ML19210D606
| ML19210D606 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 11/23/1979 |
| From: | Burstein S WISCONSIN ELECTRIC POWER CO. |
| To: | Schwencer A Office of Nuclear Reactor Regulation |
| References | |
| NUDOCS 7911270378 | |
| Download: ML19210D606 (74) | |
Text
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Wisconsin Electnc eoWER COMPANY 231 WEST MICHIGAN, MILWAUKEE, WISCONSIN 53201 November 23, 1979 Mr. Harold R.
Denton, Director Office of Nuclear Reactor Regulation U.
S. NUCLEAR REGULATORY COMMISSION Washington, D. C.
20555 Attention:
Mr. A.
Schwencer, Chief Operating Reactors Branch 1 Gentlemen:
DOCKET 50-266 STEAM GENERATORS POINT BEACH NUCLEAR PLANT, UNIT 1 On November 5, 1979, we met with the NRC Staff at our reauest to review recent steam generator experiences at Unit 1 of our Point Beach Nuclear Plant and the results of tube inspections and tests on this unit.
As a result of a petition directed to the Commission by Wisconsin's Environmental Decade dated November 14, 1979, NRC Staff requested a further meeting on this matter, which was held in Bethesda on November 20 with representatives of the NRC, Wisconsin's Environmental Decade, Public Service Commission of Wisconsin, Union of Concerned Scientists, Wisconsin Electric, and Westinghouse Electric Corporation and members of the press and public.
At this latter meeting, we presented information and data previously reviewed with the Staff in regard to the Unit 1 steam generator tube problems and responded to detailed questions of the Staff and petitioner.
At the conclusion of the meeting, Mr. Darrell Eisenhut requested that we submit in writing the materials presented and reviewed during the meeting.
This transmittal is in response to that request.
Attached hereto are enclosures covering the various items of our discussions as follows:
1.
Chemistry History During this phase of the discussion, we reviewed the early phosphate chemical treatment utilized at Point Beach Nuclear Plant, methods and degree of chemistry control, changes in phosphate chemistry, chemical h8(
h (l feed, and stemm generator modifications previouely i
g adopted, and the change to, and experience with, all volatile chemical treatment.
79112703 7S 1397 208
Mr. Harold R. Denton November 23, 1979 2.
History of Tube Defects and Plugging We discussed the early experience with the tube thinning and cracking on Unit 1 which has been arrested since 1975, together with the reasons believed responsible for this experience.
We also reviewed the limited denting phenomena observed at Point Beach, and discussed why this plant did not experience significant tube degradation due to this cause.
We described the early signs of cravice corrosion cracking and the recent large number of such observations in August and October of this year, together with their distribution, size, probable cause and effect.
Additionally, we discussed quality assurance activities in respect to such inspection and repair operations and employe radiation exposure censiderations.
3.
Physical Properties and Testing - Safety Considerations Based on the August and October inspections, we described the analytical program we had undertaken, including the removal of three tube sample specimens from various areas of the "A" steam generator of Unit 1.
We described the removal technique and forces, the metallurgical and physical tests applied to the specimens, and the test results of all samples removed.
We discussed the design of the steam generator and the intergranular corrosion attack found in the unrolled crevice area of the tubes within the tube sheet.
We discussed the safety implications of this phenomenon in respect to loss of coolant, main steam line break, and feedwater line break accidents.
4.
Accident Analysis We reviewed the results of emergency core cooling system,
analyses performed with 18% steam generator tubes plugged at 2250 psi and 2000 psi main coolant system pressure and with nominal and reduced main coolant system temperatures.
5.
Actions to Minimize Degradation and to Assure Safety We described the various actions we had taken and proposed in operating conditions, testing programs, and operating limits to assure public health and safety and to minimize further steam generator tube degradation.
We discussed immediate programs being implemented and long-term solutions under investigation.
1397 209
Mr. Harold R.
Denton November 23, 1979 For details in respect to each of these principal subjects, please refer to the attached enclosures.
We also would refer you to our letters of November 2, 1979 and November 19, 1979 in respect to 2000 psi operation and ECCS analysis.
In summary, we made the following observations and conclusions:
1.
The early difficulties with Unit 1 steam generator tubes were principally due to thinning or cracking caused by phosphate chemical treatment employed between unit start-up and September 1974, when a change to all volatile chemical treatment was made.
Since 1975 no thinning or cracking problems have been observed with this unit.
2.
A minor amount of denting was observed in Unit 1, but this phenomenon has not progressed to any appreciable extent.
3.
Indications of crevice corrosion attack appeared in 1977, but remained relatively minor until August 1979 when 99 tubes (1. 5% of total) required plugging due to this cause.
Inspections conducted during the refueling outage of this unit in October 1979 revealed an additional 134 tubes (2.1%) having this type defect.
4.
Based on samples removed from the Unit 1 steam generator and from other plants in previous years, these defects are concluded to be intergranular corrosion attack of the Inconel 600 tube material in the narrow crevice area caused by residue of caustic materials remaining from phosphate chemical treatment and possibly from earlier condenser tube leakage.
5.
This corrosion is confined to the crevice area.
No evidence of this intergranular attack was found in areas of tube above the tube sheet.
6.
Forces required to remove the sample tubes were as follows:
Tube No.
Pulling Force, Lbs.
R15C45 25,600 (tube broke in pulling)
~
R22C37 25,400 R20C73 13,000 Aforceof28,500pobndswasexertedonTubeR15C45, at which time the pulling tool failed.
This tube was subsequently broken 1-1/2" below the top of the tuta sheet with the force indicated above.
These forces demonstrate there is no safety concern with respect to tube pull-out of bundle lifting with steam or feedline break accidents.
1397 210
t Mr. Harold R.
Denton November 23, 1979 7.
Burst tests conducted on three samples from two tubes were as follows:
Tube No.
Burst Pressure, psi R22C37 11,700 (yield, no burst)
R22C37 6,800 R15C45 5,100 All bursts were Pf longitudinal failures.
No circum-ferential failures were observed.
The first five-inch sample of the K22C37 tube (above) was taken from a location whi-h transversed the tube sheet top-tube interface.
The other tuo five-inch samples were from within the crevice region.
