The steam generator system’s primary function is to convert chemical or nuclear energy bound in the fuel to heat and produce high temperature, high pres- sure steam. The variety of fuel sources, the high tem- perature nature of these processes, and the large number of subsystem interfaces contribute to the chal- lenging nature of the design process. The initial steps in evaluating the steam generating system include es- tablishing key interfaces with other plant systems and with the power cycle. These are typically set by the end user or consulting engineer after an in-depth evaluation indicates: 1) the need for the expanded power supply or steam source, 2) the most economical fuel selection and type of steam producing system, 3) the plant location, and 4) the desired power cycle or process steam conditions. The key requirements fall into six major areas:
1. Steam minimum, nominal, and maximum flow rates; pressure and temperature; need for one or more steam reheat stages; auxiliary equipment steam usage; and future requirements.
2. Source of the steam flow makeup or replacement wa- ter supply, water chemistry and inlet temperature. 3. The type and range of fuels considered, including
worst case conditions, and the chemical analyses (proximate and ultimate analyses) for each fuel or mixture of fuels.
4. Elevation above sea level, overall climate history and forecast, earthquake potential and space limitations. 5. Emissions control requirements and applicable
government regulations and standards.
6. The types of auxiliary equipment; overall plant and boiler efficiency; access needs; evaluation penalties, e.g., power usage; planned operating modes including expected load cycling require- ments, e.g., peaking, intermediate or base load; and likely future plant use.
When these interfaces are established, boiler design and evaluation may begin.
Systematic approach
There are a variety of evaluation approaches that can be used to meet the specific steam generator per- formance requirements. These include the multiple iterations commonly found in thermal design where real world complexities and nonlinear, noncontinuous interactions prevent a straightforward solution. The process begins by understanding the particular appli- cation and system to define conditions such as steam flow requirements, fuel source, operating dynamics, and emissions limits, among others. From these, the designer proceeds to assess the steam generator op- tions, interfaces, and equipment needs to achieve per- formance. Using a coal-fired boiler as an example, a systematic approach would include the following:
1. Specify the steam supply requirements to define the overall inputs of fuel, air and water, and the steam output conditions.
2. Evaluate the heat balances and heat absorption by type of steam generator surface.
3. Perform combustion calculations to define heat in- put and gas flow requirements.
4. Configure the combustion system to complete the combustion process while minimizing emissions (fuel preparation, combustion and air handling). 5. Configure the furnace and other heat transfer sur- faces to satisfy temperature, material, and perfor- mance tradeoffs while meeting the system control needs.
6. Size other water-side and steam-side components. 7. Specify the back-end tradeoffs on the final heat recovery devices such as water heaters (economiz- ers) and air heaters.
8. Check the steam generating system performance to ensure that the design criteria are met.
9. Verify overall unit performance.
10. Repeat steps 2 through 9 until the desired steam mass flow and temperature are achieved over the specified range of load conditions.
11. Use American Society of Mechanical Engineers (ASME) Code rules to design pressure parts to meet the anticipated operating conditions and com- plete detailed mechanical design.
12. Design and integrate environmental protection equipment to achieve prescribed emissions levels. 13. Incorporate auxiliaries as needed, such as tube surface cleaning equipment, fans, instrumenta- tion and controls, to complete the design and as- sure safe and continuous operation.
The life cycle and daily operation of the steam gen- erator (and the plant in which it will operate) are important elements to be considered from the begin- ning of the design and throughout the design process. Today, some steam generators will be required to op- erate efficiently and reliably for up to 60 years or more. During this time, many components will wear out because of the aggressive environment, so routine inspection of pressure parts is needed to assure con- tinued reliability. Unit operating procedures, such as the permitted severity and magnitude of transients, may be monitored to prevent reduced unit life. Oper- ating practices including water treatment, cycling op- eration procedures, and preventive maintenance pro- grams, among others, can significantly affect steam generator availability and reliability. Key unit com- ponents may be upgraded to improve performance. In each case, decisions made during the design phase and subsequent operation can substantially enhance the life and performance of the unit.
System design example
Now that the basic fossil fuel and nuclear steam generating systems have been described, it is appro- priate to explore the general design and engineering process. While each of the many systems requires spe- cialized evaluations, they share many common ele- ments. To illustrate how the design process works, a small industrial B&W PFI gas-fired boiler has been selected for discussion. (See Figs. 22 and 23.)
