Chemical Treatment Requirements for Condensate Systems

Corrosion damage in steam-condensing equipment and systems that collect, return and store condensate for reuse as boiler feedwater is a continuing problem at industrial plants, government installations, institutions, hotel, office and commercial buildings. Power engineers long have recognized that steam condensate is corrosive to iron and steel piping systems, and will attack many non-ferrous alloys as well.

Material costs and labor for replacement of corroded piping or repair of damaged equipment are appreciable and growing. Where condensate lines are buried in concrete floors or installed in walls of permanent structures, replacement costs will be far greater than those of the original construction. Failure of corroded condensate piping not only damages building and equipment, but also may cause finished product losses. Interruption of steam service to repair corrosion damage causes inconvenience, lost time and production losses; shutdown of major equipment may be required during repairs.

Corrosion products carried back to boilers in condensate returns may deposit on steam generating surfaces causing over-heating failures or localized corrosion of boiler tubes. Buildup of metal oxides in condensate systems fouls traps, strainers and piping, reducing flow capacity and increasing pumping costs.

The growing demands for steam to be used in absorption air conditioning, process and humidification systems have intensified corrosion problems previously related to heating seasons. Repair of damage caused by condensate system corrosion no longer can be handled as a summer maintenance project. Instead, engineers responsible for steam plant operation and building maintenance now must recognize the need for year around corrosion control programs and improved procedures for monitoring corrosion in critical steam/condensate systems.

Origins of Corrosion Agents – Carbon dioxide and Oxygen

Carbon dioxide (CO2) and oxygen are the main corrosive agents in steam. Carbon dioxide dissolves in condensate to form corrosive carbonic acid. This, in turn, lowers the condensate pH and makes it corrosive to steel and other metals.

H2O + CO2 —– H2CO3

Dissolved oxygen also is corrosive to system metals, and when present along with CO2 in the system, greatly intensifies the corrosion activity of carbonic acid. Mechanical factors of the system design and operation also contribute to condensate system problems. This must be considered in the overall corrosion control program.

Much of the oxygen in steam enters the boiler in poorly deaerated feedwater. Deaerators may be operated with inadequate steam supply, at temperatures well below those needed for effective oxygen removal, or experience mechanical problems and malfunctions. This includes faulty venting of non-condensable gases. Oxygen enters the deaerator both in makeup water and in returning condensate. Gravity and vacuum return systems may draw in air at receiver vents, radiator relief valves, at vacuum pump packing glands, around valve stems, and similar in-leakage points. Even deaerators and deaerating heaters may create partial vacuums that draw in air. This occurs in the event of steam supply failure or a drop in steam pressure under light load conditions. Process heat coils, dryers and sterilizers equipped with air relief vents will draw in air when the heating cycle is interrupted and partial vacuums are created by condensation.

The internal use of chemical oxygen scavengers (sodium sulfite and hydrazine) in boiler water should neutralize most of the dissolved oxygen that is not removed by feedwater deaeration. But the fact remains that some oxygen still is released from the boiler in steam and dissolved in condensate to cause corrosion. More oxygen is added to condensate by the various in-leakage sources mentioned earlier.

The major source of carbon dioxide in steam is the natural carbonate-bicarbonate alkalinity of boiler makeup water. Although small amounts of dissolved carbon dioxide gas are naturally present in many water supplies, the bicarbonate alkalinity is a far greater source of CO2. Alkaline salts such as calcium and magnesium bicarbonate in feedwater readily decompose at boiler temperatures, liberating carbon dioxide into the steam.

HCO3 + heat —– CO2 + OH

The addition of soda ash (Na2CO3) to feedwater also increases the CO2 potential of the steam. About 80% of the soda ash dissociates at boiler pressures of 100 to 200 psig to release CO2 and hydroxide alkalinity. The decomposition reactions of carbonate alkalinity and sodium carbonate (soda ash) are as follows:

CO3-2 + H2O —– CO2 + 2(OH)

Na2CO3 + H2O —– CO2 + 2NaOH

The carbon dioxide potential of the steam is increased by sodium zeolite softening of the makeup water. This process removes calcium and magnesium hardness from the raw water, converting calcium and magnesium bicarbonates into sodium bicarbonate. This sodium salt completely decomposes in the boiler to release CO2. The CO2 released from 100 ppm carbonate alkalinity is about 35 ppm as CO2. The total CO2 produced by 100 ppm sodium bicarbonate is much higher – about 79 ppm as CO2.

