Chemical Treatment Requirements for Steam and Hot Water Systems

Boilers, in one form or another, have been used for centuries to produce steam for heat and power. Today, boilers produce steam to drive electric turbines, heat buildings, and provide power for countless industrial and commercial applications. Although the steam uses may vary, the importance of maintaining the water quality in these systems remains the same. Without good water quality management, steam boilers and condensate systems are susceptible to costly operating problems and unscheduled outages.

This blog post discusses the problems water can cause in steam and hot water systems, and how these problems can be prevented or controlled by an effective water management program. We will cover the following topics:

  • Boilers and auxiliaries

  • Problems water can cause in steam systems

  • Removing dissolved oxygen

  • Deposit control methods

  • Corrosion and corrosion control

  • Steam purity and quality


Boiler design and operating characteristics play an important role in the selection of water treatment equipment, chemicals, and control ranges.

What is a boiler? A boiler is simply a heat exchanger that uses radiant heat and hot flue gases, liberated from the burning of fuel, to generate steam and hot water for heating and process loads, including power generation. In a steam plant, the boiler is best defined as a vessel for the generation and enclosing of a vapor under pressure.

A steam plant consists of three (3) essential elements — (1) a furnace to convert chemical energy to thermal energy through combustion, (2) a boiler to convert the thermal and radiant energy of combustion gases to heat content (enthalpy) of the steam through heat transfer, and (3) a prime mover to convert a portion of the heat content of the steam to mechanical energy through expansion.

A boiler system may be considered as three (3) separate sections — (1) a feed system that supplies water to the boiler, (2) the boiler itself, and (3) the steam and condensate system.

Most industrial boilers operate in the low to medium pressure range. These pressure ranges are identified arbitrarily as less than 300 psig (low) and 301 to 600 psig (medium). Many industrial boilers operate in the range of 601 to 900 psig or higher, but as working pressure increases, feedwater quality requirements become progressively more stringent, and the nature of the water treatment program must also vary. Certain industrial boilers are designed to operate in the high pressure range of 1000 to 2000 psig. Utility steam generators operate at very high pressures (above 2000 psig), or even above the critical pressure and temperature (3206.2 psig and 705.4 oF) at which steam and water weigh the same.

Industrial boilers are best categorized as either firetube or watertube.

Firetube boilers – In these units, the hot fireside gases are passed through the tubes with the water on the outside of the tubes, all of which is contained within a pressure vessel.

Wet back firetube boilers have a waterwall at the back of the boiler in the area where the combustion gases reverse direction to make a return pass through the boiler tubes. This design increases the overall heat transfer area of the boiler.

Dry back firetube boilers have refractory at the back end instead of a water wall. Internal maintenance is simplified, but refractory replacement is expensive and overheating, gouging and cracking of tube ends at the entrance to the return gas passages often cause problems.

Watertube boilers – In these boilers the water is passed through the tubes and the hot combustion gases are on the outside of the tubes.

In terms of number of units in service, firetube boilers are more common than watertube boilers. Inherent safety problems with firetube boilers sparked the further development of the watertube design. The small diameter tubes used to contain water in the watertube boiler are not stressed critically even when pressure is increased to thousands of pounds per square inch. This greatly reduced the explosion risk associated with the firetube boiler. Today, firetube boilers are limited to operating pressures of about 300 psig.

Several watertube boiler types are found in service today.

Longitudinal (Long) Drum, Straight Tube boiler generates 5,000 to 80,000 pounds of steam per hour with design pressures ranging from 160 to 325 psi. The maximum size of a longitudinal (long) drum boiler is limited because steam and water circulating in tubes from the front and back headers are connected to the steam drum in circumferential rows. The drum diameter determines the number of tubes that can be connected to the drum and limits the width and, therefore, the size of the boiler.

Cross Drum, Straight Tube boilers have the steam drum placed at right angles to the boiler tubes. This boiler could conceivably be built to any required capacity. Boilers of this type have a wide field application and have been designed from 5,000 to 525,000 pounds of steam per hour with design pressures from 160 to 1450 psi.

Bent Tube Design boilers are more commonly encountered today than the straight tube design. The bent tube design opened the door for practically unlimited size and pressure ratings for boilers. Several types of bent tube boilers have been designed for a wide variety of applications. One is the low-head bent tube multi-drum boiler that is similar to the straight inclined tube box-header boiler with a cross drum except that the tubes are directly connected to drums and better facilities are available for removal of sludge and separation of steam.

The integral furnace-type boiler uses heat-adsorbing water wall tubes instead of the firebrick previously used and these water wall tubes are incorporated in the complete boiler water circulation design.

The most popular and efficient boiler of the bent tube type has been the Stirling design. The original Stirling had two upper drums and a lower drum, but was changed to three upper drums and one lower drum later. The main advantage of the multi-drum bent tube design is its ability to produce steam of good quality where water conditions cannot be maintained within reasonable limits, and its ability to handle widely fluctuating loads.

With the development of better methods of externally treating water, it was possible to design a more efficient steam boiler design that was simpler than the four drum design. This is the two drum boiler with one drum directly over the other along with water cooled furnace walls. This is the basic design of the present high pressure, high temperature boilers used in industrial and utility power plants.

A-type boilers have two small lower drums and a larger upper steam drum. This permits efficient steam/water separation. Most steam production occurs in the center furnace wall tubes entering the steam drum.

D-type boilers are flexible units with a mud drum and steam drum stacked vertically with water wall combustion chamber plus multiple convective passes. The fire is either along the drum line or at right angles to the drum.

O-type boilers are also compact 2 drum design. Boiler tubes form an O-shape as they connect to the top and bottom drums. Because of height limitations in transportation, the units are frequently quite long. The fire is down the center of the boiler in line with the drums.

