01 POWER ISLAND / 01 CCPP / V. Ganapathy-Industrial Boilers and HRSG-Design (2003)

first when boiling starts. Calcium carbonate deposits quickly, forming a white friable deposit. Magnesium phosphate is a binder that can produce very hard, adherent deposits. Insoluble silicates are present in many boilers. The presence of sodium hydroxide, phosphate, or sulfate may be considered proof that complete evaporation has occurred in the tubes, because these are easily soluble salts.

Sludge or easily removable deposits accumulate at the bottom of the tubes in the mud drum and should be removed by intermittent blowdown, generally once per shift. Based on conductivity readings, the frequency may be increased or decreased. Continuous blowdown is usually taken from the steam drum a few inches from above the waterline, where the concentration of solids is the highest.

Any boiler water treatment program should be reviewed with a water chemistry consultant, because this program can vary on a case-to-case basis. Generally the objective is to add chemicals to prevent scale formation caused by feedwater hardness constituents such as calcium and magnesium compounds and to provide pH control in the boiler to enhance maintenance of a protective oxide film on boiler water surfaces. There are methods such a phosphate-hydroxide, coordinated phosphate, chelant treatment, and polymer treatment methods. In medium and low pressure boilers, all these methods have been used.

Carryover of impurities with steam is a major concern in boilers having superheaters and also if steam is used in a steam turbine. Carryover results from both ineffective mechanical separation methods and vaporous carryover of certain salts. Vaporous carryover is a function of steam density and can be controlled only by controlling the boiler water solids, whereas mechanical carryover is governed by the efficiency of the steam separators used. Total solids carryover in steam is the sum of mechanical and vaporous carryover of impurities.

The steam purity requirements for saturated steam turbines are not stringent. Because the saturated steam begins to condense on the first stage of the turbine, water-soluble contaminants carried with the steam do not form deposits. Unless the steam is contaminated with solid particles or acidic gases, its purity does not significantly affect the turbine performance. However, there can be erosion concerns due to water droplets moving at high speeds.

With superheated steam, steam purity is critical to the turbine. Salts that are soluble in superheated steam may condense or precipitate and adhere to the metal surfaces as the steam is cooled when it expands. Deposition from steam can cause turbine valves to stick. Reduced efficiency and turbine imbalance are the other concerns. Deposition and corrosion occur in the ‘‘salt zone’’ just above the saturation line and on surfaces in the wet steam zone. The solubility of all low volatility impurities such as salts, hydroxides, silicon dioxide, and metal oxides decreases as steam expands in the turbine and is lowest at the saturation line. The moisture formed has the ability to dissolve most of the salts and carry them downstream. The critical region for deposition in turbines operating on superheated steam is the blade row located just upward of the Wilson line.

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Mechanical carryover results from entrainment of small droplets of boiler water in the separated steam. Because the entrained water droplets contain the same concentration and proportions of solids as in the boiler water, the steam will also contain these solids as a function of its moisture content.

Foaming in the boiler water will also result in carryover. Common causes are excessive boiler water solids, excessive alkalinity, or the presence of organic matter such as oil. Continuous blowdown should be done to maintain the boiler water concentration below the ASME=ABMA levels.

Unlike mechanical carryover, vaporous carryover is selective because it depends on the solubility of the salts in steam. Silica is an example of a contaminant that has this tendency, particularly at high steam pressures, above 700 psig. Boiler water of a higher pH helps minimize the carryover. Drum internals (Fig. 3.26) serve to remove moisture from the steam as it leaves the drum and enters the superheater. Generally the belly pan collects the steam–water mixture from the riser tubes and directs it inside the drum, where a chevron separator consisting of multiple vanes with tortuous paths separates the moisture from the steam. The mass flow of the mixture is the circulation ratio times the steam generation. Hence the belly pan width must be sized to handle the flow of this mixture. The steam purity required depends on the application. Saturated steam used in process heating applications can have a large carryover of solids, as much as 3–5 ppm. Drum internals need not be elaborate in these cases. A few steam turbine suppliers demand steam purity in the range of parts per billion for superheated steam, whereas some accept even 100 ppb total dissolved solids.

FIGURE 3.26 Arrangement of steam drum internals.

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Restrictions are also placed on sodium and silica in steam. Typical silica levels are 20 ppb. By maintaining proper boiler water chemistry as suggested in Q5.17, per ABMA and ASME, one can ensure that the steam purity is acceptable. Maintaining an alkaline condition (pH about 10–11.5) in the boiler water minimizes corrosion in the boiler; however, the alkalinity should also not exceed 700 ppm CaCO3. Above this level chemical reactions liberate CO2 into steam, which results in the corrosion of steam and return lines.

