CONTENTS PAGES TYPES OF SCALES ...1 Introduction... 1 Carbonates... 9 Silica...12 Sulfates...14 Iron Scales... 15
Causes of Boiler Scales and Deposits...18
PREVENTING DAMAGE BY SCALE...19
Softening ... 19
Oxygen Removal...20
Effects of Dissolved Oxygen...20
Mechanical Deaeration... 21
Chemical Oxygen Removal...25
Polymers, Chelants, and Inhibitors...33
Polymers ...33 Chelants ...34 Inhibitors...35 Blowdown ... 36 Cleaning Boilers...38 Alkaline Cleaning ...39 Acid Cleaning ...40 Chelant Cleaning...41 GLOSSARY ...42
TYPES OF SCALES Introduction
The use of boilers in the petroleum industry has diminished over the years, but many are still used. Boilers are no longer used on drilling rigs, but they are used in gas processing and refining. Steam generators are used for thermal stimulation in the production of shallow, heavy oil deposits. The composition of boiler feed water and quality in relation to boiler operation have been studied for 150 years. Much of the knowledge we apply to oil field water treating was developed in connection with the improvement of boiler safety.
The purpose of boiler water treatment is to prevent the formation of scales and deposits, prevent corrosion in boiler and steam systems, and to maintain steam purity (Figure 1).
FIGURE 1. Objectives of Boiler Feed Water Treatment
Boiler water treatment can be divided into two classes: external and internal. External
treatment is that which is applied to the water before it enters the boiler and consists of
suspended solids removal, dissolved gas removal, and softening. Internal treatment is that which is added to the boiler itself such as chelants, polymers, buffers, caustic, and inhibitors. The purity of boiler water, thus, the extent of treatment required, increases as the working
To avoid:
•
Scale•
Deposition•
Corrosion•
Steam Contamination•
Overheating•
EmbrittlementFIGURE 2. Types of Treatment and Classes of Boilers
A simplified diagram of a typical boiler is shown in Figure 3. Only power boilers have
superheaters, and not all boilers have natural circulation (or convective circulation). The
drawing in Figure 3 serves as orientation for the topics to follow. We will not discuss steam generators very much because they are not used extensively in Saudi Aramco. An oil field steam generator has the general configuration shown in Figure 4. It is a once-through steam-making device and typically makes 80% quality (80% steam, 20% water) steam.
External treatment: Applied before water enters the boiler (suspended solids, dissolved gas, softening)
Internal treatment: Applied to boiler itself (chelants, polymers, buffers, caustic, inhibitors)
Low pressure: <200 psig Intermediate pressure: >200<500 psig High pressure: >500<2000 psig
Although the objectives of boiler water treatment are threefold, we will concentrate on the prevention of scale in boilers. Corrosion will be discussed where a scale is involved. Boiler scaling is very serious. It accounts for about 40% of all boiler failures. Combustion temperatures are over 3000 °F. Boiler tubes fail if their temperature exceeds 900 °F. Therefore, heat transfer through the tube is the only way for a boiler tube to survive.
If scale forms in a tube, heat transfer is impaired, and the tube temperature may rise above 900 °F and fail. The thermal conductivity of scale is only 5% that of steel. The higher the heat transfer, the less scale a boiler can tolerate (Figure 5). A tube with a heat input of 10,000 BTU/ft2/hr can tolerate 0.1 inches of scale since the temperature drop across the scale will be only 111 °F. However, if the heat input is 100,000 BTU/ft2/hr, the temperature drop across
0.1 inch of scale is 1110 °F. The tube will suffer creep (expand) and eventually fail.
FIGURE 5. Effect of Heat Transfer on ∆T Across 0.1 Inches of Scale
Besides insulating tube walls, scales and deposits roughen surfaces. The rough surfaces increase the drag coefficient, decreasing water circulation. Lower water circulation causes premature steaming with resultant overheating. Even sodium salts can deposit under these conditions. Hydrogen embrittlement of boiler tubes occurs only when scales are present, usually in high pressure boilers. Hydrogen from corrosion accumulates under scales where it permeates the tube wall, causing hydrogen embrittlement. The resulting spectacular failures are caused by intergranular cracking of the tube.
Three distinctive kinds of scales (Figure 6) are found in boilers:
•
Scales•
Deposits•
Soluble saltsScales are formed by salts that have retrograde solubility, such as salts whose solubility decreases with temperature. Some salts of calcium, silicon, aluminum, iron, and sodium have retrograde solubilities. This gives boiler deposits a wide spectrum of compositions.
Scale Thickness (inch) Heat Input
(BTU/ft2/hr) (°F)T,Scale
0.1 10,000 111
FIGURE 6. Three Kinds of Scales in Boilers
Deposits are solids carried by the boiler water that become baked in place on a solid surface. They attach to the solid surface because of their electrical charge. Oil contamination in boiler water can cause deposition of suspended solids. Iron oxides and silicates are common components of sludges. Draining a hot boiler contributes to deposits by leaving suspended solids behind where they become baked in place.
Soluble salts deposit when a boiler tube superheats, that is, steam covers the internal surface. They also result from the carryover of boiler water into the superheater. There the water evaporates, leaving a deposit of soluble salts. Soluble salt deposition in superheaters occurs whenever the solids content of steam exceeds 300 ppb (parts per billion).
The variety of scale constituents found in boilers can be seen in Figure 7. The most common boiler scale is calcium carbonate. The calcium carbonate scale is seldom pure and usually contains iron, silica, and magnesium. Besides water quality, the composition of boiler scales depends on such factors as firing rate, condition of the boiler, and blowdown rate. Two
FIGURE 7. Crystalline Scale Deposits NOTE: From Betz Handbook, 1967.
