do organic amines have a role in the treatment of high purity boiler feedwater?

7/27/2019 Do Organic Amines have a Role in the Treatment of High Purity Boiler Feedwater?

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TP1196EN.doc May-12

TechnicalPaper

Do Organic Amines have a Role in the

Treatment of High Purity Boiler Feedwater?

Author: James Robinson

Abstract

Organic amines have been widely used to treat high-purity boiler feedwater since at least the 1940s. Alt-hough notable benefits have been derived, some consider the use of these amines to be risky. In addition,the use of organic chemicals for boiler feedwater treatment often causes steam and condensate cationconductivity levels to exceed current power industry guidelines. The benefits that can be derived and ques-

tions concerning the use of both neutralizing and filming amines are presented to help plant operators as-sess the potential value to be gained from using these amines in their systems.

Volatile Alkaline Treatments

Volatile alkaline treatments such as ammonia and neutralizing amines are used to elevate feedwater andcondensate pH in nearly all high-purity boiler feedwater systems. Some commonly used neutralizing aminesare morpholine, cyclohexylamine (CHA), diethylaminoethanolamine (DEAE) methoxypropylamine (MOPA) andethanolamine (ETA).

A major advantage of employing neutralizing amines in the treatment of water systems is the flexibility theyprovide with respect to distribution of the chemical between the liquid and vapor phases in two-phase sys-tems (Figure 1).

Figure 1 The steam-water distribution ratios of ammonia and various amines vary as a functionof system pressure (temperature) and pH.


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Page 2 Technical Paper

Also, the high temperature in most parts of the boiler-steam system affects the temperature of the waterunder operating conditions. Compared to ammonia, certain amines are better able to maintain alkaline pHlevels at the temperature of the water in steam generators (Figure 2).

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0

0.2

0.4

0.6

0.8

1

1.2

1.4

0 500 1000 1500

pHIncrease

OverPureWater

System Pressure, PSIG

Increase of pH at Temperature Compared to thatof Pure Water as a Function of Boiler Operating

Pressure When pH at 25 C is Adjusted to 9.0 withVarious Alkalizing Treatments

Ammonia

Cyclohexylamine

Ethanolamine

Figure 2 The effect of boiler pressure (temperature) on pH at temperature when otherwise pure wateris adjusted to a pH 9.0 at 25C with various volatile alkalizing chemicals.

Low-Pressure Evaporators in Heat Recovery Steam Generators

Many low-pressure (LP) evaporators in the heat recovery steam generators (HRSGs) of gas turbines are thesource of feedwater for the intermediate-pressure (IP) and high-pressure (HP) evaporators and for the steamattemperating water. Consequently, the traditional chemicals used to control pH in low-pressure boilers,phosphate and caustic, cannot be used in these LP evaporators -- so volatile chemicals must be relied uponfor pH control. Partially as a result of this inability to use phosphate and caustic in the LP evaporators, nu-merous flow-accelerated corrosion (FAC) problems have been encountered.

While some FAC problems are observed in the economizer inlet and other single-phase flow areas of theevaporator, many are in the two-phase flow areas, such as the outlet ends of riser tubes and the steam sep-arating equipment (Figure 3). Although fluid velocity and metallurgy are major factors in this metal wastage,the pH of the liquid phase also has a significant effect. All else being equal, the lower the pH of the liquidphase the greater the metal wastage. Since the vapor-liquid distribution and the at-temperature basicity of

the volatile alkaline treatment affect the pH of the liquid in the two-phase flow regions of the LP evaporator,the amount of metal wastage in this area is also affected.


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Technical Paper Page 3

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2010, General Electric Company

Figure 3 FAC caused serious damage to this low-pressure evaporator steam separator.

To illustrate the effects of the steam-water distribution ratio and the at-temperature basicity of volatile alka-line treatments in LP evaporators, models were developed using Water & Process Technologies ComputerModeling System (CMS)1 software. To develop the models, the CMSprogram calculates the steam-water dis-tribution constants and acid dissociation constants of the feedwater contaminants and alkalizing agents atthe operating temperature of the evaporator. It then uses flow data to project the distribution of the constit-uents in the water and steam phases and calculates the pH of each stream at both the temperature of thesystem (pHt) and at 25C (pH25C).

For the purposes of this illustration, an LP evaporator model that converts 10 percent of the feedwater into100 psig (700kPa) steam and riser tubes that develop a steam-to-liquid weight ratio of 0.1 was used. Figures

3a through 3d show the projected pHt and pH25C developed at various locations in the LP evaporator whenammonia or ETA is fed to the feedwater. The projected chemistry of each of the LP evaporator streams isprovided in Tables 1a through 1d.