Packaged Steam Generators have become very common as the need for boilers that can be shipped and installed as a single unit has steadily grown. These are shop built, skid mounted units that contain all the accessories and appurtenances necessary for controlling the feedwater, steam and fuel. Packaged steam generators may be firetube or watertube types.

High Temperature Hot Water (HTHW) Generators for institutional, industrial and commercial heating installations have experienced lagging interest because of sophisticated system design requirements. Nevertheless, by increasing the temperature (351 to 450 o F) and pressure of hot water, and increasing the size of the generator, some advantages are gained over steam heating systems. HTHW properties are materially different from steam. It has high density, high specific heat, low viscosity and good thermal conductivity. Pressure changes have negligible effect on the density, specific heat and thermal conductivity of HTHW.

High Pressure, High Temperature Boilers for utility power applications have experienced steady increases in operating pressures from 1200 psi to 5500 psi. Superheated steam temperatures have increased from 700 o F to 1200 o F. Boiler capacities have increased from around 140,000 pounds of steam per hour to about 3,000,000 pounds of steam per hour. These increases have been necessitated by growing power requirements.

The increased costs of fuel, labor and materials have forced the introduction of more efficient boilers and turbine generator sets to supply more power at less cost. The greatest gain in thermal efficiency is obtained by superheating steam that is already at a high temperature corresponding to the saturation steam temperature for the higher pressures. Another gain in efficiency is obtained by reheating the steam.

Boiler Rating Factors

In the early days of steam power, boilers and engines were coordinated in size through knowledge that the typical steam engine required about 34 pounds of steam per horsepower-hour. A typical 100 horsepower steam engine required 3,450 pounds of steam per hour when it was operated at rated load. A terminology was created in the boiler industry to fit these facts. A 3,450 pounds per hour steam boiler was called a 100-horsepower boiler. It was sized appropriately for a 100 horsepower engine. Thirty-four and one half pounds of boiler steam per hour became know as developed boiler horsepower. The magnitude of the developed boiler horsepower was subject to the minor variations in steam and feedwater conditions common to the age.

Boiler Rating Factors

1 Boiler horsepower

Nominally 34.5 pounds of steam per hour

1 Rated boiler horsepower

10 square feet of effective heating surface (6, 8 and 12 square feet have also been used

1 Developed boiler horsepower

33, 475 Btu absorbed per hour

(34.5 lbs water X 970.3 Btu/lb

Percent rated capacity

Developed horsepower / rated horsepower

Factor of evaporation

Btu absorbed per pound of steam / 970.3

Actual evaporation

Pounds of steam generated per hour

Equivalent evaporation

Actual evaporation X factor of evaporation

Kilo Btu per hour, kB

Total Btu absorbed per hour / 1000

Meg Btu per hour, MB

Total Btu absorbed per hour / 1,000,000

Steam Drum Internals

One of the mains challenges in boiler design is to develop a unit that will produce the required amount of steam of a quality below guaranteed moisture content. A normal guarantee for steam quality is 0.5% moisture. However, this moisture is boiler water. If the boiler water contains 2,000 ppm of dissolved solids, 0.5% moisture or one half pound of boiler water per 100 pounds of steam would result in a concentration of 10 ppm solids in the steam. This means that every 1 million pounds of steam delivered by the boiler would carry along 10 pounds of solids.

Most modern generating plants demand very high steam purities with total solids entrainment well below 0.5 ppm even though boiler industry guarantees only go down to 1 ppm. To obtain this degree of purity, boiler steam drum internals must be highly efficient and maintained in proper working order. In addition, boiler water conditions must be maintained so that foaming caused by high boiler water solids concentration and alkalinity or by contaminants such as oil or grease is held to a minimum.

Two common steam separator designs are the baffle plate and corrugated separator. These are routinely used in modern steam boilers to achieve the guaranteed steam purity targets. For separation at high pressures, centrifugal units are required. Two common types of centrifugal separators are the cyclone and the turbo units.

Steam drum internals maintain steam quality and purity

Steam separators, even of the centrifugal type, are incapable of reducing silica concentration in the steam. As the silica is in the vapor form, it cannot be removed by simple steam separation. However, steam washers have been developed that show promise as a means of reducing silica in steam.

Heat Recovery Boiler Components

With firetube boiler designs, considerable heat value is lost in combustion gases discharged to the stack at elevated temperatures. For most firetube designs, superheaters and air preheaters are not practical. Economizers, used to raise boiler feedwater temperature, may be employed for some heat recovery.

Modern watertube boilers may include several components to recover added heat from combustion gases. These include superheaters, reheaters, economizers, stage heaters, and air preheaters. Substantial increases in steam generator efficiency are obtainable by the use of economizers (1% increase for each 10 o F increase in feedwater temperature) and air preheaters (2.5% efficiency increase for each 100 o F drop in exit gas temperatures). This means a 2% efficiency gain for each 100 o F increase in combustion air temperature.

Economizers usually employ cast iron or steel tube heat exchangers to preheat feedwater. Finned tubing is used to extend the heat absorbing surfaces. Cast iron is chosen where flue gas temperatures are low and acid condensation is expected. Economizers may be located integrally within the boiler setting or separately installed in the flue gas flow preceding the air preheater.

Air Heaters achieve final heat recovery from boiler flue gases. Two basic types are tubular and regenerative. Tubular air heaters consist of cast iron or steel tubes joined to tube sheets that are enclosed in a reinforced casing that have air and gas inlets/outlets. They are available in vertical and horizontal designs.

Regenerative air heaters contain rotating (2 – 3 rpm) heat storage elements that accumulate heat from flue gas and transfer it to incoming cold air. These offer large contact areas for heat transfer with little resistance to air and gas flow. Corrosion can be a problem in the low temperature gas zone with either type.


