ML20058J663

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Viewgraphs Entitled, Past Experience W/Pipe Wall Thinning in Nuclear Power Plants, Presented to US-USSR Jcccnrs Working Group 10 on 890605-09
ML20058J663
Person / Time
Issue date: 06/05/1989
From: Taboada A
NRC OFFICE OF NUCLEAR REGULATORY RESEARCH (RES)
To:
References
JCCCNRS-WG-10, WG-10(6), NUDOCS 9012020145
Download: ML20058J663 (52)
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l: j i PAST, EXPERIENCE WITH EROSION / CORROSION IN USA L l

  • Problem Of Pipe Thinning Due To i

l Erosion / Corrosion Was High-Lighted By A I Catastrophic Pipe Failure At The Surry Nuclear Plant In December 1986 l

  • However, Over The Past 15 Years, Numerous l

Nuclear Reactors Have Experienced High Rates Of l Wear in Parts Of Secondary Systems (Approx. 200 l Events) i

  • Erosion / Corrosion Occurred in Carbon Steel Components With Certain Combinations Of Geometry, Flow Rate, Temperature And Chemistry

1 l' PIPE FAILURE i AT SURRY POWER STATION i l e On December 9,1986 i 1 I i t

  1. Non-Nuclear Pipe Failed Catastrophically j

l' l l 9 Release Of High Pressure Steam

  • Reselted in injuries To Eight Workers, Four Of Which Proved Fatal l

l

[ .SURRY POWER STATION /- i, ]

  • Two Unit Plant i
  • Three-Loop PWR's, Each Rated At //d WMe j

i e Initial Operation - 1972 e 76,000 Hours Of Operation 1 I

  • Failure in Steel Suction Line To Main Feedwater l

Pump 1 Elbow Attached To A 24-inch Condensate Supply Header e Temperature 370 F, Pressure 370 PSIG l e Flow Rate 17 FPS i l

l i SURRY PIPE FAILURE e Complete Separation Of 18-Inch Pipe l e Double Ended Break l i Pipe Twisted And Rotated Causing Distortion And l Buckling Away From Break i j e Displaced The Broken Pipe End - 10 Feet j i i j

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i /I INFLUENCINGYARIABLES ON EROSION l CORROSION AT SURRY i l l e Elbow-Splitting Tee Configuration l 1 l

  • pH Levels Of System i:8.8 - 9.2?
  • Water Chemistry Control During Operating Years j

i I l

  • Material Composition I: Low Trace CR <0.02%

I i l 8 System Temperature I: In Peak Range) i e Bulk Fluid Velocity 17 Ft/Sec 18" Branch

i i

l e Low Oxvoen Content Of System 1 PPB l

19 TROJAN NUCLEAR PLANT e Extensive inspections Of Piping Conducted During 1987 Refueling f Outage-Follow On To Surry Pipe Failure f Found Evidence Of Pipe Wall Thinning At Numerous Locations l 8 I Some Of Thinned Locations Not Previously identified As Likely Sites l 8 For Erosion / Corrosion By industry Guidelines e For First Time Pipe Wall Thinning Reported - In Safety-Related Portion Of Feedwater Line l - In Straight Sections Of Pipe Away From Fittings l e Conditions Of Pipe l - Carbon Steel Material (A106 GR B) - Velocity Of Flow 22.6 Ft/Sec - Temperature 245 F - pH 8.G - 9.0 e Thickness Loss From 0.59 inch As Installed To 0.39 To 0.46 inch Which Is Less Than Allowable - Design Requirements - 051 inch e Piping Being Replaced e improved inspection Program Planned For Future

