Gas Turbine Heat Recovery Steam Generators (HRSGs) are widely used in cogeneration or combined-cycle plants to recover energy from turbine exhaust gases. Gas turbines are widely used in chemical plants, refineries and industrial plants as a source of clean electrical power. Often HRSGs are added to utilize the energy from the exhaust gases to generate low-pressure process steam (in cogeneration plants) or high-pressure, high-temperature superheated steam for use in steam turbines (in combined-cycle plants).

HRSGs have certain features and characteristics that are different from conventional gas or oil fired boilers which will be explained in this series of articles. Understanding these differences will help plant engineers and consultants plan and build better and more efficient cogeneration or combined cycle plants.

1. The amount of exhaust gases flowing through a HRSG relative to the steam generation is very large, compared to conventional boilers, as seen below in Table 1.
2. The exhaust gas is relatively clean as natural gas, naphtha or distillate oil is usually fired in gas turbines.
3. Due to the low temperature of the gases entering the HRSG (850 to 1,050°F in unfired mode) and the associated low log-mean temperature differences in various sections such as the superheater, evaporator and economizer, large surface areas are required. Hence finned tubes are inevitably used to make the HRSG compact.
4. The exhaust gases contain about 14 to 16 vol% free oxygen, which enables them to be fired without using additional air. This improves the fuel utilization significantly and additional steam can be generated at nearly 100% efficiency.
5. Multiple pressure steam generation may be required to lower the exhaust gas temperature and recover more energy. It is not unusual to see 2 or 3 pressure levels in large plants. The gas/steam temperature profile is set by thermodynamic considerations by what are known as pinch and approach points, which will be discussed later.
6. Variations in exhaust gas flow and temperature (due to load or ambient conditions) affect the HRSG performance significantly.
7. Different types of designs are available, such as natural circulation, forced and once through.

 

Table 1: Gas/Steam Ratios in Heat Recovery Steam Generators
System	Gas inlet temperature, °F	Gas/steam ratio
Unfired	800-1,000	5.5 to 7
Supplementary fired	1,000-1,700	2.5 to 5.5
Furnace fired	1,700-3,200	1.2 to 2.5
Conventional boilers	3,300-3,600	1 to 1.2

[Superheater duty or steam-pressure gas analysis may affect these numbers but they show the trend.]

As an example, if the gas turbine exhaust flow is about 150,000 lb/h at 900°F, it can generate about 20 to 25,000 lb/h of saturated steam at 300 to 600 psig in the unfired mode. If supplementary firing is introduced, the steam generation can be easily doubled. If furnace firing is done, the steam produced will be quadrupled. Procedures to evaluate these flows at various conditions will be discussed later.Part 1 of this series on gas-turbine Heat Recovery Steam Generators (HRSGs), described their basic function in recovering energy from turbine exhaust gases. Here in Part 2, we will define pinch and approach points, which govern the gas and steam temperature profiles in HRSGs.

In conventional boilers, the gas temperature at the sections such as the superheater and evaporator are so high compared to the steam temperature that the effect of steam pressure hardly matters and does not affect the exit gas temperature. The exit temperature is typically around 320 °F, depending on feedwater temperature in the economizer.

However in single-pressure HRSGs such as that shown in Table 1 in Part 1 (and consisting of a superheater, evaporator and economizer), since Tg1 is low (900 to 1,000 °F), we cannot achieve any exit gas temperature we would like. Steam pressure and temperature will affect the temperature profiles as well as the steam production.

In the above diagram, Tg1, Tg2, Tg3, Tg4 are the gas temperatures at the inlet, and at the exit of the superheater, evaporator and economizer. Ts = saturation temperature, Ts2 = superheated steam temperature. Tw1, Tw2 are the water temperatures entering and leaving the economizer. Pinch point = difference between the gas temperature leaving the evaporator and saturated steam temperature = (Tg3-Ts) Approach point = difference between saturated steam temperature and water temperature leaving the economizer = (Ts-Tw2)

Pinch and approach points cannot be arbitrarily selected. The above values are reasonable, based on inlet gas temperature, use of extended surfaces and industry experience. If bare tubes are being used, or if inlet gas temperature is higher, say, 1,400-1,500 °F, then the pinch and approach points will be higher. Table 2 below shows suggested pinch and approach points. These values are based on common, reasonable HRSG designs. Note that pinch and approach points have to be higher with bare tubes, as compact designs are not possible as with finned tubes.

