Avoiding Waterside Corrosion Problems in Ethylene Plant Steam

Water Technologies & Solutions technical paper

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avoiding waterside corrosion problems in ethylene plant steam systems Author: James O. Robinson, Senior Technical Advisor, SUEZ, Trevose, PA, USA

Proper water chemistry controls are essential to maintaining reliable, efficient operation of the steam generating systems in ethylene plants. Ethylene plants usually have three steam generating systems; transfer line exchangers, dilution steam generators and fired boilers. This paper will discuss the transfer line

exchangers although many of the same principles apply to the fired boilers as well.

transfer line exchangers The main purpose of the transfer line exchanger (TLE) is to rapidly cool the pyrolysis coil effluent gases. Rapid cooling stops the cracking reaction and maintains effluent composition by eliminating secondary reactions.

Figure 1: Typical Pyrolysis Furnace and Transfer Line Exchangers Schematic

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There have been many designs of transfer line exchangers over the years. Many TLEs are shell and tube exchangers with water on the shell side and hot process gas in the tubes while others are tube within a tube design. Some TLEs are horizontal bundles, many are vertical bundles.

Figure 2: Vertical TLE water on the shell side

Figure 3: Vertical TLE, gas in the inner tube, water and

steam in the annulus between the inner and outer tube.

why do transfer line exchangers experience corrosion? Boiler tube iron exposed to water corrodes forming ferrous hydroxide plus hydrogen.

Fe + 2H2O ® Fe(OH)2 + H2

In high temperature boiler water, the ferrous hydroxide corrosion product further reacts with water to form a magnetite layer on the tube surfaces.

3Fe(OH)2 + H2O + Heat ® Fe3O4 + 3H2O + H2

It is this magnetite layer which protects the tube metal from further corrosion.

Figure 4: Boiler steel corrodes in water, but at high

temperature the corrosion products form a protective magnetite layer on the tube surface.

Figure 5 shows the relative corrosion of carbon steel in 310C (590F) water as a function of pH when the water is contaminated by hydrochloric acid or sodium hydroxide. This data shows that the magnetite layer is protective over a wide pH range. Consequently, very rarely is the bulk boiler water chemistry the cause of significant equipment damage.

Figure 5: The relative corrosion of steel by HCl and

NaOH at 310C (490F) is fairly low over a wide 25C pH range.1

Why then are corrosion problems much more common than rare events of wide pH excursions of the boiler water? The answer lies in the phenomenon of localized concentration of the boiler water, which causes pH excursions far beyond those typical of the bulk boiler water.

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What causes this localized concentration of boiler water? Traditionally, and still most commonly today, it is deposits on the steam generating surfaces, although heat flux and water circulation rates also have their influence. Low levels of feedwater contaminants, either acid or alkali, present in the boiler water are concentrated by boiling beneath these deposits. This localized concentration of contaminants causes wide pH deviations from the pH of the bulk boiler water.

Figure 6: Heavy metal oxides present in the boiler

feedwater tend to settle on or near the bottom tube sheet. Circulating boiler water does not readily dilute the water beneath deposits. Consequently, when these deposits are on the heat transfer surfaces, the water beneath the deposits concentrates by boiling resulting in pH excursions which destroy the protective magnetite layer.

Figure 7: Caustic corrosion as result of high boiler water

concentration beneath deposits.

how do we control this under deposit corrosion in the TLE? The first step to controlling under-deposit corrosion is to control the potential for deposits to form. This requires effective operation of the makeup demineralizers and condensate polishers to limit the amount of potential deposit forming contaminants such as calcium, magnesium, silica, iron and copper in the boiler feedwater to the lowest practical level. It is also necessary to limit the pickup of iron and copper from the feedwater and condensate systems due to corrosion and/or flow accelerated corrosion of those systems.

In addition to limiting the amount of deposit forming substances allowed to enter the boiler feedwater, it is equally important to limit the amount of acidic contaminants, such as chloride and sulfate, as well as any alkaline contaminants such as sodium and potassium, from the boiler feedwater.

