ML19344D243
| ML19344D243 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 03/06/1980 |
| From: | Hunstad A NORTHERN STATES POWER CO. |
| To: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| Shared Package | |
| ML19344D241 | List: |
| References | |
| LER-80-003-01X, LER-80-3-1X, TAC-12657, NUDOCS 8003110581 | |
| Download: ML19344D243 (50) | |
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. 3. . UPDATE REPORT LICENSEE EVENT REPORT PREVIOUS REPORT DATE 012380 CONTROL BLOCK: l 1
l l l l l
.lh (PLEASE PRINT OR TYPE ALL REQUIRED INFORMATION) l 1b8l@
l 10 I8i 9l 1! N 7 l P CODE LICENSEE l I l N l 2 l@150 l 0ilCENSE 14 l - l NUMBER 0 l 0 l 0 l 0 l 0l 25 -l260 l LICENSE 0 l@lTYPE 4 JOl1 l 517 CA1 l 1 l@l CON'T 10lll 7 8 S Ur C @l0 l 5 l0 l0 l0 l 3l 0l 6@l 0l 1lEVENT 60 61 OOCKET NUMBER 68 69 0l DATE 9l 8l 0@l 0l 3l 0l 6! 8l 0l@ d4 7b REPOR1 DATE 80 EVENT DESCRIPTION AND PROBABLE CONSEQUENCES h ITTTI I During eddy current testing of tubes in Unit 2 steam generators, several l l0 l3; l indications Of tube' degradation were seen. See attached details. l 0 4 l 1 0 s I l 101611 I 10171 I l I O is i l I
' CO I:'E ##$E C0 SieC$DE COMPONENT CODE Sue OE SU E O 9 lC lB l@ ]@ ]@ l Hl Tl El Xl Cl Hl@ ]@ g @
7 8 9 10 11 12 13 18 19 20 y SEQUENTIAL OCCURRENCE REPORT REVISION LER EVENT YE AR REPORT NO. CODE TYPE NO.
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g l--J 1010131 Lc.] 10111 lx I L-J LtJ l218lol 22 23 24 26 27 28 29 30 31 32 K N AC N O LANT MET HOURS S8 IT FOR 8. SUPPLIE MANUFACTURER W 33
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35 M l .0 l 1 l 4 l 4 l 37 40 W@ 41 [Y_j@ 42 W@ 43 lW l 1l 2 l 0l@ 44 41 CAUSE DESCRIPTION AND CORRECTIVE ACTIONS h l'T1Tl l Several tubes were plunned and one tube was removed for further examination. See i 1 i l attached details. I , i 2 l 1 l l l l 3_j I I 1 4 l 1 7 8 9 80 ST % POWER OTHER STATUS DtS O RY DISCOVERY DESCRIPTION 1 5 y @ l0l0l0l@l N/A l W@l Eddy current testing l ACTIVITY CO TENT AMOUNT OF ACTIVITY LOCATION OF RELE ASE 1 6 RELEASE @D OF RELEASEQl NA l l NA l i 7 8 9 10 11 44 45 80 i PERSONNEL EXPOSURES NUMBER TYPE DESCRIPTION i 7 l 0 l 0 l 0 l@l Z l@] NA l
' ' ' ,ERSON~E'L ' IN,unS "
NuueER DESCRietiONh i s NA l 7 8 9 l 0 l 0 l 011l@l12 80 LOSS OF OR DAMAGE TO FACILITY TYPE DESCRIPTION ! t 9 y@l NA 80 3110 l 7 8 9 10 80 PU8LICITY NRC USE ONL Y
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NAME OF PREPARER
. . unstad PHONE:
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Attachment to P-RO-80-3 Event Description
~
Eddy current examinations of tubing in both Prairie Island Unit 2 steam gener-- ators (S.G. No. 21 and No. 22) were performed (January 7-18, 1980), during the
.recent refueling outage. fin addition to complying with Technical Specification-requirements, the examination plan was focused on the peripheral tubes in the inlet side of both steam generators. These examinations of the peripheral tubes were planned to determine if there were-any signs of tube damage due to foreign cbjects.
