Water chemistry control maintains plant health

An arsenal of diverse water treatments is necessary to fight corrosion and fouling and to avoid potentially enormous repair costs

By Brad Buecker

Burns & McDonnell

Using steam to convert energy from fossil fuels to electricity requires reliable operation from many components, most notably the steam-generating boiler and turbine. A major factor in reliable operation is proper control of boiler water and feedwater chemistry. Without this control, boilers and turbines can become fouled or corroded, resulting in enormous costs to repair damaged boiler tubes or turbine blades. Years of experience with water chemistry control has led to some proven and emerging treatment programs utility managers and engineers can use to improve plant reliability.

Ion exchange

Good chemistry control starts with the makeup system. If poor water is introduced to the boiler, even the best chemical treatment program will not eliminate fouling and tube corrosion. For boilers that operate more than 4.25 Megapascal (MPa), the most common makeup treatment is ion exchange. Figure 1 shows the simplest ion exchange arrangement.

Makeup water first passes through a granular carbon-filter bed to remove organics and oxidants such as chlorine. Organics can foul ion-exchange beds, and chlorine attacks the polymer substrate in the ion-exchange resins. The makeup then passes through a bed of cation-exchange beads where media contain millions of exchange sites with the following chemical structure:

R–SO3-H+ (R = bead material, usually polystyrene crosslinked with divynylbenzene.)

As water passes through the bed, cations such as calcium, magnesium and sodium are exchanged for hydrogen ions (H+). Because the resin contains a vast number of exchange sites, the bed is quite efficient at removing dissolved solids. The acidified effluent then passes through an anion resin bed with exchange sites identical to or quite similar to the following structure:

CH3

|

R–N–CH3+OH-

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CH3

As the water passes through the resin, impurities such as bicarbonates, chlorides, sulfates and silicates are exchanged for hydroxide ions. The hydroxide combines with the hydrogen ions introduced from the cation bed to produce water.

Eventually, the available exchange sites are exhausted. When this occurs, the demineralizer is taken out of service. Plant personnel then rinse the cation bed with a dilute acid solution (usually sulfuric, sometimes hydrochloric), then rinse the anion bed with a dilute sodium hydroxide solution. This process, known as regeneration, restores the beds to operating efficiency.

This basic cation/anion arrangement is suitable for boilers operating up to about 6.65 MPa. For higher-pressure boilers, the effluent from the cation/anion beds is usually polished in a mixed-bed vessel containing a mixture of cation and anion resin. A cation/anion/mixed-bed demineralizer can produce water suitable for use even in supercritical boilers.

Reverse osmosis

Because demineralizers often require fairly large amounts of acid and sodium hydroxide to regenerate the exchange resins, other methods of water purification are becoming popular. A rapidly emerging treatment technique is reverse osmosis (RO). In this process, high pressure forces makeup water through membranes containing microscopic pores as small as 1 angstrom. The pores allow water to diffuse through the membranes but restrict the flow of dissolved solids.

Figure 2 shows a typical RO vessel arrangement. Influent water is introduced along the pressure vessel at 1.48 MPa to 4.24 MPa. As the influent passes through the membrane spacers and along the membranes, pressure forces purified water to the center of the membrane elements. Dissolved solids rejected by the membranes collect at an intermediate point, and both streams exit the end of the pressure vessel housing. In fresh-water applications, the first RO pass will produce about half purified water and half concentrate. Because a single-pass RO rejects so much water, the concentrate is usually passed through a second RO vessel to again obtain a 50/50 split. Thus, overall purified water production is 75 percent.

Today`s RO membranes can reject up to 99 percent of incoming dissolved solids and can produce an effluent suitable for use in low-pressure boilers. RO becomes particularly attractive economically when the total dissolved solids in the makeup are more than about 150 milligrams per liter (mg/l). Depending on the flow rate needed, RO pressure vessels may be installed in multiple, parallel configurations.

When RO is used in conjunction with demineralization, several benefits are possible. RO removes contaminants without the need for regeneration. Thus, plant operators can greatly purify incoming makeup without using excessive chemicals. A demineralizer then polishes the water to high purity. Using RO to purify feed to the demineralizer drastically reduces demineralizer regeneration frequency. An RO/demineralizer arrangement is particularly suitable for high-level purification of water that contains a large amount of dissolved solids.