Reducing the Carbon Dioxide Potential of Steam

All pretreatment methods that reduce the carbonate and bicarbonate alkalinity of the makeup water will reduce the CO2 release from the boiler feedwater during steam generation. Pretreatment processes such as lime or lime-soda ash softening (cold or hot), reverse osmosis, demineralization, or split stream ion exchange all reduce makeup water alkalinity and simplify corrosion control in return condensate systems. The sodium zeolite softening process does not reduce the carbonate – bicarbonate alkalinity of the makeup water. This tends to aggravate condensate system corrosion problems rather than relieve them.

Characteristic Forms of Corrosion – Nature and Identification

Carbonic acid corrosion usually shows up in the form of distinct channeling or “grooving” along the lower sides of condensate lines and extending up the pipe walls to the average condensate depth. Sometimes the groove will be almost as uniform as if it had been machined. It may cause uniform thinning of pipe walls when lines run full of condensate. Attack usually penetrates and shows up first in the thinnest, most highly stressed, parts of pipe fittings such as short nipples, threaded ends of joints, unions and elbows.

Corrosion products are usually absent at the attack location, but may appear downstream. The iron is dissolved, forming ferrous bicarbonate, which stays in solution initially then decomposes to release CO2 and reacts with dissolved oxygen to form various types of iron oxides.

Iron reacts with carbonic acid to form ferrous bicarbonate and hydrogen gas.

Fe + 2H2CO3 —– Fe(HCO3)2 + H2

(Ferrous bicarbonate)

Ferrous bicarbonate decomposes to form ferrous oxide and releases carbon dioxide gas.

Fe(HCO3)2 —– FeO + 2CO2 + H2O

(Ferrous oxide)

Ferrous bicarbonate reacts with oxygen to form ferric oxide and releases more carbon dioxide gas.

4(Fe(HCO3)2 + O2 —– 2Fe2O3 + 8CO2 + 4H2O

(Ferric oxide)

Other compounds found in condensate system deposits include magnetic iron oxide (magnetite) and ferrous carbonate (FeCO3). Note that decomposition of the iron bicarbonate and its reactions with oxygen both release CO2, which is then free to redissolve in the condensate and start the corrosion cycle again. The iron bicarbonate also raises the condensate pH by virtue of tying up carbonic acid. This often leads to a false sense of security when only pH tests are used for condensate monitoring. The condensate from active corrosion areas often show pH within the desired range because of the presence of dissolved iron bicarbonate. If the condensate had been tested for dissolved iron or had corrosion coupons been installed in the system, they would have shown serious corrosion in progress.

Dissolved oxygen attack appears as irregular, scattered pitting usually accompanied by oxide deposits or “tubercles” near the corrosion location. But if both oxygen and carbonic acid are in the condensate, the oxygen corrosion products may stay in solution until carried further downstream. The combined effects of oxygen and carbonic acid show up as irregular pitting joined together by carbonic acid grooves to form a continuous but irregular flow pattern. This is called combined pitting and grooving or sometimes “worming.” Since dissolved oxygen increases the reaction rate between carbonic acid and iron, the combined attack proceeds more rapidly than that caused by either corroding substance working alone.

Other corrosion types encountered in return line systems include impingement or wire drawing. Here wet steam or corrosive condensate contacts metal surfaces at high velocity, causing erosive loss of protective oxides and inhibitor films. This action continually exposes fresh metal to attack. This can occur at elbows and pipe bends carrying high velocity wet steam (turbine exhaust lines, for example) or where steam traps discharge into larger return lines.

Steam collapse, causing cavitation effects, also occurs where high pressure traps discharge into low pressure, colder return lines. The resulting shock forces strip away oxide layers and inhibitor films, causing severe localized attack.

