-SG 1.7X10-6 l
(o.3yd (o.esyd
(.coansy)
(.oc e3y )
LEAK RATE (L/H) 70 1.6 0.10 0.08 l
LEAK CAUSE WALL THilgillIG WALL THilWIING EXPLOSIVE PLUG EXPLOSIVE PLUG SCC -+ SCC SCC - SCC i
h
l Table 5.2(2)
STEAM GENERATOR LEAK EVENT (2/3)
PLAllT HlHAHA 2 DATE OF LEAK JAN. 8 OCT. 24 FEB. 8 OCCURRENCE 1975 1979 1983 ACTIVITY LEVEL IN 2RY SIIIE MONITOR R-15
'70~100 50 ~100 45~50 (CPM)
~ 1300
-- 160
- 55 I
R-19 350~400 300~400.
100 (CPM)
-+ 900
-- 480 ColWENSER EJECTOR IX10-5 2X10-5 (uC /cc)
SG BLOWDOW (uti/cc)
A-SG GX10-5 A-SG 6.'2X10-7 A-SG B.6 B-SG 3X10-6 B-SG 1.3X10-5 B-SG SX10-7 i
(o.ozy )
@002Jr'")
LEAK RATE (L/H) 4.0 0.55 LEAK CAUSE WALL TillHNING SCC SCC (T.S. CREVICE)
(T.S. CREVICE)
Table 5.2(3)
STEAM GEllERATOR LEAK EVENT (3/3)
.1 PLANT TAKAHAMA 1 Ollig DATE OF LEAK JAN. 23 SEP. 1 OCCURRENCE 1977 1981 ACTIVITY LEVEL IN 2RY SIDE MONITOR R-15 60 100 70 (CPM)
-* 220 v
R-19 100 200 70 (CPM)
-+ 1850 CONDENSER EJECTOR 2.8X10-5 (uCi/cc)
SG.BLOWD0lm (uCI/cc)
A-SG fi.9X10-7 A-SG 8.5X'10-7 B-SG 2.11X10-5 B-SG 8.5X10-7 C-SG 1.1X10-6 C-SG 8.5X10-7 D-SG 3.2X10-6 (o.I 3py (O.oofyg )
LEAK RATE (L/H) 1.6 0.5 LEAK CAUSE SCC SCC (T.S. CREVICE)
(ROW.1 U-BEND)
6 SYSTEM RESPONSE 6.1 System Response During Accident of SG Tube Rupture (SGTR) and Leakage (1) Relating to General Aspects of Plant Operating Procedure The plant operating procedures in Japan are prepared for each plant based on the so-called scenario written following the proceeding of the events, and following each step of actions taken.
The operating procedures are prepared for events up to a complete severance of one single SG tube, which is the design basis event considered in the safety evaluation. With respect to the operating procedures in the event of multiple j
tube rupture, the same operating procedures as for a single tube failure is considered applicable, although further studies are necessary in the light of the possibility of water flooding in the affected SG and of establishing conditions for termination of the emergency core cooling system (ECCS).
Cases of small leaks not serious enough for ECCS actuation have occurred about 10 times in the past in Japan.
But, in all these cases, it has been possible to completely attain cold shutdown by the normal plant cooldown procedures.
The major operating procedures in the event of a tube failure leading to ECCS actuation are explained as follows:
1 i
(2) Major Operating Procedures (a)
Identification of Affected SG l
Identification can be made by abnormal rise of water level in the affected SG or by high level of radiation detected by sampling or by radiation monitor.
(b) Isolation of Affected SG In order to reduce the amount of the radioactive materials released to the outside of the system to minimal, early isolation of the release route from the turbine system and isolation of the release route around the affected SG must be made.
Also in order to minimize the possibility of water flooding in the affected SG, the main feed-water and the auxiliary feedwater must be terminated as early as possible.
(c) Use of Non-Safety Bus After ECCS Actuation Signal Initiation In the case of our domestic (i.e., Japanese) plants, from the view-l point of the rise of peak cladding temperature during a small loss-j of-cooolant accident, it is designed that the service of the non-safety bus is interrupted after initiation of a signal for ECCS actuation, and such auxiliary equipments normally used as the reactor i
coolant pump (RCP), circulating water pump, etc., are stopped.
Con-sequently, after having terminated the leak of the primary coolant, i
i A.2-57
=
the power source of the bus is restored, and pressurizer spray valves and turbine by pass valves are used as necessary.
(Note:
a safety-injection signal causes loss of power to RCPs.)
(d) Cooldown of the Primary Coolant System by Intact SG In order to assure subcooling of the intact primary loop at the time when the primary system's depressurization has been finished, the main steam relief valve of the intact SG is used to cool down the primary loop.