Regardless of the boiler type, water can cause problems in steam and condensate systems. These problems generally fall into one of three categories

  • Scale

  • Corrosion

  • Carryover

Scale forms in the boiler as a result of the precipitation of impurities in the boiler feedwater. The common scales found in modern steam boilers include calcium carbonate, calcium phosphate, calcium sulfate, silica and iron oxides. These scale deposits generally form in high heat transfer areas, but can also be found as loose material in the lower drum or in the steam drum below the water line.

Because most plants soften the boiler feedwater, calcium scales are less common than in the old days when feedwater contained appreciable hardness. As a result, most scale deposits contain a high percentage of iron oxides that have been returned to the boiler through the condensate system.

Corrosion is an ongoing process in steam and condensate systems. The type of corrosion, however, varies depending on the environment and the mechanism of attack.

Pitting-type attack is common on boiler metal surfaces. This is caused by dissolved oxygen in the boiler feedwater. This form of corrosion is readily identified by the numerous small pits that form on the boiler tubes and drums.

Caustic attack occurs wherever free “OH” alkalinity can concentrate in the boiler. Typically, this is at a crevice or leak where boiler water under pressure can flash to steam leaving concentrated boiler water salts behind. Caustic attack also occurs beneath accumulated corrosion products and deposits whenever “OH” alkalinity is present. In firetube boilers, caustic attack is frequently observed at the ends of the boiler tubes when refractory-backed boilers operate for extended periods at maximum output. The white hot refractory promotes steam blanketing or caustic gouging right at the rolled tube ends.

Carryover refers to the contamination of the steam with boiler water. It is caused by several conditions common to both firetube and watertube boilers.

Misting occurs when small water droplets are carried with the steam. These droplets form each time a steam bubble separates from the water surface much like the mist that forms when a carbonated soda is poured into a glass. The release of gas bubbles creates small droplets or a mist on the surface of the soda.

Foaming is a result of “bubbles” in the boiler water that cause an expansion of water volume in the boiler. Foaming is promoted by high total dissolved solids, high alkalinity, and contamination by organics like oil and grease.

Priming refers to “surging” of water in the boiler drum. This is usually related to the boiler design and operating conditions. A common cause is rapid increases in load that cause a rise in water level in the boiler.

Mechanical conditions may also promote carryover. These include maintaining too high of a water level, malfunction of steam separation equipment, and as mentioned previously, sudden load swings.

Volatile carryover is characterized by the vaporization of silica into the steam. These volatile solids can deposit downstream on steam turbine blades and other steam-using equipment.


The objective of a sound boiler water treatment program is to prevent or minimize the problems water can cause in modern steam boilers. Likewise, corrosion control in the steam condensate system is necessary to protect system piping and minimize the accumulation of iron oxides in the boiler.

Scale and deposit control begins with proper external treatment of the boiler feedwater. This includes hardness removal by softening the makeup and internal treatment of the boiler water to prevent the formation of scale on heat transfer surfaces. Various softening methods are utilized including ion exchange, reverse osmosis, and electrodialysis (EDR). High pressure boiler applications require further pretreatment of feedwater to remove hardness, alkalinity, and silica. In this case, complete demineralization of the makeup is required.

Internal treatment of the boiler water includes keeping the hardness in solution by the addition of chelants such as EDTA, or by the controlled precipitation of solids by the addition of phosphate. In addition, various polymers and sequestering agents are utilized to prevent the deposition of scale deposits on heat transfer surfaces.

Corrosion control begins by removing the dissolved oxygen from the boiler feedwater. This is best accomplished by mechanical deaeration of the feedwater in combination with the supplemental addition of a chemical oxygen scavenger such as sodium sulfite or hydrazine. Further improvements are realized by reducing the carbon dioxide potential of the steam by carbonate and bicarbonate alkalinity reduction in the boiler feedwater. Reducing the carbon dioxide (CO2) concentration in the steam decreases the tendency of carbonic acid to form in the condensate.

Carryover is primarily controlled mechanically by the use of steam separation equipment and by proper operating practice. Some forms of carryover, however, such as foaming can be minimized by controlling the free “OH” alkalinity of the boiler water and the addition of chemical antifoams.


Dissolved oxygen and carbon dioxide cause problems in boilers and condensate systems. Oxygen is the cause of pitting-type corrosion in boilers and feedwater systems. Carbon dioxide volatizes with the steam to produce carbonic acid in the condensate, which is corrosive to system metals. Removal of these gases from the boiler feedwater is necessary to control these corrosion reactions.

Oxygen enters the steam system in the makeup water. Fresh makeup typically contains 6 to 8 ppm dissolved oxygen. Additional oxygen may be drawn into the condensate from areas that are under vacuum. Oxygen present in the makeup and condensate combine to produce a corrosive mix in the boiler feedwater. Unless it is removed, it will promote oxygen pitting attack of the feedwater lines and boiler internals.

Carbon dioxide may be present in the fresh makeup, but it is primarily produced by the thermal breakdown of bicarbonate alkalinity in the boiler to produce free COgas. The CO2 is carried by the steam where it dissolves in the condensate to form carbonic acid.

Deaeration is the removal of corrosive gases, such as oxygen and carbon dioxide, from the boiler feedwater. The deaeration principle is based on two fundamental chemical laws. The first states that the solubility of a gas decreases with an increase in the temperature of the liquid. The second, Henry’s Law, says that the concentration of the dissolved gas is proportional to the partial pressure of the gas in the free space above the liquid. From this it is clear that removal of dissolved gases can be accomplished by heating the liquid and by reducing the system pressure.

Carbon dioxide can be removed from cold water by passing it through an aerator or degasifier. Degasifier columns are constructed with trays or packing to break the water into smaller droplets to enhance the removal efficiency of the dissolved gas. A flow of air is passed through the column, counter to the water flow, where it strips the CO2 from the water. The air stream is then exhausted to the atmosphere. This process can also be carried out under vacuum.


