Steam generator

(PD) Photo: Yo-sei Shoshi
Figure 1: Power plant of the Tokyo Electric Power Company (TEPCO), in Yokohama , Japan, fueled with liquified natural gas (LNG)

A steam generator is a device that uses a heat source to boil liquid water and convert it into its vapor phase, referred to as steam. The heat may be derived from the combustion of a fuel such as coal, petroleum fuel oil, natural gas, municipal waste or biomass, a nuclear fission reactor and other sources.

There are a great many different types of steam generators ranging in size from small medical and domestic humidifiers to large steam generators used in conventional coal-fired power plants that generate about 3,500 kilograms of steam per megawatt-hour of energy production. The adjacent photo depicts an 1150 MW power plant with three steam generators which generate a total of about 4,025,000 kg/hour of steam.

Many small commercial and industrial steam generators are referred to as "boilers". In common usage, domestic water heaters are also referred to as "boilers", however they do not boil water nor do they generate any steam.

Evolution of steam generator designs

(CC) Drawing: Ruben Castelnuovo
Figure 2: Simplified schematic diagram of a fire tube boiler.

Fire-tube boilers

In the late 18th century, various design configurations of fire-tube boilers began to be widely used for steam generation in industrial plants, railway locomotives and steamboats. Fire-tube boilers are so named because the fuel combustion product gases (flue gas) flow through tubes surrounded by water contained in an outer cylindrical drum (see Figure 2). Today, steam-driven locomotives and river boats have virtually disappeared and fire-tube boilers are not used for steam generation in modern utility power plants.

However, they are still used in some industrial plants to generate saturated steam at pressures of up to about 18 bar and at rates ranging up to about 25,000 kg/hour. In that range, fire-tube boilers offer low capital cost, operational reliability, rapid response to load changes and no need for highly skilled labor.

The major shortcoming of fire-tube boilers is that the water and steam are contained within the outer cylindrical shell and that shell is subject to size and pressure limitations. The tensile stress (or hoop stress) on the cylindrical shell walls is a function of the shell diameter and the internal steam pressure:

$\sigma ={\frac {p\,d}{2\,t}}$

where σ is the tensile stress (hoop stress) in Pa, p is the internal gauge pressure in Pa, d is the internal diameter of the cylindrical shell in m and t is the thickness of the cylindrical shell wall in m.

The ever-growing need for increased quantities of steam at higher and higher pressures could not be provided by fire-tube boilers because, as can be seen in the above equation, both higher pressures and larger diameter shells led to prohibitively thicker and more expensive shells.

(PD) Image: Babcock & Wilcox Company
Figure 3: Representation of a water-tube boiler in the early 1900s.

(PD) Drawing: The Stirling Company
Figure 4: A Stirling four drum boiler

Water-tube boilers

Water-tube boilers with longitudinal steam drums, as in Figure 3, were developed to allow increases in generated steam pressure and increased capacity. The water-tube boilers, in which water flowed through inclined tubes and the combustion product gases flowed outside the tubes, put the desired higher steam pressures in the small diameter tubes which could withstand the tensile stress of higher pressures without requiring excessively thick tube walls.

The relatively smaller steam drums (in comparison with the fire-tube shells) were also capable of withstanding the tensile stress of the desired higher pressures without needing excessively thick drum walls.

The water-tube boiler went through several stages of design and development. The steam drum was arranged either parallel to the tubes (as shown in Figure 3) or transverse to the tubes, in which case the boiler was referred to as being a "cross drum" rather than a "longitudinal drum" boiler. Cross drum boilers could accommodate more tubes than longitudinal drum boilers and they were designed to generate steam pressures of up to about 100 bar and at rates ranging up to about 225,000 kg/hour.

The next stage of development involved using slightly bent tubes, three to four steam drums and one to two mud drums at the bottom of the tubes (see Figure 4). The three sets of bent tubes, as shown in Figure 4, each represent a bank of tubes extending from the front of the steam drums back to the rear of the drums. Thus, the longer the steam drums, the more tubes were available and the more heat transfer surface was available. The tubes were bent slightly so that they entered and exited the steam drums radially. Baffles made of firebrick forced the flue gas to travel upwards from the mud drum to the right-hand steam drum and then downwards from the middle steam drum to the mud drum and finally upwards to the left-hand steam drum and out the flue gas exit in the upper left-hand corner. in essence, as shown in Figure 4, the baffles created a multi-pathway for the flue gas.