(e) Depressurization of Primary Loop After having initiated the cooldown of the primary system by the intact SG, the depressurization of the primary system is started as early as possible by a pressurizer relief valve to the extent that the subcooling of the primary intact loop can be assured to reduce the leak amount from the primary system to the affected SG, and it is also intended to reduce the possibility of water flooding in the affected SG.
At the time of the completion of depressuriza-tion, the closing of the relief valve of the pressurizer is made sure.
(f) Action to be Taken When SG Steam Relief Valve is Stuck Open When the affected SG pressure is lower than the steam pressure at no load, confirm the isolation of those routes that have the possibility of steam release including the SG steam relief valve stuck open.
Both the target cooling temperature of the intact primary loop cooling and the starting time of depressurization of the primary system are different from the case when there is no abnormal steam release from the affected SG, to assure subcooling in the primary intact loop.
(g) ECCS Termination After completion of the primary system depressurization, ECCS termina-tion criteria, such as repressurization of the primary system by ECCS injection, recovering the water level of the pressurizer, and sub-cooling of the intact primary loop, are confirmed and then ECCS is terminated.
The ECCS termination criterion of primary repressuri-zation has been established to keep the leak amount of the primary coolant small, and also to minimize the possibility of water flooding in the affected SG.
After termination of ECCS, the normal charging and letdown system is employed.
(h) RCP Restart Confirming that it is possible to prevent the primary system's abrupt pressure variation right after RCP restart, and also that the oper-ating condition is such that the integrity of RCP is firmly assured, the RCP of the intact loop is to be restarted.
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I (i) Cooldown of the Affected SG The affected SG steam relief valve and turbine bypass valves are not i
used to cool down the affected SG in order to prevent releasing radio-active materials to the outside of the system and to the turbine system.
The affected SG is cooled down via reverse heat transfer l
from the affected SG secondary to the primary coolant system cooled by the intact SG steam relief valve or turbine bypass valve.
(3) Others t
(a) Relating to Formation of Steam Phase in Primary Cooling System Following the initiation of an ECCS actuation signal and after the RCP has stopped, the primary coolant flow moves to natural circula-4 tion.
During the process of the primary system depressurization by the pressurizer relief valve, there is a possibility of forming a steam phase in the affected primary loop and the top of the reactor vessel.
But its amount is so small that it does not obstruct the j
heat removal by natural circulation in the intact loop.
(b) Establishment of Natural Circulation Heat removal from the primary system by virtue of natural circulation is confirmed in each step of the operating procedures, i.e., the i
primary system is maintained around no-load temperature after tripping l
of the reactor, the main steam relief valve of the intact SG is opened so that the no-load temperature of the primary system is further a
i cooled down, and the subcooling of the intact primary loop has been assured before the termination of ECCS.
j i
l 6.2 Conclusion on Radiation In our country (Japan), there have been experienced about 10 times quite trivial cases of SG tube leak events in the past.
In all these cases, exhaust gas monitors of the water condenser detected leakage.
As no plant operation accompanying SG tube leak is permitted, the nuclear power station, after having i
taken necessary action, follows the normal plant shutdown procedures to bring the nuclear reactor to cold shutdown.
1 In the event of initiation of SG tube leakage, it is monitored and detected i
by the SG blowdown monitor and'the condenser exhaust gas monitor, and the l
radiation-level high signals are sent out.
SG blowdown water and condenser exhaust gas are isolated by the radiation-level high signals.
The condenser _
i exhaust gas is discharged from the auxiliary building exhaust stack or the containment exhaust stack through the exhaust gas system of the controlled
,t access area.
l Evaluation of Released Activity Durina Post SGTR Accident l
The evaluation of released activity in a design-basis accident is made relating to the following conditions:
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(1) A hypothetical assumption is made on a complete and instantanous severance (double-ended break) of a single SG tube.
(2) For the secondary-system radiation source,.the following.shall be assumed:
(a) Noble gas and iodine as fission products released into the primary coolant based on 1% fuel defect during norma? operation.
(b) Noble gas and iodine as fission products additionally released, as_a result of the accident, into the primary coolant from tte fuel defects given in (a) above).
For this additionally released activity, gap activity shall be transferred to the primary coolant in proportion to depressurization of,the primary coolant until the affected SG is. isolated following the accident.
(3) Noble gas and iodine activity, transferred from the primary system into the secondary system until the affected SG is isolated, shall depend on the concentration of the primary. coolant.
(4) The whole amount of noble gas activity transferred into the secondary system shall be released to the atmosphere.