These tests demonstrate that even the significantly degraded tubes have a capability to withstand the maximum accident primary-secondary differential pressure of 2000 psi with margins of safety of 2.5 or greate7;.
A new tube burst pressure is nominally in the 10-12,000 psi range.
8.
Metallurgical examination reveals sound tube metal under the area of corrosion attack having metal properties equivalent to virgin material.
Metal thickness required for various conditions of operation and accident are as follows:
Double-ended failure during steamline break 0.005 inch Tube rupture during normal operation 0.008 inch Tube rupture during steamline break 0.013 inch No collapse during LOCA (With 6% ovality) 0.020 inch (With zero ovality) 0.011, inch Because C% ovality in the crevice is deemed impossible, it is believed that 70% wall thickness degradation would still leave sufficient material of sound metallurgical capability to withstand accident conditions, even if intergranular attack extended to this depth in areas of tube above the tube sheet.
Since these tube defects are confined to the tube sheet crevice area, even greater tube wall penetration can be tolerated without exceeding safety requirements under accident conditions.
1397 21I
c Mr. Hhrold R. Denton November 23, 1979 9.
Present eddy current testing has demonstrated its capability to detect cracks from a range of 20%
through wall to full-wall penetration.
This technique, however, is not an effective means of detecting intergranular corrosion in the absence of cracks.
Because a diametrically unrestrained tube, such as in the space above the tube sheet and outside tube support plates, expands under internal pressure, intergranular corrosion in such areas would be revealed as cracks.
In the tightly constrained areas within the tube sheet, tube expansion under internal pressure is effectively precluded.
While this makes eddy current indication of intergranular attack incapable, the totally contained tube cannot expand under internal pressure to cause significant cracking or rupture during normal or accident conditions.
10.
Tube clearances within the tube sheet can vary because of manufacturing tolerances from.016 in to.022" cn the diameter.
These clearances are probably further reduced by the caustic and corrosion products.
The tubes in the crevice area are, thus, tightly confined within the tube sheet, which severely limits any primary to secondary leakage and prevents tube collapse in the event of excessive secondary to primary pressure differential.
11.
ECCS analysis demonstrates that operation with 18%
of the tubes plugged is well within established safety criteria at either 2250 psi or 2000 psi reactor coolant system pressure or at nominal or reduced primary system temperatures.
12.
No tube failures due to crevice corrosion have occurred on the cold leg side of the Point Beach steam generators.
Research indicates such inter,-
granular corrosion attack is sensitive to temperature.
13.
While we conclude that safe coeration of Point Beach Unit 1 is not presently jeopardized, we nevertheless intend to proceed with the following program to provide additv>nal assurance of continued safety:
a.
Conduct an 800 psid hydrostatic test, secondary to primary, before return to power.
Such test pressure exceeds the pressure which might be imposed on the steam generator tubes in the event of a loss of coolant accident.
Should any significant leakage develop, the failed tubes will be plugged.
(This test was successfully performed on Unit 1 on November 12, 1979.)
1397 212
c tir. Harold R.
Denton November 23, 1979 b.
Conduct a 2000 psid primary to secondary hydroctatic test prior to return to power.
Should any significant leakage develop, tubes will be plugged.
This test pressure exceeds that which could develop during a steamline or feed level break and, thus, demonstrates the tubes' ability to maintain their integrity during such events.
(This test was successfully performed on November 20, 1979.)
c.
Presuming NRC approval of the Technical Specification change previously requested, operate the reactor coolant system at the nominal pressure of 2000 psig rather than 2250 psig.
This reduces internal pressure stresses during operation approximately 15%.
d.
Continue close surveillance of primary to secondary leakage and shutdown and plug leaking tubes if:
1.
Sudden leakage of 150 gpd (0.10 gpm) occurs, or 2.
Any leakage of 250 gpd (0.17 gpm) is experienced, or 3.
Rate of change of leakage increases above 15 gpd per day (0.01 gpm) between 150 gpd and 250 gpd total.
e.
Repeat 2000 psid primary to secondary hydrostatic test in approximately 30 days and, if satisfactory, again, in 60-90 days.
Should any significant leakage develop per Item d above, leaking tubes will be plugged.
f.
Increase the frequency of eddy current testing of Unit 1 steam generators A and B by performing an eddy current test in accordance with Technical Specifications within one year of return to power rather than in two years as now provided.
All eddy current tapes to be reviewed by qualified (Level III) reviewers.
14.
On return to power operation, we are planning the following program in an attempt to retard further tube degradation:
1397 213
f Mr. Harold R.
Denton November 23, 1979 Reduce reactor coolant system hot leg temperature a.
to approximately 557'F.
This will result in lower secondary steam pressure and, hence, lower power output due to limited flow capability of main turbine control valves.
Maximum output under these conditions is expected to be 83% full power or 413 MWe net.
Testing will be performed to assure main steam moisture carryover does not exceed design value of 0.25%.
b.
Continue close surveillance of feedwater chemistry conditions and condenser tube leakage.
c.
Perform sludge lancing within 12 months of return to power.
The effects of these operating conditions will be reviewed with the NRC Staff if any significant results are obtained or if any cignificant changes to this pro 7 ram are contemplated.
15.
Although Wisconsin's Environmental Decade petition contained a number of statements which we believe are in error, its major safety concern relates to the American Physical Society, Lewis Report, (1975), reference to the potential for steam generator tube failure during a severe LOCA which could adversely affect ECCS performance.
Since the present tube degradation problem at Point Beach is confined to the tube sheet crevice area, and since a tube collapse within the tube sheet area cannot occur during a LOCA or otherwise, the possibility of having secondary side inventory interfere with blowdown and reflood during a LOCA does not exist.
Insofar as rupture of a tube above the tube sheet during LOCA is concerned, there is nothing in the present o'r foreseeable steam generator tubing characteristics inspection or operating programs that constitutes a change from previous conditions.
In conclusion, we have demonstrated that continued operation of Unit 1 at Point Beach would not compromise public health and safety.
The existing basis for continued safe operation of this unit is still applicable.
We have shown that the intergranular attack is confined to the tube sheet crevice location.
The burst tests demonstrate even the affected tubes have ample margin as compared to calculated loads.