The mud drums were suspended from the bottom of the tube banks and were free to move when the tube banks expanded as they heated up during boiler start-ups or contracted as they cooled down during boiler shutdowns. The purpose of the mud drum was to collect any solids that precipitated out from the water and the mud drums had provisions for blow-down of the collected solid.

Referring again to Figure 4, the fuel combustion zone was located in the lower right-hand section of the boiler and the design included provisions for an adequate combustion air supply as well as adequate flue gas stack draft.

Such designs were referred to as Stirling boilers, named after Alan Stirling who designed his first boiler in 1883 and patented it in 1892, four years after forming the Stirling Boiler Company of New York in 1888. One of the important advantages of the Stirling design was that the tubes were readily accessible, which made for easier inspection and maintenance or replacement of the tubes.

The Stirling boilers with four steam drums were superseded by a simpler two drum design with a steam drum directly above a water (mud) drum and bent water tubes connecting the two drums. Later designs of the two drum version had a single flue gas path. In general, the Stirling boiler was capable of handling rapidly varying loads and was also adaptable to using various fuels. It could be said that the Stirling boilers were the forerunners of the modern steam generators used in power plants.

The Babcock and Wilcox Company purchased and assimilated the Stirling Boiler Company in 1906 and began mass production of the Stirling boilers. Although widely used for large steam generating plants in the period between 1900 and World War II (the early 1940's), Stirling boilers are rarely seen today.

Modern power plant steam generators

The large steam generators used in modern power plants to generate electricity are almost entirely some type of water-tube design, owing to their ability to operate at higher pressures.

(PD) Image: Milton Beychok
Figure 5A: Large, coal-fired subcritical steam generator in a power plant.

(CC) Photo: Matthew High
Figure 5B: Two 750 MW oil and gas-fired, supercritical steam to electric power plants at Moss Landing, California

Power plants using fuel combustion heat for steam generation

Plants generating electric power with steam generated from fuel combustion heat may burn coal, petroleum fuel oil, natural gas, municipal waste or biomass. Depending upon whether the pressure of the steam being generated is below or above the critical pressure of water (221 bar), a power plant steam generator may be either a subcritical (below 221 bar) or a supercritical (above 221 bar) steam generator. Figure 1 (see above) is a photo that shows the magnitude of a large modern power plant that generates subcritical steam from combustion of a fuel and Figure 5B is a photo that shows the magnitude of a large supercritical steam power plant.

The output superheated steam from subcritical steam generators, in power plants using fuel combustion, usually range in pressure from 130 to 190 bar, in temperature from 540 to 560 °C and at steam rates ranging from about 400,000 to about 5,000,000 kg/hour. The adjacent Figure 5A provides a schematic diagram of a typical electric power plant using fuel combustion to generate subcritical steam and Figure 5B depicts the physical appearance of such power plants. The overall height of such steam generators ranges up to about 70 metres.

As shown, the unit has a steam drum and uses water-tubes embedded in the walls of the generator's furnace combustion zone. The saturated steam from the steam drum is superheated by flowing through tubes heated by the hot combustion gases. The hot combustion gases are also used to preheat the boiler feedwater entering the steam drum and the combustion air entering the combustion zone.

There are three configurations for such steam generators:

• Natural circulation in which liquid water flows downward from the steam drum via the downcomer (see Figure 5A) and a mixture of steam and water returns to the steam drum by flowing upward via the tubes embedded in the furnace wall. The difference in density between the downward flowing liquid water and the upward flowing mixture of steam and liquid provides sufficient driving force to induce the circulating flow.

• Forced circulation in which a pump in the downcomer provides additional driving force for the circulating flow. The assistance of a pump is usually provided when generating steam at above about 170 bar because, at pressures above 170 bar, the density difference between the downcomer liquid and the liquid-steam mixture in the furnace wall tubes is reduced sufficiently to limit the circulating flow rate.