A typical deaerator consists of a deaerating section and a storage section. The deaerating section has three basic zones:

  • Inlet spray and vent condenser

  • Heating and distributing zone

  • Deaerating zone

Tray-type Deaerator

Water enters the deaerator through the upper dome and is sprayed or atomized by spray valves into an atmosphere of steam. Initial heating of the water takes place in this zone.

The water then passes onto the distribution trays for further heating. The distribution trays are designed so the water overflowing the top trays cascades to the next tray and then on to each successive tray. The water is heated to the saturation temperature of the steam in this zone. This accomplishes essentially 100% oxygen and CO2 removal.

Low pressure steam provides the “heating and scrubbing” action in the deaerator. The steam enters the deaerator through the shell side and provides a blanket of steam entirely surrounding the internal compartment. It then flows into the bottom of the deaerating compartment and upward through the deaerating tray zone. The hottest steam meets the hottest water in the lower tier of trays, which ensures optimum gas removal.

The final path of the steam passes by the vent condenser. Here the influent water is preheated and final condensation of the steam occurs. The remaining steam is exhausted, along with the non-condensable gases, to the atmosphere.

Spray-type Deaerator

The spray-type deaerator breaks the influent water flow into smaller droplets by spray nozzles instead of a series of trays. The principles of deaeration are the same, however.

Both spray and tray type deaerators utilize similar heating sections where initial feedwater heating takes place and close to 90% of the gas release occurs. This is done either by an inlet spray pipe or by spring-loaded water spray nozzles. The intimate mixing of the atomizing spray with the steam provides a high degree of scrubbing action to release the gases from the water surface.


Tray and spray type deaerators have the same basic requirements for complete removal of dissolved gases.

  • Heat the water to full saturation temperature and pressure

  • Agitate to expose maximum surface to scrubbing atmosphere

  • Vent non-condensable gases to the atmosphere

The various deaerator designs accomplish these objectives in different ways, but the basic requirements for oxygen removal remain the same. For spray deaerators, a minimum of a 50 o F increase in temperature is required to allow spray-type units to operate effectively at full load. This means that spray type deaerators operating in the range of 2 to 5 psig would require maximum inlet water temperatures of around 170 o F at all times. As a result, the effectiveness of deaeration in a spray type unit decreases as the load increases. Generally, deaerators perform poorly at loads below 25% of design rating because the heating steam requirements are not sufficient to maintain high steam flow and velocity.

Tray type deaerators use a different method for the release of the dissolved gases. Tray type deaerators are designed with as many as 24 tray tiers to permit adequate cascading and maximum surface exposure to the scrubbing action of the steam. Regardless of inlet water temperature, the same amount of water surface is exposed for gas release. As operating loads change, the ratio of surface area to water flow increases. This assures effective deaeration under all inlet water temperatures and flow conditions. For a deaerator used under varying load conditions or at high inlet water temperatures, the tray type deaerator gives the most satisfactory results over the entire operating range.


Sufficient steam flow is required to heat the water to saturation and transport the dissolved gases to the atmosphere. Excessive steam flow, however, wastes energy. How much steam is required to insure optimum dissolved gas removal at maximum efficiency?

As a general rule of thumb, the following formula is useful in calculating the vent rate of any deaerator.

Total Vent Rate, lbs/hr = Operating pressure (absolute)

Times the cubic centimeters O2 in influent

Times the capacity of the unit, lbs/hr

Divided by 200,000 (a constant)

The amount of steam required to heat the makeup and condensate to within 1 o F of the saturated steam temperature is equal to 15 to 16 percent of the total deaerator output in pounds per hour. This is normal for a unit having an average percentage of cold water makeup. The steam requirement is variable, especially if the makeup is first treated in a hot process softener or comes from an evaporator or passes through stage heaters. If superheat exists in the heating steam, less steam flow is required. The amount of steam required by the deaerator varies from 0.98 to 1.10 percent decrease in steam flow for every 20 o F rise in superheat temperature over the saturation temperature of the steam at design working pressure. This does not include the total steam requirement needed for venting, nor does it include the amount of heat that is lost from the deaerator through radiation losses.

Overall, corrosion damage caused by dissolved oxygen and carbon dioxide in boiler, turbines, process equipment and steam distribution systems is a costly problem. Complete removal of these gases by mechanical deaeration is the best method of prevention.


Steam and hot water generators are specialized heat exchangers designed to heat water to saturation temperature and pressure. Generally constructed from steel, modern boilers strive to accomplish this basic function with maximum heat transfer efficiency. This imposes increased heat flux across the boiler tube, which mandates ever increasing vigilance over the boiler water chemistry.

The quality of the water used in these units poses a threat to their continuous, reliable and safe operation. Mineral impurities may deposit on boiler surfaces, reducing the heat transfer efficiency. Dissolved gases cause corrosion of boiler metal. And impurities such as silica may adversely affect the steam purity. These potential problems, and others, must be taken into consideration when designing an effective boiler water treatment program.


Boiler deposits form as a result of the precipitation of mineral impurities present in the feedwater. These impurities include calcium and magnesium hardness, iron corrosion products and silica.

Scale deposits generally form in the areas of highest heat transfer because of the inverse solubility of many calcium salts with temperature. These deposits have an insulating property that reduce heat transfer efficiency and increase tube metal temperature. Severe deposition results in overheating type boiler failures. Typical boiler scales include calcium carbonate, calcium sulfate, calcium phosphate, iron oxide, magnesium silicate and magnesium hydroxide.

Scale deposits also contribute to boiler corrosion. Porous deposits allow the concentration of caustic soda under the deposits, resulting in caustic embrittlement of boiler metal.