Tensile tests, plug tests, and stress analysis confirm tube integrity. Tube removal forces demonstrate the capability of the tubes to carry substantial loads.
Our operating history and that of others confirm that detectable leakage appears before serious tube degradation.
Proposed operating and testing programs demonstrate safety margins and may retard further degradation.
1397 214
f Mr. Harold R.
Denton November 23, 1979 As we advised you previously, Unit 1 will not be returned to power without NRC concurrence, We appreciate your continuing immediate review of this matter.
Please telephone us if you have any question or require further information.
Very truly yours, 7
p__ _._.. _
^
=:=-
/
Sol Burstein Execptive ice Presi ent Enclosures Copy to:
Mr. Clarence Riederer Public Service Commission of Wisconsin Ms. Kathleen Falk, General Counsel Wisconsin's Environmental Decade, Inc.
Marian Moe, Esquire Office of General Counsel H-1047 U. S. Nuclear Regulatory Commission
~
e ENCLOSURE 1 Chemistry History The chemistry history of Unit 1 is summarized in View-graph 1.
From initial startup at the end of 1970 to January 1972, phosphate chemistry was used for steam generator chemistry control.
In addition to continuous feed, phosphates were batch-fed to the steam generators in attempts to maintain specified phosphate concentrations.
Steam generator blowdown was intermittent, in accordance with then-existing control practices.
During early 1971, Unit 1 experienced numerous condenser tube leaks, free caustic was present in the steam generators and sodium to phosphate (Na/PO4) ratios were generally high.
The condenser leakagc' problems decreased after modifications to the condenser in 1911.
Na/PO4 ratios remained high and free caustic was present during
~
the remainder of the period.
From January 1972 to September 1972, phosphate concentra-tions were increased using the same batch and continuous feeding methods.
The periods of operation with free caustic were reduced and the Na/PO4 ratios were generally controlled between 2.0 and 2.6.
The unit was shut down for its first rsfueling in September 1972.
Following completion of the refueling and maintenance outage in March 1973, the phosphate feed system was modified to allow better control and continuous blowdown was initiated.
In 1597 216 El-1
e c
early 1974, the Na/PO4 control ratios were adjusted to between 2.3 and 2.6.
During the April 1974 refueling shutdown, the steam generators were sludge lanced.
Between May and October 1974, phosphate chemistry control was further improved and in June 1974 tube lane bloc!cing devices were installed to improve circulation and sludge removal.
In September 1974, an online conversion to all volatile treatment (AVT) was performed by discontinuing phosphate feed and initiating maximum steam generator blowdown.
The online conversion was marginally successful, however, and free caustic was confirmed in November 1974.
During November, a 48-hour shutdown and soak were performed for phosphate removal.
The unit was sludge lanced and returned to power with AVT treatment.
During 1975, as shown on Viewgraph 2, operation with AVT chemistry indicated free caustic was present during operation and sodium and phosphate hideout return was present during unit shu.tdown.
During 1976 and 1977, levels of free caustic generally decreased although free caustic was frequently detected.
Sodium and phosphate continued to be detected during unit shutdowns.
In 1978 and 1979, free caustic was normally below detection limits and sodium and phosphate, although stil'1 present, were much lower during unit shutdown.
The continuing improvement in AVT chemistry control from 1975 to present has been due in large part to increased attention to condenser leakage and the continuing development of leakage detection capability.
In 1978, additional condenser hotwell cation conductivity devices were installed on individual
}3 El-2
e hotwells to allow identification of condenser leaks in individual condenser sections.
Conductivity values are recorded for confirmation of condenser integrity.
Leak detection limits are in the order of 0.05 to 0.1 gallons per minute and Freon detection instrumentation has been used to identify tubes with very small leaks.
When a condenser leak is identified, administrative policy is to reduce power as soon as practicable, isolate the leaking portion of the condenser, and plug the leaking tube.
These monitoring capabilities and policies ensure condenser integrity and minimize introduction of contaminants to the steam generator.
It was pointed out, in response to a question, that while chloride spikes approaching 10 ppm were present in steam generator blowdown after shutdown, normal operating chloride levels were approximately 100 ppb.
Chlorides, while present, do not appear to be a dominant factor in the crevice corrosion phenomenon.
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ENCLOSURE 2 History of Tube Defects and Plugging The first indication of possible tubewall degradation at Point Beach occurred in Unit 1 in April 1971 (approximately six months after initial criticality) when steam generator leakage was detected.
This leakage varied with time but always was less than 0.05 gpm.
Upon inspection of the steam generator tubing during the first refueling and maintenance outage (October 1972 -
March 1973), the location and mechanism of the tube degradation were identified.
Stress corrosion cracking was identified on the tube surfaces just above the top of~the tubesheet, within the boundaries of the sludge deposition zone in the central region of the hot leg side of the tube bundle The tubas affected x
exhibited axially oriented cracking in the short length of tube generally within the sludge deposition zone.
From March 1973 to August 1974, no steam generator leakage was observed at Point Beach in either Unit 1 or Unit 2.
During refueling outages in both units in 1974, indications of minor tubewall degradation were detected in.both units.
The distribution of eddy current indications (most of which were less than 20 percent of the wall thickness) indicated that the corrosion mechanism was localized thinning of the tubewall due to phosphate corrosion.
These indications were largely confined to the same region in which cracking had been found in 1972 in Unit 1, that is, within the region of the sludge deposition, zone.
There were also scattered indications of thinning noted in certain areas at the tube support pletes where concentration of chemicals could occur.
1397 221 E2-
e In February 1975, a steam generator tube break of approximately 125 gpm occurred in Unit 1.
After shutdown, eddy current inspection revealed indications of tubewall penetration in the same area where tube degradation occurred in 1972.
The cause for these indications and the tube break was judged to be stress corrosion cracking.
The first steam generator leak in Unit 2 occurred in August 1975 in a single periphe.ral tube at the top of the tubesheet.
The cause of this leak was not determined and none of the neighboring tubes had indications of tube degradation, although eddy current inspection indicated some thinning of tubes in the central region of the tube bundle.
Analysis of the eddy current data also indicated the presence of minor denting in Unit 2.
Minor denting was subsequently discovered in Unit 1 during an eddy current inspection performed in November, 1975.