Some specifications for boiler feed water and boiler water are given in Figure 8. The specifications for feed water and boiler water are not the same because the dissolved solids are concentrated in the boiler. The boiler water specifications are given for blowdown and internal treatment control. If the silica or specific conductance (TDS) are exceeded, some blowdown is discharged. Components in the feed water guidelines are those that might deposit before the specifications for the boiler water are exceeded.
Name Formula Acmite Na2O • Fe2O3 • 4SiO2 Analcite Na2O • Al2O3 • 4SiO2 • 2H2O Anhydrite CaSO4 Argonite CaCO3 Brucite Mg(OH)2 Calcite CaCO3
Cancrinite 4Na2O • CaO • 4Al2O3 • 2CO2 • 9SiO2 • 3H2O
Hematite Fe2O3
Hydroxyapatite Ca10(OH)2(PO4)6
Magnetite Fe3O4
Noselite 4Na2O • 3Al2O3 • 6 SiO2 • SO4
Pectolite Na2O • 4CaO • 6SiO2 • H2O
Quartz SiO2
Serpentine 3MgO • 2SiO2 • 2H2O
Thenardite Na2SO4
Wollastonite CaSiO3
Drum Feed Water Boiler Water Pressure
(psig) Iron(ppm) Copper(ppm) TotalHardness (ppm CaCO3) Silica (ppm) TotalAlkalinity (ppm CaCO3) Specific Conductivity ( mhos/cm) 0-300 0.100 0.050 0.30 150 700 7000 301-450 0.050 0.025 0.30 90 600 6000 451-600 0.030 0.020 0.20 40 500 5000 601-750 0.025 0.020 0.20 30 400 4000 751-900 0.020 0.015 0.10 20 300 3000 901-1000 0.020 0.015 0.05 8 200 2000 1001-1500 0.010 0.010 0.0 2 0 150 1501-2000 0.010 0.010 0.0 1 0 100
FIGURE 8. ASME Guidelines for Boilers
Some chemicals used for internal boiler water treatment are given in Figure 9. The organic polymers (tannins, lignin derivatives, starch, and glucose derivatives) are seldom used anymore. They have been replaced by more effective synthetic polymers, such as polyacrylic acids, which also have better thermal stability. Also, the synthetic polymers are typically used in combination with a chelant such as EDTA to prevent or perhaps dissolve scales.
FIGURE 9. Chemicals Used in Boiler Water Treatment NOTE: From Powell, Water Conditioning for Industry, McGraw-Hill Book Co., p. 243 (1954).
Corrective Treatment Required Type of Chemical
Maintenance of feed-water pH and boiler-water
alkalinity for scale and corrosion control Caustic sodaSoda ash Sulfuric acid
Prevention of boiler scale by internal softening of the boiler water Phosphates Soda ash Sodium aluminate Alginates Sodium silicate Conditioning of boiler sludge to prevent adherence to
internal boiler surfaces
Tannins
Lignin derivatives Starch
Polyacrylates Prevention of scale from hot water in pipelines, stage
heaters, economizers, etc.
Polyphosphates Tannins
Lignin derivatives Chelants
Prevention of oxygen corrosion by chemical de-aeration
of boiler feed water SulfitesFerrous hydroxide Hydrazine
Prevention of corrosion by protective film formation Tannins
Lignin derivatives Glucose derivatives Prevention of corrosion by condensate Amine compounds
Ammonia Prevention of foam in boiler water Polyamides
Polyalkylene glycols Inhibition of caustic embrittlement Sodium sulfate
Phosphates Tannins Nitrates
Carbonates
Carbonate and bicarbonate ions affect both scale formation and corrosion in boiler systems. The bicarbonate salts of Ca++ and Mg++ are soluble in feed water but decompose at boiler
operating temperatures to form CaCO3, Mg(OH)2, and CO2 (Figure 10). The CO2 is given off
with the steam. When the steam condenses, CO2 dissolves in the condensate, making it
acidic. The acidic condensate is corrosive to steel. This is one reason that the alkalinity of boiler water is strictly limited (refer to Figure 8).
FIGURE 10. Decomposition of Bicarbonates to Form Scales
Bicarbonate and carbonate also decompose to form hydroxyl ions in the boiler. First, the bicarbonate ions decompose to carbonate, CO2, and water. The carbonate ions, in turn,
decompose to form hydroxyl ions and CO2 (Figure 11).
FIGURE 11. Decomposition of Carbonate and Bicarbonate
The carbonate decomposition goes only to about 80% completion so the decomposition of 1 ppm of carbonate forms 0.58 ppm of CO2. Bicarbonate decomposition goes 100% to
completion so 1 ppm of bicarbonate will form 0.36 ppm CO2 plus 0.49 ppm carbonate. The
0.49 ppm carbonate, in turn, is 80% decomposed to form 0.80 × 0.58, or 0.29 ppm CO2. The
total CO2 formed from 1 ppm of HCO3- is 0.65 ppm (Figure 12).
Ca(HCO3)2 + HEAT → CaCO3 + CO2 + H2O
Mg(HCO3)2 + HEAT → Mg(OH)2 + 2CO2
2NaHCO3 + HEAT → Na2CO3 + CO2 + H2O
FIGURE 12. The Relationships of Alkalinity and CO2
Alkalinity is expressed as CaCO3 because it was common practice to use unsoftened water in
low pressure boilers (<200 psig) and to precipitate the hardness by adding Na2CO3 (Figure
13). The calcium carbonate and magnesium hydroxide form a sludge that goes off with the blowdown. Deposition of the solids is prevented by adding a chemical dispersant such as tannin or starch.