Most probable locations for concentrated corrosion attack are inside space heater tubes, in process heating coils, dryer rolls, etc. Where steam condenses continuously the attack shows up as thinning in the constantly wetted sections. Just downstream from condensing units the attack is likely to be severe in condensate lines and fittings. Poorly drained condensate lines that “pool” condensate or run continuously at a steady liquid level will develop “grooving” problems, particularly in areas subject to oxygen in-leakage. Other trouble spots are found near remote ends of large low-pressure heating systems where CO2 tends to build up in the remaining steam.

Influence of Flow Rates, Concentration and Solution Rate

Since carbonic acid attack is proportional to the pounds of acid contacting the metal surface in a given period, both the amount of carbon dioxide in solution and the condensate flow rate control the corrosion rate. In oxygen attack, the corrosion rate mainly is a function of oxygen concentration.

Not all of the carbon dioxide in steam goes into solution immediately when the steam condenses. At the entrance to a steam condensing system, the amount of carbon dioxide may only be a small fraction of the total vapor. As the steam condenses, however, the percentage of carbon dioxide in the remaining vapor increases and more will go into solution. This explains why severe carbonic acid attack often occurs near remote ends of heating systems or in isolated condensing units that operate intermittently even though carbon dioxide content of the steam leaving the boiler is low. When steam condensation begins, the first condensate contains little dissolved carbon dioxide, since the initial partial pressure of CO2 in the steam is low. The remaining carbon dioxide accumulates in the vapor phase. With continued steam condensation, the equilibrium content of the accumulated vapor may be several hundred times the concentration of carbon dioxide in the steam leaving the boiler or dissolved in discharged condensate.

When incoming steam is shut off, pressure drops as the unit or system cools. Accumulated carbon dioxide dissolves into the residual condensate causing the pH to drop sharply and accelerating corrosion. Proper drainage from intermittently operated condensing units is vital. Continuous venting with positive pressures in such units also helps reduce damaging accumulations of carbonic acid.

Sampling and Testing Condensate Samples

Condensate samples should be taken from systems in continuous use, and as close as possible to the point of condensation. For example, a sampling connection immediately downstream from the trap serving a large space heater or process heating coil is an excellent location. It is important to sample freshly-form condensate rather than the condensate mixture accumulated in receiver tanks. The condensate taken from close to the condensing unit will be representative of the most serious corrosion potential to be expected and should have the highest CO2 content and lowest pH. If we wait until this aggressive condensate has returned to the receiver, the condensate tests may be misleading. This is because of corrosion reactions that occur in the return system, the formation of iron bicarbonate and other corrosion products, and the resulting alteration of condensate pH plus carbonic acid and iron concentrations.

In addition to sampling and testing condensate, methods are needed for monitoring system corrosion rates. It is desirable to employ test specimens or sections that will furnish visual indications as to type, location and severity of corrosion attack. Corrosion test specimens also must be properly installed in steadily flowing condensate lines so as to be continuously immersed in condensate. In some cases a drop leg is needed to keep the specimen immersed. A bypass line with proper shutoff valves and unions may also be needed so specimens can be inserted and removed without having to close down the system.

Corrosion coupons are widely used for measuring the corrosion rate in condensate systems. While acceptable for corrosion weight loss measurements and indications of penetration rates, they give little or no indication as to the nature of attack in the system other than pitting. The weighed coupons are inserted into the condensate system by means of a pipe plug drilled to accommodate a short section of phenolic rod. This rod acts as an insulating mounting for the coupon. The piping arrangement for the corrosion coupon must be arranged to provide continuous immersion during the scheduled period of test.

Regular sampling and testing of condensate for dissolved metals such as iron and copper is an effective means for monitoring the corrosion activity in the system. For these tests, samples collected at condensate receivers are acceptable, since they should show the maximum amount of iron and copper corrosion products returning to the boilers. They also give an indication as to how much return line plugging can be expected from iron oxide and other corrosion product deposits.

Corrosion Inhibitors

Corrosion inhibitors added to the boiler or steam header will aid in reducing corrosion caused by carbonic acid and dissolved oxygen in the condensate. Two general classes of amines are used for condensate system protection – neutralizing amines and filming amines.

Neutralizing amines volatilize with the steam and condense with the steam condensate. Here they neutralize carbonic acid and raise condensate pH.

