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

TABLE 3.5 Effect of Excess Air and Exit Gas Temperature on Efficiencya

a Steam flow ¼ 100,000 lb=h, 300 psig sat, feedwater temp ¼ 230 F, 2% blowdown, ambient temp ¼ 80 F, relative humidity ¼ 60%, boiler duty ¼ 100.8 MM Btu=h, fuel cost ¼ $3=MM Btu.

As shown in Tables 3.4 and 3.7, the efficiency of packaged boilers varies with load. This information may be used as a planning tool as discussed, particularly when the plant has HRSGs in addition to steam generators.

Combination Firing

Boiler efficiency calculations are done using ASME PTC 4.1 methods, as shown in Q6.19. When a combination of fuels is fired, the calculations can be involved. The results from a program developed are shown in Fig. 3.14. They show the performance of a boiler firing two different fuels at the same time. Based on the exit gas temperature and measured or predicted oxygen for the flue gas mixture, one can simulate the excess air and obtain the performance with individual fuels first and then obtain the combined effect on air and gas flows, flue gas analysis, combustion temperatures, heat losses, and efficiency.

BURNERS

The fuel burner is an important component of any boiler. Burner designs have undergone several iterations during the last decade. Burner suppliers such as Coen and Todd are offering burners that result in single-digit NOx emissions and very low CO levels, competing with the SCR system presently used in the industry for single-digit NOx emissions. However, these burners use a large amount of flue gas recirculation, and flame stability at low loads is a concern. Development work is going on to improve on these results. Fuel or air staging and

Copyright © 2003 Marcel Dekker, Inc.

FIGURE 3.14 Efficiency calculations for simultaneous firing of fuels.

steam injection are the other methods used by burner suppliers to control NOx. Today single burners are used for capacities up to 300–350 MM Btu=h on gas or oil firing.

Often more than one fuel is fired in the burner. When different gaseous fuels are fired in a burner, the fuel gas pressure has to be adjusted at the burner inlet to ensure proper fuel flow.

Example 6

Let us say that a burner is firing 5 MM Btu=h on LHV basis using a fuel of lower heating value, 1400 Btu=ft3, and molecular weight 25.8 at a pressure of 30 psig. Assuming the nozzles remain the same, what should be done when a fuel of

Copyright © 2003 Marcel Dekker, Inc.

heating value 700 Btu=ft3 whose molecular weight is 11.6 is fired, the duty being the same?

Solution: The gas pressure should be adjusted; otherwise it would be difficult to control the heat input. The pressure drop across the nozzles is related to the flow of fuel as follows (Subscripts 1 and 2 refer to fuels 1 and 2):

DP1 ¼ KW 2=MW ¼ KQ2MW

K is a constant ¼ 30=Q1 MW

Basically we are converting the pressure drop equation from mass to volumetric flow.

Because the heat input by both fuels is the same,

Q1 LHV1 ¼ Q2 LHV2

where LHV is the lower heating value of the fuel, Btu=ft3. 30

Q21 MW1

Rewriting Q2 in terms of Q1 and simplifying, we have

700 2 25:8 ¼ 17 psi 1400 11:6

Thus we should have a lower fuel gas pressure to ensure the same heat input.

COMBUSTION CONTROLS

The function of a combustion control system is to ensure that the steam generation matches the steam demand. When the demand exceeds the supply, the steam pressure will decrease and vice versa. Although a few utility boilers generate steam at sliding pressures, packaged boilers typically generate steam at fixed pressure. The control system immediately adjusts the fuel input to maintain the steam pressure. The following methods are typically used for combustion control.

Single-Point Positioning: This is a simple and safe system for combustion control. A common jackshaft is modulated by a power unit based on variations in drum pressure and is mechanically linked to both the fuel control value and the air control damper. This system is limited to small boilers, typically below 100,000 lb=h, that have an integral fan mounted

Copyright © 2003 Marcel Dekker, Inc.

on top of the wind-box and are fired by a single fuel of nearly constant heating value. Fuel heating values should not vary, and only one fuel can be fired at a time. When low CO values are desired such as less than 70 ppmv, an oxygen trim is added.

Parallel Positioning System: This system is used on large boilers where a remote fan supplies air to the wind-box. It has separate pneumatic power units for controlling air and fuel.