[ 3 ~ SURVEY TO DETERMINE EROSION / CORROSION EXPERIENCE A Survey Of 28 US Plants And 2 Foreign Plants Was Performed To Determine Experience With Erosion / Corrosion; The Ranges l Of Feedwater Velocities, Pressures, And Temperatures ~ Encountered; Water Chemistry Histories; And The Materials in The Feedwater And Steam Piping I Plants in Erosion / Corrosion Survey ) i Beaver Rancho Seco l l Calvert 1 Salem 1 l Calvert 2 San Onofre 1 l Crystal San Onofre 2&3 Ft. Calhoun Surry 1 j H.B. Robinson Surry 2 I j Indian Point 2 Trojan Indian Point 3 Turkey Point 3 Kewaunee Turkey Point 4 Oconee 1&2 Zion 1&2 Oconee 3 GKN-Palisades Vorhauve' i l l

l i i COMPONENTS WITH EROSION / l CORROSION REPORTED IN SURVEY l i i i i l i i Wet Steam MSR ~ Feedwater J Feedwater Other i Piping Chevrons Piping Tubes Ring Turbine Components { Yes/No 28/1 15/9 14/14 10/11 2/24 22/3 13/9 i % Yes 96.5 62.5 50 47.6 7.7 88 59.1 i t i i / l l

[ ( RESULTS OF SURVEY l t I l j i. t i f Total Affected t Components Elbows Tee's Diffusers Reducers Valves Orifices Other I Totals 5348/460* 2717/307 618753 182/21 268/4 789/3 52/2 69/72 l Averages / unit 297.1/28.8 159.8/19.2 36.4/3'.3 10.7/1.5 15.8/0.3 46.4/0.2 3.1/0.2 6.3/4.2 i i % Replaced 8 11.0 3.0 11.0 1.5 0.4 3.0 Total number of components / number of components with E-C. 1 l i

t 2 ACTIONS TO RESOLVE WALL THINNING PROBLEMS i 4 o NRC AND NUCLEAR INDUSTRY HAVE INITIATED i l INSPECTION PROGRAMS TO: j l t J EVALUATE EXTENT OF PROBLEM l SAFETY SIGNIFICANCE AND RISK ASPECTS DETERMINE THE STATE OF KNOWLEDGE ON EROSION / CORROSION l ESTABLISH PREDICTIVE CAPABILITY o INDUSTRY HAS DEVELOPED INSPECTION GUIDELINES I l t WHICH ARE BEING APPLIED TO U.S. NUCLEAR PLANTS ( I RESULTS TO DATE INDICATE THIS A GENERIC CONDITION, f o NC [ ISOLATED CASE i l o CHANGES 'ARE IN PROGRESS TO ASME SECTION XI j CODE RULES TO ADDRESS WALL THINNING PROBLEMS AT4A i

( BNL-NUREG-43765 (7) EROSION CORROSION AT NUCLEAR POWER STATIONS

  • Carl J. Czajkowski Department of Nuclear Energy Brookhaven National Laboratory Upton, NY 11973 Erosiu corrosion is usually defined as the acceleration or increase in the rate of corrosion caused by the relative movement between a corrosive fluid and the metal surface. In principle, it should be distinguished from the effect of fluid flow that accelerates general corrosion by increasing the rate of mass transport of reactive species (i.e., a cathodic reactant, such as oxygen) to the metal surface, or the rate of removal of corrosion products from the metal surface.

Erosion-corroWon should also be distinguished from forms of erosion such as cavitation and impingement damage. Impingement damage involves the impact of liquid droplets present in a gaseous fluid through forces generally perpen-dicular to the metal surface, whereas cavitation arises from the collapse of gas bubbles contained in a fast flowing liquid phase, also through perpendicular pulsive forces. Wear of last-stage turbine blades by water droplets and cavitation damage of pumps by steam bubbles are typical examples of each phenomenon. Together with erosion by solid particles, they are essentially mechanical forms of metal ieterioration, because the contribution of corrosion usually is thought to be almost negligible. In these three phenomena, direct damage of the metal occurs when the forces involved in the impact are higher than the material. strength. Carbon steels are extensively used in low pressure and high pressure turbine sections and fee. water heaters in both fossil fueled and nuclear power plants. These materials are also used in many ancillary components of the steam-water circuit, such as moisture separators, reheaters, pipes, pumps, etc. l. In these components high flow velocities under single phase (water) or two-phase j. (wet steam) conditions prevail. Damage associated with erosion corrosion under single phase conditions has been observed at inlet ends in high pressure feedwater heater tubes, feedwater l tube inlets in steam ~ generators of gas-cooled reactors, feedwater pumps, t.nd in the. catastrophic failure of a suction line to the main feedwater pump at the Surry Unit 2 nuclear power plant. Two phase erosion-corrosion is a more widespread problem and it has been frequently observed in steam extraction piping, cross over pipes from high pressure turbine to the moisture separator, and on the steam side of feedwater heat tubes, as well as in many other auxiliary components of the steam water cycle. i i L Uhis work was performed under the auspices of the U.S. Nuclear Regulatory Commission, Office of Nuclear Regulatory Research. 1 w-. y

