taming condenser tube leaks - david g. daniels

8/11/2019 Taming Condenser Tube Leaks - David G. Daniels

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Taming Condenser Tube Leaks, Part I

By David G. Daniels, Mechanical & Materials Engineering

September 1, 2010

Summer peaks are still with us, and every unit on your system must be prepared to operate at amoments notice. Spot power prices are so high that you expect phone calls asking for a few more

megawatts from your units. Then your plant chemistry lab calls to report a condenser tube leak.

Your options are few: Shut down immediately and get charged with a forced outage, ignore the leak

and keeping running until fall, or schedule a maintenance outage next weekend and hope the leak

can be found and fixed. In Part I, we examine what you need to know in order to make an informed

decision. In Part II, well explore the actual damage mechanisms.

Condenser tube failures continue to be the most common source of plant boiler and steam

contamination. They are also unpredictable in size and location and can be difficult to detect.

Improvements in water treatment equipment, such as reverse osmosis membranes, have reduced

demineralizer regeneration problems, the next-most-frequent major cause of boiler water

contamination. At some plants, the combination of reverse osmosis and a continuous electro-

deionization unit has essentially eliminated contamination caused by the water treatment system.

Some guidelines for selecting new water treatment equipment were presented in an earlier article

(Avoid These 10 Mistakes When Selecting Your New Water Treatment System, September2009).

Although condenser tube material is an important factor in the durability of your condenser, you

cant always alloy your way out of condenser tube leaks. Stainless steel is subject to cracking on

the steam side and microbiologically influenced corrosion on the water side. Even titanium tubes

have been known to leak.

Deciding between a forced shutdown to repair a potential condenser leak and pushing your luck by

continuing to run your unit requires an understanding of the common modes of condenser failure.

When a leak is confirmed, your next move will determine ifor, in most cases, how muchdamage

is done to the boiler and turbine.

Protect Your Steam Turbine

For the majority of plants that use condenser cooling water, a condenser tube leak means a drop in

boiler pH. For many units, control of the boiler pH is the primary determinant of whether or not the

contamination is severe enough to take the unit off line. Obviously, if the boiler pH cannot be

controlled, and particularly if the pH drops below 8, the unit must come off line immediately.

However, the converse is not always true. Just because the boiler pH can be maintained above 8 by

adding additional phosphate and caustic and increasing the rate of boiler blowdown doesnt meanthat contamination is not damaging the boiler or steam turbine.
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Steam turbines are particularly vulnerable to even minute amounts of contamination accumulating

on the steam turbine blades. It is critical that steam purity guidelines be constantly maintained to

minimize steam turbine corrosion. Corrosion in a steam turbine typically occurs in the low pressure

(LP) section of the turbine where the steam has lost most of its superheat and is approaching

saturation temperature. For this reason, steam purity guidelines are not significantly different for

different boiler operating pressures or temperatures.

During a contamination event such as a condenser tube leak, significant damage can occur to the

LP turbine in relatively few hours of operation with high levels of sodium hydroxide, chlorides, or

sulfates in the steam. These chemicals, precipitating in the LP turbine, can result in stress corrosion

cracking or corrosion fatigue failures.

Steam passing through the turbine (preferably sampled at the reheat steam sample station after

attemperation) should contain less than 2 ppb of sodium and have a cation conductivity of less than

0.2 microsiemens/cm (Figure 1). These two critical parameters need to be continuously monitored

and displayed and alarmed in the control room. The limit of 0.2 S/cm of cation conductivity can be

affected by the presence of organic acids and carbon dioxide in some units (see sidebar).

1. Measuring sodium. Measuring the sodium

content of water and steam in modern power plants

is critical; however, measurements are problematic.

Modern analyzers, such as the Hach Model 9245,

can detect levels of sodium down to 0.01 ppb.

Courtesy: Hach USA.