The only other significant occurrences of tube degradation observed at Point Beach is intergranular corrosion of the tubes within the tubesheet crevice region of Unit 1.
The first observation of this phenomenon at Point Beach was, accompanied by tube leakage in September 1977.
Subsequent limited occurrences of this phenomenon in Point Beach Unit 1 were confirmed in September 1978 and March 1979.
In August 1979 and October 1979, significant numbers of tubes in Unit 1 were found to be affected by intergranular corrosion in the crevice region.
Viewgraphs 1 and 2 provide a summary of tubes plugged in each of the steam generators for Units 1 and 2, respectively.
Plugged tubes have been categorized by type of degradation and 1397 222 s2-2
e by time of plugging.
The denting phenomenon, although present in many of the steam generator tubes of both units, has not resulted in plugging of significant numbers of tubes in either unit.
Stress corrosion cracking above the tubesheet and tube thinning accounted for the majority of tubes plugged in the first few years of operation.
Based on more recent experience, both of these corrosion mechanisms appear to have been arrested.
Crevice corrosion has accounted for less than half the tubes plugged in Unit 1 to date.
It has not been observed on Unit 2 even though Unit 2 has operated for approximately the length of time which it took for crevice corrosion to be observed in Unit 1.
As shown in Viewgraphs 1 and 2, less than one-tenth the number
'of tubes have been plugged in Unit 2 as in Unit 1.
The general distribution of tube plugging is shown on Viewgraphs 3 and 4 for steam generator A and 5 and 6 for steam generator B and indicate tubes plugged after the August 1979 and October 1979 shutdowns.
As shown in the viewgraphs, the majority of tubes plugged are in the sludge deposition zone (" Kidney zone")
of the steam generators.
Viewgraph 1 indicates a total of four tubes plugged at various times due to mistakes in identifying the correct tube for plugging.
Considering the total number of tubes plugged in Unit 1 steam generators and the difficulties associated with working in confined and high radiation areas, this number of errors is not unexpected.
1397 223 E2-3 e
e To ensure that the correct tubes are plugged, the following general procedures are used:
1.
Following designation of a tube to be plugged, a confirmation is made by eddy current inspection.
2.
The hot leg end of the tube is located and marked with the aid of templates used during eddy current examinations.
~
3.
A probe is inserted over the U-bend and out the cold leg end of the tube.
This tube end is than also marked.
4.
Explosive plugs and primer cord are inserted into both ends and the correct tubes are, again, verified by visual examinations.
5.
Following plugging, tubesheet photographs are taken and inspected to verify that the correct tubes have been plugged.
'If the shutdown is only for plugging a leakin' tite, there is no need for tubesheet photography.
However, the plugged,
tube is marked on the previous photographs.
The distribution of crevice defects by depth of the defect and by defect location is shown in Viewgraph 7.
Approxi-mately 80 percent of the defects had greater than 80 percent through-wall penetration.
Approximately 40 percent.of the defects in steam generator A are within the top three inches of the
' tubesheet crevice compared to approximately 24 percent for steam generator B.
The distribution of defects by location appears to E2-4
e be more uniform in steam generator B than in steam generator A.
In addition to the data shown in Viewgraph 7, approximately 28 and 10 percent of the defects in steam generator A are within the The top two and one inches of the crevice, respectively.
corresponding values for steam generator B are approximately 10 and 8 percent, respectively.
Eddy current testing is currently not able to detect intergranular corrosion within the tubesheet.
Significant
(>20 percent through wall) cracks or tube wall penetrations in the tubesheet area are, however, detectable by eddy current testing.
The conditions within the tubesheet crevices are such that the tubing material affected by intergranular corrosion is held in place by the tubesheet itself and the crevice condition shows a minimum of grain dislocations or material loss.
As'a result, the grains in the suspect region remain in physical and electrical contact providing a continuous path for eddy currents induced in the tubewall when the eddy current test is performed.
The material, therefore, may show no eddy current indication of the corrosion within the tubesheet crevices unless there is cracking through a portion of the tube wall.
Work is underway to develop simulations in the laboratory for the purpose of determining the sensitivity of eddy current testing to inter-granular corrosion and to eva'luate alternative methods where feasible.
Recent experience with tube degradation due to intergranular attack indicates that more frequent inspections by eddy current testing may result.
If further tubes are pulled 1397 2
3 E2-5
5
=
t for analysis, this will also require radiation exposure beyond tube inspection and plugging.
Radiation exposure estimates from recent refueling inspections and the October 1979 refueling are as follows:
Exposure to Steam Generater Personnel 1976 40 man-Rem (3 to 4 for sludge lancing) 1977 118 man-Rem (3 to 4 for sludge lancing) 1978 40 man-Rem (3 to 4 for sludge lancing)
Oct. 1979 255 man-Rem (estimated)
The 1977 exposure is higher than normal due to diffi-culties in repairing leaking explosive tube plugs and, thus, are
'not believed to be typical.
Preliminary estimates of the exposure during the October 1979 refueling are as follows:
Steam generator decontamination 20 man-Rem Sludge lancing, eddy current 80 to 100 man-Rem testing, and tube plugging Tube pulling 135 to 155 man-Rem The tube plugging in 1976 and 1978 was minimal! therefore, a reasonable estimate of the exposure during a normal eddy-current inspection is in the order of 36 man-Rem.
Comparing this to the total exposure for eddy current testing and tube plugging in October 1979 indicates exposures in the order of 50 to 60 man-Rem for plugging approximately 140 tubes, or 0.4 man-Rem per tube.
Three tubes were pulled for analysis with an estimated exposure in the order of 150 man-Rem, or 50 man-Rem per tube.