I 1 Damage of such pwer plant components generally occurs at locations where there is severe fluid turbulence adjacent to the metal surface, either as a result of inherently high fluid velocities (e.g., >2 m/s) or due to the presence of features (bend, tee, orifice, etc.) generating high local turbulence levels. In many cases the metal surface is characterized by the occurrence of over-lapping " horseshoe" pits resulting in a scalloped appearance. Micro pitting of the metal surfaces also occurs, being related to an accelerated attack on the pearlite grains of the carbon steel. Many U.S. utilities implemented an erosion / corrosion monitoring program for two phase lines in 1982 after the 24-inch pipe rupture (extraction steam i line) at the Oconee Unit 2. Some expanded their program to include high-energy single phase piping after the failure of a heater drain discharge pipe at the Trojan Plant in 1985. The vast majority of U.S. utilities expanded their program to include large moderate energy single phase piping systems after the feedwater line break at Surry Unit 2 in 1986. Most licensees established an erosion / corrosion multi disciplinary task forces in early 1987 addressing the issue of pipe wall thinning. These task forces addressed the following issues: 1) develop a predictive method to select inspection locat 'ons based on pipe configurations, materials, velocities, and water chemistry; 2) inspect each unit using various NDE methods at points established by system modeling; 3) develop a baseline from the information gathered during inspections and use it for treading purpose; and i 4) expand the overall program to include the utility's fossil units. These task forces established action plans requiring pipe one inch and larger with system temperature greater than 100*C be inspected. In general, piping over eight inches in diameter were given priority. These pipes include Main Steam, Extraction Steam, Heater Drains, Condensate, Feedwater, and Reheat

systems, i

The locations for inspection were selected based on the NUMARC Guidelines or calculated flow rates, piping geometries and past experience. The EPRI "CHEC" computer code was used in most cases to determine the most susceptible areas of erosion / corrosion damage. However, most licensees indicated that the results were more consistent when the selections were made based on operating conditions and engineering judgement than they were based on the computer code alone. U.S. utilities implicitly or explicitly adopt an acceptance criteria for making repair / replacement decisions consistent with the NUMARC Guidelines for erosion / corrosion in single phase lines. 2