As far as the feedwater is concerned, proper deaeration and the removal of oxygen by chemical methods helps. Demineralized water is required if it is used for attemperation to control the steam temperature. Once-through steam generators and HRSGs need zero solids because complete evaporation of water occurs inside the tubes. Dissolved oxygen is the factor most responsible for the corrosion of steel surfaces in contact with water. Oxygen should be less than 5–7 ppb to minimize these concerns. Chemicals such as hydrazine or sodium sulfite are added to minimize oxygen corrosion.

Scale formation can affect the tube wall temperatures in fire tube as well as water tube boilers; as discussed above.

A few plants do not spend sufficient money on water treatment facilities. Table 3.9 shows how a large amount of blowdown increases the cost of operation and why it pays to invest in a good water treatment system. Corrosion and steam purity problems result in additional costs, which cannot be quantified because they lead to unscheduled maintenance. The additional amount of fuel fired to generate the same amount of steam is significant over a period of time. I have seen blowdown on the order of 15–20% in a few refineries.

TABLE 3.9 Cost of Blowdowna

a Boiler efficiency ¼ 83% HHV; fuel cost ¼ $3=MM Btu. Operating for 8000 h=y.

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FIRE TUBE BOILERS

Packaged fire tube boilers (Fig. 3.3) generate low pressure saturated steam, generally below 300 psig. Above this pressure, the thickness of the corrugated central furnace (referred to as Morrison pipe) becomes larger and it is difficult to make the corrugations. The corrugations help to reduce the thickness of the furnace, which operates at a high metal temperature because it contains the flame. The corrugations also help to handle the thermal expansion differences between the furnace and the smaller tubes in the second and third passes, which operate at lower tube wall temperatures. Note that the tube sheets are fixed at the ends of the tubes, and without this flexibility large stresses would be introduced into the tube sheets and the tubes. The thickness of a tube subjected to external pressure is higher than that subjected to internal pressure, as shown in Table 2.2. Fire tube boilers are typically rated in boiler horsepower (BHP); Q5.08 shows how one can relate BHP to steam generation. Often these boilers do not need an economizer, because the exit gas temperature, due to the low pressure of steam, is around 400– 450 F. However, an economizer is used when high efficiency is desired.

The number of passes on the tube side depends upon the supplier. Typically three to four passes are used. In the wetback design the turnaround section is immersed in the water, so the hot gases leaving the furnace do not contact the refractory as in the dryback design, which is less expensive to build. However, the wetback design has fewer problems with refractory maintenance than the dryback design. Wet or water-cooled rear doors are also available that minimize refractory maintenance concerns in dryback boilers. The typical gas temperature at the furnace exit is about 2000–2200 F, hence the turnaround section with refractory often requires maintenance.

Oil and gaseous fuels are generally fired in packaged fire tube boilers. Solid fuels such as wood shavings have also been fired. The boiler capacity has been limited to about 80,000 lb=h, because it becomes more expensive to build these boilers as shop-assembled units as the capacity increases. The heat transfer coefficient with gas flowing inside the tubes is generally less than when it flows outside the tubes; hence fire tube boilers are large compared to water tube designs. They are considered economical below 50,000 lb=h of steam. It is generally difficult to install a superheater in these designs. NOx control methods such as flue gas recirculation or the use of low-NOx burners have also been used with these boilers. Due to the large amount of water inventory compared to equivalent water tube designs, these boilers take a little longer to start up. Steam purity is generally poor, because the steam is mainly used in heating applications where steam purity is not a concern and therefore no drum internals are used. Often single-shell fire tube boilers such as those shown in Fig. 3.3 generate steam with 3–15 ppm purity. Elevated drums have been used on fire tube boilers to

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obtain steam with a very high purity if required. The design would be similar to the elevated drum waste heat boiler discussed in Chapter 2.

When it comes to generating superheated steam, a water tube boiler has more options, because the superheater can be placed within a bank of tubes or in the radiant section or beyond the convection section as discussed above. However, in the case of a fire tube boiler, the options are limited; a possible location is between the tube passes, but the gas temperatures there are either too high or too low, making it difficult to design a reasonable superheater. Therefore, packaged fire tube boilers generally generate saturated steam.

The water inventory in a fire tube boiler is generally larger, thus requiring a longer start-up period. Heating surfaces can be cleaned by using retractable or rotary blowers at any location in a water tube boiler, whereas in a fire tube, access for cleaning is available either at the turnaround section or at the tube sheet ends.