Full Metering with Cross Limiting: This system is expensive but is recommended for accurate air=fuel ratios, for keeping oxygen levels optimized, and for its firing precision. Fuel and air flows are measured continuously and are adjusted as required to maintain the desired air=fuel ratio. Air leads on load increases, and fuel leads on load decreases. This system allows simultaneous firing of two or more fuels. When emission levels are stringent and a large flue gas recirculation rate is used, this method is used and offers better control over the combustion process.

As far as the boiler is concerned, a three-element-level control system is generally used to control the drum water level. Other controls would include steam temperature and master pressure control. Figure 3.15a and 3.15b show typical schemes of gas-side and steam-side instrumentation and controls, respectively, used in packaged boilers.

FAN SELECTION

Packaged steam generators of today use a single fan for up to 250,000 lb=h of steam. The furnaces of oiland gas-fired boilers are pressurized, hence the fan parameters should be selected with care. Estimating the flow or head inaccurately can force the fan to operate in an unstable region or result in the horsepower being too high and the operation inefficient. The density of air should be accurately estimated, so elevation and ambient temperature conditions should be considered. In some cold locations, a steam–air preheat coil is used to preheat the air before it enters the fan, and this adds to the pressure drop. When flue gas recirculation is required, usually the flue gases from the boiler exit are sucked in by the fan, which handles the resistance of the entire system. The density of the mixed air is lower, owing to the higher temperature of the air mixed with the flue gases. The fan should be selected for the lowest density case, as explained in Q9.06, because the mass flow of air is important for combustion and not the volumetric flow. The effect of gas density on fan performance is shown in Fig. 3.16a.

Large margins on flow and head should not be specified, because this leads to oversizing of the fan and can force the fan operating point to the extreme right of the curve in Fig. 3.16b, where the horsepower can be extremely high; a lot of energy is also wasted. Inlet vane control is typically used for controlling the flow

Copyright © 2003 Marcel Dekker, Inc.

FIGURE 3.15a Scheme of boiler controls—gas side. (Courtesy of ABCO Industries, Abilene, TX.)

Copyright © 2003 Marcel Dekker, Inc.

FIGURE 3.15b Scheme of boiler controls—steam side. (Courtesy of ABCO Industries, Abilene, TX.)

Copyright © 2003 Marcel Dekker, Inc.

FIGURE 3.16 (a) Fan performance and range of operation. (b) Effect of system resistance on fan horsepower. (c) Effect of vane position on flow reduction in fans.

of air; this system typically operates stably between 20% and 100% vane opening, which does not translate into a large flow difference, as can be seen from Fig. 3.16c. Hence a small margin on flow and head is preferred—about 15% margin on flow and 20–25% on head is adequate; otherwise one may have to use a variable-speed drive or frequency modulation for control, which is expensive. Underestimating the fan head can also cause the fan to operate in the unstable

Copyright © 2003 Marcel Dekker, Inc.

FIGURE 3.16 Continued.

region as shown in Fig. 3.16a. Curve 2 in Fig. 3.16b is the estimated curve, and the actual curve 1 is to the left, close to the unstable region with positive slope. It also delivers less flow than required. The fan operating point must preferably be in the negatively sloping portion of the head versus flow curve; otherwise the fan could operate in the unstable region, causing surges and vibration. The flue gas recirculation lines must be properly sized; typical air and flue gas velocity in ducts is about 40 ft=s.

The flue gas recirculation line is usually connected to the fan inlet in gas and distillate oil–fired boilers. This increases the size of the forced draft fan. The higher gas pressure drop in the boiler due to the increased mass flow should also be considered when selecting the fan. A separate recirculation fan is used occasionally when heavy fuel oils containing sulfur are fired and the flue gases are admitted into the burner wind-box. If the flue gases were allowed to mix with the cold air at the fan inlet, the mixture temperature could fall below the acid dew point, possibly leading to corrosion.

The fan inlet duct and downstream ductwork must have proper flow distribution. Pulsations and duct vibrations are likely if the inlet airflow to the fan blades is not smooth and the maldistribution in velocity is large. Similarly, the ductwork between the fan and wind-box should be designed to minimize flow maldistribution to ensure proper airflow to the burner.