 

Table 2: Suggested pinch, approach points
Item	Pinch point, °F		Approach point, °F
Evaporator type	Bare	Finned
Inlet gas temp, °F 1, 200-1, 800 750-1, 200	130-150 80-130	30-60 10-30	40-70 10-40

The calculations below will explain why we cannot obtain any desired exit gas temperature with single-pressure HRSGS.

Considering the superheater and evaporator, we have from energy balance:

Wg×Cpg×(Tg1-Tg3) = Ws×(hs2-hw2)  (1)

considering the entire HRSG,

Wg×Cpg×(Tg1-Tg4) = Ws×(hs2-hw1)  (2)

where Wg = gas flow, Ws = steam generation, Cpg = gas specific heat (considering it to vary little with gas temperatures for simplicity). Heat loss and blowdown are also neglected to illustrate the point below. Dividing (1) by (2), we have:

(Tg1-Tg3)/(Tg1-Tg4) = (hs2-hw2)/(hs2-hw2) = K

For steam generation to occur and for a thermodynamically feasible temperature profile, two conditions must be met: Tg3>Ts and Tg4>Tw1. If pinch and approach points are arbitrarily selected, it is likely that one of these conditions may fail. Table 3 below shows K values and exit gas temperatures for 20 °F pinch and 15 °F approach, which are typical in unfired HRSGS.

It can be seen from Table 3 below that:

1. As steam pressures increases, the exit gas temperature increases
2. If a superheater is used, less steam is generated, and hence the capacity of the economizer as a heat sink decreases and so the exit gas temperature increases further. Note that at 600 psig, the exit gas with a superheater is nearly 400 °F, while at 100-psig saturated, it is 300 °F. This is the reason I mentioned earlier that exit gas temperature cannot be arbitrarily assumed in HRSGs. One has to perform what is called HRSG simulation to arrive at heat balances and temperature profiles. Software that I have written (available at http://members.aol.com/rajammal/boilers.html) performs these complex calculations for single or multiple pressures in unfired or fired conditions. Contact the author for a free demo program.

Table 3: HRSG exit gas temperatures
Press, psig	steam temp, °F	sat temp, °F	K	exit gas, °F
100	sat	338	0.904	300
150	sat	366	0.8754	313
250	sat	406	0.8337	332
400	sat	448	0.7895	353
400	600	450	0.8063	367
600	sat	490	0.74	373
600	750	492	.7728	398
[gas inlet temperature = 900 °F, pinch = 20 °F, approach = 15 °F]

Example 1: Determine the HRSG exit gas temperature when gas inlet temperature = 90 °F and steam pressure = 100-psig saturated. Use 20 °F pinch and 15 °F approach points.

Solution: There is no superheater. Evaluate K = 0.904 using enthalpies from steam tables. Saturated steam temperature = 338 °F. Hence Tg3 = 338 + 20 = 358 °F. Tw2 = 338 - 15 = 323 °F. (900-358)/(900-Tg4) = 0.904 or Tg4 = 300 °F.

Example 2: What is Tg4 when steam pressure = 600 psig and steam temperature = 750 °F?

Solution: K = 0.7728. Sat temp = 492 °F. Tw2 = 477 °F. Tg3 = 512 °F. Hence (900-512)/(900-Tg4) = 0.7728 or Tg4 = 398 °F. Hence a 300 °F stack temperature is thermodynamically not possible.

Example 3: Why can't we obtain 300 °F stack gas temperature at 600-psig, 750 °F?

Solution: K = 0.7728. Let us compute Tg3 from: (900-Tg3)/(900-300) = 0.7728 or Tg3 = 436 °F, which is below the saturation temperature of 492 °F. This called a temperature cross.

Example 4: What should be done to obtain 300 °F with above steam parameters?

Solution: If Tg1 is increased by firing to say 1,600 °F, and assuming K does not change much, (1,600-Tg3)/(1,600-300) = 0.7728 or Tg3=595 °F. This is an achievable pinch point. Similarly, it can be shown that with lower gas temperature, say 700-800 °F (gas turbine at low load operation), the exit gas temperature will be higher.

The conclusion is that with HRSGs, we cannot assume an exit gas temperature and calculate the duty or steam production. Many consultants however commit this error while developing specifications. Simulation programs are available that can generate valuable information on HRSG temperature profiles and steam generation.

Temperature Profile Calculations
The following procedure explains how one can estimate the gas/steam temperature profiles and the steam generation in HRSGs.

Example: 140,000 lb/h of turbine exhaust gases at 980 °F enter a HRSG generating saturated steam at 200 psig. Determine the steam generation and temperature profiles. Feedwater temperature = 230 °F and blowdown = 5%.