Stated another way, very pure boiler feedwater is required.

what criteria can be applied to assure the feedwater is of satisfactory purity? The American Society of Mechanical Engineers (ASME) and the German Utility Boiler Operators Association (VGB) along with several others have published feedwater and boiler water chemistry recommendations for fossil fuel fired boilers as a function of operating pressure. Only the ASME addresses waste heat boilers and they specifically exclude “waste heat boilers of unusual design” from coverage in their consensus document.2 In spite of this, lacking other guidance, many ethylene plant operators refer to the ASME, VGB or other associations’ recommendations for establishing their feedwater and boiler water purity criteria.

However, due to system design and operating expectations, there are reasons ethylene plant waste heat boilers may have a need for more stringent feedwater purity requirements than those specified for conventional fossil fuel fired boilers. For example, in many ethylene plants, the hot gas enters the TLE through a bottom tube sheet, the most likely location for heavy metal oxide feedwater contaminants such as iron oxide to settle and form deposits. Consequently, water side deposition tends to be highest in the area of highest heat flux


increasing the potential for under deposit boiling and concentration of any acidic or caustic contaminants present in the circulating water.

In addition to not having high heat input into the lower sections, the fossil fuel fired boilers are removed from service, inspected and cleaned when necessary, every 1to 3 years. In contrast, ethylene plant waste heat boilers are often scheduled to be operated for 6 to 10 years between turnarounds.

what can a plant do if they will not always have the desired feedwater purity? The ability to achieve the desired feedwater purity is often affected by system design and operating limitations. For example, copper alloy surface condensers are often a part of ethylene plant steam-condensate systems. To minimize copper alloy corrosion, the condensate pH should be less than 9.2, and the condensate should be essentially free from oxygen. To minimize iron pick up from steel alloys, the condensate and feedwater pH should be higher than 9.2 and a few ppb, for example 5 ppb, of oxygen should be present. As a result, systems with both steel and copper components require compromises in the chemistry that are not ideal for the protection of either one.

In addition to system metallurgy concerns, there can be numerous operating constraints in ethylene plants which limit the ability to optimize feedwater purity at all times. Consequently, it is common practice in the U.S. to feed phosphate to buffer the boiler water so that low level acidic or caustic contamination does not cause large pH excursions when localized concentration occurs. Most commonly coordinated phosphate-pH chemistry has been employed.

Coordinated phosphate-pH chemistry maintains a mixture of disodium phosphate and trisodium phosphate in the boiler water. Typically, sodium to phosphate mole ratios are maintained below 3.0 so that low levels of acidic contamination convert some of the trisodium phosphate to disodium phosphate and low levels of caustic contamination convert some of the disodium phosphate to trisodium phosphate.

Na3PO4 + HCl ® Na2HPO4 + NaCl

Na2HPO4 + NaOH ® Na3PO4 + H2O

At normal tube metal temperatures, the boiler water remains non-corrosive even when concentrated. In addition, in the event of boiler water carryover, the steam system is protected from acidic and caustic

stress corrosion cracking (SCC) mechanisms. Therefore, coordinated phosphate-pH chemistry is SUEZ’s recommended treatment of choice for most TLEs.

acid phosphate corrosion Some systems using congruent phosphate-pH treatment suffer acidic phosphate corrosion when the boiler water is concentrated beneath deposits. This is the result of localized concentration of phosphate chemistry and high tube metal temperature.

Figure 8: Concentration of phosphate chemistry

beneath deposits near the inlet tube sheet led to acidic phosphate corrosion of this TLE tube. It is usually impossible to visually differentiate between caustic corrosion and acid phosphate corrosion. Analyses of the deposits formed and a review of operating chemistry are required to identify the cause of the corrosion.

Research at the University of Newfoundland3 found that the tendency for acid phosphate corrosion of the normally protective magnetite layer increases with increasing phosphate levels and temperature and decreasing sodium to phosphate mole ratios. For example, they reported that for an equal molar mixture of trisodium and disodium phosphate, it takes 8550 ppm of phosphate (PO4) to corrode the magnetite layer at 320C (608F) while at 360C (680F) it only takes 475 ppm.


