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

In addition to the oxidation of H2S to SO2 and the reaction of SO2 with H2S in the reaction furnace, many other side reactions occur, such as

CO2 þ H2S ! COS þ H2O COS þ H2S ! CS2 þ H2O 2COS ! CO2 þ CS2

The gas stream contains CO2; H2S; SO2; H2; CH4, and water vapor in addition to various species of sulfur. The duty of the boiler behind the sulfur combustor includes both sensible heat from cooling of the gas stream from 2600 F to about 650 F and the duty associated with the transformation of various species of sulfur. The reaction furnace normally operates at 1800–2800 F, and the flue gases are cooled in a waste heat boiler (Fig. 2.5), in which saturated steam at about 600 psig is generated. This is typically of two-gas-pass design, though single-pass designs have been used. The gas is cooled to about 1200 F in the first pass and finally to about 650 F in the two-pass boiler.

Figure 2.6 shows the boiler for a large sulfur recovery plant, which consists of two separate shells for each pass connected to a common steam drum. The steam drum is external to the boiler. The external downcomer and riser system ensures adequate cooling of the tubes and the tube sheet, which is refractorylined; ferrules are also used for further protection of the tube sheet. Ferrules are generally made of ceramic material and are used to transfer the heat from the hot flue gases (at about 2800 F) to the tubes, which are cooled by water. The refractory on the tube sheet, which is about 4 in. thick and made of a high grade, high density castable, lowers the tube sheet temperature at the hot end and thus limits the thermal stress across it. The inlet gas chamber is also refractory-lined. The casing is kept above 350–400 F through a combination of internal and external insulation to minimize concerns regarding acid dew point corrosion. This is often referred to as ‘‘hot casing.’’ Q8.56 discusses this concept. The exit gas chamber is externally insulated, as are also the drum, downcomer, riser pipes, and exchanger. The high pressure saturated steam, which is generated at about 600– 650 psig, is purified by using steam drum internals and sent for process use. About 65–70% of the sulfur is removed in the boiler as liquid sulfur by using heated drains.

Though the boiler generally operates above the sulfur dew point, some sulfur may condense at partial loads and during transient start-up or shutdown mode. The cooled gases exiting the exchanger are reheated to maintain acceptable reaction rates and to ensure that process gases remain above the sulfur dew point and are sent to the catalyst beds for further conversion as shown in Fig. 2.4. The catalytic reactors using alumina or bauxite catalysts operate at lower temperatures, ranging from 200 to 315 C. Because this reaction represents an equilibrium chemical reaction, it is not possible for a Claus plant to convert all of the

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FIGURE 2.5 Waste heat boiler for sulfur recovery plant. (Courtesy of ABCO Industries, Abilene, TX.)

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FIGURE 2.6 Multiple boiler passes connected to a common steam drum. (Courtesy of ABCO Industries, Abilene, TX.)

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FIGURE 2.7 Sulfur condenser. (Courtesy of ABCO Industries, Abilene, TX.)

incoming sulfur to elemental sulfur. Therefore two or more stages are used. Each catalytic stage can recover one half to two-thirds of the incoming sulfur. Acid gas is also introduced at each catalyst stage as shown. The gas stream from each stage is cooled in another low pressure boiler, called the sulfur condenser, which condenses some of the sulfur. These gas streams generate low pressure steam at about 50–70 psig in the sulfur condenser.

If the flue gas quantity is small, a single-shell fire tube boiler handles all the streams from the reactors (Fig. 2.7). Each stage has its own gas inlet and exit connections. The outlet gas temperatures of these exchangers are around 330– 360 F. From the condenser of the final catalytic stage the process stream passes on to some form of tail gas treatment process. The tail gas contains H2S; SO2, sulfur vapor, and traces of other sulfur compounds and is further treated downstream and vented.

SULFURIC ACID PLANT HEAT RECOVERY

Sulfuric acid is an important chemical that is manufactured using the contact process. Heat recovery plays a significant role in this system, whose main objective, is to cool the gas stream to a desired temperature for further processing.

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Raw sulfur is burned with air in a combustion chamber, generating sulfur dioxide, oxygen, and nitrogen. The gases, at about 1900 F and at a pressure of about 50 in. WC, pass through a waste heat boiler generating saturated or superheated steam. The boiler could be of fire tube or water tube design. The gases are cooled to about 800 F, which is the optimum temperature for conversion of SO2 to SO3. The exit gas temperature from the boiler decreases as the load decreases.

In order to maintain the exit gas temperature at 800 F at varying loads, a gas bypass system is incorporated into the boiler, either internally or externally (Fig. 2.8). The gases then pass through a converter where SO2 gets converted to SO3 in a few stages in the presence of catalyst beds. The reactions are exothermic, and the gas temperature increases by 40–100 F. Air heating or superheating of steam is necessary to cool the gases back to 800 F. After the last stage of conversion, most of the SO2 has been converted to SO3. The gas stream containing SO3 gases at about 900 F is cooled in an economizer before being sent to an absorption tower. The flue gas stream is absorbed in dilute sulfuric acid to form concentrated sulfuric acid. The scheme is shown in Fig. 2.9. The steam thus generated in these waste heat boilers is used for process as well as for power generation.