• A once-through system in which no steam drum is provided and the boiler feedwater goes through the economizer, the furnace wall tubes and the superheater section in one continuous pass and there is no recirculation. In essence, the feedwater pump supplies the motive force for the flow through the system.

Figure 6 below schematically depicts the three configurations:

(PD) Diagram: Milton Beychok
Figure 6: Thermal power plant steam generator configurations

The critical point of a pure substance denotes the conditions above which distinct liquid and gas phases do not exist and there is no phase boundary between liquid and gas. As the critical point is approached, the properties of the gas and liquid phases approach one another, resulting in only one phase at the critical point: a homogeneous supercritical fluid. Thus, for supercritical steam generators, the once through system in Figure 6 is the configuration of choice, since there is no liquid or vapor above the critical point and there is no need for a steam drum to separate the non-existing liquid and gas phases. The term "boiler" should not be used for a supercritical pressure steam generator, as no "boiling" actually occurs in such systems.

A number of pioneering supercritical pressure once-through systems were built for the utility industry, many with pressures in the range of 310 to 340 bar and temperatures of 620 to 650 °C (well above the critical point of water). To reduce operational complexity and improve equipment reliability, subsequent supercritical systems were built at more moderate conditions of about 240 bar and 540 to 565 °C. The primary disadvantage of supercritical steam generators is the need for extremely pure feedwater, in the order of about 0.1 ppm by weight of total dissolved solids (TDS).

(CC) Photo: Peter J. Baer
Figure 7A: HRSGs for two combined cycle power plant units

(PD) Photo: Tennessee Valley Authority
Figure 7B: TVA's Caledonia combined cycle power plant (3 units)

Heat recovery steam generators

A heat recovery steam generator (HRSG) is a heat exchanger or series of heat exchangers that recovers heat from a hot gas stream and uses that heat to produce steam for driving steam turbines or as process steam in industrial facilities or as steam for district heating.

An HRSG is an important part of a combined cycle power plant (CCPP) or a cogeneration power plant. In both of those types of power plants, the HRSG uses the hot flue gas at approximately 500 to 650 °C from a gas turbine to produce high-pressure steam. The steam produced by an HRSG in a gas turbine combined cycle power plant is used solely for generating electrical power. However, the steam produced by an HRSG in a cogeneration power plant is used partially for generating electrical power and partially for district heating or for process steam.

The combined cycle power plant, schematically depicted in Figure 8 below, is so named because it combines the Brayton cycle for the gas turbine and the Rankine cycle for the steam turbines. About 60 percent of the overall electrical power generated in a CCPP is produced by an electrical generator driven by the gas turbine and about 40 percent is produced by another electrical generator driven by the high-pressure and low-pressure steam turbines. For large scale power plants, a typical CCPP might use sets consisting of a gas turbine driving a 400 MW electricity generator and steam turbines driving a 200 MW generator (for a total of 600 MW), and the power plant might have 2 or more such sets.

The primary component heat exchangers of an HRSG are the economizer, the evaporator and its associated steam drum and the superheater as shown in Figure 9 below. An HRSG may be in horizontal ducting with the hot gas flowing horizontally across vertical tubes as in Figure 9 or it may be in vertical ducting with the hot gas flowing vertically across horizontal tubes. In either horizontal or vertical HRSGs, there may be a single evaporator and steam drum or there may be two or three evaporators and steam drums producing steam at two or three different pressures. Figure 9 depicts an HRSG using two evaporators and steam drums to produce high pressure steam and low pressure steam, with each evaporator and steam drum having an associated economizer and superheater. In some cases, supplementary fuel firing may be provided in an additional section at the front end of the HRSG to provide additional heat and higher temperature gas. Figures 7A and 7B (just above) shows the actual physical appearance of horizontal HRSGs in a multi-unit combined cycle power plant.

(PD) Diagram: Milton Beychok Figure 8: Schematic diagram of a typical combined cycle power plant

(PD) Drawing: Milton Beychok Figure 9: Layout of typical HRSG in a combined cycle power plant

There are a number of other HRSG applications. For example, some gas turbines are designed to burn liquid fuels (rather than fuel gas) such as petroleum naphtha or diesel oil and others burn the syngas (synthetic gas) produced by coal gasification in an integrated gasification combined cycle plant commonly referred to as an IGCC plant. As another example, a combined cycle power plant may use a diesel engine rather than a gas turbine. In almost all such other applications, HSRGs are used to produce steam to be used for power generation.