Commonly used neutralizing amines include morpholine, cyclohexylamine and diethylaminoethanol (DEAE). Other, chemically similar, amine compounds are also used. In some cases, mixtures or blends of neutralizing amines have advantages when dealing with large steam/condensate systems using both high pressure and reduced pressure steam, or those including turbines and low pressure steam heating loads. Ammonia is used as a neutralizing agent for carbonic acid also, but generally is restricted to large all-iron systems because of its corrosivity to copper alloys when oxygen is present.

The dosages of neutralizing amines are based on the CO2 content of the steam. Since these inhibitors function only by neutralizing carbonic acid, they must be added in proportion to the average CO2 level in the steam as estimated from the carbonate-bicarbonate alkalinity of the feedwater. If concentrated (100% active) amines were practical, it would take about 2 ppm of amine to neutralize one ppm of dissolved CO2 in the condensate. For practical reasons, amine solutions of 20 to 40% are used. They are easier to handle and are non-flammable at these concentrations. With the 20% to 40% strength amines, it takes from 5 to 10 ppm to neutralize each ppm of CO2 in the condensate. In addition to the amounts needed to neutralize dissolved CO2, small extra dosages are added to raise the pH of the treated condensate to the usual operating range of pH 7.5 to 8.5.

After the initial starting dosage is determined, further adjustments in amine dosages are made to accomplish the treatment objectives.

  • pH adjustment to get the pH up to at least 7.0 at the discharges of all steam-condensing units and within the desired range elsewhere through the return system

  • To keep the dissolved iron and copper at very low levels, i.e. well below 0.1 ppm

  • To maintain low corrosion rates on corrosion coupons installed in steam condensing and return systems.

The criteria by which specific amines are selected to accomplish these objectives are determined by several factors. Among these is the CO2 potential of the feedwater, the presence or absence of dissolved oxygen, the pressure and temperature relationships in steam-using and return systems, and the overall economics.

Since the only function of neutralizing amines is to neutralize carbonic acid in condensate, they have no utility in preventing oxygen corrosion. Also, they must be used in stoichiometric amounts; that is, the dosage goes up in proportion to the carbonic acid concentration. Consequently, neutralizing amines would not be an acceptable choice when the CO2 potential of the feedwater is very high and dissolved oxygen is a problem. Simple economics may rule out neutralizing amine use when the feedwater alkalinity is high.

Distribution ratios characteristics of neutralizing amines also introduce an important consideration. The distribution ratio determines the concentration of amine required in the steam to get one ppm dissolved in the condensate. This characteristic differs widely for morpholine, cyclohexylamine and diethylaminoethanol (DEAE). For cyclohexylamine about 4 to 5 ppm are needed in steam to get one ppm dissolved in the condensate. DEAE is more efficient, having a steam/condensate distribution ratio of about 2. Morpholine has the lowest distribution ratio of about 0.4. This indicates the highest tendency to dissolve in first-formed condensate.

Cyclohexylamine is very effective in protecting low pressure and reduced pressure steam systems and their condensate return lines. It reaches remote ends of the system, which morpholine cannot do because of its low distribution ratio. DEAE is intermediate in distribution ratio and solubility between morpholine and cyclohexylamine, indicating utility in protection of mixed pressure systems with some high pressure steam use along with reduced pressure heating steam demand.

In summary, morpholine is the most effective in condensate systems where pressures average at least 50 psig or above. Cyclohexylamine is the material of choice for systems operating at pressures below 50 psig, especially those including reduced pressure steam heating systems. DEAE falls between these two extremes in characteristics, so should be useful for mixed-pressure systems with both high pressure and low pressure steam and return systems.

Filming amines offer an alternative approach to condensate system protection. A filming inhibitor does not neutralize carbon dioxide; instead it establishes a non-wettable, absorbed film on the metal surface. This wax-like protection provides a barrier between the metal and the condensate. Dosages required are low at 1 to 3 ppm and are substantially independent of the concentration of carbon dioxide and dissolved oxygen. In contrast to neutralizing amines, filming amines prevent attack by both carbon dioxide and dissolved oxygen.

The dosages of filming amine products are adjusted to produce an amine residual of 0.1 to 0.5 ppm in the returned condensate. (They have little effect on condensate pH, so they are not regulated on the basis of pH control. As with neutralizing amines, the objective is the same, to keep the corrosion rates low as measured by coupons testers and to keep iron and copper concentrations as low as possible.