(5) The iodine activity transferred into the secondary syEtem shall be released to the atmosphere with steam at the gas / liquid partition factor of 100.
(6) After the isolation of the affected SG, iodine shall be released to the atmosphere due to the steam leakage from the secor.dary system valves.
The initial steam leak rate from the valves.shall be the dtsign value and, 4
thereafter, steam leakage shall continue, corresponding to the secondary, system pressure which decreases down to the level of the atmospheric pressure in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after isolation.
(7) The off-site exposure dose due to the released activity evaluated by the above assumption shall be less than 0.5 reta of the whole body exposure dose and less than 1.5 rem of thyroid gland exposure dose for a child.
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Significant Steam Generator Tube Rupture Accident Assumptions NRC Design Basis Accident Japanese Design Basis Accident One tube with a double ended rupture, as the Complete severance (double-ended rupture) of a limiting case for leakage of multiple tubes.
single SG tube.
Plant-specific Technical Specification limit Concentration of iodine in the primary coolant on initial coolant concentration. (1.0 pCi/gm calculated based on a UE fuel defect, which varies dose equivalent I-131* for plants with Standard per plant. Iodine is I-131 - I-135, and I-131 Technical Specification and between 2.0 pCf/gm equivalent concentration is abcut 2 - 4 pCi/g.
dose equivalent I-131 and no specific limit on radiolodines for plants without Standard Technical Specifications)
Plant-specific accident duration almost always The isolation duration of the affected SG is 0.5 - 0.8 hr 0.5 hr.
(varies per plant).
Relief through atmospheric dump or relief valves The secondary system pressure decreases to the level of a
c until pressure reduction in the affected steam a:.ospheric pressure after one day from the isolation generator, plant specific, almost always 0.5 hr.
of the affected SG.
The leakage occurs from the sec-condary system valve. The defect of atmospheric release Condition-dependent decontamination factor.
valve open is a double failure and, though not a design Specified calculations have used an average value basis accident, it is well evaluated and is confirmed of 10 for Westinghouse and Combustion Engineering to meet the criteria.
plants and 1 for Babcock and Wilcox plants.
Spiking of dose equivalent I-131 release rate The gas / liquid partition factor of iodine is set at 100.
(C1/sec) by a factor of 500.
l The noble gas and iodine in the fuel gap of EE defected fuel are additionally released in proportion to the depressurization of the primary cooling system until the affected SG is isolated.
Thyroid dose guideline of 30 rem.
The thyroid dose criteria value is 1.5 rem.
[95% worst 2 hr meteorology]
[97% worst meteorology]
- That concentration of I-131 which alone would produce the same thyroid dose at the quantity and isotopic l
mixture of radioisotopes actually present.
The items given above for design basis accidents are different in the case of a major accident or a hypothetical accident of SGTR on the site evaluation basis, as follows:
In the case of a major accident:
(5) As to the iodine transferred into the secondary system, only 1% shall be organic iodine and the whole amount shall be released into the atmosphere, while the remaining 99% shall be inorganic iodine and released into the atmosphere with steam at the gas / liquid partition factor of 100.
(G) After the isolation of the affected SG, inorganic iodine snall be released into atmosphere due to the steam leakage from the secondary system valves.
The initial steam leak rate from the valves shall be with margin for the design value.
The steam leakage from the valves shall continue corresponding to the secondary system pressure which descreases linearly down to the level of the atmospheric pressure in 24 hrs after isolation.
(7) The off-site exposure dose due to the released activity evaluated by the above assumption shall be less than 25 rem of the whole body exposure dose and less than 150 rem of thyroid gland exposure cose for a child.
In the case of a hypothetical accident:
(2) Noble gas and iodine as fission products additionally released into the primary coolant from the defected fuel as a result of the acci-dent, as described in item (b), shall be transferred into the primary cooling system instantaneously following the accident.
(5) The same as in the case of a major accident.
(6) After isolation of the affected SG, inorganic iodine shall be released into the atmosphere due to the steam leakage from the secondary system valves.
The initial staam leak rate from the valves shall continue during 30 days at the rate with margin for the design value.
(7) The off-site exposure dose due to the released activity evaluated by the above assumption shall be less than 25 rem'of the whole body exposure dose and less than 300 rem of thyroid gland exposure dose for an adult.
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l 7 OTHER ISSUES Q.7-1 Water Hammer The Japanese FWR plants have no experience in any event of water hammer in any of these systems:
main steam, main feedwater, and auxiliary feedwater.
It is considered necessary to pay careful attention to those aspects of piping design having no drain pool, abrupt closing of valves, SG water level, water feeding, etc.
With respect to SG J-tubes, they are being used in the GENKAI No. 2 plant.