- Westinghouse, along with technical support from Zetec Corporation, was contracted to perform and evaluate the data from the eddy current examinations. These examinations were performed using West fnghouse's new multi-frequency eddy current testing system. .This' system provided iacreased analytical capability for deter-mining' tube integrity. The four frequencies and their modes that were used for each examination were 400 KHz,100 KHz and 10 KHz in the differential mode and ;
-100 KHz in the absolute mode.
In addition, Westinghouse was contracted to perform a visual examination, using , mirrors and fiber optics, of both steam generators to detect the presence of i
' foreign objects.
During the completion of the eddy current inspection for the inlet, side of S.G. No. 21, one tube (row 1 column 1) was detected as having a 66% OD indication . l approximately 17' inches above the tube sheet. Due to the location of this tube ' !. and the indication, and with no other indications detected, foreign object damage was suspected. (This tube damage was later confirmed as being caused a' by the improper installation of 'the tube ldne blocking device which is a plate assembly used to redirect flow across the tube sheet. See Figure-5.) Thus, j the examination plan for the outlet side of S.G. No. 21 was increased to in-clude the entire periphery of the tube bundle. The results of the tube inspection fo- the outlet side of S.G. No. 21 revealed signs of tube deterioration in six 'of the ~ peripheral tubes. These indications l were -located at either the first or second tube support. The inspection plan of the outlet side was expanded until it was sufficiently demonstrated that this tube deterioration was primarily confined to the tubes at the periphery of the tube bundle at the first and second tube supports.
- _ A simila'r inspection was performed on S.G. No. 22 and resulted in similar findings. Figures-1, 2, 3 and 4 identify the tubes that were inspected'and those tubes that were plugged for the inlet.and outlet side of both steam gen-erators. Table I identifies the percentage of tubes that were inspected and
- Table II.provides a tabulation of the number of deteriorated tubes for each l -steam generator.
I
a+. Attachment to P-RO-80-3 (con't) Cause Description Corrosion; see Appendix A for a preliminary report on examination of the removed tube. Corrective Actions
- a. . Tube Plugging-The plugging criterion of the Technical SpecificaEion is 50% of tube wall thinning. ' Additional conservatism was.used and all tubes that had areas
- of wall thinnin'g greater than 43% were plugged. In addition, as a preven-tive measure, the tubes that are directly-in line with the tube lane block-ting' devices, which are the row 1 column 1 and the row 1 column 94 tubes, were' plugged in both steam generators. (This measure was taken even though improvements in design were made to assure' proper location and locking of these' blocking devices.) Table III identifies all the tubes that were
~ plugged during this outage.
Westinghouse ~was also contracted to pull one of the- degraded tubes and per-form'the necessary analysis to determine the mechanism for tube. wall deter-ioration.' The results of this analytical work substantiated the eddy current results. 1 b. Chemistry Surveillance A program of investigation,into the secondary chemistry of the unit was started. Sludge lance samples from the Jan. - Feb. '80 outage were sent to NWT, Inc. for analysis.. These samples were from both 21 and 22 steam generators. The week of February. 3,1980, a Westinghouse chemistry support group was called in'to analyze steam generator water during the unit startup. Analyses were run at discrete points and additional samples gathered for further analysis at Pittsburgh.. At the same time NSP chemistry personnel ran heatup_ analyses and drew concurrent grab samples for shipment to NWT, Inc. Westinghouse left the site on 2/8/80 with the samples. NSP continued to sample the subsequent _cooldown and heatup on 2/9 and 2/10 with?onsite-analyses and grab samples to be air freighted to.NWT, Inc. on 2/11. Then during the power escalation' dual samples were drawn at- discrete - powerilevels for both Westinghouse and NWT, Inc. and these were air shipped - on'2/21.. These samples ~ will all be subjected to ion chromatogre.phy for anion and cation ~ identification and quantification. Plant personnel will. duplicate the samples drawn on Unit 2 with samples from - the Unit 1 startup during the week of 2/25. These samples will be'sent to both NWT, Inc. and Westinghouse to be analyzed and compared to the Unit 2 data in an' attempt to identify any inconsistencies.. NSP is in-the. process d 6-Artschment to P-RO-80-3 (con't)
- b. Chemistry Surveillance (con't) of-purchasing an ion chromatography unit-that will allow analysis to be done for low level anions and cations on the site. A review of chemistry logs from Unit 2 for the past five years revealed no trends that would warrant any present changes in chemical operating procedures and practices.