FIGURE 13. Precipitation of Hardness with Soda Ash
For higher pressure boilers (>200<1000 psig), the decomposition of carbonate to NaOH and CO2 is too great for precipitating calcium as calcium carbonate. Phosphates – either
trisodium phosphate or sodium tripolyphosphate – are used. Calcium precipitates as calcium phosphate, which forms an easily manageable sludge. Phosphate treatment is difficult to manage because the alkalinity is critical. Mg++ will precipitate as magnesium silicate if
silicates are present. If silica is low or absent, Mg(OH)2 is formed if the alkalinity is correct.
If the alkalinity is low, the magnesium phosphate will precipitate as highly-charged particles that are likely to form a boiler deposit. Polymers will effectively disperse magnesium silicate, Mg(OH)2, and Ca3(PO4)2. However, polymers are not very effective in dispersing
Mg3(PO4)2.
Today boiler water is softened to <1 ppm of total hardness as CaCO3 and a chelant is added in
internal treatment to solubilize any residual hardness. A polymer is almost always used 1 ppm CO3-- = 0.58 ppm CO2 (80% decomposed)
1 ppm HCO3- = 0.36 ppm CO2 + 0.49 ppm CO3-- (100% decomposed)
0.49 ppm CO3-- = 0.29 ppm CO2 (80% decomposed)
So, 1 ppm HCO3- = 0.65 ppm CO2 + 0.098 ppm CO3
--When alkalinities are expressed as CaCO3:
1 ppm CO3-- (as CaCO3) = 0.35 ppm CO2
1 ppm HCO3- (as CaCO3) = 0.79 ppm CO2 (total)
Ca++ + Na
2CO3→ CaCO3 + 2Na+
Mg++ + Na
together with the chelant to disperse any solids formed. This procedure has a very good record in controlling boiler scaling and deposition.
Silica
Depositions of silica (SiO2) by itself do not usually occur in boilers unless there is a drastic
change in water treatment practice. The solubility of silica in water increases with both temperature and pH. Therefore, the solubility increases enormously under boiler operating conditions of high pH (10-12) and high temperature (Figures 14 and 15). The concentration of silica in fresh water sources averages less than 50 ppm.
FIGURE 14. Solubility of Silica in Water as a Function of Temperature
NOTE: From Linke in Seidell's Solubilities, 4th edition.
FIGURE 15. Effect of pH on the Solubility of Silica at 25 °C NOTE: From Linke in Seidell's Solubilities, 4th edition.
If residual Mg++ ions are present in boiler water and silica is high, it is possible to precipitate serpentine: 3MgO • 2SiO2 • 2H2O. The greatest danger of high silica is contamination of
steam and deposition in the superheater from carryover. Carryover caused by foaming can be prevented by adding an antifoaming agent such as a high molecular weight amide, alcohol, ester, or silicone.
Silica is surprisingly soluble in steam. Unless the guidelines in Figure 8 are followed, silica will be carried from boiler water to the steam where it will deposit on turbines and other steam systems (Figure 16). The reason for the decreasing limit on silica concentration as boiler pressure increases (Figure 8) is obvious from Figure 16. At pH 9 and 2000 psig, the concentration of silica in steam increases to 4% of the concentration in water from which the steam was evaporated.
T (°C) Solubility SiO2 (wt %) 100 0.043 150 0.062 200 0.081 pH Solubility SiO2 (wt %) 6 0.011 8 0.012 10 0.035 11 0.330
FIGURE 16. Effect of Pressure and Boiler Water pH on the Silica Distribution Ratio
Small amounts of aluminum, iron, manganese, and copper cause precipitation of silica in boilers even at low levels of silica. For this reason, the recommended limits on these metals in boiler feed water are very low (Figure 17). These ions are normally removed by softeners, but they can be introduced by corrosion in the feed water system between the softener and
FIGURE 17. Recommended Limits for Boiler Feed Water
Silica contents of water can be lowered by hot lime softening, MgO coprecipitation, or ion
exchange. Guidelines for controlling silica in refinery cooling water are shown in Figure 18.
The keys to silica control in cooling water include periodic blowdown, use of a silica-specific dispersant, and removal of silica from make-up (if necessary).
FIGURE 18. Guidelines for Controlling Silica in Refinery Cooling Waters Sulfates
Sulfate is not regarded as a problem in boiler feed water. The sulfate content of fresh water sources is sufficiently low that no effort is made to remove sulfate. It is removed from feed waters for high pressure boilers that require demineralized feed water.
Sodium sulfate is used to prevent caustic cracking in boilers. Caustic cracking requires a leak or means of concentrating caustic at a point of stress. It used to occur frequently in riveted boilers, but modern designs have overcome most problems of caustic cracking except around rolled tube ends.
Concentration in Boiler Feed Water (mg/l)
Ion 0-150 psi 150-700 psi 700-1500 psi >1500 psi
Al 5 0.1 0.01 0.01 Fe 1 0.3 0.05 ----Mn 0.3 0.1 0.01 0.01 Cu 0.5 0.05 0.05 0.01
•
Periodic blowdown•
Silica <150 ppm if pH ² 7•
Silica <200 ppm if pH 8.5-9•
Use of silica-specific dispersant•
Removal of silica by iron salts, MgO, or ion exchangeThe solubility of calcium sulfate is so high that it is not a problem in boilers. It is formed only where carryover occurs and other soluble salts are deposited as well. In cooling waters, CaSO4 concentration must be greater than 1700 ppm for CaSO4 to be troublesome. For
blowdown control in cooling waters, the product of the Ca++ in mg/l times the SO 4
--concentration in mg/l should be maintained at less than 500,000 (Figure 19).