Basically, the customer has one overriding need: when the valve is turned on, steam is expected to be
supplied at the desired pressure, temperature and flow rate. In this example, the customer specifies 400,000 lb/h (50.4 kg/s) of superheated steam at 600 psi (4.14 MPa) and 850F (454C). The customer has agreed to supply high purity feedwater at 280F (138C) and to supply natural gas as a fuel source. As with all steam generating systems, there are a number of additional constraints and requirements as discussed in Steam
generator interfaces, but the major job of the steam
generator or boiler is to supply steam.
Combustion of the natural gas produces a stream of combustion products or flue gas at perhaps 3600F (1982C). To maximize the steam generator thermal efficiency, it is important to cool these gases as much as possible while generating the steam. The minimum flue gas outlet temperature is established based upon technical and economic factors (discussed below). For now, a 310F (154C) outlet temperature to the exhaust stack is selected. The approximate steam and flue gas temperature curves are shown in Fig. 24 and define the heat transfer process. The heat transfer surface for the furnace, boiler bank, superheater and air heater is approximately 69,000 ft2 (6410 m2).
From a design perspective, the PFI boiler can be viewed as either a steam heater or gas cooler. The lat- ter approach is most often selected for design. The design fuel heat input is calculated by dividing the steam heat output by the target steam generator ther- mal efficiency. Based upon the resulting fuel flow, com- bustion calculations define the air flow requirements and combustion products gas weight. The heat trans- fer surface is then configured in the most economical way to cool the flue gas to the temperature necessary for the target steam generator efficiency. Before pro- ceeding to follow the gas through the cooling process, the amount of heat recovery for each of the different boiler surfaces (superheater and boiler) must be established.
Fig. 25 illustrates the water heating process from an inlet temperature of 280F (138C) to the superheater
steam outlet temperature of 850F (454C). This curve indicates that about 20% of the heat absorbed is used to raise the water from its inlet temperature to the saturation temperature of 490F (254C). 60% of the energy is then used to evaporate the water to produce saturated steam. The remaining 20% of the heat in- put is used to superheat or raise the steam tempera- ture to the desired outlet temperature of 850F (454C). The fuel and the combustion process selected set the geometry of the furnace. In this case, simple circular burners are used. The objective of the burners is to mix the fuel and air rapidly to produce a stable flame and complete combustion while minimizing the forma- tion of NOx emissions. Burners are available in sev-
eral standardized sizes. The specific size and number are selected from past experience to provide the de- sired heat input rate while permitting the necessary level of load range control. The windbox, which dis- tributes the air to individual burners, is designed to provide a uniform air flow at low enough velocities to permit the burners to function properly.
The furnace volume is then set to allow complete fuel combustion. The distances between burners and between the burners and the floor, roof, and side walls are determined from the known characteristics of the particular burner flame. Adequate clearances are specified to prevent flame impingement on the furnace surfaces, which could overheat the tubes and cause tube failures.
Once the furnace dimensions are set, this volume is enclosed in a water-cooled membrane panel surface. This construction provides a gas-tight, all steel enclo- sure which minimizes energy loss, generates some steam and minimizes furnace maintenance. As shown in Fig. 23, the roof and floor tubes are inclined slightly to enhance water flow and prevent steam from collect- ing on the tube surface. Trapped steam could result in overheating of the tubes. Heat transfer from the flame to the furnace enclosure surfaces occurs primarily by thermal radiation. As a result, the heat input rates per Fig. 23 Small industrial boiler – sectional view.
unit area of surface are very high and relatively inde- pendent of the tubewall temperatures. Boiling water provides an effective means to cool the tubes and keep the tube metal temperatures within acceptable limits as long as the boiling conditions are maintained.
Fig. 26 shows the effect of the furnace on gas tem- perature. The gas temperature is reduced from 3600 at point A to 2400F at point B (1982 to 1316C), while boiling takes place in the water walls (points 1 to 2). A large amount of heat transfer takes place on a small amount of surface. From the furnace, the gases pass through the furnace screen tubes shown in Fig. 23. The temperature drops a small amount [50F (28C)] from points B to C in Fig. 26, but more importantly, the superheater surface is partially shielded from the furnace thermal radiation. The furnace screen tubes are connected to the drum and contain boiling water. Next, the gas passes through the superheater where the gas temperature drops from 2350 at point C to 1750F at point D (1288 to 954C). Saturated steam from the drum is passed through the superheater tub- ing to raise its temperature from 490F (254C) satura- tion temperature to the 850F (454C) desired outlet tem- perature (points 5 to 4).