NSP will continue to work with Westinghouse and NWT, Inc., an EPRI-funded consultant on steam generator chemistry, to identify the species of concern.
- c. Condensate Polisher Operation The condensate polishing system was put into service for the first time during December 1977. Resin bleed-through was suspected with the earliest use of the system because of a slight increase in ' steam generator cation conductivity during a relatively short time period each time a polisher was put into service. Because of the bleed-through problem it was decided to use the system sparingly until the problem could be corrected. Conse-quently, the system was operated during startup to eliminate the heavy sediment load from getting to the steam generators and for testing purposes to check out changes in the polisher design. It was also used to test dif ferent types of powdered resin performance. Sone of the individual polisher runs weJe quite long while other polisher runs were of very short duration. A total of 32 precoats were applied to Unit #2 polishers and 25 precoats to Unit #1 polishers.
It was determined that the major problems contributing to resin bleed-through were inadequate pre-coat which would allow bleed-through via the unprecoated septum area,-reclaim water containing precoat material which is used for back flushing the polisher during the initia{ filter change operation, and resin collection within low velocity areas in the septums during preconting which moves into the steam generator upon initiation of Zull flow operation. Also, the use of different brand name resin and different quality resin needed to be investigated to determine which resulted in the lowest bleed-through and yet maintain the ion exchange capacity needed. The inadequate precoat problem was solved with the assistance of the manu-facturer. A small scale vessel was built in April of 1978 and by August i 1978 a new baffle system was demonstrated acceptable. The first distri- ) bution baffle was installed in 21 polisher November 1978. Additioral prob- ' lems were encountered requiring redesign and testinr,. This was accomplished and a new design installed in 21 polisher December 1978. A long testing run was initiated using 21 polisher with very good precoating results. However, each new precoat produced a cation conductivity rise in the steam generator when initially placed on the line. The 22 polisher and 23 polisher were modified in August of 79. The 12 and 13 polisher were modified in October of 1979. Number 11 polisher was modified in January of 1980. A series of bleed-through tests were completed on 21 and 22 polisher during August and ' September of 1979. Results indicated several hundred ppb resin fines within the first 10 minutes, then 1 or 2 ppb (lower limit of detection) after 30 minutes on-line. r -
. o Attachment'to P-RO-80-3 (con't)
- c. Condensate lolisher Operation (con't)
Reclaim water used to flush. powdered resin material from the polisher was found to contain resin _ fines. This was due to the inability of the clam-shell filter system to adequately clean the water for reuse. The reclaim water system needed a modit'ication to correct the problem. Because the system was not functioning properly all water used for flushing and pre-coating was taken from t.he condensate storage tanks. The problem of resin deposits.in the septums results because of the design. During precoating the lower flow velocity allows resin particles to settle within the septum which is on the discharge surface. Upon initiation of full flow the higher velocity washes this resin into the steam generators. Possible solutions such as higher velocity-precoating flow tad the redesign of the septum are being considered. Seven different types of powdsred resins have been testei. on-line. The best results (smallest bleed-thrc .gh) appears to be .with a spec.' i.1 pre-washed resin. At least one t5st tith this resin resulted in little or no noticeable increase in steam generator cation conductivity upon initiation of full flow. This resin is selected for use in the event the polishers would be needed for operation. Our intent la to use the polisher only when necessary until the problems are resolved. The polishers will be used in the event of a very small condenser leak because with the present modificttions and changes to our operation the' benefit of polisher operation.may outweigh the disadvantage of a small amount of resin bleed-through. Operation of the polisher during plant startup and op* ation for special testing will be coc sidered on a case-by-case basis until the steam generator
. inning problem is resolved.