Nuclear power plant steam generation

(PD) Drawing: Milton Beychok
Figure 10: The two most common types of nuclear power plants

The Calder Hall nuclear power plant in the United Kingdom was the world's first nuclear power plant to produce electricity in commercial quantities and began operations in 1956. The Shippingport Atomic Power Station in Shippingport, Pennsylvania was the first commercial nuclear power plant in the United States of America and was opened in 1957. As of 2007, There were more than 430 operational nuclear power plants worldwide and they produced about 15% of the world's electricity.

There are a good many different types of nuclear power plants, but the two most prevalent operational plants use either a Boiling Water Reactor (BWR) or a Pressurized Water Reactor (PWR). Figure 10 presents a schematic diagram of how steam is generated in those two types of nuclear power plants:

• In the BWR, the nuclear reactor's coolant water is boiled into saturated steam within the reactor itself by absorbing the heat created by the nuclear fission reaction. The steam produced within the reactor is generally at a pressure of about 70 to 75 bar and a temperature of about 290 to 300 °C and is routed to the turbine-generators outside the reactor containment structure for conversion into electricity.

• In the PWR, the reactor's coolant water is pressurized up to as much as 160 bar of pressure and 330 °C of temperature and there is no boiling within the reactor. The hot, pressurized coolant water flows through heat exchange tubes within a steam generator where it exchanges heat with the generator's feedwater and converts it into steam. The reactor coolant water is then pumped back to the reactor. The top section of the generator is a steam-water separator. The flow of coolant water from the reactor through the steam generator and back to reactor is referred to as the primary loop. The flow of feedwater into the steam generator, conversion of the feedwater into steam , flowing the steam through the turbine-generators located outside the containment structure, condensing of the exhaust steam from the turbine-generators and recycling of the condensed steam as feedwater to the steam generator is referred to as the secondary loop. All of the primary loop is located within the nuclear reactor containment structure. The secondary loop is partially within the containment structure and partially outside the structure.

Thus, in essence, the steam generator in a BWR nuclear reactor is the reactor itself and the steam generator in a PWR reactor is simply a vertical heat exchanger. Both the BWR and PWR plants generate saturated steam at essentially the same temperature and pressure, and both may use either light water (ordinary water) or heavy water as the reactor coolant. About 65% of the total power generated by nuclear power plants is from PWR reactor systems.

(PD) Drawing: Milton Beychok
Figure 11: Schematic flow diagram of the SEGS concentrated solar power plants in the Mojave Desert.

Solar power steam generators

Solar power is the generation of electricity from sunlight and it can be accomplished with photovoltaics which uses an array of cells containing material that converts sunlight directly into electricity. This method does not involve the generation of steam.

Solar power can also be accomplished indirectly by using lenses or mirrors to focus solar radiation into a concentrated beam of heat. The concentrated beam is then used as a heat source to generate steam for conversion into electric power. This method is referred to as concentrated solar power (CSP) and there are a number of different designs for concentrating solar radiation. The various designs all operate on the same simple principle of reflecting and concentrating sunlight and vary from one another by the use of different types of mirrors.

As of 2009, of all the various CSP plants in operation worldwide, the largest ones are the solar energy generating systems (SEGS) plants operating in California's Mojave Desert. Figure 11 presents a schematic flow diagram of the SEGS plants which use large fields of parallel trough mirrors. The mirrors focus their concentrated beam of heat on pipes located above the center of the troughs that run the length of the mirror fields and contain a circulating heat transfer fluid (HTF) (a synthetic oil). The HTF entering the mirror field is at about 270 °C and it is heated to about 390 °C as it flows through the mirror field. The hot HTD is then used in a series of heat exchangers as shown in Figure 11 to generate superheated steam at a pressure of about 100 bar and a temperature of about 375°C. The superheated steam is then routed to steam turbines that drive electricity generators in the same types and arrangement of equipment as used in conventional fuel-fired steam generators.