Figure 4a shows that when ammonia is used to control the feedwater pH 25C at 9.2, the expected pH at tem-perature in the liquid exiting the riser tube is 6.4. By comparison, Figure 4b shows that when ETA is used tocontrol the feedwater pH25C at 9.2, the expected pH at temperature in the liquid exiting the riser tube is 6.7.Although this 0.3 unit difference in pH does not seem large, experience has shown that it is enough to dra-matically reduce FAC problems in many systems. To develop the same 6.7 pHt in the liquid exiting the risertube when using ammonia, the feedwater pH25C must be increased to 9.6, as shown in Figure 4c. Dooleyand Anderson have suggested that the pH25C should be at least 9.8 to control two-phase FAC when ammoniais used.2 This is to boost the pH at temperature one full unit above that of pure water, which is 5.8 at 100 psig

(700kPa)


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Figure 4a The use of ammonia to control LP feedwater pH 25C at 9.2 often results in FAC in riser tubes

Figure 4b The use of ETA to control LP feedwater pH25C at 9.2 usually controls FAC in risertubes. However, the use of ETA alone can produce a low pH in the condensed steam.


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Figure 4c The use of ammonia to control LP feedwater pH25C at 9.6 usually controls FAC in riser tubes. However, thisresults in nearly 10 ppm of ammonia in the steam, making it unsatisfactory for many uses.

Figures 4b and 4c show that the use of ETA or ammonia alone may not provide satisfactory results through-out the system. The use of ETA alone may effectively protect the LP evaporator riser tubes from FAC, but re-sult in low steam pH. By contrast, feeding enough ammonia to control FAC in the LP evaporator riser tubesmay cause excessive ammonia in the steam. For these systems, a blend of amines or ammonia and anamine may prove desirable. The model in Figure 4d illustrates how a blend of ETA and ammonia can providea better pH balance throughout the LP evaporator.

Figure 4d - A blend of ETA and ammonia produces a nearly uniform pH throughout the LP system.


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High-Pressure Evaporators in Heat Recovery Steam GeneratorsAnother advantage of organic amines is the ability to provide protection to high-pressure (HP) evaporatorsagainst acidic feedwater contamination. HP evaporators are often treated with either all volatile treatment(AVT) or low-level phosphate-caustic treatment. When ammonia is used for feedwater pH control, thesetreatments provide very limited protection against feedwater contamination.

This is illustrated in Figure 5, which depicts a model of the HP evaporator developed using CMS. This model

evaporator operates at 1500 psig with 0.5 percent blowdown. The feedwater pH is maintained at 9.4 by theaddition of a volatile alkalizing agent. This normally very high purity evaporator feedwater would have a cat-ion conductivity of 0.12 S /cm due to the presence of 20 ppb carbon dioxide. As a result of additional con-tamination in the form of 5 ppb of acidic chloride, the model evaporator feedwater cation conductivity isincreased to 0.17 S /cm.

Figure 5 - HP evaporator with 5 ppb acidic chloride (cation conductivity of 0.17 S/cm)contamination of the boiler feedwater.

Since much on-load corrosion of 1500 psig evaporators is due to underdeposit corrosion (Figure 6), CMSmodels were designed to show the effect of different treatment chemistries on pH in both the bulk boiler wa-ter and boiler water that has been concentrated 10 fold beneath a deposit. This information is presented in

Figures 7a through 7d.


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Figure 6 Under deposit corrosion is the main cause of on-load high-pressure boiler tube failures.

Figures 7a and 7b show the projected results for all volatile treatment (AVT) with ammonia and ETA, respec-tively. Figure 7a shows that with ammonia treatment, although the pH25C of the bulk boiler water is 8.3, thepHt is 5.0, well below the pHt of 5.7 for pure water. In addition, the concentrated water beneath the deposit isprojected to be highly corrosive, with a pHt of 3.8.

By contrast, in the ETA treated system, Figure 7b shows that the bulk boiler water pH25C is projected to be 9.6and the pHt is projected to be 6.0, slightly above that of pure water at this temperature. The pHt of the con-centrated water beneath the deposit is projected to be 5.3. Although this is still not optimum, it is significantlybetter than the pHt of 3.8 that is projected for the ammonia-treated system.

Figure 7a The pH at temperature is acidic in both the bulk boiler water and beneath a deposit in a 1500 psig boilertube with ammonia-based AVT feedwater treatment, when 5 ppb of acidic chloride contamination (cation conductivity

of 0.17 S/cm) is in the boiler feedwater.