Control of boiler deposits is best achieved by effective pretreatment methods for hardness and alkalinity reduction in combination with various internal treatment methods to produce boiler sludge that is non-adherent and easily removed by routine blowdown. Internal boiler treatment programs fall into two categories: either precipitating phosphate cycle or non-precipitating chelant programs.

Chelant Treatment Program

Chelants react with feedwater impurities to form soluble complexes with hardness, iron and copper. The two chemicals used for this purpose are ethylaminediaminetetraacetic acid (EDTA) and nitrilotriacetic acid (NTA). (Because of concerns over the potential carcinogenic properties of NTA it has fallen out of favor in boiler water treatment applications.) The chelant “holds on” to the complexed ion to prevent it from precipitating as a boiler deposit.

EDTA forms a more stable complex than NTA and finds application in boilers up to 1200 psig. NTA is limited to operating pressures of less than 900 psig.

Chelants must be applied to feedwaters with less than 2 ppm total hardness. The feedwater must be fully deaerated to prevent decomposition of the chelants. High hardness, aerated feedwaters substantially increase the chelant demand, and because of the higher cost of the chelant chemical, make the economics of the treatment program unfavorable.

Chelants are aggressive toward steel. The chelant solution must be fed to the boiler water line through a stainless steel injection quill into the center of the pipe ID. This gives the chemical time to complex with the feedwater impurities and become fully diluted prior to coming into contact with boiler metal. High levels of chelants will attack the feedwater piping and dissolve protective iron oxide from the boiler.

Chelant dosages are controlled either by calculating the total chelant demand of calcium, magnesium, iron, copper and aluminum in the feedwater and then injecting stoichiometric amounts to meet this demand, or by substoichiometric injection of only enough chelant to complex the calcium hardness. Excess chelant residuals in the boiler are kept to a minimum to prevent boiler corrosion. Typical free chelant residuals in the feedwater are maintained in the 1 to 2 ppm range.

Four (4) parts of Na4EDTA (as the dry salt) are required to complex 1 part of calcium hardness. Liquid solutions of chelant require a proportionately higher dosage. Because of the expense of chelants compared to phosphate-based programs, chelant treatment is only appropriate for high quality feedwaters averaging less than 2 ppm total hardness; preferably less than 1.0 ppm. EDTA must be added after the feedwater has been deaerated and any oxygen traces scavenged with catalyzed sulfite. Otherwise, EDTA reacts with dissolved oxygen. 1 ppm O2 destroys 100 ppm EDTA.

Phosphate Treatment Program

Conventional phosphate treatment utilizes inorganic phosphate, such as sodium phosphate, to react with calcium hardness to produce an insoluble salt of calcium phosphate. Excess hydroxide alkalinity (OH alkalinity) is required to promote the reaction of calcium and phosphate to form calcium hydroxyapatite Ca3(PO4)2(OH)2, a nonadherent form of calcium phosphate that is more readily removed in the boiler blowdown. Magnesium hardness also reacts with hydroxide alkalinity to form magnesium hydroxide, Mg(OH)2 , sludge. If silica is present, it is absorbed onto the magnesium hydroxide to form serpentine.

The conventional phosphate method is applicable to boilers operating up to 1000 psig. Pretreatment of the boiler feedwater for hardness reduction is recommended, but successful application of this approach has been achieved with feedwater hardness as high as 60 ppm. An excess of 20 to 40 ppm orthophosphate is maintained in the boiler water to drive the precipitation reaction to completion and guard against upsets in feedwater hardness. Hydroxide alkalinity (OH) is provided by the addition of caustic soda. Excess OH residuals of 50 to 250 ppm as OH are recommended for complete formation of hydroxyapatite and serpentine sludge.

Coordinated phosphate treatment limits the amount of free hydroxide alkalinity present in the boiler water to prevent caustic corrosion of boiler metal. The amount of OH alkalinity is controlled by the PO4 and H2O equilibrium:

PO4-3 + H2O —– HPO4-2 + OH

The sodium to phosphate ratio (Na:PO4) is maintained between 2.85:1 and 3.0:1 according to the pH versus PO4 equilibrium curve. Above the equilibrium line, free caustic soda exists with trisodium phosphate. Below the curve, no free OH alkalinity is present.

Coordinated phosphate programs are used in high pressure boilers operating in the 1000 to 1500 psig range. Demineralized feedwater is required to maintain an alkalinity-free makeup. A phosphate residual of 5 to 15 ppm PO4 is maintained in the boiler. Sodium hydroxide, disodium phosphate and trisodium phosphate are utilized to control and adjust the pH of the boiler water along the equilibrium curve. Disodium phosphate, being more acidic, depresses the boiler pH. Trisodium phosphate reacts in the boiler to produce caustic alkalinity and raise the pH. Careful monitoring and control of boiler water chemistry is required to maintain the equilibrium balance between pH and phosphate residual.

Coordinated phosphate treatment is very effective for boilers operating in the 1000 to 1500 psig range. Above 1500 psig, however, this program often results in caustic corrosion of boiler metal. This is an indirect result of phosphate hideout phenomena. If boiler water solids concentrate or dry out on the boiler surface, trisodium phosphate does not precipitate or dry out as trisodium phosphate (Na3PO4), but rather as a chemical composition of sodium hydrogen phosphate having the composition ratio of Na2.8H0.2PO4. The molar ratio of sodium to phosphate is known as the congruent ratio. As this reaction occurs, sodium hydroxide forms in the boiler water as follows:

Na3PO4 + 0.2H2O —– Na2.8H0.2PO4 + 0.2NaOH

The free caustic soda (NaOH) is then available to concentrate on the metal surfaces. This typically happens under corrosion products or within pockets of steam that prevent rinsing of concentrated solids from the tube wall.