I ( In general, utilities have been replacing all piping that shows a significant amount of wall thinning. Most replacement piping has been made of the same carbon steel (ASTM A 106 Grade' B and ASTM A 234 WPB or the ASME SA equivalents. However, depending on availability, in some cases)b Cr-1 Mo steel (SA 335 Grade P22) or other low-alloy steels were also used for replacement piping. In some instances, the licensees may opt to weld overlay over a thinned area of piping so that it exceeds the minimum wall thickness requirements of the piping system. In cases where a pipe is repaired by weld overlay, the pipe wall %ickness is monitored closely to ensure the pipe integrity. Overlays only stay in place until the next outage at which time they are replaced with pipe of the same specification or a more resistant low-alloy steel. All replacement pipe welds are welded without backing rings to minimize erosion / corrosion effects. Even though most utilities are replacing piping with i similar material, the most common method of reducing the possibility of erosion / corrosion failures is by utilizing materials that are more resistant to the phenomenon. The addition of even small amounts (approximately 2%) of chromium to a steel has shown significant decreases in the rate of erosion / corrosion with stainless steels being almost immune to the phenomenon. After the Surry accident, Virginia power utilized ultrasonic examination to evaluate pipe thickness at their plants. Erosion / corrosion damage initiates on the inside surface and progresses outward in pipin cannot detect the phenomenon until leakage occurs. g, so visual examinations Most U.S. utilities use either ultrasonic examinations or radiographic techniques for pipe wall thickness measurements with the vast majority opting for ultrasonic inspections. Some utilities are using "through insulation" radiography techniques for detection of wall-thinning in small bore piping. If wall thinning is identified by radiography, insulation is removed and actual depth of wall thinning determined by ultrasonic (manual) measurement, in actual practice, utilities indicated that piping eight inches in diameter and less has been replaced rather than measuring the actual thickness if erosion / corrosion thinning is detected. The ultrasonic examinations reproducibility is assured through the use of a layout grid pattern (or the pipe), using 3 6 inch grid spacing. Two pieces from the Surry 2 failure investigation were subjected to examination (at BNL) ultrasonically ("D" meter-long tudinal wave and 45' shear wave). These specimens were cut from the weld joint between the fabricated tee joint and the header from Surry Unit 2. Each specimen had significant erosion damage on the inside surface of the pipe adjacent to the weld. Both of these specimens had a grid pattern stencilled on the outside surface of the pipe and were subjected to ultrasonic thickness measurements in addition to physical (caliper) measurements. This examination emphasized the importance of the grid spacing size when making field measurements. Ir, general, the 10 plant survey (conducted in 1988) of erosion / corrosion program implementation at nuclear units showed that programs were established l which used qualified inspectors and provided an effective method for mitigating l future erosion / corrosion incidents. 3

..dT o ~ wc-o cc) ~ REFRESHER ON DEVELOPMENT OF GEZIP i l e ZINC CORREIATION OBSERVED IN PLANTS l l i e HYPOTHESIS DEVELOPED l i l e IAB TESTS VERIFIED HYPOTHESIS l e Co-60 BUILDUP TESTS PROVIDED FINAL VERIFICATION

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Q; LABORATORY VERIFICATION OF
7,INC BENEFITS 1

i 0.5 1 1 304 Stoic less Steel l q 1 l co ._o 0.4 - E-1 I t. I ~E' l _5 0.3 f .o .g E' if . o.2 - U '52 i .O-0.1 - j. I 0.0 ; i i i i l l 1 l l O 20 40 60 80 100 120 Zine Concentration in Water (ppb) l N526 ~ i 3 y e- ,g~, m ,,m. y,, -.u,, y- ,g-._ .n p.- y a ,g.--..

/ m. .o. n + + n. EGEZIP SPECIFICATION 4 e CONDITIONING PERIOD

  • First 2000 hrs Of Zine Injection
  • Target Concentration

- 10 ppb Soluble Zine In ExW e MAINTENANCE PERIOD -Balance Of Plant Operation

  • Target C,ancentration

- -5 ppb Soluble Zine In RxW Zine >15 ppt No More Than 10% Of Time e FEEDWATER' IRON

  • Identified Goal =< 2 ppb NO3G-

LABORATORY VERIFICATION OF ZINC BENEFITS 2.0 - i 316 Stainless Steel 1.8 - NWC t i n 1.6 - O i N E i ,o 1.4 - i D3 1.2 - HWC a. a y 1.0 - s m-0.8 - o t W o 0.6 '- O O.4 - I % NWC + Zn l 0.2 - HWC + Zn 0.0 " ~0 400 800 1200 1600 2000 2400 L Exposure Time (hrs) N525

~ ZINC INJECTION PLANTS e . HOPE CREEK .' First New -Plant To Implement Zine Injection e MIIIRTONE PT 1 . First Mature Plant To Implement Zine Injection e NINE MILE PT 2 . Implemented During Start-up Test Phase NOSS w=- ~ ---o

m l ~ GEZIP System Schematic-Low Flow. - Bypass. injection . Agitator. Domin Water Double Diophragm injection Pumps 7 A I V A V 1/4" Tubing an l J Zinc Supply Tonk-Q l V l 1-1/2" Bypass Pipe Reactor Feedwater Pumps ~. _ =.

g_. 3 m. t p l 4 DOSE RATE MEASUREMENTS e HOPE CREnK-j

  • Surveillance Ontage 0 0.75 EFPY

_57 mR/hr Herueling outage o 1.04 EFPY 72 mR/hr i e Next Measurement January 1989 e NINE MHR.PT 2 Surveinance Outage 0 0.45 EFPY 24 mR/hr

  • :Next? Measurement Fall 1989 MIILSTONE PT 1 Next-Measurement Spring 1989 4

N054 $ 2. _-.u_ ..~._. . - _ - _ = _ _. _ - - - _ -.