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Figure 7b The pH at temperature is slightly alkaline in the bulk boiler water and slightly acidic beneath a deposit in a

1500 psig boiler tube with ETA based AVT treatment when 5 ppb of acidic chloride contamination (cation conductivity of0.17 S/cm) is in the boiler feedwater.

Figures 7c and 7d illustrate the advantages of using ETA compared to ammonia for feedwater pH controlunder the following conditions: The boiler water is treated with 0.5 ppm of trisodium phosphate and 0.5 ppmof sodium hydroxide, and the feedwater is contaminated with 5 ppb of acidic chloride.

Figure 7c shows that with ammonia feedwater treatment, the 5 ppb of feedwater chloride produces an acid-ic pHt of 5.4 in the bulk boiler water and 4.4 beneath the deposit. Acidic corrosion is very likely under theseconditions even though the bulk boiler water has an alkaline pH25C of 8.4.

By contrast, as illustrated in Figure 7d, if ETA is used for feedwater treatment, the bulk boiler water pHt is pro-jected to be 6.3, which is slightly alkaline, and the pH t of the water concentrated beneath the deposit is pro-

jected to be only slightly acidic at 5.7.

Figure 7c The pH at temperature is acidic in both the bulk boiler water and beneath a deposit in a 1500 psig boilertube with low-level trisodium phosphate, caustic and ammonia feedwater treatment, when 5 ppb of acidic chloride

contamination (cation conductivity of 0.17 S/cm) is in the boiler feedwater.


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Figure 7d The pH at temperature is slightly alkaline in the bulk boiler water and slightly acidic beneath a deposit in a1500 psig boiler tube with low-level trisodium phosphate, caustic and ETA feedwater treatment, when 5 ppb of acidic

chloride contamination (cation conductivity of 0.17 S/cm) is in the boiler feedwater.

The information extracted from Figures 7b and 7c and presented in Table 3 of the appendix shows that atthe model conditions, the AVT treatment using ETA for feedwater pH elevation provides better protectionfrom acidic chloride corrosion than does low-level phosphate and caustic treatment when ammonia is usedfor feedwater pH control. The pHt of the bulk boiler water is maintained at 6.0 with the ETA-based AVTtreatment, while it drops to 5.4 when using low-level phosphate and caustic treatment with ammonia forfeedwater pH control. Beneath the deposit, the pHt of the AVT treatment using ETA becomes slightly acidicat 5.7. By comparison, the pHt beneath the deposit with the low-level phosphate, caustic and ammonia

treatment is 4.4.

Boilers designed with adequate circulation so that phosphate hideout is not an issue can obtain significantlygreater protection from acidic chloride contamination by maintaining an increased level of trisodium phos-phate in the boiler water. As shown in Figure 7e, the feed of trisodium phosphate to maintain 6 ppm ofphosphate in the boiler water maintains alkaline water with a pHt of 7.7 in the bulk boiler water and 8.7 whenconcentrated 10 times beneath a deposit, in the presence of 5 ppb acidic chloride feedwater contamination.

The increased protection from acidic corrosion provided by ETA or increased TSP is afforded without theneed for adding caustic to the system, reducing the risk of steam system damage.


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Figure 7e - The pH at temperature remains alkaline in both the bulk boiler water and beneath a deposit in a 1500 psig

boiler tube with 6 ppm of phosphate in the boiler water when the feedwater has 5 ppb of acidic chloride.

Filming Amines

Filming amines have been used almost as long as neutralizing amines to protect equipment by forming anon-wettable film on metal surfaces. Figure 8 shows the protection polyamine application afforded corro-sion coupons exposed to 100 ppb of oxygen at 230F (110C) for 7 days.4

Figure 8 Filming amines form a non-wettable film on metal surfaces, providing protection against oxygen corrosion.The above coupons were exposed to a filmer-neutralizer treatment and 100 ppb of dissolved oxygen in demineralizedwater at 230F for seven days. The average corrosion rate was measured to be 0.23 mils/yr with no noticeable pitting

observed.


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In the industrial sector, filming amines have been particularly useful for controlling 2-phase flow acceleratedcorrosion and protecting equipment when it is out of service. Filming amines were applied to a limited num-ber of electric power plants in the 1950s, with the following favorable results reported at Cincinnati Gas andElectric5

1. The film gives protection against carbon dioxide and oxygen corrosion.2. Filming amine gives protection to systems used frequently for stand-by service because it offers

protection against oxygen which is often present in this type of service.