FIGURE 19. Guidelines for Sulfate
Waters that contain organic matter and sulfate ions are prone to support sulfate-reducing
bacteria when deaerated. These bacteria form hydrogen sulfide, which interferes with the
formation of the magnetite protective film, thereby damaging boilers. If the conditions exist for growth of sulfate-reducers, they should be eliminated by altering the process or by using biocides.
Iron Scales
Iron scales in boilers are particularly damaging. The recommended limits on iron concentrations in boiler feed waters are, therefore, quite low (refer to Figure 17).
Iron deposits in boilers are porous. They allow water beneath the scale to evaporate, causing a localized increase in NaOH concentration. Caustic concentrations under iron deposits can be 1%, or more, which is sufficient to interfere with the formation of a protective Fe3O4 film.
The tube wall continues to corrode, sloughing off Fe3O4 flakes that accumulate in drums and
other quiescent places in the boiler. This type of corrosion is called “caustic gouging” (Figure 20).
•
SO4-- not a problem in boilers if guidelines are met•
SO4-- maximum for cooling waters = 1700 ppmFIGURE 20. Caustic Gouging Beneath a Porous Iron Deposit
Caustic gouging is prevented by buffering boiler water with disodium phosphate. This compound reacts with NaOH to form trisodium phosphate, thus, preventing the accumulation of NaOH beneath deposits (Figure 21). For pH control, the Na+ ion concentration should be
less than three times the PO4--- concentration.
FIGURE 21. Use of Phosphate for pH Control
When temperatures reach or exceed 900 °F, steel reacts directly with steam to form Fe3O4 and
hydrogen. The Fe3O4 formed under these conditions is not protective. The reaction continues
until the steel fails. Such failures occur in superheaters with restricted steam flow, such as NaOH + Na2HPO4↔ Na3PO4 + H2O
Na+ PO4
during low-load operation. They also occur in boiler tubes that are steam blanketed by overheating.
Causes of Boiler Scales and Deposits
Boiler scales and deposits occur even with the best programs of external and internal treatments. For this reason, boilers are subjected to close monitoring, periodic inspections, and cleaning when necessary.
Scales and deposits are inevitable in boilers because of the difficulty of maintaining consistent treatments. Softeners are subject to channeling and degradation of the ion-exchange resin. Also, tight schedules might require the draining of a hot boiler or start-up with cold, aerated water. Overfiring also causes scales. Surges in steam demand and burner malfunctions are common causes of overfiring (Figure 22).
FIGURE 22. Common Causes of Boiler Scales and Deposits
Boiler operation without cleaning can be extended by preventive treatments, described in the next section, such as chelant treatment to remove scale deposits.
•
Softener channeling•
Degradation of ion exchange resins•
Filter malfunctions•
Draining hot boiler•
Start-up with cold, aerated water•
Overfiring•
Burner malfunctions•
Incomplete oxygen removal•
Corrosion in supply pipingPREVENTING DAMAGE BY SCALE Softening
Water is “softened” to remove hardness ions Ca++ and Mg++. Generally, a softening process
will remove all divalent cations including Fe++, Mn++, and Co++. Demineralizers are
designed to remove all ions from water to produce a product similar to distilled water. A softening process must be tailored to the water source that is available and to the boiler in which the water is to be used. It is usually not desirable to rely on a softening resin to remove Fe++ because iron ions are irreversibly adsorbed on the ion exchange resin. If iron
concentrations are high, a separate iron-removal process should be installed. As we have seen, the higher pressure boilers require lower TDS and lower hardness ion concentrations. A generalized list of softening processes that are available is given in Figure 23. All of the processes are used in oil fields for one purpose or another. Note that some of the processes produce hardness levels that are lower than other processes. Some increase alkalinity, some lower alkalinity, some lower TDS, while others increase TDS or do not change it.
Type Process
Na cation exchange For low pressure boilers, <1 ppm hardness, no reduction of alkalinity or TDS. H cation exchange Lowers TDS, more expensive, <1 ppm hardness, lowers alkalinity, for higher
TDS waters.
Mixed bed Removes TDS and alkalinity, high cost. Hot lime-soda Lowers TDS, silica, involved, high alkalinity. Hot lime + ion exchange Lowers alkalinity, hardness <1 ppm.
Distillation Removes TDS and alkalinity, high cost.
Reverse osmosis A membrane process, lowers hardness, alkalinity, and TDS.
Electroosmosis A membrane process, similar results as reverse osmosis but more maintenance.
The cost of operating softening processes depends on the quality of the raw water that is available. The cost of water softened by cation exchange resins is less than $0.20/bbl. The cost for these processes increases as the TDS and hardness of the feed water increases because they are less efficient and must be regenerated more frequently. Hot lime processes rival the ion exchange processes in cost, but they can operate with waters having high TDS. The more exotic processes that remove all, or almost all, TDS are the most expensive, ranging about $0.20 to $1.00 per barrel of water product.