AIR HEATERS

Air heaters are used in a few waste heat boilers for preheating combustion air. Incineration plants and reformer furnaces also use preheated air. Decades ago they were used in boilers that fired solid, liquid, and gaseous fuels. However, with NOx limitations for all kinds of fuels, they are now used only if the combustion of the fuel warrants it. If the gaseous fuel has a low heating value or if the solid fuel has a significant amount of moisture, then hot air is required for drying the fuel and also to ensure combustion with a stable flame. A gas to gas heater, which is similar to an air heater, is also used in incineration heat recovery plants where waste fuel is heated by the flue gases from the incinerator before entering the thermal or catalytic incinerator. In gas-fired or liquid fuel–fired packaged boilers, air heaters are not generally used. An economizer is the main heat recovery equipment. There are several types of air heaters, including tubular, regenerative, and heat pipes, the latter being a recent development. In all these heat exchangers, air is preheated by using hot flue gases from the boiler or heater. The flue gases could flow outside or inside the tubes. If the flue gases contain dust or ash particles, it is preferable to make them flow inside the tubes so that the shell or casing is not fouled, because it is more difficult to clean the exterior surfaces. The air takes a multipass route outside the tubes as shown in Fig. 3.27. Q8.28 shows the sizing procedures.

One of the concerns with air heaters is low temperature corrosion at the cold end. The tube wall temperature or the plate temperature at the cold end falls below the acid dew point of the flue gases if the incoming air temperature is low. Also, tube wall and plate temperatures are lower at lower loads because of their low heat transfer coefficients. Steam is often used to increase the incoming air temperature and thus mitigate this concern.

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FIGURE 3.27 (a) Rotary regenerative air heater. (b) Tubular air heater.

There are two types of regenerative air heaters, one in which the heater matrix rotates, and one in which the connecting air and flue gas duct work rotate. The first type is called the Ljungstrom air heater. The energy from the hot flue gases is transferred to a slowly rotating matrix made of enamel or alloy=carbon steel material, which absorbs the heat and then transfers it to the cold air as it rotates. The elements are contained in baskets, which makes cleaning or replacement easier. Regenerative air heaters are more compact than tubular air heaters, which are heavy and occupy a lot of space. The gasand air-side pressure drops are high in both these types of air heaters, adding to the fan power consumption. Due to the low heat transfer coefficients of air and flue gases and a low log-mean temperature difference (LMTD), surface area requirements are large for air heaters. However, a lot of surface area can be packed into each basket of a regenerative air heater, so they are more compact than the tubular heater.

One of the problems with regenerative air heaters is the leakage of air from the flue gas side that affects the power consumption and efficiency of the fan. Though the leakage may be low, on the order of 5–10% depending upon the seal design, it is significant in large plants. In tubular air heaters, failure of the tubes or expansion joints could result in leakage from the air side to the gas side, but this is minimal.

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In regenerative air heaters, corrosion concerns are addressed by using enamel or corten materials at the cold end. In the case of tubular air heaters, the entire section of tubes may have to be replaced. In some designs of regenerative air heaters, a selective coating of catalytic materials is given to the heating elements to promote the reaction of NOx with ammonia or urea, which is injected upstream of the air heater. NOx is thus reduced. The ammonium bisulfate formed is removed periodically by online soot blowing.

Both tubular and regenerative air heaters are widely used in pulverized coal–fired or fluid bed coal-fired boiler plants.

HEAT PIPES

Heat pipes (Fig. 3.28) were introduced into the heat recovery market about 40 years ago. A heat pipe consists of a bundle of pipes filled with a working fluid such as toluene, naphthalene, or water and sealed. Heat from the flue gas evaporates the working fluid collected in the lower end of the slightly inclined pipes (6–10 from horizontal), and the vapor flows to the condensing section, where it gives up heat to the incoming combustion air.

Condensed fluid returns by gravity to the evaporative section assisted by an internal capillary wick, which is essentially a porous surfaces or circumferentially spiraled grove of proprietary design. The process of evaporation and condensa-

FIGURE 3.28 Arrangement of a heat pipe.

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tion continues as long as there is a temperature difference between the air and flue gases.

In a typical design, there is a divider plate at the middle of the tube that supports the tube and also maintains a seal between the hot flue gases and the cold air. Pipe surfaces are finned to make the heat transfer surfaces compact. Finned surfaces are used because the heat transfer coefficient inside the tubes is very high due to the condensation and evaporation. Fin density is based on cleanliness of the gas stream.

Heat pipes offer several advantages over conventional air heaters:

1.They are compact and weigh less than other air heaters due to the use of extended surfaces.

2.They have zero leakage because the pipes are stationary and the divider plate is welded to the tubes.

3.No auxiliary power is needed, because heat pipes do not need a power source to operate.

4.Maintenance is low because there are no rotating parts.

5.They have low corrosion potential. Owing to the isothermal behavior of the pipes, the minimum tube metal temperature is higher than in other types of exchangers. By selecting proper working fluids, it is possible to maintain the cold end above the acid dew point. The tubes also operate at constant temperature along their entire length because of the phase transfer process.