The main boiler behind the sulfur combustor could be of fire tube or water tube design, depending on gas flow. Extended surfaces may also be used if the gas stream has no dust. Sometimes, owing to inadequate air filtration and poor

FIGURE 2.8 Gas bypass systems for HRSG exit gas temperature control.

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FIGURE 2.9 Scheme of a sulfuric acid plant. 1, sulfur combustion furnace; 2, waste heat boiler; 3, contact apparatus; 4, superheater; 5, economizer; 6, absorption tower.

combustion, particulates are present in the flue gases, which could preclude the use of finned tubes. One has to be concerned about the casing design because of the possibility of sulfur condensation and corrosion. Soot blowing is not recommended, because it affects the gas analysis and adds moisture to the flue gases and may cause acid condensation.

Water-cooled furnace designs have an advantage in that the casing operates at the saturation temperature of steam, hence acid corrosion is unlikely. The main concern in sulfuric acid plants is corrosion due to acid condensation from moisture reacting with SO3. This is minimized by starting up and shutting down the plants on clean fuels if possible and avoiding frequent start-ups and shutdowns, which induce a cooler environment for possible acid condensation over the exchanger or economizer tubes. The boiler and exchanger casings must also be maintained above the dew point by using a ‘‘hot casing’’ design, which reduces the heat loss to the surroundings while at the same time keeping the casing hot, above 350–400 F, as required. Boilers may be kept in hot standby if frequent shutdowns and start-ups are likely.

The feedwater temperature as it enters the economizer has to be high, often above 320 F, to minimize acid dew point corrosion because the gas contains SO3. Carbon steel tubes with continuously welded solid fins have been used in several plants in the United States, whereas in Europe and Asia cast iron gilled tubes shrunk over carbon steel tubes are widely used. In a few projects, the sulfur deposits found their way between the gilled iron rings and the tubes and caused corrosion problems. The choice of tube materials is based on the preference and experience of the end user and the boiler supplier.

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The internal gas bypass system increases the shell diameter compared to the external bypass system. The bypass pipe also cools the gases to some extent, so the damper is not exposed to the high temperature gases as in the external bypass system, where the damper is located in a refractory-lined pipe and handles the hot inlet gases. Operability and maintenance of the damper are important aspects of boiler operation. Both internal and external gas bypass systems have been used in the industry.

In fire tube boilers, ferrules and the refractory lining on the tube sheet protect the tube sheet from the hot gases. An external steam drum with downcomers and risers ensures adequate circulation of the steam–water mixture inside the shell.

HEAT RECOVERY IN HYDROGEN PLANTS

Hydrogen and ammonia are valuable chemicals in various processes. The steam reforming process is widely used to produce hydrogen from fossil fuels such as natural gas, oil, or even coal as shown in Fig. 2.10. There are several variations of the process, but basically the steam reforming process converts a mixture of hydrocarbons and steam into hydrogen, methane, and carbon dioxide in the presence of nickel catalyst inside tubes. Before entering the reformer, the natural gas has to be desulfurized in order to protect the reformer tubes and catalysts from sulfur poisoning. The desulfurized gas is mixed with process steam, preheated to about 500 C in the flue gas boiler, then sent through the tubes of the reformer. Reactions occur inside the tubes of the reformer at 800–950 C.

FIGURE 2.10 Steam reforming process in hydrogen plants. 1, natural gas; 2, sulfur removal; 3, reformer; 4, reformed gas boiler; 5, flue gas boiler; 6, shift converter; 7, air preheater; 8, air; 9, CO2 removal and methanation; 10, Pressure Swing Adsorption (PSA); 11, H2 product; 12, stack; 13, CO2 by-product.

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Reforming pressures range from 20 to 40 atm, depending on the process equipment supplier.

CnHm þ nH2O ! nCO þ ðm=2 þ nÞH2

CH4 þ H2O Ð CO þ 3H2

CO þ H2O Ð CO2 þ H2

The overall reaction is highly endothermic, so the reaction heat has to be provided from outside by firing fuel such as natural gas or naphtha outside the tubes. This generates flue gases, typically at 1800 F and atmospheric pressure, that are used to generate high pressure superheated steam in a water tube waste heat boiler, generally referred to as a flue gas boiler. The flue gases also preheat the steam– fuel mixture and air.