Softening operation is usually automated and untended. However, the quality of the product water must be monitored closely. Continuous hardness monitors are used, but they must be supplemented by frequent analyses of the water for hardness and alkalinity. A small laboratory for monitoring is usually associated with softener plant operation. The required analyses do not require much time to perform and can be done by the boiler operator. Good monitoring will disclose malfunctions in the softening process before any harm is done to the boiler. Provision should be made to divert product water back to the raw water supply in the event that off-spec water is produced.
Oxygen Removal
Effects of Dissolved Oxygen
The removal of oxygen from boiler feed water is as important as softening. Dissolved oxygen prevents the formation of the protective Fe3O4 film in boilers. It causes pitting attack of steel
and the deposition of nonprotective iron scales (Figure 24). For these reasons, oxygen is always removed from boiler feed water.
FIGURE 24. Effects of Dissolved Oxygen
•
Prevents protective Fe3O4•
Causes pitting attack of steelMechanical Deaeration
Large boiler installations and those that cannot tolerate added salts (high pressure boilers) employ steam stripping to remove dissolved oxygen from feed water (Figure 25). There are several types of mechanical deaeraters. The most efficient is the tray-type deaerating heater. The incoming water is sprayed into a steam atmosphere where it is heated to near its boiling point. Heating the water decreases the solubility of dissolved oxygen in the water. The oxygen that is liberated from the water is carried away by venting a small part of the steam from the vessel. The water cascades down a series of trays cocurrently with steam. The deaerated water is stored in a steam-blanketed vessel below the stripping vessel. A tray-type deaerating heater will lower the oxygen content of water to less than 1 ppb. Other dissolved gases, such as CO2 and NH3, are also removed to an extent dependent on the alkalinity of the
Horizontal spray deaerating heaters are less expensive than the tray-type, but they do not remove oxygen as completely (Figure 26). The product water from a horizontal spray deaerating heater contains about 0.1 ppm of dissolved oxygen. Therefore, a chemical oxygen
scavenger must be added to the product water to complete the removal of oxygen. Water
enters the deaerater through a sprayer that breaks the water up into droplets for thorough contact with a steam atmosphere. The heated water then is stripped by more steam in a riser before cascading to storage.
FIGURE 26. Horizontal Spray Deaerating Heater
Vacuum deaeraters are used where heating of the water is not desired (Figure 27). This type
of deaerater is simply a trayed tower to which a vacuum is applied by a mechanical pump or by a steam jet. The oxygen partial pressure is lowered by the vacuum, causing oxygen to disengage from the water according to Henry’s Law. Vaporization of the water then carries the oxygen off through the vacuum pump.
Vacuum deaeraters lower dissolved oxygen to about 0.5 ppm. Therefore, supplementary chemical treatment is necessary. The extent to which oxygen is removed depends on the vacuum maintained (Figure 28). The higher the vacuum, the higher the energy input required. The best cost-effectiveness is generally to remove the last 0.5 ppm by chemical additives.
Chemical Oxygen Removal
Two types of chemical oxygen scavengers are used for boiler water treatment. Sulfites are used for boilers operating at less than 1000 psig and hydrazine is used for boilers operating above 1000 psig. The reason for the pressure limitation is that sulfites add to the TDS of the boiler water while hydrazine does not (Figure 29). It requires 7.88 ppm of sodium sulfite to remove 1 ppm of oxygen. Only 1 ppm of hydrazine is required to remove 1 ppm of oxygen.
FIGURE 29. Chemical Oxygen Scavengers
Sulfites are preferred oxygen scavengers when they can be used because they are inexpensive, react rapidly, and are universally available. The sulfite can be in the form of sodium sulfite, sodium bisulfite, ammonium sulfite, ammonium bisulfite, or sulfur dioxide (Figure 30). All of these chemicals form sulfite ions when dissolved in water. Therefore, they have the same net reaction with dissolved oxygen. There are differences in the storage and applications of the chemicals as explained below.
Na2SO3 + 12 O2 → Na2SO4 7.88 ppm/ppm O2
N2H4 + O2 → 2H2O + N2 1 ppm/ppm O2
Na2SO3 + 12 O2 → Na2SO4 (sodium sulfite)
2NaHSO3 + O2 → Na2SO4 + H2SO4 (sodium bisulfite)
(NH4)2SO3 + 12 O2 → (NH4)2SO4 (ammonium sulfite)
2NH4HSO3 + O2 → (NH4)2SO4 + H2SO4 (ammonium bisulfite) 1
Sulfites hydrolyze in water to SO2 (sulfur dioxide), HSO3- (bisulfite ion), and SO3-- (sulfite
ion). The relative proportion of each product depends on the pH of the water (Figure 31).
FIGURE 31. Distribution of Sulfite Species as a Function of pH
Of the sulfite species, sulfite is the ion that reacts with dissolved oxygen. No reaction occurs below pH 4-5 where sulfite ceases to exist. The reaction occurs with increasing rate from pH 5 to pH 7. The reaction is very rapid above pH 7 where the predominate ion is sulfite. Less than a minute is required to remove all oxygen.
Sodium sulfite and ammonium sulfite form alkaline solutions when dissolved in water. When stored as a concentrate, these solutions must be protected from the atmosphere because they will react with oxygen from the air. The solutions can be blanketed with an inert gas, or they can be “poisoned” with 5 ppm of ascorbic acid (Figure 32). Ascorbic acid prevents the reaction of sulfite with oxygen at a concentration of 5 ppm. When the concentrate is injected into boiler water, and the ascorbic acid is thereby diluted, the reaction with dissolved oxygen is then normal.