Recall that cation conductivity is not a measurement of any specific contaminant but a composite

parameterthe sum of the acid form of all anions in the sample (see Cation Conductivity

Monitoring: A Reality Check, May 2008). The actual corrosive species in steam that are inferred by

cation conductivity are chloride and sulfate. The actual limit of chloride and sulfate in steam for

normal operation should be less than or equal to 2 ppb. However, it is rare that a utility will install the

dedicated instrumentation and personnel to analyze these parameters directly. Normally, if the

cation conductivity is within limits, chloride and sulfate will also be well below 2 ppb. However, there
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is a potential bypass route for contamination that is often overlooked. When feedwater is used for

attemperation, it can be a source of steam contamination during condenser tube leaks.

If chloride and [Ed: correction] sulfate in the steam cannot be maintained below 8 ppm (less than

four times the normal operating limit of 2 ppb), the unit should come off line as soon as possible and

definitely within 24 hours, regardless of boiler water chemistry readings. When contamination is

suspected, the direct measurement of chloride and sulfate may be required to ensure that the

turbine is not being harmed.

Early Detection Is Essential

Although some condenser tube leaks occur suddenly and catastrophically, most start small and

grow steadily worse over time. Early detection makes it possible to plan for an outage at a

convenient time to fix the leak. Some utilities have chosen to monitor for chloride in the boiler water

directly with online chloride analyzers such as the Thermo Fisher Scientific Orion 1817LL Chloridenew version analyzer, which can measure down to 5 ppb chloride (Figure 2).

2. Measuring chlorides. Thermo Fisher Scientifics

Orion 1817LL low-level chloride monitor is

specifically designed to measure the presence of

chlorides in boiler water down to levels as low as 5

ppb. The presence of chlorides at such low levels is

an early indicator of a condenser leak. Courtesy:

Thermo Fisher Scientific Inc.

For drum boilers, close monitoring of boiler chemistry may provide the first indication of a condenser

tube leak. One approach is to monitor the cation conductivity of the boiler water. The cation

conductivity, minus the contribution of any added phosphate, is a reflection of the amount of chloride

and sulfate in the boiler water. Any increase in the boiler water chloride or sulfate level would be due

to contamination.

On Bacteria Testing and ORP Control

In some cases, plant operators and their chemical suppliers put an undeserved amount of trust in

various cooling water treatment control methods and assume that biofouling is in control when it


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really is not. Biofouling, its sources, and possible solutions were discussed in earlier articles

(Organics in the Boiler and Steam: Good or Bad?September 2006 and Biofouling Control Options

for Cooling Systems, September 2007).

The collection and analysis of a cooling water sample for microbiological countswhether those are

sulfate-reducing bacteria, fungus, or just general aerobic bacteriatells very little, if anything, about

the amount or viability of biofilms in the condenser water boxes, the tubes, or the tower and whether

or not microbiologically influenced corrosion (MIC) is occurring. The free-swimming or planktonic

bacteria collected in a water sample do not cause MIC, and these bacteria are the ones that are

most quickly dispatched by biocides, so low counts or the absence of these in the water can

produce a false sense of security (Figure 3).

3. MIC pits. Microbiological-induced corrosion

(MIC) shows up as pits on stainless steel

condenser tubing.Courtesy: Andy Howell, Xcel

Energy

However, the opposite case is not true. If the random collection of a cooling water sample shows

significant numbers of corrosive bacteria, it is very likely that the biocide program is not working.

The high bacteria level may have been present for weeks or months before is it discovered by a

water sample. By that time, the damage may already be done or biofilms may be so well established

that they are difficult to remove with anything except mechanical cleaning.

In order to understand the activity of biofilms in the tower, you must collect and analyze biofilms in

the system by simulating a tower surface (a corrosion coupon is one example), exposing it to

constantly flowing cooling water, and then analyzing the amount of microbiological activity of the

biofilm on that surface. There are also a number of indirect methods for tracking biofilm growth by

monitoring how biofilms affect cooling water flow or heat transfer in a controlled environment, or by

monitoring the electrical properties of a probe placed in the water. Often a combination of these

methods is needed.