=_ 1 BWR RADIATION BUILDUP RECIRCULATION SYSTEM PIPING 400< i e n mont j g i A W Mp. .-+ .,~2

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MILLSTONE ZINC INJECTION TEST t 1.0/ 0.90 Reactor Scrg e 5 .0.70 3 o 0.60 Ioo 0.50 . 3 First Zinc injection .2 0.40 o U) - t 0.30 a: 0.20 0.10 ^ =MW 'O.00 12/24. 01/13 02/02 02/22 03/14 04/33 04/23 05/13 06/02 06/22 1987 I N528 m e I * + a

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Millstone GEZIP Test!

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+ .~ ~ ~ ^ ~ l *.. "i MIIJSTONE GEZIP REACTOR. WATER ISOTOPIC: ANALYSES J. l 0.20 l l-0.18 -

3 0.16 ' -

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%e . Millstone Pt.1 Recirculation Pipe Rodiotion Fm 350 - d I 300 N e .cb i ,E, 250 - A E /1 1 200 3 E 150 - ? 8 / uinew mp + 100 t g_ O Decontamination O O 2 4 6 i l Operating Years Since Decontamination .m "A" Suct +' "B" Suct o "A" Dis A "B" Dis G EZP UOST 3 EN EF CIAL A-~~ER J ECO \\ muoose

4 POTENTIAL ZINC THEORY MECHANISM =g I i D' t = +.*

5.

)= ) s . s e..3 d 9001.BAL ORIDE 4RTM LATTICE DEPRCTS BNC STASIUIED ORIDE DEP9 CTS WNICH ALLOW OtFFUS00N 9.e., CCHR0880N) OCCUFIED SY P'C, )WUS 980 OIFPUO90N 9 4., A E 7. 19~"; e '3t A Zine Reduces Ionic Mobility In Corrosion Filtn Thinner Films Result g ~ ,.I n

l NEW ZINC INJECTION PLANTS i l \\ l -e FITZPATRICK

  • First; Plant To Implement Zine and HWC l

l-i PERRY: I

  • Prototype Passive System Will Be Tested l

l-l l N055 f t I

[,. l ZINC DEPLETED IN Zn-64 .. k L

o ISOTOPIC DISTRIBUTION

. NATURAL ZINC ) <Zn-65, 243 d) I;Zn-67, stable) 46.6% eZn-64. 27.9% -

  • Zn-66 l

lZn-68, stable) 4.1% I

  • L Zn --

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  • Zn-70 e

DEPLETED ZINC j i L

  • Can 'Be Accomplished In Gas Centrifuges j
  • Expect First Product Soon l

+ Evaluating Benefits At Both 10% Zn-64 And 5% Zn-64: l

  • Initial Product Will Be Expensive

- Expect l Price' To Drop As Volume Increases' l N057 -.u, ,,__.c:

.- = +- ~. ~' GEZiP :SystemlSchematic l PassiveJZinc Option 1 i A i V j i \\ E E E I t I E t Zinc Oxide-r'7 i Pellet Bed Recycle Row i M Eductor i l .kM I Fcv a f Reactor Ferdwater Pumps PZO l i I m. r 3

3_y ~ ~ y y 1.