6.They undergo only low stresses because the tubes are fixed at the midpoint and are allowed to expand at either end.

7.Individual pipe failure does not appreciably affect the overall performance of the unit.

8.Gasand air-side pressure drops are generally lower than in tubular or regenerative air heaters owing to the compactness of the design.

CONDENSING HEAT EXCHANGERS

The conventional design of economizers and air heaters ensures that cold end corrosion due to condensing sulfuric acid or water vapor does not occur because the minimum tube wall temperature is maintained above the dew points. However, owing to this design philosophy, a significant amount of energy is lost or not recovered in boilers and HRSGs. The condensing heat exchanger is designed to allow for the condensation of acid and water vapor over the heat transfer surfaces, thus recovering a significant amount of sensible and latent heat from the flue gases. The efficiency of a boiler plant with a condensing heat recovery system can be close to 99%. With natural gas firing, the partial pressure of water vapor is about 18%, whereas with oil fuels it is about 12%. With the

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condensation of this water vapor, significant improvement in efficiency can be obtained by using oil-fired boilers as shown in Fig. 3.29. Due to the improvement in the overall efficiency of the boiler or HRSG, the emissions of CO2, NOx and CO are also reduced.

Unlike conventional economizers and air heaters, which maintain temperatures above 270–300 F to prevent condensation, the condensing exchanger can operate with water or air at ambient temperatures. Hence condensate or makeup water at 60–80 F or so can be directly used to be heated up by the flue gases, whereas in a noncondensing exchanger the lowest feedwater temperature would vary from 230 to 270 F. Hence the exit flue gas temperature can be around 100– 130 F versus 270–300 F. Because the exchanger tube surface and the exhaust section of the exchanger are below the dew point of water vapor, a rain of condensate is produced through dropwise condensation of the water vapor. This condensate passes around the tube array, carrying particulates and acids that have been scrubbed and washed from the tubes. A few designs handle the problem of heat recovery and scrubbing at the same time to remove particulates and acid gases from the waste gas stream from incineration plants.

The condensing exchanger consists of specially designed tubes coated with a 0.015 in. extruded layer of FEP Teflon. The inside surfaces of the heat exchanger are covered with a 0.06 in. thick sheet of PTFE Teflon. During fabrication, the tubes are pushed through extruded tube seals in the Tefloncovered tube sheet to form a resilient Teflon-to-Teflon seal. This ensures that all heat exchanger surfaces exposed to the flue gases are protected against acid corrosion. To protect the Teflon, the inlet gas temperature is limited to about 500 F. The tubes are generally made of Alloy C70600, which protects them

FIGURE 3.29 Efficiency improvement in oil and gas firing using a condensing exchanger.

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against acid corrosion. The tube sheet and casing are coated with Teflon to prevent corrosion. The sub dew point condensing exchanger uses bare tubes due to the coating required and hence is larger than a finned tube bundle for the same duty.

Potential applications also include recovery of water from the gas turbine exhaust for recycle, reducing the amount of fresh makeup water required. The water could be redirected with proper treatment into the steam–water injection system for reducing NOx emissions. Cheng cycle systems, in which a large amount of steam is injected into a gas turbine, are also candidates for condensing exchangers.

GLASS EXCHANGERS

Borosilicate glass (Pyrex) tubing has been used in heat recovery applications because it is most resistant to chemical attack and presents no corrosion problems. Fouling is minimal due to the smoothness of the surfaces. These tubes also have a low coefficient of expansion and are resistant to thermal shock, which makes them suitable as heat exchanger tubes. However, the temperature limit is about 500 F, and the pressure limit is also low, on the order of 60 psig or less. The thermal conductivity is lower than that of carbon steel, by about onethird; however, because the tube wall thickness is low, the wall resistance to heat transfer is also low. Thus, compared to carbon steel tubes the overall heat transfer coefficient is lower by only a small margin. Flue gas to water heat recovery has been accomplished by using glass exchangers.

SPECIFYING PACKAGED BOILERS

The following process data should be specified as a minimum.

1.Steam parameters such as flow, pressure, temperature, and feedwater temperature. If saturated steam is taken from the boiler for deaeration or for NOx control, fuel oil heating, etc., it should be so stated. If the makeup water flow is 100%, the deaeration steam could be in the range of 15% of the steam generation and therefore not an insignificant amount.

2.If superheated steam is required, the steam temperature control range should be specified. Generally the steam temperature can be maintained from 50 to 100%. A larger range requires a larger superheater. Also, if several fuels were fired, the steam temperature would vary as discussed above.

3.Analysis of feedwater entering the economizer should be stated so that the blowdown requirements can be evaluated. An example is given in

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