Solution: Assume that the gas specific heat = 0.27 Btu/lb°F at the evaporator and 0.253 at the economizer. Specific heats vary with gas analysis and temperature; software is available to evaluate these terms accurately. For illustration purposes the average estimates will be used.

Let us assume that pinch point = 20 °F and approach point = 15 °F. Saturation steam temperature from steam tables = 388 °F. Hence, the gas temperature leaving evaporator = 408 °F. Water temperature entering it = 388-15 = 373 °F. Evaporator duty = 140,000 × 0.99 × 0.27 × (980-408) = 21.4 million Btu/h [0.99 refers to the 1% heat loss from the HRSG]

Enthalpy absorbed by steam in the evaporator = (1199.3-345) + 0.05 × (362.2-345) = 855.2 Btu/lb [1199.3, 345, and 362.2 refer to enthalpies of saturated steam, water entering evaporator and saturated water respectively. 0.05 refers to the 5% blow down.]

Hence steam generated = 21.4 million Btu/h/855.2 = 25,000 lb/h
Economizer duty = 25,000×1.05×(345-198.5) = 3.84 MM Btu/h
[198.5 is the enthalpy of feedwater entering the economizer, derived from steam tables]
Gas temperature drop in economizer = 3, 84,000/(140,000×.99×.253) = 109 °F
Hence exit gas = 408-109 = 299 °F

Note that if a superheater were present, the same procedure would be used. We first compute the duty of the superheater and evaporator based on gas temperature difference between inlet and evaporator exit and then the steam generation as above. The gas temperature drop across the superheater and economizer are computed to obtain all the four gas temperatures.

Table 4 below gives the gas specific heat for typical gas turbine exhaust gases with a composition of (vol %) CO2 = 3, H2O = 7, N2 = 75, and O2 = 15.

 

Table 4
Gas temp, °F	sp. heat
200	0.2529
400	0.2584
600	0.2643
800	0.2705
1,000	0.2767

The above procedure computes what is known as the Design Temperature Profile.Parts 1 and 2 of this series reviewed the basic operating principles of heat-recovery steam generators (HSRGs) working with gas turbine in industrial heating and power-generation schemes. Here, we will examine how to analyze HRSGs based on the operating conditions. Gas-turbine HRSGs operate at different conditions of gas flow, exhaust gas temperature and analysis due to the variations in gas-turbine exhaust parameters. These parameters vary with ambient temperature, fuel composition and load. Hence, predicting HRSG performance under different conditions is a must for consultants, plant engineers and HRSG designers. However, since HRSGs in general are of the convective type, one can easily simulate their off-design performance without actually designing the HRSG in terms of tube sizes, dimensions, surface areas, etc. A little knowledge of basics will help understand the process.

First the design temperature profile as discussed above is obtained at design conditions. We know the duty of each section and the gas/steam temperatures. Then one computes the U.S. values for each section:

(U.S.) = Q/DT, where Q = duty in Btu/h, DT = log-mean temperature difference, °F. U = overall heat transfer coefficient, Btu/ft2h°F and S = surface area, ft2

Then under different gas inlet conditions, the (U.S.) design values are corrected for gas analysis, temperature and gas flow [see my book "Waste Heat Boiler Deskbook" for equations.]

Then the actual duty transferred at each section is obtained using the equation (U.S.) corrected × DT. Gas/steam temperature profiles, duty and steam generation at off-design cases may be then obtained. Note that the pinch and approach points are assumed only for the design case calculations. In off-design mode, the pinch and approach points are arrived at through an iterative calculation, performed by the program using the corrected (US) values.

The author's HRSGs simulation program does these calculations for complex single or multi-pressure, unfired, or fired HRSGs. One can quickly evaluate how a HRSG performs under different gas turbine loads, ambient temperatures, how much supplementary firing is required and steam flows at different modules.

The following table shows the results from a simple simulation calculation using the HRSGs program. It shows how much fuel is required to generate different amounts of steam. Firing temperatures, gas/steam temperatures, oxygen consumed are all obtained in seconds. The first column shows the design conditions of a HRSG in unfired mode using a pinch and approach of 20 °F and the other columns show the off-design performance at higher steam flows.

 

item	case 1	case 2	case 3
gas flow, lb/h	150,000	150,000	150,000
inlet gas temperature, °F	900	900	900
firing temperature, °F	900	1281	1707
burner duty, million Btu/h	0	16.81	37.52
Steam flow, lb/h	22,780	40,000	60,000
exit gas temperature, °F	326	315	311
boiler duty, million Btu/h	22.66	39.8	59.9
System efficiency, %	68.7	79.2	84.0
[feedwater = 230 F, blowdown = 3%, steam pressure = 200 psig. Gas analysis (vol%): CO2 = 3, H2O = 7, N2 = 75, O2 = 15. Fuel input is on LHV basis.]