From these data, the following exposure commitments are estimated for a tube inspection outage:
, \\}g7h E2-6
e Sludge lancing 4 man-Rem Eddy current inspection 36 man-Rem Tube plugging 0.4 man-Rem per tube Tube pulling 50 man-Rem per tube The basic technique used to minimize radiation exposure during steam generator inspection operations is to limit the time spent in the vicinity of, or inside, the steam generators. Techniques used to accomplish this are as follows: Use of experienced personnel as far as practical Remote readout instrumentation and television surveillance of operations Remotely operated inspection equipment which requires a minimum of entries for fixture changes Means to expedite and verify correct tube locations, i.e., marked templates Television and photographic verification of leak indications and plugged tubes Improved decontamination techniques may be used if future tube pulling is scheduled, although the decontamination attempt in October 1979 involved considerable radiation exposure and was not successful due to equipment problems. 1397 227 E2-7
VIEWGRAPH 1 i 11/13/79 I UNIT 1 STEAM GENERATOR TUBE PLUGGING HISTORY Tubes Plugged Date of Thinning or Crevice Cumulative Outage Elapsed Time Denting Cracking Corrosion Other Total Percent (Years) A B A B A B A B A B A B AII 12/21/70 0 <0.1 0 1 14 4(2) 102 95 3.1 2.9 9/30/72 1.8 87 91 g 4/6/74 3.3 1 1 103 96 3.2 2.9 2/26/75 4.2 59 98 162 194 5.0 6.0 11/16/75 4.9 6 4 168 198 5.2 6.1 10/1/76 5.8 168 198 5.2 6.i I 6/24/77 6.5 1 168 199 5.2 6.1 10/4/77 ,6.9 10 179 201 5.5 6.2 1 2 2/1/78 7.1 (3) 180 201 5.5 6.2 9/20/78 7.7 1 6 4 187 205 5.7 6.3 3/1/79 8.2 8 1 195 206 6.0 6.3 8/5/79 8.6 52 45 247 251 7.6 7.7 I4I 8/29/79 8.8 252 251 7.7 7.7 2 3 II 10/5/79 8.9 70 64 7 4 329 319 10.1 9.8 1 i Notes: (1) Plugged during manufacture. 8 (2) Fourteen tubes in A were plugged due to gouging during machining for clad repair. Three tubes in B were removed for analysis and one was plugged by mistake. (3) Plugged tube was in periphery. tra (4) An audit of tubesheet photographs indicated three tubes which were plugged but previously 'f) not included in inspection reports. N (5) Seven tubes in A included three with defects less than the plugging limit, two tubes which ) had no indications but which were pulled for analysis, and two tubes plugged by mistake. rs) rs) Four tubes in B included three tubes with indications less than the plugging limit and one Cx) tube plugged by mistake.
VIEWGRAPil 2 11/13/79 UNIT 2 STEAM GENERATOR TUBE PLUGGING IIISTORY Tubes Plugged Cumukative Date of Thinning or Crevice Outage Elapsed Time Denting Cracking Corrosion Other Total Percent (Years) A, B A_ B A B A, B A, B_ A_ .B III 1 1(3) 1 1 <0.1 <0.1 8/2/72 O 0.6 <0.1 <0.1 3/8/73(2) 3 4 4 5 0.1 0.1 10/17/74 2.2 4 8 0.1 0.2 3 8/11/75 3.0 18 12 0.6 0.4 14 4 2/26/76 3.6 20 17 0.6 0.5 5 3/4/77 4.6 2 ~0.7
- 0. 5, 22 17 2
3/ /78 5.6 22 18 0.7 0.6 1 3/ /79 6.6 22 18 0.7 0.6 Present 7.3 Notes: (1) 20 percent power operation. (2) Begin increase to 100 percent power. Achieved in April 1972. (3) One tube plugged during manufacture and one tube not installed. ~O N N N sO e.
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L f ENCLOSURE 3 Physical Properties and Testing - Safety Considerations Three sections of hot leg tubing from'A steam generator were removed and sent to the laboratory of the Westinghouse R&D Center in Pittsburgh for detailed investigation of the metallurgi-cal and physical properties and characteristics. Viewgraph 1 lists the types of investigations that were conducted on the tube samples at the Westinghouse laboratory. Included were eddy current testing (ECT) in the laboratory, radiography, i.e., X-ray of the tube by standard industrial radiographic techniques by'the non-destructive test (NDT) group at the labs, metallographic examinations and instrumental microanalyses of the small amounts of materials from the pl' ant that were retained on the surfaces of the pulled tubes. These analyses included the scanning electron microscope (SEM), energy-dispersive analysis of X-ray (EDAX), electron beam microprobe analysis, and an X-ray diffraction pattern determina-tion and speci'es identification of a small powder sample taken from the tube surface. The tube sections were also subjected to extensive mechanical properties' testing. The mechanical properties tests will be discussed in detail. The next three viewgraphs show the tube sections that were removed and how and where the various test samples were taken for these examinations.. Viewgraph 2 shows the first tube section that was removed from Row 15, Column 45. Primary flow is upward. About 20-1/2" of tubing were received in five sections, the longest ~ 1397 235 E3-1
L e of which was a 14-5/8" piece. This long piece extended up to the point where it broke in pulling at a point about 2" below the top of the tubesheet. This tube was extensively examined at many elevations by scanning electron microscopy (SEM), X-ray analysis (EDAX), and by metallography. Three kinds of mechanical properties tests were made; these include a hydraulic pressure test (burst test) on the 5" long section, lead plug load-displacement test on the two 1-inch sections shown, and tensile tests in which stress-strain diagrams were obtained on conventional-geometry sub-size tensile samples that were machined out of the tube at the location shown. Viewgraph 3 shows the second tube, Row 22 Column-37, from the central region. (It is actually the third tube that was pulled in chronological order.) This tube extended no well above the tubesheet [to just below the first support plate (SP)] and afforded the investigators the opportunity, therefore, to conduct both mechanical properties tests and metallographic examinations of material that was outside of the crevice as well as within the crevice. The upper 5" long section identified for the hydraulic burst test spanned the top of the tubesheet and extended about 2-1/2" above and below this location. A second hyd'raulic bu~rst test on a 5" sample was conducted on a section from within the crevice. The other mechanical properties tests indicated were the lead plug load-displacement tests, and tensile samples were again machined from samples deep within the crevice. Note.that a transverse metallographic cross section was made on a section above the tubesheet immediately adjacent to the upper hydraulic burst sample. E3-2 1397 236