The other area in which trust is often misplaced is the control of MIC and biofilms using an oxidation

reduction potential (ORP) probe. The use of an ORP probe for biological control also has a long
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history in the chemical process industry where organic, sulfur-, and nitrogen-bearing chemicals can

be pulled into cooling water via air or can leak from the process. In these cases, a sudden drop in

ORP (or a smaller-than-expected rise when the bleach pump starts) may indicate the presence of a

bleach-consuming chemical such as ammonia or hydrogen sulfide in the water and signal that the

operator should investigate further. However, these environments are far removed from a

conventional power plant cooling tower.

In a power plant, a properly maintained ORP probe will indicate whether or not a bleach pump is

operating. Similarly, if you have to dechlorinate your cooling water, the probe also does an excellent

job of determining if a bisulfite pump is working. It cannot, however, be correlated with, or substitute

for, determining the free available chlorine or total residual chlorine concentration. It should also not

be used to in some way imply the effectiveness of the biocide program to control biofilms in the

system. Unfortunately, there are too many variables that can affect the ORP readingsuch as pH,

conductivity, and the concentration of other chemical species in the cooling water (particularlychloride)to draw any consistent correlation.

If continuous monitoring of free available chlorine or total residual chlorine is desired (or required),

there are online colorimetric analyzers and amperometric sensors that provide this information. It is

important to remember that some analyzers read both hypochlorous acid and hypochlorite ion or

may only read one. The pH of the cooling water combined with an understanding of the pH

dependence of hypochlorous acid is critical to the interpretation of the analyzer output

Analysis of the boiler water is often far more sensitive to contamination than a steam or feedwater

analysis for cation conductivity, as the boiler blowdown valve is generally closed or very close to

closed. Contaminants in the feedwater are also concentrated hundreds of times in the boiler water,

making them far easier to detect. A boiler that sees an increase of 100 ppb of chloride in the boiler

water is in effect measuring an increase in the feedwater chloride level of 0.5 ppb in a boiler with

200 cycles of concentration. This increase is unlikely to be detected by cation conductivity,

particularly in the presence of organic acids and carbon dioxide.

Online sodium analyzers on feedwater may also be an excellent method for catching a condenser

tube leak early, before it has a chance to contaminate the steam or cause boiler chemistry

problems. These online analyzers, which can be purchased from a number of excellent vendors

(including Swan Analytical Instruments and Hach), now claim detection limits into the low parts per

trillion range and can be very reliable. For some plants, direct analysis of chloride, sulfate, and

sodium at low levels can be performed by ion chromatography, using a benchtop unit or even an

online monitor.


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Hide and Go Seek

If the decision is made that the plant must take an immediate forced outage, then there is also a

concern about whether the leak can be quickly found and plugged. The ability to detect a leak is the

product of its size, the conductivity or sodium in the cooling water, and the method used to detect

the leaks.

When half of the condenser can be safely isolated while the unit is running (or at least while there is

still vacuum on the condenser) any number of methods have been tried to find condenser tube

leaks. Some operators have used food wrap, candles, rubber stoppers, and shaving cream.

However, helium detectors are more sensitive and reliable and can quickly locate even very small

condenser tube leaks. The latest helium leak detectors have become much more portable and

easier to operate.

Though the design of each plant is somewhat different, an approximation of the size of a condenser

tube leak can be made by looking at the cooling water chemistry, the feedwater chemistry, and

some basic fluid dynamics.

As an example, consider the typical cooling water analysis summarized here, where the water

comes from a local surface source and the pH of the cooling water is adjusted with sulfuric acid:

Specific conductivity (S/cm): 4,000

Calcium (ppm as CaCO3): 770

Magnesium (ppm as CaCO3): 350

Sodium (ppm): 340

Chloride (ppm): 370

Sulfate (ppm): 1,200

Lets also assume that the cooling water pressure in the water box is 25 psig and that the unit

produces about 1 million pounds of steam an hour, meaning that the flow through the hotwell is also

about 1 million pounds per hour, or 2,000 gpm.