Following can be seen from above table:

1. Supplementary firing is an efficient method of generating additional steam in HRSGs. The additional boiler duty is nearly equal to the fuel input, which suggests that supplementary firing is 100% efficient. Compare this to conventional boilers, where fuel efficiency is about 90-93%. Hence if one requires additional steam in cogeneration plants, the first place to look for is the HRSG. While planning cogeneration projects, engineers should see that the HRSG is designed as a fired HRSG, even though it could be more expensive. In the long run, it pays for itself.

2. The exit gas temperature is also reduced at higher steam loads. This is due to the fact that the economizer acts as a bigger heat sink at higher steam loads. Note that the gas flow through the HRSG is nearly the same at 60,000 lb/h as it is at 22,780 lb/h. Hence with the same gas flow, but with higher water low, the economizer is able to pull the gas temperature lower.

3. The oxygen content is reduced due to supplementary firing, because no additional air is required. The oxygen content drops from 15% volume in unfired mode to 10.67 at 60,000 lb/h. This process is opposite to that which happens in conventional boilers, where losses are increased with higher excess air. We reduce the excess air with supplementary firing, which is why the efficiency also improves. The next section shows how the oxygen content varies with amount of fuel fired.

Oxygen Consumption vs. Fuel Input
Gas turbine HRSGs are usually fired with fuels such as natural gas or distillate oils to generate additional steam. Firing temperatures are limited to about 1,650 °F in the case of supplementary fired HRSGs, which have insulated casing design. In these systems, the casing of the HRSG is internally insulated with several layers of ceramic fiber and protected from the hot gases by an alloy steel liner. Duct burners are used for this purpose. No additional air is required as turbine exhaust contains about 13 to 15% oxygen by volume. In case of HRSGs with significant steam injection in gas turbines, the oxygen content reduces to about 11 to 12% and augmenting air may be required if suggested by the burner supplier. Firing above 1,650 °F requires water-cooled furnace design for the HRSG.

Oxygen consumption is often an important factor in determining burner type and process parameters. The following derivation shows the relation between the oxygen consumption and fuel input.

The energy Q in Btu/h on Lower Heating Value basis (LHV) required to raise Wg lb/h of turbine exhaust gases from a temperature of t1 to t2 is given by:

Q = Wg × (h2-h1) where h1 and h2 correspond to the enthalpy of the gas at t1 and t2.

If O is the % volume of oxygen in the exhaust gases entering the burner, the equivalent amount of air Wa in the exhaust is approximately: Wa = 100 × Wg × O × 32/(23 × 100 × 29.5)

In the above equation, we are merely converting the moles of oxygen from a volume to a weight basis.

A molecular weight of 29.5 is used for the exhaust gases. The quantities 32 and 23 are the molecular weights of oxygen and wt% of oxygen in air.

Simplifying the above, we have:

Wa = 0.0417WgO

Now let us relate the air required for combustion with fuel fired. From basic combustion calculations and from articles earlier on combustion, we know that each type of fuel requires a constant amount of air A for combustion for each Million Btu fired. A = 745 for oil and 730 for natural gas. Thus 106/HHV lb of fuel requires A lb of air. Hence Q/LHV lb of fuel requires:

(Q/LHV) × A × HHV/106 lb of air. And this is equal to Wa from above. (Q/LHV) × A × HHV/106 = Wa = 0.0417WgO or Q = 0.0417WgO× 106 × LHV/(HHV × A)

for natural gas and fuel oils it can be shown that LHV/A/HHV = 0.00124. Hence substituting in above,

Q = 58.4WgO

This equation gives the relation between oxygen consumption O and Q.

Example: It is desired to raise the temperature of 150,000 lb/h of turbine exhaust gases from 950 to 1,575 °F in order to double the steam output of a HRSG. If exhaust contains 15% oxygen by volume, determine the oxygen consumed.

Q = 150,000 × 0.31 × (1575-950) = 29 × 106 Btu/h where 0.31 is the average specific heat. The author's burner program or HRSGs program provides accurate computation of the fuel input.

Hence O = 29 × 106/(150,000 × 58.4) = 3.32 or the final oxygen content = 11.68%, which is still high. This tells us that we can raise the gas temperature further if required, provided the HRSG design can be compatible.

By V. Ganapathy