Congruent phosphate treatment is a variation of the coordinated phosphate regime. This boiler water control method was developed to insure that hydroxide formation does not occur under hideout conditions. Here the boiler water chemistry is controlled to achieve “zero” free caustic alkalinity. The sodium to phosphate ratio is maintained between 2.3:1 and 2.6:1 via the pH versus PO4 control chart. These limits are set based on the premise that the Na to PO4 ratio in the boiler should be no greater than the congruent ratio. Under these conditions, no free sodium hydroxide should form anywhere in the boiler, thus preventing caustic attack of steel. A mixture of trisodium and disodium phophsate is used to maintain the boiler pH and phosphate levels below the 2.6:1 equilibrium curve, i.e. no free OH alkalinity.

Congruent phosphate programs find application in boilers operating in the 1500 to 2500 psig range. Demineralized feedwater is required. Typically, phosphate residuals are maintained between 2 and 5 ppm.

Equilibrium phosphate treatment allows some free hydroxide alkalinity, but the sodium to phosphate ratio is not determined by the equilibrium curve used in the coordinated and congruent phosphate methods. Here the phosphate is maintained at less than 2.4 ppm with hydroxide alkalinity kept at less than 1.0 ppm OH. In this way, the pH becomes a function of the amount of OH present, typically pH 9.3 to 9.6. The problem of phosphate hideout, common in the congruent and coordinated phosphate programs, is reported to be minimal under this control mechanism.

Summary of Phosphate Treatment Programs







20 to 40

50 to 250

Not Appl

11 to 12


5 to 25


2.85 to 3.1

9 to 10.5


2 to 5


2.3 to 2.6

8.8 to 9.4


< 2 to 4

< 1.0

Not Appl

9.3 to 9.6

Phosphate Products

Many products are available, both in powder and liquid form, to provide the required phosphate residual in the boiler. In most cases, the available phosphate in the product will be given as percent P2O5, but the specific mixture of phosphates used will not be disclosed. The P2O5 content and equivalent weights for various phosphates are presented in the following table.

Equivalent Weights of Phosphate Products

Phosphate Compound





Trisodium phosphate -12 H2O



Trisodium phosphate (anhydrous)



Disodium phosphate – 12 H2O



Disodium phosphate (anhydrous)



Monosodium phosphate – 1 H2O



Monosodium phosphate (anhydrous)



Sodium hexametaphosphate (anhydrous)

67.5 to 69.0


Sodium tripolyphosphate (anhydrous)

57.0 to 58.0





From these figures we can determine the equivalent weight of any phosphate or phosphate mixture from which the P2O5 content is known. Simply divide the equivalent weight of P2O5 (23.7) by the percentage of P2O5 in the product.

Phosphate reacts with feedwater hardness and OH alkalinity to produce hydroxyapatite, an insoluble sludge. If we write the chemical equation for hydroxyapatite as 3Ca3(PO4)2 * Ca(OH)2 and calculate the molecular weight of the compound, we see that only a little over 90% of the calcium reacts with the phosphate. The remainder combines with OH alkalinity to form calcium hydroxide. Since only 90% of the calcium hardness reacts with phosphate, the calculated amount of phosphate can be reduced by 10%.

Example: Determine the amount of disodium phosphate required to precipitate 30 ppm calcium (as Ca) to form hydroxyapatite.

Answer: 30 ppm calcium as calcium ion equals 75.0 ppm calcium as calcium carbonate, or 1.5 equivalent per million (epm). Anhydrous disodium phosphate has an equivalent weight of 47.3. Therefore, to produce hydroxyapatite, multiply the epm calcium times the equivalent weight of disodium phosphate required. The 0.90 factor reflects that only 90% of the calcium reacts with the phosphate. Completing this equation we have:

1.5 X 47.3 X 0.9 = 64 ppm disodium phosphate (anhydrous)

This is the amount of phosphate required to react with 30 ppm calcium ion. 64 ppm disodium phosphate divided by 120 equals 0.533 lbs disodium phosphate per 1000 gallons of treated water.

If we compare the calcium content expressed as calcium carbonate (75 ppm) with the amount of disodium phosphate required (64 ppm), we see that 0.85 ppm disodium phosphate is required to react with each ppm calcium expressed as calcium carbonate. Or, if we express calcium as the ion, about 2.13 ppm phosphate is required to react with each ppm of calcium.

Boiler Water Dispersants and Sludge Conditioners

Boiler phosphate and chelant treatment programs are frequently supplemented with polymer dispersants to help condition boiler sludge for removal by routine blowdown. These sludge conditioners are designed to keep the insoluble materials nonadherent, fluid, and free flowing so they do not “bake on” to heat transfer surfaces.

Many types of boiler sludge conditioners have found application in water treatment. Early products were based on naturally occurring compounds such as tannins, lignins, starch and carboxymethylcellulose (CMC). Tannins and lignins are extracts from bark and wood pulp that have demonstrated effectiveness as boiler sludge dispersants and chelants. These materials are no longer in common use having been replaced by synthetic boiler polymers that are chemically better defined.

Polyacrylate is the first synthetic polymer used in water treatment. It functions primarily as a dispersant for calcium and magnesium sludge, but is not as effective in dispersing iron as other synthetic polymers. Typical dosages are 5 to 20 ppm as active polymer.

Polymethacrylate is a close cousin to polyacrylate, but is better for iron sludge dispersion. Typical dosages are 5 to 20 ppm.

Sulfonated styrene/maleic copolymers are recent additions to the boiler polymer lineup. These products are better dispersants for iron than polyacrylate or polymethacrylate. Dosages fall into the 5 to 10 ppm range.

Sulfonated polymers are effective at lower dosages of 1 to 10 ppm. This dispersant is also effective in transporting iron through the boiler and may be used up to 1500 psig.