FIGURE 32. Effect of Ascorbic Acid on the Reaction of Sodium Sulfite with Oxygen
Sodium bisulfite and ammonium bisulfite form acidic solutions when dissolved in water so their concentrated solutions can be stored without protection from air.
FIGURE 33. Application of SO2 for Oxygen Removal
Sulfites often require a catalyst to react rapidly with dissolved oxygen (Figure 34). In some waters, depending on trace ions that are present, the reaction might take hours to complete. With catalyst added, the reaction requires less than 60 seconds to go to completion. The most common catalysts used are cobalt (Co++) or nickel (Ni++) ions, which are added at a
FIGURE 34. Reaction Rates of Catalyzed and Uncatalyzed Sodium Sulfite
Even if a catalyst is used, it cannot be assumed that adding sulfite is going to remove oxygen from the water. The results must be monitored, either with an electronic meter or chemical means, to measure dissolved oxygen residual. A very convenient method for measuring dissolved oxygen is with the ampoule-type of chemical indicator (Chem-MET). The reaction must be monitored because trace amounts of aldehydes, some corrosion inhibitors, and some
If catalyzed sulfite does not react with dissolved oxygen, the interfering substance must be removed or the sulfite must be added at a point in the process where it does react. If the interfering substance cannot be removed, then oxygen might have to be removed mechanically with hydrazine supplementary treatment.
Hydrazine is used for oxygen removal in boilers where TDS concentrations must be kept to a minimum. Liquid hydrazine has a very low flash point and is dangerous to handle. It is used as a 30% solution, which has no flash point. Hydrazine reacts very slowly with dissolved oxygen at ambient temperatures and is catalyzed only by copper ions (Cu++) and by
hydroquinone (Figure 35). Copper ions are not desirable in boilers and hydroquinone is a weak catalyst. The reaction of hydrazine with oxygen is very fast at higher temperatures. Therefore, the reaction is usually completed in the economizer before water enters the boiler itself.
FIGURE 35. Reaction of Hydrazine with Dissolved Oxygen in the Presence of Various
Hydrazine decomposes at temperatures above 400 °F (Figure 36) to form ammonia and nitrogen. Although ammonia is not harmful to the boiler, it will be carried over with steam where it can attack copper and copper alloys.
Polymers, Chelants, and Inhibitors Polymers
When low-pressure boilers (<250 psig) used unsoftened water, hardness was precipitated in the boiler by adding Na2CO3. The resulting sludge had a tendency to cake unless a dispersant
of some kind was added. Before the development of synthetic polymers, natural products such as starch, lignin, and tannins were used as dispersants. Today’s synthetic polymers are more effective, more thermally stable, and more reliable than the natural products formerly used. Polymer additions in the range of about 1 ppm are a normal part of internal boiler water treatment. The polymers are usually used in a polymer-chelant combination treatment.
Synthetic polymers in use today for internal boiler-water treatment are polyacrylates, polymethacrylates, and polyacrylamides. They function by adsorbing on suspended particles. All particles have the same charge and, therefore, repel one another and prevent agglomeration. The temperature limit for synthetic polymers is <700 °F, which allows their use in most boilers (Figure 37).
Polymers act best as dispersants when they have a molecular weight of less than 10,000. Some synthetic polymers work best for hardness salts, some are better for iron compounds, and some have a broad spectrum of effectiveness. It is a good idea to have some knowledge of the type of solids that require dispersing. A comparison of your needs with the demonstrated effectiveness of several vendors’ products should disclose the best polymer for your needs. If there is a doubt about the composition of solids, or it is a mixture of hardness salts and iron compounds, then a broad-spectrum dispersant would be best. Polymers provide an additional dividend in distorting crystal growth. The distortion of crystal growth weakens crystal structure so scales are less likely to adhere to heated surfaces.
Temperature (°F) Modified Lignosulfonate Sodium Polyacrylate and Polymethacrylate
500 Considerable charring No change 600 Almost totally charred No change
Chelants
Chelants, usually EDTA or NTA, are used in internal treatment of boilers to complex residual hardness and iron ions. They are usually added at concentrations of about 10 ppm unless hardness scales exist in the boiler. Higher concentrations are used to dissolve existing scales in a form of “in-situ” cleaning. Care must be exercised in using excess chelant. A high concentration will cause thinning of stressed members, such as tube ends. Since corrosion by chelants requires several months at a continuously high concentration in the boiler water, it is easy to avoid.
Both EDTA and NTA are used for boiler water treatment. EDTA is preferred because of its high stability constant for complexing most of the undesirable ions occurring in boilers (Figure 38). Also, EDTA has better thermal stability than does NTA. The upper limit for EDTA is 1200 psig. For NTA, the upper limit is 900 psig.
FIGURE 38. Stability Constants of EDTA and NTA
The high stability constant of the chelants for iron (Figure 38) indicate that the mechanism of corrosion by excess chelant is by preventing the formation of protective Fe3O4 (Figure 39).
Iron reacts with water at temperatures above about 225 °F to form ferrous ions (Fe++) and
hydrogen. Part of the ferrous ions are then oxidized by OH- ions to form ferrite ions (FeO 2-),
which precipitate as ferrous ferrite, or Fe3O4. The reaction is favored by alkaline conditions
and the absence of reducing agents such as sulfide ions. Excess chelant will complex ferrous ions preventing the precipitation of Fe3O4. It is best not to rely on chelants alone to remove
iron deposits. It is better to use a chelant/polymer combination.