3. Filming amine has no adverse effects on copper and copper bearing alloys. It may offer protec-tion to such alloys

And Arkansas Power and & Light6

1. With filming-amine treatment well established, unit startup after a prolonged outage shows amore rapid decrease in boiler water turbidity.

2. Residual film during the outage protects metal in the feedwater system from the corrosive ef-fects of oxygen and other elements in the air.

3. Since filming-amine treatment started, a marked decrease in boiler sludge has been noted.

More recently, First Energy Corp reported on the benefits they are currently experiencing using filming aminetreatment.7 Among the benefits noted were:

1. this type of chemical control program can protect both iron and copper systems even whenexposed to oxidizing all volatile treatment and ammonia cycle conditions.

2. Testing of this program also indicates a significant reduction in Fe2+, an indication of protectionagainst FAC.

Based on the experience at these three utilities, it is anticipated filming amines can provide improved protec-tion for those systems that cycle frequently.

Why are Organic Amines not more Widely Used in the Power Industry?

In spite of the benefits that can be derived by employing properly selected neutralizing amines, their use isrestricted from many power plant systems for numerous reasons. One major reason is the thermal decom-

position of neutralizing amines in steam superheaters and reheaters. The amount of decomposition thatoccurs depends on the particular chemicals used, the temperature of the superheat and reheat steam, andthe time of exposure at those temperatures.

Ammonia, carbon dioxide, acetate and formate are some of the most commonly formed decompositionproducts. Carbon dioxide, acetate and formate have been of concern due to their potential for causing cor-rosion in the steam-condensate system and because of their masking effect on cation conductivity meas-urements. Ammonia formation is also of concern due to the increased potential for corrosion in systemswith copper alloys.

CORROSION CAUSED BY CARBON DIOXIDE AND ORGANIC ACIDS - Carbon dioxide is well known for the nu-merous acidic condensate corrosion problems it has caused in boiler systems with sodium zeolite softenedmake-up water. On a much more limited basis, there have been reports of acidic organic contamination of

boiler feedwater also causing corrosion. While not all answers are known, investigations of these reports3

,operating experiences reported by Carvalho8,9 and discussions from recent conferences have concluded thatthe priority for control of carbon dioxide and organic acid corrosion is maintaining sufficient pH throughoutthe system.10

CATION CONDUCTIVITY - Cation conductivity is widely used in the power industry to detect contamination ofcondensate, feedwater and steam. It has proven very useful for identifying the presence of anions such aschloride and sulfate in the condensate as the result of condenser tube leaks. However, it also provides anundifferentiated indication when carbon dioxide, formate and acetate are also present. Consequently, thismakes cation conductivity a less effective tool for detecting the potentially more damaging chloride andsulfate contaminants.


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Turbine manufacturers usually specify a cation conductivity limit for the turbine inlet steam of less than 0.2or 0.3 S/cm. In the absence of other contaminants, it takes 16 ppb (g/l) and 25 ppb (g/l) of chloride toproduce cation conductivity levels of 0.2 S/cm and 0.3 S/cm, respectively. Some manufacturers thatspecify chloride levels have limits of 5 ppb (5 g/l), others as low as 3 ppb (g/l). Five ppb (g/l) of chlorideproduces a cation conductivity level of approximately 0.09 S/cm when no other contaminant is present.

It can be readily seen that the specified cation conductivity limits do not assure that other limits such as

those for chloride or sulfate are met. At the same time, many personnel in cycling plants know well that car-bon dioxide contamination makes meeting cation conductivity limits on startup difficult, if not impossible.Consequently, there is a clear need for a more definitive monitoring tool, one that better quantifies theknown turbine corrodents such as chloride and sulfate.

Degassing can be used to expel carbon dioxide from the sample stream, eliminating its effect on cation con-ductivity. Therefore, degassed cation conductivity has increased sensitivity to chloride and sulfate contami-nation when carbon dioxide is present in the original sample. Consequently, this steam purity monitoringmethodology is gaining in popularity, especially in those plants in cycling service.

Turbine manufacturers have taken different positions with respect to degassed cation conductivity. Onemanufacturer limits the use of degassed cation conductivity to the commissioning period. Another manu-facturer allows higher cation conductivity if it is known to be caused by carbon dioxide.