SUPERHEATERS

The superheater is an important component of a packaged boiler. The degree of superheat could be very high, with steam temperatures up to 1000 F, or as low as

Copyright © 2003 Marcel Dekker, Inc.

50 F. With a very low degree of superheat, one can locate the superheater behind the evaporator and ahead of the economizer. In this case, the superheater may require a large surface area due to the low log-mean temperature difference, but extended surfaces may be used (if distillate oils and gaseous fuels are fired) to make it compact.

Radiant superheaters, which are typically located in the furnace exit region, are widely used by several boiler manufacturers. Radiant superheaters have to be designed very carefully because they operate in a much harsher environment than convective superheaters, which are located in the convective zone behind screen tubes as shown in Fig. 3.17a. Radiant superheaters are located at the furnace exit or in the turning section (Fig. 3.17b). The furnace exit gas temperature is a difficult parameter to estimate. Variations in excess air, flue gas recirculation rates, and burner flame patterns can affect this value and the temperature distribution across the furnace exit plane. The gas temperature in operation could be off by 100–150 F from the predicted value. The turning section is also subject to nonuniformity in gas flow and turbulence, which can affect the superheater performance. Thus its duty can be either underestimated or overestimated by a large margin.

The convective superheater is shielded behind screen tubes as shown in Fig. 3.17a and often operates at 1800–1900 F in comparison with the 2200–2300 F for radiant designs. Because it operates at lower tube wall temperatures, its life can be longer, but it requires a greater surface area because of the lower log-mean temperature difference. However, owing to the lower operating temperatures, a convective superheater can use a lower grade material than the radiant design, and this helps balance the cost to some extent. Also, its location behind screen tubes helps reduce the gas flow nonuniformity to a great extent; hence predicting its performance is easier and more reliable than predicting the performance of the single-stage radiant superheater.

FIGURE 3.17 Location of convective and radiant superheater. 1, Superheater; 2, burner; 3, screen evaporator.

Copyright © 2003 Marcel Dekker, Inc.

Several boilers operate at partial loads of less than 60% for large periods. The radiant superheater, by its nature, absorbs more enthalpy at lower loads, hence the steam temperature increases at lower loads. Convective heat transfer depends on mass flow of flue gases, so as the load decreases, the gas flow and temperature decrease at the superheater region, and therefore the steam temperature and the tube wall temperatures drop with load. Also if at 100% load the steam-side pressure drop in a radiant superheater is 50 psi, then at 30%, it will be about 5 psi, which can lead to concerns about steam flow distribution through the tubes when it is receiving more radiant energy per unit mass of steam. Coupled with nonuniform gas flow distribution at low loads and low gas velocities, the radiant superheater poses several concerns about its tube wall temperatures and hence its life.

The convective superheater is located behind several rows of screen tubes that shield it from furnace radiation. Gas flow entering the superheater is well mixed; hence it is easier to predict its performance and tube wall temperatures. As mentioned earlier, its surface area requirement may be more, but one is assured of low tube wall temperatures and hence longer life.

The steam temperature in a convective superheater generally decreases as the load falls off, whereas in a radiant design it remains within a small range over a larger load range. Hence the convective design has to be sized to ensure that the required steam temperature is achieved at the lowest load, which can increase its size and cost.

The choice of whether to use a radiant or a convective superheater is based on the experience of the supplier. Because the surface area requirements are significantly different due to the different log-mean temperature differences, this is yet another reason that a comparison of surface areas can be misleading.

If heavy oil is fired in the boiler, the problems associated with slagging and high temperature corrosion pose concerns for the longevity and operability of radiant superheaters as discussed below, so convective superheater designs are preferred in such cases. Packaged boilers use limited space compared to utility or field-erected boilers; with high gas velocities and slagging potential in the furnace exit region, the radiant design is vulnerable. Even with a convective superheater design, care should be taken to use retractable soot blowers, and there should be adequate space provided for cleaning and maintenance.

Steam Temperature Control

The steam temperature in packaged boilers is often controlled from 60% to 100% load by using a two-stage superheater design with interstage attemperation as shown in Fig. 3.18. Steam temperature can also be maintained from 10% to 100%; however, this calls for a much larger superheater surface area. Demineralized water should be used for attemperation, because it does not add solids to

Copyright © 2003 Marcel Dekker, Inc.