Log K
Ion EDTA NTA
Ca++ 10.59 6.41
Mg++ 8.69 5.41 Fe++ 14.33 8.82
FIGURE 39. Prevention of Magnetite Formation by EDTA Inhibitors
Results on several boilers with various offending ions treated with EDTA or NTA are shown in Figure 40. Note that NTA does not prevent deposition in several instances. However, EDTA prevented deposition in all cases except for Fe+++ when (OH)- > 5 ppm. This problem
can be overcome by using EDTA in external treatment of condensate returns where the Fe+++ forms and where (OH)- is less than 5 ppm.
3Fe + 6H2O → 3Fe++ + 6OH- + 3H2
3Fe++ + 4OH-→ 2(FeO
2)- + H2 + 2H+
______________________________
3Fe + 4H2O → Fe(FeO2)2 + 4H2 (overall reaction)
EDTA + Fe++→ EDTA • Fe++
Log K = 14.33 = EDTA • Fe++ EDTA Fe++
FIGURE 40. Results of Boiler Treatments with EDTA and NTA Blowdown
Water is evaporated in a boiler until solids concentrations are perhaps 20 times that in the feed water. Both suspended and dissolved solids accumulate. To prevent the accumulation of solids to the point where deposition or foaming occurs, a part of the water is discharged either continuously or periodically. The discharge of concentrated boiler water is called blowdown.
Cation Competing Anion Chelant Remarks
Ca++ CO
3-- EDTA/NTA No problem
Ca++ PO
4--- NTA Deposition
Ca++ PO
4--->10 ppm EDTA Some deposition
Fe++ OH- EDTA No problem Fe++ OH->5 ppm NTA Deposition
Fe+++ OH->5 ppm EDTA Some deposition
Fe+++ OH->5 ppm NTA Deposition
Mg++ OH- NTA/EDTA No problem
Mg++ SiO2>40 ppm NTA Deposition
Mg++ SiO2>300 ppm EDTA Some deposition
Al+++ OH-<30 ppm EDTA/NTA Al-chelant complex
The volume of blowdown is expressed as a percentage of the volume of feed water (Figure 41). A 5% blowdown is then 5% of the feed water. A feed water rate of 1000 gal/hr with a 5% blowdown would be 50 gal/hr of blowdown. The blowdown rate is usually based on the recommended limit of TDS in the boiler water (Figure 42). The TDS can be monitored by electrical conductivity of the boiler water and feed water. Electrical conductivity is not always closely correlatable with TDS, especially if the pH or alkalinity fluctuates. The direct measurement of TDS by evaporating a measured volume of water is a slow procedure. The results are also inaccurate if TDS limits are very low. For these reasons, only one ion, such as Cl- or Na+, is often used to control boiler blowdown.
FIGURE 41. Expressions for the Blowdown Required
Per cent blowdown = (V blowdown) (100) (V feed) Also, blowdown = (TDS in feed) (100)
(TDS in boiler) Also, blowdown = (Cl- in feed) (100)
(Cl- in boiler)
Boiler Pressure
(psig) Total DissolvedSolids (ppm)
Total Alkalinity
(ppm) SuspendedSolids (ppm) Silica*(ppm)
0-300 3500 700 300 125
301-450 3000 600 250 90 451-600 2500 500 150 50 601-750 2000 400 100 35
Keeping the blowdown volume – and the heat loss – as low as possible is economical. The blowdown is usually flashed in a drum before discharge. Heat and condensate are recovered from the vapor, and the volume of waste water to disposal is diminished.
Recommended limits on some boiler water components are given in Figure 42. Using the limit of 3000 ppm for boilers operating at 301 to 450 psig and a feed water that contains 210 ppm of TDS, the blowdown rate is
210 × 100 3000 = 7%
If the feed water rate is 900 gal/hr, the blowdown rate is 900 × 0.07 = 63 gal/hr
Cleaning Boilers
The accumulation of scales, deposits and debris in boilers is inevitable. The question is what and where to clean. These questions are subdivided as shown in Figure 43. These questions require a management/technical decision based on individual circumstances. In general, the decisions generally follow the schedule in Figure 44.
FIGURE 43. What and When to Clean a Boiler
WHAT: 1. Boiler/economizer 2. Condensate/feed water 3. Superheater/reheater
WHEN: 1. Alkaline clean before start-up 2. Alkaline clean and acid/chelant
before start-up
3. Alkaline clean before initial operation and acid/chelant after several weeks to 1 year of operation
FIGURE 44. The Usual Cleaning Procedures Applied to Boilers at Start-up
Subsequent cleanings performed after operation are based on experience and a number of parameters that limit boiler operation if exceeded (Figure 45). Scheduled shut-downs for cleaning are far better and more economical than unscheduled shut-downs or boiler failure.
FIGURE 45. Parameters That Indicate When Cleaning Is Advisable Alkaline Cleaning
Hot alkaline cleaning removes oil so subsequent cleaning procedures are more effective. The Package boilers: Only hot alkaline cleaning
Sub-critical, field erected: Hot alkaline cleaning + acid/chelant cleaning of boiler/economizer
Supercritical: Hot alkaline cleaning + acid/chelant cleaning of boiler/economizer, con-denser/feed water, and sometimes superheater/reheater
Deposit Monitoring: Monitor tube wall temperature Monitor tube creep (expansion) X-ray
Priming Surging Corrosion Monitoring: Hydrogen
Iron
Acid Cleaning
Acid cleaning removes iron scales and other acid-soluble scales and deposits. The acid can be either circulated or left in the boiler for a period of time (fill and soak). Usually, 5% inhibited HCl is used for cleaning, but H3PO4, H2PO4, and sulfamic acids are used also.