Ion chromatography (IC) is a more direct approach to monitoring the strongly acidic anions, such as chlo-rides and sulfates, known to be of major concern. The relatively high cost of the analytical instrumentationand the personnel attention required to operate it have curtailed the popularity of this approach. 10

Although not experienced in the three previously reported case histories, filming amines have a reputationfor moving previously formed corrosion products from their original location to steam traps, instrument linesand condensate polishers where they may foul the equipment. Consequently, while the application of filmingamines is expected to result in cleaner metal surfaces and reduced corrosion, some period of clean up maybe experienced before the full benefits of filming amine application are realized.

Conclusions

Organic amines have been used for decades and continue to be used to protect steam plant equipment and

maintain reliable, efficient plant operations. Their proper use can provide increased corrosion protection notavailable through the use of inorganic chemicals alone. The authors have found that these organic treat-ments or their decomposition products have low corrosion risk as long as pH is adequately maintained

Thermal instability limits the application of organic chemicals, especially neutralizing amines in power plantapplications, because of the effect of the decomposition products on cation conductivity measurements.This effect decreases the sensitivity of cation conductivity for detecting condenser tube leaks and oftenboosts the steam cation conductivity above the steam turbine manufacturers specification.

The conundrum is that many avoid using organic chemical treatments because their use causes them toexceed the turbine manufacturers steam cation conductivity limits. Yet, meeting those limits does not as-sure that potentially acidic species, such as chloride and sulfate, are within an acceptable range. In addition,one of the most damaging potential steam contaminants, sodium hydroxide, is not detected by cation con-ductivity at all.

Improved criteria for steam purity and plant-friendly methods of monitoring those criteria are needed. Fornow, plant operators must evaluate their own specific needs, compare those needs to the information avail-able and select the treatment that is expected to provide the most value to their plant.


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References

1. Robinson, J., New Computer Modeling System Improves Condensate Treatment, Corrosion Asia, Singa-pore, September, 1994

2. Dooley, B., Anderson, B., HRSG Assessments Identify Trends in Cycle Chemistry, Thermal Transient Per-formance, Power Plant Chemistry, March, 2009

3. Denk, J., Svoboda, R., Stress Corrosion Cracking Due to Carbon Dioxide and Organic Impurities in theSteam/Water Cycle Power Plant Chemistry, July 2006

4. Crovetto, R., etal. Research Evaluation of Polyamine Chemistry for Boiler Treatment: Corrosion Protec-tion, NACE Corrosion 2011, Houston, Texas

5. Galloway, E., Filming Amines Control Corrosion in Utility Plant Condensate System, Corrosion, Volume15, August, 1959

6. White, J.P., Filming Amines Reduce Corrosion at Arkansas P&L, Power, April, 1960

7. Verib, George J., An Alternative Chemistry for Both Operational and Layup Protection of High-PressureSteam-Water Cycles Using an Organic Filming Amine, Power Plant Chemistry, 2011, 13(5)

8. Carvalho, L, etal. Cation Conductivity and Power Reliability A 20 Plant Survey, International Water

Conference, Pittsburgh, PA 20019. Carvalho, L, etal. Is Cation Conductivity Monitoring Relevant For Todays Combined Cycle Power Plant?

Yet Another Case Study Says It Is Not, IWC 06-30, International Water Conference, Pittsburgh, PA2006

10.Mathews, J. A., Challenges in Cycle Chemistry Power Plant Chemistry, May, 2009

11.Newton, Beverly, et.al., Fear and Loathing in a Combined Cycle Power Plant Ion Chromatography in aBox, International Water Conference, 2004 Pittsburgh, PA


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Appendix

Table 1a (Figure 4a)LP Evaporator Steam Drum 100 psig (700 kPa) Steam Flow = 10% of Feedwater Flow - CO2

Contamination of Feedwater - Ammonia Treatment to Feedwater pH25C of 9.2

Feedwater Blowdown Riser Steam

CO2, ppb (g/l) 3


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Table 2c (Figure 7c) HP Evaporator 1500 psig (10,500 kPa) Blowdown = 0.5% of Feedwater Flow - CO2 and ChlorideContamination of Feedwater Ammonia Feedwater Treatment Low-Level Phosphate and Caustic Treatment of the

Boiler Water

Feedwater Riser Tube Under Deposit

CO2, ppb (g/l) 20


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Table 2e (Figure 7e) HP Evaporator 1500 psig (10,500 kPa) Blowdown = 0.5% of Feedwater Flow - CO2 and ChlorideContamination of Feedwater Ammonia Feedwater Treatment Trisodiumphosphate Treatment of the Boiler Water

Feedwater Riser Tube Under Deposit

CO2, ppb (g/l) 20

do organic amines have a role in the treatment of high purity boiler feedwater?

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