Condensate/feedwater treatment

In a typical fossil-fired steam plant, exhaust steam from the turbine passes through a condenser and then through a series of feedwater heaters on its return to the boiler. Plant chemists must carefully control water chemistry to prevent feedwater-component corrosion and corrosion product carryover to the boiler.

Most feedwater system corrosion is caused by dissolved gases (oxygen and carbon dioxide in particular) or by contaminant leakage from the condenser or demineralizer. Dissolved gases usually enter the system via air leaks in or around the condenser. Common locations include cracks in the expansion joint between the turbine and condenser, cracks in the condenser shell at pipe penetrations, and leaking turbine explosion diaphragms.

When dissolved gases build up in the feedwater system, several corrosion mechanisms are possible. Oxygen can cause carbon-steel pitting, which may lead to premature failures. Oxygen may also assist in the dissolution of copper from copper-bearing heat exchanger tubes, especially in the presence of ammonia. Carbon dioxide will combine with water to form carbonic acid, lowering the feedwater pH and causing general corrosion in feedwater piping.

Oxygen scavengers

Corrosion by dissolved gases can be very severe. For this reason, most feedwater systems are chemically treated to prevent such attack. Usually, plant chemists add an oxygen scavenger such as hydrazine or a hydrazine substitute for oxygen removal, and ammonia or an amine compound to adjust pH into the alkaline range.

Practical guidelines suggest that a small residual (~20 to 40 micrograms/liter) of oxygen scavenger be maintained in solution. Because feedwater is normally very pure, pH adjustment does not usually require a heavy chemical dosage. Plant chemists should maintain ammonia levels below 0.5 mg/l, because higher concentrations can cause corrosion of copper-bearing alloys, especially if some oxygen is present. For feedwater systems containing all ferrous metallurgy, the recommended feedwater pH range is 9.2 to 9.4. For systems containing mixed ferrous and copper metallurgy, the recommended pH range is 8.8 to 9.3.

Oxygenated treatment

Another feedwater treatment becoming more popular is oxygenated treatment (OT), which seems to violate the guidelines mentioned above. At a number of utilities, especially in Europe and now also in the United States, chemists deliberately introduce oxygen or hydrogen peroxide to the feedwater system in concentrations ranging from about 50 to 300 microg/l. In systems containing all ferrous metallurgy, a controlled supply of oxygen causes the normal oxide coating on the tube surface (magnetite) to be overlaid with a thin, tightly adherent layer of ferric oxide hydrate. This layer is much more dense and tightly bonding than the magnetite layer that forms in conventional oxygen scavenger programs.

A number of utilities that have switched from oxygen scavenger programs to OT programs have reported a significant decrease in dissolved iron levels in the feedwater. However, this treatment must be used with great care. It is not suitable for use in systems containing copper alloy feedwater heaters because of oxygen`s corrosive tendencies toward copper. Furthermore, water purity in oxygenated systems must be maintained at a very high level. This usually requires plant managers to equip the unit with a condensate polisher. If deposits are allowed to form in OT units, corrosion will occur under the deposits due to differential oxygen concentration cell formation. The corrosion is localized and can be extremely destructive.

Most plant operators using oxygenated treatment are doing so on once-through units, although some are applying OT to drum units. Plant operators or engineers contemplating an OT program should first consult with experts to learn the details.

Boiler water treatment

In the boiler, where conditions are harshest, corrosion can become very destructive. Therefore, water chemistry becomes extremely critical. The two major sources of boiler water contamination are corrosion product carryover from the feedwater system and introduction of impurities via condenser tube leaks. In the former case, when iron and copper feedwater corrosion products reach the boiler, they leave deposits on the boiler tubes, usually in the high-heat areas. Not only do these deposits reduce heat transfer, but they can also cause underdeposit or galvanic corrosion. Because the corrosion is often localized, premature tube failures may result. Proper feedwater treatment, as discussed previously, minimizes these problems.

Contaminants introduced to the boiler water via condenser tube leaks can be more serious. Because a condenser usually contains thousands of tubes, leaks will occasionally develop. Often, a leak will occur where the tube is rolled into the tubesheet. Sometimes, upper tube steam erosion will cause leaks. Whatever the cause, a leaking tube allows impure cooling water to enter the condensate. The principal contaminants–calcium, magnesium, silica and bicarbonate–will react under the high temperatures in the boiler to produce very undesirable compounds. The following equations illustrate two of these typical reactions.