- d. Future Examinations Future steam generator examinations will be done with a plan similar to what was done on Unit 2 in the 1980 refueling. All tubes with previous indications will be examined, except of course those that were plugged.
- e. Summary of NSP-NRC Meeting Appendix B contains a summary of material presented at the February 12 meeting.
p TABLE I Amount and Extent of Eddy Current Examination for Prairie Island Unit 2 Steam Generator Tubes - January 1980 STEAM GENER/. TOR EXAMINATION TUBE NUMBER & TUBE SIDE AMOUNT EXTENT PERCENTAGE 21 Inlet 119 Past 7th Support 3.5% 315 Around U-Bend 9.0% 63 Tight Radius U-Bend 1.9% 21 Outlet 429 Past 3rd Support 12.7% 266 Past 7th Support 7.9% 27 Tight Radius U-Bend 1.0% 22 Inlet- 80 Past 1st Support 2.0% 105 Past 7th Support 3.0% 318 Around U-Bend , 9.0% 89 Tight Radius U-Bend 2.6% 4 22 Outlet 3 Past 1st Support 'O.0% Past 3rd Support 928 27.0% 212 Past 7th Support 6.0% i
, c-
- TABLE II S.C. No. 21 NUMBER OF TUBES
% OF WALL TilINNING INLET OUTLET
>50% 1 1
>20%, <50% 0 10
<20% 0 29 S.G. No. 22
>50% 0 4
>20%, <50% 0 39
<20% 0 53
1.sBLE III Steam Generator Tubes-Plugged Dw.l.'g Prairie Island Unit 2 January 1980-Refueling Outage. STEAM GENERATOR- TUBE NUMBER' PERCENTAGE OF _ NUMBER- ROW COL. WALL THINNING REMARKS S.G. No. 21 1 1- 66% 1 94 --- Preventive 35 78 72% i S.G. No. 22' 1 1 --- Preventive 94 1 --- Preventive 34 79 43% Pulled 34 18 48% 42 , 34 54% 43 37- 47% 44 37 47%
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+MANWAY 5 din.Og$; R.22;;g;-
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APPENDIX A _ EXAMINATION OF REMOVED TUBE Recent eddy current examinations of Prairie Island Unit 2 steam generator tubes revealed indications in a number of tubes. The indications ranged from less than 20% of wall thickness to one at approximately 75%, with the majority in the less than 20% category. The indications were interpreted as some form of OD wall loss,. located in the center of the. support plate intersection. To determine the actual cause of the indication, a representative tube, R34C79 of S/G 22 was removed on Jan. 27, 1980 and sent to the Westinghouse Forest Hills site for detailed examination. The purpose of this document is to briefly report the initial findings of this examination and to , discuss the preliminary conclusions. , NON-DESTRUCTIVE EXAMINATION OF TUBE R34C79 All tube section containing support plate intersection were photographed at 4 rotations (O*, 90', 180*, 270*). Only the first and second intersections exhibited wall loss, the next four inter-sections had slight discolorations and possibly local deposits and the seventh exhibited shallow circumferential strihtions. All support zones were radiographed using the double wall tecnnique. 4 The first support zone exhibited so.010" maximum wall reduction while the second support zone had approximately 0.020" - 0.025" wall loss. The 3rd, 4th, 5th, 6th and 7th showed no detectable wall loss. Standards shot with each exposure revealed that 1 mil of wall reduction could be detected. +
2-2 Eddy current testing using multi-frequencies gave results similar to those obtained by radiography. The first support showed about a 0.010" wall reduction while the second support revealed 0.025" wall reduction. The remaining support zones gave no wall loss indications, f. [ Detailed profilometry of the 0D at the affected first and second inter-sections generally supported the other findings; the-maixmum OD reduction agreed with the X-ray and E/C estimates of wall loss. Destructive Examination (performed at Westinghouse R & D Center) Tube-support zcnes 1 and 2 were removed and split longitudinally so that wall measu.ements could be made using a pointed micrometer. These measurements are shown in. attached Figure 1. The deepest penetration found in support zone #1 is about 0.007" of wall loss and about 0.020" lost from support zone #2. The nominal wall