e Viewgraph 4 depicts the third tube section, Row 20 Column 73,.which was taken from nearer to the periphery of the bundle than the preceding tubes. This tube also extended well above the tubesheet and passed through the first tube support plate. The laboratory investigations included a detailed examination above the tubesheet on a transverse ring 3/4" above the secondary face of the tubesheet, and on a longitudinal 1-1/2" long section, indicated by the short vertical lines, that extended 3/4" above and below the top of the tubesheet. A metallographic examination was also made at a point deep within the crevice and numerous areas were examined by the microanalytical r technique for the composition of materials on the tube surface. Viewgraph 5 smnmarizes the results obtained on metal-lographic examination of all three tube sections. The 15-45 tube that showed an 89 percent in-plant eddy current signal was observed to have cracks through about 90 percent of the wall adjacent to the location of the in-plant signal. This confirms the plant eddy current signal (ECT). This confirmation was also obtained from SEM fractography of the field break which showed that the break was tensile overload ductile-shear due to the large pulling force and that the amount of material remaining to sustain this load was consistent with about 90 percent of the tube having been penetrated by intergranular attack (IGA). The second tube showed uniform intergranular attack to a depth of about 5 mit s within the crevice with IGA occasional deeper crack-like penetrations extending to 50 percent of the wall. No IGA was detected above the tubesheet. \\ E3-3
t Tube 3 exhibited qualitatively similar features to tube 2 with, again, about 5 miles uniform IGA within the crevice, with fewer penetrations to a depth of 16 mils, or about 33% of the 50-mil wall thickness. Again, no IGA was detected above and the longitudinal metallographic section that the tubesheet, extended 3/4" below the tubesheet showed no IGA along its entire 1-1/2" length. Viewgraph 6 is a longitudinal metallographic cross section of a section of tube 15-45 taken 3" below the break. This is a macrophotograph of a micro. The OD outer surface is at the top and at the bottom (partially cut off by the printing process) with the tube axis running left-to-right. The ID . surfaces are across the wall from the OD surfaces. Note the macroscopically visible penetrations which were torn open from the tube pulling. Note also that macroscopically these extend only about 1/3 of the tube wall and that, macroscopically, the inner approximately 2/3 of the tube wall is unaffected. Viewgraph 9 depicts the transverse metallographic cross section just above the top of the tubesheet and adjac,ent to the hydraulic burst sample on the second tube. This location is about 2-1/2" above the secondary face of the tubesheet. In the upper photomicrograph, the full tube wall is seen with the OD at the top and the ID at the bottom. High magnification examination of the OD region, shown in a representative photomicrograph in the lower picture, reveals no IGA. 1397 238 E3-4
Specimens were reraved from tubes 15-45 and 22-37 for mechanical tests. Tensile tests lead plug tests and burst tests were performed. The results indicated that the properties of the base core material which has not seen general intergranular attack is similar to virgin material and that the burst strength of the tubes provides significant margin to resist tube burst during postulated accident conditions. The tensile specimen size and shape was first described (Viewgraph 131 and the results from the tensile testing described. The results must be interpreted with an understanding of the condition of the tubes prior to tensile testing. The specimens from tube 15-45 were taken fror. a section of the tube which experienced only small strains during the pulling operation and tube 22-37 specimens were from an area of the tube which saw significant strain induced during the pulling operation on the order of 10 percent. The differences between these two specimens indicate that tube 22-37 specimens saw significant strain hardening which explains the differences in tensile test results, The test specimens Tl to T5 on Viewgraph 14 demonstrate an equivalent engineering strain, including the effect of previous strain hardening, of approximately 30 percent, This magnitude of strain capability is large. The apparent difference between the total strain of the T1 to T5 specimens and the virgin specimen can be explained by understanding that the engineering strain is an average strain over the gage length. The irregularity of the thickness of specimen would indicate that the average strain over the gage length would be less than the virgin material strain \\ E3-5
because of highly localized strain occurring in the attacked specimens. On the basis of the specimen tests and conditions, it is concluded that the remaining core material properties is similar to virgin material properties. Lead plug tests were run on specimens from tube 15-45. The primary result of use from the lead plug tests is the diametral expansion obtained prior to failure. This data (Viewgraph 15) demonstrates that the tube has sufficient ductility to expand' into contact with the tubesheet within the crevice. Burst tests were performed and are the most important test of those performed. The test results, shown in Viewgraph 16, demonstrate that: 1. Substantial margin to prevent burst exists for the tube in the in'ergranularly attacked region (maximum pressure applied to the tube during a secondary side pipe break will be approximately 2000 psia) ; and 2. The dif ference in burst strength between the specimens from deep in the crevice and that which spans the tubesheet indicates essentially no degradation in burst strength in the region of the tubesheet from a virgin tube burst strenath. This coincides with the result of the metallurgical examination which concluded that there was no intergranular attack above this tubesheet. }3h7 E3-6
The next portion of the presentation (Viewgraphs 17 through 20) reviewed the evaluation of various conditions performed for the tubes. Considered were a double ended tube failure during a seccadary side pipe break, tube rupture during normal operation and during a secondary side pipe break, and collapse during a LOCA. Tabulated were the required thicknesses of remaining wall in the tube for intergranular attack both inside and outside the tubeaheet. These conditions outside the tubesheet were considered for thoroughness and are not indicated as being an existing condition. The tube examination and test specifically indicate that intergranular attack does not exist above the tubesheet. The results of these evaluations indicate that
- 1) outside the tubesheet, 40 percent of the wall is required to prevent occurrence of the stated conditions *, and 2) inside the tubesheet, the equivalent wall thickness should be 10 pcreent of the wall and the ductility of the tube must allow expansion of the tube to the tubesheet wall.
The conditions of the tubes examined and the test results indicate that these requirements are met. The condition of cracking both above and below th'e tubesheet was also evaluated (Viewgraphs 21 and 22). For cracks outside the tubesheet, test results have shown that a tube will leak to a degree which will require plant shutdown prior to rupture of the tube. For cracks inside the tubesheet, either the crack will be deep enough within the tubesheet to prevent it from being pulled out of the tubesheet or the crack will be close enough to the tubesheet such that leak rates will require the plant to b'e shutdown.
- Assuming, conservatively, 6 percent tube ovality.