Suppose that there were a sudden increase of sodium at the condensate discharge of 5 ppb caused

by a condenser tube leak. The increase of sodium in the condensate would be unmistakable, as it is

far above any normal fluctuation from other potential sources of contamination. Such a leak would

also produce feedwater chloride of approximately 5 ppb and sulfate of 16 ppb. Although it is difficult

to predict precisely at these low levels, you may also see an increase of about 0.2 S/cm in cation

conductivity from this leak. In cases where the cation conductivity is stable, such an increase would

be seen as unusual and warrant further investigation. In cases where makeup water or organic

treatment chemical additions vary, it may be more difficult to determine if the increase in cation

conductivity is from a condenser tube leak or some other cause.

Although an increase in sodium at the condensate pump discharge may signal an analyzer problem,

and an increase in cation conductivity could have a number of possible sources, if there were an


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increase in both, then the probability of a condenser tube leak is very high. This is why both cation

conductivity and sodium analyzers are must-have analyzers on both a steam sample (reheat or

main steam) and at the condensate pump discharge.

Given the levels of sodium and cation conductivity in this example, the change in chemistry

suggests a leak of approximately 100 ml/minutea leak in a single tube smaller than the period at

the end of this sentence. It would be very difficult to find such a leak with anything but a helium leak

detector.

However small the leak, its effect is substantial. Chlorides at 5 ppb in the feedwater would

concentrate considerably in the boiler water and would likely increase to well above 1 ppm chloride

in most utility boilers that normally keep the continuous blowdown line essentially closed during

operation. A level of even 1 ppm chloride would be intolerable for a unit operating on any boiler

water treatment except, perhaps, a high-level phosphate treatment. Even with the blowdown open

and continuous high levels of phosphate feed, the potential for underdeposit corrosion, such as

hydrogen damage forming in the boiler, is substantial.

The Electric Power Resesarch Institute (EPRI) Chemistry Guidelines (on the EPRI website) provide

charts showing the acceptable levels of chloride and sulfate for various operating pressures. When

a condenser tube leak is suspected, analytical methods must be in place to analyze chloride and

sulfate levels in the boiler frequently. The boiler must come off line if the established limits cannot be

maintained not only for pH, but also for chloride and sulfate.

Make Your Decision

With proper analytical monitoring techniques, such as a low-level sodium analyzer at the

condensate pump discharge and a continuous chloride analyzer on the boiler water, you may be

able to detect very small condenser tube leaks in time to let you run to the weekend and avoid a

forced outage. If so, operating the boiler to minimize attemperation flow will minimize contamination

of the steam and hence minimize the chance for later boiler and steam turbine problems. However,

if the chloride and sulfate levels in the steam or boiler quickly rise (when the condenser leak is

large), the unit must immediately come off line to prevent substantial and costly damage to the unit.

In either case, good analytical instruments that are properly placed in the boiler and cooling water

systems are vital to making informed decisions.

One final thought: Remember to drain and flush the hotwell and drain the boiler when you come

down for a condenser tube leak in order to remove any accumulated contamination. Be especially

vigilant during the subsequent start-up to ensure that the right tube was plugged and that the

chemistry is quickly returning to normal. In any case of severe contamination, a chemical cleaning of

the boiler should be scheduled for the next outage.

In Part II, we explore the different mechanisms that cause condenser tube leaks.


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Taming Condenser Tube Leaks, Part II

David G. Daniels, Mechanical & Materials Engineering

October 1, 2010

In Part I of this two-part report we examined the various chemical forces at work in condenser tubeleaks, the steam plant components placed at risk, and the suite of instrumentation most capable of

providing early warning of a leak. Assuming you were able to repair the leak and quickly resume

operation, the next step is to identify the damage mechanisms that caused the problem so you can

minimize future leaks.

Condenser tube leaks are caused by corrosion or damage mechanisms that affect the entire

condenser. Those mechanisms will continue to cause additional leaks until the root cause(s) of the

failures are identified and changes are made to materials, water treatment, or plant operations toeliminate them. This article describes some of the more common condenser tube failure

mechanisms and provides a brief discussion of how they might be prevented.