thickness is 0.050". Examination of the tube surface was accomplished using the Scanning Electron Microscope (S.E.M.) and deposits analyzed on the Energy Dispersive - X-Ray Analyzer (E.D. A.X. ). These results show the surface deposits to be the typical boiler water specie. Some spot analyses within the dis-turbed zone show high sulfur peaks. Other microanalytical tools will be used to further explore these deposits. Several metallographic samples have been prepared from the 1st and 2nd support plate areas. Representative photographs are seen in Figures 2 l 'and 3. Figure 2 is a half ring sample taken near the area of deepest attack on support zone #2. Figure 3 shows representative areas in the i etched condition. No.intergranular attack and no cold working of the ( surface -is seen in the damaged area. Knoop microhardness traverses were done on samples from both the first
~and second support zones. Figures 2 and 4 give the results 'for support .
.#2.. It can be seen that hardnesses near the surface of the damaged zone (Figure 2) are. less than that outside the damaged zone (Figure 4).
The higher readings in the unaffected region are normal and are due
- to surface work hardening. imparted by. the final belt polishing operation of the tubing during manufacture. Figure: 5 gives similar results ob-tained.on support zone #1.
! *p' , 3-Conversion of a Vickers 100g hardness reading to Rockwell B shows this tubipg to be about 89.2 RB wh'ich is no'rmal for a mill annealed tubing
~ product.
The lack of evidence of surface cold work, adduced both from the micro-hardness traverses and the metallography, essentially eliminate wear and vibration as the primary cause of the degradation. The most likely cause is-corrosion, caused by the local-concentr'ation of an as yet undetermined contaminant in the crevices formed between the tubes and the
. tube support plate holes.
Additional metallography is underway at several other intersections and more detailed examinations are planned but it is unlikely that the initial conclusion will be affected. The major effort will be the micro-analyses of the affected surfaces to identify the contaminant: involved. Sulfur bearing compounds are suspect, because of the reported instances of resin carryover from the Powdex polisher and the EDAX indication of sulfur on the affected surface.
- conclusions of the Tube Examination Findings
l l The preliminary conclusions are as follows: l [ 'l
- 1. Since wear / vibration are apparently not involved, no mechanical revi..uis to the steam generators are suggested.
2'. There is no kncv.a safety issue. The eddy current in-service inspection plan, however, will have to be revised in regard to-Reg. Guide 1.83. 3.- The identification and source of the contaminants must be determined and appropriate operational procedures taken to (1) reduce the , . contaminant inventory and (2) to prevent further ingress. A brief. discussion of each of.the above items follow. e
Mechanical Revisions eThe effect of the original mechanical modifications (which were made
.on Prarie Island Unit 2 prior to start-up) on both tube wear and corrosion can be summarized as follows:
soecific Modifications
- 1. 'Downcomer Res.istance Plate Removal A. Fretting / Wear - The velocity at the bundle inlet is increased from about 5 to 9 ft/sec. This would increase the potential for fretting or wear between the tube and'the support.
B. Corrosion - The circulation ratio is increased from 2.4 to 5.2, thereby increasing the support plate pressure drop and the flow between the tube and the support, which is beneficial. Nevertheless, the periphery of the bundle likely has a lower velocity ' region, so that the local circulation flow may not have been increased significantly.
- 2. 80-20 Feedwater Flow' Split at the Feedring A. Fretting / Wear - Minimal effect because the flow split does -
not affect the velocity at the tube bundle inlet.