}39[ 2k) E3-7
The presentation concluded (Viewgraph 23) by summarizing the mechanical test results as indicating that the core of the tube has properties similar to a virgin material and that the burst strength tests showed the limitation of the corrosion to below the tubesheet and the burst strength of the tube spanning the tubesheet as similar to virgin material. e 1397 242 e
== E3-8
VIEWGRAPH 1 POINT BEACH L S/G A TUBE SAMPLES: W R&D CENTER INVESTIGATION. e LAB ECT e RADIOGRAPHY e METALL0 GRAPHY e MICR0 ANALYSES e SEM/EDAX e ELECTRON BEAM MICR0 PROBE e X-RAY DIFFRACTION e MECHANICAL PROPERTIES DETERMINATIONS e HYDRAULIC PRESSURIZATION e LOAD-DISPLACEMENT WITH LEAD PLUGS e ST.ESS-STRAIN TENSILE TESTS 1397 243 m# ma ewe e - e e-+
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.v / POINT BEACH 1, S/G A, TUBE A 15-45, HL WITHIN TUBE SHEET: CENTRAL BUNDLE REGION LONGITUDIiiALCROSSSECTION 3397 249
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VIEWGRAPH ll 6 POINT BEACH 1, S/G A, TUBE 22-37, HL FIRST SUPPORT PLATE: CENTRAL BUNDLE REGION 1. LABORATORY EDDY-CURRENT INSPECTION: / NO INDICATION 2. LABORATORY " SINGLE" WALL" (HIGH RESOLUTION) RADIOGRAPHY: / NO TUBE WALL DEGRADATION 0 4 1397 253
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ENCLOSURE 4 Accident Analysis Table 1 summarizes the presently licensed mode of operation as well as the expected mode of operation at reduced pressure and temperature. Should Unit 1 operate at only reduced pressure, the normal operating conditions would be the same except that the Plant would be operating at 2,000 psia. When Unit 1 is operated at reduced temperature, secondary pressure decreases, reducing the Unit's electrical output due to the maximum flow capability of the turbine with valves wide open. With a hot leg temperature of approximately 557*F, it is estimated that the unit output will'be 83% of full power. At the low temperature condition, the expected core inlet temperature will be 510*F. Table 2 describes the approved Point Beach LOCA analysis. Table 3 summarizc the effect on peak clad temperature for changes in the number of steam generator tubes plugged and a reduction in primary system pressure. LOCA results at various operating conditions are listed in Table 4. Four c,ases are presented. Case One is the ECCS analysis presently approved by the NRC with 10 percent of the steam generator tubes plugged. Case 2 represents the case recently filed, with 18 percent of the tubes plugged and at normal reactor coolant system pressure and temperature. Case 3 shows the sensitivity to the reduction in primary system pressure to 2,000 psia with 18 percent of the steam generator tubes plugged. Case 4 is provided for information to show the margin available when operating at the expected i397 266 E4-1
conditions of reduced pressure, temperature, and the resulting 83 percent power level. All of the peak clad temperatures given on this i'able include the addition of 60'F for upper plenum injection as can be seen in the results. All the possible operating conditions meet the requiremants of 10 CFR Part 50.46 of the Commission's Regulations. 1397 267 e D E4-2
TABLE 1 POINT BFAQ OWPATI'1G C000lTIGS NDPVAL OWPATION PQER LEVEL 100% PRIFARY SYSE1 PESSUE 2,250 PSIA ~ HOT EG EFEPATUE 598F COLD LEG EFEPATUE 542 F LOOP TEPEPATUE DIFFEENCE 56F AVEPAGE TBfERATUPE 570 F SECOEARY PESSURE _800 PSIA LO4 PPESSURE AfD TB4EPATUE OPERATION PQER LEVEL 83% PRIFARY SYSTEM PESSUE 2,000 PSIA HOT LEG TDFEPATUE 557,3 F COLD LEG TBPEPATURE 510,0F LOOP EFEPATURE DIFEREiCE 47,3 F AVD.4GE TBPEPATUE 533.6 F SECORARY PESSUE ' 600 PSIA N e 1397 268 4
s TABLE 2 . ^. CURREllTLY APPROVED POIllT BEACH LOCA Af!ALYSES }' c. 9,. +.- -e
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4 .,z. - ~ s I) PERF0PJ1ED WITH THE C'JP.REl:TLY APPROVED WESTIllGHOUSE EVALUATI0fl MODEL (FEBRUARY 1.978 l:0 DEL) i...,. c.,.... II) Af!ALYSES ACCOUNTED FOR 10 PERCENT TUBE PLUGGING RESULTS: (1) PCT = 2067 F (2) PEAKING FACTOR = 2.32 U U (3) fMRGIfi TO 2200 F IS 133 F O 1397 269 e b s ~'
TABLE 3 RECENT CHANGES AT POINT BEACH WHICH IMPACT LOCA ANALYSES I) INCREASED TUBE PLUGGING A) INCREASED FROM 10% TO 18% B) SENSITIVITY OF APPROXIMATELY 6*F/l% T.P. C) APCT = +48*F II) REDUCED PRIMARY PRESSURE A) REDUCED FROM 2280 TO 2000 PSIA B) SENSITIVITY OF APPROXIMATELY 2.85*F/100 PSIA C) APCT = 8*F III) REDUCED PRIMARY PRESSURE + TEMPERATURE A) REDUCED COLD LEG TEMPERATURE FROM 544 *F TO 510*F B) REDUCED POWER BY 17% C. SENSITIVITY: REDUCED PCT BY 290?P 1397 270
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TABLE 4 LOCA RESULTS AT VARIOUS OPERATING CONDITIONS FOR POINT BEACH PARAMETER CASE 1 CASE 2 CASE 3 CASE 4 POWER 100% 100% 100% 83% % TUBE PLUGGING 10 18 18 18 RCS PRESSURE 2280 2280 2000 2000 TCOLD 540 544 544 510 PSEC 771 799 799 580 FQ 2.32 2.32 2.32 2.32 PCT 2067 2113 2121 1830 ELEVATION 7.5 7.5 7.5 7.5 e e O G S e 6* e a weg e, a M mee
e ENCLOSURE 5 Actions to Minimize Degradation and To Assure Safety A crevice-flushing technique has been developed to attempt to remove soluble materials from tubesheet crevices and thereby to aid in minimizing or arresting further degradation of tubes in the crevices. This procedure, viewgraph 1, involves the following steps: 1. Fill steam generators to one to two feet with demineralized water or condensato. 2. Heat up to 250*F with reactor coolant pumps and with main steam stop valves closed. 3. Hold for one hour to dissolve material in crevices. 4. Subcool water in the steam generators by adding demineralized water or condensate. 5. Depressurize with the atmospheric steam dump valves. This should cause the solution in the crevices to flash and be forced out by the flashed steam. 6. Cool to about 200 F by cooling the primary system. This will collapse the steam in the crevices which, in turn, refills the crevices with water. 7. Drain the steam generators. Viewgraph 2 provides the preliminary results of the use of this procedure for Unit 1 steam generators. As shown in the viewgraph, 14 cycles were performed and several pounds of sodium and phosphate were removed from each of the steam generators. Since there are two possible sources of soluble sodium and phosphate in the steam generators (crevices and residual sludge) attempts were made to define.the removal of material from the crevices by sampling prior to the depressurization step and E5-1