The first step is to obtain a sample of the tube that failed for metallurgical examination to determine

the failure mode. Nondestructive evaluation (NDE) techniques, such as eddy current testing, may be

needed to provide an indication of the scope of the damage, but they cannot pinpoint a failure

mechanism. Together, metallurgical testing plus some type of NDE can lead you to the root cause

of the failure.

Condenser Tube Materials

Common condenser tube materials include various grades of copper brasses such as admiralty

brass, 90:10 copper-nickel (Cu-Ni), and 70:30 Cu-Ni. In copper alloy condensers, it is not

uncommon to find higher-grade materials, such as stainless steel tubes, used in the air removal

section.

Series 300 stainless steel alloys, such as 304 and 316L, are now fairly common in new construction

in both freshwater and seawater applications. Higher-grade duplex stainless steels, such as AL6XN

and 6 Mo stainless steel alloys, may also be used. Superferritic stainless steel, such as Sea-Cure,

has also been used for cooling water where high levels of chloride are present. These improved

materials are required when using brackish and other alternative water sources.

The duplex and superferritic stainless steels are far more resistant to stress corrosion cracking than

the Series 300 alloys. The table lists stainless steel materials with their Pitting Resistance

Equivalent Number (PREN) and Critical Crevice Corrosion Temperature (CCCT). The maximum

chloride value is the value below which chloride crevice corrosion will not occur.


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Corrosion and pitting resistance of various stainless steel alloys. Source: J.C. Tverberg, Performance o

Superferritic Stainless Steels in High Chloride Waters, presented at Condenser Technology: Seminar and

Conference, EPRI, Palo Alto, Calif., 2002

The standardized testing conditions under which these values were developed are much worse than

conditions normally experienced using traditional sources of cooling water. The best approach is to

use this information as a comparison of the relative corrosion resistance of one alloy against

another, not to set limits for cooling water chemistry. Not shown in the table are titanium alloys that

are also used in seawater applications or when the cooling water supply is high in chlorides.

Each of these materials has its advantages and disadvantages. As noted above, certain stainless

steel alloys are more resistant to chloride pitting and corrosion than other alloys. Copper alloys,

such as 90:10 and 70:30, though often discounted due to their lower resistance to erosion, have a

natural resistance to microbiologically influenced corrosion (MIC) caused by the toxicity of copper

ions to many living species. However, this same toxicity may create a problem if the plants cooling

water discharge is returned to a public waterway. In such cases, a plant may be required to maintain

the copper concentration of the discharged cooling water below very low levels.

Often, when retubing an existing condenser, the material selection may be limited due to the lower

heat transfer coefficients of stainless steel and titanium alloys compared with copper alloys.

Titanium alloys, though typically considered immune to corrosion from the cooling water side, have

failed due to impingement from saturated steam dump lines in the condenser. They can also suffer

from failures if steel tools scratch and penetrate the protective titanium oxide layer.

Common Condenser Tube Failure Mechanisms


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In our experience, the most common causes of condenser tube failure are related to erosion,

corrosion, or some form of mechanical damage. The following discussion is meant to guide your

initial examination of the failed tubes and to help you close in on the root cause.

Erosion.Cooling water erosion of condenser tubes occurs in areas of high turbulence and velocity

such as in the first few inches of the inlet to the condenser tube, or in areas where there is an

anomaly in the tube, such as a deposit or foreign object that the water must flow around. Figure 1

shows the latter case.

1. Cratered brass. Admiralty brass tubing that carries the cooling water in a condenser can erode because of

excessive water velocities or because the water is contaminated. Courtesy: M&M Engineering

Erosion is worse during periods of high flow rates or when sand, fly ash, or other abrasive materialsare entrained in the water. High localized flow rates can occur when the tube sheet is partially

blocked by debris. Copper-nickel alloys have twice the resistance to erosion of admiralty brass. But

there is at least an order of magnitude difference between copper-nickel alloys and stainless steel or

titanium alloys. Erosion can also affect the tube sheet and create leaks in the crevice between the

tube and tube sheet.