'B. Corrosion - The 80/20 flow split reduces the thermal siphoning of flow from the cold leg to the hot leg. Since more of the recirculating flow remains in the cold leg, this is expected ,
to produce a small increase in the circulation pattern _in the peripheral cold leg region. However, the reduction in mixing between the feed and recirculating flows in the cold leg causes the bulk cold leg concentration of dissolved chemicals to in-crease from .8 to .9 of the recirculation flow concentration.
' Consequently, the net effect is likely to be small.
b 3. Tube Lane Blockage and Blowdown Redirection A. Fretting / Wear - -The crossflow velocities at the bundle entrance are increased slightly. B. Corrosion - The increased velocities. should promote a small F
' increase in flow at the bundle periphery.
t i e,--- - a
l . ! It. [s concluded that higher velocities in the bundle do increase the potential for wear, but have either no effect or are slightly beneficial with regard to corrosion. Since the evidence does not support a wear
. phenomenon, no change in the modifications made to the steam generators are recommended. ,
l Contaminant Identification and Control It is recommended that a test program be immediately implemented, prior to Unit 2 power operation, to identify the chemical species in the secondary side bulk water and to sample subsequently during power ramp, power operation and shutdown so as to characterize chemical hideout I and return. l
~
I l l L l l l o e i I
Safety Issue , f The safety position for steam generator *ube degradation is that the tube will leak a detectable amount of primary fluid before the defect reaches a
, critical flaw size. This is known as the tube leak before break hypothesis. .
The issue with the tube degradation at prairie Island is whether this form of degradation follows the previous patterns. The examination of the Prairie Island tube indicates that a corrosive environment has affected the tubes. The examined tube had two areas where the corrosion was the most severe. These areas are at the first and second support plate locations, with the.:ccond support plate area having the most pronounced corrosion. The second support plate area has a truncated penetration. It is postulated that if the corrosion were to continue, the more affected area would precede the lesser affected surrounding area and form a pin hole type leak in the tube wall. The first support area does not appear to have a truncated penetration. This area appears to be in the early stages and may progress to a truncated position.
.The characteristic of a ' tube that has a hole type defect is that as the hole and the leak rate increase, the tube's burst strength also decreases. However, the leak rate increases at a faster rate than the tube's burst pressure de-creases. This form of steam generator tube degradation will cause a tube to leak before break and does not pose a safety issue for continued operation.
The other safety objective is to prevent any ste'am generator tube from degrading to the point where a leak will occur. The time required for a leak to occur is a function of the corrosion rate. The investigatiori of the degraded tube leads to a hypothesis that the corrosion may be a result of the intrusion of resins from the condensate polishers which have been used sporadically since December, .1977. It is postulated that this fonn of corrosion took place during the two years of condensate polisher availability. This information allows a rate of-corrosion to be estimated. Each area of degradation establishes its
. individual rate of corrosion dependent upon the unique steam generator con-I' ditions in that area. The remaining affected tubes in service'have ECT indications that are less than 45% of tube wall thickness. If we assume a maximum corrosion of 45% over 24 months, than the anticipated maximum corrosion I
l
l i e rate is approximately 1.8% per month. The minimum tube wall required for faulted plant conditions is 0.013 inches from a nominal thickness of 0.050 inches. Thus a minimum remaining wall of 26% thickness is needed to sustain plant faulted conditions. This difference between the minimum required tube wall thickness and the remaining tube wall thickness in a tube with a 45% ECT indication is the amount of tube wall which may be lost via the corrosion mechanism. This amount of tube wall is 0.0145" or 29% of the tube wall. Therefore, the postulated corrosion rate of approximately 1.8% per month should permit an estimated operating time of. approximately 15 months without viola' ting the plant faulted condition
. minimum tube wall. .