Before that, all plants used a bottom discharge type, and no on-site modifica-tion to install J-tubes was performed.
With respect to the phenomenon of thermal stratification in the vicinity of the SG feedwater inlet nozzle, we have confirmed the production of this kind of phenomenon by performance of a single model experiment after first hearing of cracks appearing in a feedwater nozzle in the D.C. Cook plant.
In the case of the Japanese PWR plants, it is difficult to think, judging from the present aspects of frequency of use of auxiliary feedwater, its temperature, will,ing and open-end configurations, water quality control, etc., that there weld occur thermal cycle fatigue so easily.
T (1) Have you' experienced any water hammer events in the main steam or in the main or auxiliary feedwater system?
No experience of a water hammer event.
(2) What procedural changes or modifications have you made with respect to water hammer?
In the case of our existing plants, our procedures have been changed so that when the water level in an SG comes down to the level where the feed-water ring is exposed, the feedwater flow rate to recover the original level is slowed down a little so that any possible occurrence of a water hammer phenomenon is made difficult.
In the case of new plants, design is made to provide J-tubes for feedwater to make it difficult for a water hammer to take place, while the procedures are the same as in the existing plants.
(3) Have you had any experience with thermal cycle fatigue cracking b 's feedwater line?
No experience.
(4) Do you have a program related to thermal cycle fatigue cracking in feed-water lines?
No particular program, except that we had a shaple model experiment to confirm the actual occurrence in the past of thermal stratification phenomenon in the vicinity of a feedwater inlet-tube nozzle.
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(5) Are the main steam lines designed to withstand steam generator overfill (water solid condition)?
In order to avoid overfilling of SG water into the main steam line, we have designed to have a higher SG water level so that the feedwater line is isolated.
A. 2-6 4
A, NRC F oRM 335
- 1. REPORT NUMBE R (A er DOCJ U.S. NUCLEAR REGULATORY COMMISSION BIBLIOGRAPHIC DATA SHEET NUREG-1056
[
4 TITLE AN UBT4TLE (Add youme Na, #f auerspaass) 2- (L* * *I REPORf 0. U.S.-JAPAN 1983 MEETINGS ON STEAM GENERATORS I
- 3. RECIPIEN ACCESSION NO.
- 5. DATE MORT CWWD 7 AUTHORtSI MON Tf l YEAR farch 1994 9 PE RFORMING ORGANI TION N AME AND MAILING ADORESS (tache I, Coe)
D/E REPORT ISSUED l YEAR TNTHApril 1984 Office of Nuclea Reactor Regulation 4 g,,,,,
U.S. Nuclear Regu tory Commission
}
Washington, D.C.
55 g
- e. (c. we, 12 SPONSORING ORGANIZATION NA AND MAILING ADDRESS (Inckelt le Codel 10 PROJECT / TASK / WORK UNIT NO.
Office of Nuclear React Regulation ii. CONTRACT NO.
U. S. Nuclear Regulatory ommission Washington, D. C. 20555 13 TYPE OF REPORT E RIOD COVE RE D (Incbsere daars)
Technical Report
/
15 SUPPLEMENTARY NOTES 14 " " * *#
- 16. ABSTR ACT QOO words or wasJ This is a report on a trip to Japa y personnel of the U.S., Nuclear Regulatory Commission in 1983 to exchange info, ation on steam generators of nuclear power plants. Steam generators of, Jap,ar ressurized water reactors have experienced nearly all of the forms of degrada}#se tion hat have been experienced in U.S.
recirculating-type steam generat#rs, ex pt for denting and pitting. More tubes have been plugged per year of r,pactor op ation in Japanese than in U.S. steam generators, but much of the Japanese tube lugging is preventative rather than the resultofleaksexperienced.jThenumbero eaks per reactor year is much smaller forJapanesethanforU.S.sJeamgenerators. No steam generators have been replaced in Japan while several have been rep 'ced in the U.S.
The Japanese experiencemayberelatedgotheirverystringe inspection and maintenance programs for steam generators.
/
17 KEY WORDS Af40 DOCUMENT AN A[YSIS 17a. DESCRIPTORS Steam Generators Japan iL PWRs (Pressurized Water Reactors)
Tube Ruptures Tube Degradatio l'
ira iDENTiriERS OPEN ENdD TERMS
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18 AV AILABILITY STAT ENT a
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i UNITED STATES pounta ctass mast NUCLEAR RE!ULATORY COMMISSION NTAGylcsts raio WASHINGTON, D.C. 20065 wasa. o. c.
n neus m.1st OFFICIAL SUS 8 NESS PENALTY FOR PRr/ ATE USE. 6300 99999 I
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