In some processes the effluents of the primary reformer are led to the secondary reformer, where they are mixed with preheated air. Chemical reactions occur, and the catalysts convert the methane partly to hydrogen. The effluent from the reformer, called reformed gas, is at a high gas pressure, typically 20–40 atm, and contains hydrogen, water vapor, methane, carbon dioxide, and carbon monoxide. This gas stream is then cooled from about 1600 F to 600 F in a reformed gas boiler, which is generally an elevated drum fire tube boiler (Fig. 2.11) with provision for gas bypass control to maintain the exit gas temperature constant at all loads. The exit gas temperature from the boiler decreases as the duty of the boiler decreases, and the bypass valve adjusts the flow between the incoming hot gases and the cool exit gases to maintain a constant exit gas temperature at all loads. The cooled gases then enter a shift converter, where CO is converted to CO2 in the presence of catalyst and steam. Additional hydrogen is also produced. The exothermic reaction raises the gas temperature to about 800 F. The CO content is reduced from about 13% to 3%. A waste heat boiler referred to as a converted gas boiler cools the gas stream before it enters the next stage of conversion, where CO is reduced to less than 0.3%. The next stage is the methanator, in which catalysts convert traces of CO and CO2 to methane and water vapor. The H2; CO, and unreacted methane are then separated. This produces a gas stream that can be recycled to process feed and produce hydrogen of 98–99% purity that is further purified by the pressure swing adsorption method. In older plants carbon dioxide is removed in a liquid absorption system and finally the gas goes through a methanation step to remove residual traces of carbon oxides.

In large plants, the flue gas and reformed gas boilers are separate units but have a common steam system, whereas in small hydrogen plants these boilers can be combined into a single module. The flue gas boiler is a water tube unit; the reformed and converted gas boilers are fire tube units connected to the same steam drum. The flue gas boiler contains various heating surfaces such as the feed

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FIGURE 2.11 Reformed gas boiler with internal gas bypass system. (Courtesy of ABCO Industries, Abilene, TX.)

preheat coil, evaporator, superheater, economizer, and air heater. The casing is refractory-lined, and extended surfaces are used where feasible because the gas stream is generally clean. The steam generated in the reformed gas boiler is often combined with the saturated steam generated in the flue gas boiler and then superheated in the superheater of the flue gas boiler. This is a substantial quantity of steam (often referred to as import steam), so the performance of the superheater must be checked for cases when the import steam quantity diminishes or is reduced to zero for various reasons.

The reformed gas boiler, which handles gases containing a large volume of hydrogen and water at high pressure, operates at high heat flux; the heat transfer coefficient with reformed gases is about 6–8 times higher than those of typical flue gases from combustion of natural gas; see Q8.64. Hence the heat flux at the inlet to the reformed gas boiler is limited to less than 100,000 Btu=ft2h to minimize concerns about vapor formation over the tubes and possible departure from nucleate boiling conditions (DNB). The gas properties for typical reformed gas and flue gases are listed in Table 8.45 (Chap. 8). The higher thermal conductivity and specific heat and lower viscosity coupled with higher mass

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flow per tube leads to higher heat transfer rates and hence higher heat flux in reformed gas boilers. Note that the heat transfer coefficient is proportional to

specific heat 0:4 ðthermal conductivityÞ0:6 viscosity

as discussed in Q8.02.

Generally fire tube boilers are ideal for high gas pressures, though a few European suppliers have built water tube designs for this application.

GAS TURBINE HRSGs

Gas turbine–based combined cycle and cogeneration plants are springing up throughout the world. The advantages of gas turbine plants are discussed in Chapter 1. Though gas turbine exhaust is used to heat industrial heat transfer fluids and gases, the emphasis here will be on steam generation. Gas turbine exhaust is clean; therefore water tube boilers with extended surfaces are the natural choice for heat recovery applications. It is also relevant here to mention briefly a few peculiar aspects of gas turbine exhaust gases in order to understand the design features of HRSGs better.

As discussed in Chapter 1, gas turbine combustor temperature is limited to about 2400–2500 F for metallurgical reasons. Therefore a large amount of compressed air is used to cool the flame, which in turn increases the exhaust gas flow from the turbine. After expansion in the turbine, the gas exits at about 1000 F and at a few inches of water column above atmospheric pressure. The exhaust gas contains about 6–10% by volume (vol%) of water vapor and about 14 vol% of oxygen. Gas turbines that are heavily injected with steam have a different exhaust gas analysis, which is discussed later. The large amount of oxygen in the exhaust gases enables fuel to be fired in the exhaust gases without the addition of air; the higher gas inlet temperature to the HRSG in turn generates more steam in the HRSG. Because of these large ratio of gas to steam flow compared to steam generators, HRSGs are huge in comparison. For example, the cross section of an unfired HRSG generating, say, 100,000 lb=h of steam will be about 6 times as large as that of a packaged boiler generating the same amount of steam.

Another important aspect of gas turbine HRSGs is that the exhaust gas flow remains nearly constant, and increasing the gas inlet temperature through auxiliary fuel firing increases the steam generation. Unlike in a conventional steam generator, the ratio of gas to steam flow in an HRSG varies significantly with steam generation. This in turn affects the gas and steam temperature profiles in the HRSG.

A water–steam mixture boils at a constant temperature at a given steam pressure; hence the gas temperature distribution across the HRSG surfaces is influenced by the saturation temperature of steam. Generally, the lower the gas

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