SUMMARY

e BENEFITS OF ZINC IDENTIFIED IN PLANTS e VERIFIED IN LABORATORY e IMPLEMENTED AT THREE PIANTS e LOW DOSE RATES! ACHEIVED e DEPLETED ZINC CAN CONTROL Zn-65 e ZINC INJECTION NOW VERIFIED TECHNIQUE

i. e

~

LU C~-to(y) l 3., I -VERIFICATION OF EROSION-CORROSION AT NUCLEAR POWER PLANTS -i l 1 A i i l . I, L L If i l=l. i m i CARL CZAJK0WSKI u 1' E -BROOKHAVEN NATIONAL LAB 0P.ATORY ~. a >l i - 4 l l;:, u. u l: s,- .' b ' \\ r e i ,f a q iu t -Y j' I - i //? G ,1 ?; '=? .t l,' '

i EROSION - CORROSION s ACCELERATED OR-INCREASED RATE OF CORROSION CAUSED BY THE RELATIVE MOVEMENT BETWEEN A CORROSIVE FLUID AND A METAL'S SURFACE. e-A MASS TRANSPORT PHENOMENON. i k 7 p 1' l ? ':\\ c u' j f ',ii, 4e 4 e j' i

4 EDRI "CHEC" COMPUTER PROGRAM e "CHEC" CHEXAl - tiOR0WITZ - EROSION - CORROSION PROGRAM e INTENDED PURPOSE OF. PROGRAM: RANK COMPONENTS IN THE PIPING SYSTEM BY ORDER OF EROSION-CORROSION SUSCEPTIBILITY PICK MOST SUSCEPTIBLE INSPECTION LOCATIONS INCORPORATE WALL THICKNESS VERIFICATIONS ~ TO DEVELOP' A-PLANT SPECIFIC MODEL. FOR WALL -THINNING PREDICTIONS e MOST UTILITIES INSPECTED INDICATED THAT SUSPECT LOCATION INFORMATION WAS MORE CONSISTENT WHEN BASED ON PLANT SPECIFIC OPERATING. CONDITIONS YaViM8 iidMtN4t. wqty q,cgygg 6eoms Abrs eh. 4

Mdct.,6f R VT LlTT MMGE#/FA/I 28'Sw Rc6 CouAJc.t( NUMARC WORKING GROUP GUIDELINES (EROSION-CORROSION) e INITIAL SAMPLE - 10 MOST SUSCEPTIBLE LOCATIONS AND 5 ADDITIONAL LOCATIONS e-SAMPLE EXPANSION e INSPECTION e ACCEPTANCE CRITERIA T,,, WEAR' CODE ALLOWABLE MINIMUM WALL THICKNESS'AT THE END 0F-THE-NEXT-REFUELING CYCLE ~0R EXPECTED OPERATING CYCLE (+10%c MARGIN- 0F THAT TIME) Msfa. kens (k gl) //3 yj k) +k.y,M4.: glik 4 w ese were e4 4 ce4.ler co qW4 l%B8. 4,4 uww n.%.d"

r-SAMPLE EXPANSION (NUMARC) FOR EACH. PRODUCT (COMPONENT) FOUND BELOW CODE MINIMUM OR EXPECTED TO BE BELOW WITHIN NEXT a REFUELING-CYCLE OR EXPECTED OPERATING CYCLE (+10 MARGIN AT THAT TIME) AND.IS KNOWN TO BE CAUSED BY EROSION-CORROSION THEN:

o INSPECTION SHALL BE.

EXPANDED TO INCLUDE y ADDITIONAL SUSCEPTIBLE COMPONENTS.

THESE TO-INCLUDE' SIMILAR OR-LIKE ' COMPONENTS (I.E.,

-SISTER' TRAIN.'0R SIMILAR ARRANGEMENT) OR a i COMP 9NENTS IN PROXIMITY 0F CONCERN. he ti i p 1 t 4 ar t

j g. I '. l NRC ACTIONS TO ADDRESS EROSION-CORROSION l. l-o INFORMATION NOTICE 86-106 "FEEDWATER LINE BREAK" AFTER SURRY INCIDENT-(12/16/86) e INFORMATION NOTICE 87-36 (8/4/87) AFTER TROJAN-WALL THINNING -INCIDENT L L s NRC-BULLETIN 87-01 (7/9/87)' REQUIRED 'ALL LICENSEES T0 ' PROVIDE TO USNRC -INFORMATION' ON -THEIR: SINGLE PHASE AND1TWO PHASE CARBON PIPING SYSTEM EROSION- ~ CORROSION MONITORING PROGRAM y e. NRC/BNL:. JOINTLY EVALUATED 10 PLANTS. (ON SITE' VISITS). ON-THEIR IMPLEMENTATION.0F THEIR STATED 1 ~ ' EROSION-CORROSION MONITORING . PROGRAM- -(87-01 RESPONSE)! 3 W R.S f 7'PwRS j , pg nJ ,nkd..{ AloMAlc c,?hl,;,s v