Since the boiler water in most TLEs is closer to 320C than 360C, one might think it would take several thousand ppm of this mixture to corrode the magnetite layer. That would be true if the tube surface is clean and has good contact with the circulating boiler water. However, in the presence of deposits or high heat flux and marginal circulation the tube metal temperature can easily increase above that of the boiler water.

This research also found that the major corrosion product of acid phosphate attack was maricite, a sodium-iron-phosphate compound (NaFePO4). They further noted that an ideal phosphate treatment would maintain sodium to phosphate mole ratios high enough to avoid the formation of maricite. The minimum sodium to phosphate mole ratios high enough to do this were determined to be 2.5 to 1.0 at 320C and 2.7 to 1.0 at 360C. This being the case, it is logical to conclude that acidic phosphate corrosion might be effectively controlled by maintaining a minimum sodium to phosphate mole ratio of 2.8 to 1.0.

Table 1: University of Newfoundland studies found three key factors that increase the risk of acidic phosphate corrosion.

Factors That Increase the Risk of Acidic Phosphate Corrosion

• Lowering Na/PO4 mole ratios

• Increasing phosphate concentration

• Increasing temperature

how can an operator tell if acidic phosphate hideout and corrosion may be a problem before a failure occurs? The answer is to monitor the phosphate and pH levels during changes in operating rate, such as when switching from normal operation to the decoking cycle. The phosphate and pH levels should either stay the same or if they change, they should both change in the same direction. That is if the phosphate increases as it re-dissolves into the boiler water, the pH should also increase. If the phosphate increases and the pH decreases, that is a sign that acid phosphate hideout and corrosion has occurred.

Figure 9: Phosphate increased and pH decreased

whenever this boiler had a load reduction, a sign of acid phosphate hideout and corrosion.

what can a plant do if indications of acid phosphate corrosion are noted? Deposits are often the cause of both localized phosphate concentration and increased tube metal temperature. The use of chemical treatments effective for the control of deposition, especially iron deposition, has proven beneficial in many TLEs. SUEZ’s OptiSperse* HTP products have proven beneficial for this purpose.

It is also important to operate the intermittent bottom blowdowns frequently during start-ups and decoking as particulate iron levels are usually highest during load changes.

One sure way to eliminate acid phosphate corrosion is to eliminate the feed of phosphate to the boiler water. This is most commonly done by using what is known as All Volatile Treatment (AVT). As the name implies, only volatile chemicals are fed to the boiler feedwater, typically neutralizing amines and a volatile oxygen scavenger, but in some instances, volatile filming amines are also employed.

When selecting an amine product for AVT, the inclusion of an amine with sufficiently low volatility that a significant amount stays in the boiler water to neutralize low level acidic feedwater contamination can be beneficial. However, because neutralizing amines have a greater effect on the pH of cooled boiler water samples than on the pH of the water in the boiler, cooled boiler water sample pH cannot be relied on as a means of control when using AVT. For example, monoethanolamine, (MEA) has sufficiently low volatility that a significant amount will stay in the boiler water making it attractive as a component of the amine products used for AVT treatments.


Figure 10 shows the effect acidic feedwater chloride contamination has on the cooled boiler water sample pH when MEA is used to control boiler feedwater pH at 9.0. The pH of the boiler water sample gives the impression that the boiler water is still quite alkaline even with 30 ppb of chloride (as Cl) in the feedwater. However, MEA, as with most other amines, does not ionize well in high temperature water so that the pH of the water in the boiler is actually slightly acidic with 5 ppb of chloride (as Cl) in the feedwater even though the cooled sample pH is greater than 9.2. Consequently, it is critical to monitor the boiler water levels of contamiation closely when using AVT.

Figure 10: Compared to most other amines, a larger

percentage of MEA stays in the boiler water to provide some protection against acidic feedwater contamination. However, because amines are weak bases at high temperature, cooled blowdown samples can give a false impression of the protection afforded when acidic contaminants are encountered. In the boiler, the water becomes slightly acidic when 5 ppb of chloride (as Cl) is present in the feedwater, even though the cooled blowdown sample pH is 9.27.