Other synthetic boiler polymers have been developed that claim superior performance under specific operating conditions. These include

  • phosphino/carboxylic copolymers

  • sulfonated styrene/acrylic/maleic terpolymers

  • acrylic acid/methylpropane/sulfonic acid (AMPS)

Boiler water dispersants that are used in the treatment of steam systems where the steam comes into contact with food or food products are regulated by the FDA. Boiler water dispersants approved for such use under FDA 21 CFR Sec 173.310 include:

  • Acrylic acid/2-acrylamido-2-methyl propane sulfonic acid copolymer (AMPS)

  • Poly (acrylic acid-co-hydrophosphite), sodium salt

  • Polymaleic acid

  • Sodium polyacrylate

  • Sodium polymethacrylate

  • Sodium carboxy-methylcellulose

  • Tannin

  • Sodium lignosulfonate

  • Lignosulfonic acid

  • Sodium alginate

  • Ammonium alginate

  • Sodium humate

  • Sodium acetate

  • Acrylamide-sodium acrylate resin

Typical polymer dosages are between 5 and 25 ppm as 100% active polymer. Boiler polymers are marketed as dilute solutions of these active ingredients, however, so typical product dosages are between 100 and 500 ppm.

Since boiler polymers are non-volatile, they concentrate in the boiler. Chemical tests are available for estimating the polymer residual, but the tests are difficult to perform and the accuracy is not very good. For these reasons, the dosage of polymeric sludge conditioners is frequently determined by direct calculation from steam production rates and cycles of concentration. The dosage of the polymer product is adjusted by regulating the output of the chemical pump or by boiler blowdown.


Corrosion is a reaction between a metal and its environment. In an operating boiler, several corrosion mechanisms exist that can result in rapid attack of boiler steel and significantly reduce the useful life of steam generating equipment. These include oxygen-pitting, caustic embrittlement, and hydrogen embrittlement.

Oxygen pitting attack is caused by dissolved oxygen in the boiler feedwater. This problem is readily identified by the numerous small pits that form on the metal surface. Prevention of oxygen pitting is accomplished by complete removal of the dissolved oxygen by mechanical deaeration and chemical oxygen scavengers. Common oxygen scavengers include reducing agents such as sodium sulfite and hydrazine.

The dissolved oxygen content of feedwater can be estimated from the temperature of the water and the working pressure of the deaerator. The following table presents the dissolved oxygen concentration at a given feedwater temperature and pressure.

Maximum Expected Dissolved Oxygen Level

At Listed Deaerator Temperatures and Pressures

Deaerator Working Pressure, psig

Dissolved Oxygen







































































Caustic embrittlement is caused by the concentration of caustic soda at a crevice or leak where boiler water can flash to steam leaving concentrated boiler water salts behind. If the metal is stressed, the caustic soda will cause cracking of the steel. In a metallurgical exam, the cracking is seen as between the metal grains. Caustic embrittlement is actually a misnomer. It is more accurately characterized as caustic induced stress corrosion cracking of steel.

Caustic embrittlement can be effectively controlled by sealing leaks and welding tube joints, eliminating free OH alkalinity such as in congruent phosphate programs, and in some cases adding sodium nitrate as an inhibitor.

Hydrogen embrittlement is caused by the presence of hydrogen that results from the corrosion of iron.

Fe + 2H+ —– Fe+2 + H2

The hydrogen from this reaction may penetrate steel and react with the carbon to produce methane (CH4).

Although the hydrogen can diffuse through the steel microstructure, the methane cannot. The trapped methane exerts pressure on the grain boundaries and weakens the metal. These are embrittlement failures commonly referred to as hydrogen damage or hydrogen embrittlement.

Oxygen Scavenger Dosage Calculations

Once the oxygen content of the feedwater is determined, it is possible to calculate the scavenger dosage. The sulfite dosage is the sum of the ppm needed to neutralize the dissolved oxygen plus additional amounts needed to produce acceptable boiler water residuals. For low to moderate pressures, sulfite residuals range from 20 to 50 ppm. The excess required depends on the residual desired in the boiler and the number of feedwater concentrations maintained in the boiler.

The theoretical dosage of sodium sulfite (100% purity) is 8 ppm sulfite for every 1 ppm (0.7 cc per liter) of dissolved oxygen. However, correction must be made for the activity or purity of the commercial sulfite, which is about 90%, and for the efficiency of the scavenging reaction. From a practical viewpoint, the sulfite dosage is 10 ppm per ppm of dissolved oxygen in the feedwater. Additional sulfite must then be added to produce the required sulfite residual.

Sodium Sulfite Required to Produce Residuals

of 30, 20, 10, or 5 ppm in the Boiler

(dosages in lbs per 1000 gallons)

Boiler Cycles

30 ppm

20 ppm

10 ppm

5 ppm



















































From Water Treatment for Industrial and Other Uses by Eskel Nordel, 2nd Ed. Page 266

The theoretical dosage of hydrazine (100% active) is 1 ppm per ppm of dissolved oxygen. Because of the explosive nature of pure hydrazine, it is available for industrial use in 35% active solutions. It, therefore, takes 3 ppm of 35% active hydrazine to neutralize 1 ppm of dissolved oxygen. In addition, a low residual of from 1 to 3 ppm is required in the boiler to accelerate the reduction of ferrous oxides.


High temperature hot water systems (HTHW) differ from steam boilers in that these are essentially closed systems. Hot water is circulated from the generator through the areas of heat exchange and then back to the generator. Water losses are minimal unless through unintentional leaks. Nevertheless, high temperature hot water generators are subject to corrosion damage and deposition unless steps are taken to implement an effective water treatment program.

Makeup Water Quality

The quality of the water used to fill a hot water system has an affect on the performance of the corrosion control program. Hard water poses a scaling problem in these systems. For hot water systems, the water should be softened if it exceeds 300 ppm total hardness. For high temperature hot water (HTHW) loops, consider softening the makeup water if it exceeds 10 ppm.