Field experience and laboratory studies show that boiler water carryover destroys octadecylamine protective films. The sulfate ion is particularly critical. As little as 8 ppm sulfate is sufficient to nullify the value of the inhibitor. Oil contamination also reduces the effectiveness of octadecylamine performance. Therefore, precautions to minimize carryover and keep oil out of the steam system are essential to accomplishing effective corrosion control with filming amines.

A useful characteristic of the filming inhibitors is their ability to displace corrosion deposits and fouling layers of all types. When starting filming amine treatment in an old, corroded system, initial concentrations should be well below the desired final level. Raise the dosages very gradually to help minimize plugging of traps, strainers, etc caused by too-rapid removal of corrosion products and other foulants.

The removal of fouling layers naturally improves heat transfer efficiency at condensing surfaces. In addition to the elimination of fouling factors, octadecylamine and other filming inhibitors improve heat transfer by promoting drop wise condensation of steam and better runoff of condensate. In many large paper mills, marked improvement in drum drier heat transfer efficiency can be obtained by filming amine use.

Overall, filming amines should be used where oxygen corrosion is the major problem and where high CO2 potential of the boiler feedwater rules out neutralizing amines from economic considerations.

FDA, USDA and OSHA Restrictions on the Use of Amines

The toxicity aspects of steam system corrosion inhibitors suggest than in concentrated solution both morpholine and cyclohexylamine are strongly alkaline and are classed as toxic or hazardous chemicals under provisions of the Occupational Safety and Health Act of 1970 (OSHA) or the Hazardous Substances Act. They are rated toxic if ingested and exhibit irritant and caustic effects when brought in contact with the lungs, skin or eyes. In the 20% to 40% dilutions commonly marketed for industrial water treatment use, toxicity aspects are considerably diminished. However, contact with the eyes or excessive skin contact must be avoided.

Commercially available dilutions of neutralizing amines usually have no flash point or flash points that are well below the minimum of OSHA “flammable” category. Emulsions of octadecylamine generally are non-flammable.

Morpholine was assigned a Threshold Limit Value (TLV) for vapor toxicity of 20 ppm by volume (70 mg/cu meter by weight) at the 1968 meeting of American Conference of Government Industrial Hygienists in St. Louis. For cyclohexylamine vapor, the maximum allowable concentration is usually accepted at 10 ppm by volume.

The possibility of accidental poisoning from either amine is remote because of their strong, unpleasant (fishy) odors and bitter taste. However, because of the alkaline, irritant nature of these amines to the skin on prolonged contact and the possibility of eye damage in case of contact with strong solutions, appropriate safety precautions must be taken when handling the concentrates or making solutions. Protective gloves and goggles or face shield are recommended to prevent skin or eye exposure. Likewise, adequate ventilation should be provided in areas where strong solutions are handles or in case of accidental spills.

Steam humidification – The use of neutralizing amines for steam treatment and other volatile boiler chemicals is limited and controlled as regulated by OSHA Title 29 Code of Federal Regulations Section 1910.1000. This regulation controls an employee’s exposure to neutralizing amines and other air contaminants.

Food preparation – The listed neutralizing amines and octadecylamine are authorized for use in the production of steam in food process. This applies to plants and installations where steam contacts food products within the dosage limits set by the FDA and published in Food Additive Regulations, 21 CFR Subpart D Section 173.310. Authorized food industry applications include the manufacture of paper and paperboard used for food packaging.

The authorizations for use of filming and neutralizing amines in Federally-inspected meat, poultry and egg-processing establishments are obtained through the USDA. These authorizations require that all constituents must be included in Food Additives Regulations 21 CFR Subpart D Section 173.310 covering boiler water additives.

Fluid milk processing – Use of amine products in dairy and fluid milk processing operations is prohibited by FDA. This use is specifically excepted in Boiler Water Additives Section 21 CFR Subpart D Section 173.310..

Autoclaving – The use of steam treated with octadecylamine has been approved by FDA for autoclaving of surgical instruments and gauze in hospitals and drug establishments at limits specified in the regulations. Steam treated with neutralizing amines is also acceptable.


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