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APPENDIX B - matsrial prszentsd at NORTilERN STA1ES POWElt COMPANY - NRC HEETING FEBRUARY 12, 1980 Westingl.ouse Torest Hills lSite .,
,i lHTRODUCTION: NSP i
- l. Tube Ucar Caused by Blocking Device l
. and Corrective Action. ,
E. Watzl l 11 Cold-leg, Peripheral Tube Findings - i
- a. Review In-Plant inspection Findings D. D. Malinowski
- b. Tube Pull & Lab Examination R. G. Aspden
- c. Sunma ry A. W. Klein
- Cause ,
- Rate
- d. Safety Considerations C. W. Hirst
- c. ~ Future Actions NSP/ Westinghouse
- Chemistry Surveillance Inspection Plans
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prepared from the second support zonc. These numbers can be compared to those in Figurc 2 taken in the damaged area.
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. l L2 1
,,,i,.ir 2l0l5 r SAFETY EVALUATION l
e I.EAVAGE NID CRITICAL AREA l l
- Twe IIDEGRITY
- CORROSIONRATE e OPERAT!!1GlitTERVAL
- CONCLUS10N O g e
LEAKAGE A fi D CRITICAL AREA : e DEFir41Tloti 0F If.AK
- IbRML Siiutooa PRoctDuRES l 4
tb SAFEGUARDS ACTUATIOri Ib41rtAL LEAK PLol AREA
. 3/8 Irci DIN 4ETER Il0LE ,
. FLGl AREA = ,110 So, Irl.
i tb41ra. LEAK PLOl
. 125 GRi I
- PROFILE OF CORRODED AREAS Ort PRAIRIE ISLArm 2 R34 C79 TSP #2 AREA.060x.1875=.011So. Irs.
- TSP #1 AREA.24x.1875=.045So,III, i
e LEAK RATE VS, BURST PRESSURE e 5 4 l
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e e TUBE INTEGRITY I e
- TUBEWALLREQUIRED NoRfML .008 FAULIED .013 l 1
e
- TustBuRSTDATA CORROS!OrtPROFILES TuaEBuRSTTESTS O
e e
. 6 GE0liETitY OF -
LLIPTICAL WASTAGE S P E C l li E tt 4 I C3- I n p .- - .. - . x FAT i >
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9 e ' 4
BURST PRESSURES FOR TilREE il E'A T S OF 0.875 I ll . X 0.050 IN. SPECIMENS ilEAT B, llEATE, llEATF, DEFECTTYPE 50 Ksl YlELD @lKS1 YIELD 41KslYIELD ' - 9460 9180 Ul! DEFECTED 9260 9275 9665 9450 9 410 9500 9240
~
ELLIPTICALWASTAGE
~
55-fD% 5550 5635 5465 RC = .12" 5635 5280 .5700 . LENGE = 1 h" 85-90% 2950 e . Re = 6" 2970 . REF: NJREG/CR-0277, JULY 1978 4 . . O 9 l
12,531-40 I lt;,oco , A - uniform Thinning 12,000 - RANGE 0' so lo sE watt BURST PRESSURE FDU lHlHG 10,000 -
/ D
/
/
G /* b
' # 40 TO 45% WALL E O 8,000 - REMAlllING "d / O :/
p vs f, 21 TO 277 WLLL g p/ RIHA IN ihG . t 6,000 ZO , p# O l
~
E p', 10 TO 155 WALL /p
-REMAINI O -
11,000 ,_ _ _ . _ . . _ . _ __. ._'
- / /
p/ _/ I s 2,000 -
\
# TilROUGH Walt i EXPERlHEN~ALCURVEl I
I
. i I ! l l l i I I i o
~
0.0 0.2 0 . 11 0.6 0.8 1.0 1.2 ! . tl I.6 l'. 8 2.0 2.2 I
, __._ . . RECIPROCAL FLAW LENGTH ( T IN~I)
Figure 5. noom Temper.itore Bur:t Pressure of 7/8"'ubes>vith Machined Flats
. (Ref. IlCAP-8429) .
2 ex q mI - A o 1- a
CORROS10f1 RATE
- CORRODEllTSOURCE RESINlilTRUS10fl C0t1DEf1SATEPOLISHERS
* - TuBEEXPOSURETOCORR0DEllT POLISHERAVAILABILITY12/T/
24 lb4mS OPERAT10fl
. TusECORROS10tlRATE c .