After the HTF has been though the series of heat exchangers, it flows into an expansion tank from which it is pumped back to the inlet of the mirror fields.

There were nine SEGS plants constructed, the first one in 1984 and the last one in 1990, and they have now been in reliable operation for many years. Their total design output was 354 MW. The last and largest unit (SEGS IX) was designed for an 80 MW output and has 484,000 m² of mirror fields.

Some of the SEGS plants have a thermal energy storage system (see Figure 11) where molten salt at 290 °C may be heated to 370 °C and stored for subsequent use as supplemental heating of the HTF when needed. Some of the plants also have a fuel-fired steam generator for use when needed. Figures 12 and 13 depict the parabolic trough mirrors as well as the mirror fields.

(PD) Photo: National Oceanic and Atmospheric Administration Figure 12: Parabolic trough mirrors used in concentrated solar power plants

(PD) Photo: Sandia National Laboratory Figure 13: Fields of parabolic trough mirrors at the SEGS solar power plants in the Mojave Desert

Other types of steam generators

(CC) Drawing: Milton Beychok
Figure 14: Kettle-type steam generator

Kettle-type exchangers

Petroleum refineries, petrochemical plants and other process plants often have many waste heat sources that can be used for producing steam, usually saturated steam. In many such cases, a kettle-type exchanger (the same type as the kettle reboilers used for many industrial distillation towers) is used as a steam generator.

Figure 14 is a schematic diagram of a kettle-type heat exchanger designed to produce saturated steam. The hot fluid denoted in the figure could be either a hot liquid or a hot vapor stream.

The kettle-type heat exchanger is limited to generating low-pressure steam for the same reason that applies to fire-tube boilers (see above), namely that the thickness of the exchanger's outer shell would become impractical at very high pressures.

Waste heat steam generation in copper smelting

(CC) Diagram: Milton Beychok
Figure 15: Outokumpu flash smelting of copper

The are a good many methods used for extracting metallic copper (Cu) from copper-bearing ores. One of those methods is to use a process known flash smelting and there various designs for flash smelters: the Outokumpu process, the INCO process, the Mitsubishi process, the Noranda process and the WORCRA process. The most commonly used copper flash smelter by far is the Outokumpu process developed in Finland, during the late 1940s, which is described just below.

The copper-bearing ore is usually chalcopyrite (CuFeS₂) which is first crushed and ground and then subjected to a flotation process to produce a concentrate that contains between 20 and 40 percent copper. That concentrate is then fed, along with oxygen-enriched air, into a flame in the reaction section (called the reaction shaft) of the Outokumpu flash smelter. The flame is initially ignited by natural gas or other fuel and subsequently is maintained by the combustion of the sulfur contained in the copper concentrate feedstock.

As shown in Figure 15, the settler section of flash smelter contains molten matte and slag, which is at a temperature of about 1350 °C. The matte (50 to 70 percent copper) may sometimes also be called blister copper and is withdrawn for subsequent conversion into the endproduct metallic copper. The slag contains most of the impurities in the feedstock and is mostly discarded.

The combustion product offgas may contain between 20 and 60 percent gaseous sulfur dioxide (SO₂) and is at a temperature of about 1300 °C. The hot combustion gas is used to exchange heat with pressurized water and thereby generate steam in what the smelting industry calls waste heat boilers (WHBs) or tunnel boilers. The hot combustion gas also contains small solid particles (dust) and about 60 to 65 percent of that dust is periodically removed from the heat exchange tubes within the WHBs by spring hammers. The remainder of the dust is removed in an electrostatic precipitator (ESP) after the gas has been cooled to a temperature that can be tolerated by an ESP, namely about 350 °C or less. The dust is subsequently recycled back into the reaction shaft feedstock. The dust-free SO₂-rich gas from the ESP is sent to another plant for conversion into sulfuric acid (H₂SO₄).

The WHBs typically generate saturated steam at a pressure of about 40 to 60 bar and a temperature of about 250 to 285 °C. The first WHB in Figure 15 is the so-called radiant section, the second WHB is the so-called convection section and a single steam drum serves both sections.. Due to size constraints, Figure 15 does not show the steam drum or the various heat exchange tubes in the WHBs, but they are similar to the HRSGs shown in Figure 9 above.