The location of the superheater and its configura- tion are critical in order to keep the steam outlet tem- perature constant under all load conditions. This in- volves radiation heat transfer from the furnace with convection heat transfer from the gas passing across the surface. In addition, where dirty gases such as combustion products from coal are used, the spacing of the superheater tubes is also adjusted to accommo- date the accumulation of fouling ash deposits and the use of cleaning equipment.
After the superheater, almost half of the energy in the gas stream has been recovered with only a small amount of heat transfer surface [approximately 6400 ft2 (595 m2)]. This is possible because of the large tem-
perature difference between the gas and the boiling
water or steam. The gas temperature has now been dra- matically reduced, requiring much larger heat transfer surfaces to recover incremental amounts of energy.
The balance of the steam is generated by passing the gas through the boiler bank. (See Figs. 22 and 23.) This bank is composed of a large number of water- containing tubes that connect the steam drum to a lower (mud) drum. The temperature of the boiling water is effectively constant (points 5 to 6 in Fig. 26), while the gas temperature drops by almost 1000F (556C) to an outlet temperature of 760F (404C), be- tween points D and E. The tubes are spaced as closely as possible to increase the gas flow heat transfer rate. If a particulate-laden gas stream were present, the spacing would be set to limit erosion of the tubes, re- duce the heat transfer degradation due to ash depos- its, and permit removal of the ash. Spacing is also controlled by the allowable pressure drop across the bank. In addition, a baffle can be used in the boiler bank bundle to force the gas to travel at higher veloc- ity through the bundle, increase the heat transfer rate, and thereby reduce the bundle size and cost. To re- cover this additional percentage of the supplied en- ergy, the boiler bank contains more than 32,000 ft2
(3000 m2) of surface, or approximately nine times more
surface per unit of energy than in the high tempera- ture furnace and superheater. At this point in the process, the temperature difference between the satu- rated water and gas is only 270F (150C), between points 6 and E in Fig. 26.
Economics and technical limits dictate the type and arrangement of additional heat transfer surfaces. An economizer or water-cooled heat exchanger could be used to heat the makeup or feedwater and cool the gas. The lowest gas exit temperature possible is the inlet temperature of the feedwater [280F (138C)]. However, the economizer would have to be infinitely large to accomplish this goal. Even if the exit gas temperature is 310F (154C), the temperature difference at this point in the heat exchanger would only be 30F (17C), still making the heat exchanger relatively large. In- stead of incorporating an economizer, an air preheater could be used to recover the remaining gas energy and preheat the combustion air. This would reduce the Fig. 24 Industrial boiler – temperature versus heat transfer surface.
natural gas needed to heat the steam generator. Air heaters can be very compact. Also, air preheating can enhance the combustion of many difficult to burn fu- els such as coal. All of the parameters are reviewed to select the most economical solution that meets the tech- nical requirements.
In this case, the decision has been made to use an air heater and not an economizer. The air heater is designed to take 80F (27C) ambient air (point 9) and increase the temperature to 570F (299C), at point 8. This hot air is then fed to the burners. At the same time, the gas temperature is dropped from 760F (404C) to the desired 310F (154C) outlet temperature (points E to F). If a much lower gas outlet temperature than 310F (154C) is used, the heat exchanger surfaces may become uneconomically large, although this is a case by case decision. In addition, for fuels such as oil or coal which can produce acid constituents in the gas stream (such as sulfur oxides), lower exit gas tem- peratures may result in condensation of these constitu- ents onto the heat transfer surfaces, and excessive corrosion damage. The gas is then exhausted through the stack to the atmosphere.
Finally, the feedwater temperature increases from 280F (138C) to saturation temperature of 490F (254C). In the absence of an economizer, the feedwater is supplied directly to the drum where it is mixed with the water flowing through the boiler bank tubes and furnace. The flow rate of this circulating water in industrial units is approximately 25 times higher than the feedwater flow rate. Therefore, when the feedwater is mixed in the drum, it quickly ap- proaches the saturation temperature without appre- ciably lowering the temperature of the recirculating water in the boiler tubes.
Reviewing the water portion of the system, the feed- water is supplied to the drum where it mixes with the recirculating water after the steam is extracted and sent to the superheater. The drum internals are spe-
cially designed so that the now slightly subcooled water flows down through a portion of the boiler bank tubes to the lower or mud drum. This water is then distributed to the remainder of the boiler bank tubes (also called risers) and the furnace enclosure tubes where it is partially converted to steam (approximately 4% steam by weight). The steam-water mixture is then returned to the steam drum. Here, the steam- water mixture is passed through separators where the steam is separated from the water. The steam is then sent to the superheater, and from there to its end use. The remaining water is mixed with the feedwater and is again distributed to the downcomer tubes.