  • All,eg AAs w..[;.44 4

7 t*%4 (sur.ve.a 4gg L n.+.. u. v. s.,,o u, 45.( s.d, y

e REMEDIAL ACTION TO ADDRESS PIPE WALL THINNING l mL I 9 a I L a '5 L e 1-li a f CARL CZAJK0WSKI- [. BROOKHAVEN NATIONAL LABORATORY-l .[ .s . l 1 o m i I ' ], -a 7, na e r -.---w-, a s

O l$ .* ~ ~ c. ~.... m a u,7 Erosion-Corrosion Problems Experience Taledo Edison MSR to Condenser (Drains, Large and Small) Reheat Steam Line to Aux Boiler Aux Boiler Sparger .0.T.S.C. Blow Down Line to Condenser r H.P. F.W. Heater to Deareator Heater NYPA Cross Over/ Cross Under Lines Cold Reheat Extraction Line to LP Heater (H.C.10%)

  • BWR Feedwater Discharge Line to LP Heaters

-Baltimore Gas & Electric i Extraction Steam from Cold. Reheat Third: Stage Extraction to the HP Feedwater Heater MSR Drains .First Stage HSR Drain Tank to FW Heater i i Steam Generator' Blowdown (2, 4, 6, inch lines) l! FW Recire Lines l' 'HP Feedwater Heater Drain to-Fifth FWH u s 'WPPSS-Aux Boiler Problems 4 i LDuquenne Power. iNo Piping Problems.(Beaver Valley) .MSR K -ColdiReheat

)

n p. -OPPD- 's. Extraction HP Turn ie Lines ic MS no MSR's h' Extraction Drain from LP Turbine (2")- l kb 1hthsees } f-;C werg L t"Dkte s h.yp

~ MAJOR FACTORS CONTROLLING EROSION-CORROSION e ALLOY COMPOSITION e WATER CHEMIS(RY e TEMPERATURE + e PIPING DESIGN / HYDRODYNAMIC CONDITIONS 1 l '4' !-/ i ) \\ F {\\ ~,... .k i <

.M ~

4) d>0*

5*8' g fk //// g +4,p <d/ IMAGE WALUATION g 4: Tesn uost mim jp 1.0 lf 2 E 'd l5E BE U 1.1 E.g~ E=2.0 = .8 m " 1.25 " I.4 i.6

==

150mm 4 6" 4 k%/ /4% <%+

  • s&#b,7

~ = ~ ~ p n '% b % 4 by g ~ n

,,; h$3N (['h, i
t. 4 fe;;,

%,g]I(,q. a q: 4

Typical Cherical Compob4tions of A106 Crade B, A234 Grade VPB and E7018 Weld Metal A106 Grade B Chemical Requirement Actual Surry Results Carbon, max. 0.30 0.20 Magnanese 0.29-1.06 0.83 Phosphorous, max. 0.048 <.005 Sulfur, max. 0 Ofi .023 Silicon, min. 0.10 0.10 Chromium N.R. 0.07 Nickel N.R. 0.02 Molybdenum N.R. 0.01 N.R. = No requirement < = Lesa than A234 Crade WPB Chemical Roouirement Carbon, max. .030 0.23 Magnanese-0.29-1.06 0.69 Phosphorous, max.-. 0.050 <0.005 Sulfur, max. 0.058 0.013 . Silicon, min. 0.10 0.22 Chromium N.R. 0.07 Nickel N.R. 0.01 Molybdenum N.R. 0.01 N.R = No requirement < = Less than E7018* Chemia al ' Requirement i Carbon N.R. 0.11 l Magnanese, max. 1.06 0.77 Silicow, max 0.75 0.56 Nickel, max. 0.30 0.02 Chromium, max. 0.20 0.04 Molybdenum,-max. 0.03 <0.01 Vanadium, max. 0.03 Not analyzed for Phosphurous N.R. < 0. 00,5 Sulfur N.M. 0.016' N.R = No requirement < = Less than