and performing a materials balance. These calculations indicate approximately 33 and 38 percent of the total materials removed were from the crevices in steam generators A and B, respectively. Further evaluations of these data will be performed. 1397 273 i 9 E5-2
POINT BEACH UNIT 1 CREVICE-FLUSHING PROCEDURE 1. Fill steam generator to 1 to 2 feet. 2. Heat up to 250*F. 3. Hold for about one hour. 4. Subcool water on tubesheet. 5. Depressurize with atmospheric steam dumps. Crevice solution flahses. 6. Cool primary system to 200'F crevice steam collapses. 7. Drain and refill. \\29I e 8 e ES-3
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s Hydrostatic pressure tests were performed after completing tube inspections and plugging. An 800 psi secondary to primary pressure test was successfully conducted in November 1979 to verify zero tube leakage and the capability of the unit to withstand the maximum LOCA. On November 20, 1979, a 2000 psi primary to secondary differential pressure test was successfully applied to Unit 1 to demonstrate its capability to withstand without tube failure a main steam line or feed line break. On return to service, it is planned to conduct a primary to secondary differential pressure test in approximately 30 days and to repair any leakage detected. If no leakage is found, this primary to secondary differential pressure test will Fa repeated in 60-90 days. A Technical Specification eddy current examination of both Unit 1 steam generator tubes will be performed not later than one year from return of the unit to service, unless required sooner by tube leakage or plugging experience. A 100% eddy current examination was conducted in October-November 1979. On return to service, monitoring of plant chemistry will be rigorously followed. Primary t'o secondary leakage will be closely monitored with the following limits requiring immediate plant shutdown: 1. Sudden primary-secondary leakage of 150 gpd (0.10 gpm) or greater. 2. Any primary-secondary leakage exceeding 250 gpd (0.17 gpm). 3. Increase in rate of primary-secondary leakage of greater than 15 gpd per day (0:01 gpm) if the total leak rate exceeds 150 gpd. Present Technical Specification limits are 500 gpd (0.35 gpm). }}97 276 E5-5
e The intergra. alar corro.sive attack ebserved in the tube sheet crevice area of steam generator tube sections removed from the Point Beach 1 plant is indicative of caustic stress corrosion cracking. Microanalysis of deposits on the affected sections also show the presence of alkaline forming species. Laboratory studies show that there is a significant temperature dependence of caustic stress corrosion cracking as illustrated in Figures A and B. These results are for pressurized capsules exposed to 10% and 50% NaOH at varying stresses at temperatures ranging from 650 to 550'F. As can be seen, reducing the temperature below 600 F significantly extends the time for SCC to occur. This temperature dependence is further illustrated in Figure C where temperature is plotted versus rate constant for both 10% and 50% NaOH.(1}The rate constant is developed from a linear crack growth rate law: dl kt = dt 1 = Crack length t = Time k = Rate constant dl = kt dt it" + Et o 2 k = 2(1 -l ) t g - AH/ kl RT = 2 g t If l <<<l g t Plot log K versus 1/T (1) This plot is based upon the time to develop a 3 mil crack in mill annealed Inconel 600 at 30 ksi in 10% and 50% NaOH solutions. }397 277 ES-6
e Tn ptCME O YA Cl'5 Y'!4 I rl Cr3 TS N' SV urs 'T~'EloF3* A7"f'd 20-t M A I-600 }! 9 ~ Q R u m n I ~ T f~ T s O s b 14 150 - ~b v ~ y g 3 } i 5 e N a "O k O N s X ~ .4 .y foa _~ r .h a E .Q f 4 go O 530 SSO 'O MO U op 1397 278 fmek eky }k_, al .m e T.5-8
.e Curve 630722-A NaOH 50% 105 550 F o o <0.5 mits e o 0.5 to 5 mils X 50 X 0.5 to 5 mils 50% NaOH 650 F b O s 1 \\ 1,, \\ o-U 30 g g; \\ >10 mils a E G 20' - 5 to 10 mils d h ;,.- .g X I' 10' 0.5 to 5 mits I I I 0 O 10G0 2000 30C0 4000 5000 6000 .7CCO Exposure Time, hrs Fig.10-Caustic cracking of mill annealed. alloy 600 at 550 F and 650 F (Lines depict zones of crack depth from 1G% NaOH at 600 F) ~ k[ek$kbkm 1397 279 ES-9
e Curve 660721-A NaOH 50L 105 575 F a o .5 to 5 mils 50 a\\ m 3 50 s 0' \\ >10 mils 2 a G g=- 5 to 10 mits 20 .\\ o 0.5 to 5 D1-10 mils O I I I i O 1000 2000 3000 4000 5000 6000 7000 Exposure Time, hrs. Fig. 9-Caustic cracking of mill anneated alloy 600 at 575 F (Lines dep,ict zones of crach depth from 10% NaCH at 600=F) D '9[ }$n AAA D*" l0 .M 1397 28'O E5-10
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L i t In addition to the foregoing actions, Licensees are investigating lon,'" term solutions, including sleeving, retubing in place, and replacement of the steam generator lower assemblies or the entire steam generator units. On the basis of these data and on the basis of the Point Beach Unit 1 experience wherein no crevice corrosion failures have occurred on the cold leg side of the steam generators, it is planned to return Unit.1 to service at reduced operating temperatures of 575*F T and 0*F T H C* e t e e ES-12}}