Erosion can also occur from the steam side. Emergency dump lines or drain headers can impinge

on the condenser tubing below in a very localized area. In one case, the proximity of a reheater

dump header caused a high-velocity water and steam mixture to impinge on the top row of acondenser with titanium tubes (Figure 2). The plant is seawater-cooled, and the resulting tube leak

caused massive contamination of the turbine requiring an extended outage to clean and inspect the


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turbine and associated valves and piping. Erosion of support plates may also increase the

propensity for vibration damage.

2. Leaky titanium tubes. Wet steam caused the erosion of these titanium condenser tubes. Courtesy: M&M

Engineering.

Erosion on the waterside can be minimized by keeping the tube sheet and tubes clean and free of

debris and operating the cooling water flow rates within the design range. Regular inspection can

detect waterside erosion. Tube inserts, both metal and plastic, have been used to protect the first

few inches of the condenser tube from further erosion and leaks.

Care should be taken when using very high pressure cleaning equipment on condenser tubes.

Excessive pressure or inexperienced operators can damage tubes and create more problems than

they solve.

Regular and careful visual inspection of the steam side of the condenser should locate areas where

steam erosion is occurring. Steam/water shields can then be installed to deflect impingement, or the

affected tubes can be plugged or replaced with a more erosion-resistant alloy.

Waterside Corrosion. One of the most common cooling waterside corrosion mechanisms in

condenser tubing is microbiologically influenced corrosion (Figure 3). It is far too common in

stainless steel tubing and less common, but still possible, in copper alloy tubing. A very few cases of

corrosion in titanium tubes have even been ascribed to MIC.


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3. MIC damage. This stainless steel condenser tubing was attacked by microbiologically influenced corrosion

(MIC).Courtesy: M&M Engineering.

Stainless steel condenser tubing is protected from corrosion by a thin layer of metal oxide. When a

biofilm forms over the tube, the chemistry between the biofilm and the condenser tube often

becomes corrosive to the oxide layer and underlying metal. The more well-established, thick, and

microbiologically diverse the biofilm is, the more likely it is that MIC can form underneath it.

In nearly any water-containing systemand certainly in cooling towers and once-through cooling

applicationsbiofilms cannot be eliminated; they can only be controlled. (See Biofouling Control

Options for Cooling Systems, September 2007 in our online archives at

http://www.powermag.com.)

The most common control strategy for biofilm in cooling water is the use of bleach to produce

hypochlorous acid, an effective biocide. In some cases the bleach is combined with sodium bromide

to produce hypobromous acid, which is a better biocide in alkaline pH cooling water. In cooling

towers, the effectiveness of bleach or bleach/bromide can be enhanced with biodispersants. Bleach

or bleach/bromide, applied properly and consistently, will typically provide adequate control of

biofilms and minimize MIC.

Mechanical cleaning, whether with brushes, scrapers, foam balls, or high-pressure water lancing, is

the only cleaning technique that can effectively remove all biofilm in a condenser tube. Units that

regularly use one or more of these mechanical cleaning methods are far less likely to see

condenser tube failures due to MIC or other issues with biofilm, regardless of the biocide program

that is in use.
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Titanium tubes have a very tenacious and chemically inert passivation layer that protects them from

nearly all corrosion mechanisms. It is very difficult to accumulate enough of the right kind of bacteria

in a conventional power plant cooling system to create an environment that would be corrosive to

titanium oxide. However, titanium tubes are still subject to biofilm accumulations that can slow the

flow through a condenser and cause problems in the cooling tower when biofilm accumulates on the

fill.

Steamside Corrosion. Corrosion is also often found on the steamside of a condenser tube.

Admiralty brass tubing is susceptible to both ammonia grooving and ammonia-induced stress

corrosion cracking.