INDIVIDUAL l.I) CATION CORROSION RATE ! LARGESTECTIr4DICATIONINSERVICEIS45%
- CALCULATED CORROSION RATE OF 1.8% / l'ltflTH 0
l e
O P E R~A T I il G l il T E R V A L
- REQUIREDlllulfM4IUBEWALL 13 lIILS = 26%
- LhRcLc ECT IrmCATION IN SERVICE 457. = 55% REfMINING WAU.
- CORROS10t1 RATE 1.8%PERl'10ffTH
- PERT 41SSIBLE OPERATif1G li1TERVAL FOR ll.INitU4 IUBE WALL REl%Illit1G WALL - REQUIRED WALL
=
16I'l0NTHSOFOPERATION CORROSIONRATE .
?
CONCLUSIONS
- ADEQUATE BURST PRESSURE IS Ihlt1TAlf1ED
- CORR 0Sloft RATE 1.8% PER lGITH e OPERATif1G IffTERVAL 16 Ih4THS 9
e l l l
?
Il
(> ga y .s 'Is- Il t' '~
~2/1 tlT.:>
StHtVI.Y Ol' WESTINGl!OUSE OPERATING PLAllTS COLD LEG STEAM GENERATOR EC DATA e Plants reporting TSP clevation tube wastage: HillAMA #2 1/75 5 tubes TAKAllAMA #1 12/75 8 tubes
. GINNA 2/79 (3/75) 2 tubes PRAIRit ISLAND #2 1/80 (f[ ,91' tube's ROBINSON #2 11/75 3 tubes e ' Tube pulls at Mihama #2 and Takahama #1 Indicated PO4 wastage e Findings at Robinson #2 and Ginna were following periods of P0 g usage i and during first examinations of. the Cold Leg areas where the endications existed. .
e PO4 wastage is the probable cause since no new - Indications have been found since that time e No other plants have reported Cold Leg wastage in the absence of PO4 history I l !~ l s I
.t. ., , . , ,
l* . (ggpf.es s e e a e n s--
, myn, PRAlltil: ISLAfID #2 STEAll CLitt itAIOR Itl5Pl.C110tl5
.l Af4UAltY , l')80 SG #21 SG #22
-e INLET e Tubes inspected e thru U-bend (720 mil probc) 345 345 e - thru U-bend (560 mil probc) 63 90 e thru #7 Support Plate 92 92 e thru'#1 Support Plate . 75 e Indications Rc' ported 1 0 l
e OUILET l e Tubes inspected - e thru U-bend (540 mil probc) 27 0 e thru:#3 Support Plate' 466 934
^
e thru #7 Support Plate 257 213 e Indications Reported e 3 20% Eddy Current Indications 30 37 i e < 20% Eddy Current Indications 30 54 l l t
+
~
. . . I.
SUMMARY
OF METALLURGICAL EXAMINATION TSP Obs. #1 #2 #4 #6 '#7 VALL REDUCTION LVDT. 9 mils 22 mils None Nonc X-ray Thinning Thinning Micrometer 10 mils 20 mils
. Metallography 7.5 mils 25 mils None Nonc OD suface at wall thinned location of TSP Nos. I and 2.
- l. No intergranular attack was present.
- 2. No evidence for increased cold work at surface; based on metallography and microhardness readings.
3 Arcas were of gross deposits, f requently contain , swirls, and have pits nearby.
- 4. Deposits in and near wall thinned area contain Na, P A1, Si, Ca, S,
- Cl, K, T1, Mg, Ni, Cr, Fe.
i I
_ CONCLUSIONS TR011 TUDE EXAMINATION
- 1. The primary cause of the wall loss at the first and second tube support plate indications is corrosion from an cs yet unidentified corrodent.
- 2. Wear and/or fretting is climinated as a significant causative agent.
3 Resin carryover from the Powdex polisher.is possibly one source of contamination. a f 4 4 i i i d _ _ , ,_ , _ - ,,n. - - , -, ,- - - - - e r- - -}}