  • Requirements for E7018 electrode were found in the ASME Boiler and. Pressure Vessel Code, Section 11, Part C, Section SFA 5.1, 1983 Ed i t i on.

l

Trojan Piping Chemical Compositions Composition in wt. % SA 106 60 degree 90 degree 90 degree Element Grade B elbow elbow (D) elbow (B) Carbon 0.30 max 0.30 0.27 0.13 Manganese 0.29-1.06 1.03 0.91 1.23 l Phosphorus 0.048 max 0.005 0.005 0.005 i Sul fur 0.038 max 0.015 0.020 0.025 Chromium Not specified 0.15 0.15 0.18 Ni ckel 0.04 0.05 0.07 Holybdenun <0.01 0.04 0.04 Copper 0.08 0.07 0.08 Silicon 0.10 min - Insuf ficient material for analysis - 1 (Analyses by outside contractor), Table 2 Chromium Reanalyses l l Chromium content wt % 60 degree elbow 0.024 90 degree elbow 0.036 Straight pipe length 0.072 S/G B Bottom (Fig.11) 0.053 9 -c

TEMPERATURE EFFECTS EROSION-CORROSION (FLOW ASSISTED CORROSION) OCCURS IN BOTH SINGLE AND TWO PHASE SYSTEMS. o SINGLE PHASE (CARBON STEEL) EROSION-CORROSION IN TEMPERATURE RANGE OF 80 - 230 C. f e TWO PHASE (CARBON STEEL) EROSION-CORROSION IN TEMPERATURE RANGE OF 140 - 260 C. l \\ o MAXIMUM EROSION-CORROSION (SINGLE' PHASE CARBON STEEL) I?O - 150 C. I t l

p 4 COMMON LOCATIONS FOR EROSION-CORROSION METAL LOSS c e SINGLE PHASE HIGH PRESSURE FEEDWATER HEATER TUBES (INLET END) FEEDWATER TUBE INLETS STEAM GENERATORS (GAS COOLED REACTORS) FEEDWATER. PUMPS -SUCTION LINE TO HAIN FEEDWATER PUMP (SURRY UNIT 2)' e TWO PB SE STEAM EXTRACTION PIPING -CROSS-0VER PIPES FROM HIGH PRESSURE TURBINE TO MOISTURE SEPARATOR STEAM SIDE --FEEDWATER HEATER TUBES VARIOUS AUXILLIARY STEAM SIDE COMPONENTS _.,,.,,,s

L . UTILITY PIPE REPLACEMENT c e MOST UTILITIES MEET NUMARC GUIDELINES FOR PIPE l REPLACEMENT l e MANY UTILITIES HAVE REPLACED PIPING WITH L SIMILAR/SAME MATERIALS AS ORIGINAL INSTALLATION L (ASTM A106 GRB, ASTM A234-WPB) OR ASME EQUIVALENTS L e OCCASIONAL REPLACEMENTS WITH 2 1/4 CR Mo STEELS, IF AVAILABLE AVAILABILITY (ESPECIALLY FITTINGS) HAS BEEN l SCARCE WITH LONG DELAYS l IF CORROSION RATE DETERMINED, TREAT REPLACE-L i MENT AS A NORMAL MAINTENANCE. ITEM; ELIMINATES COMPLICATED WELDING AND . STRESS RELIEF L OPERATIONS L i e WELD OVERLAYS.ARE USED BY SOME UTILITIES IN AREAS 0F WALL THINNING. NORMALLY PIPE IS REPLACED AT L NEXT GUTAGE e PIPE LESS THAN EIGHT INCHES IN DIAMETER, NORMALLY. L REPLACED IF EROSION-CORROSION DETECTED l O O bCLe k y \\act > % h r 3 aW USM rep y*$ em - -}}

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