Ca++ + 2HCO3- + heat Æ CaCO3Ø + CO2 + H2O

Mg++ + 2Cl- + 2H2O Æ Mg(OH)2Ø + 2HCl

As the equations illustrate, the reactions of impurities in the boiler water can create compounds that form scale (such as calcium carbonate or products that drastically affect water pH, such as HCl. Boiler tube failures or other problems have been known to occur within days, sometimes hours, after a severe condenser tube leak. The author once observed a condition where a condenser tube leak caused a drop in boiler water pH from 9.2 to 5.8 in 45 minutes. In another instance, a condenser tube leak so fouled the boiler water that contaminants in large proportions were carried over with the steam. Before the situation could be corrected, the entire turbine became coated with salt deposits.1

Because contaminant in-leakage to a boiler can never be entirely prevented, operators must carefully treat boiler water to mitigate the effects of contamination. Sodium phosphate compounds are the most popular treatment for sub-critical boilers (greater than 22.09 MPa). Adding tri-sodium phosphate to boiler water serves two distinct purposes. First, tri-sodium phosphate is an alkaline compound that raises boiler-water pH to minimize corrosion. Second, the phosphate ion, or the alkalinity produced by it, reacts with impurities such as calcium, magnesium and silica to form soft precipitates, removable via boiler blowdown. Plant chemists sometimes supplement phosphate programs with organic chelants to help hold iron and other contaminants in solution.

Tri-sodium phosphate will react with water to produce free hydroxide, which can concentrate underneath tube deposits and cause caustic corrosion. Thus, chemists usually operate phosphate treatment programs on a coordinated or congruent basis. In these applications, adding di-sodium phosphate to the system maintains the solution`s sodium-to-phosphate molar ratio below 3:1. Figure 3 shows the recommended guidelines for a coordinated phosphate program. Maintaining sodium phosphate ratios between 2.3 and 2.8 causes the water to remain alkaline but keeps bulk hydroxide concentrations low enough to prevent underdeposit caustic attack.

In boilers operating at more than 13.9 MPa, a phenomenon known as phosphate hideout may occur. Sodium phosphates, like the scale-forming compounds they are designed to minimize, exhibit retrograde solubility. They become less soluble at higher temperatures. In high-pressure boilers, the heat flux at higher loads is so great that sodium phosphate will precipitate on the tube walls. The sodium-to-phosphate ratio in this precipitate is usually lower than that in the bulk water. Thus, as the boiler comes up in load, sodium phosphate begins to precipitate, leaving the remaining chemical in solution with a sodium phosphate ratio greater than 3:1. The boiler water pH then increases. The chemist may then add di-sodium phosphate to correct the pH, but much of it may hide out as well. When boiler load is reduced, the precipitated phosphate redissolves and drives the pH downward. Water chemistry can fluctuate rather severely in boilers that suffer from phosphate hideout.

For this reason, some chemists at high-pressure stations have switched to an equilibrium phosphate treatment program. In this program, phosphate levels in the boiler water are kept below 1 to 2 ppm, and sodium hydroxide is used to adjust the pH. The advantage of this program is that it minimizes or prevents hideout. A major drawback is that phosphate is quickly consumed when contaminants leak into the boiler.

Phosphate treatment is not possible for once-through units because the boiler water does not circulate through the waterwall tubes to a drum and then back again. These units must operate on all-volatile treatment (AVT). In an AVT program, the alkalinity of the feedwater and boiler water is maintained solely by ammonia or amine, which volatilizes with the steam. Because the boiler water contains no contaminant removal compounds such as phosphate, makeup water purity must remain at very high levels. It is an imperative that any such unit be equipped with a condensate polisher to remove any contaminants entering the condensate system long before they can cause problems in the boiler.

Conclusions

Many factors go into a good utility chemistry program. Concepts presented here are only an overview. Other critical areas include proper water/steam chemistry monitoring, solids control in the boiler to prevent contaminant carryover to the turbine, and procedures to take in the event of a chemistry upset.

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Multiple reverse osmosis pressure vessels in parallel.

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References

1. E. Loper, C. Trantham, T. Gunn, and B. Buecker, “On-Line Water Chemistry Monitoring: A Valuable Tool When Integrated Into Plant Operation,” Power Engineering, Vol. 98, No. 10, October 1994.

AUTHOR

Brad Buecker is a senior water chemist for Burns & McDonnell. Formerly an analytical chemist and project engineer for City Water, Light & Power, Springfield, Ill., USA, Buecker holds a bachelor`s degree in chemistry from Iowa Sate University.