An alternative to AVT treatment to avoid acidic phosphate corrosion is to reduce the amount of phosphate used to treat the boiler water since the concentration of phosphate affects the potential for acid phosphate corrosion to occur. The move to lower phosphate levels may be beneficial however, as shown by the University of Newfoundland research studies it is equally important to maintain adequate sodium to phosphate mole ratios in the boiler water. For example, the VGB recommendation to maintain boiler water phosphate between 1 and 3 ppm (as PO4) and the pH between 9.3 and 9.7 typically establishes the

sodium to phosphate mole ratio in the range of 2.6/ 1.0 to 7.4/1.0.

The low levels of phosphate and increased sodium to phosphate mole ratios certainly reduce the risk of acidic phosphate corrosion. However, this control allows up to 1.9 ppm of free caustic in the boiler water which increases the risk of caustic corrosion, not only of the TLE, but of caustic stress corrosion cracking in the steam system4 in the event of boiler water carryover. It is also important to remember that the reason for feeding phosphate is to compensate for those times when very high feedwater purity standards are not being met. The less phosphate being maintained in the boiler water, the less contamination it takes to overcome the phosphate buffer and cause corrosion.

Consequently, if reliable performance is to be achieved with AVT or low level phosphate treatment, the TLEs must be provided with very high purity feedwater to minimize the potential for deposition and potentially corrosive contaminants in the feedwater on a continuous basis. As a result, SUEZ recommends that plants that need to, or elect to, operate with AVT or low phosphate levels in the boiler water strive to meet the feedwater purity requirements proposed in Table 2. Note that in some respects the proposed criteria assure higher purity feedwater than either the ASME or VGB recommendations require. For example, feedwater chlorides are limited to 0.005 ppm in order to avoid acidic pH depression in the cycled up boiler water when the phosphate level is limited to 3 ppm (as PO4) or less.

Table 2: SUEZ recommendations for TLE feedwater purity goals

Feedwater Parameters SUEZ 1500 psig Ethylene TLEs

Oxygen, ppm <0.01

pH @ 25C 8.8 – 9.2 (copper) 9.2 – 9.6 (all steel)

Total iron, ppm <0.01

Total copper, ppm <0.003

Chloride, ppm <0.005

Sulfate, ppm <0.005

Silica, ppm <0.010

Sodium + potassium <0.005


how should the water chemistry be monitored to assure reliable feedwater contamination and boiler water chemistry control? The demineralized make up water, the condensate polisher treated water and the boiler feedwater should all be monitored with in-line analyzers. The mixed bed make up water and the condensate polisher streams should be continuously monitored with in-line conductivity probes and the treated waters should have conductivities less than 0.1 µS/cm.

Conductivity levels higher than this indicate contamination that needs to be corrected. Although a common practice, samples of this water should not be collected from an open storage tank or transported to a laboratory for either conductivity or pH analysis as adsorption of carbon dioxide from the atmosphere will erroneously indicate contamination of the water being produced.

The feedwater pH should be measured with an in-line pH meter or indirectly by an in-line conductivity meter. If the makeup water and polished condensate have less than 0.1 µS/cm conductivity then there should be a very good correlation between the specific conductance imparted to the water by the amine and the pH of the water. As with the conductivity measurements, the use of inline monitors will avoid errors introduced due to atmospheric carbon dioxide contamination of grab samples and will provide a continuous monitor of the feedwater pH.

If all volatile or low level phosphate treatment is to be used, the TLE feedwater streams should be monitored by inline cation conductivity (sometimes referred to acid conductivity) meters so than any acidic contamination of the feedwater is detected and corrective actions can be implemented quickly.

The boiler water phosphate-pH control relationship should be based only on the non-volatile chemistry, since it is important to maintain an adequate sodium to phosphate mole ratio. Volatile chemicals such as neutralizing amines, while present to some extent in the boiler water, will not provide significant protection to the tube metal in areas of boiler water concentration for two reasons. First, while the amines significantly affect the pH of a cooled boiler water sample, they have very little effect on the pH of the high temperature water in the TLE. Second, the amines will vaporize into the steam phase as the water is concentrated by boiling.