The natural alkalinity in raw water presents further problems in hot water systems. The bicarbonates decompose to hydroxide, which in turn elevate the pH. This promotes caustic embrittlement of steel. Use demineralized or dealkalized water if the total alkalinity exceeds 400 ppm in hot water systems, or if it is greater than 15 ppm in HTHW systems.

Overall, the water used in a hot water loop should be of the best quality available. As a general rule, demineralized is better than soft water which is better than hard water. Some engineers resist the use of demineralized water because of the notion that it is more “aggressive” or corrosive than soft water. Although it is true that untreated, aerated demineralized water is very corrosive, particularly at hot water temperatures, corrosion inhibitors such as sodium nitrite and sodium sulfite passivate metal surfaces and remove dissolved oxygen resulting in a final product water that is noncorrosive.

If the closed system experiences significant water losses, the water should be deaerated to prevent oxygen ingress into the system. Fresh makeup water contains up to 8 ppm dissolved oxygen. If oxygenated water is continuously added to a closed system, particularly at elevated temperatures, the result will be oxygen-pitting attack on mild steel. In this situation, maintenance of sufficient sulfite or nitrite residuals are required to protect the system from corrosion damage.

Chemical Treatment Options

Several chemical treatment methods have been developed for closed loop systems. The selection of one treatment method over another is determined by the water quality, system metallurgy, and any environmental or safety issues at hand.

If the heating system is new, it should be chemically cleaned prior to the start of the treatment program. Chemical cleaning removes oil, mill scale, dirt, welding fluxes and other contaminates that can interfere with the performance of the treatment program. Chemical cleaning is also recommended for older systems that have suffered from corrosion. After the system is clean, apply one of the following treatment programs.

Sodium chromate has been used successfully for years in hot water systems. Alkaline sodium chromate is an oxidizing agent and functions by forming a dense gamma oxide film on mild steel. A minimum of 300 ppm as sodium chromate is required for system protection. High temperature hot water systems and diesel engine cooling water loops require higher dosages of from 2000 to 2500 ppm.

Chromates are toxic substances and a suspected carcinogen. Because of this toxicity, the discharge of chromate has been restricted by the EPA. Chromate is also known to cause dermatitis in workers who come into prolonged contact with this chemical.

Borate-nitrite formulations provide equivalent corrosion protection to chromate. The sodium tetraborate creates a buffer in the system that stabilizes the pH between 9.0 and 9.5. A minimum of 500 ppm of sodum nitrite is required for corrosion protection of mild steel. A 1000 ppm residual as sodium nitrite is recommended in hot water systems. And for those waters that are high in chlorides and sulfates, 1500 ppm of sodium nitrite is required. A general recommendation for inhibitor levels is 800 to 1200 ppm as sodium nitrite.

Like chromates, high concentrations of nitrites are thought to attack some pump seals. The exact mechanism for this attack is unclear. The same seal may function very well in one system and poortly in another, leading one to conclude that other factors like suspended solids levels may play a greater role than inhibitor concentrations.

Borate-nitrite powders have a low solubility in water (about 3% by weight). Pre-mixed liquid formulations, although more costly, are often used for this reason.

Sodium sulfite – caustic soda programs are used in many hot water systems. The sulfite residual should be maintained between 30 and 60 ppm with sufficient caustic soda added to adjust the pH to within 9.3 to 9.5. This is an effective approach when properly applied. It is less expensive than other options and presents few disposal problems.

If the system suffers from air in leakage, the sulfite will be consumed at a rapid rate. Continued addition of more sulfite will cause the dissolved solids in the water to increase significantly.

The use of caustic soda for pH adjustment causes the water to be poorly buffered. Overfeed of caustic increases the pH above the desired 9.0 to 9.5 range. Draining the system or treatment with sulfuric acid is then required to bring the pH within range.

Hydrazine – morpholine is an all-volatile treatment approach that is very effective in high temperature hot water systems. This is particularly true where increased levels of dissolved solids pose a potential deposition problem.

Hydrazine reacts with dissolved oxygen to promote the formation of a dense, corrosion resistant magnetic iron oxide (magnetite) film on steel surfaces. Sufficient morpholine is added to adjust and maintain the pH between 9.0 and 9.5. Generally, a 50 to 200 ppm residual of hydrazine is maintained in the system to guard against oxygen ingress and to promote the maintenance of the magnetite film.

On the negative side, the pH of the water is poorly buffered by the morpholine, so overfeed situations can lead to pH’s above 9.5. Hydrazine also partially decomposes to form ammonia, which can cause accelerated corrosion of copper and other yellow metals.

Hydrazine has recently come under scrutiny as a possible carcinogen. Although it is not banned from use, many plants are seeking safer alternatives to the use of this oxygen scavenger.

Molybdates are used alone or in combination with other inhibitors in hot water systems. Molybdates are often referred to as “chromate substitutes”, since they function in a manner similar to this classic anodic inhibitor. In truth, molybdates are much weaker oxidants than chromate.

A minimum of 100 to 200 ppm of molybdate as MoO4 is required for corrosion protection. Higher dosages are required in more aggressive waters. The pH of the system should be maintained above 7.5. Enhanced protection of yellow metals can be obtained by blending molybdate with tolytriazole. Often molybdate is used in combination with nitrite to afford better protection at lower molybdate concentrations.

Molybdates are generally accepted as being less toxic than chromate. However, the EPA is looking more closely at the environmental impact of molybdates. This may eventually lead to more stringent limitations on the use and discharge of molybdate inhibitors.

Overall, proper water treatment practice is required to prevent water-related problems in steam and hot water systems. These problems include scale deposition and corrosion of boiler metal. In addition to the selection and maintenance of makeup water pretreatment schemes, the application and control of an effective chemical treatment program is required to insure the continuous, reliable and safe operation of the plant equipment.


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