Ammonia grooving occurs when ammonia added for pH control of the feedwater and carbon dioxide

and oxygen from air in-leakage condense with the steam, run down the inside of the tube sheet orother support, and cause corrosion in the crevice between the tube and tube sheet (Figure 4).

Although the focus is often on reducing ammonia (and therefore the pH of the feedwater), the real

culprit is the air in-leakage, which brings in the carbon dioxide and oxygen. Both carbon dioxide and

oxygen are essential to the corrosion process. This is why the air removal sections of admiralty

condensers often contain stainless steel tubes.

4. Groovy tubes. Too much ammonia in the cooling water caused grooving on both sides of a condenser tube

support. Courtesy: Andy Howell, Xcel Energy.

Carbon dioxide also lowers the pH of the condensate, requiring additional ammonia feed to maintain

the desired pH in the feedwater, producing higher ammonia levels in the condensate. High levels of

ammonia can also cause stress corrosion cracking in admiralty brass (Figure 5).


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5. Admiralty attacked. Excess ammonia in the cooling water can also cause stress corrosion cracking of

admiralty brass tubing. Courtesy: Andy Howell, Xcel Energy.

Susceptibility to ammonia grooving and ammonia-induced stress corrosion cracking drops

dramatically as the amount of nickel in the alloy increases. Even a 90:10 Cu-Ni alloy provides far

more protection against these forms of corrosion.

Series 300 stainless steel alloys are susceptible to chloride-induced stress corrosion cracking,

though a serious contamination event and a concentration mechanism (crevice or wet/dry

conditions) would normally be required to create chloride-induced stress corrosion cracking on the

steam side of a condenser tube.

Stainless steel alloys are also susceptible to enoblement corrosion. This form of corrosion results

from the combined action of manganese in the water source, bacteria, and the action of bleach or

chlorine. Manganese can be found in seawater, lakes, and rivers. In freshwater sources, the levels

of manganese can spike seasonally with lake turnover or spring runoff. Bacteria in biofilms on the

surface of the condenser tubes can collect and precipitate the manganese and create a black

magnesium oxide coating. This coating can create an uneven deposit layer that is more noble than

the stainless steel, making it the anode and thus causing pitting corrosion.

Other Failure Modes

Mechanical vibration can result in catastrophic condenser tube failures or leaks that are very difficult

to find because they open and close depending on steam conditions. The number of tube failures

due to vibration may increase suddenly after a turbine upgrade that uses more steam or creates a

different set of harmonic vibrations in the condenser.


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When considering a turbine upgrade, it is good to examine the condenser design to ensure that the

changed steam flow rate doesnt create areas of mid-span collisions, fretting, or fatigue in the

condenser tubes. Regular visual inspection of tube supports, NDE, and modeling of the condenser

with computational fluid dynamics analysis are all tools that can be used to determine the potential

for failures due to vibration.

Plugging of the tube sheet with debris and macro-biological fouling (such as from fish or clams) can

be problematic for units using cooling water from lakes, rivers, or seawater. A small tear in a screen

can result in a large accumulation of debris on the tube sheet that can plug a significant number of

the condenser tubes, forcing the remaining water through the remaining tubes at higher velocities.

The plugged or partially plugged tubes can develop calcium carbonate deposits and silt

accumulations due to slower flows. These deposits can then become havens for microbiologically

influenced corrosion.

Freeze protection is also important for any condenser where temperatures drop below freezing or

any using cooling water that can freeze. Some water boxes may not drain completely, particularly if

the drain is partially blocked or rusted shut. Figure 6 shows a titanium tube that failed due to

freezing temperatures.

6. Frozen solid. This titanium condenser

tube failed when water left in the tube

froze. Courtesy: Andy Howell, Xcel

Energy.

Special thanks to Ray Post of ChemTreat and Andy Howell of Xcel Energy for their contributions to

this article.

David G. Daniels ([email protected]) is a principal of M&M Engineering and a

POWER contributing editor.

taming condenser tube leaks - david g. daniels

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