Consequently, either the pH measurements should be adjusted for the amount of amine present in the boiler water sample or the standard control chart should be modified to account for the effect the amine has on the pH measurement. Theoretically, this adjustment should be made in every instance, but it becomes more important at lower phosphate levels and also with the use of lower distribution ratio neutralizing amines. The lower the amine distribution ratio, the higher the concentration of amine in the boiler water for a given feedwater pH.

Figure 11 shows the effect SUEZ’s product, Steamate* NA0660, a blend of amines with a minimum distribution ratio of 1.0 (concentration in the boiler water no greater than the concentration in the feedwater), has on the pH measurement in a typical ethylene plant TLE blow down sample when fed to maintain the feedwater pH at 9.0. It can be seen that above 5 ppm of phosphate, the amines have little effect on the measured pH. However, in the phosphate range of 1 to 3 ppm, even the relatively high distribution ratio amines in Steamate NA0660 have a very significant effect on the measured pH.

Figure 11: The feed of SUEZ Steamate NA0660 to

maintain a feedwater pH25C of 9.0 has a significant effect on the boiler water pH25, especially at phosphate levels below 5 ppm. Other products containing amines with low distribution ratios such as monoethanolamine (MEA) have a much larger effect on the pH25C measurement.

As noted earlier, based on the University of Newfoundland study it is logical to assume that if a plant maintains the sodium to phosphate mole ratio equal to or in excess of 2.8 to 1.0 the risk of acid


phosphate corrosion is greatly reduced. However, if the effect of the feedwater amine on the pH of the boiler water sample is ignored, the sodium to phosphate ratio in the boiler water may be much lower than thought. Figure 12 shows the effect two different amine blends fed to maintain the feedwater pH at 9.0 can have on the boiler water pH required to maintain a minimum sodium to phosphate mole ratio of 2.8 to 1.0.

Figure 11 – To maintain an appropriate sodium to

phosphate mole ratio in the boiler water when employing a low level phosphate treatment, it is important to consider the impact of the feedwater amine on the boiler water pH. This chart shows the effect of two different neutralizing amine blends fed to maintain the feedwater pH25C at 9.0 on the pH of a 2.8/1.0 sodium to phosphate molar ratio boiler water.

Steam sodium should be monitored or a regular basis so that any significant steam contamination can be identified before turbine capacity is lost or damage occurs. If a treatment regime that allows free caustic in the boiler water is selected, it becomes increasingly important to minimize the amount of boiler water carried over into the steam. Consequently, inline sodium analyzers are recommended to monitor the carryover into the steam of all superheated steam turbines and steam sodium levels greater than 10 ppb should get prompt attention.

summary Reliable operation of transfer line exchangers requires high purity feedwater, an effective monitoring program to quickly identify any deviation from feedwater purity requirements and an appropriate response to any feedwater purity deviations encountered.

The use of dispersants to limit deposit accumulations and phosphate to limit pH excursions due to low level feedwater contamination have proven beneficial in many plants. Some instances of acidic phosphate corrosion have led to lowering or eliminating boiler water phosphate levels in some plants. If less than 5 ppm of phosphate is being maintained in the boiler water, it is important to account for the effect that the feedwater amine has on the boiler water pH measurements when pH control limits are being established.

If free caustic is allowed in the boiler water, the continuous production of high purity steam becomes even more critical to steam system reliability and should be monitored accordingly.

references 1 Klein, H.A. “Corrosion in High Pressure Boilers”,

Electricité de France and French, July 8, 1970 2 ASM CRTD-Vol. 34, “Consensus on Operating

Practices for the Control of Feedwater and Boiler Water Chemistry in Modern Industrial Boilers”, 1994

3 Tremaine, Peter, et al, “Phosphate Interactions with Metal Oxides Under High Performance Boiler Hideout Conditions”, 54th International Water Conference, Pittsburgh, PA, 1993

4 Bussert, Curran and Gould, SUEZ, “The Effect of Water Chemistry on the Reliability of Modern Large Steam Turbines”, Journal of Engineering for Power, July, 1979

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Avoiding Waterside Corrosion Problems in Ethylene Plant Steam