Cleaning with organic acids, such as citric acid and hydroxyacetic + formic acids, are also practiced. A summary of cleaning compounds is shown in the Reference section.
The procedure for circulating acid is given in Figure 46. It is important that samples be taken periodically and analyzed for acid strength and iron content. Acid is added, as needed, to maintain the desired concentration. Cleaning is complete when the iron concentration in the circulating acid slows to a low rate of increase with time. The unit is first filled with hot water at the maximum temperature allowed by the corrosion inhibitor used in the acid. The water is circulated until uniform temperature is reached.
FIGURE 46. Procedure for Circulation Acid Cleaning
Effluent is taken from the highest point to a heated surge tank and is then returned to the lowest point by an acid-resistant pump. Flushing with clean water and alkaline conditioner must follow the acid treatment.
The fill and soak method of acid cleaning is less effective and takes longer than does the circulating method. The procedure for the fill and soak method is given in Figure 47. Basically, the procedure is the same as for the circulating method except that the boiler is initially filled with inhibited acid instead of warm water. Remember that hydrogen gas forms in all acid cleaning and should be vented safely.
1. Fill with hot water.
2. Circulate to uniform temperature.
3. Add inhibited acid to 4-6% concentration. 4. Circulate until dissolution stops.
5. Maintain acid concentration. 6. Drain, flush with water.
7. Neutralize with Na2CO3, NaOH, or Na3PO4.
8. Lower level and fire to 50 psig. 9. Flush with clean, warm water.
FIGURE 47. Procedure for the Fill and Soak Method of Acid Cleaning Chelant Cleaning
Chelant cleaning is safer and easier on the boiler than acid cleaning. The chelant, when supplemented with an oxidizing agent, removes copper deposits in addition to hardness salts and most iron compounds. The usual procedure for chelant cleaning is given in Figure 48. Air can be injected to oxidize copper or a separate cleaning can be applied specifically for removing copper.
FIGURE 48. Procedure for Cleaning With Chelants
Metallic copper plates out in boilers when the boiler water contains copper ions formed by corrosion of brass or copper in condensate systems. Copper deposits will cause pitting attack
1. Fill with inhibited acid
2. Monitor acid strength and add acid as necessary 3. Drain and flush with clean, warm water.
4. Fill with neutralizing solution 5. Lower level and fire to 50 psig 6. Flush with clean water
1. Heat boiler water to 275 °F. 2. Add inhibitor to drum.
3. Add chelant to 3 to 6% concentration.
4. Heat and cool alternately between 325 and 275 °F for several cycles until the iron concentration levels off.
5. Cool to 180 °F, bubble air to oxidize copper. 6. Drain when copper concentration stabilizes. 7. Flush with clean water.
GLOSSARY
alkalinity The amount of acid required to lower the pH of a water to pH 4.5 - 5.2. It is a measure of the total alkali in a water including carbonate, bicarbonate, and hydroxyl ions.
blowdown The periodic or continuous removal of a portion of the water from a boiler.
caustic cracking Cracking of stressed steel caused by the accumulation of hot, caustic salts.
caustic gouging Corrosion that occurs in boilers beneath porous iron scales or deposits.
condensate Water formed by condensing steam.
deaerater A device that removes dissolved oxygen from water.
demineralized water Water from which all salts have been removed by mixed-bed ion exchange. All cations are exchanged for H+ and
all anions are exchanged for OH-.
deposits An accumulation of suspended solids that have agglomerated on a boiler surface.
electroosmosis The process of diffusing water through a membrane under the force of an electric field to remove certain ions from water.
external treatment Treatment applied to a water before it enters a boiler.
hydrazine A compound of nitrogen and hydrogen, N2H4, used as an
oxygen scavenger in boilers.
hydrogen embrittlement The resulting brittleness of some steels because they have absorbed hydrogen.
hydrogen cation exchange An ion-exchange resin that trades hydrogen ions for Ca++
internal treatment Treatment applied to water inside a boiler.
ion exchange The trading of an ion from water for one carried on a solid.
magnetite A magnetic form of iron oxide, Fe3O4.
mixed bed A combination of hydrogen exchange resin and hydroxyl exchange resins for demineralizing water.
mud drum The vessel that collects suspended solids from boiler water.
overfiring The act of burning more fuel in a boiler than it can use.
oxygen scavenger A chemical that reacts with dissolved oxygen in water.
retrograde solubility Solubility that decreases with increasing temperature.
reverse osmosis The process of forcing water through a semipermeable membrane to lower the ion content of the water.
saturated steam Steam that is in equilibrium, or at the same temperature, as the water from which it was boiled.
serpentine A form of magnesium silicate, 3MgO•2SiO2•2H2O. silica Silicon dioxide, SiO2.
sodium cation exchange An ion-exchange resin that trades sodium ions for Ca++
and Mg++ in water.
steam quality The percentage of effluent from a boiler that is steam, the remainder being water. For example, 80% quality is 80% steam and 20% water.
sulfate-reducing bacteria Bacteria that convert sulfate ions to hydrogen sulfide under anaerobic conditions.
sulfite An ion of sulfur and oxygen, SO3--, in which sulfur has
an oxidation state of +4.
superheated steam Saturated steam that is heated to a higher temperature.
superheater The boiler tubes through which saturated steam passes to be superheated.
vacuum deaerater A trayed column through which water is passed under vacuum to remove dissolved oxygen.
